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•	state, provincial, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an effect on rate structure, and affect the speed at and degree to which competition enters the natural gas and oil industries;

•	outcomes of litigation and regulatory investigations, proceedings or inquiries;

•	weather and other natural phenomena, including the economic, operational and other effects of hurricanes and storms;

•	the timing and extent of changes in commodity prices, interest rates and foreign currency exchange rates;

•	general economic conditions, including the risk of a prolonged economic slowdown or decline, or the risk of delay in a recovery, which can affect the long-term demand for natural gas and oil and related services;

•	potential effects arising from terrorist attacks and any consequential or other hostilities;

•	changes in environmental, safety and other laws and regulations;

•	the development of alternative energy resources;

•	results and costs of financing efforts, including the ability to obtain financing on favorable terms, which can be affected by various factors, including credit ratings and general market and economic conditions;

•	increases in the cost of goods and services required to complete capital projects;

•	declines in the market prices of equity and debt securities and resulting funding requirements for defined benefit pension plans;

•	growth in opportunities, including the timing and success of efforts to develop United States and Canadian pipeline, storage, gathering, processing and other related infrastructure projects and the effects of competition;

•	the performance of natural gas and oil transmission and storage, distribution, and gathering and processing facilities;

•	the extent of success in connecting natural gas and oil supplies to gathering, processing and transmission systems and in connecting to expanding gas and oil markets;

•	the effects of accounting pronouncements issued periodically by accounting standard-setting bodies;

•	conditions of the capital markets during the periods covered by forward-looking statements; and

•	the ability to successfully complete merger, acquisition or divestiture plans; regulatory or other limitations imposed as a result of a merger, acquisition or divestiture; and the success of the business following a merger, acquisition or divestiture.

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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. Fee-based arrangements include natural gas arrangements pursuant to which DCP Midstream obtains natural gas at the wellhead or other receipt points at an index-related price at the delivery point less a specified amount, generally the same as the transportation fees it would otherwise charge for transportation of the natural gas from the wellhead location to the delivery point. The revenue DCP Midstream earns from these arrangements is directly related to the volume of natural gas or NGLs that flows through its systems and is not dependent on commodity prices.

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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.

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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.

•	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.

•	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.

•	The Fisheries Act (Canada), which regulates activities near any body of water in Canada.

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

•	The Canadian Environmental Protection Act, which, among other things, requires the reporting of greenhouse gas (GHG) emissions from our operations in Canada. Additional regulations to be promulgated under this Act may require the reduction of GHGs, nitrogen oxides, sulphur oxides, volatile organic compounds and particulate matter.

•	The Alberta Climate Change and Emissions Management Act (The Act) which, as of 2007, required certain facilities to meet reductions in emission intensity. The Act was applicable to our Empress facility in Alberta beginning in 2008.

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The Canadian Environmental Assessment Act, 2012 (CEAA 2012) requires the NEB to consider potential environmental effects in their decisions for designated projects. The NEB under its enabling statute also conducts environmental assessments for projects that are not specifically designated under CEEA 2012. In either case, prior to receiving an approval to construct or operate a federally-regulated pipeline or facility, the NEB must consider a series of environmental factors, in particular whether the project has the potential to have adverse environmental effects. These types of assessments occur in relation to both maintenance and capital projects.

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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;

•	supply of and demand for energy commodities, including any decrease in the production of natural gas and oil which could negatively affect our processing and transmission businesses due to lower throughput;

•	capacity and transmission service into, or out of, our markets; and

•	petrochemical demand for NGLs.

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•	the ability to obtain necessary approvals and permits by regulatory agencies on a timely basis and on acceptable terms and to maintain those approvals and permits issued and satisfy the terms and conditions imposed therein;

•	the availability of skilled labor, equipment and materials to complete expansion projects;

•	potential changes in federal, state and local statutes and regulations, including environmental requirements, that may prevent a project from proceeding or increase the anticipated cost of the project;

•	impediments on our ability to acquire rights-of-way or land rights on a timely basis and on acceptable terms;

•	the ability to construct projects within anticipated costs, including the risk of cost overruns resulting from inflation or increased costs of equipment, materials or labor, weather, geologic conditions or other factors beyond our control, that may be material; and

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•	general economic factors that affect the demand for natural gas infrastructure.

