SE-2014.12.31 10K

 
 
 
 
 
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, 2014 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, 2014: $28,000,000,000
Number of shares of Common Stock, $0.001 par value, outstanding at January 31, 2015: 671,089,528
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement for the 2015 Annual Meeting of Shareholders are incorporated by reference in Part III.
 
 
 
 
 



SPECTRA ENERGY CORP
FORM 10-K FOR THE YEAR ENDED
DECEMBER 31, 2014
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 U.S. 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 Corp, through its subsidiaries and equity affiliates, owns and operates a large and diversified portfolio of complementary natural gas-related energy assets and is one of North America’s leading natural gas infrastructure companies. We also own and operate a crude oil pipeline system that connects Canadian and 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 United States, the Maritime Provinces in Canada, the Pacific Northwest in the United States and Canada, and in the province of Ontario, Canada. We also provide natural gas sales and distribution services to retail customers in Ontario, and natural gas gathering and processing services to customers in western Canada. 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 United States based on wellhead volumes, 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 295 billion cubic feet (Bcf) of net storage capacity in the United States 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 an 82% 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.), 49.9% of Southeast Supply Header, LLC (SESH), 33% of DCP Sand Hills Pipeline, LLC (Sand Hills), 33% of DCP Southern Hills Pipeline, LLC (Southern Hills), 50% of Steckman Ridge, LP (Steckman Ridge) and 50% of Gulfstream Natural Gas System, L.L.C. (Gulfstream). We own another 4% indirect interest in Sand Hills and 4% indirect interest in Southern Hills through our ownership interest in DCP Midstream, which is considered our Field Services segment.
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 and NGLs through interstate pipeline systems for customers in various regions of the midwestern, northeastern and southeastern United States and Canada. Its pipeline systems consist of approximately 17,000 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. Actual throughput and storage injections/withdrawals do not have a significant effect on revenues or earnings.
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 82% 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, one with 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 8,600 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 74 Bcf, owned by Market Hub and Bobcat.






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Algonquin
We have an effective 82% 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.




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East Tennessee
We have an effective 82% 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.





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Maritimes & Northeast Pipeline
We have an effective 64% 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 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.

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Ozark
We have an effective 82% ownership interest in Ozark Gas Transmission and Ozark Gas Gathering through our ownership of SEP. Ozark Gas Transmission consists of an approximately 530-mile natural gas transmission system extending from southeastern Oklahoma through Arkansas to southeastern Missouri. Ozark Gas Gathering consists of an approximately 365-mile natural gas gathering system, with associated compressor stations, that primarily serves Arkoma basin producers in eastern Oklahoma.
On April 28, 2014, Ozark Gas Transmission entered into an agreement with Magellan Midstream Partners, L.P. (Magellan) to lease an approximately 159-mile stretch of natural gas pipeline to Magellan and perform the necessary conversion work to allow for the transportation of petroleum liquids. Ozark Gas Transmission expects to receive approval from the FERC and begin the necessary conversion work by mid 2015.


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Big Sandy
We have an effective 82% ownership interest in Big Sandy, which was acquired in 2011, 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 41% 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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SESH
We have an effective 41% total investment in SESH, an approximately 290-mile natural gas transmission system, with associated compressor stations, operated jointly by Spectra Energy and CenterPoint Energy Southeastern Pipelines Holding, LLC (CenterPoint). 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 49.9% directly by SEP and 0.1% directly by Spectra Energy as part of our “Other” segment, with the remaining 50% owned by CenterPoint and Enable Midstream Partners, LP, collectively. Spectra Energy expects to contribute its remaining 0.1% interest in SESH to SEP in November 2015. Our investment in SESH is accounted for under the equity method of accounting.
Market Hub
We have an effective 82% ownership interest in Market Hub 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 48 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 eight pipeline systems, including the Texas Eastern system.
Saltville
We have an effective 82% 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 82% ownership interest in Bobcat through our ownership of SEP. Bobcat, an approximately 26 Bcf salt dome facility acquired in 2010, is strategically located on the Gulf Coast near Henry Hub, interconnecting with five major interstate pipelines, including Texas Eastern.

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Steckman Ridge
We have an effective 41% 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.
Express-Platte
We have an effective 82% ownership interest in Express-Platte, acquired in March 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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Sand Hills / Southern Hills
In 2012, we acquired direct one-third ownership interests in Sand Hills and Southern Hills. DCP Midstream Partners, LP (DCP Partners) (DCP Midstream’s publicly traded master limited partnership) and Phillips 66 also each own a direct one-third interest in each of the two pipelines. With our effective 82% ownership interest of SEP and our 50% ownership interest of DCP Midstream, we have 31% effective ownership interests in Sand Hills and Southern Hills. Our investments in Sand Hills and Southern Hills are accounted for under the equity method of accounting.
The Sand Hills pipeline is an approximately 900 mile pipeline engaged in the business of transporting NGLs and provides takeaway service from the Permian and Eagle Ford basins to fractionation facilities along the Texas Gulf Coast and the Mont Belvieu, Texas market hub. The Southern Hills pipeline is also an approximately 900 mile pipeline engaged in the business of transporting NGLs and provides takeaway service from the Midcontinent to fractionation facilities along the Texas Gulf Coast and the Mont Belvieu, Texas market hub. The Sand Hills and Southern Hills pipelines were placed into service in the second quarter of 2013.
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.
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.

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In transporting NGLs, Sand Hills and Southern Hills compete with a number of major interstate and intrastate pipelines, including those affiliated with major integrated oil companies, and rail and truck fleet operations. In general, Sand Hills and Southern Hills compete with these entities in terms of transportation fees, reliability and quality of customer 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 United States. 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.
Sand Hills and Southern Hills generate the majority of their revenues from fee-based arrangements. The revenues earned by Sand Hills and Southern Hills are for long-term contracts relating to the transportation of NGLs and generally are not dependent on commodity prices.


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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 United States.
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 160 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 bases 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 and 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. Throughput for the BC Pipeline totaled 801 trillion British thermal units (TBtu) in 2014, compared to 699 TBtu in 2013 and 662 TBtu in 2012.
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 nine 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 700 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 United States. 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 Exxon Mobil Corporation and Emera, Inc. M&N Canada facilities include associated compressor stations and has 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. Customer demands for toll certainty and lower cost-tailored services have promoted increased competition from other midstream service companies and producers.
Natural gas competes with other forms of energy available to Western Canada Transmission & Processing’s customers and end-users, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability or price of natural gas, NGLs and other forms of energy, levels of business activity, long-term economic conditions, conservation, legislation, governmental regulations, the ability to convert to alternative fuels, weather and other factors affect the demand for natural gas in the areas that Western Canada Transmission & Processing serves.
In addition to the fee-for-service pipeline and gathering and processing businesses, we compete with other NGL extraction facilities at Empress, Alberta for the right to extract and purchase NGLs from natural gas shippers on the TransCanada pipeline system. To extract and acquire NGLs, we must be competitive in the 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 United States and Canada) using the southern portion of the transmission pipeline and markets in Alberta through pipeline interconnects in northern British Columbia with Nova Gas Transmission Ltd. (Nova). 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 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. 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. Effective January 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 a 22% interest in 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.
DCP Midstream owns or operates assets in 17 states in the United States. DCP Midstream’s gathering systems include connections to several interstate and intrastate natural gas and NGL pipeline systems, one natural gas storage facility and one NGL storage facility. DCP Midstream operates in a diverse number of regions, including the Permian Basin, Eagle Ford, Niobrara/DJ Basin and Midcontinent. DCP Midstream owns or operates approximately 68,000 miles of gathering and transmission pipeline.
As of December 31, 2014, 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, 2014, DCP Midstream owned or operated 12 fractionators. In addition, DCP Midstream operates a propane wholesale marketing business and a seven million barrel propane and butane storage facility in the northeastern United States.
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 individual consumers. DCP Midstream also stores residue natural gas at its 14 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

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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 Partners owns direct one-third ownership interests in the Sand Hills and Southern Hills NGL pipelines; SEP also owns direct one-third ownership interests. With our 50% ownership of DCP Midstream and our 82% ownership interest of SEP, we have 31% effective ownership interests in Sand Hills and Southern Hills. See “Business - Businesses - Spectra Energy Partners” for further discussion of Sand Hills and Southern Hills.
DCP Midstream’s operating results are significantly affected by changes in average NGL, natural gas and crude oil prices, which have fluctuated significantly over the last several years. DCP Midstream closely monitors the risks associated with these price changes. See Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk for a discussion of DCP Midstream’s exposure to changes in commodity prices.
Competition
In gathering, processing, 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 wind down period in December 2014, and expires in January 2019. DCP Midstream anticipates continuing to purchase and sell commodities with ConocoPhillips as a third-party and with Phillips 66 and CPChem as related parties, 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 70% 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

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to the volume of natural gas or NGLs that flows through its systems and is not dependent on commodity prices. 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 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 United States 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. 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 United States. 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.

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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 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 (British Columbia), the Environmental Protection and Enhancement Act (Alberta) and the Environmental Protection Act (Ontario) are provincial laws governing various aspects, including permitting and site remediation obligations, of our facilities and operations in those provinces.
The Canadian Environmental Protection Act, 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.

