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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, 2011 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, 2011: $17,800,000,000
Number of shares of Common Stock, $0.001 par value, outstanding at January 31, 2012: 651,150,825
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement for the 2012 Annual Meeting of Shareholders are incorporated by reference in Part III.
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SPECTRA ENERGY CORP
FORM 10-K FOR THE YEAR ENDED
DECEMBER 31, 2011
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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. 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 own a 50% 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 4,329 trillion British thermal units (TBtu) in 2011, compared to 4,248 TBtu in 2010 and 3,987 TBtu in 2009. These amounts include throughput on 100%-owned U.S. and Canadian pipelines and our proportional share of throughput on pipelines that are not 100%-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 100%-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, 100%-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 14,600 miles of transmission pipelines with eight 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), Big Sandy Pipeline, LLC (Big Sandy), 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. 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.
U.S. Transmission’s proportional throughput for its pipelines totaled 2,770 TBtu in 2011, compared to 2,708 TBtu in 2010 and 2,574 TBtu in 2009. This includes throughput on 100%-owned pipelines and our proportional share of throughput on pipelines that are not 100%-owned. Demand on the pipeline and storage systems is seasonal, with the highest throughput occurring during colder periods in the first and fourth calendar quarters, and storage injections occurring primarily during the summer periods. Actual throughput and storage injections/withdrawals do not have a significant impact on revenues or earnings.
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.
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In 2007, we completed our initial public offering (IPO) of Spectra Energy Partners, LP (Spectra Energy Partners), a natural gas infrastructure master limited partnership which is part of the U.S. Transmission segment. We currently retain a 64% equity interest in Spectra Energy Partners, which owns 100% of East Tennessee, 100% of Saltville, 100% of Ozark Gas Gathering and Ozark Gas Transmission, 100% of Big Sandy, 50% of Market Hub and 49% of Gulfstream. Spectra Energy directly owns the remaining 50% interest in Market Hub and a 1% interest in Gulfstream. Spectra Energy Partners is a publicly traded entity which trades on the New York Stock Exchange under the symbol “SEP.” See Part II. Item 8. Financial Statements and Supplementary Data, Note 3 of Notes to Consolidated Financial Statements for further discussion of Spectra Energy Partners.
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 100%-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 affiliated storage facilities in Texas and Louisiana, aggregating 65 Bcf, owned by Market Hub and Bobcat.
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New Jersey-New York Expansion. This proposed 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 which should help eliminate existing bottlenecks in the region’s interstate transmission pipeline grid. With a capacity of 800 million cubic-feet-per-day (MMcf/d) of natural gas, the project is fully 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 continued throughout 2011, with various environmental and other permits being received. Although the FERC recently announced a delay in the issuance of the Final Environmental Impact Statement, a FERC certificate is expected in April 2012 which would allow construction to begin in June 2012 as scheduled. As discussed under Item 1A. Risk Factors, risks associated with any capital expansion program include regulatory, development, operational and market risks. The project is expected to be in service in late fourth quarter of 2013 at a cost of up to $1.2 billion.
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 locations 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 64% 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 890 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 64% 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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Big Sandy
We have an effective 64% ownership interest in Big Sandy, which was acquired by Spectra Energy Partners in July 2011. Big Sandy is a 68-mile, FERC-regulated natural gas transmission pipeline located in eastern Kentucky. Big Sandy’s interconnect with the Tennessee Gas Pipeline system links the Huron Shale and Appalachian Basin natural gas supplies to the mid-Atlantic and northeast markets.
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Gulfstream
We have an effective 32% 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 286-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 82% 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 51 Bcf. The Moss Bluff facility consists of four 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 eight 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 64% 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, a 14 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 and Dominion Transmission 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 for 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 with 100 years of experience and service to customers. The distribution business serves approximately 1.4 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 storage and transportation 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’ distribution system consists of approximately 39,000 miles of 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 2,900 miles of high-pressure pipeline and six mainline compressor stations.
Competition
Union Gas’ distribution system 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 newly required facilities even within Union Gas’ 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 Union Gas will remain unchanged throughout the five-year incentive regulation period (2008-2012). In 2011, Union Gas filed an application with the OEB for new rates for 2013. This filing included updated revenue and cost forecasts to reset rates, as well as 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. Union Gas plans to file its application for a new multi-year incentive regulation framework after receiving the OEB decision on its 2013 rate application.
Since 2006, Union Gas has provided storage services to customers outside its franchise area and new storage services under a framework established by the OEB that supports unregulated storage investments and allows Union Gas to compete with third-party storage providers on bases of price, terms of service, and flexibility and reliability of service. Under that framework, Union Gas was required to share its long-term storage margins with ratepayers until 2011 when no sharing of margins is required. Existing storage services to customers within Union Gas’ franchise area, however, have continued to be provided at cost-based rates and are not subject to third-party competition.
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, the level of business activity, conservation, legislation, governmental regulations, the ability to convert to alternative fuels, and other factors.
Customers and Contracts
Most of Union Gas’ power generation customers, 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 from the sale of the natural gas commodity, gas distribution margins are not affected by either the source of customers’ gas supply or its price, except to the extent that prices affect actual customer usage.
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 seven years, with the longest being slightly more than 21 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 (NGL) 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 713 TBtu in 2011, compared to 627 TBtu in 2010 and 604 TBtu in 2009.
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 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.
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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, the largest of our expansion projects in western Canada, 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 that 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 product sales markets we serve. Declines in eastbound flows of natural gas through Empress, Alberta and competitive market pressure continue to cause an increase in the premiums that we pay to shippers to extract NGLs compared with historical premiums paid.
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 in the 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 fee-for-service contracts which do not expose us to direct 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. The majority of propane is sold to propane retailers. Butane is sold mainly into the motor gasoline refinery market and condensate sales are sold to the crude blending and crude diluent markets. Profit margins are driven by the market prices of NGL products, extraction premiums paid to shippers, shrinkage make-up natural gas prices and other operating costs.
Field Services consists of our 50% investment in DCP Midstream, which is accounted for as an equity investment. DCP Midstream gathers, processes, treats, compresses, transports and stores natural gas. In addition, DCP also fractionates, transports, gathers, treats, processes, stores, markets and trades NGLs. ConocoPhillips currently owns the remaining 50% interest in DCP Midstream. DCP Midstream owns a 27% 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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During the third quarter of 2011, ConocoPhillips announced plans to separate its business into two stand-alone publicly traded companies, and anticipates completing the proposed separation during the first half of 2012. As a result of this potential transaction, DCP Midstream will no longer be owned 50% by ConocoPhillips. ConocoPhillips’ 50% ownership interest in DCP Midstream will be transferred to the new downstream company, Phillips 66. DCP Midstream does not anticipate that the change in ownership will have a material impact on its operations.
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, one natural gas storage facility and one NGL 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 62,000 miles of gathering and transmission pipeline.
As of December 31, 2011, DCP Midstream owned or operated 61 natural gas processing plants, which separate raw natural gas that has been gathered on its own systems and third-party systems into condensate, NGLs and residue gas.
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. As of December 31, 2011, DCP Midstream owned or operated 12 fractionators. In addition, DCP Midstream operates a propane wholesale marketing business in the northeastern United States.
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 its 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, processing and storing natural gas, as well as producing, 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, NGL transporters 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.
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Customers and Contracts
DCP Midstream sells NGLs to a variety of customers ranging from large, multi-national petrochemical and refining companies to small regional retail propane distributors. Substantially all of DCP Midstream’s NGL sales are made at market-based prices, including approximately 40% of its NGL production that is committed to ConocoPhillips and its affiliate, Chevron Phillips Chemical Company LLC, under existing contracts that have primary terms that are effective until January 1, 2015. Should the contract not be renegotiated or renewed, it provides for a five year ratable wind-down period through 2020. In 2011, 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/index arrangements. In general, DCP Midstream purchases natural gas from producers at the wellhead or other receipt points, treats and processes it, and then sells the residue natural gas and NGLs based on index prices from published index market prices. DCP Midstream remits to the producers either an agreed-upon percentage of the actual proceeds received from the sale of the residue natural gas and NGLs, or an agreed-upon percentage of the proceeds based on index related prices for the natural gas and the NGLs, regardless of the actual amount of proceeds which DCP Midstream receives. Certain of these arrangements may also result in DCP Midstream returning all or a portion of the residue natural gas and/or the NGLs to the producer in lieu of returning sales proceeds. DCP Midstream’s revenues from these arrangements relate directly with the prices of natural gas, crude oil and NGLs. |
| • | Fee-based arrangements. DCP Midstream receives a fee or fees for one or more of the following services: gathering, processing, compressing, treating or transporting natural gas. Fee-based arrangements include natural gas purchase arrangements pursuant to which DCP Midstream purchases natural gas at the wellhead or other receipt points at an index related price at the delivery point less a specified amount, generally the same as the fees it would otherwise charge for gathering of natural gas from the wellhead location to the delivery point. 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. To the extent that a sustained decline in commodity prices results in a decline in volumes, however, DCP Midstream’s revenues from these arrangements could be reduced. |
| • | Keep-whole and wellhead purchase arrangement. DCP Midstream gathers raw natural gas from producers for processing, markets the NGLs and returns to the producer residual natural gas with a Btu content equivalent to the Btu content of the natural gas gathered. Under the terms of a wellhead purchase contract, DCP Midstream purchases natural gas from the producer at the wellhead or defined receipt point for processing and markets the resulting NGLs and residue gas at market prices. DCP Midstream is exposed to the difference between the value of the NGLs extracted from processing and the value of the Btu-equivalent of the residue natural gas, or frac-spread. DCP Midstream benefits in periods when NGL prices are higher relative to natural gas prices when that frac spread exceeds its operating costs. |
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. The revenues that DCP Midstream earns from the sale of condensate correlate directly with crude oil prices.
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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.
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 various federal and provincial agencies with respect to pipeline safety, including the NEB and the Transportation Safety Board, the British Columbia Oil and Gas Commission, the Alberta Energy Resources Conservation Board and the Ontario Technical Standards and Safety Authority.
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 that transport natural gas in interstate commerce provide services under Section 311 of the Natural Gas Policy Act of 1978, they are subject to FERC regulation. DCP Midstream’s interstate natural gas pipeline operations are also subject to regulation by the FERC. The natural gas gathering and processing activities of DCP Midstream are not subject to FERC regulation.
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We are subject to various U.S. federal, state and local laws and regulations, as well as Canadian federal and provincial regulations, regarding air and water quality, hazardous and solid waste disposal and other environmental matters.
Environmental laws and regulations affecting our U.S.-based operations 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 us, 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 therefore have CERCLA liabilities. |
| • | 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. |
Environmental laws and regulations affecting our Canadian-based operations include, but are not limited to:
| • | 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. |
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| • | The Canadian Environmental Protection Act, pursuant to which, among other things, requires the 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 required 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 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 5,700 employees as of December 31, 2011, including approximately 3,600 employees in Canada. In addition, DCP Midstream employed approximately 3,000 employees as of such date. Approximately 1,500 of our Canadian employees 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, 2012.