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

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•	Spectra Energy Partners’ earnings benefited mainly from expansions, primarily on Texas Eastern, and higher transportation revenues due to higher tariff rates and volumes on the Express pipeline.

•	Distribution’s earnings decreased mainly due to a weaker Canadian dollar and lower customer usage as a result of warmer weather.

•	Western Canada Transmission & Processing’s earnings decreased mainly due to lower NGL sales prices and a weaker Canadian dollar, partially offset by lower unit cost of sales at the Empress operations.

•	Field Services’ earnings decreased mainly due to continued lower commodity prices, goodwill and other asset impairments, net of tax impacts and lower gains associated with the issuance of partnership units by DCP Partners, partially offset by asset growth, improved operating efficiencies and other initiatives.

•	Building off the strength of our asset base.

•	Maximizing that base through sector leading operations and service.

•	Effectively executing the projects we have secured.

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•	Securing new growth opportunities that add value for our investors within each of our business segments.

•	Expanding our value chain participation into complementary infrastructure assets.

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•	the effects of a weaker Canadian dollar at Distribution and Western Canada Transmission & Processing,

•	lower NGL prices, lower sales volumes of residual natural gas and non-cash mark-to-market gains and losses associated with the risk management program, net of an increase from settlement gains associated with the risk management program at the Empress operations at Western Canada Transmission & Processing and

•	lower customer usage due to warmer weather, net of growth in the number of customers at Distribution, partially offset by

•	revenues from expansion projects primarily on Texas Eastern and East Tennessee at Spectra Energy Partners.

•	the effects of a weaker Canadian dollar at Distribution and Western Canada Transmission & Processing,

•	decreased volumes of natural gas purchases for extraction and make-up and lower costs of sales at Western Canada Transmission & Processing and

•	lower volumes of natural gas sold due to warmer weather, net of growth in the number of customers at Distribution, partially offset by

•	goodwill impairment charges associated with the Westcoast acquisition in 2002 at Other.

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revenues from expansion projects primarily at Texas Eastern, the acquisition of Express-Platte in March 2013, higher natural gas transportation revenues due to new contracts and an increase in crude oil transportation revenues for both Express and Platte Pipeline, mainly as a result of increased tariff rates and higher volumes, and higher processing revenues, net of lower storage revenues due to lower rates at Spectra Energy Partners,

•	higher sales volumes of residual natural gas, non-cash mark-to-market gains associated with the risk management program implemented in early 2014 and higher propane sales prices, net of lower sales volumes of NGLs at the Empress operations, and an increase in gathering and processing revenues at Western Canada Transmission & Processing, and

•	higher customer usage of natural gas primarily as a result of colder weather, higher natural gas prices passed through to customers and growth in the number of customers, net of lower storage revenues due to lower prices and 2014 earnings to be shared with customers under the new incentive regulation framework at Distribution, partially offset by

•	the effects of a weaker Canadian dollar at Western Canada Transmission & Processing and Distribution.

•	increased volumes of natural gas purchases for extraction and make-up, and a non-cash charge to reduce the value of propane inventory to net realizable value at the Empress operations, higher plant turnaround and maintenance costs, and higher plant fuel costs due to higher prices at the Empress operations at Western Canada Transmission & Processing,

•	higher volumes of natural gas sold due to colder weather, higher natural gas prices passed through to customers and growth in the number of customers at Distribution and

•	expansion projects, primarily at Texas Eastern, and the acquisition of Express-Platte at Spectra Energy Partners, partially offset by

•	the effects of a weaker Canadian dollar at Distribution and Western Canada Transmission & Processing.

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(a)	Includes foreign currency transaction gains and losses related to segment EBITDA.

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(a)	Thousand barrels per day.

•	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.

•	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.

•	a $168 million increase due to expansion projects, primarily at Texas Eastern,

•	a $68 million increase primarily due to the acquisition of Express-Platte in March 2013,

•	a $44 million increase due to higher natural gas transportation revenues due to new contracts, mainly at Texas Eastern and Algonquin,

•	a $26 million increase in crude oil transportation revenues for both Express and Platte pipelines, mainly as a result of increased tariff rates and higher revenue volumes and

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•	a $19 million increase due to higher processing revenues mainly due to volumes, partially offset by

•	a $25 million decrease in gas storage revenues due to lower rates.

