Edgar Filing: Spectra Energy Corp.

Form 10-Q for quarterly period ended March 31, 2010

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, 2010

¨	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 April 30, 2010: 647,987,459

SPECTRA ENERGY CORP

FORM 10-Q FOR THE QUARTER ENDED

March 31, 2010

INDEX


		Page
PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)	4

	Condensed Consolidated Statements of Operations for the three months ended March 31, 2010 and 2009	4

	Condensed Consolidated Balance Sheets as of March 31, 2010 and December 31, 2009	5

	Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2010 and 2009	7

	Condensed Consolidated Statements of Equity for the three months ended March 31, 2010 and 2009	8

	Notes to Condensed Consolidated Financial Statements	9

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	37

Item 4.	Controls and Procedures	37

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	38

Item 1A.	Risk Factors	38

Item 6.	Exhibits	38

	Signatures	39

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, 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;

•

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 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 the 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,
	2010		2009
Operating Revenues
Transportation, storage and processing of natural gas	$	710	$	608
Distribution of natural gas		584		635
Sales of natural gas liquids		146		109
Other		40		32

Total operating revenues		1,480		1,384

Operating Expenses
Natural gas and petroleum products purchased		452		505
Operating, maintenance and other		302		264
Depreciation and amortization		161		136
Property and other taxes		73		64

Total operating expenses		988		969

Gains on Sales of Other Assets and Other, net		—		10

Operating Income		492		425

Other Income and Expenses
Equity in earnings of unconsolidated affiliates		122		167
Other income and expenses, net		4		9

Total other income and expenses		126		176

Interest Expense		159		150

Earnings From Continuing Operations Before Income Taxes		459		451
Income Tax Expense from Continuing Operations		97		139

Income From Continuing Operations		362		312
Income From Discontinued Operations, net of tax		16		3

Net Income		378		315
Net Income—Noncontrolling Interests		20		17

Net Income—Controlling Interests	$	358	$	298


Common Stock Data
Weighted-average shares outstanding
Basic		648		628
Diluted		649		629
Earnings per share from continuing operations
Basic and Diluted	$	0.53	$	0.47
Earnings per share
Basic and Diluted	$	0.55	$	0.47
Dividends per share	$	0.25	$	0.25

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)


	March 31, 2010		December 31, 2009
ASSETS

Current Assets
Cash and cash equivalents	$	158	$	196
Receivables, net		772		778
Inventory		202		321
Other		137		134

Total current assets		1,269		1,429


Investments and Other Assets
Investments in and loans to unconsolidated affiliates		2,006		2,001
Goodwill		4,062		3,948
Other		416		407

Total investments and other assets		6,484		6,356


Property, Plant and Equipment
Cost		20,539		19,960
Less accumulated depreciation and amortization		4,833		4,613

Net property, plant and equipment		15,706		15,347

Regulatory Assets and Deferred Debits		988		947

Total Assets	$	24,447	$	24,079

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions, except per-share amounts)


	March 31, 2010		December 31, 2009
LIABILITIES AND EQUITY

Current Liabilities
Accounts payable	$	416	$	333
Short-term borrowings and commercial paper		185		162
Taxes accrued		118		139
Interest accrued		165		167
Current maturities of long-term debt		679		809
Other		640		885

Total current liabilities		2,203		2,495

Long-term Debt		9,088		8,947


Deferred Credits and Other Liabilities
Deferred income taxes		3,187		3,113
Regulatory and other		1,657		1,634

Total deferred credits and other liabilities		4,844		4,747

Commitments and Contingencies

Preferred Stock of Subsidiaries		258		225


Equity
Preferred stock, $0.001 par, 22 million shares authorized, no shares outstanding		—		—
Common stock, $0.001 par, 1 billion shares authorized, 648 million and 647 million shares outstanding at March 31, 2010 and December 31, 2009, respectively		1		1
Additional paid-in capital		4,684		4,700
Retained earnings		1,293		1,096
Accumulated other comprehensive income		1,519		1,328

Total controlling interests		7,497		7,125
Noncontrolling interests		557		540

Total equity		8,054		7,665

Total Liabilities and Equity	$	24,447	$	24,079

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)


	Three Months Ended March 31,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	378		$	315
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		165			140
Deferred income tax expense		22			104
Equity in earnings of unconsolidated affiliates		(122	)		(167	)
Distributions received from unconsolidated affiliates		108			16
Other		(81	)		148

Net cash provided by operating activities		470			556


CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(176	)		(147	)
Investments in and loans to unconsolidated affiliates		(3	)		(29	)
Proceeds from sales and maturities of available-for-sale securities		—			32
Distributions received from unconsolidated affiliates		—			4
Other		(27	)		(2	)

Net cash used in investing activities		(206	)		(142	)


CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt		720			693
Payments for the redemption of long-term debt		(864	)		(852	)
Net increase (decrease) in short-term borrowings and commercial paper		21			(530	)
Distributions to noncontrolling interests		(21	)		(9	)
Contributions from noncontrolling interests		2			2
Proceeds from the issuance of Spectra Energy common stock		—			448
Dividends paid on common stock		(161	)		(157	)
Other		1			—

Net cash used in financing activities		(302	)		(405	)

Effect of exchange rate changes on cash		—			(2	)

