Edgar Filing: Spectra Energy Corp.

Form 10-Q for quarterly period ended March 31, 2011

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2011

¨	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 x 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 x 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 x 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 x

Number of shares of Common Stock, $0.001 par value, outstanding as of March 31, 2011: 649,889,656

SPECTRA ENERGY CORP

FORM 10-Q FOR THE QUARTER ENDED

March 31, 2011

INDEX


		Page
PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)		4

	Condensed Consolidated Statements of Operations for the three months ended March 31, 2011 and 2010		4

	Condensed Consolidated Balance Sheets as of March 31, 2011 and December 31, 2010		5

	Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2011 and 2010		7

	Condensed Consolidated Statements of Equity for the three months ended March 31, 2011 and 2010		8

	Notes to Condensed Consolidated Financial Statements		9

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		29

Item 3.	Quantitative and Qualitative Disclosures about Market Risk		38

Item 4.	Controls and Procedures		39

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings		39

Item 1A.	Risk Factors		40

Item 6.	Exhibits		40

	Signatures		42

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 are based on management’s beliefs and assumptions. 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 involve risks and uncertainties that may cause actual results to be materially different from the results predicted. Factors 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 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 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 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 transmission and storage, distribution, and gathering and processing facilities;

•

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

•

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

•

conditions of the capital markets during the periods covered by these 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.

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 March 31,
	2011		2010
Operating Revenues
Transportation, storage and processing of natural gas	$	791	$	710
Distribution of natural gas		607		584
Sales of natural gas liquids		177		146
Other		37		40

Total operating revenues		1,612		1,480

Operating Expenses
Natural gas and petroleum products purchased		485		452
Operating, maintenance and other		314		302
Depreciation and amortization		175		161
Property and other taxes		85		73

Total operating expenses		1,059		988

Gains on Sales of Other Assets and Other, net		4		—

Operating Income		557		492

Other Income and Expenses
Equity in earnings of unconsolidated affiliates		106		122
Other income and expenses, net		6		4

Total other income and expenses		112		126

Interest Expense		155		159

Earnings From Continuing Operations Before Income Taxes		514		459
Income Tax Expense From Continuing Operations		139		97

Income From Continuing Operations		375		362
Income From Discontinued Operations, net of tax		7		16

Net Income		382		378
Net Income—Noncontrolling Interests		25		20

Net Income—Controlling Interests	$	357	$	358


Common Stock Data
Weighted-average shares outstanding
Basic		649		648
Diluted		651		649
Earnings per share from continuing operations
Basic and Diluted	$	0.54	$	0.53
Earnings per share
Basic and Diluted	$	0.55	$	0.55
Dividends per share	$	0.26	$	0.25

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)


	March 31, 2011		December 31, 2010
ASSETS

Current Assets
Cash and cash equivalents	$	140	$	130
Receivables, net		1,016		1,018
Inventory		143		287
Other		218		203

Total current assets		1,517		1,638


Investments and Other Assets
Investments in and loans to unconsolidated affiliates		2,061		2,033
Goodwill		4,396		4,305
Other		636		665

Total investments and other assets		7,093		7,003


Property, Plant and Equipment
Cost		22,841		22,162
Less accumulated depreciation and amortization		5,411		5,182

Net property, plant and equipment		17,430		16,980

Regulatory Assets and Deferred Debits		1,111		1,065

Total Assets	$	27,151	$	26,686

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions, except per-share amounts)


	March 31, 2011		December 31, 2010
LIABILITIES AND EQUITY

Current Liabilities
Accounts payable	$	460	$	369
Short-term borrowings and commercial paper		655		836
Taxes accrued		80		59
Interest accrued		159		167
Current maturities of long-term debt		323		315
Other		640		777

Total current liabilities		2,317		2,523


Long-term Debt		10,257		10,169


Deferred Credits and Other Liabilities
Deferred income taxes		3,717		3,555
Regulatory and other		1,701		1,694

Total deferred credits and other liabilities		5,418		5,249


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, 650 million and 649 million shares outstanding at March 31, 2011 and December 31, 2010, respectively		1		1
Additional paid-in capital		4,740		4,726
Retained earnings		1,674		1,487
Accumulated other comprehensive income		1,803		1,595

Total controlling interests		8,218		7,809
Noncontrolling interests		683		678

Total equity		8,901		8,487

Total Liabilities and Equity	$	27,151	$	26,686

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)


	Three Months Ended March 31,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	382		$	378
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		178			165
Deferred income tax expense		109			22
Equity in earnings of unconsolidated affiliates		(106	)		(122	)
Distributions received from unconsolidated affiliates		104			108
Other		55			(81	)

Net cash provided by operating activities		722			470


CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(329	)		(176	)
Investments in and loans to unconsolidated affiliates		(4	)		(3	)
Purchases of held-to-maturity securities		(214	)		(148	)
Proceeds from sales and maturities of held-to-maturity securities		186			126
Purchases of available-for-sale securities		(548	)		(12	)
Proceeds from sales and maturities of available-for-sale securities		576			—
Other		1			(8	)

Net cash used in investing activities		(332	)		(221	)


CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt		919			720
Payments for the redemption of long-term debt		(942	)		(864	)
Net increase (decrease) in short-term borrowings and commercial paper		(182	)		21
Distributions to noncontrolling interests		(23	)		(21	)
Dividends paid on common stock		(170	)		(161	)
Other		16			3

Net cash used in financing activities		(382	)		(302	)

Effect of exchange rate changes on cash		2			—

Net increase (decrease) in cash and cash equivalents		10			(53	)
Cash and cash equivalents at beginning of period		130			166

Cash and cash equivalents at end of period	$	140		$	113

Supplemental Disclosures
Property, plant and equipment accruals	$	112		$	35

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(Unaudited)

(In millions)


	Common Stock		Additional Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income					Noncontrolling Interests			Total
	Common Stock		Additional Paid-in Capital			Retained Earnings			Foreign Currency Translation Adjustments		Other			Noncontrolling Interests			Total
December 31, 2010	$	1	$	4,726		$	1,487		$	2,010	$	(415	)	$	678		$	8,487
Net income		—		—			357			—		—			25			382
Foreign currency translation adjustments		—		—			—			188		—			3			191
Unrealized mark-to-market net gain on hedges		—		—			—			—		1			—			1
Reclassification of cash flow hedges into earnings		—		—			—			—		3			—			3
Pension and benefits impact		—		—			—			—		8			—			8
Dividends on common stock		—		—			(170	)		—		—			—			(170	)
Stock-based compensation		—		14			—			—		—			—			14
Distributions to noncontrolling interests		—		—			—			—		—			(23	)		(23	)
Other, net		—		—			—			—		8			—			8

March 31, 2011	$	1	$	4,740		$	1,674		$	2,198	$	(395	)	$	683		$	8,901


December 31, 2009	$	1	$	4,645		$	1,088		$	1,682	$	(375	)	$	540		$	7,581
Net income		—		—			358			—		—			20			378
Foreign currency translation adjustments		—		—			—			199		—			14			213
Unrealized mark-to-market net loss on hedges		—		—			—			—		(14	)		—			(14	)
Pension and benefits impact		—		—			—			—		6			—			6
Dividends on common stock		—		—			(161	)		—		—			—			(161	)
Stock-based compensation		—		6			—			—		—			—			6
Distributions to noncontrolling interests		—		—			—			—		—			(21	)		(21	)
Contributions from noncontrolling interests		—		—			—			—		—			2			2
Other, net		—		(22	)		—			—		—			2			(20	)

March 31, 2010	$	1	$	4,629		$	1,285		$	1,881	$	(383	)	$	557		$	7,970

See Notes to Condensed Consolidated Financial Statements.

