Spectra Energy Corp.
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.
On September 6, 2016, we announced that we entered into a definitive merger agreement with Enbridge Inc. (Enbridge) under which Enbridge and Spectra Energy will combine in a stock-for-stock merger transaction, which values Spectra Energy’s stock at approximately $28 billion, based on the closing price of Enbridge’s common shares as of September 2, 2016. This transaction was approved by the boards of directors and shareholders of both Spectra Energy and Enbridge and has received all necessary regulatory approvals. The transaction is expected to close on February 27, 2017.
Upon completion of the proposed merger, Spectra Energy shareholders will receive 0.984 Enbridge common shares for each share of Spectra Energy stock they own. The consideration to be received by Spectra Energy shareholders is valued at $40.33 per Spectra Energy share, based on the closing price of Enbridge common shares as of September 2, 2016, representing an approximate 11.5% premium to the closing price of Spectra Energy stock as of September 2, 2016. Upon completion of the merger, Enbridge shareholders are expected to own approximately 57% of the combined company and Spectra Energy shareholders are expected to own approximately 43%.
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.
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 75% equity interest in SEP, a natural gas and crude oil infrastructure master limited partnership, which owns 100% of Texas Eastern Transmission, LP (Texas Eastern), 91% 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).
In October 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.
Texas Eastern
We have an effective 75% 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 75 Bcf, owned by Market Hub and Bobcat.
Algonquin
We have an effective 68% 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.
East Tennessee
We have an effective 75% 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.
Maritimes & Northeast Pipeline
We have an effective 59% 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.
Ozark
We have an effective 75% 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.
Big Sandy
We have an effective 75% 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.
Gulfstream
We have an effective 38% 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.
Express-Platte
We have an effective 75% ownership interest in Express-Platte 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 and crude oil storage of approximately 5.6 million barrels. 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.
SESH
We have an effective 38% 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 six 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.
Market Hub
We have an effective 75% 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 46 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 ten interconnections serving eight pipeline systems, including the Texas Eastern system.
Saltville
We have an effective 75% 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 75% ownership interest in Bobcat through our ownership of SEP. Bobcat, an approximately 29 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 38% 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, flexibility and reliability of service.
The natural gas transported in our transmission business competes with other forms of energy available to our customers and end-users, including electricity, coal, propane and fuel oils. Factors that influence the demand for natural gas include price changes, the availability of natural gas and other forms of energy, levels of business activity, long-term economic conditions, conservation, legislation, governmental regulations, the ability to convert to alternative fuels, weather and other factors.
Spectra Energy Partners’ crude oil transportation business competes with pipelines, rail, truck and barge facilities that transport crude oil from production areas to refinery markets. The principal elements of competition are location, rates, terms of service, flexibility and reliability of service.
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.
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 1.5 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 (Dawn), 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 or control the supply of natural gas from the point of local supply to customers. Union Gas’ underground natural gas storage facilities have a working capacity of approximately 165 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, the OEB Decision in the Generic Proceeding on Community Expansion provides a framework that facilitates the entry of new participants and allows for competition as it pertains to serving rural and First Nation communities that do not currently have access to natural gas.
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.
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.
WESTERN CANADA TRANSMISSION & PROCESSING
Our Western Canada Transmission & Processing business is comprised of the BC Pipeline, BC Field Services, Canadian Midstream and M&N Canada.
On August 4, 2016, Westcoast Energy Inc. (Westcoast) completed the sale of its ownership interest in the Empress NGL operations (Empress) to Plains Midstream Canada ULC. See Part II. Item 8. Financial Statements and Supplementary Data, Note 3 of Notes to Consolidated Financial Statements for further discussion.
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 nine natural gas processing plants and approximately 600 miles of gathering pipelines. This business is primarily regulated by the province where the assets are located, either BC or 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 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.
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. 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 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.
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.
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. As of December 31, 2016, DCP Midstream owned an approximate 21% interest in DCP Midstream Partners, LP (DCP Partners), a publicly traded master limited partnership which traded 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 January 1, 2017, DCP Midstream and DCP Partners closed a transaction combining the two companies. The combined company was renamed DCP Midstream, LP which currently trades on the NYSE under the symbol "DCP." DCP Midstream currently owns an approximate 38% interest in DCP Midstream, LP following the transaction.
In October 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.
As of December 31, 2016 DCP Midstream owned or operated 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 64,000 miles of gathering and transmission pipeline.
As of December 31, 2016, DCP Midstream also owned or operated 61 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, 2016, DCP Midstream owned or operated 12 fractionators. In addition, DCP Midstream operates a propane wholesale marketing business and an 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 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. 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 27% of DCP Midstream’s NGL production was committed to Phillips 66 and CPChem as of December 31, 2016. 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.
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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.
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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. 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. 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.
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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 and crude oil transportation 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 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.
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:
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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.
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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.
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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.
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The Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act, which requires certain solid wastes, including hazardous wastes, to be managed pursuant to a comprehensive regulatory regime. As part of our business, we generate solid waste within the scope of these regulations and therefore must comply with such regulations.
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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.
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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:
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The Fisheries Act (Canada), which regulates activities near any body of water in Canada.
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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.
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The Canadian Environmental Protection Act, which, among other things, requires the reporting of greenhouse gas (GHG) emissions from our operations in Canada. Additional regulations to be promulgated under this Act may require the reduction of GHGs, nitrogen oxides, sulphur oxides, volatile organic compounds and particulate matter.
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The Canadian Environmental Assessment Act, 2012 (CEAA 2012) requires the NEB to consider potential environmental effects in its decisions for designated projects. The NEB under its enabling statute also conducts
environmental assessments for projects that are not specifically designated under CEAA 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 21, of Notes to Consolidated Financial Statements.
Except to the extent discussed in Notes 5 and 21, 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 20 of Notes to Consolidated Financial Statements.
Employees
We had approximately 6,000 employees as of December 31, 2016, including approximately 3,600 employees in Canada. In addition, DCP Midstream employed approximately 2,700 employees as of such date. Approximately 1,300 of our Canadian employees are subject to collective bargaining agreements governing their employment with us. Approximately 80% of those employees are covered under agreements that either have expired or will expire by December 31, 2017.
Executive and Other Officers
The following table sets forth information regarding our executive and other officers.
Name
Age
Position
Gregory L. Ebel
President and Chief Executive Officer, Director
J. Patrick Reddy
Chief Financial Officer
Dorothy M. Ables
Chief Administrative Officer
Guy G. Buckley
Chief Development Officer
Julie A. Dill
Chief Communications Officer
Reginald D. Hedgebeth
General Counsel
William T. Yardley
President, U.S. Transmission and Storage
Allen C. Capps
Vice President and Controller
Laura Buss Sayavedra
Vice President and Treasurer
Gregory L. Ebel assumed his current position as President and Chief Executive Officer in January 2009. Mr. Ebel currently serves as the Chairman of the Board of Directors of both, Spectra Energy Corp and Spectra Energy Partners GP, LLC. He also serves on the Board of Directors of DCP Midstream, LLC.
J. Patrick Reddy joined Spectra Energy in January 2009 as Chief Financial Officer. Mr. Reddy 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. 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. Mr. Buckley currently serves on the Board of Directors of DCP Midstream, LLC.
Julie A. Dill assumed her current position as Chief Communications Officer in January 2014. Ms. Dill previously served as Group Vice President-Strategy from January 2012 to December 2013, and as President and Chief Executive Officer of Spectra Energy Partners GP, LLC from January 2012 to October 2013. 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.
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.
Laura Buss Sayavedra assumed her current position as Vice President and Treasurer in January 2014. Ms. Sayavedra previously served as Vice President-Strategy from March 2013 to December 2013, and as Vice President and Chief Financial Officer of Spectra Energy Partners GP, LLC from July 2008 to February 2013.
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:
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weather conditions, such as abnormally mild winter or summer weather, resulting in lower energy usage for heating or cooling purposes, respectively;
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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;
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capacity and transmission service into, or out of, our markets; and
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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 2016 would have resulted in an estimated net loss on the translation of local currency earnings of approximately $22 million on our Consolidated Statement of Operations. In addition, if a 10% devaluation had occurred on December 31, 2016, the Consolidated Balance Sheet would have been negatively impacted by $389 million through a cumulative translation adjustment in Accumulated Other Comprehensive Income (AOCI). At December 31, 2016, one U.S. dollar translated into 1.34 Canadian dollars.
In addition, we maintain credit facilities that typically include financial covenants which limit the amount of debt that can be outstanding as a percentage of total capital for Spectra Energy or of a specific subsidiary. Failure to maintain these covenants could preclude us from issuing commercial paper or letters of credit, or borrowing under our revolving credit facilities, and could require other affiliates to immediately pay down any outstanding drawn amounts under other revolving credit agreements, which could affect cash flows or restrict business. Foreign currency fluctuations have a direct impact on our ability to maintain certain of these financial covenants.
Natural gas gathering and processing, 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, natural gas and to oil primarily in our Field Services segment. The effect of commodity price fluctuations on our earnings could be material.
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:
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the ability to obtain necessary approvals and permits from 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;
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the availability of skilled labor, equipment and materials to complete expansion projects;
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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;
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impediments on our ability to acquire rights-of-way or land rights on a timely basis and on acceptable terms;
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the ability to construct projects within anticipated costs, including the risk of cost overruns resulting from inflation or increased costs of equipment, materials or labor, weather, geologic conditions or other factors beyond our control, that may be material; and
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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.
We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any necessary pipeline repair or preventative or remedial measures.
The DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transmission pipelines located where a leak or rupture could do the most harm in “high consequence areas.” The regulations require operators to:
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perform ongoing assessments of pipeline integrity;
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identify and characterize applicable threats to pipeline segments that could affect a high consequence area;
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improve data collection, integration and analysis;
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repair and remediate the pipeline as necessary; and
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implement preventive and mitigating actions.
Our actual implementation costs may be affected by industry-wide demand for the associated contractors and service providers. Additionally, should we fail to comply with DOT regulations, we could be subject to penalties and fines
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. Additionally, PHMSA will establish standards for storage facilities. 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 pipeline operations are subject to pipeline safety regulations overseen by the NEB or provincial regulators. Applicable legislation and regulation require us to comply with a significant set of requirements for the design, construction, maintenance and operation of our 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, as well as to impose financial requirements for future abandonment and major pipeline releases.
Compliance with these legislative changes may impose additional costs on new Canadian pipeline projects as well as on existing operations. Failure to comply with applicable regulations could result in a number of consequences which may have an adverse effect on our operations, earnings, financial condition and cash flows.
Our operations are subject to numerous environmental laws and regulations, compliance with which may require significant capital expenditures, increase our cost of operations and affect or limit our business plans, or expose us to environmental liabilities.
We are subject to numerous environmental laws and regulations affecting many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations can result in increased capital, operating and other costs. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Compliance with environmental laws and regulations can require significant expenditures, including expenditures for cleanup costs and damages arising out of contaminated properties. In particular, compliance with major Clean Air Act regulatory programs 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 parts per billion (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). 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. We expect that costs we incur to comply with environmental regulations in the future will have a significant effect on our earnings and cash flows.
Due to the speculative outlook regarding any U.S. federal and state 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 outcomes of which are uncertain, and resolutions adverse to us could negatively affect our earnings, financial condition and cash flows.
We are subject to numerous legal proceedings. Litigation is subject to many uncertainties, and we cannot predict the outcome of individual matters with assurance. It is reasonably possible that the final resolution of some of the matters in which we are involved could require additional expenditures, in excess of established reserves, over an extended period of time and in a range of amounts that could have a material effect on our earnings and cash flows.
We rely on access to short-term and long-term capital markets to finance capital requirements and support liquidity needs, and access to those markets can be affected, particularly if we or our rated subsidiaries are unable to maintain an investment-grade credit rating, which could affect our cash flows or restrict business.
Our business is financed to a large degree through debt. The maturity and repayment profile of debt used to finance investments often does not correlate to cash flows from assets. Accordingly, we rely on access to both short-term and long-term capital markets as a source of liquidity for capital requirements not satisfied by cash flows from operations and to fund investments originally financed through debt. Our senior unsecured long-term debt is currently rated investment-grade by various rating agencies. If the rating agencies were to rate us or our rated subsidiaries below investment-grade, our borrowing costs would increase, perhaps significantly. Consequently, we would likely be required to pay a higher interest rate in future financings and our potential pool of investors and funding sources could decrease.
We maintain revolving credit facilities to provide back-up for commercial paper programs for borrowings and/or letters of credit at various entities. These facilities typically include financial covenants which limit the amount of debt that can be outstanding as a percentage of the total capital for the specific entity. Failure to maintain these covenants at a particular entity could preclude that entity from issuing commercial paper or letters of credit or borrowing under the revolving credit facility and could require other affiliates to immediately pay down any outstanding drawn amounts under other revolving credit agreements, which could affect cash flows or restrict business. Furthermore, if Spectra Energy’s short-term debt rating were to be below tier 2 (for example, A-2 for Standard and Poor’s, P-2 for Moody’s Investor Service and 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 Ontario, 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 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 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, 2016, 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, 2016.
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.
Except for the matters described below, we have no material pending legal proceedings that are required to be disclosed hereunder. For information regarding other legal proceedings, including regulatory and environmental matters, see Notes 5 and 21 of Notes to Consolidated Financial Statements.
We and our board of directors are named as defendants in six putative class action lawsuits filed by purported stockholders of Spectra Energy that challenge the proposed merger with Enbridge. The lawsuits include Paul Parshall v. Spectra Energy Corp, et al., 12809-CB, filed in the Court of Chancery for the State of Delaware, and Mary Lincoln v. Spectra Energy Corp, et al., 16-cv-03019, Joseph Koller v. Spectra Energy Corp, et al., 16-cv-03059, Joseph Costner v. Spectra Energy Corp et al., 16-cv-03065, John L. Williams v. Spectra Energy Corp et al., 16-cv-03069, and Joseph McMillan v. Spectra Energy Corp et al., 16-cv-03130, all filed in the United States District Court for the Southern District of Texas. The complaints allege, among other things, that Spectra Energy and its board of directors breached their fiduciary duties (in the Delaware lawsuit) and violated Sections 14(a) and 20(a) of the Exchange Act and Rule 14a-9 promulgated thereunder (in the Southern District of Texas lawsuits), as applicable, by issuing or causing to be issued an allegedly materially misleading and incomplete preliminary
proxy statement in connection with the proposed merger. Enbridge and its subsidiary are also named as defendants in the Delaware lawsuit, and the Delaware complaint alleges, among other things, that Enbridge and its subsidiary aided and abetted Spectra Energy’s board of directors’ alleged breach of fiduciary duties. Plaintiffs seek as relief, among other things, an injunction against the merger, rescission of the merger to the extent it is already implemented, declaratory relief, costs and attorneys’ fees, and/or damages. We believe the actions are without merit and intend to vigorously defend against them.
Item 4. Mine Safety Disclosures.
Not applicable.
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Our common stock is traded on the NYSE under the symbol “SE.” As of January 31, 2017, there were approximately 100,245 holders of record of our common stock and approximately 573,800 beneficial owners.
Common Stock Data by Quarter
_________
(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, 2012 through December 31, 2016 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.
Dividends
Consistent with our near-term objective of increasing our cash dividend by $0.14 per year through 2018, we announced a $0.14 annual dividend increase on January 5, 2017. We expect to continue our policy of paying regular cash dividends. The declaration and payment of dividends are subject to the sole discretion of our Board of Directors and will depend upon many factors, including the financial condition, earnings and capital requirements of our operating subsidiaries, covenants associated with certain debt obligations, legal requirements, regulatory constraints and other factors deemed relevant by our Board of Directors.
Issuer Purchases of Equity Securities
_________
(a) Includes deemed repurchase of shares of common stock from company employees in connection with the company’s long-term incentive plan.
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.
INTRODUCTION
Management’s Discussion and Analysis should be read in conjunction with Item 8. Financial Statements and Supplementary Data.
EXECUTIVE OVERVIEW
Throughout 2016, 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 2017 to $0.44 per share, which represents an increase in our annual dividend by $0.14 per share per year.
During 2016, our earnings increased mainly due to expansion projects at Spectra Energy Partners and impairments in 2015 at Field Services, partially offset by pipeline inspection and repair costs related to the Texas Eastern incident near Delmont, Pennsylvania at Spectra Energy Partners and a lower Canadian dollar at Distribution and Western Canada Transmission & Processing.
We reported net income from controlling interests of $693 million and $1.00 of earnings per share for 2016 compared to net income from controlling interests of $196 million and $0.29 of earnings per share for 2015.
Earnings highlights for 2016 compared to 2015 include the following:
•
Spectra Energy Partners’ earnings benefited mainly from expansion projects, more than offset by pipeline inspection and repair costs related to the Texas Eastern incident near Delmont, Pennsylvania.
•
Distribution’s earnings remained flat mainly due to incremental earnings from the 2015 Dawn-Parkway expansion project and higher storage margins, offset by the effect of a lower Canadian dollar and warmer weather.
•
Western Canada Transmission & Processing’s earnings decreased mainly due to lower firm gathering and processing revenues and the effect of a lower Canadian dollar, partially offset by lower plant turnaround costs.
•
Field Services’ earnings increased mainly due to the 2015 impairments of goodwill and other assets and an increase in gathering and processing margins, partially offset by expiration of hedges in 2016 and unfavorable results of initiatives to mitigate commodity price risk.
We invested $3.9 billion of capital and investment expenditures in 2016, including $3.3 billion of expansion and investment capital expenditures. Successful execution of our 2016 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 $4.6 billion planned for 2017, 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 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, 2016, our revolving credit facilities included Spectra Energy Capital, LLC’s (Spectra Capital’s) two facilities totaling $3.0 billion, SEP’s $2.5 billion facility, Westcoast’s 400 million Canadian dollar facility, and Union Gas’ 700 million Canadian dollar facility. These facilities are used principally as back-stops for commercial paper programs. At December 31, 2016 and 2015, our consolidated debt-to-capitalization ratio was 56.4% and 59.8%, respectively.
On September 6, 2016, we announced that we entered into a definitive merger agreement with Enbridge under which Enbridge and Spectra Energy will combine in a stock-for-stock merger transaction, which values Spectra Energy’s stock at approximately $28 billion, based on the closing price of Enbridge’s common shares as of September 2, 2016. This transaction was approved by the boards of directors and shareholders of both Spectra Energy and Enbridge and has received all necessary regulatory approvals. The transaction is expected to close in February 27, 2017.
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 to premium markets. We will grow our business by way of 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.
•
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 evolve, 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 to Mexico) 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 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. In recent years, growing North American crude oil production displaced imports from overseas and led to increased demand for crude oil transportation and logistics. Although depressed global crude oil prices resulted in declining North American oil production, we expect a return to attractive pricing and growing North American production outlook. Thus, we remain confident about long-term growth in North American oil production and our ability to capture future liquids and crude oil pipeline business.
Successful execution of our strategy will depend on maintaining our reputation and leadership as a safe and reliable operator and the effective execution of our capital projects. Continued growth and new opportunities will be determined by key factors, such as the continued growth and production 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 2020. This demand growth is primarily driven by the natural gas-fired electricity generation sector, including regional Gulf Coast exports of LNG, exports to Mexico and a significant industrial and petrochemical expansion. 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 still includes significant production from traditional sources in the Rockies, Midcontinent, and the U.S. Gulf Coast and is augmented by significant resource growth in Appalachia and west Texas. Also, significant supply sources continue to be identified for development in western Canada. These supply shifts are shaping the growth strategies that we 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 social and environmental activism and political pressures have arisen around the production processes associated with extracting natural gas from 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 uncertainty on timing of permitting and execution of new projects.
Our key crude oil markets include the Rocky Mountain and Midwest states. Growth in our business is dependent on incremental crude oil supply from North American sources and the ability of that supply to displace imported crude oil from overseas. Lower crude oil prices over the past two years have 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. Over the past two years, commodity prices have declined substantially and have experienced significant volatility. Drilling activity levels vary by geographic area. As a result of lower commodity prices, some regions may see larger reductions in activity than others based on basin economics. Sustained low commodity prices could result in a decrease in exploration and development activities in the fields served by DCP Midstream’s gas gathering, 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.
While the increase in natural gas supply has been largely positive for midstream companies, lower price dynamics and shifting preferences on producing basins may impact some of our business and pipelines in the long-term. The supply increase has 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, however, significant increases in demand on the Gulf Coast, particularly for exports, should improve the value of our storage service in the future.
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 off-site impacts of our operations, install emissions 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 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. Additionally, PHMSA issued an interim final rule, effective January 2017, that addresses safety issues related to underground natural gas storage facilities. We believe our existing storage facilities conform to the majority of the requirements of the new rule.
In light of the changing environmental and safety laws and regulations described above, we are evaluating efforts required to maintain compliance with such laws and regulations and, in addition, are assessing ways to improve overall system integrity, efficiency and reliability. The capital costs to effectively modernize our pipelines accordingly will be substantial and will be incurred over several years.
Additionally, investments and projects located in Canada expose us to risks related to Canadian laws, taxes, economic conditions, fluctuations in currency rates, political conditions and policies of the Canadian government. During the past several years, the Canadian dollar has fluctuated compared to the U.S. dollar, which affected earnings to varying degrees for brief periods. Changes in the exchange rate or any other factors are difficult to predict and may affect our future results.
Certain of our segments’ earnings are affected by fluctuations in commodity prices, especially the earnings of Field Services, which is 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.
Based on current projections, our expected effective income tax rate will approximate 20%-21% for 2017. 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 2017, 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 have also experienced increased scrutiny placed on the permitting and construction of new projects from social and environmental activism; which can sometimes impact the timing of when construction activities, and the ultimate completion of a project, can occur relative to the expected timeline. 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.
RESULTS OF OPERATIONS
2016 Compared to 2015
Operating Revenues. The $318 million decrease was driven by:
•
lower firm gathering and processing revenues, a decrease from the sale of Empress in August 2016 and lower NGL prices at Western Canada Transmission & Processing,
•
lower natural gas prices passed through to customers and lower usage due to warmer weather, partially offset by growth in the number of customers, incremental earnings from the 2015 Dawn-Parkway expansion project, higher rates due to increased demand side management (DSM) program charges and higher storage margins at Distribution and
•
the effects of a lower Canadian dollar at Distribution and Western Canada Transmission & Processing, partially offset by
•
higher revenues from expansion projects at Spectra Energy Partners.
Operating Expenses. The $474 million decrease was driven by:
•
lower plant turnaround costs, lower costs of NGL sales and a decrease from the sale of Empress in August 2016 at Western Canada Transmission & Processing,
•
lower natural gas prices passed through to customers and lower volumes of natural gas sold due to warmer weather, partially offset by growth in the number of customers and higher DSM program charges, net of lower employee related charges at Distribution,
•
the effects of a lower Canadian dollar at Distribution and Western Canada Transmission & Processing and
•
the 2015 goodwill impairment charges associated with the Westcoast acquisition in 2002 at Other, partially offset by
•
higher costs related to the merger with Enbridge and higher employee benefits costs at Other and
•
pipeline inspection and repair costs, higher costs related to expansion and property tax accruals due to the absence of a 2015 tax benefit at Spectra Energy Partners.
Gain (loss) on sales of other assets and other, net. The $30 million change was primarily the result of the sale of the Pesh natural gas processing facilities in the fourth quarter of 2016 at Western Canada Transmission & Processing.
Other Income and Expenses. The $447 million change was primarily attributable to higher equity earnings from Field Services mainly due to the 2015 impairments of goodwill and other assets at DCP Midstream.
Interest Expense. The $42 million decrease was mainly due to higher capitalized interest, the reversal of an interest accrual related to the release of tax reserves, and a lower Canadian dollar, partially offset by higher average long-term debt balances.
