Edgar Filing: Spectra Energy Corp.

Document

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, 2016



¨	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, 2016: 701,100,679

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SPECTRA ENERGY CORP

FORM 10-Q FOR THE QUARTER ENDED

June 30, 2016

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, 2016 and 2015	4
	Condensed Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2016 and 2015	5
	Condensed Consolidated Balance Sheets as of June 30, 2016 and December 31, 2015	6
	Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2016 and 2015	8
	Condensed Consolidated Statements of Equity for the six months ended June 30, 2016 and 2015	9
	Notes to Condensed Consolidated Financial Statements	10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	45
Item 4.	Controls and Procedures	46

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	46
Item 1A.	Risk Factors	46
Item 6.	Exhibits	47
	Signatures	48

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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 United States and Canadian pipeline, storage, gathering, processing and other related infrastructure projects and the effects of competition;


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


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


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


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


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

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,
	2016		2015			2016		2015
Operating Revenues
Transportation, storage and processing of natural gas	$	810	$	802		$	1,634	$	1,644
Distribution of natural gas	228		238			639		845
Sales of natural gas liquids	12		31			53		97
Transportation of crude oil	88		90			173		174
Other	21		31			44		55
Total operating revenues	1,159		1,192			2,543		2,815
Operating Expenses
Natural gas and petroleum products purchased	101		119			351		551
Operating, maintenance and other	392		389			733		743
Depreciation and amortization	196		193			389		386
Property and other taxes	99		85			205		188
Total operating expenses	788		786			1,678		1,868
Operating Income	371		406			865		947
Other Income and Expenses
Earnings (loss) from equity investments	16		(189		)	49		(165		)
Other income and expenses, net	39		22			71		42
Total other income and expenses	55		(167		)	120		(123		)
Interest Expense	153		166			304		325
Earnings Before Income Taxes	273		73			681		499
Income Tax Expense (Benefit)	52		(7		)	150		94
Net Income	221		80			531		405
Net Income—Noncontrolling Interests	72		62			148		120
Net Income—Controlling Interests	$	149	$	18		$	383	$	285
Common Stock Data
Weighted-average shares outstanding
Basic	699		671			687		671
Diluted	701		672			688		672
Earnings per share
Basic and diluted	$	0.21	$	0.03		$	0.56	$	0.42
Dividends per share	$	0.405	$	0.37		$	0.81	$	0.74

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,
	2016		2015			2016		2015
Net Income	$	221	$	80		$	531	$	405
Other comprehensive income (loss):
Foreign currency translation adjustments	50		87			351		(405		)
Pension and benefits impact (net of taxes of $2, $2, $4 and $5, respectively)	4		7			9		13
Other	3		(1		)	2		—
Total other comprehensive income (loss)	57		93			362		(392		)
Total Comprehensive Income, net of tax	278		173			893		13
Less: Comprehensive Income—Noncontrolling Interests	75		64			155		114
Comprehensive Income (Loss)—Controlling Interests	$	203	$	109		$	738	$	(101	)

See Notes to Condensed Consolidated Financial Statements.

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SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)



	June 30, 2016		December 31, 2015
ASSETS

Current Assets
Cash and cash equivalents	$	240	$	213
Receivables, net	708		806
Inventory	185		307
Assets held for sale	225		—
Fuel tracker	33		41
Other	246		281
Total current assets	1,637		1,648

Investments and Other Assets
Investments in and loans to unconsolidated affiliates	2,657		2,592
Goodwill	4,217		4,154
Other	373		310
Total investments and other assets	7,247		7,056

Property, Plant and Equipment
Cost	32,003		29,843
Less accumulated depreciation and amortization	7,296		6,925
Net property, plant and equipment	24,707		22,918

Regulatory Assets and Deferred Debits	1,456		1,301

Total Assets	$	35,047	$	32,923

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, 2016		December 31, 2015
LIABILITIES AND EQUITY

Current Liabilities
Accounts payable	$	709	$	511
Commercial paper	1,113		1,112
Taxes accrued	80		78
Interest accrued	181		179
Current maturities of long-term debt	68		652
Liabilities held for sale	56		—
Other	579		860
Total current liabilities	2,786		3,392

Long-term Debt	13,584		12,892

Deferred Credits and Other Liabilities
Deferred income taxes	5,694		5,445
Regulatory and other	1,421		1,323
Total deferred credits and other liabilities	7,115		6,768

Commitments and Contingencies

Preferred Stock of Subsidiaries	339		339

Equity
Preferred stock, $0.001 par, 22 million shares authorized, no shares outstanding	—		—
Common stock, $0.001 par, 1 billion shares authorized, 701 million and 671 million shares outstanding at June 30, 2016 and December 31, 2015, respectively	1		1
Additional paid-in capital	5,944		5,053
Retained earnings	1,567		1,741
Accumulated other comprehensive income (loss)	86		(269		)
Total controlling interests	7,598		6,526
Noncontrolling interests	3,625		3,006
Total equity	11,223		9,532

Total Liabilities and Equity	$	35,047	$	32,923

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,
	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	531		$	405
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	397			393
Deferred income tax expense	131			25
(Earnings) loss from equity investments	(49		)	165
Distributions from equity investments	52			93
Other	177			375
Net cash provided by operating activities	1,239			1,456
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(1,520		)	(989		)
Investments in and loans to unconsolidated affiliates	(112		)	(34		)
Purchase of intangible, net	(40		)	—
Purchases of held-to-maturity securities	(346		)	(329		)
Proceeds from sales and maturities of held-to-maturity securities	364			344
Purchases of available-for-sale securities	(329		)	—
Proceeds from sales and maturities of available-for-sale securities	330			1
Distributions from equity investments	45			35
Distribution to equity investment	(148		)	—
Other changes in restricted funds	11			(6		)
Other	1			2
Net cash used in investing activities	(1,744		)	(976		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	382			994
Payments for the redemption of long-term debt	(619		)	(39		)
Net decrease in commercial paper	(23		)	(1,030		)
Distributions to noncontrolling interests	(114		)	(93		)
Contributions from noncontrolling interests	278			90
Proceeds from the issuances of Spectra Energy common stock	868			—
Proceeds from the issuances of Spectra Energy Partners, LP common units	321			180
Dividends paid on common stock	(557		)	(499		)
Other	(8		)	(9		)
Net cash provided by (used in) financing activities	528			(406		)
Effect of exchange rate changes on cash	4			(2		)
Net increase in cash and cash equivalents	27			72
Cash and cash equivalents at beginning of period	213			215
Cash and cash equivalents at end of period	$	240		$	287
Supplemental Disclosures
Property, plant and equipment non-cash accruals	$	317		$	197

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 (Loss)
	Common Stock		Additional Paid-in Capital			Retained Earnings			Foreign Currency Translation Adjustments			Other			Noncontrolling Interests			Total
December 31, 2015	$	1	$	5,053		$	1,741		$	79		$	(348	)	$	3,006		$	9,532
Net income	—		—			383			—			—			148			531
Other comprehensive income	—		—			—			346			9			7			362
Dividends on common stock	—		—			(557		)	—			—			—			(557		)
Stock-based compensation	—		10			—			—			—			—			10
Distributions to noncontrolling interests	—		—			—			—			—			(116		)	(116		)
Contributions from noncontrolling interests	—		—			—			—			—			278			278
Spectra Energy common stock issued	—		868			—			—			—			—			868
Spectra Energy Partners, LP common units issued	—		15			—			—			—			297			312
Other, net	—		(2		)	—			—			—			5			3
June 30, 2016	$	1	$	5,944		$	1,567		$	425		$	(339	)	$	3,625		$	11,223

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

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 United States (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 U.S., the Maritime Provinces in Canada, the Pacific Northwest in the U.S. 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 U.S. 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, 2015, 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 U.S., 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 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, Empress NGL operations (Empress), Canadian Midstream, and Maritimes & Northeast Pipeline Limited Partnership (M&N Canada). BC Pipeline, BC Field Services and M&N Canada operations are primarily subject to the rules and regulations of the NEB. See Note 8 for additional discussion of Empress.

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, 2016, 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 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, 2016
Spectra Energy Partners	$	618	$	—		$	618		$	78	$	471
Distribution	284		—			284			47		104
Western Canada Transmission & Processing	254		4			258			59		97
Field Services	—		—			—			—		(14		)
Total reportable segments	1,156		4			1,160			184		658
Other	3		16			19			12		(36		)
Eliminations	—		(20		)	(20		)	—		—
Depreciation and amortization	—		—			—			—		196
Interest expense	—		—			—			—		153
Total consolidated	$	1,159	$	—		$	1,159		$	196	$	273

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

Six Months Ended June 30, 2016
Spectra Energy Partners	$	1,242	$	—		$	1,242		$	155	$	944
Distribution	749		—			749			91		274
Western Canada Transmission & Processing	548		15			563			117		220
Field Services	—		—			—			—		(11		)
Total reportable segments	2,539		15			2,554			363		1,427
Other	4		32			36			26		(55		)
Eliminations	—		(47		)	(47		)	—		—
Depreciation and amortization	—		—			—			—		389
Interest expense	—		—			—			—		304
Interest income and other (a)	—		—			—			—		2
Total consolidated	$	2,543	$	—		$	2,543		$	389	$	681

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

___________________________________


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

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3. Regulatory Matters

Union Gas. In December 2015, Union Gas filed an application with the OEB for the disposition of the 2014 demand side management (DSM) deferral and variance account balances. As a result of this application, Union Gas has a receivable from customers of approximately $9 million as of June 30, 2016 and $8 million as of December 31, 2015, which is reflected as Current Assets—Other on the Condensed Consolidated Balance Sheets. In June 2016, the OEB approved Union Gas' application as filed and Union Gas will begin to recover the receivable from ratepayers effective October 1, 2016.