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, 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. In addition, we own a 50% interest in DCP Midstream, LLC (DCP Midstream), one of the largest natural gas gatherers and processors in the United States.

Basis of Presentation. The accompanying Condensed Consolidated Financial Statements include our accounts and the accounts of our majority-owned subsidiaries. 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, 2010, 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.

We have corrected the presentation of certain restricted cash balances in the accompanying Condensed Consolidated Statements of Cash Flows. Cash and Cash Equivalents as of March 31, 2010 was reduced by $45 million and Cash Used in Investing Activities for the three-month period was reduced by $15 million from amounts previously reported. We have also corrected certain balances in the accompanying Condensed Consolidated Statements of Equity due to errors identified during 2010 related primarily to the impacts of Canadian federal and provincial tax rate changes on deferred income tax balances associated with our Canadian operations. We have concluded that these corrections are immaterial to our previously issued financial statements.

The corrections related to deferred income tax balances are as follows:


Condensed Consolidated Statement of Equity	Additional Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income—Foreign Currency Translation Adjustments			Accumulated Other Comprehensive Income—Other			Total Equity
							(in millions)
March 31, 2010
As previously reported	$	4,684		$	1,293		$	1,885		$	(366	)	$	8,054
Decrease		(55	)		(8	)		(4	)		(17	)		(84	)

As corrected	$	4,629		$	1,285		$	1,881		$	(383	)	$	7,970

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

2. Business Segments

We manage our business in four reportable segments: U.S. Transmission, Distribution, Western Canada Transmission & Processing and Field Services. The remainder of our business operations is presented as “Other,” and consists of unallocated corporate costs, wholly 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 within our defined 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, LP (Spectra Energy Partners), a master limited partnership, 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 natural gas liquids (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).

Field Services gathers and processes natural gas and fractionates, markets and trades NGLs. It conducts operations through DCP Midstream, which is owned 50% by us and 50% by ConocoPhillips. 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 27% ownership interest in DCP Midstream Partners, LP (DCP Partners), a master limited partnership.

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) from continuing operations less noncontrolling interests related to those earnings.

On a segment basis, EBIT 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.

Business Segment Data


	Unaffiliated Revenues		Intersegment Revenues			Total Operating Revenues (a)			Segment EBIT/ Consolidated Earnings from Continuing Operations before Income Taxes (a)
			(in millions)
Three Months Ended March 31, 2011
U.S. Transmission	$	481	$	2		$	483		$	279
Distribution		696		—			696			167
Western Canada Transmission & Processing		433		6			439			141
Field Services		—		—			—			81

Total reportable segments		1,610		8			1,618			668
Other		2		15			17			(24	)
Eliminations		—		(23	)		(23	)		—
Interest expense		—		—			—			155
Interest income and other (b)		—		—			—			25

Total consolidated	$	1,612	$	—		$	1,612		$	514

Three Months Ended March 31, 2010
U.S. Transmission	$	456	$	1		$	457		$	247
Distribution		668		—			668			146
Western Canada Transmission & Processing		355		—			355			119
Field Services		—		—			—			99

Total reportable segments		1,479		1			1,480			611
Other		1		12			13			(14	)
Eliminations		—		(13	)		(13	)		—
Interest expense		—		—			—			159
Interest income and other (b)		—		—			—			21

Total consolidated	$	1,480	$	—		$	1,480		$	459

(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.

3. Regulatory Matters

Maritimes & Northeast Pipeline Limited Partnership (M&N LP). M&N LP filed an application with the NEB in July 2010 seeking compensation for funds held in escrow. The NEB has determined that the issue of compensation for funds held in escrow will be addressed in two parts. The first part consisted of a hearing, which occurred in March 2011, to determine if M&N LP should be compensated for funds held in escrow and if so, how the amount of compensation should be determined. If the NEB decides M&N LP should be compensated for escrow funds, the NEB will allow a period for parties to negotiate with respect to the appropriate level of compensation. If the parties do not reach agreement within this period, the NEB will establish a further process to determine the appropriate level of compensation for these funds. A decision from the NEB is expected in June 2011.

Ozark Gas Transmission, L.L.C. (Ozark Gas Transmission). In 2010, FERC initiated a rate proceeding that required Ozark to file a Cost and Revenue Study by February 1, 2011. On March 22, 2011, the parties involved in this rate proceeding reached a settlement in principle. The settlement agreement was filed with the FERC on April 30, 2011. A final FERC order on the settlement agreement is expected by mid-2011. Management believes that the effects of this matter will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

4. Income Taxes

Income tax expense from continuing operations for the three months ended March 31, 2011 was $139 million, compared to $97 million for the same period in 2010. The higher income tax expense resulted from higher earnings from continuing operations in the first quarter of 2011 and favorable tax audit settlements totaling $24 million in the first quarter of 2010.

The effective tax rate for income from continuing operations for the three months ended March 31, 2011 was 27%, compared to 21% for the same period in 2010. The lower effective tax rate in the first quarter of 2010 was primarily due to the favorable tax audit settlements. The favorable tax audit settlements in 2010 were related mainly to an administrative change by the Canadian federal government that resulted in tax refunds from historical tax years and a reduction to the deferred tax liability.

No material net change in uncertain tax benefits was recognized during the three months ended March 31, 2011. Although uncertain, no material increases or decreases in uncertain tax benefits are expected to occur prior to March 31, 2012.

5. Discontinued Operations

Discontinued operations is mostly comprised of the net effects of a settlement arrangement related to prior liquefied natural gas contracts and an immaterial positive income tax adjustment in 2010 related to previously discontinued operations.

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 (Benefit)			Income From Discontinued Operations, Net of Tax
	(in millions)
Three Months Ended March 31, 2011
Other	$	84	$	10	$	3		$	7

Total consolidated	$	84	$	10	$	3		$	7

Three Months Ended March 31, 2010
Other	$	91	$	5	$	(11	)	$	16

Total consolidated	$	91	$	5	$	(11	)	$	16

6. Comprehensive Income

Components of comprehensive income are as follows:


	Three Months Ended March 31,
	2011		2010
	(in millions)
Net income	$	382	$	378
Other comprehensive income
Foreign currency translation adjustments		191		213
Unrealized mark-to-market net gain (loss) on hedges		1		(14	)
Reclassification of cash flow hedges into earnings		3		—
Pension and benefits impact		8		6
Other		8		—

Total comprehensive income, net of tax		593		583
Less: comprehensive income—noncontrolling interests		28		34

Comprehensive income—controlling interests	$	565	$	549

7. Earnings per Common Share

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

The following table presents our basic and diluted EPS calculations:


	Three Months Ended March 31,
	2011		2010
	(in millions, except per-share amounts)
Income from continuing operations, net of tax—controlling interests	$	350	$	342
Income from discontinued operations, net of tax—controlling interests		7		16

Net income—controlling interests	$	357	$	358

Weighted-average common shares, outstanding
Basic		649		648
Diluted		651		649
Basic and diluted earnings per common share
Continuing operations	$	0.54	$	0.53
Discontinued operations, net of tax		0.01		0.02

Total basic and diluted earnings per common share	$	0.55	$	0.55

Weighted-average shares used to calculate diluted EPS includes the effect of certain options and restricted stock awards. Certain other options and stock awards related to approximately five million and 10 million shares for the three months ended March 31, 2011 and 2010, respectively, were not included in the calculation of diluted EPS because either the option exercise prices were greater than the average market price of the common shares during these periods or performance measures related to the awards had not yet been met.