Income Tax Expense. The $55 million increase was primarily attributable to tax benefits associated with loss on investment due to impairments of goodwill and other assets at DCP Midstream in 2015, partially offset by the sale of Empress, tax rate changes and the release of tax reserves in 2016.
The effective tax rate was 17.5% in 2016 compared to 26% in 2015. 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 primarily by higher noncontrolling ownership interests at Spectra Energy Partners, partially offset by lower earnings at Spectra Energy Partners.
2015 Compared to 2014
Operating Revenues. The $669 million decrease was driven by:
•
the effects of a lower 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 Empress 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 $173 million decrease was driven by:
•
the effects of a lower 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 lower 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 lower 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.
For a more detailed discussion of earnings drivers, see the segment discussions that follow.
Segment Results
Management evaluates segment performance based on earnings before interest, 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 from 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 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 and natural gas gathering and processing services to customers in western Canada, the U.S. Pacific Northwest 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, 2016, 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
___________
(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.
Spectra Energy Partners
____________
(a)
Thousand barrels per day.
2016 Compared to 2015
Operating Revenues. The $78 million increase was driven by:
•
a $113 million increase due to expansion projects, primarily on Texas Eastern and Algonquin,
•
a $7 million increase in storage revenues due to new contracts at higher rates and
•
a $7 million increase in crude oil transportation revenues due to the Express Enhancement expansion project placed into service in October 2016, partially offset by
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a $16 million decrease in recoveries of electric power and other costs passed through to gas transmission customers,
•
a $15 million decrease in processing revenues primarily due to lower volumes,
•
a $10 million decrease in crude oil transportation revenues, as a result of lower volumes primarily on the Platte pipeline, substantially offset by increased tariff rates mainly on the Express pipeline and
•
a $9 million decrease in natural gas transportation revenues mainly from interruptible transportation on Texas Eastern and M&N U.S. and short-term firm transportation on Algonquin.
Operating, Maintenance and Other. The $89 million increase was driven by:
•
an $80 million increase due to pipeline inspection and repair costs related to the Texas Eastern incident near Delmont, Pennsylvania,
•
a $47 million increase in costs related to expansion and
•
an $11 million increase in property tax accruals due to the absence of a 2015 tax benefit, partially offset by
•
a $16 million decrease in electric power and other costs passed through to gas transmission customers,
•
an $11 million decrease in power costs due to lower usage in 2016 and maintenance costs on the Express and Platte pipelines,
•
a $9 million decrease due to a prior year non-cash impairment charge on Ozark Gas Gathering,
•
an $8 million decrease in operating costs and
•
a $4 million decrease in project development costs.
Other Income and Expenses. The $15 million increase was mainly due to higher allowance for funds used during construction (AFUDC) resulting from higher capital spending on expansion projects, partially offset by the absence of equity earnings from Sand Hills and Southern Hills owned until October 2015.
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 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 U.S. Asset Dropdown of an additional 24.95% interest in SESH.
Matters Affecting Future Spectra Energy Partners Results
We plan to grow our earnings 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 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 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 impairment of our storage assets.
Spectra Energy Partners also plans to continue earnings growth by maximizing throughput on all sections of the pipeline systems. This entails connecting, where possible, to downstream pipelines, 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 all pipelines. This will require ongoing increases in supply of crude oil and continued access to attractive markets.
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.
FERC’s current policy permits pipelines and storage companies to include a tax allowance in the cost-of-service used as the basis for calculating their regulated rates. For pipelines and storage companies owned by partnerships or limited liability company interests, the current tax allowance policy reflects the actual or potential income tax liability on the FERC jurisdictional income attributable to all partnership or limited liability company interests if the ultimate owner of the interest has an actual or potential income tax liability on such income. On December 15, 2016, FERC issued a Notice of Inquiry requesting energy industry input on how the FERC should address income tax allowances in cost-based rates proposed by pipeline companies organized as part of a master limited partnership. This Notice of Inquiry was issued in response to a remand from the U.S. Court of Appeals for the D.C. Circuit in United Airlines v. FERC, in which the court determined that FERC had not justified its conclusion that an oil pipeline organized as a partnership would not “double recover” its taxes under the current policy by both including a tax allowance in its cost-based rates and earning a return on equity calculated on a pre-tax basis. We cannot predict whether the FERC will successfully justify its conclusion that there is no double recovery of taxes under these circumstances or whether the FERC will modify its current policy on either income tax allowances or return on equity calculations for pipeline companies organized as part of a master limited partnership. However, any modification that reduces or eliminates an income tax allowance for pipeline companies organized as a part of a master limited partnership or decreases the return on equity for such pipelines could result in an adverse impact on our revenues associated with the transportation and storage services we provide pursuant to cost-based rates. We believe any changes would be prospective from the date of any FERC determination for our regulated entities. Some entities have authority to charge market-based rates and therefore this tax allowance issue does not affect the rates that they charge their customers.
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 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. Additionally, PHMSA issued an interim final rule, effective January 2017, that addresses safety issues related to underground natural gas storage facilities. We believe our existing storage facilities conform to the majority of the requirements of the new rule.
In light of the changing environmental and safety laws and regulations described above, we are evaluating efforts required to maintain compliance with such laws and regulations and, in addition, are assessing ways to improve overall system integrity, efficiency and reliability. The capital costs to effectively modernize our pipelines accordingly will be substantial and will be incurred over several years.
Distribution
____________
(a)
Trillion British thermal units.
2016 Compared to 2015
Operating Revenues. The $157 million decrease was driven by:
•
an $87 million decrease from lower natural gas prices passed through to customers. Prices charged to customers are adjusted quarterly based on the 12 month New York Mercantile Exchange (NYMEX) forecast,
•
a $76 million decrease in residential customer usage of natural gas primarily due to warmer weather in 2016 and
•
a $62 million decrease resulting from a lower Canadian dollar, partially offset by
•
a $30 million increase from growth in the number of customers,
•
a $22 million increase from the 2015 Dawn-Parkway expansion project,
•
a $16 million increase in rates primarily due to increased DSM program charges and
•
a $10 million increase in storage margins primarily due to higher storage pricing.
Natural Gas Purchased. The $158 million decrease was driven by:
•
an $88 million decrease from lower natural gas prices passed through to customers,
•
a $67 million decrease due to lower volumes of natural gas sold to residential customers primarily due to warmer weather and
•
a $27 million decrease resulting from a lower Canadian dollar, partially offset by
•
a $22 million increase from growth in the number of customers.
Operating, Maintenance and Other. The $3 million increase was driven by:
•
a $13 million increase in operating and maintenance expenses primarily due to increased DSM program charges, net of lower employee related costs, partially offset by
•
a $12 million decrease resulting from a lower Canadian dollar.
2015 Compared to 2014
Operating Revenues. The $316 million decrease was driven by:
•
a $225 million decrease resulting from a lower 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 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 lower Canadian dollar,
•
a $93 million decrease due to lower volumes of natural gas sold to residential customers primarily due to warmer weather and
•
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 lower 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. This expansion will consist of a compressor station and associated facilities, 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 demand, 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 continued 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
2016 Compared to 2015
Operating Revenues. The $265 million decrease was driven by:
•
a $106 million decrease due to the sale of Empress,
•
a $66 million decrease in firm gathering and processing revenues,
•
a $45 million decrease resulting from a lower Canadian dollar,
•
a $37 million decrease arising from changes in non-cash mark-to-market commodity-related pricing adjustments associated with the risk management program at Empress and
•
a $23 million decrease due to lower NGL prices.
Natural Gas and Petroleum Products Purchased. The $125 million decrease was driven by:
•
a $92 million decrease due to the sale of Empress,
•
a $24 million decrease primarily as a result of lower costs of NGL sales and
•
a $6 million decrease resulting from a lower Canadian dollar.
Operating, Maintenance and Other. The $60 million decrease was driven by:
•
a $25 million decrease in plant turnaround costs,
•
a $20 million decrease due to the sale of Empress and
•
a $20 million decrease resulting from a lower Canadian dollar.
Gain (Loss) on Sales of Other Assets and Other, net. The $27 million change was primarily the result of the sale of the Pesh natural gas processing facilities in the fourth quarter of 2016.
2015 Compared to 2014
Operating Revenues. The $617 million decrease was driven by:
•
a $199 million decrease resulting from a lower Canadian dollar,
•
a $194 million decrease due to lower NGL prices associated with Empress,
•
a $141 million decrease due primarily to lower sales volumes of residual natural gas at Empress,
•
a $108 million decrease arising from non-cash mark-to-market gains and losses associated with the risk management program at Empress,
•
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 Empress, partially offset by
•
a $61 million increase from settlement gains associated with the risk management program at Empress.
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 Empress,
•
a $67 million decrease primarily as a result of lower costs of sales at Empress and
•
a $30 million decrease resulting from a lower Canadian dollar.
Operating, Maintenance and Other. The $74 million decrease was driven by:
•
a $91 million decrease resulting from a lower 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.
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.
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
____________
(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.
2016 Compared to 2015
EBITDA increased $421 million mainly as the result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:
•
a $400 million increase primarily as a result of the 2015 goodwill and other asset impairments, net of tax impacts,
•
an $88 million increase in gathering and processing margins primarily as a result of asset growth and favorable contract realignments,
•
a $45 million increase primarily as a result of a producer settlement,
•
a $24 million increase due to favorable results from ownership interests in NGL pipelines, partially offset by unfavorable results from wholesale propane and
•
a $19 million increase primarily attributable to lower operating expenses as a result of cost savings initiatives in operations, net of additional costs from asset growth, partially offset by
•
a $55 million decrease primarily as a result of the expiration of hedges in the first quarter of 2016,
•
a $35 million decrease resulting from increased net income attributable to noncontrolling interests primarily as a result of asset growth and prior year impairments,
•
a $20 million decrease from income taxes primarily as a result of a conversion of a taxable entity to a limited liability company and
•
a $15 million decrease from commodity-sensitive processing arrangements, due to decreased crude oil and natural gas prices, partially offset by increased NGL prices.
2015 Compared to 2014
EBITDA decreased $678 million mainly as 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 wholesale propane,
•
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, 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.
Supplemental Data
Below is supplemental information for DCP Midstream’s operating results (presented at 100%):
Matters Affecting Future Field Services Results
The midstream natural 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. Various factors impact both commodity prices and volumes. If commodity prices weaken for a sustained period, DCP Midstream’s natural gas throughput and NGL volumes may be 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; DCP Midstream has observed decreases in drilling activity in certain regions, and increases in drilling activity in others.
A decline in commodity prices has resulted in a decrease in exploration and development activities in certain fields served by DCP Midstream’s gas gathering and residue gas and NGL pipeline transportation systems, and DCP Midstream’s natural gas processing and treating plants, which could lead to further reduced utilization of these assets. DCP Midstream’s long-term view is that commodity prices will be at levels that it believes will support growth in natural gas, condensate and NGL production. DCP Midstream believes that future commodity prices will be influenced by North American supply deliverability, the severity of winter and summer weather, the level of North American production and drilling activity by exploration and production companies and the balance of trade between imports and exports of LNG, NGLs and crude oil.
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 oil-based feedstock to lighter NGL-based feedstocks, including ethane. This increased demand in future years 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 provide support for the increasing supply of NGLs. Although there can be, and has been, volatility in NGL prices, longer term DCP Midstream believes that there will be sufficient demand in NGLs to support increasing supply.
Other
2016 Compared to 2015
EBITDA. The $258 million change was driven by:
•
$333 million due to the 2015 goodwill impairment charges associated with the Westcoast acquisition in 2002, partially offset by
•
$38 million due to higher costs primarily related to the merger with Enbridge announced on September 6, 2016,
•
$25 million due to higher employee benefit costs and
•
$10 million due to a captive insurance general liability reserve related to the Texas Eastern incident near Delmont, Pennsylvania.
2015 Compared to 2014
EBITDA. The $326 million change primarily reflects goodwill impairment charges associated with the Westcoast acquisition in 2002.
Matters Affecting Future Other Results
Future results will continue to include operating costs related to corporate and business services we provide for our operations. We will also include the costs associated with the merger with Enbridge and self-insured losses associated with our captive insurance entities and the impact of stock prices changes on benefits expense.
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 $1,551
million as of December 31, 2016 and $1,397 million as of December 31, 2015. Total regulatory liabilities were $434 million as of December 31, 2016 and $385 million as of December 31, 2015.
Impairment of Goodwill
We had goodwill balances of $4,181 million at December 31, 2016 and $4,154 million at December 31, 2015. The increase in goodwill in 2016 was 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 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, 2016 (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 April 1, 2016 (our annual testing date) that would warrant re-testing for goodwill impairment.
Revenue Recognition
Revenues from the transmission, storage, processing, distribution and sales of natural gas, from the transportation and storage of crude oil, and from the sales of NGLs, are recognized when either the service is provided or the product is delivered. Revenues related to these services provided or products delivered but not yet billed are estimated each month. These estimates are generally based on contract data, regulatory information, estimated distribution usage based on historical data adjusted for heating degree days, commodity prices and preliminary throughput and allocation measurements. Final bills for the current month are billed and collected in the following month. Differences between actual and estimated 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 2016, the assumed average return was 7.50% for the U.S. pension plan assets, 7.15% for the Canadian pension plan assets and 6.33% 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-quality bonds for which the timing and amount of cash outflows approximate the estimated payouts of the plans. Discount rates of 4.57% for the U.S. plans and 4.03% for the Canadian plans were used to calculate the 2016 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 approximately $1 million for U.S. plans and $4 million for Canadian plans. Discount rates of 4.10% for the U.S. plans and 3.81% for the Canadian plans were used to calculate the 2016 year-end benefit obligations and represent a weighted average of the applicable rates for all U.S. and Canadian plans, respectively. The weighted average discount rates used to determine the benefit obligation decreased approximately 0.47% for the U.S. plans and approximately 0.22% for the Canadian plans during 2016. The decrease in the benefit obligation discount rate and actuarial experience during 2016 resulted in an increase in benefit obligations at December 31, 2016 compared to December 31, 2015.
See Note 26 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, 2016, we had negative working capital of $2,133 million. This balance includes commercial paper liabilities totaling $1,453 million and current maturities of long-term debt of $551 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 2017. 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.
We have access to five revolving credit facilities, including Spectra Capital’s two facilities totaling $3.0 billion, SEP’s $2.5 billion facility, Westcoast’s 400 million Canadian dollar facility and Union Gas’ 700 million Canadian dollar facility, with available capacity of $1.9 billion under SEP’s credit facility and $2.9 billion under our other subsidiaries’ credit facilities. 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 for temporary funding of capital expenditures and 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 17 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, 2016, our capital structure was 56.4% debt, 25.8% common equity of controlling interests and 17.8% 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 2016 and 2015. We received total tax and periodic distributions from DCP midstream of $237 million in 2014. These distributions are classified within Cash Flows from Operating Activities in the Consolidated Statements of 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, 2016, $164 million of Cash and Cash Equivalents was held by our Canadian subsidiaries. Historically, we have reinvested a substantial portion of our Canadian operations’ earnings in Canada. Earnings not needed by our Canadian operations have been distributed to Spectra Energy Corp (the U.S. parent) with minimal incremental U.S. tax liability. We anticipate continued substantial reinvestment of our future Canadian earnings in Canada; however, future distributions to Spectra Energy Corp may incur incremental U.S. tax at the U.S. statutory rate without the 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 $4.6 billion in 2017 and $2.0 billion in 2018, 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:
Operating Cash Flows
Net cash provided by operating activities decreased $221 million to $2,026 million in 2016 compared to 2015. This change was driven mostly by non-cash goodwill impairments recorded in 2015, offset by higher earnings.
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.
Investing Cash Flows
Net cash flows used in investing activities increased $1,048 million to $3,830 million in 2016 compared to 2015. This change was driven mostly by:
•
a $902 million net increase in capital and investment expenditures and
•
a $396 million distribution received from Gulfstream with proceeds from a Gulfstream debt offering in 2015, partially offset by
•
a $204 million of proceeds related to the sale of Empress in 2016 and
•
a $148 million contribution to Gulfstream used to retire debt in 2016, compared to a $248 million contribution in 2015.
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.
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.
Capital and investment expenditures for 2016 totaled $3,874 million and included $3,261 million for expansion projects and $613 million for maintenance and other projects.
We project 2017 capital and investment expenditures of approximately $5.3 billion, consisting of approximately $2.8 billion for Spectra Energy Partners, $0.7 billion for Distribution, $0.8 billion for Western Canada Transmission & Processing, and $1.0 billion for Other. Total projected 2017 capital and investment expenditures include approximately $4.6 billion of expansion capital expenditures and $0.7 billion for maintenance and upgrades of existing plants, pipelines and infrastructure to serve growth. These projections 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 2016, including:
•
Algonquin Incremental Market - A 342 million cubic feet per day (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. 72% of the project was placed in-service in the fourth quarter of 2016 with the remainder to go in-service in the first quarter 2017.
•
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 Midstream Partners, L.P. (Magellan) to transport approximately 75,000 barrels per day (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 occurred during the third quarter of 2016.
•
Gulf Market Expansion - This Texas Eastern system expansion project connects growth markets (Gulf Coast LNG and industrials) with diverse, growing shale supply. The project consists of installing reverse-compression capability at six compressor stations to provide up to 650 MMcf/d of incremental capacity. The project will be executed in two phases. Phase 1 was placed into service in the fourth quarter of 2016, and provides 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 39 MMcf/d of incremental capacity. The project was placed in-service during the third quarter of 2016.
•
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 was placed in-service during the fourth quarter of 2016.
•
Burlington-Oakville - 290 MMcf/d of new capacity for the Burlington/Oakville market. The project consists of seven miles of 20 inch pipe. The project was placed in-service during the fourth quarter 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 pipeline from Hamilton to Milton, Ontario, and the installation of a new compressor and associated infrastructure at Lobo. The project was placed in-service during the fourth quarter of 2016.
•
Express Enhancement - This project will increase system capacity by 21,000 Bbls/d. Facilities include the addition of tank storage at Hardisty, Alberta and Buffalo, Montana and additional pumps at Buffalo, Montana. The project was placed in-service during the third quarter of 2016.
•
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 northeastern BC. The first portion of this project was completed in the fourth quarter of 2016 with remaining work to be placed in-service in 2017 and 2018.
In addition to the remaining work mentioned above, significant 2017 expansion projects expenditures are also expected to include:
•
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.
•
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.
•
High Pine Expansion - A 240 MMcf/d expansion of the T-North pipeline system consisting of two 42 inch pipeline loops totaling approximately 23 miles in length 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 2017.
•
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 Montney production area. This project is expected to be in service within the first half of 2017.
•
Nexus - Greenfield path to transport 1.5 Bcf/d from Texas Eastern’s pipeline to the Union Gas hub in Ontario, Canada. The facilities will consist of approximately 255 miles of 36 inch pipeline across northern Ohio to the Detroit, Michigan area, the addition of four new compressor stations totaling 130,000 horsepower and six meter stations. The project is expected to be in-service during the second half of 2017.
•
Access South / Adair Southwest / Lebanon Extension - This project combined is designed to attach emerging Ohio Marcellus and Utica natural gas supplies to new markets in the Midwest and Southeast along Texas Eastern’s existing footprint totaling 622 MMcf/d of gas deliveries to customers. The project is expected to be in-service during the second half of 2017.
•
Atlantic Bridge - This project is an expansion of the Algonquin system to transport 131 MMcf/d of natural gas to the New England Region. Addition or expansion of pipelines, compressor stations and meter stations will be required. The project is expected to be in-service during the second half of 2017.
•
Panhandle Reinforcement - Creates approximately 97 MMcf/d of transmission capacity, meeting future residential, commercial and industrial demands along the Chatham and Windsor corridor for the next five years. This project will also eliminate forecasted operating and maintenance costs on the existing section being removed. This project will replace 25 miles of existing nominal pipe size 16 pipeline with a new nominal pipe size 36 pipeline from Dawn to Dover Transmission Station. It also includes station modifications and upgrades at Dawn, Dover Centre, Dover Transmission and Mersea Gate Station. The project is pending OEB approval and is targeted to be in-service during the second half of 2017.
•
Texas Eastern Appalachian Lease - This project is designed to create a gas path from the Texas Eastern mainline system in Monroe County, Ohio, utilizing the Ohio Pipeline Energy Network pipeline, to deliver gas northward to Nexus at Kensington, Ohio. The pipeline portion of the project is due to go in service during the second half of 2017, and the compressor station portion is due to go in service during the second half of 2018.
•
South Texas Expansion - The project will expand the Texas Eastern facilities in order to deliver 400 MMcf/d gas supplies from east of Vidor, Texas to high demand markets in south Texas with a single delivery point in Petronila. The project is expected to be in-service during the second half of 2018.
•
Bayway Lateral - This project will deliver 296 MMcf/d to two new customers at the Bayway Refinery site in Linden, New Jersey. The Project consists of a tap into Texas Eastern Line 38, a new 2,300 foot 24 inch lateral and two new meter stations. The Project will deliver approximately 231 MMcf/d to Linden Cogen and approximately 65 MMcf/d to Phillips 66. The project is expected to be in-service during the first half of 2018.
•
Valley Crossing Pipeline - A new 42 inch and 48 inch 162 mile mainline pipeline, designed to carry 2.6 Bcf/d of gas from the Agua Dulce hub to an offshore tie-in with the Comisión Federal de Electricidad (Mexico’s state-owned utility) Sur de Texas-Tuxpan project. The project is expected to be in-service during the second half of 2018.
•
Wyndwood - This project includes a 36 inch pipeline loop approximately 17 miles in length alongside the existing Fort St. John mainline to provide 50 MMcf/d of additional capacity to our T-North delivery points at the Sunset Creek compressor site and Station 2. The project is expected to be in-service during the first half of 2018.
•
PennEast - A 1,000 MMcf/d 36 inch pipeline with scalable facilities and two compressor stations that runs 105 miles from northeast Pennsylvania production to Texas Eastern-Lambertville and Transco-Woodbridge. The project is expected to be in-service during the second half of 2018.
•
Stratton Ridge - This project will deliver 322 MMcf/d of gas from Stratton Ridge Storage to Freeport LNG Train 3. The project scope also consists of additional compression, piping, and metering and regulation work on the Angleton Compressor Station and Angleton Line, as well as work on the Brazoria Interconnector Gas Pipeline and Mont Belvieu, Joaquin, Huntsville, Hempstead, and Provident City Station Sites. The project is expected to be in-service during the first half of 2019.
Financing Cash Flows and Liquidity
Net cash flows provided by financing activities increased $1,350 million to $1,890 million in 2016 compared to 2015. This change was driven mostly by:
•
$879 million of proceeds from the issuance of Spectra Energy’s common stock in 2016,
•
net commercial paper issuances of $319 million in 2016, compared to net commercial paper redemptions of $439 million in 2015 and
•
$229 million of proceeds from the issuance of Westcoast’s preferred stock in 2016, compared to $84 million of proceeds in 2015, partially offset by
•
$531 million of net proceeds from long-term debt in 2016, compared to net proceeds of $1,300 million in 2015.
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
•
net commercial paper redemptions of $439 million in 2015, compared to net commercial paper issuances of $574 million in 2014.
Significant Financing Activities-2016
Debt Issuances. The following long-term debt issuances were completed during 2016 as part of our overall financing plan to fund capital expenditures, to refinance maturing debt obligations and for other corporate purposes:
__________________
(a)
U.S. dollar equivalent at time of issuance.