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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.
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 20, of Notes to Consolidated Financial Statements.
Except to the extent discussed in Notes 5 and 20, 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 19 of Notes to Consolidated Financial Statements.
Employees
We had approximately 5,900 employees as of December 31, 2014, including approximately 3,600 employees in Canada. In addition, DCP Midstream employed approximately 3,500 employees as of such date. Approximately 1,400 of our Canadian employees are subject to collective bargaining agreements governing their employment with us. Approximately 38% of those employees are covered under agreements that either have expired or will expire by December 31, 2015.

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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
50
President and Chief Executive Officer, Director
J. Patrick Reddy
62
Chief Financial Officer
Dorothy M. Ables
57
Chief Administrative Officer
Guy G. Buckley
54
Chief Development Officer
Julie A. Dill
55
Chief Communications Officer
Reginald D. Hedgebeth
47
General Counsel
William T. Yardley
50
President, U.S. Transmission and Storage
Allen C. Capps
44
Vice President and Controller
Laura Buss Sayavedra
47
Vice President and Treasurer
Gregory L. Ebel assumed his current position as President and Chief Executive Officer on January 1, 2009. He previously served as Group Executive and Chief Financial Officer 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 on January 1, 2014. Ms. Dill previously served as Group Vice President - Strategy from January 2013 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’s 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 on January 1, 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 2014 would have resulted in an estimated net loss on the translation of local currency earnings of approximately $44 million on our Consolidated Statement of Operations. In addition, if a 10% devaluation had occurred on December 31, 2014, the Consolidated Balance Sheet would have been negatively impacted by $499 million through a cumulative translation adjustment in Accumulated Other Comprehensive Income (AOCI). At December 31, 2014, one U.S. dollar translated into 1.16 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 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;

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the ability to construct projects within anticipated costs, including the risk of cost overruns resulting from inflation or increased costs of equipment, materials or labor, weather, geologic conditions or other factors beyond our control, that may be material; and
general economic factors that affect the demand for natural gas infrastructure.
Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated cost. As a result, new facilities may not achieve their expected investment return, which could affect our earnings, financial position and cash flows.
Gathering and processing, 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.
In 2010, serious pipeline incidents on systems unrelated to ours focused the attention of Congress and the public on pipeline safety. Legislative proposals were introduced in Congress to strengthen the PHMSA’s enforcement and penalty authority, and expand the scope of its oversight. In 2011, PHMSA initiated an Advance Notice of Proposed Rulemaking announcing its consideration of substantial revisions in its regulations to increase pipeline safety. In January 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 was signed into law. This Act (the 2012 PSA Amendments) amends the Pipeline Safety Act in a number of significant ways, including:
Authorizing PHMSA to assess higher penalties for violations of its regulations,
Requiring PHMSA to adopt appropriate regulations within two years requiring the use of automatic or remote-controlled shutoff valves on new or rebuilt pipeline facilities and to perform a study on the application of such technology to existing pipeline facilities in High Consequence Areas (HCAs),
Requiring operators of pipelines to verify maximum allowable operating pressure and report exceedances within five days,
Requiring PHMSA to study and report on the adequacy of soil cover requirements in HCAs, and
Requiring PHMSA to evaluate in detail whether integrity management requirements should be expanded to pipeline segments outside of HCAs (where the requirements currently apply).
Many of these legislative changes, such as increasing penalties, have been completed, while others are substantially in progress with resolution expected in 2015. Additionally, Congress is tasked with reauthorization of the Pipeline Safety Act during fiscal year 2015. 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

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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 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. 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.
Failure to comply with environmental regulations may result in the imposition of fines, penalties and injunctive measures affecting our operating assets. In addition, changes in environmental laws and regulations or the enactment of new environmental laws or regulations could result in a material increase in our cost of compliance with such laws and regulations. We may not be able to obtain or maintain from time to time all required environmental regulatory approvals for our operating assets or development projects. If there is a delay in obtaining any required environmental regulatory approvals, if we fail to obtain or comply with them or if environmental laws or regulations change or are administered in a more stringent manner, the operations of facilities or the development of new facilities could be prevented, delayed or become subject to additional costs. No assurance can be made that the costs that may be incurred to comply with environmental regulations in the future will not have a significant effect on our earnings and cash flows.
The enactment of climate change legislation or the adoption of regulations under the existing Clean Air Act could result in increased operating costs and delays in obtaining necessary permits for our capital projects.
The current international climate framework, the United Nations-sponsored Kyoto Protocol, prescribed specific targets to reduce GHG emissions for developed countries for the 2008-2012 period. The Kyoto Protocol expired in 2012 and had not been signed by the U.S.; however, at the Copenhagen Climate Change Summit in 2009, the U.S. indicated it would reduce carbon dioxide emissions by 17% below 2005 levels by 2020. The United Nations-sponsored international negotiations held in Durban, South Africa in 2011 resulted in a non-binding agreement (Durban Agreement) to develop a roadmap aimed at creating a global agreement on climate action to be implemented by 2020. The U.S. is a party to the Durban agreement. In the interim period before 2020, the Kyoto Protocol will continue in effect, although it is expected that not all of the current parties will choose to commit for this extended period.
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 GHGs 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

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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 greenhouse gas initiatives, and a number are developing their own programs that would mandate reductions in GHG emissions. Public interest groups 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.
In 2010, the EPA issued the Prevention of Significant Deterioration (PSD) and the Title V Greenhouse Gas Tailoring Rule (Tailoring Rule). Beginning in 2011, the Tailoring Rule required that construction of new or modification of existing major sources of GHG emissions be subject to the PSD air permitting program (and later, the Title V permitting program), although the regulation also significantly increased the emissions thresholds that would subject facilities to these regulations. The scope of the Tailoring rule was limited by a 2015 U.S. Supreme Court decision, which determined that sources which are major sources only for GHGs (Step 2 sources) are no longer subject to the PSD permitting process. EPA followed with guidance indicating it will not enforce PSD permitting against these Step 2 sources. However, some states incorporated GHG permitting into their state regulations, and may continue to enforce these requirements. We anticipate that in the future, some new capital projects or projects to modify existing facilities could be subject to additional state-required permitting requirements related to GHG emissions that may result in delays in completing such projects. In 2014, the EPA proposed revising regulations to the National Ambient Air Quality Standards (NAAQS) that would lower the existing standard from 75 parts per billion (ppb) set in 2008, to a standard between 65 and 70 ppb. This may increase the non-attainment areas along our system and the number of affected facilities. These facilities may require pollution control or replacement of equipment to comply with tightened standards and may face a less certain permitting process. In 2015, the Obama Administration issued its intention to regulate methane emissions from new and modified natural gas transmission and storage sources, and its expectation for voluntary emission decreases from existing sources. While uncertainty remains as to how this blueprint will be implemented, we anticipate that additional controls or costs may be incurred.
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 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.

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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 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 British Columbia and Alberta, which could affect future access to public lands, and the success of these claims could have a significant effect on natural gas production and processing.
Certain aboriginal groups have claimed aboriginal and treaty rights over a substantial portion of public lands on which our facilities in British Columbia and Alberta, and the gas supply areas served by those facilities, are located. The existence of these claims, which range from the assertion of rights of limited use to aboriginal title, has given rise to some uncertainty regarding access to public lands for future development purposes. Such claims, if successful, could have a significant effect on natural gas production in British Columbia and Alberta, which could have a material effect on the volume of natural gas processed at our facilities and of NGLs and other products transported in the associated pipelines. In addition, 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 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 high for companies, like us, operating in any energy infrastructure industry that handles volatile gaseous and liquid hydrocarbons. The potential for terrorism, including cyber-terrorism, has subjected our operations to increased risks that could have a material effect on our business. In particular, we may experience increased capital and operating costs to implement increased security for our facilities and pipelines, such as additional physical facility and pipeline security, and additional security personnel. Moreover, any physical damage to high profile facilities resulting from acts of terrorism may not be covered, or covered fully, by insurance. We may be required to expend material amounts of capital to repair any facilities, the expenditure of which could affect our business and cash flows.
Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.

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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, 2014, we had over 100 primary facilities located in the United States and Canada. We generally own sites associated with our major pipeline facilities, such as compressor stations. However, we generally operate our transmission 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 16 of Notes to Consolidated Financial Statements, none of our properties were secured by mortgages or other material security interests at December 31, 2014.
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 20 of Notes to Consolidated Financial Statements for discussions of other legal proceedings.
Item 4. Mine Safety Disclosures.
Not applicable.
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Our common stock is traded on the NYSE under the symbol “SE.” As of January 31, 2015, there were approximately 114,000 holders of record of our common stock and approximately 534,000 beneficial owners.
Common Stock Data by Quarter 
2014
 
Dividends Per
Common Share
 
Stock Price Range (a)
High
 
Low
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

2013
 
 
 
 
 
 
 
 
 
First Quarter
 
 
0.305

 
 
30.94

 
 
26.86

Second Quarter
 
 
0.305

 
 
34.83

 
 
29.62

Third Quarter
 
 
0.305

 
 
37.11

 
 
32.57

Fourth Quarter
 
 
0.305

 
 
36.16

 
 
32.80

 
________ _
(a)
Stock prices represent the intra-day high and low price.


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Stock Performance Graph

The following graph reflects the comparative changes in the value from January 1, 2010 through December 31, 2014 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,
2010
 
December 31,
 
 
2010
 
2011
 
2012
 
2013
 
2014
Spectra Energy Corp
 
$
100.00

 
$
127.46

 
$
163.20

 
$
151.07

 
$
204.03

 
$
215.48

S&P 500 Stock Index
 
100.00

 
115.06

 
117.49

 
136.30

 
180.44

 
205.14

S&P 500 Storage & Transportation Index
 
100.00

 
127.40

 
188.45

 
211.53

 
254.69

 
295.23

Dividends
Our near-term objective is to increase our cash dividend by $0.14 per year through 2017. 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.