8. Marketable Securities and Restricted Funds

Available-for-Sale Marketable Securities (AFS Securities). During 2010, we invested a portion of the proceeds from Spectra Energy Partners’ issuance of common units to the public in AFS securities, which include investments in money market funds and commercial paper. These investments, which totaled $171 million as of March 31, 2011 and $209 million as of December 31, 2010, are pledged as collateral against Spectra Energy Partners’ term loan and are classified as Investments and Other Assets—Other on the Condensed Consolidated Balance Sheets. In addition, we had $17 million as of March 31, 2011 and $15 million as of December 31, 2010 of other AFS securities, classified as Investments and Other Assets—Other.

Purchases and sales of AFS securities are presented on a gross basis within Cash Flows from Investing Activities on the Condensed Consolidated Statements of Cash Flows.

There were no gross unrealized holding gains or losses associated with investments in AFS securities at March 31, 2011 or December 31, 2010. Estimated fair values of AFS securities follow:


	Estimated Fair Value
	March 31, 2011		December 31, 2010
	(in millions)
Corporate debt securities	$	183	$	222
Money market funds		5		2

Total available-for-sale investments	$	188	$	224

Held-to-Maturity Marketable Securities (HTM Securities). HTM securities, totaling $215 million as of March 31, 2011 and $182 million as of December 31, 2010, are classified as Investments and Other Assets—Other. These securities, consisting of Canadian government securities and bankers acceptance notes, are restricted funds pursuant to certain M&N LP debt agreements. These funds, plus future cash from operations that would otherwise be available for distribution to the partners of M&N LP, are placed in escrow until the balance in escrow is sufficient to fund all future debt service on the notes. The notes payable, totaling $241 million as of March 31, 2011 and $234 million as of December 31, 2010, have semi-annual interest and principal payments and are due in 2019.

At March 31, 2011, the contractual maturities of outstanding HTM securities are less than one year. Purchases and sales of HTM securities are presented on a gross basis within Cash Flows from Investing Activities.

There were no gross unrecognized holding gains or losses associated with investments in HTM securities at March 31, 2011 or December 31, 2010. Estimated fair values of HTM securities follow:


	Estimated Fair Value
	March 31, 2011		December 31, 2010
	(in millions)
Canadian government securities	$	121	$	182
Bankers acceptance notes		94		—

Total held-to-maturity investments	$	215	$	182

Other Restricted Funds. In addition to the HTM securities held in escrow described above, we had funds totaling $61 million at March 31, 2011 and $44 million at December 31, 2010 classified as Current Assets—Other and $5 million at December 31, 2010 classified as Investments and Other Assets—Other that were also considered restricted funds. These restricted funds are mostly related to insurance and additional amounts for the M&N LP debt service requirements.

9. 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 cost, primarily using average cost. The components of inventory are as follows:


	March 31, 2011		December 31, 2010
	(in millions)
Natural gas	$	47	$	175
NGLs		22		41
Materials and supplies		74		71

Total inventory	$	143	$	287

10. 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 March 31,
	2011		2010
	(in millions)
Operating revenues	$	2,929	$	3,115
Operating expenses		2,755		2,842
Operating income		174		273
Net income		125		196
Net income attributable to members’ interests		133		181

DCP Midstream recorded gains on sales of common units of DCP Partners to equity in the first quarters of 2011 and 2010. Our proportionate 50% share, totaling $14 million and $9 million, respectively, was recorded in Equity in Earnings of Unconsolidated Affiliates in the Condensed Consolidated Statements of Operations.

11. Debt and Credit Facilities

Available Credit Facilities and Restrictive Debt Covenants


	Expiration Date		Total Credit Facilities Capacity		Outstanding at March 31, 2011								Available Credit Facilities Capacity
	Expiration Date		Total Credit Facilities Capacity		Commercial Paper		Revolving Credit		Letters of Credit		Total		Available Credit Facilities Capacity
							(in millions)
Spectra Energy Capital, LLC (a)
Multi-year syndicated		2012	$	1,500	$	628	$	—	$	14	$	642	$	858
Westcoast Energy Inc. (b,c)
Multi-year syndicated		2011		206		—		—		—		—		206
Union Gas (d)
Multi-year syndicated		2012		515		27		—		—		27		488
Spectra Energy Partners
Multi-year syndicated		2012		500		—		312		—		312		188

Total			$	2,721	$	655	$	312	$	14	$	981	$	1,740

(a)	Credit facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 65%.

(b)	U.S. dollar equivalent at March 31, 2011. The credit facility totals 200 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 40% at March 31, 2011.

(c)	In May 2011, Westcoast Energy, Inc. entered into a new 300 million Canadian dollar credit facility that expires in May 2015, which replaced its 200 million Canadian dollar credit facility that was scheduled to expire in June 2011.

(d)

U.S. dollar equivalent at March 31, 2011. The credit facility totals 500 million Canadian dollars and contains a covenant that requires the Union Gas debt-to-total capitalization ratio to not exceed 75% and a provision which requires Union Gas to repay all borrowings under the facility for a period of two days during the second quarter of each year. The ratio was 61% at March 31, 2011.

The issuances of commercial paper, letters of credit and other borrowings reduce the amounts available under the credit facilities.

Our credit agreements contain various financial and other 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 March 31, 2011, 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.

12. Fair Value Measurements

The following table 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	March 31, 2011
Description	Condensed Consolidated Balance Sheet Caption	Total		Level 1		Level 2		Level 3
		(in millions)
Corporate debt securities	Cash and cash equivalents	$	72	$	—	$	72	$	—
Corporate debt securities	Investments and other assets—other		183		—		183		—
Derivative assets—interest rate swaps	Investments and other assets—other		33		—		33		—
Money market funds	Investments and other assets—other		25		25		—		—

Total Assets		$	313	$	25	$	288	$	—

Derivative liabilities—natural gas purchase contracts	Deferred credits and other liabilities—regulatory and other	$	6	$	—	$	—	$	6
Derivative liabilities—interest rate swaps	Deferred credits and other liabilities—regulatory and other		17		—		17		—

Total Liabilities		$	23	$	—	$	17	$	6


Description	Condensed Consolidated Balance Sheet Caption	December 31, 2010
Description	Condensed Consolidated Balance Sheet Caption	Total		Level 1		Level 2		Level 3
		(in millions)
Corporate debt securities	Cash and cash equivalents	$	74	$	—	$	74	$	—
Corporate debt securities	Investments and other assets—other		222		—		222		—
Derivative assets—interest rate swaps	Investments and other assets—other		48		—		48		—
Money market funds	Investments and other assets—other		25		25		—		—

Total Assets		$	369	$	25	$	344	$	—

Derivative liabilities—natural gas purchase contracts	Deferred credits and other liabilities—regulatory and other	$	6	$	—	$	—	$	6
Derivative liabilities—interest rate swaps	Deferred credits and other liabilities—regulatory and other		20		—		20		—

Total Liabilities		$	26	$	—	$	20	$	6

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


	Three Months Ended March 31,
	2011			2010
	(in millions)
Long-term derivative assets (liabilities)
Fair value, beginning of period	$	(6	)	$	15
Total realized/unrealized gains (losses):
Included in earnings		(1	)		—
Included in other comprehensive income		1			(15	)

Fair value, end of period	$	(6	)	$	—

Total gains (losses) for the period included in earnings (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets/liabilities held at the end of the period	$	3		$	—

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, primarily corporate debt securities, 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 multiple sources 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.


	March 31, 2011				December 31, 2010
	Book Value		Approximate Fair Value		Book Value		Approximate Fair Value
	(in millions)
Notes receivable, current (a)	$	52	$	53	$	50	$	51
Notes receivable, noncurrent (b)		71		71		71		71
Long-term debt, including current maturities		10,580		11,808		10,484		11,874

(a)	Included within Receivables, Net on the Condensed Consolidated Balance Sheets.

(b)	Included within Investments and Other Assets—Other on the Condensed Consolidated Balance Sheets.

The book value and fair value of long-term debt include the impacts of certain “pay floating—receive fixed” interest rate swaps that are designated as fair value hedges.

