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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, 2010 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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 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 June 30, 2010: $13,000,000,000
Number of shares of Common Stock, $0.001 par value, outstanding at January 31, 2011: 648,616,985
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement for the 2011 Annual Meeting of Shareholders are incorporated by reference in Part III.
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FORM 10-K FOR THE YEAR ENDED
DECEMBER 31, 2010
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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 the risk of a prolonged economic slowdown or decline, or the risk of delay in a recovery, which can affect the long-term demand for natural gas and related services; |
| • | potential effects arising from terrorist attacks and any consequential or other hostilities; |
| • | changes in environmental, safety and other laws and regulations; |
| • | the development of alternative energy resources; |
| • | 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 market and economic conditions; |
| • | increases in the cost of goods and services required to complete capital projects; |
| • | declines in the market prices of equity and debt securities and resulting funding requirements for defined benefit pension plans; |
| • | growth in opportunities, including the timing and success of efforts to develop U.S. and Canadian pipeline, storage, gathering, processing and other related 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 these 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
The terms “we,” “our,” “us,” and “Spectra Energy” as used in this report refer collectively to Spectra Energy Corp and its subsidiaries unless the context suggests otherwise. These terms are used for convenience only and are not intended as a precise description of any separate legal entity within Spectra Energy.
Spectra Energy Corp, through its subsidiaries and equity affiliates, 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, we and our predecessor companies have developed critically important pipelines and related energy infrastructure connecting natural gas supply sources to premium markets. We operate in three key areas of the natural gas industry: gathering and processing, transmission and storage, and distribution. Based in Houston, Texas, we provide 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. We also provide 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, we hold a 50% ownership interest in DCP Midstream, LLC (DCP Midstream), one of the largest natural gas gatherers and processors in the United States, based in Denver, Colorado. Our internet website is http://www.spectraenergy.com.
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Our natural gas pipeline systems consist of over 19,000 miles of transmission pipelines. Our proportional throughput for our pipelines totaled 4,248 trillion British thermal units (TBtu) in 2010, compared to 3,987 TBtu in 2009 and 3,733 TBtu in 2008. These amounts include throughput on wholly owned U.S. and Canadian pipelines and our proportional share of throughput on pipelines that are not wholly owned. Our storage facilities provide approximately 305 billion cubic feet (Bcf) of storage capacity in the United States and Canada.
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 us and all of our outstanding common stock was distributed to Duke Energy’s shareholders.
We manage our business in four reportable segments: U.S. Transmission, Distribution, Western Canada Transmission & Processing, and Field Services. The remainder of our 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 our businesses. For financial information on our business segments, see Part II. Item 8. Financial Statements and Supplementary Data, Note 5 of Notes to Consolidated Financial Statements.
Our U.S. Transmission business provides transportation and storage of natural gas for customers in various regions of the northeastern and southeastern United States and the Maritime Provinces in Canada. Our U.S. pipeline systems consist of more than 14,400 miles of transmission pipelines with seven primary transmission systems: Texas Eastern Transmission, LP (Texas Eastern), Algonquin Gas Transmission, LLC (Algonquin), East Tennessee Natural Gas, LLC (East Tennessee), Maritimes & Northeast Pipeline, L.L.C. and Maritimes & Northeast Pipeline Limited Partnership (collectively, Maritimes & Northeast Pipeline), Ozark Gas Transmission, L.L.C. (Ozark Gas Transmission), Gulfstream Natural Gas System, LLC (Gulfstream) and Southeast Supply Header, LLC (SESH). The pipeline systems in our U.S. Transmission business receive natural gas from major North American producing regions for delivery to their respective markets. U.S. Transmission’s proportional throughput for its pipelines totaled 2,708 TBtu in 2010, compared to 2,574 TBtu in 2009 and 2,218 TBtu in 2008. This includes throughput on wholly owned pipelines and our 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 services are provided on a short-term or seasonal basis.
U.S. Transmission provides storage services through Saltville Gas Storage Company L.L.C. (Saltville), Market Hub Partners Holding’s (Market Hub’s) Moss Bluff and Egan storage facilities, Steckman Ridge, LP (Steckman Ridge), Bobcat Gas Storage (Bobcat) and Texas Eastern’s facilities. Gathering services are provided through Ozark Gas Gathering, L.L.C (Ozark Gas Gathering). 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. FERC is the U.S. agency that regulates the transportation of natural gas in interstate commerce.
In 2007, we completed our initial public offering (IPO) of Spectra Energy Partners, LP (Spectra Energy Partners), a newly formed, natural gas infrastructure master limited partnership which is part of the U.S.
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Transmission segment. Subsequent to the dropdown of Saltville and the P-25 pipeline assets into Spectra Energy Partners in 2008, the acquisition of NOARK Pipeline System, Limited Partnership (NOARK) in 2009 and an additional dropdown of ownership interests in Gulfstream in 2010, we currently retain a 69% equity interest in Spectra Energy Partners, which owns 100% of East Tennessee, 100% of Saltville, 100% of Ozark Gas Gathering and Ozark Gas Transmission, 50% of Market Hub and 49% of Gulfstream. Spectra Energy directly owns a 50% interest in Market Hub and a 1% interest in Gulfstream. Spectra Energy Partners is a separate, publicly traded entity which trades on the New York Stock Exchange under the symbol “SEP.”
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. Texas Eastern has two storage facilities in Pennsylvania held through joint ventures and one wholly owned and operated storage facility in Maryland. Texas Eastern’s total working capacity in these three facilities is 74 Bcf. In addition, Texas Eastern’s system is connected to Steckman Ridge, a 12 Bcf storage facility in Pennsylvania owned by our joint venture with New Jersey Resources (NJR), and three storage facilities in Texas and Louisiana, aggregating 63 Bcf, owned by Market Hub Partners and Bobcat Gas Storage.
New Jersey-New York Expansion. This expansion of the Texas Eastern pipeline system is designed to transport new, critically needed natural gas supplies to high-demand markets in northern New Jersey and New York City. With a capacity of 800 million cubic-feet-per-day (Mmcf/d) of natural gas, the project is fully
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subscribed with commitments for firm transportation service. In December 2010, we filed an application with the FERC for this expansion project. Substantial design, environmental and related work will be ongoing throughout 2011. As discussed under Item 1A. Risk Factors, risks associated with any capital expansion program include regulatory, development, operational and market risks. The $850 million project is expected to be in service in November 2013 and should help to eliminate existing bottlenecks in the region’s interstate transmission pipeline grid.
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 1,125 miles of pipeline with seven compressor stations.
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East Tennessee
East Tennessee’s transmission system crosses Texas Eastern’s system at two points in Tennessee and consists of two mainline systems totaling approximately 1,500 miles of pipeline in Tennessee, Georgia, North Carolina and Virginia, with 21 compressor stations. East Tennessee has a liquefied natural gas (LNG, natural gas that has been converted to liquid form) storage facility in Tennessee with a total working capacity of 1 Bcf. East Tennessee also connects to the Saltville storage facilities in Virginia that have a working gas capacity of approximately 5 Bcf.
We have an effective 69% ownership interest in East Tennessee through our ownership of Spectra Energy Partners.
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Maritimes & Northeast Pipeline
Maritimes & Northeast Pipeline’s gas transmission system is operated through Maritimes & Northeast Pipeline Limited Partnership (M&N LP), the Canadian portion of this system, and Maritimes & Northeast Pipeline, L.L.C. (M&N LLC), the U.S. portion. We have 78% ownership interests in both segments of the system and affiliates of Exxon Mobil Corporation and Emera, Inc. have the remaining interests. The Maritimes & Northeast Pipeline transmission system consists of approximately 850 miles of pipeline originating from landfall of the producing fields in Nova Scotia through New Brunswick, Maine, New Hampshire and Massachusetts, connecting to the Algonquin system in Beverly, Massachusetts. There are seven compressor stations on the Maritimes & Northeast Pipeline system.
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Ozark
We have an effective 69% ownership interest in Ozark Gas Transmission and Ozark Gas Gathering, which was acquired by Spectra Energy Partners in 2009. Ozark Gas Transmission consists of a 565-mile interstate natural gas pipeline system extending from southeastern Oklahoma through Arkansas to southeastern Missouri. Ozark Gas Gathering consists of a 365-mile gathering system that primarily serves Arkoma basin producers in eastern Oklahoma.
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Gulfstream
We have an effective 35% investment in Gulfstream, a 745-mile interstate natural gas pipeline system operated jointly by us and The Williams Companies, Inc. Gulfstream transports natural gas from Mississippi, Alabama, Louisiana and Texas, crossing the Gulf of Mexico to markets in central and southern Florida. Gulfstream has three compressor stations. Gulfstream is directly owned 1% by Spectra Energy, 49% by Spectra Energy Partners and 50% by affiliates of The Williams Companies, Inc. Our investment in Gulfstream is accounted for under the equity method of accounting.
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SESH
We have a 50% investment in SESH, a 275-mile interstate natural gas pipeline system with three mainline compressor stations owned and operated jointly by us and CenterPoint Energy, Inc. SESH, which began operations in September 2008, extends from the Perryville Hub in northeastern Louisiana where the emerging shale gas production of eastern Texas, northern Louisiana and Arkansas, along with conventional production, is reached from five major interconnections. SESH extends to Alabama, interconnecting with 14 major north-south pipelines and three high-deliverability storage facilities. Our investment in SESH is accounted for under the equity method of accounting.
Market Hub
We have an effective 85% ownership interest in Market Hub, which owns and operates two natural gas storage facilities, Moss Bluff and Egan, with a total storage capacity of approximately 45 Bcf. The Moss Bluff facility consists of three salt dome storage caverns located in southeast Texas and has access to five pipeline systems including the Texas Eastern system. The Egan facility consists of four salt dome storage caverns located in south central Louisiana and has access to seven pipeline systems including the Texas Eastern system. Market Hub is a general partnership in which Spectra Energy and Spectra Energy Partners each have a 50% direct interest.
Saltville
We have an effective 69% ownership interest in Saltville through our ownership of Spectra Energy Partners. Saltville owns and operates natural gas storage facilities in Virginia with a total storage capacity of approximately 5 Bcf. The storage facilities interconnect with East Tennessee’s system. This salt cavern facility offers high-deliverability capabilities and is strategically located near markets in Tennessee, Virginia and North Carolina.
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Bobcat
We have a 100% ownership interest in Bobcat, an 18 Bcf salt dome facility which was acquired in August 2010. Bobcat is strategically located on the Gulf Coast near Henry Hub and interconnects with five major interstate pipelines, including Texas Eastern. Bobcat’s storage capacity is expected to be 46 Bcf by the end of 2016 when fully developed.
Steckman Ridge
We have a 50% investment in Steckman Ridge, a 12 Bcf depleted reservoir storage facility located in south central Pennsylvania that interconnects with the Texas Eastern system. Steckman Ridge, which began operations in April 2009, is operated by us and owned 50% by us and 50% by NJR Steckman Ridge Storage Company. Our investment in Steckman Ridge is accounted for under the equity method of accounting.
Competition
Our U.S. Transmission transportation and storage businesses compete with similar facilities that serve our 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 we transport in our transmission business competes with other forms of energy available to our 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, levels of business activity, long-term economic conditions, conservation, legislation, governmental regulations, the ability to convert to alternative fuels, weather and other factors.
Customers and Contracts
In general, our U.S. Transmission pipelines provide transportation and storage services to local distribution companies (LDCs, companies that obtain a major portion of their revenues from retail distribution systems for the delivery of natural gas for ultimate consumption), electric power generators, exploration and production companies, and industrial and commercial customers, as well as energy marketers. Transportation and storage services are generally 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 our storage facilities, plus a small variable component that is based on volumes transported, injected or withdrawn, which is intended to recover variable costs.
We also provide interruptible transportation and storage services where customers can use capacity if it is available at the time of the request. Interruptible revenues depend on the amount of volumes transported or stored and the associated market rates for this interruptible service. New projects placed into service may initially have higher levels of interruptible services at inception. Storage operations also provide a variety of other value-added services including natural gas parking, loaning and balancing services to meet our customers’ needs.
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We provide distribution services in Canada through our subsidiary, Union Gas Limited (Union Gas). Union Gas is a major Canadian natural gas storage, transmission and distribution company based in Ontario. The distribution business serves approximately 1.3 million residential, commercial and industrial customers in more than 400 communities across northern, southwestern and eastern Ontario. Union Gas’ growing storage and transmission business offers services to customers at the Dawn Hub, the largest underground storage facility in Canada and one of the largest in North America. It offers customers an important link in the movement of natural gas from Western Canada and U.S. supply basins to markets in central Canada and the northeast United States.
Union Gas’ system consists of approximately 37,600 miles of distribution main and service pipelines. Distribution pipelines carry or control the supply of natural gas from the point of local supply to customers. Union Gas’ underground natural gas storage facilities have a working capacity of approximately 155 Bcf in 23 underground facilities located in depleted gas fields. Its transmission system consists of approximately 3,000 miles of high-pressure pipeline and six mainline compressor stations.
Competition
Union Gas is regulated by the Ontario Energy Board (OEB) pursuant to the provisions of the Ontario Energy Board Act (1998) and is subject to regulation in a number of areas including rates. Union Gas is not generally subject to third-party competition within its distribution franchise area. However, as a result of a 2006 decision by the OEB, physical bypass of new expansion 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.
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The incentive regulation framework approved by the OEB in 2008 establishes new rates at the beginning of each year through the use of a pricing formula rather than through the examination of revenue and cost forecasts. The allowed return on equity (ROE) for Union Gas is formula-based and is periodically established by the OEB. The established ROE for 2008 will remain unchanged throughout the five-year incentive regulation period (2008-2012). In 2011, Union Gas expects to make an application to the OEB that will result in new rates for 2013 and future periods. This filing will include updated revenue and cost forecasts to reset rates, as well a proposal to increase to the allowed ROE pursuant to the OEB’s policy report on the Cost of Capital for Ontario’s Regulated Utilities. In addition, the application will include proposals for the next incentive regulation framework.
In 2006, the OEB found that the market for storage services is sufficiently competitive, and therefore decided to deregulate the prices for storage services to customers outside Union Gas’ franchise area and the prices for new storage services to customers within its franchise area. This Storage Forbearance Decision created an unregulated storage operation within Union Gas and provides the framework required to support new unregulated storage investments. For these unregulated services, Union Gas competes against third-party storage providers for storage on the basis of price, terms of service, and flexibility and reliability of service. The Storage Forbearance Decision requires Union Gas to continue to share long-term storage margins with ratepayers over a four-year phase-out period that started in 2008. Effective in 2011, there will no longer be any sharing of margins with Union Gas customers on long-term storage transactions.
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 weather, price changes, the availability of natural gas and other forms of energy, levels of business activity, economic conditions, conservation, legislation, governmental regulations, the ability to convert to alternative fuels, and other factors.
Customers and Contracts
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 either the source of customers’ gas supply or its price.
Union Gas provides its in-franchise customers with regulated distribution, transmission and storage services. Union Gas also provides unregulated natural gas storage and regulated transportation services for other utilities and energy market participants, including large 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 eight years, with the longest being approximately 25 years.
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WESTERN CANADA TRANSMISSION & PROCESSING
Our Western Canada Transmission & Processing business is comprised of the BC Pipeline and BC Field Services operations, and the Natural Gas Liquids (NGLs) Marketing and Canadian Midstream operations.
BC Pipeline and BC Field Services provide fee-based 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 BC, Alberta and the U.S. Pacific Northwest. BC Pipeline has approximately 1,725 miles of transmission pipeline in BC and Alberta, as well as 18 mainline compressor stations. Throughput for the BC Pipeline totaled 627 TBtu in 2010, compared to 604 TBtu in 2009 and 615 TBtu in 2008.
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 by the producers. NGLs are liquid hydrocarbons extracted during the processing of natural gas. Principal commercial NGLs include butanes, propane, natural gasoline and ethane. The BC Field Services business includes five gas processing plants located in BC, 17 field compressor stations and approximately 1,550 miles of gathering pipelines.
The Canadian Midstream business provides similar gas gathering and processing services in BC and Alberta and consists of 11 natural gas processing plants and approximately 650 miles of gathering pipelines.
The Empress NGL 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 United States. Assets include a majority ownership interest in an NGL extraction plant, an integrated NGL fractionation facility, an NGL transmission pipeline, seven terminals where NGLs are loaded for shipping or
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transferred into product sales pipelines, two NGL storage facilities and an NGL marketing business. The Empress extraction and fractionation plant is located in Empress, Alberta.
Fort Nelson Expansion. In 2009, firm contracts for approximately 800 Mmcf/d were signed for incremental gathering and processing service in the Fort Nelson area of northeastern British Columbia. The Fort Nelson expansion program consists of a series of 10 discrete gathering and processing projects, with a total projected capital expenditure of approximately $1 billion. Nine of the ten projects were placed in service in 2009 and 2010. The new 250 Mmcf/d Fort Nelson North processing facility, which is the final phase and most significant capital outlay of the program, is under construction and is expected to be brought in-service in 2012. Upon completion, we will operate over 1.2 Bcf/d of raw gas processing capacity and associated gathering pipelines in the Fort Nelson area.
Competition
Western Canada Transmission & Processing businesses compete with third-party midstream companies, exploration and production companies, and pipelines in the gathering, processing and transportation of natural gas and the extraction and marketing of NGL products. Western Canada Transmission & Processing 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, NGLs and other forms of energy, levels of business activity, long-term economic conditions, conservation, legislation, governmental regulations, the ability to convert to alternative fuels, weather and other factors affect the demand for natural gas in the areas Western Canada Transmission & Processing serves.
In addition to the fee for service pipeline and gathering and processing businesses, we compete 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, we must be competitive in the premium or fee we pay to natural gas shippers. We also compete with other NGL marketers in the various markets we serve. Declines in eastbound flows of natural gas through Empress, Alberta caused an increase in 2010 in the premiums that we paid to shippers to extract NGLs.
Customers & Contracts
BC Pipeline provides: (i) transportation services from the outlet of natural gas processing plants primarily in northeast BC to LDCs, end-use industrial and commercial customers, marketers, and exploration and production companies requiring transportation services to the nearest natural gas trading hub; and (ii) transportation services primarily to downstream markets in the Pacific Northwest (both United States and Canada). 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. BC Pipeline also provides interruptible transportation services where customers can use capacity if it is available at the time of request. Payments under these services are based on volumes transported.
The BC Field Services and Canadian Midstream operations in western Canada provide raw natural gas gathering and processing services to exploration and production companies under agreements which are primarily fee-for-service contracts which do not expose us to commodity-price risk. These operations provide both firm and interruptible services.
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The NGL extraction operation at Empress, Alberta is jointly owned with a partner and has capacity to produce approximately 63,000 barrels of NGLs per day (our share is approximately 58,000 barrels per day at full capacity). At Empress, we extract and purchase NGLs from natural gas shippers on the TransCanada pipeline system. In addition to paying shippers a negotiated extraction fee, we keep the shipper whole by returning an equivalent amount of natural gas for the NGLs that were extracted. After NGLs are extracted, we fractionate the NGLs into ethane, propane, butanes and condensate, and sell these products into the marketplace. All ethane is sold to Alberta-based petrochemical companies. In addition to paying for natural gas shrinkage, the ethane buyers pay us a negotiated cost-of-service price or a negotiated fixed price. We sell the remaining products—propane, butane and condensate—at market prices and are exposed to the difference between the selling prices and the shrinkage makeup price of natural gas plus the extraction premium and operating costs. The majority of propane is sold to propane retailers. 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 we can obtain for these products are affected by numerous factors including competition, weather, transportation costs and supply and demand factors.