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Item 6. Selected Financial Data.
The following selected financial data should be read in conjunction with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data.
 
 
2014
 
2013
 
2012
 
2011
 
2010
 
(dollars in millions, except per-share amounts)
Statements of Operations
 
 
 
 
 
 
 
 
 
Operating revenues
$
5,903

 
$
5,518

 
$
5,075

 
$
5,351

 
$
4,945

Operating income
1,924

 
1,666

 
1,575

 
1,763

 
1,674

Income from continuing operations
1,283

 
1,159

 
1,045

 
1,257

 
1,123

Net income—noncontrolling interests
201

 
121

 
107

 
98

 
80

Net income—controlling interests
1,082

 
1,038

 
940

 
1,184

 
1,049

Ratio of Earnings to Fixed Charges
3.6

 
2.9

 
2.8

 
3.4

 
3.1

Common Stock Data
 
 
 
 
 
 
 
 
 
Earnings per share from continuing operations
 
 
 
 
 
 
 
 
 
Basic
$
1.61

 
$
1.55

 
$
1.44

 
$
1.78

 
$
1.61

Diluted
1.61

 
1.55

 
1.43

 
1.77

 
1.60

Earnings per share
 
 
 
 
 
 
 
 
 
Basic
1.61

 
1.55

 
1.44

 
1.82

 
1.62

Diluted
1.61

 
1.55

 
1.43

 
1.81

 
1.61

Dividends per share
1.375

 
1.22

 
1.145

 
1.06

 
1.00

 
 
December 31,
 
2014
 
2013
 
2012
 
2011
 
2010
 
(in millions)
Balance Sheets
 
 
 
 
 
 
 
 
 
Total assets
$
34,040

 
$
33,533

 
$
30,587

 
$
28,138

 
$
26,686

Long-term debt including capital leases, less current maturities
12,769

 
12,488

 
10,653

 
10,146

 
10,169



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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
INTRODUCTION
Management’s Discussion and Analysis should be read in conjunction with Item 8. Financial Statements and Supplementary Data.
EXECUTIVE OVERVIEW
Throughout 2014, 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 fourth quarter of 2014 to $0.37 per share, which represents an increase in our annual dividend by $0.14 per share.
During 2014, our earnings benefited from expansion projects and the acquisition of Express-Platte at Spectra Energy Partners, higher earnings from our Empress NGL business at Western Canada Transmission & Processing, and higher customer usage due primarily to colder weather at Distribution. These favorable results were partially offset by a weaker Canadian dollar at Distribution and Western Canada Transmission & Processing, and an increase in net income attributable to noncontrolling interests as a result of growth in DCP Partners’ operation and the effects of dropdown hedges and lower commodity prices at Field Services.
We reported net income from controlling interests of $1,082 million and $1.61 of diluted earnings per share for 2014 compared to net income from controlling interests of $1,038 million and $1.55 of diluted earnings per share for 2013.
Earnings highlights for 2014 compared to 2013 include the following:
Spectra Energy Partners’ earnings increased mainly due to expansion projects, primarily at Texas Eastern, higher earnings from the continued ramp up of volumes at Sand Hills and Southern Hills, 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 pipelines mainly as a result of increased tariff rates and higher revenue volumes, partially offset by lower storage revenues due to lower rates and lower allowance for funds used during construction (AFUDC) due to decreased capital spending.
Distribution’s earnings decreased mainly due to a weaker Canadian dollar, lower storage revenues due to lower prices and 2014 earnings to be shared with customers under the new incentive regulation framework, partially offset by higher customer usage primarily as a result of colder weather and increased customer growth.
Western Canada Transmission & Processing’s earnings benefited from higher earnings at the Empress NGL business mainly due to non-cash mark-to-market gains associated with the risk management program implemented in early 2014 and higher propane prices, and higher gathering and processing revenues, partially offset by higher plant turnaround and maintenance costs and the effect of a weaker Canadian dollar.
Field Services’ earnings decreased, reflecting mainly an increase in net income attributable to noncontrolling interests as a result of growth in DCP Partners’ operations and the effects of dropdown hedges, lower commodity prices, higher operating costs, losses on sales of assets and a goodwill impairment in 2014 compared to gains on sales of assets in 2013, and lower gains associated with the issuance of partnership units by DCP Partners, partially offset by increased gathering and processing margins due to asset growth and higher volumes, and favorable results from trading and marketing and DCP Partners’ mark-to-market activity.
We invested $2.3 billion of capital and investment expenditures in 2014, including $1.5 billion of expansion and investment capital expenditures. Successful execution of our 2014 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 $2.7 billion planned for 2015. 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. In 2015, we plan to issue approximately $1.7 billion of

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combined long-term debt and commercial paper, including the refinancing of approximately $0.3 billion of long-term debt maturities. As of December 31, 2014, 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, 2014 and 2013, our debt-to-capitalization ratio was 58%.
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 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.
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 natural gas-fired generation, growth in industrial markets, incremental gathering and processing requirements in western Canada, LNG exports in North America, growth related to moving new sources of gas supplies to markets 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 increases. Growing North American crude oil production is displacing imports from overseas and driving increased demand for crude oil transportation and logistics. Although recent decreases in global crude oil prices may dampen near-term growth in North American oil production, we remain confident about the long-term proposition and our ability to capture future opportunities and grow our crude oil pipeline business.
Successful execution of our strategy will be determined by such key factors as the continued production of, and the consumption of, natural gas, NGLs and crude oil within the United States and Canada, our ability to provide creative solutions for customers’ evolving energy needs, maintaining leadership as a safe and reliable operator, and continued successful execution on our capital projects.
We continue to be actively engaged in the national discussions in both the United States 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 British Columbia and the Pacific Northwest.
Our combined key natural gas markets—the northeastern and the southeastern United States, the Pacific Northwest, British Columbia and Ontario—are projected to continue to exhibit higher than average annual growth in natural gas demand

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versus the North American and continental United States 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 United States 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 and West Coast of the United States. Growth in our business is dependent on growing crude oil supply from North American sources and the ability of that supply to displace imported crude oil from overseas. The recent decline in crude oil prices may adversely affect the availability and cost-competitiveness of North American crude oil supply and 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 production have reduced producer demand for expansions of the British Columbia 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. Commodity prices have declined substantially, and experienced significant volatility during the latter part of 2014. The price of crude oil has continued to decline in the first part of 2015. If commodity prices remain weak for a sustained period, DCP Midstream’s natural gas throughput and NGL volumes will be negatively impacted, particularly as producers are curtailing or redirecting drilling. Drilling activity levels vary by geographic area, but in general, DCP Midstream has observed decreases in drilling activity with lower commodity prices. Furthermore a sustained 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 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, there has been a shift to extracting gas in richer, “wet” gas areas, like the Marcellus shale. This has depressed activity in “dry” fields like the Fayetteville shale where our Ozark gathering and transmission assets are located. As the balance of supply and demand evolves, we expect activity in these areas to push prices higher. However, should the activity in the region continue to decline, our businesses there may be subject to 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 United States 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 U.S. Department of Transportation. These laws and regulations require us to comply with a significant set of requirements for the design, construction, maintenance and operation of our interstate pipelines. In January 2012, the Pipeline Safety, Regulatory

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Certainty, and Job Creation Act of 2011 was signed into law. This Act amends the Pipeline Safety Act in a number of significant ways, including the assessing of higher penalties for violations.
Many of the changes to the Pipeline Safety Act have been completed, while others are substantially in progress with resolution expected in 2015. Additionally, Congress is tasked with reauthorization of the Pipeline Safety Act during fiscal year 2015. 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.
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 Specta 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 2015. Our overall expected tax rate largely depends on the proportion of earnings in the United States to the earnings of our Canadian operations. Our earnings in the United States 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 approximately 6% for 2015, 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.