The fair values of cash and cash equivalents, restricted cash, short-term investments, accounts receivable, accounts payable, short-term borrowings 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 2011 and 2010 periods, there were no material adjustments to assets and liabilities measured at fair value on a nonrecurring basis.

13. Risk Management and Hedging Activities

We are exposed to the impact of market fluctuations in the prices of NGLs and natural gas purchased as a result of our Empress operations in Canada. 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 forward physical transactions as well as other derivatives, primarily around interest rate exposures.

At March 31, 2011, we had “pay floating—receive fixed” interest rate swaps outstanding with a total notional principal amount of $1,500 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 cash flows related to our long-term fixed-rate debt securities into variable-rate debt in order to achieve our desired mix of fixed and variable-rate debt. Our target is to maintain 20-25% of variable-rate debt in our capital structure. At Spectra Energy Partners, we had third-party “pay fixed—receive floating” interest rate swaps outstanding with a total notional principal amount of $40 million to mitigate our exposure to variable interest rates on loans outstanding under its revolving credit facility.

Our equity investment affiliate, DCP Midstream, also has risk exposures primarily associated with market prices of NGLs and natural gas. DCP Midstream manages these risks separate from Spectra Energy, and utilizes various risk management strategies, including the use of commodity derivatives.

Other than interest rate swaps described above, we did not have any significant derivatives outstanding during the three months ended March 31, 2011.

14. Commitments and Contingencies

Environmental

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

Like others in the energy industry, we and our affiliates are responsible for environmental remediation at various contaminated sites. These include some properties that are part of our ongoing operations, sites formerly owned or used by us, and sites owned by third parties. Remediation typically involves management of contaminated soils and may involve groundwater remediation. Managed in conjunction with relevant international, federal, state/provincial and local agencies, activities vary with site conditions and locations, remedial requirements, complexity and sharing of responsibility. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, we or our affiliates could potentially be held responsible for contamination caused by other parties. In some instances, we may share liability associated with contamination with other potentially responsible parties, and may also benefit from 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 accruals related to extended environmental-related activities totaling $13 million at March 31, 2011 and $14 million as of December 31, 2010. These accruals 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 may 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 adverse 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 March 31, 2011 or December 31, 2010 related to litigation.

Other Commitments and Contingencies

See Note 15 for a discussion of guarantees and indemnifications.

15. Guarantees and Indemnifications

We have various financial guarantees and indemnifications which are issued in the normal course of business. As discussed below, these contracts include financial guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. We enter into these arrangements to facilitate a commercial transaction with a third party by enhancing the value of the transaction to the third party. To varying degrees,

these guarantees involve elements of performance and credit risk, which are not included on the 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-wholly 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 March 31, 2011 was approximately $406 million, which has been indemnified by Duke Energy as discussed above. One of these 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, has issued similar joint and several guarantees to the same D/FD project owners.

Westcoast Energy Inc. (Westcoast), a wholly 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, 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. The maximum potential amount of future payments Westcoast could have been required to make under those performance guarantees of unconsolidated entities and third-party entities as of March 31, 2011 was $22 million. Of these guarantees, $5 million expire in 2015 and the remaining have no contractual expirations.

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, tax, 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 March 31, 2011, the amounts recorded for the guarantees and indemnifications, described above, including the indemnifications by Duke Energy to us, are not material, both individually and in the aggregate.

16. Employee Benefit Plans

Retirement Plans. We have a qualified non-contributory defined benefit (DB) retirement plan for U.S. employees and non-qualified plans for various executive retirement and savings plans. 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 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 $5 million to our U.S. retirement plans in the three-month periods ended March 31, 2011 and made no contributions for the same period in 2010. We made total contributions to the Canadian DC and qualified DB plans of $17 million during each of the three-month periods ended March 31, 2011 and 2010. We anticipate that we will make total contributions of approximately $20 million to the U.S. plans and approximately $75 million to the Canadian plans in 2011.

Qualified Pension Plans—Components of Net Periodic Pension Cost


	Three Months Ended March 31,
	2011			2010
	(in millions)
U.S.
Service cost benefit earned	$	3		$	3
Interest cost on projected benefit obligation		6			6
Expected return on plan assets		(8	)		(8	)
Amortization of loss		3			2

Net periodic pension cost	$	4		$	3

Canada
Service cost benefit earned	$	5		$	4
Interest cost on projected benefit obligation		12			11
Expected return on plan assets		(12	)		(11	)
Amortization of loss		6			4
Amortization of prior service costs		—			1

Net periodic pension cost	$	11		$	9

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


	Three Months Ended March 31,
	2011		2010
	(in millions)
Canada
Interest cost on projected benefit obligation	$	2	$	2

Net periodic pension cost	$	2	$	2

The U.S. non-qualified benefit plan had no net periodic pension cost recorded during the three-month periods ended March 31, 2011 or 2010.

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 March 31,
	2011			2010
	(in millions)
U.S.
Interest cost on accumulated post-retirement benefit obligation	$	3		$	3
Expected return on plan assets		(1	)		(1	)
Amortization of net transition liability		—			1

Net periodic other post-retirement benefit cost	$	2		$	3

Canada
Service cost benefit earned	$	1		$	1
Interest cost on accumulated post-retirement benefit obligation		2			1

Net periodic other post-retirement benefit cost	$	3		$	2

17. Consolidating Financial Information

Spectra Energy Corp has agreed to fully and unconditionally guarantee the payment of principal and interest under all series of notes outstanding under the Senior Indenture of Spectra Energy Capital, LLC (Spectra Capital), a wholly 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 wholly owned subsidiaries of Spectra Capital. This information should be read in conjunction with our accompanying Condensed Consolidated Financial Statements and notes thereto.

Spectra Energy Corp

Condensed Consolidating Statement of Operations

Three Months Ended March 31, 2011

(Unaudited)

(In millions)


	Spectra Energy Corp			Spectra Capital		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Total operating revenues	$	—		$	—	$	1,612	$	—		$	1,612
Total operating expenses		3			—		1,056		—			1,059
Gains on sales of other assets and other, net		—			—		4		—			4

Operating income (loss)		(3	)		—		560		—			557
Equity in earnings of unconsolidated affiliates		—			—		106		—			106
Equity in earnings of subsidiaries		359			510		—		(869	)		—
Other income and expenses, net		—			—		6		—			6
Interest expense		—			48		107		—			155

Earnings from continuing operations before income taxes		356			462		565		(869	)		514
Income tax expense (benefit) from continuing operations		(1	)		103		37		—			139

Income from continuing operations		357			359		528		(869	)		375
Income from discontinued operations, net of tax		—			—		7		—			7

Net income		357			359		535		(869	)		382
Net income—noncontrolling interests		—			—		25		—			25

Net income—controlling interests	$	357		$	359	$	510	$	(869	)	$	357

Spectra Energy Corp

Condensed Consolidating Statement of Operations

Three Months Ended March 31, 2010

(Unaudited)

(In millions)


	Spectra Energy Corp			Spectra Capital		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Total operating revenues	$	—		$	—	$	1,480	$	—		$	1,480
Total operating expenses		3			—		985		—			988

Operating income (loss)		(3	)		—		495		—			492
Equity in earnings of unconsolidated affiliates		—			—		122		—			122
Equity in earnings of subsidiaries		360			501		—		(861	)		—
Other income and expenses, net		—			2		2		—			4
Interest expense		—			50		109		—			159

Earnings from continuing operations before income taxes		357			453		510		(861	)		459
Income tax expense (benefit) from continuing operations		(1	)		93		5		—			97

Income from continuing operations		358			360		505		(861	)		362
Income from discontinued operations, net of tax		—			—		16		—			16

