Edgar Filing: Spectra Energy Corp.

SE-2014.06.30 10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q



ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2014



¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 1-33007

SPECTRA ENERGY CORP

(Exact Name of Registrant as Specified in its Charter)



Delaware		20-5413139
(State or other jurisdiction of incorporation)		(IRS Employer Identification No.)

5400 Westheimer Court

Houston, Texas 77056

(Address of principal executive offices, including zip code)

713-627-5400

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of Exchange Act.

Large accelerated filer ý Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No ý

Number of shares of Common Stock, $0.001 par value, outstanding as of June 30, 2014: 670,893,796

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SPECTRA ENERGY CORP

FORM 10-Q FOR THE QUARTER ENDED

June 30, 2014

INDEX



		Page
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)	4
	Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2014 and 2013	4
	Condensed Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2014 and 2013	5
	Condensed Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013	6
	Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2014 and 2013	8
	Condensed Consolidated Statements of Equity for the six months ended June 30, 2014 and 2013	9
	Notes to Condensed Consolidated Financial Statements	10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	45
Item 4.	Controls and Procedures	45

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	46
Item 1A.	Risk Factors	46
Item 6.	Exhibits	46
	Signatures	47

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This document includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements represent management’s intentions, plans, expectations, assumptions and beliefs about future events. These forward-looking statements are identified by terms and phrases such as: anticipate, believe, intend, estimate, expect, continue, should, could, may, plan, project, predict, will, potential, forecast, and similar expressions. Forward-looking statements are subject to risks, uncertainties and other factors, many of which are outside our control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. Factors used to develop these forward-looking statements and that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:


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


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


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


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


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


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


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


•	the development of alternative energy resources;


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


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


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


•	growth in opportunities, including the timing and success of efforts to develop 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.

In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than Spectra Energy Corp has described. Spectra Energy Corp undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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PART I. FINANCIAL INFORMATION



Item 1.	Financial Statements.

SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In millions, except per-share amounts)



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Operating Revenues
Transportation, storage and processing of natural gas	$	780	$	766	$	1,667	$	1,566
Distribution of natural gas	309		283		935		908
Sales of natural gas liquids	40		65		227		177
Transportation of crude oil	70		67		141		80
Other	54		39		126		78
Total operating revenues	1,253		1,220		3,096		2,809
Operating Expenses
Natural gas and petroleum products purchased	209		167		737		632
Operating, maintenance and other	405		410		768		742
Depreciation and amortization	199		196		399		382
Property and other taxes	102		93		215		193
Total operating expenses	915		866		2,119		1,949
Operating Income	338		354		977		860
Other Income and Expenses
Equity in earnings of unconsolidated affiliates	85		72		246		182
Other income and expenses, net	6		22		15		55
Total other income and expenses	91		94		261		237
Interest Expense	176		160		354		309
Earnings Before Income Taxes	253		288		884		788
Income Tax Expense	65		62		229		192
Net Income	188		226		655		596
Net Income—Noncontrolling Interests	42		27		90		57
Net Income—Controlling Interests	$	146	$	199	$	565	$	539
Common Stock Data
Weighted-average shares outstanding
Basic	671		669		671		669
Diluted	673		671		672		671
Earnings per share
Basic	$	0.22	$	0.30	$	0.84	$	0.81
Diluted	$	0.22	$	0.30	$	0.84	$	0.80
Dividends per share	$	0.335	$	0.305	$	0.67	$	0.61

See Notes to Condensed Consolidated Financial Statements.

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SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(In millions)



	Three Months Ended June 30,					Six Months Ended June 30,
	2014		2013			2014			2013
Net Income	$	188	$	226		$	655		$	596
Other comprehensive income (loss)
Foreign currency translation adjustments	223		(251		)	(25		)	(440		)
Unrealized mark-to-market net gain on hedges	1		—			3			3
Reclassification of cash flow hedges into earnings	1		2			3			4
Pension and benefits impact (net of taxes of $3, $5, $6 and $9, respectively)	6		10			13			21
Other	—		(1		)	—			—
Total other comprehensive income (loss)	231		(240		)	(6		)	(412		)
Total Comprehensive Income (Loss), net of tax	419		(14		)	649			184
Less: Comprehensive Income—Noncontrolling Interests	45		25			89			52
Comprehensive Income (Loss)—Controlling Interests	$	374	$	(39	)	$	560		$	132

See Notes to Condensed Consolidated Financial Statements.

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SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)



	June 30, 2014		December 31, 2013
ASSETS

Current Assets
Cash and cash equivalents	$	300	$	201
Receivables, net	1,222		1,336
Inventory	277		263
Fuel tracker	165		28
Other	241		253
Total current assets	2,205		2,081

Investments and Other Assets
Investments in and loans to unconsolidated affiliates	2,803		3,043
Goodwill	4,841		4,810
Other	398		385
Total investments and other assets	8,042		8,238

Property, Plant and Equipment
Cost	29,223		28,456
Less accumulated depreciation and amortization	6,963		6,627
Net property, plant and equipment	22,260		21,829

Regulatory Assets and Deferred Debits	1,439		1,385

Total Assets	$	33,946	$	33,533

See Notes to Condensed Consolidated Financial Statements.

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SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions, except per-share amounts)



	June 30, 2014		December 31, 2013
LIABILITIES AND EQUITY

Current Liabilities
Accounts payable	$	518	$	440
Commercial paper	769		1,032
Taxes accrued	103		72
Interest accrued	193		201
Current maturities of long-term debt	496		1,197
Other	1,077		1,097
Total current liabilities	3,156		4,039

Long-term Debt	13,141		12,488

Deferred Credits and Other Liabilities
Deferred income taxes	5,223		4,968
Regulatory and other	1,423		1,457
Total deferred credits and other liabilities	6,646		6,425

Commitments and Contingencies

Preferred Stock of Subsidiaries	258		258

Equity
Preferred stock, $0.001 par, 22 million shares authorized, no shares outstanding	—		—
Common stock, $0.001 par, 1 billion shares authorized, 671 million and 670 million shares outstanding at June 30, 2014 and December 31, 2013, respectively	1		1
Additional paid-in capital	4,918		4,869
Retained earnings	2,497		2,383
Accumulated other comprehensive income	1,236		1,241
Total controlling interests	8,652		8,494
Noncontrolling interests	2,093		1,829
Total equity	10,745		10,323

Total Liabilities and Equity	$	33,946	$	33,533

See Notes to Condensed Consolidated Financial Statements.

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SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)



	Six Months Ended June 30,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	655		$	596
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	405			388
Deferred income tax expense	224			182
Equity in earnings of unconsolidated affiliates	(246		)	(182		)
Distributions received from unconsolidated affiliates	199			147
Other	(28		)	69
Net cash provided by operating activities	1,209			1,200
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(833		)	(959		)
Investments in and loans to unconsolidated affiliates	(30		)	(168		)
Acquisitions, net of cash acquired	—			(1,254		)
Purchases of held-to-maturity securities	(437		)	(456		)
Proceeds from sales and maturities of held-to-maturity securities	453			463
Purchases of available-for-sale securities	(13		)	(2,899		)
Proceeds from sales and maturities of available-for-sale securities	7			2,722
Distributions received from unconsolidated affiliates	242			13
Other changes in restricted funds	(1		)	1
Other	—			2
Net cash used in investing activities	(612		)	(2,535		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	712			1,848
Payments for the redemption of long-term debt	(736		)	(546		)
Net increase (decrease) in commercial paper	(256		)	440
Distributions to noncontrolling interests	(81		)	(69		)
Contributions from noncontrolling interests	112			—
Dividends paid on common stock	(453		)	(412		)
Proceeds from the issuance of Spectra Energy Partners, LP common units	191			190
Other	12			10
Net cash provided by (used in) financing activities	(499		)	1,461
Effect of exchange rate changes on cash	1			(3		)
Net increase in cash and cash equivalents	99			123
Cash and cash equivalents at beginning of period	201			94
Cash and cash equivalents at end of period	$	300		$	217
Supplemental Disclosures
Property, plant and equipment non-cash accruals	$	118		$	148

See Notes to Condensed Consolidated Financial Statements.

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SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(Unaudited)

(In millions)



	Common Stock		Additional Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income
	Common Stock		Additional Paid-in Capital			Retained Earnings			Foreign Currency Translation Adjustments			Other			Noncontrolling Interests			Total
December 31, 2013	$	1	$	4,869		$	2,383		$	1,557		$	(316	)	$	1,829		$	10,323
Net income	—		—			565			—			—			90			655
Other comprehensive income (loss)	—		—			—			(24		)	19			(1		)	(6		)
Dividends on common stock	—		—			(451		)	—			—			—			(451		)
Stock-based compensation	—		6			—			—			—			—			6
Distributions to noncontrolling interests	—		—			—			—			—			(81		)	(81		)
Contributions from noncontrolling interests	—		—			—			—			—			112			112
Spectra Energy common stock issued	—		9			—			—			—			—			9
Spectra Energy Partners, LP common units issued	—		29			—			—			—			144			173
Transfer of interests in subsidiaries to Spectra Energy Partners, LP	—		—			—			—			—			1			1
Other, net	—		5						—			—			(1		)	4
June 30, 2014	$	1	$	4,918		$	2,497		$	1,533		$	(297	)	$	2,093		$	10,745

December 31, 2012	$	1	$	5,297		$	2,165		$	2,044		$	(535	)	$	871		$	9,843
Net income	—		—			539			—			—			57			596
Other comprehensive income (loss)	—		—			—			(435		)	28			(5		)	(412		)
Dividends on common stock	—		—			(410		)	—			—			—			(410		)
Stock-based compensation	—		4			—			—			—			—			4
Distributions to noncontrolling interests	—		—			—			—			—			(69		)	(69		)
Spectra Energy common stock issued	—		10			—			—			—			—			10
Spectra Energy Partners, LP common units issued	—		38			—			—			—			128			166
Other, net			(2		)	—									3			1
June 30, 2013	$	1	$	5,347		$	2,294		$	1,609		$	(507	)	$	985		$	9,729

See Notes to Condensed Consolidated Financial Statements.

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SPECTRA ENERGY CORP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. General

The terms “we,” “our,” “us” and “Spectra Energy” as used in this report refer collectively to Spectra Energy Corp and its subsidiaries unless the context suggests otherwise. These terms are used for convenience only and are not intended as a precise description of any separate legal entity within Spectra Energy. The term “Spectra Energy Partners” refers to our Spectra Energy Partners operating segment. The term “SEP” refers to Spectra Energy Partners, LP, our master limited partnership.

Nature of Operations. Spectra Energy Corp, through its subsidiaries and equity affiliates, owns and operates a large and diversified portfolio of complementary natural gas-related energy assets, and owns and operates a crude oil pipeline system that connects Canadian and U.S. producers to refineries in the U.S. Rocky Mountain and Midwest regions. We currently operate in three key areas of the natural gas industry: gathering and processing, transmission and storage, and distribution. We provide transmission and storage of natural gas to customers in various regions of the northeastern and southeastern United States, the Maritime Provinces in Canada, the Pacific Northwest in the United States and Canada, and in the province of Ontario, Canada. We also provide natural gas sales and distribution services to retail customers in Ontario, and natural gas gathering and processing services to customers in western Canada. We also own a 50% interest in DCP Midstream, LLC (DCP Midstream), based in Denver, Colorado, one of the leading natural gas gatherers in the United States based on wellhead volumes, and one of the largest U.S. producers and marketers of natural gas liquids (NGLs).

Basis of Presentation. The accompanying Condensed Consolidated Financial Statements include our accounts and the accounts of our majority-owned subsidiaries, after eliminating intercompany transactions and balances. These interim financial statements should be read in conjunction with the consolidated financial statements included in our Annual Report on Form

10-K for the year ended December 31, 2013, and reflect all normal recurring adjustments that are, in our opinion, necessary to fairly present our results of operations and financial position. Amounts reported in the Condensed Consolidated Statements of Operations are not necessarily indicative of amounts expected for the respective annual periods due to the effects of seasonal temperature variations on energy consumption, primarily in our gas distribution operations, as well as changing commodity prices on certain of our processing operations and other factors.

Use of Estimates. To conform with generally accepted accounting principles (GAAP) in the United States, we make estimates and assumptions that affect the amounts reported in the Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements. Although these estimates are based on our best available knowledge at the time, actual results could differ.

2. Acquisition of Express-Platte

In March 2013, we acquired 100% of the ownership interests in the Express-Platte crude oil pipeline system for $1.5 billion, consisting of $1.25 billion in cash and $260 million of acquired debt, before working capital adjustments. The Express-Platte pipeline system, which begins in Hardisty, Alberta, and terminates in Wood River, Illinois, is comprised of both the Express and Platte crude oil pipelines. The Express pipeline carries crude oil to U.S. refining markets in the Rockies area, including Montana, Wyoming, Colorado and Utah. The Platte pipeline, which interconnects with Express pipeline in Casper, Wyoming, transports crude oil predominantly from the Bakken shale and western Canada to refineries in the Midwest. In 2013, subsidiaries of Spectra Energy contributed a 100% interest in the U.S. portion of Express-Platte and sold a 100% ownership interest in the Canadian portion to SEP.

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The following table summarizes the fair values of the assets and liabilities acquired as of the date of the acquisition.