•	a $33 million increase from expansion projects, primarily at Texas Eastern,

•	a $25 million increase due to the acquisition of Express-Platte and

•	a $10 million increase in operating costs mostly due to repairs and maintenance, partially offset by

•	an $11 million decrease mostly due to 2013 transaction costs related to the U.S. Assets Dropdown to SEP.

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(a)	Trillion British thermal units.

•	a $225 million decrease resulting from a weaker Canadian dollar,

•	a $114 million decrease in residential customer usage of natural gas, mainly due to weather that was warmer than in 2014 and

•	a $13 million decrease from lower natural gas prices passed through to customers. Prices charged to customers are adjusted quarterly based on the 12 month New York Mercantile Exchange (NYMEX) forecast, partially offset by

•	a $31 million increase from growth in the number of customers.

•	a $98 million decrease resulting from a weaker Canadian dollar,

•	a $93 million decrease due to lower volumes of natural gas sold to residential customers primarily due to warmer weather,

•	a $13 million decrease from lower natural gas prices passed through to customers, partially offset by

•	a $20 million increase from growth in the number of customers.

•	a $147 million decrease resulting from a weaker Canadian dollar,

•	an $8 million decrease in storage revenues primarily due to lower storage prices, partially offset by

•	an $81 million increase in customer usage of natural gas primarily due to weather that was colder than in 2013,

•	a $34 million increase from higher natural gas prices passed through to customers. Prices charged to customers are adjusted quarterly based on the 12 month NYMEX forecast and

•	a $34 million increase from growth in the number of customers.

•	a $65 million increase due to higher volumes of natural gas sold primarily due to colder weather,

•	a $34 million increase from higher natural gas prices passed through to customers and

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•	a $25 million increase from growth in the number of customers, partially offset by

•	a $73 million decrease resulting from a weaker Canadian dollar.

•	a $199 million decrease resulting from a weaker Canadian dollar,

•	a $194 million decrease due to lower NGL prices associated with the Empress operations,

•	a $141 million decrease due primarily to lower sales volumes of residual natural gas at the Empress operations,

•	a $108 million decrease arising from non-cash mark-to-market gains and losses associated with the risk management program at the Empress operations,

•	a $20 million decrease in transmission revenues due to lower interruptible transmission revenues and lower tolls charged to customers at M&N Canada and

•	a $14 million decrease in sales volumes of NGLs at the Empress operations, partially offset by

•	a $61 million increase from settlement gains associated with the risk management program at the Empress operations.

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•	a $160 million decrease due to lower volumes of natural gas purchases for extraction and make-up at the Empress operations,

•	a $67 million decrease primarily as a result of lower costs of sales at the Empress facility and

•	a $30 million decrease resulting from a weaker Canadian dollar.

•	a $91 million decrease resulting from a weaker Canadian dollar and

•	an $18 million decrease primarily in costs passed through to customers at M&N Canada, partially offset by

•	an $18 million increase due to overhead reduction costs and

•	a $7 million non-cash asset impairment loss related to a natural gas processing plant.

•	a $112 million increase due primarily to higher sales volumes of residual natural gas at the Empress operations,

•	an $85 million increase from non-cash mark-to-market gains associated with the risk management program implemented in early 2014,

•	a $41 million increase due to higher propane prices associated with the Empress NGL business,

•	a $19 million increase in gathering and processing revenues from new facilities in the Horn River and Montney unconventional development areas,

•	a $17 million increase in gathering and processing revenues from existing facilities,

•	a $17 million increase from settlement gains associated with the risk management program implemented in early 2014,

•	a $13 million increase in transmission revenues due primarily to higher tolls at BC Pipeline,

•	an $8 million increase primarily in interruptible transmission revenues due to a new supply source connected to the M&N Canada system and

•	a $6 million increase in carbon and other non-income tax expense recovered from customers, partially offset by

•	a $143 million decrease as a result of a weaker Canadian dollar and

•	a $43 million decrease due to lower sales volumes of NGLs from decreased demand in the market at the Empress operations.

•	a $98 million increase due primarily to higher volumes of natural gas purchases for extraction and make-up at Empress and

•	a $19 million non-cash charge to reduce the value of propane inventory at the Empress operations to net realizable value at December 31, 2014, partially offset by

•	a $36 million decrease as a result of a weaker Canadian dollar and

•	an $8 million decrease primarily as a result of lower costs of NGL purchases at the Empress facility.