Field Services consists of our 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 owns a 30% interest in DCP Midstream Partners, LP (DCP Partners), a master limited partnership. As its general partner, DCP Midstream accounts for its investment in DCP Partners as a consolidated subsidiary.
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DCP Midstream operates in 26 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 nine major natural gas producing regions: Mid-Continent, Rocky Mountain, East Texas-North Louisiana, Barnett Shale, Gulf Coast, South Texas, Central Texas, Antrim Shale and Permian Basin. DCP Midstream owns or operates approximately 61,000 miles of gathering and transmission pipeline, with approximately 37,000 active receipt points.
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 operates 61 natural gas processing plants.
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 in the Northeastern U.S. which includes nine propane terminals.
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 also stores residue gas at its 9 Bcf Spindletop natural gas storage facility located near Beaumont, 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, natural gas and crude oil prices, which have fluctuated significantly over the last few years. DCP Midstream closely monitors the risks associated with these price changes. See Part II. 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.
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 processors, and brokers, marketers and distributors of natural gas supplies. Competition for natural gas supplies is based mostly 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 mostly upon reliability, services offered and the prices 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
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ConocoPhillips and its affiliate, Chevron Phillips Chemical Company LLC, under existing contracts that have primary terms that are effective until January 1, 2015. In 2010, sales to ConocoPhillips and Chevron Phillips Chemical Company LLC, combined, represented approximately 22% 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. More than 70% of volumes of gas that are gathered and processed are under percentage-of-proceeds contracts.
| • | 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 prices of natural gas, crude oil and NGLs. |
| • | Fee-based arrangements. DCP Midstream receives a fee 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.
We purchase 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.
We operate a North American supply chain management network with employees dedicated to this function in the United States and Canada. Our supply chain management group uses economies-of-scale to maximize the efficiency of supply networks where applicable. DCP Midstream performs its own supply chain management function.
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 our 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 the extension, enlargement and abandonment of facilities. In addition, certain operations are subject to oversight by state regulatory commissions.
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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.
Our U.S. Transmission and DCP Midstream operations are subject to the jurisdiction of the Environmental Protection Agency (EPA) and various other federal, state and local environmental agencies. See “Environmental Matters” for a discussion of environmental regulation. Our U.S. interstate natural gas pipelines and certain of DCP Midstream’s gathering and transmission pipelines are also subject to the regulations of the U.S. Department of Transportation concerning pipeline safety. Our Canadian operations are governed by the NEB, the Technical Standards and Safety Authority and various other federal and local agencies 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. Our BC Field Services business in western Canada is regulated by the NEB pursuant to a framework for light-handed regulation under which the NEB acts on a complaints-basis for rates associated with that business. Similarly, the rates charged by our Canadian Midstream operations for gathering and processing services in western Canada are regulated on a complaints-basis by applicable provincial regulators. Our 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 of DCP Midstream are not subject to FERC regulation.
We are subject to various 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 us include, but are not limited to:
| • | The Clean Air Act (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. Our natural gas processing, transmission and storage assets are considered sources of air emissions and are thereby subject to the CAA. Owners and/or operators of air emission sources, like ourselves, 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 (Clean Water 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. The OPA imposes certain spill prevention, control and countermeasure requirements. Although we are primarily a natural gas business, the OPA affects our business primarily because of the presence of liquid hydrocarbons (condensate) in our offshore pipelines. |
| • | The Comprehensive Environmental Response, Compensation and Liability Act (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 our operations, we have disposed of waste at many different sites and have CERCLA liabilities at some properties we own. |
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| • | 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 our business, we generate 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 historical use of lubricating oils containing PCBs, the internal surfaces of some of our 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 site approvals. Many of our capital projects require federal agency review, and therefore the environmental effects of proposed projects are a factor in determining whether we 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 provincial laws governing various aspects, including permitting and site remediation obligations, of our facilities and operations in those provinces. |
| • | The Canadian Environmental Protection Act, pursuant to which, among other things, regulations require reporting of greenhouse gas (GHG) emissions from our operations in Canada. Additional regulations to be promulgated under this Act may require the reduction of GHGs, nitrogen oxides, sulphur oxides, volatile organic compounds and particulate matter. |
| • | The Alberta Climate Change and Emissions Management Act, which, pursuant to regulations that came into effect in 2007, requires certain facilities to meet reductions in emission intensity starting in 2007. The Act was applicable to our Empress facility in Alberta beginning in 2008. |
For more information on environmental matters, including possible liability and capital costs, see Part II. Item 8. Financial Statements and Supplementary Data, Notes 6 and 19 of Notes to Consolidated Financial Statements.
Except to the extent discussed in Notes 6 and 19, 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 our various business units and is not expected to have a material adverse effect on our competitive position or consolidated results of operations, financial position or cash flows.
For a discussion of our Canadian operations and the risks associated with them, see Part II. 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 5 and 18 of Notes to Consolidated Financial Statements.
We had approximately 5,500 employees as of December 31, 2010, including approximately 3,500 employees outside of the United States, all in Canada. In addition, DCP Midstream employed approximately 2,800 employees as of such date. Approximately 1,500 of our employees, all of whom are located in Canada, are subject to collective bargaining agreements governing their employment with us. Approximately 60% of those employees are covered under agreements that either have expired or will expire by December 31, 2011.
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The following table sets forth information regarding our executive and other officers.
| Name |
Age |
Position | ||||
| Gregory L. Ebel |
46 | President and Chief Executive Officer, Director | ||||
| J. Patrick Reddy |
58 | Chief Financial Officer | ||||
| Dorothy M. Ables |
53 | Chief Administrative Officer | ||||
| John R. Arensdorf |
60 | Chief Communications Officer | ||||
| Alan N. Harris |
57 | Chief Development and Operations Officer | ||||
| Reginald D. Hedgebeth |
43 | General Counsel | ||||
| Steve W. Baker |
47 | Vice President and Treasurer | ||||
| Sabra L. Harrington |
48 | Vice President and Controller | ||||
Gregory L. Ebel assumed his current position as President and Chief Executive Officer on January 1, 2009. He previously served as Group Executive and Chief Financial Officer from January 2007. Mr. Ebel served as President of Union Gas from January 2005 until January 2007. Mr. Ebel currently serves on the Board of Directors of DCP Midstream, LLC.
J. Patrick Reddy joined Spectra Energy in January 2009 as Chief Financial Officer. Mr. Reddy served as Senior Vice President and Chief Financial Officer at Atmos Energy Corporation from September 2000 to December 2008. Mr. Reddy currently serves on the Board of Directors of DCP Midstream, LLC.
Dorothy M. Ables assumed her current position as Chief Administrative Officer in November 2008. Prior to then, she served as Vice President of Audit Services and Chief Ethics and Compliance Officer from January 2007; Vice President of Audit Services for Duke Energy Corporation from April 2006 to December 2006; and Vice President, Audit Services and Chief Compliance Officer for Duke Energy Corporation from February 2004 to March 2006.
John R. Arensdorf assumed his current position in November 2008. He previously served as Vice President, Investor Relations from January 2007. Prior to then, Mr. Arensdorf served as General Manager, Investor Relations at Duke Energy from April 2006 to December 2006 and as General Manager, Internal Controls from November 2004 to April 2006.
Alan N. Harris assumed his current position as Chief Development Officer and Chief Operations Officer in November 2008. He previously served as Group Executive and Chief Development Officer since January 2007. Prior to then, Mr. Harris served as Group Vice President and Chief Financial Officer of Duke Energy Gas Transmission from February 2004 to January 2007. Mr. Harris currently serves on the Board of Directors of DCP Midstream Partners, LP.
Reginald D. Hedgebeth assumed his current position as General Counsel in March 2009. He previously served as Senior Vice President, General Counsel and Secretary with Circuit City Stores, Inc. from July 2005 to March 2009.
Steve W. Baker assumed his current position as Vice-President and Treasurer in April 2010. He previously served as Vice-President, Business Development Storage and Transmission at Union Gas from September 2007 to March 2010 and Vice-President, Business Development and Commercial Accounts at Union Gas from January 2004 to August 2007.
Sabra L. Harrington assumed her current position as Vice President and Controller in January 2007. Prior to then, she served as Vice President, Financial Strategy of Duke Energy Gas Transmission from February 2006 and as Vice President and Controller of Duke Energy Gas Transmission from August 2003 until February 2006.
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We were incorporated on July 28, 2006 as a Delaware corporation. Our principal executive offices are located at 5400 Westheimer Court, Houston, Texas 77056 and our telephone number is 713-627-5400. We electronically file various 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 we file 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 us, including our reports filed with the SEC, is available through our web site at http://www.spectraenergy.com. Such reports are accessible at no charge through our web site and are made available as soon as reasonably practicable after such material is filed with or furnished to the SEC. Our website and the information contained on that site, or connected to that site, are not incorporated by reference into this report.
Discussed below are the material risk factors relating to Spectra Energy.
Reductions in demand for natural gas and low market prices of commodities adversely affect our operations and cash flows.
Our regulated businesses are generally economically stable and are not significantly affected in the short-term by changing commodity prices. However, all of our businesses can be negatively affected in the long term by sustained downturns in the economy or long-term conservation efforts, which could affect long-term demand and market prices for natural gas and NGLs, all of which are beyond our control and could impair the ability to meet long-term goals.
Most of our 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 our 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 result in the non-renewal of long-term contracts at the time of expiration. Lower demand for natural gas and lower prices for natural gas and NGLs could result from multiple factors that affect the markets where we operate, including:
| • | weather conditions, such as 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 our processing business due to lower throughput; |
| • | capacity and transmission service into or out of our markets; and |
| • | petrochemical demand for NGLs. |
The lack of availability of natural gas resources may cause customers to seek alternative energy resources, which could materially adversely affect our revenues, earnings and cash flows.
Our 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 are accessible by our pipeline, gathering, processing and distribution assets. Lack of commercial quantities of natural gas available to these assets could cause customers to seek alternative energy resources, thereby reducing their reliance on our services, which in turn would materially adversely affect our revenues, earnings and cash flows.
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Investments and projects located in Canada expose us to fluctuations in currency rates that may adversely affect our results of operations, cash flows and compliance with debt covenants.
We are exposed to foreign currency risk from our Canadian operations. An average 10% devaluation in the Canadian dollar exchange rate during 2010 would have resulted in an estimated net loss on the translation of local currency earnings of approximately $48 million on our Consolidated Statement of Operations. In addition, if a 10% devaluation had occurred on December 31, 2010, the Consolidated Balance Sheet would have been negatively impacted by $595 million through a cumulative translation adjustment in Accumulated Other Comprehensive Income (AOCI). At December 31, 2010, one U.S. dollar translated into one Canadian dollar.
In addition, we maintain credit facilities that typically include financial covenants which limit the amount of debt that can be outstanding as a percentage of total capital for Spectra Energy or of a specific subsidiary. Failure to maintain these covenants could preclude us from issuing commercial paper or letters of credit or borrowing under our revolving credit facilities and could require other affiliates to immediately pay down any outstanding drawn amounts under other revolving credit agreements, which could adversely affect cash flows or restrict business. Foreign currency fluctuations have a direct impact on our ability to maintain certain of these financial covenants.
Natural gas gathering and processing operations are subject to commodity price risk, which could result in a decrease in our earnings and reduced cash flows.
We have 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. We are exposed to market price fluctuations of NGLs, natural gas and oil primarily in our Field Services segment. Based on a sensitivity analysis as of December 31, 2010, a 10¢ per-gallon move in NGL prices would affect our annual pre-tax earnings by approximately $65 million in 2011, primarily from Field Services. For the same period, a 50¢ per-million-British-thermal-units (MMbtu) move in natural gas prices would affect our annual pre-tax earnings by approximately $15 million and a $10 per-barrel move in oil prices would affect our annual pre-tax earnings by approximately $25 million.
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 effects of commodity price changes on our earnings could be significantly different than these estimates.
Our business is subject to extensive regulation that affects our operations and costs.
Our U.S. assets and operations are subject to regulation by various federal, state and local authorities, including regulation by the FERC and by various authorities under federal, state and local environmental laws. Our 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 our business, including, among other things, the ability to determine terms and rates for services provided by some of our businesses, make acquisitions, construct, expand and operate facilities, issue equity or debt securities, and pay dividends.
In addition, regulators in both the United States 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 our business, earnings, financial condition and cash flows.
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Execution of our capital projects subjects us to construction risks, increases in labor and material costs, and other risks that may adversely affect our financial results.
A significant portion of our 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, operational and market 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; |
| • | potential changes in federal, state and local statutes and regulations, including environmental requirements, that may prevent a project from proceeding or increase the anticipated cost of the project; |
| • | impediments on our ability to acquire rights-of-way or land rights on a timely basis and on acceptable terms; |
| • | the ability to construct projects within anticipated costs, including the risk of cost overruns resulting from inflation or increased costs of equipment, materials or labor, weather, geologic conditions or other factors beyond our control, that may be material; and |
| • | general economic factors that affect the demand for natural gas infrastructure. |
Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated cost. As a result, new facilities may not achieve their expected investment return, which could adversely affect our earnings, financial position and cash flows.
Gathering and processing, transmission and storage, and distribution activities involve numerous risks that may result in accidents or otherwise affect our operations.
There are a variety of hazards and operating risks inherent in natural gas gathering and processing, transmission, storage, and distribution 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. 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. We do not maintain insurance coverage against all of these risks and losses, and any insurance coverage we 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 our business, earnings, financial condition and cash flows.
We are subject to pipeline safety laws and regulations, compliance with which can require significant capital expenditures, can increase our cost of operations and may affect or limit our business plans.
Our interstate pipeline operations are subject to pipeline safety regulation administered by the Pipeline and Hazardous Materials Safety Administration (the PHMSA) of the U.S. Department of Transportation. These laws and regulations require us to comply with a significant set of requirements for the design, construction, maintenance and operation of our interstate pipelines. These regulations, among other things, include requirements to monitor and maintain the integrity of our pipelines. The regulations determine the pressures at which our pipelines can operate. Pipeline failures or failure to comply with applicable regulations could result in reduction of allowable operating pressures as authorized by the PHMSA, which would reduce available capacity on our pipelines. Should any of these risks materialize, it could have a material adverse effect on our operations, earnings, financial condition and cash flows.
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We are subject to numerous environmental laws and regulations, compliance with which can require significant capital expenditures, increase our cost of operations and may affect or limit our business plans, or expose us to environmental liabilities.
We are subject to numerous environmental laws and regulations affecting many aspects of our 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 us 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 our operating assets. In addition, changes in environmental laws and regulations or the enactment of new environmental laws or regulations could result in a material increase in our cost of compliance with such laws and regulations. We may not be able to obtain or maintain from time to time all required environmental regulatory approvals for our operating assets or development projects. If there is a delay in obtaining any required environmental regulatory approvals, if we fail to obtain or comply with them or if environmental laws or regulations change or are administered in a more stringent manner, the operations 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 may be incurred to comply with environmental regulations in the future will not have a material adverse effect on our earnings and cash flows.
The enactment of future climate change legislation could result in increased operating costs and delays in obtaining necessary permits for our capital projects.
The current international climate framework, the United Nations-sponsored Kyoto Protocol, prescribes specific targets to reduce GHG emissions for developed countries for the 2008-2012 period. The Kyoto Protocol expires in 2012 and has not been signed by the United States. United Nations-sponsored international negotiations were held in Cancun, Mexico in December 2010 with the intent of defining a future agreement for 2012 and beyond. While the talks resulted in a limited political agreement, to date, a binding successor accord to the Kyoto Protocol has not been realized.
While Canada is a signatory to the Kyoto Protocol, the Canadian federal government has confirmed it will not achieve the targets within the timeframes specified. Instead, the government in 2008 outlined a regulatory framework mandating GHG reductions from large final emitters. Regulatory design details from the Government of Canada remain forthcoming. We expect a number of our assets and operations in Canada will be affected by future federal climate change regulations. However, the materiality of any potential compliance costs is unknown at this time as the final form of the regulation and compliance options has yet to be determined by policymakers.
In the United States, climate change action is evolving at state, regional and federal levels. We expect that some of our assets and operations in the United States could be affected either directly or indirectly by eventual mandatory GHG programs; however, the timing and specific policy objectives in many jurisdictions, including at the federal level, remain uncertain. In addition, a number of Canadian provinces and U.S. states have joined regional greenhouse gas initiatives, and a number are developing their own programs that would mandate reductions in GHG emissions. However, as the key details of future GHG restrictions and compliance mechanisms remain undefined, the likely future effects on our business are highly uncertain.
The EPA finalized a Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule in 2009 to address how GHG emissions would be regulated under the existing Clean Air Act. Regulation is scheduled to begin in 2011, and over time, certain existing Spectra Energy U.S. facilities will be subject to this regulation. Some new construction and modification projects in the future may be subject to this regulation as well. At this time, it is not anticipated that the costs will be material; however, many implementation details are
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still unknown. There may be additional permitting requirements which may result in delays in completing capital projects. In addition, several legislative proposals that would impose GHG emissions constraints have been considered by the U.S. Congress. To date, no such legislation has been enacted into law.
Due to the speculative outlook regarding any U.S. federal and state policies and the uncertainty of the Canadian federal and provincial policies, we cannot estimate the potential effect of proposed GHG policies on our future consolidated results of operations, financial position or cash flows. However, such legislation or regulation could materially increase our operating costs, require material capital expenditures or create additional permitting, which could delay proposed construction projects.
We are involved in numerous legal proceedings, the outcome of which are uncertain, and resolutions adverse to us could negatively affect our earnings, financial condition and cash flows.
We are subject to numerous legal proceedings. Litigation is subject to many uncertainties, and we cannot predict the outcome of individual matters with assurance. It is reasonably possible that the final resolution of some of the matters in which we are 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 our earnings and cash flows.
We rely on access to short-term and long-term capital markets to finance capital requirements and support liquidity needs, and access to those markets can be adversely affected, particularly if we or our rated subsidiaries are unable to maintain an investment-grade credit rating, which could adversely affect our cash flows or restrict business.
Our 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, we rely on access to both short-term and long-term capital markets as a source of liquidity for capital requirements not satisfied by the cash flows from operations and to fund investments originally financed through debt. Our senior unsecured long-term debt is currently rated investment-grade by various rating agencies. If the rating agencies were to rate us or our rated subsidiaries below investment-grade, our borrowing costs would increase, perhaps significantly. In addition, we would likely be required to pay a higher interest rate in future financings and our potential pool of investors and funding sources could decrease.
We maintain revolving credit facilities to provide back-up for commercial paper programs for borrowings 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 flows or restrict business. Furthermore, if our short-term debt rating were to be below tier 2 (for example, A-2 for Standard and Poor’s and P-2 for Moody’s Investor Service), access to the commercial paper market could be significantly limited. Although this would not affect our ability to draw under our credit facilities, borrowing costs could be significantly higher.
If we are not able to access capital at competitive rates, our ability to finance operations and implement our strategy may be adversely affected. Restrictions on our ability to access financial markets may also affect our ability to execute our business plan as scheduled. An inability to access capital may limit our ability to pursue improvements or acquisitions that we may otherwise rely on for future growth. Any downgrade or other event negatively affecting the credit ratings of our subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could increase our 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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We may be unable to secure renewals of long-term transportation agreements, which could expose our transportation volumes and revenues to increased volatility.