	Purchase Price Allocation
	(in millions)
Cash purchase price	$	1,250
Working capital and other purchase adjustments	71
Total	1,321
Cash	67
Receivables	25
Other current assets	9
Property, plant and equipment	1,251
Accounts payable	(18		)
Other current liabilities	(17		)
Deferred credits and other liabilities	(259		)
Long-term debt, including current portion	(260		)
Total assets acquired/liabilities assumed	798
Goodwill	$	523

The purchase price is greater than the sum of fair values of the net assets acquired, resulting in goodwill as noted above. The goodwill reflects the value of the strategic location of the pipeline and the opportunity to grow the business. Goodwill related to the acquisition of Express-Platte is not deductible for income tax purposes.

The allocation of the fair values of assets and liabilities acquired related to the acquisition of Express-Platte was finalized in the first quarter of 2014, resulting in the following adjustments to amounts reported as of December 31, 2013: a $60 million decrease in Property, Plant and Equipment, a $1 million decrease in Other Current Assets and a $24 million decrease in Deferred Credits and Other Liabilities, resulting in a $37 million increase in Goodwill.

Pro forma results of operations that reflect the acquisition of Express-Platte as if the acquisition had occurred as of the beginning of 2013 are not presented as they do not materially differ from actual results reported in our Condensed Consolidated Statements of Operations.

3. Business Segments

In November 2013, Spectra Energy contributed substantially all of its remaining U.S. transmission, storage and liquids assets to SEP (the U.S. Assets Dropdown). As a result of this transaction, we realigned our reportable segments structure. Amounts presented herein for 2013 segment information have been recast to conform to our current segment reporting presentation. There were no changes to consolidated data as a result of the recast of our segment information.

We manage our business in four reportable segments: Spectra Energy Partners, Distribution, Western Canada Transmission & Processing and Field Services. The remainder of our business operations is presented as “Other,” and consists of unallocated corporate costs and employee benefit plan assets and liabilities, 100%-owned captive insurance subsidiaries and other miscellaneous activities.

Our chief operating decision maker (CODM) regularly reviews financial information about each of these segments in deciding how to allocate resources and evaluate performance. There is no aggregation within our reportable business segments.

The presentation of our Spectra Energy Partners segment is reflective of the parent-level focus by our CODM, considering the resource allocation and governance provisions associated with SEP’s master limited partnership structure. SEP maintains a capital and cash management structure that is separate from Spectra Energy’s, is self-funding and maintains its own lines of bank credit and cash management accounts. It is in this context that our CODM evaluates the Spectra Energy Partners segment as a whole, without regard to any of SEP’s individual businesses. These factors, coupled with a different cost of capital of our other businesses, serve to differentiate how our Spectra Energy Partners segment is managed as compared to how SEP is managed.

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Spectra Energy Partners provides transmission, storage and gathering of natural gas, as well as the transportation of crude oil and natural gas liquids (NGLs) through interstate pipeline systems for customers in various regions of the midwestern, northeastern and southeastern United States and Canada. The natural gas transmission and storage operations are primarily subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC). The crude oil transportation operations are primarily subject to regulation by the FERC in the U.S. and the National Energy Board (NEB) in Canada. Our Spectra Energy Partners segment is composed of the operations of SEP, less governance costs, which are included in “Other.”

Distribution provides retail natural gas distribution service in Ontario, Canada, as well as natural gas transmission and storage services to other utilities and energy market participants. These services are provided by Union Gas Limited (Union Gas), and are primarily subject to the rules and regulations of the Ontario Energy Board (OEB).

Western Canada Transmission & Processing provides transmission of natural gas, natural gas gathering and processing services, and NGL extraction, fractionation, transportation, storage and marketing to customers in western Canada, the northern tier of the United States and the Maritime Provinces in Canada. This segment conducts business mostly through BC Pipeline, BC Field Services, and the NGL marketing and Canadian Midstream businesses, and Maritimes & Northeast Pipeline Limited Partnership (M&N Canada). BC Pipeline and BC Field Services operations are primarily subject to the rules and regulations of the NEB.

Field Services gathers, compresses, treats, processes, transports, stores and sells natural gas, produces, fractionates, transports, stores and sells NGLs, and recovers and sells condensate. In addition, Field Services trades and markets natural gas and NGLs. It conducts operations through DCP Midstream, which is owned 50% by us and 50% by Phillips 66. DCP Midstream gathers raw natural gas through gathering systems located in nine major conventional and non-conventional natural gas producing regions: Mid-Continent, Rocky Mountain, East Texas-North Louisiana, Barnett Shale, Gulf Coast, South Texas, Central Texas, Antrim Shale and Permian Basin. DCP Midstream Partners, LP (DCP Partners) is a publicly-traded master limited partnership, of which DCP Midstream acts as general partner. As of June 30, 2014, DCP Midstream had an approximate 22% ownership interest in DCP Partners, including DCP Midstream’s limited partner and general partner interests.

Our reportable segments offer different products and services and are managed separately as business units. Management evaluates segment performance based on earnings from continuing operations before interest, taxes, and depreciation and amortization (EBITDA). Cash, cash equivalents and short-term investments are managed at the parent-company levels, so the associated gains and losses from foreign currency transactions, and interest and dividend income are excluded from the segments’ EBITDA. Our segment EBITDA may not be comparable to similarly titled measures of other companies because other companies may not calculate EBITDA in the same manner. Transactions between reportable segments are accounted for on the same basis as transactions with unaffiliated third parties.

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Business Segment Data



Condensed Consolidated Statements of Operations
	Unaffiliated Revenues		Intersegment Revenues			Total Operating Revenues			Depreciation and Amortization		Segment EBITDA/ Consolidated Earnings before Income Taxes
	(in millions)
Three Months Ended June 30, 2014
Spectra Energy Partners	$	531	$	—		$	531		$	72	$	374
Distribution	360		—			360			48		112
Western Canada Transmission & Processing	360		31			391			68		111
Field Services	—		—			—			—		54
Total reportable segments	1,251		31			1,282			188		651
Other	2		17			19			11		(24		)
Eliminations	—		(48		)	(48		)	—		—
Depreciation and amortization	—		—			—			—		199
Interest expense	—		—			—			—		176
Interest income and other	—		—			—			—		1
Total consolidated	$	1,253	$	—		$	1,253		$	199	$	253

Three Months Ended June 30, 2013
Spectra Energy Partners	$	492	$	—		$	492		$	65	$	358
Distribution	352		—			352			51		115
Western Canada Transmission & Processing	373		18			391			70		157
Field Services	—		—			—			—		46
Total reportable segments	1,217		18			1,235			186		676
Other	3		15			18			10		(29		)
Eliminations	—		(33		)	(33		)	—		—
Depreciation and amortization	—		—			—			—		196
Interest expense	—		—			—			—		160
Interest income and other	—		—			—			—		(3		)
Total consolidated	$	1,220	$	—		$	1,220		$	196	$	288

Six Months Ended June 30, 2014
Spectra Energy Partners	$	1,112	$	—		$	1,112		$	145	$	803
Distribution	1,078		—			1,078			97		338
Western Canada Transmission & Processing	901		65			966			135		348
Field Services	—		—			—			—		184
Total reportable segments	3,091		65			3,156			377		1,673
Other	5		32			37			22		(41		)
Eliminations	—		(97		)	(97		)	—		—
Depreciation and amortization	—		—			—			—		399
Interest expense	—		—			—			—		354
Interest income and other	—		—			—			—		5
Total consolidated	$	3,096	$	—		$	3,096		$	399	$	884

Six Months Ended June 30, 2013
Spectra Energy Partners	$	951	$	—		$	951		$	126	$	705
Distribution	1,051		—			1,051			102		335
Western Canada Transmission & Processing	801		33			834			134		347
Field Services	—		—			—			—		134
Total reportable segments	2,803		33			2,836			362		1,521
Other	6		30			36			20		(43		)
Eliminations	—		(63		)	(63		)	—		—
Depreciation and amortization	—		—			—			—		382
Interest expense	—		—			—			—		309
Interest income and other	—		—			—			—		1
Total consolidated	$	2,809	$	—		$	2,809		$	382	$	788

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4. Regulatory Matters

Union Gas. In January 2014, Union Gas filed a notice of motion seeking leave to appeal to the Ontario Court of Appeal (Court of Appeal) for the unsuccessful appeal to the Ontario Divisional Court on the OEB’s treatment of 2011 revenues derived from the optimization of our upstream transportation contracts. A decision from the Court of Appeal on the notice of motion was issued in April 2014 granting leave to appeal. In May 2014, Union Gas filed a notice of appeal and a hearing is scheduled for December 2014.

Union Gas filed an application with the OEB in May 2013 for the annual disposition of the 2012 non-commodity deferral account balances. A decision on that application was issued by the OEB in March 2014. Among other things, the OEB determined that revenues derived from the optimization of Union Gas’ upstream transportation contracts in 2012 will be treated as revenues and included in utility earnings instead of a reduction to gas costs. The decision also denied a proposal to recover certain over-refunds to customers and reduced incentive amounts related to Union Gas’ 2011 energy conservation program. As a result of this OEB decision, Union Gas recognized pre-tax income of $10 million in the first quarter of 2014, comprised of a $32 million increase in Transportation, Storage and Processing of Natural Gas revenues, a $15 million decrease in Distribution of Natural Gas revenues and a $7 million decrease in Other revenues on the Condensed Consolidated Statements of Operations. In addition, the decision also approved the deferral of pension expense for recovery from customers, resulting in pre-tax income of $7 million, recorded as a reduction in Operating, Maintenance and Other expense in the second quarter of 2014.

On May 2, 2014, Union Gas filed an application with the OEB for the annual disposition of its 2013 non-commodity deferral account balances. The combined impact is a net payable to customers of approximately $21 million which is primarily reflected as Current Liabilities—Other on the Condensed Consolidated Balance Sheets at June 30, 2014. A hearing and decision from the OEB is expected later this year.

5. Income Taxes

Income tax expense was $65 million for the three months ended June 30, 2014, compared with $62 million for the same period in 2013. The higher tax expense was driven by the reversal of tax reserves in the 2013 period as a result of favorable Canadian federal income tax legislation enacted in the second quarter of 2013, mostly offset by lower Canadian earnings in 2014.

Income tax expense was $229 million for the six months ended June 30, 2014, compared with $192 million for the same period in 2013. The higher tax expense was driven primarily by higher earnings and the reversal of tax reserves in the 2013 period.

The effective income tax rate for the three months ended June 30, 2014 and 2013 was 26% and 22%, respectively, and 26% and 24% for the six-month periods, respectively. The lower effective tax rates in the 2013 periods resulted primarily from the reversal of tax reserves in the second quarter of 2013.

There was no material net change in unrecognized tax benefits recorded during the six-month period ended June 30, 2014. Although uncertain, we believe it is reasonably possible that the total amount of unrecognized tax benefits could decrease by approximately $15 million to $20 million prior to June 30, 2015.

In September 2013, the U.S. Treasury and the Internal Revenue Service (IRS) issued final regulations regarding the deduction and capitalization of expenditures related to tangible property (tangible property regulations). The final IRS regulations apply to amounts paid to acquire, produce, or improve tangible property as well as dispositions of such property and are for tax years beginning on or after January 1, 2014. We are currently evaluating the tangible property regulations and awaiting the release of additional regulations and industry specific guidance. Any changes resulting from the tangible property regulations will affect the timing of deducting expenditures for tax purposes and the impact will be reflected in income tax payable or receivable, deferred taxes and cash paid for income taxes. Our earnings will not be impacted.

6. Earnings per Common Share

Basic earnings per common share (EPS) is computed by dividing net income from controlling interests by the weighted-average number of common shares outstanding during the period. Diluted EPS is computed by dividing net income from controlling interests by the diluted weighted-average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock, such as stock options, stock-based performance unit awards and phantom stock awards, were exercised, settled or converted into common stock.

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The following table presents our basic and diluted EPS calculations:



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	(in millions, except per-share amounts)

Net income—controlling interests	$	146	$	199	$	565	$	539
Weighted-average common shares outstanding
Basic	671		669		671		669
Diluted	673		671		672		671
Basic earnings per common share (a)	$	0.22	$	0.30	$	0.84	$	0.81
Diluted earnings per common share (a)	$	0.22	$	0.30	$	0.84	$	0.80

—————

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

rounding.

7. Accumulated Other Comprehensive Income

The following table presents the net of tax changes in Accumulated Other Comprehensive Income (AOCI) by component and amounts reclassified out of AOCI to Net Income, excluding amounts attributable to noncontrolling interests:



	Foreign Currency Translation Adjustments			Pension and Post-retirement Benefit Plan Obligations				Gas Purchase Contract Hedges			Other			Total Accumulated Other Comprehensive Income
							(in millions)
March 31, 2014	$	1,313		$	(297	)		$	(7	)	$	(1	)	$	1,008
Reclassified to net income	—			—				—			1			1
Other AOCI activity	220			6				1			—			227
June 30, 2014	$	1,533		$	(291	)		$	(6	)	$	—		$	1,236

March 31, 2013	$	1,858		$	(496	)		$	(18	)	$	(4	)	$	1,340
Reclassified to net income	—			—				1			1			2
Other AOCI activity	(249		)	10				—			(1		)	(240		)
June 30, 2013	$	1,609		$	(486	)		$	(17	)	$	(4	)	$	1,102

December 31, 2013	$	1,557		$	(304	)		$	(11	)	$	(1	)	$	1,241
Reclassified to net income	—			—				2			1			3
Other AOCI activity	(24		)	13				3			—			(8		)
June 30, 2014	$	1,533		$	(291	)		$	(6	)	$	—		$	1,236

December 31, 2012	$	2,044		$	(507	)		$	(23	)	$	(5	)	$	1,509
Reclassified to net income	—			—				3			1			4
Other AOCI activity	(435		)	21				3			—			(411		)
June 30, 2013	$	1,609		$	(486	)		$	(17	)	$	(4	)	$	1,102

Reclassifications to Net Income are primarily included in Other Income and Expenses, Net on our Condensed Consolidated Statements of Operations.

