Edgar Filing: Spectra Energy Corp.

SE-2013.09.30 10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q



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

For the quarterly period ended September 30, 2013



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

For the transition period from to

Commission file number 1-33007

SPECTRA ENERGY CORP

(Exact Name of Registrant as Specified in its Charter)



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

5400 Westheimer Court

Houston, Texas 77056

(Address of principal executive offices, including zip code)

713-627-5400

(Registrant’s telephone number, including area code)

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

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

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

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

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

Number of shares of Common Stock, $0.001 par value, outstanding as of September 30, 2013: 670,039,114

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SPECTRA ENERGY CORP

FORM 10-Q FOR THE QUARTER ENDED

September 30, 2013

INDEX



		Page
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)	4
	Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2013 and 2012	4
	Condensed Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2013 and 2012	5
	Condensed Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012	6
	Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2013 and 2012	8
	Condensed Consolidated Statements of Equity for the nine months ended September 30, 2013 and 2012	9
	Notes to Condensed Consolidated Financial Statements	10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	50
Item 4.	Controls and Procedures	50

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	51
Item 1A.	Risk Factors	51
Item 6.	Exhibits	51
	Signatures	52

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


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


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


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


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


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


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


•	the development of alternative energy resources;


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


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


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


•	growth in opportunities, including the timing and success of efforts to develop U.S. and Canadian pipeline, storage, gathering, processing and other related infrastructure projects and the effects of competition;


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


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


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


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


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

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

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PART I. FINANCIAL INFORMATION



Item 1.	Financial Statements.

SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In millions, except per-share amounts)



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Operating Revenues
Transportation, storage and processing of natural gas	$	758	$	791	$	2,324	$	2,406
Distribution of natural gas	202		180		1,110		925
Sales of natural gas liquids	82		74		259		279
Transportation of crude oil	71		—		151		—
Other	31		27		109		118
Total operating revenues	1,144		1,072		3,953		3,728
Operating Expenses
Natural gas and petroleum products purchased	123		125		755		704
Operating, maintenance and other	403		348		1,145		1,003
Depreciation and amortization	195		188		577		557
Property and other taxes	90		83		283		252
Total operating expenses	811		744		2,760		2,516
Gains on Sales of Other Assets and Other, net	—		—		—		2
Operating Income	333		328		1,193		1,214
Other Income and Expenses
Equity in earnings of unconsolidated affiliates	163		88		345		297
Other income and expenses, net	48		19		103		53
Total other income and expenses	211		107		448		350
Interest Expense	167		159		476		471
Earnings From Continuing Operations Before Income Taxes	377		276		1,165		1,093
Income Tax Expense From Continuing Operations	85		72		277		289
Income From Continuing Operations	292		204		888		804
Income From Discontinued Operations, net of tax	—		—		—		2
Net Income	292		204		888		806
Net Income—Noncontrolling Interests	29		25		86		79
Net Income—Controlling Interests	$	263	$	179	$	802	$	727
Common Stock Data
Weighted-average shares outstanding
Basic	670		653		669		653
Diluted	672		655		671		655
Earnings per share from continuing operations
Basic and Diluted	$	0.39	$	0.27	$	1.20	$	1.11
Earnings per share
Basic and Diluted	$	0.39	$	0.27	$	1.20	$	1.11
Dividends per share	$	0.305	$	0.28	$	0.915	$	0.84

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 September 30,				Nine Months Ended September 30,
	2013		2012		2013			2012
Net Income	$	292	$	204	$	888		$	806
Other comprehensive income (loss)
Foreign currency translation adjustments	150		252		(290		)	281
Unrealized mark-to-market net gain on hedges	2		2		5			5
Reclassification of cash flow hedges into earnings	2		3		6			7
Pension and benefits impact (net of taxes of $4, $5, $13 and $5, respectively)	10		8		31			31
Other	1		—		1			—
Total other comprehensive income (loss)	165		265		(247		)	324
Total Comprehensive Income, net of tax	457		469		641			1,130
Less: Comprehensive Income—Noncontrolling Interests	30		29		82			83
Comprehensive Income—Controlling Interests	$	427	$	440	$	559		$	1,047

See Notes to Condensed Consolidated Financial Statements.

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SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)



	September 30, 2013		December 31, 2012
ASSETS

Current Assets
Cash and cash equivalents	$	160	$	94
Receivables, net	966		970
Inventory	429		309
Other	366		290
Total current assets	1,921		1,663

Investments and Other Assets
Investments in and loans to unconsolidated affiliates	3,026		2,692
Goodwill	4,869		4,513
Other	2,360		572
Total investments and other assets	10,255		7,777

Property, Plant and Equipment
Cost	28,399		26,257
Less accumulated depreciation and amortization	6,577		6,352
Net property, plant and equipment	21,822		19,905

Regulatory Assets and Deferred Debits	1,355		1,242

Total Assets	$	35,353	$	30,587

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)



	September 30, 2013		December 31, 2012
LIABILITIES AND EQUITY

Current Liabilities
Accounts payable	$	428	$	464
Commercial paper	2,049		1,259
Taxes accrued	58		67
Interest accrued	169		185
Current maturities of long-term debt	2,504		921
Other	951		895
Total current liabilities	6,159		3,791

Long-term Debt	12,268		10,653

Deferred Credits and Other Liabilities
Deferred income taxes	5,062		4,358
Regulatory and other	1,609		1,684
Total deferred credits and other liabilities	6,671		6,042

Commitments and Contingencies

Preferred Stock of Subsidiaries	258		258

Equity
Preferred stock, $0.001 par, 22 million shares authorized, no shares outstanding	—		—
Common stock, $0.001 par, 1 billion shares authorized, 670 million and 668 million shares outstanding at September 30, 2013 and December 31, 2012, respectively	1		1
Additional paid-in capital	5,314		5,297
Retained earnings	2,352		2,165
Accumulated other comprehensive income	1,266		1,509
Total controlling interests	8,933		8,972
Noncontrolling interests	1,064		871
Total equity	9,997		9,843

Total Liabilities and Equity	$	35,353	$	30,587

See Notes to Condensed Consolidated Financial Statements.

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SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)



	Nine Months Ended September 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	888		$	806
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	587			566
Deferred income tax expense	278			174
Equity in earnings of unconsolidated affiliates	(345		)	(297		)
Distributions received from unconsolidated affiliates	215			252
Other	(223		)	(47		)
Net cash provided by operating activities	1,400			1,454
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(1,476		)	(1,418		)
Investments in and loans to unconsolidated affiliates	(224		)	—
Acquisitions, net of cash acquired	(1,254		)	(30		)
Purchases of held-to-maturity securities	(632		)	(2,276		)
Proceeds from sales and maturities of held-to-maturity securities	623			2,173
Purchases of available-for-sale securities	(5,665		)	(15		)
Proceeds from sales and maturities of available-for-sale securities	3,810			21
Distributions received from unconsolidated affiliates	17			11
Other changes in restricted funds	(1		)	77
Other	2			7
Net cash used in investing activities	(4,800		)	(1,450		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	3,972			350
Payments for the redemption of long-term debt	(796		)	(28		)
Net increase in commercial paper	803			256
Distributions to noncontrolling interests	(104		)	(86		)
Dividends paid on common stock	(616		)	(555		)
Proceeds from the issuance of Spectra Energy Partners, LP common units	190			—
Other	18			28
Net cash provided by (used in) financing activities	3,467			(35		)
Effect of exchange rate changes on cash	(1		)	3
Net increase (decrease) in cash and cash equivalents	66			(28		)
Cash and cash equivalents at beginning of period	94			174
Cash and cash equivalents at end of period	$	160		$	146
Supplemental Disclosures
Property, plant and equipment non-cash accruals	$	107		$	192

See Notes to Condensed Consolidated Financial Statements.

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SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(Unaudited)

(In millions)



	Common Stock		Additional Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income
	Common Stock		Additional Paid-in Capital			Retained Earnings			Foreign Currency Translation Adjustments			Other			Noncontrolling Interests			Total
December 31, 2012	$	1	$	5,297		$	2,165		$	2,044		$	(535	)	$	871		$	9,843
Net income	—		—			802			—			—			86			888
Other comprehensive income (loss)	—		—			—			(286		)	43			(4		)	(247		)
Dividends on common stock	—		—			(615		)	—			—			—			(615		)
Stock-based compensation	—		13			—			—			—			—			13
Distributions to noncontrolling interests	—		—			—			—			—			(104		)	(104		)
Spectra Energy common stock issued	—		21			—			—			—			—			21
Spectra Energy Partners, LP common units issued	—		38			—			—			—			128			166
Transfer of interests in Express-Platte to Spectra Energy Partners, LP	—		(53		)	—			—			—			84			31
Other, net	—		(2		)	—			—			—			3			1
September 30, 2013	$	1	$	5,314		$	2,352		$	1,758		$	(492	)	$	1,064		$	9,997

December 31, 2011	$	1	$	4,814		$	1,977		$	1,832		$	(559	)	$	831		$	8,896
Net income	—		—			727			—			—			79			806
Other comprehensive income	—		—			—			277			43			4			324
Dividends on common stock	—		—			(552		)	—			—			—			(552		)
Stock-based compensation	—		17			—			—			—			—			17
Distributions to noncontrolling interests	—		—			—			—			—			(86		)	(86		)
Spectra Energy common stock issued	—		13			—			—			—			—			13
September 30, 2012	$	1	$	4,844		$	2,152		$	2,109		$	(516	)	$	828		$	9,418

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.

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, currently operating in three key areas of the natural gas industry: gathering and processing, transmission and storage, and distribution. We provide transportation and storage of natural gas to customers in various regions of the northeastern and southeastern United States, the Maritime Provinces in Canada and the Pacific Northwest in the United States and Canada, and in the province of Ontario, Canada. We also provide natural gas sales and distribution services to retail customers in Ontario, and natural gas gathering and processing services to customers in western Canada. We also own a 50% interest in DCP Midstream, LLC (DCP Midstream), based in Denver, Colorado, one of the leading natural gas gatherers in the United States based on wellhead volumes, and one of the largest U.S. producers and marketers of natural gas liquids (NGLs). In addition, with the first quarter 2013 acquisition of the Express-Platte pipeline system, we own and operate a crude oil pipeline system that connects Canadian and U.S. producers to refineries in the U.S. Rocky Mountain and Midwest regions.

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, 2012, and reflect all normal recurring adjustments that are, in our opinion, necessary to fairly present our results of operations and financial position. Amounts reported in the Condensed Consolidated Statements of Operations are not necessarily indicative of amounts expected for the respective annual periods due to the effects of seasonal temperature variations on energy consumption, primarily in our gas distribution operations, as well as changing commodity prices on certain of our processing operations and other factors.

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

2. Acquisition of Express-Platte

On March 14, 2013, we acquired 100% of the ownership interests in the Express-Platte pipeline system from Borealis Infrastructure, the Ontario Teachers’ Pension Plan and Kinder Morgan Energy Partners for $1.49 billion, consisting of $1.25 billion in cash and $242 million of acquired debt, before working capital adjustments. The Express-Platte pipeline system, which begins in Hardisty, Alberta, and terminates in Wood River, Illinois, is comprised of both the Express and Platte crude oil pipelines. The Express pipeline carries crude oil to U.S. refining markets in the Rockies area, including Montana, Wyoming, Colorado and Utah. The Platte pipeline, which interconnects with Express pipeline in Casper, transports crude oil predominantly from the Bakken shale and western Canada to refineries in the Midwest. These assets are a part of our new reportable business segment, “Liquids,” which also includes our direct one-third ownership interests in DCP Sand Hills Pipeline, LLC (Sand Hills) and DCP Southern Hills Pipeline, LLC (Southern Hills).

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The following table summarizes the preliminary fair values of the assets and liabilities acquired as of March 14, 2013. Subsequent adjustments may be recorded upon the completion of the valuation and the final determination of the purchase price allocation.



	Purchase Price Allocation
	(in millions)
Cash purchase price	$	1,250
Working capital and other purchase adjustments	71
Total	1,321
Cash	67
Receivables	21
Other current assets	10
Property, plant and equipment	1,352
Accounts payable	(20		)
Other current liabilities	(19		)
Deferred credits and other liabilities	(326		)
Long-term debt, including current portion	(242		)
Total assets acquired/liabilities assumed	843
Goodwill	$	478

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

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

As of September 30, 2013, Express-Platte debt, including current maturities, totaled $228 million, consisting of $118 million of 7.39% subordinated notes due 2019 and $110 million of 6.09% senior notes due 2020. The notes are secured by the assignment of the Express-Platte transportation receivables and by the Canadian portion of the Express-Platte pipeline system assets.

On November 1, 2013, we completed the first of three closings related to the contribution by Spectra Energy to Spectra Energy Partners of substantially all of Spectra Energy's remaining interests in its other subsidiaries that own U.S. transmission and storage and liquids assets, including Spectra Energy's remaining 60% interest in the U.S. portion of Express-Platte. See Note 3 for further discussion.