We may be unable to secure renewals of long-term transportation agreements in the future for our natural gas transmission business as a result of economic factors, lack of commercial gas supply available to our systems, changing gas supply flow patterns in North America, increased competition or changes in regulation. Without long-term transportation agreements, our revenues and contract volumes would be exposed to increased volatility. The inability to secure these agreements would materially adversely affect our business, earnings, financial condition and cash flows.
We are exposed to the credit risk of our customers.
We are exposed to the credit risk of our customers in the ordinary course of our business. Generally, our customers are rated investment-grade, are otherwise considered creditworthy or provide us security to satisfy credit concerns. Approximately 90% of our credit exposures for transportation, storage, and gathering and processing services are with customers who have an investment-grade rating (or the equivalent based on our evaluation) or are secured by collateral. However, we cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including possible declines in our customers’ creditworthiness. As a result of future capital projects for which natural gas producers may be the primary customer, the percentage of our customers who are rated investment-grade may decline. While we monitor these situations carefully and take appropriate measures when deemed necessary, it is possible that customer payment defaults, if significant, could have a material adverse effect on our earnings and cash flows.
Market-based natural gas storage operations are subject to commodity price volatility, which could result in variability in our earnings and cash flows.
We have market-based rates for some of our storage operations and sell our 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 relative to demand, our approach to managing our market-based storage contract portfolio may not protect us from significant variations in storage revenues as contracts renew.
Native land claims have been asserted in British Columbia and Alberta, which could affect future access to public lands, and the success of these claims could have a significant adverse effect on natural gas production and processing.
Certain aboriginal groups have claimed aboriginal and treaty rights over a substantial portion of public lands on which our 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 our facilities and of NGLs and other products transported in the associated pipelines. In addition, certain aboriginal groups in Ontario have claimed aboriginal and treaty rights in areas where Union Gas’ Dawn storage and transmission assets are located and also in areas where the Dawn-Trafalgar pipeline route is located. The existence of these claims could give rise to future uncertainty regarding land tenure depending upon their negotiated outcomes. We cannot predict the outcome of any of these claims or the effect they may ultimately have on our business and operations.
Protecting against potential terrorist activities requires significant capital expenditures and a successful terrorist attack could adversely affect our 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
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companies, like ours, operating in any energy infrastructure industry that handles volatile gaseous and liquid hydrocarbons. The potential for terrorism, including cyber-terrorism, has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, we may experience increased capital and operating costs to implement increased security for our 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. We may be required to expend material amounts of capital to repair any facilities, the expenditure of which could adversely affect our business and cash flows.
Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.
Poor investment performance of our pension plan holdings and other factors affecting pension plan costs could unfavorably affect our earnings, financial position and liquidity.
Our costs of providing defined benefit pension plans are dependent upon a number of factors, such as the rates of return on plan assets, discount rates used to measure pension liabilities, actuarial gains and losses, future government regulation and our contributions made to the plans. Without sustained growth in the pension plan investments over time to increase the value of our plan assets, and depending upon the other factors impacting our costs as listed above, we could experience net asset, expense and funding volatility. This volatility could have a material effect on our earnings and cash flows.
Item 1B. Unresolved Staff Comments.
None.
At December 31, 2010, we had over 100 primary facilities located in the United States and Canada. We generally own sites associated with our major pipeline facilities, such as compressor stations. However, we generally operate our transmission facilities—transmission and distribution pipelines—using rights of way pursuant to easements to install and operate pipelines, but we do not own the land. Except as described in Part II. Item 8. Financial Statements and Supplementary Data, Note 15 of Notes to Consolidated Financial Statements, none of our properties were secured by mortgages or other material security interests at December 31, 2010.
Our corporate headquarters are located at 5400 Westheimer Court, Houston, Texas 77056, which is a leased facility. The lease expires in April 2018. We also maintain offices in, among other places, Calgary, Alberta; Vancouver, British Columbia; Chatham, Ontario; Waltham, Massachusetts; Tampa, Florida; Halifax, Nova Scotia; Toronto, Ontario; and Nashville, Tennessee. For a description of our material properties, see Item 1. Business.
We have no material pending legal proceedings that are required to be disclosed hereunder. See Note 19 of Notes to Consolidated Financial Statements for discussions of other legal proceedings.
Item 4. [Removed and Reserved]
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PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Our common stock is traded on the New York Stock Exchange under the symbol “SE.” As of January 31, 2011, there were approximately 141,000 holders of record of our common stock and approximately 450,000 beneficial owners.
Common Stock Data by Quarter
| 2010 |
Dividends Per Common Share |
Stock Price Range (a) | ||||||||||
| High | Low | |||||||||||
| First Quarter |
$ | 0.25 | $ | 23.06 | $ | 20.30 | ||||||
| Second Quarter |
0.25 | 23.85 | 18.57 | |||||||||
| Third Quarter |
0.25 | 22.81 | 19.67 | |||||||||
| Fourth Quarter |
0.25 | 25.45 | 22.37 | |||||||||
| 2009 |
||||||||||||
| First Quarter |
0.25 | 17.47 | 11.21 | |||||||||
| Second Quarter |
0.25 | 17.61 | 13.75 | |||||||||
| Third Quarter |
0.25 | 19.73 | 15.81 | |||||||||
| Fourth Quarter |
0.25 | 20.78 | 18.26 | |||||||||
| (a) | Stock prices represent the intra-day high and low price. |
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Stock Performance Graph
The following graph reflects the comparative changes in the value from January 3, 2007, the first trading day of Spectra Energy common stock on the New York Stock Exchange, through December 31, 2010 of $100 invested in (1) Spectra Energy’s common stock, (2) the Standard & Poor’s 500 Stock Index, and (3) the Standard & Poor’s 500 Oil & Gas Storage & Transportation Index. The amounts included in the table were calculated assuming the reinvestment of dividends at the time dividends were paid.
| January 3, 2007 |
December 31, | |||||||||||||||||||
| 2007 | 2008 | 2009 | 2010 | |||||||||||||||||
| Spectra Energy Corp |
$ | 100.00 | $ | 93.47 | $ | 59.54 | $ | 82.34 | $ | 104.95 | ||||||||||
| S&P 500 Stock Index |
100.00 | 105.60 | 66.53 | 84.14 | 96.81 | |||||||||||||||
| S&P 500 Storage & Transportation Index |
100.00 | 114.30 | 56.81 | 79.38 | 101.13 | |||||||||||||||
Dividends
We currently anticipate an average dividend payout ratio over time of approximately 65% of our estimated annual net income from controlling interests per share of common stock and expect to continue our policy of paying regular cash dividends. The actual payout ratio, however, may vary from year to year depending on earnings levels. The declaration and payment of dividends are subject to the sole discretion of our Board of Directors and depends upon many factors, including the financial condition, earnings and capital requirements of our operating subsidiaries, covenants associated with certain debt obligations, legal requirements, regulatory constraints and other factors deemed relevant by our Board of Directors.
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 Statements and Supplementary 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 our predecessor
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entity for financial statement reporting purposes. Accordingly, the information presented below for 2006 is that of Spectra Capital. This information is not necessarily indicative of future performance or what our results of operations and financial position would have been if we had operated as a separate, stand-alone entity in 2006.
We have identified certain immaterial errors in our previously issued financial statements. The following selected financial data reflect the corrections of those errors. See Item 8. Financial Statements and Supplementary Data, Note 2 of Notes to Consolidated Financial Statements for further discussion.
| 2010 | 2009(a) | 2008(a) | 2007(b) | 2006(b,c) | ||||||||||||||||
| (Unaudited) (dollars in millions, except per-share amounts) |
||||||||||||||||||||
| Statements of Operations |
||||||||||||||||||||
| Operating revenues |
$ | 4,945 | $ | 4,552 | $ | 5,074 | $ | 4,704 | $ | 4,501 | ||||||||||
| Operating income |
1,674 | 1,475 | 1,480 | 1,426 | 1,234 | |||||||||||||||
| Income from continuing operations |
1,123 | 919 | 1,195 | 990 | 917 | |||||||||||||||
| Net income—noncontrolling interests |
80 | 75 | 65 | 70 | 61 | |||||||||||||||
| Net income—controlling interests |
1,049 | 849 | 1,132 | 945 | 1,189 | |||||||||||||||
| Ratio of Earnings to Fixed Charges |
3.1 | 2.8 | 3.6 | 3.1 | 3.0 | |||||||||||||||
| Common Stock Data |
||||||||||||||||||||
| Earnings per share from continuing operations |
||||||||||||||||||||
| Basic |
$ | 1.61 | $ | 1.31 | $ | 1.82 | $ | 1.47 | n/a | |||||||||||
| Diluted |
1.60 | 1.31 | 1.81 | 1.46 | n/a | |||||||||||||||
| Earnings per share |
||||||||||||||||||||
| Basic |
1.62 | 1.32 | 1.82 | 1.49 | n/a | |||||||||||||||
| Diluted |
1.61 | 1.32 | 1.81 | 1.49 | n/a | |||||||||||||||
| Dividends per share |
1.00 | 1.00 | 0.96 | 0.88 | n/a | |||||||||||||||
| December 31, | ||||||||||||||||||||
| 2010 | 2009(d) | 2008 | 2007 | 2006 | ||||||||||||||||
| (in millions) | ||||||||||||||||||||
| Balance Sheets |
||||||||||||||||||||
| Total assets |
$ | 26,686 | $ | 24,091 | $ | 21,924 | $ | 22,970 | $ | 20,345 | ||||||||||
| Long-term debt including capital leases, less current maturities |
10,169 | 8,947 | 8,290 | 8,345 | 7,726 | |||||||||||||||
| (a) | See Note 2 of Notes to Consolidated Financial Statements for amounts previously reported. |
| (b) | Amounts previously reported: Income from Continuing Operations—$1,002 million (2007) and $972 million (2006); Net Income—Controlling Interests—$957 million (2007) and $1,244 million (2006); Earnings Per Share From Continuing Operations—Basic and Diluted—$1.48 (2007); Earnings Per Share—Basic and Diluted—$1.51 (2007). |
| (c) | Significant transactions reflected in 2006 results include: the transfer of certain businesses to Duke Energy in December 2006 in preparation of our spin-off from Duke Energy, with total assets of approximately $5.1 billion and operating revenues of $1.0 billion; our indirect transfer of Duke Energy North America Midwestern assets to Duke Energy Ohio, Inc., with approximately $1.6 billion of assets and operating revenues of $788 million; a $250 million gain associated with the creation of the Crescent Resources joint venture; and the subsequent deconsolidation of Crescent Resources. |
| (d) | Total Assets previously reported as $24,079 million as of December 31, 2009. |
| n/a | Indicates not applicable. |
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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 Item 8. Financial Statements and Supplementary Data.
During 2010, we identified certain immaterial errors in our previously issued financial statements related primarily to the impacts of enacted Canadian federal and provincial tax rate changes on deferred income tax balances associated with our Canadian operations. The following discussions reflect the correction of these immaterial errors. See Note 2 of Notes to Consolidated Financial Statements for further discussion.
EXECUTIVE OVERVIEW
Throughout 2010, we continued to successfully execute on the long-term strategies and objectives we have outlined for our shareholders. These included exceeding our earnings objectives, the successful execution on capital expansion plans that underlie our growth objectives, and maintaining a strong balance sheet. In addition, we executed contracts in 2010 that support substantial continued growth of our market positions.
We also advanced our position as an advisor and partner of choice by continuing to build productive relationships with stakeholders that enable us to successfully permit projects and achieve sector-leading ratings on both the Dow Jones Sustainability Index and the Carbon Disclosure Project. Our “advisor of choice” efforts focused on ensuring stable regulatory environments where we operate, advocating the benefits of natural gas and engaging our employees in reaching out to their elected officials on issues important to us and the natural gas industry. In 2010, we saw noteworthy improvements in our safety metrics related to our high-performance culture objective, with employee recordable incidents down significantly.
During 2010, our fee-based businesses at U.S. Transmission, Distribution and Western Canada Transmission & Processing performed well by meeting the needs of our customers and generating increased earnings and cash flows from successful expansion projects placed in service. In addition, commodity prices at Field Services and a strengthened Canadian dollar improved significantly compared to 2009 and positively affected our earnings in 2010. We reported net income from controlling interests of $1,049 million, and $1.61 of diluted earnings per share for 2010 compared to net income from controlling interests of $849 million, and $1.32 of diluted earnings per share for 2009.
We invested $1.4 billion of capital and investment expenditures in 2010, including approximately $700 million of expansion capital expenditures. This does not include the $540 million acquisition of the Bobcat assets and development project. We successfully completed our 2010 expansion plans, with returns on these projects well above our targeted 10-12% return on capital employed range. Return on capital employed as it relates to expansion projects is calculated by us as incremental earnings before interest and taxes generated by a project divided by the total cost of the project. We plan to increase our expansion capital spending to a total of approximately $5.0 billion from 2011 through 2015, with approximately $1.4 billion planned for 2011, as we continue to pursue opportunities around new natural gas supply volumes in Western Canada and the Appalachian and Southeast regions of the United States.
Financing activities in 2010 and the capital growth projected in 2011 through 2015 are based on continued strong fee-based earnings and cash flows, as well as continued prudent financial management of our capitalization structure. We are committed to an investment grade balance sheet. Debt, including short-term borrowings and commercial paper, increased $1.4 billion in 2010. However, at December 31, 2010, our debt-to-capitalization ratio remained at 56%. Total capitalization benefited from earnings, a strengthening Canadian dollar and the issuance of additional public units of Spectra Energy Partners in 2010.
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As of December 31, 2010, we continue to have ongoing access to approximately $1.6 billion available under our credit facilities and expect to continue to utilize commercial paper and revolving lines of credit, as needed, to complement our ongoing cash flows to fund liquidity needs throughout 2011. Financing activities in 2011 will include the refinancing of debt maturities of approximately $300 million and the issuance of commercial paper under our revolving credit facilities. We also anticipate accessing the markets for other long-term financing to fund our ongoing capital expansion program.
In the fourth quarter of 2010, Spectra Energy Partners acquired an additional 24.5% interest in Gulfstream from Spectra Energy (the Gulfstream acquisition) for approximately $330 million. Also in the fourth quarter of 2010, Spectra Energy Partners issued 6.9 million common units to the public and 0.1 million general partner units to Spectra Energy, netting us proceeds from the issuances of $216 million. Total Stockholders’ Equity, including Noncontrolling Interests, increased $180 million as a result of these transactions. See Note 3 of Notes to Consolidated Financial Statements for further discussion.
Our Strategy. Our primary business objective is to create superior and sustainable value for our investors, customers, employees and communities by providing natural gas gathering, processing, transmission, storage and distribution services. We intend to accomplish this objective by executing the following overall business strategies, which remain consistent with our 2010 strategies:
| • | Deliver on 2011 financial commitments. |
| • | Develop new opportunities and projects that add long-term shareholder value and meet customers’ needs. |
| • | Effectively execute on our 2011 expansion plans. |
| • | Enhance and solidify our profile and position as an advisor and partner of choice. |
| • | Build on our high-performance culture by focusing on safety and employee engagement. |
We know we are successful when we are the supplier of choice for our customers, the employer of choice for individuals, the advisor of choice on policy and regulation for governments and regulators, the partner of choice for our communities, and the investment opportunity of choice for investors.
2010 Financial Results. We reported net income from controlling interests of $1,049 million in 2010 compared to net income from controlling interests of $849 million in 2009. The increase in net income from controlling interests mainly reflects the positive impact of NGL prices on earnings from Field Services, a stronger Canadian dollar and expansion projects at U.S. Transmission and Western Canada Transmission & Processing. NGL prices are correlated to higher crude oil prices, which averaged $80 per barrel for 2010 versus $62 per barrel in 2009. These increases in earnings were partially offset by the recognition of a $135 million deferred gain ($85 million after-tax) in 2009 associated with partnership units previously issued by DCP Partners.
Highlights for 2010 include the following:
| • | U.S. Transmission’s earnings benefited from successful execution of planned expansion projects as well as the Bobcat acquisition, partially offset by higher operating costs as a result of a reimbursement of project development costs and the capitalization of previously expensed development costs in 2009, |
| • | Distribution’s earnings increased mainly as a result of a stronger Canadian dollar, and lower operating fuel costs, partially offset by lower customer usage of natural gas due to warmer weather in the first half of 2010 and higher employee benefit costs, |
| • | Western Canada Transmission & Processing earnings increased mainly as a result of higher gathering and processing earnings from expansions and a stronger Canadian dollar, partially offset by higher operating and maintenance costs due partly to plant maintenance turnarounds in 2010, and |
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| • | Field Services earnings benefited from higher commodity prices, partially offset by a gain recognized in 2009 associated with partnership units issued by DCP Partners and lower gathering and processing margins resulting from lower volumes and efficiencies in 2010. |
Significant Economic Factors For Our Business. Our regulated businesses are generally economically stable and are not significantly affected in the short-term by changing commodity prices. However, all of our businesses can be negatively affected in the long term by sustained downturns in the economy or long-term conservation efforts, which could affect long-term demand and market prices for natural gas and NGLs, all of which are beyond our control and could impair our ability to meet long-term goals.
Most of our 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 our 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 result in the non-renewal of long-term contracts at the time of expiration. Pipeline transportation and storage customers continue to renew most contracts as they expire. Processing revenues and the earnings and distributions from our Field Services segment are also affected by volumes of natural gas made available to our systems, which are primarily driven by levels of natural gas drilling activity. Current levels of interest remain strong for natural gas exploration and drilling in the areas that affect our Western Canada Transmission & Processing and Field Services segments, primarily driven by recent positive developments around unconventional gas reserves production in numerous locations within North America.
Our combined key markets—the northeastern and the southeastern United States, the Pacific Northwest, British Columbia and Ontario—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 2019. 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 our growth strategies. Traditionally, supply to our markets has come from the Gulf Coast region, both onshore and offshore, as well as from fields in western and eastern Canada. The national supply profile is shifting to new sources of gas from basins in the Rockies, Mid-Continent, Appalachia, Texas and Louisiana. These supply shifts are shaping the growth strategies that we 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.”
Our businesses in the United States 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 we cannot predict the future course of changes in the regulatory environment or the ultimate effect that any future changes will have on our businesses. Additionally, investments and projects located in Canada expose us to risks related to Canadian laws, taxes, economic conditions, fluctuations in currency rates, political conditions and policies of the Canadian government. From 2002 through 2010, the Canadian dollar strengthened significantly compared to the U.S. dollar, which favorably affected earnings and equity during these periods, except in the fourth quarter 2008 and the first quarter 2009 when the Canadian dollar weakened significantly in a very short period of time. Changes in this exchange rate or other of these factors are difficult to predict and may affect our future results and financial position.
Certain of our earnings are affected by fluctuations in commodity prices, especially the earnings of DCP Midstream. We evaluate, on an ongoing basis, the risks associated with commodity price volatility and currently do not have any plans to enter into hedge positions around these earnings.
Based on current projections, it is expected that our effective income tax rate on continuing operations will approximate 28 – 29% for 2011. Our overall effective tax rate largely depends on the proportion of earnings in the United States, subject to a 35% federal statutory tax rate, to the earnings of our Canadian operations, with an effective tax rate of approximately 19% that is driven by lower statutory rates and recognition of certain regulatory tax benefits.
