Edgar Filing: Spectra Energy Corp.

SE-2015.06.30 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, 2015



¨	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 the 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, 2015: 671,363,087

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SPECTRA ENERGY CORP

FORM 10-Q FOR THE QUARTER ENDED

June 30, 2015

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, 2015 and 2014	4
	Condensed Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2015 and 2014	5
	Condensed Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014	6
	Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2015 and 2014	8
	Condensed Consolidated Statements of Equity for the six months ended June 30, 2015 and 2014	9
	Notes to Condensed Consolidated Financial Statements	10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	44
Item 4.	Controls and Procedures	45

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	45
Item 1A.	Risk Factors	45
Item 6.	Exhibits	45
	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,
	2015			2014		2015			2014
Operating Revenues
Transportation, storage and processing of natural gas	$	802		$	780	$	1,644		$	1,667
Distribution of natural gas	238			309		845			935
Sales of natural gas liquids	31			40		97			227
Transportation of crude oil	90			70		174			141
Other	31			54		55			126
Total operating revenues	1,192			1,253		2,815			3,096
Operating Expenses
Natural gas and petroleum products purchased	119			209		551			737
Operating, maintenance and other	389			405		743			768
Depreciation and amortization	193			199		386			399
Property and other taxes	85			102		188			215
Total operating expenses	786			915		1,868			2,119
Operating Income	406			338		947			977
Other Income and Expenses
Earnings (loss) from equity investments	(189		)	85		(165		)	246
Other income and expenses, net	22			6		42			15
Total other income and expenses	(167		)	91		(123		)	261
Interest Expense	166			176		325			354
Earnings Before Income Taxes	73			253		499			884
Income Tax Expense (Benefit)	(7		)	65		94			229
Net Income	80			188		405			655
Net Income—Noncontrolling Interests	62			42		120			90
Net Income—Controlling Interests	$	18		$	146	$	285		$	565
Common Stock Data
Weighted-average shares outstanding
Basic	671			671		671			671
Diluted	672			673		672			672
Earnings per share
Basic and diluted	$	0.03		$	0.22	$	0.42		$	0.84
Dividends per share	$	0.37		$	0.335	$	0.74		$	0.67

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,
	2015			2014		2015			2014
Net Income	$	80		$	188	$	405		$	655
Other comprehensive income (loss):
Foreign currency translation adjustments	87			223		(405		)	(25		)
Non-cash mark-to-market net gain on hedges	—			1		—			3
Reclassification of cash flow hedges into earnings	—			1		—			3
Pension and benefits impact (net of taxes of $2, $3, $5 and $6, respectively)	7			6		13			13
Other	(1		)	—		—			—
Total other comprehensive income (loss)	93			231		(392		)	(6		)
Total Comprehensive Income, net of tax	173			419		13			649
Less: Comprehensive Income—Noncontrolling Interests	64			45		114			89
Comprehensive Income (Loss)—Controlling Interests	$	109		$	374	$	(101	)	$	560

See Notes to Condensed Consolidated Financial Statements.

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SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)



	June 30, 2015		December 31, 2014
ASSETS

Current Assets
Cash and cash equivalents	$	287	$	215
Receivables, net	880		1,336
Inventory	248		313
Fuel tracker	57		102
Other	265		366
Total current assets	1,737		2,332

Investments and Other Assets
Investments in and loans to unconsolidated affiliates	2,701		2,966
Goodwill	4,615		4,714
Other	307		327
Total investments and other assets	7,623		8,007

Property, Plant and Equipment
Cost	29,250		29,211
Less accumulated depreciation and amortization	6,969		6,904
Net property, plant and equipment	22,281		22,307

Regulatory Assets and Deferred Debits	1,403		1,394

Total Assets	$	33,044	$	34,040

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, 2015		December 31, 2014
LIABILITIES AND EQUITY

Current Liabilities
Accounts payable	$	557	$	458
Commercial paper	535		1,583
Taxes accrued	108		91
Interest accrued	188		181
Current maturities of long-term debt	917		327
Other	832		1,169
Total current liabilities	3,137		3,809

Long-term Debt	12,783		12,769

Deferred Credits and Other Liabilities
Deferred income taxes	5,459		5,405
Regulatory and other	1,328		1,401
Total deferred credits and other liabilities	6,787		6,806

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 shares outstanding at June 30, 2015 and December 31, 2014	1		1
Additional paid-in capital	4,990		4,956
Retained earnings	2,329		2,541
Accumulated other comprehensive income	276		662
Total controlling interests	7,596		8,160
Noncontrolling interests	2,483		2,238
Total equity	10,079		10,398

Total Liabilities and Equity	$	33,044	$	34,040

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,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	405		$	655
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	393			405
Deferred income tax expense	25			224
(Earnings) loss from equity investments	165			(246		)
Distributions received from unconsolidated affiliates	93			199
Other	375			(28		)
Net cash provided by operating activities	1,456			1,209
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(989		)	(833		)
Investments in and loans to unconsolidated affiliates	(34		)	(30		)
Purchases of held-to-maturity securities	(329		)	(437		)
Proceeds from sales and maturities of held-to-maturity securities	344			453
Purchases of available-for-sale securities	—			(13		)
Proceeds from sales and maturities of available-for-sale securities	1			7
Distributions received from unconsolidated affiliates	35			242
Other changes in restricted funds	(6		)	(1		)
Other	2			—
Net cash used in investing activities	(976		)	(612		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	994			712
Payments for the redemption of long-term debt	(39		)	(736		)
Net decrease in commercial paper	(1,030		)	(256		)
Distributions to noncontrolling interests	(93		)	(81		)
Contributions from noncontrolling interests	90			112
Proceeds from the issuances of Spectra Energy Partners, LP common units	180			191
Dividends paid on common stock	(499		)	(453		)
Other	(9		)	12
Net cash used in financing activities	(406		)	(499		)
Effect of exchange rate changes on cash	(2		)	1
Net increase in cash and cash equivalents	72			99
Cash and cash equivalents at beginning of period	215			201
Cash and cash equivalents at end of period	$	287		$	300
Supplemental Disclosures
Property, plant and equipment non-cash accruals	$	197		$	118

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, 2014	$	1	$	4,956	$	2,541		$	1,016		$	(354	)	$	2,238		$	10,398
Net income	—		—		285			—			—			120			405
Other comprehensive income (loss)	—		—		—			(399		)	13			(6		)	(392		)
Dividends on common stock	—		—		(498		)	—			—			—			(498		)
Stock-based compensation	—		6		—			—			—			—			6
Distributions to noncontrolling interests	—		—		—			—			—			(93		)	(93		)
Contributions from noncontrolling interests	—		—		—			—			—			90			90
Spectra Energy common stock issued	—		1		—			—			—			—			1
Spectra Energy Partners, LP common units issued	—		25		—			—			—			139			164
Other, net	—		2		1			—			—			(5		)	(2		)
June 30, 2015	$	1	$	4,990	$	2,329		$	617		$	(341	)	$	2,483		$	10,079

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

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, 2014, 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. Business Segments

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

Our 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.

Spectra Energy's presentation of its Spectra Energy Partners segment is reflective of the parent-level focus by our CODM, considering the resource allocation and governance provisions associated with SEP’s master limited partnership structure. SEP maintains a capital and cash management structure that is separate from Spectra Energy’s, is self-funding and maintains its own lines of bank credit and cash management accounts. From a Spectra Energy perspective, our CODM evaluates the Spectra Energy Partners segment as a whole, without regard to any of SEP’s individual businesses.

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

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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 U.S. 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 and M&N Canada 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, recovers and sells condensate, and trades and markets natural gas and NGLs. It conducts operations through DCP Midstream, which is owned 50% by us and 50% by Phillips 66. DCP Midstream gathers raw natural gas through gathering systems connecting to several interstate and intrastate natural gas and NGL pipeline systems, one natural gas storage facility and one NGL storage facility. DCP Midstream operates in a diverse number of regions, including the Permian Basin, Eagle Ford, Niobrara/DJ Basin and the Midcontinent. DCP Midstream Partners, LP (DCP Partners) is a publicly traded master limited partnership, of which DCP Midstream acts as general partner. As of June 30, 2015, DCP Midstream had an approximate 21% ownership interest in DCP Partners, including DCP Midstream’s limited partner and general partner interests.

