10-K 1 se-2015123110k.htm 10-K 10-K
 
 
 
 
 
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, 2015 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, 2015: $22,000,000,000
Number of shares of Common Stock, $0.001 par value, outstanding at January 31, 2016: 671,500,270
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement for the 2016 Annual Meeting of Shareholders are incorporated by reference in Part III.
 
 
 
 
 



SPECTRA ENERGY CORP
FORM 10-K FOR THE YEAR ENDED
DECEMBER 31, 2015
TABLE OF CONTENTS
 
Item
 
Page
 
PART I.
 
1.
 
 
 
 
 
 
 
 
 
 
 
 
 
1A.
1B.
2.
3.
4.
 
PART II.
 
5.
6.
7.
7A.
8.
9.
9A.
9B.
 
PART III.
 
10.
11.
12.
13.
14.
 
PART IV.
 
15.
 
 
 

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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 represent management’s intentions, plans, expectations, assumptions and beliefs about future events. 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 are subject to risks, uncertainties and other factors, many of which are outside our control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. Factors used to develop these forward-looking statements and that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:
state, provincial, 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 and oil 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 oil 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 and costs 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 United States and Canadian pipeline, storage, gathering, processing and other related infrastructure projects and the effects of competition;
the performance of natural gas and oil transmission and storage, distribution, and gathering and processing facilities;
the extent of success in connecting natural gas and oil supplies to gathering, processing and transmission systems and in connecting to expanding gas and oil markets;
the effects of accounting pronouncements issued periodically by accounting standard-setting bodies;
conditions of the capital markets during the periods covered by 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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Item 1. Business.
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. The term “Spectra Energy Partners” refers to our Spectra Energy Partners operating segment. The term “SEP” refers to Spectra Energy Partners, LP, our master limited partnership.
General
Spectra Energy, 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. We also own and operate a crude oil pipeline system that connects Canadian and United States (U.S.) producers to refineries in the U.S. Rocky Mountain and Midwest regions. For over 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 currently operate in three key areas of the natural gas industry: gathering and processing, transmission and storage, and distribution. We provide transmission and storage of natural gas to customers in various regions of the northeastern and southeastern U.S., the Maritime provinces in Canada, the Pacific Northwest in the U.S. 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. We also own a 50% interest in DCP Midstream, LLC (DCP Midstream), based in Denver, Colorado, one of the leading natural gas gatherers in the U.S., and one of the largest U.S. producers and marketers of natural gas liquids (NGLs). Our internet website is http://www.spectraenergy.com.
Our natural gas pipeline systems consist of approximately 21,000 miles of transmission pipelines. Our storage facilities provide approximately 300 billion cubic feet (Bcf) of net storage capacity in the U.S. and Canada. Our crude oil pipeline system, Express-Platte, consists of over 1,700 miles of transmission pipeline comprised of the Express pipeline and the Platte pipeline systems.

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Businesses
We manage our business in four reportable segments: Spectra Energy Partners, Distribution, Western Canada Transmission & Processing and Field Services. The remainder of our business operations is presented as “Other,” and consists of unallocated corporate costs, employee benefit plan assets and liabilities, 100%-owned captive insurance subsidiaries, 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 4 of Notes to Consolidated Financial Statements.
SPECTRA ENERGY PARTNERS
We currently own a 78% equity interest in SEP, a natural gas, crude oil and NGL infrastructure master limited partnership, which owns 100% of Texas Eastern Transmission, LP (Texas Eastern), 100% of Algonquin Gas Transmission, LLC (Algonquin), 100% of East Tennessee Natural Gas, LLC (East Tennessee), 100% of Express-Platte, 100% of Saltville Gas Storage Company L.L.C. (Saltville), 100% of Ozark Gas Gathering, L.L.C. (Ozark Gas Gathering) and Ozark Gas Transmission, L.L.C. (Ozark Gas Transmission), 100% of Big Sandy Pipeline, LLC (Big Sandy), 100% of Market Hub Partners Holding (Market Hub), 100% of Bobcat Gas Storage (Bobcat), 78% of Maritimes & Northeast Pipeline, L.L.C. (M&N U.S.), 50% of Southeast Supply Header, LLC (SESH), 50% of Steckman Ridge, LP (Steckman Ridge) and 50% of Gulfstream Natural Gas System, L.L.C. (Gulfstream).
On October 30, 2015, Spectra Energy acquired SEP's 33.3% ownership interests in DCP Sand Hills Pipeline, LLC (Sand Hills) and DCP Southern Hills Pipeline, LLC (Southern Hills). See Part II. Item 8. Financial Statements and Supplementary Data, Notes 2 and 3 of Notes to Consolidated Financial Statements for further discussion.
SEP is a publicly traded entity which trades on the New York Stock Exchange (NYSE) under the symbol “SEP.” See Part II. Item 8. Financial Statements and Supplementary Data, Note 2 of Notes to Consolidated Financial Statements for further discussion of SEP.
Our Spectra Energy Partners business primarily provides transmission, storage and gathering of natural gas, as well as the transportation and storage of crude oil through interstate pipeline systems for customers in various regions of the midwestern, northeastern and southern U.S. and Canada. Its pipeline systems consist of approximately 15,400 miles of transmission and transportation pipelines. The pipeline systems in our Spectra Energy Partners business receive natural gas and crude oil 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, where customers reserve capacity in the pipeline. Interruptible services, where customers can use capacity if it is available at the time of the request, are provided on a short-term or seasonal basis. Demand on the natural gas pipeline and storage systems is seasonal, with the highest throughput occurring during colder periods in the first and fourth quarters, and storage injections occurring primarily during the summer periods.
Most of Spectra Energy Partners’ 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 and crude oil in interstate commerce. The National Energy Board (NEB) is the Canadian agency that regulates the transportation of crude oil in Canada.

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Texas Eastern
We have an effective 78% ownership interest in Texas Eastern through our ownership of SEP. The Texas Eastern natural 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, the first of which has one to four 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 associated 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 400 miles of pipeline. 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 joint venture capacity in these three facilities is 74 Bcf. In addition, Texas Eastern’s system is connected to Steckman Ridge, a 12 Bcf joint venture storage facility in Pennsylvania, and three affiliated storage facilities in Texas and Louisiana, aggregating 77 Bcf, owned by Market Hub and Bobcat.

6



Algonquin
                        
We have an effective 78% ownership interest in Algonquin through our ownership of SEP. The Algonquin natural gas transmission system connects with Texas Eastern’s facilities in New Jersey and extends approximately 250 miles through New Jersey, New York, Connecticut, Rhode Island and Massachusetts where it connects to the Maritimes & Northeast Pipeline. The system consists of approximately 1,130 miles of pipeline with associated compressor stations.

7



East Tennessee
                
We have an effective 78% ownership interest in East Tennessee through our ownership of SEP. East Tennessee’s natural gas 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 associated 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.

8



Maritimes & Northeast Pipeline
We have an effective 60% ownership interest in M&N U.S. through our ownership of SEP. M&N U.S. is owned 78% directly by SEP, with affiliates of Emera, Inc. and Exxon Mobil Corporation directly owning the remaining 13% and 9% interests, respectively. M&N U.S. is an approximately 350-mile mainline interstate natural gas transmission system which extends from the border of Canada near Baileyville, Maine to northeastern Massachusetts. M&N U.S. is connected to the Canadian portion of the Maritimes & Northeast Pipeline system, Maritimes & Northeast Pipeline Limited Partnership (M&N Canada), which is owned 78% by us as part of our Western Canada Transmission & Processing segment. M&N U.S. facilities include compressor stations, with a market delivery capability of approximately 0.8 billion cubic feet per day (Bcf/d) of natural gas. The pipeline’s location and key interconnects with our transmission system link regional natural gas supplies to the northeast U.S. markets.

9



Ozark
                
We have an effective 78% ownership interest in Ozark Gas Transmission and Ozark Gas Gathering through our ownership of SEP. Ozark Gas Transmission consists of an approximately 365-mile natural gas transmission system extending from southeastern Oklahoma through Arkansas to southeastern Missouri. Ozark Gas Gathering consists of an approximately 330-mile natural gas gathering system, with associated compressor stations, that primarily serves Arkoma basin producers in eastern Oklahoma.

10



Big Sandy
                    
We have an effective 78% ownership interest in Big Sandy through our ownership of SEP. Big Sandy is an approximately 70-mile natural gas transmission system, with associated compressor stations, located in eastern Kentucky. Big Sandy’s interconnection 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 39% investment in Gulfstream through our ownership of SEP. Gulfstream is an approximately 745-mile interstate natural gas transmission system, with associated compressor stations, operated jointly by us and The Williams Companies, Inc. (Williams). Gulfstream transports natural gas from Mississippi, Alabama, Louisiana and Texas, crossing the Gulf of Mexico to markets in central and southern Florida. Gulfstream is owned 50% directly by SEP and 50% by affiliates of Williams. Our investment in Gulfstream is accounted for under the equity method of accounting.

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Express-Platte
We have an effective 78% ownership interest in Express-Platte, acquired in 2013, through our ownership of SEP. The Express-Platte pipeline system, an approximately 1,700-mile crude oil transportation system, which begins in Hardisty, Alberta, and terminates in Wood River, Illinois, is comprised of both the Express and Platte crude oil pipelines. The Express pipeline carries crude oil to U.S. refining markets in the Rockies area, including Montana, Wyoming, Colorado and Utah. The Platte pipeline, which interconnects with the Express pipeline in Casper, Wyoming, transports crude oil predominantly from the Bakken shale and western Canada to refineries in the Midwest.












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SESH
We have an effective 39% total investment in SESH through our ownership of SEP, an approximately 290-mile natural gas transmission system, with associated compressor stations, operated jointly by Spectra Energy and CenterPoint Energy Southeastern Pipelines Holding, LLC. SESH 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. SESH is owned 50% directly by SEP and 50% by Enable Midstream Partners, LP. Our investment in SESH is accounted for under the equity method of accounting.












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Market Hub
We have an effective 78% ownership interest in Market Hub through our ownership of SEP. Market Hub owns and operates two natural gas storage facilities, Moss Bluff and Egan, with a total storage capacity of approximately 47 Bcf. The Moss Bluff facility consists of four salt dome storage caverns located in southeast Texas, with 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, with access to ten pipeline systems, including the Texas Eastern system.
Saltville
We have an effective 78% ownership interest in Saltville through our ownership of SEP. Saltville owns and operates natural gas storage facilities in Virginia with a total storage capacity of approximately 5 Bcf, interconnecting 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.
Bobcat
We have an effective 78% ownership interest in Bobcat through our ownership of SEP. Bobcat, an approximately 30 Bcf salt dome facility, is strategically located on the Gulf Coast near Henry Hub, interconnecting with five major interstate pipelines, including Texas Eastern.
Steckman Ridge
We have an effective 39% investment in Steckman Ridge through our ownership of SEP. Steckman Ridge is an approximately 12 Bcf depleted reservoir storage facility located in south central Pennsylvania that interconnects with the Texas Eastern and Dominion Transmission, Inc. systems. Steckman Ridge is owned 50% directly by SEP and 50% by NJR Steckman Ridge Storage Company. Our investment in Steckman Ridge is accounted for under the equity method of accounting.
Competition
Spectra Energy Partners’ natural gas transmission and storage businesses compete with similar facilities that serve our supply and market areas in the transmission and storage of natural gas. The principal elements of competition are location, rates, terms of service, and flexibility and reliability of service.
The natural gas transported 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.

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Spectra Energy Partners’ crude oil transportation business competes with pipelines, rail, truck and barge facilities that transport crude oil from production areas to refinery markets. The principal elements of competition are location, rates, terms of service, flexibility and reliability of service.
Customers and Contracts
In general, Spectra Energy Partners’ natural gas pipelines provide transmission 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. Transmission 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 the 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.
Spectra Energy Partners also provides interruptible transmission 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 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.
Customers on the Express-Platte system are primarily refineries located in the Rocky Mountain and Midwestern states of the U.S. Other customers include oil producers and marketing entities. Express capacity is typically contracted under long-term committed contracts where customers reserve capacity and pay commitment charges based on a contracted volume even if they do not ship. A small amount of Express capacity and all Platte capacity is used by uncommitted shippers who only pay for the pipeline capacity that is actually used in a given month.


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DISTRIBUTION
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 over 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’ storage and transmission business offers storage and transmission services to customers at the Dawn Hub, the largest integrated 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 U.S.
Union Gas’ distribution system consists of approximately 40,000 miles of main and service pipelines. Distribution pipelines carry natural gas from the point of local supply to customers. Union Gas’ underground natural gas storage facilities have a working capacity of approximately 163 Bcf in 25 underground facilities located in depleted gas fields. Its transmission system consists of approximately 3,000 miles of high-pressure pipeline and associated 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, physical bypass of Union Gas’ system may be permitted, even within Union Gas’ distribution franchise area. In addition, other companies could enter Union Gas’ markets or regulations could change.
Union Gas provides 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 basis of price, terms of service, and flexibility and reliability of service. 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.

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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 transmission 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.

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WESTERN CANADA TRANSMISSION & PROCESSING
Our Western Canada Transmission & Processing business is comprised of the BC Pipeline, BC Field Services, Canadian Midstream, Empress NGL operations, and M&N Canada.
BC Pipeline and BC Field Services provide fee-based natural gas transmission and gas gathering and processing services. BC Pipeline is regulated by the NEB under full cost-of-service regulation. BC Pipeline 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 1,750 miles of transmission pipeline in BC and Alberta, as well as associated mainline compressor stations.
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 eight gas processing plants located in BC, associated field compressor stations and approximately 1,400 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 800 miles of gathering pipelines. This business is primarily regulated by the province where the assets are located, either BC or Alberta.
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 U.S. Assets include a majority ownership interest in an NGL extraction plant, an integrated NGL fractionation facility, an NGL transmission pipeline, ten 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.
We own approximately 78% of M&N Canada, with affiliates of Emera, Inc. and Exxon Mobil Corporation directly owning the remaining 13% and 9% interests, respectively. M&N Canada is an approximately 550-mile mainline interprovincial natural gas transmission system which extends from Goldboro, Nova Scotia to the U.S. border near Baileyville, Maine. M&N Canada is connected to the U.S. portion of the Maritimes & Northeast Pipeline system, M&N U.S., which is directly owned by SEP (part of our Spectra Energy Partners segment) and affiliates of Emera, Inc. and Exxon Mobil Corporation. M&N Canada facilities include associated compressor stations and have a market delivery capability of approximately 0.6 Bcf/d of natural gas. The pipeline’s location and key interconnects with Spectra Energy’s transmission system link regional natural gas supplies to the northeast U.S. and Atlantic Canadian markets.