In March 2016, Union Gas filed a Draft Rate Order with the OEB for rates effective January 1, 2016 based on the OEB's February 24, 2016 updated Decision and Order on the 2015-2020 DSM Plan. In May 2016, a decision from the OEB was received approving recovery from ratepayers of approximately $19 million effective January 1, 2016 with an implementation date of July 1, 2016.

In April 2016, Union Gas filed an application with the OEB for the annual disposition of the 2015 deferral account balances. As a result, Union Gas has a net receivable from customers of approximately $18 million as of June 30, 2016 and December 31, 2015, which is primarily reflected as Current Assets—Other on the Condensed Consolidated Balance Sheets. Union Gas filed a Settlement Proposal with the OEB in July 2016 reflecting a full settlement on all issues in the proceeding. Union Gas is proposing to implement the disposition of the balances on October 1, 2016. A decision from the OEB is expected later this year.

4. Income Taxes

Income tax expense was $52 million for the three months ended June 30, 2016, compared to an income tax benefit of $7 million for the same period in 2015. Income tax expense was $150 million for the six months ended June 30, 2016, compared to $94 million for the same period in 2015. The higher tax expense for both periods was primarily due to the $72 million tax impact of the loss on investment due to the partial impairment of goodwill at DCP Midstream in 2015, partially offset by tax rate changes in 2016.

The effective income tax rate was 19% for the three months ended June 30, 2016, compared to negative 10% for the same period in 2015. The effective income tax rate was 22% for the six months ended June 30, 2016, compared to 19% for the same period in 2015. The higher effective income tax rate for both periods was primarily due to the $72 million tax impact of the loss on investment due to the partial impairment of goodwill at DCP Midstream in 2015, partially offset by tax rate changes in 2016.

There was a $7 million increase in unrecognized tax benefits recorded during the six months ended June 30, 2016. Although uncertain, we believe it is reasonably possible that the total amount of unrecognized tax benefits could decrease by approximately $30 million to $40 million prior to June 30, 2017 due to audit settlements and statute of limitations expirations.

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,
	2016		2015		2016		2015
	(in millions, except per-share amounts)
Net income—controlling interests	$	149	$	18	$	383	$	285
Weighted-average common shares outstanding
Basic	699		671		687		671
Diluted	701		672		688		672
Basic and diluted earnings per common share (a)	$	0.21	$	0.03	$	0.56	$	0.42

___________________

(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 (Loss)

The following table presents the net of tax changes in Accumulated Other Comprehensive Income (AOCI) by component, 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 (Loss)
	(in millions)
March 31, 2016	$	376		$	(341	)	$	—		$	(3	)	$	32
Other AOCI activity	49			4			—			1			54
June 30, 2016	$	425		$	(337	)	$	—		$	(2	)	$	86

March 31, 2015	$	532		$	(345	)	$	—		$	(2	)	$	185
Other AOCI activity	85			7			—			(1		)	91
June 30, 2015	$	617		$	(338	)	$	—		$	(3	)	$	276

December 31, 2015	$	79		$	(346	)	$	(3	)	$	1		$	(269	)
Other AOCI activity	346			9			3			(3		)	355
June 30, 2016	$	425		$	(337	)	$	—		$	(2	)	$	86

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

7. Inventory

Inventory consists of natural gas and NGLs held in storage for transmission and processing, and also includes materials and supplies. In the second quarter of 2016, Westcoast Energy Inc. (Westcoast) entered into a definitive agreement to sell its ownership interest in Empress which resulted in NGLs being reclassified out of Inventory to Assets Held for Sale on the Condensed Consolidated Balance Sheet as of June 30, 2016. See Note 8 for further discussion. 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, 2016		December 31, 2015
	(in millions)
Natural gas	$	115	$	217
NGLs	—		23
Materials and supplies	70		67
Total inventory	$	185	$	307

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8. Assets Held for Sale

On April 2, 2016, Westcoast entered into a definitive agreement to sell its ownership interest in Empress for a cash purchase price of approximately 200 million Canadian dollars plus customary closing adjustments. This transaction is expected to close in the second half of 2016. The associated assets and liabilities are included in the Western Canada Transmission & Processing segment and classified as Assets Held for Sale and Liabilities Held for Sale, respectively, on the Condensed Consolidated Balance Sheet as of June 30, 2016.

As these assets are classified as held for sale, we evaluated the book value compared to the lower of the carrying amounts or fair value less costs to sell. As of June 30, 2016, we determined that the fair value less costs to sell exceeded the carrying amount of the assets held for sale, therefore, no adjustment to book value was necessary. The carrying amounts of the assets and liabilities classified as Assets Held for Sale and Liabilities Held for Sale on our Condensed Consolidated Balance Sheet are as follows:



	June 30, 2016
	(in millions)
Assets Held for Sale
Cash and cash equivalents	$	7
Receivables, net	8
Inventory	28
Current assets—other	7
Investments and other assets—other	11
Net property, plant and equipment	164
Total assets held for sale	$	225
Liabilities Held for Sale
Accounts payable	$	9
Taxes accrued	1
Current liabilities—other	6
Deferred credits and other liabilities—deferred income taxes	28
Deferred credits and other liabilities—regulatory and other	12
Total liabilities held for sale	$	56

9. Investments in and Loans to Unconsolidated Affiliates

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(in millions)
Operating revenues	$	1,586		$	1,869		$	3,013		$	3,912
Operating expenses	1,592			2,332			2,957			4,323
Operating income (loss)	(6		)	(463		)	56			(411		)
Net income (loss)	(16		)	(491		)	32			(497		)
Net income (loss) attributable to members’ interests	(29		)	(466		)	(18		)	(503		)

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, totaled $2 million during the six months ended June 30, 2015 and is reflected in Earnings (Loss) From Equity Investments in the Condensed Consolidated Statement of Operations.

During the second quarter of 2015 DCP Midstream recognized a $427 million partial goodwill impairment, which reduced our equity earnings from DCP Midstream by $122 million after-tax. DCP Midstream finalized the calculation of their goodwill impairment in the third quarter of 2015.

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Related Party Transactions

During the third quarter of 2015, Gulfstream Natural Gas System, LLC (Gulfstream) issued unsecured debt of $800 million to fund the repayment of its current debt. Gulfstream distributed $396 million, our proportionate share of proceeds, to us of which we contributed $248 million back to Gulfstream in the fourth quarter of 2015 and the remaining $148 million, classified as Cash Flows from Investing Activities—Distribution to Equity Investment, in the second quarter of 2016.

10. Variable Interest Entities

Sabal Trail. On April 1, 2016, NextEra Energy, Inc. (NextEra) purchased a 9.5% interest in Sabal Trail Transmission, LLC (Sabal Trail) from SEP. Consideration for this transaction consisted of approximately $110 million cash, $102 million of which is classified as Cash Flows from Financing Activities—Contributions from Noncontrolling Interests. See Note 11 for additional information related to this transaction. As of June 30, 2016, we have an effective 38.3% ownership interest in Sabal Trail through our ownership of SEP. Sabal Trail is a joint venture that is constructing a natural gas pipeline to transport natural gas to Florida. Sabal Trail is a variable interest entity (VIE) due to insufficient equity at risk to finance its activities. We determined that we are the primary beneficiary because we direct the activities of Sabal Trail that most significantly impact its economic performance and we consolidate Sabal Trail in our financial statements. The current estimate of the total remaining construction cost is approximately $1.8 billion.

The following summarizes assets and liabilities for Sabal Trail as of June 30, 2016 and December 31, 2015:



Condensed Consolidated Balance Sheets Caption	June 30, 2016		December 31, 2015
	(in millions)
Assets
Current assets	$	114	$	118
Net property, plant and equipment	1,184		773
Regulatory assets and deferred debits	41		25
Total Assets	$	1,339	$	916
Liabilities and Equity
Current liabilities	$	90	$	84
Equity	1,249		832
Total Liabilities and Equity	$	1,339	$	916

Nexus. We have an effective 38.3% ownership interest in Nexus Gas Transmission, LLC (Nexus) through our ownership of SEP. Nexus is a joint venture that is constructing a natural gas pipeline from Ohio to Michigan and continuing on to Ontario, Canada. Nexus is a VIE due to insufficient equity at risk to finance its activities. We determined that we are not the primary beneficiary because the power to direct the activities of Nexus that most significantly impact its economic performance is shared. Nexus is accounted for under the equity method. Our maximum exposure to loss is $1.0 billion. We have an investment in Nexus of $205 million and $90 million as of June 30, 2016 and December 31, 2015, respectively, classified as Investments in and Loans to Unconsolidated Affiliates on our Condensed Consolidated Balance Sheets.