Net increase (decrease) in cash and cash equivalents		(38	)		7
Cash and cash equivalents at beginning of period		196			214

Cash and cash equivalents at end of period	$	158		$	221


Supplemental Disclosures
Property, plant and equipment accruals	$	35		$	28

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
	Common Stock		Additional Paid-in Capital			Retained Earnings			Foreign Currency Translation Adjustments			Other			Noncontrolling Interests			Total
December 31, 2009	$	1	$	4,700		$	1,096		$	1,686		$	(358	)	$	540		$	7,665
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	$	4,684		$	1,293		$	1,885		$	(366	)	$	557		$	8,054


December 31, 2008	$	1	$	4,104		$	899		$	881		$	(345	)	$	470		$	6,010
Net income		—		—			298			—			—			17			315
Foreign currency translation adjustments		—		—			—			(203	)		—			(2	)		(205	)
Unrealized mark-to-market net loss on hedges		—		—			—			—			(6	)		—			(6	)
Common stock issuance		—		448			—			—			—			—			448
Pension and benefits impact		—		—			—			—			4			—			4
Reclassification of deferred gain on sale of units of Spectra Energy Partners, LP		—		59			—			—			—			—			59
Dividends on common stock		—		—			(163	)		—			—			—			(163	)
Stock-based compensation		—		(1	)		—			—			—			—			(1	)
Distributions to noncontrolling interests		—		—			—			—			—			(12	)		(12	)
Contributions from noncontrolling interests		—		—			—			—			—			2			2
Other, net		—		11			—			—			—			2			13

March 31, 2009	$	1	$	4,621		$	1,034		$	678		$	(347	)	$	477		$	6,464

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, our majority-owned subsidiaries where we have control and those variable interest entities, if any, where we are the primary beneficiary. 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, 2009, and reflect all normal recurring adjustments that are, in our opinion, necessary to fairly present our results of operations and financial position. Amounts reported in the Condensed Consolidated Statements of Operations are not necessarily indicative of amounts expected for the respective annual periods due to the effects of seasonal temperature variations on energy consumption, primarily in our gas distribution operations, as well as changing commodity prices on certain of our processing operations and other factors.

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

2. Business Segments

We manage our business in four reportable segments: 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 Federal Energy Regulatory Commission’s (FERC’s) rules and regulations.

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 primarily 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 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.

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 Revenues (a)			Segment EBIT / Consolidated Earnings from Continuing Operations before Income Taxes (a)
	(in millions)
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

Three Months Ended March 31, 2009
U.S. Transmission	$	403	$	2		$	405		$	217
Distribution		708		—			708			152
Western Canada Transmission & Processing		271		—			271			81
Field Services		—		—			—			150

Total reportable segments		1,382		2			1,384			600
Other		2		10			12			(24	)
Eliminations		—		(12	)		(12	)		—
Interest expense		—		—			—			150
Interest income and other (b)		—		—			—			25

Total consolidated	$	1,384	$	—		$	1,384		$	451

(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, L.L.C. (M&N LLC). During 2009, M&N LLC filed a rate case with the FERC. The rate case included the impact of the Phase IV expansion facilities that went into service in January 2009 and resulted in lower recourse rates that went into effect in August 2009. On March 4, 2010, M&N LLC filed a settlement with FERC that resolves all issues in the case. On March 18, 2010, the settlement was certified by the Presiding Administrative Law Judge and on April 30, 2010 was approved by the FERC. Although the settlement will result in a reduction to M&N LLC’s recourse rates, the settlement will not have a material impact on consolidated results of operations.

4. Income Taxes

Income tax expense from continuing operations for the three months ended March 31, 2010 was $97 million, compared to $139 million reported in the same period in 2009. The effective tax rate for income from continuing operations for the three months ended March 31, 2010 was 21.1% as compared to 30.8% for the same period in 2009. The lower income tax expense and lower effective tax rate were primarily due to favorable tax audit settlements and lower Canadian tax rates.

The favorable tax audit settlements were related mainly to an administrative change by the Canadian federal government that resulted in cash tax refunds from historical tax years and a reduction to the deferred tax liability. We did not have any uncertain tax benefits associated with these settlements.

We recognized no material changes in unrecognized tax benefits during the first quarter of 2010. Although uncertain, we believe it is reasonably possible that prior to March 31, 2011 the total amount of unrecognized tax benefits could decrease by approximately $10 million, related to the expiration of statutes of limitation.

5. Discontinued Operations

Discontinued operations includes the net effects of a settlement arrangement related to prior liquefied natural gas transportation contracts and, during the first quarter of 2010, an immaterial income tax adjustment related to previously discontinued operations.