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Competition
Western Canada Transmission & Processing businesses compete with third-party midstream companies, exploration and production companies, and pipelines in the gathering, processing and transmission of natural gas and the extraction and marketing of NGL products. The principal elements of competition are location, rates, terms of service, and flexibility and reliability of service.
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 Nova Gas Transmission Ltd. (Nova/TransCanada) pipeline system. To extract and acquire NGLs, we must be competitive in the prices or fees we pay to gas shippers and suppliers. We also compete with other NGL marketers in the various product sales markets we serve.
Customers & Contracts
BC Pipeline provides: (i) transmission 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 transmission services to the nearest natural gas trading hub; and (ii) transmission services primarily to downstream markets in the Pacific Northwest (both in the U.S. and Canada) using the southern portion of the transmission pipeline and markets in Alberta through pipeline interconnects in northern BC with Nova/TransCanada. 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 transmission 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. However, a sustained decline in natural gas prices has impacted our ability to negotiate and renew expiring service contracts with customers in certain areas of our operations. The BC Field Services and Canadian Midstream operations provide both firm and interruptible services.
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 (Bbls/d) (our share is approximately 58,000 Bbls/d at full capacity). At Empress, we extract and purchase NGLs from natural gas shippers on the Nova/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. We further compete with other NGL extraction facilities to purchase and ship natural gas to our extraction and separation plant at Empress where we extract NGLs before selling the residue natural gas. 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 is 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. Empress’ customers are U.S.-based and Canadian-based.
Operating results at Empress are significantly affected by changes in average NGL and natural gas prices, which have fluctuated significantly over the last several years. We continue to closely monitor the risks associated with these price changes.
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. In 2014, we implemented a commodity hedging program at Empress in an effort to mitigate a large portion of commodity risk.

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FIELD SERVICES
Field Services consists of our 50% investment in DCP Midstream, which is accounted for as an equity investment. DCP Midstream gathers, compresses, treats, processes, transports, stores and sells natural gas. In addition, this segment produces, fractionates, transports, stores and sells NGLs, recovers and sells condensate and trades and markets natural gas and NGLs. Phillips 66 owns the other 50% interest in DCP Midstream. DCP Midstream currently owns an approximate 21% interest in DCP Midstream Partners, LP (DCP Partners), a publicly traded master limited partnership which trades on the NYSE under the symbol “DPM.” As its general partner, DCP Midstream accounts for its investment in DCP Partners as a consolidated subsidiary.
On October 30, 2015, Spectra Energy contributed our 33.3% interests in Sand Hills and Southern Hills NGL pipelines to DCP Midstream. See Part II. Item 8. Financial Statements and Supplementary Data, Note 3 of Notes to Consolidated Financial Statements for further discussion of this transaction.
DCP Midstream owns or operates assets in 17 states in the U.S. 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 operates in a diverse number of regions, including the Permian Basin, Eagle Ford, Niobrara/DJ Basin and Midcontinent. DCP Midstream owns or operates approximately 67,000 miles of gathering and transmission pipeline.
As of December 31, 2015, DCP Midstream owned or operated 64 natural gas processing plants, which separate raw natural gas that has been gathered on DCP Midstream’s 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, 2015, DCP Midstream owned or operated 12 fractionators. In addition, DCP Midstream operates a propane wholesale marketing business and a eight million barrel propane and butane storage facility in the northeastern U.S.
The residue natural gas (gas that has had associated NGLs removed) 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

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individual consumers. DCP Midstream also stores residue natural gas at its 12 Bcf Southeast Texas 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 price risk and to provide additional services to its customers. Asset-based gas trading and marketing activities are supported by ownership of the Southeast Texas storage facility and various intrastate pipelines which provide access to market centers/hubs such as Katy, Texas and the Houston Ship Channel.
DCP Midstream’s operating results are significantly affected by changes in average NGL, natural gas and crude oil prices, which have declined substantially. 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, transporting and storing natural gas, as well as producing, marketing and transporting 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, pricing arrangements offered by the gatherer/processor and the ability of the gatherer/processor to obtain a satisfactory price for the producer’s residue natural gas and extracted NGLs. Competition for sales to customers is based mostly upon reliability, services offered and the prices of delivered natural gas and NGLs.
Customers and Contracts
DCP Midstream sells a portion of its NGLs to Phillips 66 and Chevron Phillips Chemical Company LLC (CPChem). In addition, DCP Midstream purchases NGLs from CPChem. Prior to December 31, 2014 approximately 35% of DCP Midstream’s NGL production was committed to Phillips 66 and CPChem under 15-year contracts, the primary production commitment of which began a ratable wind down period in December 2014 and expires in January 2019. Approximately 28% of DCP Midstream’s NGL production was committed to Phillips 66 and CPChem as of December 31, 2015. DCP Midstream anticipates continuing to purchase and sell commodities with Phillips 66 and CPChem, in the ordinary course of business.
The residual natural gas, primarily methane, that results from processing raw natural gas is sold at market-based prices to marketers and end-users, including 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 75% of the 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, gathers the wellhead natural gas through its gathering system, 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 by DCP Midstream from the sale of the residue natural gas, NGLs and condensate, or an agreed-upon percentage of the proceeds based on index-related prices or contractual recoveries for the natural gas, NGLs and condensate, regardless of the actual amount of sales proceeds which DCP Midstream receives. DCP Midstream keeps the difference between the proceeds received and the amount remitted back to the producer. Under percentage-of-liquids arrangements, DCP Midstream does not keep any amounts related to the residue natural gas proceeds and only keeps amounts related to the difference between the proceeds received and the amount remitted back to the producer related to NGLs and condensate. Certain of these arrangements may also result in the producer retaining title to all or a portion of the residue natural gas and/or the NGLs in lieu of DCP Midstream returning sales proceeds to the producer. Additionally, these arrangements may include fee-based components. DCP Midstream’s revenues from percentage-of-proceeds/index arrangements are directly related to the prices of natural gas, NGLs or condensate. DCP Midstream’s revenues under percentage-of-liquids arrangements are directly related to the price of NGLs and condensate.
Fee-based arrangements. DCP Midstream receives a fee or fees for one or more of the following services: gathering, compressing, treating, processing, transporting or storing natural gas, and fractionating, storing and transporting NGLs. Fee-based arrangements include natural gas arrangements pursuant to which DCP Midstream obtains 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 transportation fees it would otherwise charge for transportation of the 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 or NGLs that flows through its systems and is not dependent on commodity prices.

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However, to the extent that a sustained decline in commodity prices results in a decline in volumes, DCP Midstream’s revenues from these arrangements would be reduced.
Keep-whole and wellhead purchase arrangements. DCP Midstream gathers raw natural gas from producers for processing, the NGLs and condensate are sold and the residue natural gas is returned to the producer with a British thermal unit (Btu) content equivalent to the Btu content of the natural gas gathered. This arrangement keeps the producer whole to the thermal value of the natural gas received. 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 natural gas at market prices. Under these types of contracts, 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, where that frac spread exceeds our cost.
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.
Supplies and Raw Materials
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, pumps, 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 U.S. and Canada. Our supply chain management group uses economies-of-scale to maximize the efficiency of supply networks where applicable. The price of equipment and materials may vary however, perhaps substantially, from year to year. DCP Midstream performs its own supply chain management function.
Regulations
Most of our U.S. gas transmission, crude oil pipeline and storage operations are regulated by the FERC. The FERC regulates natural gas transmission in U.S. interstate commerce including the establishment of rates for services. The FERC also regulates the construction of U.S. interstate natural gas pipelines and storage facilities, including the extension, enlargement and abandonment of facilities. In addition, certain operations are subject to oversight by state regulatory commissions. To the extent that the natural gas intrastate pipelines that transport or store natural gas in interstate commerce provide services under Section 311 of the Natural Gas Policy Act of 1978, they are subject to FERC regulations. 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 transmission of gas by intrastate pipelines.
Our Spectra Energy Partners 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 (DOT) concerning pipeline safety.
Express-Platte pipeline system rates and tariffs are subject to regulation by the NEB in Canada and the FERC in the U.S. In addition, the Platte pipeline also operates as an intrastate pipeline in Wyoming and is subject to jurisdiction by the Wyoming Public Service Commission.
The intrastate natural gas and NGL pipelines owned by us and 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.
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 Regulator and the Ontario Technical Standards and Safety Authority.
Our Canadian natural gas transmission and distribution operations 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

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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 business is not under any form of rate regulation.
Environmental Matters
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) amended 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 (BC), the Environmental Protection and Enhancement Act (Alberta) and the Environmental Protection Act (Ontario) are provincial laws governing various aspects, including permitting and site remediation obligations, of our facilities and operations in those provinces.
The Canadian Environmental Protection Act, 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 (The Act) which, as of 2007, required certain facilities to meet reductions in emission intensity. The Act was applicable to our Empress facility in Alberta beginning in 2008.

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The Canadian Environmental Assessment Act, 2012 (CEAA 2012) requires the NEB to consider potential environmental effects in their decisions for designated projects. The NEB under its enabling statute also conducts environmental assessments for projects that are not specifically designated under CEEA 2012. In either case, prior to receiving an approval to construct or operate a federally-regulated pipeline or facility, the NEB must consider a series of environmental factors, in particular whether the project has the potential to have adverse environmental effects. These types of assessments occur in relation to both maintenance and capital projects.
For more information on environmental matters, including possible liability and capital costs, see Part II. Item 8. Financial Statements and Supplementary Data, Notes 5 and 19, of Notes to Consolidated Financial Statements.
Except to the extent discussed in Notes 5 and 19, compliance with international, federal, state, provincial and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of 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.
Geographic Regions
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 4 and 18 of Notes to Consolidated Financial Statements.
Employees
We had approximately 6,000 employees as of December 31, 2015, including approximately 3,600 employees in Canada. In addition, DCP Midstream employed approximately 3,200 employees as of such date. Approximately 1,400 of our Canadian employees are subject to collective bargaining agreements governing their employment with us. Approximately 20% of those employees are covered under agreements that either have expired or will expire by December 31, 2016.

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Executive and Other Officers
The following table sets forth information regarding our executive and other officers.
 
Name
Age
Position
Gregory L. Ebel
51
President and Chief Executive Officer, Director
J. Patrick Reddy
63
Chief Financial Officer
Dorothy M. Ables
58
Chief Administrative Officer
Guy G. Buckley
55
Chief Development Officer
Julie A. Dill
56
Chief Communications Officer
Reginald D. Hedgebeth
48
General Counsel
William T. Yardley
51
President, U.S. Transmission and Storage
Allen C. Capps
45
Vice President and Controller
Laura Buss Sayavedra
48
Vice President and Treasurer
Gregory L. Ebel assumed his current position as President and Chief Executive Officer in January 2009. He previously served as Group Executive and Chief Financial Officer since January 2007. Mr. Ebel currently serves as the Chairman of the Board of Directors of Spectra Energy Corp and on the Board of Directors of Spectra Energy Partners GP, LLC and DCP Midstream, LLC.
J. Patrick Reddy joined Spectra Energy in January 2009 as Chief Financial Officer. Mr. Reddy served as Senior Vice President and Chief Financial Officer at Atmos Energy Corporation from 2000 to 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. Ms. Ables currently serves on the Board of Directors of Spectra Energy Partners GP, LLC.
Guy G. Buckley assumed his current position as Chief Development Officer in January 2014. He previously served as Treasurer and Group Vice President-Mergers and Acquisitions from January 2012 to December 2013, and as Group Vice President, Corporate Strategy and Development from December 2008 to December 2011. Mr. Buckley currently serves on the Board of Directors of DCP Midstream, LLC.
Julie A. Dill assumed her current position as Chief Communications Officer January 2014. Ms. Dill previously served as Group Vice President-Strategy from January 2012 to December 2013, as President and Chief Executive Officer of Spectra Energy Partners, GP, LLC from January 2012 to October 2013 and as President of Union Gas Limited from December 2006 through December 2011. Ms. Dill currently serves on the Board of Directors of Spectra Energy Partners GP, LLC.
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.
William T. Yardley assumed his current position as President, U.S. Transmission and Storage in January 2013. Prior to then, he served as Group Vice President of Northeastern U.S. Assets and Operations since 2007. Mr. Yardley currently serves on the Board of Directors of Spectra Energy Partners GP, LLC.
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.
Laura Buss Sayavedra assumed her current position as Vice President and Treasurer January 2014. Ms. Sayavedra previously served as Vice President-Strategy from March 2013 to December 2013, as Vice President and Chief Financial Officer of Spectra Energy Partners, GP, LLC from July 2008 to February 2013, and as Vice President, Strategic Development and Analysis of Spectra Energy Corp from January 2007 to June 2008.

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Additional Information
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 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 website at http://www.spectraenergy.com. Such reports are accessible at no charge through our website 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.
Item 1A. Risk Factors.
Discussed below are the material risk factors relating to Spectra Energy.
Reductions in demand for natural gas and oil, and low market prices of commodities adversely affect our operations and cash flows.
Our regulated businesses are generally economically stable; they are not significantly affected in the short-term by changing commodity prices. However, our businesses can all 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, oil and NGLs. These factors 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 could reduce the volume of natural gas and NGLs transported and distributed or gathered and processed at our plants, and the volume of oil transported, 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, resulting in the non-renewal of long-term contracts at the time of expiration. Lower demand along with lower prices for natural gas, oil 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, resulting in lower energy usage for heating or cooling purposes, respectively;
supply of and demand for energy commodities, including any decrease in the production of natural gas and oil which could negatively affect our processing and transmission businesses 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 and oil resources may cause customers to seek alternative energy resources, which could materially affect our revenues, earnings and cash flows.
Our natural gas and oil businesses are dependent on the continued availability of natural gas and oil production and reserves. Prices for natural gas and oil, regulatory limitations on the development of natural gas and oil 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 and oil 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 2015 would have resulted in an estimated net gain on the translation of local currency earnings of approximately $24 million on our Consolidated Statement of Operations. In addition, if a 10% devaluation had occurred on December 31, 2015, the Consolidated Balance Sheet would have been negatively impacted by $356 million through a cumulative translation adjustment in Accumulated Other Comprehensive Income (AOCI). At December 31, 2015, one U.S. dollar translated into 1.38 Canadian dollars.

