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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 U.S. and Canadian pipeline, storage, gathering, processing and other related infrastructure projects and the effects of competition;

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

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

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

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

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

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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

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

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

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

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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;

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

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

•	Authorizing PHMSA to assess higher penalties for violations of its regulations,

•	Requiring PHMSA to adopt appropriate regulations within two years requiring the use of automatic or remote-controlled shutoff valves on new or rebuilt pipeline facilities and to perform a study on the application of such technology to existing pipeline facilities in High Consequence Areas (HCAs),

•	Requiring operators of pipelines to verify maximum allowable operating pressure and report exceedances within five days,

•	Requiring PHMSA to study and report on the adequacy of soil cover requirements in HCAs, and

•	Requiring PHMSA to evaluate in detail whether integrity management requirements should be expanded to pipeline segments outside of HCAs (where the requirements currently apply).

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

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Spectra Energy Partners’ earnings increased mainly due to expansion projects, primarily at Texas Eastern, higher earnings from the continued ramp up of volumes at Sand Hills and Southern Hills, the acquisition of Express-Platte in March 2013, higher natural gas transportation revenues due to new contracts, and an increase in crude oil transportation revenues for both Express and Platte pipelines mainly as a result of increased tariff rates and higher revenue volumes, partially offset by lower storage revenues due to lower rates and lower allowance for funds used during construction (AFUDC) due to decreased capital spending.

•	Distribution’s earnings decreased mainly due to a weaker Canadian dollar, lower storage revenues due to lower prices and 2014 earnings to be shared with customers under the new incentive regulation framework, partially offset by higher customer usage primarily as a result of colder weather and increased customer growth.

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Western Canada Transmission & Processing’s earnings benefited from higher earnings at the Empress NGL business mainly due to non-cash mark-to-market gains associated with the risk management program implemented in early 2014 and higher propane prices, and higher gathering and processing revenues, partially offset by higher plant turnaround and maintenance costs and the effect of a weaker Canadian dollar.

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Field Services’ earnings decreased, reflecting mainly an increase in net income attributable to noncontrolling interests as a result of growth in DCP Partners’ operations and the effects of dropdown hedges, lower commodity prices, higher operating costs, losses on sales of assets and a goodwill impairment in 2014 compared to gains on sales of assets in 2013, and lower gains associated with the issuance of partnership units by DCP Partners, partially offset by increased gathering and processing margins due to asset growth and higher volumes, and favorable results from trading and marketing and DCP Partners’ mark-to-market activity.

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•	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.

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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 Distribution and Western Canada Transmission & Processing.

•	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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•	revenues from Express-Platte acquired in March 2013, net of lower recoveries of electric power and other costs passed through to customers, and lower storage revenues at Spectra Energy Partners,

•	higher customer usage of natural gas as a result of colder weather, higher natural gas prices passed through to customers, higher distribution rates, an adjustment in 2012 related to an unfavorable OEB decision affecting transportation revenues, and growth in the number of customers, net of lower short-term transportation and storage revenues at Distribution,

•	higher revenues from expansion projects at Western Canada Transmission & Processing and Spectra Energy Partners, and

•	higher NGL sales prices and volumes at the Empress operations, net of lower contracted volumes in the conventional gathering and processing business at Western Canada Transmission & Processing, partially offset by

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

•	an increase in volumes of natural gas sold due to colder weather, higher natural gas prices passed through to customers, increased gas purchased due to growth in the number of customers and higher operating fuel costs at Distribution,

•	operating costs from Express-Platte, net of lower electric power and other costs passed through to customers at Spectra Energy Partners,

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increased volumes of natural gas purchases for extraction and make-up at the Empress operations, higher depreciation expense from expansion projects, scheduled plant turnarounds in 2013, increased operating costs of new facilities and higher benefit and labor costs, net of lower production costs due primarily to lower extraction premiums and a noncash charge in 2012 to write down propane inventory at the Empress operations, at Western Canada Transmission & Processing, and

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•	higher corporate costs driven primarily by transaction costs associated with the U.S. Assets Dropdown and higher employee benefit costs, partially offset by

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

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(a)	Thousand barrels per day.

(b)	Data includes only activity since March 14, 2013, the date of the acquisition of Express-Platte.

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

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

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

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

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

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

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

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

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

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

•	a $286 million increase due to the acquisition of Express-Platte in March 2013 and expansion projects primarily at Texas Eastern, partially offset by

•	a $42 million decrease in recoveries of electric power and other costs passed through to customers,

•	a $24 million decrease due to lower storage revenues as a result of lower contract renewal rates, and

•	an $8 million decrease from lower processing revenues.