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The following table sets forth information regarding our executive and other officers.
| Name |
Age |
Position | ||||
| Gregory L. Ebel |
47 | President and Chief Executive Officer, Director | ||||
| J. Patrick Reddy |
59 | Chief Financial Officer | ||||
| Dorothy M. Ables |
54 | Chief Administrative Officer | ||||
| John R. Arensdorf |
61 | Chief Communications Officer | ||||
| Alan N. Harris |
58 | Chief Development and Operations Officer | ||||
| Reginald D. Hedgebeth |
44 | General Counsel | ||||
| Guy G. Buckley |
51 | Group Vice President and Treasurer | ||||
| Allen C. Capps |
41 | 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.
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.
John R. Arensdorf assumed his current position in November 2008. He previously served as Vice President, Investor Relations from January 2007.
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. 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.
Guy G. Buckley assumed his current position as Group Vice President and Treasurer in January 2012. He previously served as Group Vice President, Corporate Development and Strategy since December 2008 and was Vice President Mergers and Acquisitions from January 2007 to December 2008.
Allen C. Capps assumed his current position as Vice President and Controller in January 2012. He previously served as Vice President, Business Development, Storage and Transmission, for Union Gas from April 2010. Prior to then, Mr. Capps served as Vice President and Treasurer for Spectra Energy Corp from December 2007 until April 2010, and Director of Finance of EPCO, Inc., a midstream energy company, from April 2006.
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, proxy statements and amendments to such reports. The public may read and copy any materials that we file with the SEC at the SEC’s Public
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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 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 on the development of natural gas supplies, 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 affect our revenues, earnings and cash flows.
Investments and projects located in Canada expose us to fluctuations in currency rates that may 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 2011 would have resulted in an estimated net loss on the translation of local currency earnings of approximately $53 million on our Consolidated Statement of Operations. In addition,
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if a 10% devaluation had occurred on December 31, 2011, the Consolidated Balance Sheet would have been negatively impacted by $641 million through a cumulative translation adjustment in Accumulated Other Comprehensive Income (AOCI). At December 31, 2011, one U.S. dollar translated into 1.02 Canadian dollars.
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 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, and market-based storage 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, 2011, a 10¢ per-gallon move in NGL prices would affect our annual pre-tax earnings by approximately $70 million in 2012, 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 $16 million and a $10 per-barrel move in oil prices would affect our annual pre-tax earnings by approximately $22 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.
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, including possible declines, as contracts renew.
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 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 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 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 effect on our business, earnings, financial condition and cash flows.
We are subject to pipeline safety laws and regulations, compliance with which may require significant capital expenditures, increase our cost of operations and 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 (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.
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In 2010, serious pipeline incidents on systems unrelated to ours focused the attention of Congress and the public on pipeline safety. Legislative proposals have been introduced in Congress that would strengthen the PHMSA’s enforcement and penalty authority, and expand the scope of its oversight. In August 2011, PHMSA initiated an Advance Notice of Proposed Rulemaking announcing its consideration of substantial revisions in its regulations to increase pipeline safety. PHMSA also has issued guidance that states it will focus near-term enforcement efforts on recordkeeping and integrity management following urgent recommendations by the National Transportation Safety Board related to pipeline pressure and recordkeeping. On January 3, 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 was signed into law. This Act (the 2012 PSA Amendments) amends the Pipeline Safety Act in a number of significant ways, including:
| • | Authorizing PHMSA to assess higher penalties for violations of its regulations, |
| • | Requiring PHMSA to adopt appropriate regulations within two years requiring the use of automatic or remote-controlled shutoff valves on new or rebuilt pipeline facilities and to perform a study on the application of such technology to existing pipeline facilities in High Consequence Areas (HCAs), |
| • | Requiring operators of pipelines to verify maximum allowable operating pressure and report exceedances within five days, |
| • | Requiring PHMSA to study and report on the adequacy of soil cover requirements in HCAs, and |
| • | Requiring PHMSA to evaluate in detail whether integrity management requirements should be expanded to pipeline segments outside of HCAs (where the requirements currently apply). |
These legislative changes, when implemented, will impose additional costs on new pipeline projects as well as on existing operations. It is still uncertain what regulatory changes PHMSA will propose as a result of the Advance Notice of Proposed Rulemaking, but PHMSA will begin to undertake the various requirements imposed on it by the 2012 PSA Amendments. In this climate of increasingly stringent regulation, pipeline failures or failures to comply with applicable regulations could result in reduction of allowable operating pressures as authorized by PHMSA, which would reduce available capacity on our pipelines. Should any of these risks materialize, it may have a material effect on our operations, earnings, financial condition and cash flows.
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 effect on our earnings and cash flows.
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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 Durban, South Africa in December 2011 with the intent of defining a future agreement for 2012 and beyond. A non-binding agreement was reached to develop a roadmap aimed at creating a global agreement on climate action to be implemented by 2020.
In December 2011 after the international negotiations in Durban, South Africa, Canada announced that it is withdrawing from the Kyoto Protocol. In 2008 the Canadian government outlined a regulatory framework mandating GHG reductions from large final emitters. Regulatory design details from the Government of Canada remain forthcoming. However, Canada has reaffirmed its strong preference for a harmonized approach with that of the United States. Regardless of the timing, we expect a number of our assets and operations in Canada will be affected by pending 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 began 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, although additional permitting requirements could 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.
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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 affected, particularly if we or our rated subsidiaries are unable to maintain an investment-grade credit rating, which could 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. Consequently, 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 affect cash flows or restrict business. Furthermore, if Spectra Energy’s short-term debt rating were to be below tier 2 (for example, A-2 for Standard and Poor’s, P-2 for Moody’s Investor Service and F2 for Fitch Ratings), 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 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.
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 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 effect on our earnings and cash flows.
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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 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 effect on natural gas production in British Columbia and Alberta, which could have a material 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 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 high for companies, like us, operating in any energy infrastructure industry that handle volatile gaseous and liquid hydrocarbons. The potential for terrorism, including cyber-terrorism, has subjected our operations to increased risks that could have a material 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 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 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.
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At December 31, 2011, 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, 2011.
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. Mine Safety Disclosures.
Not applicable.
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, 2012, there were approximately 135,000 holders of record of our common stock and approximately 465,000 beneficial owners.
Common Stock Data by Quarter
| 2011 |
Dividends Per Common Share |
Stock Price Range (a) |
||||||||||
| High | Low | |||||||||||
| First Quarter |
$ | 0.26 | $ | 27.50 | $ | 24.44 | ||||||
| Second Quarter |
0.26 | 29.24 | 26.17 | |||||||||
| Third Quarter |
0.26 | 28.00 | 22.80 | |||||||||
| Fourth Quarter |
0.28 | 31.33 | 23.17 | |||||||||
| 2010 |
||||||||||||
| 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 | |||||||||
| (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, 2011 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 | 2011 | ||||||||||||||||||||
| Spectra Energy Corp |
$ | 100.00 | $ | 93.47 | $ | 59.54 | $ | 82.34 | $ | 104.95 | $ | 134.38 | ||||||||||||
| S&P 500 Stock Index |
100.00 | 105.60 | 66.53 | 84.14 | 96.81 | 98.86 | ||||||||||||||||||
| S&P 500 Storage & Transportation Index |
100.00 | 114.30 | 56.81 | 79.38 | 101.13 | 149.59 | ||||||||||||||||||
Dividends
Our near-term objective is to increase our dividend by at least $0.08 per year and to continue paying cash dividends in the future. In the long-term, we anticipate paying dividends at an average payout ratio level of between 60%-65% of our 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. The declaration and payment of dividends is 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.
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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.
| 2011 | 2010 | 2009 | 2008 | 2007 | ||||||||||||||||
| (Unaudited) (dollars in millions, except per-share amounts) |
||||||||||||||||||||
| Statements of Operations |
||||||||||||||||||||
| Operating revenues |
$ | 5,351 | $ | 4,945 | $ | 4,552 | $ | 5,074 | $ | 4,704 | ||||||||||
| Operating income |
1,763 | 1,674 | 1,475 | 1,480 | 1,426 | |||||||||||||||
| Income from continuing operations |
1,257 | 1,123 | 919 | 1,195 | 990 | |||||||||||||||
| Net income—noncontrolling interests |
98 | 80 | 75 | 65 | 70 | |||||||||||||||
| Net income—controlling interests |
1,184 | 1,049 | 849 | 1,132 | 945 | |||||||||||||||
| Ratio of Earnings to Fixed Charges |
3.4 | 3.1 | 2.8 | 3.6 | 3.1 | |||||||||||||||
| Common Stock Data |
||||||||||||||||||||
| Earnings per share from continuing operations |
||||||||||||||||||||
| Basic |
$ | 1.78 | $ | 1.61 | $ | 1.31 | $ | 1.82 | $ | 1.47 | ||||||||||
| Diluted |
1.77 | 1.60 | 1.31 | 1.81 | 1.46 | |||||||||||||||
| Earnings per share |
||||||||||||||||||||
| Basic |
1.82 | 1.62 | 1.32 | 1.82 | 1.49 | |||||||||||||||
| Diluted |
1.81 | 1.61 | 1.32 | 1.81 | 1.49 | |||||||||||||||
| Dividends per share |
1.06 | 1.00 | 1.00 | 0.96 | 0.88 | |||||||||||||||
| December 31, | ||||||||||||||||||||
| 2011 | 2010 | 2009 | 2008 | 2007 | ||||||||||||||||
| (in millions) | ||||||||||||||||||||
| Balance Sheets |
||||||||||||||||||||
| Total assets |
$ | 28,138 | $ | 26,686 | $ | 24,091 | $ | 21,924 | $ | 22,970 | ||||||||||
| Long-term debt including capital leases, less current maturities |
10,146 | 10,169 | 8,947 | 8,290 | 8,345 | |||||||||||||||
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.
EXECUTIVE OVERVIEW
Throughout 2011, we continued to successfully execute on the long-term strategies that we outlined for our shareholders. These included solid earnings growth in 2011, the successful execution on capital expansion plans that underlie our growth objectives, and maintaining a strong balance sheet. These results, combined with future growth opportunities, led our Board of Directors to approve an increase in our quarterly dividend effective with the fourth quarter of 2011 to $0.28 per share, or $1.12 annually, representing an $0.08 increase from the third-quarter annual level. Our near-term objective is to increase our dividend by at least $0.08 per year and to continue paying cash dividends in the future. In the long-term, we anticipate paying dividends at an average payout ratio level of between 60%-65% of our net income from controlling interests per share of common stock.
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During 2011, 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, NGL prices improved significantly compared to 2010, contributing to higher earnings in 2011. We reported net income from controlling interests of $1,184 million, and $1.81 of diluted earnings per share for 2011 compared to net income from controlling interests of $1,049 million, and $1.61 of diluted earnings per share for 2010.