•	a $38 million increase in plant turnaround and repair costs,

•	a $9 million increase in Empress plant fuel costs due primarily to higher prices,

•	an $8 million increase in maintenance expense,

•	a $6 million increase primarily in costs passed through to customers at M&N Canada,

•	a $6 million increase in carbon and other non-income tax expense,

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•	a $6 million increase in operating costs of new facilities and

•	a $5 million increase due to software support services, partially offset by

•	a $48 million decrease as a result of a weaker Canadian dollar.

(a)	Reflects 100% of volumes.

(b)	Trillion British thermal units per day.

(c)	Average price based on NYMEX Henry Hub.

(d)	Million British thermal units.

(e)	Does not reflect results of commodity hedges.

(f)	Average price based on NYMEX calendar month.

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•	a $451 million decrease from commodity-sensitive processing arrangements, due to decreased NGL, crude oil and natural gas prices,

•	a $392 million decrease primarily as a result of goodwill and other asset impairments, net of tax impacts,

•	a $71 million decrease in gains associated with the issuance of partnership units by DCP Partners in 2015 compared to 2014 and

•	a $15 million decrease primarily attributable to higher depreciation expense as a result of asset growth, partially offset by

•	an $87 million increase in gathering and processing margins as a result of asset growth, net of volume declines in certain geographic regions,

•	an $81 million increase resulting from decreased net income attributable to noncontrolling interests as a result of unrealized derivative activity, goodwill impairment recognized during the year ended December 31, 2015 and a greater portion of distributions allocated to the general partner of DCP Partners through our incentive distribution rights, net of asset growth at DCP Partners,

•	a $36 million increase as a result of favorable results from ownership interests in NGL pipelines, primarily attributable to the ramp-up of the Sand Hills and Front Range pipelines and favorable results from the Wholesale Propane Logistics business,

•	a $24 million increase as a result of net gains on sales of assets in 2015, compared to a loss on the sale of an asset in 2014,

•	a $16 million increase primarily attributable to lower operating expenses as a result of cost savings initiatives in operations, net of additional costs from asset growth and

•	a $14 million increase as a result of favorable results from third-party derivative instruments used to mitigate a portion of its expected commodity cash flow risk.

•	a $78 million decrease resulting from increased net income attributable to noncontrolling interests as a result of growth in DCP Partners’ operations, as well as the effects of dropdown hedges,

•	a $45 million decrease from commodity-sensitive processing arrangements, due to the impact of higher transportation and fractionation costs on our realized prices and decreased crude oil prices, partially offset by increased natural gas prices,

•	a $43 million decrease primarily attributable to higher operating expenses as a result of increased spending on reliability programs, as well as growth in Field Services’ operations,

•	a $26 million decrease primarily as a result of losses on sales of assets and a goodwill impairment charge in 2014 compared to gains on sales of assets in 2013,

•	a $25 million decrease in gains associated with issuances of partnership units by DCP Partners in 2014 compared to 2013,

•	a $19 million decrease mainly due to higher interest expense as a result of higher interest rates from newly issued debt and lower capitalized interest on certain projects which were placed in service in 2013 and

•	a $17 million decrease primarily attributable to higher depreciation expense as a result of growth in Field Services’ business, partially offset by

•	an $83 million increase in gathering and processing margins as a result of asset growth and higher volumes in certain of our geographic regions and

•	a $43 million increase as a result of DCP Partners’ favorable results from third-party mark-to-market on derivative instruments used to mitigate a portion of its expected commodity cash flow risk, favorable results from Sand Hills and

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•	higher earnings and

•	distributions from equity investments, partially offset by

•	changes in working capital.

•	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.

•	a $1,254 million net cash outlay for the acquisition of Express-Platte in March 2013 and

•	a $179 million increase in distributions from equity investments in 2014, comprised mostly of a $200 million distribution from SESH with proceeds from a SESH debt offering, partially offset by

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•	$6 million of net purchases of available-for-sale securities in 2014 compared to $146 million of net proceeds in 2013 and

•	a $28 million increase in capital and investment expenditures in 2014. Capital and investment expenditures include a $189 million investment in SESH, used by SESH to retire debt.

(a)	Excludes the $1,254 million net cash outlay for the acquisition of Express-Platte in March 2013. See Note 3 of Notes to Consolidated Financial Statements for further discussions.