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RESULTS OF OPERATIONS
 
2014
 
2013
 
2012
 
(in millions)
Operating revenues
$
5,903

 
$
5,518

 
$
5,075

Operating expenses
3,979

 
3,852

 
3,500

Operating income
1,924

 
1,666

 
1,575

Other income and expenses
420

 
569

 
465

Interest expense
679

 
657

 
625

Earnings from continuing operations before income taxes
1,665

 
1,578

 
1,415

Income tax expense from continuing operations
382

 
419

 
370

Income from continuing operations
1,283

 
1,159

 
1,045

Income from discontinued operations, net of tax

 

 
2

Net income
1,283

 
1,159

 
1,047

Net income—noncontrolling interests
201

 
121

 
107

Net income—controlling interests
$
1,082

 
$
1,038

 
$
940

2014 Compared to 2013
Operating Revenues. The $385 million, or 7%, 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 Distribution and Western Canada Transmission & Processing.
Operating Expenses. The $127 million, or 3%, 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.
Operating Income. The $258 million increase was driven by higher earnings 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 pipelines mainly as a result of increased tariff rates and higher volumes, net of lower storage revenues due to lower rates at Spectra Energy Partners. The increase was also attributable to non-cash mark-to-market gains associated with the risk management program implemented in early 2014 and higher propane prices from the Empress NGL business, and higher gathering and processing revenues, net of higher plant turnaround and maintenance costs at Western Canada Transmission & Processing. Furthermore, the increase reflected higher customer usage primarily as a result of colder weather and increased 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

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Distribution. These increases were 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, lower commodity prices, higher operating costs due to increased spending on reliability programs and growth in operations, losses on sales of assets and a goodwill impairment charge in 2014 compared to gains on sales of assets in 2013 and lower gains associated with the issuance of partnership units by DCP Partners, net of increased gathering and processing margins due to asset growth and higher volumes, favorable results from trading and marketing and DCP Partners’ mark-to-market activity. Lower AFUDC due to decreased capital spending at Spectra Energy Partners also contributed to the decrease. These decreases were partially offset by higher earnings from Sand Hills and Southern Hills at Spectra Energy Partners.
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 from Continuing Operations. 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 for income from continuing operations 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.
2013 Compared to 2012
Operating Revenues. The $443 million, or 9%, increase was driven by:
revenues from Express-Platte acquired in March 2013, net of lower recoveries of electric power and other costs passed through to customers, and lower storage revenues at Spectra Energy Partners,
higher customer usage of natural gas as a result of colder weather, higher natural gas prices passed through to customers, higher distribution rates, an adjustment in 2012 related to an unfavorable OEB decision affecting transportation revenues, and growth in the number of customers, net of lower short-term transportation and storage revenues at Distribution,
higher revenues from expansion projects at Western Canada Transmission & Processing and Spectra Energy Partners, and
higher NGL sales prices and volumes at the Empress operations, net of lower contracted volumes in the conventional gathering and processing business at Western Canada Transmission & Processing, partially offset by
the effects of a weaker Canadian dollar at Western Canada Transmission & Processing and Distribution.
Operating Expenses. The $352 million, or 10%, increase was driven by:
an increase in volumes of natural gas sold due to colder weather, higher natural gas prices passed through to customers, increased gas purchased due to growth in the number of customers and higher operating fuel costs at Distribution,
operating costs from Express-Platte, net of lower electric power and other costs passed through to customers at Spectra Energy Partners,
increased volumes of natural gas purchases for extraction and make-up at the Empress operations, higher depreciation expense from expansion projects, scheduled plant turnarounds in 2013, increased operating costs of new facilities and higher benefit and labor costs, net of lower production costs due primarily to lower extraction premiums and a noncash charge in 2012 to write down propane inventory at the Empress operations, at Western Canada Transmission & Processing, and

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higher corporate costs driven primarily by transaction costs associated with the U.S. Assets Dropdown and higher employee benefit costs, partially offset by
the effects of a weaker Canadian dollar at Distribution and Western Canada Transmission & Processing.
Operating Income. The $91 million increase was driven by the acquisition of Express-Platte and Texas Eastern expansion projects at Spectra Energy Partners, and higher NGL earnings at the Empress operations due mainly to lower production costs and higher sales prices, net of lower contracted volumes in the conventional gathering and processing business and higher operating and maintenance costs at Western Canada Transmission & Processing. In addition, higher distribution rates, a 2012 adjustment related to an unfavorable decision by the OEB affecting transportation revenues and colder weather, net of lower transportation and storage revenues at Distribution contributed to the increase in the Operating Income. These increases were partially offset by the effects of a weaker Canadian dollar and higher corporate costs.
Other Income and Expenses. The $104 million increase was attributable to higher equity earnings from Field Services mainly due to the gains associated with the issuance of partnership units by DCP Partners and lower operating costs, partially offset by higher interest expense and the effects of asset dropdowns from DCP Midstream to DCP Partners. The increase was also due to higher AFUDC resulting from increased capital spending on expansion projects at Spectra Energy Partners, partially offset by lower AFUDC at Western Canada Transmission & Processing due to decreased capital spending on expansion projects.
Interest Expense. The $32 million increase was mainly due to higher average debt balances related to the acquisition of Express-Platte, partially offset by a weaker Canadian dollar.
Income Tax Expense from Continuing Operations. The $49 million increase was mainly attributable to higher earnings, the revaluation of accumulated deferred state taxes as a result of the U.S. Assets Dropdown and the non-deductibility of transaction costs, partially offset by favorable enacted Canadian federal income tax legislation and the recognition of certain regulatory tax benefits. The effective tax rate for income from continuing operations was 27% in 2013 compared to 26% in 2012. 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 $14 million increase was driven by higher earnings from Spectra Energy Partners, the issuances of partnerships units by SEP to the public in 2012 and 2013, and the dropdown of a 38.76% interest in M&N U.S. to SEP in 2012, partially offset by the issuances of partnerships units by SEP to Spectra Energy in November 2013 in association with the U.S. Assets Dropdown.
For a more detailed discussion of earnings drivers, see the segment discussions that follow.
Segment Results
Management evaluates segment performance based on earnings from continuing operations before interest, taxes, and depreciation and amortization (EBITDA) transactions. 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 United States 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,

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2014 DCP Midstream had an approximate 22% 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
 
2014
 
2013
 
2012
 
(in millions)
Spectra Energy Partners
$
1,669

 
$
1,433

 
$
1,259

Distribution
552

 
574

 
587

Western Canada Transmission & Processing
754

 
736

 
694

Field Services
217

 
343

 
279

Total reportable segment EBITDA
3,192

 
3,086

 
2,819

Other
(58
)
 
(86
)
 
(36
)
Total reportable segment and other EBITDA
3,134

 
3,000

 
2,783

Depreciation and amortization
796

 
772

 
746

Interest expense
679

 
657

 
625

Interest income and other
6

 
7

 
3

Earnings from continuing operations before income taxes
$
1,665

 
$
1,578

 
$
1,415

The amounts discussed below include intercompany transactions that are eliminated in the Consolidated Financial Statements.
Spectra Energy Partners 
 
2014
 
2013
 
Increase
(Decrease)
 
2012
 
Increase
(Decrease)
 
(in millions, except where noted)
Operating revenues
$
2,269

 
$
1,965

 
$
304

 
$
1,754

 
$
211

Operating expenses
 
 
 
 
 
 
 
 
 
Operating, maintenance and other
781

 
715

 
66

 
626

 
89

Other income and expenses
181

 
183

 
(2
)
 
131

 
52

EBITDA
$
1,669

 
$
1,433

 
$
236

 
$
1,259

 
$
174

Express pipeline revenue receipts, MBbl/d (a,b)
223

 
219

 
4

 
N/A

 
N/A

Platte PADD II deliveries, MBbl/d (b)
170

 
168

 
2

 
N/A

 
N/A

____________
(a)
Thousand barrels per day.
(b)
Data includes only activity since March 14, 2013, the date of the acquisition of Express-Platte.

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
a $19 million increase due to higher processing revenues mainly due to volume, 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,

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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.
EBITDA. The $236 million increase was driven by expansions, primarily at Texas Eastern, higher earnings from Sand Hills and Southern Hills, the acquisition of Express-Platte, higher natural gas transportation revenues due to new contracts mainly at Texas Eastern and Algonquin, an 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 higher processing revenues, partially offset by lower storage revenues due to lower rates and lower AFUDC due to decreased capital spending.

2013 Compared to 2012
Operating Revenues. The $211 million increase was driven by:
a $286 million increase due to the acquisition of Express-Platte in March 2013 and expansion projects primarily at Texas Eastern, partially offset by
a $42 million decrease in recoveries of electric power and other costs passed through to customers,
a $24 million decrease due to lower storage revenues as a result of lower contract renewal rates, and
an $8 million decrease from lower processing revenues.
Operating, Maintenance and Other. The $89 million increase was driven by:
a $115 million increase from the acquisition of Express-Platte and expansion projects primarily at Texas Eastern,
a $10 million increase due to higher employee benefit costs and ad valorem taxes, net of lower software amortization, and
a $7 million charge for transaction costs related to the U.S. Assets Dropdown to SEP, partially offset by
a $42 million decrease in electric power and other costs passed through to customers.
Other Income and Expenses. The $52 million increase was primarily due to higher AFUDC resulting from increased capital spending on expansion projects.
EBITDA. The $174 million increase was driven by the acquisition of Express-Platte and higher earnings from expansions at Texas Eastern, partially offset by lower storage revenues, higher operating costs and lower processing revenues.
Matters Affecting Future Spectra Energy Partners Results
Spectra Energy Partners plans to continue earnings growth through capital efficient projects, such as transportation and storage expansion to support a two-pronged “supply push” / “market pull” strategy, as well as continued focus on optimizing the performance of the existing operations through organizational efficiencies and cost control. “Supply push” is when producers agree to pay to transport specified volumes of natural gas in order to support the construction of new pipelines or the expansion of existing pipelines. “Market pull” is taking gas away from established liquid supply points and building pipeline transportation capacity to satisfy end-user demand in new markets or demand growth in existing markets.
Future earnings growth will be dependent on the success of 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, there has been a shift to extracting gas in richer, “wet” gas areas, like the Marcellus shale. This has depressed activity in “dry” fields like the Fayetteville shale where our Ozark gathering and transmission assets are located. As the balance of supply and demand evolves, we expect activity in these areas to push prices higher. However, should the activity in the region continue to decline, our businesses there may be subject to possible impairment.