Earnings highlights for 2011 include the following:
| • | U.S. Transmission’s earnings benefited from the successful execution of planned expansion projects, partially offset by lower contracted volumes and rates and higher operating costs, |
| • | Distribution’s earnings reflect higher customer usage of natural gas in core markets and a stronger Canadian dollar, partially offset by higher operating costs, |
| • | Western Canada Transmission & Processing earnings increased mainly as a result of higher gathering and processing earnings from expansions and a stronger Canadian dollar, and |
| • | Field Services earnings increased as a result of higher commodity prices and lower interest expense, partially offset by higher planned operating expenses. |
We invested $1.9 billion of capital and investment expenditures in 2011, including approximately $1.1 billion of expansion capital expenditures. In addition, we acquired the Big Sandy pipeline assets in 2011 for approximately $390 million. Successful execution of our 2011 projects allowed us to continue to achieve aggregate returns in excess of 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 continue to foresee significant expansion capital spending over the next several years, with approximately $1.3 billion planned for 2012, as we execute on identified opportunities around new natural gas supply volumes in Western Canada and the Appalachian and southeast regions of the United States.
We are committed to an investment-grade balance sheet and continued prudent financial management of our capitalization structure. Therefore, financing these growth activities will continue to be based on our strong, and growing, fee-based earnings and cash flows as well as the issuance of long-term debt. In 2012, we plan to issue approximately $1.3 billion of combined long-term debt and commercial paper, including the refinancing of approximately $500 million of long-term debt maturities. In addition, as part of our overall financial management, we have ongoing access to approximately $1.8 billion under our credit facilities as of December 31, 2011, to be utilized as needed for effective working capital management. At December 31, 2011, our debt-to-capitalization ratio is at 56%. Total capitalization benefited from strong earnings and the issuance of additional public units of Spectra Energy Partners in 2011.
Our Strategy. Our focus is on leading the natural gas infrastructure industry in terms of safe and reliable operations, customer responsiveness and profitability. Through our network of people and assets, we will increase our size, financial flexibility and services to meet the changing needs of our customers. 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 2011 strategies:
| • | Deliver on our 2012 financial commitments. |
| • | Effectively execute our 2012 expansion plans. |
| • | Leverage our asset footprint to develop new growth opportunities. |
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Natural gas supply dynamics continue to rapidly change and strengthen, and there is growing long-term potential for natural gas to be an effective solution for meeting the energy needs of North America. This causes us to be optimistic about future growth opportunities. Identified opportunities include conversions of coal-fired generation plants that are in close proximity to our pipelines in the southeastern and northeastern United States to natural gas-fired generation, the attachment of shale supplies to attractive markets, incremental gathering and processing requirements in western Canada, potential LNG exports from North America to Asia and other continents, and significant new liquids pipeline infrastructure, and gathering and processing facilities in our Field Services segment. With our advantage of providing access to strong supply regions as well as growing natural gas and liquids markets, we expect to continue expanding our assets and operations to meet these needs.
Successful execution of our strategy will be determined by such key factors as the continued successful production and the consumption of natural gas within the U.S. and Canada, our ability to provide creative solutions for customers’ energy needs as they evolve, and continued cost control and successful execution on capital projects.
We continue to be actively engaged in the national discussions in both the U.S. and Canada regarding the potential for natural gas to be a key component of a long-term energy solution for North America. Consistent with our key role in this solution, we are committed to operating all of our assets safely and reliably for our employees, the communities in which we operate and our customers. And we have taken a lead role in supporting natural gas pipeline safety legislation.
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 prolonged decreases in the demand for natural gas and/or 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. Lower overall economic output would cause a decline in the volume of natural gas distributed or gathered and processed at our plants, resulting in lower earnings and cash flows. This decline would mostly affect distribution revenues and gathering revenues, potentially 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. Gathering and processing revenues and the earnings and cash 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 activity in the areas that affect our Western Canada Transmission & Processing and Field Services segments remains strong, primarily driven by recent positive developments around unconventional gas reserves production in numerous locations within North America as discussed further below.
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 continental United States 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 natural gas reserves in western and eastern Canada. The national supply profile is shifting to new sources of gas from natural gas shale basins in the Rockies, Mid-Continent, Appalachia, Texas and Louisiana. And significant supply sources continue to be identified for development in western Canada. 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.” Recent community and political pressures have arisen around the production processes
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associated with extracting natural gas from the natural gas shale basins. Although we continue to believe that natural gas will remain a viable energy solution for the U.S. and Canada, these pressures could increase costs and/or cause a slowdown in the production of natural gas from these basins, and therefore, could negatively affect our growth plans.
Natural gas storage prices have recently been challenged as a result of increasing natural gas supply and narrower seasonal price spreads. Gas supply and demand dynamics continue to change as a result of the development of new unconventional shale gas supplies. These market factors will continue to keep downward pressure on storage values in the near term.
While current drilling levels are below recent historical averages, the relatively higher productivity of unconventional wells has led to increased production supporting continued growth of Western Canada Transmission & Processing’s gathering and processing business in the areas of British Columbia and Alberta where unconventional gas development is prevalent.
In certain areas of Western Canada Transmission & Processing’s operations served by conventional supply, lower natural gas prices resulting from increasing North American gas production have reduced producer demand for expansions of the British Columbia conventional gas processing plants as well as renewals of existing gas processing contracts, and could continue to do so as long as gas prices remain below historical norms.
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. During the past several years, the Canadian dollar has strengthened by more than 15% compared to the U.S. dollar, which favorably affected earnings and equity during these periods. Changes in the exchange rate or any other 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 which are most sensitive to changes in NGL prices. We evaluate, on an ongoing basis, the risks associated with commodity price volatility and currently have no plans to materially hedge our exposures to commodity prices.
Based on current projections, it is expected that our effective income tax rate on continuing operations will approximate 28%–29% for 2012. Our overall effective tax rate largely depends on the proportion of earnings in the United States to the earnings of our Canadian operations. Our earnings in the U.S. are subject to a 35% federal statutory tax rate and in Canada are subject to an effective tax rate of approximately 17% that is driven by lower statutory rates and recognition of certain regulatory tax benefits. See “Liquidity and Capital Resources” for further discussion about the tax impact of repatriating funds generated from our Canadian operations to Spectra Energy Corp (the U.S. parent).
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 affect our ability to implement our strategy. Market disruptions or a downgrade in our credit ratings may increase the cost of borrowings or 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, the pricing of materials and challenges associated with ensuring the protection of our environment and continual safety enhancements to our facilities. We maintain a strong 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.
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For further information related to management’s assessment of our risk factors, see Part I. Item 1A. Risk Factors.
RESULTS OF OPERATIONS
| 2011 | 2010 | 2009 | ||||||||||
| (in millions) | ||||||||||||
| Operating revenues |
$ | 5,351 | $ | 4,945 | $ | 4,552 | ||||||
| Operating expenses |
3,596 | 3,281 | 3,088 | |||||||||
| Gains on sales of other assets and other, net |
8 | 10 | 11 | |||||||||
|
|
|
|
|
|
|
|||||||
| Operating income |
1,763 | 1,674 | 1,475 | |||||||||
| Other income and expenses |
606 | 462 | 406 | |||||||||
| Interest expense |
625 | 630 | 610 | |||||||||
|
|
|
|
|
|
|
|||||||
| Earnings from continuing operations before income taxes |
1,744 | 1,506 | 1,271 | |||||||||
| Income tax expense from continuing operations |
487 | 383 | 352 | |||||||||
|
|
|
|
|
|
|
|||||||
| Income from continuing operations |
1,257 | 1,123 | 919 | |||||||||
| Income from discontinued operations, net of tax |
25 | 6 | 5 | |||||||||
|
|
|
|
|
|
|
|||||||
| Net income |
1,282 | 1,129 | 924 | |||||||||
| Net income—noncontrolling interests |
98 | 80 | 75 | |||||||||
|
|
|
|
|
|
|
|||||||
| Net income—controlling interests |
$ | 1,184 | $ | 1,049 | $ | 849 | ||||||
|
|
|
|
|
|
|
|||||||
2011 Compared to 2010
Operating Revenues. The $406 million, or 8%, increase was driven mainly by:
| • | revenues from expansion projects at U.S. Transmission and Western Canada Transmission & Processing and the acquisitions of Bobcat and Big Sandy at U.S. Transmission, |
| • | the effects of a stronger Canadian dollar on revenues at Distribution and Western Canada Transmission & Processing, |
| • | an increase in customer usage of natural gas due to colder weather in 2011 at Distribution, and |
| • | higher NGL and other petroleum products sales volumes from the Empress operations due to the effect of a scheduled plant turnaround in 2010, and higher NGL sales prices associated with the Empress operations in 2011 at Western Canada Transmission & Processing, partially offset by |
| • | lower natural gas prices passed through to customers at Distribution. |
Operating Expenses. The $315 million, or 10%, increase was driven mainly by:
| • | higher volumes of natural gas purchased attributable to higher demand for NGL and other petroleum products for extraction and make-up, and higher prices of natural gas purchased caused primarily by higher extraction premiums at the Empress operations at Western Canada Transmission & Processing, |
| • | higher volumes of natural gas sold as a result of colder weather in 2011 at Distribution, |
| • | the effects of a stronger Canadian dollar at Distribution and Western Canada Transmission & Processing, and |
| • | higher corporate costs, partially offset by |
| • | lower natural gas prices passed through to customers at Distribution. |
Operating Income. The $89 million increase was mainly driven by higher earnings from expansion projects at U.S. Transmission and Western Canada Transmission & Processing, and the effects of a stronger Canadian dollar, partially offset by higher corporate costs.
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Other Income and Expenses. The $144 million increase was attributable to higher equity earnings from Field Services mainly due to higher commodity prices, and lower interest and income tax expenses, partially offset by higher planned operating expenses.
Income Tax Expense from Continuing Operations. The $104 million increase was a result of higher earnings from continuing operations and higher effective tax rates. The effective tax rate for income from continuing operations was 28% in 2011 compared to 25% in 2010. 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. See Note 7 of Notes to Consolidated Financial Statements for reconciliations of our effective tax rates to the statutory tax rate.
Income from Discontinued Operations, Net of Tax. The $19 million increase reflects the 2011 recovery of losses incurred in the fourth quarter of 2010 related to a breach by a third party of certain scheduled propane deliveries to us. Higher income from propane deliveries and the recovery of losses in 2011 were offset by a favorable income tax adjustment related to previously discontinued operations in the first quarter of 2010.
Net Income—Noncontrolling Interests. The $18 million increase was mainly driven by an increase in the noncontrolling interests ownership percentage resulting from the Spectra Energy Partners public sales of additional partner units in December 2010 and June 2011, and higher earnings from Spectra Energy Partners, primarily as a result of their acquisitions of an additional 24.5% in Gulfstream in the fourth quarter of 2010 and Big Sandy in July 2011.
For a more detailed discussion of earnings drivers, see the segment discussions that follow.
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, and |
| • | 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, partially offset by |
| • | 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, and |
| • | lower natural gas prices passed through to customers and lower operating fuel costs at Distribution. |
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Index to Financial Statements
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. See Note 7 of Notes to Consolidated Financial Statements for reconciliations of our effective tax rate to the statutory tax rate.
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.
Segment Results
Management evaluates segment performance based on earnings before interest and taxes (EBIT), which 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.