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8. Inventory

Inventory consists of natural gas and NGLs held in storage for transmission and processing, and also includes materials and supplies. Natural gas inventories primarily relate to the Distribution segment in Canada and are valued at costs approved by the OEB. The difference between the approved price and the actual cost of gas purchased is recorded as either a receivable or a current liability, as appropriate, for future disposition with customers, subject to approval by the OEB. The remaining inventory is recorded at the lower of cost or market, primarily using average cost. The components of inventory are as follows:



	June 30, 2014		December 31, 2013
	(in millions)
Natural gas	$	166	$	155
NGLs	33		30
Materials and supplies	78		78
Total inventory	$	277	$	263

9. Investments in and Loans to Unconsolidated Affiliates

Our most significant investment in unconsolidated affiliates is our 50% investment in DCP Midstream, which is accounted for under the equity method of accounting. The following represents summary financial information for DCP Midstream, presented at 100%:



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	(in millions)
Operating revenues	$	3,541	$	2,861	$	7,456	$	5,473
Operating expenses	3,387		2,671		7,032		5,121
Operating income	154		190		424		352
Net income	92		142		295		262
Net income attributable to members’ interests	89		78		254		169

DCP Partners issues, from time to time, limited partner units to the public, which are recorded by DCP Midstream directly to its equity. Our proportionate share of gains from those issuances, totaling $9 million and $7 million in the second quarters of 2014 and 2013, respectively, and $57 million and $50 million during the six-month periods ended June 30, 2014 and 2013, respectively, are reflected in Equity in Earnings of Unconsolidated Affiliates in the Condensed Consolidated Statements of Operations.

10. Goodwill

We perform our goodwill impairment test annually and evaluate goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. We completed our annual goodwill impairment test as of April 1, 2014 and no impairments were identified.

We perform our annual review for goodwill impairment at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete financial information is available, whether segment management regularly reviews the operating results of those components and whether the economic and regulatory characteristics are similar. We determined that our reporting units are equivalent to our reportable segments, except for the reporting units of our Western Canada Transmission & Processing reportable segment and our Spectra Energy Partners reportable segment, which are one level below.

As permitted under accounting guidance on testing goodwill for impairment, we perform either a qualitative assessment or a quantitative assessment of each of our reporting units based on management’s judgment. With respect to our qualitative assessments, we consider events and circumstances specific to us, such as macroeconomic conditions, industry and market considerations, cost factors and overall financial performance, when evaluating whether it is more likely than not that the fair values of our reporting units are less than their respective carrying amounts.

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The following presents changes in goodwill during 2014:



	Goodwill
	(in millions)
December 31, 2013	$	4,810
Acquisition of Express-Platte	37
Foreign currency translation	(6		)
June 30, 2014	$	4,841

See Note 2 for discussion of the acquisition of Express-Platte and an adjustment to Goodwill recorded in the first quarter of 2014 related to the acquisition.

11. Marketable Securities and Restricted Funds

We routinely invest excess cash and various restricted balances in securities such as commercial paper, bankers acceptances, corporate debt securities, treasury bills and money market funds in the United States and Canada. We do not purchase marketable securities for speculative purposes, therefore we do not have any securities classified as trading securities. While we do not routinely sell marketable securities prior to their scheduled maturity dates, some of our investments may be held and restricted for insurance purposes, so these investments are classified as available-for-sale (AFS) marketable securities as they may occasionally be sold prior to their scheduled maturity dates due to the unexpected timing of cash needs. Initial investments in securities are classified as purchases of the respective type of securities (AFS marketable securities or held-to-maturity (HTM) marketable securities). Maturities of securities are classified within proceeds from sales and maturities of securities in the Condensed Consolidated Statements of Cash Flows.

AFS Securities. AFS securities are as follows:



	Estimated Fair Value
	June 30, 2014		December 31, 2013
	(in millions)
Corporate debt securities	$	24	$	18
Money market funds	1		1
Total available-for-sale securities	$	25	$	19

Our AFS securities are classified on the Condensed Consolidated Balance Sheets as follows:



	Estimated Fair Value
	June 30, 2014		December 31, 2013
	(in millions)
Restricted funds
Investments and other assets—other	$	1	$	1
Non-restricted funds
Current assets—other	—		7
Investments and other assets—other	24		11
Total available-for-sale securities	$	25	$	19

At June 30, 2014, the weighted-average contractual maturity of outstanding AFS securities was two years.

There were no material gross unrealized holding gains or losses associated with investments in AFS securities at June 30, 2014 or December 31, 2013.

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HTM Securities. All of our HTM securities are restricted funds and are as follows:



		Estimated Fair Value
Description	Condensed Consolidated Balance Sheet Caption	June 30, 2014		December 31, 2013
		(in millions)
Bankers acceptances	Current assets—other	$	35	$	35
Canadian government securities	Current assets—other	33		34
Money market funds	Current assets—other	4		3
Canadian government securities	Investments and other assets—other	125		131
Bankers acceptances	Investments and other assets—other	—		10
Total held-to-maturity securities		$	197	$	213

All of our HTM securities are restricted funds pursuant to certain M&N Canada and Express-Platte debt agreements. The funds restricted for M&N Canada, plus future cash from operations that would otherwise be available for distribution to the partners of M&N Canada, are required to be placed in escrow until the balance in escrow is sufficient to fund all future debt service on the M&N Canada 6.90% senior secured notes. There are sufficient funds held in escrow to fund all future debt service on these M&N Canada notes.

At June 30, 2014, the weighted-average contractual maturity of outstanding HTM securities was one year.

There were no material gross unrecognized holding gains or losses associated with investments in HTM securities at June 30, 2014 or December 31, 2013.

Other Restricted Funds. In addition to the portions of the AFS and HTM securities that were restricted funds as described above, we had other restricted funds totaling $20 million at June 30, 2014 and $19 million at December 31, 2013 classified as Current Assets—Other. These restricted funds are related to additional amounts for the M&N Canada debt service requirements and insurance.

Changes in restricted funds’ balances are presented within Cash Flows from Investing Activities on our Condensed Consolidated Statements of Cash Flows.

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12. Debt and Credit Facilities

Available Credit Facilities and Restrictive Debt Covenants



	Expiration Date	Total Credit Facilities Capacity		Commercial Paper Outstanding at June 30, 2014		Available Credit Facilities Capacity
	Expiration Date	Total Credit Facilities Capacity		Commercial Paper Outstanding at June 30, 2014		Available Credit Facilities Capacity
		(in millions)
Spectra Energy Capital, LLC (a)	2018	$	1,000	$	220	$	780
SEP (b)	2018	2,000		549		1,451
Westcoast Energy Inc. (c)	2016	281		—		281
Union Gas (d)	2016	375		—		375
Total		$	3,656	$	769	$	2,887

___________


(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 56% at June 30, 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 credit agreement, of 5.0 to 1 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 to 1 or less. As of June 30, 2014, this ratio was 3.9 to 1 after giving effect to the U.S. Assets Dropdown.


(c)	U.S. dollar equivalent at June 30, 2014. The revolving credit facility is 300 million Canadian dollars and contains a covenant that requires the Westcoast Energy Inc. non-consolidated debt-to-total capitalization ratio to not exceed 75%. The ratio was 41% at June 30, 2014.


(d)	U.S. dollar equivalent at June 30, 2014. 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 65% at June 30, 2014.

The issuances of commercial paper, letters of credit and revolving borrowings reduce the amount available under the credit facilities. As of June 30, 2014, there were no letters of credit issued or revolving borrowings outstanding under the credit facilities.

Our credit agreements contain various covenants, including the maintenance of certain financial ratios. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of June 30, 2014, we were in compliance with those covenants. In addition, our credit agreements allow for acceleration of payments or termination of the agreements due to nonpayment, or in some cases, due to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. Our debt and credit agreements do not contain provisions that trigger an acceleration of indebtedness based solely on the occurrence of a material adverse change in our financial condition or results of operations.

Debt Issuances. On June 2, 2014, Union Gas issued 200 million Canadian dollars (approximately $183 million as of the issuance date) of 2.76% unsecured notes due 2021 and 250 million Canadian dollars (approximately $229 million as of the issuance date) of 4.20% unsecured notes due 2044. Net proceeds from the offerings were used for general corporate purposes.

In January 2014, Spectra Energy Capital, LLC (Spectra Capital) borrowed the full $300 million available under its unsecured term loan agreement. Interest on the borrowing is based on LIBOR (London Interbank Offered Rate) and the borrowing is due in 2018. Net proceeds from the borrowing were used for general corporate purposes.

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13. Fair Value Measurements

The following presents, for each of the fair value hierarchy levels, assets and liabilities that are measured and recorded at fair value on a recurring basis:



Description	Condensed Consolidated Balance Sheet Caption	June 30, 2014
Description	Condensed Consolidated Balance Sheet Caption	Total		Level 1		Level 2		Level 3
		(in millions)
Corporate debt securities	Cash and cash equivalents	$	73	$	—	$	73	$	—
Banker acceptances	Cash and cash equivalents	3		—		3		—
Interest rate swaps	Current assets—other	4		—		4		—
Corporate debt securities	Investments and other assets—other	24		—		24		—
Interest rate swaps	Investments and other assets—other	19		—		19		—
Money market funds	Investments and other assets—other	1		1		—		—
Total Assets		$	124	$	1	$	123	$	—
Commodity derivatives	Current liabilities—other	$	6	$	—	$	—	$	6
Interest rate swaps	Current liabilities—other	3		—		3		—
Natural gas purchase contracts	Deferred credits and other liabilities—regulatory and other	1		—		—		1
Commodity derivatives	Deferred credits and other liabilities—regulatory and other	2		—		—		2
Total Liabilities		$	12	$	—	$	3	$	9



Description	Condensed Consolidated Balance Sheet Caption	December 31, 2013
Description	Condensed Consolidated Balance Sheet Caption	Total		Level 1		Level 2		Level 3
		(in millions)
Corporate debt securities	Cash and cash equivalents	$	49	$	—	$	49	$	—
Corporate debt securities	Current assets—other	7		—		7		—
Interest rate swaps	Current assets—other	8		—		8		—
Corporate debt securities	Investments and other assets—other	11		—		11		—
Interest rate swaps	Investments and other assets—other	15		—		15		—
Money market funds	Investments and other assets—other	1		1		—		—
Total Assets		$	91	$	1	$	90	$	—
Natural gas purchase contracts	Deferred credits and other liabilities—regulatory and other	$	3	$	—	$	—	$	3
Interest rate swaps	Deferred credits and other liabilities—regulatory and other	6		—		6		—
Total Liabilities		$	9	$	—	$	6	$	3

The following presents changes in Level 3 liabilities that are measured at fair value on a recurring basis using significant unobservable inputs:



	Three Months Ended June 30,					Six Months Ended June 30,
	2014			2013		2014			2013
	(in millions)
Derivative liabilities
Fair value, beginning of period	$	5		$	6	$	3		$	9
Total realized/unrealized losses (gains):
Included in earnings	5			—		9			1
Included in other comprehensive income	(1		)	—		(4		)	(4		)
Settlements	—			—		1			—
Fair value, end of period	$	9		$	6	$	9		$	6
Total losses for the period included in earnings (or changes in net assets) attributable to the change in unrealized gains or losses relating to liabilities held at the end of the period	$	4		$	—	$	7		$	1

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Level 1

Level 1 valuations represent quoted unadjusted prices for identical instruments in active markets.

Level 2 Valuation Techniques

Fair values of our financial instruments that are actively traded in the secondary market, including our long-term debt, are determined based on market-based prices. These valuations may include inputs such as quoted market prices of the exact or similar instruments, broker or dealer quotations, or alternative pricing sources that may include models or matrix pricing tools, with reasonable levels of price transparency.

For interest rate swaps, we utilize data obtained from a third-party source for the determination of fair value. Both the future cash flows for the fixed-leg and floating-leg of our swaps are discounted to present value. In addition, credit default swap rates are used to develop the adjustment for credit risk embedded in our positions. We believe that since some of the inputs and assumptions for the calculations of fair value are derived from observable market data, a Level 2 classification is appropriate.

Level 3 Valuation Techniques

We do not have significant amounts of assets or liabilities measured and reported using Level 3 valuation techniques, which include the use of pricing models, discounted cash flow methodologies or similar techniques where at least one significant model assumption or input is unobservable. Level 3 financial instruments also include those for which the determination of fair value requires significant management judgment or estimation.

For natural gas purchases contracts and commodity derivatives, we utilize data obtained from third-party sources for the determination of fair value. The expected future cash flows arising from our swaps are discounted to present value. In addition, credit default swap rates or historical average credit default rates by credit rating are used to develop the adjustment for credit risk embedded in our positions. As these transactions are limited, we believe a Level 3 classification is appropriate.

Financial Instruments

The fair values of financial instruments that are recorded and carried at book value are summarized in the following table. Judgment is required in interpreting market data to develop the estimates of fair value. These estimates are not necessarily indicative of the amounts we could have realized in current markets.