3. Spectra Energy Partners, LP

On August 2, 2013, subsidiaries of Spectra Energy contributed a 40% interest in the U.S. portion of Express-Platte and sold a 100% ownership interest in the Canadian portion to Spectra Energy Partners. Aggregate consideration for the transactions consisted of approximately $410 million in cash and 7.2 million of newly issued Spectra Energy Partners partnership units (valued at approximately $319 million). This transfer of assets between entities resulted in a decrease to Spectra Energy’s Additional Paid-in Capital of $84 million ($53 million net of tax) and an increase to Equity-Noncontrolling Interests of $84 million on the Consolidated Balance Sheet. The change in Equity-Noncontrolling Interests primarily represents the public unitholders’ share of the increase in Spectra Energy Partners equity as a result of the issuance of additional units to Spectra Energy, less the effects of the resulting decrease in the public unitholders’ ownership percentage. Spectra Energy's ownership in Spectra Energy Partners increased to 61% as a result of the transaction.

On August 5, 2013, Spectra Energy entered into a definitive agreement with Spectra Energy Partners under which Spectra Energy will contribute to Spectra Energy Partners substantially all of Spectra Energy's remaining interests in its other

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subsidiaries that own U.S. transmission and storage and liquids assets, including Spectra Energy's remaining 60% interest in the U.S. portion of Express-Platte (The Dropdown Transactions). Spectra Energy's interest in DCP Midstream is not part of the transaction. The contributed entities had approximately $2.4 billion of third-party debt at the date of contribution. Aggregate consideration for the Dropdown Transactions, when completed, will be approximately 175.5 million in newly issued Spectra Energy Partners partnership units and approximately $2.3 billion in cash. On November 1, 2013, we completed the closing of substantially all of the Dropdown Transactions. Spectra Energy Partners paid to Spectra Energy aggregate consideration of approximately $2.3 billion in cash and the issuance of approximately 171.1 million newly issued partnership units. The first of the remaining two closings of the Dropdown Transactions is expected to occur at least 12 months following the November 1, 2013 closing, with the final closing expected to occur at least 12 months thereafter.

In April 2013, Spectra Energy Partners issued 5.2 million common units to the public, representing limited partner interests, and 0.1 million general partner units to Spectra Energy. Total net proceeds to Spectra Energy Partners were $193 million (net proceeds to Spectra Energy were $190 million) and were restricted for the purposes of funding Spectra Energy Partners’ capital expenditures and acquisitions, which includes the U.S. assets dropdown. The sale of the units decreased Spectra Energy's ownership in Spectra Energy Partners from 61% to 58%. In connection with the sale of the units, a $61 million gain ($38 million net of tax) to Additional Paid-in Capital and a $128 million increase in Equity-Noncontrolling Interests were recorded in the second quarter of 2013.

4. Business Segments

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

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

U.S. Transmission provides transportation and storage of natural gas for customers in various regions of the northeastern and southeastern United States and the Maritime Provinces in Canada. The natural gas transmission and storage operations in the U.S. are primarily subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC). Spectra Energy Partners, a master limited partnership owned 61% by Spectra Energy as of September 30, 2013, is part of the U.S. Transmission segment.

Distribution provides retail natural gas distribution service in Ontario, Canada, as well as natural gas transportation 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 transportation of natural gas, natural gas gathering and processing services, and NGLs extraction, fractionation, transportation, storage and marketing to customers in western Canada and the northern tier of the United States. This segment conducts business mostly through BC Pipeline, BC Field Services, and the NGL marketing and Canadian Midstream businesses. BC Pipeline and BC Field Services operations are primarily subject to the rules and regulations of Canada’s National Energy Board (NEB).

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Field Services gathers, compresses, treats, processes, transports, stores and sells natural gas. In addition, this segment also produces, fractionates, transports, stores, sells, markets and trades NGLs and condensate. It conducts operations through DCP Midstream, which is owned 50% by us and 50% by Phillips 66. DCP Midstream gathers raw natural gas through gathering systems located in nine major conventional and non-conventional natural gas producing regions: Mid-Continent, Rocky Mountain, East Texas-North Louisiana, Barnett Shale, Gulf Coast, South Texas, Central Texas, Antrim Shale and Permian Basin. DCP Midstream has a 23% ownership interest in DCP Midstream Partners, LP (DCP Partners), a master limited partnership.

Liquids, a newly formed segment effective with the March 2013 acquisition of Express-Platte, provides transportation of crude oil and NGLs. The Express pipeline carries crude oil from Alberta, Canada to refining markets in the Rockies area. The Platte pipeline, which interconnects with Express pipeline in Casper, Wyoming, transports crude oil predominantly from the Bakken shale and western Canada to refineries in the Midwest. These operations are primarily subject to the rules and regulations of the FERC and NEB. The Sand Hills and Southern Hills pipelines, which were placed in service in the second quarter of 2013, provide transportation of NGLs from the Permian Basin and Eagle Ford region to the premium NGL markets on the Gulf Coast, and from the Mid-Continent to Mont Belvieu, Texas, respectively. We have direct one-third ownership interests in Sand Hills and Southern Hills. DCP Midstream and Phillips 66 also each own direct one-third ownership interests in the two pipelines. Sand Hills and Southern Hills are subject to the rules and regulations of the FERC.

Our reportable segments offer different products and services and are managed separately as business units. Management evaluates segment performance based on earnings before interest and taxes (EBIT), which represents earnings from continuing operations (both operating and non-operating) before interest and taxes, net of noncontrolling interests related to those earnings. Cash, cash equivalents and short-term investments are managed centrally, so the associated realized and unrealized gains and losses from foreign currency transactions and interest and dividend income on those balances are excluded from the segments’ EBIT. 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 (a)			Segment EBIT/ Consolidated Earnings from Continuing Operations before Income Taxes (a)
			(in millions)
Three Months Ended September 30, 2013
U.S. Transmission	$	451	$	3		$	454		$	246
Distribution	264		—			264			34
Western Canada Transmission & Processing	352		15			367			90
Field Services	—		—			—			137
Liquids	76		—			76			33
Total reportable segments	1,143		18			1,161			540
Other	1		14			15			(33		)
Eliminations	—		(32		)	(32		)	—
Interest expense	—		—			—			167
Interest income and other (b)	—		—			—			37
Total consolidated	$	1,144	$	—		$	1,144		$	377

Three Months Ended September 30, 2012
U.S. Transmission	$	458	$	2		$	460		$	238
Distribution	269		—			269			55
Western Canada Transmission & Processing	343		5			348			83
Field Services	—		—			—			62
Liquids	—		—			—			—
Total reportable segments	1,070		7			1,077			438
Other	2		17			19			(29		)
Eliminations	—		(24		)	(24		)	—
Interest expense	—		—			—			159
Interest income and other (b)	—		—			—			26
Total consolidated	$	1,072	$	—		$	1,072		$	276

Nine Months Ended September 30, 2013
U.S. Transmission	$	1,386	$	8		$	1,394		$	760
Distribution	1,315		—			1,315			267
Western Canada Transmission & Processing	1,084		48			1,132			275
Field Services	—		—			—			271
Liquids	162		—			162			71
Total reportable segments	3,947		56			4,003			1,644
Other	6		38			44			(104		)
Eliminations	—		(94		)	(94		)	—
Interest expense	—		—			—			476
Interest income and other (b)	—		—			—			101
Total consolidated	$	3,953	$	—		$	3,953		$	1,165
Nine Months Ended September 30, 2012
U.S. Transmission	$	1,413	$	6		$	1,419		$	746
Distribution	1,188		—			1,188			281
Western Canada Transmission & Processing	1,121		22			1,143			315
Field Services	—		—			—			221
Liquids	—		—			—			—
Total reportable segments	3,722		28			3,750			1,563
Other	6		53			59			(83		)
Eliminations	—		(81		)	(81		)	—
Interest expense	—		—			—			471
Interest income and other (b)	—		—			—			84
Total consolidated	$	3,728	$	—		$	3,728		$	1,093


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


(b)	Includes foreign currency transaction gains and losses and the add-back of noncontrolling interests related to segment EBIT.

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Condensed Consolidated Balance Sheets



	September 30, 2013			December 31, 2012
	(in millions)
Segment Assets
U.S. Transmission	$	15,179		$	12,630
Distribution	5,810			5,842
Western Canada Transmission & Processing	6,578			6,431
Field Services	1,380			1,235
Liquids (a)	2,654			513
Total reportable segments	31,601			26,651
Other (a)	4,387			4,475
Eliminations	(635		)	(539		)
Total consolidated	$	35,353		$	30,587


(a)	The December 31, 2012 amounts presented for Liquids and Other have been re-cast to reflect the move of our investments in Sand Hills and Southern Hills, totaling $513 million, from Other to Liquids effective with the creation of the Liquids operating segment in the first quarter of 2013.

5. Regulatory Matters

Union Gas. Union Gas’ distribution rates, effective January 1, 2013, were approved by the OEB following a cost of service application since 2012 was the final year of a multi-year incentive regulation framework that began January 1, 2008.

In October 2013, the OEB approved a new five-year incentive regulation framework for Union Gas, which Union Gas will use to determine the rates they will charge customers for natural gas delivery services beginning January 1, 2014. The parameters of the new framework were determined through a settlement process and negotiated agreement with the key stakeholders who regularly participate in Union Gas’ rates applications and who represent the interests of its customers. The new incentive regulation framework establishes new rates at the beginning of each year through the use of a pricing formula rather than through the examination of revenue and cost forecasts. The framework allows for annual inflationary rate increases, offset by a productivity factor of 60% of inflation, such that the annual net rate escalator in each year is 40% of inflation. The framework also allows for rate increases in the small volume customer classes where average use is declining, a five-year term commencing in 2014, certain adjustments to base rates, the continued pass-through of gas commodity costs, upstream transportation and demand side management costs, the additional pass-through of costs associated with major capital investments and certain fuel variances, an allowance for unexpected cost changes that are outside of management’s control, earnings sharing between Union Gas and its customers beyond specified earnings levels, and equal sharing of tax changes between Union Gas and its customers.

In December 2012, Union Gas appealed the OEB’s decision on the disposition of the 2011 non-commodity deferral account balances to the Ontario Divisional Court (the Court). The basis of the appeal is impermissible retroactive ratemaking. A hearing was held in October 2013 and a decision from the Court is pending.

In May 2013, Union Gas filed an application with the OEB for the annual disposition of the 2012 non-commodity deferral account balances. The application included a proposal that revenues derived from the optimization of upstream transportation contracts in 2012 be treated as optimization revenues and included in utility earnings rather than as a reduction to gas costs. Optimization revenues had been classified as utility earnings for 2008, 2009 and 2010, and were reclassified as a reduction to gas costs by the OEB in the 2011 non-commodity deferral account balances proceeding. The net impact on customers for the 2012 non-commodity deferral account balances, including the impact of earnings sharing, would be a receivable of less than $1 million. If the OEB finds that the 2012 revenues earned from the optimization of Union Gas’ upstream transportation contracts should be treated as a reduction to gas costs, 90% of which are to be credited to customers, the combined impact on customers would be a net refund payable of $17 million, comprised of $39 million in Other Current Liabilities and $22 million in Other Current Assets, which is reflected on the Condensed Consolidated Balance Sheets at September 30, 2013 and December 31, 2012. A hearing on this matter was held in October 2013 and a decision from the OEB is pending.

Express-Platte. Express Pipeline Limited Partnership’s (Express LP’s) proposal for increases in uncommitted rates filed with the NEB became effective on April 1, 2013. Express Pipeline LLC’s (Express LLC’s) and Platte Pipe Line Company,

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LLC’s (Platte LLC’s) proposals for increases in uncommitted rates filed with the FERC became effective on July 1, 2013. Express LP’s, Express LLC’s and Platte LLC’s proposals for increases in joint committed rates filed with the NEB and FERC also became effective on April 1, 2013. Express LP, Express LLC and Platte LLC filed new joint committed rates with the NEB and FERC with an effective date of October 1, 2013.

Saltville. Saltville Gas Storage Company L.L.C. (Saltville) received FERC approval on September 26, 2013 to amend its current rate settlement and extend the deadline to file a Section 4 rate case from October 1, 2013 to February 1, 2014. The extension allows Saltville and its customers to continue discussions towards a new settlement agreement in lieu of the required Section 4 rate case filing.

6. Income Taxes

Income tax expense from continuing operations for the three months ended September 30, 2013 was $85 million, compared to $72 million for the same period in 2012. Income tax expense from continuing operations for the nine months ended September 30, 2013 was $277 million, compared to $289 million for the same period in 2012. The higher income tax expense for the three months ended September 30, 2013 resulted from higher earnings partially offset by changes in Canadian provincial tax rates and the recognition of certain regulatory tax benefits. The lower income tax expense for the nine months ended September 30, 2013 resulted mainly from favorable enacted Canadian federal income tax legislation, changes in Canadian provincial tax rates and the recognition of certain regulatory tax benefits, partially offset by higher earnings.

The effective tax rates for income from continuing operations for the three months ended September 30, 2013 and 2012 were 23% and 26%, respectively, and 24% and 26% for the nine-month periods, respectively. The lower effective tax rates in the 2013 periods resulted primarily from favorable enacted Canadian federal income tax legislation and the recognition of certain regulatory tax benefits.

We recorded a $4 million increase in unrecognized tax benefits during the nine-month period ended September 30, 2013 due to audit settlements partially offset by enacted Canadian federal income tax legislation. Although uncertain, we believe it is reasonably possible that the total amount of unrecognized tax benefits could decrease by approximately $29 million prior to September 30, 2014 as a result of the expiration of statutes of limitation.