(b)	Excludes a $71 million loan to an equity investment in 2013.

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OPEN - A 550 million cubic feet per day (MMcf/d) expansion of the Texas Eastern pipeline system consisting of new pipeline, a new compressor station and other associated facility upgrades. The project is designed to transport gas produced in the Utica Shale and Marcellus Shale to U.S. markets in the Midwest, Southeast and Gulf Coast. The project was placed in-service during the second half of 2015.

•	SESH Dentville - Installation of a single compressor located near the SESH/Texas Eastern Interconnect to maintain deliveries from Texas Eastern into SESH with changing pressure profile on Texas Eastern due to mainline expansion projects. Additional capacity range of 474 MMcf/d max, 102.2 MMcf/d min. The project was placed in-service during the fourth quarter of 2015.

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Uniontown to Gas City - The project provides shippers with 425 MMcf/d of firm transportation service from the supply-rich area west of Uniontown, Pennsylvania to a new delivery meter with Panhandle Eastern Pipe Line near Gas City, Indiana for further redelivery to markets in the Midwest. Five shippers combine to contract for the full 425 MMcf/d of capacity under the project. The project was placed in-service during the third quarter of 2015.

•	Bobcat Storage Expansion (Phase I and II) - The project as a whole is designed to expand the storage capacity and capabilities of Bobcat Gas Storage facility. Development of Cavern Well 5 increases the working gas capacity to 5.6 BCF and was placed in-service during the fourth quarter of 2015.

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•	2015 Dawn to Parkway - A 397 MMcf/d expansion of the Dawn to Parkway transmission system that consisted of the Parkway West project which includes the development of a new Greenfield compressor site west of Toronto and the installation of two new compressors and associated infrastructure, the Parkway C and D compressor units and the Brantford-Kirkwall 48 inch pipeline loop.

•	AIM - A 342 MMcf/d expansion of the Algonquin system consisting of replacement pipeline, new pipeline, new and modified meter station facilities and additional compression at existing stations. The project is designed to transport gas from existing interconnects in New Jersey and New York to LDC markets in the northeast. In-service is scheduled by the second half of 2016.

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Ozark Conversion - The project includes abandonment of portions of the Ozark Gas Transmission system from natural gas service and leasing of the abandoned lines to Magellan to transport approximately 75,000 Bbls/d of refined products. Completion of Spectra’s scope of work occurred during the third quarter of 2015. Completion of Magellan’s scope of work and system in-service is expected during the first half of 2016.

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Gulf Market Expansion - This Texas Eastern system expansion project connects growth markets (Gulf Coast LNG and industrials) with diverse, growing shale supply. The project consists of installing reverse-compression capability at six compressor stations to provide up to 650 MMcf/d. The project will be executed in two phases. Phase 1, due to go in-service in the second half of 2016, will provide north to south compression at five stations. Phase 2, due to go in-service in the second half of 2017, will provide north to south compression at one station and new compression at one existing compressor station and one new compressor station.

•	Loudon Expansion - This project will provide a customer with 40,000 decatherms per day (Dth/d) of incremental capacity. The project is expected to be in-service during the second half of 2016.

•	Sabal Trail - 1,100 MMcf/d of new capacity to access onshore shale gas supplies. Facilities include a new 465-mile pipeline, laterals and various compressor stations. The project is expected to be in-service during the first half of 2017.

•	Salem Lateral - An expansion of the Algonquin system for delivery of 115 MMcf/d of natural gas to the Footprint Salem Harbor Power Station in Salem, Massachusetts. The project is expected to be in-service during the second half of 2016.

•	Burlington-Oakville - 290 MMcf/d of new capacity for the Burlington/Oakville market. The project consists of 7 miles of 20 inch pipe. The project is expected to be in-service during the second half of 2016.

•	2016 Dawn Parkway - A 406 MMcf/d expansion of the Dawn to Parkway transmission system consisting of 12.4 miles of 48 inch Hamilton to Milton pipeline and the installation of a new compressor and associated infrastructure at Lobo. The project is expected to be in-service during the second half of 2016.

•	2017 Dawn Parkway - A 419 MMcf/d expansion of the Dawn to Parkway transmission system consisting of the addition of a new 44,500 horsepower compressor at each of our Dawn, Lobo and Bright Compressor Stations. Service to customers is expected in the second half of 2017.