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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, NGL processing and marketing, 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 and natural gas primarily in Field Services and at Empress in our Western Canada Transmission & Processing segment, and to oil primarily in our Field Services segment. The effect of commodity price fluctuations on our earnings could be material. Effective January 2014, we implemented a commodity hedging program at Empress in order to manage risks associated with Empress’ commodity price fluctuations. The commodity hedging program helps manage the fluctuations in the Conway/Mont Belvieu index prices. However, it does not manage potential fluctuations in pricing differentials between the Empress market and index prices. The changes in pricing differentials may be material and may adversely affect results.
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 revenues, 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 U.S. and Canada have taken actions to strengthen market forces in the gas pipeline industry, which have led to increased competition. In a number of key markets, natural gas pipeline and storage operators are facing competitive pressure from a number of new industry participants, such as alternative suppliers, as well as traditional pipeline competitors. Increased competition driven by regulatory changes could have a material effect on our business, earnings, financial condition and cash flows.
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 and to maintain those approvals and permits issued and satisfy the terms and conditions imposed therein;
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

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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, natural gas transmission and storage, crude oil transportation and storage, and gas 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, and crude oil transportation and storage, such as leaks, explosions, mechanical problems, activities of third parties and damage to pipelines, facilities and equipment caused by hurricanes, tornadoes, floods, fires and other natural disasters, 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.
Our operations 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 laws and regulations administered by the Pipeline and Hazardous Materials Safety Administration (PHMSA) of the DOT. 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.
PHMSA is designing an Integrity Verification Process intended to create standards to verify maximum allowable operating pressure, and to improve and expand integrity management processes. There remains uncertainty as to how these standards will be implemented, but it is expected that the changes will impose additional costs on new pipeline projects as well as on existing operations. 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 an adverse effect on our operations, earnings, financial condition and cash flows.
In Canada, our interprovincial and international pipeline operations are subject to pipeline safety regulations overseen by the NEB. Applicable legislation and regulation require us to comply with a significant set of requirements for the design, construction, maintenance and operation of our interprovincial and international pipelines. Among other obligations, this regulatory framework imposes requirements to monitor and maintain the integrity of our pipelines.
As in the U.S., several legislative changes addressing pipeline safety in Canada have recently come into force. The changes evidence an increased focus on the implementation of management systems to address key areas such as emergency management, integrity management, safety, security and environmental protection. Other legislative changes have created authority for the NEB to impose administrative monetary penalties for non-compliance with the regulatory regime it administers.
Compliance with these legislative changes may impose additional costs on new Canadian pipeline projects as well as on existing operations. Failure to comply with applicable regulations could result in a number of consequences which may have an adverse effect on our operations, earnings, financial condition and cash flows.
Our operations are subject to numerous environmental laws and regulations, compliance with which may require significant capital expenditures, increase our cost of operations and 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

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arising out of contaminated properties. In particular, compliance with major Clean Air Act regulatory programs is likely to cause us to incur significant capital expenditures to obtain permits, evaluate offsite impacts of our operations, install pollution control equipment, and otherwise assure compliance. Some states in which we operate are implementing new emissions limits to comply with 2008 ozone standards regulated under the National Ambient Air Quality Standards. In 2015, the ozone standards were lowered even further from 75 ppb to 70 ppb, which may require states to implement additional emissions regulations. The precise nature of these compliance obligations at each of our facilities has not been finally determined and may depend in part on future regulatory changes. In addition, compliance with new and emerging environmental regulatory programs is likely to significantly increase our operating costs compared to historical levels.
In the U.S., climate change action is evolving at state, regional and federal levels. The Supreme Court decision in Massachusetts v. EPA in 2007 established that greenhouse gas (GHG) emissions were pollutants subject to regulation under the Clean Air Act. Pursuant to federal regulations, we are currently subject to an obligation to report our GHG emissions at our largest emitting facilities, but are not generally subject to limits on emissions of GHGs, (except to the extent that some GHGs consist of volatile organic compounds and nitrous oxides that are subject to emission limits). Proposed regulation may extend our reporting obligations to additional facilities and activities. In addition, a number of Canadian provinces and U.S. states have joined regional GHG initiatives, and a number are developing their own programs that would mandate reductions in GHG emissions. Public interest groups and regulatory agencies are increasingly focusing on the emission of methane associated with natural gas development and transmission as a source of 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. For its part, Canada has reaffirmed its strong preference for a harmonized approach with that of the U.S. While federal GHG related regulatory design details remain forthcoming, provincial authorities have been actively pursuing related initiatives.
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 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. Costs we may incur to comply with environmental regulations in the future may have a significant effect on our earnings and cash flows.
Due to the speculative outlook regarding any U.S. federal and state policies and the uncertainty of the Canadian federal and provincial policies, we cannot estimate the potential effect of proposed GHG policies on our future consolidated results of operations, financial position or cash flows. However, such legislation or regulation could materially increase our operating costs, require material capital expenditures or create additional permitting, which could delay proposed construction projects.
We are involved in numerous legal proceedings, the outcome of which are uncertain, and resolutions adverse to us could negatively affect our earnings, financial condition and cash flows.
We are subject to numerous legal proceedings. Litigation is subject to many uncertainties, and we cannot predict the outcome of individual matters with assurance. It is reasonably possible that the final resolution of some of the matters in which we are involved could require additional expenditures, in excess of established reserves, over an extended period of time and in a range of amounts that could have a material effect on our earnings and cash flows.
We rely on access to short-term and long-term capital markets to finance capital requirements and support liquidity needs, and access to those markets can be 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 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

30



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 and crude oil transportation businesses 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. A significant amount of our credit exposures for transmission, 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 and oil producers may be the primary customer, our credit exposure with below investment-grade customers may increase. 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.
Native land claims have been asserted in BC 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 BC 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 BC 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, various aboriginal groups in Ontario have claimed aboriginal and treaty rights in areas where Union Gas’ facilities, and the gas supply areas served by those facilities, are 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, including cyber-terrorism, 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 U.S. and its allies could be directed against companies operating in the U.S. This risk is particularly relevant for companies, like ours, operating in any energy infrastructure industry that handles volatile gaseous and liquid hydrocarbons. The potential for terrorism, including cyber-terrorism, has subjected our operations to increased risks that could have an adverse effect on our business. In particular, we may experience increased capital and operating costs to implement increased security for our facilities and pipelines, such as additional physical facility and pipeline security, and additional security personnel. Moreover, any physical damage to high profile facilities resulting from acts of terrorism may not be covered, or covered fully, by insurance. We may be required to expend material amounts of capital to repair any facilities, the expenditure of which could affect our business and cash flows. A

31



cyber attack could also lead to a significant interruption in our operations or unauthorized release of confidential or otherwise protected information, which could damage our reputation or lead to financial losses.
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.
Item 2. Properties.
At December 31, 2015, we had over 100 primary facilities located in the U.S. and Canada. We generally own sites associated with our major pipeline facilities, such as compressor stations. However, we generally operate our 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, 2015.
Our corporate headquarters are located at 5400 Westheimer Court, Houston, Texas 77056, which is a leased facility. The lease expires in 2026. We also maintain offices in, among other places, Calgary, Alberta and Chatham, Ontario. For a description of our material properties, see Item 1. Business.
Item 3. Legal Proceedings.
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.

32



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 NYSE under the symbol “SE.” As of January 31, 2016, there were approximately 107,000 holders of record of our common stock and approximately 566,000 beneficial owners.
Common Stock Data by Quarter 
2015
 
Dividends Per
Common Share
 
Stock Price Range (a)
High
 
Low
First Quarter
 
 
$
0.370

 
 
$
36.90

 
 
$
32.43

Second Quarter
 
 
0.370

 
 
38.47

 
 
32.19

Third Quarter
 
 
0.370

 
 
32.84

 
 
25.22

Fourth Quarter
 
 
0.370

 
 
30.55

 
 
21.43

2014
 
 
 
 
 
 
 
 
 
First Quarter
 
 
$
0.335

 
 
$
38.73

 
 
$
34.23

Second Quarter
 
 
0.335

 
 
42.61

 
 
37.17

Third Quarter
 
 
0.335

 
 
43.12

 
 
38.55

Fourth Quarter
 
 
0.370

 
 
40.00

 
 
32.50

 
________ _
(a)
Stock prices represent the intra-day high and low price.
Stock Performance Graph
The following graph reflects the comparative changes in the value from January 1, 2011 through December 31, 2015 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 1,
2011
 
December 31,
 
 
2011
 
2012
 
2013
 
2014
 
2015
Spectra Energy Corp
 
$
100.00

 
$
128.04

 
$
118.53

 
$
160.08

 
$
169.06

 
$
116.78

S&P 500 Stock Index
 
100.00

 
102.11

 
118.45

 
156.82

 
178.28

 
180.75

S&P 500 Storage & Transportation Index
 
100.00

 
147.92

 
166.04

 
199.91

 
231.73

 
117.44


33



Dividends
Our near-term objective is to increase our cash dividend by $0.14 per year through 2018. 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.
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.
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
2012
 
2011
 
(dollars in millions, except per-share amounts)
Statements of Operations
 
 
 
 
 
 
 
 
 
Operating revenues
$
5,234

 
$
5,903

 
$
5,518

 
$
5,075

 
$
5,351

Operating income
1,433

 
1,924

 
1,666

 
1,575

 
1,763

Income from continuing operations
460

 
1,283

 
1,159

 
1,045

 
1,257

Net income—noncontrolling interests
264

 
201

 
121

 
107

 
98

Net income—controlling interests
196

 
1,082

 
1,038

 
940

 
1,184

Ratio of Earnings to Fixed Charges
3.1

 
3.6

 
2.9

 
2.8

 
3.4

Common Stock Data
 
 
 
 
 
 
 
 
 
Earnings per share from continuing operations
 
 
 
 
 
 
 
 
 
Basic
$
0.29

 
$
1.61

 
$
1.55

 
$
1.44

 
$
1.78

Diluted
0.29

 
1.61

 
1.55

 
1.43

 
1.77

Earnings per share
 
 
 
 
 
 
 
 
 
Basic
0.29

 
1.61

 
1.55

 
1.44

 
1.82

Diluted
0.29

 
1.61

 
1.55

 
1.43

 
1.81

Dividends per share
1.48

 
1.375

 
1.22

 
1.145

 
1.06

 
December 31,
 
2015
 
2014
 
2013
 
2012
 
2011
 
(in millions)
Balance Sheets
 
 
 
 
 
 
 
 
 
Total assets
$
32,923

 
$
33,998

 
$
33,486

 
$
30,544

 
$
28,096

Long-term debt including capital leases, less current maturities
12,892

 
12,727

 
12,441

 
10,610

 
10,104



34



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 2015, we continued to successfully execute the long-term strategies we outlined for our shareholders—meeting the needs of our customers, generating strong earnings and cash flows from our fee-based assets, executing capital expansion plans that underlie our growth objectives, and maintaining our investment-grade 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 first quarter of 2016 to $0.405 per share, which represents an increase in our annual dividend by $0.14 per share per year.
During 2015, our earnings decreased due to a weaker Canadian dollar at Distribution and Western Canada Transmission & Processing and sustained lower commodity prices at Field Services, partially offset by increased earnings as a result of expansion projects at Spectra Energy Partners.
We reported net income from controlling interests of $196 million and $0.29 of earnings per share for 2015 compared to net income from controlling interests of $1,082 million and $1.61 of earnings per share for 2014.
Earnings highlights for 2015 compared to 2014 include the following:
Spectra Energy Partners’ earnings benefited mainly from expansions, primarily on Texas Eastern, and higher transportation revenues due to higher tariff rates and volumes on the Express pipeline.
Distribution’s earnings decreased mainly due to a weaker Canadian dollar and lower customer usage as a result of warmer weather.
Western Canada Transmission & Processing’s earnings decreased mainly due to lower NGL sales prices and a weaker Canadian dollar, partially offset by lower unit cost of sales at the Empress operations.
Field Services’ earnings decreased mainly due to continued lower commodity prices, goodwill and other asset impairments, net of tax impacts and lower gains associated with the issuance of partnership units by DCP Partners, partially offset by asset growth, improved operating efficiencies and other initiatives.
We invested $3.0 billion of capital and investment expenditures in 2015, including $2.3 billion of expansion and investment capital expenditures. Successful execution of our 2015 projects allowed us to continue to achieve aggregate returns over the past several years consistent with our targeted 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 $3.7 billion planned for 2016, excluding contributions from noncontrolling interests. Concurrently, we executed on identified opportunities leveraging our asset footprint to capture incremental growth, connecting large diverse markets with growing supply throughout North America.
We are committed to an investment-grade balance sheet and continued prudent financial management of our capital 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 debt and equity securities. As of December 31, 2015, our four revolving credit facilities consisted of Spectra Energy Capital, LLC’s (Spectra Capital’s) $1.0 billion facility, SEP’s $2.0 billion facility, Westcoast Energy, Inc.’s (Westcoast’s) 400 million Canadian dollar facility, and Union Gas’ 500 million Canadian dollar facility. These facilities are used principally as back-stops for commercial paper programs. At December 31, 2015 and 2014, our consolidated debt-to-capitalization ratio was 59.8% and 58%, respectively.
Our Strategy.    Our strategy is to create superior and sustainable value for our investors, customers, employees and communities by delivering natural gas, liquids and crude oil infrastructure to premium markets. We will grow our business through organic growth, greenfield expansions and strategic acquisitions, with a steadfast focus on safety, reliability, customer responsiveness and profitability. We intend to accomplish this by:
Building off the strength of our asset base.
Maximizing that base through sector leading operations and service.
Effectively executing the projects we have secured.