•	a $115 million increase from the acquisition of Express-Platte and expansion projects primarily at Texas Eastern,

•	a $10 million increase due to higher employee benefit costs and ad valorem taxes, net of lower software amortization, and

•	a $7 million charge for transaction costs related to the U.S. Assets Dropdown to SEP, partially offset by

•	a $42 million decrease in electric power and other costs passed through to customers.

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

•	an $8 million decrease in storage revenues primarily due to lower storage prices, and

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

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•	an $81 million increase in customer usage of natural gas primarily due to weather that was more than 7% colder than in 2013,

•	a $34 million increase from higher natural gas prices passed through to customers. Prices charged to customers are adjusted quarterly based on the 12 months New York Mercantile Exchange (NYMEX) forecasts,

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

•	a $10 million increase, net of 2012 earnings sharing, as a result of a decision by the OEB in 2014 primarily regarding certain 2012 revenues realized from the optimization of upstream transportation contracts being treated as utility earnings.

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

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

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

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

•	a $30 million decrease resulting from a weaker Canadian dollar, and

•	a $7 million decrease resulting from the deferral of pension expense approved by the OEB for recovery from customers.

•	a $129 million increase in customer usage of natural gas primarily due to weather that was more than 18% colder than 2012,

•	a $59 million increase from higher natural gas prices passed through to customers. Prices charged to customers are adjusted quarterly based on the 12 month NYMEX forecast,

•	a $41 million increase from higher distribution rates approved by the OEB,

•	a $38 million increase due to an adjustment in 2012 as a result of an unexpected decision from the OEB in November 2012 requiring certain revenues realized from the optimization of upstream transportation contracts be refunded to customers, and

•	a $36 million increase from growth in the number of customers, partially offset by

•	a $55 million decrease resulting from a weaker Canadian dollar,

•	a $28 million decrease mainly in short-term transportation revenues due to lower exchange service revenues, net of a settlement received from the termination of a transportation contract,

•	a $21 million decrease in storage revenues primarily due to lower prices, and

•	a $20 million decrease as a result of the sharing of revenues realized from the optimization of upstream transportation contracts in accordance with an OEB rate order effective January 1, 2013.

•	a $103 million increase due to higher volumes of natural gas sold due to colder weather,

•	a $59 million increase from higher natural gas prices passed through to customers,

•	a $28 million increase from growth in the number of customers, and

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•	a $15 million increase in operating fuel costs primarily due to gas measurement variances, partially offset by

•	a $24 million decrease resulting from a weaker Canadian dollar.

•	a $20 million increase primarily driven by higher employee benefit costs, partially offset by

•	a $14 million decrease resulting from a weaker Canadian dollar.

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

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

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

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

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

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

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

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

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

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

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

•	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,

•	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 $59 million increase in gathering and processing revenues due primarily to expansion in unconventional areas for Horn River and Montney development,

•	a $39 million increase due to higher sales prices associated with the Empress NGL business,

•	a $35 million increase due primarily to higher sales volumes of residual natural gas at the Empress operations,

•	a $22 million increase in transmission revenues due primarily to expansion on the T-North Pipeline,

•	a $17 million increase in NGL sales volumes at Empress,

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•	a $9 million increase in carbon and other non-income tax expense recovered from customers, and

•	a $9 million increase primarily driven by interruptible transmission revenues and higher 2013 tolls charged to customers at M&N Canada, partially offset by

•	a $58 million decrease as a result of a weaker Canadian dollar, and

•	a $44 million decrease in conventional gathering and processing revenues due primarily to lower contracted volumes.

•	a $53 million decrease as a result of lower production costs for the Empress facility caused primarily by lower extraction premiums,

•	a $14 million decrease as a result of a weaker Canadian dollar, and

•	a $14 million noncash charge in 2012 to write down propane inventory at the Empress operations, partially offset by

•	a $35 million increase in volumes of natural gas purchases for extraction and make-up at Empress.

•	a $20 million increase due to scheduled plant turnarounds in 2013,

•	a $16 million increase due to operating costs of the new facilities at Dawson and Fort Nelson North,

•	a $14 million increase due to higher benefit and labor costs,

•	a $12 million increase primarily in costs passed through to customers at M&N Canada,

•	a $9 million increase in carbon and other non-income tax expense, and

•	a $6 million increase in Empress plant fuel and electricity costs due to higher prices, partially offset by

•	a $21 million decrease as a result of a weaker Canadian dollar.

