10-K
 
 
 
 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2015 or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from              to             
Commission file number 1-33007
SPECTRA ENERGY CORP
(Exact name of registrant as specified in its charter)
Delaware
 
20-5413139
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
 
 
 
5400 Westheimer Court, Houston, Texas
 
77056
(Address of principal executive offices)
 
(Zip Code)
713-627-5400
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
 
Name of Each Exchange on Which Registered
Common Stock, par value $0.001
 
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  x    No  ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.    Yes  ¨    No  x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer x
Accelerated filer ¨
Non-accelerated filer ¨
Smaller reporting company ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No x   
Estimated aggregate market value of the common equity held by nonaffiliates of the registrant June 30, 2015: $22,000,000,000
Number of shares of Common Stock, $0.001 par value, outstanding at January 31, 2016: 671,500,270
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement for the 2016 Annual Meeting of Shareholders are incorporated by reference in Part III.
 
 
 
 
 



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

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This document includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements represent management’s intentions, plans, expectations, assumptions and beliefs about future events. These forward-looking statements are identified by terms and phrases such as: anticipate, believe, intend, estimate, expect, continue, should, could, may, plan, project, predict, will, potential, forecast, and similar expressions. Forward-looking statements are subject to risks, uncertainties and other factors, many of which are outside our control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. Factors used to develop these forward-looking statements and that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:
state, provincial, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an effect on rate structure, and affect the speed at and degree to which competition enters the natural gas and oil industries;
outcomes of litigation and regulatory investigations, proceedings or inquiries;
weather and other natural phenomena, including the economic, operational and other effects of hurricanes and storms;
the timing and extent of changes in commodity prices, interest rates and foreign currency exchange rates;
general economic conditions, including the risk of a prolonged economic slowdown or decline, or the risk of delay in a recovery, which can affect the long-term demand for natural gas and oil and related services;
potential effects arising from terrorist attacks and any consequential or other hostilities;
changes in environmental, safety and other laws and regulations;
the development of alternative energy resources;
results and costs of financing efforts, including the ability to obtain financing on favorable terms, which can be affected by various factors, including credit ratings and general market and economic conditions;
increases in the cost of goods and services required to complete capital projects;
declines in the market prices of equity and debt securities and resulting funding requirements for defined benefit pension plans;
growth in opportunities, including the timing and success of efforts to develop United States and Canadian pipeline, storage, gathering, processing and other related infrastructure projects and the effects of competition;
the performance of natural gas and oil transmission and storage, distribution, and gathering and processing facilities;
the extent of success in connecting natural gas and oil supplies to gathering, processing and transmission systems and in connecting to expanding gas and oil markets;
the effects of accounting pronouncements issued periodically by accounting standard-setting bodies;
conditions of the capital markets during the periods covered by forward-looking statements; and
the ability to successfully complete merger, acquisition or divestiture plans; regulatory or other limitations imposed as a result of a merger, acquisition or divestiture; and the success of the business following a merger, acquisition or divestiture.
In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than Spectra Energy Corp has described. Spectra Energy Corp undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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Item 1. Business.
The terms “we,” “our,” “us” and “Spectra Energy” as used in this report refer collectively to Spectra Energy Corp and its subsidiaries unless the context suggests otherwise. These terms are used for convenience only and are not intended as a precise description of any separate legal entity within Spectra Energy. The term “Spectra Energy Partners” refers to our Spectra Energy Partners operating segment. The term “SEP” refers to Spectra Energy Partners, LP, our master limited partnership.
General
Spectra Energy, through its subsidiaries and equity affiliates, owns and operates a large and diversified portfolio of complementary natural gas-related energy assets and is one of North America’s leading natural gas infrastructure companies. We also own and operate a crude oil pipeline system that connects Canadian and United States (U.S.) producers to refineries in the U.S. Rocky Mountain and Midwest regions. For over a century, we and our predecessor companies have developed critically important pipelines and related energy infrastructure connecting natural gas supply sources to premium markets. We currently operate in three key areas of the natural gas industry: gathering and processing, transmission and storage, and distribution. We provide transmission and storage of natural gas to customers in various regions of the northeastern and southeastern U.S., the Maritime provinces in Canada, the Pacific Northwest in the U.S. and Canada, and in the province of Ontario, Canada. We also provide natural gas sales and distribution services to retail customers in Ontario, and natural gas gathering and processing services to customers in western Canada. We also own a 50% interest in DCP Midstream, LLC (DCP Midstream), based in Denver, Colorado, one of the leading natural gas gatherers in the U.S., and one of the largest U.S. producers and marketers of natural gas liquids (NGLs). Our internet website is http://www.spectraenergy.com.
Our natural gas pipeline systems consist of approximately 21,000 miles of transmission pipelines. Our storage facilities provide approximately 300 billion cubic feet (Bcf) of net storage capacity in the U.S. and Canada. Our crude oil pipeline system, Express-Platte, consists of over 1,700 miles of transmission pipeline comprised of the Express pipeline and the Platte pipeline systems.

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

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Texas Eastern
We have an effective 78% ownership interest in Texas Eastern through our ownership of SEP. The Texas Eastern natural gas transmission system extends approximately 1,700 miles from producing fields in the Gulf Coast region of Texas and Louisiana to Ohio, Pennsylvania, New Jersey and New York. It consists of two parallel systems, the first of which has one to four large-diameter parallel pipelines and the other with one to three large-diameter pipelines. Texas Eastern’s onshore system consists of approximately 8,700 miles of pipeline and associated compressor stations (facilities that increase the pressure of gas to facilitate its pipeline transmission). Texas Eastern also owns and operates two offshore Louisiana pipeline systems, which extend approximately 100 miles into the Gulf of Mexico and include approximately 400 miles of pipeline. Texas Eastern has two storage facilities in Pennsylvania held through joint ventures and one 100%-owned and operated storage facility in Maryland. Texas Eastern’s total working joint venture capacity in these three facilities is 74 Bcf. In addition, Texas Eastern’s system is connected to Steckman Ridge, a 12 Bcf joint venture storage facility in Pennsylvania, and three affiliated storage facilities in Texas and Louisiana, aggregating 77 Bcf, owned by Market Hub and Bobcat.

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

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East Tennessee
                
We have an effective 78% ownership interest in East Tennessee through our ownership of SEP. East Tennessee’s natural gas transmission system crosses Texas Eastern’s system at two locations in Tennessee and consists of two mainline systems totaling approximately 1,500 miles of pipeline in Tennessee, Georgia, North Carolina and Virginia, with associated compressor stations. East Tennessee has a liquefied natural gas (LNG), natural gas that has been converted to liquid form, storage facility in Tennessee with a total working capacity of 1 Bcf. East Tennessee also connects to the Saltville storage facilities in Virginia that have a working gas capacity of approximately 5 Bcf.

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

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

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Big Sandy
                    
We have an effective 78% ownership interest in Big Sandy through our ownership of SEP. Big Sandy is an approximately 70-mile natural gas transmission system, with associated compressor stations, located in eastern Kentucky. Big Sandy’s interconnection with the Tennessee Gas Pipeline system links the Huron Shale and Appalachian Basin natural gas supplies to the mid-Atlantic and northeast markets.

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

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












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SESH
We have an effective 39% total investment in SESH through our ownership of SEP, an approximately 290-mile natural gas transmission system, with associated compressor stations, operated jointly by Spectra Energy and CenterPoint Energy Southeastern Pipelines Holding, LLC. SESH extends from the Perryville Hub in northeastern Louisiana where the emerging shale gas production of eastern Texas, northern Louisiana and Arkansas, along with conventional production, is reached from five major interconnections. SESH extends to Alabama, interconnecting with 14 major north-south pipelines and three high-deliverability storage facilities. SESH is owned 50% directly by SEP and 50% by Enable Midstream Partners, LP. Our investment in SESH is accounted for under the equity method of accounting.












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Market Hub
We have an effective 78% ownership interest in Market Hub through our ownership of SEP. Market Hub owns and operates two natural gas storage facilities, Moss Bluff and Egan, with a total storage capacity of approximately 47 Bcf. The Moss Bluff facility consists of four salt dome storage caverns located in southeast Texas, with access to five pipeline systems including the Texas Eastern system. The Egan facility consists of four salt dome storage caverns located in south central Louisiana, with access to ten pipeline systems, including the Texas Eastern system.
Saltville
We have an effective 78% ownership interest in Saltville through our ownership of SEP. Saltville owns and operates natural gas storage facilities in Virginia with a total storage capacity of approximately 5 Bcf, interconnecting with East Tennessee’s system. This salt cavern facility offers high-deliverability capabilities and is strategically located near markets in Tennessee, Virginia and North Carolina.
Bobcat
We have an effective 78% ownership interest in Bobcat through our ownership of SEP. Bobcat, an approximately 30 Bcf salt dome facility, is strategically located on the Gulf Coast near Henry Hub, interconnecting with five major interstate pipelines, including Texas Eastern.
Steckman Ridge
We have an effective 39% investment in Steckman Ridge through our ownership of SEP. Steckman Ridge is an approximately 12 Bcf depleted reservoir storage facility located in south central Pennsylvania that interconnects with the Texas Eastern and Dominion Transmission, Inc. systems. Steckman Ridge is owned 50% directly by SEP and 50% by NJR Steckman Ridge Storage Company. Our investment in Steckman Ridge is accounted for under the equity method of accounting.
Competition
Spectra Energy Partners’ natural gas transmission and storage businesses compete with similar facilities that serve our supply and market areas in the transmission and storage of natural gas. The principal elements of competition are location, rates, terms of service, and flexibility and reliability of service.
The natural gas transported in our transmission business competes with other forms of energy available to our customers and end-users, including electricity, coal, propane and fuel oils. Factors that influence the demand for natural gas include price changes, the availability of natural gas and other forms of energy, levels of business activity, long-term economic conditions, conservation, legislation, governmental regulations, the ability to convert to alternative fuels, weather and other factors.

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Spectra Energy Partners’ crude oil transportation business competes with pipelines, rail, truck and barge facilities that transport crude oil from production areas to refinery markets. The principal elements of competition are location, rates, terms of service, flexibility and reliability of service.
Customers and Contracts
In general, Spectra Energy Partners’ natural gas pipelines provide transmission and storage services for local distribution companies (LDCs, companies that obtain a major portion of their revenues from retail distribution systems for the delivery of natural gas for ultimate consumption), electric power generators, exploration and production companies, and industrial and commercial customers, as well as energy marketers. Transmission and storage services are generally provided under firm agreements where customers reserve capacity in pipelines and storage facilities. The vast majority of these agreements provide for fixed reservation charges that are paid monthly regardless of the actual volumes transported on the pipelines or injected or withdrawn from our storage facilities, plus a small variable component that is based on volumes transported, injected or withdrawn, which is intended to recover variable costs.
Spectra Energy Partners also provides interruptible transmission and storage services where customers can use capacity if it is available at the time of the request. Interruptible revenues depend on the amount of volumes transported or stored and the associated rates for this interruptible service. New projects placed into service may initially have higher levels of interruptible services at inception. Storage operations also provide a variety of other value-added services including natural gas parking, loaning and balancing services to meet our customers’ needs.
Customers on the Express-Platte system are primarily refineries located in the Rocky Mountain and Midwestern states of the U.S. Other customers include oil producers and marketing entities. Express capacity is typically contracted under long-term committed contracts where customers reserve capacity and pay commitment charges based on a contracted volume even if they do not ship. A small amount of Express capacity and all Platte capacity is used by uncommitted shippers who only pay for the pipeline capacity that is actually used in a given month.


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DISTRIBUTION
We provide distribution services in Canada through our subsidiary, Union Gas Limited (Union Gas). Union Gas is a major Canadian natural gas storage, transmission and distribution company based in Ontario with over 100 years of experience and service to customers. The distribution business serves approximately 1.4 million residential, commercial and industrial customers in more than 400 communities across northern, southwestern and eastern Ontario. Union Gas’ storage and transmission business offers storage and transmission services to customers at the Dawn Hub, the largest integrated underground storage facility in Canada and one of the largest in North America. It offers customers an important link in the movement of natural gas from western Canada and U.S. supply basins to markets in central Canada and the northeast U.S.
Union Gas’ distribution system consists of approximately 40,000 miles of main and service pipelines. Distribution pipelines carry natural gas from the point of local supply to customers. Union Gas’ underground natural gas storage facilities have a working capacity of approximately 163 Bcf in 25 underground facilities located in depleted gas fields. Its transmission system consists of approximately 3,000 miles of high-pressure pipeline and associated mainline compressor stations.
Competition
Union Gas’ distribution system is regulated by the Ontario Energy Board (OEB) pursuant to the provisions of the Ontario Energy Board Act (1998) and is subject to regulation in a number of areas, including rates. Union Gas is not generally subject to third-party competition within its distribution franchise area. However, physical bypass of Union Gas’ system may be permitted, even within Union Gas’ distribution franchise area. In addition, other companies could enter Union Gas’ markets or regulations could change.
Union Gas provides storage services to customers outside its franchise area and new storage services under a framework established by the OEB that supports unregulated storage investments and allows Union Gas to compete with third-party storage providers on basis of price, terms of service, and flexibility and reliability of service. Existing storage services to customers within Union Gas’ franchise area, however, have continued to be provided at cost-based rates and are not subject to third-party competition.

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Union Gas competes with other forms of energy available to its customers and end-users, including electricity, coal, propane and fuel oils. Factors that influence the demand for natural gas include weather, price changes, the availability of natural gas and other forms of energy, the level of business activity, conservation, legislation, governmental regulations, the ability to convert to alternative fuels and other factors.
Customers and Contracts
Most of Union Gas’ power generation customers, industrial and large commercial customers, and a portion of residential customers, purchase their natural gas directly from suppliers or marketers. Because Union Gas earns income from the distribution of natural gas and not from the sale of the natural gas commodity, gas distribution margins are not affected by either the source of customers’ gas supply or its price, except to the extent that prices affect actual customer usage.
Union Gas provides its in-franchise customers with regulated distribution, transmission and storage services. Union Gas also provides unregulated natural gas storage and regulated transmission services for other utilities and energy market participants, including large natural gas transmission and distribution companies. A substantial amount of Union Gas’ annual transportation and storage revenue is generated by fixed demand charges.

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WESTERN CANADA TRANSMISSION & PROCESSING
Our Western Canada Transmission & Processing business is comprised of the BC Pipeline, BC Field Services, Canadian Midstream, Empress NGL operations, and M&N Canada.
BC Pipeline and BC Field Services provide fee-based natural gas transmission and gas gathering and processing services. BC Pipeline is regulated by the NEB under full cost-of-service regulation. BC Pipeline transports processed natural gas from facilities primarily in northeast British Columbia (BC) to markets in BC, Alberta and the U.S. Pacific Northwest. BC Pipeline has approximately 1,750 miles of transmission pipeline in BC and Alberta, as well as associated mainline compressor stations.
The BC Field Services business, which is regulated by the NEB under a “light-handed” regulatory model, consists of raw gas gathering pipelines and gas processing facilities, primarily in northeast BC. These facilities provide services to natural gas producers to remove impurities from the raw gas stream including water, carbon dioxide, hydrogen sulfide and other substances. Where required, these facilities also remove various NGLs for subsequent sale by the producers. NGLs are liquid hydrocarbons extracted during the processing of natural gas. Principal commercial NGLs include butanes, propane, natural gasoline and ethane. The BC Field Services business includes eight gas processing plants located in BC, associated field compressor stations and approximately 1,400 miles of gathering pipelines.
The Canadian Midstream business provides similar gas gathering and processing services in BC and Alberta and consists of 11 natural gas processing plants and approximately 800 miles of gathering pipelines. This business is primarily regulated by the province where the assets are located, either BC or Alberta.
The Empress NGL business provides NGL extraction, fractionation, transportation, storage and marketing services to western Canadian producers and NGL customers throughout Canada and the northern tier of the U.S. Assets include a majority ownership interest in an NGL extraction plant, an integrated NGL fractionation facility, an NGL transmission pipeline, ten terminals where NGLs are loaded for shipping or transferred into product sales pipelines, two NGL storage facilities and an NGL marketing business. The Empress extraction and fractionation plant is located in Empress, Alberta.
We own approximately 78% of M&N Canada, with affiliates of Emera, Inc. and Exxon Mobil Corporation directly owning the remaining 13% and 9% interests, respectively. M&N Canada is an approximately 550-mile mainline interprovincial natural gas transmission system which extends from Goldboro, Nova Scotia to the U.S. border near Baileyville, Maine. M&N Canada is connected to the U.S. portion of the Maritimes & Northeast Pipeline system, M&N U.S., which is directly owned by SEP (part of our Spectra Energy Partners segment) and affiliates of Emera, Inc. and Exxon Mobil Corporation. M&N Canada facilities include associated compressor stations and have a market delivery capability of approximately 0.6 Bcf/d of natural gas. The pipeline’s location and key interconnects with Spectra Energy’s transmission system link regional natural gas supplies to the northeast U.S. and Atlantic Canadian markets.

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Competition
Western Canada Transmission & Processing businesses compete with third-party midstream companies, exploration and production companies, and pipelines in the gathering, processing and transmission of natural gas and the extraction and marketing of NGL products. The principal elements of competition are location, rates, terms of service, and flexibility and reliability of service.
Natural gas competes with other forms of energy available to Western Canada Transmission & Processing’s customers and end-users, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability or price of natural gas, NGLs and other forms of energy, levels of business activity, long-term economic conditions, conservation, legislation, governmental regulations, the ability to convert to alternative fuels, weather and other factors affect the demand for natural gas in the areas that Western Canada Transmission & Processing serves.
In addition to the fee-for-service pipeline and gathering and processing businesses, we compete with other NGL extraction facilities at Empress, Alberta for the right to extract and purchase NGLs from natural gas shippers on the Nova Gas Transmission Ltd. (Nova/TransCanada) pipeline system. To extract and acquire NGLs, we must be competitive in the prices or fees we pay to gas shippers and suppliers. We also compete with other NGL marketers in the various product sales markets we serve.
Customers & Contracts
BC Pipeline provides: (i) transmission services from the outlet of natural gas processing plants primarily in northeast BC to LDCs, end-use industrial and commercial customers, marketers, and exploration and production companies requiring transmission services to the nearest natural gas trading hub; and (ii) transmission services primarily to downstream markets in the Pacific Northwest (both in the U.S. and Canada) using the southern portion of the transmission pipeline and markets in Alberta through pipeline interconnects in northern BC with Nova/TransCanada. The majority of transportation services are provided under firm agreements, which provide for fixed reservation charges that are paid monthly regardless of actual volumes transported on the pipeline, plus a small variable component that is based on volumes transported to recover variable costs. BC Pipeline also provides interruptible transmission services where customers can use capacity if it is available at the time of request. Payments under these services are based on volumes transported.
The BC Field Services and Canadian Midstream operations in western Canada provide raw natural gas gathering and processing services to exploration and production companies under agreements which are fee-for-service contracts which do not expose us to direct commodity-price risk. However, a sustained decline in natural gas prices has impacted our ability to negotiate and renew expiring service contracts with customers in certain areas of our operations. The BC Field Services and Canadian Midstream operations provide both firm and interruptible services.
The NGL extraction operation at Empress, Alberta is jointly owned with a partner and has capacity to produce approximately 63,000 barrels of NGLs per day (Bbls/d) (our share is approximately 58,000 Bbls/d at full capacity). At Empress, we extract and purchase NGLs from natural gas shippers on the Nova/TransCanada pipeline system. In addition to paying shippers a negotiated extraction fee, we keep the shipper whole by returning an equivalent amount of natural gas for the NGLs that were extracted. We further compete with other NGL extraction facilities to purchase and ship natural gas to our extraction and separation plant at Empress where we extract NGLs before selling the residue natural gas. After NGLs are extracted, we fractionate the NGLs into ethane, propane, butanes and condensate, and sell these products into the marketplace. All ethane is sold to Alberta-based petrochemical companies. In addition to paying for natural gas shrinkage, the ethane buyers pay us a negotiated cost-of-service price or a negotiated fixed price. We sell the remaining products—propane, butane and condensate—at market prices. The majority of propane is sold to propane retailers. Butane is sold mainly into the motor gasoline refinery market and condensate is sold to the crude blending and crude diluent markets. Profit margins are driven by the market prices of NGL products, extraction premiums paid to shippers, shrinkage make-up natural gas prices and other operating costs. Empress’ customers are U.S.-based and Canadian-based.
Operating results at Empress are significantly affected by changes in average NGL and natural gas prices, which have fluctuated significantly over the last several years. We continue to closely monitor the risks associated with these price changes.
We employ policies and procedures to manage Spectra Energy’s risks associated with Empress’ commodity price fluctuations, which may include the use of forward physical transactions as well as commodity derivatives. In 2014, we implemented a commodity hedging program at Empress in an effort to mitigate a large portion of commodity risk.

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

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individual consumers. DCP Midstream also stores residue natural gas at its 12 Bcf Southeast Texas natural gas storage facility located near Beaumont, Texas.
DCP Midstream uses NGL trading and storage at its Mont Belvieu, Texas and Conway, Kansas NGL market centers to manage price risk and to provide additional services to its customers. Asset-based gas trading and marketing activities are supported by ownership of the Southeast Texas storage facility and various intrastate pipelines which provide access to market centers/hubs such as Katy, Texas and the Houston Ship Channel.
DCP Midstream’s operating results are significantly affected by changes in average NGL, natural gas and crude oil prices, which have declined substantially. DCP Midstream closely monitors the risks associated with these price changes. See Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk for a discussion of DCP Midstream’s exposure to changes in commodity prices.
Competition
In gathering, processing, transporting and storing natural gas, as well as producing, marketing and transporting NGLs, DCP Midstream competes with major integrated oil companies, major interstate and intrastate pipelines, national and local natural gas gatherers and processors, NGL transporters and brokers, marketers and distributors of natural gas supplies. Competition for natural gas supplies is based mostly on the reputation, efficiency and reliability of operations, the availability of gathering and transportation to high-demand markets, pricing arrangements offered by the gatherer/processor and the ability of the gatherer/processor to obtain a satisfactory price for the producer’s residue natural gas and extracted NGLs. Competition for sales to customers is based mostly upon reliability, services offered and the prices of delivered natural gas and NGLs.
Customers and Contracts
DCP Midstream sells a portion of its NGLs to Phillips 66 and Chevron Phillips Chemical Company LLC (CPChem). In addition, DCP Midstream purchases NGLs from CPChem. Prior to December 31, 2014 approximately 35% of DCP Midstream’s NGL production was committed to Phillips 66 and CPChem under 15-year contracts, the primary production commitment of which began a ratable wind down period in December 2014 and expires in January 2019. Approximately 28% of DCP Midstream’s NGL production was committed to Phillips 66 and CPChem as of December 31, 2015. DCP Midstream anticipates continuing to purchase and sell commodities with Phillips 66 and CPChem, in the ordinary course of business.
The residual natural gas, primarily methane, that results from processing raw natural gas is sold at market-based prices to marketers and end-users, including large industrial companies, natural gas distribution companies and electric utilities. DCP Midstream purchases or takes custody of substantially all of its raw natural gas from producers, principally under the following types of contractual arrangements. More than 75% of the volumes of gas that are gathered and processed are under percentage-of-proceeds contracts.
Percentage-of-proceeds/index arrangements. In general, DCP Midstream purchases natural gas from producers at the wellhead or other receipt points, gathers the wellhead natural gas through its gathering system, treats and processes it, and then sells the residue natural gas and NGLs based on index prices from published index market prices. DCP Midstream remits to the producers either an agreed-upon percentage of the actual proceeds received by DCP Midstream from the sale of the residue natural gas, NGLs and condensate, or an agreed-upon percentage of the proceeds based on index-related prices or contractual recoveries for the natural gas, NGLs and condensate, regardless of the actual amount of sales proceeds which DCP Midstream receives. DCP Midstream keeps the difference between the proceeds received and the amount remitted back to the producer. Under percentage-of-liquids arrangements, DCP Midstream does not keep any amounts related to the residue natural gas proceeds and only keeps amounts related to the difference between the proceeds received and the amount remitted back to the producer related to NGLs and condensate. Certain of these arrangements may also result in the producer retaining title to all or a portion of the residue natural gas and/or the NGLs in lieu of DCP Midstream returning sales proceeds to the producer. Additionally, these arrangements may include fee-based components. DCP Midstream’s revenues from percentage-of-proceeds/index arrangements are directly related to the prices of natural gas, NGLs or condensate. DCP Midstream’s revenues under percentage-of-liquids arrangements are directly related to the price of NGLs and condensate.
Fee-based arrangements. DCP Midstream receives a fee or fees for one or more of the following services: gathering, compressing, treating, processing, transporting or storing natural gas, and fractionating, storing and transporting NGLs. Fee-based arrangements include natural gas arrangements pursuant to which DCP Midstream obtains natural gas at the wellhead or other receipt points at an index-related price at the delivery point less a specified amount, generally the same as the transportation fees it would otherwise charge for transportation of the natural gas from the wellhead location to the delivery point. The revenue DCP Midstream earns from these arrangements is directly related to the volume of natural gas or NGLs that flows through its systems and is not dependent on commodity prices.

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However, to the extent that a sustained decline in commodity prices results in a decline in volumes, DCP Midstream’s revenues from these arrangements would be reduced.
Keep-whole and wellhead purchase arrangements. DCP Midstream gathers raw natural gas from producers for processing, the NGLs and condensate are sold and the residue natural gas is returned to the producer with a British thermal unit (Btu) content equivalent to the Btu content of the natural gas gathered. This arrangement keeps the producer whole to the thermal value of the natural gas received. Under the terms of a wellhead purchase contract, DCP Midstream purchases natural gas from the producer at the wellhead or defined receipt point for processing and markets the resulting NGLs and residue natural gas at market prices. Under these types of contracts, DCP Midstream is exposed to the difference between the value of the NGLs extracted from processing and the value of the Btu-equivalent of the residue natural gas, or frac spread. DCP Midstream benefits in periods when NGL prices are higher relative to natural gas prices, where that frac spread exceeds our cost.
As defined by the terms of the above arrangements, DCP Midstream also sells condensate, which is generally similar to crude oil and is produced in association with natural gas gathering and processing. The revenues that DCP Midstream earns from the sale of condensate correlate directly with crude oil prices.
Supplies and Raw Materials
We purchase a variety of manufactured equipment and materials for use in operations and expansion projects. The primary equipment and materials utilized in operations and project execution processes are steel pipe, compression engines, pumps, valves, fittings, polyethylene plastic pipe, gas meters and other consumables.
We operate a North American supply chain management network with employees dedicated to this function in the U.S. and Canada. Our supply chain management group uses economies-of-scale to maximize the efficiency of supply networks where applicable. The price of equipment and materials may vary however, perhaps substantially, from year to year. DCP Midstream performs its own supply chain management function.
Regulations
Most of our U.S. gas transmission, crude oil pipeline and storage operations are regulated by the FERC. The FERC regulates natural gas transmission in U.S. interstate commerce including the establishment of rates for services. The FERC also regulates the construction of U.S. interstate natural gas pipelines and storage facilities, including the extension, enlargement and abandonment of facilities. In addition, certain operations are subject to oversight by state regulatory commissions. To the extent that the natural gas intrastate pipelines that transport or store natural gas in interstate commerce provide services under Section 311 of the Natural Gas Policy Act of 1978, they are subject to FERC regulations. The FERC may propose and implement new rules and regulations affecting interstate natural gas transmission and storage companies, which remain subject to the FERC’s jurisdiction. These initiatives may also affect certain transmission of gas by intrastate pipelines.
Our Spectra Energy Partners and DCP Midstream operations are subject to the jurisdiction of the Environmental Protection Agency (EPA) and various other federal, state and local environmental agencies. See “Environmental Matters” for a discussion of environmental regulation. Our U.S. interstate natural gas pipelines and certain of DCP Midstream’s gathering and transmission pipelines are also subject to the regulations of the U.S. Department of Transportation (DOT) concerning pipeline safety.
Express-Platte pipeline system rates and tariffs are subject to regulation by the NEB in Canada and the FERC in the U.S. In addition, the Platte pipeline also operates as an intrastate pipeline in Wyoming and is subject to jurisdiction by the Wyoming Public Service Commission.
The intrastate natural gas and NGL pipelines owned by us and DCP Midstream are subject to state regulation. To the extent that the natural gas intrastate pipelines that transport natural gas in interstate commerce provide services under Section 311 of the Natural Gas Policy Act of 1978, they are subject to FERC regulation. DCP Midstream’s interstate natural gas pipeline operations are also subject to regulation by the FERC. The natural gas gathering and processing activities of DCP Midstream are not subject to FERC regulation.
Our Canadian operations are governed by various federal and provincial agencies with respect to pipeline safety, including the NEB and the Transportation Safety Board, the British Columbia Oil and Gas Commission, the Alberta Energy Regulator and the Ontario Technical Standards and Safety Authority.
Our Canadian natural gas transmission and distribution operations and approximately two-thirds of the storage operations in Canada, are subject to regulation by the NEB or the provincial agencies in Canada, such as the OEB. These agencies have jurisdiction similar to the FERC for regulating rates, the terms and conditions of service, the construction of additional facilities

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and acquisitions. Our BC Field Services business in western Canada is regulated by the NEB pursuant to a framework for light-handed regulation under which the NEB acts on a complaints-basis for rates associated with that business. Similarly, the rates charged by our Canadian Midstream operations for gathering and processing services in western Canada are regulated on a complaints-basis by applicable provincial regulators. Our Empress NGL business is not under any form of rate regulation.
Environmental Matters
We are subject to various U.S. federal, state and local laws and regulations, as well as Canadian federal and provincial regulations, regarding air and water quality, hazardous and solid waste disposal and other environmental matters.
Environmental laws and regulations affecting our U.S.-based operations include, but are not limited to:
The Clean Air Act (CAA) and the 1990 amendments to the CAA, as well as state laws and regulations affecting air emissions (including State Implementation Plans related to existing and new national ambient air quality standards), which may limit new sources of air emissions. Our natural gas processing, transmission and storage assets are considered sources of air emissions and are thereby subject to the CAA. Owners and/or operators of air emission sources, like us, are responsible for obtaining permits for existing and new sources of air emissions and for annual compliance and reporting.
The Federal Water Pollution Control Act (Clean Water Act), which requires permits for facilities that discharge wastewaters into the environment. The Oil Pollution Act (OPA) amended parts of the Clean Water Act and other statutes as they pertain to the prevention of and response to oil spills. The OPA imposes certain spill prevention, control and countermeasure requirements. Although we are primarily a natural gas business, the OPA affects our business primarily because of the presence of liquid hydrocarbons (condensate) in our offshore pipelines.
The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), which imposes liability for remediation costs associated with environmentally contaminated sites. Under CERCLA, any individual or entity that currently owns or in the past owned or operated a disposal site can be held liable and required to share in remediation costs, as well as transporters or generators of hazardous substances sent to a disposal site. Because of the geographical extent of our operations, we have disposed of waste at many different sites and therefore have CERCLA liabilities.
The Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act, which requires certain solid wastes, including hazardous wastes, to be managed pursuant to a comprehensive regulatory regime. As part of our business, we generate solid waste within the scope of these regulations and therefore must comply with such regulations.
The Toxic Substances Control Act, which requires that polychlorinated biphenyl (PCB) contaminated materials be managed in accordance with a comprehensive regulatory regime. Because of the historical use of lubricating oils containing PCBs, the internal surfaces of some of our pipeline systems are contaminated with PCBs, and liquids and other materials removed from these pipelines must be managed in compliance with such regulations.
The National Environmental Policy Act, which requires federal agencies to consider potential environmental effects in their decisions, including site approvals. Many of our capital projects require federal agency review, and therefore the environmental effects of proposed projects are a factor in determining whether we will be permitted to complete proposed projects.
Environmental laws and regulations affecting our Canadian-based operations include, but are not limited to:
The Fisheries Act (Canada), which regulates activities near any body of water in Canada.
The Environmental Management Act (BC), the Environmental Protection and Enhancement Act (Alberta) and the Environmental Protection Act (Ontario) are provincial laws governing various aspects, including permitting and site remediation obligations, of our facilities and operations in those provinces.
The Canadian Environmental Protection Act, which, among other things, requires the reporting of greenhouse gas (GHG) emissions from our operations in Canada. Additional regulations to be promulgated under this Act may require the reduction of GHGs, nitrogen oxides, sulphur oxides, volatile organic compounds and particulate matter.
The Alberta Climate Change and Emissions Management Act (The Act) which, as of 2007, required certain facilities to meet reductions in emission intensity. The Act was applicable to our Empress facility in Alberta beginning in 2008.

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The Canadian Environmental Assessment Act, 2012 (CEAA 2012) requires the NEB to consider potential environmental effects in their decisions for designated projects. The NEB under its enabling statute also conducts environmental assessments for projects that are not specifically designated under CEEA 2012. In either case, prior to receiving an approval to construct or operate a federally-regulated pipeline or facility, the NEB must consider a series of environmental factors, in particular whether the project has the potential to have adverse environmental effects. These types of assessments occur in relation to both maintenance and capital projects.
For more information on environmental matters, including possible liability and capital costs, see Part II. Item 8. Financial Statements and Supplementary Data, Notes 5 and 19, of Notes to Consolidated Financial Statements.
Except to the extent discussed in Notes 5 and 19, compliance with international, federal, state, provincial and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of our various business units and is not expected to have a material effect on our competitive position or consolidated results of operations, financial position or cash flows.
Geographic Regions
For a discussion of our Canadian operations and the risks associated with them, see Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Quantitative and Qualitative Disclosures About Market Risk—Foreign Currency Risk, and Notes 4 and 18 of Notes to Consolidated Financial Statements.
Employees
We had approximately 6,000 employees as of December 31, 2015, including approximately 3,600 employees in Canada. In addition, DCP Midstream employed approximately 3,200 employees as of such date. Approximately 1,400 of our Canadian employees are subject to collective bargaining agreements governing their employment with us. Approximately 20% of those employees are covered under agreements that either have expired or will expire by December 31, 2016.

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Executive and Other Officers
The following table sets forth information regarding our executive and other officers.
 
Name
Age
Position
Gregory L. Ebel
51
President and Chief Executive Officer, Director
J. Patrick Reddy
63
Chief Financial Officer
Dorothy M. Ables
58
Chief Administrative Officer
Guy G. Buckley
55
Chief Development Officer
Julie A. Dill
56
Chief Communications Officer
Reginald D. Hedgebeth
48
General Counsel
William T. Yardley
51
President, U.S. Transmission and Storage
Allen C. Capps
45
Vice President and Controller
Laura Buss Sayavedra
48
Vice President and Treasurer
Gregory L. Ebel assumed his current position as President and Chief Executive Officer in January 2009. He previously served as Group Executive and Chief Financial Officer since January 2007. Mr. Ebel currently serves as the Chairman of the Board of Directors of Spectra Energy Corp and on the Board of Directors of Spectra Energy Partners GP, LLC and DCP Midstream, LLC.
J. Patrick Reddy joined Spectra Energy in January 2009 as Chief Financial Officer. Mr. Reddy served as Senior Vice President and Chief Financial Officer at Atmos Energy Corporation from 2000 to 2008. Mr. Reddy currently serves on the Board of Directors of DCP Midstream, LLC.
Dorothy M. Ables assumed her current position as Chief Administrative Officer in November 2008. Prior to then, she served as Vice President of Audit Services and Chief Ethics and Compliance Officer from January 2007. Ms. Ables currently serves on the Board of Directors of Spectra Energy Partners GP, LLC.
Guy G. Buckley assumed his current position as Chief Development Officer in January 2014. He previously served as Treasurer and Group Vice President-Mergers and Acquisitions from January 2012 to December 2013, and as Group Vice President, Corporate Strategy and Development from December 2008 to December 2011. Mr. Buckley currently serves on the Board of Directors of DCP Midstream, LLC.
Julie A. Dill assumed her current position as Chief Communications Officer January 2014. Ms. Dill previously served as Group Vice President-Strategy from January 2012 to December 2013, as President and Chief Executive Officer of Spectra Energy Partners, GP, LLC from January 2012 to October 2013 and as President of Union Gas Limited from December 2006 through December 2011. Ms. Dill currently serves on the Board of Directors of Spectra Energy Partners GP, LLC.
Reginald D. Hedgebeth assumed his current position as General Counsel in March 2009. He previously served as Senior Vice President, General Counsel and Secretary with Circuit City Stores, Inc. from July 2005 to March 2009.
William T. Yardley assumed his current position as President, U.S. Transmission and Storage in January 2013. Prior to then, he served as Group Vice President of Northeastern U.S. Assets and Operations since 2007. Mr. Yardley currently serves on the Board of Directors of Spectra Energy Partners GP, LLC.
Allen C. Capps assumed his current position as Vice President and Controller in January 2012. He previously served as Vice President, Business Development, Storage and Transmission, for Union Gas from April 2010. Prior to then, Mr. Capps served as Vice President and Treasurer for Spectra Energy Corp from December 2007 until April 2010.
Laura Buss Sayavedra assumed her current position as Vice President and Treasurer January 2014. Ms. Sayavedra previously served as Vice President-Strategy from March 2013 to December 2013, as Vice President and Chief Financial Officer of Spectra Energy Partners, GP, LLC from July 2008 to February 2013, and as Vice President, Strategic Development and Analysis of Spectra Energy Corp from January 2007 to June 2008.

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Additional Information
We were incorporated on July 28, 2006 as a Delaware corporation. Our principal executive offices are located at 5400 Westheimer Court, Houston, Texas 77056 and our telephone number is 713-627-5400. We electronically file various reports with the Securities and Exchange Commission (SEC), including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and amendments to such reports. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov. Additionally, information about us, including our reports filed with the SEC, is available through our website at http://www.spectraenergy.com. Such reports are accessible at no charge through our website and are made available as soon as reasonably practicable after such material is filed with or furnished to the SEC. Our website and the information contained on that site, or connected to that site, are not incorporated by reference into this report.
Item 1A. Risk Factors.
Discussed below are the material risk factors relating to Spectra Energy.
Reductions in demand for natural gas and oil, and low market prices of commodities adversely affect our operations and cash flows.
Our regulated businesses are generally economically stable; they are not significantly affected in the short-term by changing commodity prices. However, our businesses can all be negatively affected in the long-term by sustained downturns in the economy or long-term conservation efforts, which could affect long-term demand and market prices for natural gas, oil and NGLs. These factors are beyond our control and could impair the ability to meet long-term goals.
Most of our revenues are based on regulated tariff rates, which include the recovery of certain fuel costs. However, lower overall economic output could reduce the volume of natural gas and NGLs transported and distributed or gathered and processed at our plants, and the volume of oil transported, resulting in lower earnings and cash flows. This decline would primarily affect distribution revenues in the short term. Transmission revenues could be affected by long-term economic declines, resulting in the non-renewal of long-term contracts at the time of expiration. Lower demand along with lower prices for natural gas, oil and NGLs could result from multiple factors that affect the markets where we operate, including:
weather conditions, such as abnormally mild winter or summer weather, resulting in lower energy usage for heating or cooling purposes, respectively;
supply of and demand for energy commodities, including any decrease in the production of natural gas and oil which could negatively affect our processing and transmission businesses due to lower throughput;
capacity and transmission service into, or out of, our markets; and
petrochemical demand for NGLs.
The lack of availability of natural gas and oil resources may cause customers to seek alternative energy resources, which could materially affect our revenues, earnings and cash flows.
Our natural gas and oil businesses are dependent on the continued availability of natural gas and oil production and reserves. Prices for natural gas and oil, regulatory limitations on the development of natural gas and oil supplies, or a shift in supply sources could adversely affect development of additional reserves and production that are accessible by our pipeline, gathering, processing and distribution assets. Lack of commercial quantities of natural gas and oil available to these assets could cause customers to seek alternative energy resources, thereby reducing their reliance on our services, which in turn would materially affect our revenues, earnings and cash flows.
Investments and projects located in Canada expose us to fluctuations in currency rates that may affect our results of operations, cash flows and compliance with debt covenants.
We are exposed to foreign currency risk from our Canadian operations. An average 10% devaluation in the Canadian dollar exchange rate during 2015 would have resulted in an estimated net gain on the translation of local currency earnings of approximately $24 million on our Consolidated Statement of Operations. In addition, if a 10% devaluation had occurred on December 31, 2015, the Consolidated Balance Sheet would have been negatively impacted by $356 million through a cumulative translation adjustment in Accumulated Other Comprehensive Income (AOCI). At December 31, 2015, one U.S. dollar translated into 1.38 Canadian dollars.

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In addition, we maintain credit facilities that typically include financial covenants which limit the amount of debt that can be outstanding as a percentage of total capital for Spectra Energy or of a specific subsidiary. Failure to maintain these covenants could preclude us from issuing commercial paper or letters of credit, or borrowing under our revolving credit facilities, and could require other affiliates to immediately pay down any outstanding drawn amounts under other revolving credit agreements, which could affect cash flows or restrict business. Foreign currency fluctuations have a direct impact on our ability to maintain certain of these financial covenants.
Natural gas gathering and processing, NGL processing and marketing, and market-based storage operations are subject to commodity price risk, which could result in a decrease in our earnings and reduced cash flows.
We have gathering and processing operations that consist of contracts to buy and sell commodities, including contracts for natural gas, NGLs and other commodities that are settled by the delivery of the commodity or cash. We are exposed to market price fluctuations of NGLs and natural gas primarily in Field Services and at Empress in our Western Canada Transmission & Processing segment, and to oil primarily in our Field Services segment. The effect of commodity price fluctuations on our earnings could be material. Effective January 2014, we implemented a commodity hedging program at Empress in order to manage risks associated with Empress’ commodity price fluctuations. The commodity hedging program helps manage the fluctuations in the Conway/Mont Belvieu index prices. However, it does not manage potential fluctuations in pricing differentials between the Empress market and index prices. The changes in pricing differentials may be material and may adversely affect results.
We have market-based rates for some of our storage operations and sell our storage services based on natural gas market spreads and volatility. If natural gas market spreads or volatility deviate from historical norms or there is significant growth in the amount of storage capacity available to natural gas markets relative to demand, our approach to managing our market-based storage contract portfolio may not protect us from significant variations in storage revenues, including possible declines, as contracts renew.
Our business is subject to extensive regulation that affects our revenues, operations and costs.
Our U.S. assets and operations are subject to regulation by various federal, state and local authorities, including regulation by the FERC and by various authorities under federal, state and local environmental laws. Our natural gas assets and operations in Canada are also subject to regulation by federal, provincial and local authorities, including the NEB and the OEB, and by various federal and provincial authorities under environmental laws. Regulation affects almost every aspect of our business, including, among other things, the ability to determine terms and rates for services provided by some of our businesses, make acquisitions, construct, expand and operate facilities, issue equity or debt securities, and pay dividends.
In addition, regulators in both the U.S. and Canada have taken actions to strengthen market forces in the gas pipeline industry, which have led to increased competition. In a number of key markets, natural gas pipeline and storage operators are facing competitive pressure from a number of new industry participants, such as alternative suppliers, as well as traditional pipeline competitors. Increased competition driven by regulatory changes could have a material effect on our business, earnings, financial condition and cash flows.
Execution of our capital projects subjects us to construction risks, increases in labor and material costs, and other risks that may affect our financial results.
A significant portion of our growth is accomplished through the construction of new pipelines and storage facilities as well as the expansion of existing facilities. Construction of these facilities is subject to various regulatory, development, operational and market risks, including:
the ability to obtain necessary approvals and permits by regulatory agencies on a timely basis and on acceptable terms and to maintain those approvals and permits issued and satisfy the terms and conditions imposed therein;
the availability of skilled labor, equipment and materials to complete expansion projects;
potential changes in federal, state and local statutes and regulations, including environmental requirements, that may prevent a project from proceeding or increase the anticipated cost of the project;
impediments on our ability to acquire rights-of-way or land rights on a timely basis and on acceptable terms;
the ability to construct projects within anticipated costs, including the risk of cost overruns resulting from inflation or increased costs of equipment, materials or labor, weather, geologic conditions or other factors beyond our control, that may be material; and

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general economic factors that affect the demand for natural gas infrastructure.
Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated cost. As a result, new facilities may not achieve their expected investment return, which could affect our earnings, financial position and cash flows.
Gathering and processing, natural gas transmission and storage, crude oil transportation and storage, and gas distribution activities involve numerous risks that may result in accidents or otherwise affect our operations.
There are a variety of hazards and operating risks inherent in natural gas gathering and processing, transmission, storage, and distribution activities, and crude oil transportation and storage, such as leaks, explosions, mechanical problems, activities of third parties and damage to pipelines, facilities and equipment caused by hurricanes, tornadoes, floods, fires and other natural disasters, that could cause substantial financial losses. In addition, these risks could result in significant injury, loss of life, significant damage to property, environmental pollution and impairment of operations, any of which could result in substantial losses. For pipeline and storage assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damage resulting from these risks could be greater. We do not maintain insurance coverage against all of these risks and losses, and any insurance coverage we might maintain may not fully cover the damages caused by those risks and losses. Therefore, should any of these risks materialize, it could have a material effect on our business, earnings, financial condition and cash flows.
Our operations are subject to pipeline safety laws and regulations, compliance with which may require significant capital expenditures, increase our cost of operations and affect or limit our business plans.
Our interstate pipeline operations are subject to pipeline safety laws and regulations administered by the Pipeline and Hazardous Materials Safety Administration (PHMSA) of the DOT. These laws and regulations require us to comply with a significant set of requirements for the design, construction, maintenance and operation of our interstate pipelines. These regulations, among other things, include requirements to monitor and maintain the integrity of our pipelines. The regulations determine the pressures at which our pipelines can operate.
PHMSA is designing an Integrity Verification Process intended to create standards to verify maximum allowable operating pressure, and to improve and expand integrity management processes. There remains uncertainty as to how these standards will be implemented, but it is expected that the changes will impose additional costs on new pipeline projects as well as on existing operations. In this climate of increasingly stringent regulation, pipeline failures or failures to comply with applicable regulations could result in reduction of allowable operating pressures as authorized by PHMSA, which would reduce available capacity on our pipelines. Should any of these risks materialize, it may have an adverse effect on our operations, earnings, financial condition and cash flows.
In Canada, our interprovincial and international pipeline operations are subject to pipeline safety regulations overseen by the NEB. Applicable legislation and regulation require us to comply with a significant set of requirements for the design, construction, maintenance and operation of our interprovincial and international pipelines. Among other obligations, this regulatory framework imposes requirements to monitor and maintain the integrity of our pipelines.
As in the U.S., several legislative changes addressing pipeline safety in Canada have recently come into force. The changes evidence an increased focus on the implementation of management systems to address key areas such as emergency management, integrity management, safety, security and environmental protection. Other legislative changes have created authority for the NEB to impose administrative monetary penalties for non-compliance with the regulatory regime it administers.
Compliance with these legislative changes may impose additional costs on new Canadian pipeline projects as well as on existing operations. Failure to comply with applicable regulations could result in a number of consequences which may have an adverse effect on our operations, earnings, financial condition and cash flows.
Our operations are subject to numerous environmental laws and regulations, compliance with which may require significant capital expenditures, increase our cost of operations and affect or limit our business plans, or expose us to environmental liabilities.
We are subject to numerous environmental laws and regulations affecting many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations can result in increased capital, operating and other costs. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Compliance with environmental laws and regulations can require significant expenditures, including expenditures for cleanup costs and damages

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arising out of contaminated properties. In particular, compliance with major Clean Air Act regulatory programs is likely to cause us to incur significant capital expenditures to obtain permits, evaluate offsite impacts of our operations, install pollution control equipment, and otherwise assure compliance. Some states in which we operate are implementing new emissions limits to comply with 2008 ozone standards regulated under the National Ambient Air Quality Standards. In 2015, the ozone standards were lowered even further from 75 ppb to 70 ppb, which may require states to implement additional emissions regulations. The precise nature of these compliance obligations at each of our facilities has not been finally determined and may depend in part on future regulatory changes. In addition, compliance with new and emerging environmental regulatory programs is likely to significantly increase our operating costs compared to historical levels.
In the U.S., climate change action is evolving at state, regional and federal levels. The Supreme Court decision in Massachusetts v. EPA in 2007 established that greenhouse gas (GHG) emissions were pollutants subject to regulation under the Clean Air Act. Pursuant to federal regulations, we are currently subject to an obligation to report our GHG emissions at our largest emitting facilities, but are not generally subject to limits on emissions of GHGs, (except to the extent that some GHGs consist of volatile organic compounds and nitrous oxides that are subject to emission limits). Proposed regulation may extend our reporting obligations to additional facilities and activities. In addition, a number of Canadian provinces and U.S. states have joined regional GHG initiatives, and a number are developing their own programs that would mandate reductions in GHG emissions. Public interest groups and regulatory agencies are increasingly focusing on the emission of methane associated with natural gas development and transmission as a source of GHG emissions. However, as the key details of future GHG restrictions and compliance mechanisms remain undefined, the likely future effects on our business are highly uncertain. For its part, Canada has reaffirmed its strong preference for a harmonized approach with that of the U.S. While federal GHG related regulatory design details remain forthcoming, provincial authorities have been actively pursuing related initiatives.
Failure to comply with environmental regulations may result in the imposition of fines, penalties and injunctive measures affecting our operating assets. In addition, changes in environmental laws and regulations or the enactment of new environmental laws or regulations could result in a material increase in our cost of compliance with such laws and regulations. We may not be able to obtain or maintain all required environmental regulatory approvals for our operating assets or development projects. If there is a delay in obtaining any required environmental regulatory approvals, if we fail to obtain or comply with them, or if environmental laws or regulations change or are administered in a more stringent manner, the operations of facilities or the development of new facilities could be prevented, delayed or become subject to additional costs. Costs we may incur to comply with environmental regulations in the future may have a significant effect on our earnings and cash flows.
Due to the speculative outlook regarding any U.S. federal and state policies and the uncertainty of the Canadian federal and provincial policies, we cannot estimate the potential effect of proposed GHG policies on our future consolidated results of operations, financial position or cash flows. However, such legislation or regulation could materially increase our operating costs, require material capital expenditures or create additional permitting, which could delay proposed construction projects.
We are involved in numerous legal proceedings, the outcome of which are uncertain, and resolutions adverse to us could negatively affect our earnings, financial condition and cash flows.
We are subject to numerous legal proceedings. Litigation is subject to many uncertainties, and we cannot predict the outcome of individual matters with assurance. It is reasonably possible that the final resolution of some of the matters in which we are involved could require additional expenditures, in excess of established reserves, over an extended period of time and in a range of amounts that could have a material effect on our earnings and cash flows.
We rely on access to short-term and long-term capital markets to finance capital requirements and support liquidity needs, and access to those markets can be affected, particularly if we or our rated subsidiaries are unable to maintain an investment-grade credit rating, which could affect our cash flows or restrict business.
Our business is financed to a large degree through debt. The maturity and repayment profile of debt used to finance investments often does not correlate to cash flows from assets. Accordingly, we rely on access to both short-term and long-term capital markets as a source of liquidity for capital requirements not satisfied by cash flows from operations and to fund investments originally financed through debt. Our senior unsecured long-term debt is currently rated investment-grade by various rating agencies. If the rating agencies were to rate us or our rated subsidiaries below investment-grade, our borrowing costs would increase, perhaps significantly. Consequently, we would likely be required to pay a higher interest rate in future financings and our potential pool of investors and funding sources could decrease.
We maintain revolving credit facilities to provide back-up for commercial paper programs for borrowings and/or letters of credit at various entities. These facilities typically include financial covenants which limit the amount of debt that can be outstanding as a percentage of the total capital for the specific entity. Failure to maintain these covenants at a particular entity could preclude that entity from issuing commercial paper or letters of credit or borrowing under the revolving credit facility and

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could require other affiliates to immediately pay down any outstanding drawn amounts under other revolving credit agreements, which could affect cash flows or restrict business. Furthermore, if Spectra Energy’s short-term debt rating were to be below tier 2 (for example, A-2 for Standard and Poor’s, P-2 for Moody’s Investor Service and F2 for Fitch Ratings), access to the commercial paper market could be significantly limited. Although this would not affect our ability to draw under our credit facilities, borrowing costs could be significantly higher.
If we are not able to access capital at competitive rates, our ability to finance operations and implement our strategy may be affected. Restrictions on our ability to access financial markets may also affect our ability to execute our business plan as scheduled. An inability to access capital may limit our ability to pursue improvements or acquisitions that we may otherwise rely on for future growth. Any downgrade or other event negatively affecting the credit ratings of our subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could increase our need to provide liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing the liquidity and borrowing availability of the consolidated group.
We may be unable to secure renewals of long-term transportation agreements, which could expose our transportation volumes and revenues to increased volatility.
We may be unable to secure renewals of long-term transportation agreements in the future for our natural gas transmission and crude oil transportation businesses as a result of economic factors, lack of commercial gas supply available to our systems, changing gas supply flow patterns in North America, increased competition or changes in regulation. Without long-term transportation agreements, our revenues and contract volumes would be exposed to increased volatility. The inability to secure these agreements would materially affect our business, earnings, financial condition and cash flows.
We are exposed to the credit risk of our customers.
We are exposed to the credit risk of our customers in the ordinary course of our business. Generally, our customers are rated investment-grade, are otherwise considered creditworthy or provide us security to satisfy credit concerns. A significant amount of our credit exposures for transmission, storage, and gathering and processing services are with customers who have an investment-grade rating (or the equivalent based on our evaluation) or are secured by collateral. However, we cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including possible declines in our customers’ creditworthiness. As a result of future capital projects for which natural gas and oil producers may be the primary customer, our credit exposure with below investment-grade customers may increase. While we monitor these situations carefully and take appropriate measures when deemed necessary, it is possible that customer payment defaults, if significant, could have a material effect on our earnings and cash flows.
Native land claims have been asserted in BC and Alberta, which could affect future access to public lands, and the success of these claims could have a significant effect on natural gas production and processing.
Certain aboriginal groups have claimed aboriginal and treaty rights over a substantial portion of public lands on which our facilities in BC and Alberta, and the gas supply areas served by those facilities, are located. The existence of these claims, which range from the assertion of rights of limited use to aboriginal title, has given rise to some uncertainty regarding access to public lands for future development purposes. Such claims, if successful, could have a significant effect on natural gas production in BC and Alberta, which could have a material effect on the volume of natural gas processed at our facilities and of NGLs and other products transported in the associated pipelines. In addition, various aboriginal groups in Ontario have claimed aboriginal and treaty rights in areas where Union Gas’ facilities, and the gas supply areas served by those facilities, are located. The existence of these claims could give rise to future uncertainty regarding land tenure depending upon their negotiated outcomes. We cannot predict the outcome of any of these claims or the effect they may ultimately have on our business and operations.
Protecting against potential terrorist activities, including cyber-terrorism, requires significant capital expenditures and a successful terrorist attack could affect our business.
Acts of terrorism and any possible reprisals as a consequence of any action by the U.S. and its allies could be directed against companies operating in the U.S. This risk is particularly relevant for companies, like ours, operating in any energy infrastructure industry that handles volatile gaseous and liquid hydrocarbons. The potential for terrorism, including cyber-terrorism, has subjected our operations to increased risks that could have an adverse effect on our business. In particular, we may experience increased capital and operating costs to implement increased security for our facilities and pipelines, such as additional physical facility and pipeline security, and additional security personnel. Moreover, any physical damage to high profile facilities resulting from acts of terrorism may not be covered, or covered fully, by insurance. We may be required to expend material amounts of capital to repair any facilities, the expenditure of which could affect our business and cash flows. A

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cyber attack could also lead to a significant interruption in our operations or unauthorized release of confidential or otherwise protected information, which could damage our reputation or lead to financial losses.
Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.
Poor investment performance of our pension plan holdings and other factors affecting pension plan costs could affect our earnings, financial position and liquidity.
Our costs of providing defined benefit pension plans are dependent upon a number of factors, such as the rates of return on plan assets, discount rates used to measure pension liabilities, actuarial gains and losses, future government regulation and our contributions made to the plans. Without sustained growth in the pension plan investments over time to increase the value of our plan assets, and depending upon the other factors impacting our costs as listed above, we could experience net asset, expense and funding volatility. This volatility could have a material effect on our earnings and cash flows.
Item 1B. Unresolved Staff Comments.
None.
Item 2. Properties.
At December 31, 2015, we had over 100 primary facilities located in the U.S. and Canada. We generally own sites associated with our major pipeline facilities, such as compressor stations. However, we generally operate our transmission and distribution pipelines using rights of way pursuant to easements to install and operate pipelines, but we do not own the land. Except as described in Part II. Item 8. Financial Statements and Supplementary Data, Note 15 of Notes to Consolidated Financial Statements, none of our properties were secured by mortgages or other material security interests at December 31, 2015.
Our corporate headquarters are located at 5400 Westheimer Court, Houston, Texas 77056, which is a leased facility. The lease expires in 2026. We also maintain offices in, among other places, Calgary, Alberta and Chatham, Ontario. For a description of our material properties, see Item 1. Business.
Item 3. Legal Proceedings.
We have no material pending legal proceedings that are required to be disclosed hereunder. See Note 19 of Notes to Consolidated Financial Statements for discussions of other legal proceedings.
Item 4. Mine Safety Disclosures.
Not applicable.