11. Intangible Asset

During the first quarter of 2016 SEP entered into a project coordination agreement (PCA) with NextEra, Duke Energy Corporation (Duke Energy) and Williams Partners L.P. In accordance with the agreement, payments will be made, based on SEP’s proportional ownership interest in Sabal Trail, as certain milestones of the project are met. During the first quarter of 2016, the first milestone was achieved and paid, consisting of $48 million. On April 1, 2016, NextEra purchased an additional 9.5% interest in Sabal Trail from SEP, reducing SEP’s ownership interest in Sabal Trail to 50%. Upon purchase of the additional ownership interest, NextEra reimbursed SEP $8 million for NextEra’s proportional share of the first milestone payment, which reduced SEP’s total milestone payments to $40 million as of June 30, 2016, both of which are classified as Cash Flows from Investing Activities—Purchase of Intangible, Net. This PCA is an intangible asset and is classified as Investments and Other Assets—Other on our Condensed Consolidated Balance Sheet. The intangible asset will be amortized over a period of 25 years beginning at the time of in-service of Sabal Trail, which is expected to occur during the first half of 2017.

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12. 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, 2016 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.

See Note 9 for discussion related to the 2015 partial impairment of goodwill recognized by DCP Midstream.

13. Marketable Securities and Restricted Funds

We routinely invest excess cash and various restricted balances in securities such as commercial paper, bankers acceptances, corporate debt securities, Canadian equity 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, capital expenditures and NEB regulatory requirements, 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, 2016		December 31, 2015
	(in millions)
Corporate debt securities (a)	$	15	$	31
Canadian equity securities (b)	15		—
Total available-for-sale securities	$	30	$	31

___________________________________


(a)	Amounts related to certain construction projects.


(b)	Amounts related to restricted funds held and collected from customers of Western Canada Transmission & Processing and Express-Platte for Canadian pipeline abandonment in accordance with the NEB’s regulatory requirements.

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



	Estimated Fair Value
	June 30, 2016		December 31, 2015
	(in millions)
Restricted funds
Investments and other assets—other	$	24	$	11
Non-restricted funds
Current assets—other	6		20
Total available-for-sale securities	$	30	$	31

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At June 30, 2016, 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, 2016 or December 31, 2015.

HTM Securities. HTM securities are as follows:



		Estimated Fair Value
Description	Condensed Consolidated Balance Sheets Caption	June 30, 2016		December 31, 2015
		(in millions)
Bankers acceptances	Current assets—other	$	28	$	30
Canadian government securities	Current assets—other	25		24
Money market funds	Current assets—other	3		3
Canadian government securities	Investments and other assets—other	54		50
Bankers acceptances	Investments and other assets—other	—		12
Total held-to-maturity securities		$	110	$	119

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, 2016.

At June 30, 2016, the weighted-average contractual maturity of outstanding HTM securities was less than one year.

There were no material gross unrecognized holding gains or losses associated with investments in HTM securities at June 30, 2016 or December 31, 2015.

Other Restricted Funds. In addition to the portions of the AFS and HTM securities that were restricted as described above, we had other restricted funds totaling $12 million at June 30, 2016 and $11 million at December 31, 2015 classified as Current Assets—Other on the Condensed Consolidated Balance Sheets. These restricted funds are related to additional amounts for insurance. We also had other restricted funds totaling $26 million at June 30, 2016 and $38 million at December 31, 2015 classified as Investments and Other Assets—Other on the Condensed Consolidated Balance Sheets. Included in these restricted funds are $16 million and $24 million at June 30, 2016 and December 31, 2015, respectively, related to funds held and collected from customers of Western Canada Transmission & Processing and Express-Platte for Canadian pipeline abandonment in accordance with the NEB’s regulatory requirements and $10 million and $14 million, respectively, related to certain construction projects.

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

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14. Debt and Credit Facilities

Available Credit Facilities and Restrictive Debt Covenants



	Expiration Date	Total Credit Facilities Capacity		Commercial Paper Outstanding at June 30, 2016		Available Credit Facilities Capacity
		(in millions)
Spectra Energy Capital, LLC (a)	2021	$	1,000	$	363	$	637
SEP (b)	2021	2,500		693		1,807
Westcoast (c)	2021	310		57		253
Union Gas (d)	2021	542		—		542
Total		$	4,352	$	1,113	$	3,239

_________


(a)	Revolving credit facility contains a covenant requiring the Spectra Energy consolidated debt-to-total capitalization ratio, as defined in the agreement, to not exceed 65%. Per the terms of the agreement, collateralized debt is excluded from the calculation of the ratio. This ratio was 56% at June 30, 2016.


(b)	Revolving credit facility contains a covenant that requires SEP to maintain a ratio of total Consolidated Indebtedness-to-Consolidated EBITDA, as defined in the agreement, of 5.0 to 1 or less. As of June 30, 2016, this ratio was 3.5 to 1.


(c)	U.S. dollar equivalent at June 30, 2016. The revolving credit facility is 400 million Canadian dollars and contains a covenant that requires the Westcoast non-consolidated debt-to-total capitalization ratio to not exceed 75%. The ratio was 34% at June 30, 2016.


(d)	U.S. dollar equivalent at June 30, 2016. The revolving credit facility is 700 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 66% at June 30, 2016.

On April 29, 2016, we amended the Union Gas and SEP revolving credit agreements. The Union Gas revolving credit facility was increased to 700 million Canadian dollars and the SEP revolving facility was increased to $2.5 billion. The expiration of both facilities was extended, with both facilities expiring in 2021.

On April 29, 2016, we amended the Westcoast and Spectra Energy Capital, LLC (Spectra Capital) revolving credit agreements. The expiration of both credit facilities was extended, with both facilities expiring in 2021.

The issuances of commercial paper, letters of credit and revolving borrowings reduce the amount available under the credit facilities. As of June 30, 2016, 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, 2016, 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 May 31, 2016, Union Gas issued 250 million Canadian dollars (approximately $191 million as of the issuance date) of 2.81% unsecured notes due 2026 and 250 million Canadian dollars (approximately $191 million as of the issuance date) of 3.80% unsecured notes due 2046. Net proceeds from the offerings were used for repayment of short term debt and debt maturities, capital expenditures and general corporate purposes.

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15. 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, 2016
Description	Condensed Consolidated Balance Sheet Caption	Total		Level 1		Level 2		Level 3
		(in millions)
Corporate debt securities	Cash and cash equivalents	$	161	$	—	$	161	$	—
Corporate debt securities	Current assets—other	6		—		6		—
Corporate debt securities	Investments and other assets—other	9		—		9		—
Interest rate swaps	Investments and other assets—other	76		—		76		—
Canadian equity securities	Investments and other assets—other	15		15		—		—
Total Assets		$	267	$	15	$	252	$	—
Commodity derivatives	Liabilities held for sale	$	2	$	—	$	—	$	2
Total Liabilities		$	2	$	—	$	—	$	2



Description	Condensed Consolidated Balance Sheet Caption	December 31, 2015
Description	Condensed Consolidated Balance Sheet Caption	Total		Level 1		Level 2		Level 3
		(in millions)
Corporate debt securities	Cash and cash equivalents	$	137	$	—	$	137	$	—
Corporate debt securities	Current assets—other	20		—		20		—
Commodity derivatives	Current assets—other	36		—		—		36
Commodity derivatives	Investments and other assets—other	5		—		—		5
Corporate debt securities	Investments and other assets—other	11		—		11		—
Interest rate swaps	Investments and other assets—other	37		—		37		—
Total Assets		$	246	$	—	$	205	$	41

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,
	2016			2015			2016			2015
	(in millions)
Derivative assets (liabilities)
Fair value, beginning of period	$	10		$	49		$	41		$	78
Total gains (losses):
Included in earnings	(11		)	3			(15		)	9
Included in other comprehensive income	—			1			1			(5		)
Purchases	—			2			(1		)	3
Settlements	(1		)	(5		)	(28		)	(35		)
Fair value, end of period	$	(2	)	$	50		$	(2	)	$	50
Unrealized losses relating to instruments held at the end of the period	$	(8	)	$	—		$	(31	)	$	(16	)

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

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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, 2016 consist of NGL revenue swap contracts related to the Empress assets in Western Canada Transmission & Processing. As of June 30, 2016, 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, 2016, a 10¢ per gallon movement in underlying forward NGL prices, primarily propane prices, would affect the estimated fair value of our NGL derivatives by $1 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, 2016				December 31, 2015
	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)	13,638		14,994		13,567		13,891

__________


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


(b)	Excludes commercial paper, 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.

The fair values of cash and cash equivalents, restricted cash, short-term investments, accounts receivable, notes 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, 2016 and 2015, there were no material adjustments to assets and liabilities measured at fair value on a nonrecurring basis.

16. 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. As of April 2016, we are no longer entering into new contracts under our risk management program at Empress.