Our reportable segments offer different products and services and are managed separately as business units. Management evaluates segment performance based on earnings 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, 2015
Spectra Energy Partners	$	603	$	—		$	603		$	72	$	478
Distribution	290		—			290			45		98
Western Canada Transmission & Processing	297		7			304			63		104
Field Services	—		—			—			—		(233		)
Total reportable segments	1,190		7			1,197			180		447
Other	2		15			17			13		(12		)
Eliminations	—		(22		)	(22		)	—		—
Depreciation and amortization	—		—			—			—		193
Interest expense	—		—			—			—		166
Interest income and other (a)	—		—			—			—		(3		)
Total consolidated	$	1,192	$	—		$	1,192		$	193	$	73

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 (a)	—		—			—			—		1
Total consolidated	$	1,253	$	—		$	1,253		$	199	$	253

Six Months Ended June 30, 2015
Spectra Energy Partners	$	1,209	$	—		$	1,209		$	146	$	933
Distribution	952		—			952			90		290
Western Canada Transmission & Processing	650		24			674			125		265
Field Services	—		—			—			—		(250		)
Total reportable segments	2,811		24			2,835			361		1,238
Other	4		31			35			25		(27		)
Eliminations	—		(55		)	(55		)	—		—
Depreciation and amortization	—		—			—			—		386
Interest expense	—		—			—			—		325
Interest income and other (a)	—		—			—			—		(1		)
Total consolidated	$	2,815	$	—		$	2,815		$	386	$	499

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 (a)	—		—			—			—		5
Total consolidated	$	3,096	$	—		$	3,096		$	399	$	884

___________________________________


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

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3. Regulatory Matters

Union Gas. In 2012, the OEB determined that revenues derived from the optimization of Union Gas’ upstream transportation contracts in 2011 would be treated as a reduction to gas costs rather than being treated as optimization revenues and included in utility earnings. In May 2014, Union Gas filed a notice of appeal to the Ontario Court of Appeal and a hearing was held in December 2014. The appeal was dismissed in June 2015 and no further appeals will be filed.

In December 2014, Union Gas filed an application with the OEB for the disposition of the 2013 energy conservation deferral and variance account balances. As a result of this application, Union Gas has a receivable from customers of approximately $8 million and $9 million at June 30, 2015 and December 31, 2014, respectively, which is reflected as Current Assets—Other on the Condensed Consolidated Balance Sheets. A written hearing concluded in April 2015. In June 2015, a decision from the OEB was received approving recovery from ratepayers effective July 1, 2015.

In April 2015, the OEB issued its decision on Union Gas’ application for an order approving an interruptible liquefied natural gas (LNG) service. The OEB determined that it would not regulate this service, as it was satisfied that there is LNG competition sufficient to protect the public interest and approved the proposed cross charges between the regulated and unregulated services until an application for new rates in 2019 is filed. At this time, Union Gas does not expect any material financial impact as a result of this decision.

4. Income Taxes

Income tax benefit was $7 million for the three months ended June 30, 2015, compared to an income tax expense of $65 million for the same period in 2014. Income tax expense was $94 million for the six months ended June 30, 2015, compared to $229 million for the same period in 2014. The lower tax expense for both periods was primarily due to the $72 million tax impact of the impairment of goodwill at DCP Midstream, lower earnings and the effect of a weaker Canadian dollar.

The effective income tax rate was negative 10% for the three months ended June 30, 2015, compared to 26% for the same period in 2014. The effective income tax rate was 19% for the six months ended June 30, 2015, compared to 26% for the same period in 2014. The lower effective income tax rates in both periods were primarily attributable to the $72 million tax impact of the impairment of goodwill at DCP Midstream.

There was a $6 million increase in unrecognized tax benefits recorded during the six months ended June 30, 2015. Although uncertain, we believe it is reasonably possible that the total amount of unrecognized tax benefits could decrease by approximately $25 million to $30 million prior to June 30, 2016, as a result of the expiration of statutes of limitations and expected audit settlements.

5. 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.

The following table presents our basic and diluted EPS calculations:



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(in millions, except per-share amounts)
Net income—controlling interests	$	18	$	146	$	285	$	565
Weighted-average common shares outstanding
Basic	671		671		671		671
Diluted	672		673		672		672
Basic and diluted earnings per common share (a)	$	0.03	$	0.22	$	0.42	$	0.84

___________________

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

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6. 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, 2015	$	532		$	(345	)		$	—		$	(2	)	$	185
Other AOCI activity	85			7				—			(1		)	91
June 30, 2015	$	617		$	(338	)		$	—		$	(3	)	$	276

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

December 31, 2014	$	1,016		$	(351	)		$	(3	)	$	—		$	662
Other AOCI activity	(399		)	13				3			(3		)	(386		)
June 30, 2015	$	617		$	(338	)		$	—		$	(3	)	$	276

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

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

7. 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, 2015		December 31, 2014
	(in millions)
Natural gas	$	134	$	211
NGLs	42		28
Materials and supplies	72		74
Total inventory	$	248	$	313

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8. 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,
	2015			2014		2015			2014
	(in millions)
Operating revenues	$	1,869		$	3,541	$	3,912		$	7,456
Operating expenses	2,332			3,387		4,323			7,032
Operating income (loss)	(463		)	154		(411		)	424
Net income (loss)	(491		)	92		(497		)	295
Net income (loss) attributable to members’ interests	(466		)	89		(503		)	254

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 in the second quarter of 2014, and $2 million and $57 million during the six month periods ending June 30, 2015 and 2014, respectively, are reflected in Earnings (Loss) From Equity Investments in the Condensed Consolidated Statements of Operations.

Due to the significant downturn in commodity prices over the past three quarters, including further deterioration in the second quarter of 2015, DCP Midstream determined it was more likely than not that the estimated fair values of certain of its goodwill reporting units and certain of DCP Partners goodwill reporting units were below their carrying amount, and performed a goodwill impairment test. The impairment test was based on an internal discounted cash flow model taking into account various observable and non-observable factors, such as prices, volumes, expenses and discount rate. The impairment test resulted in DCP Midstream’s recognition of a $427 million goodwill impairment during the second quarter of 2015, which reduced our equity earnings from DCP Midstream by $122 million after-tax. This impairment represents DCP Midstream’s best estimate pending finalization of the fair value assessments.

Due to the impairment of goodwill recognized by DCP Midstream, we assessed our equity investment in DCP Midstream and determined that no indicators of impairment were noted.

9. 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, 2015 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 and Spectra Energy Partners reportable segments, which are one level below.

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

Our Empress NGL and BC Field Services businesses, reporting units within Western Canada Transmission & Processing, are affected by commodity prices. We performed our Empress NGL and BC Field Services reporting units’ impairment tests using updated assumptions and financial data and concluded that there was no impairment of goodwill for either business unit.

See Note 8 for discussion related to the impairment of goodwill recognized by DCP Midstream.

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10. Marketable Securities and Restricted Funds

We routinely invest excess cash and various restricted balances in securities such as commercial paper, banker’s acceptances, corporate debt securities, treasury bills and money market funds in the U.S. and Canada. We do not purchase marketable securities for speculative purposes; therefore we do not have any securities classified as trading securities. While we do not routinely sell marketable securities prior to their scheduled maturity dates, some of our investments may be held and restricted for insurance purposes, 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, 2015		December 31, 2014
	(in millions)
Corporate debt securities	$	22	$	23
Money market funds	—		1
Total available-for-sale securities	$	22	$	24

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



	Estimated Fair Value
	June 30, 2015		December 31, 2014
	(in millions)
Restricted funds
Investments and other assets—other	$	—	$	1
Non-restricted funds
Current assets—other	2		3
Investments and other assets—other	20		20
Total available-for-sale securities	$	22	$	24

At June 30, 2015, the weighted-average contractual maturity of outstanding AFS securities was less than one year.

There were no material gross unrealized holding gains or losses associated with investments in AFS securities at June 30, 2015 or December 31, 2014.

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



		Estimated Fair Value
Description	Condensed Consolidated Balance Sheets Caption	June 30, 2015		December 31, 2014
		(in millions)
Banker’s acceptances	Current assets—other	$	34	$	38
Canadian government securities	Current assets—other	27		30
Money market funds	Current assets—other	3		3
Canadian government securities	Investments and other assets—other	81		101
Total held-to-maturity securities		$	145	$	172

All of our HTM securities are restricted funds pursuant to certain M&N Canada and Express-Platte (our crude oil pipeline system) debt agreements. The funds restricted for M&N Canada, plus future cash from operations that would otherwise be available for distribution to the partners of M&N Canada, are required to be placed in escrow until the balance in escrow is sufficient to fund all future debt service on the M&N Canada 6.90% senior secured notes. There are sufficient funds held in escrow to fund all future debt service on these M&N Canada notes as of June 30, 2015.

At June 30, 2015, the weighted-average contractual maturity of outstanding HTM securities was less than one year.