35



Securing new growth opportunities that add value for our investors within each of our business segments.
Expanding our value chain participation into complementary infrastructure assets.
Natural gas supply dynamics continue to rapidly change, and there is general recognition that natural gas can be an effective solution for meeting the energy needs of North America and beyond. This causes us to be optimistic about future growth opportunities. Identified opportunities include growth in gas-fired power generation and industrial markets, LNG exports from North America, growth related to moving new sources of gas supplies to markets (including exports) and significant new liquids pipeline infrastructure. With our advantage of providing continuous access from leading supply regions through to the last mile of pipe in growing natural gas, NGL and crude oil markets, we expect to continue expanding our assets and operations to meet the evolving needs of our customers.
Crude oil supply dynamics also continue to evolve as North American production moved from growth to decline. Growing North American crude oil production had in recent years displaced imports from overseas and was driving increased demand for crude oil transportation and logistics. Although depressed global crude oil prices have resulted in declining North American oil production, we remain confident about long-term growth in North American oil production and our ability to capture future opportunities to grow our crude oil pipeline business.
Successful execution of our strategy will depend on successfully maintaining our leadership as a safe and reliable operator and the successful execution of our capital projects. Continued growth and new opportunities will be determined by key factors, such as the continued production and the consumption of natural gas, NGLs and crude oil within North America and our ability to provide creative solutions to meet the markets’ evolving energy needs in both North America and beyond.
We continue to be actively engaged in the national discussions in both the U.S. and Canada regarding energy policy and have taken a lead role in shaping policy as it relates to pipeline safety and operations.
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 crude oil, 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 reduce the volume of natural gas and NGLs transported and distributed or gathered and processed at our plants, and the volume of crude oil transported, resulting in lower earnings and cash flows. This decline would primarily affect distribution revenues and gathering and processing revenues, potentially in the short term. Transmission revenues could be affected by long-term economic declines resulting 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. While experiencing a decline in production from conventional gas wells, natural gas exploration and drilling activity in the areas that affect our Western Canada Transmission & Processing and Field Services segments remain stable, primarily driven by recent positive “supply push developments around unconventional gas reserves production in numerous locations within North America as discussed further below and by “demand pull projects in BC and the Pacific Northwest.
Our combined key natural gas markets—the northeastern and the southeastern U.S., the Pacific Northwest, BC and Ontario—are projected to continue to exhibit higher than average annual growth in natural gas demand versus the North American and continental U.S. average growth rates through 2019. This demand growth is primarily driven by the natural gas-fired electricity generation sector and other new industrial gas demands, including LNG. 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, Midcontinent, Appalachia, Texas and Louisiana. Also, 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 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.
Our key crude oil markets include the Rocky Mountain and Midwest states with growing connectivity to the Gulf Coast of the U.S. Growth in our business is dependent on growing crude oil supply from North American sources and the ability of

36



that supply to displace imported crude oil from overseas. The recent decline in crude oil prices has adversely affected the availability and cost-competitiveness of North American crude oil supply. This has not adversely affected our crude oil pipeline business, but sustained low oil prices could have a negative impact on our current business and associated growth opportunities.
In certain areas of Western Canada Transmission & Processing’s operations, lower natural gas prices resulting from increasing North American gas supply have reduced producer demand for expansions of the BC 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.
DCP Midstream’s business has commodity price exposure as a result of being compensated for certain services in the form of commodities rather than cash. For gathering and processing services and sales, DCP Midstream predominantly receives commodities as payment but may also receive fees, depending on the types of contracts. Commodity prices have declined substantially and have experienced significant volatility. If commodity prices continue to remain weak for a sustained period, DCP Midstream’s natural gas throughput and NGL volumes may be further impacted, particularly as producers are curtailing or redirecting drilling, which could further reduce DCP Midstream's earnings and cash flows. Drilling activity levels vary by geographic area, but in general, DCP Midstream has observed decreases in drilling activity with lower commodity prices. A continued decline in commodity prices could result in a decrease in exploration and development activities in the fields served by DCP Midstream's gas gathering and residue gas and NGL pipeline transportation systems, and DCP Midstream's natural gas treating and processing plants, which could lead to further reduced utilization of these assets.
The shift to and increase in natural gas supply have resulted in declines in the price of natural gas in North America. As a result, a shift occurred to extraction of gas in richer, “wet” gas areas with higher NGL content which depressed activity in “dry” fields like the Fayetteville Shale formation where our Ozark assets are located. This, in turn, contributed to a resulting over-supply of pipeline take-away capacity in these areas. As the balance of supply and demand evolves, we expect activity in these areas to push prices higher. However, should supply and demand not come into balance, our businesses there may be subject to further possible impairment. The supply increase has also had a negative impact on the seasonal price spreads historically seen between the summer and winter months. As a result, the value of storage assets and contracts has declined in recent years, negatively impacting the results of our storage facilities. While we expect storage values to stabilize and strengthen in the future, should these market factors continue to keep downward pressure on the seasonality spread and re-contracting, we could be subject to further reduced value and possible impairment of our storage assets.
Our businesses in the U.S. and Canada are subject to laws and regulations on the federal, state and provincial levels. Regulations applicable to the natural gas transmission, crude oil transportation and storage industries 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.
These laws and regulations can result in increased capital, operating and other costs. Environmental 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. In particular, compliance with major Clean Air Act regulatory programs may cause us to incur significant capital expenditures to obtain permits, evaluate offsite impacts of our operations, install pollution control equipment, and otherwise assure compliance.
Our interstate pipeline operations are subject to pipeline safety laws and regulations administered by PHMSA of the DOT. 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.
PHMSA is designing an Integrity Verification Process intended to create standards to verify maximum allowable operating pressure, and to improve and expand integrity management processes. There remains uncertainty as to how these standards will be implemented, but it is expected that the changes will impose additional costs on new pipeline projects as well as on existing operations. 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 an adverse effect on our operations, earnings, financial condition or cash flows.
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 fluctuated compared to the U.S. dollar, which affected earnings to varying degrees for brief periods. Changes in the exchange rate or any other factors are difficult to predict and may affect our future results.

37



Certain of our segments’ earnings are affected by fluctuations in commodity prices, especially the earnings of Field Services and our Empress NGL business at Western Canada Transmission & Processing, which are most sensitive to changes in NGL prices. DCP Midstream manages its direct exposure to these market prices separate from Spectra Energy, and utilizes various risk management strategies, including the use of commodity derivatives. We evaluate the risks associated with commodity price volatility on an ongoing basis and implemented a commodity hedging program at Western Canada Transmission & Processing’s Empress NGL business effective January 2014. We have elected to not apply cash flow hedge accounting.
Based on current projections, our expected effective income tax rate will approximate 21%–22% for 2016. Our overall expected tax rate largely depends on the proportion of earnings in the U.S. to the earnings of our Canadian operations. Our earnings in the U.S. are subject to a combined federal and state statutory tax rate of approximately 37%. Our earnings in Canada are subject to a combined federal and provincial statutory tax rate of approximately 26%, but we anticipate an effective Canadian tax rate of less than 1% for 2016, driven primarily by the 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.
For further information related to management’s assessment of our risk factors, see Part I. Item 1A. Risk Factors.


38



RESULTS OF OPERATIONS
 
2015
 
2014
 
2013
 
(in millions)
Operating revenues
$
5,234

 
$
5,903

 
$
5,518

Operating expenses
3,801

 
3,979

 
3,852

Operating income
1,433

 
1,924

 
1,666

Other income and expenses
(176
)
 
420

 
569

Interest expense
636

 
679

 
657

Earnings before income taxes
621

 
1,665

 
1,578

Income tax expense
161

 
382

 
419

Net income
460

 
1,283

 
1,159

Net income—noncontrolling interests
264

 
201

 
121

Net income—controlling interests
$
196

 
$
1,082

 
$
1,038

2015 Compared to 2014
Operating Revenues. The $669 million decrease was driven by:
the effects of a weaker Canadian dollar at Distribution and Western Canada Transmission & Processing,
lower NGL prices, lower sales volumes of residual natural gas and non-cash mark-to-market gains and losses associated with the risk management program, net of an increase from settlement gains associated with the risk management program at the Empress operations at Western Canada Transmission & Processing and
lower customer usage due to warmer weather, net of growth in the number of customers at Distribution, partially offset by
revenues from expansion projects primarily on Texas Eastern and East Tennessee at Spectra Energy Partners.
Operating Expenses. The $178 million decrease was driven by:
the effects of a weaker Canadian dollar at Distribution and Western Canada Transmission & Processing,
decreased volumes of natural gas purchases for extraction and make-up and lower costs of sales at Western Canada Transmission & Processing and
lower volumes of natural gas sold due to warmer weather, net of growth in the number of customers at Distribution, partially offset by
goodwill impairment charges associated with the Westcoast acquisition in 2002 at Other.
Other Income and Expenses. The $596 million decrease was attributable to lower equity earnings from Field
Services mainly due to decreased commodity prices and goodwill and other asset impairments.
Interest Expense. The $43 million decrease was mainly due to a weaker Canadian dollar and higher capital expenditures, partially offset by higher average long-term debt balances.
Income Tax Expense. The $221 million decrease was mainly due to tax benefits associated with loss on investment due to impairments of goodwill and other assets at DCP Midstream, lower earnings and the effect of a weaker Canadian dollar.
The effective tax rate was 26% in 2015 compared to 23% in 2014. See Note 6 of Notes to Consolidated Financial Statements for reconciliations of our effective tax rates to the statutory tax rate.
Net Income-Noncontrolling Interests. The $63 million increase was driven by higher earnings from Spectra Energy Partners.

39



2014 Compared to 2013
Operating Revenues. The $385 million increase was driven by:
revenues from expansion projects primarily at Texas Eastern, the acquisition of Express-Platte in March 2013, higher natural gas transportation revenues due to new contracts and an increase in crude oil transportation revenues for both Express and Platte Pipeline, mainly as a result of increased tariff rates and higher volumes, and higher processing revenues, net of lower storage revenues due to lower rates at Spectra Energy Partners,
higher sales volumes of residual natural gas, non-cash mark-to-market gains associated with the risk management program implemented in early 2014 and higher propane sales prices, net of lower sales volumes of NGLs at the Empress operations, and an increase in gathering and processing revenues at Western Canada Transmission & Processing, and
higher customer usage of natural gas primarily as a result of colder weather, higher natural gas prices passed through to customers and growth in the number of customers, net of lower storage revenues due to lower prices and 2014 earnings to be shared with customers under the new incentive regulation framework at Distribution, partially offset by
the effects of a weaker Canadian dollar at Western Canada Transmission & Processing and Distribution.
Operating Expenses. The $127 million increase was driven by:
increased volumes of natural gas purchases for extraction and make-up, and a non-cash charge to reduce the value of propane inventory to net realizable value at the Empress operations, higher plant turnaround and maintenance costs, and higher plant fuel costs due to higher prices at the Empress operations at Western Canada Transmission & Processing,
higher volumes of natural gas sold due to colder weather, higher natural gas prices passed through to customers and growth in the number of customers at Distribution and
expansion projects, primarily at Texas Eastern, and the acquisition of Express-Platte at Spectra Energy Partners, partially offset by
the effects of a weaker Canadian dollar at Distribution and Western Canada Transmission & Processing.
Other Income and Expenses. The $149 million decrease was attributable to lower equity earnings from Field Services mainly due to an increase in net income attributable to noncontrolling interests as a result of growth in DCP Partners’ operations and the effects of dropdown hedges and lower commodity prices.
Interest Expense. The $22 million increase was mainly due to lower capitalized interest from projects placed in service in 2013 and higher average debt balances, partially offset by a weaker Canadian dollar.
Income Tax Expense. The $37 million decrease was mainly due to a lower effective state tax rate in 2014 and the 2013 revaluation of our accumulated deferred state taxes as a result of Spectra Energy's contribution of substantially all of its remaining U.S. transmission, storage and liquids assets to SEP on November 1, 2013 (U.S. Assets Dropdown), partially offset by the reversal of tax reserves in 2013 as a result of favorable Canadian income tax legislation.
The effective tax rate was 23% in 2014 compared to 27% in 2013. See Note 6 of Notes to Consolidated Financial Statements for reconciliations of our effective tax rates to the statutory tax rate.
Net Income-Noncontrolling Interests. The $80 million increase was driven by higher earnings from Spectra Energy Partners, partially offset by the effects of a decrease in the average ownership percentage of SEP held by the public, primarily as a result of the issuance of SEP partnership units to Spectra Energy in November 2013 associated with the U.S. Assets Dropdown.
For a more detailed discussion of earnings drivers, see the segment discussions that follow.

40



Segment Results
Management evaluates segment performance based on earnings before interest, taxes, and depreciation and amortization (EBITDA). Cash, cash equivalents and short-term investments are managed at the parent-company levels, so the gains and losses on foreign currency transactions and interest and dividend income are excluded from the segments’ EBITDA. We consider segment EBITDA to be a good indicator of each segment’s operating performance from its continuing operations, as it represents the results of our operations without regard to financing methods or capital structures. Our segment EBITDA may not be comparable to similarly titled measures of other companies because other companies may not calculate EBITDA in the same manner.
Spectra Energy Partners provides transmission, storage and gathering of natural gas for customers in various regions of the northeastern and southeastern U.S. and operates a crude oil pipeline system that connects Canadian and U.S. producers to refineries in the U.S. Rocky Mountain and Midwest regions.
Distribution provides retail natural gas distribution services in Ontario, Canada, as well as natural gas transmission and storage services to other utilities and energy market participants.
Western Canada Transmission & Processing provides transmission of natural gas, natural gas gathering and processing services, and NGL extraction, fractionation, transportation, storage and marketing to customers in western Canada, the northern tier of the U.S. and the Maritime Provinces in Canada.
Field Services gathers, compresses, treats, processes, transports, stores and sells natural gas; produces, fractionates, transports, stores and sells NGLs; recovers and sells condensate; and trades and markets natural gas and NGLs. It conducts operations through DCP Midstream, which is owned 50% by us and 50% by Phillips 66. DCP Midstream operates in a diverse number of regions, including the Permian Basin, Eagle Ford, Niobrara/DJ Basin and the Midcontinent. As of December 31, 2015 DCP Midstream had an approximate 21% ownership interest in DCP Partners, a publicly-traded master limited partnership.
Segment EBITDA is summarized in the following table. Detailed discussions follow.
EBITDA by Business Segment
 
2015
 
2014
 
2013
 
(in millions)
Spectra Energy Partners
$
1,905

 
$
1,669

 
$
1,433

Distribution
473

 
552

 
574

Western Canada Transmission & Processing
491

 
754

 
736

Field Services
(461
)
 
217

 
343

Total reportable segment EBITDA
2,408

 
3,192

 
3,086

Other
(384
)
 
(58
)
 
(86
)
Total reportable segment and other EBITDA
2,024

 
3,134

 
3,000

Depreciation and amortization
764

 
796

 
772

Interest expense
636

 
679

 
657

Interest income and other (a)
(3
)
 
6

 
7

Earnings before income taxes
$
621

 
$
1,665

 
$
1,578

___________
(a)
Includes foreign currency transaction gains and losses related to segment EBITDA.
The amounts discussed below include intercompany transactions that are eliminated in the Consolidated Financial Statements.

