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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 from the sale of the residue natural gas and NGLs, or an agreed-upon percentage of the proceeds based on index-related prices for natural gas and NGLs regardless of the actual amount of sales proceeds which DCP Midstream receives. 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, crude oil and/or NGLs.

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Fee-based arrangements. DCP Midstream receives a fee or fees for one or more of the following services: gathering, processing, compressing, treating, storing or transporting 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 fees it would otherwise charge for gathering 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 flow through its systems and is not dependent on commodity prices. However, to the extent that a sustained decline in commodity prices results in a decline in volumes, DCP Midstream’s revenues from these arrangements could be reduced.

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Keep-whole and wellhead purchase arrangements. DCP Midstream gathers raw natural gas from producers for processing, the NGLs and condensate are sold and the residue natural gas is returned to the producer with a 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. 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. Under these types of contracts, DCP Midstream benefits in periods when NGL prices are higher relative to natural gas prices.

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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.

•	The Alberta Climate Change and Emissions Management 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.

•	The Alberta Environmental Protection and Enhancement Act which governing various aspects, including permitting and site remediation obligations.

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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 the earnings of Express-Platte that was acquired in March 2013 and expansion projects at Texas Eastern, partially offset by lower storage revenues,

•	Distribution’s earnings reflected lower transportation and storage revenues and higher employee benefit costs, partially offset by an increase in distribution rates, an adjustment in 2012 related to an unfavorable decision by the OEB affecting transportation revenues, and higher customer usage as a result of colder weather,

•	Western Canada Transmission & Processing’s earnings benefited mostly from higher NGL earnings at Empress due to lower production costs and higher sales prices in addition to higher earnings from expansions, partially offset by lower contracted volumes in the conventional gathering and processing business, and higher operating and maintenance costs, and

•	Field Services’ earnings reflected an increase in gains associated with the issuance of partnership units by DCP Partners and lower operating costs, partially offset by higher interest expense and the effects of asset dropdowns to DCP Partners.

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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 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

•	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 decrease in customer usage of natural gas largely due to warmer weather in 2012, lower natural gas prices passed through to customers, and an unexpected decision by OEB in 2012 affecting transportation revenues at Distribution,

•	lower NGL sales prices and volumes in the Empress NGL business and a decrease in contracted volumes in the conventional gathering and processing business at Western Canada Transmission & Processing, and

•	lower storage revenues, lower rates, contract reductions and lower processing revenues at Spectra Energy Partners, partially offset by

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

•	lower natural gas prices passed through to customers and lower natural gas purchased resulting from decreased volumes in natural gas sold primarily due to warmer weather in 2012, net of increased gas purchased due to growth in the number of customers at Distribution, and

•	lower equipment repairs and maintenance expenses, pipeline integrity costs, employee benefits and other costs, net of accelerated amortization of software at Spectra Energy Partners, partially offset by

•	higher depreciation and amortization from expansion projects placed in service at Western Canada Transmission & Processing and Spectra Energy Partners.

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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 $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 $51 million increase from expansion projects and the acquisition of Big Sandy in July 2011, and

•	a $12 million increase in recoveries of electric power and other costs passed through to customers, partially offset by

•	a $29 million decrease from lower storage revenues and contract reductions at Texas Eastern and Ozark Gas Transmission, and

•	a $24 million decrease in processing revenues associated with pipeline operations caused by lower prices.

•	a $32 million decrease due to lower equipment repairs and maintenance expenses, pipeline integrity costs, employee benefits and other costs, partially offset by accelerated software amortization, and

•	a $6 million decrease from project development costs expensed in 2011, partially offset by

•	a $12 million increase in electric power and other costs passed through to customers.

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•	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 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).