On September 13, 2013, the Internal Revenue Service released final tangible property regulations governing repairs and capitalization, effective for taxable years beginning on or after January 1, 2014. We anticipate the release of additional regulations and industry specific guidance in the fourth quarter of 2013. We are currently evaluating what impacts the final regulations may have on us.

7. Discontinued Operations

Discontinued operations in 2012 was mostly comprised of the net effects of a settlement arrangement related to prior liquefied natural gas (LNG) contracts. Purchases and sales of propane under these agreements ended during the second quarter of 2012. See Note 11 for further discussion.

The following table summarizes results classified as Income from Discontinued Operations, Net of Tax in the accompanying Condensed Consolidated Statements of Operations:



	Revenues		Pre-tax Earnings		Income Tax Expense		Income From Discontinued Operations, Net of Tax
	(in millions)

Nine Months Ended September 30, 2012
Other	$	99	$	3	$	1	$	2
Total consolidated	$	99	$	3	$	1	$	2

8. 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

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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 September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(in millions, except per-share amounts)

Income from continuing operations, net of tax—controlling interests	$	263	$	179	$	802	$	725
Income from discontinued operations, net of tax—controlling interests	—		—		—		2
Net income—controlling interests	$	263	$	179	$	802	$	727
Weighted-average common shares outstanding
Basic	670		653		669		653
Diluted	672		655		671		655
Basic and diluted earnings per common share (a)	$	0.39	$	0.27	$	1.20	$	1.11

__________


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

9. Accumulated Other Comprehensive Income

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



	Foreign Currency Translation Adjustments			Pension and Post-retirement Benefit Plan Obligations				Gas Purchase Contract Hedges			Other			Total Accumulated Other Comprehensive Income
							(in millions)
June 30, 2013	$	1,609		$	(486	)		$	(17	)	$	(4	)	$	1,102
Reclassified to Net Income	—			—				2			—			2
Other AOCI activity	149			10				1			2			162
September 30, 2013	$	1,758		$	(476	)		$	(14	)	$	(2	)	$	1,266

December 31, 2012	$	2,044		$	(507	)		$	(23	)	$	(5	)	$	1,509
Reclassified to Net Income	—			—				5			1			6
Other AOCI activity	(286		)	31				4			2			(249		)
September 30, 2013	$	1,758		$	(476	)		$	(14	)	$	(2	)	$	1,266

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

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10. Inventory

Inventory consists of natural gas and NGLs held in storage for transmission and processing, and also includes materials and supplies. Natural gas inventories primarily relate to the Distribution segment in Canada and are valued at costs approved by the OEB. The difference between the approved price and the actual cost of gas purchased is recorded in either accounts receivable or other current liabilities, 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:



	September 30, 2013		December 31, 2012
	(in millions)
Natural gas	$	285	$	200
NGLs	64		31
Materials and supplies	80		78
Total inventory	$	429	$	309

11. 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 September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(in millions)
Operating revenues	$	3,068	$	2,355	$	8,541	$	7,476
Operating expenses	2,823		2,233		7,944		6,925
Operating income	245		122		597		551
Net income	177		89		439		429
Net income attributable to members’ interests	191		95		360		371

DCP Midstream recorded gains on sales of common units of DCP Partners in 2013 and 2012 directly to DCP Midstream’s equity. Our proportionate 50% share, totaling $41 million and $14 million in the third quarters of 2013 and 2012, respectively, and $91 million and $36 million during the nine-month periods ended September 30, 2013 and 2012, respectively, was recorded in Equity in Earnings of Unconsolidated Affiliates in the Condensed Consolidated Statements of Operations.

Related Party Transactions. In 2008, we entered into a settlement agreement related to certain LNG transportation contracts under which one of our subsidiaries’ claims were satisfied pursuant to commercial transactions involving the purchase of propane from certain parties. We subsequently entered into associated agreements with affiliates of DCP Midstream for the sale of these propane volumes. Net purchases and sales of propane under these arrangements are reflected as discontinued operations. Purchases of propane under the settlement agreement, and subsequent sales to affiliates of DCP Midstream, ended during the second quarter of 2012. Sales of propane to affiliates of DCP Midstream was $99 million for the nine months ended September 30, 2012.

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, 2013 and no impairments were identified.

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

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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.

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.

Our Empress NGL business, a reporting unit within Western Canada Transmission & Processing, is significantly affected by fluctuations in commodity prices. We updated our Empress NGL reporting unit’s impairment test using recent operational information, financial data and June 30, 2013 commodity prices, and concluded there was no impairment of goodwill related to Empress. The operating results of our Empress NGL reporting unit improved during the third quarter of 2013 due to, among other things, improved commodity prices. Therefore, no additional impairment test was deemed necessary.

The following presents changes in goodwill during 2013:



	Goodwill
	(in millions)
December 31, 2012	$	4,513
Acquisition of Express-Platte	478
Foreign currency translation	(122		)
September 30, 2013	$	4,869

See Note 2 for discussion of the acquisition of Express-Platte.

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, treasury bills and money market funds in the United States and Canada. We do not purchase marketable securities for speculative purposes, therefore we do not have any securities classified as trading securities. While we do not routinely sell marketable securities prior to their scheduled maturity dates, some of our investments are held and restricted for the purposes of funding Spectra Energy Partners’ future capital expenditures and acquisitions, and for insurance, 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
	September 30, 2013		December 31, 2012
	(in millions)
Corporate debt securities	$	136	$	164
Money market funds	1,884		1
Total available-for-sale securities	$	2,020	$	165

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Most of our AFS securities are restricted funds and are as follows:



	Estimated Fair Value
	September 30, 2013		December 31, 2012
	(in millions)
Restricted funds
Investments and other assets—other	$	2,004	$	142
Non-restricted funds
Current assets—other	14		16
Investments and other assets—other	2		7
Total available-for-sale securities	$	2,020	$	165

During the second quarter of 2013, we invested the proceeds from Spectra Energy Partners’ issuance of common units in AFS marketable securities. These securities are restricted for the purpose of funding future Spectra Energy Partners’ capital expenditures and acquisitions.

In September 2013, we invested the net proceeds from Spectra Energy Partners’ $1.9 billion issuance of long-term debt in AFS marketable securities. These securities are restricted for the purpose of paying a portion of the cash consideration for Spectra Energy Corp’s U.S. assets dropdown to Spectra Energy Partners.

At September 30, 2013, 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 September 30, 2013 or December 31, 2012.

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



		Estimated Fair Value
Description	Condensed Consolidated Balance Sheet Caption	September 30, 2013		December 31, 2012
		(in millions)
Bankers acceptances	Current assets—other	$	61	$	37
Canadian government securities	Current assets—other	37		39
Money market funds	Current assets—other	10		—
Canadian government securities	Investments and other assets—other	161		171
Bankers acceptances	Investments and other assets—other	—		15
Total held-to-maturity securities		$	269	$	262

All of our HTM securities are restricted funds pursuant to certain Maritimes & Northeast Pipeline Limited Partnership (M&N LP) and Express-Platte debt agreements. The funds restricted for M&N LP, plus future cash from operations that would have otherwise been available for distribution to the partners of M&N LP, were required to be placed in escrow until the balance in escrow was sufficient to fund all future debt service on the M&N LP notes. There were sufficient funds held in escrow to fund all future debt service on the M&N LP notes as of September 30, 2013.

At September 30, 2013, 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 September 30, 2013 or December 31, 2012.

Other Restricted Funds. In addition to the portions of the AFS and HTM securities that were restricted funds as described above, we had other restricted funds totaling $14 million at September 30, 2013 and $21 million at December 31, 2012 classified as Current Assets—Other. These restricted funds are related to additional amounts for insurance.

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

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14. Debt and Credit Facilities

Available Credit Facilities and Restrictive Debt Covenants



	Expiration Date	Total Credit Facilities Capacity		Outstanding at September 30, 2013						Available Credit Facilities Capacity
	Expiration Date	Total Credit Facilities Capacity		Commercial Paper		Letters of Credit		Total		Available Credit Facilities Capacity
		(in millions)
Spectra Energy Capital, LLC
Multi-year syndicated (a)	2016	$	1,500	$	1,227	$	—	$	1,227	$	273
Westcoast Energy Inc.
Multi-year syndicated (b)	2016	291		158		—		158		133
Union Gas
Multi-year syndicated (c)	2016	388		119		—		119		269
Spectra Energy Partners
Multi-year syndicated (d)	2016	700		545		—		545		155
Total		$	2,879	$	2,049	$	—	$	2,049	$	830

___________


(a)	Credit facility contains a covenant requiring the Spectra Energy Corp consolidated debt-to-total capitalization ratio, as defined in the agreement, to not exceed 65%. This ratio was 62% at September 30, 2013.


(b)	U.S. dollar equivalent at September 30, 2013. The credit facility is 300 million Canadian dollars and contains a covenant that requires the Westcoast Energy Inc. non-consolidated debt-to-total capitalization ratio to not exceed 75%. The ratio was 46% at September 30, 2013.


(c)	U.S. dollar equivalent at September 30, 2013. The credit facility is 400 million Canadian dollars and contains a covenant that requires the Union Gas debt-to-total capitalization ratio to not exceed 75% and a provision which requires Union Gas to repay all borrowings under the facility for a period of two days during the second quarter of each year. The ratio was 67% at September 30, 2013.

(d)

Credit facility contains a covenant that requires Spectra Energy Partners to maintain a ratio of total Debt-to-Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA), as defined in the credit agreement, of 5.0 or less, provided that for three fiscal quarters subsequent to certain acquisitions (such as the November 1, 2013 U.S. assets drop down from Spectra Energy Corp), the ratio may be 5.5 or less. As of September 30, 2013, this ratio was 4.3 after giving effect to the impact of the dropdown. Adjusted EBITDA is a non-GAAP measure. Because Adjusted EBITDA excludes some, but not all, items that affect net income and is defined differently by companies in our industry, Spectra Energy Partners’ definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies. Adjusted EBITDA should not be considered an alternative to net income, operating income, cash from operations or any other measure of financial performance or liquidity presented in accordance with GAAP.

On November 1, 2013, we amended and restated Spectra Energy Capital, LLC (Spectra Capital) and Spectra Energy Partners credit agreements. The Spectra Capital credit facility was decreased to $1.0 billion, and the Spectra Energy Partners credit facility was increased to $2.0 billion. Both facilities expire in 2018.

The issuances of commercial paper, letters of credit and revolving borrowings reduce the amounts available 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 September 30, 2013, 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.

The terms of the amended and restated Spectra Capital credit agreement requires our consolidated debt-to-total capitalization ratio, as defined in the agreement, to be 65% or lower. Per the terms of the agreement, collateralized debt is excluded in the calculation of the ratio. This ratio was 62% at September 30, 2013.

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Delayed-draw Term Loan. In December 2012, Spectra Capital entered into a three-year $1.2 billion unsecured delayed-draw term loan agreement which allowed for up to four borrowings prior to March 1, 2013. The full $1.2 billion available under the agreement was borrowed in the first quarter of 2013. These borrowings are classified as Current Maturities of Long-term Debt on our Condensed Consolidated Balance Sheets as of September 30, 2013 and as Long-term Debt as of December 31, 2012. Proceeds from borrowings under the term loan were used for general corporate purposes, including acquisitions and to refinance existing indebtedness. Borrowings under this term loan agreement were repaid on November 1, 2013 with proceeds received from Spectra Energy Partners from the U.S. assets dropdown, and the loan agreement was terminated.

On November 1, 2013, Spectra Capital entered into a five-year $300 million senior unsecured delayed-draw five-year term loan agreement which allows for up to one borrowing prior to December 31, 2013. There were no borrowings under this agreement as of November 7, 2013.

Debt Issuances

On September 25, 2013, Spectra Energy Partners issued $1,900 million aggregate principal amount of senior unsecured notes, comprised of $500 million of 2.95% senior notes due in 2018, $1,000 million of 4.75% senior notes due in 2024 and $400 million of 5.95% senior notes due in 2043. Net proceeds from the offering were used to pay a portion of the cash consideration for Spectra Energy Corp’s U.S. assets dropdown to Spectra Energy Partners on November 1, 2013.

On July 2, 2013, Union Gas issued 250 million Canadian dollars (approximately $237 million as of the issuance date) of 3.79% unsecured notes due in 2023. Net proceeds from the offering were used for general corporate purposes.