	June 30, 2014				December 31, 2013
	Book Value		Approximate Fair Value		Book Value		Approximate Fair Value
	(in millions)
Note receivable, noncurrent (a)	$	71	$	71	$	71	$	71
Long-term debt, including current maturities (b)	13,625		15,226		13,668		14,701

__________


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


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

The fair value of our long-term debt is determined based on market-based prices as described in the Level 2 valuation technique described above and is classified as Level 2.

The fair values of cash and cash equivalents, restricted cash, short-term investments, accounts receivable, note receivable-noncurrent, accounts payable and commercial paper are not materially different from their carrying amounts because of the short-term nature of these instruments or because the stated rates approximate market rates.

During the 2014 and 2013 periods, there were no material adjustments to assets and liabilities measured at fair value on a nonrecurring basis.

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14. Risk Management and Hedging Activities

We are exposed to the impact of market fluctuations in the prices of NGLs and natural gas purchased as a result of our investment in DCP Midstream, the ownership of the NGL marketing operations in western Canada and processing associated with our U.S. pipeline assets. Exposure to interest rate risk exists as a result of the issuance of variable and fixed-rate debt and commercial paper. We are exposed to foreign currency risk from our Canadian operations. We employ established policies and procedures to manage our risks associated with these market fluctuations, which may include the use of derivatives, mostly around interest rate and commodity exposures.

DCP Midstream manages their direct exposure to market prices separate from Spectra Energy, and utilizes various risk management strategies, including the use of commodity derivatives.

Other than interest rate swaps and commodity derivatives described below, we did not have any significant derivatives outstanding during the six months ended June 30, 2014.

Interest Rate Swaps

At June 30, 2014, we had “pay floating—receive fixed” interest rate swaps outstanding with a total notional principal amount of $1,617 million to hedge against changes in the fair value of our fixed-rate debt that arise as a result of changes in market interest rates. These swaps also allow us to transform a portion of the underlying interest payments related to our long-term fixed-rate debt securities into variable-rate interest payments in order to achieve our desired mix of fixed and variable-rate debt.

Information about our interest rate swaps that had netting or rights of offset arrangements are as follows:



	June 30, 2014						December 31, 2013
	Gross Amounts Presented in the Condensed Consolidated Balance Sheets		Amounts Not Offset in the Condensed Consolidated Balance Sheets		Net Amount		Gross Amounts Presented in the Condensed Consolidated Balance Sheets		Amounts Not Offset in the Condensed Consolidated Balance Sheets		Net Amount
Description	(in millions)
Assets	$	23	$	2	$	21	$	23	$	3	$	20
Liabilities	3		2		1		6		3		3

At June 30, 2014, we had interest rate swaps with another counterparty which were in a liability position of $2 million which could be terminated by the counterparty if one of our credit ratings falls below investment grade. In addition, we had one interest rate swap with a counterparty which was in a liability position of $1 million which could be terminated at any time.

Commodity Derivatives

Effective January 2014, we instituted a commodity price risk management program at Western Canada Transmission & Processing’s Empress NGL business and elected to not apply cash flow hedge accounting.

At June 30, 2014, we had commodity mark-to-market derivatives outstanding with a total notional amount of 129 million gallons. The longest dated commodity derivative contract we currently have expires in 2017.

Information about our commodity derivatives that had netting or rights of offset arrangements are as follows:



	June 30, 2014
	Gross Amounts		Gross Amounts Offset		Net Amount Presented in the Condensed Consolidated Balance Sheets
Description	(in millions)
Assets	$	140	$	140	$	—
Liabilities	148		140		8

Substantially all of our commodity derivative agreements outstanding at June 30, 2014 have provisions that require collateral to be posted in the amount of the net liability position if one of our credit ratings falls below investment grade.

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Information regarding the impacts of commodity derivatives on our Condensed Consolidated Statements of Operations are as follows:



		Periods Ended June 30, 2014
Derivatives	Condensed Consolidated Statement of Operations Caption	Three Months			Six Months
		(in millions)
Commodity derivatives	Sales of natural gas liquids	$	(4	)	$	(7	)

15. Commitments and Contingencies

Environmental

We are subject to various U.S. federal, state and local laws and regulations, as well as Canadian federal and provincial laws, regarding air and water quality, hazardous and solid waste disposal and other environmental matters. These laws and regulations can change from time to time, imposing new obligations on us.

Like others in the energy industry, we and our affiliates are responsible for environmental remediation at various contaminated sites. These include some properties that are part of our ongoing operations, sites formerly owned or used by us, and sites owned by third parties. Remediation typically involves management of contaminated soils and may involve groundwater remediation. Managed in conjunction with relevant federal, state/provincial and local agencies, activities vary with site conditions and locations, remedial requirements, complexity and sharing of responsibility. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, we or our affiliates could potentially be held responsible for contamination caused by other parties. In some instances, we may share liability associated with contamination with other potentially responsible parties, and may also benefit from contractual indemnities that cover some or all cleanup costs. All of these sites generally are managed in the normal course of business or affiliated operations. We believe there are no matters outstanding that upon resolution will have a material effect on our consolidated results of operations, financial position or cash flows.

Litigation

Litigation and Legal Proceedings. We are involved in legal, tax and regulatory proceedings in various forums arising in the ordinary course of business, including matters regarding contract and payment claims, some of which involve substantial monetary amounts. We have insurance coverage for certain of these losses should they be incurred. We believe that the final disposition of these proceedings will not have a material effect on our consolidated results of operations, financial position or cash flows.

Legal costs related to the defense of loss contingencies are expensed as incurred. We had no material reserves for legal matters recorded as of June 30, 2014 or December 31, 2013 related to litigation.

Other Commitments and Contingencies

See Note 16 for a discussion of guarantees and indemnifications.

16. Guarantees and Indemnifications

We have various financial guarantees and indemnifications which are issued in the normal course of business. As discussed below, these contracts include financial guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. We enter into these arrangements to facilitate a commercial transaction with a third party by enhancing the value of the transaction to the third party. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on our Condensed Consolidated Balance Sheets. The possibility of having to perform under these guarantees and indemnifications is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events.

We have issued performance guarantees to customers and other third parties that guarantee the payment and performance of other parties, including certain non-100%-owned entities. In connection with our spin-off from Duke Energy Corporation (Duke Energy) in 2007, certain guarantees that were previously issued by us were assigned to, or replaced by, Duke Energy as guarantor in 2006. For any remaining guarantees of other Duke Energy obligations, Duke Energy has indemnified us against any losses incurred under these guarantee arrangements. The maximum potential amount of future payments we could have been required to make under these performance guarantees as of June 30, 2014 was approximately $406 million, which has been indemnified by Duke Energy as discussed above. One of these outstanding performance guarantees, which has a

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maximum potential amount of future payment of $201 million, expires in 2028. The remaining guarantees have no contractual expirations.

We have also issued joint and several guarantees to some of the Duke/Fluor Daniel (D/FD) project owners, guaranteeing the performance of D/FD under its engineering, procurement and construction contracts and other contractual commitments in place at the time of our spin-off from Duke Energy. D/FD is one of the entities transferred to Duke Energy in connection with our spin-off. Substantially all of these guarantees have no contractual expiration and no stated maximum amount of future payments that we could be required to make. Fluor Enterprises Inc., as 50% owner in D/FD, issued similar joint and several guarantees to the same D/FD project owners.

Westcoast Energy, Inc. (Westcoast), a 100%-owned subsidiary, has issued performance guarantees to third parties guaranteeing the performance of unconsolidated entities, such as equity method investments, and of entities previously sold by Westcoast to third parties. Those guarantees require Westcoast to make payment to the guaranteed third party upon the failure of such unconsolidated or sold entity to make payment under some of its contractual obligations, such as debt agreements, purchase contracts and leases. Certain guarantees that were previously issued by Westcoast for obligations of entities that remained a part of Duke Energy are considered guarantees of third party performance; however, Duke Energy has indemnified us against any losses incurred under these guarantee arrangements.

We have entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These agreements typically cover environmental, litigation and other matters, as well as breaches of representations, warranties and covenants. Typically, claims may be made by third parties for various periods of time depending on the nature of the claim. Our potential exposure under these indemnification agreements can range from a specified amount, such as the purchase price, to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. We are unable to estimate the total potential amount of future payments under these indemnification agreements due to several factors, such as the unlimited exposure under certain guarantees.

As of June 30, 2014, the amounts recorded for the guarantees and indemnifications described above are not material, both individually and in the aggregate.

17. Issuances of SEP Units

During the first half of 2014, SEP issued 3.9 million common units to the public, representing limited partner interests, and 80,000 general partner units to Spectra Energy under its continuous offering program. Total net proceeds to SEP were $195 million (net proceeds to Spectra Energy were $191 million). In connection with the issuances of the units, a $47 million gain ($29 million net of tax) to Additional Paid-in Capital and a $144 million increase in Equity-Noncontrolling Interests were recorded in the first half of 2014. The issuances decreased Spectra Energy's ownership in SEP from 84% to 83% at June 30, 2014.

The following table presents the effects of the issuances of SEP units:



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	(in millions)
Net income-controlling interests	$	146	$	199	$	565	$	539
Increase in additional paid-in capital resulting from issuances of SEP units	19		38		29		38
Total net income-controlling interests and changes in equity-controlling interests	$	165	$	237	$	594	$	577

18. Employee Benefit Plans

Retirement Plans. We have a qualified non-contributory defined benefit (DB) retirement plan for most U.S. employees and non-qualified, non-contributory, unfunded defined benefit plans which cover certain current and former U.S. executives. Our Westcoast subsidiary maintains qualified and non-qualified, contributory and non-contributory, DB and defined contribution (DC) retirement plans covering substantially all employees of our Canadian operations.

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Our policy is to fund our retirement plans, where applicable, on an actuarial basis to provide assets sufficient to meet benefits to be paid to plan participants or as required by legislation or plan terms. We made contributions of $10 million to our U.S. retirement plans in the six months ended June 30, 2014 and $11 million in the same period in 2013. We made total contributions to the Canadian DC and DB plans of $26 million in the six months ended June 30, 2014 and $46 million in the same period in 2013. We anticipate that we will make total contributions of approximately $22 million to the U.S. plans and approximately $40 million to the Canadian plans in 2014.

Qualified and Non-Qualified Pension Plans—Components of Net Periodic Pension Cost



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(in millions)
U.S.
Service cost benefit earned	$	4		$	4		$	9		$	9
Interest cost on projected benefit obligation	6			6			12			11
Expected return on plan assets	(9		)	(8		)	(19		)	(16		)
Amortization of loss	3			5			6			10
Net periodic pension cost	$	4		$	7		$	8		$	14

Canada
Service cost benefit earned	$	8		$	8		$	15		$	16
Interest cost on projected benefit obligation	13			12			26			25
Expected return on plan assets	(18		)	(16		)	(35		)	(33		)
Amortization of loss	5			9			11			18
Amortization of prior service cost	1			1			1			1
Net periodic pension cost	$	9		$	14		$	18		$	27

Other Post-Retirement Benefit Plans. We provide certain health care and life insurance benefits for retired employees on a contributory and non-contributory basis. Employees are eligible for these benefits if they have met age and service requirements at retirement, as defined in the plans.

Other Post-Retirement Benefit Plans—Components of Net Periodic Benefit Cost



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(in millions)
U.S.
Interest cost on accumulated post-retirement benefit obligation	$	2		$	2		$	4		$	4
Expected return on plan assets	(1		)	(1		)	(2		)	(2		)
Amortization of loss	—			1			—			1
Net periodic other post-retirement benefit cost	$	1		$	2		$	2		$	3

Canada
Service cost benefit earned	$	1		$	1		$	2		$	2
Interest cost on accumulated post-retirement benefit obligation	2			1			3			3
Net periodic other post-retirement benefit cost	$	3		$	2		$	5		$	5

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Retirement/Savings Plan

In addition to the retirement plans described above, we also have defined contribution employee savings plans available to both U.S. and Canadian employees. Employees may participate in a matching contribution where we match a certain percentage of before-tax employee contributions of up to 6% of eligible pay per pay period for U.S. employees and up to 5% of eligible pay per pay period for Canadian employees. We expensed pre-tax employer matching contributions of $4 million in both the three-month periods ended June 30, 2014 and 2013 and $7 million in both the six-month periods ended June 30, 2014 and 2013 for U.S. employees. We expensed pre-tax employer matching contributions of $3 million in both the three-month periods ended June 30, 2014 and 2013 and $6 million in both the six-month periods ended June 30, 2014 and 2013 for Canadian employees.

19. Consolidating Financial Information

Spectra Energy Corp has agreed to fully and unconditionally guarantee the payment of principal and interest under all series of notes outstanding under the Senior Indenture of Spectra Capital, a 100%-owned, consolidated subsidiary. In accordance with Securities and Exchange Commission (SEC) rules, the following condensed consolidating financial information is presented. The information shown for Spectra Energy Corp and Spectra Capital is presented utilizing the equity method of accounting for investments in subsidiaries, as required. The non-guarantor subsidiaries column represents all consolidated subsidiaries of Spectra Capital. This information should be read in conjunction with our accompanying Condensed Consolidated Financial Statements and notes thereto.