•	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 New York Mercantile Exchange (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 revenue, 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

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•	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

•	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 $114 million decrease in customer usage of natural gas primarily due to weather that was more than 10% warmer than in 2011,

•	a $92 million decrease from lower natural gas prices passed through to customers,

•	a $38 million decrease 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,

•	a $12 million decrease resulting from a weaker Canadian dollar, and

•	a $6 million decrease as a result of an unfavorable decision by the OEB affecting 2010 and 2011 storage revenues, partially offset by

•	a $60 million increase from growth in the number of customers,

•	an $18 million increase in short-term transportation service revenues, and

•	a $16 million increase due to lower earnings to be shared with customers.

•	a $92 million decrease from lower natural gas prices passed through to customers, and

•	an $88 million decrease due to lower volumes of natural gas sold primarily due to warmer weather, partially offset by

•	a $53 million increase from growth in the number of customers.

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•	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,

•	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 $134 million decrease due to lower NGL sales prices associated with the Empress NGL business,

•	a $46 million decrease in contracted volumes in the conventional gathering and processing business due to decontracting as a result of low natural gas prices and the effect of customers’ shift to unconventional developments,

•	a $28 million decrease due to lower NGL sales volumes associated with the Empress NGL business primarily as a result of warmer weather,

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

•	a $9 million decrease due to lower rates at M&N Canada, partially offset by

•	a $63 million increase in gathering and processing revenues due to contracted volumes from expansions associated with non-conventional supply discoveries in the Horn River and Montney areas of British Columbia,

•	a $16 million increase in transmission revenues primarily due to expansion,

•	a $10 million increase from recovery of British Columbia carbon tax and other non-income tax expense from customers, and

•	a $5 million increase due primarily to higher sales volumes of residual natural gas in the Empress NGL business.

•	a $14 million non-cash charge to reduce the book value of propane inventory at our Empress NGL business to estimated net realizable value, and

•	an $11 million increase in natural gas purchases for extraction at the Empress extraction facility primarily due to increased volumes, partially offset by

•	a $9 million decrease as a result of lower costs of natural gas purchased in the Empress NGL business caused primarily by lower extraction premiums,

•	an $8 million decrease due primarily to lower volumes of make-up gas purchases in the Empress NGL business as a result of lower NGL production, and

•	a $3 million decrease due to a weaker Canadian dollar.

•	an $18 million decrease due primarily to plant turnaround costs in 2011 that did not recur in the 2012 period,

•	an $11 million decrease due primarily to lower plant fuel and electricity costs at the Empress NGL business,

•	a $5 million decrease due to a weaker Canadian dollar, and

•	a $3 million decrease primarily in the costs passed through to customers at M&N Canada, partially offset by

•	a $14 million increase in maintenance costs for new and existing facilities mainly due to overhauls and deactivation of projects,

•	a $10 million increase in British Columbia carbon tax and other non-income tax expense, and

•	an $8 million increase in project development costs due primarily to LNG pipeline project development.

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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.

(f)	Average price based on NYMEX calendar month.

•	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

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•	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.

•	a $272 million decrease from commodity-sensitive processing arrangements due to decreased commodity prices,

•	a $27 million decrease primarily attributable to higher operating costs, largely resulting from a planned increase in repairs and maintenance activities due to asset growth, and

•	a $24 million decrease attributable to unfavorable results from gas and NGL marketing, partially offset by

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a $60 million increase due to decreased depreciation expense as a result of changes to the remaining useful lives of DCP Midstream’s gathering, transmission, processing, storage and other assets during the second quarter of 2012. The key contributing factor to the change was an increase in producers' estimated remaining economically recoverable commodity reserves, resulting from advances in extraction processes, such as hydraulic fracturing and horizontal drilling, as well as improved technology used to locate commodity reserves,

•	a $50 million increase in gathering and processing volumes, as a result of asset growth across certain geographic regions and the absence of severe weather which caused wellhead freeze-offs which shut in gas wells and reduced recoveries in 2011,

•	a $19 million increase in gains associated with the issuance of partnership units by DCP Partners,

•	a $10 million increase attributable to lower interest expense due to higher capitalized interest in 2012 as a result of growth, and

•	a $9 million increase in earnings from DCP Partners as a result of growth and mark-to-market gains on derivative instruments used to protect distributable cash flows.