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	September 30, 2013
Description	Condensed Consolidated Balance Sheet Caption	Total		Level 1		Level 2		Level 3
		(in millions)
Corporate debt securities	Cash and cash equivalents	$	79	$	—	$	79	$	—
Corporate debt securities	Current assets—other	14		—		14		—
Derivative assets—interest rate swaps	Current assets—other	9		—		9		—
Corporate debt securities	Investments and other assets—other	122		—		122		—
Derivative assets—interest rate swaps	Investments and other assets—other	18		—		18		—
Money market funds	Investments and other assets—other	1,884		1,884		—		—
Total Assets		$	2,126	$	1,884	$	242	$	—
Derivative liabilities—natural gas purchase contracts	Deferred credits and other liabilities—regulatory and other	$	5	$	—	$	—	$	5
Derivative liabilities—interest rate swaps	Deferred credits and other liabilities—regulatory and other	6		—		6		—
Total Liabilities		$	11	$	—	$	6	$	5



Description	Condensed Consolidated Balance Sheet Caption	December 31, 2012
Description	Condensed Consolidated Balance Sheet Caption	Total		Level 1		Level 2		Level 3
		(in millions)
Corporate debt securities	Cash and cash equivalents	$	52	$	—	$	52	$	—
Corporate debt securities	Current assets—other	16		—		16		—
Derivative assets—interest rate swaps	Current assets—other	13		—		13		—
Corporate debt securities	Investments and other assets—other	148		—		148		—
Derivative assets—interest rate swaps	Investments and other assets—other	48		—		48		—
Money market funds	Investments and other assets—other	1		1		—		—
Total Assets		$	278	$	1	$	277	$	—
Derivative liabilities—natural gas purchase contracts	Deferred credits and other liabilities—regulatory and other	$	9	$	—	$	—	$	9
Derivative liabilities—interest rate swaps	Deferred credits and other liabilities—regulatory and other	12		—		12		—
Total Liabilities		$	21	$	—	$	12	$	9

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in millions)
Long-term derivative liabilities
Fair value, beginning of period	$	6		$	10		$	9		$	14
Total realized/unrealized losses (gains):
Included in earnings	1			1			2			1
Included in other comprehensive income	(2		)	(3		)	(6		)	(6		)
Settlements	—			—			—			(1		)
Fair value, end of period	$	5		$	8		$	5		$	8
Total losses for the period included in earnings (or changes in net assets) attributable to the change in unrealized gains or losses relating to liabilities held at the end of the period	$	1		$	1		$	2		$	1

Level 1

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

Level 2 Valuation Techniques

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

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

Level 3 Valuation Techniques

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

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.



	September 30, 2013				December 31, 2012
	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)	14,764		15,857		11,518		13,539

___________________________________


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


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

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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.

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

During the 2013 and 2012 periods, 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, and the ownership of the NGL marketing operations in western Canada and the processing plants 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, primarily around interest rate exposures.

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

At September 30, 2013, we had “pay floating—receive fixed” interest rate swaps outstanding with a total notional principal amount of $1,343 million to hedge against changes in the fair value of our fixed-rate debt that arise as a result of changes in market interest rates. These swaps also allow us to transform a portion of the underlying interest payments related to our long-term fixed-rate debt securities into variable-rate interest payments in order to achieve our desired mix of fixed and variable-rate debt.

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



	Gross Amounts Presented in the Condensed Consolidated Balance Sheets		Amounts Not Offset in the Condensed Consolidated Balance Sheets		Net Amount		Gross Amounts Presented in the Condensed Consolidated Balance Sheets		Amounts Not Offset in the Condensed Consolidated Balance Sheets		Net Amount
Description	September 30, 2013						December 31, 2012
	(in millions)
Assets	$	27	$	3	$	24	$	61	$	7	$	54
Liabilities	6		3		3		12		7		5

As of September 30, 2013, we had an interest rate swap with a counterparty which was in a net liability position of $3 million which could be terminated at any time. In addition, we had an interest rate swap with another counterparty which was in a net liability position of $3 million which could be terminated by the counterparty if any of our credit ratings falls below investment grade.

Other than interest rate swaps described above, we did not have any significant derivatives outstanding during the nine months ended September 30, 2013.

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, hazardous and solid waste disposal and other environmental matters. These laws and regulations can change from time to time, imposing new obligations on us.

Like others in the energy industry, we and our affiliates are responsible for environmental remediation at various contaminated sites. These include some properties that are part of our ongoing operations, sites formerly owned or used by us, and sites owned by third parties. Remediation typically involves management of contaminated soils and may involve groundwater remediation. Managed in conjunction with relevant federal, state/provincial and local agencies, activities vary with site conditions and locations, remedial requirements, complexity and sharing of responsibility. If remediation activities

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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 insurance policies or 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.

Included in Deferred Credits and Other Liabilities—Regulatory and Other on the Condensed Consolidated Balance Sheets are undiscounted liabilities related to extended environmental-related activities totaling $11 million as of September 30, 2013 and $13 million as of December 31, 2012. These liabilities represent provisions for costs associated with remediation activities at some of our current and former sites, as well as other environmental contingent liabilities.

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 recorded as of September 30, 2013 or December 31, 2012 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 Corporation (Duke Energy) in 2007, certain guarantees that were previously issued by us were assigned to, or replaced by, Duke Energy as guarantor in 2006. For any remaining guarantees of other Duke Energy obligations, Duke Energy has indemnified us against any losses incurred under these guarantee arrangements. The maximum potential amount of future payments we could have been required to make under these performance guarantees as of September 30, 2013 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 Energy Inc. (Westcoast), a 100%-owned subsidiary, has issued performance guarantees to third parties guaranteeing the performance of unconsolidated entities, such as equity method investments, and of entities previously sold by Westcoast to third parties. Those guarantees require Westcoast to make payment to the guaranteed third party upon the failure of such unconsolidated or sold entity to make payment under some of its contractual obligations, such as debt agreements, purchase contracts and leases. Certain guarantees that were previously issued by Westcoast for obligations of entities that remained a part of Duke Energy are considered guarantees of third party performance; however, Duke Energy has indemnified us against any losses incurred under these guarantee arrangements.

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

As of September 30, 2013, the amounts recorded for the guarantees and indemnifications described above are not material, both individually and in the aggregate.

19. Effects of Changes in Noncontrolling Interests Ownership

The following table presents the effects of changes in our ownership interests in non-100%-owned consolidated subsidiaries:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(in millions)
Net Income - Controlling Interests	$	263	$	179	$	802	$	727
Increase in Additional Paid-in Capital resulting from sale of units of Spectra Energy Partners (a)	—		—		38		—
Total Net Income - Controlling Interests and changes in Equity - Controlling Interests	$	263	$	179	$	840	$	727

______________

(a) See Note 3 for further discussion.

20. Employee Benefit Plans

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

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 $21 million to our U.S. retirement plans in both of the nine-month periods ended September 30, 2013 and 2012. We made total contributions to the Canadian DC and qualified DB plans of $62 million in the nine months ended September 30, 2013 and $52 million in the same period in 2012. We anticipate that we will make total contributions of approximately $22 million to the U.S. plans and approximately $87 million to the Canadian plans in 2013.

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in millions)
U.S.
Service cost benefit earned	$	5		$	4		$	14		$	11
Interest cost on projected benefit obligation	5			5			16			17
Expected return on plan assets	(9		)	(8		)	(25		)	(23		)
Amortization of loss	5			4			15			11
Net periodic pension cost	$	6		$	5		$	20		$	16

Canada
Service cost benefit earned	$	9		$	7		$	25		$	20
Interest cost on projected benefit obligation	13			13			38			38
Expected return on plan assets	(17		)	(15		)	(50		)	(44		)
Amortization of loss	9			10			27			28
Amortization of prior service costs	—			—			1			1
Net periodic pension cost	$	14		$	15		$	41		$	43

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 September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in millions)
U.S.
Service cost benefit earned	$	1		$	1		$	1		$	1
Interest cost on accumulated post-retirement benefit obligation	2			2			6			6
Expected return on plan assets	(1		)	(1		)	(3		)	(3		)
Amortization of loss	—			—			1			1
Net periodic other post-retirement benefit cost	$	2		$	2		$	5		$	5

Canada
Service cost benefit earned	$	1		$	2		$	3		$	6
Interest cost on accumulated post-retirement benefit obligation	2			2			5			5
Amortization of loss	—			—			—			1
Amortization of prior service credit	—			(1		)	—			(1		)
Net periodic other post-retirement benefit cost	$	3		$	3		$	8		$	11

Retirement/Savings Plan

We have 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 $3 million and $2 million in the three-month periods ended September 30, 2013 and 2012, respectively, and $10 million and $9 million in the nine-month periods ended September 30, 2013 and 2012, respectively, for U.S. employees. We expensed pre-tax employer matching contributions of $4 million and $3 million in the three-month periods ended September 30, 2013 and 2012, respectively, and $10 million and $9 million in the nine-month periods ended September 30, 2013 and 2012, respectively, for Canadian employees.

21. 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.

Certain amounts in the condensed consolidating statement of cash flows for the 2012 period, primarily cash flows related to intercompany receivables, payables and advances, have been reclassified to conform to the current period presentation.

Spectra Energy Corp

Condensed Consolidating Statements of Operations

(Unaudited)

(In millions)



	Spectra Energy Corp			Spectra Capital		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Three Months Ended September 30, 2013
Total operating revenues	$	—		$	—	$	1,146		$	(2	)	$	1,144
Total operating expenses	4			—		809			(2		)	811
Operating income (loss)	(4		)	—		337			—			333
Equity in earnings of unconsolidated affiliates	—			—		163			—			163
Equity in earnings of subsidiaries	263			403		—			(666		)	—
Other income and expenses, net	2			10		36			—			48
Interest expense	—			56		111			—			167
Earnings before income taxes	261			357		425			(666		)	377
Income tax expense (benefit)	(2		)	94		(7		)	—			85
Net income	263			263		432			(666		)	292
Net income—noncontrolling interests	—			—		29			—			29
Net income—controlling interests	$	263		$	263	$	403		$	(666	)	$	263

Three Months Ended September 30, 2012
Total operating revenues	$	—		$	—	$	1,073		$	(1	)	$	1,072
Total operating expenses	3			—		742			(1		)	744
Operating income (loss)	(3		)	—		331			—			328
Equity in earnings of unconsolidated affiliates	—			—		88			—			88
Equity in earnings of subsidiaries	181			290		—			(471		)	—
Other income and expenses, net	(2		)	—		21			—			19
Interest expense	—			48		111			—			159
Earnings before income taxes	176			242		329			(471		)	276
Income tax expense (benefit)	(3		)	61		14			—			72
Net income	179			181		315			(471		)	204
Net income—noncontrolling interests	—			—		25			—			25
Net income—controlling interests	$	179		$	181	$	290		$	(471	)	$	179

Spectra Energy Corp

Condensed Consolidating Statements of Operations

(Unaudited)

(In millions)



	Spectra Energy Corp			Spectra Capital		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Nine Months Ended September 30, 2013
Total operating revenues	$	—		$	—	$	3,956		$	(3	)	$	3,953
Total operating expenses	7			—		2,756			(3		)	2,760
Operating income (loss)	(7		)	—		1,200			—			1,193
Equity in earnings of unconsolidated affiliates	—			—		345			—			345
Equity in earnings of subsidiaries	794			1,229		—			(2,023		)	—
Other income and expenses, net	(1		)	14		90			—			103
Interest expense	—			155		321			—			476
Earnings before income taxes	786			1,088		1,314			(2,023		)	1,165
Income tax expense (benefit)	(16		)	294		(1		)	—			277
Net income	802			794		1,315			(2,023		)	888
Net income—noncontrolling interests	—			—		86			—			86
Net income—controlling interests	$	802		$	794	$	1,229		$	(2,023	)	$	802

Nine Months Ended September 30, 2012
Total operating revenues	$	—		$	—	$	3,730		$	(2	)	$	3,728
Total operating expenses	11			—		2,507			(2		)	2,516
Gains on sales of other assets and other, net	—			—		2			—			2
Operating income (loss)	(11		)	—		1,225			—			1,214
Equity in earnings of unconsolidated affiliates	—			—		297			—			297
Equity in earnings of subsidiaries	726			1,118		—			(1,844		)	—
Other income and expenses, net	(3		)	1		55			—			53
Interest expense	—			144		327			—			471
Earnings from continuing operations before income taxes	712			975		1,250			(1,844		)	1,093
Income tax expense (benefit) from continuing operations	(16		)	249		56			—			289
Income from continuing operations	728			726		1,194			(1,844		)	804
Income (loss) from discontinued operations, net of tax	(1		)	—		3			—			2
Net income	727			726		1,197			(1,844		)	806
Net income—noncontrolling interests	—			—		79			—			79
Net income—controlling interests	$	727		$	726	$	1,118		$	(1,844	)	$	727

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 September 30, 2013
Net income	$	263	$	263	$	432	$	(666	)	$	292
Other comprehensive income	4		1		160		—			165
Total comprehensive income, net of tax	267		264		592		(666		)	457
Less: comprehensive income—noncontrolling interests	—		—		30		—			30
Comprehensive income—controlling interests	$	267	$	264	$	562	$	(666	)	$	427

Three Months Ended September 30, 2012
Net income	$	179	$	181	$	315	$	(471	)	$	204
Other comprehensive income	2		1		262		—			265
Total comprehensive income, net of tax	181		182		577		(471		)	469
Less: comprehensive income—noncontrolling interests	—		—		29		—			29
Comprehensive income—controlling interests	$	181	$	182	$	548	$	(471	)	$	440



Nine Months Ended September 30, 2013
Net income	$	802	$	794	$	1,315		$	(2,023	)	$	888
Other comprehensive income (loss)	11		2		(260		)	—			(247		)
Total comprehensive income, net of tax	813		796		1,055			(2,023		)	641
Less: comprehensive income—noncontrolling interests	—		—		82			—			82
Comprehensive income—controlling interests	$	813	$	796	$	973		$	(2,023	)	$	559