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


	Operating Revenues		Pre-tax Earnings		Income Tax Expense (Benefit)			Income From Discontinued Operations, Net of Tax
	(in millions)
Three Months Ended March 31, 2010
Other	$	91	$	5	$	(11	)	$	16

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

Three Months Ended March 31, 2009
Other	$	43	$	4	$	1		$	3

Total consolidated	$	43	$	4	$	1		$	3

6. Comprehensive Income

Components of comprehensive income are as follows:


	Three Months Ended March 31,
	2010			2009
	(in millions)
Net income	$	378		$	315
Other comprehensive income
Foreign currency translation adjustments		213			(205	)
Unrealized mark-to-market net loss on hedges		(14	)		(6	)
Pension and benefits impact		6			4

Total comprehensive income, net of tax		583			108
Less: comprehensive income—noncontrolling interests		34			15

Comprehensive income—controlling interests	$	549		$	93

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,
	2010		2009
	(in millions, except per-share amounts)
Income from continuing operations, net of tax—controlling interests	$	342	$	295
Income from discontinued operations, net of tax—controlling interests		16		3

Net income—controlling interests	$	358	$	298


Weighted-average common shares outstanding
Basic		648		628
Diluted		649		629

Basic and diluted earnings per common share
Continuing operations	$	0.53	$	0.47
Discontinued operations, net of tax		0.02		—

Total basic and diluted earnings per common share	$	0.55	$	0.47

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 10 million shares for the three months ended March 31, 2010 and 13 million shares for the three months ended March 31, 2009 were not included in the calculation of diluted EPS. These options and stock awards were not included 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. Inventory

Inventory consists primarily 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, 2010		December 31, 2009
	(in millions)
Natural gas	$	107	$	219
NGLs		24		21
Materials and supplies		71		81

Total inventory	$	202	$	321

9. Investments in and Loans to Unconsolidated Affiliates

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


	Three Months Ended March 31,
	2010		2009
	(in millions)
Operating revenues	$	3,115	$	1,927
Operating expenses		2,842		1,823
Operating income		273		104
Net income		196		43
Net income attributable to members’ interests		181		30

In January 2009, DCP Midstream reclassified to equity certain deferred gains on sales of common units in DCP Midstream Partners, LP (DCP Partners). Our proportionate 50% share, totaling $135 million, was recorded in Equity in Earnings of Unconsolidated Affiliates in the Condensed Consolidated Statement of Operations in the first quarter of 2009.

10. Debt and Credit Facilities

Available Credit Facilities and Restrictive Debt Covenants


	Expiration Date	Credit Facilities Capacity		Outstanding at March 31, 2010
	Expiration Date	Credit Facilities Capacity		Commercial Paper		Revolving Credit		Letters of Credit		Total
	(in millions)
Spectra Energy Capital, LLC (a)
Multi-year syndicated	2012	$	1,500	$	59	$	—	$	12	$	71
Westcoast Energy Inc. (b)
Multi-year syndicated	2011		197		91		—		—		91
364-day bilateral	2010		20		—		—		1		1
Union Gas (c)
Multi-year syndicated	2012		492		35		—		—		35
364-day bilateral	2010		15		—		—		4		4
Spectra Energy Partners, LP
Multi-year syndicated	2012		500		—		240		—		240

Total		$	2,724	$	185	$	240	$	17	$	442

(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, 2010. Two credit facilities, totaling 220 million Canadian dollars, each contain a covenant that requires the debt-to-total capitalization ratio to not exceed 75%.

(c)

U.S. dollar equivalent at March 31, 2010. Two credit facilities, totaling 515 million Canadian dollars, each contain a covenant that requires the debt-to-total capitalization ratio to not exceed 75%. The multi-year syndicated facility contains 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 issuance of commercial paper, letters of credit and other borrowings reduces the amount 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, 2010, 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.

11. 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:


		March 31, 2010
Description	Condensed Consolidated Balance Sheet Caption	Total		Level 1		Level 2		Level 3
		(in millions)
Corporate debt securities	Cash and cash equivalents	$	52	$	—	$	52	$	—
Corporate debt securities	Short-term investments		12		12		—		—
Derivative assets—interest rate swaps	Investments and other assets—other		23		—		23		—
Money market funds	Investments and other assets—other		19		19		—		—

Total Assets		$	106	$	31	$	75	$	—

Derivative liabilities—interest rate swaps	Deferred credits and other liabilities— regulatory and other	$	17	$	—	$	17	$	—

Total Liabilities		$	17	$	—	$	17	$	—


		December 31, 2009
Description	Condensed Consolidated Balance Sheet Caption	Total		Level 1		Level 2		Level 3
		(in millions)
Money market funds	Cash and cash equivalents	$	14	$	14	$	—	$	—
Corporate debt securities	Cash and cash equivalents		50		—		50		—
Derivative assets—natural gas purchase contract	Investments and other assets—other		15		—		—		15
Derivative assets—interest rate swaps	Investments and other assets—other		18		—		18		—
Money market funds	Investments and other assets—other		25		25		—		—

Total Assets		$	122	$	39	$	68	$	15

Derivative liabilities—interest rate swaps	Deferred credits and other liabilities— regulatory and other	$	17	$	—	$	17	$	—

Total Liabilities		$	17	$	—	$	17	$	—

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:


	Short-Term Derivative Assets		Short-Term Derivative Liabilities		Long-Term Derivative Assets			Long-Term Derivative Liabilities
	(in millions)
Fair value at December 31, 2009	$	—	$	—	$	15		$	—
Total gains or losses (realized/unrealized):
Included in earnings		—		—		—			—
Included in Investments and Other Assets—Other		—		—		—			—
Included in other comprehensive income		—		—		(15	)		—

Fair value at March 31, 2010	$	—	$	—	$	—		$	—

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 held at March 31, 2010	$	—	$	—	$	—		$	—


	Short-Term Derivative Assets		Short-Term Derivative Liabilities		Long-Term Derivative Assets			Long-Term Derivative Liabilities
	(in millions)
Fair value at December 31, 2008	$	—	$	—	$	36		$	—
Total gains or losses (realized/unrealized):
Included in earnings		—		—		(1	)		—
Included in Investments and Other Assets—Other		—		—		(2	)		—
Included in other comprehensive income		—		—		(7	)		—

Fair value at March 31, 2009	$	—	$	—	$	26		$	—

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 held at March 31, 2009	$	—	$	—	$	(1	)	$	—

Level 1

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

Level 2 Valuation Techniques

Fair values of our financial instruments, primarily corporate debt securities that are actively traded in the secondary market, 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.