Spectra Energy Common Stock Issuances. On March 1, 2016, we entered into an equity distribution agreement under which we may sell and issue common stock up to an aggregate offering price of $500 million. The equity distribution agreement allows us to offer and sell common stock at prices deemed appropriate through sales agents. Sales of common stock under the equity distribution agreement will be made by means of ordinary brokers’ transactions through the facilities of the NYSE, in block transactions, or as otherwise agreed upon by one or more of the sales agents and us. We intend to use the net proceeds from sales under this at-the-market program for general corporate purposes, including investments in subsidiaries to fund capital expenditures. We issued approximately 12.9 million of common shares to the public under this program, for total net proceeds of $383 million through December 31, 2016.
In April 2016, we issued 16.1 million common shares to the public for net proceeds of approximately $479 million. Net proceeds from the offering were used to purchase approximately 10.4 million common units in SEP. SEP used the proceeds from our unit purchase for general corporate purposes, including the funding of its current expansion capital plan.
SEP Common Unit Issuances. In 2016, SEP issued 12.8 million common units to the public under its at-the-market program and approximately 262,000 general partner units to Spectra Energy. Total net proceeds to SEP were $591 million (net proceeds to Spectra Energy were $579 million). In April 2016, SEP issued 10.4 million common units and 0.2 million general partner units to Spectra Energy in a private placement transaction.
In connection with the issuances of the units, a $50 million gain ($31 million net of tax) to Additional Paid-in Capital and a $528 million increase in Equity-Noncontrolling Interests were recorded in 2016. The issuances decreased Spectra Energy’s ownership in SEP from 78% to 75% at December 31, 2016.
In 2017, SEP has issued 0.5 million common units to the public and approximately 9,000 general partner units to Spectra Energy, for total net proceeds to SEP of $21 million (net proceeds to Spectra Energy were $21 million) through its at-the-market program.
Westcoast Preferred Stock Issuance. On August 30, 2016, Westcoast issued 12 million Cumulative 5-Year Minimum Rate Reset Redeemable First Preferred Shares, Series 12 for an aggregate principle amount of 300 million Canadian dollars (approximately $229 million as of the issuance date). Net proceeds from the issuance were used to fund capital expenditures and for general corporate purposes.
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:
__________________
(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. In December 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.
Significant Financing Activities-2014
Debt Issuances. The following long-term debt issuances were completed during 2014:
__________________
(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.
Available Credit Facilities and Restrictive Debt Covenants
__________________
(a)
Revolving credit facilities contain a covenant requiring the Spectra Energy consolidated debt-to-total capitalization ratio, as defined in the agreements, to not exceed 65%. Per the terms of the agreements, collateralized debt is excluded from the calculation of the ratio. This ratio was 56.3% at December 31, 2016.
(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, 2016, this ratio was 3.8 to 1.
(c)
U.S. dollar equivalent at December 31, 2016. 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 33.2% at December 31, 2016.
(d)
U.S. dollar equivalent at December 31, 2016. The revolving credit facility is 700 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 69.0% at December 31, 2016.
On September 29, 2016, we entered into a new one-year, $2 billion credit facility at Spectra Capital, which expires in 2017. Proceeds from borrowings under the credit facility will be used for general corporate purposes. Amounts borrowed under the credit facility must be repaid following any change in control, including any that results from the proposed merger with Enbridge.
On April 29, 2016, we amended the Union Gas and SEP revolving credit agreements. The Union Gas revolving credit facility was increased to 700 million Canadian dollars and the SEP revolving facility was increased to $2.5 billion. The expiration of both facilities was extended, with both facilities expiring in 2021.
On April 29, 2016, we amended the Westcoast and Spectra Capital revolving credit agreements. The expiration of both credit facilities was extended, with both facilities expiring in 2021.
The issuances of commercial paper, letters of credit and revolving borrowings reduce the amounts available under the credit facilities. As of December 31, 2016, 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, 2016, 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 56.3% at December 31, 2016. 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, 2016, however, it is not likely that a material adverse effect would occur as a result of a weakened Canadian dollar.
Dividends. Consistent with our near-term objective of increasing our cash dividend by $0.14 per year through 2018, we announced a $0.14 annual dividend increase on January 5, 2017. We expect to continue our policy of paying regular cash dividends. The declaration and payment of dividends are subject to the sole discretion of our Board of Directors and will depend upon many factors, including the financial condition, earnings and capital requirements of our operating subsidiaries, covenants associated with certain debt obligations, legal requirements, regulatory constraints and other factors deemed relevant by our Board of Directors. We declared a quarterly cash dividend of $0.44 per common share on January 5, 2017 payable on March 1, 2017 to shareholders of record at the close of business on February 15, 2017.
Other Financing Matters. Spectra Energy Corp, Spectra Capital and SEP have effective shelf registration statements on file with the SEC to register the issuance of unlimited amounts of various equity and debt securities. SEP also has $359 million available as of December 31, 2016 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 1.2 billion Canadian dollars (approximately $893 million) available as of December 31, 2016 for the issuance of debt securities in the Canadian market under their medium term note shelf prospectuses, which expired on January 4, 2017.
On March 18, 2016, Westcoast filed a new 1 billion Canadian dollar short form base shelf prospectus, which provides for the issuance of first preferred shares. As of the date of this filing, Westcoast has 700 million Canadian dollars (approximately $521 million) available for the issuance of preferred shares under this prospectus, which expires on April 18, 2018.
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 22 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.
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 21 and 22 of Notes to Consolidated Financial Statements.
Contractual Obligations
We enter into contracts that require payment of cash at certain periods based on certain specified minimum quantities and prices. The following table summarizes our contractual cash obligations for each of the periods presented. The table below excludes all amounts classified as Current Liabilities on the December 31, 2016 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 2017.
Contractual Obligations as of December 31, 2016
__________
(a)
See Note 17 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 21.
(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 natural gas. For contracts where the price paid is based on an index, the amount is based on forward market prices at December 31, 2016.
(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 2017 retirement plan contributions (see Note 26). We are unable to estimate retirement plan contributions beyond 2017 due primarily to uncertainties about market performance of plan assets. Excludes cash obligations for asset retirement activities (see Note 16) 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 21) 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 Sheet 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 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.
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, 2016 and 2015, a 10¢ per-gallon change in NGL prices would affect our annual pre-tax earnings by approximately $25 million in 2017 and $40 million in 2016 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 in both periods, and a $10 per-barrel change in oil prices would affect our annual pre-tax earnings by approximately $20 million in both periods.
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 20 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.
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, 17 and 20 of Notes to Consolidated Financial Statements.
As of December 31, 2016, 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 billion 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, 2016, it was estimated that if short-term interest rates average 100 basis points higher (lower) in 2017 than in 2016, interest expense, net of offsetting interest income, would fluctuate by $39 million before tax. Comparatively, based on a sensitivity analysis as of December 31, 2015, had short-term interest rates averaged 100 basis points higher (lower) in 2016 than in 2015, it was estimated that interest expense, net of offsetting interest income, would have fluctuated by approximately $35 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, 2016 and 2015.
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 2016 would have resulted in an estimated net loss on the translation of local currency earnings of approximately $22 million on our Consolidated Statement of Operations. In addition, if a 10% devaluation had occurred on December 31, 2016, the Consolidated Balance Sheet would have been negatively impacted by $389 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, 2016, one U.S. dollar translated into 1.34 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 21 of Notes to Consolidated Financial Statements.
New Accounting Pronouncements
See Note 1 of Notes to Consolidated Financial Statements for discussion.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Quantitative and Qualitative Disclosures About Market Risk for discussion.
Item 8. Financial Statements and Supplementary Data.
Management’s Annual Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining an adequate system of internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes, in accordance with generally accepted accounting principles. Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies and procedures may deteriorate.
Our management, including our Chief Executive Officer and Chief Financial Officer, has conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2016 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, 2016.
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.
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, 2016 and 2015, 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, 2016. 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, 2016 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, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, 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, 2016, 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 24, 2017
SPECTRA ENERGY CORP
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per-share amounts)
See Notes to Consolidated Financial Statements.
SPECTRA ENERGY CORP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions)
See Notes to Consolidated Financial Statements.
SPECTRA ENERGY CORP
CONSOLIDATED BALANCE SHEETS
(In millions)
See Notes to Consolidated Financial Statements.
SPECTRA ENERGY CORP
CONSOLIDATED BALANCE SHEETS
(In millions, except per-share amounts)
See Notes to Consolidated Financial Statements.
SPECTRA ENERGY CORP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
See Notes to Consolidated Financial Statements.
SPECTRA ENERGY CORP
CONSOLIDATED STATEMENTS OF EQUITY
(In millions)
See Notes to Consolidated Financial Statements.
SPECTRA ENERGY CORP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
INDEX
Page
1. Summary of Operations and Significant Accounting Policies
2. Spectra Energy Partners, LP
3. Acquisitions and Dispositions
4. Business Segments
5. Regulatory Matters
6. Income Taxes
7. Earnings per Common Share
8. Accumulated Other Comprehensive Income (Loss)
9. Inventory
10. Investments in and Loans to Unconsolidated Affiliates and Related Party Transactions
11. Variable Interest Entities
12. Intangible Assets
13. Goodwill
14. Marketable Securities and Restricted Funds
15. Property, Plant and Equipment
16. Asset Retirement Obligations
17. Debt and Credit Facilities
18. Preferred Stock of Subsidiaries
19. Fair Value Measurements
20. Risk Management and Hedging Activities
21. Commitments and Contingencies
22. Guarantees and Indemnifications
23. Issuances of Common Stock
24. Effects of Changes in Noncontrolling Interests Ownership
25. Stock-Based Compensation
26. Employee Benefit Plans
27. Condensed Consolidating Financial Information
28. Quarterly Financial Data (Unaudited)
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.
On September 6, 2016, we announced that we entered into a definitive merger agreement with Enbridge Inc. (Enbridge) under which Enbridge and Spectra Energy will combine in a stock-for-stock merger transaction, which values Spectra Energy’s stock at approximately $28 billion, based on the closing price of Enbridge’s common shares as of September 2, 2016. This transaction was approved by the boards of directors and shareholders of both Spectra Energy and Enbridge and has received all necessary regulatory approvals. The transaction is expected to close on February 27, 2017.
Upon completion of the proposed merger, Spectra Energy shareholders will receive 0.984 Enbridge common shares for each share of Spectra Energy stock they own. The consideration to be received by Spectra Energy shareholders is valued at $40.33 per Spectra Energy share, based on the closing price of Enbridge common shares as of September 2, 2016, representing an approximate 11.5% premium to the closing price of Spectra Energy stock as of September 2, 2016. Upon completion of the
merger, Enbridge shareholders are expected to own approximately 57% of the combined company and Spectra Energy shareholders are expected to own approximately 43%.
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 United States (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.
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 $1 million in 2016 and $6 million in 2015 and gains totaled $3 million in 2014, 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 revenues are immaterial. There were no customers accounting for 10% or more of consolidated revenues during 2016, 2015 or 2014. 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 25 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 26 for further discussion.
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. 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 $232 million in 2016 (an equity component of $164 million and an interest expense component of $68 million), $143 million in 2015 (an equity component of $111 million and an interest expense component of $32 million) and $72 million in 2014 (an equity component of $53 million and an interest expense component of $19 million). The equity component of AFUDC, a non-cash item, is included as a reconciling item to net income within Cash Flows from Operating Activities-Other, Assets in the Consolidated Statements of Cash Flows.
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 17 and any investments that are considered restricted funds.
Inventory. Inventory consists of natural gas held in storage for transmission and processing, and also includes materials and supplies. The NGLs previously included in inventory were disposed of as part of the sale of the Empress NGL operations (Empress) on August 4, 2016. See Note 3 for further discussion related to the sale of Empress. 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 on the Consolidated Balance Sheets, 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 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 $407 million and $291 million as of December 31, 2016 and December 31, 2015, respectively, and Other Current Liabilities include $382 million and $287 million as of December 31, 2016 and December 31, 2015, 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. Prior to the sale of Empress on August 4, 2016, we maintained a commodity hedging program at the Western Canada Transmission & Processing segment. 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.
Fair Value Hedges. Derivatives may be designated as 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 fair values of hedged items. We document hedging activity by instrument type and risk management strategy.
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 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 goodwill impairment charges of $270 million for BC Field Services and $63 million for Empress associated with the Westcoast Energy Inc. (Westcoast) acquisition in 2002. No impairments of goodwill were recorded in 2016 or 2014. See Note 13 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 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.
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 Accounting Standards Updates (ASUs) were adopted during 2016 and the effect of such adoption has been presented in the accompanying Consolidated Financial Statements:
In June 2014, the Financial Accounting Standards Board (FASB) issued ASU No. 2014-10, “Development Stage Entities (Topic 915): Elimination of Certain Financial Reporting Requirements, Including an Amendment to Variable Interest Entities Guidance in Topic 810, Consolidation,” which amends the consolidation guidance around reporting entities that invest in development stage entities. We adopted the consolidation guidance of this amendment on January 1, 2016 and applied it retrospectively with no material effect on our consolidated results of operations, financial position or cash flows. This ASU resulted in certain of our entities being classified as Variable Interest Entities (VIEs). See Note 11 for discussion of our VIEs.
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 required reevaluation of certain entities for consolidation and required us to revise our documentation regarding the consolidation or deconsolidation of such entities. We adopted this standard on January 1, 2016 with no material effect on our consolidated results of operations, financial position or cash flows.
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. We adopted this standard on January 1, 2016. The adoption of this standard did not have a material impact on our consolidated results of operations, financial position or cash flows.
Pending. The following ASUs have been issued but not yet adopted:
In May 2014, the FASB issued ASU No. 2014-09,“Revenue from Contracts with Customers (Topic 606),” in an effort to improve revenue recognition practices across entities and industries. The ASU introduces a single, principles-based revenue recognition model which centers on the core principle of an entity recognizing revenue in a manner that depicts the transfer of goods and services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. Since its release, the FASB has issued multiple amendments clarifying and/or amending ASU No. 2014-09. We have substantially completed a review of contracts with customers in relation to the requirements of ASU No. 2014-09. While we have not identified any material difference in the amount or timing of revenue recognition for the categories we have reviewed to date, our evaluation is not complete and we have not concluded on the overall impacts of adopting this standard. In addition, we are in the process of implementing appropriate changes to our business processes, systems and controls to support the recognition and disclosure requirements under the new standard. ASU No. 2014-09 is effective for us on January 1, 2018 and allows for either full retrospective or modified retrospective adoption.
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, 2017 and is not expected to have a material impact on our consolidated results of operations, financial position or cash flows.
In January 2016, the FASB issued ASU No. 2016-01, “Financial Instruments-Overall (Topic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities,” which amends the classification and measurement of financial 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 on January 1, 2018. Early adoption is not permitted. We are currently evaluating this ASU and its potential impact on us.
In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842),” to improve the financial reporting around leasing transactions. The new guidance requires companies to begin recording assets and liabilities arising from those leases classified as operating leases under previous guidance. Furthermore, the new guidance will require significant additional disclosures about the amount, timing and uncertainty of cash flows from leases. Topic 842 retains a distinction between finance leases and operating leases. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the classification criteria for distinguishing between capital leases and operating leases in previous guidance. The result of retaining a distinction between finance leases and operating leases is that under the lessee accounting model in Topic 842, the effect of leases in the statement of comprehensive income and the statement of cash flows is largely unchanged from previous guidance. This ASU is effective for us January 1, 2019. We are currently evaluating this ASU and its potential impact on us.
In March 2016, the FASB issued ASU No. 2016-05, “Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships,” which clarifies the hedge accounting impact when there is a change in one of the counterparties to the derivative contract (i.e. novation). This ASU is effective for us January 1, 2017. This ASU is not expected to have a material impact on our consolidated results of operations, financial position or cash flows.
In March 2016, the FASB issued ASU No. 2016-06, “Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments,” which simplifies the embedded derivative analysis for debt instruments containing contingent call or put options. This ASU is effective for us January 1, 2017. This ASU is not expected to have a material impact on our consolidated results of operations, financial position or cash flows.
In March 2016, the FASB issued ASU No. 2016-07, “Investments-Equity Method and Joint Ventures (Topic 323): Simplifying the Transition to the Equity Method of Accounting,” which eliminates the requirement to apply the equity method of accounting retrospectively when a reporting entity obtains significant influence over a previously held investment. This ASU is effective for us January 1, 2017. This ASU is not expected to have a material impact on our consolidated results of operations, financial position or cash flows.
In March 2016, the FASB issued ASU No. 2016-09, “Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting,” which simplifies several aspects of the accounting for share-based payment award transactions. This update requires classification changes for certain tax cash flows within the statement of cash flows and requires all excess tax benefits and tax deficiencies to be recorded through the income statement. In addition, the update provides an accounting policy election around forfeitures and raises the threshold for liability classification of share-based awards withheld for tax withholding requirements. This ASU is effective for us on January 1, 2017. This ASU is not expected to have a material impact on our consolidated results of operations, financial position or cash flows.
In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,” to replace the incurred loss impairment methodology with a methodology that reflects expected credit losses and requires the consideration of a broader range of reasonable and supportable information to inform credit loss estimates. This ASU is effective for us on January 1, 2020. We are currently evaluating this ASU and its potential impact on us.
In August 2016, the FASB issued ASU No. 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,” to provide guidance on specific cash flow issues with the objective of reducing the existing diversity in practice. This ASU is effective for us on January 1, 2018. We are currently evaluating this ASU and its potential impact on us.
In October 2016, the FASB issued ASU No. 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory,” to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. This ASU is effective for us on January 1, 2018. We are currently evaluating this ASU and its potential impact on us.
In October 2016, the FASB issued ASU No. 2016-17, “Consolidation (Topic 810): Interests Held through Related Parties That Are under Common Control,” to amend the consolidation guidance on how a reporting entity that is the single decision maker of a VIE should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. This ASU is effective for us on January 1, 2017. This ASU is not expected to have a material impact on our consolidated results of operations, financial position or cash flows.
In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash,” to address the diversity in the classification and presentation of changes in restricted cash and restricted cash equivalents on the statement of cash flows. The update requires that restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. This ASU is effective for us on January 1, 2018. We are currently evaluating this ASU and its potential impact on us.
In January 2017, the FASB issued ASU No. 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business,” which revises the definition of a business. This ASU is effective for us on January 1, 2018. We are currently evaluating this ASU and its potential impact on us.
In January 2017, the FASB issued No. ASU 2017-04, “Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment,” to simplify the subsequent measurement of goodwill. The guidance eliminates Step 2 from the goodwill impairment test which required computing an implied fair value to measure the amount of the goodwill impairment. A goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. This ASU is effective for us on January 1, 2020. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We are currently evaluating this ASU and its potential impact on us.
2015. The following ASUs were adopted during 2015 and the effect of such adoption has been presented in the accompanying Consolidated Financial Statements:
In April 2014, the 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 presentation of $46 million of debt issuance costs 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, “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 to 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 flows.
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.
2. Spectra Energy Partners, LP
SEP is our natural gas infrastructure and crude oil pipeline master limited partnership. As of December 31, 2016, Spectra Energy owned 75% of SEP, including a 2% general partner interest.
Sand Hills and Southern Hills. In October 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 resulted in
the reduction of any associated distribution payable to us, effective 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. The total reduction of distributions to us from SEP was $16 million for the year ended December 31, 2016.
U.S. Assets Dropdown. During 2013, Spectra Energy contributed substantially all of its interests in its subsidiaries that own U.S. transmission and storage and liquids assets and assigned them to SEP (collectively, the U.S. Assets Dropdown), excluding a 25.05% ownership interest in Southeast Supply Header, LLC (SESH) and a 1% ownership interest in Steckman Ridge, LP (Steckman Ridge). This was the first of three planned transactions.
In 2014, we completed the second of the 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.
The third, and final, transaction related to the U.S. Assets Dropdown occurred in November 2015. It consisted of Spectra Energy’s contribution of the remaining 0.1% interest in SESH to SEP. Total consideration for the third transaction 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.
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 (NYSE), 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 12.8 million, 12.0 million and 6.4 million common units to the public in 2016, 2015 and 2014, respectively, for total net proceeds of $579 million, $546 million and $327 million, respectively. In 2016, 2015 and 2014, SEP also issued 262,000, 245,000 and 132,000 general partner units, respectively, to Spectra Energy.
In April 2016, SEP issued 10.4 million common units and 0.2 million general partner units to Spectra Energy in a private placement transaction. See Note 23 for further discussion.
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. In October 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.
Dispositions. On August 4, 2016, Westcoast completed the sale of its ownership interests in Empress to Plains Midstream Canada ULC. Consideration received by Westcoast in this transaction was approximately $204 million in cash, including approximately $51 million for inventory and working capital. The total consideration is subject to final working capital adjustments, which are expected to be finalized in the first half of 2017. The sale resulted in a pre-tax loss of less than $1 million and a tax benefit of $27 million, which are reflected in Gain (Loss) on Sales of Other Assets and Other, net and Income Tax Expense, respectively, on our Consolidated Statement of Operations for the year ended December 31, 2016.
As discussed above, in October 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, LP (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.
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 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 and natural gas gathering and processing services to customers in western Canada, the U.S. Pacific Northwest and the Maritime Provinces in Canada. This segment conducts business mostly through BC Pipeline, BC Field Services, 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. See Note 3 for discussion related to the sale of Empress on August 4, 2016.
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, 2016, 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.
Business Segment Data
__________
(a)
Includes foreign currency transaction gains and losses related to segment EBITDA.
Geographic Data
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.
________
(a)
Included in Inventory, Fuel Tracker, Current Assets-Other, Taxes Accrued 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 gas commodity and 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 $344 million as of December 31, 2016 and $291 million as of December 31, 2015 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 $293 million as of December 31, 2016 and $258 million as of December 31, 2015. 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 $10 million as of December 31, 2016 and $48 million as of December 31, 2015 representing gas cost collections from customers under approved rates that vary from actual 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 $789 million as of December 31, 2016 and $727 million as of December 31, 2015 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 June 2016, a decision from the OEB was received approving recovery of the 2014 Demand Side Management (DSM) deferral and variance account balances from ratepayers. Union Gas began recovery of approximately $9 million from customers on October 1, 2016.
In March 2016, Union Gas filed a Draft Rate Order with the OEB for rates effective January 1, 2016 based on the OEB’s February 24, 2016 updated Decision and Order on the 2015-2020 DSM Plan. In May 2016, a decision from the OEB was received approving recovery from ratepayers of approximately $19 million effective January 1, 2016 with an implementation date of July 1, 2016.
As part of Union Gas’ 2017 rates application, Union Gas has included an approved DSM budget of approximately $43 million in 2017 rates. The 2017 budget was approved as part of the OEB Revised Decision in the 2015-2020 DSM Plan proceeding.
In April 2016, Union Gas filed an application with the OEB for the annual disposition of the 2015 deferral account balances. As a result, Union Gas had a net receivable from customers of approximately $18 million. In August 2016, a decision from the OEB was received approving recovery from ratepayers which began October 1, 2016.
6. Income Taxes
Income Tax Expense Components
Earnings before Income Taxes
Reconciliation of Income Tax Expense at the U.S. Federal Statutory Tax Rate to Actual Income Tax Expense
Net Deferred Income Tax Liability Components
________
(a)
These amounts are classified as Deferred Credits and Other Liabilities-Deferred Income Taxes in the Consolidated Balance Sheets.
At December 31, 2016, we had a federal net operating loss carryforward, net of unrecognized tax benefits, of $572 million that expires at various times beginning in 2021. The deferred tax asset attributable to the federal net operating loss, net of unrecognized tax benefits, is $200 million. We had valuation allowances of $9 million at both December 31, 2016 and 2015 against the deferred tax asset related to the federal net operating loss carryforward.
At December 31, 2016, we had a state net operating loss carryforward, net of unrecognized tax benefits, of approximately $399 million that expires at various times beginning in 2020. The deferred tax asset attributable to the state net operating loss carryforward, net of federal impacts and unrecognized tax benefits, is $20 million. We had a valuation allowance of $1 million at December 31, 2015 against the deferred tax asset related to the state net operating loss carryforward and other state tax credits.