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PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Our common stock is traded on the NYSE under the symbol “SE.” As of January 31, 2016, there were approximately 107,000 holders of record of our common stock and approximately 566,000 beneficial owners.
Common Stock Data by Quarter 
2015
 
Dividends Per
Common Share
 
Stock Price Range (a)
High
 
Low
First Quarter
 
 
$
0.370

 
 
$
36.90

 
 
$
32.43

Second Quarter
 
 
0.370

 
 
38.47

 
 
32.19

Third Quarter
 
 
0.370

 
 
32.84

 
 
25.22

Fourth Quarter
 
 
0.370

 
 
30.55

 
 
21.43

2014
 
 
 
 
 
 
 
 
 
First Quarter
 
 
$
0.335

 
 
$
38.73

 
 
$
34.23

Second Quarter
 
 
0.335

 
 
42.61

 
 
37.17

Third Quarter
 
 
0.335

 
 
43.12

 
 
38.55

Fourth Quarter
 
 
0.370

 
 
40.00

 
 
32.50

 
________ _
(a)
Stock prices represent the intra-day high and low price.
Stock Performance Graph
The following graph reflects the comparative changes in the value from January 1, 2011 through December 31, 2015 of $100 invested in (1) Spectra Energy’s common stock, (2) the Standard & Poor’s 500 Stock Index and (3) the Standard & Poor’s 500 Oil & Gas Storage & Transportation Index. The amounts included in the table were calculated assuming the reinvestment of dividends at the time dividends were paid.
 
 
January 1,
2011
 
December 31,
 
 
2011
 
2012
 
2013
 
2014
 
2015
Spectra Energy Corp
 
$
100.00

 
$
128.04

 
$
118.53

 
$
160.08

 
$
169.06

 
$
116.78

S&P 500 Stock Index
 
100.00

 
102.11

 
118.45

 
156.82

 
178.28

 
180.75

S&P 500 Storage & Transportation Index
 
100.00

 
147.92

 
166.04

 
199.91

 
231.73

 
117.44


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Dividends
Our near-term objective is to increase our cash dividend by $0.14 per year through 2018. We expect to continue our policy of paying regular cash dividends. The declaration and payment of dividends are subject to the sole discretion of our Board of Directors and will depend upon many factors, including the financial condition, earnings and capital requirements of our operating subsidiaries, covenants associated with certain debt obligations, legal requirements, regulatory constraints and other factors deemed relevant by our Board of Directors.
Item 6. Selected Financial Data.
The following selected financial data should be read in conjunction with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data.
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
2012
 
2011
 
(dollars in millions, except per-share amounts)
Statements of Operations
 
 
 
 
 
 
 
 
 
Operating revenues
$
5,234

 
$
5,903

 
$
5,518

 
$
5,075

 
$
5,351

Operating income
1,433

 
1,924

 
1,666

 
1,575

 
1,763

Income from continuing operations
460

 
1,283

 
1,159

 
1,045

 
1,257

Net income—noncontrolling interests
264

 
201

 
121

 
107

 
98

Net income—controlling interests
196

 
1,082

 
1,038

 
940

 
1,184

Ratio of Earnings to Fixed Charges
3.1

 
3.6

 
2.9

 
2.8

 
3.4

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

 
$
1.61

 
$
1.55

 
$
1.44

 
$
1.78

Diluted
0.29

 
1.61

 
1.55

 
1.43

 
1.77

Earnings per share
 
 
 
 
 
 
 
 
 
Basic
0.29

 
1.61

 
1.55

 
1.44

 
1.82

Diluted
0.29

 
1.61

 
1.55

 
1.43

 
1.81

Dividends per share
1.48

 
1.375

 
1.22

 
1.145

 
1.06

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

 
$
33,998

 
$
33,486

 
$
30,544

 
$
28,096

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

 
12,727

 
12,441

 
10,610

 
10,104



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

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Securing new growth opportunities that add value for our investors within each of our business segments.
Expanding our value chain participation into complementary infrastructure assets.
Natural gas supply dynamics continue to rapidly change, and there is general recognition that natural gas can be an effective solution for meeting the energy needs of North America and beyond. This causes us to be optimistic about future growth opportunities. Identified opportunities include growth in gas-fired power generation and industrial markets, LNG exports from North America, growth related to moving new sources of gas supplies to markets (including exports) and significant new liquids pipeline infrastructure. With our advantage of providing continuous access from leading supply regions through to the last mile of pipe in growing natural gas, NGL and crude oil markets, we expect to continue expanding our assets and operations to meet the evolving needs of our customers.
Crude oil supply dynamics also continue to evolve as North American production moved from growth to decline. Growing North American crude oil production had in recent years displaced imports from overseas and was driving increased demand for crude oil transportation and logistics. Although depressed global crude oil prices have resulted in declining North American oil production, we remain confident about long-term growth in North American oil production and our ability to capture future opportunities to grow our crude oil pipeline business.
Successful execution of our strategy will depend on successfully maintaining our leadership as a safe and reliable operator and the successful execution of our capital projects. Continued growth and new opportunities will be determined by key factors, such as the continued production and the consumption of natural gas, NGLs and crude oil within North America and our ability to provide creative solutions to meet the markets’ evolving energy needs in both North America and beyond.
We continue to be actively engaged in the national discussions in both the U.S. and Canada regarding energy policy and have taken a lead role in shaping policy as it relates to pipeline safety and operations.
Significant Economic Factors For Our Business.    Our regulated businesses are generally economically stable and are not significantly affected in the short-term by changing commodity prices. However, all of our businesses can be negatively affected in the long term by sustained downturns in the economy or prolonged decreases in the demand for crude oil, natural gas and/or NGLs, all of which are beyond our control and could impair our ability to meet long-term goals.
Most of our revenues are based on regulated tariff rates, which include the recovery of certain fuel costs. Lower overall economic output would reduce the volume of natural gas and NGLs transported and distributed or gathered and processed at our plants, and the volume of crude oil transported, resulting in lower earnings and cash flows. This decline would primarily affect distribution revenues and gathering and processing revenues, potentially in the short term. Transmission revenues could be affected by long-term economic declines resulting in the non-renewal of long-term contracts at the time of expiration. Pipeline transportation and storage customers continue to renew most contracts as they expire. Gathering and processing revenues and the earnings and cash distributions from our Field Services segment are also affected by volumes of natural gas made available to our systems, which are primarily driven by levels of natural gas drilling activity. While experiencing a decline in production from conventional gas wells, natural gas exploration and drilling activity in the areas that affect our Western Canada Transmission & Processing and Field Services segments remain stable, primarily driven by recent positive “supply push developments around unconventional gas reserves production in numerous locations within North America as discussed further below and by “demand pull projects in BC and the Pacific Northwest.
Our combined key natural gas markets—the northeastern and the southeastern U.S., the Pacific Northwest, BC and Ontario—are projected to continue to exhibit higher than average annual growth in natural gas demand versus the North American and continental U.S. average growth rates through 2019. This demand growth is primarily driven by the natural gas-fired electricity generation sector and other new industrial gas demands, including LNG. The natural gas industry is currently experiencing a significant shift in the sources of supply, and this dramatic change is affecting our growth strategies. Traditionally, supply to our markets has come from the Gulf Coast region, both onshore and offshore, as well as from natural gas reserves in western and eastern Canada. The national supply profile is shifting to new sources of gas from natural gas shale basins in the Rockies, Midcontinent, Appalachia, Texas and Louisiana. Also, significant supply sources continue to be identified for development in western Canada. These supply shifts are shaping the growth strategies that we will pursue, and therefore, will affect the nature of the projects anticipated in the capital and investment expenditure increases discussed below in “Liquidity and Capital Resources.” Recent community and political pressures have arisen around the production processes associated with extracting natural gas from the natural gas shale basins. Although we continue to believe that natural gas will remain a viable energy solution for the U.S. and Canada, these pressures could increase costs and/or cause a slowdown in the production of natural gas from these basins, and therefore, could negatively affect our growth plans.
Our key crude oil markets include the Rocky Mountain and Midwest states with growing connectivity to the Gulf Coast of the U.S. Growth in our business is dependent on growing crude oil supply from North American sources and the ability of

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

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Certain of our segments’ earnings are affected by fluctuations in commodity prices, especially the earnings of Field Services and our Empress NGL business at Western Canada Transmission & Processing, which are most sensitive to changes in NGL prices. DCP Midstream manages its direct exposure to these market prices separate from Spectra Energy, and utilizes various risk management strategies, including the use of commodity derivatives. We evaluate the risks associated with commodity price volatility on an ongoing basis and implemented a commodity hedging program at Western Canada Transmission & Processing’s Empress NGL business effective January 2014. We have elected to not apply cash flow hedge accounting.
Based on current projections, our expected effective income tax rate will approximate 21%–22% for 2016. Our overall expected tax rate largely depends on the proportion of earnings in the U.S. to the earnings of our Canadian operations. Our earnings in the U.S. are subject to a combined federal and state statutory tax rate of approximately 37%. Our earnings in Canada are subject to a combined federal and provincial statutory tax rate of approximately 26%, but we anticipate an effective Canadian tax rate of less than 1% for 2016, driven primarily by the recognition of certain regulatory tax benefits. See “Liquidity and Capital Resources” for further discussion about the tax impact of repatriating funds generated from our Canadian operations to Spectra Energy Corp (the U.S. parent).
Our strategic objectives include a critical focus on capital expansion projects that will require access to capital markets. An inability to access capital at competitive rates could affect our ability to implement our strategy. Market disruptions or a downgrade in our credit ratings may increase the cost of borrowings or affect our ability to access one or more sources of liquidity.
During the past few years, capital expansion projects have been exposed to cost pressures associated with the availability of skilled labor, the pricing of materials and challenges associated with ensuring the protection of our environment and continual safety enhancements to our facilities. We maintain a strong focus on project management activities to address these pressures as we move forward with planned expansion opportunities. Significant cost increases could negatively affect the returns ultimately earned on current and future expansions.
For further information related to management’s assessment of our risk factors, see Part I. Item 1A. Risk Factors.


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

 
$
5,903

 
$
5,518

Operating expenses
3,801

 
3,979

 
3,852

Operating income
1,433

 
1,924

 
1,666

Other income and expenses
(176
)
 
420

 
569

Interest expense
636

 
679

 
657

Earnings before income taxes
621

 
1,665

 
1,578

Income tax expense
161

 
382

 
419

Net income
460

 
1,283

 
1,159

Net income—noncontrolling interests
264

 
201

 
121

Net income—controlling interests
$
196

 
$
1,082

 
$
1,038

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

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

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

 
$
1,669

 
$
1,433

Distribution
473

 
552

 
574

Western Canada Transmission & Processing
491

 
754

 
736

Field Services
(461
)
 
217

 
343

Total reportable segment EBITDA
2,408

 
3,192

 
3,086

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

 
3,134

 
3,000

Depreciation and amortization
764

 
796

 
772

Interest expense
636

 
679

 
657

Interest income and other (a)
(3
)
 
6

 
7

Earnings before income taxes
$
621

 
$
1,665

 
$
1,578

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

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

 
$
2,269

 
$
186

 
$
1,965

 
$
304

Operating expenses
 
 
 
 
 
 
 
 
 
Operating, maintenance and other
828

 
781

 
47

 
715

 
66

Other income and expenses
278

 
181

 
97

 
183

 
(2
)
EBITDA
$
1,905

 
$
1,669

 
$
236

 
$
1,433

 
$
236

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

 
223

 
16

 
219

 
4

Platte PADD II deliveries, MBbl/d
162

 
170

 
(8
)
 
168

 
2

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

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

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

 
$
1,843

 
$
(316
)
 
$
1,848

 
$
(5
)
Operating expenses
 
 
 
 
 
 
 
 
 
Natural gas purchased
691

 
879

 
(188
)
 
826

 
53

Operating, maintenance and other
363

 
411

 
(48
)
 
448

 
(37
)
Other income and expenses

 
(1
)
 
1

 

 
(1
)
EBITDA
$
473

 
$
552

 
$
(79
)
 
$
574

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

 
1,420

 
17

 
1,399

 
21

Heating degree days, Fahrenheit
7,387

 
8,111

 
(724
)
 
7,540

 
571

Pipeline throughput, TBtu (a)
759

 
713

 
46

 
907

 
(194
)
Canadian dollar exchange rate, average
1.28

 
1.10

 
0.18

 
1.03

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

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

 
$
1,902

 
$
(617
)
 
$
1,767

 
$
135

Operating expenses
 
 
 
 
 
 
 
 
 
Natural gas and petroleum products purchased
193

 
466

 
(273
)
 
391

 
75

Operating, maintenance and other
611

 
687

 
(76
)
 
649

 
38

Other income and expenses
10

 
5

 
5

 
9

 
(4
)
EBITDA
$
491

 
$
754

 
$
(263
)
 
$
736

 
$
18

Pipeline throughput, TBtu
923

 
934

 
(11
)
 
780

 
154

Volumes processed, TBtu
658

 
721

 
(63
)
 
704

 
17

Canadian dollar exchange rate, average
1.28

 
1.10

 
0.18

 
1.03

 
0.07

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

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

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a $6 million increase in operating costs of new facilities and
a $5 million increase due to software support services, partially offset by
a $48 million decrease as a result of a weaker Canadian dollar.
Matters Affecting Future Western Canada Transmission & Processing Results
Western Canada Transmission & Processing plans to continue earnings growth through capital efficient “supply push” and “demand pull” initiatives. “Supply push” growth projects are associated with gathering and processing expansions and incremental transportation capacity to support drilling activity in northern BC. Sizable growth in production is being driven by the application of new drilling technologies to unconventional gas reservoirs, with current growth heaviest in the southern and northern sections of the Montney play. “Demand pull” growth projects are associated with both small and large scale LNG exports as well as new natural gas-fired electricity generation, methanol, and fertilizer plants in BC and the Pacific Northwest. Prolific nearby gas supplies and favorable international market access have made gas focused projects in BC and the U.S. Pacific Northwest very attractive. Earnings can fluctuate from period to period as a result of the timing of processing plant turnarounds that reduce revenues while a plant is out of service and increase operating costs as a result of the turnaround maintenance work. Western Canada Transmission & Processing’s processing plants are generally scheduled for turnaround work every three to four years, with the work being staggered to prevent significant outages at any given time in a single geographic area. Future earnings will also be affected by the ability to renew service contracts and regulatory stability. Earnings from processing services will be affected by the ability to access additional natural gas reserves. In addition, the Empress NGL business will be affected by NGL prices, gas flows eastbound beyond Empress and costs of acquiring natural gas, NGL extraction rights and NGLs.
During the past several years, the Canadian dollar has fluctuated compared to the U.S. dollar, which affected earnings to varying degrees for brief periods. Changes in the exchange rate are difficult to predict and may affect future results.
In certain areas of Western Canada Transmission & Processing’s operations, lower natural gas prices resulting from increasing North American gas production have reduced producer demand for both expansions of the BC gas processing plants as well as renewals of existing gas processing contracts, and could continue to do so as long as gas prices remain below historical norms.
Field Services
 
2015
 
2014
 
Increase
(Decrease)
 
2013
 
Increase
(Decrease)
 
(in millions, except where noted)
Earnings (loss) from equity investments
$
(461
)
 
$
217

 
$
(678
)
 
$
343

 
$
(126
)
EBITDA
$
(461
)
 
$
217

 
$
(678
)
 
$
343

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

 
7.3

 
(0.2
)
 
7.1

 
0.2

NGL production, MBbl/d (a)
410

 
454

 
(44
)
 
426

 
28

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

 
$
4.41

 
$
(1.75
)
 
$
3.65

 
$
0.76

Average NGL price per gallon (e)
$
0.45

 
$
0.89

 
$
(0.44
)
 
$
0.90

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

 
$
93.06

 
$
(44.26
)
 
$
98.04

 
$
(4.98
)
____________

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

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Table of Contents

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

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

 
$
14,013

 
$
12,038

Operating expenses
8,227

 
13,262

 
11,230

Operating income (loss)
(807
)
 
751

 
808

Other income and expenses
182

 
83

 
35

Interest expense, net
320

 
287

 
249

Income tax expense (benefit)
(102
)
 
11

 
10

Net income (loss)
(843
)
 
536

 
584

Net income—noncontrolling interests
86

 
248

 
93

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

 
$
491

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

 
$
72

 
$
1

 
$
72

 
$

Operating expenses
 
 
 
 
 
 
 
 
 
Operating, maintenance and other
457

 
141

 
316

 
185

 
(44
)
Other income and expenses

 
11

 
(11
)
 
27

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


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2015 Compared to 2014
EBITDA. The $326 million change primarily reflects goodwill impairment charges associated with the Westcoast acquisition in 2002.
2014 Compared to 2013
EBITDA. The $28 million change reflects lower transaction costs associated with the U.S. Assets Dropdown and lower employee benefit costs, partially offset by a 2013 benefit from the reversal of an uncertain tax position related to matters prior to the spin-off of Spectra Energy in 2007.
Matters Affecting Future Other Results
Future Other results will continue to include corporate and business services we provide for our operations, and will also include operating costs and self-insured losses associated with our captive insurance entities. The results for Other could be impacted by the number and severity of insured property losses.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The application of accounting policies and estimates is an important process that continues to evolve as our operations change and accounting guidance is issued. We have identified a number of critical accounting policies and estimates that require the use of significant estimates and judgments.
We base our estimates and judgments on historical experience and on other assumptions that we believe are reasonable at the time of application. These estimates and judgments may change as time passes and more information becomes available. If estimates are different than the actual amounts recorded, adjustments are made in subsequent periods to take into consideration the new information. We discuss our critical accounting policies and estimates and other significant accounting policies with our Audit Committee.
Regulatory Accounting
We account for certain of our operations under accounting for regulated entities. As a result, we record assets and liabilities that result from the regulated ratemaking process that may not be recorded under generally accepted accounting principles for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers or for instances where the regulator provides current rates that are intended to recover costs that are expected to be incurred in the future. We continually assess whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders to other regulated entities. Based on this assessment, we believe our existing regulatory assets, which primarily relate to the future collection of deferred income tax costs for our Canadian regulated operations, are probable of recovery. This assessment reflects the current political and regulatory climate at the state, provincial and federal levels, and is subject to change in the future. If future recovery of costs ceases to be probable, regulatory asset write-offs would be required. Additionally, regulatory agencies can provide flexibility in the manner and timing of the depreciation of property, plant and equipment and amortization of regulatory assets. Total regulatory assets were $1,397 million as of December 31, 2015 and $1,494 million as of December 31, 2014. Total regulatory liabilities were $385 million as of December 31, 2015 and $430 million as of December 31, 2014.
Impairment of Goodwill
We had goodwill balances of $4,154 million at December 31, 2015 and $4,714 million at December 31, 2014. The decrease in goodwill in 2015 was primarily due to the $333 million impairment of goodwill of our BC Field Services business and our Empress NGL operations associated with the Westcoast acquisition in 2002, as well as the result of foreign currency translation.
As permitted under accounting guidance on testing goodwill for impairment, we perform either a qualitative assessment or a quantitative assessment of each of our reporting units based on management’s judgment. With respect to our qualitative assessments, we consider events and circumstances specific to us, such as macroeconomic conditions, industry and market considerations, cost factors and overall financial performance, when evaluating whether it is more likely than not that the fair values of our reporting units are less than their respective carrying amounts.
In connection with our quantitative assessments, we primarily use a discounted cash flow analysis to determine fair values of those reporting units. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in key markets

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served by our operations, regulatory stability, the ability to renew contracts, commodity prices (where appropriate) and foreign currency exchange rates, as well as other factors that affect our reporting units’ revenue, expense and capital expenditure projections.
Based on the results of our annual goodwill impairment testing, no indicators of impairment were noted and the fair values of the reporting units that we assessed at April 1, 2015 (our annual testing date) were in excess of their respective carrying values.
We believe the assumptions used in our analyses are appropriate and result in reasonable estimates of the fair values of our reporting units. However, the assumptions used are subject to uncertainty, and declines in the future performance or cash flows of our reporting units, changing business conditions, further sustained declines in commodity prices or increases to our weighted average cost of capital assumptions may result in the recognition of impairment charges, which could be significant.
No triggering events have occurred with our reporting units since the April 1, 2015 test that would warrant re-testing for goodwill impairment except for BC Field Services and Empress.
In the fourth quarter of 2015, we continued to assess goodwill at BC Field Services and Empress and performed further testing based on a combination of an income approach and a market approach. The impairment test resulted in recognition of a $270 million goodwill impairment for BC Field Services and a $63 million goodwill impairment for Empress which resulted in a total goodwill impairment of $333 million.
Due to the significant downturn in commodity prices, DCP Midstream performed a goodwill impairment test which was finalized in the third quarter of 2015. The impairment test was based on an internal discounted cash flow model taking into account various observable and non-observable factors, such as prices, volumes, expenses and discount rate. The impairment test resulted in DCP Midstream’s recognition of a $460 million goodwill impairment, which reduced our equity earnings from DCP Midstream by $123 million after-tax for the nine month period ending September 30, 2015.
Due to the impairment of goodwill recognized by DCP Midstream, we assessed our equity investment in DCP Midstream and determined that our investment’s fair value exceeded it's carrying value.
Revenue Recognition
Revenues from the transmission, storage, processing, distribution and sales of natural gas, from the transportation and storage of crude oil, and from the sales of NGLs, are recognized when either the service is provided or the product is delivered. Revenues related to these services provided or products delivered but not yet billed are estimated each month. These estimates are generally based on contract data, regulatory information, estimated distribution usage based on historical data adjusted for heating degree days, commodity prices and preliminary throughput and allocation measurements. Final bills for the current month are billed and collected in the following month. Differences between actual and estimated unbilled revenues are immaterial.
Pension and Other Post-Retirement Benefits
The calculations of pension and other post-retirement expense and liabilities require the use of numerous assumptions. Changes in these assumptions can result in different reported expense and liability amounts, and future actual demographic and economic outcomes can differ from the assumptions. We believe that the most critical assumptions used in the accounting for pension and other post-retirement benefits are the expected long-term rate of return on plan assets, the assumed discount rate, and the medical and prescription drug cost trend rate assumptions.
Future changes in plan asset returns, assumed discount rates and various other factors related to the participants in our pension and post-retirement plans will impact future pension expense and funding.
The expected return on plan assets is important, as certain of our pension and other post-retirement benefit plans are partially funded. Expected long-term rates of return on plan assets are developed by using a weighted average of expected returns for each asset class to which the plan assets are allocated. For 2015, the assumed average return was 8.00% for the U.S. pension plan assets, 7.40% for the Canadian pension plan assets and 6.90% for the U.S. other post-retirement benefit assets. A change in the rate of return of 25 basis points for these assets would impact annual benefit expense by approximately $1 million before tax for U.S. plans and by approximately $2 million before tax for Canadian plans. The Canadian other post-retirement benefit plans are not funded.
Since pension and other post-retirement benefit cost and obligations are measured on a discounted basis, the discount rates used to determine the net periodic benefit cost and the benefit obligation are significant assumptions. Discount rates used for our defined benefit and other post-retirement benefit plans are based on the yields constructed from a portfolio of high-

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quality bonds for which the timing and amount of cash outflows approximate the estimated payouts of the plans. Discount rates of 4.10% for the U.S. plans and 4.00% for the Canadian plans were used to calculate the 2015 net periodic benefit cost, and represent a weighted average of the applicable rates for all U.S. and Canadian plans, respectively. A 25 basis-point change in the discount rates would impact annual before-tax net periodic benefit cost by less than $1 million for U.S. plans and $4 million for Canadian plans. Discount rates of 4.44% for the U.S. plans and 4.03% for the Canadian plans were used to calculate the 2015 year-end benefit obligations and represent a weighted average of the applicable rates for all U.S. and Canadian plans, respectively. The weighted average discount rates used to determine the benefit obligation increased approximately 0.35% for the U.S. plans and approximately 0.03% for the Canadian plans during 2015. The increase in the benefit obligation discount rate and actuarial experience during 2015 resulted in a decrease in benefit obligations at December 31, 2015 compared to December 31, 2014.
See Note 23 of Notes to Consolidated Financial Statements for more information on pension and other post-retirement benefits.
LIQUIDITY AND CAPITAL RESOURCES
Known Trends and Uncertainties
As of December 31, 2015, we had negative working capital of $1,744 million. This balance includes commercial paper liabilities totaling $1,112 million, current maturities of long-term debt of $652 million and a payable to an equity investment of $148 million. We will rely upon cash flows from operations and various financing transactions, which may include debt and/or equity issuances, to fund our liquidity and capital requirements for 2016. SEP is expected to be self-funding through its cash flows from operations, use of its revolving credit facility and its access to capital markets. We receive cash distributions from SEP in accordance with the partnership agreement, which considers our level of ownership and incentive distribution rights.
As of December 31, 2015, our four revolving credit facilities included Spectra Capital’s $1.0 billion facility, SEP’s $2.0 billion facility, Westcoast’s 400 million Canadian dollar facility and Union Gas’ 500 million Canadian dollar facility. These facilities are used principally as back-stops for commercial paper programs. At Spectra Capital, SEP and Westcoast, we primarily use commercial paper for temporary funding of capital expenditures. At Union Gas, we primarily use commercial paper to support short-term working capital fluctuations. We also utilize commercial paper, other variable-rate debt and interest rate swaps to achieve our desired mix of fixed and variable-rate debt. See Note 15 of Notes to Consolidated Financial Statements for a discussion of available credit facilities and Financing Cash Flows and Liquidity for a discussion of effective shelf registrations.
Our consolidated capital structure includes commercial paper, long-term debt (including current maturities), preferred stock of subsidiaries and total equity. As of December 31, 2015, our capital structure was 59.8% debt, 26.6% common equity of controlling interests and 13.6% noncontrolling interests and preferred stock of subsidiaries.
Cash flows from operations for our 100%-owned and majority-owned businesses are stable given that approximately 90% of revenues are derived from fee-based services, of which most are regulated. However, total operating cash flows are subject to a number of factors, including, but not limited to, earnings sensitivities to weather, commodity prices, distributions from our equity investments and the timing of cost recoveries pursuant to regulatory approvals. See Part I. Item 1A. Risk Factors for further discussion.
Cash distributions from our equity investment, DCP Midstream, can fluctuate, mostly as a result of earnings sensitivities to commodity prices, as well as its level of capital expenditures and other investing activities. DCP Midstream funds its operations and investing activities mostly from its operating cash flows, third-party debt and equity transactions associated with DCP Partners. DCP Midstream is required to make quarterly tax distributions to us based on allocated taxable income. In addition to tax distributions, periodic distributions are determined by DCP Midstream’s board of directors based on its earnings, operating cash flows and other factors, including capital expenditures and other investing activities, commodity prices outlook and the credit environment. We received no tax or periodic distributions from DCP Midstream during 2015. We received total tax and periodic distributions from DCP midstream of $237 million in 2014 and $215 million in 2013. These distributions are classified within Operating Cash Flows. We continue to assess the effect of sustained lower commodity prices and other activities at DCP Midstream on cash expected to be received from DCP Midstream and adjust our expansion or other activities as necessary.
In addition, cash flows from our Canadian operations are generally used to fund the ongoing Canadian businesses and future Canadian growth. At December 31, 2015, $131 million of Cash and Cash Equivalents was held by our Canadian subsidiaries. Historically, we have reinvested a substantial portion of our Canadian operations’ earnings in Canada. Earnings not needed by our Canadian operations have been distributed to Spectra Energy Corp (the U.S. parent) with minimal

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incremental U.S. tax liability. We anticipate continued substantial reinvestment of our future Canadian earnings in Canada; however, future distributions to Spectra Energy Corp may incur incremental U.S. tax at the U.S. statutory rate without the ability to use foreign tax credits. The timing of when distributions may incur such incremental U.S. tax depends on many factors, such as the amount of future capital expansions in Canada, the tax characterization of our distributions as returns of capital or dividends, the impacts of tax planning on merger and acquisition activities and tax legislation at the time of the distributions.
As we execute on our strategic objectives around organic growth and expansion projects, expansion expenditures are expected to approximate $3.7 billion in 2016 and $2.2 billion in 2017, excluding contributions from noncontrolling interests. The timing and extent of these expenditures are likely to vary significantly from year to year, depending mostly on general economic conditions and market requirements. Given that we expect to continue to pursue expansion and earnings growth opportunities over the next several years and also given the scheduled maturities of our existing debt instruments, capital resources will continue to include long-term borrowings and possibly securing additional sources of capital including debt and/or equity securities. We remain committed to maintaining a capital structure and liquidity profile that continue to support an investment-grade credit rating.
Cash Flow Analysis
The following table summarizes the changes in cash flows for each of the periods presented:
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
(in millions)
Net cash provided by (used in):
 
 
 
 
 
Operating activities
$
2,247

 
$
2,221

 
$
2,030

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

 
(199
)
 
1,316

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

 
107

Cash and cash equivalents at beginning of the period
215

 
201

 
94

Cash and cash equivalents at end of the period
$
213

 
$
215

 
$
201

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

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$6 million of net purchases of available-for-sale securities in 2014 compared to $146 million of net proceeds in 2013 and
a $28 million increase in capital and investment expenditures in 2014. Capital and investment expenditures include a $189 million investment in SESH, used by SESH to retire debt.
Capital and Investment Expenditures by Business Segment
Capital and investment expenditures are detailed by business segment in the following table. Capital and investment expenditures presented below include expenditures from continuing operations.
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
(in millions)
Spectra Energy Partners (a,b)
$
2,007

 
$
1,241

 
$
1,299

Distribution
544

 
427

 
357

Western Canada Transmission & Processing
360

 
473

 
561

Total reportable segments
2,911

 
2,141

 
2,217

Other
61

 
146

 
42

Total consolidated
$
2,972

 
$
2,287

 
$
2,259

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

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

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

 
3.50
%
 
2025
SEP
500

 
4.50
%
 
2045
Westcoast
222

(a)
3.77
%

2025
Westcoast
37

(a)
4.79
%
 
2041
Union Gas
152

(a)
3.19
%

2025
Union Gas
190

(a)
4.20
%

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

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

 
variable

 
2018
Westcoast
316

(a)
3.43
%
 
2024
Union Gas
229

(a)
4.20
%
 
2044
Union Gas
183

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

(a) 
variable

 
N/A
Spectra Capital
650

  
3.30
%
 
2023
SEP
1,000

  
4.75
%
 
2024
SEP
500

  
2.95
%
 
2018
SEP
400

  
5.95
%
 
2043
SEP
400

  
variable

 
2018
Union Gas
237

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

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

 
$
481

 
$
519

SEP (b)
2019
 
2,000

 
476

 
1,524

Westcoast (c)
2019
 
289

 
6

 
283

Union Gas (d)
2019
 
361

 
149

 
212

Total
 
 
$
3,650

 
$
1,112

 
$
2,538

  __________________
(a)
Revolving credit facility contains a covenant requiring the Spectra Energy consolidated debt-to-total capitalization ratio, as defined in the agreement, to not exceed 65%. Per the terms of the agreement, collateralized debt is excluded from the calculation of the ratio. This ratio was 59.6% at December 31, 2015.
(b)
Revolving credit facility contains a covenant that requires SEP to maintain a ratio of total Consolidated Indebtedness-to-Consolidated EBITDA, as defined in the agreement, of 5.0 to 1 or less. As of December 31, 2015, this ratio was 3.6 to 1.
(c)
U.S. dollar equivalent at December 31, 2015. The revolving credit facility is 400 million Canadian dollars and contains a covenant that requires the Westcoast non-consolidated debt-to-total capitalization ratio to not exceed 75%. The ratio was 35.4% at December 31, 2015.
(d)
U.S. dollar equivalent at December 31, 2015. The revolving credit facility is 500 million Canadian dollars and contains a covenant that requires the Union Gas debt-to-total capitalization ratio to not exceed 75% and a provision which requires Union Gas to repay all borrowings under the facility for a period of two days during the second quarter of each year. The ratio was 67.8% at December 31, 2015.
The issuances of commercial paper, letters of credit and revolving borrowings reduce the amounts available under the credit facilities. As of December 31, 2015, there were no letters of credit issued or revolving borrowings outstanding under the credit facilities.
Our credit agreements contain various covenants, including the maintenance of certain financial ratios. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of December 31, 2015, we were in compliance with those covenants. In addition, our credit agreements allow for acceleration of payments or termination of the agreements due to nonpayment, or in some cases, due to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. Our debt and credit agreements do not contain provisions that trigger an acceleration of indebtedness based solely on the occurrence of a material adverse change in our financial condition or results of operations.
As noted above, the terms of our Spectra Capital credit agreements require our consolidated debt-to-total-capitalization ratio, as defined in the agreement, to be 65% or lower. Per the terms of the agreement, collateralized debt is excluded from the calculation of the ratio. This ratio was 59.6% at December 31, 2015. Our equity and, as a result, this ratio, is sensitive to significant movements of the Canadian dollar relative to the U.S. dollar due to the significance of our Canadian operations as discussed in “Quantitative and Qualitative Disclosures About Market Risk—Foreign Currency Risk.” Based on the strength of our total capitalization as of December 31, 2015, however, it is not likely that a material adverse effect would occur as a result of a weakened Canadian dollar.
Dividends.    Our near-term objective is to increase our cash dividend by $0.14 per share, per year, through 2018. We expect to continue our policy of paying regular cash dividends. The declaration and payment of dividends are subject to the sole discretion of our Board of Directors and will depend upon many factors, including the financial condition, earnings and capital requirements of our operating subsidiaries, covenants associated with certain debt obligations, legal requirements, regulatory constraints and other factors deemed relevant by our Board of Directors. We declared a quarterly cash dividend of $0.405 per common share on January 05, 2016 payable on March 08, 2016 to shareholders of record at the close of business on February 12, 2016.
Other Financing Matters.    Spectra Energy Corp and Spectra Capital have an effective shelf registration statement on file with the SEC to register the issuance of unlimited amounts of various equity and debt securities. SEP has an effective shelf registration statement on file with the SEC to register the issuance of unlimited amounts of limited partner common units. SEP also has $944 million available as of December 31, 2015 for the issuance of limited partner common units under another effective shelf registration statement on file with the SEC related to its at-the-market program. Westcoast and Union Gas have an aggregate 1.7 billion Canadian dollars (approximately $1.2 billion) available as of December 31, 2015 for the issuance of debt securities in the Canadian market under their medium term note shelf prospectuses.

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Off-Balance Sheet Arrangements
We enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include financial guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. See Note 20 of Notes to Consolidated Financial Statements for further discussion of guarantee arrangements.
Most of the guarantee arrangements that we enter into enhance the credit standings of certain subsidiaries, non-consolidated entities or less than 100%-owned entities, enabling them to conduct business. As such, these guarantee arrangements involve elements of performance and credit risk which are not included on our Consolidated Balance Sheets. The possibility of us having to honor our contingencies is largely dependent upon the future operations of our subsidiaries, investees and other third parties, or the occurrence of certain future events.
Issuance of these guarantee arrangements is not required for the majority of our operations. As such, if we discontinued issuing these guarantee arrangements, there would not be a material impact to our consolidated results of operations, financial position or cash flows.
We do not have material off-balance sheet financing entities or structures, except for normal operating lease arrangements, guarantee arrangements and financings entered into by DCP Midstream and our other equity investments. For additional information on these commitments, see Notes 19 and 20 of Notes to Consolidated Financial Statements.

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Contractual Obligations
We enter into contracts that require payment of cash at certain periods based on certain specified minimum quantities and prices. The following table summarizes our contractual cash obligations for each of the periods presented. The table below excludes all amounts classified as Current Liabilities on the December 31, 2015 Consolidated Balance Sheet other than Current Maturities of Long-Term Debt. It is expected that the majority of Current Liabilities will be paid in cash in 2016.
Contractual Obligations as of December 31, 2015
 
Payments Due By Period
 
Total
 
2016
 
2017 &
2018
 
2019 &
2020
 
2021 &
Beyond
 
(in millions)
Long-term debt (a)
$
20,472

 
$
1,300

 
$
4,038

 
$
2,635

 
$
12,499

Operating leases (b)
334

 
49

 
80

 
66

 
139

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

 
188

 
424

 
284

 
1,890

Energy commodity contracts (e)
240

 
227

 
13

 

 

Other purchase obligations (f)
532

 
418

 
58

 
34

 
22

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

 
46

 
8

 

 

Total contractual cash obligations
$
24,418

 
$
2,228

 
$
4,621

 
$
3,019

 
$
14,550

__________
(a)
See Note 15 of Notes to Consolidated Financial Statements. Amounts include principal payments and estimated scheduled interest payments over the life of the associated debt and capital lease obligations.
(b)
See Note 19.
(c)
Purchase obligations reflected in the Consolidated Balance Sheets have been excluded from the above table.
(d)
Includes firm capacity payments that provide us with uninterrupted firm access to natural gas transportation and storage.
(e)
Includes contractual obligations to purchase physical quantities of NGLs and natural gas. Amounts include certain hedges as defined by applicable accounting standards. For contracts where the price paid is based on an index, the amount is based on forward market prices at December 31, 2015.
(f)
Includes contracts for software and consulting or advisory services. Amounts also include contractual obligations for engineering, procurement and construction costs for pipeline projects. Amounts exclude certain open purchase orders for services that are provided on demand, where the timing of the purchase cannot be determined.
(g)
Includes estimated 2016 retirement plan contributions (see Note 23). We are unable to estimate retirement plan contributions beyond 2016 due primarily to uncertainties about market performance of plan assets. Excludes cash obligations for asset retirement activities (see Note 14) because the amount of cash flows to be paid to settle the asset retirement obligations is not known with certainty as we may use internal or external resources to perform retirement activities. Amounts also exclude reserves for litigation and environmental remediation (see Note 19) and regulatory liabilities (see Note 5) because we are uncertain as to the amount and/or timing of when cash payments will be required. Amounts also exclude deferred income taxes and investment tax credits on the Consolidated Balance Sheets since cash payments for income taxes are determined primarily by taxable income for each discrete fiscal year.
Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risks associated with commodity prices, credit exposure, interest rates, equity prices and foreign currency exchange rates. We have established comprehensive risk management policies to monitor and manage these market risks. Our Chief Financial Officer is responsible for the overall governance of managing credit risk and commodity price risk, including monitoring exposure limits.
Commodity Price Risk
We are exposed to the impact of market fluctuations in the prices of NGLs and natural gas purchased as a result of our investment in DCP Midstream, and the ownership of the NGL marketing operations in western Canada and processing associated with certain of our U.S. pipeline assets. Price risk represents the potential risk of loss from adverse changes in the market price of these energy commodities. Our exposure to commodity price risk is influenced by a number of factors, including contract size, length, market liquidity, location and unique or specific contract terms.
Within the Western Canada Transmission & Processing segment, we employ policies and procedures to manage Spectra Energy’s risks associated with Empress’ commodity price fluctuations, which may include the use of forward physical

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transactions as well as commodity derivatives. In 2014, we implemented a commodity hedging program at Empress and have elected to not apply cash flow hedge accounting.
DCP Midstream manages its direct exposure to market prices separate from Spectra Energy, and utilizes various risk management strategies, including the use of commodity derivatives.
We are exposed to market price fluctuations of NGLs, natural gas and oil in our Field Services segment. Based on a sensitivity analysis as of December 31, 2015 and 2014, a 10¢ per-gallon change in NGL prices would affect our annual pre-tax earnings by approximately $40 million in 2016 and $55 million in 2015 for Field Services. For the same periods, a 50¢ per-MMBtu change in natural gas prices would affect our annual pre-tax earnings by approximately $18 million and $23 million, respectively, and a $10 per-barrel change in oil prices would affect our annual pre-tax earnings by approximately $20 million and $25 million, respectively.
Within the Western Canada Transmission & Processing segment, we have NGL marketing operations with contracts to buy and sell commodities, including natural gas, NGLs and other commodities that are settled by the delivery of the commodity or cash. With respect to the Empress assets in Western Canada Transmission & Processing, a 10¢ per-gallon change in NGL prices, primarily propane prices, would affect our annual pre-tax earnings by approximately $23 million in 2016. For the same period, a 50¢ per-MMBtu change in natural gas prices would affect our annual pre-tax earnings by approximately $6 million. These estimates do not include the effects of commodity derivatives or variability in business activity that may occur as a result of such things as changes in the demand for our products or changes in plant operations. Empress is also exposed to changes in the fair value of our commodity derivatives as a result of fluctuations in the market price of NGLs. At December 31, 2015, a 10¢ per-gallon movement in underlying commodity NGL prices would affect the estimated fair value of commodity derivatives by approximately $15 million.
These hypothetical calculations consider estimated production levels, but do not consider other potential effects that might result from such changes in commodity prices. The actual effect of commodity price changes on our earnings could be significantly different than these estimates.
See also Notes 1 and 18 of Notes to Consolidated Financial Statements.
Credit Risk
Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. Our principal customers for natural gas transmission, storage, and gathering and processing services are industrial end-users, marketers, exploration and production companies, LDCs and utilities located throughout the U.S. and Canada. Customers on the Express-Platte system are primarily refineries located in the Rocky Mountain and Midwestern states of the U.S. Other customers include oil producers and marketing entities. We have concentrations of receivables from natural gas utilities and their affiliates, industrial customers and marketers throughout these regions, as well as retail distribution customers in Canada. These concentrations of customers may affect our overall credit risk in that risk factors can negatively affect the credit quality of the entire sector. Credit risk associated with gas distribution services are primarily affected by general economic conditions in the service territory.
Where exposed to credit risk, we analyze the customers’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We also obtain parental guarantees, cash deposits or letters of credit from customers to provide credit support, where appropriate, based on our financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each contract. A significant amount of our credit exposures for transmission, storage, and gathering and processing services are with customers who have an investment-grade rating (or the equivalent based on our evaluation) or are secured by collateral. However, we cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including possible declines in our customers’ creditworthiness.
Based on our policies for managing credit risk, our current exposures and our credit and other reserves, we do not anticipate a material effect on our consolidated financial position or results of operations as a result of non-performance by any counterparty.

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Interest Rate Risk
We are exposed to risk resulting from changes in interest rates as a result of our issuance of variable and fixed-rate debt and commercial paper. We manage our interest rate exposure by limiting our variable-rate exposures to percentages of total debt and by monitoring the effects of market changes in interest rates. We also enter into financial derivative instruments, including, but not limited to, interest rate swaps and rate lock agreements to manage and mitigate interest rate risk exposure. See also Notes 1, 15 and 18 of Notes to Consolidated Financial Statements.
As of December 31, 2015, we had interest rate hedges in place for various purposes. We are party to “pay floating—receive fixed” interest rate swaps with a total notional amount of $2,000 million to hedge against changes in the fair value of our fixed-rate debt that arise as a result of changes in market interest rates. These swaps also allow us to transform a portion of the underlying interest payments related to our long-term fixed-rate debt securities into variable-rate interest payments in order to achieve our desired mix of fixed and variable-rate debt.
Based on a sensitivity analysis as of December 31, 2015, it was estimated that if short-term interest rates average 100 basis points higher (lower) in 2016 than in 2015, interest expense, net of offsetting interest income, would fluctuate by $35 million. Comparatively, based on a sensitivity analysis as of December 31, 2014, had short-term interest rates averaged 100 basis points higher (lower) in 2015 than in 2014, it was estimated that interest expense, net of offsetting interest income, would have fluctuated by approximately $32 million. These amounts were estimated by considering the effect of the hypothetical interest rates on variable-rate debt outstanding, adjusted for interest rate hedges, short term investments, and cash and cash equivalents outstanding as of December 31, 2015 and 2014.
Equity Price Risk
Our cost of providing non-contributory defined benefit retirement and postretirement benefit plans are dependent upon, among other things, rates of return on plan assets. These plan assets expose us to price fluctuations in equity markets. In addition, our captive insurance companies maintain various investments to fund certain business risks and losses. Those investments may, from time to time, include investments in equity securities. Volatility of equity markets, particularly declines, will not only impact our cost of providing retirement and postretirement benefits, but will also impact the funding level requirements of those benefits.
We manage equity price risk by, among other things, diversifying our investments in equity investments, setting target allocations of investment types, periodically reviewing actual asset allocations and rebalancing allocations if warranted, and utilizing external investment advisors.
Foreign Currency Risk
We are exposed to foreign currency risk from our Canadian operations. To mitigate risks associated with foreign currency fluctuations, contracts may be denominated in or indexed to the U.S. dollar and/or local inflation rates, or investments may be naturally hedged through debt denominated or issued in the foreign currency.
To monitor our currency exchange rate risks, we use sensitivity analysis, which measures the effect of devaluation of the Canadian dollar. An average 10% devaluation in the Canadian dollar exchange rate during 2015 would have resulted in an estimated net loss on the translation of local currency earnings of approximately $24 million on our Consolidated Statement of Operations. In addition, if a 10% devaluation had occurred on December 31, 2015, the Consolidated Balance Sheet would have been negatively impacted by $356 million through a cumulative translation adjustment in AOCI and, this devaluation would result in an immaterial impact to our debt-to-total capitalization ratio. At December 31, 2015, one U.S. dollar translated into 1.38 Canadian dollars.
As discussed earlier, we maintain credit facilities that typically include financial covenants which limit the amount of debt that can be outstanding as a percentage of total capital for Spectra Energy or of a specific subsidiary. Failure to maintain these covenants could preclude us from issuing commercial paper or letters of credit or borrowing under our revolving credit facilities and could require other affiliates to immediately pay down any outstanding drawn amounts under other revolving credit agreements, which could adversely affect cash flows or restrict business. As a result of the impact of foreign currency fluctuations on our consolidated equity, these fluctuations have a direct impact on our ability to maintain certain of these financial covenants.
OTHER ISSUES
For information on other issues, see Notes 5 and 19 of Notes to Consolidated Financial Statements.