Net income		358			360		521		(861	)		378
Net income—noncontrolling interests		—			—		20		—			20

Net income—controlling interests	$	358		$	360	$	501	$	(861	)	$	358

Spectra Energy Corp

Condensed Consolidating Balance Sheet

March 31, 2011

(Unaudited)

(In millions)


	Spectra Energy Corp			Spectra Capital		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash and cash equivalents	$	—		$	6	$	134		$	—		$	140
Receivables (payables)—consolidated subsidiaries		(83	)		208		(125	)		—			—
Receivables (payables)—other		(8	)		2		1,022			—			1,016
Other current assets		61			34		266			—			361

Total current assets		(30	)		250		1,297			—			1,517
Investments in and loans to unconsolidated affiliates		—			74		1,987			—			2,061
Investments in consolidated subsidiaries		11,371			14,548		—			(25,919	)		—
Advances receivable (payable)—consolidated subsidiaries		(2,981	)		3,543		6			(568	)		—
Goodwill		—			—		4,396			—			4,396
Other assets		38			40		558			—			636
Property, plant and equipment, net		—			—		17,430			—			17,430
Regulatory assets and deferred debits		1			13		1,097			—			1,111

Total Assets	$	8,399		$	18,468	$	26,771		$	(26,487	)	$	27,151

Accounts payable—other	$	1		$	96	$	363		$	—		$	460
Short-term borrowings and commercial paper		—			1,196		27			(568	)		655
Accrued taxes payable (receivable)		(22	)		18		84			—			80
Current maturities of long-term debt		—			8		315			—			323
Other current liabilities		41			58		700			—			799

Total current liabilities		20			1,376		1,489			(568	)		2,317
Long-term debt		—			3,292		6,965			—			10,257
Deferred credits and other liabilities		161			2,429		2,828			—			5,418
Preferred stock of subsidiaries		—			—		258			—			258
Equity
Controlling interests		8,218			11,371		14,548			(25,919	)		8,218
Noncontrolling interests		—			—		683			—			683

Total equity		8,218			11,371		15,231			(25,919	)		8,901

Total Liabilities and Equity	$	8,399		$	18,468	$	26,771		$	(26,487	)	$	27,151

Spectra Energy Corp

Condensed Consolidating Balance Sheet

December 31, 2010

(Unaudited)

(In millions)


	Spectra Energy Corp			Spectra Capital		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash and cash equivalents	$	—		$	—	$	130		$	—		$	130
Receivables (payables)—consolidated subsidiaries		(46	)		208		(162	)		—			—
Receivables (payables)—other		(4	)		1		1,021			—			1,018
Other current assets		63			37		390			—			490

Total current assets		13			246		1,379			—			1,638
Investments in and loans to unconsolidated affiliates		—			74		1,959			—			2,033
Investments in consolidated subsidiaries		10,683			13,979		—			(24,662	)		—
Advances receivable (payable)—consolidated subsidiaries		(2,835	)		3,463		(57	)		(571	)		—
Goodwill		—			—		4,305			—			4,305
Other assets		43			45		577			—			665
Property, plant and equipment, net		—			—		16,980			—			16,980
Regulatory assets and deferred debits		—			13		1,052			—			1,065

Total Assets	$	7,904		$	17,820	$	26,195		$	(25,233	)	$	26,686

Accounts payable—other	$	1		$	76	$	292		$	—		$	369
Short-term borrowings and commercial paper		—			1,250		157			(571	)		836
Accrued taxes payable (receivable)		(145	)		99		105			—			59
Current maturities of long-term debt		—			8		307			—			315
Other current liabilities		76			67		801			—			944

Total current liabilities		(68	)		1,500		1,662			(571	)		2,523
Long-term debt		—			3,302		6,867			—			10,169
Deferred credits and other liabilities		163			2,335		2,751			—			5,249
Preferred stock of subsidiaries		—			—		258			—			258
Equity
Controlling interests		7,809			10,683		13,979			(24,662	)		7,809
Noncontrolling interests		—			—		678			—			678

Total equity		7,809			10,683		14,657			(24,662	)		8,487

Total Liabilities and Equity	$	7,904		$	17,820	$	26,195		$	(25,233	)	$	26,686

Spectra Energy Corp

Condensed Consolidating Statements of Cash Flows

Three Months Ended March 31, 2011

(Unaudited)

(In millions)


	Spectra Energy Corp			Spectra Capital			Non-Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	357		$	359		$	535		$	(869	)	$	382
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		—			—			178			—			178
Equity in earnings of unconsolidated affiliates		—			—			(106	)		—			(106	)
Equity in earnings of subsidiaries		(359	)		(510	)		—			869			—
Distributions received from unconsolidated affiliates		—			—			104			—			104
Other		(13	)		129			48			—			164

Net cash provided by (used in) operating activities		(15	)		(22	)		759			—			722

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		—			—			(329	)		—			(329	)
Investments in and loans to unconsolidated affiliates		—			—			(4	)		—			(4	)
Purchases of held-to-maturity securities		—			—			(214	)		—			(214	)
Proceeds from sales and maturities of held-to-maturity securities		—			—			186			—			186
Purchases of available-for-sale securities		—			—			(548	)		—			(548	)
Proceeds from sales and maturities of available-for-sale securities		—			—			576			—			576
Other		—			—			1			—			1

Net cash used in investing activities		—			—			(332	)		—			(332	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt		—			—			919			—			919
Payments for the redemption of long-term debt		—			—			(942	)		—			(942	)
Net decrease in short-term borrowings and commercial paper		—			(51	)		(131	)		—			(182	)
Distributions to noncontrolling interests		—			—			(23	)		—			(23	)
Dividends paid on common stock		(170	)		—			—			—			(170	)
Distributions and advances from (to) affiliates		168			79			(247	)		—			—
Other		17			—			(1	)		—			16

Net cash provided by (used in) financing activities		15			28			(425	)		—			(382	)

Effect of exchange rate changes on cash		—			—			2			—			2

Net increase in cash and cash equivalents		—			6			4			—			10
Cash and cash equivalents at beginning of period		—			—			130			—			130

Cash and cash equivalents at end of period	$	—		$	6		$	134		$	—		$	140

Spectra Energy Corp

Condensed Consolidating Statements of Cash Flows

Three Months Ended March 31, 2010

(Unaudited)

(In millions)


	Spectra Energy Corp			Spectra Capital			Non-Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	358		$	360		$	521		$	(861	)	$	378
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		—			—			165			—			165
Equity in earnings of unconsolidated affiliates		—			—			(122	)		—			(122	)
Equity in earnings of subsidiaries		(360	)		(501	)		—			861			—
Distributions received from unconsolidated affiliates		—			—			108			—			108
Other		(49	)		85			(95	)		—			(59	)

Net cash provided by (used in) operating activities		(51	)		(56	)		577			—			470

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		—			—			(176	)		—			(176	)
Investments in and loans to unconsolidated affiliates		—			—			(3	)		—			(3	)
Purchases of held-to-maturity securities		—			—			(148	)		—			(148	)
Proceeds from sales and maturities of held-to-maturity securities		—			—			126			—			126
Purchases of available-for-sale securities		—			—			(12	)		—			(12	)
Other		—			—			(8	)		—			(8	)

Net cash used in investing activities		—			—			(221	)		—			(221	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt		—			—			720			—			720
Payments for the redemption of long-term debt		—			—			(864	)		—			(864	)
Net increase in short-term borrowings and commercial paper		—			17			4			—			21
Distributions to noncontrolling interests		—			—			(21	)		—			(21	)
Dividends paid on common stock		(161	)		(3	)		—			3			(161	)
Distributions and advances from (to) affiliates		212			43			(252	)		(3	)		—
Other		—			—			3			—			3

Net cash provided by (used in) financing activities		51			57			(410	)		—			(302	)

Effect of exchange rate changes on cash		—			—			—			—			—

Net increase (decrease) in cash and cash equivalents		—			1			(54	)		—			(53	)
Cash and cash equivalents at beginning of period		—			—			166			—			166

Cash and cash equivalents at end of period	$	—		$	1		$	112		$	—		$	113

18. New Accounting Pronouncements

There were no significant accounting pronouncements adopted during the three months ended March 31, 2011 that had a material impact on our consolidated results of operations, financial position or cash flows.