Nine Months Ended September 30, 2012
Net income	$	727	$	726	$	1,197		$	(1,844	)	$	806
Other comprehensive income	9		2		313			—			324
Total comprehensive income, net of tax	736		728		1,510			(1,844		)	1,130
Less: comprehensive income—noncontrolling interests	—		—		83			—			83
Comprehensive income—controlling interests	$	736	$	728	$	1,427		$	(1,844	)	$	1,047

Spectra Energy Corp

Condensed Consolidating Balance Sheet

September 30, 2013

(Unaudited)

(In millions)



	Spectra Energy Corp		Spectra Capital		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Cash and cash equivalents	$	—	$	2	$	158	$	—		$	160
Receivables—consolidated subsidiaries	11		318		—		(329		)	—
Receivables—other	—		21		945		—			966
Other current assets	37		20		738		—			795
Total current assets	48		361		1,841		(329		)	1,921
Investments in and loans to unconsolidated affiliates	—		70		2,956		—			3,026
Investments in consolidated subsidiaries	13,558		17,571		—		(31,129		)	—
Advances receivable—consolidated subsidiaries	—		5,922		—		(5,922		)	—
Notes receivable—consolidated subsidiaries	—		—		1,092		(1,092		)	—
Goodwill	—		—		4,869		—			4,869
Other assets	39		34		2,287		—			2,360
Property, plant and equipment, net	—		—		21,822		—			21,822
Regulatory assets and deferred debits	2		16		1,337		—			1,355
Total Assets	$	13,647	$	23,974	$	36,204	$	(38,472	)	$	35,353

Accounts payable—other	$	2	$	95	$	331	$	—		$	428
Accounts payable—consolidated subsidiaries	—		—		329		(329		)	—
Commercial paper	—		1,227		822		—			2,049
Short-term borrowings—consolidated subsidiaries	—		1,092		—		(1,092		)	—
Accrued taxes payable	1		—		57		—			58
Current maturities of long-term debt	—		1,757		747		—			2,504
Other current liabilities	61		68		991		—			1,120
Total current liabilities	64		4,239		3,277		(1,421		)	6,159
Long-term debt	—		2,611		9,657		—			12,268
Advances payable—consolidated subsidiaries	4,463		—		1,459		(5,922		)	—
Deferred credits and other liabilities	187		3,566		2,918		—			6,671
Preferred stock of subsidiaries	—		—		258		—			258
Equity
Controlling interests	8,933		13,558		17,571		(31,129		)	8,933
Noncontrolling interests	—		—		1,064		—			1,064
Total equity	8,933		13,558		18,635		(31,129		)	9,997
Total Liabilities and Equity	$	13,647	$	23,974	$	36,204	$	(38,472	)	$	35,353

Spectra Energy Corp

Condensed Consolidating Balance Sheet

December 31, 2012

(Unaudited)

(In millions)



	Spectra Energy Corp		Spectra Capital		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Cash and cash equivalents	$	—	$	3	$	91	$	—		$	94
Receivables—consolidated subsidiaries	164		—		—		(164		)	—
Receivables—other	1		56		913		—			970
Other current assets	17		23		559		—			599
Total current assets	182		82		1,563		(164		)	1,663
Investments in and loans to unconsolidated affiliates	—		70		2,622		—			2,692
Investments in consolidated subsidiaries	12,974		14,969		—		(27,943		)	—
Advances receivable—consolidated subsidiaries	—		5,658		—		(5,658		)	—
Notes receivable—consolidated subsidiaries	—		—		912		(912		)	—
Goodwill	—		—		4,513		—			4,513
Other assets	39		67		466		—			572
Property, plant and equipment, net	—		—		19,905		—			19,905
Regulatory assets and deferred debits	3		14		1,225		—			1,242
Total Assets	$	13,198	$	20,860	$	31,206	$	(34,677	)	$	30,587

Accounts payable—other	$	4	$	74	$	386	$	—		$	464
Accounts payable—consolidated subsidiaries	—		91		73		(164		)	—
Commercial paper	—		513		746		—			1,259
Short-term borrowings—consolidated subsidiaries	—		912		—		(912		)	—
Accrued taxes payable	10		—		57		—			67
Current maturities of long-term debt	—		744		177		—			921
Other current liabilities	61		106		913		—			1,080
Total current liabilities	75		2,440		2,352		(1,076		)	3,791
Long-term debt	—		2,550		8,103		—			10,653
Advances payable—consolidated subsidiaries	3,957		—		1,701		(5,658		)	—
Deferred credits and other liabilities	194		2,896		2,952		—			6,042
Preferred stock of subsidiaries	—		—		258		—			258
Equity
Controlling interests	8,972		12,974		14,969		(27,943		)	8,972
Noncontrolling interests	—		—		871		—			871
Total equity	8,972		12,974		15,840		(27,943		)	9,843
Total Liabilities and Equity	$	13,198	$	20,860	$	31,206	$	(34,677	)	$	30,587

Spectra Energy Corp

Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2013

(Unaudited)

(In millions)



	Spectra Energy Corp			Spectra Capital			Non-Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	802		$	794		$	1,315		$	(2,023	)	$	888
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	—			—			587			—			587
Equity in earnings of unconsolidated affiliates	—			—			(345		)	—			(345		)
Equity in earnings of consolidated subsidiaries	(794		)	(1,229		)	—			2,023			—
Distributions received from unconsolidated affiliates	—			—			215			—			215
Other	(18		)	812			(739		)	—			55
Net cash provided by (used in) operating activities	(10		)	377			1,033			—			1,400
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	—			—			(1,476		)	—			(1,476		)
Investments in and loans to unconsolidated affiliates	—			—			(224		)	—			(224		)
Acquisitions, net of cash acquired	—			—			(1,254		)	—			(1,254		)
Purchases of held-to-maturity securities	—			—			(632		)	—			(632		)
Proceeds from sales and maturities of held-to-maturity securities	—			—			623			—			623
Purchases of available-for-sale securities	—			—			(5,665		)	—			(5,665		)
Proceeds from sales and maturities of available-for-sale securities	—			—			3,810			—			3,810
Distributions received from unconsolidated affiliates	—			—			17			—			17
Advances from (to) affiliates	153			(1,039		)	—			886			—
Other changes in restricted funds	—			—			(1		)	—			(1		)
Other	—			—			2			—			2
Net cash provided by (used in) investing activities	153			(1,039		)	(4,800		)	886			(4,800		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	—			1,848			2,124			—			3,972
Payments for the redemption of long-term debt	—			(745		)	(51		)	—			(796		)
Net increase in commercial paper	—			713			90			—			803
Net decrease in short-term borrowings—consolidated subsidiaries	—			180			—			(180		)	—
Distributions to noncontrolling interests	—			—			(104		)	—			(104		)
Proceeds from the issuance of Spectra Energy Partners common units	—			—			190			—			190
Dividends paid on common stock	(616		)	—			—			—			(616		)
Distributions and advances from (to) affiliates	447			(1,330		)	1,589			(706		)	—
Other	26			(5		)	(3		)	—			18
Net cash provided by (used in) financing activities	(143		)	661			3,835			(886		)	3,467
Effect of exchange rate changes on cash	—			—			(1		)	—			(1		)
Net increase (decrease) in cash and cash equivalents	—			(1		)	67			—			66
Cash and cash equivalents at beginning of period	—			3			91			—			94
Cash and cash equivalents at end of period	$	—		$	2		$	158		$	—		$	160

Spectra Energy Corp

Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2012

(Unaudited)

(In millions)



	Spectra Energy Corp			Spectra Capital			Non-Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	727		$	726		$	1,197		$	(1,844	)	$	806
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	—			—			566			—			566
Equity in earnings of unconsolidated affiliates	—			—			(297		)	—			(297		)
Equity in earnings of consolidated subsidiaries	(726		)	(1,118		)	—			1,844			—
Distributions received from unconsolidated affiliates	—			—			252			—			252
Other	41			212			(126		)	—			127
Net cash provided by (used in) operating activities	42			(180		)	1,592			—			1,454
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	—			—			(1,418		)	—			(1,418		)
Acquisitions	—			—			(30		)	—			(30		)
Purchases of held-to-maturity securities	—			—			(2,276		)	—			(2,276		)
Proceeds from sales and maturities of held-to-maturity securities	—			—			2,173			—			2,173
Purchases of available-for-securities	—			—			(15		)				(15		)
Proceeds from sales and maturities of available-for-sale securities	—			—			21			—			21
Distributions received from unconsolidated affiliates	—			—			11			—			11
Advances from (to) affiliates	(62		)	(181		)	33			210			—
Other changes in restricted funds	—			—			77			—			77
Other	—			—			7			—			7
Net cash used in investing activities	(62		)	(181		)	(1,417		)	210			(1,450		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	—			—			350			—			350
Payments for the redemption of long-term debt	—			—			(28		)	—			(28		)
Net increase in commercial paper	—			122			134			—			256
Distributions to noncontrolling interests	—			—			(86		)	—			(86		)
Dividends paid on common stock	(555		)	—			—			—			(555		)
Distributions and advances from (to) affiliates	546			238			(574		)	(210		)	—
Other	29			—			(1		)	—			28
Net cash provided by (used in) financing activities	20			360			(205		)	(210		)	(35		)
Effect of exchange rate changes on cash	—			—			3			—			3
Net decrease in cash and cash equivalents	—			(1		)	(27		)	—			(28		)
Cash and cash equivalents at beginning of period	—			2			172			—			174
Cash and cash equivalents at end of period	$	—		$	1		$	145		$	—		$	146

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22. New Accounting Pronouncements

There were no significant accounting pronouncements adopted during the nine months ended September 30, 2013 that had a material impact on our consolidated results of operations, financial position or cash flows.

23. Subsequent Events

On November 1, 2013, we completed the first of three closings related to the contribution by Spectra Energy to Spectra Energy Partners of substantially all of Spectra Energy’s remaining interests in its other subsidiaries that own U.S. transmission and storage and liquids assets, including Spectra Energy’s remaining 60% interest in the U.S. portion of Express-Platte. See Note 3 for further discussion.

On November 1, 2013, Spectra Energy Partners entered into and borrowed $400 million under a senior unsecured five-year term loan agreement. Proceeds from the borrowing were used to pay Spectra Energy for a portion of the U.S. assets dropdown.

On November 1, 2013, Spectra Capital paid off the $1.2 billion of borrowings outstanding under its existing three-year term loan agreement and the agreement was terminated.



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 September 30, 2013 and 2012, we reported net income from controlling interests of $263 million and $179 million, respectively. For the nine months ended September 30, 2013 and 2012, we reported net income from controlling interests of $802 million and $727 million, respectively.

The highlights for the three months and nine months ended September 30, 2013 include the following:


•	U.S. Transmission’s earnings increased mainly due to higher earnings from expansion projects at Texas Eastern Transmission, LP (Texas Eastern), partially offset by lower storage revenues and higher operating costs,


•	Distribution’s earnings for the three-month period reflected expected lower short-term transportation and storage revenues. The decrease in earnings for the nine-month period was mainly due to lower transportation and storage revenues, and higher employee benefit costs, partially offset by an increase in distribution rates and higher customer usage as a result of colder weather,

•

Western Canada Transmission & Processing’s earnings for the three-month period increased mainly due to higher NGL earnings at Empress due mainly to higher propane prices and lower production costs, mostly offset by expected lower earnings in the conventional gathering and processing business, driven by lower contracted volumes, and increased benefit and other costs. For the nine-month period, the decrease in earnings was mostly attributable to lower earnings in the conventional gathering and processing business driven mainly by expected lower contracted volumes and scheduled major plant turnarounds primarily in the second quarter of 2013, partially offset by higher NGL earnings at Empress due to lower production costs,

•

Field Services’ earnings for the three-month period increased mostly due to an increase in gains associated with the issuance of partnership units by DCP Partners, higher commodity prices, higher gathering and processing volumes due to asset growth and lower operating costs, partially offset by higher interest expense. The increase in earnings for the nine-month period was mostly due to an increase in gains associated with the issuance of partnership units by DCP Partners and lower operating costs, partially offset by the effects of asset dropdowns to DCP Partners, higher interest expense and lower commodity prices, and


•	Liquid’s results primarily reflect the earnings of Express-Platte that was acquired in March 2013.

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We closed our acquisition of Express-Platte in March 2013. Express-Platte forms a significant part of our new reportable business segment, “Liquids,” which also includes our one-third ownership interests in Sand Hills and Southern Hills, which were placed in service in the second quarter of 2013. See Notes 2 and 4 of Notes to Condensed Consolidated Financial Statements for further discussion.

In August 2013, subsidiaries of Spectra Energy contributed a 40% interest in the U.S. portion of Express-Platte and sold a 100% ownership interest in the Canadian portion to Spectra Energy Partners. Aggregate consideration for the transactions consisted of approximately $410 million in cash and $319 million of newly issued Spectra Energy Partners partnership units. Spectra Energy’s ownership in Spectra Energy Partners increased to 61% as a result of the transaction.

On November 1, 2013, we completed the first of three closings related to the contribution by Spectra Energy to Spectra Energy Partners of substantially all of Spectra Energy’s remaining interests in its other subsidiaries that own U.S. transmission and storage and liquids assets, including Spectra Energy's remaining 60% interest in the U.S. portion of Express-Platte. See Note 3 for further discussion.

In the first nine months of 2013, we had $1.7 billion of capital and investment expenditures in addition to the acquisition of Express-Platte. Excluding the acquisition of Express-Platte, we currently project approximately $2.4 billion of capital and investment expenditures for the full year, including expansion capital expenditures of approximately $1.6 billion.