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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 plans to continue earnings growth by maximizing throughput on all sections of the pipeline systems. On 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. On the Southern Hills and Sand Hills NGL pipelines, volumes will continue to increase as NGL supply increases behind the system and new extraction plants are connected to the pipeline.  Extensions may be added to the lines and pumps may be added to increase capacity.
Future earnings growth will be dependent on the success in renewing existing contracts or in securing new supply and market for all pipelines. This will require ongoing increases in supply of both crude oil and NGL and continued access to attractive markets. For the NGL pipelines, continued growth is dependent on successful execution of expansion projects to attach new supply.
Spectra Energy Partners interstate pipeline operations are subject to pipeline safety regulations administered by PHMSA of the U.S. Department of Transportation. These laws and regulations require us to comply with a significant set of requirements for the design, construction, maintenance and operation of our interstate pipelines. In January 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 was signed into law. This Act amends the Pipeline Safety Act in a number of significant ways, including the assessing of higher penalties for violations.
Many of the changes to the Pipeline Safety Act have been completed, while others are substantially in progress with resolution expected in 2015. Additionally, Congress is tasked with reauthorization of the Pipeline Safety Act during fiscal year 2015. 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.
Distribution 
 
2014
 
2013
 
Increase
(Decrease)
 
2012
 
Increase
(Decrease)
 
(in millions, except where noted)
Operating revenues
$
1,843

 
$
1,848

 
$
(5
)
 
$
1,666

 
$
182

Operating expenses
 
 
 
 
 
 
 
 
 
Natural gas purchased
879

 
826

 
53

 
638

 
188

Operating, maintenance and other
411

 
448

 
(37
)
 
441

 
7

Other income and expenses
(1
)
 

 
(1
)
 

 

EBITDA
$
552

 
$
574

 
$
(22
)
 
$
587

 
$
(13
)
Number of customers, thousands
1,420

 
1,399

 
21

 
1,379

 
20

Heating degree days, Fahrenheit
8,111

 
7,540

 
571

 
6,385

 
1,155

Pipeline throughput, TBtu
713

 
907

 
(194
)
 
818

 
89

Canadian dollar exchange rate, average
1.10

 
1.03

 
0.07

 
1.00

 
0.03
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, and
a $7 million decrease due to 2014 earnings to be shared with customers under the new incentive regulation framework, partially offset by

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an $81 million increase in customer usage of natural gas primarily due to weather that was more than 7% 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 months New York Mercantile Exchange (NYMEX) forecasts,
a $34 million increase from growth in the number of customers, and
a $10 million increase, net of 2012 earnings sharing, as a result of a decision by the OEB in 2014 primarily regarding certain 2012 revenues realized from the optimization of upstream transportation contracts being treated as utility earnings.
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
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, and
a $7 million decrease resulting from the deferral of pension expense approved by the OEB for recovery from customers.
EBITDA. The $22 million decrease was largely the result of a weaker Canadian dollar, lower storage revenues and 2014 earnings to be shared with customers under the new incentive regulation framework, partially offset by higher customer usage due to colder weather, increased revenues, net of 2012 earnings sharing, as a result of a decision by the OEB in 2014 primarily regarding certain 2012 revenues realized from the optimization of upstream transportation contracts being treated as utility earnings and increased customer growth.
2013 Compared to 2012
Operating Revenues. The $182 million increase was driven by:
a $129 million increase in customer usage of natural gas primarily due to weather that was more than 18% colder than 2012,
a $59 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,
a $41 million increase from higher distribution rates approved by the OEB,
a $38 million increase due to an adjustment in 2012 as a result of an unexpected decision from the OEB in November 2012 requiring certain revenues realized from the optimization of upstream transportation contracts be refunded to customers, and
a $36 million increase from growth in the number of customers, partially offset by
a $55 million decrease resulting from a weaker Canadian dollar,
a $28 million decrease mainly in short-term transportation revenues due to lower exchange service revenues, net of a settlement received from the termination of a transportation contract,
a $21 million decrease in storage revenues primarily due to lower prices, and
a $20 million decrease as a result of the sharing of revenues realized from the optimization of upstream transportation contracts in accordance with an OEB rate order effective January 1, 2013.
Natural Gas Purchased. The $188 million increase was driven by:
a $103 million increase due to higher volumes of natural gas sold due to colder weather,
a $59 million increase from higher natural gas prices passed through to customers,
a $28 million increase from growth in the number of customers, and

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a $15 million increase in operating fuel costs primarily due to gas measurement variances, partially offset by
a $24 million decrease resulting from a weaker Canadian dollar.
Operating, Maintenance and Other. The $7 million increase was driven by:
a $20 million increase primarily driven by higher employee benefit costs, partially offset by
a $14 million decrease resulting from a weaker Canadian dollar.
EBITDA. The $13 million decrease was largely the result of lower transportation and storage revenues, higher employee benefit costs, a weaker Canadian dollar and higher operating fuel costs, partially offset by an increase in distribution rates, an adjustment in 2012 related to an unfavorable decision by the OEB affecting transportation revenues and higher customer usage due to colder weather.
Matters Affecting Future Distribution Results
Distribution plans to continue to expand the Dawn-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. The current 2015 Parkway site and compression expansion is under construction while the 2015 Brantford-Kirkwall pipeline and ancillary facilities are dependent on approval of a third party project, the approval of which is expected in mid 2015. We expect that the long-term demand for natural gas in Ontario will remain relatively stable with continued growth in peak-day demands. 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 unregulated storage values to stabilize and strengthen.
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 future results.
Western Canada Transmission & Processing 
 
2014
 
2013
 
Increase
(Decrease)
 
2012
 
Increase
(Decrease)
 
(in millions, except where noted)
Operating revenues
$
1,902

 
$
1,767

 
$
135

 
$
1,679

 
$
88

Operating expenses
 
 
 
 
 
 
 
 
 
Natural gas and petroleum products purchased
466

 
391

 
75

 
437

 
(46
)
Operating, maintenance and other
687

 
649

 
38

 
585

 
64

Other income and expenses
5

 
9

 
(4
)
 
37

 
(28
)
EBITDA
$
754

 
$
736

 
$
18

 
$
694

 
$
42

Pipeline throughput, TBtu
934

 
780

 
154

 
745

 
35

Volumes processed, TBtu
721

 
704

 
17

 
665

 
39

Canadian dollar exchange rate, average
1.10

 
1.03

 
0.07
 
1.00

 
0.03

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,

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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,
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.
Other Income and Expenses. The $4 million decrease was driven primarily by lower AFUDC resulting from decreased capital spending on expansion projects.
EBITDA. The $18 million increase was driven by higher earnings at the Empress NGL business due mainly to non-cash mark-to-market gains associated with the risk management program implemented in early 2014 and higher propane sales prices and higher gathering and processing revenues, partially offset by higher plant turnaround and maintenance expenses and the effect of a weaker Canadian dollar.
2013 Compared to 2012
Operating Revenues. The $88 million increase was driven by:
a $59 million increase in gathering and processing revenues due primarily to expansion in unconventional areas for Horn River and Montney development,
a $39 million increase due to higher sales prices associated with the Empress NGL business,
a $35 million increase due primarily to higher sales volumes of residual natural gas at the Empress operations,
a $22 million increase in transmission revenues due primarily to expansion on the T-North Pipeline,
a $17 million increase in NGL sales volumes at Empress,

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a $9 million increase in carbon and other non-income tax expense recovered from customers, and
a $9 million increase primarily driven by interruptible transmission revenues and higher 2013 tolls charged to customers at M&N Canada, partially offset by
a $58 million decrease as a result of a weaker Canadian dollar, and
a $44 million decrease in conventional gathering and processing revenues due primarily to lower contracted volumes.
Natural Gas and Petroleum Products Purchased. The $46 million decrease was driven by:
a $53 million decrease as a result of lower production costs for the Empress facility caused primarily by lower extraction premiums,
a $14 million decrease as a result of a weaker Canadian dollar, and
a $14 million noncash charge in 2012 to write down propane inventory at the Empress operations, partially offset by
a $35 million increase in volumes of natural gas purchases for extraction and make-up at Empress.
Operating, Maintenance and Other. The $64 million increase was driven by:
a $20 million increase due to scheduled plant turnarounds in 2013,
a $16 million increase due to operating costs of the new facilities at Dawson and Fort Nelson North,
a $14 million increase due to higher benefit and labor costs,
a $12 million increase primarily in costs passed through to customers at M&N Canada,
a $9 million increase in carbon and other non-income tax expense, and
a $6 million increase in Empress plant fuel and electricity costs due to higher prices, partially offset by
a $21 million decrease as a result of a weaker Canadian dollar.
Other Income and Expenses. The $28 million decrease was driven primarily by lower AFUDC resulting from decreased capital spending on expansion projects.
EBITDA. The $42 million increase was driven by higher earnings at the Empress NGL business due mainly to lower production costs and higher sales prices, and earnings from expansions, partially offset by lower contracted volumes in the conventional gathering and processing business, higher operating and maintenance costs and the effect 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 British Columbia. “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 British Columbia and the Pacific Northwest. 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 British Columbia 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.