Spectra Energy Corp

Condensed Consolidating Statements of Operations

(Unaudited)

(In millions)



	Spectra Energy Corp			Spectra Capital			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Three Months Ended June 30, 2014
Total operating revenues	$	—		$	—		$	1,253		$	—		$	1,253
Total operating expenses	—			1			914			—			915
Operating income (loss)	—			(1		)	339			—			338
Equity in earnings of unconsolidated affiliates	—			—			85			—			85
Equity in earnings of consolidated subsidiaries	125			264			—			(389		)	—
Other income and expenses, net	(1		)	—			7			—			6
Interest expense	—			66			110			—			176
Earnings before income taxes	124			197			321			(389		)	253
Income tax expense (benefit)	(22		)	72			15			—			65
Net income	146			125			306			(389		)	188
Net income—noncontrolling interests	—			—			42			—			42
Net income—controlling interests	$	146		$	125		$	264		$	(389	)	$	146

Three Months Ended June 30, 2013
Total operating revenues	$	—		$	—		$	1,220		$	—		$	1,220
Total operating expenses	1			—			865			—			866
Operating income (loss)	(1		)	—			355			—			354
Equity in earnings of unconsolidated affiliates	—			—			72			—			72
Equity in earnings of consolidated subsidiaries	194			317			—			(511		)	—
Other income and expenses, net	(1		)	1			22			—			22
Interest expense	—			51			109			—			160
Earnings before income taxes	192			267			340			(511		)	288
Income tax expense (benefit)	(7		)	73			(4		)	—			62
Net income	199			194			344			(511		)	226
Net income—noncontrolling interests	—			—			27			—			27
Net income—controlling interests	$	199		$	194		$	317		$	(511	)	$	199

Spectra Energy Corp

Condensed Consolidating Statements of Operations

(Unaudited)

(In millions)



	Spectra Energy Corp			Spectra Capital			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Six Months Ended June 30, 2014
Total operating revenues	$	—		$	—		$	3,097	$	(1	)	$	3,096
Total operating expenses	4			1			2,115		(1		)	2,119
Operating income (loss)	(4		)	(1		)	982		—			977
Equity in earnings of unconsolidated affiliates	—			—			246		—			246
Equity in earnings of consolidated subsidiaries	540			899			—		(1,439		)	—
Other income and expenses, net	(2		)	1			16		—			15
Interest expense	—			131			223		—			354
Earnings before income taxes	534			768			1,021		(1,439		)	884
Income tax expense (benefit)	(31		)	228			32		—			229
Net income	565			540			989		(1,439		)	655
Net income—noncontrolling interests	—			—			90		—			90
Net income—controlling interests	$	565		$	540		$	899	$	(1,439	)	$	565

Six Months Ended June 30, 2013
Total operating revenues	$	—		$	—		$	2,810	$	(1	)	$	2,809
Total operating expenses	3			—			1,947		(1		)	1,949
Operating income (loss)	(3		)	—			863		—			860
Equity in earnings of unconsolidated affiliates	—			—			182		—			182
Equity in earnings of consolidated subsidiaries	531			826			—		(1,357		)	—
Other income and expenses, net	(3		)	4			54		—			55
Interest expense	—			99			210		—			309
Earnings before income taxes	525			731			889		(1,357		)	788
Income tax expense (benefit)	(14		)	200			6		—			192
Net income	539			531			883		(1,357		)	596
Net income—noncontrolling interests	—			—			57		—			57
Net income—controlling interests	$	539		$	531		$	826	$	(1,357	)	$	539

Spectra Energy Corp

Condensed Consolidating Statements of Comprehensive Income

(Unaudited)

(In millions)



	Spectra Energy Corp		Spectra Capital		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Three Months Ended June 30, 2014
Net income	$	146	$	125	$	306		$	(389	)	$	188
Other comprehensive income	2		—		229			—			231
Total comprehensive income, net of tax	148		125		535			(389		)	419
Less: comprehensive income—noncontrolling interests	—		—		45			—			45
Comprehensive income—controlling interests	$	148	$	125	$	490		$	(389	)	$	374

Three Months Ended June 30, 2013
Net income	$	199	$	194	$	344		$	(511	)	$	226
Other comprehensive income (loss)	3		1		(244		)	—			(240		)
Total comprehensive income (loss), net of tax	202		195		100			(511		)	(14		)
Less: comprehensive income—noncontrolling interests	—		—		25			—			25
Comprehensive income (loss)—controlling interests	$	202	$	195	$	75		$	(511	)	$	(39	)



Six Months Ended June 30, 2014
Net income	$	565	$	540	$	989		$	(1,439	)	$	655
Other comprehensive income (loss)	4		—		(10		)	—			(6		)
Total comprehensive income, net of tax	569		540		979			(1,439		)	649
Less: comprehensive income—noncontrolling interests	—		—		89			—			89
Comprehensive income—controlling interests	$	569	$	540	$	890		$	(1,439	)	$	560

Six Months Ended June 30, 2013
Net income	$	539	$	531	$	883		$	(1,357	)	$	596
Other comprehensive income (loss)	7		1		(420		)	—			(412		)
Total comprehensive income, net of tax	546		532		463			(1,357		)	184
Less: comprehensive income—noncontrolling interests	—		—		52			—			52
Comprehensive income—controlling interests	$	546	$	532	$	411		$	(1,357	)	$	132

Spectra Energy Corp

Condensed Consolidating Balance Sheet

June 30, 2014

(Unaudited)

(In millions)



	Spectra Energy Corp		Spectra Capital		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Cash and cash equivalents	$	—	$	2	$	298	$	—		$	300
Receivables—consolidated subsidiaries	20		—		9		(29		)	—
Receivables—other	1		—		1,221		—			1,222
Other current assets	15		11		657		—			683
Total current assets	36		13		2,185		(29		)	2,205
Investments in and loans to unconsolidated affiliates	—		—		2,803		—			2,803
Investments in consolidated subsidiaries	14,574		20,993		—		(35,567		)	—
Advances receivable—consolidated subsidiaries	—		4,417		755		(5,172		)	—
Notes receivable—consolidated subsidiaries	—		—		3,215		(3,215		)	—
Goodwill	—		—		4,841		—			4,841
Other assets	42		30		326		—			398
Property, plant and equipment, net	—		—		22,260		—			22,260
Regulatory assets and deferred debits	3		15		1,421		—			1,439
Total Assets	$	14,655	$	25,468	$	37,806	$	(43,983	)	$	33,946

Accounts payable—other	$	3	$	1	$	514	$	—		$	518
Accounts payable—consolidated subsidiaries	—		11		18		(29		)	—
Commercial paper	—		220		549		—			769
Short-term borrowings—consolidated subsidiaries	—		415		—		(415		)	—
Taxes accrued	2		—		101		—			103
Current maturities of long-term debt	—		408		88		—			496
Other current liabilities	64		75		1,131		—			1,270
Total current liabilities	69		1,130		2,401		(444		)	3,156
Long-term debt	—		2,899		10,242		—			13,141
Advances payable—consolidated subsidiaries	5,172		—		—		(5,172		)	—
Notes payable—consolidated subsidiaries	—		2,800		—		(2,800		)	—
Deferred credits and other liabilities	762		4,065		1,819		—			6,646
Preferred stock of subsidiaries	—		—		258		—			258
Equity
Controlling interests	8,652		14,574		20,993		(35,567		)	8,652
Noncontrolling interests	—		—		2,093		—			2,093
Total equity	8,652		14,574		23,086		(35,567		)	10,745
Total Liabilities and Equity	$	14,655	$	25,468	$	37,806	$	(43,983	)	$	33,946

Spectra Energy Corp

Condensed Consolidating Balance Sheet

December 31, 2013

(Unaudited)

(In millions)



	Spectra Energy Corp		Spectra Capital		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Cash and cash equivalents	$	—	$	12	$	189	$	—		$	201
Receivables—consolidated subsidiaries	176		394		—		(570		)	—
Receivables—other	1		—		1,335		—			1,336
Other current assets	40		15		489		—			544
Total current assets	217		421		2,013		(570		)	2,081
Investments in and loans to unconsolidated affiliates	—		—		3,043		—			3,043
Investments in consolidated subsidiaries	13,244		19,403		—		(32,647		)	—
Advances receivable—consolidated subsidiaries	—		4,038		677		(4,715		)	—
Notes receivable—consolidated subsidiaries	—		—		3,215		(3,215		)	—
Goodwill	—		—		4,810		—			4,810
Other assets	39		30		316		—			385
Property, plant and equipment, net	—		—		21,829		—			21,829
Regulatory assets and deferred debits	3		17		1,365		—			1,385
Total Assets	$	13,503	$	23,909	$	37,268	$	(41,147	)	$	33,533

Accounts payable—other	$	4	$	—	$	436	$	—		$	440
Accounts payable—consolidated subsidiaries	89		—		481		(570		)	—
Commercial paper	—		344		688		—			1,032
Short-term borrowings—consolidated subsidiaries	—		415		—		(415		)	—
Taxes accrued	4		—		68		—			72
Current maturities of long-term debt	—		557		640		—			1,197
Other current liabilities	81		75		1,142		—			1,298
Total current liabilities	178		1,391		3,455		(985		)	4,039
Long-term debt	—		2,605		9,883		—			12,488
Advances payable—consolidated subsidiaries	4,715		—		—		(4,715		)	—
Notes payable—consolidated subsidiaries	—		2,800		—		(2,800		)	—
Deferred credits and other liabilities	116		3,869		2,440		—			6,425
Preferred stock of subsidiaries	—		—		258		—			258
Equity
Controlling interests	8,494		13,244		19,403		(32,647		)	8,494
Noncontrolling interests	—		—		1,829		—			1,829
Total equity	8,494		13,244		21,232		(32,647		)	10,323
Total Liabilities and Equity	$	13,503	$	23,909	$	37,268	$	(41,147	)	$	33,533

Spectra Energy Corp

Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2014

(Unaudited)

(In millions)



	Spectra Energy Corp			Spectra Capital			Non-Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	565		$	540		$	989		$	(1,439	)	$	655
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	—			—			405			—			405
Equity in earnings of unconsolidated affiliates	—			—			(246		)	—			(246		)
Equity in earnings of consolidated subsidiaries	(540		)	(899		)	—			1,439			—
Distributions received from unconsolidated affiliates	—			—			199			—			199
Other	(36		)	229			3			—			196
Net cash provided by (used in) operating activities	(11		)	(130		)	1,350			—			1,209
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	—			—			(833		)	—			(833		)
Investments in and loans to unconsolidated affiliates	—			—			(30		)	—			(30		)
Purchases of held-to-maturity securities	—			—			(437		)	—			(437		)
Proceeds from sales and maturities of held-to-maturity securities	—			—			453			—			453
Purchases of available-for-sale securities	—			—			(13		)	—			(13		)
Proceeds from sales and maturities of available-for-sale securities	—			—			7			—			7
Distributions received from unconsolidated affiliates	—			—			242			—			242
Advances from affiliates	85			91			—			(176		)	—
Other changes in restricted funds	—			—			(1		)	—			(1		)
Net cash provided by (used in) investing activities	85			91			(612		)	(176		)	(612		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	—			300			412			—			712
Payments for the redemption of long-term debt	—			(148		)	(588		)	—			(736		)
Net decrease in commercial paper	—			(124		)	(132		)	—			(256		)
Distributions to noncontrolling interests	—			—			(81		)	—			(81		)
Contributions from noncontrolling interests	—			—			112			—			112
Dividends paid on common stock	(453		)	—			—			—			(453		)
Proceeds from the issuance of SEP common units	—			—			191			—			191
Distributions and advances from (to) affiliates	366			1			(543		)	176			—
Other	13			—			(1		)	—			12
Net cash provided by (used in) financing activities	(74		)	29			(630		)	176			(499		)
Effect of exchange rate changes on cash	—			—			1			—			1
Net increase (decrease) in cash and cash equivalents	—			(10		)	109			—			99
Cash and cash equivalents at beginning of period	—			12			189			—			201
Cash and cash equivalents at end of period	$	—		$	2		$	298		$	—		$	300

Spectra Energy Corp

Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2013

(Unaudited)

(In millions)



	Spectra Energy Corp			Spectra Capital			Non-Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	539		$	531		$	883		$	(1,357	)	$	596
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	—			—			388			—			388
Equity in earnings of unconsolidated affiliates	—			—			(182		)	—			(182		)
Equity in earnings of consolidated subsidiaries	(531		)	(826		)	—			1,357			—
Distributions received from unconsolidated affiliates	—			—			147			—			147
Other	(7		)	335			(77		)	—			251
Net cash provided by operating activities	1			40			1,159			—			1,200
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	—			—			(959		)	—			(959		)
Investments in and loans to unconsolidated affiliates	—			—			(168		)	—			(168		)
Acquisitions, net of cash acquired	—			—			(1,254		)	—			(1,254		)
Purchases of held-to-maturity securities	—			—			(456		)	—			(456		)
Proceeds from sales and maturities of held-to-maturity securities	—			—			463			—			463
Purchases of available-for-securities	—			—			(2,899		)	—			(2,899		)
Proceeds from sales and maturities of available-for-sale securities	—			—			2,722			—			2,722
Distributions received from unconsolidated affiliates	—			—			13			—			13
Advances from (to) affiliates	156			(589		)	—			433			—
Other changes in restricted funds	—			—			1			—			1
Other	—			—			2			—			2
Net cash provided by (used in) investing activities	156			(589		)	(2,535		)	433			(2,535		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	—			1,848			—			—			1,848
Payments for the redemption of long-term debt	—			(495		)	(51		)	—			(546		)
Net increase (decrease) in commercial paper	—			615			(175		)	—			440
Net decrease in short-term borrowings—consolidated subsidiaries	—			(9		)	—			9			—
Distributions to noncontrolling interests	—			—			(69		)	—			(69		)
Dividends paid on common stock	(412		)	—			—			—			(412		)
Proceeds from the issuance of SEP common units	—			—			190			—			190
Distributions and advances from (to) affiliates	240			(1,405		)	1,607			(442		)	—
Other	15			(6		)	1			—			10
Net cash provided by (used in) financing activities	(157		)	548			1,503			(433		)	1,461
Effect of exchange rate changes on cash	—			—			(3		)	—			(3		)
Net increase (decrease) in cash and cash equivalents	—			(1		)	124			—			123
Cash and cash equivalents at beginning of period	—			3			91			—			94
Cash and cash equivalents at end of period	$	—		$	2		$	215		$	—		$	217

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20. New Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, “Revenue from Contracts with Customers (Topic 606)” which supersedes the revenue recognition requirements of “Revenue Recognition (Topic 605)” and clarifies the principles of recognizing revenue. This ASU is effective for us January 1, 2017 and is to be applied retrospectively. We are currently evaluating this ASU and its potential impact on us.