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New Accounting Pronouncements
See Note 1 of Notes to Consolidated Financial Statements for discussion.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk for discussion.
Item 8. Financial Statements and Supplementary Data.
Management’s Annual Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining an adequate system of internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes, in accordance with generally accepted accounting principles. Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies and procedures may deteriorate.
Our management, including our Chief Executive Officer and Chief Financial Officer, has conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2015 based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that evaluation, management concluded that our internal control over financial reporting was effective at the reasonable assurance level as of December 31, 2015.
Deloitte & Touche LLP, our independent registered public accounting firm, has audited and issued a report on the effectiveness of our internal control over financial reporting. Their report is included herein.


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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, 2015 and 2014, and the related consolidated statements of operations, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2015. Our audits also included the financial statement schedule listed in the index at Item 15. We also have audited the Company’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule and an opinion on the Company’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Spectra Energy Corp and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas
February 25, 2016

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

 
$
3,291

 
$
3,128

Distribution of natural gas
1,320

 
1,583

 
1,577

Sales of natural gas liquids
209

 
497

 
440

Transportation of crude oil
357

 
302

 
224

Other
123

 
230

 
149

Total operating revenues
5,234

 
5,903

 
5,518

Operating Expenses
 
 
 
 
 
Natural gas and petroleum products purchased
835

 
1,219

 
1,139

Operating, maintenance and other
1,500

 
1,571

 
1,568

Depreciation and amortization
764

 
796

 
772

Property and other taxes
353

 
393

 
373

Impairment of goodwill and other
349

 

 

Total operating expenses
3,801

 
3,979

 
3,852

Operating Income
1,433

 
1,924

 
1,666

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

 
445

Other income and expenses, net
114

 
59

 
124

Total other income and expenses
(176
)
 
420

 
569

Interest Expense
636

 
679

 
657

Earnings Before Income Taxes
621

 
1,665

 
1,578

Income Tax Expense
161

 
382

 
419

Net Income
460

 
1,283

 
1,159

Net Income—Noncontrolling Interests
264

 
201

 
121

Net Income—Controlling Interests
$
196

 
$
1,082

 
$
1,038

Common Stock Data
 
 
 
 
 
Weighted-average shares outstanding
 
 
 
 
 
Basic
671

 
671

 
669

Diluted
672

 
672

 
671

Earnings per share
 
 
 
 
 
Basic and diluted
$
0.29

 
$
1.61

 
$
1.55

Dividends per share
$
1.48

 
$
1.375

 
$
1.22



See Notes to Consolidated Financial Statements.

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SPECTRA ENERGY CORP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions)
 
 
Years Ended December 31,
 
2015
 
2014
 
2013
Net Income
$
460

 
$
1,283

 
$
1,159

Other comprehensive income (loss):
 
 
 
 
 
Foreign currency translation adjustments
(950
)
 
(548
)
 
(494
)
Non-cash mark-to-market net gain on hedges

 
4

 
7

Reclassification of cash flow hedges into earnings

 
5

 
7

Pension and benefits impact (net of tax benefit (expense) of $1, $14 and $(88), respectively)
5

 
(47
)
 
203

Other
1

 

 
2

Total other comprehensive income (loss)
(944
)
 
(586
)
 
(275
)
Total Comprehensive Income (Loss), net of tax
(484
)
 
697

 
884

Less: Comprehensive Income—Noncontrolling Interests
251

 
194

 
114

Comprehensive Income (Loss)—Controlling Interests
$
(735
)
 
$
503

 
$
770



See Notes to Consolidated Financial Statements.

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SPECTRA ENERGY CORP
CONSOLIDATED BALANCE SHEETS
(In millions)
 
December 31,
 
2015
 
2014
ASSETS
 
 
 
 
 
 
 
Current Assets
 
 
 
Cash and cash equivalents
$
213

 
$
215

Receivables (net of allowance for doubtful accounts of $11 at
December 31, 2015 and 2014)
806

 
1,336

Inventory
307

 
313

Fuel tracker
41

 
102

Other
281

 
366

Total current assets
1,648

 
2,332

 
 
 
 
Investments and Other Assets
 
 
 
Investments in and loans to unconsolidated affiliates
2,592

 
2,966

Goodwill
4,154

 
4,714

Other
310

 
327

Total investments and other assets
7,056

 
8,007

 
 
 
 
Property, Plant and Equipment
 
 
 
Cost
29,843

 
29,211

Less accumulated depreciation and amortization
6,925

 
6,904

Net property, plant and equipment
22,918

 
22,307

 
 
 
 
Regulatory Assets and Deferred Debits
1,301

 
1,352

 
 
 
 
Total Assets
$
32,923

 
$
33,998


See Notes to Consolidated Financial Statements.

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SPECTRA ENERGY CORP
CONSOLIDATED BALANCE SHEETS
(In millions, except per-share amounts)
 
 
December 31,
 
2015
 
2014
LIABILITIES AND EQUITY
 
 
 
 
 
 
 
Current Liabilities
 
 
 
Accounts payable
$
511

 
$
458

Commercial paper
1,112

 
1,583

Taxes accrued
78

 
91

Interest accrued
179

 
181

Current maturities of long-term debt
652

 
327

Other
860

 
1,169

Total current liabilities
3,392

 
3,809

 
 
 
 
Long-term Debt
12,892

 
12,727

 
 
 
 
Deferred Credits and Other Liabilities
 
 
 
Deferred income taxes
5,445

 
5,405

Regulatory and other
1,323

 
1,401

Total deferred credits and other liabilities
6,768

 
6,806

 
 
 
 
Commitments and Contingencies

 

 
 
 
 
Preferred Stock of Subsidiaries
339

 
258

 
 
 
 
Equity
 
 
 
Preferred stock, $0.001 par, 22 million shares authorized, no shares outstanding

 

Common stock, $0.001 par, 1 billion shares authorized, 671 million shares
outstanding at December 31, 2015 and 2014
1

 
1

Additional paid-in capital
5,053

 
4,956

Retained earnings
1,741

 
2,541

Accumulated other comprehensive (loss) income
(269
)
 
662

Total controlling interests
6,526

 
8,160

Noncontrolling interests
3,006

 
2,238

Total equity
9,532

 
10,398

 
 
 
 
Total Liabilities and Equity
$
32,923

 
$
33,998



See Notes to Consolidated Financial Statements.

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SPECTRA ENERGY CORP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
 
Years Ended December 31,
 
2015
 
2014
 
2013
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
 
 
Net income
$
460

 
$
1,283

 
$
1,159

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
Depreciation and amortization
778

 
809

 
787

Impairment charges
349

 

 

Deferred income tax expense
88

 
388

 
421

(Earnings) loss from equity investments
290

 
(361
)
 
(445
)
Distributions from equity investments
161

 
380

 
324

Decrease (increase) in
 
 
 
 
 
Receivables
141

 
(9
)
 
(94
)
Inventory
(40
)
 
(106
)
 
17

Other current assets
43

 
(143
)
 
(88
)
Increase (decrease) in
 
 
 
 
 
Accounts payable
26

 
25

 
(2
)
Taxes accrued
23

 
28

 
(8
)
Other current liabilities
(15
)
 
3

 
101

Other, assets
(106
)
 
(33
)
 
(111
)
Other, liabilities
49

 
(43
)
 
(31
)
Net cash provided by operating activities
2,247

 
2,221

 
2,030

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
 
 
Capital expenditures
(2,848
)
 
(2,028
)
 
(1,947
)
Investments in and loans to unconsolidated affiliates
(124
)
 
(259
)
 
(312
)
Acquisitions, net of cash acquired

 

 
(1,254
)
Purchases of held-to-maturity securities
(668
)
 
(790
)
 
(985
)
Proceeds from sales and maturities of held-to-maturity securities
695

 
815

 
1,023

Purchases of available-for-sale securities
(95
)
 
(13
)
 
(5,878
)
Proceeds from sales and maturities of available-for-sale securities
87

 
7

 
6,024

Distributions from equity investments
451

 
266

 
87

Distribution to equity investment
(248
)
 

 
(71
)
Repayment of loan to equity investment

 

 
71

Other changes in restricted funds
(33
)
 
(1
)
 
2

Other
1

 

 
4

Net cash used in investing activities
(2,782
)
 
(2,003
)
 
(3,236
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
 
 
Proceeds from the issuance of long-term debt
1,585

 
1,028

 
4,372

Payments for the redemption of long-term debt
(285
)
 
(1,184
)
 
(2,139
)
Net increase (decrease) in commercial paper
(439
)
 
574

 
(206
)
Distributions to noncontrolling interests
(198
)
 
(175
)
 
(144
)
Contributions from noncontrolling interests
248

 
145

 
23

Proceeds from the issuance of Spectra Energy Partners, LP common units
546

 
327

 
214

Proceeds from the issuance of Westcoast Energy, Inc. preferred stock
84

 

 

Dividends paid on common stock
(996
)
 
(925
)
 
(821
)
Other
(5
)
 
11

 
17

Net cash provided by (used in) financing activities
540

 
(199
)
 
1,316

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

 
107

Cash and cash equivalents at beginning of period
215

 
201

 
94

Cash and cash equivalents at end of period
$
213

 
$
215

 
$
201

Supplemental Disclosures
 
 
 
 
 
Cash paid for interest, net of amount capitalized
$
623

 
$
684

 
$
625

Net cash paid (refunds received) for income taxes
29

 
(8
)
 
43

Property, plant and equipment non-cash accruals
192

 
125

 
112


See Notes to Consolidated Financial Statements.

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SPECTRA ENERGY CORP
CONSOLIDATED STATEMENTS OF EQUITY
(In millions)
 
Common
Stock
 
Additional
Paid-in
Capital
 
Retained
Earnings
 
Accumulated Other
Comprehensive Income (Loss)
 
Noncontrolling
Interests
 
Total
 
Foreign
Currency
Translation
Adjustments
 
Other
 
December 31, 2012
$
1

 
$
5,297

 
$
2,165

 
$
2,044

 
$
(535
)
 
$
871

 
$
9,843

Net income

 

 
1,038

 

 

 
121

 
1,159

Other comprehensive income (loss)

 

 

 
(487
)
 
219

 
(7
)
 
(275
)
Dividends on common stock

 

 
(820
)
 

 

 

 
(820
)
Stock-based compensation

 
19

 

 

 

 

 
19

Distributions to noncontrolling interests

 

 

 

 

 
(144
)
 
(144
)
Contributions from noncontrolling interests

 

 

 

 

 
23

 
23

Spectra Energy common stock issued

 
23

 

 

 

 

 
23

Spectra Energy Partners, LP common units issued

 
42

 

 

 

 
147

 
189

Transfer of interests in subsidiaries to Spectra Energy Partners, LP

 
(511
)
 

 

 

 
817

 
306

Other, net

 
(1
)
 

 

 

 
1

 

December 31, 2013
1

 
4,869

 
2,383

 
1,557

 
(316
)
 
1,829

 
10,323

Net income

 

 
1,082

 

 

 
201

 
1,283

Other comprehensive loss

 

 

 
(541
)
 
(38
)
 
(7
)
 
(586
)
Dividends on common stock

 

 
(924
)
 

 

 

 
(924
)
Stock-based compensation

 
19

 

 

 

 

 
19

Distributions to noncontrolling interests

 

 

 

 

 
(175
)
 
(175
)
Contributions from noncontrolling interests

 

 

 

 

 
145

 
145

Spectra Energy common stock issued

 
11

 

 

 

 

 
11

Spectra Energy Partners, LP common units issued

 
49

 

 

 

 
248

 
297

Transfer of interests in subsidiaries to Spectra Energy Partners, LP

 
3

 

 

 

 
(1
)
 
2

Other, net

 
5

 

 

 

 
(2
)
 
3

December 31, 2014
1

 
4,956

 
2,541

 
1,016

 
(354
)
 
2,238

 
10,398

Net income

 

 
196

 

 

 
264

 
460

Other comprehensive income (loss)

 

 

 
(937
)
 
6

 
(13
)
 
(944
)
Dividends on common stock

 

 
(996
)
 

 

 

 
(996
)
Stock-based compensation

 
21

 

 

 

 

 
21

Distributions to noncontrolling interests

 

 

 

 

 
(200
)
 
(200
)
Contributions from noncontrolling interests

 

 

 

 

 
248

 
248

Spectra Energy common stock issued

 
3

 

 

 

 

 
3

Spectra Energy Partners, LP common units issued/retired

 
(105
)
 

 

 

 
635

 
530

Transfer of interests in subsidiaries

 
166

 

 

 

 
(166
)
 

Other, net

 
12

 

 

 

 

 
12

December 31, 2015
$
1

 
$
5,053

 
$
1,741

 
$
79

 
$
(348
)
 
$
3,006

 
$
9,532


See Notes to Consolidated Financial Statements.

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SPECTRA ENERGY CORP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
INDEX
 
 
 
Page
1. Summary of Operations and Significant Accounting Policies
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.
Nature of Operations. 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 owns 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. We currently operate in three key areas of the natural gas industry: gathering and processing, transmission and storage, and distribution. We provide transmission and storage of natural gas to customers in various regions of the northeastern and southeastern U.S., the Maritime Provinces in Canada, the Pacific Northwest in the U.S. and Canada, and in the province of Ontario, Canada. We also provide natural gas sales and distribution services to retail customers in Ontario, and natural gas gathering and processing services to customers in western Canada. We also own a 50% interest in DCP Midstream, LLC (DCP Midstream), based in Denver, Colorado, one of the leading natural gas gatherers in the U.S. and one of the largest U.S. producers and marketers of natural gas liquids (NGLs).
Basis of Presentation. The accompanying Consolidated Financial Statements include our accounts and the accounts of our majority-owned subsidiaries, after eliminating intercompany transactions and balances.

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Use of Estimates. To conform with generally accepted accounting principles (GAAP) in the U.S., we make estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and Notes to Consolidated Financial Statements. Although these estimates are based on our best available knowledge at the time, actual results could differ.
Fair Value Measurements. We measure the fair value of financial assets and liabilities by maximizing the use of observable inputs and minimizing the use of unobservable inputs. Fair value is the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date.
Cost-Based Regulation. The economic effects of regulation can result in a regulated company recording assets for costs that have been or are expected to be approved for recovery from customers or recording liabilities for amounts that are expected to be returned to customers or for instances where the regulator provides current rates that are intended to recover costs that are expected to be incurred in the future. Accordingly, we record assets and liabilities that result from the regulated ratemaking process that may not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders to other regulated entities. Based on this assessment, we believe our existing regulatory assets are probable of recovery. These regulatory assets and liabilities are mostly classified in the Consolidated Balance Sheets as Regulatory Assets and Deferred Debits, and Deferred Credits and Other Liabilities—Regulatory and Other. We evaluate our regulated assets, and consider factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, we may have to reduce our asset balances to reflect a market basis less than cost and write-off the associated regulatory assets and liabilities. See Note 5 for further discussion.
Foreign Currency Translation. The Canadian dollar has been determined to be the functional currency of our Canadian operations based on an assessment of the economic circumstances of those operations. Assets and liabilities of our Canadian operations are translated into U.S. dollars at current exchange rates. Translation adjustments resulting from fluctuations in exchange rates are included as a separate component of Other Comprehensive Income on the Consolidated Statements of Comprehensive Income. Revenue and expense accounts of these operations are translated at average monthly exchange rates prevailing during the periods. Gains and losses arising from transactions denominated in currencies other than the functional currency are included in the results of operations of the period in which they occur. Foreign currency transaction losses totaled $6 million in 2015, and gains totaled $3 million in 2014 and $1 million in 2013, and are included in Other Income and Expenses, Net on the Consolidated Statements of Operations. Deferred U.S. taxes related to translation gains and losses have not been provided on those Canadian operations where we expect the earnings to be indefinitely reinvested.
Revenue Recognition. Revenues from the transmission, storage, processing, distribution and sales of natural gas, from the sales of NGLs and from the transportation and storage of crude oil are generally 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. There were no customers accounting for 10% or more of consolidated revenues during 2015, 2014 or 2013. We also have certain customer contracts with billed amounts that decline annually over the terms of the contracts. Differences between the amounts billed and recognized are deferred on the Consolidated Balance Sheets.
Stock-Based Compensation. For employee awards, equity-classified and liability-classified stock-based compensation cost is measured at the grant date based on the fair value of the award. Liability-classified stock-based compensation cost is remeasured at each reporting period until settlement. Related compensation expense is recognized over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award vests, the date the employee becomes retirement-eligible or the date the market or performance condition of the award is met. Awards, including stock options, granted to employees that are retirement-eligible are deemed to have vested immediately upon issuance, and therefore, compensation cost for those awards is recognized on the date such awards are granted. See Note 22 for further discussion.
Pension and Other Post-Retirement Benefits. We fully recognize the overfunded or underfunded status of our consolidating subsidiaries’ pension and other post-retirement benefit plans as Investments and Other Assets—Other, Current Liabilities—Other or Deferred Credits and Other Liabilities—Regulatory and Other in the Consolidated Balance Sheets, as appropriate. A plan’s funded status is the difference between the fair value of plan assets and the plan’s projected benefit obligation. We record deferred plan costs and income (unrecognized losses and gains, and unrecognized prior service costs and credits) in Accumulated Other Comprehensive Income (AOCI) on the Consolidated Statements of Equity, until they are amortized and recognized as a component of benefit expense within Operating, Maintenance and Other in the Consolidated Statements of Operations. See Note 23 for further discussion.

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Allowance for Funds Used During Construction (AFUDC). AFUDC, which represents the estimated debt and equity costs of capital funds necessary to finance the construction of certain new regulated facilities, consists of two components, an equity component and an interest expense component. The equity component is a non-cash item. After construction is completed, we are permitted to recover these costs through inclusion in the rate base and in the depreciation provision. AFUDC is capitalized as a component of Property, Plant and Equipment—Cost in the Consolidated Balance Sheets, with offsetting credits to the Consolidated Statements of Operations through Other Income and Expenses, Net for the equity component and Interest Expense for the interest expense component. The total amount of AFUDC included in the Consolidated Statements of Operations was $143 million in 2015 (an equity component of $111 million and an interest expense component of $32 million), $72 million in 2014 (an equity component of $53 million and an interest expense component of $19 million) and $155 million in 2013 (an equity component of $105 million and an interest expense component of $50 million).
Income Taxes. Deferred income taxes are recognized for differences between the financial reporting and tax bases of assets and liabilities at enacted statutory tax rates in effect for the years in which the differences are expected to reverse. The effect on deferred taxes of a change in tax rates is recognized in income in the period that includes the enactment date. Actual income taxes could vary from these estimates due to future changes in income tax law or results from the final review of tax returns by federal, state or foreign tax authorities.
Financial statement effects on tax positions are recognized in the period in which it is more likely than not that the position will be sustained upon examination, the position is effectively settled or when the statute of limitations to challenge the position has expired. Interest and penalties related to unrecognized tax benefits are recorded as interest expense and other expense, respectively.
Cash and Cash Equivalents. Highly liquid investments with original maturities of three months or less at the date of acquisition are considered cash equivalents, except for the investments that were pledged as collateral against long-term debt as discussed in Note 15 and any investments that are considered restricted funds.
Inventory. Inventory consists of natural gas and NGLs held in storage for transmission and processing, and also includes materials and supplies. Natural gas inventories primarily relate to the Distribution segment in Canada and are valued at costs approved by the regulator, the Ontario Energy Board (OEB). The difference between the approved price and the actual cost of gas purchased is recorded in either Fuel Tracker or Other Current Liabilities, as appropriate, for future disposition with customers, subject to approval by the OEB. The remaining inventory is recorded at the lower of cost or market, primarily using average cost.
Natural Gas Imbalances. The Consolidated Balance Sheets include in-kind balances as a result of differences in gas volumes received and delivered for customers. Since settlement of certain imbalances is in-kind, changes in their balances do not have an effect on our Consolidated Statements of Cash Flows. Receivables include $291 million and $642 million as of December 31, 2015 and December 31, 2014, respectively, and Other Current Liabilities include $287 million and $634 million as of December 31, 2015 and December 31, 2014, respectively, related to gas imbalances. Most natural gas volumes owed to or by us are valued at natural gas market index prices as of the balance sheet dates.
Risk Management and Hedging Activities and Financial Instruments. Currently, our use of derivative instruments is primarily limited to interest rate positions and commodity pricing. All derivative instruments that do not qualify for the normal purchases and normal sales exception are recorded on the Consolidated Balance Sheets at fair value. Cash inflows and outflows related to derivative instruments are a component of Cash Flows From Operating Activities in the accompanying Consolidated Statements of Cash Flows.
Cash Flow and Fair Value Hedges. Qualifying energy commodity and other derivatives may be designated as either a hedge of a forecasted transaction (cash flow hedge) or a hedge of a recognized asset, liability or firm commitment (fair value hedge). For all hedge contracts, we prepare documentation of the hedge in accordance with accounting standards and assess whether the hedge contract is highly effective using regression analysis, both at inception and on a quarterly basis, in offsetting changes in cash flows or fair values of hedged items. We document hedging activity by instrument type (futures or swaps) and risk management strategy (commodity price risk or interest rate risk).
For derivatives designated as fair value hedges, we recognize the gain or loss on the derivative instrument, as well as the offsetting gain or loss on the hedged item in earnings, to the extent effective, in the current period. In the event the hedge is not effective, there is no offsetting gain or loss recognized in earnings for the hedged item. All derivatives designated and accounted for as hedges are classified in the same category as the item being hedged in the Consolidated Statements of Cash Flows. All components of each derivative gain or loss are included in the assessment of hedge effectiveness.
Investments. We may actively invest a portion of our available cash and restricted funds balances in various financial instruments, including taxable or tax-exempt debt securities. In addition, we invest in short-term money market securities, some

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of which are restricted due to debt collateral or insurance requirements. Investments in available-for-sale (AFS) securities are carried at fair value and investments in held-to-maturity (HTM) securities are carried at cost. Investments in money market securities are also accounted for at fair value. Realized gains and losses, and dividend and interest income related to these securities, including any amortization of discounts or premiums arising at acquisition, are included in earnings. The costs of securities sold are determined using the specific identification method. Purchases and sales of AFS and HTM securities are presented on a gross basis within Cash Flows From Investing Activities in the accompanying Consolidated Statements of Cash Flows.
Goodwill. We perform our goodwill impairment test annually and evaluate goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. In 2015 we recorded a goodwill impairment charge of $270 million for British Columbia (BC) Field Services and $63 million for Empress NGL operations associated with the Westcoast Energy, Inc. (Westcoast) acquisition in 2002. No impairments of goodwill were recorded in 2014 or 2013. See Note 11 for further discussion.
We perform our annual review for goodwill impairment at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete financial information is available, whether segment management regularly reviews the operating results of those components and whether the economic and regulatory characteristics are similar. We determined that our reporting units are equivalent to our reportable segments, except for the reporting units of our Western Canada Transmission & Processing and Spectra Energy Partners reportable segments, which are one level below.
As permitted under accounting guidance on testing goodwill for impairment, we perform either a qualitative assessment or a quantitative assessment of each of our reporting units based on management’s judgment. With respect to our qualitative assessments, we consider events and circumstances specific to us, such as macroeconomic conditions, industry and market considerations, cost factors and overall financial performance, when evaluating whether it is more likely than not that the fair values of our reporting units are less than their respective carrying amounts.
In connection with our quantitative assessments, we primarily use a discounted cash flow analysis to determine the fair values of those reporting units. Key assumptions in the determination of fair value included the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in key markets served by our operations, regulatory stability, the ability to renew contracts, commodity prices (where appropriate) and foreign currency exchange rates, as well as other factors that affect our reporting units’ revenue, expense and capital expenditure projections. If the carrying amount of the reporting unit exceeds its fair value, a comparison of the fair value and carrying value of the goodwill of that reporting unit needs to be performed. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess. Additional impairment tests are performed between the annual reviews if events or changes in circumstances make it more likely than not that the fair value of a reporting unit is below its carrying amount.
Property, Plant and Equipment. Property, plant and equipment is stated at historical cost less accumulated depreciation. We capitalize all construction-related direct labor and material costs, as well as indirect construction costs. Indirect costs include general engineering, taxes and the cost of funds used during construction. The costs of renewals and betterments that extend the useful life or increase the expected output of property, plant and equipment are also capitalized. The costs of repairs, replacements and major maintenance projects that do not extend the useful life or increase the expected output of property, plant and equipment are expensed as incurred. Depreciation is generally computed over the asset’s estimated useful life using the straight-line method.
When we retire regulated property, plant and equipment, we charge the original cost plus the cost of retirement, less salvage value, to accumulated depreciation and amortization. When we sell entire regulated operating units or retire non-regulated properties, the cost is removed from the property account and the related accumulated depreciation and amortization accounts are reduced. Any gain or loss is recorded in earnings, unless otherwise required by the applicable regulatory body.
Preliminary Project Costs. Project development costs, including expenditures for preliminary surveys, plans, investigations, environmental studies, regulatory applications and other costs incurred for the purpose of determining the feasibility of capital expansion projects, are capitalized for rate-regulated enterprises when it is determined that recovery of such costs through regulated revenues of the completed project is probable. Any inception-to-date costs of the project that were initially expensed are reversed and capitalized as Property, Plant and Equipment.
Long-Lived Asset Impairments. We evaluate whether long-lived assets, excluding goodwill, have been impaired when circumstances indicate the carrying value of those assets may not be recoverable. For such long-lived assets, an impairment exists when its carrying value exceeds the sum of estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are

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under consideration, a probability-weighted approach is used in developing estimates of future undiscounted cash flows. If the carrying value of the long-lived asset is not recoverable based on these estimated future undiscounted cash flows, an impairment loss is measured as the excess of the asset’s carrying value over its fair value, such that the asset’s carrying value is adjusted to its estimated fair value.
We assess the fair value of long-lived assets using commonly accepted techniques and may use more than one source. Sources to determine fair value include, but are not limited to, recent third-party comparable sales, internally developed discounted cash flow analyses and analyses from outside advisors. Significant changes in market conditions resulting from events such as changes in natural gas available to our systems, the condition of an asset, a change in our intent to utilize the asset or a significant change in contracted revenues or regulatory recoveries would generally require us to reassess the cash flows related to the long-lived assets.
Asset Retirement Obligations. We recognize asset retirement obligations (AROs) for legal commitments associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made and is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset.
Unamortized Debt Premium, Discount and Expense. Premiums, discounts and expenses incurred with the issuance of outstanding long-term debt are amortized over the terms of the debt issues. Any call premiums or unamortized expenses associated with refinancing higher-cost debt obligations to finance regulated assets and operations are amortized consistent with regulatory treatment of those items, where appropriate.
Environmental Expenditures. We expense environmental expenditures related to conditions caused by past operations that do not generate current or future revenues. Environmental expenditures related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Undiscounted liabilities are recorded when the necessity for environmental remediation becomes probable and the costs can be reasonably estimated, or when other potential environmental liabilities are reasonably estimable and probable.
Captive Insurance Reserves. We have captive insurance subsidiaries which provide insurance coverage to our consolidated subsidiaries as well as certain equity affiliates, on a limited basis, for various business risks and losses, such as workers compensation, property, business interruption and general liability. Liabilities include provisions for estimated losses incurred but not yet reported, as well as provisions for known claims which have been estimated on a claims-incurred basis. Incurred but not yet reported reserve estimates involve the use of assumptions and are based upon historical loss experience, industry data and other actuarial assumptions. Reserve estimates are adjusted in future periods as actual losses differ from historical experience.
Guarantees. Upon issuance or material modification of a guarantee made by us, we recognize a liability for the estimated fair value of the obligation we assume under that guarantee, if any. Fair value is estimated using a probability-weighted approach. We reduce the obligation over the term of the guarantee or related contract in a systematic and rational method as risk is reduced under the obligation.
Accounting For Sales of Stock by a Subsidiary. Sales of stock by a consolidated subsidiary are accounted for as equity transactions in those instances where a change in control does not take place.
Segment Reporting. Operating segments are components of an enterprise for which separate financial information is available and evaluated regularly by the chief operating decision maker (CODM) in deciding how to allocate resources and evaluate performance. Two or more operating segments may be aggregated into a single reportable segment provided certain criteria are met. There is no such aggregation within our defined business segments. A description of our reportable segments, consistent with how business results are reported internally to management, and the disclosure of segment information is presented in Note 4.
Consolidated Statements of Cash Flows. Cash flows from discontinued operations are combined with cash flows from continuing operations within operating, investing and financing cash flows. Cash received from insurance proceeds are classified depending on the activity that resulted in the insurance proceeds. For example, business interruption insurance proceeds are included as a component of operating activities while insurance proceeds from damaged property are included as a component of investing activities. With respect to cash overdrafts, book overdrafts are included within operating cash flows while bank overdrafts, if any, are included within financing cash flows.

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Distributions from Equity Investments. We consider distributions received from equity investments which do not exceed cumulative equity in earnings subsequent to the date of investment to be a return on investment and classify these amounts as Cash Flows From Operating Activities within the accompanying Consolidated Statements of Cash Flows. Cumulative distributions received in excess of cumulative equity in earnings subsequent to the date of investment are considered to be a return of investment and are classified as Cash Flows From Investing Activities.
New Accounting Pronouncements. The following new Accounting Standards Updates (ASUs) were adopted during 2015 and the effect of such adoption has been presented in the accompanying Consolidated Financial Statements:
In April 2014, the Financial Accounting Standards Board (FASB) issued ASU No. 2014-08, “Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.” This ASU revises the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have or will have a major effect on an entity’s operations and financial results, removing the lack of continuing involvement criteria and requiring discontinued operations reporting for the disposal of an equity method investment that meets the definition of discontinued operations. The update also requires expanded disclosures for discontinued operations, and disclosure of pretax profit or loss of certain individually significant components of an entity that do not qualify for discontinued operations reporting. This ASU was effective for us on January 1, 2015 and did not have a material impact on our consolidated results of operations, financial position or cash flows.
In April 2015, the FASB issued ASU No. 2015-03, “Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,” which requires that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, rather than as a deferred charge asset. We adopted this standard on December 31, 2015. The adoption of this ASU resulted in the retrospective adjustment of the December 31, 2014 Consolidated Balance Sheet, which resulted in the presentation of $42 million of debt issuance costs previously reported in Regulatory Assets and Deferred Debits as a reduction of Long-term Debt on our Consolidated Balance Sheet. In addition, $46 million of debt issuance costs are presented as a reduction of Long-term Debt on our December 31, 2015 Consolidated Balance Sheet.
In November 2015, the FASB issued ASU No. 2015-17, “Accounting for Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes.” This ASU simplifies the balance sheet presentation of deferred income taxes by requiring deferred tax liabilities and assets be classified as noncurrent in a classified balance sheet. We adopted this standard on December 31, 2015 and applied it prospectively. The adoption of this ASU did not have a material impact on our consolidated results of operations, financial position, or cash flow.
Pending. The following new accounting pronouncements have been issued but not yet adopted:
In February 2015, the FASB issued ASU No. 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis,” which makes changes to both the variable interest model and the voting model. These changes will require re-evaluation of certain entities for consolidation and will require us to revise our documentation regarding the consolidation or deconsolidation of such entities. This ASU is effective for us on January 1, 2016 and is not expected to have a material impact on our consolidated results of operations, financial position or cash flow.
In July 2015, the FASB issued ASU No. 2015-11, “Inventory (Topic 330): Simplifying the Measurement of Inventory,” which simplifies the subsequent measurement of inventory by requiring inventory to be measured at the lower of cost and net realizable value. This ASU is effective for us January 1, 2016 and is not expected to have a material impact on our consolidated results of operations, financial position or cash flow.
In July 2015, the FASB decided to defer the effective date of the revenue standard ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” for one year and to permit entities to early adopt the standard as of the original effective date. ASU No. 2014-09 supersedes the revenue recognition requirements of “Revenue Recognition (Topic 605)” and clarifies the principles of recognizing revenue. This ASU is effective for us January 1, 2018. We are currently evaluating this ASU and its potential impact on us.
In September 2015, the FASB issued ASU No. 2015-16, “Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments,” to simplify accounting for adjustments made to provisional amounts recognized in a business combination and to eliminate the retrospective accounting for those adjustments. This ASU is effective for us January 1, 2016 and is not expected to have a material impact on our consolidated results of operations, financial position or cash flow.
In January 2016, the FASB issued ASU 2016-01, "Financial Instruments--Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities," which amends the classification and measurement of financial

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instruments. Changes primarily affect the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. This ASU is effective for us beginning after December 15, 2017. Early adoption is not permitted. We are currently evaluating this ASU and its potential impact on us.
2014. There were no significant accounting pronouncements issued during 2014 that had a material impact on our consolidated results of operations, financial position or cash flows.
2013. There were no significant accounting pronouncements issued during 2013 that had a material impact on our consolidated results of operations, financial position or cash flows.
2. Spectra Energy Partners, LP
SEP is our natural gas infrastructure and crude oil pipeline master limited partnership. As of December 31, 2015, Spectra Energy owned 78% of SEP, including a 2% general partner interest.
Sand Hills and Southern Hills. On October 30, 2015, Spectra Energy acquired SEP’s 33.3% ownership interests in DCP Sand Hills Pipeline, LLC (Sand Hills) and DCP Southern Hills Pipeline, LLC (Southern Hills). In consideration for this transaction, SEP retired 21,560,000 of our limited partner units and 440,000 of our general partner units in SEP. This will result in the reduction of any associated distribution payable to Spectra Energy, beginning in 2016. There will also be a reduction in the aggregate quarterly distributions, if any, to Spectra Energy (as holder of incentive distribution rights), by $4 million per quarter for a period of 12 consecutive quarters, which commenced with the quarter ending on December 31, 2015 and will end with the quarter ending on September 30, 2018.
U.S. Assets Dropdown. In 2013, Spectra Energy entered into a contribution agreement with SEP (the Contribution Agreement), pursuant to which Spectra Energy agreed to contribute to SEP substantially all of Spectra Energy’s interests in its subsidiaries that own U.S. transmission and storage and liquids assets, including its remaining 60% interest in the U.S. portion of Express-Platte, and to assign to SEP its interests in certain related contracts (collectively, the U.S. Assets Dropdown).
In 2013, Spectra Energy completed the closing of substantially all of the U.S. Assets Dropdown. This first of three planned transactions consisted of all the contributed entities contemplated in the Contribution Agreement, excluding a 25.05% ownership interest in Southeast Supply Header, LLC (SESH) and a 1% ownership interest in Steckman Ridge, LP (Steckman Ridge). Consideration to Spectra Energy for the 2013 closing included $2.3 billion in cash, assumption by SEP (indirectly by acquisition of the contributed entities) of approximately $2.4 billion of third-party indebtedness of the contributed entities, 167.6 million newly issued SEP limited partner units and 3.4 million newly issued general partner units. This transfer of assets between entities under common control resulted in a decrease to Additional Paid-in Capital of $733 million ($458 million net of tax) and an increase to Equity—Noncontrolling Interests of $733 million on the Consolidated Balance Sheet in 2013. The change in Equity—Noncontrolling Interests primarily represents the public unitholders’ share of the increase in SEP’s equity as a result of the issuance of additional units to Spectra Energy, less the effects of the resulting decrease in the public unitholders’ ownership percentage of SEP. Spectra Energy’s ownership in SEP increased as a result of the transaction.
In November 2014, Spectra Energy completed the second of three planned transactions related to the U.S Assets Dropdown. This transaction consisted of contributing an additional 24.95% ownership interest in SESH and the remaining 1% interest in Steckman Ridge to SEP. Consideration to Spectra Energy was approximately 4.3 million newly issued SEP common units. Also, in connection with this transaction, SEP issued approximately 86,000 of newly issued general partner units to Spectra Energy in exchange for the same amount of common units in order to maintain Spectra Energy’s 2% general partner interest in SEP. This transfer of assets between entities under common control resulted in a decrease to Additional Paid-in Capital of $29 million ($16 million net of tax) and an increase to Equity—Noncontrolling Interests of $29 million on the Consolidated Balance Sheet in 2014. The change in Equity—Noncontrolling Interests primarily represents the public unitholders’ share of the increase in SEP’s equity as a result of the issuance of additional units to Spectra Energy, less the effects of the resulting decrease in the public unitholders’ ownership percentage of SEP. Spectra Energy’s ownership in SEP increased as a result of the transaction.
On November 4, 2015, the third, and final, transaction related to the U.S. Assets Dropdown occurred. Spectra Energy contributed the remaining 0.1% interest in SESH to SEP. Total consideration to Spectra Energy was 17,114 newly issued SEP common units. Also, in connection with this third transaction, SEP issued 342 general partner units to Spectra Energy in exchange for the same amount of common units in order to maintain Spectra Energy's 2% general partner interest in SEP.

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The contributed assets provide transportation and storage of natural gas, crude oil, and natural gas liquids for customers in various regions of the U.S. and in Alberta, Canada. The contributed assets included after all stages of the U.S. Assets Dropdown consisted of:

a 100% ownership interest in Texas Eastern Transmission, LP (Texas Eastern)
a 100% ownership interest in Algonquin Gas Transmission, LLC (Algonquin)
Spectra Energy’s remaining 60% ownership interest in the U.S. portion of Express-Platte
Spectra Energy’s remaining 38.77% ownership interest in Maritimes & Northeast Pipeline, L.L.C.
a 33.3% ownership interest in Sand Hills
a 33.3% ownership interest in Southern Hills
Spectra Energy’s remaining 1% ownership interest in Gulfstream Natural Gas System, LLC (Gulfstream)
a 50% ownership interest in SESH
a 100% ownership interest in Bobcat Gas Storage
Spectra Energy’s remaining 50% of Market Hub Partners Holding
a 50% ownership interest in Steckman Ridge
Texas Eastern’s and Express-Platte’s storage facilities
Express-Platte. In August 2013, Spectra Energy contributed a 40% interest in the U.S. portion of Express-Platte and sold a 100% ownership interest in the Canadian portion to SEP. Aggregate consideration for the transactions consisted of $410 million in cash and 7.2 million of newly issued SEP partnership units. This transfer of assets between entities, under common control, resulted in a decrease to Additional Paid-in Capital of $84 million ($53 million net of tax) and an increase to Equity—Noncontrolling Interest of $84 million. The change in Equity—Noncontrolling Interests primarily represents the public unitholders’ share of the increase in SEP equity as a result of the issuance of additional units to Spectra Energy, less the effects of the resulting decrease in the public unitholders’ ownership percentage.
Sales of SEP Common Units. SEP has entered into equity distribution agreements for its at-the-market offering program, pursuant to which SEP may offer and sell, through sales agents, common units representing limited partner interests at prices it deems appropriate having aggregate offering prices ranging from $400 million to up to $1 billion. Sales of common units, if any, will be made by means of ordinary brokers’ transactions on the New York Stock Exchange, in block transactions, or as otherwise agreed to between SEP and the sales agent. SEP intends to use the net proceeds from sales under the program for general partnership purposes, which may include debt repayment, future acquisitions and capital expenditures. Under this program SEP issued 12.0 million, 6.4 million and 0.6 million common units to the public in 2015, 2014 and 2013, respectively, for total net proceeds of $546 million, $327 million and $24 million, respectively. In 2015 and 2014, SEP also issued 245,000 and 132,000 general partner units, respectively, to Spectra Energy.
In 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 U.S. Assets Dropdown, at which time the funds were used to pay for a portion of the dropdown transaction. In connection with the sale of the units, a $61 million gain ($38 million net of tax) to Additional Paid-in Capital and a $128 million increase in Equity—Noncontrolling Interests were recorded in 2013.
3. Acquisitions and Dispositions
Acquisitions. We consolidate assets and liabilities from acquisitions as of the purchase date and include earnings from acquisitions in consolidated earnings after the purchase date. Assets acquired and liabilities assumed are recorded at estimated fair values on the date of acquisition. The purchase price less the estimated fair value of the acquired assets and liabilities meeting the definition of a “business” is recorded as goodwill. The allocation of the purchase price may be adjusted if additional information is received during the allocation period, which generally does not exceed one year from the consummation date.
Sand Hills and Southern Hills. On October 30, 2015 Spectra Energy acquired SEP’s 33.3% ownership interests in Sand Hills and Southern Hills. In consideration for this transaction, SEP retired 21,560,000 of our limited partner units and 440,000 of our general partner units in SEP. See Note 2 for further discussion. This transfer of assets between entities under common control resulted in an increase to Additional Paid-in Capital of $166 million and a decrease to Equity-Noncontrolling Interests of $166 million on the Consolidated Balance Sheet in 2015. The change in Equity-Noncontrolling Interests primarily represents the public unitholders’ share of the decrease in SEP’s equity as a result of the retirement of units previously held by us, less the effects of the resulting increase in the public unitholders’ ownership percentage of SEP. Spectra Energy’s ownership in SEP decreased as a result of the transaction.

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In 2013, subsidiaries of Spectra Energy contributed their 33.3% direct interests in Sand Hills and Southern Hills to SEP in connection with the U.S. Assets Dropdown. At the time of this contribution, DCP Midstream Partners, LP (DCP Partners), DCP Midstream’s master limited partnership, and Phillips 66 also each owned direct one-third ownership interests in the two pipelines. The Sand Hills pipeline provides NGL transportation from the Permian and Eagle Ford basins to the premium NGL markets on the Gulf Coast. The Southern Hills pipeline provides NGL transportation from the Midcontinent to Mont Belvieu, Texas. See Note 2 for further discussion.
Express-Platte. In March 2013, we acquired 100% of the ownership interests in the Express-Platte crude oil pipeline system for $1.5 billion, consisting of $1.25 billion in cash and $260 million of acquired debt, before working capital adjustments. The Express-Platte pipeline 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 Express pipeline in Casper, Wyoming, transports crude oil predominantly from the Bakken shale and western Canada to refineries in the Midwest. In 2013, subsidiaries of Spectra Energy contributed a 100% interest in the U.S. portion of Express-Platte and sold a 100% ownership interest in the Canadian portion to SEP. See Note 2 for further discussion.
The following table summarizes the fair values of the assets and liabilities acquired as of the date of the acquisition:
 
Purchase Price Allocation
 
(in millions)
Cash purchase price
$
1,250

Working capital and other purchase adjustments
71

Total
1,321

Cash
67

Receivables
25

Other current assets
9

Property, plant and equipment
1,251

Accounts payable
(18
)
Other current liabilities
(17
)
Deferred credits and other liabilities
(259
)
Long-term debt, including current portion
(260
)
Total assets acquired/liabilities assumed
798

Goodwill
$
523

The purchase price is greater than the sum of fair values of the net assets acquired, resulting in goodwill as noted above. The goodwill reflects the value of the strategic location of the pipeline and the opportunity to grow the business. Goodwill related to the acquisition of Express-Platte is not deductible for income tax purposes.
The allocation of the fair values of assets and liabilities acquired related to the acquisition of Express-Platte was finalized in the first quarter of 2014, resulting in the following adjustments to amounts reported as of December 31, 2013: a $60 million decrease in Property, Plant and Equipment, a $1 million decrease in Other Current Assets and a $24 million decrease in Deferred Credits and Other Liabilities, resulting in a $37 million increase in Goodwill.
Dispositions. As discussed above, on October 30, 2015 we acquired SEP’s 33.3% ownership interests in Sand Hills and Southern Hills. We immediately contributed our 33.3% interests in Sand Hills and Southern Hills to DCP Midstream. The contribution is reflected as a non-cash transaction in the statement of cash flows. After this contribution, DCP Midstream and DCP Partners each hold a direct one-third ownership interest in the two pipelines. The remaining one-third direct ownership interest continues to be held by Phillips 66. In consideration for this transaction, we increased our basis in the net equity of DCP Midstream and retained our 50% ownership interest.

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4. Business Segments
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 and employee benefit plan assets and liabilities, 100%-owned captive insurance subsidiaries and other miscellaneous activities.
Our CODM regularly reviews financial information about each of these segments in deciding how to allocate resources and evaluate performance. There is no aggregation within our reportable business segments.
Spectra Energy's presentation of its Spectra Energy Partners segment is reflective of the parent-level focus by our CODM, considering the resource allocation and governance provisions associated with SEP’s master limited partnership structure. SEP maintains a capital and cash management structure that is separate from Spectra Energy’s, is self-funding and maintains its own lines of bank credit and cash management accounts. From a Spectra Energy perspective, our CODM evaluates the Spectra Energy Partners segment as a whole, without regard to any of SEP’s individual businesses.
Spectra Energy Partners provides transmission, storage and gathering of natural gas, as well as the transportation of crude oil and NGLs through interstate pipeline systems for customers in various regions of the midwestern, northeastern and southern U.S. and Canada. The natural gas transmission and storage operations are primarily subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC). The crude oil transportation operations are primarily subject to regulation by the FERC in the U.S. and the National Energy Board (NEB) in Canada. Our Spectra Energy Partners segment is composed of the operations of SEP, less governance costs, which are included in “Other.”
Distribution provides retail natural gas distribution service in Ontario, Canada, as well as natural gas transmission and storage services to other utilities and energy market participants. These services are provided by Union Gas Limited (Union Gas), and are primarily subject to the rules and regulations of the OEB.
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. This segment conducts business mostly through BC Pipeline, BC Field Services, Empress NGL operations, Canadian Midstream, and Maritimes & Northeast Pipeline Limited Partnership (M&N Canada). BC Pipeline, BC Field Services and M&N Canada operations are primarily subject to the rules and regulations of the NEB.
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 gathers raw natural gas through gathering systems connecting 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 the Midcontinent. DCP Partners is a publicly traded master limited partnership, of which DCP Midstream acts as general partner. As of December 31, 2015, DCP Midstream had an approximate 21% ownership interest in DCP Partners, including DCP Midstream’s limited partner and general partner interests.
Our reportable segments offer different products and services and are managed separately as business units. Management evaluates segment performance based on earnings before interest, taxes, depreciation and amortization (EBITDA). Cash, cash equivalents and short-term investments are managed at the parent-company levels, so the associated gains and losses from foreign currency transactions and interest and dividend income are excluded from the segments’ EBITDA. 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. Transactions between reportable segments are accounted for on the same basis as transactions with unaffiliated third parties.

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Business Segment Data
 
Unaffiliated Revenues
 
Intersegment
Revenues
 
Total
Operating
Revenues
 
Segment EBITDA/
Consolidated
Earnings before
Income Taxes
 
Depreciation
and
Amortization
 
Capital and
Investment
Expenditures (a,b)
 

Assets
 
(in millions)
2015
 
 
 
 
 
 
 
 
 
 
 
 
 
Spectra Energy Partners
$
2,455

 
$

 
$
2,455

 
$
1,905

 
$
297

 
$
2,007

 
$
18,983

Distribution
1,527

 

 
1,527

 
473

 
176

 
544

 
5,209

Western Canada Transmission & Processing
1,242

 
43

 
1,285

 
491

 
243

 
360

 
5,909

Field Services

 

 

 
(461
)
 

 

 
1,660

Total reportable segments
5,224

 
43

 
5,267

 
2,408

 
716

 
2,911

 
31,761

Other
10

 
63

 
73

 
(384
)
 
48

 
61

 
1,226

Eliminations

 
(106
)
 
(106
)
 

 

 

 
(64
)
Depreciation and amortization

 

 

 
764

 

 

 

Interest expense

 

 

 
636

 

 

 

Interest income and other (c)

 

 

 
(3
)
 

 

 

Total consolidated
$
5,234

 
$

 
$
5,234

 
$
621

 
$
764

 
$
2,972

 
$
32,923

2014
 
 
 
 
 
 
 
 
 
 
 
 
 
Spectra Energy Partners
$
2,269

 
$

 
$
2,269

 
$
1,669

 
$
290

 
$
1,241

 
$
17,850

Distribution
1,843

 

 
1,843

 
552

 
192

 
427

 
6,055

Western Canada Transmission & Processing
1,781

 
121

 
1,902

 
754

 
271

 
473

 
6,913

Field Services

 

 

 
217

 

 

 
1,345

Total reportable segments
5,893

 
121

 
6,014

 
3,192

 
753

 
2,141

 
32,163

Other
10

 
62

 
72

 
(58
)
 
43

 
146

 
1,893

Eliminations

 
(183
)
 
(183
)
 

 

 

 
(58
)
Depreciation and amortization

 

 

 
796

 

 

 

Interest expense

 

 

 
679

 

 

 

Interest income and other (c)

 

 

 
6

 

 

 

Total consolidated
$
5,903

 
$

 
$
5,903

 
$
1,665

 
$
796

 
$
2,287

 
$
33,998

2013
 
 
 
 
 
 
 
 
 
 
 
 
 
Spectra Energy Partners
$
1,964

 
$
1

 
$
1,965

 
$
1,433

 
$
263

 
$
1,299

 
$
16,783

Distribution
1,848

 

 
1,848

 
574

 
199

 
357

 
6,000

Western Canada Transmission & Processing
1,694

 
73

 
1,767

 
736

 
272

 
561

 
7,157

Field Services

 

 

 
343

 

 

 
1,365

Total reportable segments
5,506

 
74

 
5,580

 
3,086

 
734

 
2,217

 
31,305

Other
12

 
60

 
72

 
(86
)
 
38

 
42

 
2,680

Eliminations

 
(134
)
 
(134
)
 

 

 

 
(499
)
Depreciation and amortization

 

 

 
772

 

 

 

Interest expense

 

 

 
657

 

 

 

Interest income and other (c)

 

 

 
7

 

 

 

Total consolidated
$
5,518

 
$

 
$
5,518

 
$
1,578

 
$
772

 
$
2,259

 
$
33,486

__________
(a)
Excludes the $1,254 million cash outlay for the acquisition of Express-Platte in 2013, part of Spectra Energy Partners.
(b)
Excludes a $71 million loan to an equity investment in 2013 at Spectra Energy Partners.
(c)
Includes foreign currency transaction gains and losses related to segment EBITDA.