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. Estimates determined as of March 31, 2010 and December 31, 2009 are not necessarily indicative of the amounts we could have realized in current markets.


	March 31, 2010				December 31, 2009
	Book Value		Approximate Fair Value		Book Value		Approximate Fair Value
	(in millions)
Long-term receivables	$	118	$	121	$	116	$	118
Long-term debt, including current maturities		9,767		10,856		9,756		10,690

The fair values of long-term debt consider the terms of the related debt absent the impacts of derivative/hedging activities. The book values 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 value 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 2010 and 2009 periods, there were no adjustments to assets and liabilities measured at fair value on a nonrecurring basis.

12. 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 $16 million at both March 31, 2010 and December 31, 2009. 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

Duke Energy Retirement Cash Balance Plan. A class action lawsuit was filed in federal court in South Carolina in 2006 against Duke Energy Corporation (Duke Energy) and the Duke Energy Retirement Cash Balance Plan. Various causes of action were alleged in the class action lawsuit, including violations of the Employee Retirement Income Security Act of 1974 (ERISA) and the Age Discrimination in Employment Act. These allegations arise out of the conversion of the Duke Power Company Employees’ Retirement Plan into the Duke Power Company Retirement Cash Balance Plan. The plaintiffs seek to represent present and former participants in the Duke Energy Retirement Cash Balance Plan. This group is estimated to include approximately 36,000 persons. Duke Energy filed its answer in March 2006, and various motions were thereafter filed by the parties, including plaintiffs’ motion to certify a class, Duke Energy’s motion to dismiss, and cross motions for summary judgment filed by both the plaintiffs and Duke Energy. The Court issued a series of rulings in June 2008 denying the plaintiffs’ class certification motion, dismissing certain of the causes of action originally filed by plaintiffs and allowing other causes of action to proceed. As a result of these rulings, the plaintiffs re-filed a new Amended Class Action Complaint in June 2008 asserting and re-pleading the claims which the Court is allowing to proceed. Duke Energy filed a motion to dismiss in July 2008 requesting the dismissal of plaintiffs’ breach of fiduciary claims. Plaintiffs filed a new motion to certify a class action in August 2008 and Duke Energy filed a response to this motion. The Court issued an Order on March 31, 2009 denying Duke Energy’s motion to dismiss plaintiffs’ breach of fiduciary claims. A hearing on the issue of class certification of plaintiffs’ remaining claims was held on April 29, 2009. On September 4, 2009, the Court issued an Order granting class certification for plaintiffs’ remaining claims and denying certification of the plaintiffs’ breach of fiduciary claims. Both parties filed motions for summary judgment on April 1, 2010 with respect to the two claims that remain in the case and which were certified as class actions last year. Duke Energy also filed a motion for summary judgment on the plaintiffs’ breach of fiduciary claims which remain in the case but were denied class action status. Future activity in this case, including additional discovery activity, will be determined and scheduled after the Court considers and issues rulings on these new motions.

In connection with the spin-off from Duke Energy in January 2007, we agreed to share with Duke Energy any liabilities or damages associated with this matter that relate to our employees that may be members of a plaintiff class if one is certified. At mediation, plaintiffs quantified their claims as being in excess of $150 million. It is not possible to predict with certainty the damages, if any, that we might incur in connection with this matter. However, based upon our current estimate of individuals that could be included in any plaintiff class, we believe that the final disposition of this matter will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

Other Litigation and Legal Proceedings. We are involved in other legal, tax and regulatory proceedings in various forums arising in the ordinary course of business, including matters regarding contract and payment claims, some of which involve substantial monetary amounts. We have insurance coverage for certain of these losses should they be incurred. We believe that the final disposition of these proceedings will not have a material 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, 2010 or December 31, 2009 related to litigation.

Other Commitments and Contingencies

See Note 13 for a discussion of guarantees and indemnifications.

13. 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 honor our contingencies 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, 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, 2010 was approximately $421 million, which has been indemnified by Duke Energy, as discussed above. One of our outstanding performance guarantees expires in 2028. The remaining guarantees have no contractual expiration.

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. D/FD is one of the entities transferred to Duke Energy in connection with our spin-off from Duke Energy. 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 non-wholly owned entities and third-party entities as of March 31, 2010 was $64 million. Of these guarantees, $4 million expire in 2015 and the remaining have no contractual expiration.

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.

At March 31, 2010, 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.

14. Risk Management and Hedging Activities

We are exposed to the impact of market fluctuations in the prices of NGLs and natural gas purchased primarily as a result of 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.