At December 31, 2016, we had a federal and state capital loss carryforward of $77 million that expires in 2021. The federal deferred tax asset attributable to the capital loss carryforward is $27 million and the state deferred tax asset attributable to the capital loss carryforward is $1 million, net of federal impacts.
At December 31, 2016, we had foreign net operating loss carryforwards of $135 million that expires at various times beginning in 2026. The deferred tax asset attributable to the foreign net operating losses is $36 million. We had valuation allowances of $1 million at both December 31, 2016 and 2015 against the deferred tax asset related to the foreign net operating loss carryforwards. At December 31, 2016, we also had a foreign capital loss carryforward of $48 million with an indefinite expiration period. The deferred tax asset attributable to the foreign capital loss carryforward is $6 million. We had valuation allowances of $6 million and $16 million at December 31, 2016 and 2015, respectively, against the deferred tax asset related to the foreign capital loss carryforward.
Reconciliation of Gross Unrecognized Income Tax Benefits
Unrecognized tax benefits totaled $75 million at December 31, 2016. Of this, $45 million would reduce the annual effective tax rate if recognized on or after January 1, 2017. We recorded a net decrease of $7 million in gross unrecognized tax benefits during 2016. This was a result of $6 million attributable to deferred tax liabilities, foreign currency exchange rate fluctuations and a $1 million decrease 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 income of $17 million in 2016 and interest expense of $2 million in 2015 related to unrecognized tax benefits. Accrued interest and penalties totaled $4 million at December 31, 2016 and $21 million at December 31, 2015.
Although uncertain, we believe it is reasonably possible that the total amount of unrecognized tax benefits could decrease by $20 million to $30 million prior to December 31, 2017 due to audit settlements and statute of limitations expirations.
We remain subject to examination for Canada income tax return filings for years 2009 through 2015 and U.S. federal income tax return filings for years 2013 through 2015. A limited number of state tax return filings remain subject to examination for years 2007 through 2015.
We have foreign subsidiaries’ undistributed earnings of approximately $1.8 billion at December 31, 2016 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 2016, 2015 and 2014, 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:
8. Accumulated Other Comprehensive Income (Loss)
The following table presents the net of tax changes in AOCI by component, excluding amounts attributable to noncontrolling interests:
9. Inventory
The components of inventory are as follows:
NGL inventory previously held at our Empress operations at Western Canada Transmission & Processing was subject to lower of cost or market. As such, we recorded non-cash charges totaling $14 million in 2015 ($10 million after tax) to Natural Gas and Petroleum Products Purchased on the Consolidated Statement of Operations to reduce propane inventory to estimated net realizable value. Empress was sold on August 4, 2016. See Note 3 for further discussion related to the sale of Empress.
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, 2016 and 2015, the carrying amounts of investments in affiliates approximated the amounts of underlying equity in net assets, with the exception of DCP Midstream, which relates to a contribution of assets recorded at carrying value in 2015. We received distributions from our equity investments of $161 million in 2016, $612 million in 2015 and $646 million in 2014. Cumulative undistributed earnings of unconsolidated affiliates totaled $33 million at December 31, 2016 and $28 million at December 31, 2015.
Spectra Energy Partners. As of December 31, 2016, our Spectra Energy Partners segment investments were mostly comprised of a 39% effective interest in Gulfstream Natural Gas System, LLC (Gulfstream), a 39% effective interest in SESH and a 39% effective interest in Steckman Ridge. In November 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, 2016 and 2015. We recorded interest income on the Steckman Ridge loan of $1 million in 2016, 2015 and 2014.
In October 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, effective 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. The total reduction of distributions to us from SEP was $16 million for the year ended December 31, 2016.
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. 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 and $73 million in 2014, are reflected in Earnings (Loss) from Equity Investments in the Consolidated Statements of Operations. There were no material gains from issuances in 2016.
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.
As previously discussed, in October 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
Equity in Earnings of Unconsolidated Affiliates
Summarized Combined Financial Information of Unconsolidated Affiliates (Presented at 100%)
Statements of Operations
Balance Sheets
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 Transmission, LP (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 $31 million in 2016, $46 million in 2015 and $79 million in 2014 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 $2 million in 2016, $3 million in 2015 and $2 million in 2014, classified as Operating Revenues-Other in our Consolidated Statements of Operations. We also recorded other revenues totaling $1 million in 2016, $4 million in 2015 and $7 million in 2014, primarily within Transportation, Storage and Processing of Natural Gas, and $4 million in 2015 and $7 million in 2014 within Sales of Natural Gas Liquids in our Consolidated Statements of Operations. There were no related party sales of natural gas liquids in 2016.
We had accounts receivable from DCP Midstream and its affiliates of $3 million at December 31, 2016 and $1 million at December 31, 2015. We received no distributions from DCP Midstream during 2016 or 2015. We received distributions from DCP Midstream of $237 million in 2014, 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, our proportionate share 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 the fourth quarter of 2015 and the remaining $148 million, classified as Cash Flows from Investing Activities-Distribution to Equity Investments, in the second quarter of 2016.
SESH. In 2014, SESH issued unsecured debt of $400 million to fund the repayment of its current debt. SESH distributed $200 million, our proportionate share 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.
Other. We provide certain administrative and other services to certain other operating entities. We recorded recoveries of costs from these affiliates of $68 million in 2016, $28 million in 2015 and $38 million in 2014. We also recorded recoveries of costs associated with a project of $116 million in 2016 and $139 million in 2015. Outstanding receivables from these affiliates totaled $21 million at December 31, 2016 and $11 million at December 31, 2015.
See also Notes 3, 18 and 20 for additional related party information.
11. Variable Interest Entities
Sabal Trail. On April 1, 2016, NextEra Energy, Inc. (NextEra) purchased a 9.5% interest in Sabal Trail Transmission, LLC (Sabal Trail) from SEP. Consideration for this transaction consisted of approximately $110 million cash, $102 million of which is classified as Cash Flows from Financing Activities-Contributions from Noncontrolling Interests. See Note 12 for additional information related to this transaction. As of December 31, 2016, we have an effective 37.6% ownership interest in Sabal Trail through our ownership of SEP. Sabal Trail is a joint venture that is constructing a natural gas pipeline to transport natural gas to Florida. Sabal Trail is a VIE due to insufficient equity at risk to finance its activities. We determined that we are the primary beneficiary because we direct the activities of Sabal Trail that most significantly impact its economic performance and we consolidate Sabal Trail in our financial statements. The current estimate of the total remaining construction cost is approximately $1.2 billion.
Valley Crossing. Valley Crossing Pipeline, LLC (Valley Crossing), our wholly-owned subsidiary, is constructing a natural gas pipeline to transport natural gas within Texas. We are the primary beneficiary because we direct the activities of Valley Crossing that most significantly impact its economic performance. Accordingly, we consolidate Valley Crossing in our financial statements. The current estimate of the total remaining construction cost is $1.4 billion.
The following table summarizes the assets and liabilities of Sabal Trail and Valley Crossing:
Nexus. We have an effective 37.6% ownership interest in Nexus Gas Transmission, LLC (Nexus) through our ownership of SEP. Nexus is a joint venture that is constructing a natural gas pipeline from Ohio to Michigan and continuing on to Ontario, Canada. Nexus is a VIE due to insufficient equity at risk to finance its activities. We determined that we are not the primary beneficiary because the power to direct the activities of Nexus that most significantly impact its economic performance is shared. Nexus is accounted for under the equity method of accounting. Our maximum exposure to loss is $1 billion. We have an investment in Nexus of $356 million and $90 million as of December 31, 2016 and December 31, 2015, respectively, classified as Investments in and Loans to Unconsolidated Affiliates on our Consolidated Balance Sheets.
On December 29, 2016, SEP issued performance guarantees to a third party and an affiliate on behalf of Nexus. See Note 22 for further discussion of the guarantee agreement.
12. Intangible Assets
During the first quarter of 2016, SEP entered into a project coordination agreement (PCA) with NextEra, Duke Energy Corporation (Duke Energy) and Williams Partners L.P. In accordance with the agreement, payments will be made, based on SEP’s proportional ownership interest in Sabal Trail, as certain milestones of the project are met. During the first quarter of 2016, the first milestone was achieved and paid, consisting of $48 million.
On April 1, 2016, NextEra purchased an additional 9.5% interest in Sabal Trail from SEP, reducing SEP’s ownership interest in Sabal Trail to 50%. Upon purchase of the additional ownership interest, NextEra reimbursed SEP $8 million for NextEra’s proportional share of the first milestone payment.
During the third quarter of 2016, the second milestone was achieved and paid, consisting of $40 million. The milestone payments are classified as Cash Flows from Investing Activities-Purchase of Intangible, Net. This PCA, in the amount of $80 million as of December 31, 2016, is an intangible asset and is classified as Investments and Other Assets-Other on our Consolidated Balance Sheet. The intangible asset will be amortized over a period of 25 years beginning at the time of in-service of Sabal Trail, which is expected to occur during the first half of 2017.
13. Goodwill
The following table presents activity within goodwill on a segment basis:
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:
In 2015, we performed additional goodwill impairment testing for BC Field Services and Empress due to the sustained downturn in commodity prices. 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 the recognition of a $270 million goodwill impairment for BC Field Services and a $63 million goodwill impairment for Empress for a total goodwill impairment of $333 million.
See Note 10 for discussion related to the 2015 impairment of goodwill recognized by DCP Midstream.
No triggering events have occurred with our reporting units since April 1, 2016 (our annual testing date) that would warrant re-testing for goodwill impairment.
14. 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, Canadian equity securities, treasury bills and money market securities 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, capital expenditures and NEB regulatory requirements, 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.
AFS Securities. AFS securities are as follows:
___________________________________
(a)
Amounts related to certain construction projects.
(b)
Amounts related to restricted funds held and collected from customers of Western Canada Transmission & Processing and Express-Platte for Canadian pipeline abandonment in accordance with the NEB’s regulatory requirements.
Our AFS securities are classified on the Consolidated Balance Sheets as follows:
At December 31, 2016, 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, 2016 or 2015.
HTM Securities. HTM securities are as follows:
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, 2016.
At December 31, 2016, 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, 2016 or 2015.
Other Restricted Funds. In addition to the portions of the AFS and HTM securities that were restricted as described above, we had other restricted funds totaling $27 million at December 31, 2016 and $11 million at December 31, 2015 classified as Current Assets-Other on the Consolidated Balance Sheets. Included in these restricted funds are $11 million at December 31, 2016 of funds received from the province of Ontario related to the Green Investment Fund that is to be distributed to eligible homeowners, based on specific energy conservation initiatives at Union Gas, $12 million and $11 million
at December 31, 2016 and December 31, 2015, respectively, related to additional amounts for insurance and $4 million at December 31, 2016 at M&N Canada pursuant to certain debt agreements.
We also had other restricted funds totaling $42 million at December 31, 2016 and $38 million at December 31, 2015 classified as Investments and Other Assets-Other on the Consolidated Balance Sheets. At December 31, 2016 these restricted funds consisted of $17 million related to funds held and collected from customers of Western Canada Transmission & Processing and Express-Platte for Canadian pipeline abandonment in accordance with the NEB’s regulatory requirements, $5 million related to certain construction projects, $17 million of funds received from the province of Ontario related to the Green Investment Fund and $3 million at M&N Canada pursuant to certain debt agreements. At December 31, 2015 these restricted funds consisted of $24 million related to funds held and collected from customers of Western Canada Transmission & Processing and Express-Platte for Canadian pipeline abandonment in accordance with the NEB’s regulatory requirements and $14 million related to certain construction projects.
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 2016 and 2015 and $4 million in 2014, and is included in Other Income and Expenses, Net on the Consolidated Statements of Operations.
15. Property, Plant and Equipment
We had no material capital leases at December 31, 2016 or 2015.
Almost 86% 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 2.66% for 2016, 2.72% for 2015 and 2.82% for 2014.
Amortization expense of intangible assets totaled $74 million in 2016, $79 million in 2015 and $74 million in 2014. Estimated amortization expense for the next five years follows:
16. Asset Retirement Obligations
Our AROs relate mostly to the legal obligations to disconnect, purge and cap abandoned pipelines, capping of abandoned storage wells, the retirement of certain gathering pipelines and processing facilities, obligations related to right-of-way agreements and contractual leases for land use and in some buildings, special handling and disposition of asbestos if it is disturbed. 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.
Reconciliation of Changes in Asset Retirement Obligation Liabilities
________
(a)
Amounts included in Deferred Credits and Other Liabilities-Regulatory and Other in the Consolidated Balance Sheets.
17. Debt and Credit Facilities
Summary of Debt and Related Terms
______
(a)
The weighted-average days to maturity was 14 days as of December 31, 2016 and 12 days as of December 31, 2015.
(b)
As of December 31, 2016 and 2015, respectively, $4,904 million and $4,681 million of debt was denominated in Canadian dollars.
(c)
Weighted-average rate on outstanding commercial paper was 1.08% at December 31, 2016 and 0.9% at December 31, 2015.
Secured Debt. Secured debt, totaling $208 million as of December 31, 2016, 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 $2,153 million of floating-rate debt as of December 31, 2016 and $1,812 million as of December 31, 2015. The weighted average interest rate of borrowings outstanding that contained floating rates was 1.35% at December 31, 2016 and 1.15% at December 31, 2015.
Annual Maturities
__________
(a)
Excludes commercial paper of $1,453 million. Includes capital leases of $14 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
__________________
(a)
Revolving credit facilities contain a covenant requiring the Spectra Energy consolidated debt-to-total capitalization ratio, as defined in the agreements, to not exceed 65%. Per the terms of the agreements, collateralized debt is excluded from the calculation of the ratio. This ratio was 56.3% at December 31, 2016.
(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, 2016, this ratio was 3.8 to 1.
(c)
U.S. dollar equivalent at December 31, 2016. 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 33.2% at December 31, 2016.
(d)
U.S. dollar equivalent at December 31, 2016. The revolving credit facility is 700 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 69.0% at December 31, 2016.
On September 29, 2016, we entered into a new one-year, $2 billion credit facility at Spectra Energy Capital, LLC (Spectra Capital), which expires in 2017. Proceeds from borrowings under the credit facility will be used for general corporate purposes. Amounts borrowed under the credit facility must be repaid following any change in control, including any that results from the proposed merger with Enbridge.
On April 29, 2016, we amended the Union Gas and SEP revolving credit agreements. The Union Gas revolving credit facility was increased to 700 million Canadian dollars and the SEP revolving facility was increased to $2.5 billion. The expiration of both facilities was extended, with both facilities expiring in 2021.
On April 29, 2016, we amended the Westcoast and Spectra Capital revolving credit agreements. The expiration of both credit facilities was extended, with both facilities expiring in 2021.
The issuances of commercial paper, letters of credit and revolving borrowings reduce the amounts available under the credit facilities. As of December 31, 2016, 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, 2016, 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 agreements, collateralized debt is excluded from the calculation of the ratio. This ratio was 56.3% at December 31, 2016. Approximately $8.4 billion of our equity (net assets) was considered restricted at December 31, 2016, representing the minimum amount of equity required to maintain the 65% consolidated debt-to-total capitalization ratio.
18. 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 49.7% of the outstanding preferred shares are redeemable at the option of Westcoast and Union Gas, as applicable.
On August 30, 2016, Westcoast issued 12 million Cumulative 5-Year Minimum Rate Reset Redeemable First Preferred Shares, Series 12 for an aggregate principal amount of 300 million Canadian dollars (approximately $229 million as of the issuance date). Net proceeds from the issuance were used to fund capital expenditures and for general corporate purposes.
In December 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.
19. 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:
The following presents changes in Level 3 assets and liabilities that are measured at fair value on a recurring basis using significant unobservable inputs:
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 required significant management judgment or estimation.
As of December 31, 2016, there are no derivative financial instruments classified as Level 3. Those reported in Level 3 at December 31, 2015 consisted of NGL revenue swap contracts related to the Empress assets in Western Canada Transmission & Processing, which were disposed of on August 4, 2016. See Note 3 for further discussion related to the sale of Empress. 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 included both observable and unobservable inputs, if the unobservable input was determined to be significant to the overall inputs, the entire valuation was categorized in Level 3. This included derivatives valued using indicative price quotations whose contract length extended into unobservable periods.
The fair value of these NGL basis swaps was determined using a discounted cash flow valuation technique based on a forward commodity basis curve. For those derivatives, the primary input to the valuation model was the forward commodity basis curve, which was based on observable or public data sources and extrapolated when observable prices were not available.
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.
__________
(a)
Included within Investments in and Loans to Unconsolidated Affiliates.
(b)
Excludes commercial paper, 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, commercial paper and short-term money market securities 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.
There were no material adjustments to assets and liabilities measured at fair value on a nonrecurring basis in 2016. In 2015, we recorded goodwill impairment charges on BC Field Services and Empress reporting units of $270 million and $63 million, respectively. See Note 13 for further discussion.
20. 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 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. As of April 2016, we ceased entering into new contracts under our Empress risk management program. See Note 3 for further discussion related to the sale of Empress.
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, 2016.
Derivative Portfolio Carrying Value as of December 31, 2016
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 19 for information regarding the presentation of these derivative positions on our Consolidated Balance Sheets.
Commodity Derivatives. Prior to the sale of Empress on August 4, 2016, our NGL marketing operations were exposed to market fluctuations in the prices of natural gas and NGLs related to natural gas processing and marketing activities.
At December 31, 2016, we had no commodity mark-to-market derivatives outstanding. At December 31, 2015, we had commodity mark-to-market derivatives outstanding that had netting or rights of offset arrangements as follows:
Substantially all of our commodity derivative agreements outstanding at December 31, 2015 had provisions that required collateral to be posted in the amount of the net liability position if one of our credit ratings fell below investment grade.
Information regarding the impacts of commodity derivatives on our Consolidated Statements of Operations is as follows:
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 2016, 2015 or 2014.
At December 31, 2016, we had “pay floating-receive fixed” interest rate swaps outstanding with a total notional amount of $2 billion 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 is as follows:
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.
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.
21. 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, climate change, 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.
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 approximately $6 million as of December 31, 2016 and $8 million as of December 31, 2015. 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 related to litigation recorded as of December 31, 2016 or 2015.
Other Commitments and Contingencies
See Note 22 for a discussion of guarantees and indemnifications.
Operating Lease Commitments
We lease assets in various areas of our operations. Consolidated rental expense for operating leases classified in Operating Income was $39 million in 2016, $47 million for 2015 and $38 million for 2014, 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, 2016 or 2015.
22. 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 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, 2016 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.
On December 29, 2016, SEP issued performance guarantees to a third party and an affiliate on behalf of an equity method investee. These guarantees were issued to enable the equity method investee to enter into long-term transportation contracts with the third party. While the likelihood is remote, the maximum potential amount of future payment SEP could have been required to make as of December 31, 2016 was $50 million. These performance guarantees expire in 2032.
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 investees, 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.
On December 30, 2016, in connection with our 50% ownership in DCP Midstream, we agreed to guarantee our portion of the obligations of the joint venture under a $424 million term loan agreement. If DCP Midstream fails to meet its obligations under the credit agreement, our maximum potential total future payments to lenders under the guarantee would be $225 million. The guarantee will terminate upon the payment of all obligations under the credit agreement, which expires in December 2019.
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 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, 2016, the amounts recorded for the guarantees and indemnifications described above are not material, both individually and in the aggregate.
23. Issuances of Common Stock
On March 1, 2016, we entered into an equity distribution agreement under which we may sell and issue common stock up to an aggregate offering price of $500 million. The equity distribution agreement allows us to offer and sell common stock at prices deemed appropriate through sales agents. Sales of common stock under the equity distribution agreement will be made by means of ordinary brokers’ transactions through the facilities of the NYSE, in block transactions, or as otherwise agreed upon by one or more of the sales agents and us. We intend to use the net proceeds from sales under this at-the-market program for general corporate purposes, including investments in subsidiaries to fund capital expenditures. We issued approximately 12.9 million of common shares to the public under this program, for total net proceeds of $383 million through December 31, 2016.
In April 2016, we issued 16.1 million common shares to the public for net proceeds of approximately $479 million. Net proceeds from the offering were used to purchase approximately 10.4 million common units in SEP. SEP used the proceeds from our unit purchase for general corporate purposes, including the funding of its current expansion capital plan.
24. 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:
________________
(a)
See Note 2 for further discussion.
25. 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 53 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 vest ratably 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.
We recorded pre-tax stock-based compensation expense as follows, the components of which are described further below:
The tax benefit in Net Income associated with the recorded stock-based compensation expense was $10 million in 2016 and $7 million in both 2015 and 2014. We recognized tax benefits from stock-based compensation cost of approximately $11 million in 2016, $1 million in 2015 and $3 million in 2014 in Additional Paid-in Capital.
Awards Activity
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. There were no liability-classified awards outstanding in 2016. The 2015 and 2014 liability-classified awards were settled in cash at vesting. We granted 593,600 equity-classified awards during 2016, 564,300 during 2015 and 557,100 during 2014, with fair values of $31 million, $27 million, and $26 million, respectively. We did not grant liability-classified awards during 2016, 2015 or 2014. Of the unvested and outstanding performance awards granted, 1,350,249 awards contain market conditions based on the total shareholder return of Spectra Energy common stock relative to a pre-defined peer group. 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
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 $26 million in 2016, less than $1 million in 2015 and $20 million in 2014. As of December 31, 2016, we expect to recognize $27 million of future compensation cost related to outstanding performance awards over a weighted-average period of less than 2 years.
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 240,610 equity-classified awards to our employees in 2016, 39,200 in 2015 and 101,500 in 2014, with fair values of $7 million, $1 million and $4 million, respectively. We awarded 302,150 liability-classified awards to our employees in 2016 and 356,100 in 2015 and 353,000 in 2014, with fair values of $9 million in 2016 and $13 million in both 2015 and 2014. The liability-classified awards are remeasured at each reporting period until settlement.
The total fair value of the shares vested was $16 million in 2016, $13 million in 2015 and $11 million in 2014. As of December 31, 2016, we expect to recognize $17 million of future compensation cost related to phantom awards over a weighted-average period of less than two years.
Stock Option Activity
We awarded 925,300 non-qualified stock options to employees during 2016, with a fair value of $2 million. We did not award any non-qualified stock options to employees during 2015 or 2014.
Weighted-Average Assumptions for Option Pricing
The risk-free rate of return was determined based on a yield curve of U.S. Treasury rates ranging from six months to ten years and a period commensurate with the expected life of the options granted. The expected volatility was established based on historical volatility over six years using daily stock price observations. The expected dividend yield was determined based on the most recent annual dividend and the stock price at the time of grant.
The total intrinsic value of options exercised was $11 million in 2016, $1 million in 2015 and $6 million in 2014. Cash received by us from options exercised was $22 million in 2016, $3 million in 2015 and $11 million in 2014. As of December 31, 2016, we expect to recognize $1 million of future compensation costs related to these stock options over a weighted average period of less than two years.
26. 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 $64 million as of December 31, 2016 and $18 million as of December 31, 2015, 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 both 2016 and 2015 and $21 million in 2014. We made total contributions to our Canadian Qualified and Non-Qualified Pension Plans of $17 million in 2016, $22 million in 2015 and $36 million in 2014. Contributions of $8 million in both 2016 and 2015 and $9 million in 2014 were made to our Canadian DC plan. We anticipate that in 2017 we will make total contributions of approximately $2 million to the U.S. Qualified and Non-Qualified Pension Plans, approximately $24 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 13 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.