Item 2.

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

INTRODUCTION

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

Executive Overview

During the first quarter of 2011, our fee-based businesses at U.S. Transmission, Distribution and Western Canada Transmission & Processing generated increased earnings and cash flows by meeting the needs of our customers and from successful expansion projects previously placed in service.

A dividend of $0.26 per common share, representing a 4% increase from the previous dividend level, was declared on January 3, 2011 and was paid on March 14, 2011. We anticipate our dividend payout ratio over time to be consistent with our targeted payout ratio, which is up to 65% of estimated annual net income from controlling interests per share of common stock.

For the three months ended March 31, 2011 and 2010, we reported net income from controlling interests of $357 million and $358 million, respectively. Earnings from expansion projects at U.S. Transmission and Western Canada Transmission & Processing, a stronger Canadian dollar and colder weather at Distribution were offset by lower earnings at Field Services and higher income tax expense.

The highlights for the three months ended March 31, 2011 include:

•

U.S. Transmission’s earnings benefited from the successful execution of planned expansion projects,

•

Distribution’s earnings increased mainly as a result of higher customer usage of natural gas due to colder weather and a stronger Canadian dollar,

•

Western Canada Transmission & Processing earnings increased mainly as a result of higher gathering and processing earnings from expansions and a stronger Canadian dollar, and

•

Field Services earnings decreased as a result of higher planned operating expenses and the negative effects of severe weather on higher-margin production areas, partially offset by higher commodity prices and lower interest expense.

In the first quarter of 2011, we had $333 million of capital and investment expenditures. We continue to project approximately $2.1 billion of capital and investment expenditures for the full year, including expansion capital of approximately $1.4 billion. 2011 expansion projects are on track and we expect that our capital spending will be significantly higher throughout the remainder of the year.

As of March 31, 2011, we have access to approximately $1.7 billion available under our credit facilities and expect to continue to utilize commercial paper and revolving lines of credit, as needed, to complement our ongoing cash flows to fund liquidity needs through the remainder of 2011. Financing activities for the remainder of 2011 will include the refinancing of debt maturities of approximately $250 million and the issuance of commercial paper under our revolving credit facilities. We also anticipate accessing the markets for other long-term financing to fund our ongoing capital expansion program.

RESULTS OF OPERATIONS


	Three Months Ended March 31,
	2011		2010
	(in millions)
Operating revenues	$	1,612	$	1,480
Operating expenses		1,059		988
Gains on sales of other assets and other, net		4		—

Operating income		557		492
Other income and expenses		112		126
Interest expense		155		159

Earnings from continuing operations before income taxes		514		459
Income tax expense from continuing operations		139		97

Income from continuing operations		375		362
Income from discontinued operations, net of tax		7		16

Net income		382		378
Net income—noncontrolling interests		25		20

Net income—controlling interests	$	357	$	358

Operating Revenues. The $132 million, or 9%, increase was driven mainly by:

•

an increase in customer usage of natural gas due to weather that was more than 13% colder than the first quarter of 2010 at Distribution,

•

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

•

revenues from the acquisition of Bobcat Gas Storage (Bobcat) and expansion projects at U.S. Transmission and Western Canada Transmission & Processing, and

•

higher NGL sales volumes from the Empress operations at Western Canada Transmission & Processing, partially offset by

•

lower natural gas prices passed through to customers at Distribution.

Operating Expenses. The $71 million, or 7%, increase was driven mainly by:

•

higher volumes of natural gas sold as a result of weather that was more than 13% colder than the first quarter 2010 and growth in the number of customers at Distribution,

•

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

•

higher volumes of natural gas purchases attributable to higher demand for NGL products and higher prices of natural gas purchased caused primarily by higher extraction premiums at the Empress operations at Western Canada Transmission & Processing, partially offset by

•

lower natural gas prices passed through to customers at Distribution.

Operating Income. The $65 million increase was mainly driven by higher earnings from expansion projects at U.S. Transmission and Western Canada Transmission & Processing, an increase in customer usage of natural gas due to colder weather at Distribution and the effects of a stronger Canadian dollar.

Other Income and Expenses. The $14 million decrease was attributable to lower equity earnings from Field Services mainly due to higher planned operating expenses, unfavorable marketing results and the negative effects of severe weather, partially offset by higher commodity prices and lower interest expense and income tax expense.

Income Tax Expense from Continuing Operations. The $42 million increase was a result of higher earnings from continuing operations in the first quarter of 2011 and favorable tax audit settlements totaling $24 million in the first quarter of 2010. The effective tax rate for income from continuing operations was 27% in the first quarter of 2011 compared to 21% in the first quarter of 2010.

Income from Discontinued Operations, Net of Tax. The $9 million decrease was due to a favorable income tax adjustment related to previously discontinued operations in 2010, partially offset by higher income from propane deliveries in 2011.

Net Income—Noncontrolling Interests. The $5 million increase was primarily driven by higher earnings from Spectra Energy Partners, primarily as a result of their acquisition of an additional 24.5% in Gulfstream Natural Gas System, LLC (Gulfstream) in the fourth quarter of 2010.

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

Segment Results

We evaluate segment performance based on EBIT from continuing operations less noncontrolling interests related to those earnings. On a segment basis, EBIT 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 March 31,
	2011			2010
	(in millions)
U.S. Transmission	$	279		$	247
Distribution		167			146
Western Canada Transmission & Processing		141			119
Field Services		81			99

Total reportable segment EBIT		668			611
Other		(24	)		(14	)

Total reportable segment and other EBIT		644			597
Interest expense		155			159
Interest income and other (a)		25			21

Earnings from continuing operations before income taxes	$	514		$	459

(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-wholly 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.

U.S. Transmission


	Three Months Ended March 31,
	2011		2010		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	483	$	457	$	26
Operating expenses
Operating, maintenance and other		146		152		(6	)
Depreciation and amortization		67		64		3
Gains on sales of other assets and other, net		4		—		4

Operating income		274		241		33
Other income and expenses		31		26		5
Noncontrolling interests		26		20		6

EBIT	$	279	$	247	$	32

Proportional throughput, TBtu (a)		804		818		(14	)

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

Operating Revenues. The $26 million increase was driven by:

•

a $34 million increase from expansion projects and the acquisition of Bobcat in August 2010, partially offset by

•

a $7 million decrease in recoveries of electric power and other costs passed through to customers, and

•

a $4 million decrease in processing revenues associated with pipeline operations caused by lower volumes.

Operating, Maintenance and Other. The $6 million decrease was driven by:

•

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

•

a $7 million decrease in operating expenses due to timing and miscellaneous adjustments, partially offset by

•

a $6 million increase from the acquisition of Bobcat and expansion projects.

Other Income and Expenses. The $5 million increase was primarily a result of higher allowance for funds used during construction-equity (AFUDC-equity) in 2011 as a result of higher capital spending.

Noncontrolling Interests. The $6 million increase was primarily driven by higher earnings from Spectra Energy Partners, primarily as a result of their acquisition of an additional 24.5% in Gulfstream in the fourth quarter 2010.

EBIT. The $32 million increase was mainly due to higher earnings from expansion projects.