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Geographic Data
 
U.S.
 
Canada
 
Consolidated
 
(in millions)
2015
 
 
 
 
 
Consolidated revenues
$
2,389

 
$
2,845

 
$
5,234

Consolidated long-lived assets
17,549

 
10,979

 
28,528

2014
 
 
 
 
 
Consolidated revenues
2,212

 
3,691

 
5,903

Consolidated long-lived assets
15,834

 
12,715

 
28,549

2013
 
 
 
 
 
Consolidated revenues
1,926

 
3,592

 
5,518

Consolidated long-lived assets
14,963

 
13,247

 
28,210


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5. Regulatory Matters
Regulatory Assets and Liabilities
We record assets and liabilities that result from the regulated ratemaking process that would not be recorded under U.S. GAAP for non-regulated entities. See Note 1 for further discussion.
The following items are reflected in the consolidated balance sheets. All regulatory assets and liabilities are excluded from rate base unless otherwise noted below.
 
Recovery/Refund
Period
 
December 31,
 
 
2015
 
2014
 
 
 
(in millions)
Regulatory Assets
 
 
 
 
 
Under-recovery of fuel costs (c)
 
$
41

 
$
44

Gas purchase costs (c)
 

 
57

Other
 
73

 
46

Total Regulatory Assets—Current (a)
 
 
114

 
147

Net regulatory asset related to income taxes (d,e)
2 years - remaining life of asset
 
1,215

 
1,271

Project development costs (d)
Through 2036
 
9

 
10

Vacation accrual (d)
Various
 
23

 
22

Deferred debt expense/premium (d)
Various
 
23

 
31

Other
Various
 
13

 
13

Total Regulatory Assets—Non Current (b)
 
 
1,283

 
1,347

Total Regulatory Assets
 
 
$
1,397

 
$
1,494

Regulatory Liabilities
 
 
 
 
 
Gas purchase costs (c)
 
$
48

 
$

Other (d)
 
32

 
59

Total Regulatory Liabilities—Current (a)
 
 
80

 
59

Removal costs (d)
Exceeds remaining life of asset
 
258

 
326

Pipeline rate credit
Life of associated liability
 
24

 
25

Other (d)
Various
 
23

 
20

Total Regulatory Liabilities—Non Current (b)
 
 
305

 
371

Total Regulatory Liabilities
 
 
$
385

 
$
430

________
(a)
Included in Inventory, Fuel Tracker, Current Assets—Other or Current Liabilities—Other.
(b)
Included in Regulatory Assets and Deferred Debits or Deferred Credits and Other Liabilities—Regulatory and Other.
(c)
Includes costs settled in cash annually through transportation rates in accordance with FERC and/or OEB gas tariffs.
(d)
All or a portion of the balance is included in rate base.
(e)
All amounts are expected to be included in future rate filings.
Union Gas. Union Gas has regulatory assets of $291 million as of December 31, 2015 and $303 million as of December 31, 2014 related to deferred income tax liabilities. Under the current OEB-authorized rate structure, income tax costs are recovered in rates based on the current income tax payable and do not include accruals for deferred income tax. However, as income taxes become payable as a result of the reversal of timing differences that created the deferred income taxes, it is expected that rates will be adjusted to recover these taxes. Since substantially all of these timing differences are related to property, plant and equipment costs, recovery of these regulatory assets is expected to occur over the life of those assets.
Union Gas has regulatory liabilities associated with plant removal costs of $258 million as of December 31, 2015 and $322 million as of December 31, 2014. These regulatory liabilities represent collections from customers under approved rates for future asset removal activities that are expected to occur associated with its regulated facilities.
In addition, Union Gas has regulatory liabilities of $48 million as of December 31, 2015 and regulatory assets of $57 million as of December 31, 2014 representing gas cost collections from customers under approved rates that vary from actual

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cost of gas for the associated periods. Union Gas files an application quarterly with the OEB to ensure that customers’ rates are updated to reflect published forward-market prices. The difference between the approved and the actual cost of gas is deferred for future repayment to or refund from customers.
BC Pipeline and BC Field Services. The BC Pipeline and BC Field Services businesses in western Canada have regulatory assets of $727 million as of December 31, 2015 and $795 million as of December 31, 2014 related to deferred income tax liabilities. Under the current NEB-authorized rate structure, income tax costs are recovered in tolls based on the current income tax payable and do not include accruals for deferred income tax. However, as income taxes become payable as a result of the reversal of timing differences that created the deferred income taxes, it is expected that transportation and field services tolls will be adjusted to recover these taxes. Since most of these timing differences are related to property, plant and equipment costs, this recovery is expected to occur over the life of those assets.
When evaluating the recoverability of the BC Pipelines’ and BC Field Services’ regulatory assets, we take into consideration the NEB regulatory environment, natural gas reserve estimates for reserves located or expected to be located near these assets, the ability to remain competitive in the markets served and projected demand growth estimates for the areas served by the BC Pipeline and BC Field Services businesses. Based on current evaluation of these factors, we believe that recovery of these tax costs is probable over the periods described above.
Rate Related Information
Union Gas. In December 2015, Union Gas filed an application with the OEB for the disposition of the 2014 energy conservation deferral and variance account balances. As a result of this application, Union Gas has a receivable from customers of approximately $8 million as of December 31, 2015 and $9 million as of December 31, 2014, which is reflected as Current Assets—Other on the Consolidated Balance Sheets. A hearing and decision from the OEB is expected in 2016.
6. Income Taxes
Income Tax Expense Components
 
2015
 
2014
 
2013
 
(in millions)
Current income taxes
 
 
 
 
 
Federal
$

 
$
1

 
$
(32
)
State
13

 
3

 
4

Foreign
60

 
(10
)
 
26

Total current income taxes
73

 
(6
)
 
(2
)
Deferred income taxes
 
 
 
 
 
Federal
145

 
335

 
353

State
(18
)
 
(17
)
 
69

Foreign
(39
)
 
70

 
(1
)
Total deferred income taxes
88

 
388

 
421

Total income tax expense
$
161

 
$
382

 
$
419

Earnings before Income Taxes
 
2015
 
2014
 
2013
 
(in millions)
Domestic
$
636

 
$
1,108

 
$
1,059

Foreign
(15
)
 
557

 
519

Total earnings before income taxes
$
621

 
$
1,665

 
$
1,578


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Reconciliation of Income Tax Expense at the U.S. Federal Statutory Tax Rate to Actual Income Tax Expense
 
2015
 
2014
 
2013
 
(in millions)
Income tax expense, computed at the statutory rate of 35%
$
217

 
$
583

 
$
552

State income tax, net of federal income tax effect
12

 
25

 
20

Tax differential on foreign earnings
(44
)
 
(125
)
 
(147
)
Noncontrolling interests
(92
)
 
(70
)
 
(42
)
Valuation allowance
1

 
2

 
(3
)
Goodwill impairment
91

 

 

Revaluation of accumulated deferred state taxes
(12
)
 
(25
)
 
31

Other items, net
(12
)
 
(8
)
 
8

Total income tax expense
$
161

 
$
382

 
$
419

Effective tax rate
25.9
%
 
22.9
%
 
26.6
%
Net Deferred Income Tax Liability Components
 
December 31,
2015
 
2014
(in millions)
Deferred credits and other liabilities
$
275

 
$
225

Net operating loss carryforward
295

 
158

Other
36

 
53

Total deferred income tax assets
606

 
436

Valuation allowance
(27
)
 
(29
)
Net deferred income tax assets
579

 
407

Investments and other assets
(1,605
)
 
(1,531
)
Accelerated depreciation rates
(4,035
)
 
(3,875
)
Regulatory assets and deferred debits
(384
)
 
(426
)
Total deferred income tax liabilities
(6,024
)
 
(5,832
)
Total net deferred income tax liabilities
$
(5,445
)
 
$
(5,425
)
The above deferred tax amounts have been classified in the Consolidated Balance Sheets as follows:
 
December 31,
 
2015
 
2014
 
(in millions)
Other current liabilities
$

 
$
(20
)
Deferred credits and other liabilities
(5,445
)
 
(5,405
)
Total net deferred income tax liabilities
$
(5,445
)
 
$
(5,425
)
At December 31, 2015, we had a federal net operating loss carryforward, net of unrecognized tax benefits, of $726 million that expires at various times beginning in 2021. The deferred tax asset attributable to the federal net operating losses, net of unrecognized tax benefits, is $254 million. At December 31, 2015 we also had a state net operating loss carryforward of approximately $381 million that expires at various times beginning in 2016. The deferred tax asset attributable to the state net operating loss carryovers is $20 million, net of federal impacts and unrecognized tax benefits, at December 31, 2015. We had valuation allowances of $9 million at both December 31, 2015 and 2014 against the deferred tax asset related to the federal net operating loss carryforward. We had valuation allowances of $1 million and less than $1 million at December 31, 2015 and 2014, respectively, against the deferred tax asset related to the state net operating loss carryforward and other state tax credits.
At December 31, 2015, we had a foreign net operating loss carryforward of $80 million that expires at various times beginning in 2026. The deferred tax asset attributable to the foreign net operating loss is $21 million. We had valuation allowances of $1 million and less than $1 million at December 31, 2015 and 2014, respectively, against the deferred tax asset related to the foreign net operating loss carryforward and property, plant and equipment. At December 31, 2015, we also had a foreign capital loss carryforward of $124 million with an indefinite expiration period. The deferred tax asset attributable to the

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foreign capital loss carryforward is $16 million. We had valuation allowances of $16 million and $20 million at December 31, 2015 and 2014, respectively, against the deferred tax asset related to the foreign capital loss carryforward.
Reconciliation of Gross Unrecognized Income Tax Benefits
 
2015
 
2014
 
2013
 
(in millions)
Balance at beginning of period
$
50

 
$
76

 
$
80

Increases related to prior year tax positions
10

 
10

 
7

Decreases related to prior year tax positions
(1
)
 
(6
)
 
(17
)
Increases related to current year tax positions
30

 
1

 
2

Settlements

 

 
(3
)
Lapse of statute of limitations
(4
)
 
(30
)
 
9

Foreign currency translation
(3
)
 
(1
)
 
(2
)
Balance at end of period
$
82

 
$
50

 
$
76

Unrecognized tax benefits totaled $82 million at December 31, 2015. Of this, $39 million would reduce the annual effective tax rate if recognized on or after January 1, 2016. We recorded a net increase of $32 million in gross unrecognized tax benefits during 2015. This was a result of $22 million attributable to deferred tax liabilities, foreign currency exchange rate fluctuations and a $10 million increase in income tax expense.
We recognize potential accrued interest and penalties related to unrecognized tax benefits as interest expense and as other expense, respectively. We recognized interest expense of $2 million in 2015 and interest income of $2 million in 2014 related to unrecognized tax benefits. Accrued interest and penalties totaled $21 million at December 31, 2015 and $19 million at December 31, 2014.
Although uncertain, we believe it is reasonably possible that the total amount of unrecognized tax benefits could decrease by $30 million to $40 million prior to December 31, 2016.
We remain subject to examination for Canada income tax return filings for years 2009 through 2014 and U.S. federal income tax return filings for years 2011 through 2014. A limited number of state tax return filings remain subject to examination for years 2007 through 2014.
We have foreign subsidiaries’ undistributed earnings of approximately $1.5 billion at December 31, 2015 that are indefinitely invested outside the U.S. and, accordingly, no U.S. federal or state income taxes have been provided on those earnings. Upon distribution of those earnings, we may be subject to both foreign withholding taxes and U.S. income taxes, net of allowable foreign tax credits. The amount of such additional taxes would be dependent on several factors, including the size and timing of the distribution and the availability of foreign tax credits. As a result, the determination of the potential amount of unrecognized withholding and deferred income taxes is not practicable.
7. Earnings per Common Share
Basic earnings per common share (EPS) is computed by dividing net income from controlling interests by the weighted-average number of common shares outstanding during the period. Diluted EPS is computed by dividing net income from controlling interests by the diluted weighted-average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock, such as stock options, stock-based performance unit awards and phantom stock awards, were exercised, settled or converted into common stock.
Weighted-average shares used to calculate diluted EPS includes the effect of certain options and restricted stock awards. In 2015, 2014 and 2013, there were no options or stock awards that were not included in the calculation of diluted EPS.
The following table presents our basic and diluted EPS calculations:
 
2015
 
2014
 
2013
 
(in millions, except per-share amounts)
Net income—controlling interests
$
196

 
$
1,082

 
$
1,038

Weighted-average common shares outstanding
 
 
 
 
 
Basic
671

 
671

 
669

Diluted
672

 
672

 
671

Basic and diluted earnings per common share
$
0.29

 
$
1.61

 
$
1.55


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8. Accumulated Other Comprehensive Income (Loss)
The following table presents the net of tax changes in AOCI by component and amounts reclassified out of AOCI to Net Income, excluding amounts attributable to noncontrolling interests:
 
Foreign Currency Translation Adjustments
 
Pension and Post-retirement Benefit Plan Obligations
 
Gas Purchase Contract Hedges
 
Other
 
Total Accumulated Other Comprehensive Income (Loss)
 
 
 
 
(in millions)
 
 
 
December 31, 2013
$
1,557

 
$
(304
)
 
$
(11
)
 
$
(1
)
 
$
1,241

Reclassified to net income

 

 
4

 
1

 
5

Other AOCI activity
(541
)
 
(47
)
 
4

 

 
(584
)
December 31, 2014
1,016

 
(351
)
 
(3
)
 

 
662

Other AOCI activity
(937
)
 
5

 

 
1

 
(931
)
December 31, 2015
$
79

 
$
(346
)
 
$
(3
)
 
$
1

 
$
(269
)
Reclassifications to Net Income are primarily included in Other Income and Expenses, Net on our Consolidated Statements of Operations.
9. Inventory
The components of inventory are as follows:
 
December 31,
 
2015
 
2014
 
(in millions)
Natural gas
$
217

 
$
211

NGLs
23

 
28

Materials and supplies
67

 
74

Total inventory
$
307

 
$
313

Our inventory at our Empress operations at Western Canada Transmission & Processing is subject to lower of cost or market. As such, we recorded non-cash charges totaling $14 million in 2015 and $19 million in 2014 ($10 million and $14 million after tax, respectively) to Natural Gas and Petroleum Products Purchased on the Consolidated Statements of Operations to reduce propane inventory to estimated net realizable value.
10. Investments in and Loans to Unconsolidated Affiliates and Related Party Transactions
Investments in affiliates for which we are not the primary beneficiary, but over which we have significant influence, are accounted for using the equity method. As of December 31, 2015 and 2014, the carrying amounts of investments in affiliates approximated the amounts of underlying equity in net assets, with the exception of DCP Midstream in 2015, which relates to a contribution of assets recorded at carrying value. We received distributions from our equity investments of $612 million in 2015, $646 million in 2014 and $411 million in 2013. Cumulative undistributed earnings of unconsolidated affiliates totaled $28 million at December 31, 2015 and $482 million at December 31, 2014.
Spectra Energy Partners. As of December 31, 2015, our Spectra Energy Partners segment investments were mostly comprised of a 39% effective interest in Gulfstream, a 39% effective interest in SESH, and a 39% effective interest in Steckman Ridge. On November 4, 2015, we contributed our remaining 0.1% interest in SESH to SEP. Total consideration to Spectra Energy was 17,114 newly issued SEP common units. This was the last of three planned transactions related to the U.S. Assets Dropdown. Also, in connection with this transaction, SEP issued 342 general partner units to Spectra Energy in exchange for the same amount of common units in order to maintain Spectra Energy's 2% general partner interest in SEP.
We have a loan outstanding to Steckman Ridge in connection with the construction of its storage facilities. The loan carries market-based interest rates and is due the earlier of October 1, 2023 or coincident with the closing of any long-term financings by Steckman Ridge. The loan receivable from Steckman Ridge, including accrued interest, totaled $71 million at December 31, 2015 and 2014. We recorded interest income on the Steckman Ridge loan of $1 million in 2015, 2014 and 2013.

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On October 30, 2015, Spectra Energy acquired SEP’s 33.3% ownership interests in Sand Hills and Southern Hills. In consideration for this transaction, SEP retired 21,560,000 of our limited partner units and 440,000 of our general partner units in SEP. This resulted in the reduction of any associated distribution payable to us, beginning in 2016. There will also be a reduction in the aggregate quarterly distributions, if any, to us (as holder of incentive distribution rights), by $4 million per quarter for a period of 12 consecutive quarters, which commenced with the quarter ending on December 31, 2015 and will end with the quarter ending on September 30, 2018.
Field Services. Our most significant investment in unconsolidated affiliates is our 50% investment in DCP Midstream, which is accounted for under the equity method of accounting. DCP Midstream is a limited liability company which is a pass-through entity for U.S. income tax purposes. DCP Midstream also owns an entity which files its own federal, foreign and state income tax returns. Income tax expense related to that entity is included in the income tax expense of DCP Midstream. Therefore, DCP Midstream’s net income attributable to members’ interests does not include income taxes for earnings which are passed through to the members based upon their ownership percentage. We recognize the tax effects of our share of DCP Midstream’s pass-through earnings in Income Tax Expense in the Consolidated Statements of Operations.
DCP Partners issues, from time to time, limited partner units to the public, which are recorded by DCP Midstream directly to its equity. Our proportionate 50% share of gains from those issuances, totaling $2 million in 2015, $73 million in 2014 and $98 million in 2013, are reflected in Earnings (Loss) from Equity Investments in the Consolidated Statements of Operations.
Due to the significant downturn in commodity prices, DCP Midstream performed a goodwill impairment test and other asset impairment tests in 2015. The impairment tests were based on internal discounted cash flow models taking into account various observable and unobservable factors, such as prices, volumes, expenses and discount rate. The impairment tests resulted in DCP Midstream’s recognition of a $460 million goodwill impairment and $342 million in other asset impairments, net of tax, which reduced our equity earnings from DCP Midstream by $231 million after-tax for 2015. Due to the impairments recognized by DCP Midstream, we assessed our equity investment in DCP Midstream and determined that our equity investment in DCP Midstream was not impaired.
As previously discussed, on October 30, 2015, we contributed our 33.3% interests in Sand Hills and Southern Hills acquired from SEP to DCP Midstream. In consideration for this transaction, we increased our basis in the net equity of DCP Midstream and retained our 50% ownership interest.
Investments in and Loans to Unconsolidated Affiliates
 
December 31, 2015
 
December 31, 2014
 
Domestic
 
International
 
Total
 
Domestic
 
International
 
Total
 
(in millions)
Spectra Energy Partners
$
904

 
$

 
$
904

 
$
1,588

 
$

 
$
1,588

Distribution

 
11

 
11

 

 
14

 
14

Western Canada Transmission & Processing

 
17

 
17

 

 
18

 
18

Field Services
1,660

 

 
1,660

 
1,345

 

 
1,345

Other

 

 

 
1

 

 
1

Total
$
2,564

 
$
28

 
$
2,592

 
$
2,934

 
$
32

 
$
2,966


Equity in Earnings of Unconsolidated Affiliates
 
2015
 
2014
 
2013
 
Domestic
 
International
 
Total
 
Domestic
 
International
 
Total
 
Domestic
 
International
 
Total
 
(in millions)
Spectra Energy Partners
$
167

 
$

 
$
167

 
$
133

 
$

 
$
133

 
$
90

 
$

 
$
90

Distribution

 
1

 
1

 

 
1

 
1

 

 
1

 
1

Western Canada Transmission & Processing

 
2

 
2

 

 
1

 
1

 

 
(1
)
 
(1
)
Field Services
(461
)
 

 
(461
)
 
217

 

 
217

 
343

 

 
343

Other
1

 

 
1

 
9

 

 
9

 
12

 

 
12

Total
$
(293
)
 
$
3

 
$
(290
)
 
$
359

 
$
2

 
$
361

 
$
445

 
$

 
$
445


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Table of Contents

Summarized Combined Financial Information of Unconsolidated Affiliates (Presented at 100%)
Statements of Operations
 
2015
 
2014
 
2013
 
DCP
Midstream
 
Other
 
Total
 
DCP
Midstream
 
Other
 
Total
 
DCP
Midstream
 
Other
 
Total
 
(in millions)
Operating revenues
$
7,420

 
$
767

 
$
8,187

 
$
14,013

 
$
744

 
$
14,757

 
$
12,038

 
$
558

 
$
12,596

Operating expenses
8,227

 
288

 
8,515

 
13,262

 
319

 
13,581

 
11,230

 
261

 
11,491

Operating income
(807
)
 
479

 
(328
)
 
751

 
425

 
1,176

 
808

 
297

 
1,105

Net income
(843
)
 
393

 
(450
)
 
536

 
332

 
868

 
584

 
206

 
790

Net income attributable to members’  interests
(929
)
 
393

 
(536
)
 
288

 
332

 
620

 
491

 
206

 
697

Balance Sheets
 
December 31, 2015
 
December 31, 2014
 
DCP
Midstream
 
Other
 
Total
 
DCP
Midstream
 
Other
 
Total
 
(in millions)
Current assets
$
800

 
$
498

 
$
1,298

 
$
1,380

 
$
241

 
$
1,621

Non-current assets
13,094

 
3,265

 
16,359

 
12,299

 
5,358

 
17,657

Current liabilities
(896
)
 
(387
)
 
(1,283
)
 
(2,938
)
 
(632
)
 
(3,570
)
Non-current liabilities
(5,894
)
 
(1,679
)
 
(7,573
)
 
(5,538
)
 
(1,197
)
 
(6,735
)
Equity—total
7,104

 
1,697

 
8,801

 
5,203

 
3,770

 
8,973

Equity—noncontrolling interests
(2,404
)
 

 
(2,404
)
 
(2,578
)
 

 
(2,578
)
Equity—controlling interests
$
4,700

 
$
1,697

 
$
6,397

 
$
2,625

 
$
3,770

 
$
6,395

Related Party Transactions
DCP Midstream. DCP Midstream processes certain of our pipeline customers’ gas to meet gas quality specifications in order to be transported on our Texas Eastern system. DCP Midstream processes the gas and sells the NGLs that are extracted from the gas. A portion of the proceeds from those sales are retained by DCP Midstream and the balance is remitted to us. We received proceeds of $46 million in 2015, $79 million in 2014 and $48 million in 2013 from DCP Midstream related to those sales, classified as Operating Revenues—Other in our Consolidated Statements of Operations.
In addition to the above, we recorded other revenues from DCP Midstream and its affiliates totaling $4 million in 2015 and $9 million in 2014 and 2013, primarily within Transportation, Storage and Processing of Natural Gas, and $4 million in 2015, $7 million in 2014 and $8 million in 2013 within Sales of Natural Gas Liquids.
We had accounts receivable from DCP Midstream and its affiliates of $1 million at December 31, 2015 and December 31, 2014. We received no distributions from DCP Midstream during 2015. We received distributions from DCP Midstream of $237 million in 2014 and $215 million in 2013, classified as Cash Flows from Operating Activities—Distributions from Equity Investments.
Gulfstream. During the third quarter of 2015, Gulfstream issued unsecured debt of $800 million to fund the repayment of its current debt. Gulfstream distributed $396 million of proceeds to us, classified as Cash Flows from Investing Activities—Distributions from Equity Investments, of which we contributed $248 million back to Gulfstream in 2015, classified as Cash Flows from Investing Activities—Loan to Equity Investment, as the current debt matured and of which we plan to contribute the remaining $148 million in the first half of 2016. At December 31, 2015, our Consolidated Balance Sheets include $148 million in Current Liabilities—Other related to this matter.
SESH. In 2014, SESH issued unsecured debt of $400 million to fund the repayment of its current debt. SESH distributed $200 million of proceeds to us, classified as Cash Flows from Investing Activities—Distributions from Equity Investments, of which we contributed $200 million back to SESH during 2014, classified as Cash Flows from Investing Activities—Investments in and Loans to Unconsolidated Affiliates, as the current debt matured.

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Other. We provide certain administrative and other services to certain other operating entities. We recorded recoveries of costs from these affiliates of $28 million in 2015, $38 million in 2014 and $68 million in 2013. We also recorded recoveries of costs associated with a project of $139 million in 2015. Outstanding receivables from these affiliates totaled $11 million at December 31, 2015 and $1 million at December 31, 2014.
See also Notes 3, 16 and 18 for additional related party information.
11. Goodwill
The following table presents activity within goodwill based on a segment basis:
 
Spectra Energy Partners
 
Distribution
 
Western Canada
Transmission &
Processing
 
Total
 
(in millions)
December 31, 2013
$
3,215

 
$
824

 
$
771

 
$
4,810

Adjustment to acquisition of Express-Platte
37

 

 

 
37

Foreign currency translation
(8
)
 
(65
)
 
(60
)
 
(133
)
December 31, 2014
3,244

 
759

 
711

 
4,714

Impairment of goodwill

 

 
(333
)
 
(333
)
Foreign currency translation
(12
)
 
(110
)
 
(105
)
 
(227
)
December 31, 2015
$
3,232

 
$
649

 
$
273

 
$
4,154

See Note 3 for discussion of the acquisition of Express-Platte and an adjustment to Goodwill recorded in the first quarter of 2014 related to the acquisition.
The following remaining goodwill amounts originating from the acquisition of Westcoast in 2002 are included as segment assets within “Other” in the segment data presented in Note 4:
 
December 31,
 
2015
 
2014
 
(in millions)
Distribution
$
646

 
$
757

Western Canada Transmission & Processing
246

 
677

Due to the sustained downturn in commodity prices, we performed a goodwill impairment test for BC Field Services and Empress in the fourth quarter of 2015. The impairment test was based on a combination of an income approach and a market approach for which the inputs are classified as Level 3. The impairment test resulted in recognition of a $270 million goodwill impairment for BC Field Services and a $63 million goodwill impairment for Empress which resulted in a total goodwill impairment of $333 million.
No triggering events occurred during the period from April 1, 2015 through December 31, 2015 that warranted re-testing for goodwill impairment except for the BC Field Services reporting unit and Empress reporting unit.
See Note 10 for discussion related to the partial impairment of goodwill recognized by DCP Midstream.
12. Marketable Securities and Restricted Funds
We routinely invest excess cash and various restricted balances in securities such as commercial paper, bankers acceptances, corporate debt securities, treasury bills and money market funds in the U.S. and Canada. We do not purchase marketable securities for speculative purposes; therefore we do not have any securities classified as trading securities. While we do not routinely sell marketable securities prior to their scheduled maturity dates, some of our investments may be held and restricted for insurance purposes and capital expenditures, so these investments are classified as AFS marketable securities as they may occasionally be sold prior to their scheduled maturity dates due to the unexpected timing of cash needs. Initial investments in securities are classified as purchases of the respective type of securities (AFS marketable securities or HTM marketable securities). Maturities of securities are classified within proceeds from sales and maturities of securities in the Consolidated Statements of Cash Flows.

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AFS Securities. AFS securities are as follows:
 
Estimated Fair Value
 
December 31,
 
2015
 
2014
 
(in millions)
Corporate debt securities
$
31

 
$
23

Money market funds

 
1

Total available-for-sale securities
$
31

 
$
24

Our AFS securities are classified on the Consolidated Balance Sheets as follows:
 
 
Estimated Fair Value
 
 
December 31,
 
 
2015
 
2014
 
 
(in millions)
Restricted funds
 
 
 
Investments and other assets—other
$
11

 
$
1

Non-restricted funds
 
 
 
Current assets—other
20

 
3

Investments and other assets—other

 
20

Total available-for-sale securities
$
31

 
$
24

At December 31, 2015, the weighted–average contractual maturity of outstanding AFS securities was less than one year.
There were no material gross unrealized holding gains or losses associated with investments in AFS securities at December 31, 2015 or 2014.
HTM Securities. All of our HTM securities are as follows:
 
 
Estimated Fair Value
 
 
December 31,
Description
Consolidated Balance Sheet Caption
2015
 
2014
 
 
(in millions)
Bankers acceptances
Current assets—other
$
30

 
$
38

Canadian government securities
Current assets—other
24

 
30

Money market funds
Current assets—other
3

 
3

Canadian government securities
Investments and other assets—other
50

 
101

Bankers acceptances
Investments and other assets—other
12

 

Total held-to-maturity securities
$
119

 
$
172

All of our HTM securities are restricted funds pursuant to certain M&N Canada and Express-Platte (our crude oil pipeline system) debt agreements. The funds restricted for M&N Canada, plus future cash from operations that would otherwise be available for distribution to the partners of M&N Canada, are required to be placed in escrow until the balance in escrow is sufficient to fund all future debt service on the M&N Canada 6.90% senior secured notes. There are sufficient funds held in escrow to fund all future debt service on these M&N Canada notes as of December 31, 2015.
At December 31, 2015, the weighted–average contractual maturity of outstanding HTM securities was less than one year.
There were no material gross unrecognized holding gains or losses associated with investments in HTM securities at December 31, 2015 or 2014.
Other Restricted Funds. In addition to the portions of the AFS and HTM securities that were restricted funds as described above, we had other restricted funds totaling $11 million at December 31, 2015 and $13 million at December 31, 2014 classified as Current Assets—Other. These restricted funds are related to additional amounts for insurance. We also had other restricted funds totaling $38 million at December 31, 2015 and $6 million at December 31, 2014 classified as Investments and Other Assets—Other. $24 million of these restricted funds are related to funds held and collected from customers for Canadian pipeline abandonment in accordance with the NEB’s regulatory requirements and $14 million are related to certain construction projects.

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Changes in restricted balances are presented within Cash Flows from Investing Activities on our Consolidated Statements of Cash Flows.
Interest income. Interest income totaled $3 million in 2015, $4 million in 2014 and $6 million 2013, and is included in Other Income and Expenses, Net on the Consolidated Statements of Operations.
13. Property, Plant and Equipment
 
Estimated
Useful Life
 
December 31,
 
2015
 
2014
 
(years)
 
(in millions)
Plant
 
 
 
 
 
Natural gas transmission
15–100

 
$
15,690

 
$
15,001

Natural gas distribution
25-60

 
2,651

 
2,971

Gathering and processing facilities
25-40

 
4,178

 
4,765

Natural gas storage
10–122

 
2,137

 
2,162

Crude oil transportation and storage
25–75

 
1,206

 
1,169

Land rights and rights of way
21–122

 
591

 
568

Other buildings and improvements
10–50

 
149

 
132

Equipment
3–40

 
301

 
343

Vehicles
5–20

 
102

 
114

Land

 
138

 
150

Construction in process

 
1,919

 
1,113

Software
4–10

 
439

 
387

Other
5–82

 
342

 
336

Total property, plant and equipment
 
 
29,843

 
29,211

Total accumulated depreciation
 
 
(6,527
)
 
(6,543
)
Total accumulated amortization
 
 
(398
)
 
(361
)
Total net property, plant and equipment
 
 
$
22,918

 
$
22,307

We had no material capital leases at December 31, 2015 or 2014.
Almost 85% of our property, plant and equipment is regulated with estimated useful lives based on rates approved by the applicable regulatory authorities in the U.S. and Canada: the FERC, the NEB and the OEB. Composite weighted-average depreciation rates were 2.72% for 2015, 2.82% for 2014 and 2.96% for 2013.
Amortization expense of intangible assets totaled $79 million in 2015, $74 million in 2014 and $65 million in 2013. Estimated amortization expense for the next five years follows:
 
Estimated
Amortization
Expense
 
(in millions)
2016
$
84

2017
80

2018
54

2019
35

2020
28


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14. Asset Retirement Obligations
Our AROs relate mostly to the retirement of certain gathering pipelines and processing facilities, obligations related to right-of-way agreements and contractual leases for land use. However, we have determined that a significant portion of our assets have an indeterminate life, and as such, the fair values of those associated retirement obligations are not reasonably estimable. These assets include onshore and some offshore pipelines, and certain processing plants and distribution facilities, whose retirement dates will depend mostly on the various natural gas supply sources that connect to our systems and the ongoing demand for natural gas usage in the markets we serve. We expect these supply sources and market demands to continue for the foreseeable future, therefore we are unable to estimate retirement dates that would result in asset retirement obligations.
AROs are adjusted each period for liabilities incurred or settled during the period, accretion expense, any revisions made to the estimated cash flows and dispositions of businesses. In 2015, SEP revised the estimated future cash flow assumptions for its ARO liabilities due to a reduction in the remaining estimated life of certain Texas Eastern offshore facilities which resulted in an increase to ARO liabilities of $32 million. In 2014, Western Canada Transmission & Processing revised the estimated future cash flow assumptions relating to asbestos abatement at its processing plants which resulted in an increase to ARO liabilities of $44 million.
Reconciliation of Changes in Asset Retirement Obligation Liabilities
 
2015
 
2014
 
(in millions)
Balance at beginning of year
$
400

 
$
350

Accretion expense
17

 
16

Revisions in estimated cash flows (a)
72

 
72

Foreign currency exchange impact
(62
)
 
(28
)
Liabilities settled
(9
)
 
(10
)
Balance at end of year (b)
$
418

 
$
400

________
(a)
Reflects revised assumptions regarding ARO Liabilities due to a reduction in the remaining estimated life of certain Texas Eastern offshore facilities in 2015 and asbestos abatement at Western Canada Transmission & Processing in 2014.
(b)
Amounts included in Deferred Credits and Other Liabilities in the Consolidated Balance Sheets.

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15. Debt and Credit Facilities
Summary of Debt and Related Terms
December 31,
 
2015
 
2014
Spectra Energy Capital, LLC
(in millions)
6.20% senior unsecured notes due April 2018
$
500

 
$
500

6.75% senior unsecured notes due July 2018
150

 
150

Variable-rate senior unsecured term loan due November 2018
300

 
300

8.00% senior unsecured notes due October 2019
500

 
500

5.65% senior unsecured notes due March 2020
300

 
300

3.30% senior unsecured notes due March 2023
650

 
650

6.75% senior unsecured notes due February 2032
240

 
240

7.50% senior unsecured notes due September 2038
250

 
250

Total Spectra Energy Capital, LLC Debt
2,890

 
2,890

 
 
 
 
SEP
 
 
 
SEP 2.95% senior unsecured notes due June 2016
250

 
250

SEP 2.95% senior unsecured notes due September 2018
500

 
500

SEP variable-rate senior unsecured term loan due November 2018
400

 
400

SEP 4.60% senior unsecured notes due June 2021
250

 
250

SEP 4.75% senior unsecured notes due March 2024
1,000

 
1,000

SEP 3.50% senior unsecured notes due March 2025
500

 

SEP 5.95% senior unsecured notes due September 2043
400

 
400

SEP 4.50% senior unsecured notes due March 2045
500

 

Texas Eastern 6.00% senior unsecured notes due September 2017
400

 
400

Texas Eastern 4.13% senior unsecured notes due December 2020
300

 
300

Texas Eastern 2.80% senior unsecured notes due October 2022
500

 
500

Texas Eastern 7.00% senior unsecured notes due July 2032
450

 
450

Algonquin 3.51% senior notes due July 2024
350

 
350

East Tennessee Natural Gas, LLC 3.10% senior notes due December 2024
200

 
200

Express-Platte 6.09% senior secured notes due January 2020
110

 
110

Express-Platte 7.39% subordinated secured notes due 2015 to 2019
42

 
74

Total SEP Debt
6,152

 
5,184

 
 
 
 
Westcoast
 
 
 
8.50% debentures due November 2015

 
108

3.28% medium-term notes due January 2016
181

 
215

8.50% debentures due September 2018
108

 
129

5.60% medium-term notes due January 2019
217

 
258

9.90% debentures due January 2020
72

 
86

4.57% medium-term notes due July 2020
181

 
215

3.88% medium-term notes due October 2021
108

 
129

3.12% medium-term notes due December 2022
181

 
215

3.43% medium-term notes due September 2024
253

 
301

8.85% debentures due July 2025
108

 
129

8.80% medium-term notes due November 2025
18

 
22

3.77% medium-term notes due December 2025
217

 

7.30% debentures due December 2026
90

 
108

6.75% medium-term notes due December 2027
108

 
129

7.15% medium-term notes due March 2031
145

 
172

4.79% medium-term notes due October 2041
145

 
129

M&N Canada 6.90% senior secured notes due 2015 to 2019
75

 
112

M&N Canada 4.34% senior secured notes due 2015 to 2019
47

 
83

Other
2

 
2

Total Westcoast Debt
$
2,256

 
$
2,542


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December 31,
 
2015
 
2014
Union Gas
(in millions)
11.50% debentures due August 2015
$

 
$
129

4.64% medium-term notes due June 2016
145

 
172

9.70% debentures due November 2017
90

 
108

5.35% medium-term notes due April 2018
145

 
172

8.75% debentures due August 2018
90

 
108

8.65% senior debentures due October 2018
54

 
64

2.76% medium-term notes due June 2021
145

 
172

4.85% medium-term notes due April 2022
90

 
108

3.79% medium-term notes due July 2023
181

 
215

3.19% medium-term notes due September 2025
145

 

8.65% debentures due November 2025
90

 
108

5.46% medium-term notes due September 2036
119

 
142

6.05% medium-term notes due September 2038
216

 
258

5.20% medium-term notes due July 2040
181

 
215

4.88% medium-term notes due June 2041
217

 
258

4.20% medium-term notes due June 2044
361

 
215

Total Union Gas Debt
2,269

 
2,444

 
 
 
 
Total
 
 
 
Long-term debt principal (including current maturities)
13,567

 
13,060

Change in fair value of debt hedged
22

 
17

Unamortized debt discount, net
(22
)
 
(12
)
Unamortized capitalized debt issuance costs (a)
(46
)
 
(42
)
Other unamortized items
4

 
7

Total other non-principal amounts
(42
)
 
(30
)
Commercial paper (b)
1,112

 
1,583

Capital Leases
19

 
24

Total debt (including capital lease obligations) (c)
14,656

 
14,637

Current maturities of long-term debt
(652
)
 
(327
)
Commercial paper (d)
(1,112
)
 
(1,583
)
Total long-term debt (including capital lease obligations)
$
12,892

 
$
12,727

______
(a)
Reflects implementation of ASU No. 2015-03 as discussed in Note 1.
(b)
The weighted-average days to maturity was 12 days as of December 31, 2015 and 14 days as of December 31, 2014.
(c)
As of December 31, 2015 and 2014, respectively, $4,681 million and $5,264 million of debt was denominated in Canadian dollars.
(d)
Weighted-average rate on outstanding commercial paper was 0.9% at December 31, 2015 and 0.6% at December 31, 2014.
Secured Debt. Secured debt, totaling $274 million as of December 31, 2015, includes project financings for M&N Canada and Express-Platte. Ownership interests in M&N Canada and certain of its accounts, revenues, business contracts and other assets are pledged as collateral. Express-Platte notes payable are secured by the assignment of the Express-Platte transportation receivables and by the Canadian portion of the Express-Platte pipeline system assets.
Floating Rate Debt. Debt included approximately $1,812 million of floating-rate debt as of December 31, 2015 and $2,283 million as of December 31, 2014. The weighted average interest rate of borrowings outstanding that contained floating rates was 1.15% at December 31, 2015 and 0.8% at December 31, 2014.

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Annual Maturities
December 31, 2015
 
(in millions)
2016
$
650

2017
543

2018
2,277

2019
745

2020
963

Thereafter
8,408

Total long-term debt, including current maturities (a)
$
13,586

__________
(a)
Excludes commercial paper of $1,112 million. Includes capital leases of $19 million.
We have the ability under certain debt facilities to call and repay the obligations prior to scheduled maturities. Therefore, the actual timing of future cash repayments could be materially different than presented above.
Available Credit Facilities and Restrictive Debt Covenants
 
Expiration
Date
 
Total
Credit
Facilities
Capacity
 
Commercial Paper Outstanding at December 31, 2015
 
Available
Credit
Facilities
Capacity
 
 
 
(in millions)
Spectra Energy Capital, LLC (a)
2019
 
$
1,000

 
$
481

 
$
519

SEP (b)
2019
 
2,000

 
476

 
1,524

Westcoast (c)
2019
 
289

 
6

 
283

Union Gas (d)
2019
 
361

 
149

 
212

Total
 
 
$
3,650

 
$
1,112

 
$
2,538

__________
(a)
Revolving credit facility contains a covenant requiring the Spectra Energy consolidated debt-to-total capitalization ratio, as defined in the agreement, to not exceed 65%. Per the terms of the agreement, collateralized debt is excluded from the calculation of the ratio. This ratio was 59.6% at December 31, 2015.
(b)
Revolving credit facility contains a covenant that requires SEP to maintain a ratio of total Consolidated Indebtedness-to-Consolidated EBITDA, as defined in the agreement, of 5.0 to 1 or less. As of December 31, 2015, this ratio was 3.6 to 1.
(c)
U.S. dollar equivalent at December 31, 2015. The revolving credit facility is 400 million Canadian dollars and contains a covenant that requires the Westcoast non-consolidated debt-to-total capitalization ratio to not exceed 75%. The ratio was 35.4% at December 31, 2015.
(d)
U.S. dollar equivalent at December 31, 2015. The revolving credit facility is 500 million Canadian dollars and contains a covenant that requires the Union Gas debt-to-total capitalization ratio to not exceed 75% and a provision which requires Union Gas to repay all borrowings under the facility for a period of two days during the second quarter of each year. The ratio was 67.8% at December 31, 2015.
The issuances of commercial paper, letters of credit and revolving borrowings reduce the amounts available under the credit facilities. As of December 31, 2015, there were no letters of credit issued or revolving borrowings outstanding under the credit facilities.
Our credit agreements contain various covenants, including the maintenance of certain financial ratios. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of December 31, 2015, we were in compliance with those covenants. In addition, our credit agreements allow for acceleration of payments or termination of the agreements due to nonpayment, or in some cases, due to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. Our debt and credit agreements do not contain provisions that trigger an acceleration of indebtedness based solely on the occurrence of a material adverse change in our financial condition or results of operations.
As noted above, the terms of our Spectra Capital, LLC (Spectra Capital) credit agreements require our consolidated debt-to-total capitalization ratio, as defined in the agreement, to be 65% or lower. Per the terms of the agreements, collateralized debt is excluded from the calculation of the ratio. This ratio was 59.6% at December 31, 2015. Approximately $7.9 billion of our equity (net assets) was considered restricted at December 31, 2015, representing the minimum amount of equity required to maintain the 65% consolidated debt-to-total capitalization ratio.

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16. Preferred Stock of Subsidiaries
Westcoast and Union Gas have outstanding preferred shares owned by third parties that are generally not redeemable prior to specified redemption dates. On or after those dates, the shares may be redeemed, in whole or in part, for cash at the option of Westcoast and Union Gas, as applicable. The shares are not subject to any sinking fund or mandatory redemption and are not convertible into common shares. As redemption of the shares is not solely within our control, we have classified the preferred stock of subsidiaries as temporary equity on our Consolidated Balance Sheets. Dividends are cumulative and payable quarterly, and are included in Net Income—Noncontrolling Interests in the Consolidated Statements of Operations. Approximately 78% of the outstanding preferred shares are redeemable at the option of Westcoast and Union Gas, as applicable.
On December 15, 2015, Westcoast issued 4.6 million Cumulative 5-Year Minimum Rate Reset Redeemable First Preferred Shares, Series 10 for an aggregate principle amount of 115 million Canadian dollars (approximately $84 million as of the issuance date). Net proceeds from the issuance were used to fund capital expenditures, to refinance maturing debt obligations and for other corporate purposes.
17. Fair Value Measurements
The following presents, for each of the fair value hierarchy levels, assets and liabilities that are measured and recorded at fair value on a recurring basis:


Description
Consolidated Balance Sheet Caption
December 31, 2015
Total
 
Level 1
 
Level 2
 
Level 3
 
 
(in millions)
Corporate debt securities
Cash and cash equivalents
$
137

 
$

 
$
137

 
$

Corporate debt securities
Current assets — other
20

 

 
20

 

Commodity derivatives
Current assets — other
36

 

 

 
36

Commodity derivatives
Investments and other assets — other
5

 

 

 
5

Corporate debt securities
Investments and other assets — other
11

 

 
11

 

Interest rate swaps
Investments and other assets — other
37

 

 
37

 

Total Assets
$
246

 
$

 
$
205

 
$
41



Description


Consolidated Balance Sheet Caption
December 31, 2014
Total
 
Level 1
 
Level 2
 
Level 3
 
 
(in millions)
Corporate debt securities
Cash and cash equivalents
$
85

 
$

 
$
85

 
$

Corporate debt securities
Current assets — other
3

 

 
3

 

Commodity derivatives
Current assets — other
57

 

 

 
57

Interest rate swaps
Current assets — other
2

 

 
2

 

Commodity derivatives
Investments and other assets — other
21

 

 

 
21

Corporate debt securities
Investments and other assets — other
20

 

 
20

 

Interest rate swaps
Investments and other assets — other
22

 

 
22

 

Money market funds
Investments and other assets — other
1

 
1

 

 

Total Assets
$
211

 
$
1

 
$
132

 
$
78


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The following presents changes in Level 3 assets and liabilities that are measured at fair value on a recurring basis using significant unobservable inputs:
 
2015
 
2014
 
(in millions)
Derivative assets (liabilities)
 
 
 
Fair value, beginning of period
$
78

 
$
(3
)
Total gains (losses):
 
 
 
Included in earnings
43

 
91

Included in other comprehensive income
(10
)
 
5

Purchases
(3
)
 

Settlements
(67
)
 
(15
)
Fair value, end of period
$
41

 
$
78

Unrealized gains (losses) relating to instruments held at the end of the period
$
(19
)
 
$
56

Level 1
Level 1 valuations represent quoted unadjusted prices for identical instruments in active markets.
Level 2 Valuation Techniques
Fair values of our financial instruments that are actively traded in the secondary market, including our long-term debt, are determined based on market-based prices. These valuations may include inputs such as quoted market prices of the exact or similar instruments, broker or dealer quotations, or alternative pricing sources that may include models or matrix pricing tools, with reasonable levels of price transparency.
For interest rate swaps, we utilize data obtained from a third-party source for the determination of fair value. Both the future cash flows for the fixed-leg and floating-leg of our swaps are discounted to present value. In addition, credit default swap rates are used to develop the adjustment for credit risk embedded in our positions. We believe that since some of the inputs and assumptions for the calculations of fair value are derived from observable market data, a Level 2 classification is appropriate.
Level 3 Valuation Techniques
Level 3 valuation techniques include the use of pricing models, discounted cash flow methodologies or similar techniques where at least one significant model assumption or input is unobservable. Level 3 financial instruments also include those for which the determination of fair value requires significant management judgment or estimation.
The derivative financial instruments reported in Level 3 at December 31, 2015 consist of NGL revenue swap contracts related to the Empress assets in Western Canada Transmission & Processing. As of December 31, 2015, we reported certain of our NGL basis swaps at fair value using Level 3 inputs due to such derivatives not having observable market prices for substantially the full term of the derivative asset or liability. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract length extends into unobservable periods.
The fair value of these NGL basis swaps is determined using a discounted cash flow valuation technique based on a forward commodity basis curve. For these derivatives, the primary input to the valuation model is the forward commodity basis curve, which is based on observable or public data sources and extrapolated when observable prices are not available.
The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives are the forward natural gas basis curves, for which a significant portion of the derivative’s term is beyond available forward pricing. At December 31, 2015, a 10¢ per gallon movement in underlying forward NGL prices would affect the estimated fair value of our NGL derivatives by $15 million. This calculated amount does not take into account any other changes to the fair value measurement calculation.

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Financial Instruments
The fair values of financial instruments that are recorded and carried at book value are summarized in the following table. Judgment is required in interpreting market data to develop the estimates of fair value. These estimates are not necessarily indicative of the amounts we could have realized in current markets.
 
December 31,
 
2015
 
2014
 
Book
Value
 
Approximate
Fair Value
 
Book
Value
 
Approximate
Fair Value
 
(in millions)
Note receivable, noncurrent (a)
$
71

 
$
71

 
$
71

 
$
71

Long-term debt, including current maturities (b)
13,567

 
13,891

 
13,060

 
14,446

__________
(a)
Included within Investments in and Loans to Unconsolidated Affiliates.
(b)
Excludes capital leases, unamortized items and fair value hedge carrying value adjustments.
The fair value of our long-term debt is determined based on market-based prices as described in the Level 2 valuation technique described above and is classified as Level 2.
The fair values of cash and cash equivalents, restricted cash, short-term investments, accounts receivable, notes receivable—noncurrent, accounts payable and commercial paper are not materially different from their carrying amounts because of the short-term nature of these instruments or because the stated rates approximate market rates.
During the fourth quarter of 2015, we recorded goodwill impairment charges on BC Field Services and Empress reporting units of $270 million and $63 million, respectively. See Note 11 for further discussion. There were no material adjustments to assets and liabilities measured at fair value on a nonrecurring basis in 2014.
18. Risk Management and Hedging Activities
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, the ownership of the NGL marketing operations in western Canada and processing operations associated with our U.S. pipeline assets. Exposure to interest rate risk exists as a result of the issuance of variable and fixed-rate debt and commercial paper. We are exposed to foreign currency risk from our Canadian operations. We employ established policies and procedures to manage our risks associated with these market fluctuations, which may include the use of derivatives, mostly around interest rate and commodity exposures.
DCP Midstream manages their direct exposure to market prices separate from Spectra Energy, and utilizes various risk management strategies, including the use of commodity derivatives.
Other than the commodity derivatives and interest rate swaps as described below, we did not have any significant derivatives outstanding during the year ended December 31, 2015.
Derivative Portfolio Carrying Value as of December 31, 2015
 
Maturities
in 2016
 
Maturities
in 2017
 
Maturities
in 2018
 
Maturities
in 2019
and
Thereafter
 
Total
Carrying
Value
 
(in millions)
Derivatives designated as hedging instruments
 
 
 
 
 
 
 
 
 
Interest rate swaps
$

 
$
2

 
$
12

 
$
23

 
$
37

Total derivatives designated as hedging instruments

 
2

 
12

 
23

 
37

Derivatives not designated as hedging instruments
 
 
 
 
 
 
 
 
 
Commodity derivatives
36

 
5

 

 

 
41

Total derivatives not designated as hedging instruments
36

 
5

 

 

 
41

Total derivative instruments
$
36

 
$
7

 
$
12

 
$
23

 
$
78

These amounts represent the combination of amounts presented as assets for non-cash gains on mark-to-market and hedging transactions on our Consolidated Balance Sheet and do not include any derivative positions of DCP Midstream. See Note 17 for information regarding the presentation of these derivative positions on our Consolidated Balance Sheets.