41



Spectra Energy Partners 
 
2015
 
2014
 
Increase
(Decrease)
 
2013
 
Increase
(Decrease)
 
(in millions, except where noted)
Operating revenues
$
2,455

 
$
2,269

 
$
186

 
$
1,965

 
$
304

Operating expenses
 
 
 
 
 
 
 
 
 
Operating, maintenance and other
828

 
781

 
47

 
715

 
66

Other income and expenses
278

 
181

 
97

 
183

 
(2
)
EBITDA
$
1,905

 
$
1,669

 
$
236

 
$
1,433

 
$
236

Express pipeline revenue receipts, MBbl/d (a)
239

 
223

 
16

 
219

 
4

Platte PADD II deliveries, MBbl/d
162

 
170

 
(8
)
 
168

 
2

____________
(a)
Thousand barrels per day.
2015 Compared to 2014
Operating Revenues. The $186 million increase was driven by:
a $137 million increase due to expansion projects, primarily on Texas Eastern and East Tennessee,
a $54 million increase in crude oil transportation revenues as a result of increased tariff rates mainly on the Express pipeline and higher volumes on the Express and Platte pipelines and
a $43 million increase in recoveries of electric power and other costs passed through to gas transmission customers, partially offset by
a $22 million decrease in processing revenues primarily due to lower prices, net of higher volumes,
an $18 million decrease in inventory settlement revenues due primarily to sales of excess tank oil in 2014 and lower crude oil prices on the Express and Platte pipelines,
an $8 million decrease in natural gas transportation revenues mainly from short-term firm and interruptible transportation on Texas Eastern and other revenue on East Tennessee, net of higher firm transportation on Algonquin and
a $6 million decrease in storage revenues due to lower rates.
Operating, Maintenance and Other. The $47 million increase was driven by:
a $43 million increase in electric power and other costs passed through to gas transmission customers,
a $9 million increase due to the non-cash impairment charge on Ozark Gas Gathering and
an $8 million increase in operating costs, net of employee benefit costs, partially offset by
a $21 million decrease due to lower ad valorem tax accruals and
a $5 million decrease from project development costs expensed in 2014.
Other Income and Expenses. The $97 million increase was primarily due to higher Allowance for Funds Used During Construction (AFUDC) resulting from higher capital spending and higher equity earnings from Sand Hills as a result of the continued ramp up and the expansion of the pipeline, as well as the fourth quarter 2014 dropdown of an additional 24.95% interest in SESH.
2014 Compared to 2013
Operating Revenues. The $304 million increase was driven by:
a $168 million increase due to expansion projects, primarily at Texas Eastern,
a $68 million increase primarily due to the acquisition of Express-Platte in March 2013,
a $44 million increase due to higher natural gas transportation revenues due to new contracts, mainly at Texas Eastern and Algonquin,
a $26 million increase in crude oil transportation revenues for both Express and Platte pipelines, mainly as a result of increased tariff rates and higher revenue volumes and

42



a $19 million increase due to higher processing revenues mainly due to volumes, partially offset by
a $25 million decrease in gas storage revenues due to lower rates.
Operating, Maintenance and Other. The $66 million increase was driven by:
a $33 million increase from expansion projects, primarily at Texas Eastern,
a $25 million increase due to the acquisition of Express-Platte and
a $10 million increase in operating costs mostly due to repairs and maintenance, partially offset by
an $11 million decrease mostly due to 2013 transaction costs related to the U.S. Assets Dropdown to SEP.
Other Income and Expenses. The $2 million decrease was primarily due to lower AFUDC, resulting from decreased capital spending, mostly offset by higher equity earnings due to the continued ramp up of volumes at Sand Hills and Southern Hills.
Matters Affecting Future Spectra Energy Partners Results
We plan to continue earnings growth through capital efficient projects, such as transportation and storage expansion to support a two-pronged “supply push” / “market pull” strategy, as well as continued focus on optimizing the performance of the existing operations through organizational efficiencies and cost control. “Supply push” is when producers agree to pay to transport specified volumes of natural gas in order to support the construction of new pipelines or the expansion of existing pipelines. “Market pull” is taking gas away from established liquid supply points and building pipeline transportation capacity to satisfy end-user demand in new markets or demand growth in existing markets. Future earnings growth will be dependent on the success of our 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.
Gas supply and demand dynamics continue to change as a result of the development of new non-conventional shale gas supplies. The increase in natural gas supply has resulted in declines in the price of natural gas in North America. As a result, a shift occurred to extraction of gas in richer, “wet” gas areas with higher NGL content which depressed activity in “dry” fields like the Fayetteville Shale formation where our Ozark assets are located. This, in turn, contributed to a resulting over-supply of pipeline take-away capacity in these areas. As the balance of supply and demand evolves, we expect activity in these areas to push prices higher. However, should supply and demand not come into balance, our businesses there may be subject to further possible impairment. The supply increase has also had a negative impact on the seasonal price spreads historically seen between the summer and winter months. The value of storage assets and contracts has declined in recent years, negatively affecting the results of our storage facilities. While we expect storage values to stabilize and strengthen in the future, should these market factors continue to keep downward pressure on the seasonality spread and re-contracting, we could be subject to further reduced value and possible impairment of our storage assets.
Spectra Energy Partners also plans to continue earnings growth by maximizing throughput on all sections of the Express-Platte system. This entails connecting, where possible, to rail or barge terminals to extend the market reach of the pipeline to refinery-customers beyond the end of the pipeline. This also includes optimizing pipeline and storage operations and expanding terminal operations where appropriate.
Future earnings growth will be dependent on the success in renewing existing contracts or in securing new supply and market for the pipelines. This will require ongoing increases in supply of crude oil and continued access to attractive markets.
Our interstate pipeline operations are subject to pipeline safety regulations administered by PHMSA of the DOT. 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.
PHMSA is designing an Integrity Verification Process intended to create standards to verify maximum allowable operating pressure, and to improve and expand integrity management processes. There remains uncertainty as to how these standards will be implemented, but it is expected that the changes will impose additional costs on new pipeline projects as well as on existing operations. In this climate of increasingly stringent regulation, pipeline failures or failures to comply with applicable regulations could result in a 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 an adverse effect on our operations, earnings, financial condition or cash flows.

43



Distribution 
 
2015
 
2014
 
Increase
(Decrease)
 
2013
 
Increase
(Decrease)
 
(in millions, except where noted)
Operating revenues
$
1,527

 
$
1,843

 
$
(316
)
 
$
1,848

 
$
(5
)
Operating expenses
 
 
 
 
 
 
 
 
 
Natural gas purchased
691

 
879

 
(188
)
 
826

 
53

Operating, maintenance and other
363

 
411

 
(48
)
 
448

 
(37
)
Other income and expenses

 
(1
)
 
1

 

 
(1
)
EBITDA
$
473

 
$
552

 
$
(79
)
 
$
574

 
$
(22
)
Number of customers, thousands
1,437

 
1,420

 
17

 
1,399

 
21

Heating degree days, Fahrenheit
7,387

 
8,111

 
(724
)
 
7,540

 
571

Pipeline throughput, TBtu (a)
759

 
713

 
46

 
907

 
(194
)
Canadian dollar exchange rate, average
1.28

 
1.10

 
0.18

 
1.03

 
0.07
____________
(a)
Trillion British thermal units.
2015 Compared to 2014
Operating Revenues. The $316 million decrease was driven by:
a $225 million decrease resulting from a weaker Canadian dollar,
a $114 million decrease in residential customer usage of natural gas, mainly due to weather that was warmer than in 2014 and
a $13 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, partially offset by
a $31 million increase from growth in the number of customers.
Natural Gas Purchased. The $188 million decrease was driven by:
a $98 million decrease resulting from a weaker Canadian dollar,
a $93 million decrease due to lower volumes of natural gas sold to residential customers primarily due to warmer weather,
a $13 million decrease from lower natural gas prices passed through to customers, partially offset by
a $20 million increase from growth in the number of customers.
Operating, Maintenance and Other. The $48 million decrease was driven by a $57 million decrease resulting from a weaker Canadian dollar.
2014 Compared to 2013
Operating Revenues. The $5 million decrease was driven by:
a $147 million decrease resulting from a weaker Canadian dollar,
an $8 million decrease in storage revenues primarily due to lower storage prices, partially offset by
an $81 million increase in customer usage of natural gas primarily due to weather that was colder than in 2013,
a $34 million increase from higher natural gas prices passed through to customers. Prices charged to customers are adjusted quarterly based on the 12 month NYMEX forecast and
a $34 million increase from growth in the number of customers.
Natural Gas Purchased. The $53 million increase was driven by:
a $65 million increase due to higher volumes of natural gas sold primarily due to colder weather,
a $34 million increase from higher natural gas prices passed through to customers and

44



a $25 million increase from growth in the number of customers, partially offset by
a $73 million decrease resulting from a weaker Canadian dollar.
Operating, Maintenance and Other. The $37 million decrease was driven by a $30 million decrease resulting from a weaker Canadian dollar.
Matters Affecting Future Distribution Results
Distribution plans to continue to expand the Dawn to Parkway transmission system in response to increased customer demand to access new supplies at Dawn. These expansions will consist of both compression and pipeline projects, and will lead to increased earnings. We expect that the long-term demand for natural gas in Ontario will remain relatively stable with continued growth in peak-day demands, subject to the impacts of future governmental actions to reduce greenhouse gas emissions. Some modest growth driven by low natural gas prices is expected to continue with specific interest coming from communities that are not currently serviced by natural gas, given the significant price advantage relative to their alternative energy options.
Natural gas storage prices have recently been compressed 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. Going forward, Union Gas expects some improvement in unregulated storage values.
During the past several years, the Canadian dollar has fluctuated compared to the U.S. dollar, which affected earnings to varying degrees. Changes in the exchange rate or any other factors are difficult to predict and may affect future results.
Western Canada Transmission & Processing 
 
2015
 
2014
 
Increase
(Decrease)
 
2013
 
Increase
(Decrease)
 
(in millions, except where noted)
Operating revenues
$
1,285

 
$
1,902

 
$
(617
)
 
$
1,767

 
$
135

Operating expenses
 
 
 
 
 
 
 
 
 
Natural gas and petroleum products purchased
193

 
466

 
(273
)
 
391

 
75

Operating, maintenance and other
611

 
687

 
(76
)
 
649

 
38

Other income and expenses
10

 
5

 
5

 
9

 
(4
)
EBITDA
$
491

 
$
754

 
$
(263
)
 
$
736

 
$
18

Pipeline throughput, TBtu
923

 
934

 
(11
)
 
780

 
154

Volumes processed, TBtu
658

 
721

 
(63
)
 
704

 
17

Canadian dollar exchange rate, average
1.28

 
1.10

 
0.18

 
1.03

 
0.07

2015 Compared to 2014
Operating Revenues. The $617 million decrease was driven by:
a $199 million decrease resulting from a weaker Canadian dollar,
a $194 million decrease due to lower NGL prices associated with the Empress operations,
a $141 million decrease due primarily to lower sales volumes of residual natural gas at the Empress operations,
a $108 million decrease arising from non-cash mark-to-market gains and losses associated with the risk management program at the Empress operations,
a $20 million decrease in transmission revenues due to lower interruptible transmission revenues and lower tolls charged to customers at M&N Canada and
a $14 million decrease in sales volumes of NGLs at the Empress operations, partially offset by
a $61 million increase from settlement gains associated with the risk management program at the Empress operations.