Distribution


	Three Months Ended March 31,
	2011		2010		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	696	$	668	$	28
Operating expenses
Natural gas purchased		369		371		(2	)
Operating, maintenance and other		107		103		4
Depreciation and amortization		53		48		5

EBIT	$	167	$	146	$	21

Number of customers, thousands		1,345		1,328		17
Heating degree days, Fahrenheit		3,772		3,321		451
Pipeline throughput, TBtu		331		304		27
Canadian dollar exchange rate, average		0.99		1.04		(0.05	)

Operating Revenues. The $28 million increase was driven mainly by:

•

a $77 million increase in customer usage of natural gas due to weather that was more than 13% colder than the first quarter 2010,

•

a $37 million increase resulting from a stronger Canadian dollar, and

•

a $12 million increase from growth in the number of customers, partially offset by

•

a $97 million decrease primarily due to lower natural gas prices passed through to customers. Prices charged to customers are based on the 12 month New York Mercantile Exchange (NYMEX) forecast.

Natural Gas Purchased. The $2 million decrease was driven mainly by:

•

a $98 million decrease primarily from lower natural gas prices passed through to customers, mostly offset by

•

a $64 million increase due to higher volumes of natural gas sold as a result of weather that was more than 13% colder than the first quarter of 2010,

•

a $19 million increase resulting from a stronger Canadian dollar, and

•

a $10 million increase due to growth in the number of customers.

Operating, Maintenance and Other. The $4 million increase was driven primarily by a stronger Canadian dollar.

Depreciation and Amortization. The $5 million increase was driven primarily by a stronger Canadian dollar.

EBIT. The $21 million increase was mainly a result of higher usage due to colder weather, a stronger Canadian dollar and growth in the number of customers.

Western Canada Transmission & Processing


	Three Months Ended March 31,
	2011		2010		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	439	$	355	$	84
Operating expenses
Natural gas and petroleum products purchased		122		81		41
Operating, maintenance and other		133		115		18
Depreciation and amortization		46		42		4

Operating income		138		117		21
Other income and expenses		3		2		1

EBIT	$	141	$	119	$	22

Pipeline throughput, TBtu		183		150		33
Volumes processed, TBtu		176		163		13
Empress inlet volumes, TBtu		181		187		(6	)
Canadian dollar exchange rate, average		0.99		1.04		(0.05	)

Operating Revenues. The $84 million increase was driven by:

•

a $28 million increase due to higher NGL sales volumes associated with the Empress operations resulting from higher demand for NGL products caused in part by colder weather,

•

a $23 million increase as a result of a stronger Canadian dollar,

•

an $18 million increase in gathering and processing revenues due to contracted volumes from expansions associated with non-conventional supply discoveries in the Fort Nelson area, and

•

a $7 million increase from recovery of carbon and other non-income tax expense from customers.

Natural Gas and Petroleum Products Purchased. The $41 million increase was driven by:

•

an $18 million increase due primarily to higher volumes at the Empress operations resulting from higher demand for NGL products caused in part by colder weather,

•

a $16 million increase as a result of higher prices of natural gas purchased for the Empress facility caused primarily by higher extraction premiums, and

•

a $7 million increase due to a stronger Canadian dollar.

Operating, Maintenance and Other. The $18 million increase was driven by:

•

a $7 million increase due to a stronger Canadian dollar, and

•

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

Depreciation and Amortization. The $4 million increase was driven mainly by a stronger Canadian dollar, expansion projects placed in service and maintenance capital incurred.

EBIT. The $22 million increase was driven mainly by higher gathering and processing earnings from expansions and a stronger Canadian dollar.

Field Services


	Three Months Ended March 31,
	2011		2010		Increase (Decrease)
	(in millions, except where noted)
Equity in earnings of unconsolidated affiliates	$	81	$	99	$	(18	)

EBIT	$	81	$	99	$	(18	)

Natural gas gathered and processed/transported, TBtu/d (a,b)		6.7		6.7		—
NGL production, MBbl/d (a,c)		358		353		5
Average natural gas price per MMBtu (d)	$	4.11	$	5.30	$	(1.19	)
Average NGL price per gallon (e)	$	1.13	$	1.09	$	0.04
Average crude oil price per barrel (f)	$	94.10	$	78.72	$	15.38

(a)	Reflects 100% of volumes.

(b)	Trillion British thermal units per day.

(c)	Thousand barrels per day.

(d)	Million British thermal units. Average price based on NYMEX Henry Hub.

(e)	Does not reflect results of commodity hedges.

(f)	Average price based on NYMEX calendar month.

EBIT. Lower equity earnings of $18 million were mainly the result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:

•

a $20 million decrease due to higher planned operating expenses largely resulting from DCP Partners’ growth from acquisitions, increased repairs and timing of maintenance costs between periods and increased benefits costs,

•

an $11 million decrease in gathering and processing margins primarily attributable to lower volumes and recoveries across higher-margin regions due to the impact of severe weather which reduced production and lowered margins,

•

a $15 million decrease due to lower results from NGL trading and gas marketing attributable to a favorable derivative adjustment in 2010, and

•

a $5 million decrease in earnings from DCP Partners primarily as a result of higher mark-to-market losses on derivative instruments used to protect distributable cash flows, partially offset by

•

an $11 million decrease in income tax expense related to the de-recognition of certain deferred tax assets in the 2010 period,

•

a $9 million increase from commodity-sensitive processing arrangements due to increased NGL and crude oil prices, net of decreased natural gas prices,

•

a $6 million decrease in interest expense, and

•

a $5 million increase in gains associated with the issuance of partnership units by DCP Partners in 2011 compared to the same period in 2010.

Other


	Three Months Ended March 31,
	2011			2010			Increase (Decrease)
	(in millions)
Operating revenues	$	17		$	13		$	4
Operating expenses		39			24			15

Operating loss		(22	)		(11	)		(11	)
Other income and expenses		(2	)		(3	)		1

EBIT	$	(24	)	$	(14	)	$	(10	)

EBIT. The $10 million decrease in EBIT reflects higher corporate costs, including employee and retiree benefit costs.

LIQUIDITY AND CAPITAL RESOURCES

Net working capital was negative $800 million as of March 31, 2011, which included short-term borrowings and commercial paper totaling $655 million and current maturities of long-term debt of $323 million. We will rely primarily 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. We also have access to four revolving credit facilities, with available combined capacities of approximately $1.7 billion at March 31, 2011. With the exception of the Spectra Energy Partners facility which is used for bank borrowings, 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 our short-term working capital fluctuations. At Spectra Capital and Westcoast, we primarily use commercial paper for temporary funding of our 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 11 of Notes to Condensed Consolidated Financial Statements for a discussion of available credit facilities and Financing Cash Flows and Liquidity for a discussion of effective shelf registrations.

Operating Cash Flows

Net cash provided by operating activities increased $252 million to $722 million for the three months ended March 31, 2011 compared to the same period in 2010, driven mainly by:

•

lower refunds to Union Gas customers in the first quarter of 2011 for gas purchases costs collected in 2010 compared to refunds in 2010 for collections in 2009, and

•

lower net tax payments in 2011 primarily as a result of the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 which deferred a significant amount of tax payments to future periods.

Investing Cash Flows

Cash flows used in investing activities increased $111 million to $332 million in the first three months of 2011 compared to the same period in 2010. This change was driven primarily by higher capital and investment expenditures in 2011 from capital expansion projects in western Canada and the northeastern United States.


	Three Months Ended March 31,
	2011		2010
	(in millions)
Capital and Investment Expenditures
U.S. Transmission	$	132	$	73
Distribution		52		32
Western Canada Transmission & Processing		140		68
Other		9		6

Total	$	333	$	179

Capital and investment expenditures for the three months ended March 31, 2011 consisted of $197 million for expansion projects and $136 million for maintenance and other projects.