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 hedges having a total notional amount of $940 million, we did not have any significant derivatives outstanding during the three months ended March 31, 2010.

15. Sale of Common Stock

In February 2009, we issued 32.2 million shares of our common stock and received net proceeds of $448 million. We used the net proceeds to repay commercial paper as it matured. Borrowings from the commercial paper were used primarily for capital expenditures and for other general corporate purposes.

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 DB and defined contribution (DC) retirement plans covering substantially all employees of our Canadian operations.

Our policy is to fund amounts for our U.S. qualified retirement plans on an actuarial basis to provide assets sufficient to meet benefits to be paid to plan participants. We did not make contributions to our U.S. retirement plans in the three-month periods ended March 31, 2010 or 2009. We are currently planning to make approximately $30 million of discretionary contributions to the U.S. plans during 2010.

Our policy is to fund our DB retirement plans in Canada on an actuarial basis and in accordance with Canadian pension standards legislation in order to accumulate assets sufficient to meet benefit obligations. Contributions to the DC retirement plan are determined in accordance with the terms of the plan. We made total contributions to the Canadian DC and qualified DB plans of $17 million and $10 million during the three-month periods ended March 31, 2010 and 2009, respectively. We anticipate that we will make total contributions of approximately $65 million to the Canadian plans in 2010.

Qualified Pension Plans—Components of Net Periodic Pension Cost


	U.S.						Canada
	Three Months Ended March 31,
	2010			2009			2010			2009
	(in millions)
Service cost benefit earned	$	3		$	2		$	4		$	3
Interest cost on projected benefit obligation		6			7			11			9
Expected return on plan assets		(8	)		(8	)		(11	)		(10	)
Amortization of loss		2			1			4			1
Amortization of prior service costs		—			—			1			—

Net periodic pension cost	$	3		$	2		$	9		$	3


Non-Qualified Pension Benefits Plans—Components of Net Periodic Pension Cost
	U.S.				Canada
	Three Months Ended March 31,
	2010		2009		2010		2009
	(in millions)
Interest cost on projected benefit obligation	$	—	$	—	$	2	$	1

Net periodic pension cost	$	—	$	—	$	2	$	1

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


	U.S.						Canada
	Three Months Ended March 31,
	2010			2009			2010		2009
	(in millions)
Service cost benefit earned	$	—		$	—		$	1	$	1
Interest cost on accumulated post-retirement benefit obligation		3			4			1		1
Expected return on plan assets		(1	)		(1	)		—		—
Amortization of net transition liability		1			1			—		—

Net periodic other post-retirement benefit cost	$	3		$	4		$	2	$	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, 2010

(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 Statement of Operations

Three Months Ended March 31, 2009

(In millions)


	Spectra Energy Corp			Spectra Capital			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Total operating revenues	$	—		$	—		$	1,384	$	—		$	1,384
Total operating expenses		12			1			956		—			969
Gains on sales of other assets and other, net		—			—			10		—			10

Operating income (loss)		(12	)		(1	)		438		—			425
Equity in earnings of unconsolidated affiliates		—			—			167		—			167
Equity in earnings of subsidiaries		306			466			—		(772	)		—
Other income and expenses, net		—			7			2		—			9
Interest expense		—			57			93		—			150

Earnings from continuing operations before income taxes		294			415			514		(772	)		451
Income tax expense (benefit) from continuing operations		(4	)		109			34		—			139

Income from continuing operations		298			306			480		(772	)		312
Income from discontinued operations, net of tax		—			—			3		—			3

Net income		298			306			483		(772	)		315
Net income—noncontrolling interests		—			—			17		—			17

Net income—controlling interests	$	298		$	306		$	466	$	(772	)	$	298

Spectra Energy Corp

Condensed Consolidating Balance Sheet

March 31, 2010

(In millions)


	Spectra Energy Corp			Spectra Capital		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash and cash equivalents	$	—		$	1	$	157		$	—		$	158
Receivables (payables)—consolidated subsidiaries		(75	)		248		(173	)		—			—
Receivables (payables)—other		(6	)		3		775			—			772
Other current assets		8			14		317			—			339

Total current assets		(73	)		266		1,076			—			1,269
Investments in and loans to unconsolidated affiliates		—			74		1,932			—			2,006
Investments in consolidated subsidiaries		9,905			13,164		—			(23,069	)		—
Advances receivable (payable)—consolidated subsidiaries		(2,190	)		2,484		52			(346	)		—
Goodwill		—			—		4,062			—			4,062
Other assets		32			35		349			—			416
Property, plant and equipment, net		—			—		15,706			—			15,706
Regulatory assets and deferred debits		1			15		972			—			988

Total Assets	$	7,675		$	16,038	$	24,149		$	(23,415	)	$	24,447


Accounts payable (receivable)—consolidated subsidiaries	$	—		$	41	$	(41	)	$	—		$	—
Accounts payable—other		1			110		305			—			416
Short-term borrowings and commercial paper		—			405		126			(346	)		185
Accrued taxes payable (receivable)		(31	)		89		60			—			118
Current maturities of long-term debt		—			9		670			—			679
Other current liabilities		40			52		713			—			805