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.
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Index to Financial Statements
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, processes, treats, compresses, transports and stores natural gas and fractionates, transports, gathers, treats, processes, stores, 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
| 2011 | 2010 | 2009 | ||||||||||
| (in millions) | ||||||||||||
| U.S. Transmission |
$ | 983 | $ | 948 | $ | 894 | ||||||
| Distribution |
425 | 409 | 336 | |||||||||
| Western Canada Transmission & Processing |
510 | 409 | 343 | |||||||||
| Field Services |
449 | 335 | 296 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total reportable segment EBIT |
2,367 | 2,101 | 1,869 | |||||||||
| Other |
(104 | ) | (38 | ) | (74 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Total reportable segment and other EBIT |
2,263 | 2,063 | 1,795 | |||||||||
| Interest expense |
625 | 630 | 610 | |||||||||
| Interest income and other (a) |
106 | 73 | 86 | |||||||||
|
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|
|
|
|
|
|||||||
| Earnings from continuing operations before income taxes |
$ | 1,744 | $ | 1,506 | $ | 1,271 | ||||||
|
|
|
|
|
|
|
|||||||
| (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-100%-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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Index to Financial Statements
U.S. Transmission
| 2011 | 2010 | Increase (Decrease) |
2009 | Increase (Decrease) |
||||||||||||||||
| (in millions, except where noted) | ||||||||||||||||||||
| Operating revenues |
$ | 1,900 | $ | 1,821 | $ | 79 | $ | 1,690 | $ | 131 | ||||||||||
| Operating expenses |
||||||||||||||||||||
| Operating, maintenance and other |
684 | 671 | 13 | 577 | 94 | |||||||||||||||
| Depreciation and amortization |
272 | 258 | 14 | 246 | 12 | |||||||||||||||
| Gains on sales of other assets and other, net |
8 | 11 | (3 | ) | 11 | — | ||||||||||||||
|
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|
|
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|
|||||||||||
| Operating income |
952 | 903 | 49 | 878 | 25 | |||||||||||||||
| Other income and expenses |
132 | 126 | 6 | 91 | 35 | |||||||||||||||
| Noncontrolling interests |
101 | 81 | 20 | 75 | 6 | |||||||||||||||
|
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|
|
|||||||||||
| EBIT |
$ | 983 | $ | 948 | $ | 35 | $ | 894 | $ | 54 | ||||||||||
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|||||||||||
| Proportional throughput, TBtu (a) |
2,770 | 2,708 | 62 | 2,574 | 134 | |||||||||||||||
| (a) | Revenues are not significantly affected by pipeline throughput fluctuations, since revenues are primarily composed of demand charges. |
2011 Compared to 2010
Operating Revenues. The $79 million increase was driven by:
| • | a $136 million increase from expansion projects and the acquisitions of Bobcat in August 2010 and Big Sandy in July 2011, partially offset by |
| • | a $24 million decrease in recoveries of electric power and other costs passed through to customers, |
| • | a $24 million decrease from lower contracted volumes and rates as a result of contract renewals mainly at Ozark Gas Transmission and Algonquin, and |
| • | a $10 million decrease in processing revenues associated with pipeline operations caused by lower volumes. |
Operating, Maintenance and Other. The $13 million increase was driven by:
| • | a $20 million increase from acquisitions and expansion projects, |
| • | an $11 million increase in project development costs due to $6 million of costs expensed in 2011 and $5 million capitalized in 2010 from costs that were previously expensed in 2009, and |
| • | a $9 million increase in equipment repair and maintenance expenses, pipeline integrity costs, and software costs, partially offset by |
| • | a $27 million decrease in electric power and other costs passed through to customers. |
Depreciation and Amortization. The $14 million increase was mainly driven by expansion projects placed in service in 2010 and the acquisitions of Bobcat and Big Sandy.
Other Income and Expenses. The $6 million increase was primarily due to an indemnification of a tax liability related to the Bobcat acquisition.
Noncontrolling Interests. The $20 million increase was driven by an increase in the noncontrolling ownership interests resulting from the Spectra Energy Partners public sales of additional partner units in December 2010 and June 2011, and higher earnings from Spectra Energy Partners, as a result of their acquisitions of an additional 24.5% in Gulfstream in the fourth quarter 2010 and Big Sandy in July 2011.
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Index to Financial Statements
EBIT. The $35 million increase was primarily due to higher earnings from expansion projects, partially offset by higher operating expenses and lower contracted volumes and rates at Ozark Gas Transmission and Algonquin.
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 (AFUDC) 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.
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.
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.
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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.
Our interstate pipeline operations are subject to pipeline safety regulation administered by 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.
On January 3, 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 was signed into law. This Act amends the Pipeline Safety Act in a number of significant ways, including:
| • | Authorizing PHMSA to assess higher penalties for violations of its regulations, |
| • | Requiring PHMSA to adopt appropriate regulations within two years requiring the use of automatic or remote-controlled shutoff valves on new or rebuilt pipeline facilities and to perform a study on the application of such technology to existing pipeline facilities in High Consequence Areas (HCAs), |
| • | Requiring operators of pipelines to verify maximum allowable operating pressure and report exceedances within five days, |
| • | Requiring PHMSA to study and report on the adequacy of soil cover requirements in HCAs, and |
| • | Requiring PHMSA to evaluate in detail whether integrity management requirements should be expanded to pipeline segments outside of HCAs (where the requirements currently apply). |
In August 2011, PHMSA initiated an Advance Notice of Proposed Rulemaking announcing its consideration of substantial revisions in its regulations to increase pipeline safety. PHMSA also has issued an Advisory Bulletin which among other things, advises pipeline operators that if they are relying on design, construction, inspection, testing, or other data to determine the pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. These legislative and regulatory changes, when implemented, will impose additional costs on new pipeline projects as well as on existing operations. Because the extent of the new requirements and the timing of their application is still uncertain, we cannot reasonably determine the impacts that these changes will have on our operations, earnings, financial condition and cash flows at this time.
Distribution
| 2011 | 2010 | Increase (Decrease) |
2009 | Increase (Decrease) |
||||||||||||||||
| (in millions, except where noted) | ||||||||||||||||||||
| Operating revenues |
$ | 1,831 | $ | 1,779 | $ | 52 | $ | 1,745 | $ | 34 | ||||||||||
| Operating expenses |
||||||||||||||||||||
| Natural gas purchased |
760 | 770 | (10 | ) | 878 | (108 | ) | |||||||||||||
| Operating, maintenance and other |
441 | 406 | 35 | 358 | 48 | |||||||||||||||
| Depreciation and amortization |
208 | 194 | 14 | 172 | 22 | |||||||||||||||
|
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|
|
|
|
|
|
|||||||||||
| Operating income |
422 | 409 | 13 | 337 | 72 | |||||||||||||||
| Other income and expenses |
3 | — | 3 | (1 | ) | 1 | ||||||||||||||
|
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|
|
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|
|||||||||||
| EBIT |
$ | 425 | $ | 409 | $ | 16 | $ | 336 | $ | 73 | ||||||||||
|
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|
|
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|
|
|||||||||||
| Number of customers, thousands |
1,360 | 1,344 | 16 | 1,325 | 19 | |||||||||||||||
| Heating degree days, Fahrenheit |
7,122 | 6,832 | 290 | 7,435 | (603 | ) | ||||||||||||||
| Pipeline throughput, TBtu |
846 | 913 | (67 | ) | 809 | 104 | ||||||||||||||
| Canadian dollar exchange rate, average |
0.99 | 1.03 | (0.04 | ) | 1.14 | (0.11 | ) | |||||||||||||
45
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Index to Financial Statements
2011 Compared to 2010
Operating Revenues. The $52 million increase was driven mainly by:
| • | a $115 million increase in customer usage of natural gas primarily due to weather that was more than 4% colder than in 2010, |
| • | a $68 million increase resulting from a stronger Canadian dollar, |
| • | a $15 million increase from growth in the number of customers, and |
| • | a $10 million increase in short-term transportation revenue due to higher exchange revenue, partially offset by |
| • | a $136 million decrease from lower natural gas prices passed through to customers. Prices charged to customers are adjusted quarterly based on the 12 month New York Mercantile Exchange (NYMEX) forecast, |
| • | a $12 million decrease from higher earnings to be shared with customers, and |
| • | a $7 million decrease primarily due to lower storage prices. |
Natural Gas Purchased. The $10 million decrease was driven mainly by:
| • | a $136 million decrease from lower natural gas prices passed through to customers, and |
| • | a $5 million decrease in fuel and operating costs, partially offset by |
| • | a $102 million increase due to higher volumes of natural gas sold primarily as a result of weather that was more than 4% colder than in 2010, |
| • | a $28 million increase resulting from a stronger Canadian dollar, and |
| • | a $9 million increase from growth in the number of customers. |
Operating, Maintenance and Other. The $35 million increase was driven mainly by:
| • | a $21 million increase primarily due to higher employee benefits costs, and |
| • | a $17 million increase resulting from a stronger Canadian dollar. |
Depreciation and Amortization. The $14 million increase was driven primarily by a stronger Canadian dollar.
EBIT. The $16 million increase was mainly a result of a stronger Canadian dollar, higher customer usage of natural gas in core market, growth in the number of customers and higher short-term transportation revenue. These increases were partially offset by higher employee benefit costs, higher earnings to be shared with customers and lower storage prices.
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 |
46
Table of Contents
Index to Financial Statements
| • | 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 adjusted quarterly based on the 12 month NYMEX forecast, and |
| • | a $14 million decrease in customer usage of natural gas due to weather that was more than 8% warmer than in 2009. |
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.
Matters Affecting Future Distribution Results
We expect that the long-term demand for natural gas in North America will continue to grow. Furthermore, we expect growth related to the conversion of coal-fired generation to natural gas as Ontario policy continues to support the elimination of coal-fired generation by the end of 2014. However, growth outside of the power market driven by continued lower natural gas prices is expected to be offset in the near term by lower distribution throughput as a result of energy conservation initiatives.
Union Gas made an initial filing in 2011 to begin the OEB review process that will result in new rates for 2013. This filing included updated revenue and cost forecasts, as well as revised assumptions about ROE. Union Gas plans to file its application for a new multi-year incentive regulation framework after receiving the OEB decision on its 2013 rate application.
Natural gas storage prices have recently been challenged as a result of increasing natural gas supply and narrower seasonal price spreads. Gas supply and demand dynamics continue to change as a result of the development of new unconventional shale gas supplies. These market factors will continue to affect Union Gas’ unregulated storage and regulated transportation revenues in the near term.
During the past several years, 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.