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Commodity Derivatives. Our NGL marketing operations are exposed to market fluctuations in the prices of natural gas and NGLs related to natural gas processing and marketing activities. We closely monitor the potential effects of commodity price changes and may choose to enter into contracts to protect margins for a portion of future sales and fuel expenses by using financial commodity instruments, such as swaps, forward contracts and options.
Effective January 2014, we implemented a commodity price risk management program at Western Canada Transmission & Processing’s Empress NGL business and elected to not apply cash flow hedge accounting.
At December 31, 2015, we had commodity mark-to-market derivatives outstanding with a total notional amount of 152 million gallons. The longest dated commodity derivative contract we currently have expires in 2018.
Information about our commodity derivatives that had netting or rights of offset arrangements are as follows:
 
December 31, 2015
 

Gross 
Amounts
 
Gross
Amounts
Offset
 
Net Amount Presented in the Consolidated Balance Sheets
Description
(in millions)
Assets
$
104

 
$
63

 
$
41

Liabilities
63

 
63

 

Substantially all of our commodity derivative agreements outstanding at December 31, 2015 have provisions that require collateral to be posted in the amount of the net liability position if one of our credit ratings falls below investment grade.
Information regarding the impacts of commodity derivatives on our Consolidated Statements of Operations is as follows:
Derivatives
 
Consolidated Statements of Operations Caption
 
2015
 
2014
 
2013
 
 
 
 
(in millions)
Commodity derivatives
 
Sales of natural gas liquids
 
$
40

 
$
93

 
$

Interest Rate Swaps. Changes in interest rates expose us to risk 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.
For interest rate derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk is included in Interest Expense on the Consolidated Statements of Operations. There were no significant amounts of gains or losses, either effective or ineffective, recognized in net income or other comprehensive income in 2015, 2014 or 2013.
At December 31, 2015, we had “pay floating — receive fixed” interest rate swaps outstanding with a total notional amount of $2,000 million to hedge against changes in the fair value of our fixed-rate debt that arise as a result of changes in market interest rates. These swaps also allow us to transform a portion of the underlying interest payments related to our long-term fixed-rate debt securities into variable-rate interest payments in order to achieve our desired mix of fixed and variable-rate debt.
Information about our interest rate swaps that had netting or rights of offset arrangements are as follows:
 
December 31, 2015
 
December 31, 2014
 
Gross Amounts
Presented in
the Consolidated
Balance Sheets
 
Amounts Not
Offset in the
Consolidated
Balance Sheets
 
Net
Amount
 
Gross Amounts
Presented in
the Consolidated
Balance Sheets
 
Amounts Not
Offset in the
Consolidated
Balance Sheets
 
Net
Amount
Description
(in millions)
Assets
$
37

 
$

 
$
37

 
$
24

 
$

 
$
24

Foreign Currency Risk. We are exposed to foreign currency risk from investments and operations in Canada. 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.

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Credit Risk. Our principal customers for natural gas transmission and crude oil transportation, storage and gathering and processing services are industrial end-users, marketers, exploration and production companies, local distribution companies and utilities located throughout the U.S. and Canada. 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. 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.
19. Commitments and Contingencies
General Insurance
We carry, either directly or through our captive insurance companies, insurance coverages consistent with companies engaged in similar commercial operations with similar type properties. Our insurance program includes (1) commercial general and excess liability insurance for liabilities to third parties for bodily injury and property damage resulting from our operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage; (4) insurance policies in support of the indemnification provisions of our by-laws; and (5) property insurance, including machinery breakdown, on an all-risk-replacement valued basis, onshore business interruption and extra expense. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations.
Environmental
We are subject to various U.S. federal, state and local laws and regulations, as well as Canadian federal and provincial laws, regarding air and water quality, hazardous and solid waste disposal and other environmental matters. These laws and regulations can change from time to time, imposing new obligations on us.
Like others in the energy industry, we and our affiliates are responsible for environmental remediation at various contaminated sites. These include some properties that are part of our ongoing operations, sites formerly owned or used by us, and sites owned by third parties. Remediation typically involves management of contaminated soils and may involve groundwater remediation. Managed in conjunction with relevant federal, state/provincial and local agencies, activities vary with site conditions and locations, remedial requirements, complexity and sharing of responsibility. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, we or our affiliates could potentially be held responsible for contamination caused by other parties. In some instances, we may share liability associated with contamination with other potentially responsible parties, and may also benefit from contractual indemnities that cover some or all cleanup costs. All of these sites generally are managed in the normal course of business or affiliated operations. We believe that there are no matters outstanding that upon resolution will have a material effect on our consolidated results of operations, financial position or cash flows.
Included in Deferred Credits and Other Liabilities—Regulatory and Other on the Consolidated Balance Sheets are undiscounted liabilities related to extended environmental-related activities totaling $8 million as of December 31, 2015 and $10 million as of December 31, 2014. These liabilities represent provisions for costs associated with remediation activities at some of our current and former sites, as well as other environmental contingent liabilities.
Litigation
Litigation and Legal Proceedings. We are involved in legal, tax and regulatory proceedings in various forums arising in the ordinary course of business, including matters regarding contract and payment claims, some of which involve substantial monetary amounts. We have insurance coverage for certain of these losses should they be incurred. We believe that the final disposition of these proceedings will not have a material effect on our consolidated results of operations, financial position or cash flows.
Legal costs related to the defense of loss contingencies are expensed as incurred. We had no material reserves for legal matters recorded as of December 31, 2015 or 2014 related to litigation.
Other Commitments and Contingencies
See Note 20 for a discussion of guarantees and indemnifications.

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Operating Lease Commitments
We lease assets in various areas of our operations. Consolidated rental expense for operating leases classified in Operating Income was $47 million in 2015 and $38 million for both 2014 and 2013, which is included in Operating, Maintenance and Other on the Consolidated Statements of Operations. The following is a summary of future minimum lease payments under operating leases which at inception had noncancellable terms of more than one year. We had no material capital lease commitments as of December 31, 2015 or 2014.
 
Long-term
Operating
Leases
 
(in millions)
2016
$
49

2017
41

2018
39

2019
35

2020
31

Thereafter
139

Total future minimum lease payments
$
334

20. Guarantees and Indemnifications
We have various financial guarantees and indemnifications which are issued in the normal course of business. As discussed below, these contracts include financial guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. We enter into these arrangements to facilitate a commercial transaction with a third party by enhancing the value of the transaction to the third party. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on our Consolidated Balance Sheets. The possibility of having to perform under these guarantees and indemnifications is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events.
We have issued performance guarantees to customers and other third parties that guarantee the payment and performance of other parties, including certain non-100%-owned entities. In connection with our spin-off from Duke Energy Corporation (Duke Energy) in 2007, certain guarantees that were previously issued by us were assigned to, or replaced by, Duke Energy as guarantor in 2006. For any remaining guarantees of other Duke Energy obligations, Duke Energy has indemnified us against any losses incurred under these guarantee arrangements. The maximum potential amount of future payments we could have been required to make under these performance guarantees as of December 31, 2015 was approximately $406 million, which has been indemnified by Duke Energy as discussed above. One of these outstanding performance guarantees, which has a maximum potential amount of future payment of $201 million, expires in 2028. The remaining guarantees have no contractual expirations.
We have also issued joint and several guarantees to some of the Duke/Fluor Daniel (D/FD) project owners, guaranteeing the performance of D/FD under its engineering, procurement and construction contracts and other contractual commitments in place at the time of our spin-off from Duke Energy. D/FD is one of the entities transferred to Duke Energy in connection with our spin-off. Substantially all of these guarantees have no contractual expiration and no stated maximum amount of future payments that we could be required to make. Fluor Enterprises Inc., as 50% owner in D/FD, issued similar joint and several guarantees to the same D/FD project owners.
Westcoast, a 100%-owned subsidiary, has issued performance guarantees to third parties guaranteeing the performance of unconsolidated entities, such as equity method investments, and of entities previously sold by Westcoast to third parties. Those guarantees require Westcoast to make payment to the guaranteed third party upon the failure of such unconsolidated or sold entity to make payment under some of its contractual obligations, such as debt agreements, purchase contracts and leases. Certain guarantees that were previously issued by Westcoast for obligations of entities that remained a part of Duke Energy are considered guarantees of third party performance; however, Duke Energy has indemnified us against any losses incurred under these guarantee arrangements.
We have entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These agreements typically cover environmental, litigation and other matters, as well as breaches of representations, warranties and covenants. Typically, claims may be made by third parties for various periods of time, depending on the nature of the claim. Our potential exposure under these indemnification agreements can range from a specified amount, such as the purchase price, to an unlimited dollar amount, depending on the

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nature of the claim and the particular transaction. We are unable to estimate the total potential amount of future payments under these indemnification agreements due to several factors, such as the unlimited exposure under certain guarantees.
As of December 31, 2015, the amounts recorded for the guarantees and indemnifications described above are not material, both individually and in the aggregate.
21. Effects of Changes in Noncontrolling Interests Ownership
The following table presents the effects of changes in our ownership interests in non-100%-owned consolidated subsidiaries:
 
2015
 
2014
 
2013
 
(in millions)
Net income—controlling interests
$
196

 
$
1,082

 
$
1,038

Increase (decrease) in additional paid-in capital resulting from issuances/retirements of SEP units (a)
(105
)
 
49

 
42

Total net income—controlling interests and changes in equity—controlling interests
$
91

 
$
1,131

 
$
1,080

________________
(a)
See Note 2 for further discussion.
22. Stock-Based Compensation
The Spectra Energy Corp 2007 Long-Term Incentive Plan (the 2007 LTIP), as amended and restated, provides for the granting of stock options, restricted and unrestricted stock awards and units, and other equity-based awards, to employees and other key individuals who perform services for us. A maximum of 40 million shares of common stock may be awarded under the 2007 LTIP.
Restricted, performance and phantom awards granted under the 2007 LTIP typically become 100% vested on the three-year anniversary of the grant date. Equity-classified and liability-classified stock-based compensation cost is measured at the grant date based on the fair value of the award. Liability-classified stock-based compensation cost is re-measured at each reporting period until settlement. Related compensation expense is recognized over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award becomes vested, the date the employee becomes retirement-eligible, or the date the market or performance condition is met.
Options granted under the 2007 LTIP are issued with exercise prices equal to the fair market value of our common stock on the grant date, have ten-year terms and generally vest over a three-year term. Compensation expense related to stock options is recognized over the requisite service period. The requisite service period for stock options is the same as the vesting period, with the exception of retirement eligible employees, who have shorter requisite service periods ending when the employees become retirement eligible. We issue new shares upon exercising or vesting of share-based awards. The Black-Scholes option-pricing model is used to estimate the fair value of options at grant date. All outstanding stock options are fully vested, and as a result, we do not expect to recognize future compensation costs related to these stock options.
We recorded pre-tax stock-based compensation expense as follows, the components of which are described further below:
 
2015
 
2014
 
2013
 
(in millions)
Phantom awards
$
11

 
$
14

 
$
13

Performance awards
18

 
13

 
33

Total
$
29

 
$
27

 
$
46

The tax benefit in Net Income associated with the recorded stock-based compensation expense was $7 million in both 2015 and 2014, and $8 million 2013. We recognized tax benefits from stock-based compensation cost of approximately $1 million in 2015, $3 million in 2014 and $5 million in 2013 in Additional Paid-in Capital.

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Awards Activity
 
Performance Awards
 
Phantom Awards
 
Units
 
Weighted
Average
Grant
Date Fair
Value
 
Units
 
Weighted
Average
Grant
Date Fair
Value
 
(thousands)
 
 
 
(thousands)
 
 
Outstanding at December 31, 2014
1,775

 
$
35

 
1,281

 
$
33

Granted
564

 
48

 
395

 
36

Vested
(2
)
 
41

 
(428
)
 
31

Forfeited
(635
)
 
22

 
(36
)
 
30

Outstanding at December 31, 2015
1,702

 
39

 
1,212

 
28

Awards expected to vest
1,608

 
39

 
1,176

 
28

Performance Awards
Under the 2007 LTIP, we can also grant stock-based performance awards. The performance awards generally vest over three years at the earliest, if performance metrics are met. The liability-classified awards will be settled in cash at vesting. We granted 564,300 equity-classified awards during 2015, 557,100 during 2014 and 356,600 during 2013, with fair values of $27 million in 2015, $26 million in 2014 and $13 million in 2013. We did not grant liability-classified awards during 2015 or 2014; however, we granted 343,700 during 2013, with a fair value of $13 million. Of the unvested and outstanding performance awards granted, 1,689,640 awards contain market conditions based on the total shareholder return of Spectra Energy common stock relative to a pre-defined peer group, and 12,900 awards contain performance conditions based on EBITDA performance of one subsidiary company. The equity-classified and liability-classified awards with market conditions are valued using the Monte Carlo valuation method. The liability-classified awards are remeasured at each reporting period until settlement.
Weighted-Average Assumptions for Stock-Based Performance Awards
 
2015
 
2014
 
2013
Risk-free rate of return
1.1%
 
0.7%
 
0.4%
Expected life
3 years
 
3 years
 
3 years
Expected volatility—Spectra Energy
18%
 
20%
 
21%
Expected volatility—peer group
13%-27%
 
14%–32%
 
13%–33%
Market index (a)
N/A
 
N/A
 
16%
_________
(a)
Beginning in 2014, the valuation model was refined to use an alternate analytical approach to project future stock prices in order to improve consistency and efficiency. The improved approach does not require the use of a market index assumption to determine the future stock price used in the valuation model. As such, the volatility of the market index assumption will not be presented going forward. Based on our assessment, it was determined that this refinement did not have a significant impact on the fair value of the shares for all periods presented.
The risk-free rate of return was determined based on a yield of three-year U.S. Treasury bonds on the grant date. The expected volatility was established based on historical volatility over three years using daily stock price observations. Because the award payout includes dividend equivalents, no dividend yield assumption is required.
The total fair value of the shares vested was less than $1 million in 2015, $20 million in 2014 and $19 million in 2013. As of December 31, 2015, we expect to recognize $26 million of future compensation cost related to outstanding performance awards over a weighted-average period of less than one year.
Phantom Awards
Under the 2007 LTIP, we can also grant stock-based phantom awards. The phantom awards generally vest over three years. The liability-classified awards will be settled in cash at vesting. We awarded 39,200 equity-classified awards to our employees in 2015, 101,500 in 2014 and 474,500 in 2013, with fair values of $1 million, $4 million and $14 million, respectively. We awarded 356,100 liability-classified awards to our employees in 2015 and 353,000 in 2014, with fair values of $13 million for both 2015 and 2014. The liability-classified awards are remeasured at each reporting period until settlement.

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The total fair value of the shares vested was $13 million in 2015, $11 million in 2014 and $14 million in 2013. As of December 31, 2015, we expect to recognize $12 million of future compensation cost related to phantom awards over a weighted-average period of less than two years.
Stock Option Activity
 
Options
 
Weighted-
Average
Exercise
Price
 
Weighted-
Average
Remaining
Life
 
Aggregate
Intrinsic
Value
 
(in thousands)
 
 
 
(in years)
 
(in millions)
Outstanding at December 31, 2014
1,102

 
$
25

 
2.0
 
$
12

Exercised
(134
)
 
23

 
 
 
 
Forfeited or expired
(10
)
 
23

 
 
 
 
Outstanding at December 31, 2015
958

 
26

 
1.2
 

Exercisable at December 31, 2015
958

 
26

 
1.2
 

We did not award any non-qualified stock options to employees during 2015, 2014 or 2013.
The total intrinsic value of options exercised was $1 million in 2015, $6 million in 2014 and $21 million in 2013. Cash received by us from options exercised was $3 million in 2015, $11 million in 2014 and $43 million in 2013. All stock options are fully vested, and as a result, we do not expect to recognize future compensation costs related to these stock options.
23. Employee Benefit Plans
Retirement Plans. We have a qualified non-contributory defined benefit (DB) retirement plan for U.S. employees (U.S. Qualified Pension Plan). This plan covers U.S. employees using a cash balance formula. Under a cash balance formula, a plan participant accumulates a retirement benefit consisting of pay credits that are based upon a percentage (which may vary with age and years of service) of current eligible earnings and current interest credits.
We also maintain non-qualified, non-contributory, unfunded defined benefit plans (U.S. Non-Qualified Pension Plans) which cover certain current and former U.S. executives. The U.S. Non-Qualified Pension Plans have no plan assets. There are other non-qualified plans such as savings and deferred compensation plans which cover certain current and former U.S. executives. Pursuant to trust agreements, Spectra Energy has set aside funds for certain of the above non-qualified plans in several trusts. Although these funds are restrictive in nature, they remain a component of our general assets and are subject to the claims of creditors. These trust funds totaling $18 million as of December 31, 2015 and $17 million as of December 31, 2014, invested in money market funds and valued using a Level 1 hierarchy level, are considered AFS securities and are classified as Investments and Other Assets—Other on the Consolidated Balance Sheets.
In addition, our Westcoast subsidiary maintains qualified and non-qualified, contributory and non-contributory DB (Canadian Qualified Pension Plan and Canadian Non-Qualified Pension Plan, respectively) and defined contribution (Canadian DC) retirement plans covering substantially all employees of our Canadian operations. The DB plans provide retirement benefits based on each plan participant’s years of service and final average earnings. Under the Canadian DC plan, company contributions are determined according to the terms of the plan and based on each plan participant’s age, years of service and current eligible earnings. We also provide non-qualified DB supplemental pensions to all employees who retire under a DB qualified pension plan and whose pension is limited by the maximum pension limits under the Income Tax Act (Canada). We report our Canadian benefit plans separate from the U.S. plans due to differences in actuarial assumptions.
Our policy is to fund our retirement plans, where applicable, on an actuarial basis to provide assets sufficient to meet benefits to be paid to plan participants or as required by legislation or plan terms. We made contributions to our U.S. Qualified and Non-Qualified Pension Plans of $22 million in 2015, $21 million in 2014 and $22 million in 2013. We made total contributions to our Canadian Qualified and Non-Qualified Pension Plans of $22 million in 2015, $36 million in 2014 and $80 million in 2013. Contributions of $8 million in 2015 and $9 million in both 2014 and 2013 were made to our Canadian DC plan. We anticipate that in 2016 we will make total contributions of approximately $22 million to the U.S. Qualified and Non-Qualified Pension Plans, approximately $16 million to the Canadian Qualified and Non-Qualified Pension Plans and approximately $8 million to the Canadian DC Plan.
Actuarial gains and losses are amortized over the average remaining service period of active employees. The average remaining service period of active employees covered by the U.S. Qualified and Non-Qualified Pension Plans is 11 years. The average remaining service periods of active employees covered by the Canadian Qualified and Non-Qualified Pension Plans is 11 years. We determine the market-related value of plan assets using a calculated value that recognizes changes in fair value of the plan assets over five years for the U.S. plans and over three years for the Canadian plans.

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Qualified and Non-Qualified Pension Plans
Change in Projected Benefit Obligation and Change in Fair Value of Plan Assets
 
U.S.
 
Canada
 
2015
 
2014
 
2015
 
2014
 
(in millions)
Change in Projected Benefit Obligation
 
 
 
 
 
 
 
Projected benefit obligation, beginning of period
$
586

 
$
575

 
$
1,202

 
$
1,131

Service cost
19

 
19

 
28

 
25

Interest cost
24

 
24

 
43

 
52

Actuarial loss (gain)
(18
)
 
13

 
(3
)
 
143

Participant contributions

 

 
5

 
5

Benefits paid
(40
)
 
(45
)
 
(47
)
 
(49
)
Foreign currency translation effect

 

 
(194
)
 
(105
)
Projected benefit obligation, end of period
571

 
586

 
1,034

 
1,202

Change in Fair Value of Plan Assets
 
 
 
 
 
 
 
Plan assets, beginning of period
551

 
531

 
1,050

 
1,040

Actual return on plan assets
(1
)
 
44

 
52

 
115

Benefits paid
(40
)
 
(45
)
 
(47
)
 
(49
)
Employer contributions
22

 
21

 
22

 
36

Plan participants’ contributions

 

 
5

 
5

Expected non-investment expenses

 

 
(3
)
 
(3
)
Foreign currency translation effect

 

 
(171
)
 
(94
)
Plan assets, end of period
532

 
551

 
908

 
1,050

Net amount recognized
$
(39
)
 
$
(35
)
 
$
(126
)
 
$
(152
)
Accumulated Benefit Obligation
$
549

 
$
567

 
$
967

 
$
1,123

 
 
 
 
 
 
 
 
 
U.S.
 
Canada
 
2015
 
2014
 
2015
 
2014
 
(in millions)
Net amount recognized
 
 
 
 
 
 
 
Current Liabilities - Other
$
(2
)
 
$
(2
)
 
$
(5
)
 
$
(6
)
Deferred Credits and Other Liabilities -
Regulatory and Other
(37
)
 
(33
)
 
(142
)
 
(165
)
Other Assets - Other

 

 
21

 
19

Total net amount recognized
$
(39
)
 
$
(35
)
 
$
(126
)
 
$
(152
)
The tables above include certain nonqualified pension plans that are unfunded. Those U.S. plans had projected benefit obligations of $23 million at December 31, 2015 and $22 million at December 31, 2014. Those Canadian plans had projected benefit obligations of $103 million at December 31, 2015 and $117 million at December 31, 2014.
At December 31, 2015, U.S. plans with accumulated benefit obligations in excess of plan assets had projected benefit obligations of $23 million, accumulated benefit obligations of $20 million and no plan assets. Canadian plans with accumulated benefit obligations in excess of plan assets had projected benefit obligations of $340 million, accumulated benefit obligations of $316 million and plan assets with a fair value of $215 million.

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Amounts Recognized in Accumulated Other Comprehensive Income
 
U.S.
 
Canada
 
December 31,
 
December 31,
 
2015
 
2014
 
2015
 
2014
 
(in millions)
Net actuarial loss
$
156

 
$
141

 
$
330

 
$
345

Prior service cost

 

 
5

 
6

Total amount recognized in AOCI
$
156

 
$
141

 
$
335

 
$
351

Components of Net Periodic Pension Costs
 
U.S.
 
Canada
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
 
(in millions)
Net Periodic Pension Cost
 
 
 
 
 
 
 
 
 
 
 
Service cost benefit earned
$
19

 
$
19

 
$
19

 
$
31

 
$
29

 
$
33

Interest cost on projected benefit obligation
24

 
24

 
21

 
43

 
52

 
50

Expected return on plan assets
(42
)
 
(39
)
 
(33
)
 
(65
)
 
(69
)
 
(66
)
Amortization of prior service cost

 

 

 
1

 
2

 
2

Amortization of loss
10

 
13

 
20

 
25

 
22

 
35

Net periodic pension cost
11

 
17

 
27

 
35

 
36

 
54

Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income
 
 
 
 
 
 
 
 
 
 
 
Current year actuarial loss (gain)
25

 
8

 
(69
)
 
10

 
93

 
(133
)
Amortization of actuarial loss
(10
)
 
(13
)
 
(20
)
 
(25
)
 
(22
)
 
(35
)
Amortization of prior service credit

 

 

 
(1
)
 
(2
)
 
(2
)
Total recognized in other comprehensive income
15

 
(5
)
 
(89
)
 
(16
)
 
69

 
(170
)
Total Recognized in Net Periodic Pension Cost and Other Comprehensive Income
$
26

 
$
12

 
$
(62
)
 
$
19

 
$
105

 
$
(116
)
In 2016, approximately $7 million of actuarial losses for the U.S. plans and $17 million for the Canadian plans will be amortized from AOCI on the Consolidated Balance Sheets into net periodic pension cost, and approximately $1 million of prior service credits will be amortized from AOCI into net periodic pension costs for the Canadian plans.
Assumptions Used for Pension Benefits Accounting
 
U.S.
 
Canada
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
Benefit Obligations
 
 
 
 
 
 
 
 
 
 
 
Discount rate
4.58
%
 
4.10
%
 
4.31
%
 
4.03
%
 
4.00
%
 
4.81
%
Salary increase
4.00

 
4.00

 
4.61

 
3.00

 
3.25

 
3.25

Net Periodic Benefit Cost
 
 
 
 
 
 
 
 
 
 
 
Discount rate
4.10

 
4.31

 
3.55

 
4.00

 
4.81

 
4.15

Salary increase
4.00

 
4.61

 
4.61

 
3.25

 
3.25

 
3.25

Expected long-term rate of return on plan assets
8.00

 
8.00

 
7.40

 
7.40

 
7.40

 
7.10

The discount rates used to determine the benefit obligations are the rates at which the benefit obligations could be effectively settled. The discount rates for our U.S. and Canadian plans are developed from yields on available high-quality bonds in each country and reflect each plan’s expected cash flows.
The long-term rates of return for the U.S. and Canadian plan assets as of December 31, 2015 were developed using weighted-average calculations of expected returns based primarily on future expected returns across classes considering the use of active asset managers applied against the U.S. and Canadian plans’ respective targeted asset mix.

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Qualified Pension Plan Assets
 
U.S.
 
Canada
Asset Category
Target
Allocation
 
December 31,
 
Target
Allocation
 
December 31,
2015
 
2014
 
2015
 
2014
U.S. equity securities
23
%
 
22
%
 
31
%
 
17
%
 
18
%
 
17
%
Canadian equity securities

 

 

 
25

 
24

 
25

Other equity securities
10

 
10

 
11

 
13

 
13

 
13

Fixed income securities
57

 
57

 
48

 
45

 
45

 
45

Other investments
10

 
11

 
10

 

 

 

Total
100
%
 
100
%
 
100
%
 
100
%
 
100
%
 
100
%
Pension plan assets are maintained in master trusts in both the U.S. and Canada. The investment objective of the master trusts is to achieve reasonable returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for plan participants. The asset allocation targets were set after considering the investment objective and the risk profile with respect to the trusts. Equities are held for their high expected return. Other equity and fixed income securities are held for diversification. Investments within asset classes are diversified to achieve broad market participation and reduce the effects of individual managers or investments. We regularly review our actual asset allocation and periodically rebalance our investments to the targeted allocation when considered appropriate.
The following table summarizes the fair values of pension plan assets recorded at each fair value hierarchy level, as determined in accordance with the valuation techniques described in Note 17:
 
U.S.
 
Canada
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
(in millions)
December 31, 2015
 
Cash and cash equivalents
$
2

 
$
2

 
$

 
$

 
$
3

 
$
3

 
$

 
$

Equity securities
171

 
171

 

 

 
501

 
221

 
280

 

Fixed income securities
304

 
304

 

 

 
404

 
404

 

 

Other
55

 

 

 
55

 

 

 

 

Total
$
532

 
$
477

 
$

 
$
55

 
$
908

 
$
628

 
$
280

 
$

December 31, 2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
3

 
$
3

 
$

 
$

 
$
3

 
$
3

 
$

 
$

Equity securities
233

 
233

 

 

 
576

 
342

 
234

 

Fixed income securities
262

 
262

 

 

 
471

 
471

 

 

Other
53

 

 

 
53

 

 

 

 

Total
$
551

 
$
498

 
$

 
$
53

 
$
1,050

 
$
816

 
$
234

 
$

The following presents changes in Level 3 assets that are measured at fair value on a recurring basis using significant unobservable inputs:
 
U.S.
 
2015
 
2014
 
(in millions)
Fair value, beginning of period
$
53

 
$
49

Gain (loss) included in other comprehensive income
2

 
4

Fair value, end of period
$
55

 
$
53


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Expected Benefit Payments
 
U.S.
 
Canada
 
(in millions)
2016
$
84

 
$
44

2017
49

 
47

2018
47

 
49

2019
49

 
51

2020
50

 
54

2021 – 2025
233

 
297

Other Post-Retirement Benefit Plans
U.S. Other Post-Retirement Benefits. We provide certain health care and life insurance benefits for retired employees on a contributory and non-contributory basis. Employees are eligible for these benefits if they have met age and service requirements at retirement, as defined in the plans.
These benefit costs are accrued over an employee’s active service period to the date of full benefits eligibility. Actuarial gains and losses are amortized over the average remaining service period of the active employees of 14 years. We determine the market-related value of the plan assets using a calculated value that recognizes changes in fair value of the plan assets over five years for the U.S. plans.
Canadian Other Post-Retirement Benefits. We provide health care and life insurance benefits for retired employees on a non-contributory basis for our Canadian operations predominantly under defined contribution plans. Employees are eligible for these benefits if they have met age and service requirements at retirement, as defined in the plans. The Canadian plans are not funded.
Other Post-Retirement Benefit Plans — Change in Projected Benefit Obligation and Fair Value of Plan Assets
 
U.S.
 
Canada
 
2015
 
2014
 
2015
 
2014
 
(in millions)
Change in Benefit Obligation
 
 
 
 
 
 
 
Accumulated post-retirement benefit obligation, beginning of period
$
172

 
$
184

 
$
133

 
$
133

Service cost
1

 
1

 
4

 
4

Interest cost
7

 
8

 
5

 
6

Plan participants’ contributions
3

 
2

 

 

Actuarial loss (gain)
1

 
(7
)
 
(11
)
 
7

Medicare subsidy receivable
2

 
2

 

 

Benefits paid
(20
)
 
(18
)
 
(4
)
 
(4
)
Foreign currency translation effect

 

 
(20
)
 
(13
)
Accumulated post-retirement benefit obligation, end of period
166

 
172

 
107

 
133

Change in Fair Value of Plan Assets
 
 
 
 
 
 
 
Plan assets, beginning of period
92

 
87

 

 

Actual return on plan assets
1

 
7

 

 

Benefits paid
(20
)
 
(18
)
 
(4
)
 
(4
)
Employer contributions
12

 
14

 
4

 
4

Plan participants’ contributions
3

 
2

 

 

Plan assets, end of period
88

 
92

 

 

Net amount recognized (a)
$
(78
)
 
$
(80
)
 
$
(107
)
 
$
(133
)
_______
(a)
Recognized primarily in Deferred Credits and Other Liabilities—Regulatory and Other in the Consolidated Balance Sheets.

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Other Post-Retirement Benefit Plans — Amounts Recognized in Accumulated Other Comprehensive Income
 
U.S.
 
Canada
 
December 31,
 
December 31,
 
2015
 
2014
 
2015
 
2014
 
(in millions)
Prior service credit
$

 
$

 
$
(3
)
 
$
(4
)
Net actuarial loss (gain)
3

 
(4
)
 
1

 
12

Total amount recognized in AOCI
$
3

 
$
(4
)
 
$
(2
)
 
$
8

In 2016, approximately $1 million of prior service costs will be amortized from AOCI into net periodic pension costs for the Canadian plans.
 
U.S.
 
Canada
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
 
(in millions)
Other Post-Retirement Benefit Plans — Components of Net Periodic Benefit Cost
 
 
 
 
 
 
 
 
 
 
 
Service cost benefit earned
$
1

 
$
1

 
$
1

 
$
4

 
$
4

 
$
5

Interest cost on accumulated post-retirement benefit obligation
7

 
8

 
7

 
5

 
6

 
6

Expected return on plan assets
(6
)
 
(5
)
 
(4
)
 

 

 

Amortization of prior service credit

 

 

 
(1
)
 
(1
)
 
(1
)
Amortization of loss

 
1

 
2

 

 

 

Net periodic other post-retirement benefit cost
2

 
5

 
6

 
8

 
9

 
10

Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income
 
 
 
 
 
 
 
 
 
 
 
Current year actuarial loss (gain)
7

 
(9
)
 
(18
)
 
(11
)
 
6

 
(13
)
Amortization of actuarial loss

 
(1
)
 
(2
)
 

 

 

Amortization of prior service credit

 

 

 
1

 
1

 
1

Total recognized in other comprehensive income
7

 
(10
)
 
(20
)
 
(10
)
 
7

 
(12
)
Total recognized in net periodic benefit cost and other comprehensive income
$
9

 
$
(5
)
 
$
(14
)
 
$
(2
)
 
$
16

 
$
(2
)
Other Post-Retirement Benefits Plans — Assumptions Used for Benefits Accounting
 
U.S.
 
Canada
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
Benefit Obligations
 
 
 
 
 
 
 
 
 
 
 
Discount rate
4.53
%
 
4.08
%
 
4.46
%
 
4.03
%
 
4.00
%
 
4.83
%
Salary increase
4.00

 
4.00

 
4.61

 
3.00

 
3.25

 
3.25

Net Periodic Benefit Cost
 
 
 
 
 
 
 
 
 
 
 
Discount rate
4.08

 
4.46

 
3.70

 
4.00

 
4.83

 
4.20

Salary increase
4.00

 
4.61

 
4.61

 
3.25

 
3.25

 
3.25

Expected return on plan assets
6.83

 
6.98

 
6.51

 
N/A
 
N/A
 
N/A
The discount rates used to determine the post-retirement obligations are the rates at which the benefit obligations could be effectively settled. The discount rates for our U.S. and Canadian plans are developed from yields on available high-quality bonds in each country and reflect each plan’s expected cash flows.

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Assumed Health Care Cost Trend Rates
 
U.S.
 
Canada
 
2015
 
2014
 
2015
 
2014
Health care cost trend rate assumed for next year
7.00%
 
7.00%
 
5.50%
 
6.00%
Rate to which the cost trend is assumed to decline
5.00%
 
5.00%
 
5.00%
 
5.00%
Year that the rate reaches the ultimate trend rate
2020
 
2019
 
2017
 
2017
Sensitivity to Changes in Assumed Health Care Cost Trend Rates
 
U.S.
 
Canada
 
1% Point
Increase
 
1% Point
Decrease
 
1% Point
Increase
 
1% Point
Decrease
 
(in millions)
Effect on total service and interest costs
$

 
$

 
$
1

 
$
(1
)
Effect on post-retirement benefit obligations
7

 
(6
)
 
5

 
(5
)
Other Post-Retirement Plan Assets
 
U.S.
Asset Category
December 31,
2015
 
2014
Cash and cash equivalents
3
%
 
%
Equity securities
45

 
48

Fixed income securities
46

 
47

Other assets
6

 
5

Total
100
%
 
100
%
A portion of our other post-retirement plan assets is maintained within the U.S. master trust discussed under the pension plans above. We invest other post-retirement plan assets in the Spectra Energy Corp Employee Benefits Trust (VEBA I) and the Spectra Energy Corp Post-Retirement Medical Benefits Trust (VEBA II). The investment objective of the VEBAs is to achieve sufficient returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of promoting the security of plan benefits for participants. The VEBA trusts are passively managed.
The asset allocation table above includes the other post-retirement benefit assets held in the master trusts, VEBA I and VEBA II.
The following table summarizes the fair values of the other post-retirement plan assets recorded at each fair value hierarchy level as determined in accordance with the valuation techniques described in Note 17:
 
U.S.
 
VEBA I and VEBA II Trusts
 
Master Trust
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
(in millions)
December 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
3

 
$
3

 
$

 
$

 
$

 
$

 
$

 
$

Equity securities
24

 

 
24

 

 
15

 
15

 

 

Fixed income securities
14

 

 
14

 

 
26

 
26

 

 

Other investments

 

 

 

 
5

 

 

 
5

Total
$
41

 
$
3

 
$
38

 
$

 
$
46

 
$
41

 
$

 
$
5

December 31, 2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Equity securities
$
25

 
$

 
$
25

 
$

 
$
20

 
$
20

 
$

 
$

Fixed income securities
21

 

 
21

 

 
22

 
22

 

 

Other investments

 

 

 

 
4

 

 

 
4

Total
$
46

 
$

 
$
46

 
$

 
$
46

 
$
42

 
$

 
$
4


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The following presents changes in Level 3 assets that are measured at fair value on a recurring basis using significant unobservable inputs:
 
U.S.
 
2015
 
2014
 
(in millions)
Fair value, beginning of period
$
4

 
$
4

Unrealized gain included in other comprehensive income
1

 

Fair value, end of period
$
5

 
$
4

Other Post-Retirement Benefit Plans — Payments and Receipts
We expect to make future benefit payments, which reflect expected future service, as appropriate. As our plans provide benefits that are actuarially equivalent to the benefits received by Medicare recipients, we expect to receive future subsidies under Medicare Part D. The following benefit payments and subsidies are expected to be paid (or received) over each of the next five years and thereafter.
 
Benefit Payments
 
Medicare Part D Subsidy Receipts
 
U.S.
 
Canada
 
U.S.
 
(in millions)
2016
$
16

 
$
4

 
$
(1
)
2017
15

 
4

 
(1
)
2018
15

 
4

 
(1
)
2019
15

 
4

 
(1
)
2020
14

 
5

 
(1
)
2021 – 2025
61

 
26

 
(5
)
We anticipate making no contributions to the U.S. plans and $4 million to the Canadian plans in 2016.
Retirement/Savings Plan
In addition to the retirement plans discussed above, we also have defined contribution employee savings plans available to both U.S. and Canadian employees. Employees may participate in a matching contribution where we match a certain percentage of before-tax employee contributions of up to 6% of eligible pay per pay period for U.S. employees and up to 5% of eligible pay per pay period for Canadian employees. We expensed pre-tax employer matching contributions of $15 million in 2015 and 2014, and $14 million in 2013 for U.S employees, and $13 million in 2015, 2014 and 2013 for Canadian employees.

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24. Condensed Consolidating Financial Information
Spectra Energy Corp has agreed to fully and unconditionally guarantee the payment of principal and interest under all series of notes outstanding under the Senior Indenture of Spectra Capital, a 100%-owned, consolidated subsidiary. In accordance with the Securities and Exchange Commission rules, the following condensed consolidating financial information is presented. The information shown for Spectra Energy Corp and Spectra Capital is presented utilizing the equity method of accounting for investments in subsidiaries, as required. The non-guarantor subsidiaries column represents all consolidated subsidiaries of Spectra Capital. This information should be read in conjunction with our accompanying Consolidated Financial Statements and notes thereto.
Spectra Energy Corp
Condensed Consolidating Statement of Operations
Year Ended December 31, 2015
(In millions)
 
Spectra
Energy
Corp
 
Spectra
Capital
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Total operating revenues
$

 
$

 
$
5,237

 
$
(3
)
 
$
5,234

Total operating expenses
6

 
(4
)
 
3,802

 
(3
)
 
3,801

Operating income (loss)
(6
)
 
4

 
1,435

 

 
1,433

Loss from equity investments

 

 
(290
)
 

 
(290
)
Equity in earnings of consolidated subsidiaries
161

 
573

 

 
(734
)
 

Other income and expenses, net

 
1

 
113

 

 
114

Interest expense

 
244

 
392

 

 
636

Earnings before income taxes
155

 
334

 
866

 
(734
)
 
621

Income tax expense (benefit)
(41
)
 
173

 
29

 

 
161

Net income
196

 
161

 
837

 
(734
)
 
460

Net income—noncontrolling interests

 

 
264

 

 
264

Net income—controlling interests
$
196

 
$
161

 
$
573

 
$
(734
)
 
$
196



Spectra Energy Corp
Condensed Consolidating Statement of Operations
Year Ended December 31, 2014
(In millions) 
 
Spectra
Energy
Corp
 
Spectra
Capital
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Total operating revenues
$

 
$

 
$
5,906

 
$
(3
)
 
$
5,903

Total operating expenses
6

 
1

 
3,975

 
(3
)
 
3,979

Operating income (loss)
(6
)
 
(1
)
 
1,931

 

 
1,924

Earnings from equity investments

 

 
361

 

 
361

Equity in earnings of consolidated subsidiaries
1,054

 
1,651

 

 
(2,705
)
 

Other income and expenses, net
(2
)
 
9

 
52

 

 
59

Interest expense

 
253

 
426

 

 
679

Earnings before income taxes
1,046

 
1,406

 
1,918

 
(2,705
)
 
1,665

Income tax expense (benefit)
(36
)
 
352

 
66

 

 
382

Net income
1,082

 
1,054

 
1,852

 
(2,705
)
 
1,283

Net income—noncontrolling interests

 

 
201

 

 
201

Net income—controlling interests
$
1,082

 
$
1,054

 
$
1,651

 
$
(2,705
)
 
$
1,082



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Table of Contents


Spectra Energy Corp
Condensed Consolidating Statement of Operations
Year Ended December 31, 2013
(In millions) 
 
Spectra
Energy
Corp
 
Spectra
Capital
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Total operating revenues
$

 
$

 
$
5,521

 
$
(3
)
 
$
5,518

Total operating expenses
8

 
3

 
3,844

 
(3
)
 
3,852

Operating income (loss)
(8
)
 
(3
)
 
1,677

 

 
1,666

Earnings from equity investments

 

 
445

 

 
445

Equity in earnings of consolidated subsidiaries
1,015

 
1,649

 

 
(2,664
)
 

Other income and expenses, net
1

 
15

 
108

 

 
124

Interest expense

 
216

 
441

 

 
657

Earnings before income taxes
1,008

 
1,445

 
1,789

 
(2,664
)
 
1,578

Income tax expense (benefit)
(30
)
 
430

 
19

 

 
419

Net income
1,038

 
1,015

 
1,770

 
(2,664
)
 
1,159

Net income—noncontrolling interests

 

 
121

 

 
121

Net income—controlling interests
$
1,038

 
$
1,015

 
$
1,649

 
$
(2,664
)
 
$
1,038


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Table of Contents



Spectra Energy Corp
Condensed Consolidating Statements of Comprehensive Income
(In millions)
 
Spectra
Energy
Corp
 
Spectra
Capital
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Year Ended December 31, 2015
 
 
 
 
 
 
 
 
 
Net income
$
196

 
$
161

 
$
837

 
$
(734
)
 
$
460

Other comprehensive income (loss)
(14
)
 
1

 
(931
)
 

 
(944
)
Total comprehensive income (loss), net of tax
182

 
162

 
(94
)
 
(734
)
 
(484
)
Less: comprehensive income—noncontrolling interests

 

 
251

 

 
251

Comprehensive income (loss)—controlling interests
$
182

 
$
162

 
$
(345
)
 
$
(734
)
 
$
(735
)
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2014
 
 
 
 
 
 
 
 
 
Net income
$
1,082

 
$
1,054

 
$
1,852

 
$
(2,705
)
 
$
1,283

Other comprehensive income (loss)
9

 
1

 
(596
)
 

 
(586
)
Total comprehensive income, net of tax
1,091

 
1,055

 
1,256

 
(2,705
)
 
697

Less: comprehensive income—noncontrolling interests

 

 
194

 

 
194

Comprehensive income—controlling interests
$
1,091

 
$
1,055

 
$
1,062

 
$
(2,705
)
 
$
503

 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2013
 
 
 
 
 
 
 
 
 
Net income
$
1,038

 
$
1,015

 
$
1,770

 
$
(2,664
)
 
$
1,159

Other comprehensive income (loss)
69

 
2

 
(346
)
 

 
(275
)
Total comprehensive income, net of tax
1,107

 
1,017

 
1,424

 
(2,664
)
 
884

Less: comprehensive income—noncontrolling interests

 

 
114

 

 
114

Comprehensive income—controlling interests
$
1,107

 
$
1,017

 
$
1,310

 
$
(2,664
)
 
$
770




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Table of Contents

Spectra Energy Corp
Condensed Consolidating Balance Sheet
December 31, 2015
(In millions)
 
 
Spectra
Energy
Corp
 
Spectra
Capital
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Cash and cash equivalents
$

 
$
1

 
$
212

 
$

 
$
213

Receivables—consolidated subsidiaries
15

 
6

 
13

 
(34
)
 

Notes receivable—current—consolidated subsidiaries

 

 
387

 
(387
)
 

Receivables—other
2

 

 
804

 

 
806

Other current assets
25

 

 
604

 

 
629

Total current assets
42

 
7

 
2,020

 
(421
)
 
1,648

Investments in and loans to unconsolidated affiliates

 

 
2,592

 

 
2,592

Investments in consolidated subsidiaries
13,919

 
19,161

 

 
(33,080
)
 

Advances receivable—consolidated subsidiaries

 
5,273

 
1,326

 
(6,599
)
 

Notes receivable—consolidated subsidiaries

 

 
2,800

 
(2,800
)
 

Goodwill

 

 
4,154

 

 
4,154

Other assets
41

 
27

 
242

 

 
310

Net property, plant and equipment

 

 
22,918

 

 
22,918

Regulatory assets and deferred debits
3

 
3

 
1,295

 

 
1,301

Total Assets
$
14,005

 
$
24,471

 
$
37,347

 
$
(42,900
)
 
$
32,923

 
 
 
 
 
 
 
 
 
 
Accounts payable
$
2

 
$
3

 
$
506

 
$

 
$
511

Accounts payable—consolidated subsidiaries
4

 
28

 
2

 
(34
)
 

Commercial paper

 
481

 
631

 

 
1,112

Short-term borrowings—consolidated subsidiaries

 
387

 

 
(387
)
 

Taxes accrued
5

 

 
73

 

 
78

Current maturities of long-term debt

 

 
652

 

 
652

Other current liabilities
102

 
48

 
889

 

 
1,039

Total current liabilities
113

 
947

 
2,753

 
(421
)
 
3,392

Long-term debt

 
2,891

 
10,001

 

 
12,892

Advances payable—consolidated subsidiaries
6,599

 

 

 
(6,599
)
 

Notes payable—consolidated subsidiaries

 
2,800

 

 
(2,800
)
 

Deferred credits and other liabilities
767

 
3,914

 
2,087

 

 
6,768

Preferred stock of subsidiaries

 

 
339

 

 
339

Equity
 
 
 
 
 
 
 
 
 
Controlling interests
6,526

 
13,919

 
19,161

 
(33,080
)
 
6,526

Noncontrolling interests

 

 
3,006

 

 
3,006

Total equity
6,526

 
13,919

 
22,167

 
(33,080
)
 
9,532

Total Liabilities and Equity
$
14,005

 
$
24,471

 
$
37,347

 
$
(42,900
)
 
$
32,923




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Table of Contents

Spectra Energy Corp
Condensed Consolidating Balance Sheet
December 31, 2014
(In millions)
 
 
Spectra
Energy
Corp
 
Spectra
Capital
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Cash and cash equivalents
$

 
$
1

 
$
214

 
$

 
$
215

Receivables—consolidated subsidiaries
18

 

 
11

 
(29
)
 

Receivables—other
2

 

 
1,334

 

 
1,336

Other current assets
71

 
2

 
708

 

 
781

Total current assets
91

 
3

 
2,267

 
(29
)
 
2,332

Investments in and loans to unconsolidated affiliates

 

 
2,966

 

 
2,966

Investments in consolidated subsidiaries
14,531

 
20,562

 

 
(35,093
)
 

Advances receivable—consolidated subsidiaries

 
4,683

 
898

 
(5,581
)
 

Notes receivable—consolidated subsidiaries

 

 
3,198

 
(3,198
)
 

Goodwill

 

 
4,714

 

 
4,714

Other assets
38

 
22

 
267

 

 
327

Net property, plant and equipment

 

 
22,307

 

 
22,307

Regulatory assets and deferred debits
4

 
5

 
1,343

 

 
1,352

Total Assets
$
14,664

 
$
25,275

 
$
37,960

 
$
(43,901
)
 
$
33,998

 
 
 
 
 
 
 
 
 
 
Accounts payable
$
3

 
$

 
$
455

 
$

 
$
458

Accounts payable—consolidated subsidiaries

 
17

 
12

 
(29
)
 

Commercial paper

 
398

 
1,185

 

 
1,583

Short-term borrowings—consolidated subsidiaries

 
398

 

 
(398
)
 

Taxes accrued
5

 

 
86

 

 
91

Current maturities of long-term debt

 

 
327

 

 
327

Other current liabilities
96

 
54

 
1,200

 

 
1,350

Total current liabilities
104

 
867

 
3,265

 
(427
)
 
3,809

Long-term debt

 
2,890

 
9,837

 

 
12,727

Advances payable—consolidated subsidiaries
5,581

 

 

 
(5,581
)
 

Notes payable—consolidated subsidiaries

 
2,800

 

 
(2,800
)
 

Deferred credits and other liabilities
819

 
4,187

 
1,800

 

 
6,806

Preferred stock of subsidiaries

 

 
258

 

 
258

Equity
 
 
 
 
 
 
 
 
 
Controlling interests
8,160

 
14,531

 
20,562

 
(35,093
)
 
8,160

Noncontrolling interests

 

 
2,238

 

 
2,238

Total equity
8,160

 
14,531

 
22,800

 
(35,093
)
 
10,398

Total Liabilities and Equity
$
14,664

 
$
25,275

 
$
37,960

 
$
(43,901
)
 
$
33,998



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Table of Contents

Spectra Energy Corp
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2015
(In millions)
 
Spectra
Energy
Corp
 
Spectra
Capital
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
 
 
 
 
 
 
Net income
$
196

 
$
161

 
$
837

 
$
(734
)
 
$
460

Adjustments to reconcile net income to net cash provided by (used in) operating activities:
 
 
 
 
 
 
 
 
 
Depreciation and amortization

 

 
778

 

 
778

Impairment charges

 

 
349

 

 
349

Loss from equity investments

 

 
290

 

 
290

Equity in earnings of consolidated subsidiaries
(161
)
 
(573
)
 

 
734

 

Distributions from equity investments

 

 
161

 

 
161

Other
187

 
33

 
(11
)
 

 
209

Net cash provided by (used in) operating activities
222

 
(379
)
 
2,404

 

 
2,247

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
 
 
 
 
 
 
Capital expenditures

 

 
(2,848
)
 

 
(2,848
)
Investments in and loans to unconsolidated affiliates

 

 
(124
)
 

 
(124
)
Purchases of held-to-maturity securities

 

 
(668
)
 

 
(668
)
Proceeds from sales and maturities of held-to-maturity securities

 

 
695

 

 
695

Purchases of available-for-sale securities

 

 
(95
)
 

 
(95
)
Proceeds from sales and maturities of available-for-sale securities

 

 
87

 

 
87

Distributions from equity investments

 

 
451

 

 
451

Advances (to) from affiliates
(240
)
 
296

 