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There were no material gross unrecognized holding gains or losses associated with investments in HTM securities at June 30, 2015 or December 31, 2014.

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 $13 million at June 30, 2015 and $13 million at December 31, 2014 classified as Current Assets—Other. These restricted funds are related to additional amounts for insurance. We also had other restricted funds totaling $12 million at June 30, 2015 and $6 million at December 31, 2014 classified as Investments and Other Assets—Other. These restricted funds are related to funds held and collected from customers for Canadian pipeline abandonment in accordance with the NEB’s regulatory requirements.

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

11. Debt and Credit Facilities

Available Credit Facilities and Restrictive Debt Covenants



	Expiration Date	Total Credit Facilities Capacity		Commercial Paper Outstanding at June 30, 2015		Available Credit Facilities Capacity
	Expiration Date	Total Credit Facilities Capacity		Commercial Paper Outstanding at June 30, 2015		Available Credit Facilities Capacity
		(in millions)
Spectra Energy Capital, LLC (a)	2019	$	1,000	$	497	$	503
SEP (b)	2019	2,000		38		1,962
Westcoast Energy Inc. (c)	2019	320		—		320
Union Gas (d)	2019	400		—		400
Total		$	3,720	$	535	$	3,185

___________


(a)	Revolving credit facility contains a covenant requiring the Spectra Energy Corp consolidated debt-to-total capitalization ratio, as defined in the agreement, to not exceed 65%. Per the terms of the agreement, collateralized debt is excluded from the calculation of the ratio. This ratio was 58% at June 30, 2015.


(b)	Revolving credit facility contains a covenant that requires SEP to maintain a ratio of total Consolidated Indebtedness-to-Consolidated EBITDA, as defined in the credit agreement, of 5.0 to 1 or less. As of June 30, 2015, this ratio was 3.5 to 1.


(c)	U.S. dollar equivalent at June 30, 2015. The revolving credit facility is 400 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 33% at June 30, 2015.


(d)	U.S. dollar equivalent at June 30, 2015. The revolving credit facility is 500 million Canadian dollars and contains a covenant that requires the Union Gas debt-to-total capitalization ratio to not exceed 75% and a provision which requires Union Gas to repay all borrowings under the facility for a period of two days during the second quarter of each year. The ratio was 64% at June 30, 2015.

The issuances of commercial paper, letters of credit and revolving borrowings reduce the amount available under the credit facilities. As of June 30, 2015, 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, 2015, 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 March 12, 2015, SEP issued $500 million of 3.50% unsecured notes due 2025 and $500 million of 4.50% unsecured notes due 2045. Net proceeds from the offering were used to repay a portion of outstanding commercial paper, to fund capital expenditures and for general corporate purposes.

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12. 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, 2015
Description	Condensed Consolidated Balance Sheet Caption	Total		Level 1		Level 2		Level 3
		(in millions)
Corporate debt securities	Cash and cash equivalents	$	91	$	—	$	91	$	—
Corporate debt securities	Current assets—other	2		—		2		—
Commodity derivatives	Current assets—other	45		—		—		45
Interest rate swaps	Current assets—other	1		—		1		—
Commodity derivatives	Investments and other assets—other	5		—		—		5
Corporate debt securities	Investments and other assets—other	20		—		20		—
Interest rate swaps	Investments and other assets—other	26		—		26		—
Total Assets		$	190	$	—	$	140	$	50



Description	Condensed Consolidated Balance Sheet Caption	December 31, 2014
Description	Condensed Consolidated Balance Sheet Caption	Total		Level 1		Level 2		Level 3
		(in millions)
Corporate debt securities	Cash and cash equivalents	$	85	$	—	$	85	$	—
Corporate debt securities	Current assets—other	3		—		3		—
Commodity derivatives	Current assets—other	57		—		—		57
Interest rate swaps	Current assets—other	2		—		2		—
Commodity derivatives	Investments and other assets—other	21		—		—		21
Corporate debt securities	Investments and other assets—other	20		—		20		—
Interest rate swaps	Investments and other assets—other	22		—		22		—
Money market funds	Investments and other assets—other	1		1		—		—
Total Assets		$	211	$	1	$	132	$	78

The following presents changes in Level 3 assets and 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,
	2015			2014			2015			2014
	(in millions)
Derivative assets (liabilities)
Fair value, beginning of period	$	49		$	(5	)	$	78		$	(3	)
Total gains (losses):
Included in earnings	3			(5		)	9			(9		)
Included in other comprehensive income	1			1			(5		)	4
Purchases	2			—			3			—
Settlements	(5		)	—			(35		)	(1		)
Fair value, end of period	$	50		$	(9	)	$	50		$	(9	)
Unrealized gains (losses) relating to instruments held at the end of the period	$	—		$	(4	)	$	(16	)	$	(7	)

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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

Level 3 valuation techniques include the use of pricing models, discounted cash flow methodologies or similar techniques where at least one significant model assumption or input is unobservable. Level 3 financial instruments also include those for which the determination of fair value requires significant management judgment or estimation.

The derivative financial instruments reported in Level 3 at June 30, 2015 consist of NGL revenue swap contracts related to the Empress assets in Western Canada Transmission & Processing. As of June 30, 2015, we reported certain of our NGL basis swaps at fair value using Level 3 inputs due to such derivatives not having observable market prices for substantially the full term of the derivative asset or liability. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract length extends into unobservable periods.

The fair value of these NGL basis swaps is determined using a discounted cash flow valuation technique based on a forward commodity basis curve. For these derivatives, the primary input to the valuation model is the forward commodity basis curve, which is based on observable or public data sources and extrapolated when observable prices are not available.

The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives are the forward NGL basis curves, for which a significant portion of the derivative’s term is beyond available forward pricing. At June 30, 2015, a 10¢ per gallon movement in underlying forward NGL prices, primarily propane prices, would affect the estimated fair value of our NGL derivatives by $18 million. This calculated amount does not take into account any other changes to the fair value measurement calculation.

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, 2015				December 31, 2014
	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)	13,673		14,683		13,060		14,446

__________


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


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

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

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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 six months ended June 30, 2015 and 2014, there were no material adjustments to assets and liabilities measured at fair value on a nonrecurring basis.

13. 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 operations associated with our U.S. pipeline assets. Exposure to interest rate risk exists as a result of the issuance of variable and fixed-rate debt and commercial paper. We are exposed to foreign currency risk from our Canadian operations. We employ established policies and procedures to manage our risks associated with these market fluctuations, which may include the use of derivatives, mostly around interest rate and commodity exposures.

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

Other than the interest rate swaps and commodity derivatives as described below, we did not have significant derivatives outstanding during the six months ended June 30, 2015.

Interest Rate Swaps

At June 30, 2015, we had “pay floating—receive fixed” interest rate swaps outstanding with a total notional amount of $2,100 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, 2015						December 31, 2014
	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	$	27	$	—	$	27	$	24	$	—	$	24

Commodity Derivatives

At June 30, 2015, we had commodity mark-to-market derivatives outstanding with a total notional amount of 175 million gallons. The longest dated commodity derivative contract we currently have expires in 2018.

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



	June 30, 2015						December 31, 2014
	Gross Amounts		Gross Amounts Offset		Net Amount Presented in the Condensed Consolidated Balance Sheets		Gross Amounts		Gross Amounts Offset		Net Amount Presented in the Condensed Consolidated Balance Sheets
Description	(in millions)
Assets	$	144	$	94	$	50	$	169	$	91	$	78
Liabilities	94		94		—		91		91		—

Substantially all of our commodity derivative agreements outstanding at June 30, 2015 and December 31, 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:



		Three Months Ended June 30,					Six Months Ended June 30,
Derivatives	Condensed Consolidated Statements of Operations Caption	2015		2014			2015		2014
		(in millions)
Commodity derivatives	Sales of natural gas liquids	$	5	$	(4	)	$	12	$	(7	)

14. 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, 2015 or December 31, 2014 related to litigation.

Other Commitments and Contingencies

See Note 15 for a discussion of guarantees and indemnifications.

15. 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, 2015 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, 2015, the amounts recorded for the guarantees and indemnifications described above are not material, both individually and in the aggregate.

16. Issuances of SEP Units

During the six months ended June 30, 2015, SEP issued 3.6 million common units to the public under its at-the-market program and approximately 74,000 general partner units to Spectra Energy. Total net proceeds to SEP were $184 million (net proceeds to Spectra Energy were $180 million). In connection with the issuances of the units, a $40 million gain ($25 million net of tax) to Additional Paid-in Capital and a $139 million increase in Equity-Noncontrolling Interests were recorded during the six months ended June 30, 2015. The issuances decreased Spectra Energy's ownership in SEP from 82% to 81% at June 30, 2015.