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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, 2016.

Interest Rate Swaps

At June 30, 2016, we had “pay floating—receive fixed” interest rate swaps outstanding with a total notional amount of $2 billion 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, 2016						December 31, 2015
	Gross Amounts Presented in the Condensed Consolidated Balance Sheet		Amounts Not Offset in the Condensed Consolidated Balance Sheet		Net Amount		Gross Amounts Presented in the Condensed Consolidated Balance Sheet		Amounts Not Offset in the Condensed Consolidated Balance Sheet		Net Amount
Description	(in millions)
Assets	$	76	$	—	$	76	$	37	$	—	$	37

Commodity Derivatives

At June 30, 2016, we had commodity mark-to-market derivatives outstanding with a total notional amount of 110 million gallons at Empress. 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, 2016						December 31, 2015
	Gross Amounts		Gross Amounts Offset		Net Amount Presented in the Condensed Consolidated Balance Sheet		Gross Amounts		Gross Amounts Offset		Net Amount Presented in the Condensed Consolidated Balance Sheet
Description	(in millions)
Assets	$	61	$	61	$	—	$	104	$	63	$	41
Liabilities	63		61		2		63		63		—

Substantially all of our commodity derivative agreements outstanding at June 30, 2016 and December 31, 2015 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.

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	2016			2015		2016			2015
		(in millions)
Commodity derivatives	Sales of natural gas liquids	$	(11	)	$	5	$	(16	)	$	12

17. 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, climate change, 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

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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.

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, 2016 or December 31, 2015 related to litigation.

Other Commitments and Contingencies

See Note 18 for a discussion of guarantees and indemnifications.

18. 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 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, 2016 was approximately $406 million, which has been indemnified by Duke Energy as discussed above. One of these outstanding performance guarantees, which has a 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, 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.

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.

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As of June 30, 2016, the amounts recorded for the guarantees and indemnifications described above are not material, both individually and in the aggregate.

19. Issuances of Common Stock

On March 1, 2016, we entered into an equity distribution agreement under which we may sell and issue common stock up to an aggregate offering price of $500 million. The equity distribution agreement allows us to offer and sell common stock at prices deemed appropriate through sales agents. Sales of common stock under the equity distribution agreement will be made by means of ordinary brokers’ transactions through the facilities of the New York Stock Exchange (NYSE), in block transactions, or as otherwise agreed upon by one or more of the sales agents and us. We intend to use the net proceeds from sales under this at-the-market program for general corporate purposes, including investments in subsidiaries to fund capital expenditures. We issued approximately 12.9 million of common shares to the public under this program, for total net proceeds of $383 million through June 30, 2016.

In April 2016, we issued 16.1 million common shares to the public for net proceeds of approximately $479 million. Net proceeds from the offering were used to purchase approximately 10.4 million common units in SEP. SEP intends to use the proceeds from our unit purchase for general corporate purposes, including the funding of its current expansion capital plan.

20. Issuances of SEP Units

During the six months ended June 30, 2016, SEP issued 7.0 million common units to the public under its at-the-market program and approximately 143,000 general partner units to Spectra Energy. Total net proceeds to SEP were $327 million (net proceeds to Spectra Energy were $321 million).

In April 2016, SEP issued 10.4 million common units and 0.2 million general partner units to Spectra Energy in a private placement transaction. See Note 19 for further discussion.

In connection with the issuances of the units, a $23 million gain ($15 million net of tax) to Additional Paid-in Capital and a $297 million increase in Equity—Noncontrolling Interests were recorded during the six months ended June 30, 2016. The issuances decreased Spectra Energy’s ownership in SEP from 78% to 77% at June 30, 2016.

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(in millions)
Net income—controlling interests	$	149	$	18	$	383	$	285
Increase in additional paid-in capital resulting from issuances of SEP units	7		19		15		25
Total net income—controlling interests and changes in equity—controlling interests	$	156	$	37	$	398	$	310

21. 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 both of the six months ended June 30, 2016 and 2015. We made total contributions to the Canadian DC and DB plans of $13 million in the six months ended June 30, 2016 and $16 million in the same period in 2015. We anticipate that we will make total contributions of approximately $22 million to the U.S. plans and approximately $26 million to the Canadian plans in 2016.

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(in millions)
U.S.
Service cost benefit earned	$	5		$	5		$	10		$	10
Interest cost on projected benefit obligation	6			6			12			12
Expected return on plan assets	(10		)	(11		)	(20		)	(21		)
Amortization of loss	2			3			4			5
Net periodic pension cost	$	3		$	3		$	6		$	6

Canada
Service cost benefit earned	$	7		$	8		$	15		$	16
Interest cost on projected benefit obligation	12			11			22			22
Expected return on plan assets	(16		)	(17		)	(32		)	(34		)
Amortization of loss	4			6			9			13
Amortization of prior service cost	1			1			1			1
Net periodic pension cost	$	8		$	9		$	15		$	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,
	2016			2015			2016			2015
	(in millions)
U.S.
Interest cost on accumulated post-retirement benefit obligation	$	2		$	2		$	4		$	4
Expected return on plan assets	(1		)	(2		)	(2		)	(3		)
Net periodic other post-retirement benefit cost	$	1		$	—		$	2		$	1

Canada
Service cost benefit earned	$	—		$	1		$	1		$	2
Interest cost on accumulated post-retirement benefit obligation	1			1			2			2
Net periodic other post-retirement benefit cost	$	1		$	2		$	3		$	4

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, 2016 and 2015, and $7 million in both of the six months ended June 30, 2016 and 2015 for U.S. employees. We expensed pre-tax employer matching contributions of $3 million and $2 million in the three months ended June 30, 2016 and 2015, respectively, and $6 million and $5 million in the six months ended June 30, 2016 and 2015, respectively, for Canadian employees.

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22. 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 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, 2016
Total operating revenues	$	—		$	—		$	1,159		$	—		$	1,159
Total operating expenses	2			1			785			—			788
Operating income (loss)	(2		)	(1		)	374			—			371
Earnings from equity investments	—			—			16			—			16
Equity in earnings of consolidated subsidiaries	144			261			—			(405		)	—
Other income and expenses, net	(2		)	—			41			—			39
Interest expense	—			61			92			—			153
Earnings before income taxes	140			199			339			(405		)	273
Income tax expense (benefit)	(9		)	55			6			—			52
Net income	149			144			333			(405		)	221
Net income—noncontrolling interests	—			—			72			—			72
Net income—controlling interests	$	149		$	144		$	261		$	(405	)	$	149

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

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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, 2016
Total operating revenues	$	—		$	—		$	2,544		$	(1	)	$	2,543
Total operating expenses	5			2			1,672			(1		)	1,678
Operating income (loss)	(5		)	(2		)	872			—			865
Earnings from equity investments	—			—			49			—			49
Equity in earnings of consolidated subsidiaries	371			653			—			(1,024		)	—
Other income and expenses, net	(2		)	—			73			—			71
Interest expense	—			123			181			—			304
Earnings before income taxes	364			528			813			(1,024		)	681
Income tax expense (benefit)	(19		)	157			12			—			150
Net income	383			371			801			(1,024		)	531
Net income—noncontrolling interests	—			—			148			—			148
Net income—controlling interests	$	383		$	371		$	653		$	(1,024	)	$	383

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

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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, 2016
Net income	$	149	$	144	$	333		$	(405	)	$	221
Other comprehensive income	1		—		56			—			57
Total comprehensive income, net of tax	150		144		389			(405		)	278
Less: comprehensive income—noncontrolling interests	—		—		75			—			75
Comprehensive income—controlling interests	$	150	$	144	$	314		$	(405	)	$	203

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

Six Months Ended June 30, 2016
Net income	$	383	$	371	$	801		$	(1,024	)	$	531
Other comprehensive income	2		—		360			—			362
Total comprehensive income, net of tax	385		371		1,161			(1,024		)	893
Less: comprehensive income—noncontrolling interests	—		—		155			—			155
Comprehensive income—controlling interests	$	385	$	371	$	1,006		$	(1,024	)	$	738

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	)

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Spectra Energy Corp

Condensed Consolidating Balance Sheet

June 30, 2016

(Unaudited)

(In millions)



	Spectra Energy Corp		Spectra Capital		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Cash and cash equivalents	$	—	$	2	$	238	$	—		$	240
Receivables—consolidated subsidiaries	12		—		6		(18		)	—
Notes receivable—current—consolidated subsidiaries	—		—		388		(388		)	—
Receivables—other	1		—		707		—			708
Other current assets	12		—		677		—			689
Total current assets	25		2		2,016		(406		)	1,637
Investments in and loans to unconsolidated affiliates	—		—		2,657		—			2,657
Investments in consolidated subsidiaries	14,716		20,229		—		(34,945		)	—
Advances receivable—consolidated subsidiaries	—		5,037		1,331		(6,368		)	—
Notes receivable—consolidated subsidiaries	—		—		2,800		(2,800		)	—
Goodwill	—		—		4,217		—			4,217
Other assets	41		46		286		—			373
Net property, plant and equipment	—		—		24,707		—			24,707
Regulatory assets and deferred debits	3		4		1,449		—			1,456
Total Assets	$	14,785	$	25,318	$	39,463	$	(44,519	)	$	35,047