In April 2014, the FASB issued ASU No. 2014-08, “Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity." This ASU revises the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have or will have a major effect on an entity’s operations and financial results, removing the lack of continuing involvement criteria and requiring discontinued operations reporting for the disposal of an equity method investment that meets the definition of discontinued operations. The update also requires expanded disclosures for discontinued operations, and disclosure of pretax profit or loss of certain individually significant components of an entity that do not qualify for discontinued operations reporting. This ASU is effective for us on January 1, 2015 and is to be applied prospectively. We do not expect the adoption of the provisions of this ASU to have any impact on our consolidated results of operations, financial position or cash flows.

In 2013, the FASB issued ASU 2013-11, “Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (a Consensus of the FASB Emerging Issues Task Force),” which was issued to eliminate diversity in practice. This ASU requires entities to net unrecognized tax benefits against all same-jurisdiction net operating losses or tax credit carryforwards that would be used to settle the position with a tax authority. We adopted this standard on January 1, 2014. The adoption of this ASU did not have a material impact on our consolidated results of operations, financial position or cash flows.



Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.

INTRODUCTION

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the accompanying Condensed Consolidated Financial Statements.

In November 2013, Spectra Energy completed the U.S. Assets Dropdown to SEP. As a result of this transaction, we realigned our reportable segments structure. Amounts presented herein for 2013 segment information have been recast to conform to our current segment reporting presentation. There were no changes to consolidated data as a result of the recast of our segment information.

Executive Overview

For the three months ended June 30, 2014 and 2013, we reported net income from controlling interests of $146 million and $199 million, respectively. For the six months ended June 30, 2014 and 2013, we reported net income from controlling interests of $565 million and $539 million, respectively.

The highlights for the three months and six months ended June 30, 2014 include the following:

•

Spectra Energy Partners’ earnings for the three-month period benefited mainly from expansion projects at Texas Eastern Transmission, LP (Texas Eastern), higher transportation revenues at Express-Platte as a result of increased tariff rates and higher contracted volumes, and higher earnings from DCP Sand Hills Pipeline, LLC (Sand Hills) and DCP Southern Hills Pipeline, LLC (Southern Hills), which were placed into service in June 2013. For the six-month period, the increased earnings were driven by expansion projects at Texas Eastern, the acquisition of Express-Platte in March 2013, higher natural gas transportation revenues as a result of colder weather and higher earnings from Sand Hills and Southern Hills.

•

Distribution’s earnings for the three-month period decreased slightly mainly due to lower transportation and storage revenues and a weaker Canadian dollar, mostly offset by lower operating fuel costs and pension expense. For the six-month period, the increase in earnings was mainly due to higher customer usage as a result of colder weather, and a favorable decision by the OEB in 2014 primarily regarding certain 2012 revenues realized from the optimization of upstream transportation contracts being treated as utility earnings, mostly offset by a weaker Canadian dollar.


•	Western Canada Transmission & Processing’s earnings for the three-month period decreased due mainly to two planned major facility turnarounds in 2014 compared to one in 2013, which drove higher operating and maintenance costs as

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well as reduced revenues from the plants, and a weaker Canadian dollar. The increase in earnings for the six-month period reflected higher earnings from the Empress NGL business due primarily to higher propane prices and higher transmission revenues as a result of higher interim tolls, mostly offset by higher operating and maintenance costs, and a weaker Canadian dollar.

•

Field Services’ earnings for the three-month and the six-month periods increased largely due to higher gathering and processing volumes from new assets, stronger commodity prices and the effects of hedges at DCP Partners, partially offset by higher operating costs as a result of increased spending on reliability programs, including turnarounds, as well as growth in Field Services’ operations, and higher interest expense.

In the first six months of 2014, we had $863 million of capital and investment expenditures, excluding reimbursements from noncontrolling interests of $20 million. We currently project $2.1 billion of capital and investment expenditures for the full year, including expansion and investment capital expenditures of $1.3 billion.

We are committed to an investment-grade balance sheet and continued prudent financial management of our capital structure. Therefore, financing these growth activities will continue to be based on our strong and growing fee-based earnings and cash flows as well as the issuances of debt and/or equity securities. As of June 30, 2014, our revolving credit facilities included Spectra Capital’s $1.0 billion facility, SEP’s $2.0 billion facility, Westcoast’s 300 million Canadian dollar facility and Union Gas’ 400 million Canadian dollar facility. These facilities are used principally as back-stops for commercial paper programs.

RESULTS OF OPERATIONS



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	(in millions)
Operating revenues	$	1,253	$	1,220	$	3,096	$	2,809
Operating expenses	915		866		2,119		1,949
Operating income	338		354		977		860
Other income and expenses	91		94		261		237
Interest expense	176		160		354		309
Earnings before income taxes	253		288		884		788
Income tax expense	65		62		229		192
Net income	188		226		655		596
Net income—noncontrolling interests	42		27		90		57
Net income—controlling interests	$	146	$	199	$	565	$	539

Three Months Ended June 30, 2014 Compared to Same Periods in 2013

Operating Revenues. The $33 million, or 3%, increase was driven by:


•	revenues from expansion projects primarily from Texas Eastern at Spectra Energy Partners, and


•	higher natural gas prices passed through to customers and higher customer usage of natural gas due to a variance in estimated gas consumption in the first quarter of 2014, net of lower transportation revenue primarily due to a settlement received from the termination of a transportation contract in 2013 and lower short-term transportation revenues at Distribution, partially offset by


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

Operating Expenses. The $49 million, or 6%, increase was driven by:


•	increased volumes of natural gas purchases for extraction and make-up at the Empress operations, and higher plant turnaround and maintenance costs at Western Canada Transmission & Processing,


•	expansion projects primarily from Texas Eastern at Spectra Energy Partners, and


•	increased natural gas prices passed through to customers and higher volumes of natural gas sold primarily due to a variance in estimated gas consumption in the first quarter of 2014, net of lower operating fuel costs and the deferral of pension expense approved by the OEB for recovery from customers at Distribution, partially offset by


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

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Operating Income. The $16 million, or 5%, decrease was due mainly to two planned major facility turnarounds in 2014 compared to one in 2013, which drove higher operating and maintenance costs as well as reduced revenues from the plants at Western Canada Transmission & Processing, and a weaker Canadian dollar, partially offset by higher earnings from expansion projects at Texas Eastern and higher transportation revenues from Express-Platte as a result of increased tariff rates and higher contracted volumes at Spectra Energy Partners.

Other Income and Expenses. The $3 million, or 3%, decrease was due to lower allowance for funds used during construction (AFUDC) as a result of decreased capital spending on expansion projects at Spectra Energy Partners, partially offset by higher equity earnings from Field Services mainly due to the change in net income and related noncontrolling interest effects of dropdown hedges at DCP Partners where DCP Midstream acts as a counterparty in the second quarter of 2014 compared to the second quarter of 2013, higher gathering and processing volumes as a result of asset growth and stronger commodity prices, net of higher operating costs due to increased spending on reliability programs, including turnarounds, as well as growth in Field Services’ operations, and higher interest expense. The decrease was also partially offset by higher earnings from Sand Hills and Southern Hills which were placed into service in the second quarter of 2013.

Interest Expense. The $16 million, or 10%, increase was mainly due to lower capitalized interest from projects placed in service in 2013 and higher debt balances attributable to third-quarter 2013 debt issued by SEP primarily related to the U.S. Assets Dropdown, partially offset by a weaker Canadian dollar.

Income Tax Expense. The $3 million increase was primarily attributable to the reversal of tax reserves in the 2013 period as a result of favorable Canadian federal income tax legislation enacted in the second quarter of 2013, mostly offset by lower Canadian earnings in 2014.

The effective tax rate for income for the three-month periods ended June 30, 2014 and 2013 was 26% and 22%, respectively. The lower effective tax rate in 2013 was primarily due to the reversal of tax reserves in the second quarter of 2013.

Net Income—Noncontrolling Interests. The $15 million increase was driven by higher earnings from Spectra Energy Partners, partially offset by the effects of a decrease in the average ownership percentage of SEP held by the public, primarily as a result of the issuance of SEP partnership units to Spectra Energy in November 2013 in association with the U.S. Assets Dropdown.

Six Months Ended June 30, 2014 Compared to Same Periods in 2013

Operating Revenues. The $287 million, or 10%, increase was driven by:


•	revenues from expansion projects primarily from Texas Eastern, the acquisition of Express-Platte in March 2013 and higher natural gas transportation revenues due to colder weather at Spectra Energy Partners,

•

higher NGL sales prices and higher sales volumes of residual natural gas at the Empress operations, an increase in gathering and processing revenues from new facilities in unconventional development areas, higher transmission revenues as a result of higher interim tolls and higher interruptible transmission revenue from a new supply source connected to the M&N Canada system at Western Canada Transmission & Processing, and

•

higher customer usage of natural gas as a result of colder weather, growth in the number of customers and a favorable decision by the OEB in 2014 primarily regarding certain 2012 revenues realized from the optimization of upstream transportation contracts being treated as utility earnings, net of lower 2014 distribution rates approved by the OEB and lower transportation revenue due to a settlement received from the termination of a transportation contract in 2013 at Distribution, partially offset by


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

Operating Expenses. The $170 million, or 9%, increase was driven by:


•	increased volumes of natural gas purchases for extraction and make-up at the Empress operations, higher plant turnaround and maintenance costs, increased costs passed through to customers from M&N Canada and higher cost of NGL purchases at the Empress operations at Western Canada Transmission & Processing,


•	increased volumes of natural gas sold due to colder weather, growth in the number of customers, net of the deferral of pension expense approved by the OEB for recovery from customers at Distribution, and


•	the acquisition of Express-Platte and expansion projects primarily from Texas Eastern 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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Operating Income. The $117 million, or 14%, increase was driven by higher earnings from expansion projects at Texas Eastern and the acquisition of Express-Platte at Spectra Energy Partners, higher customer usage due to colder weather and a favorable decision by the OEB in 2014 primarily regarding certain 2012 revenues realized from the optimization of upstream transportation contracts being treated as utility earnings at Distribution and higher earnings at the Empress NGL business due primarily to higher propane prices, net of higher turnaround and maintenance costs at Western Canada Transmission & Processing, partially offset by effects of a weaker Canadian dollar at Distribution and Western Canada Transmission & Processing.

Other Income and Expenses. The $24 million, or 10%, increase was attributable to higher equity earnings from Field Services mainly due to higher commodity prices, higher gathering and processing volumes as a result of asset growth and the change in net income and related noncontrolling interest effects of dropdown hedges at DCP Partners in the second quarter of 2014 compared to the second quarter of 2013, net of higher operating costs due to increased spending on reliability programs, including turnarounds, as well as growth in Field Services’ operations, and higher interest expense. The increase was partially offset by lower AFUDC due to decreased capital spending on expansion projects, net of higher earnings from Sand Hills and Southern Hills, at Spectra Energy Partners and lower AFUDC due to decreased capital spending on expansion projects at Western Canada Transmission & Processing.

Interest Expense. The $45 million, or 15%, increase was mainly due to higher debt balances attributable to third-quarter 2013 debt issued by SEP related to the U.S. Assets Dropdown, lower capitalized interest from projects placed in service in 2013 and a weaker Canadian dollar.

Income Tax Expense. The $37 million increase was primarily attributable to the reversal of tax reserves in the 2013 period as a result of favorable Canadian federal income tax legislation enacted in the second quarter of 2013 and higher earnings in 2014.

The effective tax rate for income for the six months ended June 30, 2014 and 2013 was 26% and 24%, respectively. The lower effective tax rates in 2013 were primarily due to the reversal of tax reserves in the 2013 period.

Net Income—Noncontrolling Interests. The $33 million increase was driven by higher earnings from Spectra Energy Partners, partially offset by the effects of a decrease in the average ownership percentage of SEP held by the public, primarily as a result of the issuance of SEP partnership units to Spectra Energy in November 2013 in association with the U.S. Assets Dropdown.

For a more detailed discussion of earnings drivers, see the segment discussions that follow.

Segment Results

Management evaluates segment performance based on EBITDA. Cash, cash equivalents and short-term investments are managed at the parent-company levels, so the gains and losses from foreign currency transactions and interest and dividend income are excluded from the segments’ EBITDA. We consider segment EBITDA to be a good indicator of each segment’s operating performance from its continuing operations, as it represents the results of our operations without regard to financing methods or capital structures. Our segment EBITDA may not be comparable to similarly titled measures of other companies because other companies may not calculate EBITDA in the same manner.