We are committed to an investment-grade balance sheet and continued prudent financial management of our capitalization structure. Therefore, financing these growth activities will continue to be based on our strong and growing fee-based earnings and cash flows as well as the issuance of long-term debt and additional equity issuances at Spectra Energy Partners. We had access to $830 million available under our credit facilities as of September 30, 2013 to be utilized as needed for effective working capital management. In November 2013, we amended and restated the Spectra Capital and Spectra Energy Partners credit agreements. The Spectra Capital credit facility was decreased to $1.0 billion, and the Spectra Energy Partners credit facility was increased to $2.0 billion.

RESULTS OF OPERATIONS



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(in millions)
Operating revenues	$	1,144	$	1,072	$	3,953	$	3,728
Operating expenses	811		744		2,760		2,516
Gains on sales of other assets and other, net	—		—		—		2
Operating income	333		328		1,193		1,214
Other income and expenses	211		107		448		350
Interest expense	167		159		476		471
Earnings from continuing operations before income taxes	377		276		1,165		1,093
Income tax expense from continuing operations	85		72		277		289
Income from continuing operations	292		204		888		804
Income from discontinued operations, net of tax	—		—		—		2
Net income	292		204		888		806
Net income—noncontrolling interests	29		25		86		79
Net income—controlling interests	$	263	$	179	$	802	$	727

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Three Months Ended September 30, 2013 Compared to Same Period in 2012

Operating Revenues. The $72 million, or 7%, increase was driven by:


•	revenues from Express-Platte, which was acquired in March 2013 at Liquids,


•	higher revenues from expansion projects at Western Canada Transmission & Processing and U.S. Transmission,


•	higher propane prices at the Empress operations, net of expected lower contracted volumes in the conventional gathering and processing business at Western Canada Transmission & Processing, and


•	higher natural gas prices passed through to customers, earnings sharing in the prior year, higher industrial market usage and growth in the number of customers, net of expected lower short-term transportation and storage revenues, at Distribution, partially offset by


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


•	lower recoveries of electric power and other costs passed through to customers and lower storage revenues at U.S. Transmission.

Operating Expenses. The $67 million, or 9%, increase was driven by:


•	operating expenses from Express-Platte,


•	higher natural gas prices passed through to customers, higher industrial market usage, growth in the number of customers and higher employee benefit costs at Distribution,

•

higher operating and maintenance costs primarily due to higher employee benefit costs and increased depreciation expense from expansion projects, net of decreased volumes of natural gas purchases for extraction and make-up primarily resulting from lower plant inlet volumes and lower production costs due primarily to lower extraction premiums for the Empress operations at Western Canada Transmission & Processing, and


•	higher corporate costs primarily due to higher transaction costs, partially offset by


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


•	lower electric power and other costs passed through to customers at U.S. Transmission.

Operating Income. The $5 million, or 2%, increase was attributable to earnings from Express-Platte at Liquids and higher NGL earnings due mainly to higher propane prices and lower production costs related to the Empress operations, net of expected lower earnings in the conventional gathering and processing business, driven by lower contracted volumes, and increased benefit and other costs at Western Canada Transmission & Processing, mostly offset by expected lower short-term transportation and storage revenues at Distribution and lower storage revenues at U.S. Transmission.

Other Income and Expenses. The $104 million, or 97%, increase was attributable to higher equity earnings from Field Services mainly due to the gains associated with the issuance of partnership units by DCP Partners, higher gathering and processing volumes due to asset growth, higher commodity prices, favorable impacts of commodity hedges associated with asset dropdowns by DCP Midstream to DCP Partners, favorable results from NGL marketing and gas marketing and lower operating costs, partially offset by higher interest expense. The increase is also due to higher allowance for funds used during construction (AFUDC) resulting from increased capital spending on expansion projects at U.S. Transmission, partially offset by lower AFUDC at Western Canada Transmission & Processing due to decreased capital spending on expansion projects.

Interest Expense. The $8 million, or 5%, increase was due to higher average debt balances, partially offset by a weaker Canadian dollar.

Income Tax Expense from Continuing Operations. The $13 million increase was driven by higher earnings, partially offset by changes in Canadian provincial tax rates and the recognition of certain regulatory tax benefits. The effective tax rates for income from continuing operations for the three-month periods ended September 30, 2013 and 2012 were 23% and 26%, respectively. The lower effective tax rate was mainly due to favorable enacted Canadian federal income tax legislation and the recognition of certain regulatory tax benefits.

Net Income—Noncontrolling Interests. The $4 million increase was driven by higher earnings from Spectra Energy Partners, the Spectra Energy Partners’ additional issuances of partner units in the fourth quarter of 2012 and the second and third quarter of 2013, and the dropdown of a 38.76% interest in Maritimes & Northeast Pipeline, L.L.C. (M&N LLC) to Spectra Energy Partners in the fourth quarter of 2012.

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Nine Months Ended September 30, 2013 Compared to Same Period in 2012

Operating Revenues. The $225 million, or 6%, increase was driven by:


•	revenues from Express-Platte from the date of acquisition in March 2013 at Liquids,


•	higher customer usage of natural gas as a result of colder weather, higher natural gas prices passed through to customers, higher distribution rates and growth in the number of customers, net of expected lower transportation and storage revenues at Distribution, and


•	higher revenues from expansion projects at Western Canada Transmission & Processing and U.S. Transmission, partially offset by


•	expected lower contracted volumes in the conventional gathering and processing business at Western Canada Transmission & Processing,


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


•	lower recoveries of electric power and other costs passed through to customers, and lower transportation and storage revenues at U.S. Transmission.

Operating Expenses. The $244 million, or 10%, increase was driven by:


•	operating expenses from Express-Platte,


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

•

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


•	higher corporate costs primarily due to higher transaction costs, partially offset by


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


•	lower electric power and other costs passed through to customers at U.S. Transmission.

Operating Income. The $21 million, or 2%, decrease was mostly attributable to lower storage and transportation revenues, and higher operating costs, net of earnings from expansion projects at U.S. Transmission, lower earnings in the conventional gathering and processing business driven by expected lower contracted volumes and scheduled plant turnarounds, net of higher NGL earnings due primarily to lower production costs related to the Empress operations at Western Canada Transmission & Processing, expected lower transportation and storage revenues, and higher operating costs, net of higher distribution rates and colder weather at Distribution, and higher corporate costs. Lower operating income was mostly offset by the earnings of Express-Platte that was acquired in March 2013 at Liquids.

Other Income and Expenses. The $98 million, or 28%, increase was attributable to gains associated with the issuance of partnership units by DCP Partners and lower operating costs, partially offset by the effects of asset dropdowns from DCP Midstream to DCP Partners, higher interest expense and lower commodity prices. The increase is also due to higher AFUDC resulting from increased capital spending on expansion projects at U.S. Transmission, partially offset by lower AFUDC at Western Canada Transmission & Processing due to decreased capital spending on expansion projects.

Interest Expense. The $5 million, or 1%, increase was mainly due to higher average debt balances, partially offset by a weaker Canadian dollar and increased capitalized interest primarily resulting from our investments in Sand Hills and Southern Hills.

Income Tax Expense from Continuing Operations. The $12 million decrease was attributable to favorable enacted Canadian federal income tax legislation, changes in Canadian provincial tax rates and the recognition of certain regulatory tax benefits, partially offset by higher earnings. The effective tax rates for income from continuing operations for the nine-month periods ended September 30, 2013 and 2012 were 24% and 26%, respectively. The lower effective tax rates were mainly due to favorable enacted Canadian federal income tax legislation and the recognition of certain regulatory tax benefits.

Net Income-Noncontrolling Interests. The $7 million increase was driven by higher earnings from Spectra Energy Partners, the Spectra Energy Partners additional issuance of partner units in the fourth quarter of 2012 and the second and third quarter of 2013, and the dropdown of a 38.76% interest in M&N LLC to Spectra Energy Partners in the fourth quarter of 2012.

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

Segment Results

Management evaluates segment performance based on EBIT, which represents earnings from continuing operations (both operating and non-operating) before interest and taxes, net of noncontrolling interests related to those earnings. Cash, cash equivalents and investments are managed centrally, so the gains and losses on foreign currency remeasurement, and interest and dividend income on those balances, are excluded from the segments’ EBIT. We consider segment EBIT to be a good indicator of each segment’s operating performance from its continuing operations, as it represents the results of our ownership interest in operations without regard to financing methods or capital structures.

Our segment EBIT may not be comparable to similarly titled measures of other companies because other companies may not calculate EBIT in the same manner. Segment EBIT is summarized in the following table and detailed discussions follow:

EBIT by Business Segment



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in millions)
U.S. Transmission	$	246		$	238		$	760		$	746
Distribution	34			55			267			281
Western Canada Transmission & Processing	90			83			275			315
Field Services	137			62			271			221
Liquids	33			—			71			—
Total reportable segment EBIT	540			438			1,644			1,563
Other	(33		)	(29		)	(104		)	(83		)
Total reportable segment and other EBIT	507			409			1,540			1,480
Interest expense	167			159			476			471
Interest income and other (a)	37			26			101			84
Earnings from continuing operations before income taxes	$	377		$	276		$	1,165		$	1,093

___________


(a)	Includes foreign currency transaction gains and losses and the add-back of noncontrolling interests related to segment EBIT.

Noncontrolling interests as presented in the following segment-level discussions includes only noncontrolling interests related to EBIT of non-100%-owned subsidiaries. It does not include noncontrolling interests related to interest and taxes of those operations. The amounts discussed below include intercompany transactions that are eliminated in the Condensed Consolidated Financial Statements.

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U.S. Transmission



	Three Months Ended September 30,							Nine Months Ended September 30,
	2013		2012		Increase (Decrease)			2013		2012		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	454	$	460	$	(6	)	$	1,394	$	1,419	$	(25	)
Operating expenses
Operating, maintenance and other	167		165		2			480		484		(4		)
Depreciation and amortization	72		70		2			215		211		4
Gains on sales of other assets and other, net	1		—		1			1		3		(2		)
Operating income	216		225		(9		)	700		727		(27		)
Other income and expenses	59		40		19			152		103		49
Noncontrolling interests	29		27		2			92		84		8
EBIT	$	246	$	238	$	8		$	760	$	746	$	14

Proportional throughput, TBtu (a)	734		650		84			2,228		2,025		203

___________


(a)	Trillion British thermal units. Revenues are not significantly affected by pipeline throughput fluctuations, since revenues are primarily composed of demand charges.

Three Months Ended September 30, 2013 Compared to Same Period in 2012

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


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


•	an $8 million decrease from lower storage revenues, partially offset by


•	an $8 million increase from expansion projects primarily at Texas Eastern.

Operating, Maintenance and Other. The $2 million increase was driven by:


•	a $6 million increase in transaction costs related to the dropdown of assets into Spectra Energy Partners, and


•	a $6 million increase primarily due to higher employee benefit costs, partially offset by


•	an $8 million decrease in electric power and other costs passed through to customers.

Other Income and Expenses. The $19 million increase was primarily due to higher AFUDC resulting from increased capital spending on expansion projects.

Noncontrolling Interests. The $2 million increase was driven by the dropdown of a 38.76% interest in M&N LLC from Spectra Energy to Spectra Energy Partners in the fourth quarter of 2012 and the additional issuances of Spectra Energy Partners units.

EBIT. The $8 million increase was driven mainly by higher earnings from expansions at Texas Eastern, partially offset by lower storage revenues.

Nine months ended September 30, 2013 Compared to Same Period in 2012

Operating Revenues. The $25 million decrease was driven by:


•	a $29 million decrease in recoveries of electric power and other costs passed through to customers, and


•	a $27 million decrease from lower storage revenues and lower transportation revenues mainly at Texas Eastern, Ozark Gas Transmission, L.L.C. and Ozark Gas Gathering, L.L.C., partially offset by


•	a $21 million increase from expansion projects primarily at Texas Eastern, and


•	a $7 million increase in processing revenues associated with pipeline operations primarily due to higher volumes.

Operating, Maintenance and Other. The $4 million decrease was driven by:


•	a $25 million decrease in electric power and other costs passed through to customers, partially offset by

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•	a $16 million increase due to higher employee benefit costs and ad valorem taxes, net of lower software amortization, and


•	a $6 million increase in transaction costs related to the dropdown of assets into Spectra Energy Partners.

Depreciation and Amortization. The $4 million increase was primarily due to expansion projects and capital expenditures.

Other Income and Expenses. The $49 million increase was primarily due to higher AFUDC resulting from increased capital spending on expansion projects.

Noncontrolling Interests. The $8 million increase was driven by the dropdown of a 38.76% interest in M&N LLC from Spectra Energy to Spectra Energy Partners in the fourth quarter of 2012 and the additional issuances of Spectra Energy Partners units.

EBIT. The $14 million increase was driven by higher earnings from expansions at Texas Eastern, partially offset by lower storage revenues and higher operating costs.