 
(56
)
 

Loan to equity investment

 

 
(248
)
 

 
(248
)
Other changes in restricted funds

 

 
(33
)
 

 
(33
)
Other

 

 
1

 

 
1

Net cash provided by (used in) investing activities
(240
)
 
296

 
(2,782
)
 
(56
)
 
(2,782
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
 
 
 
 
 
 
Proceeds from the issuance of long-term debt

 

 
1,585

 

 
1,585

Payments for the redemption of long-term debt

 

 
(285
)
 

 
(285
)
Net increase (decrease) in commercial paper

 
83

 
(522
)
 

 
(439
)
Distributions to noncontrolling interests

 

 
(198
)
 

 
(198
)
Contributions from noncontrolling interests

 

 
248

 

 
248

Proceeds from the issuance of SEP common units

 

 
546

 

 
546

Proceeds from the issuance of Westcoast preferred
   stock

 

 
84

 

 
84

Dividends paid on common stock
(996
)
 

 

 

 
(996
)
Distributions and advances from (to) affiliates
1,018

 

 
(1,074
)
 
56

 

Other
(4
)
 

 
(1
)
 

 
(5
)
Net cash provided by financing activities
18

 
83

 
383

 
56

 
540

Effect of exchange rate changes on cash

 

 
(7
)
 

 
(7
)
Net decrease in cash and cash equivalents

 

 
(2
)
 

 
(2
)
Cash and cash equivalents at beginning of period

 
1

 
214

 

 
215

Cash and cash equivalents at end of period
$

 
$
1

 
$
212

 
$

 
$
213


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Table of Contents

Spectra Energy Corp
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2014
(In millions)
 
Spectra
Energy
Corp
 
Spectra
Capital
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
 
 
 
 
 
 
Net income
$
1,082

 
$
1,054

 
$
1,852

 
$
(2,705
)
 
$
1,283

Adjustments to reconcile net income to net cash provided by (used in) operating activities:
 
 
 
 
 
 
 
 
 
Depreciation and amortization

 

 
809

 

 
809

Earnings from equity investments

 

 
(361
)
 

 
(361
)
Equity in earnings of consolidated subsidiaries
(1,054
)
 
(1,651
)
 

 
2,705

 

Distributions from equity investments

 

 
380

 

 
380

Other
14

 
304

 
(208
)
 

 
110

Net cash provided by (used in) operating activities
42

 
(293
)
 
2,472

 

 
2,221

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
 
 
 
 
 
 
Capital expenditures

 

 
(2,028
)
 

 
(2,028
)
Investments in and loans to unconsolidated affiliates

 

 
(259
)
 

 
(259
)
Purchases of held-to-maturity securities

 

 
(790
)
 

 
(790
)
Proceeds from sales and maturities of held-to-maturity securities

 

 
815

 

 
815

Purchases of available-for-sale securities

 

 
(13
)
 

 
(13
)
Proceeds from sales and maturities of available-for-sale securities

 

 
7

 

 
7

Distributions from equity investments

 

 
266

 

 
266

Advances from affiliates
92

 
495

 

 
(587
)
 

Other changes in restricted funds

 

 
(1
)
 

 
(1
)
Net cash provided by (used in) investing activities
92

 
495

 
(2,003
)
 
(587
)
 
(2,003
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
 
 
 
 
 
 
Proceeds from the issuance of long-term debt

 
300

 
728

 

 
1,028

Payments for the redemption of long-term debt

 
(557
)
 
(627
)
 

 
(1,184
)
Net increase in commercial paper

 
54

 
520

 

 
574

Distributions to noncontrolling interests

 

 
(175
)
 

 
(175
)
Contributions from noncontrolling interests

 

 
145

 

 
145

Proceeds from the issuance of SEP common units

 

 
327

 

 
327

Dividends paid on common stock
(925
)
 

 

 

 
(925
)
Distributions and advances from (to) affiliates
777

 
(10
)
 
(1,354
)
 
587

 

Other
14

 

 
(3
)
 

 
11

Net cash used in financing activities
(134
)
 
(213
)
 
(439
)
 
587

 
(199
)
Effect of exchange rate changes on cash

 

 
(5
)
 

 
(5
)
Net increase (decrease) in cash and cash equivalents

 
(11
)
 
25

 

 
14

Cash and cash equivalents at beginning of period

 
12

 
189

 

 
201

Cash and cash equivalents at end of period
$

 
$
1

 
$
214

 
$

 
$
215



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Table of Contents

Spectra Energy Corp
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2013
(In millions)
 
Spectra
Energy
Corp
 
Spectra
Capital
(a)
 
Non-Guarantor
Subsidiaries
(a)
 
Eliminations
 
Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
 
 
 
 
 
 
Net income
$
1,038

 
$
1,015

 
$
1,770

 
$
(2,664
)
 
$
1,159

Adjustments to reconcile net income to net cash provided by (used in) operating activities:
 
 
 
 
 
 
 
 
 
Depreciation and amortization

 

 
787

 

 
787

Earnings from equity investments

 

 
(445
)
 

 
(445
)
Equity in earnings of consolidated subsidiaries
(1,015
)
 
(1,649
)
 

 
2,664

 

Distributions from equity investments

 

 
324

 

 
324

Other
(2
)
 
478

 
(271
)
 

 
205

Net cash provided by (used in) operating activities
21

 
(156
)
 
2,165

 

 
2,030

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
 
 
 
 
 
 
Capital expenditures

 

 
(1,947
)
 

 
(1,947
)
Investments in and loans to unconsolidated affiliates

 

 
(312
)
 

 
(312
)
Acquisitions, net of cash acquired

 

 
(1,254
)
 

 
(1,254
)
Purchases of held-to-maturity securities

 

 
(985
)
 

 
(985
)
Proceeds from sales and maturities of held-to-maturity securities

 

 
1,023

 

 
1,023

Purchases of available-for-sale securities

 

 
(5,878
)
 

 
(5,878
)
Proceeds from sales and maturities of available-for-sale securities

 

 
6,024

 

 
6,024

Distributions from equity investments

 

 
87

 

 
87

Advances to affiliates
(75
)
 
(1,856
)
 

 
1,931

 

Loan to equity investment

 

 
(71
)
 

 
(71
)
Repayment of loan to equity investment

 
71

 

 

 
71

Other changes in restricted funds

 

 
2

 

 
2

Other

 

 
4

 

 
4

Net cash used in investing activities
(75
)
 
(1,785
)
 
(3,307
)
 
1,931

 
(3,236
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
 
 
 
 
 
 
Proceeds from the issuance of long-term debt

 
1,848

 
2,524

 

 
4,372

Payments for the redemption of long-term debt

 
(1,944
)
 
(195
)
 

 
(2,139
)
Net decrease in commercial paper

 
(170
)
 
(36
)
 

 
(206
)
Net increase in short-term borrowings - consolidated subsidiaries

 
(497
)
 

 
497

 

Distributions to noncontrolling interests

 

 
(144
)
 

 
(144
)
Contributions from noncontrolling interests

 

 
23

 

 
23

Proceeds from the issuance of SEP common units

 

 
214

 

 
214

Dividends paid on common stock
(821
)
 

 

 

 
(821
)
Distributions and advances from (to) affiliates
847

 
2,718

 
(1,137
)
 
(2,428
)
 

Other
28

 
(5
)
 
(6
)
 

 
17

Net cash provided by financing activities
54

 
1,950

 
1,243

 
(1,931
)
 
1,316

Effect of exchange rate changes on cash

 

 
(3
)
 

 
(3
)
Net increase in cash and cash equivalents

 
9

 
98

 

 
107

Cash and cash equivalents at beginning of period

 
3

 
91

 

 
94

Cash and cash equivalents at end of period
$

 
$
12

 
$
189

 
$

 
$
201

____________
(a)
Excludes the effects of $3,869 million of non-cash equitizations of advances receivable owed to Spectra Capital.

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Table of Contents

25. Quarterly Financial Data (Unaudited)
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 
Total
 
(in millions, except per share amounts)
2015
 
 
 
 
 
 
 
 
 
Operating revenues
$
1,623

 
$
1,192

 
$
1,103

 
$
1,316

 
$
5,234

Operating income
541

 
406

 
389

 
97

 
1,433

Net income (loss)
325

 
80

 
243

 
(188
)
 
460

Net income (loss)—controlling interests
267

 
18

 
174

 
(263
)
 
196

Earnings (loss) per share (a)
 
 
 
 
 
 
 
 
 
Basic and diluted
0.40

 
0.03

 
0.26

 
(0.39
)
 
0.29

2014
 
 
 
 
 
 
 
 
 
Operating revenues
$
1,843

 
$
1,253

 
$
1,207

 
$
1,600

 
$
5,903

Operating income
639

 
338

 
382

 
565

 
1,924

Net income
467

 
188

 
254

 
374

 
1,283

Net income—controlling interests
419

 
146

 
201

 
316

 
1,082

Earnings per share (a)
 
 
 
 
 
 
 
 
 
Basic
0.63

 
0.22

 
0.30

 
0.47

 
1.61

Diluted
0.62

 
0.22

 
0.30

 
0.47

 
1.61

___________
(a)
Quarterly earnings-per-share amounts are stand-alone calculations and may not be additive to full-year amounts due to rounding.
Unusual or Infrequent Items
Due to the significant downturn in commodity prices, DCP Midstream performed a goodwill impairment test and other asset impairment tests in 2015. The impairment tests resulted in DCP Midstream’s recognition of a $460 million goodwill impairment and $342 million in other asset impairments, net of tax, which reduced our equity earnings from DCP Midstream by $231 million after-tax for 2015. Due to the asset impairment recognized by DCP Midstream, we assessed our equity investment in DCP Midstream and determined that our equity investment in DCP Midstream was not impaired.
During the fourth quarter of 2015, we recorded goodwill impairments associated with the acquisition of Westcoast in 2002 for BC Field Services and the Empress NGL Operations, which impacted net income by $270 million and $63 million, respectively. The impairments are included in Impairment of Goodwill and Other on the Consolidated Statement of Operations. See Note 11 for further discussion.



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SPECTRA ENERGY CORP
SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
 
Balance at
Beginning
of Period
 
Additions:
 
Deductions (a)
 
Balance at
End of
Period
Charged to
Expense
 
Charged to
Other
Accounts
 
 
(in millions)
December 31, 2015
 
 
 
 
 
 
 
 
 
Allowance for doubtful accounts
$
11

 
$
7

 
$

 
$
7

 
$
11

Other (b)
113

 
36

 
24

 
39

 
134

 
$
124

 
$
43

 
$
24

 
$
46

 
$
145

December 31, 2014
 
 
 
 
 
 
 
 
 
Allowance for doubtful accounts
$
10

 
$
6

 
$

 
$
5

 
$
11

Other (b)
164

 
29

 

 
80

 
113

 
$
174

 
$
35

 
$

 
$
85

 
$
124

December 31, 2013
 
 
 
 
 
 
 
 
 
Allowance for doubtful accounts
$
13

 
$
7

 
$

 
$
10

 
$
10

Other (b)
181

 
21

 

 
38

 
164

 
$
194

 
$
28

 
$

 
$
48

 
$
174

_________
(a)
Principally cash payments and reserve reversals.
(b)
Principally income tax, insurance-related, litigation and other reserves, included primarily in Deferred Credits and Other Liabilities—Regulatory and Other on the Consolidated Balance Sheets.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized, and reported within the time periods specified by the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2015, and based upon this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended December 31, 2015 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

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Table of Contents

Management’s Annual Report on Internal Control over Financial Reporting
The report of management required under this Item 9A. is contained in Item 8. Financial Statements and Supplementary Data, Management’s Annual Report on Internal Control over Financial Reporting.
Attestation Report of Independent Registered Public Accounting Firm
The attestation report required under this Item 9A. is contained in Item 8. Financial Statements and Supplementary Data, Report of Independent Registered Public Accounting Firm.
Item 9B. Other Information.
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance.
Reference to “Executive Officers” is included in “Part I. Item 1. Business” of this report. Other information in response to this item is incorporated by reference from our Proxy Statement relating to our 2016 annual meeting of shareholders.
Item 11. Executive Compensation.
Information in response to this item is incorporated by reference from our Proxy Statement relating to our 2016 annual meeting of shareholders.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
Information in response to this item is incorporated by reference from our Proxy Statement relating to our 2016 annual meeting of shareholders.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Information in response to this item is incorporated by reference from our Proxy Statement relating to our 2016 annual meeting of shareholders.
Item 14. Principal Accounting Fees and Services.
Information in response to this item is incorporated by reference from our Proxy Statement relating to our 2016 annual meeting of shareholders.

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Table of Contents

PART IV
Item 15. Exhibits, Financial Statement Schedules.
(a) Consolidated Financial Statements, Supplemental Financial Data and Supplemental Schedules included in Part II of this annual report are as follows:
Spectra Energy Corp:
Report of Independent Registered Accounting Firm
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Income
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Consolidated Statements of Equity
Notes to Consolidated Financial Statements
Consolidated Financial Statement Schedule II—Valuation and Qualifying Accounts and Reserves
Separate Financial Statements of Subsidiaries not Consolidated Pursuant to Rule 3-09 of Regulation S-X:
DCP Midstream, LLC:
Independent Auditors’ Report
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Income
Consolidated Statements of Cash Flows
Consolidated Statements of Changes in Equity
Notes to Consolidated Financial Statements
All other schedules are omitted because they are not required or because the required information is included in the Consolidated Financial Statements or Notes.
(c) Exhibits—See Exhibit Index immediately following the signature page.

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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: February 25, 2016
 
SPECTRA ENERGY CORP
 
 
 
By:
 
                  /s/ Gregory L. Ebel
 
 
Gregory L. Ebel
Chairman, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
 
Gregory L. Ebel*
Chairman of the Board of Directors, President and Chief Executive Officer (Principal Executive Officer and Director)
J. Patrick Reddy*
Chief Financial Officer (Principal Financial Officer)
Allen C. Capps*
Vice President and Controller (Principal Accounting Officer)
Austin A. Adams*
Director
Joseph Alvarado*
Director
Pamela L. Carter*
Director
Clarence P. Cazalot, Jr*
Director
F. Anthony Comper*
Lead Director
Peter B. Hamilton*
Director
Miranda C. Hubbs*
Director
Michael McShane*
Director
Michael G. Morris*
Director
Michael E.J. Phelps*
Director
Date: February 25, 2016
J. Patrick Reddy, by signing his name hereto, does hereby sign this document on behalf of the registrant and on behalf of each of the above-named persons previously indicated by asterisk pursuant to a power of attorney duly executed by the registrant and such persons, filed with the Securities and Exchange Commission as an exhibit hereto.
 
By:
 
                  /s/    J. Patrick Reddy        
 
 
J. Patrick Reddy
Attorney-In-Fact

125


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EXHIBIT INDEX
 
Exhibit No.
 
Exhibit Description
2.1
 
Separation and Distribution Agreement by and between Duke Energy Corporation and Spectra Energy Corp, dated as of December 13, 2006 (filed as Exhibit No. 2.1 to Form 8-K of Spectra Energy Corp on December 15, 2006).
2.2
 
Reorganization Agreement by and among ConocoPhillips, Duke Capital LLC and DCP Midstream, LLC, dated as of May 26, 2005 (filed as Exhibit No. 10.4 to Form 10-Q of Duke Energy Corporation for the quarter ended June 30, 2005, File No. 1-4928).
2.2.1
 
First Amendment to Reorganization Agreement by and among ConocoPhillips, Duke Capital LLC and DCP Midstream, LLC, dated as of June 30, 2005 (filed as Exhibit No. 10.4.1 to Form 10-Q of Duke Energy Corporation for the quarter ended June 30, 2005).
2.2.2
 
Second Amendment to Reorganization Agreement by and among ConocoPhillips, Duke Capital LLC and DCP Midstream, LLC, dated as of July 11, 2005 (filed as Exhibit No. 10.4.2 to Form 10-Q of Duke Energy Corporation for the quarter ended June 30, 2005).
2.3
 
Amended and Restated Combination Agreement, dated as of September 20, 2001, among Duke Energy Corporation, 3058368 Nova Scotia Company, 3946509 Canada Inc. and Westcoast Energy Inc. (filed as Exhibit No. 10.7 to Form 10-Q of Duke Energy Corporation for the quarter ended September 30, 2001).
2.4
 
Spectra Energy Support Agreement dated as of January 1, 2007, between Spectra Energy Corp, Duke Energy Canada Call Co. and Duke Energy Canada Exchangeco Inc. (filed as Exhibit No. 2.2 to Form S-3 of Spectra Energy Corp on January 17, 2007).
2.5
 
Spectra Energy Voting and Exchange Trust Agreement dated as of January 1, 2007, between Spectra Energy Corp, Duke Energy Canada Exchangeco Inc. and Computershare Trust Company, Inc. (filed as Exhibit No. 2.3 to Form S-3 of Spectra Energy Corp on January 17, 2007).
2.6
 
Plan of Arrangement, as approved by the Supreme Court of British Columbia by final order dated December 15, 2006 (filed as Exhibit No. 2.4 to Form S-3 of Spectra Energy Corp on January 17, 2007).
2.7
 
Securities Purchase Agreement by and among BPC Penco Corporation, Kinder Morgan Energy Partners, L.P., Ontario Teachers’ Pension Plan Board, Blackhawk Holdings Trust, 2349466 (U.S.) Grantor Trust, Express US Holdings LP, Express Holdings (Canada) Limited Partnership and 6048935 Canada Inc, dated as of December 10, 2012 (filed as Exhibit No. 2.1 to Form 8-K of Spectra Energy Corp on December 11, 2012).
2.8
 
Contribution Agreement by and between Spectra Energy Corp and Spectra Energy Partners, LP, dated as of August 5, 2013 (filed as Exhibit No. 2.1 to Form 8-K of Spectra Energy Corp on August 6, 2013).
2.8.1
 
First Amendment to Contribution Agreement by and between Spectra Energy Corp and Spectra Energy Partners, LP, dated as of October 31, 2013 (filed as Exhibit No. 2.1 to Form 8-K of Spectra Energy Corp on November 1, 2013).
2.9
 
Exchange and Redemption Agreement by and between Spectra Energy Corp and Spectra Energy Partners, LP dated as of October 18, 2015 (filed as Exhibit No. 2.1 to Form 8-K of Spectra Energy Corp on October 19, 2015).
2.10
 
Contribution Agreement by and among Phillips Gas Company, Spectra Energy DEFS Holding, LLC, Spectra Energy DEFS Holding II, LLC and DCP Midstream, LLC and, solely for the limited purposes set forth therein, Phillips 66 and Spectra Energy Corp, dated as of October 18, 2015 (filed as Exhibit No. 2.2 to Form 8-K of Spectra Energy Corp on October 19, 2015).
3.1
 
Amended and Restated Certificate of Incorporation of Spectra Energy Corp (filed as Exhibit No. 3.1 to Form 8-K of Spectra Energy Corp on December 15, 2006).
3.1.1
 
Certificate of Amendment to the Amended and Restated Certificate of Incorporation of Spectra Energy Corp (filed as Exhibit No. 3.1 to Form 8-K of Spectra Energy Corp on May 7, 2012).
3.2
 
The By-Laws of Spectra Energy Corp, as amended and restated on November 4, 2015 (filed as Exhibit No. 3.1 to Form 8-K of Spectra Energy Corp on November 5, 2015).
4.1
 
Senior Indenture between Duke Capital Corporation and The Chase Manhattan Bank, dated as of April 1, 1998 (filed as Exhibit No. 4.1 to Form S-3 of Duke Capital Corporation on April 1, 1998, File No. 333-71297).
4.2
 
First Supplemental Indenture, dated July 20, 1998, between Duke Capital Corporation and The Chase Manhattan Bank (filed as Exhibit No. 4.2 to Form 10-K of Duke Capital Corporation on March 16, 2004).
4.3
 
Second Supplemental Indenture, dated September 28, 1999, between Duke Capital Corporation and The Chase Manhattan Bank (filed as Exhibit No. 4.3 to Form 10-K of Duke Capital Corporation on March 16, 2004).


Table of Contents

Exhibit No.
 
Exhibit Description
4.4
  
Fifth Supplemental Indenture, dated February 15, 2002, between Duke Capital Corporation and JPMorgan Chase Bank (filed as Exhibit No. 4.6 to Form 10-K of Duke Capital Corporation on March 16, 2004).
4.5
  
Ninth Supplemental Indenture, dated February 20, 2004, between Duke Capital Corporation and JPMorgan Chase Bank (filed as Exhibit No. 4.10 to Form 10-K of Duke Capital Corporation on March 16, 2004).
4.6
  
Eleventh Supplemental Indenture, dated August 19, 2004, between Duke Capital LLC and JPMorgan Chase Bank (filed as Exhibit No. 4.6 to Form S-3 of Spectra Energy Corp and Spectra Energy Capital, LLC on March 26, 2008, File No. 333-141982).
4.7
  
Twelfth Supplemental Indenture, dated December 14, 2007, among Spectra Energy Capital, LLC, Spectra Energy Corp and The Bank of New York (filed as Exhibit No. 10.1 to Form 8-K of Spectra Energy Corp on December 20, 2007).
4.8
  
Thirteenth Supplemental Indenture, dated as of April 10, 2008, between Spectra Energy Capital, LLC, Spectra Energy Corp and The Bank of New York Trust Company, N.A. (filed as Exhibit No. 4.1 to Form 8-K on April 10, 2008).
4.9
  
Fourteenth Supplemental Indenture, dated as of September 8, 2008, between Spectra Energy Capital, LLC, Spectra Energy Corp and The Bank of New York Mellon Trust Company, N.A. (filed as Exhibit No. 4.1 to Form 8-K on September 9, 2008).
4.10
  
Indenture, dated May 14, 2009, between Maritimes & Northeast Pipeline, LLC and Deutsche Bank Trust Company Americas (filed as Exhibit No. 4.1 to Form 10-Q of Spectra Energy Corp for the quarter ended June 30, 2009).
4.11
  
First Supplemental Indenture, dated May 14, 2009, between Maritimes & Northeast Pipeline, LLC and Deutsche Bank Trust Company Americas (filed as Exhibit No. 4.2 to Form 10-Q of Spectra Energy Corp for the quarter ended June 30, 2009).
4.12
  
Fifteenth Supplemental Indenture, dated as of August 28, 2009, between Spectra Energy Capital, LLC, Spectra Energy Corp and The Bank of New York Mellon Trust Company, N.A. (filed as Exhibit No. 4.1 to Form 8-K on August 28, 2009).
4.13
 
Sixteenth Supplemental Indenture, dated as of February 28, 2013, between Spectra Energy Capital, LLC, Spectra Energy Corp and The Bank of New York Mellon Trust Company, N.A. (filed as Exhibit No. 4.1 to Form 8-K on February 28, 2013).
10.1
  
Tax Matters Agreement by and among Duke Energy Corporation, Spectra Energy Corp, and The Other Spectra Energy Parties, dated as of December 13, 2006 (filed as Exhibit No. 10.1 to Form 10-Q of Spectra Energy Corp for the quarter ended June 30, 2009).
10.2
  
Employee Matters Agreement by and between Duke Energy Corporation and Spectra Energy Corp, dated as of December 13, 2006 (filed as Exhibit No. 10.3 to Form 10-Q of Spectra Energy Corp for the quarter ended June 30, 2009).
10.2.1
  
First Amendment to Employee Matters Agreement, dated as of September 28, 2007, by and between Duke Energy Corporation and Spectra Energy Corp (filed as Exhibit No. 10.3.1 to Form 10-Q of Spectra Energy Corp for the quarter ended June 30, 2009).
10.3
  
Purchase and Sale Agreement, dated as of February 24, 2005, by and between Enterprise GP Holdings LP and DCP Midstream, LLC (filed as Exhibit No. 10.4 to Form 10-Q of Spectra Energy Corp for the quarter ended June 30, 2009).
10.4
  
Term Sheet Regarding the Restructuring of DCP Midstream, LLC, dated as of February 23, 2005, between Duke Energy Corporation and ConocoPhillips (filed as Exhibit No. 10.26 to Form 10-K of Duke Energy Corporation for the year ended December 31, 2004).
10.5
  
Second Amended and Restated Limited Liability Company Agreement of DCP Midstream, LLC by and between ConocoPhillips Gas Company and Duke Energy Enterprises Corporation, dated as of July 5, 2005 (filed as Exhibit No. 10.5 to Form 10-Q of Spectra Energy Corp for the quarter ended June 30, 2009).


Table of Contents

Exhibit No.
 
Exhibit Description
10.5.1
 
First Amendment, dated August 11, 2006, to Second Amended and Restated Limited Liability Company Agreement of DCP Midstream, LLC, by and between ConocoPhillips Gas Company and Duke Energy Enterprises Corporation (filed as Exhibit No. 10.5.1 to Form 10-K of Spectra Energy Corp for the year ended December 31, 2011).
10.5.2
 
Second Amendment, dated February 1, 2007, to Second Amended and Restated Limited Liability Company Agreement of DCP Midstream, LLC, by and between ConocoPhillips Gas Company and Spectra Energy DEFS Holding, LLC and Spectra Energy DEFS Holding Corp (filed as Exhibit No. 10.5.2 to Form 10-K of Spectra Energy Corp for the year ended December 31, 2011).
10.5.3
 
Third Amendment, dated April 30, 2009, to Second Amended and Restated Limited Liability Company Agreement of DCP Midstream, LLC, by and between ConocoPhillips Gas Company and Spectra Energy DEFS Holding, LLC and Spectra Energy DEFS Holding Corp (filed as Exhibit No. 10.5.3 to Form 10-K of Spectra Energy Corp for the year ended December 31, 2011).
10.5.4
 
Fourth Amendment, dated November 9, 2010, to Second Amended and Restated Limited Liability Company Agreement of DCP Midstream, LLC, by and between ConocoPhillips Gas Company and Spectra Energy DEFS Holding, LLC and Spectra Energy DEFS Holding Corp (filed as Exhibit No. 10.5.4 to Form 10-K of Spectra Energy Corp for the year ended December 31, 2011).
10.5.5
 
Fifth Amendment, dated September 9, 2014, to Second Amended and Restated Limited Liability Company Agreement of DCP Midstream, LLC, by and between Phillips Gas Company and Spectra Energy DEFS Holding II, LLC and Spectra Energy DEFS Holding Corp (filed as Exhibit No. 10.1 to Form 10-Q of Spectra Energy Corp on November 6, 2014).
10.6
 
Limited Liability Company Agreement of Gulfstream Management & Operating Services, LLC, dated as of February 1, 2001, between Duke Energy Gas Transmission Corporation and Williams Gas Pipeline Company (filed as Exhibit No. 10.18 to Form 10-K of Duke Energy Corporation for the year ended December 31, 2002).
10.7
 
Loan Agreement, dated as of February 25, 2005, between DCP Midstream, LLC and Duke Capital LLC (filed as Exhibit No. 10.6 to Form 10-Q of Spectra Energy Corp for the quarter ended June 30, 2009).
+10.8
 
Spectra Energy Corp Directors’ Savings Plan, as amended and restated (filed as Exhibit No. 10.2 to Form 10-Q of Spectra Energy Corp for the quarter ended June 30, 2012).
+10.9
 
Spectra Energy Corp Executive Savings Plan, as amended and restated (filed as Exhibit No. 10.1 to Form 10-Q of Spectra Energy Corp for the quarter ended June 30, 2012).
+10.10
 
Spectra Energy Corp Executive Cash Balance Plan, as amended and restated (filed as Exhibit No. 10.3 to Form 10-K of Spectra Energy Corp for the year ended December 31, 2011).
+10.11
 
Omnibus Amendment, dated June 20, 2014, to Spectra Energy Corp Executive Savings Plan, Spectra Energy Corp Executive Cash Balance Plan and Spectra Energy Corp 2007 Long-Term Incentive Plan (filed as Exhibit No. 10.1 to Form 10-Q of Spectra Energy Corp on August 7, 2014).
+10.12
 
Form of Change in Control Agreement (U.S.) (filed as Exhibit No. 10.11 to Form 10-K of Spectra Energy Corp for the year ended December 31, 2011).
+10.13
 
Form of Change in Control Agreement (Canada) (filed as Exhibit No. 10.12 to Form 10-K of Spectra Energy Corp for the year ended December 31, 2011).
+10.14
 
Form of Change in Control Agreement (U.S.) (2014) (filed as Exhibit No. 10.3 to Form 10-Q of Spectra Energy Corp on August 7, 2014).
+10.15
 
Form of Non-Qualified Stock Option Agreement pursuant to the Spectra Energy Corp 2007 Long-Term Incentive Plan (filed as Exhibit No. 10.18 to Form 10-K of Spectra Energy Corp for the year ended December 31, 2006).
+10.16
 
Form of Change in Control Agreement (Canada) (2014) (filed as Exhibit No. 10.4 to Form 10-Q of Spectra Energy Corp on August 7, 2014).
10.17
 
Support Agreement among Spectra Energy Midstream Holdco Management Partnership, Spectra Energy Income Fund and Spectra Energy Commercial Trust, dated March 4, 2008 (filed as Exhibit No. 10.1 to Form 10-Q of Spectra Energy Corp for the quarter ended March 31, 2008).


Table of Contents


Exhibit No.
 
Exhibit Description
+10.18
 
Form of Retention Stock Award Agreement (2010) pursuant to the Spectra Energy Corp 2007 Long-Term Incentive Plan (filed as Exhibit No. 10.1 to Form 10-Q of Spectra Energy Corp for the quarter ended June 30, 2010).
+10.19
 
Form of Retention Stock Award Agreement (2014) pursuant to the Spectra Energy Corp 2007 Long-Term Incentive Plan (filed as Exhibit No. 10.2 to Form 10-Q of Spectra Energy Corp on August 7, 2014).
+10.20
 
Spectra Energy Corp 2007 Long-Term Incentive Plan, as amended and restated (filed as Exhibit No. 10.1 to Form 8-K of Spectra Energy Corp on April 22, 2011).
+10.21
 
Spectra Energy Corp Executive Short-Term Incentive Plan, as amended and restated (filed as Exhibit No. 10.2 to Form 8-K of Spectra Energy Corp on April 22, 2011).
+10.22
 
Form of Phantom Stock Award Agreement (2011) pursuant to the Spectra Energy Corp 2007 Long-Term Incentive Plan (filed as Exhibit No. 10.3 to Form 10-Q of Spectra Energy Corp on May 5, 2011).
+10.23
 
Form of Performance Award Agreement (cash) (2011) pursuant to the Spectra Energy Corp 2007 Long-Term Incentive Plan (filed as Exhibit No. 10.4 to Form 10-Q of Spectra Energy Corp on May 5, 2011).
+10.24
 
Form of Performance Award Agreement (stock) (2011) pursuant to the Spectra Energy Corp 2007 Long-Term Incentive Plan (filed as Exhibit No. 10.5 to Form 10-Q of Spectra Energy Corp on May 5, 2011).
10.25
 
Acknowledgement and Waiver Agreement, dated as of September 6, 2011, by and among ConocoPhillips, ConocoPhillips Gas Company, Spectra Energy Corp, Spectra Energy DEFS Holding, LLC and Spectra Energy DEFS Holding Corp (filed as Exhibit No. 10.1 to Form 8-K of Spectra Energy Corp on September 12, 2011).
+10.26
 
Form of Phantom Stock Award Agreement (2013) pursuant to the Spectra Energy Corp 2007 Long-Term Incentive Plan (filed as Exhibit No. 10.1 to Form 10-Q of Spectra Energy Corp on May 8, 2013).
+10.27
 
Form of Performance Award Agreement (cash) (2013) pursuant to the Spectra Energy Corp 2007 Long-Term Incentive Plan (filed as Exhibit No. 10.2 to Form 10-Q of Spectra Energy Corp on May 8, 2013).
+10.28
 
Form of Performance Award Agreement (stock) (2013) pursuant to the Spectra Energy Corp 2007 Long-Term Incentive Plan (filed as Exhibit No. 10.3 to Form 10-Q of Spectra Energy Corp on May 8, 2013).
+10.29
 
Form of Phantom Stock Award Agreement (2014) pursuant to the Spectra Energy Corp 2007 Long-Term Incentive Plan (filed as Exhibit No. 10.1 to Form 10-Q of Spectra Energy Corp on May 8, 2014).
+10.30
 
Form of Performance Stock Award Agreement (2014) pursuant to the Spectra Energy Corp 2007 Long-Term Incentive Plan (filed as Exhibit No. 10.2 to Form 10-Q of Spectra Energy Corp on May 8, 2014).
+10.31
 
Form of Phantom Stock Award Agreement (2015) pursuant to the Spectra Energy Corp 2007 Long-Term Incentive Plan (filed as Exhibit No. 10.1 to Form 10-Q of Spectra Energy Corp on May 7, 2015).
+10.32
 
Form of Performance Stock Award Agreement (2015) pursuant to the Spectra Energy Corp 2007 Long-Term Incentive Plan (filed as Exhibit No. 10.2 to Form 10-Q of Spectra Energy Corp on May 7, 2015).
10.33
 
Amended and Restated Credit Agreement, dated as of November 1, 2013, by and among Spectra Energy Capital, LLC, as Borrower, Spectra Energy Corp, as Guarantor, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto (filed as Exhibit No. 10.1 to Form 8-K of Spectra Energy Corp on November 1, 2013).
10.34
 
Credit Agreement, dated as of November 1, 2013, by and among Spectra Energy Capital, LLC, as Borrower, Spectra Energy Corp, as Guarantor, Bank of America, N.A., as Administrative Agent, and the lenders party thereto (filed as Exhibit No. 10.2 to Form 8-K of Spectra Energy Corp on November 1, 2013).
10.35
 
Amendment No. 1 dated December 11, 2014 to Amended and Restated Credit Agreement, dated November 1, 2013, by and among Spectra Energy Capital, LLC, as Borrower, Spectra Energy Corp, as Guarantor, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto (filed as Exhibit No. 10.1 to Form 8-K of Spectra Energy Corp on December 16, 2014).
*12.1
 
Computation of Ratio of Earnings to Fixed Charges.
*21.1
 
Subsidiaries of the Registrant.
*23.1
 
Consent of Independent Registered Public Accounting Firm.
*23.2
 
Consent of Independent Auditors.
*24.1
 
Power of Attorney.
*31.1
 
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2
 
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1
 
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2
 
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


Table of Contents

Exhibit No.
 
Exhibit Description
*101.INS
 
XBRL Instance Document.
*101.SCH
 
XBRL Taxonomy Extension Schema.
*101.CAL
 
XBRL Taxonomy Extension Calculation Linkbase.
*101.DEF
 
XBRL Taxonomy Extension Definition Linkbase.
*101.LAB
 
XBRL Taxonomy Extension Label Linkbase.
*101.PRE
 
XBRL Taxonomy Extension Presentation Linkbase.
 
 
 
+ Denotes management contract or compensatory plan or arrangement.
* Filed herewith.
The total amount of securities of the registrant or its subsidiaries authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10% of the total assets of the registrant and its subsidiaries on a consolidated basis. The registrant agrees, upon request of the Securities and Exchange Commission, to furnish copies of any or all of such instruments to it.



Table of Contents

DCP MIDSTREAM, LLC
CONSOLIDATED FINANCIAL STATEMENTS
TABLE OF CONTENTS
 
Page
 
 


F-1

Table of Contents

Deloitte & Touche LLP
Suite 3600
555 Seventeenth Street
Denver, CO 80202-3942
USA

Tel: +1 303 292 5400
Fax: +1 303 312 4000
www.deloitte.com
INDEPENDENT AUDITORS REPORT

To the Board of Directors and Members of
DCP Midstream, LLC
Denver, Colorado
We have audited the accompanying consolidated financial statements of DCP Midstream, LLC and its subsidiaries (the "Company"), which comprise the consolidated balance sheets as of December 31, 2015 and 2014, and the related consolidated statements of operations, comprehensive (loss) income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2015, and the related notes to the consolidated financial statements.
Management's Responsibility for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.
Auditors’ Responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Company's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of DCP Midstream, LLC and its subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in accordance with accounting principles generally accepted in the United States of America.
Emphasis of Matter
As discussed in Note 3 to the consolidated financial statements, on December 31, 2015 the Company adopted the amended provisions of ASC subtopic 835-30, Interest-Imputation of Interest, as it pertains to reporting debt issuance costs related to notes as a direct reduction to the face amount of the note in the consolidated balance sheets, rather than as a long-term asset, and as a result, retrospectively adjusted its 2014 consolidated balance sheet. Our opinion is not modified with respect to this matter.
/s/ Deloitte & Touche LLP
February 25, 2016


F-2                     Member of
Deloitte Touche Tohmatsu Limited


Table of Contents

DCP MIDSTREAM, LLC
CONSOLIDATED BALANCE SHEETS
(millions)
 
December 31,
 
2015
 
2014
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
3

 
$
27

Accounts receivable:
 
 
 
Customers, net of allowance for doubtful accounts of $4 million and $3 million,
respectively
444

 
813

Affiliates
75

 
180

Other
21

 
39

Inventories
51

 
76

Unrealized gains on derivative instruments
156

 
165

Other
50

 
80

Total current assets
800

 
1,380

Property, plant and equipment, net
9,428

 
9,537

Investments in unconsolidated affiliates
2,992

 
1,463

Intangible assets, net
149

 
290

Goodwill
242

 
704

Unrealized gains on derivative instruments
19

 
23

Other long-term assets
251

 
240

Total assets
$
13,881

 
$
13,637

LIABILITIES AND EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable:
 
 
 
Trade
$
480

 
$
904

Affiliates
40

 
35

Other
25

 
58

Short-term borrowings

 
1,012

Current maturities of long-term debt

 
450

Unrealized losses on derivative instruments
69

 
124

Accrued interest
72

 
76

Accrued taxes
38

 
34

Accrued wages and benefits
67

 
55

Other
105

 
190

Total current liabilities
896

 
2,938

Deferred income taxes
26

 
105

Long-term debt
5,669

 
5,191

Unrealized losses on derivative instruments
12

 
15

Other long-term liabilities
187

 
185

Total liabilities
6,790

 
8,434

Commitments and contingent liabilities
 
 
 
Equity:
 
 
 
Members’ interest
4,691

 
2,630

Accumulated other comprehensive loss
(4
)
 
(5
)
Total members’ equity
4,687

 
2,625

Noncontrolling interests
2,404

 
2,578

Total equity
7,091

 
5,203

Total liabilities and equity
$
13,881

 
$
13,637

See Notes to Consolidated Financial Statements.

F-3

Table of Contents

DCP MIDSTREAM, LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
(millions)
 
Year Ended December 31,
 
2015
 
2014
 
2013
Operating revenues:
 
 
 
 
 
Sales of natural gas and petroleum products
$
6,030

 
$
11,378

 
$
9,807

Sales of natural gas and petroleum products to affiliates
765

 
2,030

 
1,732

Transportation, storage and processing
532

 
517

 
463

Trading and marketing gains, net
119

 
88

 
36

Total operating revenues
7,446

 
14,013

 
12,038

Operating costs and expenses:
 
 
 
 
 
Purchases of natural gas and petroleum products
5,571

 
11,361

 
9,679

Purchases of natural gas and petroleum products from affiliates
418

 
467

 
288

Operating and maintenance
742

 
780

 
691

Depreciation and amortization
376

 
348

 
314

Asset impairments
912

 
18

 

General and administrative
278

 
281

 
280

(Gain) loss on sale of assets, net
(42
)
 
7

 
(22
)
Restructuring costs
11

 

 

Total operating costs and expenses
8,266

 
13,262

 
11,230

Operating (loss) income
(820
)
 
751

 
808

Earnings from unconsolidated affiliates
182

 
83

 
35

Interest expense, net
(320
)
 
(287
)
 
(249
)
(Loss) income before income taxes
(958
)
 
547

 
594

Income tax benefit (expense)
102

 
(11
)
 
(10
)
Net (loss) income
(856
)
 
536

 
584

Net income attributable to noncontrolling interests
(86
)
 
(248
)
 
(93
)
Net (loss) income attributable to members’ interests
$
(942
)
 
$
288

 
$
491


















See Notes to Consolidated Financial Statements.

F-4

Table of Contents

DCP MIDSTREAM, LLC
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
(millions)
 
Year Ended December 31,
 
2015
 
2014
 
2013
Net (loss) income
$
(856
)
 
$
536

 
$
584

Other comprehensive income:
 
 
 
 
 
Reclassification of cash flow hedge losses into earnings
2

 
2

 
3

Total other comprehensive income
2

 
2

 
3

Total comprehensive (loss) income
(854
)
 
538

 
587

Total comprehensive income attributable to noncontrolling interests
(87
)
 
(249
)
 
(93
)
Total comprehensive (loss) income attributable to members’ interests
$
(941
)
 
$
289

 
$
494






























See Notes to Consolidated Financial Statements.

F-5

Table of Contents

DCP MIDSTREAM, LLC
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(millions)
 
Members’ Equity
 
 
 
 
 


Members’
Interest
 
Accumulated Other Comprehensive (Loss) Income
 
Noncontrolling Interests
 


Total
Equity
Balance, January 1, 2013
$
2,413

 
$
(9
)
 
$
913

 
$
3,317

Net income
491

 

 
93

 
584

Other comprehensive income

 
3

 

 
3

Dividends and distributions
(430
)
 

 
(167
)
 
(597
)
Issuance of common units by DCP Partners, net of offering costs
196

 

 
886

 
1,082

Balance, December 31, 2013
2,670

 
(6
)
 
1,725

 
4,389

Net income
288

 

 
248

 
536

Other comprehensive income

 
1

 
1

 
2

Dividends and distributions
(474
)
 

 
(252
)
 
(726
)
Issuance of common units by DCP Partners, net of offering costs
146

 

 
856

 
1,002

Balance, December 31, 2014
2,630

 
(5
)
 
2,578

 
5,203

Net (loss) income
(942
)
 

 
86

 
(856
)
Other comprehensive income

 
1

 
1

 
2

Contributions from members
3,000

 

 

 
3,000

Dividends and distributions

 

 
(289
)
 
(289
)
Issuance of common units by DCP Partners, net of offering costs
3

 

 
28

 
31

Balance, December 31, 2015
$
4,691

 
$
(4
)
 
$
2,404

 
$
7,091




















See Notes to Consolidated Financial Statements.

F-6

Table of Contents

DCP MIDSTREAM, LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
(millions)
 
Year Ended December 31,
 
2015
 
2014
 
2013
Cash flows from operating activities:
 
 
 
 
 
Net (loss) income
$
(856
)
 
$
536

 
$
584

Adjustments to reconcile net (loss) income to net cash provided by operating activities:
 
 
 
 
 
Depreciation and amortization
376

 
348

 
314

Earnings from unconsolidated affiliates
(182
)
 
(83
)
 
(35
)
Distributions from unconsolidated affiliates
217

 
141

 
52

Deferred income tax (benefit) expense
(102
)
 
9

 
4

Net unrealized gains on derivative instruments
(46
)
 
(43
)
 
(5
)
Asset impairments
912

 
18

 

(Gain) loss on sale of assets, net
(42
)
 
7

 
(22
)
Other, net
34

 
27

 
20

Changes in operating assets and liabilities which provided (used) cash:
 
 
 
 
 
Accounts receivable
491

 
397

 
(333
)
Inventories
29

 
16

 
9

Accounts payable
(401
)
 
(452
)
 
300

Other, net
11

 
(104
)
 
(50
)
Net cash provided by operating activities
441

 
817

 
838

Cash flows from investing activities:
 
 
 
 
 
Capital expenditures
(811
)
 
(1,384
)
 
(1,420
)
Investments in unconsolidated affiliates, net
(64
)
 
(161
)
 
(523
)
Proceeds from sale of assets
164

 
30

 
46

Net cash used in investing activities
(711
)
 
(1,515
)
 
(1,897
)
Cash flows from financing activities:
 
 
 
 
 
Payment of dividends and distributions to members

 
(474
)
 
(430
)
Proceeds from long-term debt
7,216

 
719

 
2,507

Payment of long-term debt
(7,196
)
 

 
(2,238
)
Contribution from member
1,500

 

 

Proceeds from issuance of common units by DCP Partners, net of offering costs
31

 
1,001

 
1,083

(Repayment) borrowings of commercial paper, net
(1,012
)
 
(288
)
 
342

Distributions paid to noncontrolling interests
(289
)
 
(252
)
 
(167
)
Payment of deferred financing costs
(4
)
 
(12
)
 
(11
)
Net cash provided by financing activities
246

 
694

 
1,086

Net change in cash and cash equivalents
(24
)
 
(4
)
 
27

Cash and cash equivalents, beginning of period
27

 
31

 
4

Cash and cash equivalents, end of period
$
3

 
$
27

 
$
31









See Notes to Consolidated Financial Statements.