47
Table of Contents
Index to Financial Statements
Western Canada Transmission & Processing
| 2011 | 2010 | Increase (Decrease) |
2009 | Increase (Decrease) |
||||||||||||||||
| (in millions, except where noted) | ||||||||||||||||||||
| Operating revenues |
$ | 1,672 | $ | 1,345 | $ | 327 | $ | 1,115 | $ | 230 | ||||||||||
| Operating expenses |
||||||||||||||||||||
| Natural gas and petroleum products purchased |
432 | 290 | 142 | 222 | 68 | |||||||||||||||
| Operating, maintenance and other |
565 | 486 | 79 | 407 | 79 | |||||||||||||||
| Depreciation and amortization |
186 | 169 | 17 | 144 | 25 | |||||||||||||||
| Loss on sales of other assets and other, net |
— | (1 | ) | 1 | — | (1 | ) | |||||||||||||
|
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|
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|
|
|||||||||||
| Operating income |
489 | 399 | 90 | 342 | 57 | |||||||||||||||
| Other income and expenses |
21 | 10 | 11 | 1 | 9 | |||||||||||||||
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|||||||||||
| EBIT |
$ | 510 | $ | 409 | $ | 101 | $ | 343 | $ | 66 | ||||||||||
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|||||||||||
| Pipeline throughput, TBtu |
713 | 627 | 86 | 604 | 23 | |||||||||||||||
| Volumes processed, TBtu |
728 | 664 | 64 | 655 | 9 | |||||||||||||||
| Empress inlet volumes, TBtu |
619 | 600 | 19 | 737 | (137 | ) | ||||||||||||||
| Canadian dollar exchange rate, average |
0.99 | 1.03 | (0.04 | ) | 1.14 | (0.11 | ) | |||||||||||||
2011 Compared to 2010
Operating Revenues. The $327 million increase was driven by:
| • | an $81 million increase in gathering and processing revenues due primarily to contracted volumes from expansions associated with non-conventional supply discoveries in the Fort Nelson area, |
| • | a $62 million increase as a result of a stronger Canadian dollar, |
| • | a $60 million increase due to higher NGL sales prices associated with the Empress operations, |
| • | a $51 million increase in sales volumes of residual natural gas primarily to Union Gas at Empress, |
| • | a $33 million increase due to higher NGL sales volumes associated with the Empress operations resulting primarily from the effect of the scheduled plant turnaround in 2010. |
| • | a $25 million increase due to higher costs of service recovered from transportation customers, and |
| • | a $23 million increase from recovery of carbon and other non-income tax expense from customers. |
Natural Gas and Petroleum Products Purchased. The $142 million increase was driven by:
| • | a $71 million increase due primarily to increased volumes of natural gas purchases for extraction and make-up at Empress, |
| • | a $65 million increase as a result of higher prices of natural gas and other petroleum products purchased for the Empress facility caused primarily by higher extraction premiums, and |
| • | a $13 million increase due to a stronger Canadian dollar. |
Operating, Maintenance and Other. The $79 million increase was driven by:
| • | a $23 million increase in carbon and other non-income tax expense, |
| • | a $22 million increase due to a stronger Canadian dollar, |
| • | a $21 million increase due primarily to higher costs of service passed through to transportation customers, and |
| • | a $7 million increase due primarily to higher maintenance costs. |
48
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Index to Financial Statements
Depreciation and Amortization. The $17 million increase was driven mainly by expansion projects placed in service and maintenance capital incurred, as well as a stronger Canadian dollar.
Other Income and Expenses. The $11 million increase was driven primarily by higher AFUDC resulting from higher capital spent on expansion projects.
EBIT. The $101 million increase was driven mainly by higher gathering and processing earnings from expansions, and a stronger Canadian dollar.
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.
49
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Index to Financial Statements
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 and incremental transportation capacity to support drilling activity in northern British Columbia as well as future LNG exports. 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 gas flows eastbound beyond Empress, costs of acquiring natural gas and NGL extraction rights, and NGL prices.
During the past several years, 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.
While current drilling levels are below recent historical averages, the relatively higher productivity of unconventional wells has led to increased production supporting continued growth of Western Canada Transmission & Processing’s gathering and processing business in the areas of British Columbia and Alberta where unconventional gas development is prevalent.
In certain areas of Western Canada Transmission & Processing’s operations served by conventional supply, lower natural gas prices resulting from increasing North American gas production have reduced producer demand for both expansions of the British Columbia conventional gas processing plants as well as renewals of existing gas processing contracts, and could continue to do so as long as gas prices remain below historical norms.
Field Services
| 2011 | 2010 | Increase (Decrease) |
2009 | Increase (Decrease) |
||||||||||||||||
| (in millions, except where noted) | ||||||||||||||||||||
| Equity in earnings of unconsolidated affiliates |
$ | 449 | $ | 335 | $ | 114 | $ | 296 | $ | 39 | ||||||||||
|
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|
|
|||||||||||
| EBIT |
$ | 449 | $ | 335 | $ | 114 | $ | 296 | $ | 39 | ||||||||||
|
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|||||||||||
| Natural gas gathered and processed/transported, TBtu/d (a,b) |
7.0 | 6.9 | 0.1 | 6.9 | — | |||||||||||||||
| NGL production, MBbl/d (a,c) |
383 | 369 | 14 | 358 | 11 | |||||||||||||||
| Average natural gas price per MMBtu (d) |
$ | 4.04 | $ | 4.39 | $ | (0.35 | ) | $ | 3.99 | $ | 0.40 | |||||||||
| Average NGL price per gallon (e) |
$ | 1.21 | $ | 0.98 | $ | 0.23 | $ | 0.71 | $ | 0.27 | ||||||||||
| Average crude oil price per barrel (f) |
$ | 95.12 | $ | 79.53 | $ | 15.59 | $ | 61.81 | $ | 17.72 | ||||||||||
| (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. |
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2011 Compared to 2010
EBIT. Higher equity earnings of $114 million were mainly the result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:
| • | a $152 million increase from commodity-sensitive processing arrangements due to increased NGL and crude oil prices, net of decreased natural gas prices, |
| • | a $20 million increase attributable to a decrease in interest expense due to favorable rates during 2011, |
| • | an $11 million increase attributable to decreased income tax expense related to the de-recognition of certain deferred tax assets in the 2010 period, and |
| • | a $9 million increase in earnings from DCP Partners as a result of growth and mark-to-market gains on derivative instruments used to protect distributable cash flows, partially offset by |
| • | a $64 million decrease due to higher operating expenses largely resulting from DCP Partners’ growth from acquisitions, increased repairs and maintenance costs and increased benefits costs, and |
| • | a $13 million decrease as a result of a gain of $30 million in 2010 associated with the issuance of partnership units by DCP Partners compared to a gain of $17 million in 2011. |
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 NGL, crude oil and natural gas 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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Supplemental Data
Below is supplemental information for DCP Midstream’s operating results (presented at 100%):
| 2011 | 2010 | 2009 | ||||||||||
| (in millions) | ||||||||||||
| Operating revenues |
$ | 12,982 | $ | 10,981 | $ | 8,560 | ||||||
| Operating expenses |
11,868 | 10,138 | 8,026 | |||||||||
|
|
|
|
|
|
|
|||||||
| Operating income |
1,114 | 843 | 534 | |||||||||
| Other income and expenses |
26 | 34 | 24 | |||||||||
| Interest expense, net |
213 | 253 | 254 | |||||||||
| Income tax expense (benefit) |
3 | 5 | (2 | ) | ||||||||
|
|
|
|
|
|
|
|||||||
| Net income |
924 | 619 | 306 | |||||||||
| Net income (loss)—noncontrolling interests |
61 | 27 | (16 | ) | ||||||||
|
|
|
|
|
|
|
|||||||
| Net income attributable to members’ interests |
$ | 863 | $ | 592 | $ | 322 | ||||||
|
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|
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|
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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 $17 million in 2011, $30 million in 2010 and $135 million in 2009 were recorded in Equity in Earnings of Unconsolidated Affiliates in the Consolidated Statement of Operations.
Matters Affecting Future Field Services Results
Drilling levels vary by geographic area, but in general, drilling remains robust in areas with a high content of liquids in the gas stream and crude drilling with associated gas production. In other areas, drilling continues to remain relatively modest. In addition, advances in technology, such as horizontal drilling and hydraulic fracturing in shale plays, have led to certain geographic areas becoming increasingly accessible. NGL production increased during 2011 as compared to 2010 due to drilling occurring in liquids-rich areas. Gas prices currently remain modest due to the increased supply, high inventory, warm winter weather 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 “long” natural gas and NGL positions. 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 drilling.
Other
| 2011 | 2010 | Increase (Decrease) |
2009 | Increase (Decrease) |
||||||||||||||||
| (in millions) | ||||||||||||||||||||
| Operating revenues |
$ | 72 | $ | 58 | $ | 14 | $ | 47 | $ | 11 | ||||||||||
| Operating expenses |
170 | 95 | 75 | 130 | (35 | ) | ||||||||||||||
|
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|
|
|
|
|
|||||||||||
| Operating loss |
(98 | ) | (37 | ) | (61 | ) | (83 | ) | 46 | |||||||||||
| Other income and expenses |
(6 | ) | (1 | ) | (5 | ) | 9 | (10 | ) | |||||||||||
|
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|
|
|
|||||||||||
| EBIT |
$ | (104 | ) | $ | (38 | ) | $ | (66 | ) | $ | (74 | ) | $ | 36 | ||||||
|
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2011 Compared to 2010
EBIT. The $66 million decrease in EBIT reflects a prior-year benefit of $31 million related to an early termination notice made by Westcoast for capacity contracts held on the Alliance pipeline, an increase in reserves of $14 million for captive insurance for miscellaneous loss events and higher corporate costs, including employee and retiree benefit costs, partially offset by an expense in the 2010 period for resolution of a corporate legal matter.
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.
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 the 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.
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 or for instances where the regulator provides current rates that are intended to recover costs that are expected to be incurred in the future. 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, which primarily relate to the future collection of deferred income tax costs for our Canadian regulated operations, 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 $1,142 million as of December 31, 2011 and $1,061 million as of December 31, 2010. Total regulatory liabilities were $562 million as of December 31, 2011 and $559 million as of December 31, 2010.
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In 2009, we recorded $18 million of pre-tax 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.
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 2011, 2010 or 2009.
We had goodwill balances of $4,420 million at December 31, 2011 and $4,305 million at December 31, 2010. The increase in goodwill in 2011 was primarily the result of $194 million of goodwill at U.S. Transmission associated with the acquisition of Big Sandy in July 2011. 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 capacity on our pipeline systems primarily as a result of forecasted growth in natural gas-fired power plants. We assumed a weighted-average long-term growth rate of 3.7% for our 2011 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 still 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 as a result of lower long-term projections of natural gas conversions and sustained mild economic growth in this region and therefore has a higher sensitivity to growth rate declines. Approximately $855 million of goodwill is allocated to our Distribution segment as of December 31, 2011.
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 2011 goodwill impairment analysis, we assumed weighted-average costs of capital ranging from 7.0% to 8.2% 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 still 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, 2011 exceeded their carrying values. No triggering events or changes in circumstances occurred during the period April 1, 2011 (our testing date) through December 31, 2011 that would warrant re-testing for goodwill impairment.
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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 used in the accounting for pension and other post-retirement benefits are the expected long-term rate of return on plan assets, the assumed discount rate, and medical and prescription drug cost trend rate assumptions.