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Field Services
 
2014
 
2013
 
Increase
(Decrease)
 
2012
 
Increase
(Decrease)
 
(in millions, except where noted)
Equity in earnings of unconsolidated affiliates
$
217

 
$
343

 
$
(126
)
 
$
279

 
$
64

EBITDA
$
217

 
$
343

 
$
(126
)
 
$
279

 
$
64

Natural gas gathered and processed/transported, TBtu/d (a,b)
7.3

 
7.1

 
0.2

 
7.1

 

NGL production, MBbl/d (a)
454

 
426

 
28

 
402

 
24

Average natural gas price per MMBtu (c,d)
$
4.41

 
$
3.65

 
$
0.76

 
$
2.79

 
$
0.86

Average NGL price per gallon (e)
$
0.89

 
$
0.90

 
$
(0.01
)
 
$
0.82

 
$
0.08

Average crude oil price per barrel (f)
$
93.06

 
$
98.04

 
$
(4.98
)
 
$
94.16

 
$
3.88

 ____________
(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. 2013 NGL prices have been revised to reflect the impact of ethane rejection.
(f)
Average price based on NYMEX calendar month.
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 Southern Hills, and favorable results from NGL trading and gas marketing, partially offset by unfavorable results from wholesale propane.

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2013 Compared to 2012
EBITDA. Higher equity earnings of $64 million were mainly the result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:
a $62 million increase in gains associated with the issuance of partnership units by DCP Partners in 2013 compared to 2012,
a $13 million increase primarily attributable to lower operating costs as a result of a cost reduction initiative and lower benefit costs,
a $10 million increase due to gains from sales of assets,
a $12 million increase attributable to the favorable results from NGL trading, and
a $9 million increase from commodity-sensitive processing arrangements due to higher natural gas and crude oil prices, net of lower NGL prices, partially offset by
a $26 million decrease primarily attributable to higher interest expense due to higher interest rates as a result of newly issued debt and lower capitalized interest on certain projects which were placed in service in 2013, and
a $15 million decrease primarily attributable to incremental dropdowns to DCP Partners, which increased net income attributable to noncontrolling interests.
Supplemental Data
Below is supplemental information for DCP Midstream’s operating results (presented at 100%): 
 
2014
 
2013
 
2012
 
(in millions)
Operating revenues
$
14,013

 
$
12,038

 
$
10,171

Operating expenses
13,262

 
11,230

 
9,427

Operating income
751

 
808

 
744

Other income and expenses
83

 
35

 
34

Interest expense, net
287

 
249

 
193

Income tax expense
11

 
10

 
2

Net income
536

 
584

 
583

Net income—noncontrolling interests
248

 
93

 
97

Net income attributable to members’ interests
$
288

 
$
491

 
$
486

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 the 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 experienced significant volatility during the latter part of 2014. The price of crude oil has continued to decline in the first part of 2015. If commodity prices remain weak for a sustained period, DCP Midstream’s natural gas throughput and NGL volumes will be negatively impacted, particularly as producers are curtailing or redirecting drilling. Drilling activity levels vary by geographic area, but in general, DCP Midstream has observed decreases in drilling activity with lower commodity prices. Furthermore a sustained 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 reduced utilization of these assets. Despite recent short-term weakness, DCP Midstream’s long-term view is that commodity prices will be at levels that DCP Midstream believes will support continued growth in natural gas, condensate and NGL production. DCP Midstream believes 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 LNG and NGLs. NGL prices are impacted by the demand from petrochemical and refining industries and export facilities. The petrochemical industry is making significant investment in building or expanding facilities to convert chemical plants from a heavier oil-based 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 or built, which provide support for the increasing supply of NGLs.

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Although there can be, and has been, near-term volatility in NGL prices, longer term DCP Midstream believes that there will be sufficient demand in NGLs to support increasing supply.
Other
 
2014
 
2013
 
Increase
(Decrease)
 
2012
 
Increase
(Decrease)
 
(in millions)
Operating revenues
$
72

 
$
72

 
$

 
$
89

 
$
(17
)
Operating expenses
 
 
 
 
 
 
 
 
 
Operating, maintenance and other
141

 
185

 
(44
)
 
140

 
45

Other income and expenses
11

 
27

 
(16
)
 
15

 
12

EBITDA
$
(58
)
 
$
(86
)
 
$
28

 
$
(36
)
 
$
(50
)
2014 Compared to 2013
EBITDA. The $28 million increase 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.
2013 Compared to 2012
EBITDA. The $50 million decrease was driven mainly by transaction costs associated with the U.S. Assets Dropdown, higher employee benefit costs, and a 2012 gain related to an early termination notice by Westcoast for capacity contracts held on Vector Pipeline, partially offset by a 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 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 affected 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 $1,494 million as of December 31, 2014 and $1,376 million as of December 31, 2013. Total regulatory liabilities were $430 million as of December 31, 2014 and $502 million as of December 31, 2013.

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Impairment of Goodwill
We had goodwill balances of $4,714 million at December 31, 2014 and $4,810 million at December 31, 2013. The decrease in goodwill in 2014 was the result of foreign currency translation, partially offset by an adjustment related to the acquisition of Express-Platte. See Note 3 of Notes to Consolidated Financial Statements for further discussion. The majority of our goodwill relates to the acquisition of Westcoast in 2002, which owns substantially all of our Canadian operations. As of the acquisition date or upon a change in reporting units, we allocate goodwill to a reporting unit, which we define as an operating segment or one level below an operating segment.
As permitted under the 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. The long-term growth rates used for the reporting units that we quantitatively assess reflect continued expansion of our assets, driven by new natural gas supplies such as shale gas in North America and increasing demand for natural gas transmission capacity on our pipeline systems primarily as a result of forecasted growth in natural gas-fired power plants and increasing demand for crude oil and NGL transportation capacity on our pipeline systems. For our regulated businesses in Canada, if an increase in the cost of capital occurred, we assumed that the effect on the corresponding reporting unit’s fair value would be ultimately offset by a similar increase in the reporting unit’s regulated revenues since those rates include a component that is based on the reporting unit’s cost of capital.
We performed a qualitative assessment for all of our reporting units to determine whether it is more likely than not that the respective fair values of these reporting units are less than their carrying amounts, including goodwill as of April 1, 2014 (our annual testing date). Based on that assessment, we determined that this condition, for all reporting units, does not exist. As such, performing the first step of the two-step impairment test for these reporting units was unnecessary. No triggering events occurred during the period from April 1, 2014 through December 31, 2014 that warranted re-testing for goodwill impairment.
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 2014, the assumed average return was 8.00% for the U.S. pension plan assets, 7.40% for the Canadian pension plan assets and 6.98% 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 $3 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 net periodic benefit cost and benefit obligation discount rates are significant assumptions. Discount rates used for our defined benefit and

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other post-retirement benefit plans are based on the yields constructed from a portfolio of high-quality bonds for which the timing and amount of cash outflows approximate the estimated payouts of the plans. Discount rates of 4.35% for the U.S. plans and 4.80% for the Canadian plans were used to calculate the 2014 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 4.09% for the U.S. plans and 4.00% for the Canadian plans were used to calculate the 2014 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 decreased approximately 0.26% for the U.S. plans and approximately 0.80% for the Canadian plans during 2014. The decrease to the benefit obligation discount rates resulted in an increase in benefit liabilities at December 31, 2014 compared to December 31, 2013.
See Note 25 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, 2014, we had negative working capital of $1,477 million. This balance includes commercial paper liabilities totaling $1,583 million and current maturities of long-term debt of $327 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 2015. 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, 2014, our four revolving credit facilities consisted of 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 16 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, 2014, our capital structure was 58% debt, 33% common equity of controlling interests and 9% noncontrolling interests and preferred stock of subsidiaries.
Cash flows from operations for our 100%-owned and majority-owned businesses are fairly stable given that approximately 90% of revenues are derived from fee-based services, of which most are regulated. However, total operating cash flows are subject to a number of factors, including, but not limited to, earnings sensitivities to weather, commodity prices, distributions from our equity affiliates, including DCP Midstream and Gulfstream, and the timing of cost recoveries pursuant to regulatory approvals. See Part I. Item 1A. Risk Factors for further discussion.
Cash distributions from our equity affiliate, 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 total tax and periodic distributions from DCP Midstream of $237 million in 2014, $215 million in 2013 and $203 million in 2012. These distributions are classified within Operating Cash Flows. We continue to assess the effect of 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, 2014, $160 million of Cash and Cash Equivalents was held by our Canadian subsidiaries. Historically, we have reinvested a substantial portion of our Canadian operations’ earnings in Canada. Earnings not needed by our Canadian operations have been distributed to Spectra Energy Corp (the U.S. parent) with minimal incremental U.S. tax liability. 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

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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 $2.7 billion in 2015 and will continue to average approximately $2.8 billion through 2016. 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,
 
2014
 
2013
 
2012
 
(in millions)
Net cash provided by (used in):
 
 
 
 
 
Operating activities
$
2,221

 
$
2,030

 
$
1,938

Investing activities
(2,003
)
 
(3,236
)
 
(2,674
)
Financing activities
(199
)
 
1,316

 
654

Effect of exchange rate changes on cash
(5
)
 
(3
)
 
2

Net increase (decrease) in cash and cash equivalents
14

 
107

 
(80
)
Cash and cash equivalents at beginning of the period
201

 
94

 
174

Cash and cash equivalents at end of the period
$
215

 
$
201

 
$
94

Operating Cash Flows
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 unconsolidated affiliates, partially offset by
changes in working capital.
Net cash provided by operating activities increased $92 million to $2,030 million in 2013 compared to 2012. This change was driven mostly by:
lower net tax payments in 2013, partially offset by
changes in working capital.
Investing Cash Flows
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 unconsolidated affiliates in 2014, comprised mostly of a $200 million distribution from SESH with proceeds from a SESH debt offering, partially offset by
$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.