•	Express Enhancement - This project will increase system capacity by 21,000 barrels per day. Facilities include the addition of tank storage at Hardisty, AB and Buffalo, MT and additional pumps at Buffalo, MT. The project is expected to be in-service during the second half of 2016.

•	High Pine Expansion - A 240 MMcf/d expansion of the T-North pipeline system consisting of two 42 inch pipeline loops and an additional compressor unit with associated infrastructure at the Sunset Creek compressor site. The project is expected to be in-service during the second half of 2016.

•	Jackfish Lake project - Consists primarily of two 36 inch pipeline loop additions totaling approximately 22 miles in length along the existing Fort St. John Mainline that will carry up to approximately 140 MMcf/d of gas from numerous receipt points in the South Montney production area. This project is expected to be in service within the first half of 2017.

•	Reliability and Maintainability (RAM) project - Designed to enhance the performance of the T-South system to accommodate the increased base load on the system being driven by increased production in Northeast BC. This project is expected to be in service in various stages in 2016 to 2018.

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•	$1,300 million of net proceeds from long-term debt in 2015, compared to net repayments of long-term debt of $156 million in 2014 and

•	$546 million proceeds from the issuance of SEP units in 2015, compared to $327 million in 2014, partially offset by

•	commercial paper redemptions of $439 million in 2015, compared to commercial paper issuances of $574 million in 2014.

•	$156 million of net redemptions of long-term debt in 2014 compared to $2,233 million of net issuances in 2013 which were mostly used to fund the acquisition of Express-Platte and the U.S. Assets Dropdown, partially offset by

•	$574 million of net commercial paper issuances in 2014 compared to $206 million of net commercial paper repayments in 2013,

•	$327 million in proceeds from SEP’s at-the-market program in 2014 compared to $214 million in proceeds from SEP’s issuance of units in 2013, and

•	$145 million of contributions from noncontrolling interest in 2014 compared to $23 million in 2013.

(a)	U.S. dollar equivalent at time of issuance.

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(a)	U.S. dollar equivalent at time of issuance.

(a)	Repaid in the fourth quarter of 2013.

(b)	U.S. dollar equivalent at time of issuance.

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(a)	Revolving credit facility contains a covenant requiring the Spectra Energy consolidated debt-to-total capitalization ratio, as defined in the agreement, to not exceed 65%. Per the terms of the agreement, collateralized debt is excluded from the calculation of the ratio. This ratio was 59.6% at December 31, 2015.

(b)	Revolving credit facility contains a covenant that requires SEP to maintain a ratio of total Consolidated Indebtedness-to-Consolidated EBITDA, as defined in the agreement, of 5.0 to 1 or less. As of December 31, 2015, this ratio was 3.6 to 1.

(c)	U.S. dollar equivalent at December 31, 2015. The revolving credit facility is 400 million Canadian dollars and contains a covenant that requires the Westcoast non-consolidated debt-to-total capitalization ratio to not exceed 75%. The ratio was 35.4% at December 31, 2015.

(d)

U.S. dollar equivalent at December 31, 2015. The revolving credit facility is 500 million Canadian dollars and contains a covenant that requires the Union Gas debt-to-total capitalization ratio to not exceed 75% and a provision which requires Union Gas to repay all borrowings under the facility for a period of two days during the second quarter of each year. The ratio was 67.8% at December 31, 2015.

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(a)	See Note 15 of Notes to Consolidated Financial Statements. Amounts include principal payments and estimated scheduled interest payments over the life of the associated debt and capital lease obligations.

(b)	See Note 19.

(c)	Purchase obligations reflected in the Consolidated Balance Sheets have been excluded from the above table.

(d)	Includes firm capacity payments that provide us with uninterrupted firm access to natural gas transportation and storage.

(e)	Includes contractual obligations to purchase physical quantities of NGLs and natural gas. Amounts include certain hedges as defined by applicable accounting standards. For contracts where the price paid is based on an index, the amount is based on forward market prices at December 31, 2015.

(f)	Includes contracts for software and consulting or advisory services. Amounts also include contractual obligations for engineering, procurement and construction costs for pipeline projects. Amounts exclude certain open purchase orders for services that are provided on demand, where the timing of the purchase cannot be determined.