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(a)	Reflects 100% of volumes.

(b)	Trillion British thermal units per day.

(c)	Average price based on NYMEX Henry Hub.

(d)	Million British thermal units.

(e)	Does not reflect results of commodity hedges. 2013 NGL prices have been revised to reflect the impact of ethane rejection.

(f)	Average price based on NYMEX calendar month.

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

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

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

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

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

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

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

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

•	a $43 million increase as a result of DCP Partners’ favorable results from third-party mark-to-market on derivative instruments used to mitigate a portion of its expected commodity cash flow risk, favorable results from Sand Hills and Southern Hills, and favorable results from NGL trading and gas marketing, partially offset by unfavorable results from wholesale propane.

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•	a $62 million increase in gains associated with the issuance of partnership units by DCP Partners in 2013 compared to 2012,

•	a $13 million increase primarily attributable to lower operating costs as a result of a cost reduction initiative and lower benefit costs,

•	a $10 million increase due to gains from sales of assets,

•	a $12 million increase attributable to the favorable results from NGL trading, and

•	a $9 million increase from commodity-sensitive processing arrangements due to higher natural gas and crude oil prices, net of lower NGL prices, partially offset by

•	a $26 million decrease primarily attributable to higher interest expense due to higher interest rates as a result of newly issued debt and lower capitalized interest on certain projects which were placed in service in 2013, and

•	a $15 million decrease primarily attributable to incremental dropdowns to DCP Partners, which increased net income attributable to noncontrolling interests.

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•	higher earnings, and

•	distributions from unconsolidated affiliates, partially offset by

•	changes in working capital.

•	lower net tax payments in 2013, partially offset by

•	changes in working capital.

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

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

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

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

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•	a $1,254 million net cash outlay for the acquisition of Express-Platte, partially offset by

•	$513 million of initial and subsequent investments in Sand Hills and Southern Hills in 2012 compared to investments of $267 million in 2013, and

•	$146 million of net proceeds of available-for-sale securities in 2013 compared to $130 million of net purchases in 2012.

(a)	Excludes the $1,254 million net cash outlay for the acquisition of Express-Platte in March 2013 and $30 million paid in 2012 for amounts previously withheld from the purchase price consideration of the acquisition of Bobcat in 2010. See Note 3 of Notes to Consolidated Financial Statements for further discussions.

(b)	Excludes a $71 million loan to an unconsolidated affiliate in 2013.

•	North Montney Development - 211 MMcf/d of new gathering and processing service and 159 MMcf/d of renewed gathering and processing service. The project includes various processing plant modifications, including reactivation of the existing Aitken Creek plant. This project was placed in-service during the first quarter of 2014.

•	Buffalo Terminal Expansion - Buffalo expansion consists of two additional 150,000 bbl above ground storage tanks along with delivery pump and piping facilities to supply crude oil to the Cenex Harvest States Front Range pipeline. This project was placed in-service during the third quarter of 2014.

•	TEAM 2014 - A 600 MMcf/d expansion of the Texas Eastern pipeline system consisting of new pipeline construction. The project is designed to transport gas produced in the Marcellus Shale to U.S. markets in the Northeast, Midwest and Gulf Coast. This project was placed in-service during the fourth quarter of 2014.

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•	Bobcat Storage Expansion - The project as a whole is designed to expand the storage capacity and capabilities of the Bobcat facility. Cavern Well 4 increases the working gas capacity by 9.9 Bcf, and was placed in-service during the fourth quarter of 2014.

•	Kingsport - An additional 61 MMcf/d on the East Tennessee system to support a customer’s multi-year project to convert five coal-fired power plant boilers to natural gas. The project was placed in-service during the fourth quarter of 2014.

•	Dawn-Parkway 2015 - A 681 MMcfd expansion of the Dawn-Parkway transmission system consisting of the Parkway West project which includes the development of a new Greenfield compressor site west of Toronto and the installation of a new compressor and associated infrastructure; the Parkway D compressor unit and the Brantford-Kirkwall NPS 48 pipeline loop.

•	OPEN - A 550 MMcf/d expansion of the Texas Eastern pipeline system consisting of new pipeline, a new compressor station and other associated facility upgrades. The project is designed to transport gas produced in the Utica Shale and Marcellus Shale to U.S. markets in the Midwest, Southeast and Gulf Coast. In-service is scheduled by the fourth quarter of 2015.