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Our strategic objectives include a critical focus on capital expansion projects that will require access to capital markets. An inability to access capital at competitive rates could adversely affect our ability to implement our strategy. Market disruptions or a downgrade in our credit ratings may increase the cost of borrowing or adversely affect our ability to access one or more sources of liquidity.
During the past few years, capital expansion projects have been exposed to cost pressures associated with the availability of skilled labor and the pricing of materials. Although certain costs have begun to decrease in the current economic conditions, there will be continual focus on project management activities to address these pressures as we move forward with planned expansion opportunities. Significant cost increases could negatively affect the returns ultimately earned on current and future expansions.
For further information related to management’s assessment of our risk factors, see Part I. Item 1A. Risk Factors.
RESULTS OF OPERATIONS
| 2010 | 2009 | 2008 | ||||||||||
| (in millions) | ||||||||||||
| Operating revenues |
$ | 4,945 | $ | 4,552 | $ | 5,074 | ||||||
| Operating expenses |
3,281 | 3,088 | 3,636 | |||||||||
| Gains on sales of other assets and other, net |
10 | 11 | 42 | |||||||||
| Operating income |
1,674 | 1,475 | 1,480 | |||||||||
| Other income and expenses |
462 | 406 | 844 | |||||||||
| Interest expense |
630 | 610 | 636 | |||||||||
| Earnings from continuing operations before income taxes |
1,506 | 1,271 | 1,688 | |||||||||
| Income tax expense from continuing operations |
383 | 352 | 493 | |||||||||
| Income from continuing operations |
1,123 | 919 | 1,195 | |||||||||
| Income from discontinued operations, net of tax |
6 | 5 | 2 | |||||||||
| Net income |
1,129 | 924 | 1,197 | |||||||||
| Net income—noncontrolling interests |
80 | 75 | 65 | |||||||||
| Net income—controlling interests |
$ | 1,049 | $ | 849 | $ | 1,132 | ||||||
2010 Compared to 2009
Operating Revenues. The $393 million, or 9%, increase was driven mainly by:
| • | the effects of a stronger Canadian dollar on revenues at Western Canada Transmission & Processing and Distribution, |
| • | higher earnings from acquisitions and expansion projects at U.S. Transmission and Western Canada Transmission & Processing, and |
| • | higher NGL revenues due to higher product prices, net of lower sales volumes, from the Empress operations at Western Canada Transmission & Processing, partially offset by |
| • | lower natural gas prices passed through to customers at Distribution. |
Operating Expenses. The $193 million, or 6%, increase was driven mainly by:
| • | the effects of a stronger Canadian dollar at Western Canada Transmission & Processing and Distribution, |
| • | a reimbursement of project development costs by customers and the capitalization of previously expensed costs on northeast expansions in 2009 and higher operating costs at U.S. Transmission in 2010, |
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| • | higher prices of natural gas purchased, net of lower production volumes, at the Empress operations and higher facilities maintenance costs related to an increase in scheduled plant turnarounds at Western Canada Transmission & Processing, and |
| • | lower net corporate costs mainly due to a benefit related to an early termination notice made by Westcoast Energy Inc. (Westcoast) for capacity contracts held on the Alliance pipeline in 2010, partially offset by |
| • | lower natural gas prices passed through to customers and lower operating fuel costs at Distribution. |
Operating Income. The $199 million increase was mainly driven by a stronger Canadian dollar, earnings from expansion projects at U.S. Transmission and Western Canada Transmission & Processing, lower operating fuel costs at Distribution and lower net corporate costs, partially offset by a reimbursement of project development costs by customers and the capitalization of previously expensed costs in 2009 at U.S. Transmission.
Other Income and Expenses. The $56 million increase was attributable to higher equity earnings from Field Services primarily due to increased commodity prices, substantially offset by a $135 million gain recognized in 2009 associated with partnership units previously issued by DCP Partners compared to a gain of $30 million in 2010.
Interest Expense. The $20 million increase was mainly due to a stronger Canadian dollar, mostly offset by lower average rates and balances.
Income Tax Expense from Continuing Operations. The $31 million increase was a result of higher earnings from continuing operations in 2010, partially offset by favorable tax settlements in 2010. The effective tax rate for income from continuing operations was 25% in 2010 compared to 28% in 2009. The lower effective tax rate in 2010 was primarily due to favorable tax settlements, including an administrative change by the Canadian federal government that resulted in cash tax refunds from historical tax years and a reduction to the deferred tax liability.
Income from Discontinued Operations, Net of Tax. The $1 million increase was due to an immaterial positive income tax adjustment in 2010 related to previously discontinued operations, mostly offset by payments by us in 2010 to an affiliate of DCP Midstream to reimburse them for damages resulting from an alleged breach by a third party of certain scheduled propane deliveries to us under the terms of a settlement agreement related to prior LNG operations.
Net Income—Noncontrolling Interests. The $5 million increase was driven by an increase in the noncontrolling interests ownership percentage due to the Spectra Energy Partners public sale of additional partner units in the second quarter of 2009 and higher earnings from Spectra Energy Partners mainly as a result of the dropdown of an additional 24.5% of Gulfstream in December 2010, partially offset by lower earnings from M&N LP and M&N LLC.
For a more detailed discussion of earnings drivers, see the segment discussions that follow.
2009 Compared to 2008
Operating Revenues. The $522 million, or 10%, decrease was driven mainly by:
| • | lower NGL prices and sales volumes associated with the Empress operations at Western Canada Transmission & Processing, |
| • | the effects of a weaker Canadian dollar on revenues at Western Canada Transmission & Processing and Distribution, and |
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| • | lower natural gas prices passed through to customers without a mark-up at Distribution, partially offset by |
| • | higher earnings from expansion projects placed into service late in 2008 and in 2009 at U.S. Transmission. |
Operating Expenses. The $548 million, or 15%, decrease was driven mainly by:
| • | lower prices and volumes of natural gas purchased for the Empress facility at Western Canada Transmission & Processing, |
| • | the effects of a weaker Canadian dollar at Western Canada Transmission & Processing and Distribution, |
| • | lower natural gas prices passed through to customers without a mark-up at Distribution, and |
| • | lower project development costs at U.S. Transmission. |
Gain on Sales of Other Assets and Other, net. The $31 million decrease was primarily due to a 2008 customer bankruptcy settlement at U.S. Transmission.
Operating Income. The $5 million decrease was mainly due to lower NGL margins associated with the Empress operations at Western Canada Transmission & Processing, a weaker Canadian dollar and a 2008 customer bankruptcy settlement at U.S. Transmission, mostly offset by higher earnings from expansion projects placed into service late in 2008 and in 2009, and lower project development costs at U.S. Transmission.
Other Income and Expenses. The $438 million decrease was attributable to lower equity in earnings from Field Services, primarily reflecting lower commodity prices in 2009 compared to 2008, partially offset by a gain recognized in the first quarter of 2009 associated with partnership units previously issued by DCP Partners.
Interest Expense. The $26 million decrease reflects mainly the recognition of gains from the termination of fair value hedges, the effects of a weaker Canadian dollar, and lower balances and rates on commercial paper, partially offset by higher debt balances.
Income Tax Expense from Continuing Operations. The $141 million decrease was a result of lower earnings from continuing operations in 2009. The effective tax rate for income from continuing operations was 28% compared to 29% in 2008. The lower effective tax rate for 2009 was mainly due to proportionally higher income generated from our Canadian operations, which are subject to lower tax rates compared to our U.S. operations, and favorable tax settlements in 2009.
Net Income—Noncontrolling Interests. The $10 million increase was driven by an increase in the noncontrolling interests ownership percentage due to the Spectra Energy Partners public sale of additional partner units in the second quarter of 2009 and higher earnings from Spectra Energy Partners and M&N LLC.
For a more detailed discussion of earnings drivers, see the segment discussions that follow.
Segment Results
We evaluate segment performance based on earnings before interest and taxes (EBIT) from continuing operations less noncontrolling interests related to those earnings. On a segment basis, EBIT represents earnings from continuing operations (both operating and non-operating) before interest and taxes, net of noncontrolling interests related to those earnings. Cash, cash equivalents and investments are managed centrally, so the gains and losses on foreign currency remeasurement, and interest and dividend income on those balances, are excluded from the segments’ EBIT. We consider segment EBIT to be a good indicator of each segment’s operating performance from its continuing operations, as it represents the results of our ownership interest in operations without regard to financing methods or capital structures.
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U.S. Transmission provides transportation and storage of natural gas for customers in various regions of the northeastern 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.
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 us and 50% by ConocoPhillips. Field Services gathers raw natural gas through gathering systems located in nine major natural gas producing regions: Mid-Continent, Rocky Mountain, East Texas-North Louisiana, Barnett Shale, Gulf Coast, South Texas, Central Texas, Antrim Shale and Permian Basin.
Our segment EBIT may not be comparable to similarly titled measures of other companies because other companies may not calculate EBIT in the same manner. Segment EBIT is summarized in the following table and detailed discussions follow:
EBIT by Business Segment
| 2010 | 2009 | 2008 | ||||||||||
| (in millions) | ||||||||||||
| U.S. Transmission |
$ | 948 | $ | 894 | $ | 844 | ||||||
| Distribution |
409 | 336 | 353 | |||||||||
| Western Canada Transmission & Processing |
409 | 343 | 398 | |||||||||
| Field Services |
335 | 296 | 716 | |||||||||
| Total reportable segment EBIT |
2,101 | 1,869 | 2,311 | |||||||||
| Other |
(38 | ) | (74 | ) | (78 | ) | ||||||
| Total reportable segment and other EBIT |
2,063 | 1,795 | 2,233 | |||||||||
| Interest expense |
630 | 610 | 636 | |||||||||
| Interest income and other (a) |
73 | 86 | 91 | |||||||||
| Earnings from continuing operations before income taxes |
$ | 1,506 | $ | 1,271 | $ | 1,688 | ||||||
| (a) | Includes foreign currency transaction gains and losses and the add-back of noncontrolling interests related to segment EBIT. |
Noncontrolling interests as presented in the following segment-level discussions includes only noncontrolling interests related to EBIT of non-wholly owned subsidiaries. It does not include noncontrolling interests related to interest and taxes of those operations. The amounts discussed below include intercompany transactions that are eliminated in the Consolidated Financial Statements.
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U.S. Transmission
| 2010 | 2009 | Increase (Decrease) |
2008 | Increase (Decrease) |
||||||||||||||||
| (in millions, except where noted) | ||||||||||||||||||||
| Operating revenues |
$ | 1,821 | $ | 1,690 | $ | 131 | $ | 1,600 | $ | 90 | ||||||||||
| Operating expenses |
||||||||||||||||||||
| Operating, maintenance and other |
671 | 577 | 94 | 595 | (18 | ) | ||||||||||||||
| Depreciation and amortization |
258 | 246 | 12 | 232 | 14 | |||||||||||||||
| Gains on sales of other assets and other, net |
11 | 11 | — | 42 | (31 | ) | ||||||||||||||
| Operating income |
903 | 878 | 25 | 815 | 63 | |||||||||||||||
| Other income and expenses |
126 | 91 | 35 | 86 | 5 | |||||||||||||||
| Noncontrolling interests |
81 | 75 | 6 | 57 | 18 | |||||||||||||||
| EBIT |
$ | 948 | $ | 894 | $ | 54 | $ | 844 | $ | 50 | ||||||||||
| Proportional throughput, TBtu (a) |
2,708 | 2,574 | 134 | 2,218 | 356 | |||||||||||||||
| (a) | Revenues are not significantly affected by pipeline throughput fluctuations, since revenues are primarily composed of demand charges. |
2010 Compared to 2009
Operating Revenues. The $131 million increase was driven by:
| • | an $86 million increase from expansion projects and acquisitions of Ozark Gas Gathering and Ozark Gas Transmission (collectively, Ozark) in May 2009 and Bobcat in August 2010, |
| • | a $22 million increase in processing revenues associated with pipeline operations resulting from higher prices, and |
| • | a $19 million increase in recoveries of electric power and other costs passed through to customers. |
Operating, Maintenance and Other. The $94 million increase was driven by:
| • | a $35 million increase in project development costs, mainly resulting from a 2009 reimbursement by customers and the capitalization of previously expensed costs on northeast expansions in 2009, |
| • | a $23 million increase from higher electric power and other costs passed through to customers, |
| • | a $20 million increase from acquisitions and expansion projects, and |
| • | a $16 million increase in benefits, pipeline integrity costs, software costs and other operating costs. |
Depreciation and Amortization. The $12 million increase was driven by expansion projects placed in service in 2009 and a stronger Canadian dollar at M&N LP.
Other Income and Expenses. The $35 million increase was mainly a result of an $18 million charge in 2009 due to the discontinuance of rate regulated accounting treatment by SESH, a $13 million increase in the allowance for funds used during construction-equity (AFUDC-equity) in 2010 as a result of higher capital spending, and a $10 million increase in equity earnings from expansion projects on Gulfstream and Steckman Ridge that were placed in service in 2009.
Noncontrolling Interests. The $6 million increase was driven by an increase in the noncontrolling interests ownership percentage due to the Spectra Energy Partners public sale of additional partner units in the second quarter of 2009 and higher earnings from Spectra Energy Partners mainly as a result of the dropdown of an additional 24.5% of Gulfstream in December 2010, partially offset by lower earnings from M&N LP and M&N LLC.
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EBIT. The $54 million increase was mainly due to higher earnings from expansion projects, partially offset by higher operating costs as a result of a reimbursement of project development costs by customers and the capitalization of previously expensed costs in 2009 on northeast expansions.
2009 Compared to 2008
Operating Revenues. The $90 million increase was driven mainly by:
| • | a $136 million increase from expansion projects placed into service late in 2008 and 2009, |
| • | a $43 million increase in transportation and other revenues primarily from Ozark Gas Transmission acquired in May 2009, and |
| • | a $14 million increase mainly in transportation and storage revenues from recoveries of fuel, electric power and other costs passed through to customers, partially offset by |
| • | an $88 million decrease in processing revenues associated with pipeline operations, caused by lower prices and volumes, |
| • | an $11 million decrease resulting from a weaker Canadian dollar at M&N LP, and |
| • | a $9 million decrease in interruptible transportation revenue due to weather and other market conditions. |
Operating, Maintenance and Other. The $18 million decrease was driven mainly by:
| • | an $82 million decrease in project development costs, reflecting a net benefit of $39 million in 2009 mainly due to a reimbursement of project development costs by customers and the capitalization of previously expensed costs on northeast expansions compared to expensed project development costs of $43 million in 2008, partially offset by |
| • | a $17 million increase from expansion projects placed in service late in 2008 and in 2009, |
| • | a $16 million increase from Ozark Gas Transmission, |
| • | a $15 million increase in operating costs, including pipeline integrity costs, equipment repairs and maintenance costs, and software costs, and |
| • | a $13 million increase in operating costs from higher fuel, electric power and other costs passed through to customers. |
Depreciation and Amortization. The $14 million increase was primarily driven by expansion projects placed into service late in 2008 and in 2009.
Gains on Sales of Other Assets and Other, net. The $31 million decrease was driven by a customer bankruptcy settlement in June 2008.
Other Income and Expenses. The $5 million increase was mainly a result of an impairment of the Islander East project in 2008 and earnings from expansion projects on Gulfstream and SESH placed into service in late 2008, mostly offset by lower AFUDC—equity associated with construction projects and from the discontinuance of rate regulated accounting treatment by SESH.
Noncontrolling Interests. The $18 million increase was driven by an increase in the noncontrolling interests ownership percentage resulting from the Spectra Energy Partners public sale of additional partner units in the second quarter of 2009 and higher earnings from Spectra Energy Partners and M&N LLC.
EBIT. The $50 million increase was mainly due to higher earnings from expansion projects, lower project development costs in 2009 and an impairment of the Islander East project in 2008. These increases were partially offset by lower processing revenues, increased operating costs and a customer bankruptcy settlement in 2008.
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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. “Supply push” is when producers agree to pay to transport specified volumes of natural gas in order to support the construction of new pipelines or the expansion of existing 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.
Future earnings growth will be dependent on the success of expansion plans in both the market and supply areas of the pipeline network, which includes, among other things, shale gas exploration and development areas, the ability to continue renewing service contracts and continued regulatory stability. Natural gas storage prices have recently been challenged as a result of increasing natural gas supply and narrower seasonal price spreads. NGL prices will continue to affect processing revenues that are associated with transportation services.
Distribution
| 2010 | 2009 | Increase (Decrease) |
2008 | Increase (Decrease) |
||||||||||||||||
| (in millions, except where noted) | ||||||||||||||||||||
| Operating revenues |
$ | 1,779 | $ | 1,745 | $ | 34 | $ | 1,991 | $ | (246 | ) | |||||||||
| Operating expenses |
||||||||||||||||||||
| Natural gas purchased |
770 | 878 | (108 | ) | 1,094 | (216 | ) | |||||||||||||
| Operating, maintenance and other |
406 | 358 | 48 | 372 | (14 | ) | ||||||||||||||
| Depreciation and amortization |
194 | 172 | 22 | 175 | (3 | ) | ||||||||||||||
| Operating income |
409 | 337 | 72 | 350 | (13 | ) | ||||||||||||||
| Other income and expenses |
— | (1 | ) | 1 | 3 | (4 | ) | |||||||||||||
| EBIT |
$ | 409 | $ | 336 | $ | 73 | $ | 353 | $ | (17 | ) | |||||||||
| Number of customers, thousands |
1,344 | 1,325 | 19 | 1,309 | 16 | |||||||||||||||
| Heating degree days, Fahrenheit |
6,832 | 7,435 | (603 | ) | 7,491 | (56 | ) | |||||||||||||
| Pipeline throughput, TBtu |
913 | 809 | 104 | 900 | (91 | ) | ||||||||||||||
| Canadian dollar exchange rate, average |
1.03 | 1.14 | (0.11 | ) | 1.07 | 0.07 | ||||||||||||||
2010 Compared to 2009
Operating Revenues. The $34 million increase was driven by:
| • | a $184 million increase resulting from a stronger Canadian dollar, |
| • | an $11 million increase due to a 2009 charge for a settlement on 2008 earnings to be shared with customers, |
| • | a $9 million increase in long-term storage resulting from a lower 2010 approved ratio of earnings to be shared with customers, and |
| • | a $5 million increase due to growth in the number of customers, partially offset by |
| • | a $152 million decrease from lower natural gas prices passed through to customers. Prices charged to customers are based on the 12 month New York Mercantile Exchange (NYMEX) forecast. |
| • | a $14 million decrease in customer usage of natural gas due to weather that was more than 8% warmer than in 2009. |
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Natural Gas Purchased. The $108 million decrease was driven mainly by:
| • | a $152 million decrease from lower natural gas prices passed through to customers, |
| • | a $28 million decrease in operating fuel costs, and |
| • | a $2 million decrease due to lower volumes of natural gas sold as a result of weather that was more than 8% warmer than in 2009, partially offset by |
| • | an $87 million increase resulting from a stronger Canadian dollar. |
Operating, Maintenance and Other. The $48 million increase was driven mainly by:
| • | a $38 million increase resulting from a stronger Canadian dollar, and |
| • | a $10 million increase related to higher employee benefits costs primarily associated with higher amortization of pension plan market value losses that have occurred in recent years. |
Depreciation and Amortization. The $22 million increase was driven primarily by a stronger Canadian dollar.