Accounts payable	$	2	$	2	$	705	$	—		$	709
Accounts payable—consolidated subsidiaries	—		15		3		(18		)	—
Commercial paper	—		363		750		—			1,113
Short-term borrowings—consolidated subsidiaries	—		388		—		(388		)	—
Taxes accrued	2		2		76		—			80
Current maturities of long-term debt	—		—		68		—			68
Other current liabilities	62		47		707		—			816
Total current liabilities	66		817		2,309		(406		)	2,786
Long-term debt	—		2,911		10,673		—			13,584
Advances payable—consolidated subsidiaries	6,368		—		—		(6,368		)	—
Notes payable—consolidated subsidiaries	—		2,800		—		(2,800		)	—
Deferred credits and other liabilities	753		4,074		2,288		—			7,115
Preferred stock of subsidiaries	—		—		339		—			339
Equity
Controlling interests	7,598		14,716		20,229		(34,945		)	7,598
Noncontrolling interests	—		—		3,625		—			3,625
Total equity	7,598		14,716		23,854		(34,945		)	11,223
Total Liabilities and Equity	$	14,785	$	25,318	$	39,463	$	(44,519	)	$	35,047

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Spectra Energy Corp

Condensed Consolidating Balance Sheet

December 31, 2015

(Unaudited)

(In millions)



	Spectra Energy Corp		Spectra Capital		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Cash and cash equivalents	$	—	$	1	$	212	$	—		$	213
Receivables—consolidated subsidiaries	15		6		13		(34		)	—
Notes receivable—current—consolidated subsidiaries	—		—		387		(387		)	—
Receivables—other	2		—		804		—			806
Other current assets	25		—		604		—			629
Total current assets	42		7		2,020		(421		)	1,648
Investments in and loans to unconsolidated affiliates	—		—		2,592		—			2,592
Investments in consolidated subsidiaries	13,919		19,161		—		(33,080		)	—
Advances receivable—consolidated subsidiaries	—		5,273		1,326		(6,599		)	—
Notes receivable—consolidated subsidiaries	—		—		2,800		(2,800		)	—
Goodwill	—		—		4,154		—			4,154
Other assets	41		27		242		—			310
Net property, plant and equipment	—		—		22,918		—			22,918
Regulatory assets and deferred debits	3		3		1,295		—			1,301
Total Assets	$	14,005	$	24,471	$	37,347	$	(42,900	)	$	32,923

Accounts payable	$	2	$	3	$	506	$	—		$	511
Accounts payable—consolidated subsidiaries	4		28		2		(34		)	—
Commercial paper	—		481		631		—			1,112
Short-term borrowings—consolidated subsidiaries	—		387		—		(387		)	—
Taxes accrued	5		—		73		—			78
Current maturities of long-term debt	—		—		652		—			652
Other current liabilities	102		48		889		—			1,039
Total current liabilities	113		947		2,753		(421		)	3,392
Long-term debt	—		2,891		10,001		—			12,892
Advances payable—consolidated subsidiaries	6,599		—		—		(6,599		)	—
Notes payable—consolidated subsidiaries	—		2,800		—		(2,800		)	—
Deferred credits and other liabilities	767		3,914		2,087		—			6,768
Preferred stock of subsidiaries	—		—		339		—			339
Equity
Controlling interests	6,526		13,919		19,161		(33,080		)	6,526
Noncontrolling interests	—		—		3,006		—			3,006
Total equity	6,526		13,919		22,167		(33,080		)	9,532
Total Liabilities and Equity	$	14,005	$	24,471	$	37,347	$	(42,900	)	$	32,923

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Spectra Energy Corp

Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2016

(Unaudited)

(In millions)



	Spectra Energy Corp			Spectra Capital			Non-Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	383		$	371		$	801		$	(1,024	)	$	531
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	—			—			397			—			397
Earnings from equity investments	—			—			(49		)	—			(49		)
Equity in earnings of consolidated subsidiaries	(371		)	(653		)	—			1,024			—
Distributions from equity investments	—			—			52			—			52
Other	(43		)	216			135			—			308
Net cash provided by (used in) operating activities	(31		)	(66		)	1,336			—			1,239
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	—			—			(1,520		)	—			(1,520		)
Investments in and loans to unconsolidated affiliates	—			—			(112		)	—			(112		)
Purchase of intangible, net	—			—			(40		)	—			(40		)
Purchases of held-to-maturity securities	—			—			(346		)	—			(346		)
Proceeds from sales and maturities of held-to-maturity securities	—			—			364			—			364
Purchases of available-for-sale securities	—			—			(329		)	—			(329		)
Proceeds from sales and maturities of available-for-sale securities	—			—			330			—			330
Distributions from equity investments	—			—			45			—			45
Distribution to equity investment	—			—			(148		)	—			(148		)
Advances from (to) affiliates	(50		)	197			—			(147		)	—
Other changes in restricted funds	—			—			11			—			11
Other	—			—			1			—			1
Net cash provided by (used in) investing activities	(50		)	197			(1,744		)	(147		)	(1,744		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	—			—			382			—			382
Payments for the redemption of long-term debt	—			—			(619		)	—			(619		)
Net increase (decrease) in commercial paper	—			(118		)	95			—			(23		)
Distributions to noncontrolling interests	—			—			(114		)	—			(114		)
Contributions from noncontrolling interests	—			—			278			—			278
Proceeds from the issuances of Spectra Energy common stock	868			—			—			—			868
Proceeds from the issuances of SEP common units	—			—			321			—			321
Dividends paid on common stock	(557		)	—			—			—			(557		)
Distributions and advances from (to) affiliates	(231		)	(12		)	96			147			—
Other	1			—			(9		)	—			(8		)
Net cash provided by (used in) financing activities	81			(130		)	430			147			528
Effect of exchange rate changes on cash	—			—			4			—			4
Net increase in cash and cash equivalents	—			1			26			—			27
Cash and cash equivalents at beginning of period	—			1			212			—			213
Cash and cash equivalents at end of period	$	—		$	2		$	238		$	—		$	240

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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 from equity investments	—			—			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 from equity investments	—			—			35			—			35
Advances from (to) 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 issuances 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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23. New Accounting Pronouncements

In June 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-10, “Development Stage Entities (Topic 915): Elimination of Certain Financial Reporting Requirements, Including an Amendment to Variable Interest Entities Guidance in Topic 810, Consolidation,” which amends the consolidation guidance around reporting entities that invest in development stage entities. We adopted the consolidation guidance of this amendment on January 1, 2016 and applied it retrospectively with no material effect on our consolidated results of operations, financial position or cash flows. This ASU did result in certain of our entities being classified as Variable Interest Entities. See Note 10 for discussion of our Variable Interest Entities.

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 required reevaluation of certain entities for consolidation and required us to revise our documentation regarding the consolidation or deconsolidation of such entities. We adopted this standard on January 1, 2016 with no material effect on our consolidated results of operations, financial position or cash flows.

In September 2015, the FASB issued ASU No. 2015-16, “Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments,” to simplify accounting for adjustments made to provisional amounts recognized in a business combination and to eliminate the retrospective accounting for those adjustments. We adopted this standard on January 1, 2016. The adoption of this standard has not had a material impact on our consolidated results of operations, financial position or cash flow.

In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842),” to improve the financial reporting around leasing transactions. The new guidance requires companies to begin recording assets and liabilities arising from those leases classified as operating leases under previous guidance. Furthermore, the new guidance will require significant additional disclosures about the amount, timing and uncertainty of cash flows from leases. Topic 842 retains a distinction between finance leases and operating leases. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the classification criteria for distinguishing between capital leases and operating leases in previous guidance. The result of retaining a distinction between finance leases and operating leases is that under the lessee accounting model in Topic 842, the effect of leases in the statement of comprehensive income and the statement of cash flows is largely unchanged from previous guidance. This ASU is effective for us January 1, 2019. We are currently evaluating this ASU and its potential impact on us.

In March 2016, the FASB issued ASU No. 2016-05, “Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships,” which clarifies the hedge accounting impact when there is a change in one of the counterparties to the derivative contract (i.e. novation). This ASU is effective for us January 1, 2017. This ASU is not expected to have a material impact on our consolidated results of operations, financial position or cash flow.

In March 2016, the FASB issued ASU No. 2016-06, “Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments,” which simplifies the embedded derivative analysis for debt instruments containing contingent call or put options. This ASU is effective for us January 1, 2017. This ASU is not expected to have a material impact on our consolidated results of operations, financial position or cash flow.

In March 2016, the FASB issued ASU No. 2016-07, “Investments—Equity Method and Joint Ventures (Topic 323): Simplifying the Transition to the Equity Method of Accounting,” which eliminates the requirement to apply the equity method of accounting retrospectively when a reporting entity obtains significant influence over a previously held investment. This ASU is effective for us January 1, 2017. We are currently evaluating this ASU and its potential impact on us.