Qualified and Non-Qualified Pension Plans
Change in Projected Benefit Obligation and Change in Fair Value of Plan Assets
The tables above include certain nonqualified pension plans that are unfunded. Those U.S. plans had projected benefit obligations of $24 million at December 31, 2016 and $23 million at December 31, 2015. Those Canadian plans had projected benefit obligations of $112 million at December 31, 2016 and $103 million at December 31, 2015.
At December 31, 2016, U.S. plans with accumulated benefit obligations in excess of plan assets had projected benefit obligations of $24 million, accumulated benefit obligations of $21 million and no plan assets. Canadian plans with accumulated benefit obligations in excess of plan assets had projected benefit obligations of $811 million, accumulated benefit obligations of $748 million and plan assets with a fair value of $631 million.
Amounts Recognized in Accumulated Other Comprehensive Income
Components of Net Periodic Pension Costs
In 2017, approximately $8 million of actuarial losses for the U.S. plans and $16 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
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, 2016 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.
Qualified Pension Plan Assets
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 19:
The following presents changes in Level 3 assets that are measured at fair value on a recurring basis using significant unobservable inputs:
Expected Benefit Payments
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
_______
(a)
Recognized primarily in Deferred Credits and Other Liabilities-Regulatory and Other in the Consolidated Balance Sheets.
Other Post-Retirement Benefit Plans-Amounts Recognized in Accumulated Other Comprehensive Income
In 2017, $1 million of prior service costs will be amortized from AOCI into net periodic pension costs for the U.S. plans and approximately $1 million for the Canadian plans.
Other Post-Retirement Benefits Plans-Assumptions Used for Benefits Accounting
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.
Assumed Health Care Cost Trend Rates
Sensitivity to Changes in Assumed Health Care Cost Trend Rates
Other Post-Retirement Plan Assets
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 19:
The following presents changes in Level 3 assets that are measured at fair value on a recurring basis using significant unobservable inputs:
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.
We anticipate making contributions of $3 million to the U.S. plans and $4 million to the Canadian plans in 2017.
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 2016, 2015 and 2014 for U.S employees. We expensed $12 million in 2016 and $13 million in 2015 and 2014 for Canadian employees.
27. 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 (SEC) 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, 2016
(In millions)
Spectra Energy Corp
Condensed Consolidating Statement of Operations
Year Ended December 31, 2015
(In millions)
Spectra Energy Corp
Condensed Consolidating Statement of Operations
Year Ended December 31, 2014
(In millions)
Spectra Energy Corp
Condensed Consolidating Statements of Comprehensive Income
(In millions)
Spectra Energy Corp
Condensed Consolidating Balance Sheet
December 31, 2016
(In millions)
Spectra Energy Corp
Condensed Consolidating Balance Sheet
December 31, 2015
(In millions)
Spectra Energy Corp
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2016
(In millions)
________
(a)
Excludes the effects of $6,416 million of non-cash equitizations of advances receivable owed to Spectra Capital and Spectra Energy Corp.
Spectra Energy Corp
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2015
(In millions)
Spectra Energy Corp
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2014
(In millions)
28. Quarterly Financial Data (Unaudited)
___________
(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.
During the fourth quarter of 2015, we recorded goodwill impairments associated with the acquisition of Westcoast in 2002 for BC Field Services and Empress, 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 13 for further discussion.
SPECTRA ENERGY CORP
SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
_________
(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, 2016, 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, 2016 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.
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 “Item 1. Business, Executive and Other Officers” of this report.
Directors of the Company
Below is biographical information for each director who serves on the Company’s Board of Directors (our Board). Each director was elected to serve for a one year term.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires our directors and executive officers, and persons owning more than 10% of our common stock, to file with the SEC initial reports of beneficial ownership of the Company’s equity securities and of certain changes in that beneficial ownership. We prepare and file these reports on behalf of our directors and executive officers. To our knowledge, all Section 16(a) reporting requirements applicable to our directors and executive officers were complied with during 2016.
Code of Business Ethics
Our Code of Business Ethics is applicable to all of the Company’s directors, officers and employees, including the Company’s president and chief executive officer, chief financial officer and controller. Our Code of Business Ethics is available on our website at http://www.spectraenergy.com in the “Corporate Governance” section and is available in print upon request. Any amendment to or waiver from our Code of Business Ethics must be approved by our Board and will be posted on our website.
Corporate Governance
Our Board recognizes that excellence in corporate governance is essential to carrying out its responsibilities to our shareholders. The framework for our corporate governance can be found in our Principles for Corporate Governance, our Code of Business Ethics, and the charters of the Audit Committee, the Compensation Committee, the Corporate Governance Committee, and the Finance and Risk Committee. You can access these governance materials on our website at http://www.spectraenergy.com in the “Corporate Governance” section. You can receive printed copies upon request.
Executive Sessions of Non-Management Directors
Our Board holds executive sessions on a regular basis without the presence of management. In his role as Lead Director, Mr. Comper’s responsibilities include presiding at executive sessions of the independent directors.
Communications with Directors
Interested parties can communicate with any of our directors by writing to our Corporate Secretary at the following address:
Corporate Secretary
Spectra Energy Corp
5400 Westheimer Court
Houston, TX 77056
Our Corporate Secretary will distribute communications to our Board, to an individual director or to selected directors, depending on the content of the communication. In accordance with rules of the NYSE, interested parties wishing to communicate only with the non-management or independent directors can address their communications to “Independent Directors, c/o Corporate Secretary” at the above-mentioned address. In that regard, the Board has requested that certain items that are unrelated to the duties and responsibilities of the Board be excluded, such as: spam; junk mail and mass mailings; service complaints; resumes and other forms of job inquiries; surveys; and business solicitations or advertisements. In addition, material that is unduly hostile, threatening, obscene or similarly unsuitable will be excluded. However, any communication that is so excluded remains available to any director upon request.
Board Committees
The Board has four standing committees - Audit; Compensation; Corporate Governance; and Finance and Risk. Each committee operates under a written charter adopted by the Board. The charters are posted on our website at http://www.spectraenergy.com in the “Corporate Governance” section. The charters are available in print to any shareholder upon request.
Item 11. Executive Compensation.
Compensation Committee Report
The Compensation Committee has reviewed and discussed the following Compensation Discussion and Analysis with management. Based on this review and discussion, the Compensation Committee recommended to our Board that the Compensation Discussion and Analysis be included in this Amendment. This report is provided by the following independent directors who comprise the Compensation Committee:
Michael E. J. Phelps (Chair)
Joseph Alvarado
Pamela L. Carter
Clarence P. Cazalot Jr
Michael G. Morris
Compensation Discussion and Analysis
In this section, we describe the design and purpose of the compensation programs that apply to the executive officers of Spectra Energy who are listed in the Summary Compensation Table. We refer to these officers as our Named Executive Officers. They are:
•
Gregory L. Ebel, Chairman, President and Chief Executive Officer
•
J. Patrick Reddy, Chief Financial Officer
•
Reginald D. Hedgebeth, General Counsel and Chief Ethics and Compliance Officer
•
Guy G. Buckley, Chief Development Officer
•
William T. Yardley, President U.S. Transmission
Summary of Compensation Philosophy
We believe that the successful execution of our strategy should result in enhanced shareholder value. Our executive compensation programs are designed to attract and retain executives who are highly qualified to carry out our strategy and to create incentives that link to our strategic direction.
To achieve these objectives, we design compensation opportunities for executives based on the following principles:
•
Compensation programs should support the accomplishment of our strategic and financial goals.
•
The majority of compensation available for our Named Executive Officers should be contingent on the Company’s attainment of pre-established performance objectives, both short-term and long-term.
•
Compensation opportunities should be aligned with the interests of shareholders, and incentive programs should be designed in consideration of their impact on shareholders, both immediately and in the long-term.
•
Compensation opportunities - as measured by the sum of salary, short-term cash incentive target, and the targeted value of long-term compensation awards - should be sufficiently competitive (in relation to the median of the markets in which we compete for executives) to attract, retain and incentivize Spectra Energy’s executives.
•
Fringe benefits, perquisite programs and other forms of indirect compensation should be minimized.
Role of Performance Measures in Our Compensation Program
Each year the Compensation Committee establishes financial and operational objectives for each Named Executive Officer that are linked to our strategic goals. Our compensation plans are designed to reduce compensation below targeted payouts if these objectives are not realized. Alternatively, in the event we exceed our objectives, these plans are designed to compensate executives at above-target levels.
Providing safe and reliable operations continues to be a foundational strategy of our business. Although safe and reliable operations benefit the Company and its shareholders in the long-term, the Compensation Committee believes that this goal is best measured in the short-term. The Compensation Committee also believes it is important to link compensation opportunities for our executives to our stock performance over the long-term. Given these considerations, the Committee links compensation
incentive opportunities with meeting financial targets while providing safe and reliable operations in the short-term, and enhancing shareholder return over the long-term.
Consistent with this philosophy, the Committee has structured our annual short-term incentive program to provide our Named Executive Officers with incentives to reach short-term strategic objectives that are aligned with the Company’s long-term strategic plan. Short-term cash payouts are tied to specific financial and operational goals at the corporate and business unit level, where appropriate, that align with our strategic objectives and our shareholders’ interests:
•
80% of each executive’s short-term cash incentive opportunity is based upon targets for our ongoing Distributable Cash Flow (DCF), Spectra Energy Transmission EBITDA and return on capital employed (ROCE) of our core businesses.
•
The remaining 20% is based upon achieving operational and safety objectives.
Please see “Salary and Total Pay Opportunities” to learn more about these performance measures and why the Committee chose them.
In our long-term incentives, the Committee emphasizes total shareholder return (TSR). A substantial portion of the compensation opportunities for our Named Executive Officers consists of long-term equity-based incentives that are designed both to align our executives’ interests with our shareholders’ long-term interests and to provide meaningful performance and retention incentives:
•
50% of the long-term incentive grants made to our Named Executive Officers vest based on TSR measured over a three-year period.
•
30% of the grants are subject to vesting requirements at the end of three years.
•
20% of the grants are non-qualified stock options, which become exercisable over a three-year period.
Please see “Salary and Total Pay Opportunities” for more detail about our long-term incentives.
2016 Shareholder Advisory Vote on Compensation
We have traditionally received very strong support for our executive compensation practices. In an advisory vote held at the 2016 Annual Meeting, our shareholders voted in strong support of the executive compensation programs and on the compensation earned by our Named Executive Officers, with a vote of 95% in favor.
Compensation-Setting Process
Compensation Committee
The Compensation Committee’s responsibilities include:
•
establishing and reviewing the Company’s overall compensation philosophy;
•
reviewing the effectiveness of our compensation program on a regular basis and approving changes to the program;
•
reviewing and approving the salaries and other compensation of all our executive officers, including the Named Executive Officers, and any agreements with executive officers regarding their compensation;
•
with input from our Board, performing an annual evaluation of our Chief Executive Officer’s performance; and
•
making recommendations to our Board on targeted compensation levels for our Chief Executive Officer.
The Compensation Committee operates under a written charter adopted by our Board, which you may view in the “Corporate Governance” section of our website at http://www.spectraenergy.com.
Five independent directors make up our Compensation Committee: Michael E. J. Phelps (Chair), Joseph Alvarado, Pamela L. Carter, Clarence P. Cazalot Jr and Michael G. Morris. Each has had significant responsibility for the design and administration of executive compensation programs, having served either on other public company compensation committees or as the senior executive of a business unit.
It is expected that the Compensation Committee will meet as often as is necessary to perform its duties and responsibilities. In 2016, the Committee met nine times. Our Chief Executive Officer and other members of management may attend Compensation Committee meetings, as invited. The Compensation Committee also meets in executive session without the presence of management or its consultant.
The Chair of the Compensation Committee works with management to establish meeting agendas. The Committee receives and reviews materials in advance of each meeting; these may include information that management believes will be helpful to the Compensation Committee, as well as materials the Committee has specifically requested. In 2016, these materials addressed matters such as (1) the competitiveness of executive compensation programs based on market data; (2) total compensation provided to Spectra Energy executives; (3) trends and legislative activity in executive compensation and/or benefits; (4) executive stock ownership levels; (5) corporate financial and operational performance compared to predetermined objectives; and (6) compensation, incentive and benefits matters related to the proposed merger between the Company and Enbridge (the Merger).
Compensation Committee Interlocks and Insider Participation
None of the members of our Compensation Committee is or has been an officer or employee of Spectra Energy. In addition, during the last fiscal year, none of our executive officers served as a member of the board or the compensation committee of any entity in which a Spectra Energy Board or Compensation Committee member is an executive officer.
Committee Advisors
Since 2007, the Compensation Committee has retained ExeQuity, LLP (ExeQuity) as its independent compensation consultant. ExeQuity reports directly to the Compensation Committee on matters related to executive compensation, advises it on best practices and analyzes meeting materials prepared by management. It confers, independently of management, with the Committee’s Chair and with the full Committee, although it may discuss compensation matters with management on a limited basis at the Committee’s direction. As needed, ExeQuity meets with the Committee in executive sessions at which no one from Spectra Energy’s management is present. ExeQuity performs no other services for the Company.
In 2016, ExeQuity prepared materials for the Compensation Committee, reviewed materials provided to the Compensation Committee by management, consulted with the Chair prior to meetings regarding agenda items, and attended Committee meetings.
In retaining ExeQuity, the Compensation Committee considered the six factors set forth in Section 303A.05(c)(iv) of the NYSE Listed Company Manual concerning potential conflicts of interest. In addition, after a review of information provided by
each member of the Compensation Committee, as well as information provided by ExeQuity, the Compensation Committee determined that there are no conflicts of interest raised by ExeQuity’s work with the Compensation Committee.
Role of Management
Members of Spectra Energy’s management, including our Chief Executive Officer, participate in certain aspects of the compensation-setting process, including:
•
recommending compensation programs, compensation policies, compensation levels and incentive opportunities;
•
compiling, preparing and distributing materials for Compensation Committee meetings, including market data;
•
recommending performance targets and objectives; and
•
evaluating employee performance (other than the performance of our Chief Executive Officer, whose performance is reviewed by the independent members of the Board).
In 2016, management engaged Aon Hewitt to assist management in developing its recommendations regarding compensation; in this capacity, Aon Hewitt was asked to attend the Compensation Committee meetings from time to time to discuss research and reports that it prepared at management’s request.
Factors Considered In Determining Total Compensation
The Compensation Committee also considers trends in the broader market as shown in general industry surveys. Specifically, the Compensation Committee has used the Aon Hewitt Total Compensation Management Database because it believes this survey provides a reliable indication of compensation practices in companies with revenues comparable to ours and of similar size.
External Market Conditions and Individual Factors
In addition to using benchmark survey data, the Compensation Committee takes into account external market conditions and individual factors when establishing the total compensation of each Named Executive Officer. Individual factors include the executive’s performance, level of experience, tenure, responsibilities and position. External market conditions include competitive pressures for the executive’s particular position within the industry, economic developments, the condition of labor markets, and the financial and market performance of the Company. To assist in its evaluation, the Compensation Committee uses tally sheets that provide the details of an executive’s historical and proposed compensation. Finally, the Compensation Committee considers internal equity when evaluating the compensation of our Named Executive Officers relative to one another.
Risk Considerations in Our Compensation Program
In addition to reviewing market factors, the Compensation Committee reviews the alignment of the executive compensation program components with the interests of our shareholders. The overall mix and design of our executives’ short- and long-term incentive compensation opportunities are balanced to mitigate undue risk and promote the health of the Company.
To drive long-term decision-making, our total incentive opportunities place greater emphasis on long-term goals. In our short-term program, no more than 30% of a Named Executive Officer’s targeted award is dependent on any one performance measure. Our short-term measures are chosen to balance the importance of generating short-term earnings and cash with the efficiency and effectiveness of our employed capital. Seventy (70) percent of each executive’s long-term opportunity is contingent on the performance of our stock on an absolute and relative basis, and each executive is required to own certain amounts of Spectra Energy stock, which provides continued alignment with our shareholders’ interests in the long-term growth of the Company.
Elements of Our Compensation Program
The objective of our compensation program is to link total compensation to individual and company performance on both a short-term and long-term basis. To carry out this objective, the program is structured to include short-term incentives that reward the achievement of predetermined performance objectives and long-term incentives that reward stock performance and encourage our executives to align their interests with those of shareholders.
PRINCIPAL COMPENSATION COMPONENTS FOR NAMED EXECUTIVE OFFICERS
2016 Compensation
Pay Mix
An executive’s total compensation opportunity is the sum of annual base salary, annual cash incentive target and the target value of his annual long-term incentive grant. The opportunity established for each of our Named Executive Officers is intended to provide total target compensation that falls in the median range for individuals who hold comparable positions in the markets in which we compete for executive talent.
For 2016, the total target pay opportunity, in aggregate, was at the market median for our Named Executive Officers.
Consistent with the pay-for-performance objectives of our compensation program, 84% of our Chief Executive Officer’s total target pay opportunity, and an average of 69% of all other Named Executive Officers’ total target pay opportunity, was in the form of short-term and long-term incentives.
The following charts show the mix of total target compensation for our Chief Executive Officer and for the other Named Executive Officers.
Salary and Total Pay Opportunities
Chief Executive Officer
The Compensation Committee made no change to Mr. Ebel’s 2016 total compensation opportunity due to his target compensation being in line with overall general industry survey data and in recognition of industry market conditions at the time his compensation was reviewed in February 2016.
Other Named Executive Officers
In February 2016, the Compensation Committee reviewed the 2015 total target pay opportunities of our Named Executive Officers and considered factors such as job responsibilities, levels of experience, individual performance, the salaries of executives in comparable positions as obtained from market surveys, internal comparisons and current market conditions. The Compensation Committee also reviewed the 2015 total target pay opportunities for our executives to see how those opportunities compare with pay opportunities at companies with which we compete for talent.
No merit increases were awarded to our Named Executive Officers, however Messrs. Buckley and Yardley each received a 9% base salary adjustment due to increased responsibility and to align with market.
The following table shows the 2016 target pay opportunities for each Named Executive Officer.
__________
(a)
Base salary effective March 1, 2016
Short-Term Incentive Opportunities
The 2016 short-term incentive opportunities under the Spectra Energy Executive Short-Term Incentive (STI) Plan were designed to compensate executives based on the Company’s 2016 financial and operational performance against goals set at the beginning of the year, and also on each executive’s overall individual performance during the year. The Committee established threshold, target and maximum incentive opportunities for each participant, expressed as a percentage of base salary. Target STI awards for our Named Executive Officers in 2016 are reflected in the 2016 Target Pay Opportunities table above.
Under guidelines adopted for the 2016 STI program, the Compensation Committee set a maximum payment opportunity on 2016 short-term incentive payments for all of our executives equal to 200% of their STI target. In order to meet requirements relating to the Company’s tax deduction under Section 162(m) of the Internal Revenue Code, annual incentive payouts are initially set at this maximum level to the extent that performance against any one of the Spectra Energy, Spectra Energy Transmission or business unit financial goals meets the threshold level of performance. To determine actual payouts, however, the Compensation Committee then applies negative discretion by reducing awards through the application of the framework described below in conjunction with actual performance against the Company’s financial and operational measures and consideration of individual performance.
The maximum that could be earned for performance on financial and operational measures was 200% of target. The amount that could be paid for performance at a specified minimum level for any measure was 50% of the target amount. 100% of the target amount would be paid for performance at the target level. No compensation was to be earned if performance fell below a specified minimum level.
As shown in the following table, STI payments for our Named Executive Officers were based on the achievement of financial and operational objectives related to management responsibilities for the Company, including the Company’s DCF, EBITDA and business unit ROCE, achievement of certain Environmental, Health and Safety (EHS) and operational goals, with an additional review based on an overall assessment of individual performance during the year.
Spectra Energy Ongoing DCF is a measure regarding cash generation. The Committee replaced the EPS metric used in 2015 with ongoing DCF for 2016 to place greater focus on cash generation and to better align with how our shareholder’s measure the Company’s performance. Target performance was set at $1,369 million, a level that matched our corporate forecasts. Maximum payout was set at $1,574 million, a level judged to be difficult to achieve, and minimum performance was set at $1,180 million, the lowest level that would justify a payout. Spectra Energy Transmission EBITDA is a measure of the effectiveness of the core business’s ability to generate cash without depreciation, interest or taxes, excluding our joint venture, DCP Midstream. In determining this measure, we have eliminated the impact of certain factors in order to make this measure a clearer gauge of the performance of our four core business units, including among others, the elimination of the effect of commodity price changes, the effect of exchange rate fluctuations in Canadian currency and the impact of weather at our distribution business unit. Target performance was set at $2,902 million, a level that matched our corporate forecasts. Maximum performance was set at $3,134 million, and minimum performance was set at $2,786 million, levels deemed by the Compensation Committee to be significant challenges or minimally acceptable, respectively.
Spectra Energy Transmission ROCE reflects the efficiency and effectiveness of capital deployment in our core business. Our business is capital-intensive and depends on the effective execution of our projects. Our ability to achieve our targeted returns on these projects is vital to the success of our business. Spectra Energy Transmission ROCE is one of the 2016 STI performance measures used for all of our Named Executive Officers, with the exception of Mr. Yardley whose measure and results are based on our U.S. Transmission business unit. We define Spectra Energy Transmission ROCE as our EBIT (excluding results from DCP Midstream) divided by our annual average total debt plus equity minus cash on hand and our investment in DCP Midstream. Target performance was set at 8.92%, a level consistent with corporate forecasts. Maximum performance was set at 9.81%, and minimum performance was set at 8.47%. Similar to other measures, maximum and minimum performance were set at levels deemed by the Compensation Committee to be significant challenges or minimally acceptable, respectively.
An EHS and Operations Scorecard was designed given the importance of safe and reliable operations and was designed to provide alignment and a common culture in all of our field and office locations. We emphasized the importance of a zero-injury culture by measuring improvement in frequency rates for recordable employee and contractor injury and preventable vehicle incidents. Annual targets in these areas are set to achieve incremental improvement in performance over prior years’ results.
We emphasized reliable operations by measuring reliability of performance at our compressor stations, processing plants and our liquid transmission system. We also focused on asset safety for our gas and liquid transmission assets.
Determination of 2016 Short-Term Incentive Payments
At the end of the 2016 cycle, management prepared a report on the achievement of the financial and EHS/operational goals under our STI plan. The Compensation Committee reviewed and approved these results, along with any proposed adjustments based on individual performance for each Named Executive Officer. In the case of Named Executive Officers other than our Chief Executive Officer, the Chief Executive Officer made recommendations to the Committee regarding any adjustments based on individual performance. In the case of our Chief Executive Officer, the Committee reviewed and approved his performance against financial and operational objectives and his overall individual performance. Following this process, the Compensation Committee approved the final performance results and payment of incentives to all Named Executive Officers.
The table below shows the level of performance needed to achieve the threshold, target and maximum payouts established for each financial goal, as well as the actual 2016 results and actual payout percentages. As discussed above, for each goal, achievement of the threshold, target and maximum amounts would result in corresponding payout percentages of 50%, 100% and 200%, respectively, of the target level.
For example, an executive’s short-term incentive payment associated with our Spectra Energy ongoing DCF results was calculated as 25% of the executive’s target cash incentive opportunity (25% being the weighting assigned to the DCF measure) multiplied by the actual 2016 payout percentage for the DCF measure, which was 106.83%.
__________
(a)
U.S. Transmission ROCE is used for Mr. Yardley, which achieved a payout percentage of 0%.
In determining the final award amounts, the Committee also considered other factors, including Mr. Ebel’s leadership in driving strong company performance in 2016, enhancing the Company’s financial strength, delivering record capital expansion projects in service and securing new projects. The Committee also included in its final determination of awards Messrs. Reddy’s, Hedgebeth’s, Buckley’s and Yardley’s performance related to the success of the items noted above.