EBIT. The $73 million increase was mainly a result of a stronger Canadian dollar, lower operating fuel costs, a 2009 settlement on 2008 earnings sharing and higher storage and transportation revenues, partially offset by a decrease in customer usage of natural gas due to warmer weather in 2010 and higher employee benefits costs.
2009 Compared to 2008
Operating Revenues. The $246 million decrease was driven mainly by:
| • | a $160 million decrease resulting from a weaker Canadian dollar, |
| • | a $130 million decrease from lower natural gas prices passed through to customers without a mark-up, |
| • | a $69 million decrease in customer usage of natural gas due to the impacts of the economic recession, and |
| • | an $11 million decrease due to a 2009 settlement on 2008 earnings to be shared with customers, partially offset by |
| • | a $56 million increase due to growth in the number of customers, |
| • | a $40 million increase in storage and transportation revenues attributable to expansion of the storage system and an increase in short-term transportation services provided to customers, |
| • | a $15 million increase resulting from a charge in 2008 due to an unfavorable decision from the OEB related to unregulated storage revenues, and |
| • | a $9 million increase due to lower 2009 regulated earnings to be shared with customers. |
Natural Gas Purchased. The $216 million decrease was driven mainly by:
| • | a $130 million decrease from lower natural gas prices passed through to customers without a mark-up, |
| • | a $91 million decrease resulting from a weaker Canadian dollar, and |
| • | a $56 million decrease in customer usage of natural gas due to the impacts of the economic recession, partially offset by |
| • | a $48 million increase due to growth in the number of customers, and |
| • | a $6 million increase in fuel used in operations. |
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Operating, Maintenance and Other. The $14 million decrease was driven primarily by:
| • | a $24 million decrease resulting from a weaker Canadian dollar, partially offset by |
| • | a $9 million increase as a result of expansion projects. |
Depreciation and Amortization. The $3 million decrease was driven by:
| • | a $12 million decrease resulting from a weaker Canadian dollar, mostly offset by |
| • | a $9 million increase as a result of expansion projects. |
EBIT. The $17 million decrease was mainly a result of a weaker Canadian dollar, lower customer usage and higher expenses related to expansion projects. These decreases were partially offset by higher storage and transportation revenues and growth in the number of customers.
Matters Affecting Future Distribution Results
We expect that the long-term demand for natural gas in North America will continue to grow. However, potential lasting effects of the economic recession could impact retail and industrial gas usage by Union Gas distribution customers in the near term. Distribution’s earnings are affected significantly by weather during the winter heating season.
Union Gas expects to make an initial filing in 2011 to begin the OEB review process that will result in new rates for 2013 and possibly future periods. This filing will include updated revenue and cost forecasts, as well as revised assumptions about ROE and the incentive regulation framework.
Future growth prospects for Union Gas include opportunities around unregulated storage operations. Natural gas storage prices have recently been challenged as a result of increasing natural gas supply and narrower seasonal price spreads. These market factors will continue to affect Union Gas’ unregulated storage revenues.
From 2002 through 2010, the Canadian dollar has generally strengthened compared to the U.S. dollar, which favorably affected earnings during these periods, except in the fourth quarter 2008 and the first quarter 2009 when the Canadian dollar weakened significantly in a very short period of time. Changes in the exchange rate or any other factors are difficult to predict and may affect future results.
Western Canada Transmission & Processing
| 2010 | 2009 | Increase (Decrease) |
2008 | Increase (Decrease) |
||||||||||||||||
| (in millions, except where noted) | ||||||||||||||||||||
| Operating revenues |
$ | 1,345 | $ | 1,115 | $ | 230 | $ | 1,482 | $ | (367 | ) | |||||||||
| Operating expenses |
||||||||||||||||||||
| Natural gas and petroleum products purchased |
290 | 222 | 68 | 496 | (274 | ) | ||||||||||||||
| Operating, maintenance and other |
486 | 407 | 79 | 445 | (38 | ) | ||||||||||||||
| Depreciation and amortization |
169 | 144 | 25 | 147 | (3 | ) | ||||||||||||||
| Loss on sales of other assets and other, net |
(1 | ) | — | (1 | ) | — | — | |||||||||||||
| Operating income |
399 | 342 | 57 | 394 | (52 | ) | ||||||||||||||
| Other income and expenses |
10 | 1 | 9 | 5 | (4 | ) | ||||||||||||||
| Noncontrolling interests |
— | — | — | 1 | (1 | ) | ||||||||||||||
| EBIT |
$ | 409 | $ | 343 | $ | 66 | $ | 398 | $ | (55 | ) | |||||||||
| Pipeline throughput, TBtu |
627 | 604 | 23 | 615 | (11 | ) | ||||||||||||||
| Volumes processed, TBtu |
664 | 655 | 9 | 698 | (43 | ) | ||||||||||||||
| Empress inlet volumes, TBtu |
600 | 737 | (137 | ) | 820 | (83 | ) | |||||||||||||
| Canadian dollar exchange rate, average |
1.03 | 1.14 | (0.11 | ) | 1.07 | 0.07 | ||||||||||||||
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2010 Compared to 2009
Operating Revenues. The $230 million increase was driven by:
| • | a $125 million increase as a result of a stronger Canadian dollar, |
| • | a $76 million increase due to higher NGL product prices associated with the Empress operations, |
| • | a $52 million increase resulting from higher gathering and processing revenues due to contracted volumes from expansions associated with non-conventional supply discoveries in the Fort Nelson, South Peace and West Doe areas, and |
| • | a $10 million increase from recovery of carbon and other non-income tax expense from customers, partially offset by |
| • | a $40 million decrease due to lower NGL sales volumes, including lower volumes associated with an approximate 25-day scheduled plant turnaround in 2010 at the Empress operations. |
Natural Gas and Petroleum Products Purchased. The $68 million increase was driven by:
| • | a $65 million increase as a result of higher prices of natural gas purchased for the Empress facility caused primarily by higher extraction premiums, and |
| • | a $26 million increase caused by a stronger Canadian dollar, partially offset by |
| • | a $23 million decrease due primarily to lower production volumes at the Empress operations, including lower volumes associated with the scheduled plant turnaround in 2010. |
Operating, Maintenance and Other. The $79 million increase was driven by:
| • | a $44 million increase caused by a stronger Canadian dollar, |
| • | a $13 million increase relating to an increase in scheduled plant turnarounds at various locations including Empress and Grizzly Valley, |
| • | a $10 million increase in carbon and other non-income tax expense, and |
| • | a $7 million increase in maintenance costs related primarily to new facilities. |
Depreciation and Amortization. The $25 million increase was driven mainly by a stronger Canadian dollar, expansion projects placed in service and maintenance capital incurred in 2009 and 2010.
Other Income and Expenses. The $9 million increase was a result of income arising from the replacement of a natural gas purchase contract at the McMahon cogeneration facility and an increase in the equity earnings of this equity investment.
EBIT. The $66 million increase was driven mainly by a stronger Canadian dollar and higher gathering and processing earnings from expansions, partially offset by higher operating and maintenance costs.
2009 Compared to 2008
Operating Revenues. The $367 million decrease was driven mainly by:
| • | a $263 million decrease due to lower NGL product prices associated with the Empress operations, |
| • | a $101 million decrease due primarily to lower NGL sales volumes related to the Empress operations as a result of reduced natural gas production by producers caused by lower natural gas prices and high royalties, and |
| • | a $71 million decrease as a result of a weaker Canadian dollar, partially offset by |
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| • | a $53 million increase resulting primarily from higher gathering and processing revenues due to higher firm contract revenue, and |
| • | a $15 million increase in revenues to recover carbon tax expense from customers. |
Natural Gas and Petroleum Products Purchased. The $274 million decrease was driven mainly by:
| • | a $186 million decrease arising from primarily lower prices of natural gas purchased for the Empress facility, |
| • | a $75 million decrease mainly as a result of lower volumes of natural gas purchased for the Empress facility, and |
| • | a $13 million decrease caused by a weaker Canadian dollar. |
Operating, Maintenance and Other. The $38 million decrease was driven mainly by:
| • | a $32 million decrease caused by a weaker Canadian dollar, and |
| • | a $29 million decrease in plant fuel and electricity costs at the Empress facility, partially offset by |
| • | a $15 million increase in the carbon tax expense, and |
| • | an $8 million increase in maintenance and other project costs. |
Depreciation and Amortization. The $3 million decrease was driven primarily by:
| • | an $8 million decrease resulting from a weaker Canadian dollar, mostly offset by |
| • | a $5 million increase as a result of expansion projects placed into service in 2009. |
EBIT. The $55 million decrease was driven mainly by lower NGL gross margins that negatively impacted the Empress operations, as well as a weaker Canadian dollar, partially offset by higher gathering and processing revenues, and lower plant fuel and electricity costs at the Empress facility.
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 a plant is out of service and increase operating costs as a result of the turnaround maintenance work. Western Canada Transmission & Processing’s 17 processing plants are generally scheduled for turnaround work every three to four years, with the work being staggered to prevent significant outages at any given time in a single geographic area. Future earnings will also 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.
From 2002 through 2010, the Canadian dollar has generally strengthened compared to the U.S. dollar, which favorably affected earnings during these periods, except in the fourth quarter 2008 and the first quarter of 2009 when the Canadian dollar weakened significantly in a very short period of time. Changes in the exchange rate or any other factors are difficult to predict and may affect future results.
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While current drilling levels are below recent historical averages, the continued strength of land sales and other indicators of development interest specifically relating to shale gas exploration and development in the areas of British Columbia and Alberta that are in close proximity to our facilities support the increase in long- term growth rates that occurred in 2008 and were sustained in 2009 and 2010. It is possible, however, that sustained lower natural gas prices brought about by increasing gas reserves could reduce producer demand for both expansions of the British Colombia gas processing plants as well as renewals of existing gas processing contracts.
Field Services
| 2010 | 2009 | Increase (Decrease) |
2008 | Increase (Decrease) |
||||||||||||||||
| (in millions, except where noted) | ||||||||||||||||||||
| Equity in earnings of unconsolidated affiliates |
$ | 335 | $ | 296 | $ | 39 | $ | 716 | $ | (420 | ) | |||||||||
| EBIT |
$ | 335 | $ | 296 | $ | 39 | $ | 716 | $ | (420 | ) | |||||||||
| Natural gas gathered and processed/transported, TBtu/d (a,b) |
6.9 | 6.9 | — | 7.1 | (0.2 | ) | ||||||||||||||
| NGL production, MBbl/d (a,c) |
369 | 358 | 11 | 360 | (2 | ) | ||||||||||||||
| Average natural gas price per MMBtu (d) |
$ | 4.39 | $ | 3.99 | $ | 0.40 | $ | 9.03 | $ | (5.04 | ) | |||||||||
| Average NGL price per gallon (e) |
$ | 0.98 | $ | 0.71 | $ | 0.27 | $ | 1.23 | $ | (0.52 | ) | |||||||||
| Average crude oil price per barrel (f) |
$ | 79.53 | $ | 61.81 | $ | 17.72 | $ | 99.67 | $ | (37.86 | ) | |||||||||
| (a) | Reflects 100% of volumes. |
| (b) | Trillion British thermal units per day. |
| (c) | Thousand barrels per day. |
| (d) | Average price based on NYMEX Henry Hub. |
| (e) | Does not reflect results of commodity hedges. |
| (f) | Average price based on NYMEX calendar month. |
2010 Compared to 2009
EBIT. Higher equity earnings of $39 million were mainly the result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:
| • | a $186 million increase from commodity-sensitive processing arrangements due to increased commodity prices, and |
| • | a $15 million increase in earnings from DCP Partners primarily as a result of lower mark-to-market losses on derivative instruments used to protect distributable cash flows, partially offset by |
| • | a $105 million decrease as a result of a gain of $135 million in 2009 associated with the issuance of partnership units by DCP Partners compared to a gain of $30 million in 2010, |
| • | a $26 million decrease in gathering and processing margins due to lower volumes and efficiencies, largely attributable to the impact of severe weather, curtailments and third party outages in 2010 that affected operations, partially offset by growth, |
| • | a $14 million decrease due to higher income tax expense primarily reflecting the de-recognition of certain deferred tax assets, |
| • | a $12 million decrease due to lower results from NGL trading and gas marketing, and |
| • | a $7 million decrease due to higher operating expenses largely resulting from DCP Partners’ acquisitions growth, increased repairs and maintenance costs, the impact of hurricane insurance recoveries in 2009 and increased benefits costs. |
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2009 Compared to 2008
EBIT. Lower equity in earnings of $420 million were mainly the result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:
| • | a $492 million decrease from commodity-sensitive processing arrangements, due to decreased commodity prices, |
| • | a $48 million decrease in gathering and processing margins largely attributable to lower volumes resulting primarily from reduced drilling and lower recoveries and efficiencies, partially offset by the impact of hurricanes in 2008, |
| • | a $28 million decrease due to higher net interest expense resulting from increased debt associated with growth, acquisitions and a special distribution paid in 2008, and higher borrowing costs during 2009, |
| • | a $23 million decrease in earnings from DCP Partners primarily as a result of mark-to-market losses on derivative instruments used to protect distributable cash flows, compared to gains in 2008, and |
| • | a $9 million decrease primarily attributable to gains on sales of assets in 2008, partially offset by |
| • | a $135 million gain associated with partnership units previously issued by DCP Partners, |
| • | a $29 million increase in NGL trading and gas marketing, and |
| • | a $17 million increase mainly as a result of lower operating and maintenance expenses due to a cost reduction initiative and the impact of decreased commodity prices in 2009, partially offset by higher depreciation expense as a result of capital spending and acquisitions in 2008 and 2009. |
Supplemental Data
Below is supplemental information for DCP Midstream’s operating results (presented at 100%):
| 2010 | 2009 | 2008 | ||||||||||
| (in millions) | ||||||||||||
| Operating revenues |
$ | 10,981 | $ | 8,560 | $ | 16,398 | ||||||
| Operating expenses |
10,138 | 8,026 | 14,704 | |||||||||
| Operating income |
843 | 534 | 1,694 | |||||||||
| Other income and expenses |
34 | 24 | 20 | |||||||||
| Interest expense, net |
253 | 254 | 198 | |||||||||
| Income tax expense (benefit) |
5 | (2 | ) | (3 | ) | |||||||
| Net income |
619 | 306 | 1,519 | |||||||||
| Net income (loss)—noncontrolling interests |
27 | (16 | ) | 88 | ||||||||
| Net income attributable to members’ interests |
$ | 592 | $ | 322 | $ | 1,431 | ||||||
As a result of the adoption of a new accounting standard in 2009, DCP Midstream reclassified to equity certain deferred gains on sales of common units in DCP Partners. Our proportionate 50% share, totaling $135 million in 2009 and $30 million in 2010, were recorded in Equity in Earnings of Unconsolidated Affiliates in the Consolidated Statement of Operations.
Matters Affecting Future Field Services Results
Overall drilling and rig counts continue to improve from the drilling levels experienced in 2009, but still remain below peak levels seen in 2008. The drilling levels vary by geographic area, but in general, drilling remains robust in areas with a high content of liquids in the gas stream. In other areas, drilling continues to remain relatively modest. In addition, advances in technology, such as horizontal drilling and fractionation in shale plays, have led to certain geographic areas becoming increasingly accessible. NGL production increased
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during 2010 as compared to 2009 due to drilling occurring in liquids rich areas. Gas prices currently remain modest due to the increased supply, high inventory and reduced demand. Under DCP Midstream’s contract structures, which are predominantly percent-of-proceeds contracts, DCP Midstream receives payments in-kind in the form of commodities and, as a result, typically has a “long” natural gas position. As such, a decrease in natural gas prices can negatively impact DCP Midstream’s margin. However, any decline would be partially offset by its keep-whole contracts where gross margin is directly related to the price of NGLs and inversely related to the price of natural gas. DCP Midstream’s long-term view is that as economic conditions improve, natural gas prices will return to levels that will support sustainable levels of natural gas-related drilling.
Other
| 2010 | 2009 | Increase (Decrease) |
2008 | Increase (Decrease) |
||||||||||||||||
| (in millions) | ||||||||||||||||||||
| Operating revenues |
$ | 58 | $ | 47 | $ | 11 | $ | 45 | $ | 2 | ||||||||||
| Operating expenses |
95 | 130 | (35 | ) | 125 | 5 | ||||||||||||||
| Operating loss |
(37 | ) | (83 | ) | 46 | (80 | ) | (3 | ) | |||||||||||
| Other income and expenses |
(1 | ) | 9 | (10 | ) | 2 | 7 | |||||||||||||
| EBIT |
$ | (38 | ) | $ | (74 | ) | $ | 36 | $ | (78 | ) | $ | 4 | |||||||
2010 Compared to 2009
EBIT. The $36 million increase in EBIT reflects a benefit of $31 million related to an early termination notice made by Westcoast for capacity contracts held on the Alliance pipeline and favorable captive insurance results in 2010, partially offset by a $7 million charge in 2010 for resolution of a corporate legal matter.
2009 Compared to 2008
EBIT. The $4 million increase in EBIT reflects slightly lower corporate costs in 2009.
Matters Affecting Future Other Results
Future Other results will continue to include corporate and business services we provide for our operations, and will also include operating costs and self-insured losses associated with our captive insurance entities. The results for Other could be impacted by the number and severity of insured property losses, particularly during hurricane season.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The application of accounting policies and estimates is an important process that continues to evolve as our operations change and accounting guidance is issued. We have identified a number of critical accounting policies and estimates that require the use of significant estimates and judgments.
We base our estimates and judgments on historical experience and on other assumptions that we believe are reasonable at the time of application. These estimates and judgments may change as time passes and more information becomes available. If estimates are different than the actual amounts recorded, adjustments are made in subsequent periods to take into consideration the new information. We discuss our critical accounting policies and estimates and other significant accounting policies with our Audit Committee.
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Regulatory Accounting
We account for certain of our operations under accounting for regulated entities. As a result, we record assets and liabilities that result from the regulated ratemaking process that would not be recorded under generally accepted accounting principles 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. We continually assess 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 assessment, we believe our 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. Additionally, 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 $1,061 million as of December 31, 2010 and $976 million as of December 31, 2009. Total regulatory liabilities were $559 million as of December 31, 2010 and $678 million as of December 31, 2009.
In 2009, we recorded $18 million of charges due to the discontinuance of rate regulated accounting treatment by SESH as a result of significant increases in construction costs of the SESH pipeline beyond the original estimates. These costs were not accompanied by equivalent increases in negotiated rates charged by SESH to its customers.
In 2008, we recorded a $44 million charge representing our share of impaired assets associated with the Islander East pipeline project. Triggered by certain 2008 legal and economic events, costs associated with this project were evaluated as to probability of recovery under FERC-approved tariff rates associated with any future alternative project plan. See Note 11 of Notes to Consolidated Financial Statements for further discussion.
Impairment of Goodwill
We perform an annual goodwill impairment test and update 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. No impairments of goodwill were recorded in 2010, 2009 or 2008. Effective with our 2009 annual impairment test, we changed our test date from August 31 to April 1 in order to alleviate the information and resource constraints that historically existed during the third quarter and to better coincide with the completion of our long-term financial projections.