In March 2016, the FASB issued ASU No. 2016-08, “Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net),” to clarify implementation guidance on principal versus agent considerations. This ASU is effective for us on January 1, 2018. We are currently evaluating this ASU and its potential impact on us.

In March 2016, the FASB issued ASU No. 2016-09, “Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting,” which simplifies several aspects of the accounting for share-based payment award transactions. This ASU is effective for us January 1, 2017. We are currently evaluating this ASU and its potential impact on us.

In April 2016, the FASB issued ASU No. 2016-10, “Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing,” to clarify implementation guidance on performance obligations and licensing. This ASU is effective for us on January 1, 2018. We are currently evaluating this ASU and its potential impact on us.

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In May 2016, the FASB issued ASU No. 2016-12, “Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients,” to clarify implementation guidance on assessing collectibility, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition. This ASU is effective for us on January 1, 2018. We are currently evaluating this ASU and its potential impact on us.

In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,” to replace the incurred loss impairment methodology with a methodology that reflects expected credit losses and requires the consideration of a broader range of reasonable and supportable information to inform credit loss estimates. This ASU is effective for us on January 1, 2020. We are currently evaluating this ASU and its potential impact on us.



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, 2016 and 2015, we reported net income from controlling interests of $149 million and $18 million, respectively. For the six months ended June 30, 2016 and 2015, we reported net income from controlling interests of $383 million and $285 million, respectively.

The highlights for the three months and six months ended June 30, 2016 include the following:

•

Spectra Energy Partners’ earnings for the three-month period benefited mainly from expansion projects, more than offset by a one-time property tax accrual adjustment in 2015 and by the absence of equity earnings from DCP Sand Hills Pipeline, LLC (Sand Hills) and DCP Southern Hills Pipeline, LLC (Southern Hills) NGL pipelines, which SEP owned until October 2015. For the six-month period, earnings benefited mainly from expansion projects, more than offset by lower interruptible and short-term firm transportation revenue, a one-time property tax accrual adjustment in 2015 and by the absence of equity earnings from Sand Hills and Southern Hills.

•

Distribution’s earnings for the three-month period benefited mainly from incremental earnings from the 2015 Dawn-Parkway expansion project and colder weather, partially offset by a lower Canadian dollar. For the six-month period, earnings decreased mainly due to the effect of a lower Canadian dollar and warmer weather, partially offset by incremental earnings from the 2015 Dawn-Parkway expansion project and lower earnings to be shared with customers.


•	Western Canada Transmission & Processing’s earnings for the three and six-month periods decreased mainly due to lower firm gathering and processing revenues, lower earnings at Empress and a lower Canadian dollar, partially offset by lower plant turnaround costs.


•	Field Services’ earnings for the three and six-month periods increased mainly due to the 2015 partial impairment of goodwill at DCP Midstream and favorable contract realignment efforts and continued costs savings, partially offset by lower commodity prices.

We are conducting an assessment of the Texas Eastern Transmission, LP (Texas Eastern) natural gas transmission system across Pennsylvania and New Jersey. The assessment is the result of a corrective action order from the Pipeline and Hazardous Materials Safety Administration (PHMSA), as well as our own work plan, related to an incident on the system on April 29, 2016 near Delmont, Pennsylvania. This assessment program and the related system repairs are expected to cost approximately $75 million to $100 million. Approximately 90% of this program will be completed in 2016, with the remainder of the work to be performed in 2017. Additional inspections and repairs, if any, will be determined after the completion of this work. Importantly, we expect that by November 1, 2016, we will be in a position to fully meet our customer obligations for the winter season.

In the first six months of 2016, we had $1.6 billion of capital and investment expenditures. We currently project $4.2 billion of capital and investment expenditures for the full year, including expansion capital expenditures of $3.6 billion. These projections exclude contributions from noncontrolling interests.

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

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cash flows as well as the issuances of debt and equity securities. As of June 30, 2016, our revolving credit facilities included Spectra Capital’s $1 billion facility, SEP’s $2.5 billion facility, Westcoast’s 400 million Canadian dollar facility and Union Gas’ 700 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,
	2016		2015			2016		2015
	(in millions)
Operating revenues	$	1,159	$	1,192		$	2,543	$	2,815
Operating expenses	788		786			1,678		1,868
Operating income	371		406			865		947
Other income and expenses	55		(167		)	120		(123		)
Interest expense	153		166			304		325
Earnings before income taxes	273		73			681		499
Income tax expense (benefit)	52		(7		)	150		94
Net income	221		80			531		405
Net income—noncontrolling interests	72		62			148		120
Net income—controlling interests	$	149	$	18		$	383	$	285

Three Months Ended June 30, 2016 Compared to Same Period in 2015

Operating Revenues. The $33 million decrease was driven by:


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


•	lower firm gathering and processing revenues and a decrease from non-cash mark-to-market commodity-related pricing adjustments and lower 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, net of higher residential usage due to colder weather at Distribution, partially offset by


•	higher revenues from expansion projects at Spectra Energy Partners.

Operating Expenses. The $2 million increase was driven by:


•	higher costs related to expansion projects, higher property tax accruals due to the absence of a 2015 tax benefit and higher pipeline inspection and repair costs at Spectra Energy Partners and


•	higher volumes of natural gas sold due to colder weather, net of lower natural gas prices passed through to customers at Distribution, partially offset by


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


•	lower plant turnaround costs at Western Canada Transmission & Processing.

Other Income and Expenses. The $222 million increase was mainly attributable to lower equity losses from Field Services mainly due to the 2015 partial impairment of goodwill at DCP Midstream.

Interest Expense. The $13 million decrease was mainly due to higher capitalized interest.

Income Tax Expense. The $59 million increase was primarily attributable to the tax impact of the partial impairment of goodwill at DCP Midstream in 2015, partially offset by tax rate changes in 2016.

The effective tax rate for income from continuing operations was 19% for the three months ended June 30, 2016 compared to negative 10% for the same period in 2015.

Net Income—Noncontrolling Interests. The $10 million increase was driven primarily by higher noncontrolling ownership interests at Spectra Energy Partners.

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Six Months Ended June 30, 2016 Compared to Same Period in 2015

Operating Revenues. The $272 million decrease was driven by:


•	lower usage due to warmer weather and lower natural gas prices passed through to customers at Distribution,


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


•	a decrease from non-cash mark-to-market commodity-related pricing adjustments associated with the risk management program, lower NGL prices at the Empress operations and a decrease in firm gathering and processing revenues at Western Canada Transmission & Processing, partially offset by


•	higher revenues from expansion projects at Spectra Energy Partners.

Operating Expenses. The $190 million decrease was driven by:


•	lower volumes of natural gas sold due to warmer weather and lower natural gas prices passed through to customers at Distribution,


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


•	lower costs of sales at the Empress operations and lower plant turnaround costs at Western Canada Transmission & Processing, partially offset by


•	higher costs related to expansion projects, pipeline inspection and repair costs and property tax accruals due to the absence of a 2015 tax benefit at Spectra Energy Partners.

Other Income and Expenses. The $243 million increase was mainly attributable to lower equity losses from Field Services mainly due to the 2015 partial impairment of goodwill at DCP Midstream.

Interest Expense. The $21 million decrease was mainly due to higher capitalized interest and a lower Canadian dollar, partially offset by higher average long-term debt balances.

Income Tax Expense. The $56 million increase was primarily attributable to the tax impact on the partial impairment of goodwill at DCP Midstream in 2015, partially offset by tax rate changes in 2016.

The effective tax rate for income from continuing operations was 22% for the six months ended June 30, 2016 compared to 19% for the same period in 2015.

Net Income—Noncontrolling Interests. The $28 million increase was driven primarily by higher noncontrolling ownership interests at Spectra Energy Partners.

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

Segment Results

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

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

EBITDA by Business Segment



	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(in millions)
Spectra Energy Partners	$	471		$	478		$	944		$	933
Distribution	104			98			274			290
Western Canada Transmission & Processing	97			104			220			265
Field Services	(14		)	(233		)	(11		)	(250		)
Total reportable segment EBITDA	658			447			1,427			1,238
Other	(36		)	(12		)	(55		)	(27		)
Total reportable segment and other EBITDA	$	622		$	435		$	1,372		$	1,211
Depreciation and amortization	196			193			389			386
Interest expense	153			166			304			325
Interest income and other (a)	—			(3		)	2			(1		)
Earnings before income taxes	$	273		$	73		$	681		$	499

___________


(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,
	2016		2015		Increase (Decrease)			2016		2015		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	618	$	603	$	15		$	1,242	$	1,209	$	33
Operating expenses
Operating, maintenance and other	216		192		24			421		399		22
Other income and expenses	69		67		2			123		123		—
EBITDA	$	471	$	478	$	(7	)	$	944	$	933	$	11
Express pipeline revenue receipts, MBbl/d (a)	233		235		(2		)	233		242		(9		)
Platte PADD II deliveries, MBbl/d	143		172		(29		)	132		170		(38		)

___________


(a)	Thousand barrels per day.