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 partially 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 2011, the assumed average return was 7.00% for both the U.S. and Canadian pension plan assets and 6.25% 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 $1 million before tax for U.S. plans, and by approximately $2 million before tax for Canadian plans. 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 of cash outflows approximate the estimated payouts of the plans. The average discount rates of 4.85% for the U.S. plans and 5.26% for the Canadian plans used to calculate 2011 plan expenses represent a weighted average of the applicable rates. The applied discount rates decreased approximately 1% in 2011 compared to 2010, resulting in a significant increase in total benefit liabilities. A 25 basis-point change in the discount rates would not impact annual benefit expense for U.S. plans, but would inversely impact annual benefit expense for Canadian plans 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 2012. As of December 31, 2011, we had negative working capital of $1,337 million. This balance includes short-term borrowings and commercial paper totaling $1,052 million and current maturities of long-term debt of $525 million. We have access to four revolving credit facilities, with total combined capital commitments of approximately $2.9 billion, with approximately $1.8 billion available at December 31, 2011. These facilities are
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Index to Financial Statements
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, Spectra Energy Partners 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 Note 15 of Notes to Consolidated Financial Statements for a discussion of available credit facilities and Financing Cash Flows and Liquidity for a discussion of effective shelf registrations.
Our consolidated capital structure includes short-term borrowings and commercial paper, long-term debt (including current maturities), preferred stock of subsidiaries and total equity. As of December 31, 2011, 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 100%-owned and majority-owned 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 including DCP Midstream and Gulfstream, 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, mostly 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 mostly 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 $395 million in 2011, $288 million in 2010 and $101 million in 2009. These distributions are classified within Operating 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.
In addition, cash flows from our Canadian operations are generally used to fund the ongoing Canadian businesses and future Canadian growth, in particular the significant expansion opportunities underway in western Canada. At December 31, 2011, $165 million of Cash and Cash Equivalents was held by our Canadian subsidiaries. Historically, we have reinvested a substantial portion of our Canadian operations’ earnings in Canada. Earnings not needed by our Canadian operations have been distributed to Spectra Energy Corp (the U.S. parent) with minimal incremental U.S. tax liability. Distributions have typically been in the range of $100 million to $300 million per year. We anticipate continued substantial reinvestment of our future Canadian earnings in Canada, however, future distributions to Spectra Energy Corp may incur incremental U.S. tax at the U.S. statutory rate without the ability to use foreign tax credits. The timing of when distributions may incur such incremental U.S. tax depends on many factors, such as amount of future capital expansions in Canada, the tax characterization of our distributions as returns of capital or dividends, the impacts of tax planning on merger and acquisition activities and tax legislation at the time of the distributions.
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. Although market values have recovered since then, we made contributions to our defined benefit employee retirement plans of $165 million in 2011 to further decrease the underfunded status of these plans. Future changes in plan asset returns, assumed discount rates and various other factors related to the participants in our pension plans will impact future pension expense and funding.
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As we execute on our strategic objectives around organic growth and expansion projects, expansion expenditures are expected to approximate $1.3 billion in 2012 and will continue to average between $1.0 billion to $1.5 billion per year in 2013 and 2014. 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 and earnings growth 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 increased $778 million to $2,186 million in 2011 compared to 2010. This change was driven mostly by:
| • | lower refunds to Union Gas customers in 2011 for gas purchase costs collected in 2010 compared to refunds in 2010 for collections in 2009, |
| • | lower net tax payments in 2011 primarily as a result of the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 which deferred a significant amount of tax payments to future periods, and |
| • | higher earnings across all segments in 2011, partially offset by increased pension plan contributions in 2011. |
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. |
Investing Cash Flows
Net cash flows used in investing activities was $2,098 million in 2011 compared to $2,101 million in 2010. This change was driven mostly by:
| • | a $563 million increase in capital and investment expenditures in 2011, and |
| • | a $390 million cash outlay in 2011 for the acquisition of Big Sandy, partially offset by |
| • | a $492 million cash outlay in 2010 for the acquisition of Bobcat, and |
| • | $190 million of net proceeds from sales and maturities of available-for-sale securities in 2011 compared to $216 million of net purchases in 2010. |
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, |
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| • | 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. |
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 received a $148 million special distribution from 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.
| 2011 | 2010 | 2009 | ||||||||||
| (in millions) | ||||||||||||
| Capital and Investment Expenditures (a) |
||||||||||||
| U.S. Transmission |
$ | 773 | $ | 641 | $ | 432 | ||||||
| Distribution |
292 | 227 | 224 | |||||||||
| Western Canada Transmission & Processing |
776 | 449 | 353 | |||||||||
| Other |
78 | 39 | 32 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total consolidated |
$ | 1,919 | $ | 1,356 | $ | 1,041 | ||||||
|
|
|
|
|
|
|
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| (a) | Excludes the acquisitions of Big Sandy ($390 million) in 2011, Bobcat ($492 million) in 2010 and Ozark ($295 million) in 2009. See Note 4 of Notes to Consolidated Financial Statements for further discussion. |
Capital and investment expenditures for 2011 totaled $1,919 million and included $1,139 million for expansion projects and $780 million for maintenance and other projects. We project 2012 capital and investment expenditures of approximately $2.0 billion, consisting of approximately $1.1 billion for U.S. Transmission, $0.3 billion for Distribution and $0.6 billion for Western Canada Transmission & Processing. Total projected 2012 capital and investment expenditures include approximately $1.3 billion of expansion capital expenditures and $0.7 billion for maintenance and upgrades of existing plants, pipelines and infrastructure to serve growth.
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 2011, including:
| • | TEMAX / Time III—Phase II—The final part of a two-phased expansion on the Texas Eastern pipeline system from 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. |
| • | Hot Spring Lateral Project—Expansion of the Texas Eastern system to transport 112 MMcf/d to a gas-fired power plant in Arkansas. |
| • | Moss Bluff Cavern 4—Storage capacity increased as part of the multi-year Market Hub storage expansion program. |
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| • | Egan Cavern 3 Storage—Storage capacity increased as part of the multi-year Market Hub storage expansion program. |
| • | Northeastern Tennessee Project—Expansion of the East Tennessee system to transport 150 MMcf/d to a gas-fired power plant in northeast Tennessee. |
| • | Gulfstream Phase V—200 MMcf/d capacity expansion of the existing Gulfstream system through horsepower additions at two compressor stations. We are a 50% partner in the facilities. |
| • | Fort Nelson Expansion Program—An approximate 800 MMcf/d expansion of the Fort Nelson system in western Canada. Pipeline capacity expansions in northern British Columbia were completed in 2011 allowing increased volumes to flow to existing processing facilities. |
Significant 2012 expansion projects expenditures are expected to include:
| • | Fort Nelson Expansion Program—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 scheduled to be in service during the first half of 2012. |
| • | Transmission North Project—170 MMcf/d expansion of existing western Canada transmission capacity through pipeline looping, construction of a new delivery line, a compressor upgrade at an existing station and construction of a new compressor facility, all in British Columbia. In-service scheduled for first half of 2012. |
| • | Dawson Expansion—The development of a sour gas processing plant and an additional pipeline in western Canada. Phase I of 100 MMcf/d will be in service in the first half of 2012 and Phase II for an additional 100 MMcf/d is scheduled to be in service by the first half of 2013. |
| • | Fort Nelson North Montney Takeaway—360 MMcf/d expansion of the Fort Nelson Mainline consisting of 24 kilometers of pipeline looping and compressor station modifications. In-service schedule for second half of 2012. |
| • | TEAM 2012—200 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 to markets in the U.S. Northeast. In-service scheduled for the second half of 2012. |
| • | New Jersey-New York Expansion—Proposed 800 MMcf/d expansion of the Texas Eastern pipeline system consisting of a new 16-mile pipeline extension into lower Manhattan, New York and other associated facility upgrades. The project is designed to transport gas produced in the U.S. Gulf Coast, Mid-Continent, Rockies and Marcellus Shale regions into New York City. In-service is scheduled for late fourth quarter of 2013. |
| • | Bobcat Storage—The development of an additional 19.8 Bcf working gas storage cavern along with above-ground facilities in Southern Louisiana. Phased in service from 2012 through 2015 is planned. |
Financing Cash Flows and Liquidity
During 2011, we identified certain immaterial errors in our previously issued Consolidated Statements of Cash Flows related to the accounting for rollovers of outstanding borrowings under our revolving bank credit facilities. The following discussion reflects the correction of these immaterial errors and also a change in the presentation of cash borrowings and repayments under these facilities. See Note 2 of Notes to Consolidated Financial Statements for further discussion.
Net cash used in financing activities totaled $35 million in 2011 compared to $656 million provided by financing activities in 2010. This $691 million change was driven mostly by:
| • | a $240 million increase in short-term borrowings and commercial paper outstanding in 2011 compared to a $669 million increase in 2010, and |
| • | $288 million of net debt issuances in 2011, including net revolving credit facility borrowings, compared to $483 million of net issuances in 2010. |
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Net cash provided by financing activities totaled $656 million in 2010 compared to $803 million used in financing activities 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 debt issuances in 2010, which included net revolving credit facilities borrowings and a 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. |
Significant Financing Activities—2011
Debt Issuances. The following long-term debt issuances were completed during 2011 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) | ||||||||||||
| Spectra Energy Partners |
$ | 250 | 2.95 | % | 2016 | |||||||
| Spectra Energy Partners |
250 | 4.60 | % | 2021 | ||||||||
| Westcoast |
151 | (a) | 3.883 | % | 2021 | |||||||
| Westcoast |
151 | (a) | 4.791 | % | 2041 | |||||||
| Union Gas |
309 | (a) | 4.88 | % | 2041 | |||||||
| (a) | U.S. dollar equivalent at time of issuance. |
Spectra Energy Partners Common Unit Issuance. In June 2011, Spectra Energy Partners issued 7.2 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 were $218 million (net proceeds to Spectra Energy were $213 million), used to fund a portion of the acquisition of Big Sandy.
Significant Financing Activities—2010
Debt Issuances. The following long-term debt issuances were completed during 2010:
| 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. |
Spectra Energy Partners Common Unit 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
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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 long-term 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.
Spectra Energy Corp Common Stock Issuance. In 2009, in order to further protect our capitalization structure against a potential extreme decline in the Canadian dollar, Spectra Energy Corp issued 32.2 million shares of its 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.