2016 Long-Term Incentive Opportunities
We provide long-term incentive opportunities to our executive officers to achieve an alignment of executive and shareholder interests. These opportunities are designed to incentivize executives to achieve strategic goals that will maximize long-term shareholder value.
The Compensation Committee decided that our long-term incentive program for our Named Executive Officers should consist of a time-based element and performance-based elements on both an absolute and relative basis. It believes that combining these three forms of awards, with the heaviest weighting on the performance elements, is an effective means of creating a focus on shareholder return and helping us retain our executive talent in a competitive market.
Phantom units
Phantom units make up 30% of the annual Long-Term Incentive (LTI) grant value. These units generally vest at the end of three years if the grantee remains continuously employed by the Company/affiliates, at which time they are paid in cash, based on the fair market value of Spectra Energy common stock at the time of vesting. Dividend equivalents are accumulated from the date of grant and paid (in cash) only on the number of phantom units that actually vest.
Stock options
Non-qualified stock options make up 20% of the annual LTI grant value. These options generally vest ratably over three years if the grantee remains continuously employed by the Company/affiliates, at which time they become exercisable. The stock options have an exercise price based on the fair market value of Spectra Energy common stock on the date of grant and generally have a ten-year term.
Performance share units
For 2016, performance share unit awards continued to make up the remaining 50% of the target value of annual long-term compensation. These units are earned based on how the Company performs over a three-year period relative to our LTI Peer Group, which we revised to reflect changes in our industry and to better align industry results with the performance of the Company. The LTI Peer Group is made up of (1) companies in the S&P 500 Energy Index; (2) companies in the Alerian MLP Index, excluding DCP Partners and SEP and (3) Enbridge and TransCanada Corporation.
The LTI Peer Group differs from the Compensation Peer Group (See “Compensation Peer Group Comparison”) because the two groups serve two different purposes. The Compensation Peer Group provides an informal benchmark of compensation practices of companies with which we compete for executive talent, while the LTI Peer Group provides a measure of our performance compared to companies with which we compete for capital.
The vesting of performance share unit awards depends on how the TSR of our common stock (a performance metric under our long-term incentive program) compares to TSR results of our LTI Peer Group over a three-year measurement period, as shown below:
The Compensation Committee approved these percentages after reviewing similar programs adopted by many of the companies in the LTI Peer Group, reviewing the historical returns of the LTI Peer Group as well as indices that track energy company performance and consulting with its independent compensation consultant.
Once earned, the performance share units are converted to shares of Spectra Energy common stock at the time of vesting. Dividend equivalents are accumulated from the date of grant and paid (in cash) only on the number of performance share units that actually vest. The table below shows long-term incentive awards granted to our Named Executive Officers in 2016:
Determination of 2014-2016 Performance Share Unit Awards
The 2014 performance unit cycle commenced on January 1, 2014 and ended on December 31, 2016. Performance share units vest based on our TSR for this three-year period as compared to the TSR for companies in our 2014 Peer Group for LTI (which included Centerpoint Energy Inc., Consolidated Edison Inc., Dominion Resources Inc., DTE Energy Company, Enbridge, Equitable Resources Inc., Kinder Morgan Inc., National Fuel Gas Company, Nisource Inc., ONEOK Inc., PG&E Corp., Public Service Enterprise Group Inc., Sempra Energy, TransCanada Corp, Williams and Xcel Energy Inc.). Our final TSR for the three-year period was 38.07%, which is at the 62.70 percentile of the 2014 Peer Group for LTI. This resulted in a payout percentage of 142.33%. The following table lists the resulting number of 2014-2016 performance shares that vested and the total value realized including associated dividend equivalents:
Retirement and Other Benefits
Retirement Benefits
We provide our executives with retirement benefits under the Spectra Energy Retirement Savings Plan, the Spectra Energy Executive Savings Plan, the Spectra Energy Retirement Cash Balance Plan and the Spectra Energy Executive Cash Balance Plan. The Compensation Committee has determined that, based on market surveys, these plans are comparable to the benefits provided by our peers and provide an important tool for attracting and retaining our executives. Please refer to “Compensation Tables” for disclosure of the amounts paid to our Named Executive Officers under these plans.
The Spectra Energy Retirement Savings Plan, a 401(k) plan, is generally available to all our employees in the U.S. It is a tax-qualified retirement plan that provides a means for employees to save for retirement on a tax-deferred basis and to receive an employer matching contribution. Earnings on amounts credited to the plan depend on each participant’s investment choices (which may include a Spectra Energy common stock fund).
The Spectra Energy Executive Savings Plan enables executives to defer compensation, and receive employer matching contributions, in excess of the limits of the Internal Revenue Code that apply to qualified retirement plans such as the Spectra Energy Retirement Savings Plan. Investment choices under this plan are similar to those offered to all employees under the Spectra Energy Retirement Savings Plan.
The Spectra Energy Retirement Cash Balance Plan provides a defined benefit beginning at retirement, the amount of which is based on a participant’s cash balance account balance, which grows with monthly pay and interest credits.
The Spectra Energy Executive Cash Balance Plan provides executives with the retirement benefits to which they would be entitled under the Spectra Energy Retirement Cash Balance Plan in the absence of the Internal Revenue Code limits.
Perquisites and Personal Benefits
At the direction of our Board, Mr. Ebel uses the Company aircraft for personal travel in limited circumstances, primarily for business efficiency. Mr. Ebel’s family and guests may accompany him on business and personal trips. Other executive officers are not allowed to initiate personal trips on corporate or chartered aircraft. However, they are permitted to invite their spouses or guests to accompany them on business trips when space is available. When an executive officer’s use of aircraft or a guest’s travel does not meet the Internal Revenue Service’s standard for business use, the cost of that travel is imputed as income to the officer even if it did not result in incremental cost to the Company.
Severance
The Compensation Committee believes that change-in-control severance arrangements serve shareholders’ best interests by diminishing the potential distraction created by the personal uncertainties and risks that may affect our executives’ focus in the context of a potential corporate restructuring or change-in-control transaction. These protections also help ensure continuity of management in the event of certain corporate transactions.
However, the Compensation Committee believes that executives should not be unduly enriched if change-in-control severance arrangements are triggered. Accordingly, each Named Executive Officer has entered into an agreement with the Company that defines the circumstances under which severance benefits would be paid. The Compensation Committee approved the terms of these agreements after consultation with its independent compensation consultant and with outside counsel. For 2016, the agreements include the provisions listed below, which the Compensation Committee considered to be sufficient to achieve its objectives. See also “Compensation Tables-Potential Payments upon Termination of Employment or Change in Control.”
•
Agreements are triggered only if there is both a change in control of the Company and a qualifying termination of employment. This feature is commonly called a “double trigger.”
•
Cash severance benefits for the CEO are limited to three times annual salary plus three times annual target cash incentive and for the other Named Executive Officers are limited to two times annual salary plus two times annual target cash incentive.
•
Medical, dental and life insurance are continued during the two years following severance.
•
A lump-sum payment is provided for company savings-plan and pension-plan contributions.
•
A lump sum amount of $30,000 is provided for outplacement benefits.
•
Reimbursement of up to $100,000 for the cost of certain legal fees incurred in connection with claims under the agreement.
•
There is no provision to gross-up excise taxes that may be triggered under Section 4999 of the Internal Revenue Code. However, severance payments may be reduced to a level that does not trigger the excise tax if this results in greater net after-tax benefits for the executive than if severance benefits were not reduced and excise tax was paid.
•
Executives are subject to certain non-competition and non-solicitation provisions.
Other Compensation Policies
Clawback Policy
We have a policy on recovery of executive compensation (Clawback Policy). Our executive officers who are subject to Section 16 of the Exchange Act are subject to the Clawback Policy (each, a Covered Person). If our financial results are significantly restated due to fraud or intentional misconduct and a Covered Person is found to be personally responsible for the fraud or intentional misconduct that caused the need for the restatement, the Clawback Policy permits seeking recoupment of incentive, equity and/or performance-based compensation amounts awarded and paid to such Covered Person during the three-year period preceding the date of the restatement. Determinations of whether or not to seek such recoupment will be made, with respect to our Chief Executive Officer, at the sole discretion of our Board, and with respect to other Covered Persons, at the sole discretion of the Compensation Committee.
Stock Ownership Policy
We have adopted a stock ownership policy for executive officers and other key employees who receive long-term incentives. We believe that our executives should be required to own shares of Spectra Energy in order to establish an alignment between their interests and the interests of our shareholders. The employee is required to satisfy the ownership target
within five years after becoming subject to the policy. To reinforce the importance of stock ownership, employees who do not achieve their ownership targets by a preset date become ineligible for future long-term incentives unless they apply all short-term incentive payments to the purchase of our common stock until the ownership target is achieved.
The following table summarizes our stock ownership policy for our executive officers. All Named Executive Officers have exceeded their aggregate stock ownership requirement under this policy.
Stock Ownership Requirements
Derivative Transactions
Our stock trading policy applies to transactions in any securities that derive their value from our common stock or any of our debt securities. To avoid even the appearance of insider trading, this policy permits trading by our directors and executives in our securities only during a 30-day window following our quarterly or annual earnings release and only after obtaining preclearance from our Chief Executive Officer or General Counsel. In addition, because of the inherent potential for abuse, this policy restricts our directors and executives from entering into short-swing transactions, short sales, or the use of derivative securities, hedging transactions or margin accounts when such accounts or transactions relate to our securities.
Tax and Accounting Implications of Our Compensation Program
Deductibility of Executive Compensation
The Compensation Committee reviewed and considered the deductibility of executive compensation under Section 162(m) of the Internal Revenue Code, which provides that the Company generally may not deduct for federal income tax purposes annual compensation in excess of $1 million paid to certain employees. However, the $1 million limit does not apply to performance-based compensation that is paid pursuant to shareholder-approved plans and is approved by directors who qualify as “outside directors” within the meaning of Section 162(m) of the Internal Revenue Code.
The Compensation Committee generally structures and administers executive compensation plans and arrangements so that they will not be subject to the 162(m) deduction limit. However, to maintain flexibility in structuring appropriate compensation programs, the Committee may from time to time approve payments that cannot be deducted. For example, phantom units awarded to certain employees under our Long-Term Incentive Plan may not be deductible for federal income tax purposes, depending on the amount and type of other compensation these employees receive.
Accounting for Stock-Based Compensation
In accounting for employee awards, equity classified stock-based compensation cost is measured at the grant date based on the fair value of the award and is generally recognized as expense over the period beginning on the date the award is granted and ending on the earlier of the date the award vests or the date the employee becomes retirement-eligible. For accounting purposes, awards granted to retirement-eligible employees are deemed to vest on the grant date and their cost is recognized at that time. Liability classified stock-based compensation cost is re-measured at each reporting period and is recognized as expense over the requisite service period.
Internal Revenue Code Section 409A
To the extent we permit executives to defer compensation or we commit to deliver compensation at a later date than when earned and vested, we endeavor to ensure that, if applicable, the requirements of Section 409A of the Internal Revenue Code are satisfied. Failure to satisfy the Section 409A requirements could subject the executives receiving such nonqualified deferred compensation to a 20% excise tax.
Compensation Tables
This section provides information regarding the compensation of our Named Executive Officers for 2014 through 2016.
__________
(a)
Stock Awards column reflects the aggregate grant date fair value of performance share units and phantom units awards granted each year as shown in the 2016 Grants of Plan-Based Awards table and computed in accordance with the provisions of FASB ASC Topic 718. Option Awards column reflects the aggregate dollar amount recognized for financial statement reporting purposes for 2016 with respect to outstanding stock options. The aggregate dollar amounts were determined without regard to any estimate of forfeitures related to service-based vesting conditions. See Part II, Item 8. Financial Statements and Supplementary Data, Note 25 of Notes to Consolidated Financial Statements regarding assumptions underlying the valuation of equity awards. If the performance share units vested at the maximum level, the following represents the maximum value that would be payable on the performance share units granted in 2016, based on the closing stock price of our common stock on the grant date of these awards for Messrs. Ebel, Reddy, Hedgebeth, Buckley and Yardley: $5,668,640; $1,354,680; $1,008,200; $806,560; and $823,600, respectively.
(b)
Non-Equity Incentive Plan Compensation column includes amounts payable under the Spectra Energy Executive STI Plan with respect to the 2016, 2015 and 2014 performance periods. After the shareholder vote to approve the Merger, a portion of the 2016 amounts for Messrs. Ebel, Reddy, Hedgebeth and Buckley were paid in December 2016 to mitigate potential after-tax parachute costs to the Company and/or the executive under Section 280G and 4999 of the Internal Revenue Code. All remaining amounts, unless deferred, were paid, respectively, in February 2017, February 2016 and March 2015.
(c)
Change in Pension Value and Nonqualified Deferred Compensation Earnings represents the change in value during the twelve-month period ending on December 31 of each year. These changes were as follows for each Named Executive Officer:
(d)
All Other Compensation column includes the following for 2016:
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(1)
Amounts represent Company-matched charitable contributions during 2016.
(2)
The amounts shown as “Personal use of Company aircraft” reflect the personal use of the Company’s aircraft by the Named Executive Officers. When travel costs did not meet the IRS standard for “business use,” income was imputed to the officer even though such travel may not have resulted in incremental cost to Spectra Energy. The methodology used to compute the incremental cost of this benefit was based on the hourly variable cost for the use of the aircraft, plus any tax-deduction disallowance.
(e)
A portion of Mr. Ebel’s pension value for 2016, 2015 and 2014 was provided in Canadian dollars and has been converted to U.S. dollars using the Bloomberg spot rate of $0.7440 on December 31, 2016, $0.7226 on December 31, 2015 and $0.8605 on December 31, 2014.
(f)
On December 19, 2016, Mr. Buckley was awarded a $750,000 bonus to reward his extraordinary efforts in respect of the Merger.
__________
(a)
This column shows the potential payout opportunities established for the 2016 performance period under the terms of the Spectra Energy Executive STI Plan. The actual amounts paid to each executive under the plan for 2016 are disclosed in the “Summary Compensation Table.”
(b)
Awards were made in units of Spectra Energy common stock and were granted under the terms of the Spectra Energy Corp 2007 Long-Term Incentive Plan, as amended and restated.
(c)
All performance share units are earned based on how the Company performs relative to our Peer Group over a three-year performance period (January 1, 2016 to December 31, 2018). (d) All awards reflected in this column were computed in accordance with FASB ASC Topic 718. The per-share full grant date fair value of the phantom units, performance share units and stock options granted on February 16, 2016 were $28.40, $52.57 and $2.70, respectively.
__________
(a)
For options expiring on February 16, 2026, the exercise price is equal to the closing price of our common stock on the date of grant.
(b)
Messrs. Ebel, Reddy, Hedgebeth Buckley and Yardley received Spectra Energy phantom units on February 16, 2016, February 17, 2015 and February 18, 2014 which, subject to certain exceptions, vest on the third anniversary of the date of grant.
(c)
Messrs. Ebel, Reddy, Hedgebeth, Buckley and Yardley received performance share units on February 16, 2016 and February 17, 2015 which, subject to certain exceptions, are eligible for vesting on December 31, 2018 and December 31, 2017, respectively. As directed by Instruction 3 to Item 402(f)(2) of the SEC’s Regulation S-K, performance share units are listed at the maximum number of units.
__________
(a)
In order to mitigate potential after-tax parachute costs to the Company and/or the executive under Section 280G and 4999 of the Internal Revenue Code, after the shareholder vote to approve the pending Merger, the vesting of a portion of the outstanding awards held by Messrs. Ebel, Reddy, and Buckley was accelerated and these awards were settled in December 2016.
(b)
All shares included in this column are settled in shares, with the exception 56,700 shares for Mr. Ebel, which are settled in cash.
(c)
Calculated based on the closing price of a share of common stock on the respective vesting date; includes the following cash payments for dividend equivalents on vested awards: $1,269,709 to Mr. Ebel; $186,515 to Mr. Reddy; $144,112 to Mr. Hedgebeth; $131,240 to Mr. Buckley; and $99,715 to Mr. Yardley.
(d)
For Mr. Yardley, the number of shares acquired on exercise represents the gross number of shares in respect to the option that were exercised. The option was net-settled in cash by the Company, after withholding sufficient shares to cover the exercise price and withholding taxes.
Pension Benefits
This section contains information regarding benefits available to our Named Executive Officers under the Company’s pension and retirement plans.
Spectra Energy Retirement Cash Balance Plan and Executive Cash Balance
We provide pension benefits that are intended to assist our retirees with their retirement income needs. This section contains a detailed description of the plans that make up our pension program.
Each of the Named Executive Officers actively participated in pension plans sponsored by us or an affiliate in 2015. This included the Spectra Energy Retirement Cash Balance Plan (RCBP), a noncontributory, defined-benefit retirement plan that is intended to qualify under Section 401(a) of the Internal Revenue Code. The RCBP generally covers non-bargaining employees of the Company and its affiliates, and provides benefits under a “cash balance account” formula.
Each of the Named Executive Officers who participates in the RCBP has satisfied the requirements for receiving the account benefit upon termination of employment. The RCBP benefit is payable in the form of a lump sum in the amount credited to the hypothetical account at the time of benefit commencement. Payment is also available in the form of an annuity based on the actuarial equivalent of the account balance.
The amount credited to the hypothetical account is increased with monthly pay credits, as follows:
__________
(a)
For the RCBP, eligible monthly compensation is equal to Form W-2 wages, plus elective deferrals under a 401(k) or cafeteria plan. It does not include severance pay (including payment for unused vacation), expense reimbursements, allowances, cash or noncash fringe benefits, moving expenses, bonuses for performance periods in excess of one year, transition pay, long-term incentive compensation (including income resulting from any stock-based awards such as stock options, stock appreciation rights, phantom stock or restricted stock) and certain other compensation items.
If the participant earns more than the Social Security wage base, the account is credited with additional pay credits equal to 4% of eligible compensation above the Social Security wage base. Interest credits are credited monthly. The interest rate is determined quarterly based upon the 30-year Treasury rate, but with a 4% minimum and a 9% maximum.
A participant’s RCBP benefit may not be less than the amount determined under certain prior benefit formulas (including optional forms). In addition, the benefit is subject to benefit and compensation limits under the Internal Revenue Code.
Each of our Named Executive Officers was also eligible to participate in the Spectra Energy Executive Cash Balance Plan (ECBP), a noncontributory, defined-benefit retirement plan that is not intended to satisfy the requirements for qualification under Section 401(a) of the Internal Revenue Code. Benefits earned under the ECBP are attributable to (a) compensation in excess of the Internal Revenue Code’s annual compensation limit ($265,000 for 2016) for the determination of pay credits under the RCBP; (b) restoration of benefits in excess of a defined-benefit plan maximum annual benefit limit ($210,000 for 2016) under the Internal Revenue Code that applies to the RCBP; and (c) supplemental benefits granted to a particular participant. Generally, benefits earned under the RCBP and the ECBP vest upon completion of three years of service and, with certain exceptions, vested benefits generally become payable upon termination of employment with the Company.
We have established a grantor trust that is subject to the claims of our creditors into which funds related to the ECBP are deposited. Funds deposited into the trust are managed by an independent trustee subject to guidelines provided by the Company.
Pension Choices Plan for Employees of Westcoast Energy Inc. and Spectra Energy Supplemental Pension Plan
Mr. Ebel participated in the Pension Choices Plan for Employees of Westcoast and Affiliated Companies (Pension Plan) and the Spectra Energy Supplemental Executive Retirement Plan (SERP) while he resided in Canada prior to 2007. The Pension Plan is registered under the Income Tax Act and under the Pension Benefits Act (Ontario). The executive component of the Pension Plan is a non-contributory defined-benefit plan that provides a pension based on 2% of the annualized average of
the executive’s highest consecutive 36 months’ salary and cash incentive multiplied by his years of service while located in Canada. The Income Tax Act imposes a limit on the amount of benefits that can be paid from a registered pension plan.
The SERP is primarily intended to restore benefits under the Pension Plan to the level that would be available absent this limit. Mr. Ebel’s benefit accruals related to the Duke SERP were transferred to the Spectra Energy SERP effective with the spin-off. SERP benefits are paid from the general revenues of Spectra Energy generally as a life annuity. Effective with his transfer to the U.S., Mr. Ebel began participating in the Spectra Energy RCBP, and his active participation in the Pension Plan was suspended, although compensation (but not additional service) with Spectra Energy will be used in the calculation of his Pension Plan and SERP benefit. The table below provides information, determined as of December 31, 2016, about each plan that provides for payments or other benefits to our Named Executives Officers at, following or in connection with retirement:
Spectra Energy Executive Savings Plan
Under the Spectra Energy Executive Savings Plan, participants can elect to defer a portion of their base salary, short-term incentive compensation and long-term incentive compensation (other than stock options). Participants also receive a company matching contribution in excess of the contribution limits prescribed by the IRS under the Spectra Energy Retirement Savings Plan. In general, payments are made following termination of employment or death in the form of a lump sum or installments, as selected by the participant. Participants may request an accelerated distribution upon an “unforeseeable emergency.” In general, participants may direct the deemed investment of base salary deferrals, short-term incentive deferrals and matching contributions among investment options available under the Spectra Energy Retirement Savings Plan, including in a Spectra Energy Common Stock Fund. Deferrals of equity awards are credited with earnings and losses based on the performance of the Spectra Energy Common Stock Fund. We have established a grantor trust that is subject to the claims of our creditors into which funds related to the Spectra Energy Executive Savings Plan are deposited; an independent trustee manages these funds under guidelines provided by the Company.
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(a)
The table reflects contributions made to the Spectra Energy Executive Savings Plan. Executive contributions credited to the plan in 2016 include amounts reported as “Salary” in the Summary Compensation Table as well as “Non-Equity Incentive Plan Compensation” paid in 2016 but reported in the table as compensation earned in 2015. Amounts may also include elective deferrals of awards earned under our Long-Term Incentive Plan and payable in 2016.
(b)
Reflects matching contribution credits made in 2016 under the plan with respect to elective salary deferrals made by executives during 2016.
Potential Payments upon Termination of Employment or Change in Control
Under certain circumstances, each Named Executive Officer would be entitled to compensation if the executive’s employment were to terminate. The amount of compensation is contingent upon a variety of factors, including the circumstances of the termination. The agreements and terms of awards affecting this type of compensation are described below, followed by a table that estimates the amount that would become payable to each Named Executive Officer as a result of a change in control or a termination of employment, assuming a termination was effective as of December 31, 2016. The actual amounts that would be paid can be determined only at the time of the Named Executive Officer’s termination of employment.
Effect of Termination on Long-Term Incentive Awards
The following table summarizes the consequences that would occur in the event of a change in control or the termination of employment of a Named Executive Officer under our long-term incentive award agreements, without giving effect to the change in control agreements described below.
Change in Control Agreements
Each Named Executive Officer has entered into a change in control agreement with the Company. The agreements have an initial term of two years, and automatically extend for a year starting on the first anniversary of the date of the agreements. The Company or the Named Executive Officers can terminate the agreements following the initial two-year term, after providing six months advance written notice. The change in control agreements provide for payments and benefits to the executive in the event of termination of employment within two years after a “change in control” of the Company, other than termination: (1) by the Company for “cause;” (2) by reason of death or disability; or (3) of the executive for other than “good reason” (each such term as defined in the agreements).