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

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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 up to seven compressor stations to provide up to 650 MMcf/d. The project will be executed in two phases. Phase 1, due to go in-service in the fourth quarter of 2016, will provide north to south compression at five stations. Phase 2 due to go in-service in the fourth quarter of 2017 will provide north to south compression at two stations.

•	Sabal Trail - 1,100 MMcf/d of new capacity to access onshore shale gas supplies. Facilities include a new 465-mile pipeline, laterals and various compressor stations. In-service is scheduled by the second quarter of 2017.

•	Salem Lateral - An expansion of the Algonquin system for delivery of 115 MMcf/d of natural gas to the Footprint Salem Harbor Power Station in Salem, Massachusetts. In-service is scheduled by the first quarter 2016.

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Uniontown to Gas City - The project will provide shippers with 425 MMcf/d of firm transportation service from the supply-rich area west of Uniontown, Pennsylvania to a new delivery meter with Panhandle Eastern Pipe Line near Gas City, Indiana for further redelivery to markets in the Midwest. These five shippers combine to contract for the full 425 MMcf/d of capacity under the project. In-service is scheduled by the fourth quarter of 2015.

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DCP Sand Hills - Red Lake - The project includes the construction of two lateral pipelines with a combined length of 170 miles to connect a DCP gas processing plant and two third-party gas processing plants to the Sand Hills Pipeline. The project extends the reach of the Sand Hills Pipeline into a fast growing region of the Permian basin and enhances long-term throughput on the pipeline. It is expected to be in-service in the second half of 2015.

•	Ozark Conversion - The project includes abandonment of portions of the Ozark Gas Transmission system from natural gas service and leasing of the abandoned lines to Magellan to transport approximately 75,000 Bbls/d of refined products. In-service is scheduled by the third quarter of 2015.

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

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

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

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

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•	a $1,457 million net increase in long-term debt issuances in 2013 compared to 2012, mostly used to fund the acquisition of Express-Platte and the U.S. Assets Dropdown, partially offset by

•	$206 million of net repayments of commercial paper in 2013 compared to $199 million of proceeds from commercial paper in 2012, and

•	proceeds of $382 million from the issuance of Spectra Energy common stock in 2012.

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

(a)	Revolving credit facility contains a covenant requiring the Spectra Energy Corp consolidated debt-to-total capitalization ratio, as defined in the agreement, to not exceed 65%. Per the terms of the agreement, collateralized debt is excluded from the calculation of the ratio. This ratio was 58% at December 31, 2014.

(b)	Revolving credit facility contains a covenant that requires SEP to maintain a ratio of total Consolidated Indebtedness-to-Consolidated EBITDA, as defined in the agreement, of 5.0 to 1 or less. As of December 31, 2014, this ratio was 3.7 to 1.

(c)	U.S. dollar equivalent at December 31, 2014. The revolving credit facility is 400 million Canadian dollars and contains a covenant that requires the Westcoast non-consolidated debt-to-total capitalization ratio to not exceed 75%. The ratio was 35% at December 31, 2014.

(d)

U.S. dollar equivalent at December 31, 2014. The revolving credit facility is 500 million Canadian dollars and contains a covenant that requires the Union Gas debt-to-total capitalization ratio to not exceed 75% and a provision which requires Union Gas to repay all borrowings under the facility for a period of two days during the second quarter of each year. The ratio was 68% at December 31, 2014.

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(a)	See Note 16 of Notes to Consolidated Financial Statements. Amounts include principal payments and estimated scheduled interest payments over the life of the associated debt and capital lease obligations.

(b)	See Note 20.

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

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

(e)	Includes contractual obligations to purchase physical quantities of NGLs and natural gas. Amounts include certain hedges as defined by applicable accounting standards. For contracts where the price paid is based on an index, the amount is based on forward market prices at December 31, 2014.

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

(g)

Includes estimated 2015 retirement plan contributions (see Notes 25). We are unable to estimate retirement plan contributions beyond 2015 due primarily to uncertainties about market performance of plan assets. Excludes cash obligations for asset retirement activities (see Note 15) because the amount of cash flows to be paid to settle the asset retirement obligations is not known with certainty as we may use internal or external resources to perform retirement activities. Amounts also exclude reserves for litigation and environmental remediation (see Note 20) and regulatory liabilities (see Note 5) because we are uncertain as to the amount and/or timing of when cash payments will be required. Amounts also exclude deferred income taxes and investment tax credits on the Consolidated Balance Sheets since cash payments for income taxes are determined primarily by taxable income for each discrete fiscal year.