Distribution



	Three Months Ended September 30,								Nine Months Ended September 30,
	2013			2012		Increase (Decrease)			2013			2012		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	264		$	269	$	(5	)	$	1,315		$	1,188	$	127
Operating expenses
Natural gas purchased	70			50		20			567			425		142
Operating, maintenance and other	112			110		2			331			323		8
Depreciation and amortization	49			54		(5		)	151			159		(8		)
Operating income	33			55		(22		)	266			281		(15		)
Noncontrolling interests	(1		)	—		(1		)	(1		)	—		(1		)
EBIT	$	34		$	55	$	(21	)	$	267		$	281	$	(14	)

Number of customers, thousands									1,390			1,370		20
Heating degree days, Fahrenheit	356			295		61			4,844			3,994		850
Pipeline throughput, TBtu	157			158		(1		)	666			584		82
Canadian dollar exchange rate, average	1.04			1.00		0.04			1.02			1.00		0.02

Three Months Ended September 30, 2013 Compared to Same Period in 2012

Operating Revenues. The $5 million decrease was driven by:


•	a $14 million decrease primarily in short-term transportation revenues,


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


•	an $8 million decrease in storage revenues primarily due to lower prices, partially offset by


•	a $14 million increase from higher natural gas prices passed through to customers. Prices charged to customers are adjusted quarterly based on the 12 month New York Mercantile Exchange (NYMEX) forecast,


•	a $6 million increase as a result of earnings sharing in the prior year under the incentive regulation framework for which 2012 was the final year,


•	a $5 million increase mainly due to industrial market usage and growth in the number of customers, and


•	a $4 million increase from higher distribution rates in accordance with an OEB rate order effective January 1, 2013.

Natural Gas Purchased. The $20 million increase was driven by:


•	a $14 million increase from higher natural gas prices passed through to customers,


•	a $4 million increase mainly due to industrial market usage and growth in the number of customers, and


•	a $3 million increase in operating fuel costs, partially offset by


•	a $3 million decrease resulting from a weaker Canadian dollar.

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Operating, Maintenance and Other. The $2 million increase was driven by:


•	a $5 million increase primarily driven by higher employee benefit costs, mostly offset by


•	a $4 million decrease resulting from a weaker Canadian dollar.

Depreciation and Amortization. The $5 million decrease was driven by:


•	a $2 million decrease primarily due to approved lower depreciation rates, and


•	a $2 million decrease resulting from a weaker Canadian dollar.

EBIT. The $21 million decrease was largely the result of expected lower short-term transportation and storage revenues.

Nine months ended September 30, 2013 Compared to Same Period in 2012

Operating Revenues. The $127 million increase was driven by:


•	a $93 million increase in customer usage of natural gas primarily due to weather that was 21% colder than the same period in 2012,


•	a $44 million increase from higher natural gas prices passed through to customers,


•	a $27 million increase from higher distribution rates in accordance with the OEB rate order effective January 1, 2013, and


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


•	a $22 million decrease resulting from a weaker Canadian dollar,


•	a $19 million decrease primarily in short-term transportation revenues, net of a settlement received from the termination of a transportation contract,


•	a $16 million decrease in storage revenues primarily due to lower prices, and


•	a $16 million decrease as a result of the sharing of revenues realized from the optimization of upstream transportation contracts in accordance with the OEB rate order effective January 1, 2013.

Natural Gas Purchased. The $142 million increase was driven by:


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


•	a $44 million increase from higher natural gas prices passed through to customers,


•	a $19 million increase from growth in the number of customers, and


•	a $4 million increase in operating fuel costs primarily due to colder weather, partially offset by


•	an $8 million decrease resulting from a weaker Canadian dollar.

Operating, Maintenance and Other. The $8 million increase was driven by:


•	a $14 million increase primarily driven by higher employee benefit costs, partially offset by


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

Depreciation and Amortization. The $8 million decrease was driven by:


•	a $4 million decrease primarily due to approved lower depreciation rates, and


•	a $3 million decrease resulting from a weaker Canadian dollar.

EBIT. The $14 million decrease was largely the result of expected lower transportation and storage revenues and higher operating and maintenance costs primarily due to employee benefit costs, partially offset by an increase in distribution rates and higher customer usage due to colder weather.

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Western Canada Transmission & Processing



	Three Months Ended September 30,								Nine Months Ended September 30,
	2013			2012		Increase (Decrease)			2013		2012		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	367		$	348	$	19		$	1,132	$	1,143	$	(11	)
Operating expenses
Natural gas and petroleum products purchased	68			81		(13		)	238		304		(66		)
Operating, maintenance and other	150			142		8			459		406		53
Depreciation and amortization	57			50		7			167		145		22
Operating income	92			75		17			268		288		(20		)
Other income and expenses	(2		)	8		(10		)	7		27		(20		)
EBIT	$	90		$	83	$	7		$	275	$	315	$	(40	)

Pipeline throughput, TBtu	171			158		13			510		490		20
Volumes processed, TBtu	168			162		6			500		501		(1		)
Empress inlet volumes, TBtu	110			121		(11		)	335		401		(66		)
Canadian dollar exchange rate, average	1.04			1.00		0.04			1.02		1.00		0.02

Three Months Ended September 30, 2013 Compared to Same Period in 2012

Operating Revenues. The $19 million increase was driven by:


•	a $14 million increase primarily due to higher propane prices at Empress,


•	a $14 million increase in gathering and processing revenues due primarily to contracted volumes from expansions associated with unconventional supply discoveries in the Horn River and Montney areas of British Columbia,


•	a $10 million increase primarily due to higher sales volumes of residual natural gas at the Empress operations,


•	a $5 million increase in transmission revenues due primarily to expansion on the T-North Pipeline, and


•	a $2 million increase in carbon and other non-income tax expense recovered from customers, partially offset by


•	a $17 million decrease as a result of a weaker Canadian dollar, and


•	a $10 million expected decrease in contracted volumes in the conventional gathering and processing business due to decontracting as a result of customers’ shift to unconventional development.

Natural Gas and Petroleum Products Purchased. The $13 million decrease was driven by:


•	a $5 million decrease as a result of lower production costs at the Empress facility caused primarily by lower extraction premiums,


•	a $3 million decrease in volumes of natural gas purchases for extraction and make-up at Empress as a result of lower plant inlet volumes,


•	a $3 million decrease as a result of a weaker Canadian dollar, and


•	a $2 million noncash charge in the third quarter of 2012 to reduce the book value of propane inventory to estimated net realizable value at the Empress operations.

Operating, Maintenance and Other. The $8 million increase was driven by:


•	a $7 million increase due to higher benefit and labor costs,


•	a $3 million increase due to operating costs of the new facilities at Fort Nelson North, and


•	a $2 million increase in carbon and other non-income tax expense, partially offset by


•	a $7 million decrease as a result of a weaker Canadian dollar.

Depreciation and Amortization. The $7 million increase was driven primarily by expansion projects placed in service.

Other Income and Expenses. The $10 million decrease was driven primarily by lower AFUDC resulting from decreased capital spending on expansion projects.

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EBIT. The $7 million increase was driven by higher earnings at the Empress NGL business due mainly to higher propane prices and lower production costs in 2013, mostly offset by expected lower earnings in the conventional gathering and processing business, driven by lower contracted volumes, and increased benefit and other costs.

Nine months ended September 30, 2013 Compared to Same Period in 2012

Operating Revenues. The $11 million decrease was driven by:


•	a $40 million decrease in conventional gathering and processing revenues due primarily to expected lower contracted volumes,


•	a $24 million decrease as a result of a weaker Canadian dollar,


•	a $9 million decrease in NGL sales volumes at Empress, and


•	a $5 million decrease due to lower sales prices associated with the Empress NGL business, mostly offset by


•	a $38 million increase in gathering and processing revenues due primarily to expansion in unconventional areas for Horn River and Montney development,


•	a $14 million increase in transmission revenues due primarily to expansion on the T-North Pipeline,


•	a $7 million increase in carbon and other non-income tax expense recovered from customers, and


•	a $5 million increase due primarily to higher sales volumes of residual natural gas at the Empress operations.

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


•	a $32 million decrease as a result of lower production costs for the Empress facility caused primarily by lower extraction premiums,


•	a $17 million decrease in volumes of natural gas purchases for extraction and make-up at Empress, primarily as a result of lower plant inlet volumes,


•	a $10 million noncash charge in 2012 to write down propane inventory at the Empress operations, and


•	a $5 million decrease as a result of a weaker Canadian dollar.

Operating, Maintenance and Other. The $53 million increase was driven by:


•	a $23 million increase due to scheduled plant turnarounds in 2013,


•	an $11 million increase due to operating costs of the new facilities at Dawson and Fort Nelson North,


•	a $9 million increase due to higher benefit and labor costs,


•	a $7 million increase in carbon and other non-income tax expense, and


•	a $5 million increase in Empress plant fuel and electricity costs due to higher prices in 2013, partially offset by


•	a $10 million decrease as a result of a weaker Canadian dollar.

Depreciation and Amortization. The $22 million increase was driven primarily by expansion projects placed in service.

Other Income and Expenses. The $20 million decrease was driven primarily by lower AFUDC resulting from decreased capital spending on expansion projects.

EBIT. The $40 million decrease was driven mainly by lower earnings in the conventional gathering and processing business driven mainly by expected lower contracted volumes and higher operating and maintenance costs associated primarily with scheduled plant turnarounds, partially offset by higher earnings at the Empress NGL business due primarily to lower production costs.

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Field Services



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013		2012		Increase (Decrease)		2013		2012		Increase (Decrease)
	(in millions, except where noted)
Equity in earnings of unconsolidated affiliates	$	137	$	62	$	75	$	271	$	221	$	50
EBIT	$	137	$	62	$	75	$	271	$	221	$	50

Natural gas gathered and processed/transported, TBtu/d (a,b)	7.4		7.2		0.2		7.1		7.1		—
NGL production, MBbl/d (a,c)	442		398		44		417		401		16
Average natural gas price per MMBtu (d,e)	$	3.58	$	2.81	$	0.77	$	3.67	$	2.59	$	1.08
Average NGL price per gallon (f)	$	0.78	$	0.72	$	0.06	$	0.74	$	0.83	$	(0.09	)
Average crude oil price per barrel (g)	$	105.82	$	92.22	$	13.60	$	98.23	$	96.17	$	2.06

___________


(a)	Reflects 100% of volumes.


(b)	Trillion British thermal units per day.


(c)	Thousand barrels per day.


(d)	Average price based on NYMEX Henry Hub.


(e)	Million British thermal units.


(f)	Does not reflect results of commodity hedges.


(g)	Average price based on NYMEX calendar month.

Three Months Ended September 30, 2013 Compared to Same Period in 2012

EBIT. Higher equity earnings of $75 million were mainly the result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:


•	a $26 million increase in gains associated with the issuance of partnership units by DCP Midstream to DCP Partners in 2013 compared to 2012,


•	a $23 million increase in gathering and processing margins primarily attributable to higher volumes across several of DCP Midstream’s geographic regions due to asset growth,


•	an $18 million increase from commodity-sensitive processing arrangements due to higher NGL, natural gas and crude oil prices,


•	a $15 million increase attributable to the favorable impact of commodity hedges associated with dropdowns to DCP Partners and favorable results from NGL marketing and gas marketing, and


•	a $15 million increase primarily attributable to lower operating costs due to a cost reduction initiative and lower benefits costs, partially offset by


•	a $13 million decrease primarily attributable to higher interest expense due to higher interest rates as a result of newly issued debt and lower capitalized interest on certain projects which were placed in service in 2013,


•	a $5 million decrease due to higher depreciation expense as a result of growth in DCP Midstream’s business, and


•	a $2 million decrease primarily attributable to incremental dropdowns to DCP Partners, which increased net income attributable to noncontrolling interests.

Nine months ended September 30, 2013 Compared to Same Period in 2012

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


•	a $55 million increase in gains associated with the issuance of partnership units by DCP Partners in 2013 compared to 2012,


•	a $24 million increase primarily attributable to lower operating costs as a result of a cost reduction initiative and lower benefit costs,


•	a $7 million increase in gathering and processing margins primarily attributable to higher volumes across several of DCP Midstream’s geographic regions due to asset growth,

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•

a $6 million increase due to lower depreciation expense as a result of changes to the remaining useful lives of DCP Midstream’s gathering, transmission, processing, storage and other assets during the second quarter of 2012. The key contributing factor to the change is an increase in producers’ estimated remaining economically recoverable commodity reserves, resulting from advances in extraction processes, such as hydraulic fracturing and horizontal drilling, as well as improved technology used to locate commodity reserves, and


•	a $4 million increase in earnings from DCP Partners primarily as a result of growth, partially offset by


•	a $14 million decrease primarily attributable to incremental dropdowns to DCP Partners, which increased net income attributable to noncontrolling interests,


•	a $13 million decrease primarily attributable to higher interest expense due to higher interest rates as a result of newly issued debt and lower capitalized interest on certain projects which were placed in service in 2013,


•	a $10 million decrease attributable to the unfavorable impact of commodity hedges associated with dropdowns to DCP Partners and unfavorable results from NGL and gas marketing, and


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

Liquids



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013		2012		Increase (Decrease)		2013		2012		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	76	$	—	$	76	$	162	$	—	$	162
Operating expenses
Operating, maintenance and other	33		—		33		72		—		72
Depreciation and amortization	7		—		7		15		—		15
Operating income	36		—		36		75		—		75
Other income and expenses	2		—		2		1		—		1
Noncontrolling interests	5		—		5		5		—		5
EBIT	$	33	$	—	$	33	$	71	$	—	$	71

Express pipeline receipts, MBbl/d	205		—		205		204		—		204
Platte PADD II deliveries, MBbl/d	173		—		173		169		—		169
Canadian dollar exchange rate, average	1.04		—		—		1.02		—		—

Express-Platte, acquired in March 2013, forms a significant part of the Liquids segment, along with our direct equity investments in Sand Hills and Southern Hills.