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Segment EBITDA is summarized in the following table. Detailed discussions follow.

EBITDA by Business Segment



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(in millions)
Spectra Energy Partners	$	374		$	358		$	803		$	705
Distribution	112			115			338			335
Western Canada Transmission & Processing	111			157			348			347
Field Services	54			46			184			134
Total reportable segment EBITDA	651			676			1,673			1,521
Other	(24		)	(29		)	(41		)	(43		)
Total reportable segment and other EBITDA	627			647			1,632			1,478
Depreciation and amortization	199			196			399			382
Interest expense	176			160			354			309
Interest income and other	1			(3		)	5			1
Earnings before income taxes	$	253		$	288		$	884		$	788

The amounts discussed below include intercompany transactions that are eliminated in the Condensed Consolidated Financial Statements.

Spectra Energy Partners



	Three Months Ended June 30,							Six Months Ended June 30,
	2014		2013		Increase (Decrease)			2014		2013		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	531	$	492	$	39		$	1,112	$	951	$	161
Operating expenses
Operating, maintenance and other	193		183		10			378		333		45
Other income and expenses	36		49		(13		)	69		87		(18		)
EBITDA	$	374	$	358	$	16		$	803	$	705	$	98
Express pipeline receipts, MBbl/d (a,b)	170		202		(32		)	182		203		(21		)
Platte PADD II deliveries, MBbl/d (b)	176		165		11			171		165		6

___________


(a)	Thousand barrels per day.


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

Three Months Ended June 30, 2014 Compared to Same Period in 2013

Operating Revenues. The $39 million increase was driven by:


•	a $43 million increase due to expansion projects, primarily at Texas Eastern,


•	an $8 million increase due to higher natural gas transportation revenues mainly at Texas Eastern and East Tennessee Natural Gas, LLC, and


•	a $4 million increase in transportation revenues on Express-Platte system as a result of increased tariff rates and higher contracted volumes, partially offset by


•	an $8 million decrease due to lower processing revenues, and


•	a $7 million decrease in storage firm revenues due to lower contract renewal rates.

Operating, Maintenance and Other. The $10 million increase was mainly driven by an increase from expansion projects, primarily at Texas Eastern.

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Other Income and Expenses. The $13 million decrease was primarily due to lower AFUDC resulting from decreased capital spending on expansion projects, partially offset by higher earnings from Sand Hills and Southern Hills which were placed into service in the second quarter of 2013.

EBITDA. The $16 million increase was driven by expansions, primarily at Texas Eastern, higher earnings from Sand Hills and Southern Hills, and higher Express-Platte revenues, partially offset by lower processing revenues.

Six Months Ended June 30, 2014 Compared to Same Period in 2013

Operating Revenues. The $161 million increase was driven by:


•	an $85 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, and


•	a $26 million increase due to higher natural gas transportation revenues from higher demand, primarily as a result of colder weather, and


•	a $4 million increase in natural gas transportation revenues on the Express-Platte system as a result of increased tariff rates and higher contracted volumes, partially offset by


•	a $12 million decrease in storage revenues due to lower contract renewal rates, and


•	a $7 million decrease due to lower processing revenues.

Operating, Maintenance and Other. The $45 million increase was driven by:

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

•a $23 million increase from expansion projects, primarily at Texas Eastern.

Other Income and Expenses. The $18 million decrease was mainly due to lower AFUDC resulting from decreased capital spending on expansion projects, partially offset by higher earnings from Sand Hills and Southern Hills.

EBITDA. The $98 million increase was driven by expansions, primarily at Texas Eastern, the acquisition of Express-Platte, and higher earnings from Sand Hills and Southern Hills.

Distribution



	Three Months Ended June 30,								Six Months Ended June 30,
	2014		2013			Increase (Decrease)			2014			2013		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	360	$	352		$	8		$	1,078		$	1,051	$	27
Operating expenses
Natural gas purchased	152		128			24			540			497		43
Operating, maintenance and other	96		108			(12		)	199			219		(20		)
Other income and expenses	—		(1		)	1			(1		)	—		(1		)
EBITDA	$	112	$	115		$	(3	)	$	338		$	335	$	3
Number of customers, thousands									1,405			1,386		19
Heating degree days, Fahrenheit	979		963			16			5,230			4,488		742
Pipeline throughput, TBtu (a)	121		195			(74		)	415			509		(94		)
Canadian dollar exchange rate, average	1.09		1.02			0.07			1.10			1.02		0.08

___________


(a)	Trillion British thermal units.

Three Months Ended June 30, 2014 Compared to Same Period in 2013

Operating Revenues. The $8 million increase was driven by:


•	a $29 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,


•	an $11 million increase in customer usage of natural gas primarily due to a variance in estimated gas consumption in the first quarter of 2014, and

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•	a $6 million increase from growth in the number of customers, partially offset by


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


•	a $9 million decrease in transportation revenue mainly due to a settlement received from the termination of a transportation contract in the second quarter of 2013 and lower short-term transportation revenues, and


•	a $4 million decrease in storage revenue primarily due to lower storage prices.

Natural Gas Purchased. The $24 million increase was driven by:


•	a $29 million increase from higher natural gas prices passed through to customers,


•	a $10 million increase due to higher volumes of natural gas sold primarily due to a variance in estimated gas consumption in the first quarter of 2014, and


•	a $4 million increase from growth in the number of customers, partially offset by


•	an $11 million decrease resulting from a weaker Canadian dollar, and


•	an $11 million decrease in operating fuel costs primarily due to gas measurement variances.

Operating, Maintenance and Other. The $12 million decrease was driven by:


•	a $7 million decrease resulting from the deferral of pension expense approved by the OEB in 2014 for recovery from customers, and


•	a $5 million decrease resulting from a weaker Canadian dollar.

EBITDA. The $3 million decrease was largely the result of lower transportation and storage revenues and a weaker Canadian dollar, mostly offset by lower operating fuel costs and pension expense.

Six Months Ended June 30, 2014 Compared to Same Period in 2013

Operating Revenues. The $27 million increase was driven by:


•	a $106 million increase in customer usage of natural gas primarily due to weather that was more than 16% colder than in 2013,


•	a $21 million increase from growth in the number of customers,


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


•	a $7 million increase in industrial market usage, partially offset by


•	a $92 million decrease resulting from a weaker Canadian dollar,


•	a $9 million decrease primarily due to lower 2014 distribution rates approved by the OEB,


•	a $7 million decrease in transportation revenue primarily due to a settlement received from the termination of a transportation contract in the second quarter of 2013,


•	a $5 million decrease in storage revenue primarily due to lower storage prices, and


•	a $5 million decrease due to 2014 earnings to be shared with customers in accordance with the new incentive regulation framework.

Natural Gas Purchased. The $43 million increase was driven by:


•	a $76 million increase due to higher volumes of natural gas sold primarily due to colder weather,


•	a $17 million increase from growth in the number of customers, and


•	a $4 million increase in industrial market usage, partially offset by


•	a $48 million decrease resulting from a weaker Canadian dollar, and


•	a $4 million decrease in operating fuel costs primarily due to gas measurement variances.

Operating, Maintenance and Other. The $20 million decrease was driven by:


•	a $14 million decrease resulting from a weaker Canadian dollar, and


•	a $7 million decrease resulting from the deferral of pension expense approved by the OEB in 2014 for recovery from customers.

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EBITDA. The $3 million increase was largely the result of higher customer usage due to colder weather, the impact of a decision by the OEB in March 2014 primarily regarding certain 2012 revenues realized from the optimization of upstream transportation contracts being treated as utility earnings and lower pension expense, mostly offset by a weaker Canadian dollar, lower 2014 distribution rates approved by the OEB and lower transportation revenues.

Western Canada Transmission & Processing



	Three Months Ended June 30,							Six Months Ended June 30,
	2014		2013		Increase (Decrease)			2014		2013		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	391	$	391	$	—		$	966	$	834	$	132
Operating expenses
Natural gas and petroleum products purchased	91		59		32			265		170		95
Operating, maintenance and other	189		175		14			354		326		28
Other income and expenses	—		—		—			1		9		(8		)
EBITDA	$	111	$	157	$	(46	)	$	348	$	347	$	1
Pipeline throughput, TBtu	224		170		54			466		373		93
Volumes processed, TBtu	175		157		18			352		332		20
Canadian dollar exchange rate, average	1.09		1.02		0.07			1.10		1.02		0.08

Three Months Ended June 30, 2014 Compared to Same Period in 2013

Operating Revenues. Significant drivers include:


•	a $41 million increase due primarily to higher sales volumes of residual natural gas at the Empress operations,


•	a $7 million increase due to higher sales prices associated with the Empress NGL business, and


•	a $5 million increase in gathering and processing revenues due in part to new facilities at Horn River and Montney unconventional development areas, offset by


•	a $26 million decrease in NGL sales volumes at Empress, and


•	a $26 million decrease as a result of a weaker Canadian dollar.

Natural Gas and Petroleum Products Purchased. The $32 million increase was driven by:


•	a $34 million increase due primarily to higher volumes of natural gas purchases for extraction and make-up at Empress, and


•	a $4 million increase primarily as a result of higher costs of NGL purchases at the Empress facility, partially offset by


•	a $6 million decrease as a result of a weaker Canadian dollar.

Operating, Maintenance and Other. The $14 million increase was driven by:


•	a $16 million increase in plant turnaround costs, and


•	an $8 million increase in maintenance costs, partially offset by


•	a $13 million decrease as a result of a weaker Canadian dollar.

EBITDA. The $46 million decrease was due mainly to two planned major facility turnarounds in 2014 compared to one in 2013, which drove higher operating and maintenance costs as well as reduced revenues from the plants. The segment’s results also reflect the effect of a weaker Canadian dollar.

Six Months Ended June 30, 2014 Compared to Same Period in 2013

Operating Revenues. The $132 million increase was driven by:


•	an $89 million increase due primarily to higher sales volumes of residual natural gas at the Empress operations,


•	a $79 million increase due mostly to higher propane prices associated with the Empress NGL business,


•	a $17 million increase in gathering and processing revenues from new facilities at Horn River and Montney unconventional development areas,


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

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•	a $13 million increase primarily in interruptible transmission revenues due to a new supply source connected to the M&N Canada system, and


•	a $5 million increase in carbon and other non-income tax expense recovered from customers, partially offset by


•	an $80 million decrease as a result of a weaker Canadian dollar.

Natural Gas and Petroleum Products Purchased. The $95 million increase was driven by:


•	a $107 million increase due primarily to higher volumes of natural gas purchases for extraction and make-up at Empress, and


•	an $8 million increase primarily as a result of higher costs of NGL purchases at the Empress facility, partially offset by


•	a $22 million decrease as a result of a weaker Canadian dollar.

Operating, Maintenance and Other. The $28 million increase was driven by:


•	a $16 million increase in plant turnaround costs,


•	a $12 million increase in maintenance costs,


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


•	a $5 million increase in carbon and other non-income tax expense,


•	a $4 million increase in Empress plant fuel costs due primarily to higher prices, and


•	a $4 million increase in operating costs for new facilities, partially offset by


•	a $28 million decrease as a result of a weaker Canadian dollar.

Other Income and Expenses. The $8 million decrease was driven primarily by lower AFUDC resulting from decreased capital spending on expansion projects.

EBITDA. The $1 million increase was driven by higher earnings at the Empress NGL business due primarily to higher propane prices, higher transmission revenues due to higher interim tolls and gathering and processing earnings from expansion, mostly offset by higher operating and maintenance costs and the effect of a weaker Canadian dollar.

Field Services



	Three Months Ended June 30,						Six Months Ended June 30,
	2014		2013		Increase (Decrease)		2014		2013		Increase (Decrease)
	(in millions, except where noted)
Equity in earnings of unconsolidated affiliates	$	54	$	46	$	8	$	184	$	134	$	50
EBITDA	$	54	$	46	$	8	$	184	$	134	$	50
Natural gas gathered and processed/transported, TBtu/d (a,b)	7.3		7.1		0.2		7.2		7.0		0.2
NGL production, MBbl/d (a)	452		412		40		449		404		45
Average natural gas price per MMBtu (c,d)	$	4.67	$	4.09	$	0.58	$	4.80	$	3.71	$	1.09
Average NGL price per gallon (e)	$	0.93	$	0.82	$	0.11	$	1.00	$	0.86	$	0.14
Average crude oil price per barrel (f)	$	102.99	$	94.22	$	8.77	$	100.84	$	94.44	$	6.40

___________


(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. The 2013 NGL price per gallon has been revised to reflect the impact of ethane rejection.


(f)	Average price based on NYMEX calendar month.

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Three Months Ended June 30, 2014 Compared to Same Period in 2013

EBITDA. Higher equity earnings of $8 million were mainly the result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:


•	a $31 million increase primarily attributable to decreased net income attributable to noncontrolling interests as a result of DCP Partners’ losses on dropdown hedges where DCP Midstream acts as counterparty,


•	a $14 million increase in gathering and processing margins mainly due to higher volumes as a result of asset growth, and


•	a $5 million increase from commodity-sensitive processing arrangements due to higher NGL, natural gas and crude oil prices, partially offset by


•	a $25 million decrease primarily attributable to higher operating costs as a result of increased spending on reliability programs, including turnarounds, as well as growth in Field Services’ operations,


•	a $9 million decrease mainly attributable to higher interest expense due to higher interest rates from new debt and lower capitalized interest due to certain projects which were placed in service in 2013,


•	a $6 million decrease attributable to DCP Partners’ third-party mark-to-market activity and unfavorable results from gas marketing, partially offset by favorable results from NGL trading, and


•	a $5 million decrease primarily attributable to higher depreciation expense as a result of growth.