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(in millions)
Net income-controlling interests	$	18	$	146	$	285	$	565
Increase in additional paid-in capital resulting from issuances of SEP units	19		19		25		29
Total net income-controlling interests and changes in equity-controlling interests	$	37	$	165	$	310	$	594

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17. Employee Benefit Plans

Retirement Plans. We have a qualified non-contributory defined benefit (DB) retirement plan for 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.

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 $11 million to our U.S. retirement plans in the six months ended June 30, 2015 and $10 million in the same period in 2014. We made total contributions to the Canadian DC and DB plans of $16 million in the six months ended June 30, 2015 and $26 million in the same period in 2014. We anticipate that we will make total contributions of approximately $22 million to the U.S. plans and approximately $31 million to the Canadian plans in 2015.

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in millions)
U.S.
Service cost benefit earned	$	5		$	4		$	10		$	9
Interest cost on projected benefit obligation	6			6			12			12
Expected return on plan assets	(11		)	(9		)	(21		)	(19		)
Amortization of loss	3			3			5			6
Net periodic pension cost	$	3		$	4		$	6		$	8

Canada
Service cost benefit earned	$	8		$	8		$	16		$	15
Interest cost on projected benefit obligation	11			13			22			26
Expected return on plan assets	(17		)	(18		)	(34		)	(35		)
Amortization of loss	6			5			13			11
Amortization of prior service cost	1			1			1			1
Net periodic pension cost	$	9		$	9		$	18		$	18

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,
	2015			2014			2015			2014
	(in millions)
U.S.
Interest cost on accumulated post-retirement benefit obligation	$	2		$	2		$	4		$	4
Expected return on plan assets	(2		)	(1		)	(3		)	(2		)
Net periodic other post-retirement benefit cost	$	—		$	1		$	1		$	2

Canada
Service cost benefit earned	$	1		$	1		$	2		$	2
Interest cost on accumulated post-retirement benefit obligation	1			2			2			3
Net periodic other post-retirement benefit cost	$	2		$	3		$	4		$	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 of the three months ended June 30, 2015 and 2014, and $7 million in both of the six months ended June 30, 2015 and 2014 for U.S. employees. We expensed pre-tax employer matching contributions of $2 million and $3 million in the three months ended June 30, 2015 and 2014, respectively, and $5 million and $6 million in the six months ended June 30, 2015 and 2014, respectively, for Canadian employees.

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18. Condensed Consolidating Financial Information

Spectra Energy Corp has agreed to fully and unconditionally guarantee the payment of principal and interest under all series of notes outstanding under the Senior Indenture of Spectra Energy Capital, LLC (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, 2015
Total operating revenues	$	—		$	—		$	1,192		$	—		$	1,192
Total operating expenses	1			(1		)	786			—			786
Operating income (loss)	(1		)	1			406			—			406
Loss from equity investments	—			—			(189		)	—			(189		)
Equity in earnings of consolidated subsidiaries	12			62			—			(74		)	—
Other income and expenses, net	2			—			20			—			22
Interest expense	—			61			105			—			166
Earnings before income taxes	13			2			132			(74		)	73
Income tax expense (benefit)	(5		)	(10		)	8			—			(7		)
Net income	18			12			124			(74		)	80
Net income—noncontrolling interests	—			—			62			—			62
Net income—controlling interests	$	18		$	12		$	62		$	(74	)	$	18

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
Earnings from equity investments	—			—			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

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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, 2015
Total operating revenues	$	—		$	—		$	2,816		$	(1	)	$	2,815
Total operating expenses	3			(1		)	1,867			(1		)	1,868
Operating income (loss)	(3		)	1			949			—			947
Loss from equity investments	—			—			(165		)	—			(165		)
Equity in earnings of consolidated subsidiaries	275			483			—			(758		)	—
Other income and expenses, net	—			—			42			—			42
Interest expense	—			122			203			—			325
Earnings before income taxes	272			362			623			(758		)	499
Income tax expense (benefit)	(13		)	87			20			—			94
Net income	285			275			603			(758		)	405
Net income—noncontrolling interests	—			—			120			—			120
Net income—controlling interests	$	285		$	275		$	483		$	(758	)	$	285

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
Earnings from equity investments	—			—			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

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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, 2015
Net income	$	18	$	12	$	124		$	(74	)	$	80
Other comprehensive income	2		—		91			—			93
Total comprehensive income, net of tax	20		12		215			(74		)	173
Less: comprehensive income—noncontrolling interests	—		—		64			—			64
Comprehensive income—controlling interests	$	20	$	12	$	151		$	(74	)	$	109

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

Six Months Ended June 30, 2015
Net income	$	285	$	275	$	603		$	(758	)	$	405
Other comprehensive income (loss)	3		—		(395		)	—			(392		)
Total comprehensive income, net of tax	288		275		208			(758		)	13
Less: comprehensive income—noncontrolling interests	—		—		114			—			114
Comprehensive income (loss)—controlling interests	$	288	$	275	$	94		$	(758	)	$	(101	)

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

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Spectra Energy Corp

Condensed Consolidating Balance Sheet

June 30, 2015

(Unaudited)

(In millions)



	Spectra Energy Corp		Spectra Capital		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Cash and cash equivalents	$	—	$	2	$	285	$	—		$	287
Receivables—consolidated subsidiaries	10		—		18		(28		)	—
Notes receivable—current—consolidated subsidiaries	—		—		388		(388		)	—
Receivables—other	2		—		878		—			880
Other current assets	8		1		561		—			570
Total current assets	20		3		2,130		(416		)	1,737
Investments in and loans to unconsolidated affiliates	—		—		2,701		—			2,701
Investments in consolidated subsidiaries	14,515		20,198		—		(34,713		)	—
Advances receivable—consolidated subsidiaries	—		5,212		901		(6,113		)	—
Notes receivable—consolidated subsidiaries	—		—		2,800		(2,800		)	—
Goodwill	—		—		4,615		—			4,615
Other assets	41		23		243		—			307
Net property, plant and equipment	—		—		22,281		—			22,281
Regulatory assets and deferred debits	2		14		1,387		—			1,403
Total Assets	$	14,578	$	25,450	$	37,058	$	(44,042	)	$	33,044

Accounts payable	$	3	$	4	$	550	$	—		$	557
Accounts payable—consolidated subsidiaries	—		23		5		(28		)	—
Commercial paper	—		497		38		—			535
Short-term borrowings—consolidated subsidiaries	—		388		—		(388		)	—
Taxes accrued	5		18		85		—			108
Current maturities of long-term debt	—		—		917		—			917
Other current liabilities	69		53		898		—			1,020
Total current liabilities	77		983		2,493		(416		)	3,137
Long-term debt	—		2,900		9,883		—			12,783
Advances payable—consolidated subsidiaries	6,113		—		—		(6,113		)	—
Notes payable—consolidated subsidiaries	—		2,800		—		(2,800		)	—
Deferred credits and other liabilities	792		4,252		1,743		—			6,787
Preferred stock of subsidiaries	—		—		258		—			258
Equity
Controlling interests	7,596		14,515		20,198		(34,713		)	7,596
Noncontrolling interests	—		—		2,483		—			2,483
Total equity	7,596		14,515		22,681		(34,713		)	10,079
Total Liabilities and Equity	$	14,578	$	25,450	$	37,058	$	(44,042	)	$	33,044

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Spectra Energy Corp

Condensed Consolidating Balance Sheet

December 31, 2014

(Unaudited)

(In millions)



	Spectra Energy Corp		Spectra Capital		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Cash and cash equivalents	$	—	$	1	$	214	$	—		$	215
Receivables—consolidated subsidiaries	18		—		11		(29		)	—
Notes receivable—current—consolidated subsidiaries	—		—		398		(398		)	—
Receivables—other	2		—		1,334		—			1,336
Other current assets	71		2		708		—			781
Total current assets	91		3		2,665		(427		)	2,332
Investments in and loans to unconsolidated affiliates	—		—		2,966		—			2,966
Investments in consolidated subsidiaries	14,531		20,562		—		(35,093		)	—
Advances receivable—consolidated subsidiaries	—		4,683		898		(5,581		)	—
Notes receivable—consolidated subsidiaries	—		—		2,800		(2,800		)	—
Goodwill	—		—		4,714		—			4,714
Other assets	38		22		267		—			327
Net property, plant and equipment	—		—		22,307		—			22,307
Regulatory assets and deferred debits	4		15		1,375		—			1,394
Total Assets	$	14,664	$	25,285	$	37,992	$	(43,901	)	$	34,040