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Net cash flows used in investing activities increased $562 million to $3,236 million in 2013 compared to 2012. This change was driven mostly by:
a $1,254 million net cash outlay for the acquisition of Express-Platte, partially offset by
$513 million of initial and subsequent investments in Sand Hills and Southern Hills in 2012 compared to investments of $267 million in 2013, and
$146 million of net proceeds of available-for-sale securities in 2013 compared to $130 million of net purchases in 2012.
Capital and Investment Expenditures by Business Segment
Capital and investment expenditures are detailed by business segment in the following table. Capital and investment expenditures presented below include expenditures from both continuing and discontinued operations.
 
Years Ended December 31,
 
2014
 
2013
 
2012
 
(in millions)
Spectra Energy Partners (a,b)
$
1,241

 
$
1,299

 
$
1,443

Distribution
427

 
357

 
276

Western Canada Transmission & Processing
473

 
561

 
760

Total reportable segments
2,141

 
2,217

 
2,479

Other
146

 
42

 
66

Total consolidated
$
2,287

 
$
2,259

 
$
2,545

_____ ___
(a)
Excludes the $1,254 million net cash outlay for the acquisition of Express-Platte in March 2013 and $30 million paid in 2012 for amounts previously withheld from the purchase price consideration of the acquisition of Bobcat in 2010. See Note 3 of Notes to Consolidated Financial Statements for further discussions.
(b)
Excludes a $71 million loan to an unconsolidated affiliate 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 2014 totaled $2,287 million and included $1,358 million for expansion projects, $740 million for maintenance and other projects and a $189 million investment in SESH ($94 million at Spectra Energy Partners and $95 million at “Other”). SESH used the funds, along with its funds received from its other partners, to retire maturing debt.
We project 2015 capital and investment expenditures of approximately $3.4 billion, consisting of approximately $2.4 billion for Spectra Energy Partners, $0.6 billion for Distribution and $0.4 billion for Western Canada Transmission & Processing. Total projected 2015 capital and investment expenditures include approximately $2.7 billion of expansion capital expenditures and $0.7 billion for maintenance and upgrades of existing plants, pipelines and infrastructure to serve growth.
Capital expansion projects are developed and executed using results-proven project management processes. We evaluate the strategic fit and commercial and execution risks, and continuously measure performance compared to plan. Ongoing communications between project teams and senior leadership ensure we maintain the right focus and deliver the expected results.
Expansion capital expenditures included several key projects placed into service in 2014, including:
North Montney Development - 211 MMcf/d of new gathering and processing service and 159 MMcf/d of renewed gathering and processing service. The project includes various processing plant modifications, including reactivation of the existing Aitken Creek plant. This project was placed in-service during the first quarter of 2014.
Buffalo Terminal Expansion - Buffalo expansion consists of two additional 150,000 bbl above ground storage tanks along with delivery pump and piping facilities to supply crude oil to the Cenex Harvest States Front Range pipeline. This project was placed in-service during the third quarter of 2014.
TEAM 2014 - A 600 MMcf/d expansion of the Texas Eastern pipeline system consisting of new pipeline construction. The project is designed to transport gas produced in the Marcellus Shale to U.S. markets in the Northeast, Midwest and Gulf Coast. This project was placed in-service during the fourth quarter of 2014.

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Bobcat Storage Expansion - The project as a whole is designed to expand the storage capacity and capabilities of the Bobcat facility. Cavern Well 4 increases the working gas capacity by 9.9 Bcf, and was placed in-service during the fourth quarter of 2014.
Kingsport - An additional 61 MMcf/d on the East Tennessee system to support a customer’s multi-year project to convert five coal-fired power plant boilers to natural gas. The project was placed in-service during the fourth quarter of 2014.
Significant 2015 expansion projects expenditures are expected to include:
Dawn-Parkway 2015 - A 681 MMcfd expansion of the Dawn-Parkway transmission system consisting of the Parkway West project which includes the development of a new Greenfield compressor site west of Toronto and the installation of a new compressor and associated infrastructure; the Parkway D compressor unit and the Brantford-Kirkwall NPS 48 pipeline loop.
OPEN - A 550 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. In-service is scheduled by the fourth quarter of 2015.
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 fourth quarter 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 up to seven 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 fourth quarter of 2016, will provide north to south compression at five stations. Phase 2 due to go in-service in the fourth quarter of 2017 will provide north to south compression at two stations.
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. In-service is scheduled by the second quarter 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. In-service is scheduled by the first quarter 2016.
Uniontown to Gas City - The project will provide 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. These five shippers combine to contract for the full 425 MMcf/d of capacity under the project. In-service is scheduled by the fourth quarter of 2015.
DCP Sand Hills - Red Lake - The project includes the construction of two lateral pipelines with a combined length of 170 miles to connect a DCP gas processing plant and two third-party gas processing plants to the Sand Hills Pipeline. The project extends the reach of the Sand Hills Pipeline into a fast growing region of the Permian basin and enhances long-term throughput on the pipeline. It is expected to be in-service in the second half of 2015.
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. In-service is scheduled by the third quarter of 2015.

Financing Cash Flows and Liquidity
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.

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Net cash provided by financing activities increased $662 million to $1,316 million in 2013 compared to 2012. This change was driven mostly by:
a $1,457 million net increase in long-term debt issuances in 2013 compared to 2012, mostly used to fund the acquisition of Express-Platte and the U.S. Assets Dropdown, partially offset by
$206 million of net repayments of commercial paper in 2013 compared to $199 million of proceeds from commercial paper in 2012, and
proceeds of $382 million from the issuance of Spectra Energy common stock in 2012.
Significant Financing Activities—2014
Debt Issuances.    The following long-term debt issuances were completed during 2014 as part of our overall financing plan to fund capital expenditures, to refinance maturing debt obligations and for other corporate purposes:
 
Amount
 
Interest Rate
 
Due Date
 
(in millions)
 
 
 
 
Spectra 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.
In November 2013, SEP entered into an equity distribution agreement under which it may sell and issue common units up to an aggregate amount of $400 million. 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 6.4 million limited partner units to the public in 2014 under its at-the-market program and 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. In 2015 through the date of this report, SEP has issued 184,000 common units to the public and 4,000 general partner units to Spectra Energy, for total net proceeds to SEP of $10 million (net proceeds to Spectra Energy were $10 million).
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

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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.
Significant Financing Activities—2012
Debt Issuances.    The following long-term debt issuances were completed during 2012: 
 
Amount
 
Interest Rate
 
Due Date
 
(in millions)
 
 
 
 
Algonquin
$
350

  
3.51
%
 
2024
Texas Eastern
500

  
2.80
%
 
2022
East Tennessee
200

  
3.10
%
 
2024
Westcoast
251

(a) 
3.12
%
 
2022
 __________________
(a)
U.S. dollar equivalent at time of issuance.
Spectra Energy Common Stock Issuances. In 2012, Spectra Energy issued 14.7 million common shares to the public. Total net proceeds to Spectra Energy were $382 million, used to fund acquisitions and capital expenditures and for other general corporate purposes.
SEP Common Unit Issuances. In 2012, SEP issued 5.5 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 $148 million (net proceeds to Spectra Energy were $145 million) and were restricted for the purpose of funding SEP’s capital expenditures and acquisitions.
Available Credit Facilities and Restrictive Debt Covenants
 
Expiration
Date
 
Total
Credit
Facilities
Capacity
 
Commercial Paper Outstanding at December 31, 2014
 
Available
Credit
Facilities
Capacity
 
 
 
(in millions)
Spectra Capital (a)
2019
 
$
1,000

 
$
398

 
$
602

SEP (b)
2019
 
2,000

 
907

 
1,093

Westcoast (c)
2019
 
344

 
46

 
298

Union Gas (d)
2019
 
430

 
232

 
198

Total
 
 
$
3,774

 
$
1,583

 
$
2,191

  __________________
(a)
Revolving credit facility contains a covenant requiring the Spectra Energy Corp 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 58% at December 31, 2014.
(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, 2014, this ratio was 3.7 to 1.
(c)
U.S. dollar equivalent at December 31, 2014. 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% at December 31, 2014.
(d)
U.S. dollar equivalent at December 31, 2014. 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 68% at December 31, 2014.
On December 10, 2014, we amended the Westcoast and Union Gas revolving credit agreements. The Westcoast revolving credit facility was increased to 400 million Canadian dollars, and the Union Gas revolving credit facility was increased to 500 million Canadian dollars. Both facilities expire in December 2019.
On December 11, 2014, we amended the Spectra Capital and SEP revolving credit agreements. The expiration date of both credit facilities was extended one year, with both facilities expiring in December 2019.
The issuances of commercial paper, letters of credit and revolving borrowings reduce the amounts available under the credit facilities. As of December 31, 2014, there were no letters of credit issued or revolving borrowings outstanding under the credit facilities.