Six Months Ended June 30, 2014 Compared to Same Period in 2013

EBITDA. Higher equity earnings of $50 million were mainly the result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:


•	a $44 million increase from commodity-sensitive processing arrangements due to higher NGL, natural gas and crude oil prices,


•	a $26 million increase in gathering and processing margins mainly due to higher volumes as a result of asset growth,


•	a $26 million increase attributable to decreased net income attributable to noncontrolling interests as a result of DCP Partners’ losses on dropdown hedges, partially offset by growth from dropdowns,


•	a $16 million increase attributable to favorable results from NGL and gas trading and marketing, partially offset by DCP Partners’ third-party mark-to-market activity, and


•	a $7 million increase in gains associated with the issuance of partnership units by DCP Partners in 2014 compared to 2013, partially offset by


•	a $32 million decrease primarily attributable to higher operating costs as a result of increased spending on reliability programs, including turnarounds, as well as growth in Field Services’ operations,


•	a $24 million decrease mainly attributable to higher interest expense due to higher interest rates from newly issued debt and lower capitalized interest due to certain projects which were placed in service in 2013, and


•	a $13 million decrease primarily attributable to higher depreciation expense as a result of growth.

Other



	Three Months Ended June 30,									Six Months Ended June 30,
	2014			2013			Increase (Decrease)			2014			2013			Increase (Decrease)
	(in millions)
Operating revenues	$	19		$	18		$	1		$	37		$	36		$	1
Operating expenses
Operating, maintenance and other	43			49			(6		)	81			85			(4		)
Other income and expenses	—			2			(2		)	3			6			(3		)
EBITDA	$	(24	)	$	(29	)	$	5		$	(41	)	$	(43	)	$	2

Three Months Ended June 30, 2014 Compared to Same Period in 2013

EBITDA. The $5 million increase was driven by mark-to-market adjustments on performance cash awards.

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Six Months Ended June 30, 2014 Compared to Same Period in 2013

EBITDA. -The $2 million increase reflects lower corporate costs, including employee benefit costs.

Impairment of Goodwill

In connection with our quantitative assessments, we primarily use a discounted cash flow analysis to determine fair values of those reporting units. The long-term growth rates used for the reporting units that we quantitatively assessed reflect continued expansion of our assets, driven by new natural gas supplies such as shale gas in North America and increasing demand for natural gas transportation capacity on our pipeline systems primarily as a result of forecasted growth in natural gas-fired power plants and increasing demand for crude oil and NGL transportation capacity on our pipeline systems.

We performed a test on all our reporting units for our test of goodwill impairment as of April 1, 2014. Based on the results of our annual goodwill impairment testing, no indicators of impairment were noted and the fair values of the reporting units that we assessed at April 1, 2014 (our testing date) were substantially in excess of their respective carrying values.

LIQUIDITY AND CAPITAL RESOURCES

As of June 30, 2014, we had negative working capital of $951 million. This balance includes commercial paper liabilities totaling $769 million and current maturities of long-term debt of $496 million. We will rely upon cash flows from operations and various financing transactions, which may include debt and/or equity issuances, to fund our liquidity and capital requirements for the next 12 months. SEP is expected to be self-funding through its cash flows from operations, use of its revolving credit facility and its access to capital markets. We receive cash distributions from SEP in accordance with the partnership agreement, which considers our level of ownership and incentive distribution rights.

As of June 30, 2014, our revolving credit facilities included Spectra Capital’s $1.0 billion facility, SEP’s $2.0 billion facility, Westcoast’s 300 million Canadian dollar facility and Union Gas’ 400 million Canadian dollar facility. We had available capacity of $1,451 million under SEP’s credit facility and $1,436 million under our other subsidiaries’ credit facilities. These facilities are used principally as back-stops for commercial paper programs. At Spectra Capital, SEP and Westcoast, we primarily use commercial paper for temporary funding of capital expenditures. At Union Gas, we primarily use commercial paper to support short-term working capital fluctuations. We also utilize commercial paper, other variable-rate debt and interest rate swaps to achieve our desired mix of fixed and variable-rate debt. See Note 12 of Notes to Condensed Consolidated Financial Statements for a discussion of available credit facilities and Financing Cash Flows and Liquidity for a discussion of effective shelf registrations.

Cash Flow Analysis

The following table summarizes the changes in cash flows for each of the periods presented:



	Six Months Ended June 30,
	2014			2013
Net cash provided by (used in):	(in millions)
Operating activities	$	1,209		$	1,200
Investing activities	(612		)	(2,535		)
Financing activities	(499		)	1,461
Effect of exchange rate changes on cash	1			(3		)
Net increase in cash and cash equivalents	99			123
Cash and cash equivalents at beginning of the period	201			94
Cash and cash equivalents at end of the period	$	300		$	217

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Operating Cash Flows

Net cash provided by operating activities increased $9 million to $1,209 million for the six months ended June 30, 2014 compared to the same period in 2013, driven mostly by higher earnings and distributions from unconsolidated affiliates, partially offset by changes in working capital.

Investing Cash Flows

Net cash used in investing activities decreased $1,923 million to $612 million in the six months ended June 30, 2014 compared to the same period in 2013. This change was driven by:


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


•	a $264 million decrease in capital and investment expenditures in 2014,


•	a $229 million increase in distributions received from unconsolidated affiliates, comprised mostly of a distribution from Southeast Supply Header, LLC (SESH) with proceeds from a SESH debt offering, and


•	a $171 million decrease in net purchases of AFS securities in 2014.



	Six Months Ended June 30,
	2014		2013
Capital and Investment Expenditures	(in millions)
Spectra Energy Partners (a,b)	$	444	$	675
Distribution	131		113
Western Canada Transmission & Processing	270		317
Total reportable segments	845		1,105
Other	18		22
Total consolidated	$	863	$	1,127

___________


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


(b)	Excludes reimbursements from noncontrolling interests of $20 million in 2014.

Capital and investment expenditures for the six months ended June 30, 2014 consisted of $626 million for expansion projects and $237 million for maintenance and other projects.

We project 2014 capital and investment expenditures of approximately $2.1 billion, consisting of approximately $1.2 billion for Spectra Energy Partners, $0.5 billion for Distribution and $0.4 billion for Western Canada Transmission & Processing. Total projected 2014 capital and investment expenditures include approximately $1.3 billion of expansion capital expenditures and $0.8 billion for maintenance and upgrades of existing plants, pipelines and infrastructure to serve growth. This excludes an estimated $188 million capital contribution we anticipate making in August 2014 to SESH in connection with a SESH debt retirement. We continue to assess short and long-term market requirements and adjust our capital plans as required.

Financing Cash Flows and Liquidity

Net cash used in financing activities totaled $499 million in the six months ended June 30, 2014 compared to $1,461 million provided by financing activities in the same period of 2013. This change was driven by:


•	$24 million of net redemptions of long-term debt in 2014 compared to $1,302 million of net issuances in 2013 which were primarily used to fund the acquisition of Express-Platte,


•	a $256 million net decrease in commercial paper in 2014 compared to a $440 million net increase in 2013, and


•	a $41 million increase in dividends paid on common stock in 2014, partially offset by


•	a $112 million increase in contributions from noncontrolling interests in 2014.

In January 2014, Spectra Capital borrowed the full $300 million available under its unsecured term loan agreement. Interest on the borrowing is based on LIBOR and the borrowing is due in 2018. Net proceeds from the borrowing were used for general corporate purposes.

On June 2, 2014, Union Gas issued 200 million Canadian dollars (approximately $183 million as of the issuance date) of 2.76% unsecured notes due 2021 and 250 million Canadian dollars (approximately $229 million as of the issuance date) of 4.20% unsecured notes due 2044. Net proceeds from the offerings were used for general corporate purposes.

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During the first half of 2014, SEP issued 3.9 million common units to the public, representing limited partner interests, and 80,000 general partner units to Spectra Energy under its continuous offering program. Total net proceeds to SEP were $195 million (net proceeds to Spectra Energy were $191 million). The net proceeds were used for SEP’s general partnership purposes, which may have included debt repayments, future acquisitions, capital expenditures and/or additions to working capital.

Available Credit Facilities and Restrictive Debt Covenants. See Note 12 of Notes to Condensed Consolidated Financial Statements for a discussion of available credit facilities and related financial and other covenants.

The terms of our Spectra Capital credit agreement require our consolidated debt-to-total-capitalization ratio, as defined in the agreement, to be 65% or lower. Per the terms of the agreement, collateralized debt is excluded from the calculation of the ratio. As of June 30, 2014, this ratio was 56%. Our equity and, as a result, this ratio, is sensitive to significant movements of the Canadian dollar relative to the U.S. dollar due to the significance of our Canadian operations. Based on the strength of our total capitalization as of June 30, 2014, however, it is not likely that a material adverse effect would occur as a result of a weakened Canadian dollar.

Dividends. Our near-term objective is to increase our cash dividend by $0.12 per year through 2016. We expect to continue our policy of paying regular cash dividends. The declaration and payment of dividends are subject to the sole discretion of our Board of Directors and will depend upon many factors, including the financial condition, earnings and capital requirements of our operating subsidiaries, covenants associated with certain debt obligations, legal requirements, regulatory constraints and other factors deemed relevant by our Board of Directors. We declared a quarterly cash dividend of $0.335 per common share on July 15, 2014 payable on September 9, 2014 to shareholders of record at the close of business on August 12, 2014.

Other Financing Matters. Spectra Energy Corp and Spectra Capital have an effective shelf registration statement on file with the Securities and Exchange Commission (SEC) to register the issuance of unspecified amounts of various equity and debt securities. SEP has an effective shelf registration statement on file with the SEC to register the issuance of unspecified amounts of limited partner common units and various debt securities. SEP also has $282 million available as of June 30, 2014 for the issuance of limited partner common units and various debt securities under another effective shelf registration statement on file with the SEC related to its continuous offering program. Westcoast and Union Gas have an aggregate 650 million Canadian dollars (approximately $609 million) available as of June 30, 2014 for the issuance of debt securities in the Canadian market under debt shelf prospectuses.

OTHER ISSUES

New Accounting Pronouncements. See Note 20 of Notes to Condensed Consolidated Financial Statements for discussion.



Item 3.	Quantitative and Qualitative Disclosures about Market Risk.

Our exposure to market risk is described in Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2013. We believe our exposure to market risk has not changed materially since then.



Item 4.	Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized, and reported within the time periods specified by the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

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Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2014, and, based upon this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended June 30, 2014 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

PART II. OTHER INFORMATION



Item 1.	Legal Proceedings.

We have no material pending legal proceedings that are required to be disclosed hereunder. For information regarding other legal proceedings, including regulatory and environmental matters, see Notes 4 and 15 of Notes to Condensed Consolidated Financial Statements, which information is incorporated by reference into this Part II.



Item 1A.	Risk Factors.

In addition to the other information set forth in this report, careful consideration should be given to the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013 which could materially affect our financial condition or future results. There have been no material changes to those risk factors.



Item 6.	Exhibits.

Any agreements included as exhibits to this Form 10-Q may contain representations and warranties by each of the parties to the applicable agreement. These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and:


•	were not intended to be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;


•	may have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement;


•	may apply contract standards of “materiality” that are different from “materiality” under the applicable securities laws; and


•	were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement.

We acknowledge that, notwithstanding the inclusion of the foregoing cautionary statements, we are responsible for considering whether additional specific disclosures of material information regarding material contractual provisions are required to make the statements in this Form 10-Q not misleading.

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(a) Exhibits



Exhibit Number

*+10.1		Omnibus Amendment, dated June 20, 2014, to Spectra Energy Corp Executive Savings Plan, Spectra Energy Corp Executive Cash Balance Plan and Spectra Energy Corp 2007 Long-Term Incentive Plan.

*+10.2		Form of Retention Stock Award Agreement (2014) pursuant to the Spectra Energy Corp 2007 Long-Term Incentive Plan.

*+10.3		Form of Change in Control Agreement (U.S.) (2014).

*+10.4		Form of Change in Control Agreement (Canada) (2014).

*31.1		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31.2		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*32.1		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*32.2		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*101.INS		XBRL Instance Document.

*101.SCH		XBRL Taxonomy Extension Schema.

*101.CAL		XBRL Taxonomy Extension Calculation Linkbase.

*101.DEF		XBRL Taxonomy Extension Definition Linkbase.

*101.LAB		XBRL Taxonomy Extension Label Linkbase.

*101.PRE		XBRL Taxonomy Extension Presentation Linkbase.



*	Filed herewith.
+	Denotes management contract or compensatory plan or arrangement.

The total amount of securities of the registrant or its subsidiaries authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10% of the total assets of the registrant and its subsidiaries on a consolidated basis. The registrant agrees, upon request of the Securities and Exchange Commission, to furnish copies of any or all of such instruments to it.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.




						SPECTRA ENERGY CORP

Date: August 7, 2014						/s/ Gregory L. Ebel
						Gregory L. Ebel
						President and Chief Executive Officer

Date: August 7, 2014						/s/ J. Patrick Reddy
						J. Patrick Reddy
						Chief Financial Officer