(g)

Includes estimated 2016 retirement plan contributions (see Note 23). We are unable to estimate retirement plan contributions beyond 2016 due primarily to uncertainties about market performance of plan assets. Excludes cash obligations for asset retirement activities (see Note 14) because the amount of cash flows to be paid to settle the asset retirement obligations is not known with certainty as we may use internal or external resources to perform retirement activities. Amounts also exclude reserves for litigation and environmental remediation (see Note 19) and regulatory liabilities (see Note 5) because we are uncertain as to the amount and/or timing of when cash payments will be required. Amounts also exclude deferred income taxes and investment tax credits on the Consolidated Balance Sheets since cash payments for income taxes are determined primarily by taxable income for each discrete fiscal year.

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(a)	Excludes the $1,254 million cash outlay for the acquisition of Express-Platte in 2013, part of Spectra Energy Partners.

(b)	Excludes a $71 million loan to an equity investment in 2013 at Spectra Energy Partners.

(c)	Includes foreign currency transaction gains and losses related to segment EBITDA.

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(a)	Included in Inventory, Fuel Tracker, Current Assets—Other or Current Liabilities—Other.

(b)	Included in Regulatory Assets and Deferred Debits or Deferred Credits and Other Liabilities—Regulatory and Other.

(c)	Includes costs settled in cash annually through transportation rates in accordance with FERC and/or OEB gas tariffs.

(d)	All or a portion of the balance is included in rate base.

(e)	All amounts are expected to be included in future rate filings.

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(a)	Reflects revised assumptions regarding ARO Liabilities due to a reduction in the remaining estimated life of certain Texas Eastern offshore facilities in 2015 and asbestos abatement at Western Canada Transmission & Processing in 2014.

(b)	Amounts included in Deferred Credits and Other Liabilities in the Consolidated Balance Sheets.

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(a)	Reflects implementation of ASU No. 2015-03 as discussed in Note 1.

(b)	The weighted-average days to maturity was 12 days as of December 31, 2015 and 14 days as of December 31, 2014.

(c)	As of December 31, 2015 and 2014, respectively, $4,681 million and $5,264 million of debt was denominated in Canadian dollars.

(d)	Weighted-average rate on outstanding commercial paper was 0.9% at December 31, 2015 and 0.6% at December 31, 2014.

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(a)	Excludes commercial paper of $1,112 million. Includes capital leases of $19 million.

(a)	Revolving credit facility contains a covenant requiring the Spectra Energy consolidated debt-to-total capitalization ratio, as defined in the agreement, to not exceed 65%. Per the terms of the agreement, collateralized debt is excluded from the calculation of the ratio. This ratio was 59.6% at December 31, 2015.

(b)	Revolving credit facility contains a covenant that requires SEP to maintain a ratio of total Consolidated Indebtedness-to-Consolidated EBITDA, as defined in the agreement, of 5.0 to 1 or less. As of December 31, 2015, this ratio was 3.6 to 1.

(c)	U.S. dollar equivalent at December 31, 2015. The revolving credit facility is 400 million Canadian dollars and contains a covenant that requires the Westcoast non-consolidated debt-to-total capitalization ratio to not exceed 75%. The ratio was 35.4% at December 31, 2015.

(d)

U.S. dollar equivalent at December 31, 2015. The revolving credit facility is 500 million Canadian dollars and contains a covenant that requires the Union Gas debt-to-total capitalization ratio to not exceed 75% and a provision which requires Union Gas to repay all borrowings under the facility for a period of two days during the second quarter of each year. The ratio was 67.8% at December 31, 2015.

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(a)	Included within Investments in and Loans to Unconsolidated Affiliates.

(b)	Excludes capital leases, unamortized items and fair value hedge carrying value adjustments.

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(a)	See Note 2 for further discussion.

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(a)

Beginning in 2014, the valuation model was refined to use an alternate analytical approach to project future stock prices in order to improve consistency and efficiency. The improved approach does not require the use of a market index assumption to determine the future stock price used in the valuation model. As such, the volatility of the market index assumption will not be presented going forward. Based on our assessment, it was determined that this refinement did not have a significant impact on the fair value of the shares for all periods presented.

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(a)	Recognized primarily in Deferred Credits and Other Liabilities—Regulatory and Other in the Consolidated Balance Sheets.

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

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(a)	Quarterly earnings-per-share amounts are stand-alone calculations and may not be additive to full-year amounts due to rounding.

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(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.

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•	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.