Accounts payable	$	3	$	—	$	455	$	—		$	458
Accounts payable—consolidated subsidiaries	—		17		12		(29		)	—
Commercial paper	—		398		1,185		—			1,583
Short-term borrowings—consolidated subsidiaries	—		398		—		(398		)	—
Taxes accrued	5		—		86		—			91
Current maturities of long-term debt	—		—		327		—			327
Other current liabilities	96		54		1,200		—			1,350
Total current liabilities	104		867		3,265		(427		)	3,809
Long-term debt	—		2,900		9,869		—			12,769
Advances payable—consolidated subsidiaries	5,581		—		—		(5,581		)	—
Notes payable—consolidated subsidiaries	—		2,800		—		(2,800		)	—
Deferred credits and other liabilities	819		4,187		1,800		—			6,806
Preferred stock of subsidiaries	—		—		258		—			258
Equity
Controlling interests	8,160		14,531		20,562		(35,093		)	8,160
Noncontrolling interests	—		—		2,238		—			2,238
Total equity	8,160		14,531		22,800		(35,093		)	10,398
Total Liabilities and Equity	$	14,664	$	25,285	$	37,992	$	(43,901	)	$	34,040

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Spectra Energy Corp

Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2015

(Unaudited)

(In millions)



	Spectra Energy Corp			Spectra Capital			Non-Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	285		$	275		$	603		$	(758	)	$	405
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	—			—			393			—			393
Loss from equity investments	—			—			165			—			165
Equity in earnings of consolidated subsidiaries	(275		)	(483		)	—			758			—
Distributions received from unconsolidated affiliates	—			—			93			—			93
Other	30			68			302			—			400
Net cash provided by (used in) operating activities	40			(140		)	1,556			—			1,456
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	—			—			(989		)	—			(989		)
Investments in and loans to unconsolidated affiliates	—			—			(34		)	—			(34		)
Purchases of held-to-maturity securities	—			—			(329		)	—			(329		)
Proceeds from sales and maturities of held-to-maturity securities	—			—			344			—			344
Proceeds from sales and maturities of available-for-sale securities	—			—			1			—			1
Distributions received from unconsolidated affiliates	—			—			35			—			35
Advances (to) from affiliates	(72		)	46			—			26			—
Other changes in restricted funds	—			—			(6		)	—			(6		)
Other	—						2						2
Net cash provided by (used in) investing activities	(72		)	46			(976		)	26			(976		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	—			—			994			—			994
Payments for the redemption of long-term debt	—			—			(39		)	—			(39		)
Net increase (decrease) in commercial paper	—			99			(1,129		)	—			(1,030		)
Distributions to noncontrolling interests	—			—			(93		)	—			(93		)
Contributions from noncontrolling interests	—			—			90			—			90
Proceeds from the issuance of SEP common units	—			—			180			—			180
Dividends paid on common stock	(499		)	—			—			—			(499		)
Distributions and advances from (to) affiliates	532			(4		)	(502		)	(26		)	—
Other	(1		)	—			(8		)	—			(9		)
Net cash provided by (used in) financing activities	32			95			(507		)	(26		)	(406		)
Effect of exchange rate changes on cash	—			—			(2		)	—			(2		)
Net increase in cash and cash equivalents	—			1			71			—			72
Cash and cash equivalents at beginning of period	—			1			214			—			215
Cash and cash equivalents at end of period	$	—		$	2		$	285		$	—		$	287

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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
Earnings from equity investments	—			—			(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
Proceeds from the issuance of SEP common units	—			—			191			—			191
Dividends paid on common stock	(453		)	—			—			—			(453		)
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

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19. 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. In July 2015, the FASB decided to defer the effective date of the new revenue standard for one year and to permit entities to early adopt the standard as of the original effective date. This ASU is effective for us January 1, 2018. We are currently evaluating this ASU and its potential impact on us.

In February 2015, the FASB issued ASU No. 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis,” which makes changes to both the variable interest model and the voting model. These changes will require re-evaluation of certain entities for consolidation and will require us to revise our documentation regarding the consolidation or deconsolidation of such entities. ASU No. 2015-02 is effective for us January 1, 2016. We are currently evaluating this ASU and its potential impact on us.

In April 2015, the FASB issued ASU No. 2015-03, “Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,” which requires that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, rather than as a deferred charge asset. ASU No. 2015-03 is effective for us January 1, 2016 and is to be applied retrospectively. Early application is permitted. This ASU is not expected to have a material impact on our consolidated results of operations, financial position or cash flow.



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.

Executive Overview

For the three months ended June 30, 2015 and 2014, we reported net income from controlling interests of $18 million and $146 million, respectively. For the six months ended June 30, 2015 and 2014, we reported net income from controlling interests of $285 million and $565 million, respectively.

The highlights for the three months and six months ended June 30, 2015 include the following:


•	Spectra Energy Partners’ earnings for the three and six-month periods benefited mainly from expansions, primarily on Texas Eastern Transmission, LP (Texas Eastern), lower operating costs and higher earnings from equity investments.


•	Distribution’s earnings for the three-month period decreased mainly due to a weaker Canadian dollar. For the six-month period, earnings decreased due to a weaker Canadian dollar and the first quarter 2014 results including regulatory decisions from the OEB that, in aggregate, provided a benefit.

•

Western Canada Transmission & Processing’s earnings for the three-month period decreased mainly due to a weaker Canadian dollar and overhead reduction costs, partially offset by favorable results at the Empress operations due in large part to the 2014 plant turnaround. The decrease in earnings for the six-month period was mainly due to lower NGL sales prices, net of settlement gains associated with the risk management program at the Empress operations, a weaker Canadian dollar and overhead reduction costs.

•

Field Services’ earnings for the three-month period decreased largely due to an impairment of goodwill at DCP Midstream and lower commodity prices, partially offset by asset growth and improved operating efficiencies and other initiatives. For the six-month period, earnings decreased mainly due to an impairment of goodwill at DCP Midstream, lower commodity prices and lower gains associated with the issuance of partnership units by DCP Partners, partially offset by asset growth, improved operating efficiencies and other initiatives.

In the first six months of 2015, we had $1.0 billion of capital and investment expenditures. We currently project $3.5 billion of capital and investment expenditures for the full year, including expansion capital expenditures of $2.8 billion.

We are committed to an investment-grade balance sheet and continued prudent financial management of our capital structure. Therefore, financing growth activities will continue to be based on our strong and growing fee-based earnings and cash flows as well as the issuances of debt and equity securities. As of June 30, 2015, our revolving credit facilities included

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Spectra Capital’s $1.0 billion facility, SEP’s $2.0 billion facility, Westcoast’s 400 million Canadian dollar facility and Union Gas’ 500 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,
	2015			2014		2015			2014
	(in millions)
Operating revenues	$	1,192		$	1,253	$	2,815		$	3,096
Operating expenses	786			915		1,868			2,119
Operating income	406			338		947			977
Other income and expenses	(167		)	91		(123		)	261
Interest expense	166			176		325			354
Earnings before income taxes	73			253		499			884
Income tax expense (benefit)	(7		)	65		94			229
Net income	80			188		405			655
Net income—noncontrolling interests	62			42		120			90
Net income—controlling interests	$	18		$	146	$	285		$	565

Three Months Ended June 30, 2015 Compared to Same Period in 2014

Operating Revenues. The $61 million, or 5%, decrease was driven by:


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


•	lower sales volumes of residual natural gas and lower NGL prices, net of higher NGL sales volumes due to the 2014 plant turnaround and an increase from settlement gains associated with the risk management program at the Empress operations at Western Canada Transmission & Processing and


•	lower natural gas prices passed through to customers and lower customer usage of natural gas primarily due to warmer weather, at Distribution, partially offset by


•	revenues from expansion projects primarily on Texas Eastern and East Tennessee Natural Gas, LLC (East Tennessee), higher crude oil transportation revenues mainly as a result of higher contracted volumes and higher tariff revenues mainly at the Express pipeline, all at Spectra Energy Partners.

Operating Expenses. The $129 million, or 14%, decrease was driven by:


•	decreased volumes of natural gas purchases for extraction and make-up and lower costs of sales at the Empress operations, net of overhead reduction costs at Western Canada Transmission & Processing,


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


•	lower volumes of natural gas sold due to warmer weather, net of higher operating fuel costs at Distribution and


•	lower operating costs primarily due to ad valorem tax accruals at Spectra Energy Partners.