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•	lower net tax payments in 2013, partially offset by

•	changes in working capital.

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•	lower distributions received from DCP Midstream, and

•	lower overall earnings.

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

•	$513 million of initial and subsequent equity investments in Sand Hills and Southern Hills in 2012,

•	a $110 million increase in capital expenditures in 2012, and

•	$130 million of net purchases of available-for-sale securities in 2012 compared to $190 million of net proceeds from sales and maturities in 2011, partially offset by

•	a $390 million cash outlay in 2011 for the acquisition of Big Sandy.

(a)	Excludes the $1,254 million net cash outlay for the acquisition of Express-Platte in 2013, $30 million paid in 2012 for amounts previously withheld from the purchase price consideration of the acquisition of Bobcat in 2010 and the $390 million acquisition of Big Sandy in 2011. See Note 3 of Notes to Consolidated Financial Statements for further discussions.

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

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•	Fort Nelson Expansion Program—The new 250 MMcf/d Fort Nelson North processing facility, which was the final phase and most significant capital outlay of the program, was placed into service during the first quarter of 2013.

•	Dawson Expansion—The development of a sour gas processing plant and an additional pipeline in western Canada. Phase I of 100 MMcf/d was placed into service in 2012 and Phase II for an additional 100 MMcf/d was placed into service during the first quarter of 2013.

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New Jersey-New York Expansion—An 800 MMcf/d expansion of the Texas Eastern pipeline system consisting of a new 16-mile pipeline extension into lower Manhattan, New York and other associated facility upgrades. The project is designed to transport gas produced in the U.S. Gulf Coast, Mid-Continent, Rockies and Marcellus Shale regions into New York City and was placed into service during the fourth quarter of 2013.

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Sand Hills—Approximately 720 miles of NGL pipeline constructed by DCP Midstream, with an initial capacity of 200,000 Bbls/d, transporting NGLs from the Permian Basin and Eagle Ford shale regions to NGL markets on the Gulf Coast. Phase I was completed in the fourth quarter of 2012, with initial service from the Eagle Ford shale region to Mont Belvieu. Phase II provides service from the Permian Basin to the Eagle Ford shale region. This project was placed into service during the second quarter of 2013.

•	Southern Hills—Approximately 800 miles of NGL pipeline also constructed by DCP Midstream, connecting several DCP Midstream processing plants and anticipated third-party producers, providing NGL transportation from the Mid-Continent to Mont Belvieu. This project was placed into service during the second quarter of 2013.

•	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. In-service is scheduled by the second half of 2014.

•	North Montney Expansion—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. In-service is scheduled by the first half of 2014.

•	Kingsport—An additional 86 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. Approximately 25 MMcf/d of the project was placed in service in November 2013 and the remainder is scheduled to be in-service in the first quarter of 2015.

•	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 for the fourth quarter of 2015.

•	Parkway—The Parkway West project includes the development of a greenfield site west of Toronto, the installation of a compressor unit and associated infrastructure. In addition, the Parkway D compressor, combined with the Brantford-Kirkwall pipeline loop, will provide growth volumes of 681 MMcf/d. These projects are due to be placed in-service throughout 2014 and 2015.

•	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 expected by the second quarter of 2017.

•	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

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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 Spectra Energy Corp's U.S. Assets Dropdown to SEP, 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.

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

•	a $299 million decrease in 2011 of SEP’s revolving credit facility borrowings outstanding, and

•	a $189 million increase in net long-term debt issuances in 2012.

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

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(a)	Revolving credit facility and term loan contain a covenant requiring the Spectra Energy Corp consolidated debt-to-total capitalization ratio, as defined in the agreements, to not exceed 65%. This ratio was 58% at December 31, 2013.

(b)	Term loan agreement allows for one borrowing prior to January 15, 2014.