For 2016, payments and benefits included:
•
a lump-sum cash payment equal to a pro-rata amount of the executive’s target cash incentive for the year in which the termination occurs;
•
a lump-sum cash payment equal to three times for the Chief Executive Officer and two times for all other Named Executive Officers the sum of the executive’s annual base salary and target annual cash incentive opportunity in effect immediately prior to termination or, if higher, in effect immediately prior to the first occurrence of an event or circumstance constituting “good reason”;
•
continued medical, dental and basic life insurance coverage for a two-year period (which can also be provided through a third-party insurer); and
•
a lump-sum cash payment representing the amount the Company would have allocated or contributed to the executive’s qualified and nonqualified defined-benefit pension plan and defined contribution savings plan accounts during the two years following the termination date, plus the unvested portion, if any, of the executive’s accounts as of the date of termination that would have vested during such two-year period.
In addition, under certain circumstances, the agreements may provide for continued vesting of certain long-term incentive awards for two additional years.
Under the change in control agreements, each Named Executive Officer also is entitled to $30,000 for outplacement services and reimbursement of up to $100,000 for the cost of certain legal fees incurred in connection with claims under the agreements. In the event that any of the payments or benefits provided for in the change in control agreement otherwise would constitute an “excess parachute payment” (as defined in Section 280G of the Internal Revenue Code), the amount of payments or benefits would be reduced to the maximum level that would not result in excise tax under Section 4999 of the Internal Revenue Code, if this reduction would cause the executive to receive a larger after-tax amount than if no reduction were made. In the event a Named Executive Officer becomes entitled to payments and benefits under a change in control agreement, the executive would be subject to a one-year non-competition and non-solicitation provision from the date of termination, in addition to certain confidentiality and cooperation provisions.
Potential Payments Upon Termination of Employment or a Change in Control Table
The amounts listed in the following table have been estimated based on a variety of assumptions, and the actual amounts to be paid out can only be determined at the time of each Named Executive Officer’s termination of employment. Amounts shown do not include compensation to which each Named Executive Officer would be entitled without regard to termination of employment, including (a) base salary and short-term incentives that have been earned but not yet paid, and (b) amounts that have been earned, but not yet paid, under the terms of the plans listed under the Pension Benefits and Nonqualified Deferred Compensation tables.
With respect to a Named Executive Officer who is covered by a change in control agreement, the amounts shown do not reflect any reduction in payments that might be made so that the excise tax under Section 4999 of the Internal Revenue Code would not apply.
__________
(a)
Amounts in the table represent obligations of the Company under agreements currently in place, and valued as of December 31, 2016.
(b)
Amounts payable under the terms of the Named Executive Officer’s change in control agreement, not including accrued salary and cash incentive payments earned but not paid through December 31, 2016 (these amounts are reflected in the Summary Compensation Table, however).
(c)
Pursuant to the Named Executive Officers’ change in control agreements, this column represents the additional amounts that would be credited and vested in respect of the Spectra Energy Retirement Cash Balance Plan, Spectra Energy Executive Cash Balance Plan, Spectra Energy Retirement Savings Plan and the Spectra Energy Executive Savings Plan if the Named Executive Officer continued to be employed by Spectra Energy for two additional years, at the rate of base salary plus target bonus percentage as in effect on December 31, 2016.
(d)
Amounts include the maximum accrued vacation allowed under Company policy for Mr. Yardley and the amount that would be paid to each Named Executive Officer who has entered into a change in control agreement in lieu of providing continued welfare benefits for 24 months.
(e)
Amounts that would result from accelerated vesting of previously awarded stock and any associated dividend equivalent payments due upon vesting. For Messrs. Reddy and Buckley who are retirement eligible, amounts also include the continued vesting of previously awarded phantom units after the applicable termination event.
The amounts shown above with respect to the Company’s outstanding stock awards were calculated based on a variety of assumptions, including the following: (a) the Named Executive Officer terminated employment on the last day of 2016; (b) a stock price for our common stock equal to $41.09, which was the closing price on the last trading day of 2016; (c) the continuation of our dividend at the rate in effect on December 31, 2016; and (d) at actual performance through December 31, 2016 for awards granted in 2015 and 2016.
Current Equity Compensation Plan Information
The following table contains information, as of December 31, 2016, about securities to be issued upon the exercise of outstanding options, warrants and rights under our equity compensation plans, along with the weighted-average exercise price of the outstanding options, warrants and rights and the number of securities remaining available for future issuance under the plans.
__________
(a)
Represents shares available for issuance for awards of phantom unit awards, performance share unit awards or options under the Spectra Energy Corp 2007 Long-Term Incentive Plan, as amended and restated. In the case of performance share units, amounts assume target performance.
Director Compensation
Compensation Structure for Non-Employee Directors
We use a combination of cash and stock-based compensation to attract and retain qualified candidates to serve on our Board. In making its recommendation on independent director compensation, the Corporate Governance Committee considers peer and general industry data, including an analysis of director compensation provided by an independent consultant. Under our stock ownership policy, outside directors are required to own 15,000 shares of the Company’s common stock (or common stock equivalents) within five years after becoming subject to the policy. At the end of 2016, all directors had met the targeted ownership level, except for Mr. Cazalot, who is on track to reach the targeted ownership level within the five-year period. Our Chairman, President and Chief Executive Officer does not receive compensation for his services as a director.
2016 DIRECTOR COMPENSATION STRUCTURE
__________
(a)
Valued at the NYSE closing price on the date of grant
Charitable Giving Program. Under the Spectra Energy Foundation Matching Gifts Program, the Company will match contributions to qualifying institutions of up to $7,500 per director per calendar year. In 2016, the Spectra Energy Foundation made matching charitable contributions on behalf of Mr. Phelps, Mr. Adams and Mr. Hamilton.
Expense Reimbursement. The Company reimburses non-employee directors for expenses they reasonably incur in connection with attending and participating in Board and Committee meetings, director education conferences and seminars, and special functions.
2016 COMPENSATION OF NON-EMPLOYEE DIRECTORS
__________
(a)
This column reflects the aggregate grant date fair value of the stock awarded, computed in accordance with FASB ASC Topic 718.
(b)
This column reflects matching charitable contributions made by the Company in 2016 for donations made in 2016 pursuant to the Spectra Energy Foundation Matching Gifts Program, which matches contributions made by our directors to qualifying institutions up to $7,500 per director per calendar year.
The value of all perquisites and other personal benefits or property received by each non-employee director in 2016 was less than $5,000 and is not included in the above table.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The following table shows, as of January 31, 2017, the amount of our common stock beneficially owned by our directors, the executive officers listed in the Summary Compensation Table under “Compensation Tables” (referred to as the Named Executive Officers), and by all directors and executive officers as a group. The table also shows the number of common units of SEP beneficially owned by these individuals. SEP is a publicly traded master limited partnership in which Spectra Energy Corp owns approximately 75% of the outstanding equity interest.
__________
*Represents less than 1%.
The following table lists the beneficial owners of more than 5% of the outstanding shares of Spectra Energy common stock as of January 31, 2017. This information is based on the most recently available reports filed with the SEC.
Shares of common stock
Name and Address of Beneficial Owner
Beneficially Owned
Percent of Class
Blackrock, Inc. (a)
55 East 52nd Street, New York, NY 10055
44,850,401
6.4
%
The Vanguard Group (b)
100 Vanguard Blvd., Malvern, PA 19355
48,953,943
6.97
State Street Corporation (c)
One Lincoln Street, Boston, MA 02111
37,523,817
5.35
Capital World Investors (d)
333 South Hope Street, Los Angeles, CA 90071
35,467,100
__________
(a)
According to the Schedule 13G/A filed on January 27, 2017 by Blackrock Inc., these shares are beneficially owned by its clients, and it has sole voting power with respect to 38,862,412 shares and sole dispositive power with respect to all the shares.
(b)
According to the Schedule 13G/A filed on February 13, 2017 by The Vanguard Group, these shares are beneficially owned by its clients, and it has sole voting power with respect to 1,167,341 shares, shared voting power with respect to 135,713 shares, sole dispositive power with respect to 47,717,519 shares and shared dispositive power with respect to 1,236,424 shares.
(c)
According to the Schedule 13G filed on February 9, 2017 by State Street Corporation, these shares are beneficially owned by its clients, and it has shared voting power and shared dispositive power with respect to all the shares.
(d)
According to the Schedule 13G/A filed on February 13, 2017 by Capital World Investors, these shares are beneficially owned by its clients, and it has sole voting power and sole dispositive power with respect to all the shares.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Transactions with Related Persons
Our Board is responsible for the oversight and approval (or ratification) of any “related-person transactions.” These are transactions, relationships or arrangements involving the Company in which any “related person” has a direct or indirect material interest. For this purpose, the following persons are considered “related” to the Company:
•
our directors, director nominees, executive officers, and their immediate family members;
•
beneficial owners of more than 5% of our common stock and their immediate family members; and
•
entities in which a person described above is employed, has a substantial interest, or holds a position such as general partner or principal.
Under our Board’s written procedures for the reporting, review and approval of related-person transactions, the Corporate Governance Committee evaluates these transactions and approves only those that it believes are consistent with the best interests of the Company and its shareholders as the Committee determines in good faith. The Committee bases this evaluation on all relevant factors, including:
•
the benefits of the transaction to the Company;
•
the terms of the transaction and whether they were made on an arm’s-length basis and in the ordinary course of the Company’s business;
•
the direct or indirect nature of the related person’s interest in the transaction;
•
the size and expected term of the transaction; and
•
other facts and circumstances that bear on the materiality of the transaction under applicable laws and listing standards.
Independent Directors
In exercising their duties to our shareholders, our Board members should not be conflicted in any way. To minimize potential conflicts, the only member of our Board who is not independent is our Chairman, President and Chief Executive Officer.
In accordance with the standards for companies listed on the NYSE, our Board considers a director to be independent if it has affirmatively determined that the director has no material relationship with Spectra Energy or its consolidated subsidiaries, either directly or as a shareholder, director, officer or employee of an organization that has a relationship with us or our subsidiaries. Our Board makes independence determinations when it approves director nominees for election at the annual meeting and also whenever a new director joins our Board between annual meetings.
For 2016, our Board determined that none of Spectra Energy’s independent directors, nor any member of their immediate families, had a material relationship with our Company or its subsidiaries. All of these independent director nominees (Messrs. Adams, Alvarado, Cazalot, Comper, Hamilton, McShane, Morris, Phelps, and Mses. Carter and Hubbs) are therefore independent under the NYSE’s listing standards. In reaching this conclusion, our Board considered all transactions and relationships between each such nominee (or any member of his or her immediate family) and our Company and its subsidiaries.
The Board has determined that each member of the Audit Committee is “independent” under the NYSE’s listing standards, applicable securities regulations, and the Company’s categorical standards for independence. The Board has also determined that Messrs. Comper, Hamilton, McShane and Ms. Hubbs are “audit committee financial experts” as defined by the SEC. The Board has also determined that each member of the Compensation Committee is “independent” under the NYSE’s listing standards and the Company’s categorical standards for independence, a “non-employee director” under the Securities Exchange Act Rule 16b-3, and an “outside director” as defined in Section 162(m) of the Internal Revenue Code. Our Board has determined that each member of the Corporate Governance Committee is “independent” under the NYSE’s listing standards and the Company’s categorical standards for independence.
To assist in its independence determinations, our Board has adopted specific standards under which certain relationships are deemed not to impair a director’s independence.
Director Independence Standards for Relationships Deemed Immaterial
The Board has adopted categorical standards under which certain relationships are deemed not to impair a director’s independence. Those standards are as follows:
__________
* An “associated” company is one (a) for which the director or immediate family member is a general partner, principal or employee, or (b) of which the director and immediate family members together own more than 5%. An “associated” charity is one for which the director or immediate family member serves as an officer, director, advisory board member or trustee.
Board Leadership Structure
One of our Board’s key responsibilities is determining the appropriate leadership structure for the Board, which helps ensure its effective and independent oversight of management on behalf of the Company’s shareholders. Our Board has chosen one independent director, F. Anthony Comper, to serve as its Lead Director, while our President and Chief Executive Officer, Gregory L. Ebel, serves as Chairman of the Board.
We believe that our Board leadership structure is appropriate for Spectra Energy because it allows one person to speak for and lead both the Company and the Board, while also providing for effective oversight by an independent board through an independent lead director. Our Board reviews its leadership structure and has the flexibility to revise it at any time as it deems appropriate.
In his role as Lead Director, Mr. Comper has broad authority and responsibility over Board governance and operations. His responsibilities, described in our Principles for Corporate Governance, include:
•
presiding at Board meetings at which the Chairman is not present, including executive sessions of the independent directors, which are held after each Board meeting;
•
consulting with the Chairman on Board meeting agendas;
•
calling meetings of independent directors and setting agendas for executive sessions;
•
serving as a liaison between the Chairman and the independent directors;
•
approving meeting schedules to ensure that there is sufficient time for discussions; and
•
representing the Board from time to time in consultations or direct communications with shareholders.
Item 14. Principal Accounting Fees and Services.
The following table presents fees for professional services rendered by Deloitte and the member firms of Deloitte Touche Tohmatsu and their respective affiliates to the Company for 2016 and 2015:
__________
(a)
Audit Fees are fees billed or expected to be billed by Deloitte for professional services for the audit of our Consolidated Financial Statements (including associated fees for SEP) included in our annual reports on Form 10-K and review of financial statements included in our quarterly reports on Form 10-Q, services that are normally provided by Deloitte in connection with statutory, regulatory or other filings or engagements or any other service performed by Deloitte to comply with generally accepted auditing standards. Audit Fees also include fees billed or expected to be billed by Deloitte for professional services for the audit of our internal controls under the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and related regulations.
(b)
Audit-Related Fees are fees billed by Deloitte for assurance and other services that are reasonably related to the performance of an audit or review of our financial statements, including assistance with acquisitions and divestitures, and internal control reviews. Audit-Related Fees also include comfort and consent letters in connection with SEC filings and financing transactions.
(c)
Tax Fees are fees billed by Deloitte for tax-return assistance and preparation, tax-examination assistance, and professional services related to tax planning and tax strategy.
(d)
All Other Fees are fees billed by Deloitte for any services not included in the first three categories, primarily translation of audited financials into foreign languages.
All other services by the independent auditor that fall within certain designated dollar thresholds, both per engagement as well as annual aggregate, have been pre-approved under the policy. Different dollar thresholds apply to the three categories of pre-approved services specified in the policy (Audit-Related services, Tax services and Other services). All services that exceed the dollar thresholds must be approved in advance by our Audit Committee or the Audit Committee of SEP, as applicable. Pursuant to applicable provisions of the Exchange Act, the audit committees have delegated approval authority to the Chairman of each audit committee. The Chairman has presented all approval decisions to the full audit committee. All engagements performed by the independent auditor were approved by the audit committee pursuant to its pre-approval policy.
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.
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 24, 2017
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 24, 2017
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
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).
2.11
Agreement and Plan of Merger, dated as of September 5, 2016, among Spectra Energy Corp,
Enbridge Inc. and Sand Merger Sub, Inc. (filed as Exhibit No. 2.1 to Form 8-K of Spectra Energy
Corp on September 6, 2016).
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).
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).
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).
+10.12.1
Amendment, dated March 15, 2016, to Change in Control Agreement (filed as Exhibit No. 10.6 to Form 10-Q of Spectra Energy Corp on May 5, 2016).
+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).
+10.13.1
Amended and Restated Change in Control Agreement for Chair, President and CEO, dated April 26, 2016 (filed as Exhibit No. 10.1 to Form 10-Q of Spectra Energy Corp on August 3, 2016).
+10.13.2
Form of Amended and Restated Change in Control Agreement for other Named Executive Officers (filed as Exhibit No. 10.2 to Form 10-Q of Spectra Energy Corp on August 3, 2016).
+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).
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).
10.36
Equity Distribution Agreement dated as of March 1, 2016, among Spectra Energy Corp, Citigroup Global Markets Inc., Barclays Capital Inc., Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Goldman, Sachs & Co., J.P. Morgan Securities LLC, Mitsubishi UFJ Securities (USA), Inc., Mizuho Securities USA Inc., Morgan Stanley & Co. LLC, RBC Capital Markets, LLC, SMBC Nikko Securities America, Inc., SunTrust Robinson Humphrey, Inc., UBS Securities LLC and Wells Fargo Securities, LLC (filed as Exhibit 1.1 to Form 8-K of Spectra Energy Corp on March 1, 2016).
10.37
Credit Agreement, dated as of September 29, 2016, by and among Spectra Energy Capital, LLC, as borrower, Spectra Energy Corp, as guarantor, Citibank, N.A., as administrative agent, and the lenders party thereto (filed as Exhibit 10.1 to Form 8-K of Spectra Energy Corp on October 4, 2016).
+10.38
Form of Stock Option Agreement (2016) 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 5, 2016).
+10.39
Form of Performance Award Agreement (2016) 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 5, 2016).
+10.40
Form of Phantom Stock Award Agreement (2016) 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, 2016).
+10.41
Form of Phantom Stock Award Agreement (2016) 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, 2016).
+10.42
Form of Phantom Stock Award Agreement (2016) 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, 2016).
+10.43
Spectra Energy Corp 2007 Long-Term Incentive Plan, as amended and restated (filed as Exhibit 10.1 to Form 8-K of Spectra Energy Corp on May 2, 2016).
+10.44
Spectra Energy Corp Executive Short-Term Incentive Plan, as amended and restated (filed as Exhibit 10.2 to Form 8-K of Spectra Energy Corp on May 2, 2016).
*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.
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.
DCP MIDSTREAM, LLC
CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2016, 2015 and 2014
Page
Independent Auditors' Report
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Comprehensive (Loss) Income
Consolidated Statements of Changes in Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Deloitte & Touche LLP
Suite 3600
555 Seventeenth Street
Denver, CO 80202-3942
USA
INDEPENDENT AUDITORS’ REPORT Tel: +1 303 292 5400
Fax: +1 303 312 4000
To the Board of Directors and Members of www.deloitte.com
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, 2016 and 2015, 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, 2016, 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, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in accordance with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
February 17, 2017
DCP MIDSTREAM, LLC
CONSOLIDATED BALANCE SHEETS
See Notes to Consolidated Financial Statements.
DCP MIDSTREAM, LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
See Notes to Consolidated Financial Statements.
DCP MIDSTREAM, LLC
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
See Notes to Consolidated Financial Statements.
DCP MIDSTREAM, LLC
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
See Notes to Consolidated Financial Statements.
DCP MIDSTREAM, LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
See Notes to Consolidated Financial Statements.
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2016, 2015 and 2014
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.
During the third quarter of 2016, Spectra Energy entered into an Agreement and Plan of Merger (the "Merger Agreement") with Enbridge Inc. ("Enbridge"), a Canadian corporation, and anticipates completing the proposed merger during the first quarter of 2017. The Merger Agreement provides that, upon closing of the proposed merger, Spectra Energy will continue its separate corporate existence as a wholly owned subsidiary of Enbridge.
DCP Midstream, LP (the “Partnership”), formerly DCP Midstream Partners, LP, is a master limited partnership, of which we act as general partner. On December 30, 2016, we entered into a Contribution Agreement (the “Contribution Agreement”) with the Partnership and DCP Midstream Operating, LP (the “Operating Partnership”), a wholly owned subsidiary of the Partnership. The transactions and documents contemplated by the Contribution Agreement are collectively referred to hereafter as the “Transaction.” The Transaction closed effective January 1, 2017. For additional information regarding the Transaction, see Note 6 - Agreements and Transactions with Related Parties and Affiliates.
As of December 31, 2016 and 2015, we owned an approximate 21% in the Partnership 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. Our incentive distribution rights currently entitle us to receive the maximum share of 48% of incremental available cash generated by the Partnership. As the general partner of DCP Midstream, LP, 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 accordance with accounting principles generally accepted in the United States of America, or GAAP. 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 Midstream, LP, a variable interest entity for which we are the primary beneficiary, 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.
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
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 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.
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
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 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 (including forecasted commodity prices and volumes), as well as historical and other factors. 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 decrease in commodity prices may affect our estimate of future operating results, which could result in future goodwill and intangible assets impairment charges.
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.
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
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 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 the Partnership’s public unitholders, through the Partnership’s publicly traded common units, in net assets of the Partnership and the noncontrolling interest which is recorded in the Partnership’s 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 MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
The Partnership considers the payment of a quarterly distribution to the holders of its common units, to the extent the Partnership has sufficient cash from its operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner, a 100% owned subsidiary of ours. There is no guarantee, however, that the Partnership will pay the minimum quarterly distribution on the units in any quarter. The Partnership 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. 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.
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.
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
•
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.
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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, 2016, 2015 and 2014.
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, 2016 and 2015, were imbalances totaling $6 million and $21 million, respectively. Included in the consolidated balance sheets as accounts payable - other, as of December 31, 2016 and 2015, were imbalances totaling $10 million and $25 million, respectively.
Purchases of natural gas, propane and NGLs - Purchases of natural gas and NGLs represent physical purchases from suppliers. We purchase propane from natural gas processing plants and fractionation facilities, and crude oil refineries.
Significant Customers - There were no third party customers that accounted for more than 10% of total operating revenues for the years ended December 31, 2016, 2015 or 2014. We had significant transactions with affiliates for the years ended December 31, 2016, 2015 and 2014. 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.
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. 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
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
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 income tax returns of each member.
3. Recent Accounting Pronouncements
Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,” or ASU 2016-15 - In August 2016, the FASB issued ASU 2016-15, which amends certain cash flow statement classification guidance. This ASU is effective for interim and annual reporting periods beginning after December 15, 2017, with the option to early adopt for financial statements that have not been issued. We are currently evaluating the potential impact this standard will have on our consolidated statement of cash flows.
FASB ASU, 2016-02 “Leases (Topic 842),” or ASU 2016-02 - In February 2016, the FASB issued ASU 2016-02, which requires lessees to recognize a lease liability on a discounted basis and the right of use of a specified asset at the commencement date for all leases. This ASU is effective for interim and annual reporting periods beginning after December 15, 2018, with the option to early adopt for financial statements that have not been issued. We are currently evaluating the potential impact this standard will have on our consolidated financial statements and related disclosures.
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, with the option to early adopt for financial statements that have not been issued. The impact of this ASU will be evaluated upon the occurrence of future business combinations and provisional adjustments will be recorded in the period determined.
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 was effective for annual reporting periods beginning after December 15, 2015. The retrospective adoption of this ASU has been implemented and did not have any impact 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 and related interpretations and amendments - In May 2014, the FASB issued ASU 2014-09, which supersedes the revenue recognition requirements of Accounting Standards Codification 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 annual reporting periods beginning after December 15, 2016. We plan to adopt this ASU using the modified retrospective method. The initial cumulative effect will be recognized at the date of adoption. Our evaluation of ASU 2014-09 is ongoing and not complete. The FASB has issued and may issue in the future, interpretative guidance, which may cause our evaluation to change. Accordingly, at this time we cannot estimate the impact upon adoption.
4. Variable Interest Entities
ASU 2015-02 amended the conditions used to evaluate whether an entity is a variable interest entity. Following this amendment, a limited partnership is considered a variable interest entity unless a simple majority of the limited partners have substantive kick-out or participating rights. Upon the adoption of ASU 2015-02 in 2016, DCP Midstream, LP is considered a variable interest entity because the limited partners do not have substantive kick-out or participating rights. We are the primary beneficiary of the Partnership because we have the power to direct the significant activities and the obligation to receive the benefits or absorb the losses of those significant activities of the Partnership. As such, we consolidate the Partnership and recognize non-controlling interest. Prior to the adoption of ASU 2015-02, the Partnership was not a variable interest entity, however, we consolidated the Partnership under the voting interest model as we controlled the entity through our ownership and general partner interest, and the limited partners did not have substantive kick-out or participating rights.