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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, 2014, 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 agreement requires 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 58% at December 31, 2014. 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, 2014, however, it is not likely that a material adverse effect would occur as a result of a weakened Canadian dollar.
Term Loan Agreements.   In November 2013, Spectra Capital entered into a five-year $300 million senior unsecured delayed-draw term loan agreement which allowed for up to one borrowing prior to January 15, 2014. The full $300 million available under the agreement was borrowed in January 2014. These borrowings are due in November 2018.
In November 2013, SEP entered into and borrowed $400 million under a senior unsecured five-year term loan agreement. A portion of the proceeds from the borrowing was used to pay Spectra Energy for the U.S. Assets Dropdown.
In 2012, Spectra Capital entered into a three-year $1.2 billion unsecured delayed-draw term loan agreement which allowed for up to four borrowings prior to March 1, 2013. The full $1.2 billion available under the agreement was borrowed in the first quarter of 2013. Proceeds from borrowings under the term loan were used for general corporate purposes, including acquisitions and to refinance existing indebtedness. Borrowings under this term loan agreement were repaid on November 1, 2013 with proceeds received from SEP from the U.S. Assets Dropdown, and the loan agreement was terminated.

Dividends.    Our near-term objective is to increase our cash dividend by $0.14 per year through 2017. 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 $0.37 per common share on January 5, 2015 payable on March 10, 2015 to shareholders of record at the close of business on February 13, 2015.
Other Financing Matters.    Spectra Energy Corp and Spectra Capital have an effective shelf registration statement on file with the SEC to register the issuance of unspecified amounts of various equity and debt securities. SEP has an effective shelf registration statement on file with the SEC to register the issuance of unspecified amounts of limited partner common units and various debt securities. SEP also has $143 million available as of December 31, 2014 for the issuance of limited partner common units and various debt securities under an additional shelf registration statement on file with the SEC related to its at-the-market program. Westcoast and Union Gas have an aggregate 2.5 billion Canadian dollars (approximately $2.2 billion) available as of December 31, 2014 for the issuance of debt securities in the Canadian market under debt shelf prospectuses.
In January 2015, SEP filed a registration statement with the SEC to register an additional $500 million of limited partner units. This shelf registration became effective on February 2, 2015.
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 21 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.

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Issuance of these guarantee arrangements is not required for the majority of our operations. As such, if we discontinued issuing these guarantee arrangements, there would not be a material impact to our consolidated results of operations, financial position or cash flows.
We do not have any other material off-balance sheet financing entities or structures, except for normal operating lease arrangements, guarantee arrangements and financings entered into by DCP Midstream and our other equity investments. For additional information on these commitments, see Notes 20 and 21 of Notes to Consolidated Financial Statements.
Contractual Obligations
We enter into contracts that require payment of cash at certain periods based on certain specified minimum quantities and prices. The following table summarizes our contractual cash obligations for each of the periods presented. The table below excludes all amounts classified as Total Current Liabilities on the December 31, 2014 Consolidated Balance Sheet other than Current Maturities of Long-Term Debt. It is expected that the majority of Total Current Liabilities will be paid in cash in 2015.

Contractual Obligations as of December 31, 2014
 
Payments Due By Period
 
Total
 
2015
 
2016 &
2017
 
2018 &
2019
 
2020 &
Beyond
 
(in millions)
Long-term debt (a)
$
19,646

 
$
974

 
$
2,499

 
$
4,115

 
$
12,058

Operating leases (b)
352

 
50

 
86

 
68

 
148

Purchase Obligations: (c)
 
 
 
 
 
 
 
 
 
Firm capacity payments (d)
2,727

 
287

 
412

 
151

 
1,877

Energy commodity contracts (e)
507

 
457

 
50

 

 

Other purchase obligations (f)
820

 
219

 
468

 
78

 
55

Other long-term liabilities on the Consolidated Balance Sheet (g)
55

 
55

 

 

 

Total contractual cash obligations
$
24,107

 
$
2,042

 
$
3,515

 
$
4,412

 
$
14,138

__________
(a)
See Note 16 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 20.
(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, 2014.
(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 2015 retirement plan contributions (see Notes 25). We are unable to estimate retirement plan contributions beyond 2015 due primarily to uncertainties about market performance of plan assets. Excludes cash obligations for asset retirement activities (see Note 15) 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 20) 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.

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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 transactions as well as commodity derivatives. Effective January 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, 2014 and 2013, a 10¢ per-gallon change in NGL prices would affect our annual pre-tax earnings by approximately $55 million in 2015 and $59 million in 2014 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 $23 million and $21 million, and a $10 per-barrel change in oil prices would affect our annual pre-tax earnings by approximately $25 million and $27 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 $21 million in 2015. 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, 2014, a 10¢ per-gallon movement in underlying commodity NGL prices would affect the estimated fair value of commodity derivatives by approximately $16 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 19 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 United States and Canada. Customers on the Express-Platte system are primarily refineries located in the Rocky Mountain and Midwestern states of the United States. 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. As a result of future capital projects for which natural gas producers may be the primary customer, our credit exposure with below investment-grade customers may increase.

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We manage cash and restricted cash positions to maximize value while assuring appropriate amounts of cash are available, as required. We invest our available cash in high-quality money market securities. Such money market securities are designed for safety of principal and liquidity, and accordingly, do not include equity-based securities.
Based on our policies for managing credit risk, our current exposures and our credit and other reserves, we do not anticipate a material effect on our consolidated financial position or results of operations as a result of non-performance by any counterparty.
Interest Rate Risk
We are exposed to risk resulting from changes in interest rates as a result of our issuance of variable and fixed-rate debt and commercial paper. We manage our interest rate exposure by limiting our variable-rate exposures to percentages of total debt and by monitoring the effects of market changes in interest rates. We also enter into financial derivative instruments, including, but not limited to, interest rate swaps and rate lock agreements to manage and mitigate interest rate risk exposure. See also Notes 1, 16 and 19 of Notes to Consolidated Financial Statements.
As of December 31, 2014, we had interest rate hedges in place for various purposes. We are party to “pay floating—receive fixed” interest rate swaps with a total notional amount of $1,208 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, 2014, it was estimated that if short-term interest rates average 100 basis points higher (lower) in 2015 than in 2014, interest expense, net of offsetting interest income, would fluctuate by $32 million. Comparatively, based on a sensitivity analysis as of December 31, 2013, had short-term interest rates averaged 100 basis points higher (lower) in 2014 than in 2013, it was estimated that interest expense, net of offsetting interest income, would have fluctuated by approximately $24 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, 2014 and 2013.
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 2014 would have resulted in an estimated net loss on the translation of local currency earnings of approximately $44 million on our Consolidated Statement of Operation. In addition, if a 10% devaluation had occurred on December 31, 2014, the Consolidated Balance Sheet would have been negatively impacted by $499 million through a cumulative translation adjustment in AOCI. At December 31, 2014, one U.S. dollar translated into 1.16 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

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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 20 of Notes to Consolidated Financial Statements.
New Accounting Pronouncements

See Note 1 of Notes to Consolidated Financial Statements for discussion.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk for discussion.
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, 2014 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, 2014.
Deloitte & Touche LLP, our independent registered public accounting firm, has audited and issued a report on the effectiveness of our internal control over financial reporting. Their report is included herein.


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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Spectra Energy Corp
We have audited the accompanying consolidated balance sheets of Spectra Energy Corp and subsidiaries (the “Company”) as of December 31, 2014 and 2013, 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, 2014. 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, 2014, 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, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, 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, 2014, 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 27, 2015

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SPECTRA ENERGY CORP
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per-share amounts)
 
 
Years Ended December 31,
 
2014
 
2013
 
2012
Operating Revenues
 
 
 
 
 
Transportation, storage and processing of natural gas
$
3,291

 
$
3,128

 
$
3,149

Distribution of natural gas
1,583

 
1,577

 
1,366

Sales of natural gas liquids
497

 
440

 
401

Transportation of crude oil
302

 
224

 

Other
230

 
149

 
159

Total operating revenues
5,903

 
5,518

 
5,075

Operating Expenses
 
 
 
 
 
Natural gas and petroleum products purchased
1,219

 
1,139

 
1,037

Operating, maintenance and other
1,571

 
1,568

 
1,380

Depreciation and amortization
796

 
772

 
746

Property and other taxes
393

 
373

 
337

Total operating expenses
3,979

 
3,852

 
3,500

Operating Income
1,924

 
1,666

 
1,575