We had goodwill balances of $4,305 million at December 31, 2010 and $3,948 million at December 31, 2009. The increase in goodwill in 2010 was the result of foreign currency translation and $188 million of goodwill at U.S. Transmission associated with the acquisition of Bobcat in August 2010. The majority of our goodwill relates to the acquisition of Westcoast in 2002, which owns significantly all of our Canadian operations. As of the acquisition date or upon a change in reporting units, we allocate goodwill to a reporting unit, which we define as an operating segment or one level below an operating segment.
We primarily use a discounted cash flow analysis to determine fair value for each reporting unit. Key assumptions used in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in key markets served by our operations, regulatory stability, the ability to renew contracts, commodity prices (where appropriate) and foreign currency exchange rates, as well as other factors that affect our revenue, expense and capital expenditure projections.
The long-term growth rates used for our reporting units reflect continued expansion of our assets, driven by new natural gas supplies such as shale gas in North America and increasing demand for natural gas transportation
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capacity on our pipeline systems. We assumed a weighted average long-term growth rate of 3.7% for our 2010 goodwill impairment analysis. Had we assumed a 100 basis point lower growth rate for each of our reporting units, except for the Distribution reporting unit, there would have been no impairment of goodwill. The Distribution reporting unit used a long-term growth rate assumption at the lower end of our growth rate range and therefore has a lower sensitivity to growth rate declines.
We continue to monitor the effects of the economic downturn that global economies are currently facing on the long-term cost of capital utilized to calculate our reporting unit fair values. In evaluating our reporting units for our 2010 goodwill impairment analysis, we assumed weighted-average costs of capital ranging from 7.1% to 9.4% that market participants would use. Had we assumed a 100 basis point increase in the weighted- average cost of capital for each of our reporting units, there would have been no impairment of goodwill. For our regulated businesses in Canada, if an increase in the cost of capital occurred, we assume that the effect on the corresponding reporting unit’s fair value would be ultimately offset by a similar increase in the reporting unit’s regulated revenues since those rates include a component that is based on the reporting unit’s cost of capital.
Based on the results of our annual impairment testing, the fair values of our reporting units at April 1, 2010 significantly exceeded their carrying values. No triggering events or changes in circumstances occurred during the period April 1, 2010 (our testing date) through December 31, 2010 that would warrant re-testing for goodwill impairment.
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. We believe 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. Medical and prescription drug cost trend rate assumptions are also critical assumptions for other post-retirement benefits.
Capital market declines and volatility experienced during 2008 and 2009 adversely impacted the market value of investment assets used to fund Spectra Energy’s defined benefit employee retirement plans. Future changes in plan asset returns, assumed discount rates and various other factors related to the participants in our pension and post-retirement plans will impact future pension expense and funding.
The expected return on plan assets is important, since certain of our pension and other post-retirement benefit plans are funded. Expected long-term rates of return on plan assets are developed by using a weighted average of expected returns for each asset class to which the plan assets are allocated. For 2010, the assumed average return ranged from 7.00% to 7.25% for the U.S. and Canadian pension plan assets and 6.51% for the U.S. other post-retirement benefit assets. A change in the rate of return of 25 basis points for these assets would impact annual benefit expense by approximately $3 million before tax. The Canadian other post-retirement benefit plans are not funded.
Since pension and other post-retirement benefit liabilities are measured on a discounted basis, the discount rate is also a significant assumption. Discount rates used for our defined benefit and other post-retirement benefit plans are based on the yields constructed from a portfolio of high-quality bonds for which the timing and amount
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of cash outflows approximate the estimated payouts of the plans. The average discount rates of 5.31% for the U.S. plans and 5.88% for the Canadian plans used to calculate 2010 plan expenses represent a weighted average of the applicable rates. A 25 basis-point change in the discount rates would impact annual benefit expense by approximately $3 million before tax.
See Note 24 of Notes to Consolidated Financial Statements for more information on pension and other post-retirement benefits.
LIQUIDITY AND CAPITAL RESOURCES
Known Trends and Uncertainties
We will rely upon cash flows from operations and various financing transactions, which may include issuances of short-term and long-term debt, to fund our liquidity and capital requirements for 2011. As of December 31, 2010, we had negative working capital of approximately $885 million. This balance includes short-term borrowings and commercial paper totaling $836 million and current maturities of long-term debt of $315 million. We also have access to four revolving credit facilities, with available combined capacities of approximately $1.6 billion at December 31, 2010. With the exception of the Spectra Energy Partners facility which is used for bank borrowings, these facilities will be used principally as back-stops for commercial paper programs or for the issuance of letters of credit. At Union Gas, we primarily use commercial paper to support our short-term working capital fluctuations. At Spectra Capital and Westcoast, we primarily use commercial paper for temporary funding of our capital expenditures. We also utilize commercial paper, other variable-rate debt and interest rate swaps to achieve our desired mix of fixed and variable-rate debt. See Credit Ratings Summary—Other Financing Matters for discussions of effective shelf registrations and available credit facilities.
Our consolidated capital structure includes long-term debt, short-term borrowings, commercial paper and preferred stock of subsidiaries. As of December 31, 2010, our capital structure was 56% debt, 39% common equity of controlling interests and 5% noncontrolling interests and preferred stock of subsidiaries.
Cash flows from operations for our businesses are fairly stable given that approximately 90% of revenues are derived from fee-based services, of which most are regulated. However, total operating cash flows are subject to a number of factors, including, but not limited to, earnings sensitivities to weather, commodity prices, distributions from our equity affiliates and the timing of cost recoveries pursuant to regulatory approvals. See Part I. Item 1A. Risk Factors for further discussion.
In particular, cash distributions from our equity affiliate DCP Midstream can fluctuate, primarily as a result of earnings sensitivities to commodity prices, as well as their levels of capital expenditures and other investing activities. DCP Midstream funds its operations and investing activities primarily from its operating cash flows, third-party debt and equity transactions associated with DCP Partners. DCP Midstream is required to make quarterly tax distributions to us based on allocated taxable income. In addition to tax distributions, periodic distributions are determined by DCP Midstream’s board of directors based on net income, operating cash flows and other factors, including capital expenditures and other investing activities, commodity prices outlook and the credit environment. We received total tax and periodic distributions from DCP Midstream of $288 million in 2010, $101 million in 2009 and $930 million in 2008. As discussed in Note 1 of the Notes to Consolidated Financial Statements, a portion of these distributions are classified within Operating Cash Flows and the remainder is classified as Investing Cash Flows. We continually assess the effect of commodity prices and other activities at DCP Midstream on cash expected to be received from DCP Midstream, and adjust our expansion or other activities as necessary.
Capital market declines and volatility experienced during 2008 and 2009 adversely impacted the market value of investment assets used to fund Spectra Energy’s defined benefit employee retirement plans. See further discussion of the expected impact of these changes under Quantitative and Qualitative Disclosures About Market
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Risk—Equity Price Risk. Future changes in plan asset returns, assumed discount rates and various other factors related to the participants in our pension and post-retirement plans will impact future pension expense and funding.
As we execute on our strategic objectives around organic growth and expansion projects, expansion expenditures are expected to approximate $1.4 billion in 2011 and an aggregate total of $5.0 billion through 2015. The timing and extent of these expenditures are likely to vary significantly from year to year, depending mostly on general economic conditions and market requirements. Given that we expect to continue to pursue expansion opportunities over the next several years and also given the normal scheduled maturities of our existing debt instruments, capital resources will continue to include long-term borrowings. We remain committed to maintaining a capital structure and liquidity profile that continues to support an investment-grade credit rating.
Operating Cash Flows
Net cash provided by operating activities decreased $352 million to $1,408 million in 2010 compared to 2009. This change was driven mostly by:
| • | a $212 million increase in tax payments in 2010, and |
| • | a $429 million net working capital decrease at Union Gas largely resulting from the timing of gas cost expenditures and recoveries from customers pursuant to regulatory cost recovery mechanisms. Refunds were made in 2010 for gas cost collections from customers in 2009 that exceeded the actual cost of gas during that period. These decreases were partially offset by |
| • | higher earnings in 2010, and |
| • | an increase of $196 million in distributions received from unconsolidated affiliates in 2010 reflecting the effects of higher commodity prices on earnings and cash flows of DCP midstream. |
Net cash provided by operating activities decreased $45 million to $1,760 million in 2009 compared to 2008. This change was driven mostly by:
| • | a decrease of $582 million in distributions received from unconsolidated affiliates in 2009, driven by lower commodity prices at DCP Midstream, partially offset by |
| • | a $402 million net working capital increase at Union Gas primarily resulting from higher amounts of approved gas cost collections from customers that exceeded the actual cost of gas in 2009 compared to such amounts collected in 2008, and |
| • | a $222 million decrease in tax payments in 2009, primarily the result of the U.S. Economic Stimulus Plan, which deferred significant amounts of tax payments to future periods. |
Investing Cash Flows
Net cash flows used in investing activities increased $1,080 million to $2,101 million in 2010 compared to 2009. This change was driven mostly by:
| • | a $366 million increase in capital and investment expenditures in 2010, |
| • | a $492 million cash outlay in 2010 for the acquisition of Bobcat, |
| • | a $186 million receipt from SESH in 2009 to repay our loan to them, and |
| • | a $148 million distribution from Gulfstream in 2009 from the proceeds of a Gulfstream debt issuance, partially offset by |
| • | the $295 million acquisition of Ozark in 2009. |
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Net cash flows used in investing activities decreased $842 million to $1,021 million in 2009 compared to 2008. This change was driven mostly by:
| • | a $989 million decrease in capital and investment expenditures in 2009 as a result of the planned reduction in capital expansion levels for 2009, |
| • | a $186 million receipt from SESH in 2009 to repay our loan to them, and |
| • | a $274 million acquisition of units of the Income Fund in 2008 that were held by non-affiliated holders, partially offset by |
| • | the $295 million acquisition of Ozark in 2009. |
The $186 million receipt from SESH, recorded as Receipt From Affiliate—Repayment of Loan on the Consolidated Statement of Cash Flows, represents repayment of the remaining balance of an outstanding loan receivable from SESH. A portion of these funds were from the proceeds of a debt issuance by SESH.
In 2009, we also received a $148 million special distribution from Gulfstream from the proceeds of a debt issuance by Gulfstream, of which $144 million was classified as Cash Flows from Investing Activities—Distributions Received From Unconsolidated Affiliates on the Consolidated Statement of Cash Flows.
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.
| 2010 | 2009 | 2008 | ||||||||||
| (in millions) | ||||||||||||
| Capital and Investment Expenditures(a) |
||||||||||||
| U.S. Transmission |
$ | 641 | $ | 432 | $ | 1,400 | ||||||
| Distribution |
227 | 224 | 373 | |||||||||
| Western Canada Transmission & Processing |
449 | 353 | 222 | |||||||||
| Other |
39 | 32 | 35 | |||||||||
| Total consolidated |
$ | 1,356 | $ | 1,041 | $ | 2,030 | ||||||
| (a) | Excludes the acquisitions of Bobcat in 2010, Ozark in 2009 and units of the Income Fund in 2008. See Note 4 of Notes to Consolidated Financial Statements for further discussion. |
On August 30, 2010, we acquired the Bobcat assets and development project for $540 million, of which approximately $37 million has been withheld pending certain outcomes. We expect to invest an additional $400 million to $450 million to fully develop the Bobcat facility by the end of 2016. The acquisition, initially funded through the issuance of commercial paper, supports our stated plan of at least $1 billion per year in expansion capital investing through at least 2015. See Note 4 of Notes to Consolidated Financial Statements for further discussion of the acquisition of Bobcat.
| Bobcat Acquisition |
||||
| (in millions) | ||||
| Cash purchase price |
$ | 540 | ||
| Working capital and other purchase adjustments |
6 | |||
| Total |
546 | |||
| Withheld |
(37 | ) | ||
| Cash acquired |
(17 | ) | ||
| Net cash outlay for acquisition |
$ | 492 | ||
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Capital and investment expenditures for 2010 totaled $1,356 million and included $719 million for expansion projects and $637 million for maintenance and other projects. We project 2011 capital and investment expenditures of approximately $2.1 billion, consisting of approximately $1.0 billion for U.S. Transmission, $0.3 billion for Distribution and $0.8 billion for Western Canada Transmission & Processing. Total projected 2011 capital and investment expenditures include approximately $1.4 billion of expansion capital expenditures and $0.7 billion for maintenance and upgrades of existing plants, pipelines and infrastructure to serve growth. Projected capital expenditures in 2011 represents an almost 50% increase over 2010, primarily related to expansion projects.
Capital expansion projects are developed and executed using results-proven project management processes. We evaluate the strategic fit and commercial and execution risks, and continuously measure performance compared to plan. Ongoing communications between project teams and senior leadership ensure we maintain the right focus and deliver the expected results.
Expansion capital expenditures included several key projects placed into service in 2010, including:
| • | East to West—A 281 MMcf/d expansion of the Algonquin system to facilitate west-bound transportation of gas delivered into the eastern end of the system. |
| • | BC Transmission North—An expansion of existing western Canada transmission capacity to increase downstream capacity from the McMahon natural gas processing plant in northern Alberta. |
In addition, there were multi-year expansion programs, further described below, large portions of which were placed into service in 2010, including:
| • | Fort Nelson Expansion, an 830 MMcf/d expansion of the Fort Nelson system in western Canada, where significant sections of both pipeline looping and reactivation were placed into service and compression expansion at the existing Fort Nelson Plant was completed. |
| • | TEMAX / Time III, where compressor and pipeline facilities representing approximately one-half of the total Texas Eastern project were placed into service. |
| • | Egan Storage, where storage capacity was increased as part of the multi-year Market Hub Storage expansion project. |
Significant 2011 expansion projects expenditures are expected to include:
| • | TEMAX / Time III—An expansion of the Texas Eastern pipeline system from both Oakford, Pennsylvania and Clarington, Ohio to an eastern Pennsylvania interconnection with a major interstate pipeline to transport an additional 455 MMcf/d of natural gas. In-service phased in between 2010 and 2011. |
| • | TEAM 2012—A 190 MMcf/d expansion of the Texas Eastern pipeline system consisting of new pipeline and compression construction. The project is designed to transport gas produced in the Marcellus Shale production regions to markets in the U.S. Northeast. In-service is anticipated in late 2012. |
| • | New Jersey-New York Expansion—An 800 MMcf/d expansion of the Texas Eastern pipeline system consisting of a new 16 mile pipeline extension into lower Manhattan and other related facilities. The project is designed to transport gas produced in the Marcellus Shale regions into New York. In-service is anticipated in late 2013. |
| • | Bobcat Storage—The development of an additional 9.9 Bcf working gas storage cavern along with above-ground facilities. In-service scheduled for late 2012. |
| • | Fort Nelson Expansion—The new 250 Mmcf/d Fort Nelson North processing facility, which is the final phase and most significant capital outlay of the program, is under construction and is expected to be brought in-service in 2012. Upon completion, we will operate over 1.2 Bcf/d of raw gas processing capacity and associated gathering pipelines in the Fort Nelson area. |
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| • | Dawson Expansion—The development of a sour gas processing plant and an additional pipeline in western Canada. Phase 1 of 100 MMcf/d will be in-service in 2011 and phase 2 for an additional 100 MMcf/d is expected to be in service by 2013. |
| • | T-North 2011—Additional facilities required to increase downstream take-away capacity by 170 MMcf/d from the Fort Nelson area in western Canada. The project consists of compression, pipeline looping and the construction of a new sales gas line to interconnect with a major pipeline system. In-service scheduled for 2012. |
| • | Northeast Tennessee Project—An expansion of the East Tennessee system to transport 150 MMcf/d to a new gas-fired power plant in northeast Tennessee. The project consists of installation of pipeline, main line looping and regulation. In-service scheduled in 2011. |
Financing Cash Flows and Liquidity
Net cash provided by financing activities totaled $656 million in 2010 compared to $803 million used in financing in 2009. This $1,459 million change was driven mostly by:
| • | $669 million of short-term borrowings in 2010, which included funds used for the acquisition of Bobcat and increased capital expenditures, compared to a $774 million decrease in 2009 as a result of the planned reduction in commercial paper outstanding during 2009 to preserve liquidity during that period of economic downturn and instability, and |
| • | $483 million of net long-term debt issuances in 2010, which included the collateralized term loan at Spectra Energy Partners, compared to $104 million of net issuances in 2009, partially offset by |
| • | $101 million of lower distributions to noncontrolling interests in 2010, and |
| • | proceeds of $448 million in 2009 from the issuance of Spectra Energy common stock. |
Net cash used in financing activities totaled $803 million in 2009 compared to $214 million provided by financing in 2008. This $1,017 million change was driven mostly by:
| • | a $774 million decrease in short-term borrowings in 2009 compared to a $249 million increase in the 2008 period, |
| • | a $113 million decrease in contributions from noncontrolling interests in 2009, |
| • | a $104 million increase in distributions to noncontrolling interests in 2009, primarily from proceeds of the debt issuance at M&N LLC, and |
| • | $104 million of net proceeds from the issuance of long-term debt in 2009 compared to $1,157 million in 2008, partially offset by |
| • | proceeds of $448 million in 2009 from the issuance of Spectra Energy common stock, |
| • | proceeds of $208 million in 2009 from the issuance of Spectra Energy Partners’ common units, and |
| • | repurchases of Spectra Energy common stock in 2008 of $600 million. |
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Significant Financing Activities—2010
Debt Issuances. The following debt issuances were completed during 2010 as part of our overall financing plan to fund capital expenditures, to refinance maturing debt obligations and for other corporate purposes:
| Amount | Interest Rate | Due Date | ||||||||||
| (in millions) | ||||||||||||
| Texas Eastern |
$ | 300 | 4.125 | % | 2020 | |||||||
| Westcoast |
249 | (a) | 3.28 | % | 2016 | |||||||
| Westcoast |
235 | (a) | 4.57 | % | 2020 | |||||||
| Union Gas |
241 | (a) | 5.20 | % | 2040 | |||||||
| (a) | U.S. dollar equivalent at time of issuance. |
In December 2010, Spectra Energy Partners issued 6.9 million common units to the public, representing limited partner interests, and 0.1 million general partner units to Spectra Energy. Total net proceeds to Spectra Energy Partners from the issuances was $221 million (the net proceeds to Spectra Energy was $216 million), with $209 million used to purchase qualifying investment-grade securities, $7 million used to pay the debt owed to a subsidiary of Spectra Energy and $5 million used for Spectra Energy Partners’ general partnership purposes. Spectra Energy Partners also borrowed $207 million of term debt using the investment-grade securities as collateral and paid off an equal amount of its outstanding revolving credit facility loan.
Significant Financing Activities—2009
Debt Issuances. The following debt issuances were completed during 2009:
| Amount | Interest Rate | Due Date | ||||||||||
| (in millions) | ||||||||||||
| Spectra Capital |
$ | 300 | 5.65 | % | 2020 | |||||||
| M&N LP |
167 | (a) | 4.34 | % | 2019 | |||||||
| M&N LLC |
500 | 7.50 | % | 2014 | ||||||||
| (a) | U.S. dollar equivalent at time of issuance. |
Ozark Acquisition. In 2009, Spectra Energy Partners acquired all of the ownership interests of Ozark from Atlas for approximately $295 million. The transaction was initially funded by Spectra Energy Partners with $218 million drawn on its bank credit facility, $70 million borrowed under a credit facility with Spectra Energy that was created for the sole purpose of funding a portion of the acquisition, and $7 million of cash on hand. This transaction was partially refinanced by Spectra Energy Partners in 2009 through the issuance of 9.8 million common units to the public, representing limited partner interests, and 0.2 million general partner units to Spectra Energy, resulting in net proceeds of $212 million. Funds from the sale of the partner units were used by Spectra Energy Partners to repay the $70 million owed to Spectra Energy and $142 million of the amount initially drawn on the Spectra Energy Partners bank credit facility. Effective with the repayment to Spectra Energy, the credit facility with Spectra Energy was terminated.