45



Natural Gas and Petroleum Products Purchased. The $273 million decrease was driven by:
a $160 million decrease due to lower volumes of natural gas purchases for extraction and make-up at the Empress operations,
a $67 million decrease primarily as a result of lower costs of sales at the Empress facility and
a $30 million decrease resulting from a weaker Canadian dollar.
Operating, Maintenance and Other. The $76 million decrease was driven by:
a $91 million decrease resulting from a weaker Canadian dollar and
an $18 million decrease primarily in costs passed through to customers at M&N Canada, partially offset by
an $18 million increase due to overhead reduction costs and
a $7 million non-cash asset impairment loss related to a natural gas processing plant.
2014 Compared to 2013
Operating Revenues. The $135 million increase was driven by:
a $112 million increase due primarily to higher sales volumes of residual natural gas at the Empress operations,
an $85 million increase from non-cash mark-to-market gains associated with the risk management program implemented in early 2014,
a $41 million increase due to higher propane prices associated with the Empress NGL business,
a $19 million increase in gathering and processing revenues from new facilities in the Horn River and Montney unconventional development areas,
a $17 million increase in gathering and processing revenues from existing facilities,
a $17 million increase from settlement gains associated with the risk management program implemented in early 2014,
a $13 million increase in transmission revenues due primarily to higher tolls at BC Pipeline,
an $8 million increase primarily in interruptible transmission revenues due to a new supply source connected to the M&N Canada system and
a $6 million increase in carbon and other non-income tax expense recovered from customers, partially offset by
a $143 million decrease as a result of a weaker Canadian dollar and
a $43 million decrease due to lower sales volumes of NGLs from decreased demand in the market at the Empress operations.
Natural Gas and Petroleum Products Purchased. The $75 million increase was driven by:
a $98 million increase due primarily to higher volumes of natural gas purchases for extraction and make-up at Empress and
a $19 million non-cash charge to reduce the value of propane inventory at the Empress operations to net realizable value at December 31, 2014, partially offset by
a $36 million decrease as a result of a weaker Canadian dollar and
an $8 million decrease primarily as a result of lower costs of NGL purchases at the Empress facility.
Operating, Maintenance and Other. The $38 million increase was driven by:
a $38 million increase in plant turnaround and repair costs,
a $9 million increase in Empress plant fuel costs due primarily to higher prices,
an $8 million increase in maintenance expense,
a $6 million increase primarily in costs passed through to customers at M&N Canada,
a $6 million increase in carbon and other non-income tax expense,

46



a $6 million increase in operating costs of new facilities and
a $5 million increase due to software support services, partially offset by
a $48 million decrease as a result of a weaker Canadian dollar.
Matters Affecting Future Western Canada Transmission & Processing Results
Western Canada Transmission & Processing plans to continue earnings growth through capital efficient “supply push” and “demand pull” initiatives. “Supply push” growth projects are associated with gathering and processing expansions and incremental transportation capacity to support drilling activity in northern BC. Sizable growth in production is being driven by the application of new drilling technologies to unconventional gas reservoirs, with current growth heaviest in the southern and northern sections of the Montney play. “Demand pull” growth projects are associated with both small and large scale LNG exports as well as new natural gas-fired electricity generation, methanol, and fertilizer plants in BC and the Pacific Northwest. Prolific nearby gas supplies and favorable international market access have made gas focused projects in BC and the U.S. Pacific Northwest very attractive. 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 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 NGL prices, gas flows eastbound beyond Empress and costs of acquiring natural gas, NGL extraction rights and NGLs.
During the past several years, the Canadian dollar has fluctuated compared to the U.S. dollar, which affected earnings to varying degrees for brief periods. Changes in the exchange rate are difficult to predict and may affect future results.
In certain areas of Western Canada Transmission & Processing’s operations, lower natural gas prices resulting from increasing North American gas production have reduced producer demand for both expansions of the BC 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
 
2015
 
2014
 
Increase
(Decrease)
 
2013
 
Increase
(Decrease)
 
(in millions, except where noted)
Earnings (loss) from equity investments
$
(461
)
 
$
217

 
$
(678
)
 
$
343

 
$
(126
)
EBITDA
$
(461
)
 
$
217

 
$
(678
)
 
$
343

 
$
(126
)
Natural gas gathered and processed/transported, TBtu/d (a,b)
7.1

 
7.3

 
(0.2
)
 
7.1

 
0.2

NGL production, MBbl/d (a)
410

 
454

 
(44
)
 
426

 
28

Average natural gas price per MMBtu (c,d)
$
2.66

 
$
4.41

 
$
(1.75
)
 
$
3.65

 
$
0.76

Average NGL price per gallon (e)
$
0.45

 
$
0.89

 
$
(0.44
)
 
$
0.90

 
$
(0.01
)
Average crude oil price per barrel (f)
$
48.80

 
$
93.06

 
$
(44.26
)
 
$
98.04

 
$
(4.98
)
____________

(a)
Reflects 100% of volumes.
(b)
Trillion British thermal units per day.
(c)
Average price based on NYMEX Henry Hub.
(d)
Million British thermal units.
(e)
Does not reflect results of commodity hedges.
(f)
Average price based on NYMEX calendar month.

47



2015 Compared to 2014
EBITDA. Lower equity earnings of $678 million were mainly the result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:
a $451 million decrease from commodity-sensitive processing arrangements, due to decreased NGL, crude oil and natural gas prices,
a $392 million decrease primarily as a result of goodwill and other asset impairments, net of tax impacts,
a $71 million decrease in gains associated with the issuance of partnership units by DCP Partners in 2015 compared to 2014 and
a $15 million decrease primarily attributable to higher depreciation expense as a result of asset growth, partially offset by
an $87 million increase in gathering and processing margins as a result of asset growth, net of volume declines in certain geographic regions,
an $81 million increase resulting from decreased net income attributable to noncontrolling interests as a result of unrealized derivative activity, goodwill impairment recognized during the year ended December 31, 2015 and a greater portion of distributions allocated to the general partner of DCP Partners through our incentive distribution rights, net of asset growth at DCP Partners,
a $36 million increase as a result of favorable results from ownership interests in NGL pipelines, primarily attributable to the ramp-up of the Sand Hills and Front Range pipelines and favorable results from the Wholesale Propane Logistics business,
a $24 million increase as a result of net gains on sales of assets in 2015, compared to a loss on the sale of an asset in 2014,
a $16 million increase primarily attributable to lower operating expenses as a result of cost savings initiatives in operations, net of additional costs from asset growth and
a $14 million increase as a result of favorable results from third-party derivative instruments used to mitigate a portion of its expected commodity cash flow risk.
2014 Compared to 2013
EBITDA. Lower equity earnings of $126 million were mainly the result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:
a $78 million decrease resulting from increased net income attributable to noncontrolling interests as a result of growth in DCP Partners’ operations, as well as the effects of dropdown hedges,
a $45 million decrease from commodity-sensitive processing arrangements, due to the impact of higher transportation and fractionation costs on our realized prices and decreased crude oil prices, partially offset by increased natural gas prices,
a $43 million decrease primarily attributable to higher operating expenses as a result of increased spending on reliability programs, as well as growth in Field Services’ operations,
a $26 million decrease primarily as a result of losses on sales of assets and a goodwill impairment charge in 2014 compared to gains on sales of assets in 2013,
a $25 million decrease in gains associated with issuances of partnership units by DCP Partners in 2014 compared to 2013,
a $19 million decrease mainly due to higher interest expense as a result of higher interest rates from newly issued debt and lower capitalized interest on certain projects which were placed in service in 2013 and
a $17 million decrease primarily attributable to higher depreciation expense as a result of growth in Field Services’ business, partially offset by
an $83 million increase in gathering and processing margins as a result of asset growth and higher volumes in certain of our geographic regions and
a $43 million increase as a result of DCP Partners’ favorable results from third-party mark-to-market on derivative instruments used to mitigate a portion of its expected commodity cash flow risk, favorable results from Sand Hills and

48



Southern Hills, and favorable results from NGL trading and gas marketing, partially offset by unfavorable results from wholesale propane.
Supplemental Data
Below is supplemental information for DCP Midstream’s operating results (presented at 100%): 
 
2015
 
2014
 
2013
 
(in millions)
Operating revenues
$
7,420

 
$
14,013

 
$
12,038

Operating expenses
8,227

 
13,262

 
11,230

Operating income (loss)
(807
)
 
751

 
808

Other income and expenses
182

 
83

 
35

Interest expense, net
320

 
287

 
249

Income tax expense (benefit)
(102
)
 
11

 
10

Net income (loss)
(843
)
 
536

 
584

Net income—noncontrolling interests
86

 
248

 
93

Net income (loss) attributable to members’ interests
$
(929
)
 
$
288

 
$
491

Matters Affecting Future Field Services Results
The oil and gas industry is cyclical, with the operating results of companies in the industry significantly affected by drilling activity, which may be impacted by prevailing commodity prices. DCP Midstream’s business has commodity price exposure as a result of being compensated for certain services in the form of commodities rather than cash. Commodity prices have declined substantially and have experienced significant volatility. This has significantly reduced DCP Midstream’s earnings and cash flows as compared to prior years. If commodity prices continue to remain weak for a sustained period, our natural gas throughput and NGL volumes may be further impacted, particularly as producers are curtailing or redirecting drilling, which could further reduce our earnings and cash flows. Drilling activity levels vary by geographic area, but in general, we have observed widespread decreases in drilling activity with lower commodity prices.
Continued lower commodity prices could result in further decreases in exploration and development activities in the fields served by our gas gathering and residue gas and NGL pipeline transportation systems, and our natural gas treating and processing plants, which could lead to reduced utilization of these assets. Despite current weakness, our long-term view is that commodity prices will be at levels that we believe will support natural gas, condensate and NGL production. We believe that future commodity prices will be influenced by North American supply deliverability, the severity of winter and summer weather, the level of North American production and drilling activity by exploration and production companies and balance of trade between imports and exports of liquid natural gas and NGLs.
NGL prices are impacted by the demand from petrochemical and refining industries and export facilities. The petrochemical industry has been making significant investment in building and expanding facilities to convert chemical plants from a heavier oilbased feedstock to lighter NGL-based feedstocks, including ethane. This increased demand in future years as such facilities come into service should provide support for the increasing supply of ethane. Prior to those facilities commencing operations ethane prices could remain weak with supply in excess of demand. In addition, export facilities are being expanded and built, which should provide support for the increasing supply of NGLs. Although there can be, and has been, near-term volatility in NGL prices, longer term we believe that there will be sufficient demand in NGLs to support increasing supply.
Other
 
2015
 
2014
 
Increase
(Decrease)
 
2013
 
Increase
(Decrease)
 
(in millions)
Operating revenues
$
73

 
$
72

 
$
1

 
$
72

 
$

Operating expenses
 
 
 
 
 
 
 
 
 
Operating, maintenance and other
457

 
141

 
316

 
185

 
(44
)
Other income and expenses

 
11

 
(11
)
 
27

 
(16
)
EBITDA
$
(384
)
 
$
(58
)
 
$
(326
)
 
$
(86
)
 
$
28


49



2015 Compared to 2014
EBITDA. The $326 million change primarily reflects goodwill impairment charges associated with the Westcoast acquisition in 2002.
2014 Compared to 2013
EBITDA. The $28 million change reflects lower transaction costs associated with the U.S. Assets Dropdown and lower employee benefit costs, partially offset by a 2013 benefit from the reversal of an uncertain tax position related to matters prior to the spin-off of Spectra Energy in 2007.
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.
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 may 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, regulatory 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 $1,397 million as of December 31, 2015 and $1,494 million as of December 31, 2014. Total regulatory liabilities were $385 million as of December 31, 2015 and $430 million as of December 31, 2014.
Impairment of Goodwill
We had goodwill balances of $4,154 million at December 31, 2015 and $4,714 million at December 31, 2014. The decrease in goodwill in 2015 was primarily due to the $333 million impairment of goodwill of our BC Field Services business and our Empress NGL operations associated with the Westcoast acquisition in 2002, as well as the result of foreign currency translation.
As permitted under accounting guidance on testing goodwill for impairment, we perform either a qualitative assessment or a quantitative assessment of each of our reporting units based on management’s judgment. With respect to our qualitative assessments, we consider events and circumstances specific to us, such as macroeconomic conditions, industry and market considerations, cost factors and overall financial performance, when evaluating whether it is more likely than not that the fair values of our reporting units are less than their respective carrying amounts.
In connection with our quantitative assessments, we primarily use a discounted cash flow analysis to determine fair values of those reporting units. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in key markets

50



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 reporting units’ revenue, expense and capital expenditure projections.
Based on the results of our annual goodwill impairment testing, no indicators of impairment were noted and the fair values of the reporting units that we assessed at April 1, 2015 (our annual testing date) were in excess of their respective carrying values.
We believe the assumptions used in our analyses are appropriate and result in reasonable estimates of the fair values of our reporting units. However, the assumptions used are subject to uncertainty, and declines in the future performance or cash flows of our reporting units, changing business conditions, further sustained declines in commodity prices or increases to our weighted average cost of capital assumptions may result in the recognition of impairment charges, which could be significant.
No triggering events have occurred with our reporting units since the April 1, 2015 test that would warrant re-testing for goodwill impairment except for BC Field Services and Empress.
In the fourth quarter of 2015, we continued to assess goodwill at BC Field Services and Empress and performed further testing based on a combination of an income approach and a market approach. The impairment test resulted in recognition of a $270 million goodwill impairment for BC Field Services and a $63 million goodwill impairment for Empress which resulted in a total goodwill impairment of $333 million.
Due to the significant downturn in commodity prices, DCP Midstream performed a goodwill impairment test which was finalized in the third quarter of 2015. The impairment test was based on an internal discounted cash flow model taking into account various observable and non-observable factors, such as prices, volumes, expenses and discount rate. The impairment test resulted in DCP Midstream’s recognition of a $460 million goodwill impairment, which reduced our equity earnings from DCP Midstream by $123 million after-tax for the nine month period ending September 30, 2015.
Due to the impairment of goodwill recognized by DCP Midstream, we assessed our equity investment in DCP Midstream and determined that our investment’s fair value exceeded it's carrying value.
Revenue Recognition
Revenues from the transmission, storage, processing, distribution and sales of natural gas, from the transportation and storage of crude oil, 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 demographic and economic outcomes 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 the 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, as 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 2015, the assumed average return was 8.00% for the U.S. pension plan assets, 7.40% for the Canadian pension plan assets and 6.90% 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 cost and obligations are measured on a discounted basis, the discount rates used to determine the net periodic benefit cost and the benefit obligation are significant assumptions. Discount rates used for our defined benefit and other post-retirement benefit plans are based on the yields constructed from a portfolio of high-