Other Income and Expenses. The $258 million, or 284%, decrease was attributable to lower equity earnings from Field Services mainly due to an impairment of goodwill at DCP Midstream and lower commodity prices, net of increased gathering and processing margins as a result of asset growth and improved operating efficiencies and other initiatives. These decreases were partially offset by higher allowance for funds used during construction (AFUDC) resulting from higher capital spending and higher equity earnings from DCP Sand Hills Pipeline, LLC (Sand Hills) as a result of higher volumes at Spectra Energy Partners.

Interest Expense. The $10 million, or 6%, decrease was mainly due to a weaker Canadian dollar.

Income Tax Expense. The $72 million decrease was primarily attributable to the tax impact on the impairment of goodwill at DCP Midstream.

The effective tax rate for income from continuing operations was negative 10% for the three months ended June 30, 2015, compared to 26% for the same period in 2014.

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Net Income—Noncontrolling Interests. The $20 million increase was driven primarily by higher earnings from Spectra Energy Partners.

Six Months Ended June 30, 2015 Compared to Same Period in 2014

Operating Revenues. The $281 million, or 9%, decrease was driven by:


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


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


•	lower customer usage due to warmer weather, the first quarter 2014 results including regulatory decisions from the OEB that, in aggregate, provided a benefit and growth in the number of customers at Distribution, partially offset by

•

revenues from expansion projects primarily on Texas Eastern and East Tennessee, higher crude oil transportation revenues mainly as a result of higher contracted volumes and higher tariff revenues mainly at the Express pipeline and an increase in recoveries of electric power and other costs passed through to gas transmission customers, net of lower other transportation revenues on East Tennessee and interruptible transportation on Texas Eastern at Spectra Energy Partners.

Operating Expenses. The $251 million, or 12%, decrease was driven by:


•	decreased volumes of natural gas purchases for extraction and make-up and lower costs of sales at the Empress operations, net of overhead reduction costs at Western Canada Transmission & Processing and


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


•	increased electric power and other costs passed through to gas transmission customers and a non-cash impairment charge on Ozark Gas Gathering, L.L.C. (Ozark Gas Gathering), net of lower ad valorem tax accruals at Spectra Energy Partners and


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

Other Income and Expenses. The $384 million, or 147%, decrease was attributable to lower equity earnings from Field Services mainly due to an impairment of goodwill at DCP Midstream, decreased commodity prices and lower gains associated with the issuance of partnership units by DCP Partners, net of increased gathering and processing margins as a result of asset growth and higher volumes in certain geographic regions, and improved operating efficiencies. These decreases were partially offset by higher AFUDC resulting from higher capital spending and higher equity earnings from Sand Hills as a result of higher volumes at Spectra Energy Partners.

Interest Expense. The $29 million, or 8%, decrease was mainly due to a weaker Canadian dollar and lower average long-term debt balances and rates.

Income Tax Expense.The $135 million decrease was primarily due to the $72 million tax impact on the impairment of goodwill at DCP Midstream, lower earnings and the effect of a weaker Canadian dollar.

The effective tax rate for income from continuing operations was 19% for the six months ended June 30, 2015, compared to 26% for the same period in 2014.

Net Income—Noncontrolling Interests. The $30 million increase was driven primarily by higher earnings from Spectra Energy Partners.

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

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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.

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,
	2015			2014			2015			2014
	(in millions)
Spectra Energy Partners	$	478		$	374		$	933		$	803
Distribution	98			112			290			338
Western Canada Transmission & Processing	104			111			265			348
Field Services	(233		)	54			(250		)	184
Total reportable segment EBITDA	447			651			1,238			1,673
Other	(12		)	(24		)	(27		)	(41		)
Total reportable segment and other EBITDA	435			627			1,211			1,632
Depreciation and amortization	193			199			386			399
Interest expense	166			176			325			354
Interest income and other (a)	(3		)	1			(1		)	5
Earnings before income taxes	$	73		$	253		$	499		$	884

___________


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

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,
	2015		2014		Increase (Decrease)			2015		2014		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	603	$	531	$	72		$	1,209	$	1,112	$	97
Operating expenses
Operating, maintenance and other	192		193		(1		)	399		378		21
Other income and expenses	67		36		31			123		69		54
EBITDA	$	478	$	374	$	104		$	933	$	803	$	130
Express pipeline revenue receipts, MBbl/d (a)	235		204		31			242		214		28
Platte PADD II deliveries, MBbl/d	172		176		(4		)	170		171		(1		)

___________


(a)	Thousand barrels per day.

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Three Months Ended June 30, 2015 Compared to Same Period in 2014

Operating Revenues. The $72 million increase was driven by:


•	a $32 million increase due to expansion projects, primarily on Texas Eastern and East Tennessee,


•	a $20 million increase in crude oil transportation revenues as a result of higher volumes and higher tariff revenues mainly at the Express pipeline and


•	a $17 million increase in recoveries of electric power and other costs passed through to gas transmission customers.

Operating, Maintenance and Other. The $1 million decrease was driven by:


•	a $17 million decrease primarily due to ad valorem tax accruals, offset by


•	a $17 million increase in electric power and other costs passed through to gas transmission customers.

Other Income and Expenses. The $31 million increase was primarily due to higher AFUDC resulting from higher capital spending and higher equity earnings from Sand Hills as a result of higher volumes and the dropdown of an additional 24.95% interest in Southeast Supply Header, LLC (SESH).

Six Months Ended June 30, 2015 Compared to Same Period in 2014

Operating Revenues. The $97 million increase was driven by:


•	a $65 million increase due to expansion projects, primarily on Texas Eastern and East Tennessee,


•	a $33 million increase in crude oil transportation revenues as a result of higher volumes and tariff rates mainly on the Express pipeline and


•	a $31 million increase in recoveries of electric power and other costs passed through to gas transmission customers, partially offset by


•	an $11 million net decrease in natural gas transportation revenues mainly from other revenue on East Tennessee and interruptible transportation on Texas Eastern.

Operating, Maintenance and Other. The $21 million increase was driven by:


•	a $31 million increase in electric power and other costs passed through to gas transmission customers and


•	a $9 million increase due to the non-cash impairment charge on Ozark Gas Gathering, partially offset by


•	a $21 million decrease due to ad valorem tax accruals.

Other Income and Expenses. The $54 million increase was primarily due to higher AFUDC resulting from higher capital spending and higher equity earnings from Sand Hills as a result of higher volumes and the dropdown of an additional 24.95% interest in SESH.

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Distribution



	Three Months Ended June 30,							Six Months Ended June 30,
	2015		2014		Increase (Decrease)			2015		2014			Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	290	$	360	$	(70	)	$	952	$	1,078		$	(126	)
Operating expenses
Natural gas purchased	103		152		(49		)	486		540			(54		)
Operating, maintenance and other	90		96		(6		)	176		199			(23		)
Other income and expenses	1		—		1			—		(1		)	1
EBITDA	$	98	$	112	$	(14	)	$	290	$	338		$	(48	)
Number of customers, thousands								1,425		1,405			20
Heating degree days, Fahrenheit	866		979		(113		)	5,125		5,230			(105		)
Pipeline throughput, TBtu (a)	132		121		11			460		415			45
Canadian dollar exchange rate, average	1.23		1.09		0.14			1.23		1.10			0.13

___________


(a)	Trillion British thermal units.

Three Months Ended June 30, 2015 Compared to Same Period in 2014

Operating Revenues. The $70 million decrease was driven by:


•	a $36 million decrease resulting from a weaker Canadian dollar,


•	a $29 million decrease from lower natural gas prices passed through to customers. Prices charged to customers are adjusted quarterly based on the 12 month New York Mercantile Exchange (NYMEX) forecast and


•	a $20 million decrease in customer usage of natural gas primarily due to weather that was warmer than in 2014.

Natural Gas Purchased. The $49 million decrease was driven by:


•	a $29 million decrease from lower natural gas prices passed through to customers,


•	a $20 million decrease due to lower volumes of natural gas sold primarily due to warmer weather and


•	a $13 million decrease resulting from a weaker Canadian dollar, partially offset by


•	a $10 million increase in operating fuel costs primarily due to gas measurement variances.

Operating, Maintenance and Other. The $6 million decrease was mainly driven by the weaker Canadian dollar.

Six Months Ended June 30, 2015 Compared to Same Period in 2014

Operating Revenues. The $126 million decrease was driven by:


•	a $118 million decrease resulting from a weaker Canadian dollar,


•	a $23 million decrease in customer usage of natural gas primarily due to weather that was warmer than in 2014,


•	a $10 million decrease, net of 2012 earnings sharing, primarily as a result of the first quarter 2014 results including regulatory decisions from the OEB that, in aggregate, provided a benefit, partially offset by


•	a $17 million increase from higher natural gas prices passed through to customers. Prices charged to customers are adjusted quarterly based on the 12 month NYMEX forecast and


•	a $15 million increase from growth in the number of customers.