Common Stock Issuance. In 2009, in order to further protect our capitalization structure against a potential extreme decline in the Canadian dollar, we issued 32.2 million shares of our common stock and received net proceeds of $448 million. We used the net proceeds to repay commercial paper as it matured. Borrowings from the commercial paper were used for capital expenditures and for other general corporate purposes.
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Significant Financing Activities—2008
Debt Issuances. The following debt issuances were completed during 2008:
| Amount | Interest Rate | Due Date | ||||||||||
| (in millions) | ||||||||||||
| Spectra Capital |
$ | 500 | 6.20 | % | 2018 | |||||||
| Spectra Capital |
250 | 5.90 | % | 2013 | ||||||||
| Spectra Capital |
250 | 7.50 | % | 2038 | ||||||||
| Union Gas |
198 | (a) | 5.35 | % | 2018 | |||||||
| Union Gas |
281 | (a) | 6.05 | % | 2038 | |||||||
| Westcoast |
48 | (a) | 5.60 | % | 2019 | |||||||
| Westcoast |
250 | (a) | 5.60 | % | 2019 | |||||||
| (a) | U.S. dollar equivalent at time of issuance |
In 2008, M&N LLC paid $288 million to retire its outstanding bonds and bank debt and an additional $54 million early-extinguishment premium for the bonds. The payment of the premium, a regulatory asset, is presented within Cash Flows from Financing Activities—Other on the Consolidated Statements of Cash Flows.
Common Stock Repurchases. We repurchased a cumulative total of $600 million of our outstanding common stock in 2008.
Available Credit Facilities and Restrictive Debt Covenants
| Expiration Date |
Credit Facilities Capacity |
Outstanding at December 31, 2010 | Available Credit Facilities Capacity |
|||||||||||||||||||||||||
| Commercial Paper |
Revolving Credit |
Letters of Credit |
Total | |||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||||
| Spectra Capital (a) |
||||||||||||||||||||||||||||
| Multi-year syndicated |
2012 | $ | 1,500 | $ | 679 | $ | — | $ | 13 | $ | 692 | $ | 808 | |||||||||||||||
| Westcoast (b) |
||||||||||||||||||||||||||||
| Multi-year syndicated |
2011 | 200 | — | — | — | — | 200 | |||||||||||||||||||||
| Union Gas (c) |
||||||||||||||||||||||||||||
| Multi-year syndicated |
2012 | 501 | 157 | — | — | 157 | 344 | |||||||||||||||||||||
| Spectra Energy Partners |
||||||||||||||||||||||||||||
| Multi-year syndicated |
2012 | 500 | — | 299 | — | 299 | 201 | |||||||||||||||||||||
| Total |
$ | 2,701 | $ | 836 | $ | 299 | $ | 13 | $ | 1,148 | $ | 1,553 | ||||||||||||||||
| (a) | Credit facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 65%. |
| (b) | U.S. dollar equivalent at December 31, 2010. The credit facilities totals 200 million Canadian dollars and contains a covenant that requires the Westcoast non-consolidated debt-to-total capitalization ratio to not exceed 75%. The ratio was 44% at December 31, 2010. |
| (c) | U.S. dollar equivalent at December 31, 2010. The credit facilities totals 500 million Canadian dollars and contains a covenant that requires the Union Gas debt-to-total capitalization ratio to not exceed 75% and 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. The ratio was 64% at December 31, 2010. |
The issuance of commercial paper, letters of credit and other borrowings reduces the amount available under the credit facilities.
Our credit agreements contain various financial and other covenants, including the maintenance of certain financial ratios. 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, 2010, we were in compliance with those
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covenants. In addition, our credit agreements allow for the acceleration of payments or termination of the agreements due to nonpayment, or in some cases, due to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. Our debt and credit agreements do not contain provisions that trigger an acceleration of indebtedness based solely on the occurrence of a material adverse change in our financial condition or results of operations.
As noted above, the terms of our Spectra Capital credit agreement require our consolidated debt-to-total-capitalization ratio to be 65% or lower. This ratio was 56% at December 31, 2010 and December 31, 2009. Our equity, and as a result, this ratio, is sensitive to significant movements of the Canadian dollar relative to the U.S. dollar due to the significance of our Canadian operations as discussed in “Quantitative and Qualitative Disclosures About Market Risk—Foreign Currency Risk.” Based on the strength of our total capitalization as of December 31, 2010, however, it is not likely that a material adverse effect would occur as a result of a weakened Canadian dollar.
Credit Ratings
| Standard and Poor’s |
Moody’s Investor Service |
Fitch Ratings |
DBRS | |||||||||||||
| As of January 31, 2011 |
||||||||||||||||
| Spectra Capital (a) |
BBB | Baa2 | BBB | n/a | ||||||||||||
| Texas Eastern (a) |
BBB+ | Baa1 | BBB+ | n/a | ||||||||||||
| Westcoast (a) |
BBB+ | n/a | n/a | A (low) | ||||||||||||
| Union Gas (a) |
BBB+ | n/a | n/a | A | ||||||||||||
| M&N LLC (a) |
BBB | Baa3 | n/a | n/a | ||||||||||||
| M&N LP (b) |
A | A2/A3 | n/a | A | ||||||||||||
| (a) | Represents senior unsecured credit rating. |
| (b) | Represents senior secured credit rating. The A2 rating applies to M&N LP’s 6.9% notes due 2019 and the A3 rating applies to its 4.34% notes due 2019. |
| n/a | Indicates not applicable. |
The above credit ratings are dependent upon, among other factors, the ability to generate sufficient cash to fund capital and investment expenditures, our results of operations, market conditions and other factors. Our credit ratings could impact our ability to raise capital in the future, impact the cost of our capital and, as a result, have an impact on our liquidity.
Dividends. We currently anticipate an average dividend payout ratio over time of approximately 65% of estimated annual net income from controlling interests per share of common stock. The actual payout ratio, however, may vary from year to year depending on earnings levels. We expect to continue our policy of paying regular cash dividends. The declaration and payment of dividends are subject to the sole discretion of our Board of Directors and will depend upon many factors, including the financial condition, earnings and capital requirements of our operating subsidiaries, covenants associated with certain debt obligations, legal requirements, regulatory constraints and other factors deemed relevant by our Board of Directors. A dividend of $0.26 per common share, representing a 4% increase from the previous dividend level, was declared on January 3, 2011 and will be paid on March 14, 2011.
Other Financing Matters. Spectra Energy Corp and Spectra Capital have an effective shelf registration statement on file with the SEC to register the issuance of unspecified amounts of various equity and debt securities, respectively. Spectra Energy Partners has an effective shelf registration statement on file with the SEC to register the issuance of limited partner common units and various debt securities up to $1.1 billion in aggregate. In addition, as of December 31, 2010, certain of our subsidiaries in Canada have 1.75 billion Canadian dollars (approximately $1.75 billion) available for issuance in the Canadian market under debt shelf prospectuses that expire in October 2012.
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Off-Balance Sheet Arrangements
We 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 Note 20 of Notes to Consolidated Financial Statements for further discussion of guarantee arrangements.
Most of the guarantee arrangements that we enter into enhance the credit standings 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 us having to honor our contingencies is largely dependent upon the future operations of our 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 our operations. As such, if we discontinued issuing these guarantee arrangements, there would not be a material impact to our consolidated results of operations, financial position or cash flows.
In connection with our spin-off from Duke Energy, certain guarantees that were previously issued by us were assigned to, or replaced by, Duke Energy as guarantor. For any remaining guarantees of other Duke Energy obligations, Duke Energy has indemnified us against any losses incurred under these guarantee arrangements.
We do 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 Notes 19 and 20 of Notes to Consolidated Financial Statements.
Contractual Obligations
We enter into contracts that require payment of cash at certain periods based on certain specified minimum quantities and prices. The following table summarizes our contractual cash obligations for each of the periods presented. The table below excludes all amounts classified as Total Current Liabilities on the December 31, 2010 Consolidated Balance Sheet other than Current Maturities of Long-Term Debt. It is expected that the majority of Total Current Liabilities will be paid in cash in 2011.
Contractual Obligations as of December 31, 2010
| Payments Due By Period | ||||||||||||||||||||
| Total | 2011 | 2012 & 2013 |
2014 & 2015 |
2016 & Beyond |
||||||||||||||||
| (in millions) | ||||||||||||||||||||
| Long-term debt (a) |
$ | 16,755 | $ | 941 | $ | 3,133 | $ | 2,446 | $ | 10,235 | ||||||||||
| Operating leases (b) |
180 | 30 | 59 | 53 | 38 | |||||||||||||||
| Purchase Obligations: (c) |
||||||||||||||||||||
| Firm capacity payments (d) |
893 | 243 | 234 | 236 | 180 | |||||||||||||||
| Energy commodity contracts (e) |
402 | 362 | 31 | 9 | — | |||||||||||||||
| Other purchase obligations (f) |
403 | 206 | 133 | 38 | 26 | |||||||||||||||
| Other long-term liabilities on the Consolidated Balance Sheet (g) |
55 | 55 | — | — | — | |||||||||||||||
| Total contractual cash obligations |
$ | 18,688 | $ | 1,837 | $ | 3,590 | $ | 2,782 | $ | 10,479 | ||||||||||
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| (a) | See Note 15 of Notes to Consolidated Financial Statements. Amounts include estimated scheduled interest payments over the life of the associated debt. |
| (b) | See Note 19. |
| (c) | Purchase obligations reflected in the Consolidated Balance Sheets have been excluded from the above table. |
| (d) | Includes firm capacity payments that provide us with uninterrupted firm access to natural gas transportation and storage. |
| (e) | Includes contractual obligations to purchase physical quantities of NGLs and natural gas. Amounts include certain hedges as defined by applicable accounting standards. For contracts where the price paid is based on an index, the amount is based on forward market prices at December 31, 2010. |
| (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 cannot be determined. |
| (g) | Includes estimated 2011 retirement plan contributions and estimated 2011 payments related to uncertain tax positions, including interest (see Notes 7 and 24). We are unable to reasonably estimate the timing of uncertain tax positions and interest payments in years beyond 2011 due to uncertainties in the timing of cash settlements with taxing authorities and cannot estimate retirement plan contributions beyond 2011 due primarily to uncertainties about market performance of plan assets. Excludes cash obligations for asset retirement activities (see Note 14) because the amount of cash flows to be paid to settle the asset retirement obligations is not known with certainty as we may use internal or external resources to perform retirement activities. Amounts also exclude reserves for litigation and environmental remediation (see Note 19) and regulatory liabilities (see Note 6) because we are 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 primarily by taxable income for each discrete fiscal year. |
Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risks associated with commodity prices, credit exposure, interest rates, equity prices and foreign currency exchange rates. We have established comprehensive risk management policies to monitor and manage these market risks. Our Chief Financial Officer is responsible for the overall governance of managing credit risk and commodity price risk, including monitoring exposure limits.
Commodity Price Risk
We are exposed to the impact of market fluctuations in the prices of NGLs and natural gas purchased as a result of our investment in DCP Midstream, and ownership of the Empress assets in western Canada and processing plants associated with our U.S. pipeline assets. Price risk represents the potential risk of loss from adverse changes in the market price of these energy commodities. Our 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.
We employ established policies and procedures to manage Spectra Energy’s risks associated with Empress’ commodity price fluctuations, which may include the use of forward physical transactions as well as commodity derivatives. There were no significant commodity hedge transactions by Spectra Energy during 2010, 2009 or 2008.
Our equity affiliate, DCP Midstream, also has risk exposures primarily associated with market prices of NGLs and natural gas. DCP Midstream manages these risks separate from Spectra Energy, and utilizes various risk management strategies, including the use of commodity derivatives.
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We have 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. We are exposed to market price fluctuations of NGLs, natural gas and oil primarily in our Field Services segment. Based on a sensitivity analysis as of December 31, 2010 and 2009, a 10¢ per-gallon move in NGL prices would affect our annual pre-tax earnings by approximately $65 million in 2011, primarily from Field Services, as compared with approximately $60 million in 2010. For the same periods, a 50¢ per-MMbtu move in natural gas prices would affect our annual pre-tax earnings by approximately $15 million in 2011 and 2010, and a $10 per-barrel move in oil prices would affect our annual pre-tax earnings by approximately $25 million in 2011 and 2010.
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 our earnings could be significantly different than these estimates.
See also Notes 1 and 18 of Notes to Consolidated Financial Statements.
Credit Risk
Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. Our principal customers for natural gas transportation, storage, and gathering and processing services are industrial end-users, marketers, exploration and production companies, LDCs and utilities located throughout the United States and Canada. We have concentrations of receivables from natural gas utilities and their affiliates, industrial customers and marketers throughout these regions, as well as retail distribution customers in Canada. These concentrations of customers may affect our overall credit risk in that risk factors can negatively affect the credit quality of the 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, we analyze the customers’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We also obtain parental guarantees, cash deposits or letters of credit from customers to provide credit support, where appropriate, based on our financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each contract. Approximately 90% of our credit exposures for transportation, storage, and gathering and processing services are with customers who have an investment-grade rating (or the equivalent based on our evaluation) or are secured by collateral. However, we cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including possible declines in our customers’ creditworthiness. As a result of future capital projects for which natural gas producers may be the primary customer, the percentage of our customers who are rated investment-grade may decline.
We manage cash and restricted cash positions to maximize value while assuring appropriate amounts of cash are available, as required. We invest our 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.
We had no net exposure to any customer that represented greater than 10% of the gross fair value of trade accounts receivable at December 31, 2010.
Based on our policies for managing credit risk, our current exposures and our credit and other reserves, we do not anticipate a materially adverse effect on our consolidated financial position or results of operations as a result of non-performance by any counterparty.
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Interest Rate Risk
We are exposed to risk resulting from changes in interest rates as a result of our issuance of variable and fixed-rate debt and commercial paper. We manage our interest rate exposure by limiting our variable-rate exposures to percentages of total debt and by monitoring the effects of market changes in interest rates. We also enter into financial derivative instruments, including, but not limited to, interest rate swaps and rate lock agreements to manage and mitigate interest rate risk exposure. See also Notes 1, 15 and 18 of Notes to Consolidated Financial Statements.
As of December 31, 2010, we had interest rate hedges in place for various purposes. We are party to “pay floating—receive fixed” interest rate swaps with a total notional amount of $1,500 million to hedge against changes in the fair value of our fixed-rate debt that arise as a result of changes in market interest rates. These swaps also allow us to transform a portion of the underlying cash flows related to our long-term fixed-rate debt securities into variable-rate debt in order to achieve our desired mix of fixed and variable-rate debt. These positions essentially doubled in 2010 compared to 2009 as we sought to balance our financing portfolio to achieve our desired mix. At Spectra Energy Partners, we have third-party “pay fixed—receive floating” interest rate swaps with a total notional amount of $40 million to mitigate our exposure to variable interest rates on loans outstanding under the Spectra Energy Partners revolving credit facility.
Based on a sensitivity analysis as of December 31, 2010, it was estimated that if short-term interest rates average 100 basis points higher (lower) in 2011 than in 2010, interest expense, net of offsetting impacts in interest income, would increase (decrease) by $23 million. Comparatively, based on a sensitivity analysis as of December 31, 2009, had short-term interest rates averaged 100 basis points higher (lower) in 2010 than in 2009, it was estimated that interest expense, net of offsetting interest income, would have fluctuated by approximately $9 million. These amounts were estimated by considering the effect of the hypothetical interest rates on variable-rate debt outstanding, adjusted for interest rate hedges, investments, and cash and cash equivalents outstanding as of December 31, 2010 and 2009. The $14 million increase in our estimated exposure to changes in short-term market interest rates is mainly attributable to an increase in the amount of “pay floating – receive fixed” interest rate swaps outstanding as of December 31, 2010 compared to December 31, 2009 and an increase in commercial paper. As discussed above, this increase is consistent with our overall targeted mix of fixed and variable-rate debt. If short-term interest rates changed significantly, we would likely take action to manage our 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 our financial structure.
Equity Price Risk
Our cost 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 us to price fluctuations in equity markets. In addition, our 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. Volatility of equity markets, particularly declines, will not only impact our cost of providing retirement and postretirement benefits, but will also impact the funding level requirements of those benefits.
We manage equity price risk by, among other things, diversifying our investments in equity investments, setting target allocations of investment types, periodically reviewing actual asset allocations and rebalancing allocations if warranted, and utilizing outside consultants.
Foreign Currency Risk
We are exposed to foreign currency risk from our Canadian operations. To mitigate risks associated with foreign currency fluctuations, contracts may be denominated in or indexed to the U.S. dollar and/or local inflation rates, or investments may be naturally hedged through debt denominated or issued in the foreign currency.
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To monitor our currency exchange rate risks, we use sensitivity analysis, which measures the effect of devaluation of the Canadian dollar. An average 10% devaluation in the Canadian dollar exchange rate during 2010 would have resulted in an estimated net loss on the translation of local currency earnings of approximately $48 million on our Consolidated Statement of Operation. In addition, if a 10% devaluation had occurred on December 31, 2010, the Consolidated Balance Sheet would have been negatively impacted by $595 million through a cumulative translation adjustment in AOCI. At December 31, 2010, one U.S. dollar translated into one Canadian dollar.
As discussed earlier, we maintain credit facilities that typically include financial covenants which limit the amount of debt that can be outstanding as a percentage of total capital for Spectra Energy or of a specific subsidiary. Failure to maintain these covenants could preclude us from issuing commercial paper or letters of credit or borrowing under our revolving credit facilities and could require other affiliates to immediately pay down any outstanding drawn amounts under other revolving credit agreements, which could adversely affect cash flows or restrict business. As a result of the impact of foreign currency fluctuations on our consolidated equity, these fluctuations have a direct impact on our ability to maintain certain of these financial covenants.
OTHER ISSUES
Global Climate Change. Policymakers at regional, federal and international levels continue to evaluate potential legislative and regulatory compliance mechanisms to achieve reductions in global GHG emissions in an effort to address the challenge of climate change. Certain of our assets and operations in the U.S. and Canada are subject to direct and indirect effects of current global climate change regulatory actions in their respective jurisdictions, and it is likely that other assets and operations in the U.S. and Canada will become subject to direct and indirect effects of current and possible future global climate change regulatory actions.
The current international climate framework, the United Nations-sponsored Kyoto Protocol, prescribes specific targets to reduce GHG emissions for developed countries for the 2008-2012 period. The Kyoto Protocol expires in 2012 and has not been signed by the United States. United Nations-sponsored international negotiations were held in Cancun, Mexico in December 2010 with the intent of defining a future agreement for 2012 and beyond. While the talks resulted in a limited political agreement, to date, a binding successor accord to the Kyoto Protocol has not been realized.