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•

Percent-of-proceeds/index arrangements - Under percent-of-proceeds/index arrangements, we generally purchase natural gas from producers at the wellhead or other receipt points, gather the wellhead natural gas through our gathering system, treat and process the natural gas, and then sell the resulting residue natural gas, NGLs and condensate based on published index prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of the residue natural gas, NGLs and condensate, or an agreed-upon percentage of the proceeds based on index related prices or contractual recoveries for the natural gas, NGLs and condensate, regardless of the actual amount of the sales proceeds we receive. We keep the difference between the proceeds received and the amount remitted back to the producer. Under percent-of-liquid arrangements, we do not keep any amounts related to the residue natural gas proceeds and only keep amounts related to the difference between the proceeds received and the amount remitted back to the producer related to NGLs and condensate. Certain of these arrangements may also result in the producer retaining title to all or a portion of the residue natural gas and/or the NGLs, in lieu of us returning sales proceeds to the producer. Additionally, these arrangements may include fee-based components. Our revenues under percent-of-proceeds/index arrangements relate directly with the price of natural gas, NGLs and condensate. Our revenues under percent-of-liquids arrangements relate directly to the price of NGLs and condensate.

•

Fee-based arrangements - Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, compressing, treating, processing, transporting or storing natural gas and fractionating, storing and transporting NGLs. Our fee-based arrangements include natural gas arrangements pursuant to which we obtain natural gas at the wellhead, or other receipt points, at an index related price at the delivery point less a specified amount, generally the same as the transportation fees we would otherwise charge for transportation of natural gas from the wellhead location to the delivery point. The revenues we earn are directly related to the volume of natural gas or NGLs that flows through our systems and are not directly dependent on commodity prices. However, to the extent a sustained decline in commodity prices results in a decline in volumes our revenues from these arrangements would be reduced.

•

Keep-whole and wellhead purchase arrangements - Under the terms of a keep-whole processing contract, natural gas is gathered from the producer for processing, the NGLs and condensate are sold and the residue natural gas is returned to the producer with a British thermal unit, or Btu, content equivalent to the Btu content of the natural gas gathered. This arrangement keeps the producer whole to the thermal value of the natural gas received. Under the terms of a wellhead purchase contract, we purchase natural gas from the producer at the wellhead or defined receipt point for processing and then market the resulting NGLs and residue gas at market prices. Under these types of contracts, we are exposed to the difference between the value of the NGLs extracted from processing and the value of the Btu equivalent of residue natural gas, or frac spread. We benefit in periods when NGL prices are higher relative to natural gas prices when that frac spread exceeds our operating costs.

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•	Persuasive evidence of an arrangement exists - Our customary practice is to enter into a written contract.

•	Delivery - Delivery is deemed to have occurred at the time custody is transferred, or in the case of fee-based arrangements, when the services are rendered. To the extent we retain product as inventory, delivery occurs when the inventory is subsequently sold and custody is transferred to the third party purchaser.

•	The fee is fixed or determinable - We negotiate the fee for our services at the outset of our fee-based arrangements. In these arrangements, the fees are nonrefundable. For other arrangements, the amount of revenue, based on contractual terms, is determinable when the sale of the applicable product has been completed upon delivery and transfer of custody.

•

Collectability is reasonably assured - Collectability is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers’ financial position (for example, credit metrics, liquidity and credit rating) and their ability to pay. If collectability is not considered probable at the outset of an arrangement in accordance with our credit review process, revenue is not recognized until the cash is collected.

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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.

•

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

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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.

•	Level 1 - inputs are unadjusted quoted prices for identical assets or liabilities in active markets.

•	Level 2 - inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

•	Level 3 - inputs are unobservable and considered significant to the fair value measurement.

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•	If we were to have an effective event of default under our DCP Midstream Amended and Restated Credit Agreement that occurs and is continuing, our ISDA counterparties may have the right to request early termination and net settlement of any outstanding derivative liability positions.

•	Our ISDA counterparties generally have collateral thresholds of zero, requiring us to fully collateralize any commodity contracts in a net liability position, when our or DCP Partners’ credit rating is below investment grade.

•	In some cases, our ISDA contracts contain cross-default provisions that could constitute a credit-risk related contingent feature. For example, if we were to fail to make a required interest or principal payment on a debt instrument, above a predefined threshold level, and after giving effect to any applicable notice or grace period as

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