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
The following table represents amounts included in our consolidated balance sheets attributable to our variable interest entity:
The assets of the Partnership are the property of the Partnership and are not available to us for any other purpose, including as collateral for our debt securities and credit facilities with financial institutions (see Notes 12 and 18). The Partnership’s asset balances can only be used to settle its own obligations. The liabilities of the Partnership do not represent additional claims against our general assets and the creditors or beneficial interest holders of the Partnership do not have recourse to our general credit. Our maximum exposure to loss as a result of our involvement with the Partnership includes our equity investment. During the years ended December 31, 2016 and 2015, we did not provide any financial support to the Partnership that we were not contractually obligated to provide under the services agreement we have with the Partnership, which requires the Partnership to reimburse us for fees and other costs incurred by us on behalf of the Partnership.
5. Dispositions
In May 2016, the Partnership entered into a purchase and sale agreement with a third party to sell its 100% interests in its Northern Louisiana system, which primarily consisted of certain gas processing plants and gathering systems, for approximately $160 million, subject to customary purchase price adjustments. This transaction closed on July 1, 2016, and we recognized a $41 million gain on sale, net of goodwill, in our consolidated statements of operations for the year ended December 31, 2016.
6. Agreements and Transactions with Related Parties and Affiliates
DCP Midstream, LP
Contribution Agreement
On January 1, 2017, we contributed to the Partnership: (i) our ownership interests in all of our subsidiaries owning operating assets, and (ii) $424 million of cash (together the “Contributions”). In consideration of the Partnership’s receipt of the Contributions, (i) the Partnership issued 28,552,480 common units and 2,550,644 general partner units to us in a private placement and (ii) the Operating Partnership assumed $3,150 million of our debt. This represents a Transaction between entities
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
under common control and a change in reporting entity. There is no financial statement impact for the year ended December 31, 2016.
Pursuant to the Contribution Agreement, we agreed to enter into Amendment No. 3 (the “Third Amendment to the Partnership Agreement”) to the Second Amended and Restated Agreement of Limited Partnership of the Partnership, dated November 1, 2006, as amended (the “Partnership Agreement”). On January 1, 2017, we entered into the Third Amendment to the Partnership Agreement. The Third Amendment to the Partnership Agreement includes terms that amend the Partnership Agreement to cause the incentive distributions payable to us, as holders of the Partnership’s incentive distribution rights, with respect to the fiscal years 2017, 2018 and 2019 to, in certain circumstances, be reduced in an amount up to $100 million per fiscal year as necessary to provide that the distributable cash flow of the Partnership (as adjusted) during such year meets or exceeds the amount of distributions made by the Partnership (as adjusted) to the partners of the Partnership with respect to such year.
Services Agreement
Pursuant to the Contribution Agreement, on January 1, 2017, the Partnership entered into the Services and Employee Secondment Agreement (the “Services Agreement”), which replaced the services agreement between DCP Midstream and the Partnership dated February 14, 2013, as amended (the “Original Services Agreement”). Under the Services Agreement, the Partnership is required to reimburse DCP Midstream, LLC for salaries of personnel and employee benefits, as well as capital expenditures, maintenance and repair costs, taxes and other direct costs incurred by DCP Midstream, LLC on the Partnership's behalf. There is no limit on the reimbursements the Partnership makes to DCP Midstream, LLC under the Services Agreement for other expenses and expenditures incurred or payments made on our behalf.
The Partnership paid us an annual fee under the Original Services Agreement for centralized corporate functions performed by us on behalf of the Partnership. Reimbursements received from the Partnership have been eliminated in consolidation. The annual fee paid under the Original Services Agreement was $71 million for the year ended December 31, 2016.
Dividends and Distributions
During the years ended December 31, 2016 and 2015, no tax distributions were paid to the members. During the year ended December 31, 2014, we paid tax distributions of $159 million 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 years ended December 31, 2016 and 2015, no dividends were declared or paid. During the year ended December 31, 2014 we declared and paid dividends of $315 million to Phillips 66 and Spectra Energy, allocated in accordance with their respective ownership percentages.
The Partnership considers the payment of a quarterly distribution to the holders of its common units, to the extent the Partnership has sufficient cash from its operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner, a 100% owned subsidiary of ours. There is no guarantee, however, that the Partnership will pay the minimum quarterly distribution on the units in any quarter. The Partnership 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. During the years ended December 31, 2016, 2015 and 2014, the Partnership paid distributions of $359 million, $358 million and $316 million, respectively, to its limited partners, of which we received $76 million, $76 million and $69 million for our limited partner interests, respectively. Additionally, during the years ended December 31, 2016, 2015 and 2014, we received $124 million, $124 million and $104 million, respectively for our general partner interest, which includes our incentive distribution rights. Distributions from the Partnership eliminate in consolidation.
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. Approximately 27% of our NGL production was committed to Phillips 66 and CPChem as of December 31, 2016, the primary production commitment of which began a ratable wind down period in December 2014 and expires in January 2019. We anticipate continuing to purchase and sell commodities with Phillips 66 and CPChem in the ordinary course of business.
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
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.
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.
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 Midstream, LP, 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 the Partnership, 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:
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
We had balances with related parties and affiliates as follows:
7. Inventories
Inventories were as follows:
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 $3 million, $8 million and $24 million in lower of cost or market adjustments during the years ended December 31, 2016, 2015 and 2014, respectively.
8. Property, Plant and Equipment
Property, plant and equipment by classification were as follows:
Interest capitalized on construction projects was less than $1 million for the year ended December 31, 2016. Interest capitalized on construction projects for the years ended December 31, 2015 and 2014 was $32 million and $34 million, respectively.
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
Depreciation expense for the years ended December 31, 2016, 2015 and 2014 was $367 million, $357 million and $327 million, respectively.
Asset Retirement Obligations
As of December 31, 2016 and 2015, we had $124 million and $120 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 fair value is not estimable 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 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:
9. Investments in Unconsolidated Affiliates
We had investments in the following unconsolidated affiliates accounted for using the equity method:
There was an excess of the carrying amount of the investment over the underlying equity of Sand Hills of $662 million and $677 million as of December 31, 2016 and 2015, 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 $148 million and $152 million as of December 31, 2016 and 2015, respectively, which is associated with, and being amortized over the life of, the underlying long-lived assets of Southern Hills.
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
There was a deficit between the carrying amount of the investment and the underlying equity of Discovery Producer Services, LLC, or Discovery, of $20 million and $24 million as of December 31, 2016 and 2015, 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, 2016 and 2015, 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, 2016 and 2015, which is associated with, and is being amortized over the life of, the underlying long-lived assets of Texas Express.
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 $2 million and $3 million as of December 31, 2016 and 2015, respectively, which is associated with, and is being amortized over the life of the underlying long-lived assets of Mont Belvieu I.
Earnings from unconsolidated affiliates amounted to the following
The following tables summarize the combined financial information of unconsolidated affiliates:
(a) In accordance with the Panola Pipeline Company, LLC, or Panola, joint venture agreement, earnings began to accrue to the Partnership’ interest on February 1, 2016. Accordingly, activity related to Panola is included in the above tables as of and for the year ended December 31, 2016.
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
10. Goodwill
The change in the carrying amount of goodwill was as follows:
We performed our annual goodwill assessment during the third quarter of 2016 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 management regularly reviews the operating results of those components and whether the economic and regulatory characteristics are similar. As a result of our assessment, we concluded that the entire amount of goodwill disclosed on the consolidated balance sheet is recoverable. We primarily used a discounted cash flow analysis, supplemented by a market approach analysis, to perform the assessment. Key assumptions in the analysis include the discount rate, volume forecasts, 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 (including forecasted volumes and commodity prices), as well as historical and other factors.
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.
The Partnership 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 the Partnership 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 the Partnership’s Collbran, Michigan and Southeast Texas reporting units. We and the Partnership 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 the Partnership’s Collbran reporting unit. As a result, the Partnership 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 the Partnership 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 above. 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 goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value. If our forecast indicates lower commodity prices in future periods at a level and duration that results in producers curtailing or redirecting drilling in areas where we operate, it 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.
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
Intangible assets consist of customer contracts, including commodity purchase, transportation and processing contracts and related relationships. 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:
For the years ended December 31, 2016, 2015 and 2014, we recorded amortization expense of $12 million, $19 million and $21 million, respectively. As of December 31, 2016, the remaining amortization periods ranged from approximately 2 years to approximately 19 years, with a weighted-average remaining period of approximately 14 years.
Estimated future amortization for these intangible assets is as follows:
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, and/or the liquidity of the market.
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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.
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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 account our own credit rating, current credit spreads, as well as any change in such spreads since the last measurement date.
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
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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 and are categorized in their entirety in the same level of the fair value hierarchy as the lowest level input that is significant to the entire measurement. 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:
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Level 1 - inputs are unadjusted quoted prices for identical assets or liabilities in active markets.
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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.
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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, 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; 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.
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
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 our 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 other 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.
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
There were no assets measured at fair value on a non-recurring basis as of December 31, 2016. The following table presents 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 December 31, 2015:
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
(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, 2016 and 2015, there were no transfers between Level 1 and Level 2 of the fair value hierarchy.
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 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
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
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.
(a) There were no purchases, issuances or sales of derivatives or transfers into Level 3 for the year ended December 31, 2016 and 2015.
(b) Represents the amount of total gains or losses for the period, included in trading and marketing gains, net, in our 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 March 2015 novation of certain fixed price commodity derivatives, the Partnership’ position no longer eliminates
in consolidation.
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.
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.
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
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 and accounts payable 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, 2016 and December 31, 2015, the carrying value and fair value of our long-term debt were as follows:
(a) Excludes unamortized issuance costs.
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
12. Financing
(a) The swaps associated with this debt were previously terminated. The remaining long-term fair value of approximately $24 million
related to the swaps is being amortized as a reduction to interest expense through 2019, 2020 and 2030, the original maturity dates
of the debt.
(b) The DCP Midstream term-loan was not assumed by the Partnership in the Transaction.
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
Approximate future maturities of debt in the year indicated are as follows at December 31, 2016:
DCP Midstream’s Debt Securities
The DCP Midstream debt securities mature and become payable on the respective due dates, and are not subject to any sinking fund provisions. The senior debt securities are senior unsecured obligations and the junior subordinated notes are unsecured and rank subordinate in right of payment to all of our existing and future senior debt. The DCP Midstream debt securities are not guaranteed by any of our subsidiaries and are therefore, structurally subordinated to all debt and other liabilities of our subsidiaries. The debt securities include an optional redemption whereby we may elect to redeem the notes, in whole or in part from time-to-time. Additionally, we may defer the payment of all or part of the interest on the junior subordinated notes for one or more periods up to five consecutive years. The underwriters’ fees and related expenses are recorded in our consolidated balance sheets within the carrying amount of long-term debt and will be amortized over the term of the notes.
DCP Midstream’s Credit Facilities with Financial Institutions
In May 2016, we entered into a second amendment of the DCP Midstream Amended and Restated Revolving Credit Agreement, which extended the maturity date from March 2017 to May 2019 and reduced the total borrowing capacity from $1.8 billion to $700 million. The DCP Midstream Amended and Restated Revolving Credit Agreement was terminated on December 30, 2016. In conjunction with the termination of the DCP Midstream Amended and Restated Revolving Credit Agreement, $10 million of unamortized issuance costs were included in interest expense.
On December 30, 2016, we entered into a $424 million credit agreement, or the Term Loan, which matures on December 30, 2019. Proceeds from the Term Loan may be used for general company purposes, including for acquisitions, to refinance existing indebtedness, and in connection with the Transaction. Amounts repaid or prepaid under the Term Loan may not be reborrowed. Each of Phillips 66 and Spectra has guaranteed half of our borrowings under the Term Loan in proportion to their respective ownership percentages in us.
The Term Loan bears interest at either: (1) LIBOR, plus an applicable margin of 1.75% based on our current credit rating; or (2) the base rate, plus an applicable margin of 0.75% based on our current credit rating, where the base rate shall be the higher of (a) The Bank of Tokyo-Mitsubishi UFJ, Ltd.’s prime rate, (b) the federal funds rate plus 0.50%, or (c) LIBOR plus 1.0%.
DCP Midstream, LP’s Credit Facilities with Financial Institutions
DCP Midstream, LP has a $1.25 billion senior unsecured revolving credit agreement that matures on May 1, 2019, or the Amended and Restated Credit Agreement. The Amended and Restated Credit Agreement is used for working capital requirements and other general partnership purposes including acquisitions.
The Partnership's cost of borrowing under the Amended and Restated Credit Agreement is determined by a ratings-based pricing grid. Indebtedness under the Amended and Restated Credit Agreement bears interest at either: (1) LIBOR, plus an applicable margin of 1.45% based on the Partnership's current credit rating; or (2) (a) the base rate which shall be the higher of
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
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 0.45% based on the Partnership's current credit rating. The Amended and Restated Credit Agreement incurs an annual facility fee of 0.30% based on the Partnership's current credit rating. This fee is paid on drawn and undrawn portions of the $1.25 billion Amended and Restated Credit Agreement.
As of December 31, 2016, the Partnership had unused borrowing capacity of 1,031 million, net of $24 million of letters of credit, under the Amended and Restated Credit Agreement, all of which was available for working capital and other general partnership purposes. The Partnership's borrowing capacity may be limited by financial covenants set forth in the Amended and Restated Credit Agreement. Except in the case of a default, amounts borrowed under the Amended and Restated Credit Agreement will not become due prior to the May 1, 2019 maturity date.
The Amended and Restated Credit Agreement requires the Partnership to maintain a leverage ratio (the ratio of the Partnership's consolidated indebtedness to the Partnership's consolidated EBITDA, in each case as is defined by the Amended and Restated Credit Agreement) of not more than 5.0 to 1.0, and following the 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.
DCP Midstream, LP's Debt Securities
The Partnership’s debt securities are senior unsecured obligations, ranking equally in right of payment with other unsecured indebtedness, including indebtedness under the DCP Midstream, LP Amended and Restated Credit Agreement. The Partnership 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 the Partnership’s option. The underwriters’ fees and related expenses are recorded in our 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, the Partnership 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, 2016, approximately $349 million of its common units remained available for sale pursuant to the Partnership’s 2014 equity distribution agreement.
In June 2014, the Partnership 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 the Partnership to issue additional common units. In September 2014, the Partnership 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 the Partnership’s sales agents, of common units having an aggregate offering amount of up to $500 million. During the year ended December 31, 2014, the Partnership 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.
In March 2014, the Partnership issued 14,375,000 of its common units to the public at $48.90 per unit. The Partnership received proceeds of $677 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.
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
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 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 Midstream, LP 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 the Partnership’s storage caverns, The Partnership may execute a series of derivative financial instruments to mitigate a portion of the risk associated with the forecasted purchase of natural gas when the Partnership brings the storage caverns into 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 the Partnership’s previously settled base gas cash flow hedges was in a loss position of $6 million as of December 31, 2016.
Commodity Cash Flow Protection Activities
We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of our gathering, processing, sales and storage activities. For gathering, processing and storage services, we may receive cash or commodities as payment for these services, depending on the contract type. We may enter into derivative financial instruments to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices associated with our gathering, processing and sales activities, thereby stabilizing our cash flows. The Partnership is also exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate and may enter into derivative financial instruments due to the same factors. Our and the Partnership's derivative financial instruments used to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices extend through the first quarter of 2018. The commodity derivative instruments used for our and the Partnership's hedging programs 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, we and the Partnership may use crude oil swaps to mitigate a portion of the 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. When our crude oil swaps become short-term in nature, certain crude oil derivatives may be converted to NGL derivatives by entering into offsetting crude oil swaps while adding NGL swaps. Crude oil and NGL transactions are primarily accomplished through the use of forward contracts that effectively exchange floating price risk for a fixed price. The type of instrument used to mitigate a portion of the risk may vary depending on our and the Partnership’s risk management objectives. These transactions are not
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
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.
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.
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.
We previously had interest rate cash flow hedges and fair value hedges in place that were terminated. As the underlying transactions impact earnings, the remaining net loss deferred in AOCI relative to these cash flow hedges will be reclassified to interest expense, net through 2022 and 2030 and the remaining net loss included in long-term debt relative to these fair value hedges will be reclassified to interest expense, net through 2019, 2020 and 2030, the original maturity dates of the debt.
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. Approximately 27% of our NGL production was committed to Phillips 66 and CPChem as of December 31, 2016, the primary production commitment of which began a ratable wind down period in December 2014 and expires in January 2019. 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.
•
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 the Partnership’s credit rating is below investment grade.
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
•
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, 2016, we had less than $1 million of individual commodity derivative contracts that contain credit-risk related contingent features that were in a net liability 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, 2016, we have not been required to post additional collateral. Although our commodity derivative contracts that contain credit-risk related contingent features were in a net liability position as of December 31, 2016, the net liability position would be offset by contracts in a net asset position.
Collateral
As of December 31, 2016, we had cash deposits of $71 million, included in other current assets in our 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, 2016, we held cash of $5 million, included in other current liabilities in our consolidated balance sheet, related to cash postings by third parties and letters of credit of $38 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 in our 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.
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
The following tables summarize the gross and net amounts of our derivative instruments:
(a) Included in other current liabilities in our 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:
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 months ended December 31, 2016:
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 months ended December 31, 2015:
(a) Included in interest expense, net in our consolidated statements of operations.
For the years ended December 31, 2016 and 2015, 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.
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
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 our consolidated statements of operations. The following summarizes these amounts and the location within our consolidated statements of operations that such amounts are reflected:
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.
(a) Bbls represents barrels.
(b) MMBtu represents one million British thermal units.
(c) Includes 40 physical index based derivative contracts totaling (16,170,725) Bbls.
(d) Includes 1 physical index based derivative contract totaling (120,000) Bbls.
(a) Includes 37 physical index based derivative contracts totaling (22,972,000) Bbls.
(b) Includes 1 physical index based derivative contract totaling (2,700,000) Bbls.
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
14. Equity-Based Compensation
We recorded equity-based compensation expense as follows, the components of which are further described below:
The following table presents the fair value of unvested unit-based awards related to the strategic performance units and phantom units:
DCP Midstream LTIP - Under the DCP Midstream LTIP, awards may be granted to our key employees. The DCP Midstream LTIP provides for the grant of 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 the Partnership. Each award provides for the grant of dividend or distribution equivalent rights, or DERs. The DCP Midstream LTIP is administered by the compensation committee of our board of directors. All awards are subject to cliff vesting.
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
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:
(a) The 2012 grants vested at 115%.
(b) The 2013 grants vested at 115%.
(c) The 2014 grants vested at 130%.
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.
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:
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
Phantom Units - The DERs are paid quarterly in arrears. The following table presents information related to Phantom Units:
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:
DCP Midstream LP’s LTIP
On April 28, 2016, the unitholders of the Partnership approved the 2016 Long-Term Incentive Plan (the “2016 LTIP”), which replaced the 2005 LTIP that expired pursuant to its terms at the end of 2015 (the “2005 LTIP” and, together with the 2012 LTIP and the 2016 LTIP, the “LTIP”). Any outstanding awards under the 2005 LTIP will remain outstanding and settle according to the terms of such grant. The 2016 plan authorizes up to 900,000 common units to be available for issuance under awards to employees, officers, and non-employee directors of the General Partner and its affiliates. Awards under the 2016 LTIP may include unit options, phantom units, restricted units, distribution equivalent rights, unit bonuses, common unit awards, and performance awards. The 2016 LTIP will expire on the earlier of the date it is terminated by the board of directors of the General Partner or the date that all common units available under the plan have been paid or issued.
Under the Partnership’s 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 the Partnership. The Partnership’s 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. zThe 2005 LTIP phantom units consist of a notional unit based on the value of the Partnership’s common units. Subject to adjustment for certain events, an aggregate of 850,000 LPUs may be delivered pursuant to awards under the the Partnership’s 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 the Partnership. 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,
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
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 the Partnership has the intent and ability to settle certain awards within its control in units, the Partnership classifies them as equity awards based on their fair value. The fair value of the Partnership’s equity awards is determined based on the closing price of the Partnership’s common units at the grant date. Compensation expense on equity awards is recognized ratably over each vesting period. The Partnership 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-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 the Partnership’s common units at each measurement date.
As of December 31, 2016, there was less than $1 million of unrecognized compensation expense related to the DCP Midstream, LP 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, 2016, 2015 and 2014, we expensed plan contributions of $29 million, $32 million and $30 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.
16. Income Taxes
We are structured as a limited liability company, which is a pass-through entity for federal income tax purposes. During the year ended December 31, 2016, we elected to convert our one corporation, a tax paying entity, which files its own federal and state corporate income tax returns, to a limited liability company for federal & state income tax purposes. 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 (expense) benefit consisted of the following
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
Deferred income tax assets and liabilities consisted of the following:
The state deferred tax liabilities are primarily associated with Texas franchise taxes. During the year ended December 31, 2016, we recorded a reduction to our net federal deferred tax asset of $58 million resulting from the conversion of our corporation to a limited liability company.
As of December 31 2015, our federal net operating losses were $163 million. The net operating losses were fully utilized upon the conversion of our corporation to a limited liability company during the year ended December 31, 2016.
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, primarily Texas.
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.
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 consideration was received in February 2016, which we recorded as other income, net of $2 million in legal fees, in our consolidated statement of operations for the year December 31, 2016.
General Insurance - Our insurance coverage is carried with third-party insurers and with an affiliate of Phillips 66. 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.
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
Environmental - The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, fractionating, or storing natural gas, 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, in some cases, local levels that relate to worker safety, air and water quality, solid and hazardous 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, worker safety standards, and safety standards applicable to our various facilities. In addition, there is increasing focus (i) 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 and the resulting supply of NGLs, (ii) from federal regulatory agencies regarding pipeline system safety which could impose additional regulatory burdens and increase the cost of our operations, and (iii) from state and federal regulatory officials regarding the emission of greenhouse gases which could impose regulatory burdens and increase the cost of our operations. 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 existing 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, 2016 and December 31, 2015, environmental liabilities included in our consolidated balance sheets as other current liabilities were $4 million and $3 million, respectively. As of both December 31, 2016 and December 31, 2015, environmental liabilities included in our consolidated balance sheets as other long-term liabilities was $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 $37 million, $34 million and $31 million during the years ended December 31, 2016, 2015 and 2014, 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:
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 the Partnership or other liabilities related to the assets being acquired, contributed or divested. Claims may be made by third parties or the Partnership 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.
19. Restructuring Costs
In April 2016, we announced an approximate 10 percent headcount reduction, which involved the elimination of certain operational and corporate positions, as part of our ongoing effort to create efficiencies, reduce costs and transform our business.
DCP MIDSTREAM, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Years Ended December 31, 2016, 2015 and 2014
As a result of this headcount reduction, we recorded one-time employee termination costs of approximately $13 million, which are included in restructuring costs within total operating costs and expenses in our consolidated statements of operations for the year ended December 31, 2016.
As of December 31, 2016, approximately $1 million of the $13 million restructuring charge incurred is included in other current liabilities. Additionally, we expect to incur further severance costs of less than $1 million related to this phase of our restructuring plan. The severance costs estimate could change based on the number of employees that work through the required service period and the timing of those departures.
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.
20. Supplemental Cash Flow Information
21. Subsequent Events
We have evaluated subsequent events occurring through February 17, 2017, the date the consolidated financial statements were issued.
On December 30, 2016, we entered into the Contribution Agreement with the Partnership and Operating Partnership. The Transaction closed and was effective on January 1, 2017. For additional information regarding the Transaction, see Note 6 - Agreements and Transactions with Related Parties and Affiliates.
On January 26, 2017, the Partnership announced that the board of directors of the Partnership’s general partner declared a quarterly distribution of $0.78 per unit, payable on February 14, 2017 to unitholders of record on February 7, 2017, except that the owners of the Partnership's general partner will receive distributions on the units issued on January 1, 2017 beginning with the first quarter 2017 declared distribution.