Three Months Ended September 30, 2013 Compared to Same Period in 2012

EBIT. The $33 million increase reflects the earnings of Express-Platte.

Nine months ended September 30, 2013 Compared to Same Period in 2012

EBIT. The $71 million increase was primarily the earnings of Express-Platte from the date of acquisition.

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Other



	Three Months Ended September 30,									Nine Months Ended September 30,
	2013			2012			Increase (Decrease)			2013			2012			Increase (Decrease)
	(in millions)
Operating revenues	$	15		$	19		$	(4	)	$	44		$	59		$	(15	)
Operating expenses	60			46			14			160			139			21
Operating loss	(45		)	(27		)	(18		)	(116		)	(80		)	(36		)
Other income and expenses	12			(2		)	14			12			(3		)	15
EBIT	$	(33	)	$	(29	)	$	(4	)	$	(104	)	$	(83	)	$	(21	)

Three Months Ended September 30, 2013 Compared to Same Period in 2012

EBIT. The $4 million decrease reflects higher corporate costs, including transaction costs, partially offset by a reversal of an uncertain tax position related to matters prior to the spin-off of Spectra Energy in 2007.

Nine months ended September 30, 2013 Compared to Same Period in 2012

EBIT. The $21 million decrease reflects higher corporate costs, including transaction costs and employee benefit costs, partially offset by a reversal of an uncertain tax position related to matters prior to the spin-off of Spectra Energy in 2007.

Impairment of Goodwill

In connection with our quantitative assessments, we primarily use a discounted cash flow analysis to determine fair values of those reporting units. The long-term growth rates used for the reporting units that we quantitatively assessed reflect continued expansion of our assets, driven by new natural gas supplies such as shale gas in North America and increasing demand for natural gas transportation capacity on our pipeline systems primarily as a result of forecasted growth in natural gas-fired power plants. We assumed a weighted average long-term growth rate of 2.3% for our 2013 quantitative goodwill impairment analysis. Had we assumed a 100 basis point lower growth rate for each of the reporting units that we quantitatively assessed, there would have been no impairment of goodwill. We continue to monitor the effects of the global economic downturn with respect to the long-term cost of capital utilized to calculate our reporting units’ fair values. For our 2013 quantitative goodwill impairment analysis, we assumed weighted-average costs of capital ranging from 5.8% to 7.9% that market participants would use. Had we assumed a 100 basis point increase in the weighted-average cost of capital for each of the reporting units that we quantitatively assessed, there would have been no impairment of goodwill. For our regulated businesses in Canada, if an increase in the cost of capital occurred, we assumed that the effect on the corresponding reporting unit’s fair value would be ultimately offset by a similar increase in the reporting unit’s regulated revenues since those rates include a component that is based on the reporting unit’s cost of capital.

Certain commodity prices, specifically NGLs, have fluctuated in 2012 and 2013 and are generally lower than prior years’ levels. Our Empress NGL business is significantly affected by fluctuations in commodity prices. We updated our Empress NGL reporting unit’s impairment test using recent operational information, financial data and June 30, 2013 commodity prices, and concluded there was no impairment of goodwill related to Empress. The operating results of our Empress NGL reporting unit improved during the third quarter of 2013 due to, among other things, improved commodity prices. Therefore, no additional impairment test was deemed necessary. Should NGL prices decline significantly from recent levels and further reduce earnings at the Empress NGL business, this could result in a triggering event that would warrant a testing of impairment for goodwill relating to the Empress NGL reporting unit, which could result in an impairment.

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, 2013 (our testing date) were substantially in excess of their respective carrying values.

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Other than the previously described update to our Empress NGL reporting unit’s impairment test, no triggering events occurred with the other reporting units during the period April 1, 2013 through September 30, 2013 that would warrant re-testing for goodwill impairment.

LIQUIDITY AND CAPITAL RESOURCES

As of September 30, 2013, we had negative working capital of $4,238 million. This balance includes commercial paper liabilities totaling $2,049 million and current maturities of long-term debt of $2,504 million, which includes $1,200 million of term debt that was reclassified to a current liability in the third quarter of 2013. This term debt was paid in November 2013, from proceeds received from Spectra Energy Partners from the U.S. assets dropdown. We will rely upon cash flows from operations and various financing transactions, which may include issuances of short-term and long-term debt, to fund our liquidity and capital requirements for the next 12 months. At September 30, 2013, we had access to four revolving credit facilities, with total combined capital commitments of $2,879 million, with $830 million available under the facilities. In November 2013, we amended and restated the Spectra Capital and Spectra Energy Partners credit agreements. The Spectra Capital credit facility was decreased to $1.0 billion, and the Spectra Energy Partners credit facility was increased to $2.0 billion. Both facilities expire in 2018. These facilities are used principally as back-stops for commercial paper programs or for the issuance of letters of credit. At Union Gas, we primarily use commercial paper to support short-term working capital fluctuations. At Spectra Capital, Spectra Energy Partners and Westcoast, we primarily use commercial paper for temporary funding of capital expenditures. 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.

Operating Cash Flows

Net cash provided by operating activities decreased $54 million to $1,400 million for the nine months ended September 30, 2013 compared to the same period in 2012, driven mostly by changes in working capital, partially offset by lower net foreign tax payments.

Investing Cash Flows

Net cash used in investing activities increased $3,350 million to $4,800 million in the first nine months ended September 30, 2013 compared to the same period in 2012. This change was driven mainly by the acquisition of Express-Platte and purchases of AFS marketable securities from net proceeds from Spectra Energy Partners’ issuance of long-term debt.



	Nine Months Ended September 30,
	2013		2012
	(in millions)
Capital and Investment Expenditures
U.S. Transmission (a)	$	775	$	651
Distribution	238		172
Western Canada Transmission & Processing	438		548
Liquids (b)	218		—
Other	31		47
Total	$	1,700	$	1,418

___________


(a)	Excludes $30 million paid in 2012 for amounts previously withheld from the purchase price consideration of the acquisition of Bobcat Gas Storage in 2010.


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

Capital and investment expenditures for the nine months ended September 30, 2013, excluding the acquisition of Express-Platte discussed below, consisted of $1,215 million for expansion projects and $485 million for maintenance and other projects.

Excluding the acquisition of Express-Platte discussed below, we project 2013 capital and investment expenditures of approximately $2.4 billion, consisting of approximately $1.1 billion for U.S. Transmission, $0.4 billion for Distribution, $0.6 billion for Western Canada Transmission & Processing and $0.3 billion for Liquids. Total projected 2013 capital and investment expenditures include approximately $1.6 billion of expansion capital expenditures and $0.8 billion for maintenance

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and upgrades of existing plants, pipelines and infrastructure to serve growth. We continue to assess short and long-term market requirements and adjust our capital plans as required.

On March 14, 2013, we acquired Express-Platte for $1.49 billion, consisting of $1.25 billion in cash and $242 million of acquired debt, before working capital adjustments. The acquisition was primarily funded through the issuance of stock in 2012 and debt. See Note 2 of Notes to Condensed Consolidated Financial Statements for further discussion of the acquisition of Express-Platte.

Financing Cash Flows and Liquidity

Net cash provided by financing activities totaled $3,467 million in the first nine months ended September 30, 2013 compared to $35 million used in financing activities in the same period of 2012. This change was driven by:


•	a $2,854 million net increase in long-term debt issuances in 2013, primarily used to fund the acquisition of Express-Platte and Spectra Energy Corp’s U.S. assets dropdown to Spectra Energy Partners,


•	a $547 million increase in 2013 in proceeds from commercial paper issued, and


•	proceeds of $190 million from the issuance of Spectra Energy Partners common units in 2013.

In February 2013, Spectra Capital issued $650 million aggregate principal amount of 3.3% notes due in 2023. Net proceeds from the offering were used to refinance the $495 million of 6.25% notes that matured in February 2013, repay commercial paper, fund capital expenditures and for other general corporate purposes.

In the first quarter of 2013, Spectra Capital borrowed the full $1.2 billion available under an unsecured delayed-draw term loan agreement which allowed for up to four borrowings prior to March 1, 2013. Proceeds from the borrowings were used for general corporate purposes, including acquisitions and to refinance existing indebtedness. Borrowings under this term loan agreement were repaid on November 1, 2013 with proceeds received from Spectra Energy Partners from the U.S. assets dropdown and the loan agreement was terminated.

On July 2, 2013, Union issued 250 million Canadian dollars (approximately $237 million as of the issuance date) aggregate principal amount 3.79% unsecured notes due 2023. Net proceeds from the offering were used for general corporate purposes.

On September 25, 2013, Spectra Energy Partners issued $1.9 billion aggregate principal amount of senior unsecured notes comprised of $500 million of 2.95% senior notes due in 2018, $1.0 billion of 4.75% senior notes due in 2024 and $400 million of 5.95% senior notes due in 2043. Net proceeds from the offering were used to pay a portion of the cash consideration for Spectra Energy Corp’s U.S. assets dropdown to Spectra Energy Partners on November 1, 2013.

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 require our consolidated debt-to-total-capitalization ratio, as defined in the agreement, to be 65% or lower. Per the terms of the agreement, collateralized debt and Spectra Energy Partners’ debt and equity are excluded in the calculation of the ratio. As of September 30, 2013, this ratio was 62%. Our equity and, as a result, this ratio, are 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 September 30, 2013, it is unlikely that a material adverse effect would occur as a result of a weakened Canadian dollar.

On November 1, 2013, we amended and restated the Spectra Capital and Spectra Energy Partners credit agreements. The Spectra Capital credit facility was decreased to $1.0 billion, and the Spectra Energy Partners credit facility was increased to $2.0 billion. Both facilities expire in 2018.

Dividends. Our near-term objective is to increase our cash dividend by $0.12 per year through 2015. 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

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constraints and other factors deemed relevant by our Board of Directors. We declared a quarterly cash dividend of $0.305 per common share on October 8, 2013 payable on December 9, 2013 to shareholders of record at the close of business on November 8, 2013.

Other Financing Matters. On November 1, 2013, Spectra Energy Partners entered into and borrowed $400 million under a senior unsecured five-year term loan agreement. Proceeds from the borrowing were used to pay Spectra Energy for a portion of the U.S. assets dropdown.

On November 1, 2013, Spectra Capital entered into a $300 million senior unsecured delayed-draw five-year term loan agreement which allows for up to one borrowing prior to December 31, 2013. There were no borrowings under this agreement as of November 7, 2013.

Spectra Energy Corp and Spectra Capital have an effective shelf registration statement on file with the SEC to register the issuance of unspecified amounts of various equity and debt securities. Spectra Energy Partners has an effective shelf registration statement on file with the SEC to register the issuance of unspecified amounts of limited partner common units and various debt securities and another registration statement on file with the SEC to register the issuance of $500 million, in the aggregate, of limited partner common units and various debt securities. In addition, as of September 30, 2013, Westcoast and Union Gas have an aggregate 1.1 billion Canadian dollars (approximately $1.1 billion) available for the issuance of debt securities in the Canadian market under debt shelf prospectuses.

OTHER ISSUES

New Accounting Pronouncements. There were no significant accounting pronouncements adopted during the nine months ended September 30, 2013 that had a material impact on our consolidated results of operations, financial position or cash flows.



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, 2012. We believe our exposure to market risk has not changed materially since then.



Item 4.	Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

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

Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2013, 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 September 30, 2013 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

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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 5 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, 2012 and Part II, "Item 1A. Risk Factors" in our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2013, which could materially affect our financial condition or future results. There have been no material changes to those risk factors.



Item 6.	Exhibits.

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


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


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


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


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

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

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(a) Exhibits



Exhibit Number

2.1		First Amendment to Contribution Agreement by and between Spectra Energy Corp and Spectra Energy Partners, LP, dated as of October 31, 2013 (filed as Exhibit No. 2.1 to Form 8-K of Spectra Energy Corp on November 1, 2013).

3.1		The By-Laws of Spectra Energy Corp, as amended and restated on August 20, 2013 (filed as Exhibit No. 3.1 to Form 8-K of Spectra Energy Corp on August 26, 2013).

10.1		Amended and Restated Omnibus Agreement, dated November 1, 2013, by and among Spectra Energy Partners, LP, Spectra Energy Partners (DE) GP, LP, Spectra Energy Partners GP, LLC and Spectra Energy Corp (filed as Exhibit No. 10.1 to Form 8-K of Spectra Energy Corp on November 1, 2013).

10.2		Amended and Restated Credit Agreement, dated as of November 1, 2013, by and among Spectra Energy Partners, LP, as Borrower, Citibank, N.A., as Administrative Agent, and the lenders party thereto (filed as Exhibit No. 10.2 to Form 8-K of Spectra Energy Corp on November 1, 2013).

*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.

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: November 7, 2013						/s/ Gregory L. Ebel
						Gregory L. Ebel
						President and Chief Executive Officer

Date: November 7, 2013						/s/ J. Patrick Reddy
						J. Patrick Reddy
						Chief Financial Officer