F-7

Table of Contents


DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2015, 2014 and 2013
1. Description of Business and Basis of Presentation
DCP Midstream, LLC, with its consolidated subsidiaries, or us, we, our, or the Company, is a joint venture owned 50% by Phillips 66 and its affiliates, or Phillips 66, and 50% by Spectra Energy Corp and its affiliates, or Spectra Energy. We operate in the midstream natural gas industry and are engaged in the business of gathering, compressing, treating, processing, transporting, storing and selling natural gas and producing, fractionating, transporting, storing and selling natural gas liquids, or NGLs, and recovering and selling condensate. Additionally, we generate revenues by trading and marketing natural gas and NGLs.
DCP Midstream Partners, LP, or DCP Partners, is a master limited partnership, of which we act as general partner. As of December 31, 2015 and 2014, we owned an approximate 21% and 22% interest in DCP Partners, respectively, including our limited partner and general partner interests. We also own incentive distribution rights that entitle us to receive an increasing share of available cash as pre-defined distribution targets are achieved. As the general partner of DCP Partners, we have responsibility for its operations.
We are governed by a five member board of directors, consisting of two voting members from each of Phillips 66 and Spectra Energy and our Chairman of the Board, President and Chief Executive Officer, a non-voting member. All decisions requiring the approval of our board of directors are made by simple majority vote of the board, but must include at least one vote from both a Phillips 66 and Spectra Energy board member. In the event the board cannot reach a majority decision, the decision is appealed to the Chief Executive Officers of both Phillips 66 and Spectra Energy.
The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America, or GAAP. GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and notes. These consolidated financial statements include the accounts of the Company and all majority-owned subsidiaries where we have the ability to exercise control and undivided interests in jointly owned assets. We also consolidate DCP Partners, which we control through our ownership and general partner interest, and where the limited partners do not have substantive kick-out or participating rights. Investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method. Intercompany balances and transactions have been eliminated in consolidation.
2. Summary of Significant Accounting Policies
Use of Estimates - Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could differ from those estimates.
Cash and Cash Equivalents - Cash and cash equivalents include all cash balances and investments in highly liquid financial instruments purchased with an original stated maturity of 90 days or less and temporary investments of cash in short-term money market securities.
Allowance for Doubtful Accounts - Management estimates the amount of required allowances for the potential non-collectability of accounts receivable generally based upon the number of days past due, past collection experience and consideration of other relevant factors. However, past experience may not be indicative of future collections and therefore additional charges could be incurred in the future to reflect differences between estimated and actual collections.
Inventories - Inventories, which consist primarily of natural gas and NGLs held in storage for transportation, processing and sales commitments, are recorded at the lower of weighted-average cost or market value. Transportation costs are included in inventory.
Accounting for Risk Management and Derivative Activities and Financial Instruments - We designate each energy commodity derivative as either trading or non-trading. Certain non-trading derivatives may be designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge), a hedge of a recognized asset, liability or firm commitment (fair value hedge), or normal purchases or normal sales contract. The remaining other non-trading derivatives, which are related to



F-8

Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
asset based activities for which hedge accounting or the normal purchase or normal sale exception is not elected, are recorded at fair value in the consolidated balance sheets as unrealized gains or unrealized losses on derivative instruments, with changes in the fair value recognized in the consolidated statements of operations. For each derivative, the accounting method and presentation of gains and losses or revenue and expense in the consolidated statements of operations are as follows:
Classification of Contract
 
Accounting Method
 
Presentation of Gains & Losses or Revenue & Expense
Trading Derivatives
 
Mark-to-market method (a)
 
Net basis in trading and marketing gains and losses
Non-Trading Derivatives:
 
 
 
 
Cash Flow Hedge
 
Hedge method (b)
 
Gross basis in the same consolidated statements of operations category as the related hedged item
Fair Value Hedge
 
Hedge method (b)
 
Gross basis in the same consolidated statements of operations category as the related hedged item
Normal Purchases or Normal Sales
 
Accrual method (c)
 
Gross basis upon settlement in the corresponding consolidated statements of operations category based on purchase or sale
Other Non-Trading Derivatives
 
Mark-to-market method (a)
 
Net basis in trading and marketing gains and losses
 
 
 
 
 
(a) Mark-to-market method - An accounting method whereby the change in the fair value of the asset or liability is recognized in the consolidated statements of operations in trading and marketing gains and losses during the current period.
(b) Hedge method - An accounting method whereby the change in the fair value of the asset or liability is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on derivative instruments. For cash flow hedges, there is no recognition in the consolidated statements of operations for the effective portion until the service is provided or the associated delivery impacts earnings. For fair value hedges, the changes in the fair value of the asset or liability, as well as the offsetting changes in value of the hedged item, are recognized in the consolidated statements of operations in the same category as the related hedged item.
(c) Accrual method - An accounting method whereby there is no recognition in the consolidated balance sheets or consolidated statements of operations for changes in fair value of a contract until the service is provided or the associated delivery impacts earnings.
Cash Flow and Fair Value Hedges - For derivatives designated as a cash flow hedge or a fair value hedge, we maintain formal documentation of the hedge. In addition, we formally assess both at the inception of the hedging relationship and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows or fair values of hedged items. All components of each derivative gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted.
The fair value of a derivative designated as a cash flow hedge is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on derivative instruments. The change in fair value of the effective portion of a derivative designated as a cash flow hedge is recorded in the consolidated balance sheets as accumulated other comprehensive income, or AOCI, and the ineffective portion is recorded in the consolidated statements of operations. During the period in which the hedged transaction impacts earnings, amounts in AOCI associated with the hedged transaction are reclassified to the consolidated statements of operations in the same line item as the item being hedged. Hedge accounting is discontinued prospectively when it is determined that the derivative no longer qualifies as an effective hedge, or when it is probable that the hedged transaction will not occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative is subject to the mark-to-market accounting method prospectively. The derivative continues to be carried on the consolidated balance sheets at its fair value; however, subsequent changes in its fair value are recognized in current period earnings. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the hedged transaction impacts earnings, unless it is probable that the hedged transaction will not occur, in which case, the gains and losses that were previously deferred in AOCI will be immediately recognized in current period earnings.
The fair value of a derivative designated as a fair value hedge is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on derivative instruments. We recognize the gain or loss on the derivative instrument, as well as the offsetting loss or gain on the hedged item in earnings in the current period. The change in fair value of all derivatives designated and accounted for as fair value hedges are classified in the same category as the item being hedged in the consolidated statements of operations.
Valuation - When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair

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Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
value is determined based on internally developed pricing models developed primarily from historical relationships with quoted market prices and the expected relationship with quoted market prices.
Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.
Property, Plant and Equipment - Property, plant and equipment are recorded at historical cost. The cost of maintenance and repairs, which are not significant improvements, are expensed when incurred. Depreciation is computed using the straight-line method over the estimated useful lives of the assets.
Capitalized Interest - We capitalize interest during construction of major projects. Interest is calculated on the monthly outstanding capital balance and ceases in the month that the asset is placed into service. We also capitalize interest on our equity method investments which are devoting substantially all efforts to establishing a new business and have not yet begun planned principal operations. Capitalization ceases when the investee commences planned principal operations. The rates used to calculate capitalized interest are the weighted-average cost of debt, including the impact of interest rate swaps.
Asset Retirement Obligations - Asset retirement obligations associated with tangible long-lived assets are recorded at fair value in the period in which they are incurred, if a reasonable estimate of fair value can be made, and added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability is determined using a credit-adjusted risk free interest rate and accretes due to the passage of time based on the time value of money until the obligation is settled.
Our asset retirement obligations relate primarily to the retirement of various gathering pipelines and processing facilities, obligations related to right-of-way easement agreements, and contractual leases for land use. We adjust our asset retirement obligation each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows.
Goodwill and Intangible Assets - Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired business. We perform an annual impairment test of goodwill in the third quarter, and update the test during interim periods when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value of a reporting unit. We primarily use a discounted cash flow analysis, supplemented by a market approach analysis, to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples, and estimated future cash flows including an estimate of operating and general and administrative costs. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value. Adverse changes in our business or the overall operating environment such as declines in gas production volumes, loss of significant customers or a further decrease in commodity prices may affect our estimate of future operating results, which could result in future goodwill and intangible assets impairment charges for other reporting units.
Intangible assets consist primarily of customer contracts, including commodity purchase, transportation and processing contracts and related relationships. These intangible assets are amortized on a straight-line basis over the period of expected future benefit. Intangible assets are removed from the gross carrying amount and the total of accumulated amortization in the period in which they become fully amortized.
Investments in Unconsolidated Affiliates - We use the equity method to account for investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence.
We evaluate our investments in unconsolidated affiliates for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value. When there is evidence of loss in value, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred and if the loss is other than temporary. We assess the fair value of our investments in unconsolidated affiliates using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. If the estimated fair value is less than the carrying value and

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Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
management considers the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized as an impairment loss.
Long-Lived Assets - We evaluate whether the carrying value of long-lived assets, including intangible assets, has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. We consider various factors when determining if these assets should be evaluated for impairment, including but not limited to:
a significant adverse change in legal factors or business climate;
a current period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset;
an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;
significant adverse changes in the extent or manner in which an asset is used, or in its physical condition;
a significant adverse change in the market value of an asset; or
a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.
If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. We determine the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets. A prolonged period of lower commodity prices or declines in production volumes may adversely affect our estimate of future operating results, which could result in future impairment due to the potential impact on our operations and cash flows.
Unamortized Debt Premium, Discount and Expense - Premiums, discounts and costs incurred with the issuance of long-term debt are amortized over the term of the debt using the effective interest method. The premiums, discounts and unamortized costs are recorded on the consolidated balance sheets within the carrying amount of long-term debt.
Noncontrolling Interest - Noncontrolling interest represents the ownership interests of third-party entities in the net assets of consolidated affiliates, including the ownership interest of DCP Partners’ public unitholders, through DCP Partners’ publicly traded common units, in net assets of DCP Partners and the noncontrolling interest which is recorded in DCP Partners’ consolidated balance sheets. For financial reporting purposes, the assets and liabilities of these entities are consolidated with those of our own, with any third party interest in our consolidated balance sheet amounts shown as noncontrolling interest in equity. Distributions to and contributions from noncontrolling interests represent cash payments to and cash contributions from, respectively, such third-party investors.
Dividends and Distributions - Under the terms of the Second Amended and Restated LLC Agreement dated July 5, 2005, as amended, or the LLC Agreement, we are required to make quarterly distributions to Phillips 66 and Spectra Energy based on allocated taxable income. The LLC Agreement provides for taxable income to be allocated in accordance with Internal Revenue Code Section 704(c). This Code Section accounts for the variation between the adjusted tax basis and the fair market value of assets contributed to the joint venture. The distribution is based on the highest taxable income allocated to either member, with the other member receiving a proportionate amount to maintain the ownership capital accounts at 50% for both Phillips 66 and Spectra Energy. Tax distributions to the members are calculated based on estimated annual taxable income allocated to the members according to their respective ownership percentages at the date the distributions became due. Our board of directors determines the amount of the periodic dividends to be paid by considering net income attributable to members’ interests, cash flow or any other criteria deemed appropriate. The LLC Agreement restricts payment of dividends except with the approval of both members. Dividends are allocated to the members in accordance with their respective ownership percentages.
DCP Partners considers the payment of a quarterly distribution to the holders of its common units, to the extent DCP Partners has sufficient cash from its operations after establishment of cash reserves and payment of fees and expenses,

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Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
including payments to its general partner, a 100% owned subsidiary of ours. There is no guarantee, however, that DCP Partners will pay the minimum quarterly distribution on the units in any quarter. DCP Partners will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default exists, under its credit agreement.
Revenue Recognition - We generate the majority of our revenues from gathering, processing, compressing, treating, transporting, storing and selling natural gas and producing, fractionating, transporting, storing and selling NGLs and recovering and selling condensate, as well as trading and marketing of natural gas and NGLs. We realize revenues either by selling the residue natural gas, NGLs and condensate, or by receiving fees.
We obtain access to commodities and provide our midstream services principally under contracts that contain a combination of one or more of the following arrangements:
Percent-of-proceeds/index arrangements - Under percent-of-proceeds/index arrangements, we generally purchase natural gas from producers at the wellhead or other receipt points, gather the wellhead natural gas through our gathering system, treat and process the natural gas, and then sell the resulting residue natural gas, NGLs and condensate based on published index prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales 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 the sales proceeds we receive. We keep the difference between the proceeds received and the amount remitted back to the producer. Under percent-of-liquid arrangements, we do not keep any amounts related to the residue natural gas proceeds and only keep 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 us returning sales proceeds to the producer. Additionally, these arrangements may include fee-based components. Our revenues under percent-of-proceeds/index arrangements relate directly with the price of natural gas, NGLs and condensate. Our revenues under percent-of-liquids arrangements relate directly to the price of NGLs and condensate.
Fee-based arrangements - Under fee-based arrangements, we receive 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. Our fee-based arrangements include natural gas arrangements pursuant to which we obtain 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 we would otherwise charge for transportation of natural gas from the wellhead location to the delivery point. The revenues we earn are directly related to the volume of natural gas or NGLs that flows through our systems and are not directly dependent on commodity prices. However, to the extent a sustained decline in commodity prices results in a decline in volumes our revenues from these arrangements would be reduced.
Keep-whole and wellhead purchase arrangements - Under the terms of a keep-whole processing contract, natural gas is gathered from the producer for processing, the NGLs and condensate are sold and the residue natural gas is returned to the producer with a British thermal unit, or 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, we purchase natural gas from the producer at the wellhead or defined receipt point for processing and then market the resulting NGLs and residue gas at market prices. Under these types of contracts, we are exposed to the difference between the value of the NGLs extracted from processing and the value of the Btu equivalent of residue natural gas, or frac spread. We benefit in periods when NGL prices are higher relative to natural gas prices when that frac spread exceeds our operating costs.






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Table of Contents


DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
Our trading and marketing of natural gas and NGL products consists of physical purchases and sales, as well as derivative instruments.
We recognize revenues for sales and services under the four revenue recognition criteria, as follows:
Persuasive evidence of an arrangement exists - Our customary practice is to enter into a written contract.
Delivery - Delivery is deemed to have occurred at the time custody is transferred, or in the case of fee-based arrangements, when the services are rendered. To the extent we retain product as inventory, delivery occurs when the inventory is subsequently sold and custody is transferred to the third party purchaser.
The fee is fixed or determinable - We negotiate the fee for our services at the outset of our fee-based arrangements. In these arrangements, the fees are nonrefundable. For other arrangements, the amount of revenue, based on contractual terms, is determinable when the sale of the applicable product has been completed upon delivery and transfer of custody.
Collectability is reasonably assured - Collectability is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers’ financial position (for example, credit metrics, liquidity and credit rating) and their ability to pay. If collectability is not considered probable at the outset of an arrangement in accordance with our credit review process, revenue is not recognized until the cash is collected.
We generally report revenues gross in the consolidated statements of operations, as we typically act as the principal in these transactions, take custody of the product, and incur the risks and rewards of ownership. New or amended contracts for certain sales and purchases of inventory with the same counterparty, when entered into in contemplation of one another, are reported net as one transaction. We recognize revenues for our NGL and residue gas derivative trading activities net in the consolidated statements of operations as trading and marketing gains and losses. These activities include mark-to-market gains and losses on energy trading contracts, and the settlement of financial and physical energy trading contracts.
Revenue for goods and services provided but not invoiced is estimated each month and recorded along with related purchases of goods and services used but not invoiced. These estimates are generally based on estimated commodity prices, preliminary throughput measurements and allocations and contract data. There are no material differences between the actual amounts and the estimated amounts of revenues and purchases recorded at December 31, 2015, 2014 and 2013.
Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements with customers, producers or pipelines are recorded monthly as accounts receivable or accounts payable using current market prices or the weighted-average prices of natural gas or NGLs at the plant or system. These balances are settled with deliveries of natural gas or NGLs, or with cash. Included in the consolidated balance sheets as accounts receivable - other, as of December 31, 2015 and 2014, were imbalances totaling $21 million and $38 million, respectively. Included in the consolidated balance sheets as accounts payable - other, as of December 31, 2015 and 2014, were imbalances totaling $25 million and $58 million, respectively.
Significant Customers - There were no third party customers that accounted for more than 10% of total operating revenues for the years ended December 31, 2015, 2014 or 2013. We had significant transactions with affiliates for the years ended December 31, 2015, 2014 and 2013. See Note 6, Agreements and Transactions with Related Parties and Affiliates.
Environmental Expenditures - Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not generate current or future revenue, are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated.
Equity-Based Compensation - Liability classified share-based compensation cost is remeasured at each reporting date at fair value, based on the closing security price, and is recognized as expense over the requisite service period. Compensation expense for awards with graded vesting provisions is recognized on a straight-line basis over the requisite service period of each separately vesting portion of the award.



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Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
Accounting for Sales of Units by a Subsidiary - We account for sales of units by a subsidiary by recording an increase or decrease in members’ interest within equity equal to the amount of net proceeds received in excess or deficit of the carrying value of the units sold. The remaining net proceeds are recorded as an increase to noncontrolling interest.
Income Taxes - We are structured as a limited liability company, which is a pass-through entity for federal income tax purposes. We own a corporation that files its own federal, foreign and state corporate income tax returns. The income tax expense related to this corporation is included in our income tax expense, along with state, local, franchise and margin taxes of the limited liability company and other subsidiaries.
We follow the asset and liability method of accounting for income taxes. Under this method, deferred income taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and the tax basis of the assets and liabilities. Our taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statements of operations, is included in the federal returns of each partner.
3. Recent Accounting Pronouncements
Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2015-17 “Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes,” or ASU 2015-17 - In November 2015, the FASB issued ASU 2015-17, which requires deferred tax liabilities and assets to be classified as noncurrent in the consolidated balance sheet. This ASU is effective for interim and annual reporting periods beginning after December 15, 2016, and interim periods within those annual periods with the option to early adopt. We are currently assessing the impact of adoption of this ASU on our consolidated results of operations, cash flows and financial position.
FASB ASU 2015-16 “Business Combinations (Topic 805),” or ASU 2015-16 - In September 2015, the FASB issued ASU 2015-16, which requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. This ASU is effective for interim and annual reporting periods beginning after December 15, 2016, including interim periods within those fiscal years, with the option to early adopt for financial statements that have not been issued. We are currently assessing the impact of adoption of this ASU on our consolidated results of operations, cash flows and financial position.
FASB ASU 2015-11 “Inventory (Topic 330): Simplifying the Measurement of Inventory,” or ASU 2015-11 - In July 2015, the FASB issued ASU 2015-11, which requires an entity to measure in scope inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The amendments apply to inventory that is measured using first-in, first-out (FIFO) or average cost. This ASU is effective for annual reporting periods beginning after December 15, 2016, and interim periods beginning after December 15, 2017, with the option to early adopt as of the beginning of an annual or interim period. The adoption of this ASU will have no impact on our consolidated results of operations, cash flows and financial position.
FASB ASU 2015-03 “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Cost,” or ASU 2015-03 - In April 2015, the FASB issued ASU 2015-03, which requires debt issuance costs to be presented in the balance sheet as a direct deduction from the associated debt liability. The company adopted ASU 2015-03 on December 31, 2015 which required retrospective application to the 2014 consolidated balance sheet. As a result of the adoption, $35 million of debt issuance costs was recorded as a deduction from long-term debt as of December 31, 2015, and $42 million was reclassified from other long-term assets to long-term debt as of December 31, 2014, respectively.
FASB ASU 2015-02 “Consolidation - (Topic 810): Amendments to the Consolidation Analysis,” or ASU 2015-02 - In February 2015, the FASB issued ASU 2015-02, which changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. This ASU is effective for annual reporting periods beginning after December 15, 2015, and we are currently assessing the impact of adoption of this ASU on our consolidated results of operations, cash flows and financial position.

FASB ASU 2014-09 “Revenue from Contracts with Customers (Topic 606),” or ASU 2014-09 - In May 2014, the FASB issued ASU 2014-09, which supersedes the revenue recognition requirements of Accounting Standards Codification, or ASC, Topic 605 “Revenue Recognition.” This ASU is effective for annual reporting periods beginning after December 15, 2017, with the option to adopt as early as December 15, 2016. We are currently assessing the impact of adoption of this ASU on our consolidated results of operations, cash flows and financial position.

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Table of Contents


DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
4. Acquisitions
In January 2015, DCP Partners entered into an agreement with an affiliate of Enterprise Products Partners L.P., or Enterprise, to acquire a 15% ownership interest in Panola Pipeline Company, LLC, or Panola. At closing, DCP Partners paid $1 million for its interest in the joint venture. The anticipated total consideration of approximately $26 million includes DCP Partners’ proportionate share in construction costs for an expansion of the existing Panola NGL pipeline. The Panola NGL pipeline originates in Carthage, Texas and extends approximately 180 miles to Mont Belvieu, Texas. The expansion will extend the Panola NGL pipeline for approximately 60 miles and increase capacity from approximately 50 MBbls/d to 100 MBbls/d. DCP Partners, along with affiliates of Anadarko Petroleum Corporation and MarkWest Energy Partners, L.P., each own a 15% interest in Panola. Enterprise owns a 55% interest in Panola and is constructing the expansion and will operate the pipeline. In accordance with the joint venture agreement, DCP Partners began participating in the earnings of the Panola pipeline on February 1, 2016.
5. Dispositions
In July 2015, we entered into a purchase and sale agreement with a third party to sell a non-core gas processing plant and gathering system for approximately $120 million, subject to customary purchase price adjustments. This transaction closed on August 26, 2015, and we recognized a $59 million gain on sale in the consolidated statement of operations for the year ended December 31, 2015.
In May 2015, we entered into purchase and sale agreements with WTG Benedum Joint Venture to sell our 33% interest in the Benedum gas processing plant and 100% interest in the Benedum gathering system, or Benedum, for approximately $21 million, subject to customary purchase price adjustments. This transaction closed on May 13, 2015, and we recognized a $27 million loss on sale, which included $2 million of goodwill, in the consolidated statement of operations for the year ended December 31, 2015.
In January 2015, we entered into a purchase and sale agreement with Mustang Gas Products, LLC to sell our approximate 44% interest in the Dover-Hennessey gas processing plant and gathering system for approximately $29 million, subject to customary purchase price adjustments. This transaction closed on January 30, 2015, and we recognized a $10 million gain on sale in the consolidated statement of operations for the year ended December 31, 2015.
6. Agreements and Transactions with Related Parties and Affiliates
Dividends, Distributions and Contributions
During the year ended December 31, 2015, no tax distributions were paid to the members. During the years ended December 31, 2014 and 2013, we paid tax distributions of $159 million and $18 million, respectively, based on estimated annual taxable income allocated to Phillips 66 and Spectra Energy according to their respective ownership percentages at the date the distributions became due. During the year ended December 31, 2015, no dividends were declared or paid. During the years ended December 31, 2014 and 2013, we declared and paid dividends of $315 million and $412 million, respectively, to Phillips 66 and Spectra Energy, allocated in accordance with their respective ownership percentages.
During the years ended December 31, 2015, 2014 and 2013, DCP Partners paid distributions of $358 million, $316 million and $215 million, respectively, to its limited partners, of which we received $76 million, $69 million and $54 million for our limited partner interests, respectively. Additionally, during the years ended December 31, 2015, 2014 and 2013, we received $124 million, $104 million and $62 million, respectively for our general partner interest, which includes our incentive distribution rights. Distributions from DCP Partners eliminate in consolidation.
On October 30, 2015, we closed on the $3 billion contribution agreement, or Equity Contribution, with Phillips 66 and Spectra Energy under which Phillips 66 contributed $1.5 billion in cash and Spectra Energy contributed all of its interests in the Sand Hills and Southern Hills NGL pipelines to us, respectively, as capital contributions.
Phillips 66 and CPChem
We sell a portion of our NGLs to Phillips 66 and Chevron Phillips Chemical LLC, or CPChem. In addition, we purchase NGLs from CPChem. CPChem is owned 50% by Phillips 66, and is considered a related party. Prior to December 31, 2014,


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Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
approximately 35% of our NGL production was committed to Phillips 66 and CPChem, under 15-year contracts, the primary production commitment of which began a ratable wind down period in December 2014 and expires in January 2019. Approximately 28% of our NGL production was committed to Phillips 66 and CPChem as of December 31, 2015. We anticipate continuing to purchase and sell commodities with Phillips 66 and CPChem in the ordinary course of business.
Spectra Energy
We purchase natural gas and other NGL products from, and provide gathering, transportation and other services to Spectra Energy. We anticipate continuing to purchase commodities and provide services to Spectra Energy in the ordinary course of business.
DCP Partners
We have entered into a services agreement, as amended, or the Services Agreement, with DCP Partners. Under the Services Agreement, DCP Partners is required to reimburse us for salaries of operating personnel and employee benefits, as well as capital expenditures, maintenance and repair costs, taxes and other direct costs incurred by us on behalf of DCP Partners. DCP Partners also pays us an annual fee under the Services Agreement for centralized corporate functions performed by us on behalf of DCP Partners. Except with respect to the annual fee, there is no limit on the reimbursements DCP Partners makes to us under the Services Agreement for other expenses and expenditures incurred or payments made by us on behalf of DCP Partners. Reimbursements received from DCP Partners have been eliminated in consolidation. In the event DCP Partners acquires assets or its business otherwise expands, the annual fee under the Services Agreement is subject to adjustment based on the nature and extent of general and administrative services performed by us on DCP Partners’ behalf, as well as an annual adjustment based on the changes to the Consumer Price Index.
On February 23, 2015, the annual fee payable under the Services Agreement was increased to $71 million, following approval of the increase by the special committee of DCP Partners’ Board of Directors. DCP Partners’ growth, both from organic growth and acquisitions, has resulted in DCP Partners becoming a much larger portion of our business. Additionally, DCP Partners’ expansion into downstream logistics has required us to expand our capabilities and provide DCP Partners with a broader range of services than what was previously provided. As a result, we initiated a comprehensive review of our costs and the methodology for allocating general and administrative services. The result of this review reflects the level and cost of general and administrative services we provide to DCP Partners as the operator of its assets. The annual fee was effective starting January 1, 2015.
We have previously entered into derivative transactions directly with DCP Partners as a result of dropdown transactions whereby we were the counterparty. In March 2015, we novated these fixed price commodity derivatives for approximately $141 million, and DCP Partners’ counterparty is now one of the financial institutions associated with DCP Partners’ credit facility. As we are no longer the counterparty in these fixed price commodity derivatives, DCP Partners’ position no longer eliminates in our consolidated financial statements.
Unconsolidated Affiliates
We, along with other third party shippers, have entered into 15-year transportation agreements, with Sand Hills Pipeline, LLC, or Sand Hills, Southern Hills Pipeline, LLC, or Southern Hills, Front Range Pipeline LLC, or Front Range, and Texas Express Pipeline LLC, or Texas Express. Under the terms of these 15-year agreements, which commenced at each of the pipelines’ respective in-service dates and expire between 2028 and 2029, we have committed to transport minimum throughput volumes at rates defined in each of the pipelines’ respective tariffs.
Under the terms of the Sand Hills LLC Agreement and the Southern Hills LLC Agreement, or the Sand Hills and Southern Hills LLC Agreements, Sand Hills and Southern Hills are required to reimburse us for any direct costs or expenses (other than general and administration services) which we incur on behalf of Sand Hills and Southern Hills. Additionally, Sand Hills and Southern Hills each pay us an annual service fee of $5 million, for centralized corporate functions provided by us as operator of Sand Hills and Southern Hills, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, taxes and engineering. Except with respect to the annual service fee, there is no limit on the reimbursements Sand Hills and Southern Hills make to us under the Sand Hills and Southern Hills LLC Agreements for other expenses and expenditures which we incur on behalf of Sand Hills or Southern Hills.


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Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
We also sell a portion of our residue gas and NGLs to, purchase natural gas and other NGL products from, and provide gathering and transportation services to other unconsolidated affiliates. We anticipate continuing to purchase and sell commodities and provide services to unconsolidated affiliates in the ordinary course of business.
Competition
Our related parties or affiliates, including DCP Partners, Phillips 66 and Spectra Energy, are not restricted, under either the LLC Agreement or the Services Agreement, from competing with us. Our related parties or affiliates, including DCP Partners, Phillips 66 and Spectra Energy, may acquire, construct or dispose of additional midstream energy or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets.
The following table summarizes our transactions with related parties and affiliates:
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
(millions)
Phillips 66 (including CPChem):
 
 
 
 
 
   Sales of natural gas and petroleum products to affiliates
$
695
 
 
$
1,960
 
 
$
1,665
 
   Transportation, storage and processing
$
 
 
$
 
 
$
1
 
   Purchases of natural gas and petroleum products from affiliates
$
 
 
$
11
 
 
$
14
 
   Operating and general and administrative expenses (a)
$
4
 
 
$
3
 
 
$
(11
)
Spectra Energy:
 
 
 
 
 
   Transportation, storage and processing
$
 
 
$
14
 
 
$
 
   Purchases of natural gas and petroleum products from affiliates
$
50
 
 
$
88
 
 
$
74
 
   Operating and general and administrative expenses
$
6
 
 
$
10
 
 
$
10
 
Unconsolidated affiliates:
 
 
 
 
 
   Sales of natural gas and petroleum products to affiliates
$
70
 
 
$
70
 
 
$
67
 
   Transportation, storage and processing
$
3
 
 
$
12
 
 
$
10
 
   Purchases of natural gas and petroleum products from affiliates
$
368
 
 
$
368
 
 
$
200
 
 
 
 
 
 
 
(a) The year ended December 31, 2013 included a gain on the sale of sections of our existing Seaway pipeline to Phillips 66, which was treated as a reduction to operating expense in the consolidated statement of operations.
We had balances with related parties and affiliates as follows:
 
December 31,
 
2015
 
2014
 
(millions)
Phillips 66 (including CPChem):
 
 
 
   Accounts receivable
$
54
 
 
$
161
 
   Accounts payable
$
3
 
 
$
4
 
   Other assets
$
1
 
 
$
1
 
Spectra Energy:
 
 
 
   Accounts receivable
$
 
 
$
1
 
   Accounts payable
$
4
 
 
$
4
 
   Other assets
$
1
 
 
$
1
 
Unconsolidated affiliates:
 
 
 
   Accounts receivable
$
21
 
 
$
18
 
   Accounts payable
$
33
 
 
$
27
 
   Other assets
$
31
 
 
$
30
 



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Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
7. Inventories
Inventories were as follows:
 
December 31,
 
2015
 
2014
 
(millions)
Natural gas
$
29
 
 
$
36
 
NGLs
22
 
 
40
 
   Total inventories
$
51
 
 
$
76
 
We recognize lower of cost or market adjustments when the carrying value of our inventories exceeds their estimated market value. These non-cash charges are a component of purchases of natural gas, propane and NGLs in the consolidated statements of operations. We recognized $8 million, $24 million and $4 million in lower of cost or market adjustments during the years ended December 31, 2015, 2014 and 2013, respectively.
8. Property, Plant and Equipment
Property, plant and equipment by classification were as follows:
 
Depreciable
 
December 31,
 
Life
 
2015
 
2014
 
 
 
 
Gathering and transmission systems
20 - 50 years
 
$
8,815
 
 
$
8,434
 
Processing, storage and terminal facilities
35 - 60 years
 
5,102
 
 
4,522
 
Other
3 - 30 years
 
485
 
 
415
 
Construction work in progress
 
 
196
 
 
1,159
 
   Property, plant and equipment
 
 
14,598
 
 
14,530
 
Accumulated depreciation
 
 
(5,170
)
 
(4,993
)
   Property, plant and equipment, net
 
 
$
9,428
 
 
$
9,537
 
We evaluate whether the carrying value of property, plant and equipment has been impaired when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value of those assets. It was determined during the fourth quarter of 2015 that the carrying amount of certain property, plant and equipment was not recoverable. The fair value of property, plant and equipment was derived from a discounted cash flow model using Level 3 fair value measurements. We determined the carrying value of those assets were less than their fair value and recognized property, plant and equipment non-cash impairments of $302 million, which are included in asset impairments in the consolidated statement of operations for the year ended December 31, 2015.
Interest capitalized on construction projects for the years ended December 31, 2015, 2014 and 2013 was $32 million, $34 million and $40 million, respectively.
Depreciation expense for the years ended December 31, 2015, 2014 and 2013 was $357 million, $327 million and $289 million, respectively.
Asset Retirement Obligations - As of December 31, 2015 and 2014, we had $120 million and $117 million, respectively, of asset retirement obligations, or AROs, in other long-term liabilities in the consolidated balance sheets. Accretion expense is recorded within operating and maintenance expense in our consolidated statements of operations.
We identified various assets as having an indeterminate life, for which there is no requirement to establish a fair value for future retirement obligations associated with such assets. These assets include certain pipelines, gathering systems and processing facilities. A liability for these asset retirement obligations will be recorded only if and when a future retirement obligation with a determinable life is identified. These assets have an indeterminate life because they will operate for an




Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
indeterminate future period when properly maintained. Additionally, if the portion of an owned plant containing asbestos were to be modified or dismantled, we would be legally required to remove the asbestos. We currently have no plans to take actions that would require the removal of asbestos in these assets. Accordingly, the fair value of the asset retirement obligation related to this asbestos cannot be estimated and no obligation has been recorded.
The following table summarizes changes in the asset retirement obligations included in our balance sheets:
 
December 31,
 
2015
 
2014
 
(millions)
Balance, beginning of period
$
117
 
 
$
93
 
Accretion expense
7
 
 
6
 
Revisions in estimated cash flows
(4
)
 
18
 
Balance, end of period
$
120
 
 
$
117
 
9. Investments in Unconsolidated Affiliates
We had investments in the following unconsolidated affiliates accounted for using the equity method:
 
Percentage
 
December 31,
 
Ownership
 
2015
 
2014
 
 
 
(millions)
DCP Sand Hills Pipeline, LLC (a)
66.67%
 
$
1,492
 
 
$
413
 
DCP Southern Hills Pipeline, LLC (a)
66.67%
 
764
 
 
329
 
Discovery Producer Services, LLC
40.00%
 
405
 
 
407
 
Front Range Pipeline LLC
33.33%
 
170
 
 
169
 
Texas Express Pipeline LLC
10.00%
 
96
 
 
98
 
Mont Belvieu Enterprise Fractionator
12.50%
 
25
 
 
23
 
Panola Pipeline Company, LLC
15.00%
 
19
 
 
 
Mont Belvieu I Fractionation Facility
20.00%
 
11
 
 
14
 
Other unconsolidated affiliates
Various
 
10
 
 
10
 
Total investments in unconsolidated affiliates
 
 
$
2,992
 
 
$
1,463
 
 
 
 
 
 
 
(a) As of December 31, 2015, Sand Hills and Southern Hills are each owned 33.34% by us and 33.33% by DCP Partners.
There was an excess of the carrying amount of the investment over the underlying equity of Sand Hills of $677 million and $10 million as of December 31, 2015 and 2014, respectively, which is associated with and being amortized over the life of the underlying long-lived assets of Sand Hills.
There was an excess of the carrying amount of the investment over the underlying equity of Southern Hills of $152 million and $7 million as of December 31, 2015 and 2014, respectively, which is associated with, and being amortized over the life of, the underlying long-lived assets of Southern Hills.
There was a deficit between the carrying amount of the investment and the underlying equity of Discovery Producer Services, LLC, or Discovery, of $24 million and $25 million as of December 31, 2015 and 2014, respectively, which is associated with, and is being amortized over the life of, the underlying long-lived assets of Discovery.
There was an excess of the carrying amount of the investment over the underlying equity of Front Range of $5 million at both December 31, 2015 and 2014, which is associated with, and is being amortized over the life of, the underlying long-lived assets of Front Range.
There was an excess of the carrying amount of the investment over the underlying equity of Texas Express of $3 million at both December 31, 2015 and 2014, which is associated with, and is being amortized over the life of, the underlying long-lived assets of Texas Express.

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Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
There was a deficit between the carrying amount of the investment and the underlying equity of Mont Belvieu I Fractionation Facility, or Mont Belvieu I, of $3 million and $4 million as of December 31, 2015 and 2014, respectively, which is associated with, and is being amortized over the life of, the underlying long-lived assets of Mont Belvieu I.
Earnings (loss) from unconsolidated affiliates amounted to the following:
 
Year Ended December 31,
 
2015
 
2014
 
2013
 
(millions)
DCP Sand Hills Pipeline, LLC
$
62
 
 
$
27
 
 
$
5
 
Discovery Producer Services, LLC
53
 
 
7
 
 
1
 
DCP Southern Hills Pipeline, LLC
18
 
 
15
 
 
(2
)
Front Range Pipeline LLC
17
 
 
2
 
 
 
Mont Belvieu Enterprise Fractionator
15
 
 
17
 
 
13
 
Mont Belvieu I Fractionation Facility
9
 
 
12
 
 
19
 
Texas Express Pipeline LLC
8
 
 
3
 
 
(1
)
Main Pass Oil and Gathering Company (a)
 
 
 
 
1
 
Other unconsolidated affiliates
 
 
 
 
(1
)
      Total earnings from unconsolidated affiliates
$
182
 
 
$
83
 
 
$
35
 
 
 
 
 
 
 
(a) We sold our two-thirds ownership interest in Main Pass Oil and Gathering Company in August 2014.
The following tables summarize the combined financial information of unconsolidated affiliates:
 
Year Ended December 31,
 
2015
 
2014
 
2013
 
(millions)
Income statement (a):
 
 
 
 
 
   Operating revenues
$
1,142

 
$
859

 
$
556

   Operating expenses
$
541

 
$
503

 
$
359

        Net income
$
600

 
$
354

 
$
194

 
December 31,
 
2015
 
2014
 
(millions)
Balance sheet (a):
 
 
 
   Current assets
$
240
 
 
$
270
 
   Long-term assets
5,224
 
 
5,125
 
   Current liabilities
(167
)
 
(192
)
   Long-term liabilities
(230
)
 
(165
)
        Net assets
$
5,067
 
 
$
5,038
 
 
 
 
 
(a) In accordance with the Panola joint venture agreement, earnings began to accrue to DCP Partners’ interest on February 1, 2016. Accordingly, no activity related to Panola is included in the above tables as of and for the year ended December 31, 2015.









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Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
10. Goodwill and Intangible Assets
The change in the carrying amount of goodwill is as follows:
 
December 31,
 
2015
 
2014
 
(millions)
Balance, beginning of period
$
704
 
 
$
722
 
Impairment
(460
)
 
(18
)
Dispositions
(2
)
 
 
Balance, end of period
$
242
 
 
$
704
 
In the second quarter of 2015, we determined that continued weak commodity prices caused a change in circumstances warranting an interim impairment test. Using the fair value approaches described within the Summary of Significant Accounting Policies, we determined that the estimated fair value of our Mid-Continent and Permian reporting units was less than the carrying amount.
DCP Partners also performed a goodwill assessment in the second quarter of 2015 and determined that the estimated fair value of its Collbran, Michigan and Southeast Texas reporting units was less than the carrying amount, due to the same factors.
We then allocated the estimated fair value of the reporting unit among all of the assets and liabilities of the reporting unit in a hypothetical purchase price allocation. In the second quarter of 2015, we and DCP Partners recognized goodwill impairment based on our best estimate of the impairment resulting from the performance of the hypothetical purchase price allocation which totaled $378 million for our Mid-continent and Permian reporting units and $49 million for DCP Partners’ Collbran, Michigan and Southeast Texas reporting units. We and DCP Partners completed the hypothetical purchase price allocation in the third quarter of 2015 and after completing the analysis, there was no remaining fair value to assign to goodwill of DCP Partners’ Collbran reporting unit. As a result, DCP Partners recorded an additional impairment of $33 million in the third quarter of 2015.
We performed our annual goodwill assessment during the third quarter of 2015. We concluded and DCP Partners concluded that the fair value of goodwill of the remaining reporting units exceeded their carrying value, and the entire amount of goodwill disclosed on the consolidated balance sheet associated with these remaining reporting units is recoverable, therefore, no other goodwill impairments were identified or recorded for the remaining reporting units as a result of the annual goodwill assessment
Our impairment determinations involved significant assumptions and judgments, as discussed within the Summary of Significant Accounting Policies. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to additional goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value. Adverse changes in our business or the overall operating environment such as declines in gas production volumes, loss of significant customers or a further decrease in commodity prices may affect our estimate of future operating results, which could result in future goodwill impairment charges for other reporting units.
Intangible assets consist of customer contracts, including commodity purchase, transportation and processing contracts and related relationships. The assessment of our intangible assets was also updated as of December 31, 2015 in accordance with the assessment of property, plant and equipment as described within Property, Plant and Equipment, resulting in an intangible asset impairment of $122 million, which is included in asset impairments in the consolidated statement of operations for the year ended December 31, 2015.









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Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
The gross carrying amount and accumulated amortization of these intangible assets are included in the accompanying consolidated balance sheets as intangible assets, net, and are as follows:
 
December 31,
 
2015
 
2014
 
(millions)
Gross carrying amount
$
410
 
 
$
524
 
Accumulated amortization
(139
)
 
(234
)
Accumulated impairment
(122
)
 
 
    Intangible assets, net
$
149
 
 
$
290
 
For the years ended December 31, 2015, 2014 and 2013, we recorded amortization expense of $19 million, $21 million and $25 million, respectively. As of December 31, 2015, the remaining amortization periods ranged from approximately 3 years to approximately 20 years, with a weighted-average remaining period of approximately 15 years.
Estimated future amortization for these intangible assets is as follows:
 
Estimated Future Amortization
 
(millions)
2016
$
11
 
2017
11
 
2018
11
 
2019
11
 
2020
11
 
Thereafter
94
 
   Total
$
149
 
11. Fair Value Measurement
Determination of Fair Value
Below is a general description of our valuation methodologies for derivative financial assets and liabilities which are measured at fair value. Fair values are generally based upon quoted market prices or prices obtained through external sources, where available. If listed market prices or quotes are not available, we determine fair value based upon a market quote, adjusted by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. These adjustments result in a fair value for each asset or liability under an “exit price” methodology, in line with how we believe a marketplace participant would value that asset or liability. Fair values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. These adjustments may include amounts to reflect counterparty credit quality, the effect of our own creditworthiness, the time value of money and/or the liquidity of the market.
Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. Therefore, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. We record counterparty credit valuation adjustments on all derivatives that are in a net asset position as of the measurement date in accordance with our established counterparty credit policy, which takes into account any collateral margin that a counterparty may have posted with us as well as any letters of credit that they have provided.
Entity valuation adjustments are necessary to reflect the effect of our own credit quality on the fair value of our net liability positions with each counterparty. This adjustment takes into account any credit enhancements, such as collateral margin we may have posted with a counterparty, as well as any letters of credit that we have provided. The methodology to determine this adjustment is consistent with how we evaluate counterparty credit risk, taking into


F-22

Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
account our own credit rating, current credit spreads, as well as any change in such spreads since the last measurement date.
Liquidity valuation adjustments are necessary when we are not able to observe a recent market price for financial instruments that trade in less active markets for the fair value to reflect the cost of exiting the position. Exchange traded contracts are valued at market value without making any additional valuation adjustments and, therefore, no liquidity reserve is applied. For contracts other than exchange traded instruments, we mark our positions to the midpoint of the bid/ask spread, and record a liquidity reserve based upon our total net position. We believe that such practice results in the most reliable fair value measurement as viewed by a market participant.
We manage our derivative instruments on a portfolio basis and the valuation adjustments described above are calculated on this basis. We believe that the portfolio level approach represents the highest and best use for these assets as there are benefits inherent in naturally offsetting positions within the portfolio at any given time, and this approach is consistent with how a market participant would view and value the assets and liabilities. Although we take a portfolio approach to managing these assets/liabilities, in order to reflect the fair value of any one individual contract within the portfolio, we allocate all valuation adjustments down to the contract level, to the extent deemed necessary, based upon either the notional contract volume, or the contract value, whichever is more applicable.
The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. While we believe that our valuation methods are appropriate and consistent with other market participants, we recognize that the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. We review our fair value policies on a regular basis taking into consideration changes in the marketplace and, if necessary, will adjust our policies accordingly. See Note 13, Risk Management and Hedging Activities, Credit Risk and Financial Instruments.
Valuation Hierarchy
Our fair value measurements are grouped into a three-level valuation hierarchy. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows:
Level 1 - inputs are unadjusted quoted prices for identical assets or liabilities in active markets.
Level 2 - inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
Level 3 - inputs are unobservable and considered significant to the fair value measurement.
A financial instrument’s categorization within the hierarchy is based upon level of judgment involved in the most significant input in the determination of the instrument’s fair value. Following is a description of the valuation methodologies used as well as the general classification of such instruments pursuant to the hierarchy.
Commodity Derivative Assets and Liabilities
We enter into a variety of derivative financial instruments, which may include exchange traded instruments (such as New York Mercantile Exchange, or NYMEX, crude oil or natural gas futures) or over-the-counter, or OTC, instruments (such as natural gas contracts, costless commodity collars, crude oil or NGL swaps). The exchange traded instruments are generally executed on the NYMEX exchange with a highly rated broker dealer serving as the clearinghouse for individual transactions.
Our activities expose us to varying degrees of commodity price risk. To mitigate a portion of this risk and to manage commodity price risk related primarily to owned natural gas storage and pipeline assets, we engage in natural gas asset based trading and marketing, and we may enter into natural gas and crude oil derivatives to lock in a specific margin when market conditions are favorable. A portion of this may be accomplished through the use of exchange traded derivative contracts. Such instruments are generally classified as Level 1 since the value is equal to the quoted market price of the exchange traded instrument as of our balance sheet date, and no adjustments are required. Depending upon market conditions and our strategy we may enter into exchange traded derivative positions with a significant time horizon to maturity. Although such instruments are exchange traded, market prices may only be readily observable for a portion of the duration of the instrument. In order to calculate the fair value of these instruments, readily observable market information is utilized to the extent it is available;

F-23

Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
however, in the event that readily observable market data is not available, we may interpolate or extrapolate based upon observable data. In instances where we utilize an interpolated or extrapolated value, and it is considered significant to the valuation of the contract as a whole, we would classify the instrument within Level 3.
We also engage in the business of trading energy related products and services, which exposes us to market variables and commodity price risk. We may enter into physical contracts or financial instruments with the objective of realizing a positive margin from the purchase and sale of these commodity-based instruments. We may enter into derivative instruments for NGLs or other energy related products, primarily using the OTC derivative instrument markets, which are not as active and liquid as exchange traded instruments. Market quotes for such contracts may only be available for short dated positions (up to six months), and an active market itself may not exist beyond such time horizon. Contracts entered into with a relatively short time horizon for which prices are readily observable in the OTC market are generally classified within Level 2. Contracts with a longer time horizon, for which we internally generate a forward curve to value such instruments, are generally classified within Level 3. The internally generated curve may utilize a variety of assumptions including, but not limited to, data obtained from third-party pricing services, historical and future expected relationship of NGL prices to crude oil prices, the knowledge of expected supply sources coming on line, expected weather trends within certain regions of the United States, and the future expected demand for NGLs.
Each instrument is assigned to a level within the hierarchy at the end of each financial quarter depending upon the extent to which the valuation inputs are observable. Generally, an instrument will move toward a level within the hierarchy that requires a lower degree of judgment as the time to maturity approaches, and as the markets in which the asset trades will likely become more liquid and prices more readily available in the market, thus reducing the need to rely upon our internally developed assumptions. However, the level of a given instrument may change, in either direction, depending upon market conditions and the availability of market observable data.
Interest Rate Derivative Assets and Liabilities
We periodically use interest rate swap agreements as part of our overall capital strategy. These instruments effectively exchange a portion of our fixed-rate debt for floating rate debt or floating rate debt for fixed-rate debt. The swaps are generally priced based upon a London Interbank Offered Rate, or LIBOR, instrument with similar duration, adjusted by the credit spread between our company and the LIBOR instrument. Given that a portion of the swap value is derived from the credit spread, which may be observed by comparing similar assets in the market, these instruments are classified within Level 2. Default risk on either side of the swap transaction is also considered in the valuation. We record counterparty credit and entity valuation adjustments in the valuation of interest rate swaps; however, these reserves are not considered to be a significant input to the overall valuation.
Benefits
We offer certain eligible executives the opportunity to participate in DCP Midstream LP’s Non-Qualified Executive Deferred Compensation Plan, or the EDC Plan. All amounts contributed to and earned by the EDC Plan’s investments are held in a trust account, which is managed by a third-party service provider. The trust account is invested in short-term money market securities and mutual funds. These investments are recorded at fair value, with any changes in fair value being recorded as a gain or loss in the consolidated statements of operations. Given that the value of the short-term money market securities and mutual funds are publicly traded and for which market prices are readily available, these investments are classified within Level 1.
Nonfinancial Assets and Liabilities
We utilize fair value to perform impairment tests as required on our property, plant and equipment; goodwill; and long-lived intangible assets. Assets and liabilities acquired in third party business combinations are recorded at their fair value as of the date of acquisition. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3 in the event that we were required to measure and record such assets at fair value within our consolidated financial statements. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified within Level 3.


F-24

Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
During the year ended December 31, 2015, we recognized impairments of goodwill, property, plant and equipment, intangible assets and other assets of $912 million in our consolidated statement of operations as summarized in the table below. Our impairment determinations involved significant assumptions and judgments. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. As such, the fair value measurements utilized within these models are classified as non-recurring Level 3 measurements in the fair value hierarchy because they are not observable from objective sources.
The following tables present the carrying value of assets measured at fair value on a non-recurring basis, by consolidated balance sheet caption and by valuation hierarchy, as of and for the years ended December 31, 2015 and 2014:
 
Net Carrying
Value
 
Fair Value Measurements Using
 
Asset
Impairments
 
 
Level 1
 
Level 2
 
Level 3
 
 
(millions)
Year Ended December 31, 2015:
 
 
 
 
 
 
 
 
 
Goodwill
$
 
 
$
 
 
$
 
 
$
 
 
$
460
 
Property, plant and equipment
87
 
 
 
 
 
 
87
 
 
302
 
Intangible assets
36
 
 
 
 
 
 
36
 
 
122
 
Other assets
50
 
 
 
 
 
 
50
 
 
28
 
    Total non-recurring assets at fair value
$
173
 
 
$
 
 
$
 
 
$
173
 
 
$
912
 
 
 
 
 
 
 
 
 
 
 
 
Net Carrying Value
 
Fair Value Measurements Using
 
Asset
Impairments
 
 
Level 1
 
Level 2
 
Level 3
 
 
(millions)
Year Ended December 31, 2014:
 
 
 
 
 
 
 
 
 
Goodwill
$
 
 
$
 
 
$
 
 
$
 
 
$
18
 
    Total non-recurring assets at fair value
$
 
 
$
 
 
$
 
 
$
 
 
$
18
 
 
 
 
 
 
 
 
 
 
 




























F-25

Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
The following table presents the financial instruments carried at fair value on a recurring basis, by consolidated balance sheet caption and by valuation hierarchy, as described above:
 
December 31, 2015
 
December 31, 2014
 
Level 1
 
Level 2
 
Level 3
 
Total
Carrying
Value
 
Level 1
 
Level 2
 
Level 3
 
Total
Carrying
Value
 
(Millions)
Current assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives (a)
$
23
 
 
$
98
 
 
$
35
 
 
$
156
 
 
$
33
 
 
$
108
 
 
$
23
 
 
$
164
 
Interest rate derivatives (a)
$
 
 
$
 
 
$
 
 
$
 
 
$
 
 
$
1
 
 
$
 
 
$
1
 
Short-term investments (b)
$
2
 
 
$
 
 
$
 
 
$
2
 
 
$
25
 
 
$
 
 
$
 
 
$
25
 
Long-term assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives (c)
$
3
 
 
$
12
 
 
$
4
 
 
$
19
 
 
$
1
 
 
$
19
 
 
$
3
 
 
$
23
 
Mutual funds (d)
$
8
 
 
$
 
 
$
 
 
$
8
 
 
$
14
 
 
$
 
 
$
 
 
$
14
 
Current liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives (e)
$
(16
)
 
$
(30
)
 
$
(23
)
 
$
(69
)
 
$
(22
)
 
$
(57
)
 
$
(45
)
 
$
(124
)
Long-term liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives (f)
$
(1
)
 
$
(5
)
 
$
(6
)
 
$
(12
)
 
$
(2
)
 
$
(1
)
 
$
(12
)
 
$
(15
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a) Included in current unrealized gains on derivative instruments in our consolidated balance sheets.
(b) Includes short-term money market securities included in cash and cash equivalents in our consolidated balance sheets.
(c) Included in long-term unrealized gains on derivative instruments in our consolidated balance sheets.
(d) Included in other long-term assets in our consolidated balance sheets.
(e) Included in current unrealized losses on derivative instruments in our consolidated balance sheets.
(f) Included in long-term unrealized losses on derivative instruments in our consolidated balance sheets.
Changes in Levels 1 and 2 Fair Value Measurements
The determination to classify a financial instrument within Level 1 or Level 2 is based upon the availability of quoted prices for identical or similar assets and liabilities in active markets. Depending upon the information readily observable in the market, and/or the use of identical or similar quoted prices, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. To qualify as a transfer, the asset or liability must have existed in the previous reporting period and moved into a different level during the current period. Amounts transferred in and out of Level 1 and Level 2 are reflected at fair value as of the end of the period. During the years ended December 31, 2015 and 2014, there were no transfers from Level 1 to Level 2 of the fair value hierarchy.
During the years ended December 31, 2015 and 2014, we had the following transfers from Level 2 to Level 1 of the fair value hierarchy:
 
Year Ended December 31,
 
2015
 
2014 (a)
 
(millions)
Current assets
$
 
 
$
3
 
Long-term assets
$
 
 
$
1
 
Current liabilities
$
 
 
$
(4
)
Long-term liabilities
$
 
 
$
(2
)
 
 
 
 
(a) Financial instruments have moved from Level 2 to Level 1 due to the passage of time.
 
 
 
 
 
Changes in Level 3 Fair Value Measurements
The tables below illustrate a rollforward of the amounts included in our consolidated balance sheets for derivative financial instruments that we have classified within Level 3. Since financial instruments classified as Level 3 typically include

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DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
a combination of observable components (that is, components that are actively quoted and can be validated to external sources) and unobservable components, the gains and losses in the table below may include changes in fair value due in part to observable market factors, or changes to our assumptions on the unobservable components. Depending upon the information readily observable in the market, and/or the use of unobservable inputs, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. The significant unobservable inputs used in determining fair value include adjustments by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. In the event that there is a movement to/from the classification of an instrument as Level 3, we have reflected such items in the table below within the “Transfers into Level 3” and “Transfers out of Level 3” captions.
We manage our overall risk at the portfolio level and in the execution of our strategy, we may use a combination of financial instruments, which may be classified within any level. Since Level 1 and Level 2 risk management instruments are not included in the rollforwards below, the gains or losses in the tables do not reflect the effect of our total risk management activities.
 
Commodity Derivative Instruments
 
Current
Assets
 
Long-Term
Assets
 
Current
Liabilities
 
Long-Term
Liabilities
 
(millions)
Year Ended December 31, 2015 (a):
 
 
 
 
 
 
 
   Beginning balance
$
23
 
 
$
3
 
 
$
(45
)
 
$
(12
)
   Net unrealized (losses) gains included in earnings (b)
(82
)
 
1
 
 
(29
)
 
6
 
   Transfers out of Level 3 (c)
 
 
 
 
1
 
 
 
   Settlements
(25
)
 
 
 
50
 
 
 
   Novation (d)
119
 
 
 
 
 
 
 
   Ending balance
$
35
 
 
$
4
 
 
$
(23
)
 
$
(6
)
Net unrealized (losses) gains on derivatives still held included in earnings (b)
$
(84
)
 
$
1
 
 
$
(23
)
 
$
4
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2014 (a):
 
 
 
 
 
 
 
   Beginning balance
$
21
 
 
$
2
 
 
$
(10
)
 
$
(1
)
   Net unrealized gains (losses) included in earnings (b)
23
 
 
1
 
 
(41
)
 
(11
)
   Transfers out of Level 3 (c)
 
 
 
 
 
 
 
   Settlements
(21
)
 
 
 
6
 
 
 
   Ending balance
$
23
 
 
$
3
 
 
$
(45
)
 
$
(12
)
Net unrealized gains (losses) on derivatives still held included in earnings (b)
$
23
 
 
$
 
 
$
(45
)
 
$
(11
)
 
(a) There were no purchases, issuances or sales of derivatives or transfers into Level 3 for the years ended December 31, 2015 and 2014.
(b) Represents the amount of total gains or losses for the period, included in trading and marketing gains, net, in the consolidated statements of operations.
(c) Amounts transferred out of Level 3 are reflected at fair value as of the end of the period.
(d) As a result of the novation of certain fixed price commodity derivatives, DCP Partners’ position no longer eliminates in consolidation.