Natural Gas Purchased. The $54 million decrease was driven by:


•	a $60 million decrease resulting from a weaker Canadian dollar and


•	a $20 million decrease due to lower volumes of natural gas sold primarily due to warmer weather, partially offset by


•	a $17 million increase from higher natural gas prices passed through to customers and

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•	a $10 million increase from growth in the number of customers.

Operating, Maintenance and Other. The $23 million decrease was primarily driven by the weaker Canadian dollar.

Western Canada Transmission & Processing



	Three Months Ended June 30,								Six Months Ended June 30,
	2015			2014		Increase (Decrease)			2015		2014		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	304		$	391	$	(87	)	$	674	$	966	$	(292	)
Operating expenses
Natural gas and petroleum products purchased	25			91		(66		)	92		265		(173		)
Operating, maintenance and other	174			189		(15		)	321		354		(33		)
Other income and expenses	(1		)	—		(1		)	4		1		3
EBITDA	$	104		$	111	$	(7	)	$	265	$	348	$	(83	)
Pipeline throughput, TBtu	220			224		(4		)	476		466		10
Volumes processed, TBtu	156			175		(19		)	336		352		(16		)
Canadian dollar exchange rate, average	1.23			1.09		0.14			1.23		1.10		0.13

Three Months Ended June 30, 2015 Compared to Same Period in 2014

Operating Revenues. The $87 million decrease was driven by:


•	a $47 million decrease due primarily to lower sales volumes of residual natural gas at the Empress operations,


•	a $39 million decrease resulting from a weaker Canadian dollar and


•	a $23 million decrease due to lower NGL prices associated with the Empress operations, partially offset by


•	an $8 million increase in sales volumes of NGLs at the Empress operations due mostly to the 2014 plant turnaround,


•	a $7 million increase from settlement gains associated with the risk management program at the Empress operations,


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


•	a $4 million increase arising from non-cash mark-to-market gains associated with the risk management program implemented in 2014 at the Empress operations.

Natural Gas and Petroleum Products Purchased. The $66 million decrease was driven by:


•	a $55 million decrease due primarily to lower volumes of natural gas purchases for extraction and make-up at the Empress operations and


•	a $13 million decrease primarily as a result of lower costs of sales at the Empress facility, partially offset by


•	a $5 million non-cash charge to reduce the value of propane inventory at the Empress operations to net realizable value at June 30, 2015.

Operating, Maintenance and Other. The $15 million decrease was driven by:


•	a $21 million decrease resulting from a weaker Canadian dollar and


•	a $10 million decrease in plant turnaround costs, partially offset by


•	an $11 million increase due to overhead reduction costs.

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Six Months Ended June 30, 2015 Compared to Same Period in 2014

Operating Revenues. The $292 million decrease was driven by:


•	a $105 million decrease due to lower NGL prices associated with the Empress operations,


•	a $90 million decrease due primarily to lower sales volumes of residual natural gas at the Empress operations,


•	an $85 million decrease resulting from a weaker Canadian dollar,


•	a $33 million decrease in sales volumes of NGLs at the Empress operations,


•	an $18 million decrease arising from non-cash mark-to-market losses associated with the risk management program implemented in 2014 at the Empress operations and


•	a $15 million decrease in transmission revenues due to lower interruptible transmission revenues and lower tolls charged to customers at M&N Canada, partially offset by


•	a $39 million increase from settlement gains associated with the risk management program at the Empress operations and


•	a $9 million increase in gathering and processing revenues due primarily to higher volumes.

Natural Gas and Petroleum Products Purchased. The $173 million decrease was driven by:


•	a $131 million decrease due primarily to lower volumes of natural gas purchases for extraction and make-up at the Empress operations,


•	a $37 million decrease primarily as a result of lower costs of sales at the Empress facility and


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

Operating, Maintenance and Other. The $33 million decrease was driven by:


•	a $39 million decrease resulting from a weaker Canadian dollar,


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


•	a $6 million decrease in plant turnaround costs, partially offset by


•	an $11 million increase due to overhead reduction costs.

Other Income and Expenses. The $3 million increase was driven primarily by higher earnings from equity investments.

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Field Services



	Three Months Ended June 30,								Six Months Ended June 30,
	2015			2014		Increase (Decrease)			2015			2014		Increase (Decrease)
	(in millions, except where noted)
Earnings (loss) from equity investments	$	(233	)	$	54	$	(287	)	$	(250	)	$	184	$	(434	)
EBITDA	$	(233	)	$	54	$	(287	)	$	(250	)	$	184	$	(434	)
Natural gas gathered and processed/transported, TBtu/d (a,b)	7.0			7.3		(0.3		)	7.1			7.2		(0.1		)
NGL production, MBbl/d (a)	408			452		(44		)	404			449		(45		)
Average natural gas price per MMBtu (c,d)	$	2.64		$	4.67	$	(2.03	)	$	2.81		$	4.80	$	(1.99	)
Average NGL price per gallon (e)	$	0.48		$	0.93	$	(0.45	)	$	0.48		$	1.00	$	(0.52	)
Average crude oil price per barrel (f)	$	57.94		$	102.99	$	(45.05	)	$	53.29		$	100.84	$	(47.55	)

___________


(a)	Reflects 100% of volumes.


(b)	Trillion British thermal units per day.


(c)	Average price based on NYMEX Henry Hub.


(d)	Million British thermal units.


(e)	Does not reflect results of commodity hedges.


(f)	Average price based on NYMEX calendar month.

Three Months Ended June 30, 2015 Compared to Same Period in 2014

EBITDA. Lower equity earnings of $287 million were mainly the result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:


•	a $194 million decrease due to an impairment of goodwill at DCP Midstream. This impairment was due to the significant downturn in commodity prices over the past three quarters, including further deterioration in the second quarter of 2015,


•	a $120 million decrease from commodity-sensitive processing arrangements, due to decreased NGL, crude oil and natural gas prices,


•	a $12 million decrease primarily as a result of a loss on the sale of Field Services’ interest in its Benedum processing plant and gathering system and


•	a $9 million decrease in gains associated with the issuance of partnership units by DCP Partners in 2015 compared to 2014, partially offset by


•	a $26 million increase in gathering and processing margins as a result of asset growth and higher volumes in certain of our geographic regions,


•	a $16 million increase as a result of DCP Partners’ favorable results from third-party mark-to-market on derivative instruments used to mitigate a portion of its expected commodity cash flow risk and favorable results from the Sand Hills and Front Range Pipeline LLC (Front Range) NGL pipelines and


•	a $16 million increase primarily attributable to lower operating expenses as a result of improved operating efficiencies and other initiatives.

Six Months Ended June 30, 2015 Compared to Same Period in 2014

EBITDA. Lower equity earnings of $434 million were mainly the result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:


•	a $248 million decrease from commodity-sensitive processing arrangements, due to decreased NGL, crude oil and natural gas prices,


•	a $194 million decrease due to an impairment of goodwill at DCP Midstream. This impairment was due to the significant downturn in commodity prices over the past three quarters, including further deterioration in the second quarter of 2015,

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•	a $55 million decrease in gains associated with the issuance of partnership units by DCP Partners in 2015 compared to 2014 and


•	an $8 million decrease primarily as a result of a loss on the sale of Field Services’ interest in its Benedum processing plant and gathering system offset by a gain on sale of its interest in Dover-Hennessey, partially offset by


•	a $47 million increase in gathering and processing margins as a result of asset growth and higher volumes in certain of our geographic regions,


•	a $21 million increase primarily attributable lower operating expenses as a result of cost savings initiatives in operations and


•	a $12 million increase as a result of DCP Partners’ favorable results from third-party mark-to-market on derivative instruments used to mitigate a portion of its expected commodity cash flow risk and favorable results from the Sand Hills and Front Range NGL pipelines.

Other



	Three Months Ended June 30,									Six Months Ended June 30,
	2015			2014			Increase (Decrease)			2015			2014			Increase (Decrease)
	(in millions)
Operating revenues	$	17		$	19		$	(2	)	$	35		$	37		$	(2	)
Operating expenses
Operating, maintenance and other	30			43			(13		)	62			81			(19		)
Other income and expenses	1			—			1			—			3			(3		)
EBITDA	$	(12	)	$	(24	)	$	12		$	(27	)	$	(41	)	$	14

Three and Six Months Ended June 30, 2015 Compared to Same Periods in 2014

EBITDA. Both the $12 million and $14 million increases, respectively, reflect lower 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. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in key markets served by our operations, regulatory stability, the ability to renew contracts, commodity prices (where appropriate) and foreign currency exchange rates, as well as other factors that affect our reporting units’ revenue, expense and capital expenditure projections.