51



quality bonds for which the timing and amount of cash outflows approximate the estimated payouts of the plans. Discount rates of 4.10% for the U.S. plans and 4.00% for the Canadian plans were used to calculate the 2015 net periodic benefit cost, and represent a weighted average of the applicable rates for all U.S. and Canadian plans, respectively. A 25 basis-point change in the discount rates would impact annual before-tax net periodic benefit cost by less than $1 million for U.S. plans and $4 million for Canadian plans. Discount rates of 4.44% for the U.S. plans and 4.03% for the Canadian plans were used to calculate the 2015 year-end benefit obligations and represent a weighted average of the applicable rates for all U.S. and Canadian plans, respectively. The weighted average discount rates used to determine the benefit obligation increased approximately 0.35% for the U.S. plans and approximately 0.03% for the Canadian plans during 2015. The increase in the benefit obligation discount rate and actuarial experience during 2015 resulted in a decrease in benefit obligations at December 31, 2015 compared to December 31, 2014.
See Note 23 of Notes to Consolidated Financial Statements for more information on pension and other post-retirement benefits.
LIQUIDITY AND CAPITAL RESOURCES
Known Trends and Uncertainties
As of December 31, 2015, we had negative working capital of $1,744 million. This balance includes commercial paper liabilities totaling $1,112 million, current maturities of long-term debt of $652 million and a payable to an equity investment of $148 million. We will rely upon cash flows from operations and various financing transactions, which may include debt and/or equity issuances, to fund our liquidity and capital requirements for 2016. SEP is expected to be self-funding through its cash flows from operations, use of its revolving credit facility and its access to capital markets. We receive cash distributions from SEP in accordance with the partnership agreement, which considers our level of ownership and incentive distribution rights.
As of December 31, 2015, our four revolving credit facilities included Spectra Capital’s $1.0 billion facility, SEP’s $2.0 billion facility, Westcoast’s 400 million Canadian dollar facility and Union Gas’ 500 million Canadian dollar facility. These facilities are used principally as back-stops for commercial paper programs. At Spectra Capital, SEP and Westcoast, we primarily use commercial paper for temporary funding of capital expenditures. At Union Gas, we primarily use commercial paper to support short-term working capital fluctuations. 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 commercial paper, long-term debt (including current maturities), preferred stock of subsidiaries and total equity. As of December 31, 2015, our capital structure was 59.8% debt, 26.6% common equity of controlling interests and 13.6% noncontrolling interests and preferred stock of subsidiaries.
Cash flows from operations for our 100%-owned and majority-owned businesses are 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 investments and the timing of cost recoveries pursuant to regulatory approvals. See Part I. Item 1A. Risk Factors for further discussion.
Cash distributions from our equity investment, DCP Midstream, can fluctuate, mostly as a result of earnings sensitivities to commodity prices, as well as its level 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 its earnings, operating cash flows and other factors, including capital expenditures and other investing activities, commodity prices outlook and the credit environment. We received no tax or periodic distributions from DCP Midstream during 2015. We received total tax and periodic distributions from DCP midstream of $237 million in 2014 and $215 million in 2013. These distributions are classified within Operating Cash Flows. We continue to assess the effect of sustained lower 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. At December 31, 2015, $131 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

52



incremental U.S. tax liability. 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 the 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.
As we execute on our strategic objectives around organic growth and expansion projects, expansion expenditures are expected to approximate $3.7 billion in 2016 and $2.2 billion in 2017, excluding contributions from noncontrolling interests. 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 scheduled maturities of our existing debt instruments, capital resources will continue to include long-term borrowings and possibly securing additional sources of capital including debt and/or equity securities. We remain committed to maintaining a capital structure and liquidity profile that continue to support an investment-grade credit rating.
Cash Flow Analysis
The following table summarizes the changes in cash flows for each of the periods presented:
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
(in millions)
Net cash provided by (used in):
 
 
 
 
 
Operating activities
$
2,247

 
$
2,221

 
$
2,030

Investing activities
(2,782
)
 
(2,003
)
 
(3,236
)
Financing activities
540

 
(199
)
 
1,316

Effect of exchange rate changes on cash
(7
)
 
(5
)
 
(3
)
Net increase (decrease) in cash and cash equivalents
(2
)
 
14

 
107

Cash and cash equivalents at beginning of the period
215

 
201

 
94

Cash and cash equivalents at end of the period
$
213

 
$
215

 
$
201

Operating Cash Flows
Net cash provided by operating activities increased $26 million to $2,247 million in 2015 compared to 2014. This change was driven mostly by changes in working capital, mostly offset by lower earnings.
Net cash provided by operating activities increased $191 million to $2,221 million in 2014 compared to 2013. This change was driven mostly by:
higher earnings and
distributions from equity investments, partially offset by
changes in working capital.
Investing Cash Flows
Net cash flows used in investing activities increased $779 million to $2,782 million in 2015 compared to 2014. This change was driven mostly by:
a $685 million net increase in capital and investment expenditures and
a $248 million contribution to Gulfstream used to retire debt, partially offset by
a $396 million distribution received from Gulfstream with proceeds from a Gulfstream debt offering in 2015, compared to a $200 million distribution from SESH with proceeds from a SESH debt offering in 2014.
Net cash flows used in investing activities decreased $1,233 million to $2,003 million in 2014 compared to 2013. This change was driven mostly by:
a $1,254 million net cash outlay for the acquisition of Express-Platte in March 2013 and
a $179 million increase in distributions from equity investments in 2014, comprised mostly of a $200 million distribution from SESH with proceeds from a SESH debt offering, partially offset by

53



$6 million of net purchases of available-for-sale securities in 2014 compared to $146 million of net proceeds in 2013 and
a $28 million increase in capital and investment expenditures in 2014. Capital and investment expenditures include a $189 million investment in SESH, used by SESH to retire debt.
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 continuing operations.
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
(in millions)
Spectra Energy Partners (a,b)
$
2,007

 
$
1,241

 
$
1,299

Distribution
544

 
427

 
357

Western Canada Transmission & Processing
360

 
473

 
561

Total reportable segments
2,911

 
2,141

 
2,217

Other
61

 
146

 
42

Total consolidated
$
2,972

 
$
2,287

 
$
2,259

_____ ___
(a)
Excludes the $1,254 million net cash outlay for the acquisition of Express-Platte in March 2013. See Note 3 of Notes to Consolidated Financial Statements for further discussions.
(b)
Excludes a $71 million loan to an equity investment in 2013.
In March 2013, we acquired Express-Platte for $1.5 billion, consisting of $1.25 billion in cash and $260 million of acquired debt, before working capital adjustments. The acquisition was primarily funded through the issuance of stock in 2012 and debt. See Note 3 of Notes to Consolidated Financial Statements for further discussion of the acquisition of Express-Platte.
Capital and investment expenditures for 2015 totaled $2,972 million and included $2,281 million for expansion projects, $691 million for maintenance and other projects.
We project 2016 capital and investment expenditures of approximately $4.3 billion, consisting of approximately $2.7 billion for Spectra Energy Partners, $0.9 billion for Distribution and $0.7 billion for Western Canada Transmission & Processing. Total projected 2016 capital and investment expenditures include approximately $3.7 billion of expansion capital expenditures and $0.6 billion for maintenance and upgrades of existing plants, pipelines and infrastructure to serve growth. These capital and investment expenditures related to expansion exclude contributions from noncontrolling interests.
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 2015, including:
OPEN - A 550 million cubic feet per day (MMcf/d) expansion of the Texas Eastern pipeline system consisting of new pipeline, a new compressor station and other associated facility upgrades. The project is designed to transport gas produced in the Utica Shale and Marcellus Shale to U.S. markets in the Midwest, Southeast and Gulf Coast. The project was placed in-service during the second half of 2015.
SESH Dentville - Installation of a single compressor located near the SESH/Texas Eastern Interconnect to maintain deliveries from Texas Eastern into SESH with changing pressure profile on Texas Eastern due to mainline expansion projects. Additional capacity range of 474 MMcf/d max, 102.2 MMcf/d min. The project was placed in-service during the fourth quarter of 2015.
Uniontown to Gas City - The project provides shippers with 425 MMcf/d of firm transportation service from the supply-rich area west of Uniontown, Pennsylvania to a new delivery meter with Panhandle Eastern Pipe Line near Gas City, Indiana for further redelivery to markets in the Midwest. Five shippers combine to contract for the full 425 MMcf/d of capacity under the project. The project was placed in-service during the third quarter of 2015.
Bobcat Storage Expansion (Phase I and II) - The project as a whole is designed to expand the storage capacity and capabilities of Bobcat Gas Storage facility. Development of Cavern Well 5 increases the working gas capacity to 5.6 BCF and was placed in-service during the fourth quarter of 2015.

54



2015 Dawn to Parkway - A 397 MMcf/d expansion of the Dawn to Parkway transmission system that consisted of the Parkway West project which includes the development of a new Greenfield compressor site west of Toronto and the installation of two new compressors and associated infrastructure, the Parkway C and D compressor units and the Brantford-Kirkwall 48 inch pipeline loop.
Significant 2016 expansion projects expenditures are expected to include:
AIM - A 342 MMcf/d expansion of the Algonquin system consisting of replacement pipeline, new pipeline, new and modified meter station facilities and additional compression at existing stations. The project is designed to transport gas from existing interconnects in New Jersey and New York to LDC markets in the northeast. In-service is scheduled by the second half of 2016.
Ozark Conversion - The project includes abandonment of portions of the Ozark Gas Transmission system from natural gas service and leasing of the abandoned lines to Magellan to transport approximately 75,000 Bbls/d of refined products. Completion of Spectra’s scope of work occurred during the third quarter of 2015. Completion of Magellan’s scope of work and system in-service is expected during the first half of 2016.
Gulf Market Expansion - This Texas Eastern system expansion project connects growth markets (Gulf Coast LNG and industrials) with diverse, growing shale supply. The project consists of installing reverse-compression capability at six compressor stations to provide up to 650 MMcf/d. The project will be executed in two phases. Phase 1, due to go in-service in the second half of 2016, will provide north to south compression at five stations. Phase 2, due to go in-service in the second half of 2017, will provide north to south compression at one station and new compression at one existing compressor station and one new compressor station.
Loudon Expansion - This project will provide a customer with 40,000 decatherms per day (Dth/d) of incremental capacity. The project is expected to be in-service during the second half of 2016.
Sabal Trail - 1,100 MMcf/d of new capacity to access onshore shale gas supplies. Facilities include a new 465-mile pipeline, laterals and various compressor stations. The project is expected to be in-service during the first half of 2017.
Salem Lateral - An expansion of the Algonquin system for delivery of 115 MMcf/d of natural gas to the Footprint Salem Harbor Power Station in Salem, Massachusetts. The project is expected to be in-service during the second half of 2016.
Burlington-Oakville - 290 MMcf/d of new capacity for the Burlington/Oakville market. The project consists of 7 miles of 20 inch pipe. The project is expected to be in-service during the second half of 2016.
2016 Dawn Parkway - A 406 MMcf/d expansion of the Dawn to Parkway transmission system consisting of 12.4 miles of 48 inch Hamilton to Milton pipeline and the installation of a new compressor and associated infrastructure at Lobo. The project is expected to be in-service during the second half of 2016.
2017 Dawn Parkway - A 419 MMcf/d expansion of the Dawn to Parkway transmission system consisting of the addition of a new 44,500 horsepower compressor at each of our Dawn, Lobo and Bright Compressor Stations. Service to customers is expected in the second half of 2017.
Express Enhancement - This project will increase system capacity by 21,000 barrels per day. Facilities include the addition of tank storage at Hardisty, AB and Buffalo, MT and additional pumps at Buffalo, MT. The project is expected to be in-service during the second half of 2016.
High Pine Expansion - A 240 MMcf/d expansion of the T-North pipeline system consisting of two 42 inch pipeline loops and an additional compressor unit with associated infrastructure at the Sunset Creek compressor site. The project is expected to be in-service during the second half of 2016.
Jackfish Lake project - Consists primarily of two 36 inch pipeline loop additions totaling approximately 22 miles in length along the existing Fort St. John Mainline that will carry up to approximately 140 MMcf/d of gas from numerous receipt points in the South Montney production area. This project is expected to be in service within the first half of 2017.
Reliability and Maintainability (RAM) project - Designed to enhance the performance of the T-South system to accommodate the increased base load on the system being driven by increased production in Northeast BC. This project is expected to be in service in various stages in 2016 to 2018.

55



Financing Cash Flows and Liquidity
Net cash provided by financing activities totaled $540 million in 2015 compared to $199 million used in financing activities in 2014. This $739 million change was driven mostly by:
$1,300 million of net proceeds from long-term debt in 2015, compared to net repayments of long-term debt of $156 million in 2014 and
$546 million proceeds from the issuance of SEP units in 2015, compared to $327 million in 2014, partially offset by
commercial paper redemptions of $439 million in 2015, compared to commercial paper issuances of $574 million in 2014.
Net cash used in financing activities totaled $199 million in 2014 compared to $1,316 million provided by financing activities in 2013. This $1,515 million change was driven mostly by:
$156 million of net redemptions of long-term debt in 2014 compared to $2,233 million of net issuances in 2013 which were mostly used to fund the acquisition of Express-Platte and the U.S. Assets Dropdown, partially offset by
$574 million of net commercial paper issuances in 2014 compared to $206 million of net commercial paper repayments in 2013,
$327 million in proceeds from SEP’s at-the-market program in 2014 compared to $214 million in proceeds from SEP’s issuance of units in 2013, and
$145 million of contributions from noncontrolling interest in 2014 compared to $23 million in 2013.
Significant Financing Activities—2015
Debt Issuances.   The following long-term debt issuances were completed during 2015 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)
 
 
 
 
SEP
$
500

 
3.50
%
 
2025
SEP
500

 
4.50
%
 
2045
Westcoast
222

(a)
3.77
%

2025
Westcoast
37

(a)
4.79
%
 
2041
Union Gas
152

(a)
3.19
%

2025
Union Gas
190

(a)
4.20
%

2044
  __________________
(a)
U.S. dollar equivalent at time of issuance.
SEP Common Unit Issuances. In March 2015, SEP entered into an equity distribution agreement under which it may sell and issue common units up to an aggregate offering price of $500 million, and in December 2015 SEP replaced the equity distribution agreement. The terms of this new equity distribution agreement are substantially similar to those in SEP’s previous agreements and allow SEP to sell and issue up to an aggregate offering price of $1 billion of common units. This at-the-market offering program allows SEP to offer and sell its common units, representing limited partner interests, at prices it deems appropriate through a sales agent. Sales of common units, if any, will be made by means of ordinary brokers’ transactions on the NYSE, in block transactions, or as otherwise agreed to between SEP and the sales agent.
SEP issued 12.0 million limited partner units to the public in 2015 under its at-the-market program and approximately 245,000 general partner units to Spectra Energy. Total net proceeds to SEP were $557 million (net proceeds to Spectra Energy were $546 million). The net proceeds were used for SEP’s general partnership purposes, which may have included debt repayments, capital expenditures and/or additions to working capital.
Westcoast Preferred Stock Issuance. On December 15, 2015, Westcoast issued 4.6 million Cumulative 5-Year Minimum Rate Reset Redeemable First Preferred Shares, Series 10 for an aggregate principal amount of 115 million Canadian dollars (approximately $84 million as of the issuance date). Net proceeds from the issuance were used to fund capital expenditures, to refinance maturing debt obligations and for other corporate purposes.