Three Months Ended June 30, 2016 Compared to Same Period in 2015

Operating Revenues. The $15 million increase was driven by:


•	a $29 million increase due to expansion projects primarily on Texas Eastern and


•	a $3 million increase in storage revenues due to new contracts at higher rates, partially offset by


•	a $5 million decrease in recoveries of electric power and other costs passed through to gas transmission customers,


•	a $4 million decrease in processing revenues primarily due to volumes and lower prices,


•	a $4 million decrease in crude oil transportation revenues, as a result of lower Platte pipeline volumes, partially offset by increased tariff rates mainly on the Express pipeline and


•	a $4 million decrease in natural gas transportation revenues mainly from short-term firm transportation on Texas Eastern.

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Operating, Maintenance and Other. The $24 million increase was driven by:


•	a $16 million increase in expansion project costs,


•	a $9 million increase in property taxes due to the benefit recognized in 2015 and


•	a $6 million increase due to pipeline inspection and repair costs related to the Texas Eastern incident near Delmont, PA, partially offset by


•	a $5 million decrease in electric power and other costs passed through to gas transmission customers and


•	a $3 million decrease in power costs due to lower usage in 2016 on the Express and Platte pipelines.

Other Income and Expenses. Relatively flat year over year and included:


•	a $17 million increase primarily due to higher AFUDC from higher capital spending on expansion projects, offset by


•	an $18 million decrease primarily due to the absence of equity earnings from Sand Hills and Southern Hills owned until October 2015.

Six Months Ended June 30, 2016 Compared to Same Period in 2015

Operating Revenues. The $33 million increase was driven by:


•	a $57 million increase due to expansion projects, primarily on Texas Eastern, partially offset by


•	a $10 million decrease in natural gas transportation revenues mainly from interruptible transportation on Texas Eastern and Maritimes and Northeast, L.L.C. and short-term firm transportation on Algonquin Gas Transmission, LLC,


•	a $9 million decrease in recoveries of electric power and other costs passed through to gas transmission customers,


•	a $4 million decrease in processing revenues primarily due to lower prices and volumes and


•	a $4 million decrease in crude oil transportation revenues, as a result of lower volumes on the Platte and Express pipelines, substantially offset by increased tariff rates mainly on the Express pipeline.

Operating, Maintenance and Other. The $22 million increase was driven by:


•	a $31 million increase in expansion project costs,


•	a $6 million increase due to pipeline inspection and repair costs related to the Texas Eastern incident near Delmont, PA and


•	a $5 million increase in property taxes due to the benefit recognized in 2015, partially offset by


•	a $9 million decrease due to a prior year non-cash impairment charge on Ozark Gas Gathering,


•	a $9 million decrease in electric power and other costs passed through to gas transmission customers and


•	a $6 million decrease in power costs due to lower usage in 2016 on the Express and Platte pipelines.

Other Income and Expenses. Relatively flat year over year and included:


•	a $24 million increase primarily due to higher AFUDC from higher capital spending on expansion projects, offset by


•	a $31 million decrease in equity earnings primarily due to the absence of equity earnings from Sand Hills and Southern Hills owned until October 2015.

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Distribution



	Three Months Ended June 30,							Six Months Ended June 30,
	2016		2015		Increase (Decrease)			2016		2015		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	284	$	290	$	(6	)	$	749	$	952	$	(203	)
Operating expenses
Natural gas purchased	91		103		(12		)	306		486		(180		)
Operating, maintenance and other	89		90		(1		)	171		176		(5		)
Other income and expenses	—		1		(1		)	2		—		2
EBITDA	$	104	$	98	$	6		$	274	$	290	$	(16	)
Number of customers, thousands								1,446		1,425		21
Heating degree days, Fahrenheit	1,032		866		166			4,347		5,125		(778		)
Pipeline throughput, TBtu (a)	155		132		23			385		460		(75		)
Canadian dollar exchange rate, average	1.29		1.23		0.06			1.33		1.23		0.10

___________


(a)	Trillion British thermal units.

Three Months Ended June 30, 2016 Compared to Same Period in 2015

Operating Revenues. The $6 million decrease was driven by:


•	a $15 million decrease resulting from a lower Canadian dollar,


•	a $12 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 $7 million decrease in industrial market usage, partially offset by


•	a $19 million increase in residential customer usage of natural gas primarily due to colder weather in 2016,


•	a $5 million increase from the 2015 Dawn-Parkway expansion project and


•	a $4 million increase from growth in the number of customers.

Natural Gas Purchased. The $12 million decrease was driven by:


•	a $12 million decrease from lower natural gas prices passed through to customers,


•	a $7 million decrease in industrial market usage and


•	a $4 million decrease resulting from a lower Canadian dollar, partially offset by


•	a $10 million increase due to higher volumes of natural gas sold to residential customers primarily due to colder weather and


•	a $3 million increase from growth in the number of customers.

Six Months Ended June 30, 2016 Compared to Same Period in 2015

Operating Revenues. The $203 million decrease was driven by:


•	a $98 million decrease in residential customer usage of natural gas primarily due to warmer weather in 2016,


•	a $78 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,


•	a $67 million decrease resulting from a lower Canadian dollar and


•	a $9 million decrease in industrial market usage, partially offset by

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•	a $22 million increase from growth in the number of customers,


•	an $11 million increase from lower utility earnings to be shared with customers in accordance with the incentive regulation framework,


•	an $11 million increase from the 2015 Dawn-Parkway expansion project,


•	a $5 million increase in rates primarily due to increased DSM program charges and


•	a $5 million increase in storage revenue primarily due to higher storage pricing.

Natural Gas Purchased. The $180 million decrease was driven by:


•	an $80 million decrease due to lower volumes of natural gas sold to residential customers primarily due to warmer weather,


•	a $79 million decrease from lower natural gas prices passed through to customers,


•	a $29 million decrease resulting from a lower Canadian dollar and


•	a $9 million decrease in industrial market usage, partially offset by


•	an $18 million increase from growth in the number of customers.

Operating, Maintenance and Other. The $5 million decrease was driven by:


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


•	a $6 million increase in operating and maintenance expenses primarily due to higher employee related costs and increased DSM program charges.

Western Canada Transmission & Processing



	Three Months Ended June 30,								Six Months Ended June 30,
	2016		2015			Increase (Decrease)			2016		2015		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	258	$	304		$	(46	)	$	563	$	674	$	(111	)
Operating expenses
Natural gas and petroleum products purchased	15		25			(10		)	63		92		(29		)
Operating, maintenance and other	148		174			(26		)	285		321		(36		)
Other income and expenses	2		(1		)	3			5		4		1
EBITDA	$	97	$	104		$	(7	)	$	220	$	265	$	(45	)
Pipeline throughput, TBtu	214		220			(6		)	466		476		(10		)
Volumes processed, TBtu	163		156			7			339		336		3
Canadian dollar exchange rate, average	1.29		1.23			0.06			1.33		1.23		0.10

Three Months Ended June 30, 2016 Compared to Same Period in 2015

Operating Revenues. The $46 million decrease was driven by:


•	a $14 million decrease in firm gathering and processing revenues,


•	a $12 million decrease resulting from a lower Canadian dollar,


•	a $12 million decrease arising from changes in non-cash mark-to-market commodity-related pricing adjustments associated with the risk management program at the Empress operations and


•	a $5 million decrease resulting from lower settlement gains associated with the risk management program at the Empress operations.

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Natural Gas and Petroleum Products Purchased. The $10 million decrease was driven 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 and


•	a $4 million decrease primarily as a result of lower costs of NGL sales at the Empress operations.

Operating, Maintenance and Other. The $26 million decrease was driven by:


•	a $17 million decrease in plant turnaround costs and


•	a $7 million decrease resulting from a lower Canadian dollar.

Six Months Ended June 30, 2016 Compared to Same Period in 2015

Operating Revenues. The $111 million decrease was driven by:


•	a $46 million decrease resulting from a lower Canadian dollar,


•	a $25 million decrease arising from changes in non-cash mark-to-market commodity-related pricing adjustments associated with the risk management program at the Empress operations,


•	a $21 million decrease due to lower NGL prices associated with the Empress operations and


•	a $17 million decrease in firm gathering and processing revenues.

Natural Gas and Petroleum Products Purchased. The $29 million decrease was driven by:


•	a $23 million decrease primarily as a result of lower costs of NGL sales at the Empress facility and


•	a $6 million decrease resulting from a lower Canadian dollar.

Operating, Maintenance and Other. The $36 million decrease was driven by:


•	a $21 million decrease in plant turnaround costs and


•	a $21 million decrease resulting from a lower Canadian dollar.

Field Services



	Three Months Ended June 30,									Six Months Ended June 30,
	2016			2015			Increase (Decrease)			2016			2015			Increase (Decrease)
	(in millions, except where noted)
Earnings (loss) from equity investments	$	(14	)	$	(233	)	$	219		$	(11	)	$	(250	)	$	239
EBITDA	$	(14	)	$	(233	)	$	219		$	(11	)	$	(250	)	$	239
Natural gas gathered and processed/transported, TBtu/d (a,b)	6.7			7.0			(0.3		)	6.8			7.1			(0.3		)
NGL production, MBbl/d (a)	416			408			8			399			404			(5		)
Average natural gas price per MMBtu (c,d)	$	1.95		$	2.64		$	(0.69	)	$	2.02		$	2.81		$	(0.79	)
Average NGL price per gallon (e)	$	0.46		$	0.48		$	(0.02	)	$	0.41		$	0.48		$	(0.07	)
Average crude oil price per barrel (f)	$	45.64		$	57.94		$	(12.30	)	$	39.54		$	53.29		$	(13.75	)

___________


(a)	Reflects 100% of volumes.