Available Credit Facilities and Restrictive Debt Covenants
| Expiration Date |
Credit Facilities Capacity |
Outstanding at December 31, 2011 | Available Credit Facilities Capacity |
|||||||||||||||||||||||||
| Commercial Paper |
Revolving Credit |
Letters of Credit |
Total | |||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||||
| Spectra Capital (a) |
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| Multi-year syndicated |
2016 | $ | 1,500 | $ | 751 | $ | — | $ | 6 | $ | 757 | $ | 743 | |||||||||||||||
| Westcoast (b) |
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| Multi-year syndicated |
2016 | 294 | — | — | — | — | 294 | |||||||||||||||||||||
| Union Gas (c) |
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| Multi-year syndicated |
2016 | 392 | 274 | — | — | 274 | 118 | |||||||||||||||||||||
| Spectra Energy Partners (d) |
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| Multi-year syndicated |
2016 | 700 | 27 | — | — | 27 | 673 | |||||||||||||||||||||
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| Total |
$ | 2,886 | $ | 1,052 | $ | — | $ | 6 | $ | 1,058 | $ | 1,828 | ||||||||||||||||
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| (a) | Credit facility contains a covenant requiring our consolidated debt-to-total capitalization ratio, as defined in the agreement, to not exceed 65%. This ratio was 59% at December 31, 2011. |
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| (b) | U.S. dollar equivalent at December 31, 2011. The credit facility is 300 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 43% at December 31, 2011. |
| (c) | U.S. dollar equivalent at December 31, 2011. The credit facility is 400 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, 2011. |
| (d) | Credit facility contains a covenant that requires Spectra Energy Partners to maintain a ratio of total Debt-to-Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA), as defined in the credit agreement, of 5.0 or less. As of December 31, 2011, this ratio was 2.7. Adjusted EBITDA is a non-GAAP measure. Because Adjusted EBITDA excludes some, but not all, items that affect net income and is defined differently by companies in our industry, Spectra Energy Partners’ definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies. Adjusted EBITDA should not be considered an alternative to net income, operating income, cash from operations or any other measure of financial performance or liquidity presented in accordance with GAAP. |
The issuance of commercial paper, letters of credit and other borrowings reduces the amount available under the credit facilities.
During 2011, we executed the following new five-year credit facilities which replaced other credit facilities that were due to expire at various times in 2011 and 2012: a $1.5 billion facility at Spectra Capital, a $700 million facility at Spectra Energy Partners, a 400 million Canadian dollar facility at Union Gas (approximately $392 million at December 31, 2011) and a 300 million Canadian dollar facility at Westcoast (approximately $294 million at December 31, 2011).
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, 2011, we were in compliance with those 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, as defined in the agreement, to be 65% or lower. Per the terms of the new agreement, collateralized debt and Spectra Energy Partners’ debt and capitalization are excluded in the calculation of the ratio. This ratio was 59% at December 31, 2011. 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, 2011, 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, 2012 |
||||||||
| 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 | ||||
| Spectra Energy Partners (a) |
BBB | Baa3 | BBB | n/a |
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| (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. Our near-term objective is to increase our dividend by at least $0.08 per year and to continue paying cash dividends in the future. In the long-term, we anticipate paying dividends at an average payout ratio level of between 60%-65% of our 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 $0.28 per common share was declared on January 4, 2012 and will be paid on March 12, 2012.
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 also has an effective shelf registration statement on file with the SEC to register the issuance of unspecified amounts of limited partner common units and various debt securities. In addition, as of December 31, 2011, certain of our subsidiaries in Canada have 1.2 billion Canadian dollars (approximately $1.1 billion) available for issuance in the Canadian market under debt shelf prospectuses that expire in October 2012.
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 100%-owned entities, enabling them to conduct business. As such, these guarantee arrangements involve elements of performance and credit risk which are not included on our 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.
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 DCP Midstream and our other equity investments. For additional information on these commitments, see Notes 19 and 20 of Notes to Consolidated Financial Statements.
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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, 2011 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 2012.
Contractual Obligations as of December 31, 2011
| Payments Due By Period | ||||||||||||||||||||
| Total | 2012 | 2013 & 2014 |
2015 & 2016 |
2017 & Beyond |
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| (in millions) | ||||||||||||||||||||
| Long-term debt (a) |
$ | 17,057 | $ | 1,185 | $ | 3,215 | $ | 2,007 | $ | 10,650 | ||||||||||
| Operating leases (b) |
305 | 46 | 83 | 61 | 115 | |||||||||||||||
| Purchase Obligations: (c) |
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| Firm capacity payments (d) |
882 | 277 | 251 | 166 | 188 | |||||||||||||||
| Energy commodity contracts (e) |
427 | 368 | 41 | 18 | — | |||||||||||||||
| Other purchase obligations (f) |
323 | 160 | 77 | 49 | 37 | |||||||||||||||
| Other long-term liabilities on the Consolidated Balance Sheet (g) |
120 | 120 | — | — | — | |||||||||||||||
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| Total contractual cash obligations |
$ | 19,114 | $ | 2,156 | $ | 3,667 | $ | 2,301 | $ | 10,990 | ||||||||||
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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, 2011. |
| (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 2012 retirement plan contributions and estimated 2012 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 2012 due to uncertainties in the timing of cash settlements with taxing authorities and cannot estimate retirement plan contributions beyond 2012 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. |
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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 the ownership of the NGL marketing operations in western Canada and the 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 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 2011, 2010 or 2009.
DCP Midstream manages their direct exposure to these market prices separate from Spectra Energy, and utilizes various risk management strategies, including the use of commodity derivatives.
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, 2011 and 2010, a 10¢ per-gallon move in NGL prices would affect our annual pre-tax earnings by approximately $70 million in 2012, primarily from Field Services, as compared with approximately $65 million in 2011. For the same periods, a 50¢ per-MMBtu move in natural gas prices would affect our annual pre-tax earnings by approximately $16 million in 2012 and $15 million in 2011, and a $10 per-barrel move in oil prices would affect our annual pre-tax earnings by approximately $22 million in 2012 and $25 million in 2011.
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.
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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, 2011.
Based on our policies for managing credit risk, our current exposures and our credit and other reserves, we do not anticipate a material effect on our consolidated financial position or results of operations as a result of non-performance by any counterparty.
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, 2011, 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 $1,695 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 interest payments related to our long-term fixed-rate debt securities into variable-rate interest payments in order to achieve our desired mix of fixed and variable-rate debt.
Based on a sensitivity analysis as of December 31, 2011, it was estimated that if short-term interest rates average 100 basis points higher (lower) in 2012 than in 2011, interest expense, net of offsetting impacts in interest income, would increase (decrease) by $24 million. Comparatively, based on a sensitivity analysis as of December 31, 2010, had short-term interest rates averaged 100 basis points higher (lower) in 2011 than in 2010, it was estimated that interest expense, net of offsetting interest income, would have fluctuated by approximately $23 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, 2011 and 2010.
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
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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 external investment advisors.
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.
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 2011 would have resulted in an estimated net loss on the translation of local currency earnings of approximately $53 million on our Consolidated Statement of Operation. In addition, if a 10% devaluation had occurred on December 31, 2011, the Consolidated Balance Sheet would have been negatively impacted by $641 million through a cumulative translation adjustment in AOCI. At December 31, 2011, one U.S. dollar translated into 1.02 Canadian dollars.
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 Durban, South Africa in December 2011 with the intent of defining a future agreement for 2012 and beyond. An non-binding agreement was reached to develop a road map aimed at creating a global agreement on climate action to be implemented by 2020.
In 2011, the Canadian government withdrew from the Kyoto Protocol. In 2008, the Canadian government 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.
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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, no decision has been made on whether to implement the program. 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 2011, 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.
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 began 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.
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.
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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.
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, 2011 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 reasonable assurance level as of December 31, 2011.
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, 2011 and 2010, 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, 2011. 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, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule and an opinion on the Company’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Spectra Energy Corp and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in
70
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Index to Financial Statements
conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, 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 27, 2012
71
Table of Contents
Index to Financial Statements
SPECTRA ENERGY CORP
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per-share amounts)
| Years Ended December 31, | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| Operating Revenues |
||||||||||||
| Transportation, storage and processing of natural gas |
$ | 3,139 | $ | 2,870 | $ | 2,565 | ||||||
| Distribution of natural gas |
1,481 | 1,450 | 1,451 | |||||||||
| Sales of natural gas liquids |
564 | 459 | 389 | |||||||||
| Other |
167 | 166 | 147 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total operating revenues |
5,351 | 4,945 | 4,552 | |||||||||
|
|
|
|
|
|
|
|||||||
| Operating Expenses |
||||||||||||
| Natural gas and petroleum products purchased |
1,142 | 1,056 | 1,098 | |||||||||
| Operating, maintenance and other |
1,415 | 1,278 | 1,144 | |||||||||
| Depreciation and amortization |
709 | 650 | 584 | |||||||||
| Property and other taxes |
330 | 297 | 262 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total operating expenses |
3,596 | 3,281 | 3,088 | |||||||||
|
|
|
|
|
|
|
|||||||
| Gains on Sales of Other Assets and Other, net |
8 | 10 | 11 | |||||||||
|
|
|
|
|
|
|
|||||||
| Operating Income |
1,763 | 1,674 | 1,475 | |||||||||
|
|
|
|
|
|
|
|||||||
| Other Income and Expenses |
||||||||||||
| Equity in earnings of unconsolidated affiliates |
549 | 430 | 369 | |||||||||
| Other income and expenses, net |
57 | 32 | 37 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total other income and expenses |
606 | 462 | 406 | |||||||||
|
|
|
|
|
|
|
|||||||
| Interest Expense |
625 | 630 | 610 | |||||||||
|
|
|
|
|
|
|
|||||||
| Earnings From Continuing Operations Before Income Taxes |
1,744 | 1,506 | 1,271 | |||||||||
| Income Tax Expense From Continuing Operations |
487 | 383 | 352 | |||||||||
|
|
|
|
|
|
|
|||||||
| Income From Continuing Operations |
1,257 | 1,123 | 919 | |||||||||
| Income From Discontinued Operations, net of tax |
25 | 6 | 5 | |||||||||
|
|
|
|
|
|
|
|||||||
| Net Income |
1,282 | 1,129 | 924 | |||||||||
| Net Income—Noncontrolling Interests |
98 | 80 | 75 | |||||||||
|
|
|
|
|
|
|
|||||||
| Net Income—Controlling Interests |
$ | 1,184 | $ | 1,049 | $ | 849 | ||||||
|
|
|
|
|
|
|
|||||||
| Common Stock Data |
||||||||||||
| Weighted-average shares outstanding |
||||||||||||
| Basic |
650 | 648 | 642 | |||||||||
| Diluted |
653 | 650 | 643 | |||||||||
| Earnings per share from continuing operations |
||||||||||||
| Basic |
$ | 1.78 | $ | 1.61 | $ | 1.31 | ||||||
| Diluted |
$ | 1.77 | $ | 1.60 | $ | 1.31 | ||||||
| Earnings per share |
||||||||||||
| Basic |
$ | 1.82 | $ | 1.62 | $ | 1.32 | ||||||
| Diluted |
$ | 1.81 | $ | 1.61 | $ | 1.32 | ||||||
| Dividends per share |
$ | 1.06 | $ | 1.00 | $ | 1.00 | ||||||
See Notes to Consolidated Financial Statements.