56



Significant Financing Activities—2014
Debt Issuances.    The following long-term debt issuances were completed during 2014: 
 
Amount
 
Interest Rate
 
Due Date
 
(in millions)
 
 
 
 
Spectra Capital
$
300

 
variable

 
2018
Westcoast
316

(a)
3.43
%
 
2024
Union Gas
229

(a)
4.20
%
 
2044
Union Gas
183

(a)
2.76
%
 
2021
 __________________
(a)
U.S. dollar equivalent at time of issuance.
SEP Common Unit Issuances. SEP issued 6.4 million limited partner units to the public in 2014 under its at-the-market program and approximately 132,000 general partner units to Spectra Energy. Total net proceeds to SEP were $334 million (net proceeds to Spectra Energy were $327 million). The net proceeds were used for SEP’s general partnership purposes, which may have included debt repayments, future acquisitions, capital expenditures and/or additions to working capital.
Significant Financing Activities—2013
Debt Issuances.    The following long-term debt issuances were completed during 2013: 
 
Amount
 
Interest Rate
 
Due Date
 
(in millions)
 
 
 
 
Spectra Capital
$
1,200

(a) 
variable

 
N/A
Spectra Capital
650

  
3.30
%
 
2023
SEP
1,000

  
4.75
%
 
2024
SEP
500

  
2.95
%
 
2018
SEP
400

  
5.95
%
 
2043
SEP
400

  
variable

 
2018
Union Gas
237

(b) 
3.79
%
 
2023
 __________________
(a)
Repaid in the fourth quarter of 2013.
(b)
U.S. dollar equivalent at time of issuance.
SEP Common Unit Issuances. SEP issued 0.6 million common units to the public in 2013 under its at-the-market program, for total net proceeds of $24 million.
In April 2013, SEP issued 5.2 million common units to the public, representing limited partner interests, and 0.1 million general partner units to Spectra Energy. Total net proceeds to SEP were $193 million (net proceeds to Spectra Energy were $190 million). Net proceeds to SEP were temporarily invested in restricted available-for-sale securities until the Express-Platte dropdown, at which time the funds were partially used to pay for a portion of the transaction. See Note 2 of Notes to Consolidated Financial Statements for a discussion of the Express-Platte transaction with SEP.

57



Available Credit Facilities and Restrictive Debt Covenants
 
Expiration
Date
 
Total
Credit
Facilities
Capacity
 
Commercial Paper Outstanding at December 31, 2015
 
Available
Credit
Facilities
Capacity
 
 
 
(in millions)
Spectra Energy Capital, LLC (a)
2019
 
$
1,000

 
$
481

 
$
519

SEP (b)
2019
 
2,000

 
476

 
1,524

Westcoast (c)
2019
 
289

 
6

 
283

Union Gas (d)
2019
 
361

 
149

 
212

Total
 
 
$
3,650

 
$
1,112

 
$
2,538

  __________________
(a)
Revolving credit facility contains a covenant requiring the Spectra Energy consolidated debt-to-total capitalization ratio, as defined in the agreement, to not exceed 65%. Per the terms of the agreement, collateralized debt is excluded from the calculation of the ratio. This ratio was 59.6% at December 31, 2015.
(b)
Revolving credit facility contains a covenant that requires SEP to maintain a ratio of total Consolidated Indebtedness-to-Consolidated EBITDA, as defined in the agreement, of 5.0 to 1 or less. As of December 31, 2015, this ratio was 3.6 to 1.
(c)
U.S. dollar equivalent at December 31, 2015. The revolving credit facility is 400 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 35.4% at December 31, 2015.
(d)
U.S. dollar equivalent at December 31, 2015. The revolving credit facility is 500 million Canadian dollars and contains a covenant that requires the Union Gas debt-to-total capitalization ratio to not exceed 75% and a provision which requires Union Gas to repay all borrowings under the facility for a period of two days during the second quarter of each year. The ratio was 67.8% at December 31, 2015.
The issuances of commercial paper, letters of credit and revolving borrowings reduce the amounts available under the credit facilities. As of December 31, 2015, there were no letters of credit issued or revolving borrowings outstanding under the credit facilities.
Our credit agreements contain various 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, 2015, we were in compliance with those covenants. In addition, our credit agreements allow for acceleration of payments or termination of the agreements due to nonpayment, or in some cases, due to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. 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 agreements require our consolidated debt-to-total-capitalization ratio, as defined in the agreement, to be 65% or lower. Per the terms of the agreement, collateralized debt is excluded from the calculation of the ratio. This ratio was 59.6% at December 31, 2015. 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, 2015, however, it is not likely that a material adverse effect would occur as a result of a weakened Canadian dollar.
Dividends.    Our near-term objective is to increase our cash dividend by $0.14 per share, per year, through 2018. 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. We declared a quarterly cash dividend of $0.405 per common share on January 05, 2016 payable on March 08, 2016 to shareholders of record at the close of business on February 12, 2016.
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 unlimited amounts of various equity and debt securities. SEP has an effective shelf registration statement on file with the SEC to register the issuance of unlimited amounts of limited partner common units. SEP also has $944 million available as of December 31, 2015 for the issuance of limited partner common units under another effective shelf registration statement on file with the SEC related to its at-the-market program. Westcoast and Union Gas have an aggregate 1.7 billion Canadian dollars (approximately $1.2 billion) available as of December 31, 2015 for the issuance of debt securities in the Canadian market under their medium term note shelf prospectuses.

58



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 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.

59



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 Current Liabilities on the December 31, 2015 Consolidated Balance Sheet other than Current Maturities of Long-Term Debt. It is expected that the majority of Current Liabilities will be paid in cash in 2016.
Contractual Obligations as of December 31, 2015
 
Payments Due By Period
 
Total
 
2016
 
2017 &
2018
 
2019 &
2020
 
2021 &
Beyond
 
(in millions)
Long-term debt (a)
$
20,472

 
$
1,300

 
$
4,038

 
$
2,635

 
$
12,499

Operating leases (b)
334

 
49

 
80

 
66

 
139

Purchase Obligations: (c)
 
 
 
 
 
 
 
 
 
Firm capacity payments (d)
2,786

 
188

 
424

 
284

 
1,890

Energy commodity contracts (e)
240

 
227

 
13

 

 

Other purchase obligations (f)
532

 
418

 
58

 
34

 
22

Other long-term liabilities on the Consolidated Balance Sheet (g)
54

 
46

 
8

 

 

Total contractual cash obligations
$
24,418

 
$
2,228

 
$
4,621

 
$
3,019

 
$
14,550

__________
(a)
See Note 15 of Notes to Consolidated Financial Statements. Amounts include principal payments and estimated scheduled interest payments over the life of the associated debt and capital lease obligations.
(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, 2015.
(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 2016 retirement plan contributions (see Note 23). We are unable to estimate retirement plan contributions beyond 2016 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 5) because we are uncertain as to the amount and/or timing of when cash payments will be required. Amounts also exclude deferred income taxes and investment tax credits on the Consolidated Balance Sheets since cash payments for income taxes are determined primarily by taxable income for each discrete fiscal year.
Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risks associated with commodity prices, credit exposure, interest rates, equity prices and foreign currency exchange rates. We have established comprehensive risk management policies to monitor and manage these market risks. Our Chief Financial Officer is responsible for the overall governance of managing credit risk and commodity price risk, including monitoring exposure limits.
Commodity Price Risk
We are exposed to the impact of market fluctuations in the prices of NGLs and natural gas purchased as a result of our investment in DCP Midstream, and the ownership of the NGL marketing operations in western Canada and processing associated with certain of 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.
Within the Western Canada Transmission & Processing segment, 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

60



transactions as well as commodity derivatives. In 2014, we implemented a commodity hedging program at Empress and have elected to not apply cash flow hedge accounting.
DCP Midstream manages its direct exposure to market prices separate from Spectra Energy, and utilizes various risk management strategies, including the use of commodity derivatives.
We are exposed to market price fluctuations of NGLs, natural gas and oil in our Field Services segment. Based on a sensitivity analysis as of December 31, 2015 and 2014, a 10¢ per-gallon change in NGL prices would affect our annual pre-tax earnings by approximately $40 million in 2016 and $55 million in 2015 for Field Services. For the same periods, a 50¢ per-MMBtu change in natural gas prices would affect our annual pre-tax earnings by approximately $18 million and $23 million, respectively, and a $10 per-barrel change in oil prices would affect our annual pre-tax earnings by approximately $20 million and $25 million, respectively.
Within the Western Canada Transmission & Processing segment, we have NGL marketing operations with contracts to buy and sell commodities, including natural gas, NGLs and other commodities that are settled by the delivery of the commodity or cash. With respect to the Empress assets in Western Canada Transmission & Processing, a 10¢ per-gallon change in NGL prices, primarily propane prices, would affect our annual pre-tax earnings by approximately $23 million in 2016. For the same period, a 50¢ per-MMBtu change in natural gas prices would affect our annual pre-tax earnings by approximately $6 million. These estimates do not include the effects of commodity derivatives or variability in business activity that may occur as a result of such things as changes in the demand for our products or changes in plant operations. Empress is also exposed to changes in the fair value of our commodity derivatives as a result of fluctuations in the market price of NGLs. At December 31, 2015, a 10¢ per-gallon movement in underlying commodity NGL prices would affect the estimated fair value of commodity derivatives by approximately $15 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 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 transmission, storage, and gathering and processing services are industrial end-users, marketers, exploration and production companies, LDCs and utilities located throughout the U.S. and Canada. Customers on the Express-Platte system are primarily refineries located in the Rocky Mountain and Midwestern states of the U.S. Other customers include oil producers and marketing entities. We have concentrations of receivables from natural gas utilities and their affiliates, industrial customers and marketers throughout these regions, as well as retail distribution customers in Canada. These concentrations of customers may affect our overall credit risk in that risk factors can negatively affect the credit quality of the entire sector. Credit risk associated with gas distribution services are primarily affected by general economic conditions in the service territory.
Where exposed to credit risk, we analyze the customers’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We also obtain parental guarantees, cash deposits or letters of credit from customers to provide credit support, where appropriate, based on our financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each contract. A significant amount of our credit exposures for transmission, 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.
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.

61



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, 2015, 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 $2,000 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, 2015, it was estimated that if short-term interest rates average 100 basis points higher (lower) in 2016 than in 2015, interest expense, net of offsetting interest income, would fluctuate by $35 million. Comparatively, based on a sensitivity analysis as of December 31, 2014, had short-term interest rates averaged 100 basis points higher (lower) in 2015 than in 2014, it was estimated that interest expense, net of offsetting interest income, would have fluctuated by approximately $32 million. These amounts were estimated by considering the effect of the hypothetical interest rates on variable-rate debt outstanding, adjusted for interest rate hedges, short term investments, and cash and cash equivalents outstanding as of December 31, 2015 and 2014.
Equity Price Risk
Our cost of providing non-contributory defined benefit retirement and postretirement benefit plans are dependent upon, among other things, rates of return on plan assets. These plan assets expose us to price fluctuations in equity markets. In addition, our captive insurance companies maintain various investments to fund certain business risks and losses. Those investments may, from time to time, include investments in equity securities. Volatility of equity markets, particularly declines, will not only impact our cost of providing retirement and postretirement benefits, but will also impact the funding level requirements of those benefits.
We manage equity price risk by, among other things, diversifying our investments in equity investments, setting target allocations of investment types, periodically reviewing actual asset allocations and rebalancing allocations if warranted, and utilizing 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 2015 would have resulted in an estimated net loss on the translation of local currency earnings of approximately $24 million on our Consolidated Statement of Operations. In addition, if a 10% devaluation had occurred on December 31, 2015, the Consolidated Balance Sheet would have been negatively impacted by $356 million through a cumulative translation adjustment in AOCI and, this devaluation would result in an immaterial impact to our debt-to-total capitalization ratio. At December 31, 2015, one U.S. dollar translated into 1.38 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
For information on other issues, see Notes 5 and 19 of Notes to Consolidated Financial Statements.

62



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, 2015 based on the criteria established in Internal Control - Integrated Framework (2013) 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, 2015.
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.


63



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, 2015 and 2014, and the related consolidated statements of operations, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2015. 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, 2015, based on criteria established in Internal Control - Integrated Framework (2013) 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, and 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, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, 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, 2015, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas
February 25, 2016

64



SPECTRA ENERGY CORP
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per-share amounts)
 
 
Years Ended December 31,
 
2015
 
2014
 
2013
Operating Revenues
 
 
 
 
 
Transportation, storage and processing of natural gas
$
3,225

 
$
3,291

 
$
3,128

Distribution of natural gas
1,320

 
1,583

 
1,577

Sales of natural gas liquids
209

 
497

 
440

Transportation of crude oil
357

 
302

 
224

Other
123

 
230

 
149

Total operating revenues
5,234

 
5,903

 
5,518

Operating Expenses
 
 
 
 
 
Natural gas and petroleum products purchased
835

 
1,219

 
1,139

Operating, maintenance and other
1,500

 
1,571

 
1,568

Depreciation and amortization
764

 
796

 
772

Property and other taxes
353

 
393

 
373

Impairment of goodwill and other
349

 

 

Total operating expenses
3,801

 
3,979

 
3,852

Operating Income
1,433

 
1,924

 
1,666

Other Income and Expenses
 
 
 
 
 
Earnings (loss) from equity investments
(290
)
 
361

 
445

Other income and expenses, net
114

 
59

 
124

Total other income and expenses
(176
)
 
420

 
569

Interest Expense
636

 
679

 
657

Earnings Before Income Taxes
621

 
1,665

 
1,578

Income Tax Expense
161

 
382

 
419

Net Income
460

 
1,283

 
1,159

Net Income—Noncontrolling Interests
264

 
201

 
121

Net Income—Controlling Interests
$
196

 
$
1,082

 
$
1,038

Common Stock Data