While Canada is a signatory to the Kyoto Protocol, the Canadian federal government has confirmed it will not achieve the targets within the timeframes specified. Instead, the government in 2008 outlined a regulatory framework mandating GHG reductions from large final emitters. Regulatory design details from the Government of Canada remain forthcoming. We expect a number of our assets and operations in Canada will be affected by future federal climate change regulations. However, the materiality of any potential compliance costs is unknown at this time as the final form of the regulation and compliance options has yet to be determined by policymakers.
The province of British Columbia enacted a carbon tax, effective July 1, 2008. The tax applies to the purchase or use of fossil fuels, including natural gas. This tax is being recovered from customers through service tolls. British Columbia has also 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. In 2008, the province established additional interim GHG reduction targets of 6% below 2007 levels by 2012 and 18% below by 2016. British Columbia has also issued consultation papers regarding potential development of a cap and trade program; however, the final details and implementation have not been released. The materiality of any potential compliance costs is unknown at this time as the final form of additional regulations and compliance options has yet to be determined by policymakers.
In 2007, the province of Alberta adopted legislation which requires existing large emitters (facilities releasing 100,000 metric tons or more of GHG emissions annually) to reduce their annual emissions intensity by 12% beginning July 1, 2007. In 2010, one of our facilities was subject to this regulation. The regulation has not had a material impact on our consolidated results of operations, financial position or cash flows.
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In the United States, climate change action is evolving at state, regional and federal levels. We expect that some of our assets and operations in the United States could be affected by eventual mandatory GHG programs; however, the timing and specific policy objectives in many jurisdictions, including at the federal level, remain uncertain.
The United States is not a signatory to the Kyoto Protocol, nor has the federal government adopted a mandatory GHG emissions reduction requirement. However, the EPA issued a final Mandatory Greenhouse Gas Reporting rule in 2009 that required annual reporting of GHG emissions data from certain of our U.S. operations beginning in 2010. In November 2010, the EPA released additional requirements for natural gas system reporting that will expand the reporting requirements for GHG emissions in 2011. These reporting requirements are not anticipated to have a material impact on our consolidated results of operations, financial position or cash flows. The EPA also finalized a Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule in May 2010 to address how GHG emissions would be regulated under the existing Clean Air Act. Regulation is scheduled to begin in 2011, and over time, certain of our U.S. facilities will be subject to this regulation. Some new construction and modification projects in the future may be subject to this regulation as well. At this time, it is not anticipated that the costs will be material; however, many implementation details are unknown.
In addition, several legislative proposals that would impose GHG emissions constraints have been considered by the U.S. Congress. To date, no such legislation has been enacted into law. A number of states in the United States are establishing or considering state or regional programs that would mandate reductions in GHG emissions. These regional programs include the Regional Greenhouse Gas Initiative which applies only to power producers in select northeastern states, the Western Climate Initiative which includes a number of western states and the provinces of British Columbia, Ontario and Quebec, and the Midwestern Greenhouse Gas Reduction Accord which includes six midwestern states and one Canadian province. We expect some of our assets and operations could be affected either directly or indirectly by state or regional programs. However, as the key details of future GHG restrictions and compliance mechanisms remain undefined, the likely future effects on our business 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, we cannot estimate the potential effect of proposed GHG policies on our future consolidated results of operations, financial position or cash flows. However, such legislation or regulation could materially increase our operating costs, require material capital expenditures or create additional permitting, which could delay proposed construction projects. We continue to monitor the development of greenhouse gas regulatory policies in both countries.
Other. For additional information on other issues, see Notes 6 and 19 of Notes to Consolidated Financial Statements.
New Accounting Pronouncements
See Note 1 of Notes to Consolidated Financial Statements for discussion.
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
Our 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). Our 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.
Our management, including our Chief Executive Officer and Chief Financial Officer, has conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2010 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 our internal control over financial reporting was effective at the resonable assurance level as of December 31, 2010.
Deloitte & Touche LLP, our independent registered public accounting firm, has audited and issued a report on the effectiveness of our internal control over financial reporting. Their report is included herein.
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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, 2010 and 2009, and the related consolidated statements of operations, cash flows and equity and comprehensive income for each of the three years in the period ended December 31, 2010. 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, 2010, 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.
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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, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
/s/ Deloitte & Touche LLP
Houston, Texas
February 24, 2011
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SPECTRA ENERGY CORP
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per-share amounts)
| Years Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| Operating Revenues |
||||||||||||
| Transportation, storage and processing of natural gas |
$ | 2,870 | $ | 2,565 | $ | 2,343 | ||||||
| Distribution of natural gas |
1,450 | 1,451 | 1,731 | |||||||||
| Sales of natural gas liquids |
459 | 389 | 772 | |||||||||
| Other |
166 | 147 | 228 | |||||||||
| Total operating revenues |
4,945 | 4,552 | 5,074 | |||||||||
| Operating Expenses |
||||||||||||
| Natural gas and petroleum products purchased |
1,056 | 1,098 | 1,586 | |||||||||
| Operating, maintenance and other |
1,278 | 1,144 | 1,235 | |||||||||
| Depreciation and amortization |
650 | 584 | 569 | |||||||||
| Property and other taxes |
297 | 262 | 246 | |||||||||
| Total operating expenses |
3,281 | 3,088 | 3,636 | |||||||||
| Gains on Sales of Other Assets and Other, net |
10 | 11 | 42 | |||||||||
| Operating Income |
1,674 | 1,475 | 1,480 | |||||||||
| Other Income and Expenses |
||||||||||||
| Equity in earnings of unconsolidated affiliates |
430 | 369 | 778 | |||||||||
| Other income and expenses, net |
32 | 37 | 66 | |||||||||
| Total other income and expenses |
462 | 406 | 844 | |||||||||
| Interest Expense |
630 | 610 | 636 | |||||||||
| Earnings From Continuing Operations Before Income Taxes |
1,506 | 1,271 | 1,688 | |||||||||
| Income Tax Expense From Continuing Operations |
383 | 352 | 493 | |||||||||
| Income From Continuing Operations |
1,123 | 919 | 1,195 | |||||||||
| Income From Discontinued Operations, net of tax |
6 | 5 | 2 | |||||||||
| Net Income |
1,129 | 924 | 1,197 | |||||||||
| Net Income—Noncontrolling Interests |
80 | 75 | 65 | |||||||||
| Net Income—Controlling Interests |
$ | 1,049 | $ | 849 | $ | 1,132 | ||||||
| Common Stock Data |
||||||||||||
| Weighted-average shares outstanding |
||||||||||||
| Basic |
648 | 642 | 622 | |||||||||
| Diluted |
650 | 643 | 624 | |||||||||
| Earnings per share from continuing operations |
||||||||||||
| Basic |
$ | 1.61 | $ | 1.31 | $ | 1.82 | ||||||
| Diluted |
$ | 1.60 | $ | 1.31 | $ | 1.81 | ||||||
| Earnings per share |
||||||||||||
| Basic |
$ | 1.62 | $ | 1.32 | $ | 1.82 | ||||||
| Diluted |
$ | 1.61 | $ | 1.32 | $ | 1.81 | ||||||
| Dividends per share |
$ | 1.00 | $ | 1.00 | $ | 0.96 | ||||||
See Notes to Consolidated Financial Statements.
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SPECTRA ENERGY CORP
CONSOLIDATED BALANCE SHEETS
(In millions)
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| ASSETS |
||||||||
| Current Assets |
||||||||
| Cash and cash equivalents |
$ | 130 | $ | 166 | ||||
| Receivables (net of allowance for doubtful accounts of $9 and $14 at December 31, 2010 and 2009, respectively) |
1,018 | 778 | ||||||
| Inventory |
287 | 321 | ||||||
| Other |
203 | 164 | ||||||
| Total current assets |
1,638 | 1,429 | ||||||
| Investments and Other Assets |
||||||||
| Investments in and loans to unconsolidated affiliates |
2,033 | 2,001 | ||||||
| Goodwill |
4,305 | 3,948 | ||||||
| Other |
665 | 407 | ||||||
| Total investments and other assets |
7,003 | 6,356 | ||||||
| Property, Plant and Equipment |
||||||||
| Cost |
22,162 | 19,960 | ||||||
| Less accumulated depreciation and amortization |
5,182 | 4,613 | ||||||
| Net property, plant and equipment |
16,980 | 15,347 | ||||||
| Regulatory Assets and Deferred Debits |
1,065 | 959 | ||||||
| Total Assets |
$ | 26,686 | $ | 24,091 | ||||
See Notes to Consolidated Financial Statements.
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SPECTRA ENERGY CORP
CONSOLIDATED BALANCE SHEETS
(In millions, except per-share amounts)
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| LIABILITIES AND EQUITY |
||||||||
| Current Liabilities |
||||||||
| Accounts payable |
$ | 369 | $ | 333 | ||||
| Short-term borrowings and commercial paper |
836 | 162 | ||||||
| Taxes accrued |
59 | 139 | ||||||
| Interest accrued |
167 | 167 | ||||||
| Current maturities of long-term debt |
315 | 809 | ||||||
| Other |
777 | 885 | ||||||
| Total current liabilities |
2,523 | 2,495 | ||||||
| Long-term Debt |
10,169 | 8,947 | ||||||
| Deferred Credits and Other Liabilities |
||||||||
| Deferred income taxes |
3,555 | 3,209 | ||||||
| Regulatory and other |
1,694 | 1,634 | ||||||
| Total deferred credits and other liabilities |
5,249 | 4,843 | ||||||
| Commitments and Contingencies |
||||||||
| Preferred Stock of Subsidiaries |
258 | 225 | ||||||
| Equity |
||||||||
| Preferred stock, $0.001 par, 22 million shares authorized, no shares outstanding |
— | — | ||||||
| Common stock, $0.001 par, 1 billion shares authorized, 649 million and 647 million shares outstanding at December 31, 2010 and 2009, respectively |
1 | 1 | ||||||
| Additional paid-in capital |
4,726 | 4,645 | ||||||
| Retained earnings |
1,487 | 1,088 | ||||||
| Accumulated other comprehensive income |
1,595 | 1,307 | ||||||
| Total controlling interests |
7,809 | 7,041 | ||||||
| Noncontrolling interests |
678 | 540 | ||||||
| Total equity |
8,487 | 7,581 | ||||||
| Total Liabilities and Equity |
$ | 26,686 | $ | 24,091 | ||||
See Notes to Consolidated Financial Statements.
72
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CORP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
| Years Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES |
||||||||||||
| Net income |
$ | 1,129 | $ | 924 | $ | 1,197 | ||||||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||||||
| Depreciation and amortization |
664 | 598 | 581 | |||||||||
| Deferred income tax expense |
205 | 176 | 158 | |||||||||
| Equity in earnings of unconsolidated affiliates |
(430 | ) | (369 | ) | (778 | ) | ||||||
| Distributions received from unconsolidated affiliates |
391 | 195 | 777 | |||||||||
| Decrease (increase) in |
||||||||||||
| Receivables |
(50 | ) | 143 | (36 | ) | |||||||
| Inventory |
14 | 7 | (76 | ) | ||||||||
| Other current assets |
4 | 69 | (36 | ) | ||||||||
| Increase (decrease) in |
||||||||||||
| Accounts payable |
(67 | ) | 35 | 24 | ||||||||
| Taxes accrued |
(141 | ) | 78 | 8 | ||||||||
| Other current liabilities |
(184 | ) | 33 | (52 | ) | |||||||
| Other, assets |
(49 | ) | (62 | ) | 81 | |||||||
| Other, liabilities |
(78 | ) | (67 | ) | (43 | ) | ||||||
| Net cash provided by operating activities |
1,408 | 1,760 | 1,805 | |||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES |
||||||||||||
| Capital expenditures |
(1,346 | ) | (980 | ) | (1,502 | ) | ||||||
| Investments in and loans to unconsolidated affiliates |
(10 | ) | (61 | ) | (528 | ) | ||||||
| Acquisitions, net of cash acquired |
(492 | ) | (295 | ) | (274 | ) | ||||||
| Purchases of held-to-maturity securities |
(1,117 | ) | (231 | ) | — | |||||||
| Proceeds from sales and maturities of held-to-maturity securities |
1,068 | 110 | — | |||||||||
| Purchases of available-for-sale securities |
(254 | ) | — | (1,132 | ) | |||||||
| Proceeds from sales and maturities of available-for-sale securities |
38 | 32 | 1,256 | |||||||||
| Net proceeds from the sale of other assets |
— | — | 105 | |||||||||
| Distributions received from unconsolidated affiliates |
17 | 164 | 218 | |||||||||
| Receipt from affiliate—repayment of loan |
— | 186 | — | |||||||||
| Other |
(5 | ) | 54 | (6 | ) | |||||||
| Net cash used in investing activities |
(2,101 | ) | (1,021 | ) | (1,863 | ) | ||||||
| CASH FLOWS FROM FINANCING ACTIVITIES |
||||||||||||
| Proceeds from the issuance of long-term debt |
4,389 | 4,127 | 3,557 | |||||||||
| Payments for the redemption of long-term debt |
(3,906 | ) | (4,023 | ) | (2,400 | ) | ||||||
| Net increase (decrease) in short-term borrowings and commercial paper |
669 | (774 | ) | 249 | ||||||||
| Distributions to noncontrolling interests |
(73 | ) | (174 | ) | (70 | ) | ||||||
| Contributions from noncontrolling interests |
— | 2 | 115 | |||||||||
| Proceeds from the issuance of Spectra Energy common stock |
— | 448 | — | |||||||||
| Proceeds from the issuance of Spectra Energy Partners, LP common units |
216 | 208 | — | |||||||||
| Repurchases of Spectra Energy common stock |
— | — | (600 | ) | ||||||||
| Dividends paid on common stock |
(650 | ) | (631 | ) | (598 | ) | ||||||
| Other |
11 | 14 | (39 | ) | ||||||||
| Net cash provided by (used in) financing activities |
656 | (803 | ) | 214 | ||||||||
| Effect of exchange rate changes on cash |
1 | 25 | (11 | ) | ||||||||
| Net increase (decrease) in cash and cash equivalents |
(36 | ) | (39 | ) | 145 | |||||||
| Cash and cash equivalents at beginning of period |
166 | 205 | 60 | |||||||||
| Cash and cash equivalents at end of period |
$ | 130 | $ | 166 | $ | 205 | ||||||
| Supplemental Disclosures |
||||||||||||
| Cash paid for interest, net of amount capitalized |
$ | 615 | $ | 587 | $ | 611 | ||||||
| Cash paid for income taxes |
312 | 100 | 322 | |||||||||
| Property, plant and equipment noncash accruals |
58 | 24 | 44 | |||||||||
See Notes to Consolidated Financial Statements.
73
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CORP
CONSOLIDATED STATEMENTS OF EQUITY AND COMPREHENSIVE INCOME
(In millions)
| Common Stock |
Additional Paid-in Capital |
Retained Earnings |
Accumulated
Other Comprehensive Income |
|||||||||||||||||||||||||
| Foreign Currency Translation Adjustments |
Other | Noncontrolling Interests |
Total | |||||||||||||||||||||||||
| December 31, 2007 |
$ | 1 | $ | 4,603 | $ | 356 | $ | 2,026 | $ | (216 | ) | $ | 581 | $ | 7,351 | |||||||||||||
| Net income |
— | — | 1,132 | — | — | 65 | 1,197 | |||||||||||||||||||||
| Other comprehensive income (loss) |
||||||||||||||||||||||||||||
| Foreign currency translation adjustments |
— | — | — | (1,140 | ) | — | (2 | ) | (1,142 | ) | ||||||||||||||||||
| Unrealized mark-to-market net loss on hedges |
— | — | — | — | (11 | ) | — | (11 | ) | |||||||||||||||||||
| Reclassification of cash flow hedges into earnings |
— | — | — | — | 2 | — | 2 | |||||||||||||||||||||
| Pension and benefits impact |
— | — | — | — | (135 | ) | — | (135 | ) | |||||||||||||||||||
| Total comprehensive income (loss) |
(89 | ) | ||||||||||||||||||||||||||
| Spectra Energy common stock repurchase |
— | (600 | ) | — | — | — | — | (600 | ) | |||||||||||||||||||
| Dividends on common stock |
— | — | (598 | ) | — | — | — | (598 | ) | |||||||||||||||||||
| Stock-based compensation |
— | 38 | — | — | — | — | 38 | |||||||||||||||||||||
| Purchase of Spectra Energy Income Fund units |
— | — | — | — | — | (208 | ) | (208 | ) | |||||||||||||||||||
| Distributions to noncontrolling interests |
— | — | — | — | — | (73 | ) | (73 | ) | |||||||||||||||||||
| Contributions from noncontrolling interests |
— | — | — | — | — | 115 | 115 | |||||||||||||||||||||
| Other, net |
— | 8 | — | — | — | (8 | ) | — | ||||||||||||||||||||
| December 31, 2008 |
1 | 4,049 | 890 | 886 | (360 | ) | 470 | 5,936 | ||||||||||||||||||||
| Net income |
— | — | 849 | — | — | 75 | 924 | |||||||||||||||||||||
| Other comprehensive income |
||||||||||||||||||||||||||||
| Foreign currency translation adjustments |
— | — | — | 796 | — | 11 | 807 | |||||||||||||||||||||
| Unrealized mark-to-market net loss on hedges |
— | — | — | — | (9 | ) | — | (9 | ) | |||||||||||||||||||
| Reclassification of cash flow hedges into earnings |
— | — | — | — | 1 | — | 1 | |||||||||||||||||||||
| Pension and benefits impact |
— | — | — | — | (7 | ) | — | (7 | ) | |||||||||||||||||||
| Total comprehensive income |
1,716 | |||||||||||||||||||||||||||
| Dividends on common stock |
— | — | (651 | ) | — | — | — | (651 | ) | |||||||||||||||||||
| Stock-based compensation |
— | 9 | — | — | — | — | 9 | |||||||||||||||||||||
| Spectra Energy common stock issuance |
— | 448 | — | — | — | — | 448 | |||||||||||||||||||||
| Spectra Energy Partners, LP common unit issuance |
— | 25 | — | — | — | 168 | 193 | |||||||||||||||||||||
| Reclassification of deferred gain on sale of units of Spectra Energy Partners, LP |
— | 59 | — | — | — | — | 59 | |||||||||||||||||||||
| Distributions to noncontrolling interests |
— | — | — | — | — | (174 | ) | (174 | ) | |||||||||||||||||||
| Contributions from noncontrolling interests |
— | — | — | — | — | 2 | 2 | |||||||||||||||||||||
| Other, net |
— | 55 | — | — | — | (12 | ) | 43 | ||||||||||||||||||||
| December 31, 2009 |
1 | 4,645 | 1,088 | 1,682 | (375 | ) | 540 | 7,581 | ||||||||||||||||||||
| Net income |
— | — | 1,049 | — | — | 80 | 1,129 | |||||||||||||||||||||
| Other comprehensive income |
||||||||||||||||||||||||||||
| Foreign currency translation adjustments |
— | — | — | 328 | — | 16 | 344 | |||||||||||||||||||||
| Unrealized mark-to-market net loss on hedges |
— | — | — | — | (28 | ) | — | (28 | ) | |||||||||||||||||||
| Reclassification of cash flow hedges into earnings |
— | — | — | — | 1 | — | 1 | |||||||||||||||||||||
| Pension and benefits impact |
— | — | — | — | (7 | ) | — | (7 | ) | |||||||||||||||||||
| Total comprehensive income |
1,439 | |||||||||||||||||||||||||||
| Dividends on common stock |
— | — | (650 | ) | — | — | ||||||||||||||||||||||