Total current liabilities		10			706		1,833			(346	)		2,203
Long-term debt		—			3,288		5,800			—			9,088
Deferred credits and other liabilities		168			2,139		2,537			—			4,844
Preferred stock of subsidiaries		—			—		258			—			258
Equity
Controlling interests		7,497			9,905		13,164			(23,069	)		7,497
Noncontrolling interests		—			—		557			—			557

Total equity		7,497			9,905		13,721			(23,069	)		8,054

Total Liabilities and Equity	$	7,675		$	16,038	$	24,149		$	(23,415	)	$	24,447

Spectra Energy Corp

Condensed Consolidating Balance Sheet

December 31, 2009

(In millions)


	Spectra Energy Corp			Spectra Capital		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash and cash equivalents	$	—		$	—	$	196		$	—		$	196
Receivables (payables)—consolidated subsidiaries		(28	)		248		(220	)		—			—
Receivables (payables)—other		(4	)		2		780			—			778
Other current assets		6			6		443			—			455

Total current assets		(26	)		256		1,199			—			1,429
Investments in and loans to unconsolidated affiliates		—			74		1,927			—			2,001
Investments in consolidated subsidiaries		9,319			12,538		—			(21,857	)		—
Advances receivable (payable)—consolidated subsidiaries		(2,063	)		2,440		(30	)		(347	)		—
Goodwill		—			—		3,948			—			3,948
Other assets		38			30		339			—			407
Property, plant and equipment, net		—			—		15,347			—			15,347
Regulatory assets and deferred debits		1			15		931			—			947

Total Assets	$	7,269		$	15,353	$	23,661		$	(22,204	)	$	24,079


Accounts payable (receivable)—consolidated subsidiaries	$	—		$	41	$	(41	)	$	—		$	—
Accounts payable—other		1			93		239			—			333
Short-term borrowings and commercial paper		—			388		121			(347	)		162
Accrued taxes payable (receivable)		(93	)		54		178			—			139
Current maturities of long-term debt		—			9		800			—			809
Other current liabilities		64			64		924			—			1,052

Total current liabilities		(28	)		649		2,221			(347	)		2,495
Long-term debt		—			3,282		5,665			—			8,947
Deferred credits and other liabilities		172			2,103		2,472			—			4,747
Preferred stock of subsidiaries		—			—		225			—			225
Equity
Controlling interests		7,125			9,319		12,538			(21,857	)		7,125
Noncontrolling interests		—			—		540			—			540

Total equity		7,125			9,319		13,078			(21,857	)		7,665

Total Liabilities and Equity	$	7,269		$	15,353	$	23,661		$	(22,204	)	$	24,079

Spectra Energy Corp

Condensed Consolidating Statements of Cash Flows

Three Months Ended March 31, 2010

(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	)
Other		—			—			(27	)		—			(27	)

Net cash used in investing activities		—			—			(206	)		—			(206	)

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	)
Contributions from noncontrolling interests		—			—			2			—			2
Dividends paid on common stock		(161	)		(3	)		—			3			(161	)
Distributions and advances from (to) affiliates		212			43			(252	)		(3	)		—
Other		—			—			1			—			1

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			(39	)		—			(38	)
Cash and cash equivalents at beginning of period		—			—			196			—			196

Cash and cash equivalents at end of period	$	—		$	1		$	157		$	—		$	158

Spectra Energy Corp

Condensed Consolidating Statements of Cash Flows

Three Months Ended March 31, 2009

(In millions)


	Spectra Energy Corp			Spectra Capital			Non-Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	298		$	306		$	483		$	(772	)	$	315
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		—			—			140			—			140
Equity in earnings of unconsolidated affiliates		—			—			(167	)		—			(167	)
Equity in earnings of subsidiaries		(306	)		(466	)		—			772			—
Distributions received from unconsolidated affiliates		—			—			16			—			16
Other		(3	)		171			84			—			252

Net cash provided by (used in) operating activities		(11	)		11			556			—			556

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		—			—			(147	)		—			(147	)
Investments in and loans to unconsolidated affiliates		—			(7	)		(22	)		—			(29	)
Proceeds from sales and maturities of available-for-sale securities		—			—			32			—			32
Distributions received from unconsolidated affiliates		—			—			4			—			4
Other		—			—			(2	)		—			(2	)

Net cash used in investing activities		—			(7	)		(135	)		—			(142	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt		—			—			693			—			693
Payments for the redemption of long-term debt		—			(148	)		(704	)		—			(852	)
Net decrease in short-term borrowings and commercial paper		—			(363	)		(167	)		—			(530	)
Distributions to noncontrolling interests		—			—			(9	)		—			(9	)
Contributions from noncontrolling interests		—			—			2			—			2
Proceeds from the issuance of Spectra Energy common stock		448			—			—			—			448
Dividends paid on common stock		(157	)		(3	)		—			3			(157	)
Distributions and advances from (to) affiliates		(278	)		450			(169	)		(3	)		—
Other		(2	)		—			2			—			—

Net cash provided by (used in) financing activities		11			(64	)		(352	)		—			(405	)

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

Net increase (decrease) in cash and cash equivalents		—			(60	)		67			—			7
Cash and cash equivalents at beginning of period		—			60			154			—			214