We performed either a quantitative assessment or a qualitative assessment for all of our reporting units to determine whether it is more likely than not that the respective fair values of these reporting units are less than their carrying amounts, including goodwill as of April 1, 2015 (our annual testing date). 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, 2015 were substantially in excess of their respective carrying values, except for BC Field Services.

Our BC Field Services business is comprised of gathering and processing assets that, while fee based, can see volumetric impacts over the long term due to changes in commodity prices, specifically natural gas prices. Upon completion of our testing, it was determined that BC Field Services reporting unit’s fair value exceeded its carrying value by 9%. The BC Field Services reporting unit has been assigned $292 million of our total goodwill. In our quantitative assessments, our cash flow forecasts were updated to reflect the impact of the recently announced overhead reductions at Western Canada Transmission & Processing. We believe the assumptions used in our analyses are appropriate and result in reasonable estimates of the fair

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values of our reporting units. However, the assumptions used are subject to uncertainty, and declines in the future performance or cash flows of our reporting units, changing business conditions, further sustained declines in commodity prices or increases to our weighted average cost of capital assumptions may result in the recognition of impairment charges, which could be significant.

Certain commodity prices, specifically NGL prices, have fluctuated throughout 2014 and 2015 and are lower, on average, than historical levels. Our Empress NGL reporting unit is significantly affected by fluctuations in NGL commodity prices. Results of our April 1, 2015 quantitative assessment determined that Empress NGL reporting unit’s fair value was substantially in excess of carrying value. Additionally, we have a commodity hedging program at Empress which economically hedges a significant portion of their NGL sales and related make-up gas purchases, which mitigates the effects of short-term commodity price fluctuations. However, should realized NGL prices decline significantly from recent levels for a sustained period, this could result in a triggering event that would warrant testing for the impairment of goodwill relating to the Empress NGL reporting unit, which could result in an impairment.

Due to the significant downturn in commodity prices over the past three quarters, including further deterioration in the second quarter of 2015, DCP Midstream determined it was more likely than not the estimated fair values of certain of its goodwill reporting units and certain of DCP Midstream Partners, LP (DCP Partners) goodwill reporting units were below their carrying amount, and performed a goodwill impairment test. The impairment test was based on an internal discounted cash flow model taking into account various observable and non-observable factors, such as prices, volumes, expenses and discount rate. The impairment test resulted in DCP Midstream’s recognition of a $427 million goodwill impairment during the second quarter of 2015, which reduced our equity earnings from DCP Midstream by $122 million after-tax. This impairment represents DCP Midstream’s best estimate pending finalization of the fair value assessments. Due to the impairment of goodwill recognized by DCP Midstream, we assessed our equity investment in DCP Midstream and determined that no indicators of impairment were noted.

No triggering events have occurred with our reporting units since the April 1, 2015 test that would warrant re-testing for goodwill impairment.

LIQUIDITY AND CAPITAL RESOURCES

As of June 30, 2015, we had negative working capital of $1,400 million. This balance includes commercial paper liabilities totaling $535 million and current maturities of long-term debt of $917 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, 2015, our revolving credit facilities included Spectra Capital’s $1.0 billion facility, SEP’s $2.0 billion facility, Westcoast’s 400 million Canadian dollar facility and Union Gas’ 500 million Canadian dollar facility, with available capacity of $1,962 million under SEP’s credit facility and $1,223 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 11 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.

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Cash Flow Analysis

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



	Six Months Ended June 30,
	2015			2014
Net cash provided by (used in):	(in millions)
Operating activities	$	1,456		$	1,209
Investing activities	(976		)	(612		)
Financing activities	(406		)	(499		)
Effect of exchange rate changes on cash	(2		)	1
Net increase in cash and cash equivalents	72			99
Cash and cash equivalents at beginning of the period	215			201
Cash and cash equivalents at end of the period	$	287		$	300

Operating Cash Flows

Net cash provided by operating activities increased $247 million to $1,456 million in the six months ended June 30, 2015 compared to the same period in 2014, driven mostly by changes in working capital, partially offset by lower earnings.

Investing Cash Flows

Net cash used in investing activities increased $364 million to $976 million in the six months ended June 30, 2015 compared to the same period in 2014. This change was driven by:


•	a $160 million net increase in capital and investment expenditures and


•	a $207 million decrease in distributions received from unconsolidated affiliates, comprised mostly of a 2014 distribution from SESH with proceeds from a SESH debt offering.



	Six Months Ended June 30,
	2015		2014
Capital and Investment Expenditures	(in millions)
Spectra Energy Partners (a)	$	638	$	444
Distribution	207		131
Western Canada Transmission & Processing	149		270
Total reportable segments	994		845
Other	29		18
Total consolidated	$	1,023	$	863

_______________________

(a) Excludes reimbursements from noncontrolling interest of $58 million in 2015.

Capital and investment expenditures for the six months ended June 30, 2015 consisted of $760 million for expansion projects and $263 million for maintenance.

We project 2015 capital and investment expenditures of approximately $3.5 billion, consisting of approximately $2.5 billion for Spectra Energy Partners, $0.6 billion for Distribution and $0.4 billion for Western Canada Transmission & Processing. Total projected 2015 capital and investment expenditures include approximately $2.8 billion of expansion capital expenditures and $0.7 billion for maintenance and upgrades of existing plants, pipelines and infrastructure to serve growth.

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Financing Cash Flows and Liquidity

Net cash used in financing activities decreased $93 million to $406 million for the six months ended June 30, 2015 compared to the same period in 2014. This change was driven by:


•	a $979 million increase in net proceeds from long term debt, primarily due to the issuance of SEP long-term debt in 2015, which was used primarily to pay down $774 million of commercial paper and


•	$32 million from Duke Energy for a 7.5% equity share in Sabal Trail Transmission, LLC, included in contributions from noncontrolling interest, partially offset by


•	a $54 million decrease in contributions from noncontrolling interest and


•	a $46 million increase in dividends paid on common stock.

On March 12, 2015, SEP issued $500 million of 3.50% unsecured notes due 2025 and $500 million of 4.50% unsecured notes due 2045. Net proceeds from the offering were used to repay a portion of outstanding commercial paper, to fund capital expenditures and for general corporate purposes.

During the six months ended June 30, 2015, SEP issued 3.6 million common units to the public under its at-the-market program and approximately 74,000 general partner units to Spectra Energy. Total net proceeds to SEP were $184 million (net proceeds to Spectra Energy were $180 million). The net proceeds were used for SEP’s general partnership purposes, which may have included debt repayments, capital expenditures and/or additions to working capital. In 2015, SEP has issued 7.2 million common units to the public and 147,000 general partner units to Spectra Energy, for total net proceeds to SEP of $353 million (net proceeds to Spectra Energy were $346 million).

Available Credit Facilities and Restrictive Debt Covenants. See Note 11 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 and term loan require our consolidated debt-to-total-capitalization ratio, as defined in the agreements, to be 65% or lower. Per the terms of the agreements, collateralized debt is excluded from the calculation of the ratio. As of June 30, 2015, this ratio was 58%. 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, 2015, 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 $0.14 per share, per year, through 2017. We expect to continue our policy of paying regular cash dividends. The declaration and payment of dividends are subject to the sole discretion of our Board of Directors and will depend upon many factors, including the financial condition, earnings and capital requirements of our operating subsidiaries, covenants associated with certain debt obligations, legal requirements, regulatory constraints and other factors deemed relevant by our Board of Directors. We declared a quarterly cash dividend of $0.37 per common share on July 7, 2015 payable on September 9, 2015 to shareholders at close of business on August 12, 2015.

Other Financing Matters. Spectra Energy Corp and Spectra Capital have an effective shelf registration statement on file with the 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. SEP also has $357 million available as of June 30, 2015 for the issuance of limited partner common units under another effective shelf registration statement on file with the SEC related to its at-the-market program. Westcoast and Union Gas have an aggregate 2.5 billion Canadian dollars (approximately $2.0 billion) available as of June 30, 2015 for the issuance of debt securities in the Canadian market under debt shelf prospectuses.

OTHER ISSUES

New Accounting Pronouncements. See Note 19 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, 2014. We believe our exposure to market risk has not changed materially since then.

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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.

Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2015, 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, 2015 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 3 and 14 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, 2014 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

*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.

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.

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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 6, 2015						/s/ Gregory L. Ebel
						Gregory L. Ebel
						President and Chief Executive Officer

Date: August 6, 2015						/s/ J. Patrick Reddy
						J. Patrick Reddy
						Chief Financial Officer