We project 2011 capital and investment expenditures of approximately $2.1 billion, consisting of approximately $1.0 billion for U.S. Transmission, $0.3 billion for Distribution and $0.8 billion for Western Canada Transmission & Processing. Total projected 2011 capital and investment expenditures include approximately $1.4 billion of expansion capital expenditures and $0.7 billion for maintenance and upgrades of existing plants, pipelines and infrastructure to serve growth. We continue to assess short and long-term market requirements and will adjust our capital plans as required.

Financing Cash Flows and Liquidity

Net cash used in financing activities totaled $382 million in the first three months of 2011 compared to $302 million used in financing activities in the first three months of 2010. This change was driven mainly by:

•

a $182 million decrease in short-term borrowings and commercial paper outstanding in 2011 compared to a $21 million increase in the 2010 period, partially offset by

•

$121 million of higher net payments for the redemption of long-term debt in 2010.

Available Credit Facilities and Restrictive Debt Covenants. See Note 11 of Notes to Condensed Consolidated Financial Statements for a discussion of available credit facilities and related financial and other covenants. In May 2011, Westcoast entered into a new 300 million Canadian dollar credit facility that expires in May 2015, which replaced its 200 million Canadian dollar credit facility that was scheduled to expire in June 2011.

The terms of our Spectra Capital credit agreement require our consolidated debt-to-total-capitalization ratio to be 65% or lower. As of March 31, 2011, this ratio was 55%. 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 March 31, 2011, it is unlikely that a material adverse effect would occur as a result of a weakened Canadian dollar.

Credit Ratings

Standard
and
Poor’s

Moody’s
Investor
Service

Fitch
Ratings

DBRS

As of March 31, 2011

Spectra Capital (a)

BBB

Baa2

BBB

n/a

Texas Eastern Transmission, LP (a)

BBB+

Baa1

BBB+

n/a

Westcoast (a)

BBB+

n/a

A (low)

Union Gas (a)

BBB+

n/a

Maritimes & Northeast Pipeline, L.L.C. (a)

BBB

Baa3

n/a

M&N LP (b)

A2/A3

n/a

(a)	Represents senior unsecured credit rating.

(b)	Represents senior secured credit rating. The A2 rating applies to M&N LP’s 6.9% notes due 2019 and the A3 rating applies to its 4.34% notes due 2019.

n/a	Indicates not applicable.

The above credit ratings are dependent upon, among other factors, the ability to generate sufficient cash to fund capital and investment expenditures, our results of operations, market conditions and other factors. Our credit ratings could impact our ability to raise capital in the future, impact the cost of our capital and, as a result, have an impact on our liquidity.

Dividends. We currently anticipate an average dividend payout ratio over time of approximately 65% of estimated annual net income from controlling interests per share of common stock. The actual payout ratio, however, may vary from year to year depending on earnings levels. We expect to continue our policy of paying regular cash dividends. The declaration and payment of dividends are subject to the sole discretion of our Board of Directors and will depend upon many factors, including the financial condition, earnings and capital requirements of our operating subsidiaries, covenants associated with certain debt obligations, legal requirements, regulatory constraints and other factors deemed relevant by our Board of Directors. A dividend of $0.26 per common share was declared on April 18, 2011 and will be paid on June 13, 2011.

Other Financing Matters. Spectra Energy Corp and Spectra Capital have an effective shelf registration statement on file with the SEC to register the issuance of unspecified amounts of various equity and debt securities, respectively. Spectra Energy Partners has an effective shelf registration statement on file with the SEC to register the issuance of limited partner common units and various debt securities up to $1.1 billion in aggregate. In addition, as of March 31, 2011, certain of our subsidiaries in Canada have 1.8 billion Canadian dollars (approximately $1.8 billion) available for issuance in the Canadian market under debt shelf prospectuses that expire in October 2012.

OTHER ISSUES

Pipeline Safety Laws and Regulations. Laws, regulations and policies regarding pipeline safety may be enacted or changed in the future as a result of various pipeline incidents in 2010 on systems unrelated to ours. Consistent with our “advisor of choice” business strategy, we are engaged with policy makers to ensure that the importance of pipeline operations and the delivery of natural gas in interstate commerce is taken into consideration in any such policy development. See Item 1A. Risk Factors for further discussion.

New Accounting Pronouncements. See Note 18 of Notes to Condensed Consolidated Financial Statements for discussion.

Item 3.

Quantitative and Qualitative Disclosures about Market Risk.

Our exposure to market risk is described in Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2010. 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 March 31, 2011, 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 March 31, 2011 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings.

For information regarding material legal proceedings, including regulatory and environmental matters, see Notes 3 and 14 of Notes to Condensed Consolidated Financial Statements, which information is incorporated by reference into this Part II.

Item 1A.

Risk Factors.

In addition to the other information set forth in this report, careful consideration should be given to the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2010, which could materially affect our financial condition or future results. Other than the risk factor below, there have been no material changes to those risk factors.

We are subject to pipeline safety laws and regulations, compliance with which can require significant capital expenditures, can increase our cost of operations and may affect or limit our business plans.

Our interstate pipeline operations are subject to pipeline safety regulation administered by the Pipeline and Hazardous Materials Safety Administration (the PHMSA) of the U.S. Department of Transportation. These laws and regulations require us to comply with a significant set of requirements for the design, construction, maintenance and operation of our interstate pipelines. These regulations, among other things, include requirements to monitor and maintain the integrity of our pipelines. The regulations determine the pressures at which our pipelines can operate.

In 2010, serious pipeline incidents on systems unrelated to ours focused the attention of Congress and the public on pipeline safety. Legislative proposals have been introduced in Congress that would strengthen PHMSA’s enforcement and penalty authority, and expand the scope of its oversight. PHMSA has initiated an evaluation of its existing regulations and appears to be considering substantial revisions in its regulations. PHMSA also has issued guidance that states it will focus near-term enforcement efforts on recordkeeping and integrity management, following urgent National Transportation Safety Board recommendations related to pipeline pressure and recordkeeping. Because it is uncertain what legislation or regulatory changes will be enacted, we cannot determine the impact that such legislation or regulatory changes may have on our operations or financial condition at this time. Pipeline failures or failure to comply with applicable regulations could result in reduction of allowable operating pressures as authorized by the PHMSA, which would reduce available capacity on our pipelines. Should any of these risks materialize, it could have a material adverse effect on our operations, earnings, financial condition and cash flows.

Item 6.

Exhibits.

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

•

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

•

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

•

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

•

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

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

(a) Exhibits


Exhibit Number

+10.1		Spectra Energy Corp 2007 Long-Term Incentive Plan, as amended and restated (filed as Exhibit No. 10.1 to Form 8-K of Spectra Energy Corp on April 22, 2011).

+10.2		Spectra Energy Corp Executive Short-Term Incentive Plan, as amended and restated (filed as Exhibit No. 10.2 to Form 8-K of Spectra Energy Corp on April 22, 2011).

+*10.3		Form of Phantom Stock Award Agreement (2011) pursuant to the Spectra Energy Corp 2007 Long-Term Incentive Plan.

+*10.4		Form of Performance Award Agreement (cash) (2011) pursuant to the Spectra Energy Corp 2007 Long-Term Incentive Plan.

+*10.5		Form of Performance Award Agreement (stock) (2011) pursuant to the Spectra Energy Corp 2007 Long-Term Incentive Plan.

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

*31.2		Certification of the Chief Financial Officer 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.

+	Management contract or compensatory plan or arrangement.

*	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: May 9, 2011				/s/ GREGORY L. EBEL
				Gregory L. Ebel
				President and Chief Executive Officer

Date: May 9, 2011				/s/ J. PATRICK REDDY
				J. Patrick Reddy
				Chief Financial Officer