Cash and cash equivalents at end of period	$	—		$	—		$	221		$	—		$	221

18. New Accounting Pronouncements

The following new accounting pronouncement was adopted during the three months ended March 31, 2010:

In June 2009, the Financial Accounting Standards Board issued an accounting standard which is intended to address (1) the effects on certain consolidation provisions as a result of the elimination of the concept of qualifying special-purpose entities and (2) constituent concerns about the application of certain consolidation provisions including those in which the accounting and disclosures do not always provide timely and useful information about an enterprise’s involvement in a variable interest entity. The adoption of the provisions of this standard on January 1, 2010 did not have any 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

In the first quarter of 2010, our fee-based businesses at U.S. Transmission and Western Canada Transmission & Processing performed well by meeting the needs of our customers and generating increased earnings and cash flows from successful expansion projects placed in service. Commodity prices have improved significantly compared to the same period in 2009 and have positively affected our earnings in the first quarter of 2010.

For the three months ended March 31, 2010 and 2009, we reported net income from controlling interests of $358 million and $298 million, respectively. The increase reflects the positive impact of NGL prices on earnings from Field Services and Western Canada Transmission & Processing, a stronger Canadian dollar, expansion projects placed in service in 2009 at U.S. Transmission and lower income tax expense. NGL prices are correlated to higher crude oil prices, which averaged $79 per barrel for the three months ended March 31, 2010 versus $43 per barrel during the same period in 2009. The increase in earnings was partially offset by the recognition of a $135 million deferred gain ($85 million after-tax) in the first quarter of 2009 associated with partnership units previously issued by DCP Partners.

The highlights for the three months ended March 31, 2010 include:

•

U.S. Transmission’s earnings increased primarily due to expansion projects placed in service in 2009,

•

Distribution results primarily reflect warmer weather in the first quarter of 2010 compared to the 2009 first quarter, partially offset by a stronger Canadian dollar,

•

Western Canada Transmission & Processing earnings increased primarily as a result of higher NGL gross margins at the Empress processing plant and higher gathering and processing revenues, as well as a stronger Canadian dollar, and

•

Field Services earnings benefited from higher commodity prices, but decreased overall as a result of a gain recognized in 2009 associated with partnership units issued by DCP Partners.

In the first quarter of 2010, we had $179 million of capital and investment expenditures. We continue to project approximately $1.6 billion of capital and investment expenditures for the full year, including expansion capital of approximately $1.0 billion. All expansion projects remain on track for scheduled in-service dates.

As of March 31, 2010, we have access to approximately $2.3 billion in credit facilities and expect to continue to utilize commercial paper and revolving lines of credit, as needed, to fund liquidity needs throughout 2010. Financing activities in 2010 will include the refinancing of debt maturities of approximately $700 million and the issuance of commercial paper under our revolving credit facilities. We may also access the capital markets for other long-term financing if conditions are favorable.

RESULTS OF OPERATIONS


	Three Months Ended March 31,
	2010		2009
	(in millions)
Operating revenues	$	1,480	$	1,384
Operating expenses		988		969
Gains on sales of other assets and other, net		—		10

Operating income		492		425
Other income and expenses		126		176
Interest expense		159		150

Earnings from continuing operations before income taxes		459		451
Income tax expense from continuing operations		97		139

Income from continuing operations		362		312
Income from discontinued operations, net of tax		16		3

Net income		378		315
Net income—noncontrolling interests		20		17

Net income—controlling interests	$	358	$	298

Operating Revenues. The $96 million, or 7%, increase was driven primarily by:

•

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

•

higher earnings from expansion projects placed in service in 2009 and Ozark Gas Transmission, L.L.C. and Ozark Gas Gathering, L.L.C. (collectively, Ozark) acquired in May 2009 at U.S. Transmission, partly offset by

•

lower natural gas prices passed through to customers and a decrease in customer usage of natural gas due to warmer weather at Distribution.

Operating Expenses. The $19 million, or 2%, increase was driven primarily by:

•

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

•

lower natural gas prices passed through to customers and lower volumes of natural gas sold due primarily to warmer weather, partially offset by higher employee benefits costs at Distribution.

Gains on Sales of Other Assets and Other, net. The $10 million decrease was due to a 2009 customer settlement resulting from the cancellation of a capital project.

Operating Income. The $67 million, or 16%, increase was driven primarily by a stronger Canadian dollar, higher NGL margins associated with the Empress operations at Western Canada Transmission & Processing and expansion projects placed in service in 2009 at U.S. Transmission, partially offset by a decrease in customer usage of natural gas due to warmer weather at Distribution.

Other Income and Expenses. The $50 million decrease was attributable to lower equity in earnings from Field Services, primarily reflecting a gain recognized in 2009 associated with partnership units previously issued by DCP Partners, substantially offset by higher commodity prices.

Income Tax Expense from Continuing Operations. The $42 million decrease includes benefits of $24 million related to favorable 2010 tax audit settlements. The effective tax rate was 21.1% in the first quarter of 2010 compared with 30.8% in the first quarter of 2009. The lower effective tax rate is primarily due to the favorable tax audit settlements and lower Canadian tax rates.

Income from Discontinued Operations, Net of Tax. The $13 million increase was due to an income tax adjustment related to previously discontinued operations.