72
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Index to Financial Statements
SPECTRA ENERGY CORP
CONSOLIDATED BALANCE SHEETS
(In millions)
| December 31, | ||||||||
| 2011 | 2010 | |||||||
| ASSETS |
||||||||
| Current Assets |
||||||||
| Cash and cash equivalents |
$ | 174 | $ | 130 | ||||
| Receivables (net of allowance for doubtful accounts of $14 and $9 at December 31, 2011 and 2010, respectively) |
962 | 1,018 | ||||||
| Inventory |
393 | 287 | ||||||
| Other |
235 | 203 | ||||||
|
|
|
|
|
|||||
| Total current assets |
1,764 | 1,638 | ||||||
|
|
|
|
|
|||||
| Investments and Other Assets |
||||||||
| Investments in and loans to unconsolidated affiliates |
2,064 | 2,033 | ||||||
| Goodwill |
4,420 | 4,305 | ||||||
| Other |
530 | 665 | ||||||
|
|
|
|
|
|||||
| Total investments and other assets |
7,014 | 7,003 | ||||||
|
|
|
|
|
|||||
| Property, Plant and Equipment |
||||||||
| Cost |
23,932 | 22,162 | ||||||
| Less accumulated depreciation and amortization |
5,674 | 5,182 | ||||||
|
|
|
|
|
|||||
| Net property, plant and equipment |
18,258 | 16,980 | ||||||
|
|
|
|
|
|||||
| Regulatory Assets and Deferred Debits |
1,102 | 1,065 | ||||||
|
|
|
|
|
|||||
| Total Assets |
$ | 28,138 | $ | 26,686 | ||||
|
|
|
|
|
|||||
See Notes to Consolidated Financial Statements.
73
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Index to Financial Statements
SPECTRA ENERGY CORP
CONSOLIDATED BALANCE SHEETS
(In millions, except per-share amounts)
| December 31, | ||||||||
| 2011 | 2010 | |||||||
| LIABILITIES AND EQUITY |
||||||||
| Current Liabilities |
||||||||
| Accounts payable |
$ | 498 | $ | 369 | ||||
| Short-term borrowings and commercial paper |
1,052 | 836 | ||||||
| Taxes accrued |
82 | 59 | ||||||
| Interest accrued |
178 | 167 | ||||||
| Current maturities of long-term debt |
525 | 315 | ||||||
| Other |
766 | 777 | ||||||
|
|
|
|
|
|||||
| Total current liabilities |
3,101 | 2,523 | ||||||
|
|
|
|
|
|||||
| Long-term Debt |
10,146 | 10,169 | ||||||
|
|
|
|
|
|||||
| Deferred Credits and Other Liabilities |
||||||||
| Deferred income taxes |
3,940 | 3,555 | ||||||
| Regulatory and other |
1,797 | 1,694 | ||||||
|
|
|
|
|
|||||
| Total deferred credits and other liabilities |
5,737 | 5,249 | ||||||
|
|
|
|
|
|||||
| Commitments and Contingencies |
||||||||
| Preferred Stock of Subsidiaries |
258 | 258 | ||||||
|
|
|
|
|
|||||
| Equity |
||||||||
| Preferred stock, $0.001 par, 22 million shares authorized, no shares outstanding |
— | — | ||||||
| Common stock, $0.001 par, 1 billion shares authorized, 651 million and 649 million shares outstanding at December 31, 2011 and 2010, respectively |
1 | 1 | ||||||
| Additional paid-in capital |
4,814 | 4,726 | ||||||
| Retained earnings |
1,977 | 1,487 | ||||||
| Accumulated other comprehensive income |
1,273 | 1,595 | ||||||
|
|
|
|
|
|||||
| Total controlling interests |
8,065 | 7,809 | ||||||
| Noncontrolling interests |
831 | 678 | ||||||
|
|
|
|
|
|||||
| Total equity |
8,896 | 8,487 | ||||||
|
|
|
|
|
|||||
| Total Liabilities and Equity |
$ | 28,138 | $ | 26,686 | ||||
|
|
|
|
|
|||||
See Notes to Consolidated Financial Statements.
74
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Index to Financial Statements
SPECTRA ENERGY CORP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
| Years Ended December 31, | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES |
||||||||||||
| Net income |
$ | 1,282 | $ | 1,129 | $ | 924 | ||||||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||||||
| Depreciation and amortization |
725 | 664 | 598 | |||||||||
| Deferred income tax expense |
373 | 205 | 176 | |||||||||
| Equity in earnings of unconsolidated affiliates |
(549 | ) | (430 | ) | (369 | ) | ||||||
| Distributions received from unconsolidated affiliates |
499 | 391 | 195 | |||||||||
| Decrease (increase) in |
||||||||||||
| Receivables |
(15 | ) | (50 | ) | 143 | |||||||
| Inventory |
(99 | ) | 14 | 7 | ||||||||
| Other current assets |
(20 | ) | 4 | 69 | ||||||||
| Increase (decrease) in |
||||||||||||
| Accounts payable |
90 | (67 | ) | 35 | ||||||||
| Taxes accrued |
33 | (141 | ) | 78 | ||||||||
| Other current liabilities |
12 | (184 | ) | 33 | ||||||||
| Other, assets |
(42 | ) | (49 | ) | (62 | ) | ||||||
| Other, liabilities |
(103 | ) | (78 | ) | (67 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Net cash provided by operating activities |
2,186 | 1,408 | 1,760 | |||||||||
|
|
|
|
|
|
|
|||||||
| CASH FLOWS FROM INVESTING ACTIVITIES |
||||||||||||
| Capital expenditures |
(1,915 | ) | (1,346 | ) | (980 | ) | ||||||
| Investments in and loans to unconsolidated affiliates |
(4 | ) | (10 | ) | (61 | ) | ||||||
| Acquisitions, net of cash acquired |
(390 | ) | (492 | ) | (295 | ) | ||||||
| Purchases of held-to-maturity securities |
(1,695 | ) | (1,117 | ) | (231 | ) | ||||||
| Proceeds from sales and maturities of held-to-maturity securities |
1,709 | 1,068 | 110 | |||||||||
| Purchases of available-for-sale securities |
(953 | ) | (254 | ) | — | |||||||
| Proceeds from sales and maturities of available-for-sale securities |
1,143 | 38 | 32 | |||||||||
| Distributions received from unconsolidated affiliates |
17 | 17 | 164 | |||||||||
| Receipt from affiliate—repayment of loan |
— | — | 186 | |||||||||
| Other |
(10 | ) | (5 | ) | 54 | |||||||
|
|
|
|
|
|
|
|||||||
| Net cash used in investing activities |
(2,098 | ) | (2,101 | ) | (1,021 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| CASH FLOWS FROM FINANCING ACTIVITIES |
||||||||||||
| Proceeds from the issuance of long-term debt |
1,118 | 1,232 | 968 | |||||||||
| Payments for the redemption of long-term debt |
(531 | ) | (807 | ) | (864 | ) | ||||||
| Net increase (decrease) in short-term borrowings and commercial paper |
240 | 669 | (774 | ) | ||||||||
| Net increase (decrease) in revolving credit facilities borrowings |
(299 | ) | 58 | — | ||||||||
| Distributions to noncontrolling interests |
(101 | ) | (73 | ) | (174 | ) | ||||||
| Proceeds from the issuance of Spectra Energy common stock |
— | — | 448 | |||||||||
| Proceeds from the issuance of Spectra Energy Partners, LP common units |
213 | 216 | 208 | |||||||||
| Dividends paid on common stock |
(694 | ) | (650 | ) | (631 | ) | ||||||
| Other |
19 | 11 | 16 | |||||||||
|
|
|
|
|
|
|
|||||||
| Net cash provided by (used in) financing activities |
(35 | ) | 656 | (803 | ) | |||||||
|
|
|
|
|
|
|
|||||||
| Effect of exchange rate changes on cash |
(9 | ) | 1 | 25 | ||||||||
|
|
|
|
|
|
|
|||||||
| Net increase (decrease) in cash and cash equivalents |
44 | (36 | ) | (39 | ) | |||||||
| Cash and cash equivalents at beginning of period |
130 | 166 | 205 | |||||||||
|
|
|
|
|
|
|
|||||||
| Cash and cash equivalents at end of period |
$ | 174 | $ | 130 | $ | 166 | ||||||
|
|
|
|
|
|
|
|||||||
| Supplemental Disclosures |
||||||||||||
| Cash paid for interest, net of amount capitalized |
$ | 598 | $ | 615 | $ | 587 | ||||||
| Cash paid for income taxes |
76 | 312 | 100 | |||||||||
| Property, plant and equipment noncash accruals |
137 | 58 | 24 | |||||||||
See Notes to Consolidated Financial Statements.
75
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, 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 issued |
— | 448 | — | — | — | — | 448 | |||||||||||||||||||||
| Spectra Energy Partners, LP common units issued |
— | 25 | — | — | — | 168 | 193 | |||||||||||||||||||||
| Reclassification of deferred gain on sale of units of Spectra Energy Partners, LP |
— | 59 | — | — | — | — | 59 | |||||||||||||||||||||
| Distributions to noncontrolling interests |
— | — | — | — | — | (174 | ) | (174 | ) | |||||||||||||||||||
| Other, net |
— | 55 | — | — | — | (10 | ) | 45 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
| 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 | ) | — | — | — | (650 | ) | |||||||||||||||||||
| Stock-based compensation |
— | 36 | — | — | — | — | 36 | |||||||||||||||||||||
| Spectra Energy Partners, LP common units issued |
— | 50 | — | — | — | 140 | 190 | |||||||||||||||||||||
| Transfer of interest in Gulfstream to Spectra Energy Partners, LP |
— | 19 | — | — | — | (29 | ) | (10 | ) | |||||||||||||||||||
| Distributions to noncontrolling interests |
— | — | — | — | — | (73 | ) | (73 | ) | |||||||||||||||||||
| Other, net |
— | (24 | ) | — | — | (6 | ) | 4 | (26 | ) | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
| December 31, 2010 |
1 | 4,726 | 1,487 | 2,010 | (415 | ) | 678 | 8,487 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
| Net income |
— | — | 1,184 | — | — | 98 | 1,282 | |||||||||||||||||||||
| Other comprehensive income |
||||||||||||||||||||||||||||
| Foreign currency translation adjustments |
— | — | — | (178 | ) | — | (3 | ) | (181 | ) | ||||||||||||||||||
| Unrealized mark-to-market net loss on hedges |
— | — | — | — | (3 | ) | — | (3 | ) | |||||||||||||||||||
| Reclassification of cash flow hedges into earnings |
— | — | — | — | 9 | — | 9 | |||||||||||||||||||||
| Other |
— | — | — | — | 9 | 5 | 14 | |||||||||||||||||||||
| Pension and benefits impact |
— | — | — | — | (159 | ) | — | (159 | ) | |||||||||||||||||||
|
|
|
|||||||||||||||||||||||||||
| Total comprehensive income |
962 | |||||||||||||||||||||||||||
|
|
|
|||||||||||||||||||||||||||
| Dividends on common stock |
— | — | (694 | ) | — | — | — | (694 | ) | |||||||||||||||||||
| Stock-based compensation |
— | 18 | — | — | — | — | 18 | |||||||||||||||||||||
| Distributions to noncontrolling interests |
— | — | — | — | — | (101 | ) | (101 | ) | |||||||||||||||||||
| Spectra Energy common stock issued |
— | 32 | — | |||||||||||||||||||||||||