(b)	Trillion British thermal units per day.


(c)	Average price based on NYMEX Henry Hub.


(d)	Million British thermal units.


(e)	Does not reflect results of commodity hedges.


(f)	Average price based on NYMEX calendar month.

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Three Months Ended June 30, 2016 Compared to Same Period in 2015

EBITDA increased $219 million mainly as a result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:


•	a $213 million increase primarily as a result of the 2015 partial impairment of goodwill at DCP Midstream,


•	a $24 million increase in gathering and processing margins primarily as a result of asset growth and favorable contract realignment and


•	an $11 million increase due to favorable results from NGL pipelines, partially offset by


•	a $19 million decrease resulting from increased net income attributable to noncontrolling interests primarily as a result of asset growth and prior year asset impairments and


•	a $15 million decrease from commodity-sensitive processing arrangements primarily due to decreased natural gas and crude oil prices.

Six Months Ended June 30, 2016 Compared to Same Period in 2015

EBITDA increased $239 million mainly as a result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:


•	a $213 million increase primarily as a result of the 2015 partial impairment of goodwill at DCP Midstream,


•	a $49 million increase in gathering and processing margins primarily as a result of asset growth and favorable contract realignment,


•	a $45 million increase primarily as a result of a producer settlement and


•	a $23 million increase due to favorable results from NGL pipelines, partially offset by unfavorable results from wholesale propane, partially offset by


•	a $49 million decrease from commodity-sensitive processing arrangements primarily due to decreased natural gas and crude oil prices and


•	a $22 million decrease resulting from increased net income attributable to noncontrolling interests primarily as a result of asset growth and prior year asset impairments.

Other



	Three Months Ended June 30,									Six Months Ended June 30,
	2016			2015			Increase (Decrease)			2016			2015			Increase (Decrease)
	(in millions)
Operating revenues	$	19		$	17		$	2		$	36		$	35		$	1
Operating expenses
Operating, maintenance and other	53			30			23			90			62			28
Other income and expenses	(2		)	1			(3		)	(1		)	—			(1		)
EBITDA	$	(36	)	$	(12	)	$	(24	)	$	(55	)	$	(27	)	$	(28	)

Three Months Ended June 30, 2016 Compared to Same Period in 2015

EBITDA. The $24 million decrease was driven by:


•	a $10 million decrease due to captive insurance general liability reserve related to the Texas Eastern incident near Delmont, PA and


•	a $10 million decrease due to higher employee benefit costs.

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Six Months Ended June 30, 2016 Compared to Same Period in 2015

EBITDA. The $28 million decrease was driven by:


•	a $14 million decrease due to higher employee benefit costs and


•	a $10 million decrease due to captive insurance general liability reserve related to the Texas Eastern incident near Delmont, PA.

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, 2016 (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, 2016 were substantially in excess of their respective carrying values.

No triggering events have occurred with our reporting units since the April 1, 2016 test that would warrant re-testing for goodwill impairment.

LIQUIDITY AND CAPITAL RESOURCES

As of June 30, 2016, we had negative working capital of $1,149 million. This balance includes commercial paper liabilities totaling $1,113 million and accrued interest of $181 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, 2016, our four revolving credit facilities included Spectra Capital’s $1.0 billion facility, SEP’s $2.5 billion facility, Westcoast’s 400 million Canadian dollar facility and Union Gas’ 700 million Canadian dollar facility, with available capacity of $1.8 billion under SEP’s credit facility and $1.4 billion 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 for temporary funding of capital expenditures and 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 14 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,
	2016			2015
Net cash provided by (used in):	(in millions)
Operating activities	$	1,239		$	1,456
Investing activities	(1,744		)	(976		)
Financing activities	528			(406		)
Effect of exchange rate changes on cash	4			(2		)
Net increase in cash and cash equivalents	27			72
Cash and cash equivalents at beginning of period	213			215
Cash and cash equivalents at end of period	$	240		$	287

Operating Cash Flows

Net cash provided by operating activities decreased $217 million to $1,239 million in the six months ended June 30, 2016 compared to the same period in 2015, driven mostly by changes in working capital.

Investing Cash Flows

Net cash used in investing activities increased $768 million to $1,744 million in the six months ended June 30, 2016 compared to the same period in 2015. This change was driven mainly by an increase in capital and investment expenditures.



	Six Months Ended June 30,
	2016		2015
Capital and Investment Expenditures	(in millions)
Spectra Energy Partners	$	1,135	$	638
Distribution	341		207
Western Canada Transmission & Processing	133		149
Total reportable segments	1,609		994
Other	23		29
Total consolidated	$	1,632	$	1,023

Capital and investment expenditures for the six months ended June 30, 2016 consisted of $1,388 million for expansion projects and $244 million for maintenance.

We project 2016 capital and investment expenditures of approximately $4.2 billion, consisting of approximately $2.7 billion for SEP, $0.9 billion for Distribution and $0.6 billion for Western Canada Transmission & Processing. Total projected 2016 capital and investment expenditures include approximately $3.6 billion of expansion capital expenditures and $0.6 billion for maintenance and upgrades of existing plants, pipelines and infrastructure to serve growth. These projections exclude contributions from noncontrolling interests.

Financing Cash Flows and Liquidity

Net cash provided by financing activities increased $934 million to $528 million for the six months ended June 30, 2016 compared to the same period in 2015. This change was mainly driven by $868 million from Spectra Energy's common stock issuance proceeds in 2016.

Spectra Energy Common Stock Issuances. On March 1, 2016, we entered into an equity distribution agreement under which we may sell and issue common stock up to an aggregate offering price of $500 million. The equity distribution agreement allows us to offer and sell common stock at prices deemed appropriate through sales agents. Sales of common stock under the equity distribution agreement will be made by means of ordinary brokers’ transactions through the facilities of the NYSE, in block transactions, or as otherwise agreed upon by one or more of the sales agents and us. We intend to use the net proceeds from sales under this at-the-market program for general corporate purposes, including investments in subsidiaries to

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fund capital expenditures. We issued approximately 12.9 million of common shares to the public under this program, for total net proceeds of $383 million through June 30, 2016.

SEP Common Unit Issuances. During the six months ended June 30, 2016, SEP issued 7.0 million common units to the public under its at-the-market program and approximately 143,000 general partner units to Spectra Energy. Total net proceeds to SEP were $327 million (net proceeds to Spectra Energy were $321 million). In April 2016, SEP issued 10.4 million common units and 0.2 million general partner units to Spectra Energy in a private placement transaction. In connection with the issuances of the units, a $23 million gain ($15 million net of tax) to Additional Paid-in Capital and a $297 million increase in Equity—Noncontrolling Interests were recorded during the six months ended June 30, 2016. The issuances decreased Spectra Energy’s ownership in SEP from 78% to 77% at June 30, 2016. In 2016, SEP has issued 7.8 million common units to the public and approximately 160,000 general partner units to Spectra Energy, for total net proceeds to SEP of $365 million (net proceeds to Spectra Energy were $358 million) through its at-the-market program.

Available Credit Facilities and Restrictive Debt Covenants. See Note 14 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. This ratio was 56% at June 30, 2016. 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, 2016, 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 2018. 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 $0.405 per common share on July 5, 2016 payable on September 7, 2016 to shareholders of record at the close of business on August 12, 2016.

Other Financing Matters. Spectra Energy Corp, Spectra Capital and SEP have effective shelf registration statements on file with the SEC to register the issuance of unlimited amounts of various equity and debt securities. SEP also has $620 million available as of June 30, 2016 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 1.2 billion Canadian dollars (approximately $929 million) available as of June 30, 2016 for the issuance of debt securities in the Canadian market under their medium term note shelf prospectuses.

On March 18, 2016, Westcoast filed a new 1 billion Canadian dollar short form base shelf prospectus, which provides for the issuance of first preferred shares. As of the date of this filing, Westcoast has 1 billion Canadian dollars (approximately $774 million) available for the issuance of preferred shares under this prospectus, which expires on April 18, 2018.

OTHER ISSUES

New Accounting Pronouncements. See Note 23 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, 2015. 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, 2016, 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, 2016 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 17 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, 2015 which could materially affect our financial condition or future results. There have been no material changes to those risk factors.

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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.

(a) Exhibits



Exhibit Number

*10.1		Change in Control Agreement (As Amended and Restated) for Chair, President and CEO.

*10.2		Form of Change in Control Agreement (As Amended and Restated) for other Named Executive Officers.

*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 3, 2016						/s/ Gregory L. Ebel
						Gregory L. Ebel
						President and Chief Executive Officer

Date: August 3, 2016						/s/ J. Patrick Reddy
						J. Patrick Reddy
						Chief Financial Officer