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DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
Quantitative Information and Fair Value Sensitivities Related to Level 3 Unobservable Inputs
We utilize the market approach to measure the fair value of our commodity contracts. The significant unobservable inputs used in this approach are longer dated price quotes. Our sensitivity to these longer dated forward curve prices are presented in the table below. Significant changes in any of those inputs in isolation would result in significantly different fair value measurements, depending on our short or long position in these contracts.
Year Ended December 31, 2015:
 
 
Product Group
 
Fair Value (millions)
 
Forward Curve Range
 
 
Assets:
 
 
 
 
 
 
NGLs
 
$
39
 
 
$0.16 - $0.91
 
Per gallon
Liabilities:
 
 
 
 
 
 
NGLs
 
$
(29
)
 
$0.14 - $0.92
 
Per gallon
Estimated Fair Value of Financial Instruments
Valuation of a contract’s fair value is validated by an internal group independent of the marketing group. While common industry practices are used to develop valuation techniques, changes in pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition. When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and expected relationship with quoted market prices.
Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.
The fair value of our interest rate swaps, if applicable, and commodity non-trading derivatives are based on prices supported by quoted market prices and other external sources and prices based on models and other valuation methods. The “prices supported by quoted market prices and other external sources” category includes our interest rate swaps, if applicable, our NGL and crude oil swaps and our NYMEX positions in natural gas. In addition, this category includes our forward positions in natural gas for which our forward price curves are obtained from a third-party pricing service and then validated through an internal process which includes the use of independent broker quotes. This category also includes our forward positions in NGLs at points for which over-the-counter, or OTC, broker quotes for similar assets or liabilities are available for the full term of the instrument. This category also includes “strip” transactions whose pricing inputs are directly or indirectly observable from external sources and then modeled to daily or monthly prices as appropriate. The “prices based on models and other valuation methods” category includes the value of transactions for which inputs to the fair value of the instrument are unobservable in the marketplace and are considered significant to the overall fair value of the instrument. The fair value of these instruments may be based upon an internally developed price curve, which was constructed as a result of the long dated nature of the transaction or the illiquidity of the specific market point.
We have determined fair value amounts using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts.
The fair value of accounts receivable, accounts payable and short-term borrowings are not materially different from their carrying amounts because of the short-term nature of these instruments or the stated rates approximating market rates. Derivative instruments are carried at fair value. We determine the fair value of our variable rate debt based upon the discounted present value of expected future cash flows, taking into account the difference between the contractual borrowing spread and the spread for similar credit facilities available in the marketplace. We determine the fair value of our fixed-rate debt based on quotes obtained from bond dealers. We classify the fair value of our outstanding debt balances within Level 2 of the fair value hierarchy. As of December 31, 2015, the carrying and fair value of our long-term debt, including current maturities of long-


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DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
term debt, was $5,669 million and $4,754 million, respectively. As of December 31, 2014, the carrying and fair value of our long-term debt was $5,641 million and $5,951 million, respectively.
12. Financing
 
December 31,
 
2015
 
2014
 
(millions)
Commercial paper:
 
 
 
DCP Midstream’s short-term borrowings, weighted-average interest rate of 0.89% as of December 31, 2014
$

 
$
1,012

DCP Midstream’s debt securities:
 
 
 
Senior notes:
 
 
 
Issued October 2005, interest at 5.375% payable semiannually, due October 2015

 
200

Issued February 2009, interest at 9.750% payable semiannually, due March 2019 (a)
450

 
450

Issued March 2010, interest at 5.350% payable semiannually, due March 2020 (a)
600

 
600

Issued September 2011, interest at 4.750% payable semiannually, due September 2021
500

 
500

Issued August 2000, interest at 8.125% payable semiannually, due August 2030 (b)
300

 
300

Issued October 2006, interest at 6.450% payable semiannually, due November 2036
300

 
300

Issued September 2007, interest at 6.750% payable semiannually, due September 2037
450

 
450

Junior subordinated notes:
 
 
 
Issued May 2013, interest at 5.850% payable semiannually, due May 2043
550

 
550

DCP Midstream’s credit facilities with financial institutions:
 
 
 
DCP Midstream’s revolving credit agreement, weighted-average interest rate of 2.93%, due March 2017
96

 

DCP Partners’ debt securities:
 
 
 
Senior notes:
 
 
 
Issued September 2010, interest at 3.25% payable semiannually, due October 2015

 
250

Issued November 2012, interest at 2.50% payable semiannually, due December 2017
500

 
500

Issued March 2014, interest at 2.70% payable semiannually, due April 2019
325

 
325

Issued March 2012, interest at 4.95% payable semiannually, due April 2022
350

 
350

Issued March 2013, interest at 3.875% payable semiannually, due March 2023
500

 
500

Issued March 2014, interest at 5.60% payable semiannually, due April 2044
400

 
400

DCP Partners’ credit facilities with financial institutions:
 
 
 
DCP Partners’ revolving credit agreement, weighted-average variable interest rate of 1.57%, due May 2019
375

 

Fair value adjustments related to interest rate swap fair value hedges (a) (b)
26

 
29

Unamortized issuance costs
(35
)
 
(42
)
Unamortized discount
(18
)
 
(21
)
Total debt
5,669

 
6,653

Current maturities of long-term debt

 
(450
)
DCP Midstream short-term borrowings

 
(1,012
)
Total long-term debt
$
5,669

 
$
5,191

 
 
 
 
(a) During 2014, $50 million of debt associated with each of these note issuances was swapped to a floating rate obligation. These interest rate swap agreements were terminated in January 2015, and the remaining long-term fair value of less than $1 million related to these swaps will be amortized as a reduction of interest expense through March 2019 and March 2020, respectively, the original maturity date of the debt.
(b) During 2008, the swaps associated with this debt were terminated. The remaining long-term fair value of approximately $26 million related to the swaps is being amortized as a reduction to interest expense through August 2030, the original maturity date of the debt.




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Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013

Approximate future maturities of long-term debt in the year indicated are as follows at December 31, 2015:
 
Debt Maturities
 
(millions)
2016
$

2017
596

2018

2019
1,150

2020
600

Thereafter
3,350

 
5,696

Fair value adjustments related to interest rate swap fair value hedges
26

Unamortized issuance costs
(35
)
Unamortized discount
(18
)
Long-term debt
$
5,669

DCP Midstream’s Debt Securities - The DCP Midstream senior debt securities mature and become payable on the respective due dates, and are not subject to any sinking fund provisions. The DCP Midstream senior debt securities are senior unsecured obligations, and are redeemable at a premium at our option. The underwriters’ fees and related expenses are recorded on the consolidated balance sheets within the carrying amount of long-term debt and will be amortized over the term of the notes.
DCP Midstream’s Commercial Paper Program - We had a commercial paper program, or the DCP Midstream Commercial Paper Program, under which we issued unsecured commercial paper notes. As of December 31, 2014, we had $1,012 million of commercial paper outstanding, which was included in short-term borrowings in the consolidated balance sheets. In the first quarter of 2015, our credit rating was lowered below investment grade. As a result of this ratings action, we no longer have the DCP Midstream Commercial Paper Program. Our borrowings under the DCP Midstream Commercial Paper Program have been replaced with liquidity and borrowings under the DCP Midstream Amended and Restated Revolving Credit Agreement.
DCP Midstream’s Credit Facilities with Financial Institutions - In March 2015, we entered into a first amendment of the DCP Midstream Amended and Restated Revolving Credit Agreement, which reduced the total borrowing capacity of the facility from $2 billion to $1.8 billion and revised the maturity date of the facility from May 2019 to March 2017. Certain of our subsidiaries, other than DCP Partners, will provide guarantees of borrowings under this facility. In addition, borrowings under this facility will be secured with a pledge of our limited partner and general partner ownership in DCP Partners as collateral. None of our physical assets are pledged as collateral for borrowings under this facility. Along with other restrictions, the terms of this facility also restrict the payment of dividends or distributions to Phillips 66 and Spectra. The DCP Midstream Amended and Restated Revolving Credit Agreement may be used to support our capital expansion program, for working capital requirements and other general corporate purposes, including acquisitions, as well as for letters of credit. As of December 31, 2015, we had $96 million outstanding under the DCP Midstream Amended and Restated Revolving Credit Agreement.
As of December 31, 2015 and 2014, we had $20 million and $6 million in letters of credit outstanding, respectively. As of December 31, 2015, the available capacity under the DCP Midstream Amended and Restated Revolving Credit Agreement was $1,684 million, net of letters of credit, all of which was available for general working capital purposes. Our borrowing capacity may be limited by financial covenants set forth in the DCP Midstream Amended and Restated Revolving Credit Agreement. Except in the case of default, amounts borrowed under the DCP Midstream Amended and Restated Revolving Credit Agreement will not become due prior to the March 2017 maturity date.
Indebtedness under the DCP Midstream Amended and Restated Revolving Credit Agreement bears interest at either: (1) LIBOR, plus an applicable margin of 2.50%; or (2) (a) the base rate which shall be the higher of Wells Fargo Bank N.A.’s prime rate, the Federal Funds rate plus 0.50% or the LIBOR Market Index rate plus 1% plus (b) an applicable margin of 1.50%.



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Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
The DCP Midstream Amended and Restated Revolving Credit Agreement incurs an annual facility fee of 0.50%. This fee is paid on drawn and undrawn portions of the DCP Midstream Amended and Restated Revolving Credit Agreement.
The DCP Midstream Amended and Restated Revolving Credit Agreement requires us to maintain a secured leverage ratio (the ratio of secured indebtedness to consolidated EBITDA as defined) of not more than 3.25 to 1.0. Beginning with the fiscal quarter ending December 31, 2015, we must also maintain a consolidated leverage ratio (the ratio of consolidated indebtedness to consolidated EBITDA as defined) of not more than 5.0 to 1.0. In conjunction with the Equity Contribution, we amended the DCP Midstream Amended and Restated Revolving Credit Agreement covenant calculations, such that beginning with the fiscal period ending December 31, 2015 and continuing through the end of the agreement, the definition of consolidated EBITDA will now include an additional $750 million and the definition of consolidated indebtedness will now be reduced for certain cash on hand.
DCP Partners’ Credit Facilities with Financial Institutions - In May 2014, DCP Partners entered into the DCP Partners Amended and Restated Credit Agreement. The DCP Partners Amended and Restated Credit Agreement has a total borrowing capacity of $1.25 billion and is used for working capital requirements and other general partnership purposes including acquisitions. As of December 31, 2015 and 2014, DCP Partners had $1 million of letters of credit issued and outstanding under the DCP Partners Amended and Restated Credit Agreement and the DCP Partners Credit Agreement. As of December 31, 2015, the unused capacity under the DCP Partners Amended and Restated Credit Agreement was $874 million, which is net of letters of credit. DCP Partners’ borrowing capacity may be limited by financial covenants set forth in the DCP Partners Amended and Restated Credit Agreement. Except in the case of default, amounts borrowed under the DCP Partners Amended and Restated Credit Agreement will not become due prior to the May 2019 maturity date.
Indebtedness under the DCP Partners Amended and Restated Credit Agreement bears interest at either: (1) LIBOR, plus an applicable margin of 1.275% based on DCP Partners’ current credit rating; or (2) (a) the base rate which shall be the higher of Wells Fargo Bank N.A.’s prime rate, the Federal Funds rate plus 0.50% or the LIBOR Market Index rate plus 1%, plus (b) an applicable margin of 0.275% based on DCP Partners’ current credit rating. The DCP Partners Amended and Restated Credit Agreement incurs an annual facility fee of 0.225% based on DCP Partners’ current credit rating. This fee is paid on drawn and undrawn portions of the DCP Partners Amended and Restated Credit Agreement.
The DCP Partners Amended and Restated Credit Agreement requires DCP Partners to maintain a leverage ratio (the ratio of DCP Partners’ consolidated indebtedness to its consolidated EBITDA, in each case as defined) of not more than 5.0 to 1.0, and following consummation of qualifying acquisitions, not more than 5.5 to 1.0, on a temporary basis for three consecutive quarters, including the quarter in which such acquisition is consummated. Further, DCP Partners’ cost of borrowing under the DCP Partners Amended and Restated Credit Agreement is determined by a ratings based pricing grid.
DCP Partners’ Debt Securities - DCP Partners’ debt securities are senior unsecured obligations, ranking equally in right of payment with other unsecured indebtedness, including indebtedness under the DCP Partners Amended and Restated Credit Agreement. DCP Partners is not required to make mandatory redemption or sinking fund payments with respect to any of these notes, and they are redeemable at a premium at DCP Partners’ option. The underwriters’ fees and related expenses are recorded on the consolidated balance sheets within the carrying amount of long-term debt and will be amortized over the term of the notes.
Other Financing - During the year ended December 31, 2015, DCP Partners issued 788,033 of its common units pursuant to its 2014 equity distribution agreement and received proceeds of $31 million, net of commissions and offering costs of less than $1 million, which were used to finance growth opportunities and for general partnership purposes. As of December 31, 2015, approximately $349 million of its common units remained available for sale pursuant to DCP Partners’ 2014 equity distribution agreement.
In June 2014, DCP Partners filed a shelf registration statement on Form S-3 with the U.S. Securities and Exchange Commission, or SEC, with a maximum offering price of $500 million, which became effective on July 11, 2014. The shelf registration statement allows DCP Partners to issue additional common units. In September 2014, DCP Partners entered into an equity distribution agreement, or the 2014 equity distribution agreement, with a group of financial institutions as sales agents. The 2014 equity distribution agreement provides for the offer and sale from time to time, through DCP Partners’ sales agents, of common units having an aggregate offering amount of up to $500 million. During the year ended December 31, 2014, DCP Partners issued 2,256,066 of its common units pursuant to the 2014 equity distribution agreement and received proceeds of $119 million, net of commissions and accrued offering costs of $1 million, which were used to finance growth opportunities and for general partnership purposes.

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DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
In March 2014, DCP Partners issued 14,375,000 of its common units to the public at $48.90 per unit. DCP Partners received proceeds of $677 million, net of offering costs.
In August 2013, DCP Partners issued 9,000,000 of its common units to the public at $50.04 per unit. DCP Partners received proceeds of $434 million, net of offering costs.
In June 2013, DCP Partners filed a shelf registration statement on Form S-3, or the June 2013 shelf registration statement, with the SEC with a maximum offering price of $300 million, which became effective on June 27, 2013. The June 2013 shelf registration statement allowed DCP Partners to issue additional common units. In November 2013, DCP Partners entered into an equity distribution agreement, or the 2013 equity distribution agreement, related to the June 2013 shelf registration statement, with a group of financial institutions as sales agents. The 2013 equity distribution agreement provided for the offer and sale from time to time, through DCP Partners’ sales agents, of common units having an aggregate offering amount of up to $300 million. During the year ended December 31, 2014, DCP Partners issued 3,769,635 of its common units pursuant to the 2013 equity distribution agreement and received proceeds of $206 million, which is net of commissions and offering costs of $2 million. During the year ended December 31, 2013, DCP Partners issued 1,839,430 of its common units pursuant to the 2013 equity distribution agreement and received proceeds of $87 million, net of commissions and offering costs of $1 million, which were used to finance growth opportunities and for general partnership purposes. In connection with DCP Partners’ entry into the 2014 equity distribution agreement, DCP Partners terminated the 2013 equity distribution agreement in September 2014. In October 2014, DCP Partners de-registered the common units that remained unsold under the 2013 equity distribution agreement at the time of its termination.
In March 2013, DCP Partners issued 12,650,000 of its common units to the public at $40.63 per unit. DCP Partners received proceeds of $494 million, net of offering costs.
13. Risk Management and Hedging Activities, Credit Risk and Financial Instruments
Our day-to-day operations expose us to a variety of risks including but not limited to changes in the prices of commodities that we buy or sell, changes in interest rates, and the creditworthiness of each of our counterparties. We manage certain of these exposures with either physical or financial transactions. We have established a comprehensive risk management policy, or Risk Management Policy, and a risk management committee, or the Risk Management Committee, to monitor and manage market risks associated with commodity prices and counterparty credit. Our Risk Management Committee is composed of senior executives who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. The following describes each of the risks that we manage.
Commodity Price Risk
Our portfolio of commodity derivative activity is primarily accounted for using the mark-to-market method of accounting; however, depending upon our risk profile and objectives, in certain limited cases, we may execute transactions that qualify for the hedge method of accounting. The risks, strategies and instruments used to mitigate such risks, as well as the method of accounting are discussed and summarized below.
Natural Gas Asset Based Trading and Marketing
Our natural gas storage and pipeline assets are exposed to certain risks including changes in commodity prices. We manage commodity price risk related to our natural gas storage and pipeline assets through our commodity derivative program. The commercial activities related to our natural gas storage and pipeline assets primarily consist of the purchase and sale of gas and associated time spreads and basis spreads.
A time spread transaction is executed by establishing a long gas position at one point in time and establishing an equal short gas position at a different point in time. Time spread transactions allow us to lock in a margin supported by the injection, withdrawal, and storage capacity of our natural gas storage assets. We may execute basis spread transactions to mitigate the risk of sale and purchase price differentials across our system. A basis spread transaction allows us to lock in a margin on our physical purchases and sales of gas, including injections and withdrawals from storage. We typically use swaps to execute these transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period consolidated statements of operations. While gas held in our storage locations is recorded at the lower of average cost or market, the derivative instruments that are used to manage our storage facilities are recorded at fair value and any changes in fair value are currently recorded in our consolidated statements of operations. Even though we may have

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Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
economically hedged our exposure and locked in a future margin, the use of lower-of-cost-or-market accounting for our physical inventory and the use of mark-to-market accounting for our derivative instruments may subject our earnings to market volatility.
DCP Partners Commodity Cash Flow Hedges
In order for our storage facilities to remain operational, a minimum level of base gas must be maintained in each storage cavern, which is capitalized on our consolidated balance sheets as a component of property, plant and equipment, net. During construction or expansion of DCP Partners’ storage caverns, DCP Partners may execute a series of derivative financial instruments to mitigate a portion of the risk associated with the forecasted purchase of natural gas when DCP Partners brings the storage caverns to operation. These derivative financial instruments may be designated as cash flow hedges. While the cash paid upon settlement of these hedges economically fixes the cash required to purchase base gas, the deferred losses or gains would remain in accumulated other comprehensive income, or AOCI, until the cavern is emptied and the base gas is sold. The balance in AOCI of DCP Partners’ previously settled base gas cash flow hedges was in a loss position of $6 million as of December 31, 2015.
NGL Proprietary Trading
Our NGL proprietary trading activity includes trading energy related products and services. We undertake these activities through the use of fixed forward sales and purchases, basis and spread trades, storage opportunities, put/call options, term contracts and spot market trading. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and these operations may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments. These physical and financial instruments are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period consolidated statements of operations.
We employ established risk limits, policies and procedures to manage risks associated with our natural gas asset based trading and marketing and NGL proprietary trading.
Commodity Cash Flow Protection Activities at DCP Partners
DCP Partners is exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of its gathering, processing, sales and storage activities. For gathering, processing and storage services, DCP Partners may receive cash or commodities as payment for these services, depending on the contract type. DCP Partners enters into derivative financial instruments to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices associated with its gathering, processing and sales activities, thereby stabilizing its cash flows. DCP Partners has mitigated a portion of its expected commodity cash flow risk associated with its gathering, processing and sales activities through 2017 with commodity derivative instruments. DCP Partners’ commodity derivative instruments used for its hedging program are a combination of direct NGL product, crude oil and natural gas hedges. Due to the limited liquidity and tenor of the NGL derivative market, DCP Partners has used crude oil swaps and costless commodity collars to mitigate a portion of its commodity price risk exposure for NGLs. Historically, prices of NGLs have generally been related to crude oil prices; however, there are periods of time when NGL pricing may be at a greater discount to crude oil, resulting in additional exposure to NGL commodity prices. The relationship of NGLs to crude oil continues to be lower than historical relationships. Prior to March 2015, a significant amount of DCP Partners’ NGL hedges through March 2016 were direct product hedges with us. As a result of our novating these direct product commodity positions to a third party in March 2015, these positions no longer eliminate in our consolidated financial statements. When its crude oil swaps become short-term in nature, DCP Partners has periodically converted certain crude oil derivatives to NGL derivatives by entering into offsetting crude oil swaps while adding NGL swaps. DCP Partners’ crude oil and NGL transactions are primarily accomplished through the use of forward contracts that effectively exchange DCP Partners’ floating price risk for a fixed price. DCP Partners also utilizes crude oil costless commodity collars that minimize its floating price risk by establishing a fixed price floor and a fixed price ceiling. However, the type of instrument that DCP Partners uses to mitigate a portion of its risk may vary depending on DCP Partners’ risk management objective. These transactions are not designated as hedging instruments for accounting purposes and the change in fair value is reflected in the current period within our consolidated statements of operations as trading and marketing gains, net.




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Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
Interest Rate Risk
We enter into debt arrangements that have either fixed or floating rates, therefore we are exposed to market risks related to changes in interest rates. We periodically use interest rate swaps to convert our floating rate debt to fixed-rate debt or to convert our fixed-rate debt to floating rate debt. Our primary goals include: (1) maintaining an appropriate ratio of fixed-rate debt to floating-rate debt; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates.
DCP Partners periodically enters into interest rate swap agreements to mitigate a portion of its floating rate interest exposure. DCP Partners had interest rate swap agreements, which settled in June 2014, with notional values totaling $150 million.
In July 2014, we entered into an interest rate swap agreement to convert $50 million of fixed-rate debt securities issued in February 2009 to floating rate debt. Additionally, in July 2014, we entered into an interest rate swap agreement to convert $50 million of fixed-rate debt securities issued in March 2010, to floating rate debt. The interest rate fair value hedges associated with each of these interest rate swap agreements are at a floating rate based on one month LIBOR, which resets monthly and are paid semi-annually through the expiration of the securities in March 2019 and March 2020, respectively. These swap agreements meet conditions that permit the assumption of no ineffectiveness. As such, for the life of the swap agreements no ineffectiveness will be recognized. These interest rate swap agreements were terminated in January 2015, and the remaining long-term fair value relative to these interest rate swap agreements will be reclassified to interest expense, net through March 2019 and March 2020, respectively, the original maturity date of the debt, as the underlying transactions impact earnings.
We previously had interest rate cash flow hedges and fair value hedges in place that were terminated. As a result, the remaining net loss deferred in AOCI relative to these cash flow hedges and the remaining net loss included in long-term debt relative to these fair value hedges will be reclassified to interest expense, net through April 2022 and August 2030, the original maturity dates of the debt, as the underlying transactions impact earnings.
Credit Risk
Our principal customers range from large, natural gas marketers to industrial end-users for our natural gas products and services, as well as large multi-national petrochemical and refining companies, to small regional propane distributors for our NGL products and services. Substantially all of our natural gas and NGL sales are made at market-based prices. Prior to December 31, 2014, approximately 35% of our NGL production was committed to Phillips 66 and CPChem, under 15-year contracts, the primary production commitment of which expired in December 2014 and began a ratable wind down period and expires in January 2019. Approximately 28% of our NGL production was committed to Phillips 66 and CPChem as of December 31, 2015. This concentration of credit risk may affect our overall credit risk, in that these customers may be similarly affected by changes in economic, regulatory or other factors. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of these limits on an ongoing basis. We may use various master agreements that include language giving us the right to request collateral to mitigate credit exposure. The collateral language provides for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with our credit policy. The collateral language also provides that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions. In addition, our master agreements and our standard gas and NGL sales contracts contain adequate assurance provisions, which allow us to suspend deliveries and cancel agreements, or continue deliveries to the buyer after the buyer provides security for payment in a satisfactory form.
Contingent Credit Features
Each of the above risks is managed through the execution of individual contracts with a variety of counterparties. Certain of our derivative contracts may contain credit-risk related contingent provisions that may require us to take certain actions in certain circumstances.
We have International Swaps and Derivatives Association, or ISDA, contracts which are standardized master legal arrangements that establish key terms and conditions which govern certain derivative transactions. These ISDA contracts contain standard credit-risk related contingent provisions. Some of the provisions we are subject to are outlined below.


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DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
If we were to have an effective event of default under our DCP Midstream Amended and Restated Credit Agreement that occurs and is continuing, our ISDA counterparties may have the right to request early termination and net settlement of any outstanding derivative liability positions.
Our ISDA counterparties generally have collateral thresholds of zero, requiring us to fully collateralize any commodity contracts in a net liability position, when our or DCP Partners’ credit rating is below investment grade.
In some cases, our ISDA contracts contain cross-default provisions that could constitute a credit-risk related contingent feature. For example, if we were to fail to make a required interest or principal payment on a debt instrument, above a predefined threshold level, and after giving effect to any applicable notice or grace period as

defined in the ISDA contracts, our ISDA counterparties may have the right to request early termination and net settlement of any outstanding derivative positions.
Our commodity derivative contracts that are not governed by ISDA contracts do not have any credit-risk related contingent features.
Depending upon the movement of commodity prices and interest rates, each of our individual contracts with counterparties to our commodity derivative instruments or interest rate swap instruments are in either a net asset or net liability position. As of December 31, 2015, all of our individual commodity derivative contracts that contain credit-risk related contingent features were in a net asset position. If we were required to net settle our position with an individual counterparty, due to a credit-risk related event, our ISDA contracts may permit us to net all outstanding contracts with that counterparty, whether in a net asset or net liability position, as well as any cash collateral already posted. As of December 31, 2015, we were not required to post additional collateral or offset net liability contracts with contracts in a net asset position because all of our commodity derivative contracts that contain credit-risk related contingent features were in a net asset position.
Collateral
As of December 31, 2015, we had cash deposits of $7 million, included in other current assets in the consolidated balance sheets, and letters of credit of $13 million with counterparties to secure our obligations to provide future services or to perform under financial contracts. Additionally, as of December 31, 2015, we held cash of $10 million, included in other current liabilities in the consolidated balance sheet, related to cash postings by third parties and letters of credit of $20 million from counterparties to secure their future performance under financial or physical contracts. Collateral amounts held or posted may be fixed or may vary, depending on the value of the underlying contracts, and could cover normal purchases and sales, services, trading and hedging contracts. In many cases, we and our counterparties have publicly disclosed credit ratings, which may impact the amounts of collateral requirements.
Physical forward contracts and financial derivatives are generally cash settled at the expiration of the contract term. These transactions are generally subject to specific credit provisions within the contracts that would allow the seller, at its discretion, to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment satisfactory to the seller.
Offsetting
Certain of our derivative instruments are subject to a master netting or similar arrangement, whereby we may elect to settle multiple positions with an individual counterparty through a single net payment. Each of our individual derivative instruments are presented on a gross basis on the consolidated balance sheets, regardless of our ability to net settle our positions. Instruments that are governed by agreements that include net settle provisions allow final settlement, when presented with a termination event, of outstanding amounts by extinguishing the mutual debts owed between the parties in exchange for a net amount due. We have trade receivables and payables associated with derivative instruments, subject to master netting or similar agreements, which are not included in the table below.






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Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
The following tables summarize the gross and net amounts of our derivative instruments:
 
December 31, 2015
 
December 31, 2014
 
Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet
 
Amounts Not Offset in the Balance Sheet - Cash Collateral Received (a)
 
Net Amount
 
Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet
 
Amounts Not Offset in the Balance Sheet - Cash Collateral Received (a)
 
Net Amount
 
(millions)
Assets:
 
 
 
 
 
 
 
 
 
 
 
Commodity derivative instruments
$
175

 
$
(1
)
 
$
174

 
$
187

 
$
(9
)
 
$
178

Interest rate derivative instruments
$

 
$

 
$

 
$
1

 
$

 
$
1

Liabilities:
 
 
 
 
 
 
 
 
 
 
 
Commodity derivative instruments
$
(81
)
 
$

 
$
(81
)
 
$
(139
)
 
$

 
$
(139
)
 
(a) Included in other current liabilities in the consolidated balance sheets.
Summarized Derivative Information
The fair value of our derivative instruments that are designated as hedging instruments, those that are marked to market each period, and the location of each within our consolidated balance sheets, by major category, is summarized below:
 
 
December 31,
 
 
 
December 31,
Balance Sheet Line Item
 
2015
 
2014
 
Balance Sheet Line Item
 
2015
 
2014
 
 
(millions)
 
 
 
(millions)
Derivative Assets Designated as Hedging Instruments:
 
Derivative Liabilities Designated as Hedging Instruments:
Interest rate derivatives:
 
 
 
 
 
Interest rate derivatives:
 
 
 
 
Unrealized gains on derivative instruments - current
 
$

 
$
1

 
Unrealized losses on derivative instruments - current
 
$

 
$

 
 
$

 
$
1

 
 
 
$

 
$

 
 
 
 
 
 
 
 
 
 
 
Derivative Assets Not Designated as Hedging Instruments:
 
Derivative Liabilities Not Designated as Hedging Instruments:
Commodity derivatives:
 
 
 
 
 
Commodity derivatives:
 
 
 
 
Unrealized gains on derivative instruments - current
 
$
156

 
$
164

 
Unrealized losses on derivative instruments - current
 
$
(69
)
 
$
(124
)
Unrealized gains on derivative instruments - long-term
 
19

 
23

 
Unrealized losses on derivative instruments - long-term
 
(12
)
 
(15
)
 
 
$
175

 
$
187

 
 
 
$
(81
)
 
$
(139
)
The following table summarizes the balance and activity within AOCI relative to our interest rate and commodity derivatives, net of noncontrolling interest, as of and for the year ended December 31, 2015:
 
Interest Rate Derivatives
 
Commodity Derivatives
 
Total
 
(millions)
Net deferred losses in AOCI, beginning balance
$
(2
)
 
$
(3
)
 
$
(5
)
Losses reclassified from AOCI - effective portion (a)
1

 

 
1

Net deferred losses in AOCI, ending balance
$
(1
)
 
$
(3
)
 
$
(4
)
Deferred losses in AOCI expected to be reclassified into earnings over the next 12
months
$

 
$

 
$

 
(a) Included in interest expense, net in our consolidated statements of operations.




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DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
The following table summarizes the balance and activity within AOCI relative to our interest rate and commodity derivatives, net of noncontrolling interest, as of and for the year ended December 31, 2014:
 
Interest Rate Derivatives
 
Commodity Derivatives
 
Total
 
(millions)
Net deferred losses in AOCI, beginning balance
$
(3
)
 
$
(3
)
 
$
(6
)
Losses reclassified from AOCI - effective portion (a)
1

 

 
1

Net deferred losses in AOCI, ending balance
$
(2
)
 
$
(3
)
 
$
(5
)
 
(a) Included in interest expense, net in our consolidated statements of operations.
For the years ended December 31, 2015 and 2014, no derivative gains or losses were recognized in trading and marketing gains, net and interest expense, net, respectively, in our consolidated statements of operations attributable to the ineffective portion of our derivative instruments, as a result of exclusion from effectiveness testing or as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.
Changes in value of derivative instruments, for which the hedge method of accounting has not been elected from one period to the next, are recorded in the consolidated statements of operations. The following summarizes these amounts and the location within the consolidated statements of operations that such amounts are reflected:
 
 
Year Ended December 31,
Commodity Derivatives: Statement of Operations Line Item
 
2015
 
2014
 
2013
 
 
(millions)
Realized gains
 
$
73

 
$
45

 
$
31

Unrealized gains
 
46

 
43

 
5

  Trading and marketing gains, net
 
$
119

 
$
88

 
$
36

The following tables represent, by commodity type, our net long or short derivative positions, as well as the number of outstanding contracts that are expected to partially or entirely settle in each respective year. To the extent that we have long dated derivative positions that span multiple calendar years, the contract will appear in more than one line item in the table below. Additionally, relative to the hedging of certain of our storage and/or transportation assets, we may execute basis transactions for natural gas, which may result in a net long/short position of zero. These tables also present our net long or short natural gas basis swap positions separately from our net long or short natural gas positions.
 
 
December 31, 2015
 
 
Crude Oil
 
Natural Gas
 
Natural Gas Liquids
 
Natural Gas Basis Swaps
Year of Expiration
 
Net Short Position (Bbls) (a)
 
Number of Contracts
 
Net
Short
Position (MMBtu) (b)
 
Number of Contracts
 
Net
(Short) Long Position (Bbls)
 
Number of Contracts
 
Net
Long
Position (MMBtu) (b)
 
Number of Contracts
2016
 
(1,566,672
)
 
119

 
(25,059,414
)
 
378

 
(23,575,094
)
 
263

(c)
2,207,500

 
139

2017
 
(237,000
)
 
21

 
(7,387,500
)
 
9

 
(2,082,157
)
 
40

(d)
4,050,000

 
4

2018
 

 

 

 

 
120,000

 
2

 

 

 
(a) Bbls represents barrels.
(b) MMBtu represents one million British thermal units.
(c) Includes 37 physical index based derivative contracts totaling (22,972,000) Bbls.
(d) Includes 1 physical index based derivative contract totaling (2,700,000) Bbls.








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Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
 
 
December 31, 2014
 
 
Crude Oil
 
Natural Gas
 
Natural Gas Liquids
 
Natural Gas Basis Swaps
Year of Expiration
 
Net Short Position (Bbls)
 
Number of Contracts
 
Net
Short
Position (MMBtu)
 
Number of Contracts
 
Net Short Position (Bbls)
 
Number of Contracts
 
Net Long
(Short)
Position (MMBtu)
 
Number of Contracts
2015
 
(1,091,000
)
 
115

 
(18,882,800
)
 
238

 
(21,236,472
)
 
336

(a)
9,200,000

 
66

2016
 
(544,000
)
 
19

 
(3,830,000
)
 
2

 
(4,946,778
)
 
23

(b)
(1,830,000
)
 
10

2017
 

 

 
(6,387,500
)
 
4

 
(2,700,000
)
 
1

(c)

 

 
(a) Includes 41 physical index based derivative contracts totaling (20,649,707) Bbls.
(b) Includes 2 physical index based derivative contracts totaling (5,400,000) Bbls.
(c) Includes 1 physical index based derivative contract totaling (2,700,000) Bbls.

14. Equity-Based Compensation
We recorded equity-based compensation expense as follows, the components of which are further described below:
 
Year Ended December 31,
 
2015
 
2014
 
2013
 
(millions)
DCP Midstream, LLC Long-Term Incentive Plan
$
8

 
$
13

 
$
18

DCP Partners’ Long-Term Incentive Plan (DCP Partners’ LTIP)

 
1

 
2

Total
$
8

 
$
14

 
$
20

 



Vesting Period
(years)
 
Unrecognized
Compensation
Expense at
December 31, 2015
(millions)
 
Estimated
Forfeiture
Rate
 
Weighted-Average Remaining Vesting
(years)
DCP Midstream LTIP:
 
 
 
 
 
Strategic Performance Units (SPUs)
3
 
$
4

 
0%-11%
 
2
Phantom Units
1-3
 
$
4

 
0%-11%
 
2
DCP Midstream LTIP - Under the DCP Midstream LTIP, or LTIP, awards may be granted to our key employees. The DCP Midstream LTIP provides for the grant of Strategic Performance Units, or SPUs, and Phantom Units. The SPUs and Phantom Units consist of a notional unit based on the value of common shares or units of Phillips 66, Spectra Energy and DCP Partners. Each award provides for the grant of dividend or distribution equivalent rights, or DERs. The LTIP is administered by the compensation committee of our board of directors. All awards are subject to cliff vesting.

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Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
Strategic Performance Units - The number of SPUs that will ultimately vest range in value of up to 200% of the outstanding SPUs, depending on the achievement of specified performance targets over a three year period. The final performance payout is determined by the compensation committee of our board of directors. The DERs are paid in cash at the end of the performance period. The following tables presents information related to SPUs:
 
Units
 
Grant Date Weighted-Average Price Per Unit
 
Measurement Date Weighted-Average Price Per Unit
Outstanding at January 1, 2013
267,387

 
$
37.86

 
 
Granted
123,682

 
$
41.01

 
 
Forfeited
(43,658
)
 
$
38.71

 
 
Vested (a)
(116,511
)
 
$
38.02

 
 
Outstanding at December 31, 2013
230,900

 
$
39.30

 
 
Granted
116,790

 
$
54.05

 
 
Forfeited
(13,828
)
 
$
40.75

 
 
Vested (b)
(114,499
)
 
$
37.72

 
 
Outstanding at December 31, 2014
219,363

 
$
47.89

 
 
Granted
111,930

 
$
43.25

 
 
Forfeited
(29,283
)
 
$
48.02

 
 
Vested (c)
(93,551
)
 
$
41.02

 
 
Outstanding at December 31, 2015
208,459

 
$
48.46

 
$
47.39

Expected to vest
203,561

 
$
48.76

 
$
47.35

 
 
 
 
 
 
(a)    The 2011 grants vested at 142%
(b)    The 2012 grants vested at 115%
(c)    The 2013 grants vested at 115%
The estimate of SPUs that are expected to vest is based on highly subjective assumptions that could change over time, including the expected forfeiture rate and achievement of performance targets. Therefore the amounts of unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in our consolidated statements of operations.
The following table presents the fair value of units vested and the unit-based liabilities paid for unit-based awards related to the strategic performance units:
 
Units
 
Fair Value of Units Vested
 
Unit-Based Liabilities Paid
 
(millions)
Vested or paid in cash in 2013
116,511
 
$
8

 
$
7

Vested or paid in cash in 2014
114,499
 
$
7

 
$
8

Vested or paid in cash in 2015
93,551
 
$
4

 
$
7















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Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
Phantom Units - The DERs are paid quarterly in arrears. The following table presents information related to Phantom Units:
 
Units
 
Grant Date Weighted-Average Price Per Unit
 
Measurement Date Weighted-Average Price Per Unit
Outstanding at January 1, 2013
240,200

 
$
38.00

 
 
Granted
134,427

 
$
41.78

 
 
Forfeited
(23,215
)
 
$
39.81

 
 
Vested
(143,890
)
 
$
38.10

 
 
Outstanding at December 31, 2013
207,522

 
$
40.18

 
 
Granted
122,650

 
$
53.73

 
 
Forfeited
(11,130
)
 
$
41.96

 
 
Vested
(147,840
)
 
$
42.10

 
 
Outstanding at December 31, 2014
171,202

 
$
48.11

 
 
Granted
147,540

 
$
47.84

 
 
Forfeited
(17,400
)
 
$
48.40

 
 
Vested
(96,974
)
 
$
44.00

 
 
Outstanding at December 31, 2015
204,368

 
$
49.85

 
$
46.93

Expected to vest
189,422

 
$
49.96

 
$
46.92

The following table presents the fair value of units vested and the unit-based liabilities paid for unit based awards related to the phantom units:
 
Units
 
Fair Value of Units Vested
 
Unit-Based Liabilities Paid
 
 
 
(millions)
 
 
Vested or paid in cash in 2013
143,890
 
$
5

 
$
7

Vested or paid in cash in 2014
147,840
 
$
5

 
$
5

Vested or paid in cash in 2015
96,974
 
$
3

 
$
5

DCP Partners’ LTIP - Under DCP Partners’ 2005 LTIP, which was adopted by DCP Midstream GP, LLC, equity instruments may be granted to key employees, consultants and directors of DCP Midstream GP, LLC and its affiliates who perform services for DCP Partners. The DCP Partners’ 2005 LTIP provides for the grant of limited partner units, or LPUs, phantom units, unit options and substitute awards, and, with respect to unit options and phantom units, the grant of dividend equivalent rights, or DERs. The 2005 LTIP phantom units consist of a notional unit based on the value of DCP Partners’ common units. Subject to adjustment for certain events, an aggregate of 850,000 LPUs may be delivered pursuant to awards under the DCP Partners’ 2005 LTIP. Awards that are canceled or forfeited, or are withheld to satisfy DCP Midstream GP, LLC’s tax withholding obligations, are available for delivery pursuant to other awards. On February 15, 2012, the board of directors of DCP Midstream GP, LLC adopted a 2012 LTIP for employees, consultants and directors of DCP Midstream GP, LLC and its affiliates who perform services for DCP Partners. The 2012 LTIP provides for the grant of phantom units and DERs. The 2012 LTIP phantom units consist of a notional unit based on the value of common units or shares of Phillips 66 and Spectra Energy. The LTIPs were administered by the compensation committee of DCP Midstream GP, LLC’s board of directors through 2012, and by DCP Midstream GP, LLC’s board of directors beginning in 2013. Awards are issued under both LTIPs and all awards are subject to cliff vesting.
Since DCP Partners has the intent and ability to settle certain awards within its control in units, DCP Partners classifies them as equity awards based on their fair value. The fair value of DCP Partners’ equity awards is determined based on the closing price of DCP Partners’ common units at the grant date. Compensation expense on equity awards is recognized ratably over each vesting period. DCP Partners accounts for other awards which are subject to settlement in cash, including DERs, as liability awards. Compensation expense on these awards is recognized ratably over each vesting period, and will be re-


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Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
measured each reporting period for all awards outstanding until the units are vested. The fair value of all liability awards is determined based on the closing price of DCP Partners’ common units at each measurement date.
As of December 31, 2015, there was less than $1 million of unrecognized compensation expense related to DCP Partners LTIP awards.
15. Benefits
All Company employees who have reached the age of 18 and work at least 20 hours per week are eligible for participation in our 401(k) and retirement plan, to which we contribute a range of 4% to 7% of each eligible employee’s qualified earnings to the retirement plan, based on years of service. Effective on January 1, 2015, the Company added an automatic enrollment feature in the 401(k) plan, meaning all new employees are enrolled at a 6% contribution level. Employees can opt out of these contribution level or change it at any time. Additionally, we match employees’ contributions in the 401(k) plan up to 6% of qualified earnings. During the years ended December 31, 2015, 2014 and 2013, we expensed plan contributions of $32 million, $30 million and $28 million, respectively.
We offer certain eligible executives the opportunity to participate in the EDC Plan. The EDC Plan allows participants to defer current compensation on a pre-tax basis and to receive tax deferred earnings on such contributions. The EDC Plan also has make-whole provisions for plan participants who may otherwise be limited in the amount that we can contribute to the 401(k) plan on the participant’s behalf. In 2013, we liquidated the net cash surrender value of our company owned life insurance policies, in order to change service providers, and received proceeds of $29 million, which we re-invested with a new service provider in 2013. Under the new service plan, all amounts contributed to and earned by the EDC Plan’s investments are held in a trust account for the benefit of the EDC Plan participants, or general creditors in the event of our insolvency, as defined in the trust agreement. The trust assets and liability to the EDC Plan participants are part of our general assets and liabilities, respectively.
16. Income Taxes
We are structured as a limited liability company, which is a pass-through entity for federal income tax purposes. We own a corporation that files its own federal, foreign and state corporate income tax returns. The income tax benefit (expense) related to this corporation is included in our income tax benefit (expense), along with state and local taxes of the limited liability company and other subsidiaries.
Income tax benefit (expense) consisted of the following:
 
Year Ended December 31,
 
2015
 
2014
 
2013
 
(millions)
Current:
 
 
 
 
 
State income tax expense
$

 
$
(2
)
 
$
(6
)
Deferred:
 
 
 
 
 
Federal income tax benefit (expense)
97

 

 
(1
)
State income tax benefit (expense)
5

 
(9
)
 
(3
)
Total income tax benefit (expense)
$
102

 
$
(11
)
 
$
(10
)













F-41

Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
Deferred income tax assets and liabilities consisted of the following:
 
December 31,
 
2015
 
2014
 
(millions)
Deferred income tax assets:
 
 
 
Net operating loss
$
58

 
$
51

Total deferred income tax assets
58

 
51

Deferred income tax liabilities:
 
 
 
Property, plant and equipment and intangibles - federal
(35
)
 
(125
)
Property, plant and equipment and intangibles - state
(26
)
 
(31
)
Total deferred income tax liabilities
(61
)
 
(156
)
Net deferred income tax liabilities
(3
)
 
(105
)
 
 
 
 
Deferred income tax assets, net - noncurrent
23

 

Deferred income tax liabilities, net - noncurrent
(26
)
 
(105
)
 
 
 
 
Net deferred income tax liabilities
$
(3
)
 
$
(105
)
Deferred income tax assets, net are included in other long-term assets on the consolidated balance sheet as of December 31, 2015. The state deferred tax liabilities are primarily associated with Texas franchise taxes. During the year ended December 31, 2015, we recorded a reduction to our deferred tax liability of $95 million as a result of property, plant, and equipment and intangible asset impairments.
As of December 31, 2015 and 2014, our net operating losses were $163 million and $147 million, respectively. The net operating losses begin expiring in 2027. We expect to fully utilize the net operating loss carryovers, and, accordingly we have not provided a valuation allowance for the net deferred tax asset.
Our effective tax rate differs from statutory rates primarily due to our structure as a limited liability company, which is a pass-through entity for federal income tax purposes, while being treated as a taxable entity in certain states. Additionally, one of our subsidiaries is a tax paying entity for federal income tax purposes.
17. Commitments and Contingent Liabilities
Litigation - The midstream industry has seen a number of class action lawsuits involving royalty disputes, mismeasurement and mispayment allegations. We are currently named as defendants in some of these cases and customers have asserted individual audit claims related to mismeasurement and mispayment. Management believes we have meritorious defenses to these cases and, therefore, will continue to defend them vigorously. These claims, however, can be costly and time consuming to defend. We are also a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business, including, from time to time, disputes with customers over various measurement and settlement issues.
Management currently believes that these matters, taken as a whole, and after consideration of amounts accrued, insurance coverage and other indemnification arrangements, will not have a material adverse effect upon our consolidated results of operations, financial position or cash flows.
General Insurance - Our insurance coverage is carried with an affiliate of Phillips 66, an affiliate of Spectra Energy and third-party insurers. Our insurance coverage includes: (1) general liability insurance covering third-party exposures; (2) statutory workers’ compensation insurance; (3) automobile liability insurance for all owned, non-owned and hired vehicles; (4) excess liability insurance above the established primary limits for general liability and automobile liability insurance; (5) property insurance, which covers the replacement value of real and personal property and includes business interruption; and (6) insurance covering our directors and officers for acts related to our business activities. All coverage is subject to certain limits and deductibles, the terms and conditions of which are common for companies with similar types of operations.


F-42

Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
Environmental - The operation of pipelines, plants and other facilities for gathering, processing, compressing, transporting, or storing natural gas, and fractionating, transporting, gathering, processing and storing NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities incorporates compliance with environmental laws and regulations and safety standards. In addition, there is increasing focus, from city, state and federal regulatory officials and through litigation, on hydraulic fracturing and the real or perceived environmental impacts of this technique, which indirectly presents some risk to our available supply of natural gas. Failure to comply with these various health, safety and environmental laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.
We make expenditures in connection with environmental matters as part of our normal operations. As of December 31, 2015 and 2014, environmental liabilities included in the consolidated balance sheets as other current liabilities amounted to $3 million and $5 million, respectively. As of both December 31, 2015 and 2014, environmental liabilities included in the consolidated balance sheets as other long-term liabilities amounted to $9 million.
Operating Leases - We utilize assets under operating leases in several areas of operations. Consolidated rental expense, including leases with no continuing commitment, amounted to $34 million, $31 million and $36 million during the years ended December 31, 2015, 2014 and 2013, respectively. Rental expense for leases with escalation clauses is recognized on a straight line basis over the initial lease term.
Minimum rental payments under our various operating leases in the year indicated are as follows:
 
Minimum Rental Payments
 
(millions)
2016
$
60

2017
39

2018
36

2019
34

2020
29

Thereafter
63

Total minimum lease payments
$
261

18. Guarantees and Indemnifications
We periodically enter into agreements for the acquisition, contribution or divestiture of assets. These agreements contain indemnification provisions that may provide indemnity for environmental, tax, employment, outstanding litigation, breaches of representations, warranties and covenants, performance of DCP Partners or other liabilities related to the assets being acquired, contributed or divested. Claims may be made by third parties or DCP Partners under these indemnification agreements for various periods of time depending on the nature of the claim. The effective periods on these indemnification provisions generally have terms of one to 15 years, although some are longer. Our maximum potential exposure under these indemnification agreements can vary depending on the nature of the claim and the particular transaction. We are unable to estimate the total maximum potential amount of future payments under indemnification agreements due to several factors, including uncertainty as to whether claims will be made under these indemnities. We have issued guarantees and indemnifications for certain of our consolidated subsidiaries.







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Table of Contents

DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2015, 2014 and 2013
19. Restructuring Costs
As part of our effort to create efficiencies and reduce costs, we implemented a plan to reduce general and administrative and non-core operational costs. In January 2015, we announced the initial phase of this cost reduction plan, which involved the elimination of certain corporate employee positions. As a result, we recorded employee termination costs of approximately $11 million, all of which were paid during the year ended December 31, 2015, and are included in restructuring costs within total operating costs and expenses in the consolidated statement of operations for the year ended December 31, 2015.
We have identified additional opportunities to streamline operations and identify cost savings. The costs associated with these actions will be recorded when specified criteria are met, such as abandonment of leased facilities, contract and project termination, consolidation of facilities and employee relocation.
20. Supplemental Cash Flow Information
 
Year Ended December 31,
 
2015
 
2014
 
2013
 
(millions)
Cash paid for interest, net of capitalized interest
$
293

 
$
274

 
$
229

Cash paid for income taxes, net of income tax refunds received
$
3

 
$
4

 
$
6

 
 
 
 
 
 
Non-cash investing and financing activities:
 
 
 
 
 
Contribution from member
$
1,500

 
$

 
$

Property, plant and equipment acquired with accrued liabilities
$
35

 
$
145

 
$
82

Other non-cash changes in property, plant and equipment
$
(19
)
 
$
27

 
$
77

21. Subsequent Events
We have evaluated subsequent events occurring through February 25, 2016, the date the consolidated financial statements were issued.
In January 2016, we reached a settlement with a large producer in the DJ basin and received a cash payment of $89 million, a dedication of a portion of the producer’s production in the DJ Basin under a life of lease agreement and a 15 year dedication of natural gas liquids from the producer and its affiliates to the Sand Hills pipeline in the Delaware basin of the Permian region. The cash payment will be recognized as earnings in the first quarter of 2016.
On January 28, 2016, DCP Partners announced that the board of directors of DCP Partners’ general partner declared a quarterly distribution of $0.78 per unit, payable on February 12, 2016 to unitholders of record on February 8, 2016.