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(a)	Excludes amounts associated with entities included in discontinued operations.

(b)	Excludes the $1,254 million cash outlay for the acquisition of Express-Platte in March 2013 and $30 million paid in 2012 for amounts previously withheld from the purchase price consideration of the acquisition of Bobcat in 2010, all part of Spectra Energy Partners.

(c)	Excludes a $71 million loan to an unconsolidated affiliate in 2013 at Spectra Energy Partners.

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(a)	Excludes revenues associated with businesses included in discontinued operations.

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(a)	Included in Regulatory Assets and Deferred Debits unless otherwise noted.

(b)	All regulatory assets and liabilities are excluded from rate base unless otherwise noted.

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

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

(e)	Recovery/refund is over the life of the associated asset or liability.

(f)	Recoverable in future periods.

(g)	Amounts settled in cash annually through transportation rates in accordance with FERC gas tariffs.

(h)	Included in Other Current Assets.

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

(j)	The majority of this balance has a recovery period of less than one year. The recovery/refund period for the remainder is currently unknown.

(k)	Included in Deferred Credits and Other Liabilities — Regulatory and Other.

(l)	Liability is extinguished as the associated assets are retired.

(m)	Included in Other Current Liabilities.

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

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(a)	The weighted-average days to maturity was 14 days as of December 31, 2014 and 9 days as of December 31, 2013.

(b)	As of December 31, 2014 and 2013, respectively, $5,264 million and $5,248 million of debt was denominated in Canadian dollars.

(c)	Weighted-average rate on outstanding commercial paper was 0.6% at both December 31, 2014 and 2013.

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(a)	Excludes commercial paper of $1,583 million. Includes capital leases of $24 million and other non-principal amounts of $12 million.

(a)	Revolving credit facility contains a covenant requiring the Spectra Energy Corp consolidated debt-to-total capitalization ratio, as defined in the agreement, to not exceed 65%. Per the terms of the agreement, collateralized debt is excluded from the calculation of the ratio. This ratio was 58% at December 31, 2014.

(b)	Revolving credit facility contains a covenant that requires SEP to maintain a ratio of total Consolidated Indebtedness-to-Consolidated EBITDA, as defined in the agreement, of 5.0 to 1 or less. As of December 31, 2014, this ratio was 3.7 to 1.

(c)	U.S. dollar equivalent at December 31, 2014. The revolving credit facility is 400 million Canadian dollars and contains a covenant that requires the Westcoast non-consolidated debt-to-total capitalization ratio to not exceed 75%. The ratio was 35% at December 31, 2014.

(d)

U.S. dollar equivalent at December 31, 2014. The revolving credit facility is 500 million Canadian dollars and contains a covenant that requires the Union Gas debt-to-total capitalization ratio to not exceed 75% and a provision which requires Union Gas to repay all borrowings under the facility for a period of two days during the second quarter of each year. The ratio was 68% at December 31, 2014.

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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)	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)	Excludes the effects of $1,207 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.

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

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•	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 account our own credit rating, current credit spreads, as well as any change in such spreads since the last measurement date.

•

Liquidity valuation adjustments are necessary when we are not able to observe a recent market price for financial instruments that trade in less active markets for the fair value to reflect the cost of exiting the position. Exchange traded contracts are valued at market value without making any additional valuation adjustments and, therefore, no liquidity reserve is applied. For contracts other than exchange traded instruments, we mark our positions to the midpoint of the bid/ask spread, and record a liquidity reserve based upon our total net position. We believe that such practice results in the most reliable fair value measurement as viewed by a market participant.

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•	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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•	In the event that we or DCP Partners were to be downgraded below investment grade by at least one of the major credit rating agencies, certain of our ISDA counterparties would have the right to reduce our collateral threshold to zero, potentially requiring us to fully collateralize any commodity contracts in a net liability position.

•

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.

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(a)	Bbls represents barrels.

(b)	MMBtu represents one million British thermal units.

(c)	Includes 41 physical index based derivative contracts totaling (20,649,707) Bbls.

(d)	Includes 2 physical index based derivative contracts totaling (5,400,000) Bbls.

(e)	Includes 1 physical index based derivative contracts totaling (2,700,000) Bbls.

(a)	Includes 49 physical index based derivative contracts totaling (20,580,664) Bbls.

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