(c)

Revolving credit facility contains a covenant that requires SEP to maintain a ratio of total Consolidated Indebtedness-to-Consolidated EBITDA, as defined in the credit agreement, of 5.0 or less, provided that for three fiscal quarters subsequent to certain acquisitions (such as the November 1, 2013 U.S. Assets Dropdown from Spectra Energy Corp), the ratio may be 5.5 or less. As of December 31, 2013, this ratio was 4.4 after giving effect to the U.S. Assets Dropdown.

(d)	U.S. dollar equivalent at December 31, 2013. The revolving credit facility is 300 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 44% at December 31, 2013.

(e)

U.S. dollar equivalent at December 31, 2013. The revolving credit facility is 400 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% at December 31, 2013.

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

(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, 2013.

(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 2014 retirement plan contributions and estimated 2014 payments related to uncertain tax positions, including interest (see Notes 6 and 25). We are unable to reasonably estimate the timing of uncertain tax positions and interest payments in years beyond 2014 due to uncertainties in the timing of cash settlements with taxing authorities and cannot estimate retirement plan contributions beyond 2014 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 2013, $30 million paid in 2012 for amounts previously withheld from the purchase price consideration of the acquisition of Bobcat in 2010 and the $390 million acquisition of Big Sandy in 2011, 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)	Recovery/refund is over the life of the associated asset or liability.

(e)	Recoverable in future periods.

(f)	Included in rate base.

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

(h)	Recovery/refund period currently unknown.

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

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

(k)	Included in Other Current Liabilities.

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

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(a)	Reflects revised assumptions regarding expected future costs of abandonments at Union Gas.

(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 9 days as of December 31, 2013 and 14 days as of December 31, 2012.

(b)	As of December 31, 2013 and 2012, respectively, $5,248 million and $5,560 million of debt was denominated in Canadian dollars.

(c)	Weighted-average rates on outstanding commercial paper were 0.6% as of December 31, 2013 and 0.8% as of December 31, 2012.

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(a)	Excludes commercial paper of $1,032 million.

(a)	Revolving credit facility and term loan contain a covenant requiring the Spectra Energy Corp consolidated debt-to-total capitalization ratio, as defined in the agreements, to not exceed 65%. This ratio was 58% at December 31, 2013.

(b)	Term loan agreement allows for one borrowing prior to January 15, 2014.

(c)

Revolving credit facility contains a covenant that requires SEP to maintain a ratio of total Consolidated Indebtedness-to-Consolidated EBITDA, as defined in the credit agreement, of 5.0 or less, provided that for three fiscal quarters subsequent to certain acquisitions (such as the November 1, 2013 U.S. Assets Dropdown from Spectra Energy Corp), the ratio may be 5.5 or less. As of December 31, 2013, this ratio was 4.4 after giving effect to the U.S. Asset Dropdown.

(d)	U.S. dollar equivalent at December 31, 2013. The revolving credit facility is 300 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 44% at December 31, 2013.

(e)

U.S. dollar equivalent at December 31, 2013. The revolving credit facility is 400 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% at December 31, 2013.

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

(b)	Excludes 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)	For the U.S. plans, amounts are reflected in Deferred Credits and Other Liabilities—Regulatory and Other in the Consolidated Balance Sheets. For the Canadian plans, amounts are reflected in Current Liabilities - Other ($6 million), Deferred Credits and Other Liabilities - Regulatory and Other ($130 million) and Other Assets - Other ($45 million).

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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 $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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(i)	Gregory L. Ebel*

(ii)	J. Patrick Reddy*

(iii)	Allen C. Capps*

(iv)	William T. Esrey*

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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 index prices from published indexes. 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 with 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 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 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 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)	Includes 49 physical index based derivative contracts totaling (20,580,664) Bbls.

(a)	Bbls represents barrels.

(b)	Includes 34 physical index based derivative contracts totaling (13,612,800) Bbls.

(c)	Includes 2 physical index based derivative contracts totaling (9,000,000) Bbls.

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