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,
	2010			2009
	(in millions)
U.S. Transmission	$	247		$	217
Distribution		146			152
Western Canada Transmission & Processing		119			81
Field Services		99			150

Total reportable segment EBIT		611			600
Other		(14	)		(24	)

Total reportable segment and other EBIT		597			576
Interest expense		159			150
Interest income and other (a)		21			25

Earnings from continuing operations before income taxes	$	459		$	451

(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,
	2010		2009		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	457	$	405	$	52
Operating expenses
Operating, maintenance and other		152		143		9
Depreciation and amortization		64		59		5
Gains on sales of other assets and other, net		—		10		(10	)

Operating income		241		213		28
Other income and expenses		26		20		6
Noncontrolling interests		20		16		4

EBIT	$	247	$	217	$	30

Proportional throughput, TBtu (a)		818		713		105

(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 $52 million increase was driven primarily by:

•

a $21 million increase from expansion projects placed in service in 2009,

•

a $14 million increase in transportation and other revenues, primarily from Ozark acquired in May 2009,

•

an $8 million increase in processing revenues associated with pipeline operations resulting from higher prices, and

•

a $7 million increase in transportation and storage revenues from recoveries of electric power and other costs passed through to customers.

Operating, Maintenance and Other. The $9 million increase was driven primarily by:

•

a $7 million increase in operating costs from higher electric power and other costs passed through to customers,

•

a $6 million increase as a result of the Ozark operating costs, and

•

a $4 million increase in ad valorem taxes, partially offset by

•

a $10 million decrease in project development costs, reflecting a net benefit of $5 million in 2010 from the capitalization of previously expensed costs on northeast expansions compared to expensed project development costs of $5 million in 2009.

Depreciation and Amortization. The $5 million increase was primarily driven by expansion projects placed in service in 2009.

Gains on Sales of Other Assets and Other, Net. The 2009 amount of $10 million represents a customer settlement resulting from the cancellation of a capital project.

Other Income and Expenses. The $6 million increase was primarily a result of earnings from expansion projects on Gulfstream Natural Gas System, LLC and Steckman Ridge, LP that were placed in service in 2009.

EBIT. The $30 million increase was primarily due to higher earnings from expansion projects, lower project development costs and higher processing revenues, partially offset by a prior year customer settlement.

Distribution


	Three Months Ended March 31,
	2010		2009		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	668	$	708	$	(40	)
Operating expenses
Natural gas purchased		371		435		(64	)
Operating, maintenance and other		103		81		22
Depreciation and amortization		48		40		8

EBIT	$	146	$	152	$	(6	)

Number of customers, thousands		1,328		1,312		16
Heating degree days, Fahrenheit		3,321		3,698		(377	)
Pipeline throughput, TBtu		304		327		(23	)
Canadian dollar exchange rate, average		1.04		1.24		0.20

Operating Revenues. The $40 million decrease was driven primarily by:

•

a $113 million decrease from lower natural gas prices passed through to customers, and

•

a $31 million decrease in customer usage of natural gas due to weather that was more than 10% warmer than the same period in the prior year, partially offset by

•

a $107 million increase resulting from a stronger Canadian dollar.

Natural Gas Purchased. The $64 million decrease was driven primarily by:

•

a $113 million decrease from lower natural gas prices passed through to customers, and

•

a $15 million decrease due to lower volumes of natural gas sold as a result of weather that was more than 10% warmer than the same period in the prior year, partially offset by

•

a $59 million increase resulting from a stronger Canadian dollar.

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

•

a $17 million increase resulting from a stronger Canadian dollar, and

•

a $5 million increase related to higher employee benefits costs.

Depreciation and Amortization. The $8 million increase was driven primarily by a stronger Canadian dollar.

EBIT. The $6 million decrease was primarily a result of a decrease in customer usage of natural gas due to warmer weather and higher employee benefits costs, mostly offset by a stronger Canadian dollar.

Western Canada Transmission & Processing


	Three Months Ended March 31,
	2010		2009		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	355	$	271	$	84
Operating expenses
Natural gas and petroleum products purchased		81		71		10
Operating, maintenance and other		115		88		27
Depreciation and amortization		42		32		10

Operating income		117		80		37
Other income and expenses		2		1		1

EBIT	$	119	$	81	$	38

Pipeline throughput, TBtu		150		162		(12	)
Volumes processed, TBtu		163		167		(4	)
Empress inlet volumes, TBtu		187		211		(24	)
Canadian dollar exchange rate, average		1.04		1.24		0.20

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

•

a $58 million increase as a result of a stronger Canadian dollar,

•

a $26 million increase due to higher NGL product prices associated with the Empress operations, and

•

an $11 million increase resulting primarily from higher gathering and processing revenues due to higher contracted volumes from expansions, partially offset by

•

a $13 million decrease due to lower NGL sales volumes associated with the Empress operations.

Natural Gas and Petroleum Products Purchased. The $10 million increase was driven primarily by:

•

a $13 million increase caused by a stronger Canadian dollar, and

•

an $8 million increase as a result of higher prices of natural gas purchased for the Empress facility, partially offset by

•

an $11 million decrease due to lower production volumes associated with the Empress operations.

Operating, Maintenance and Other. The $27 million increase was driven primarily by:

•

an $18 million increase caused by a stronger Canadian dollar, and

•

a $9 million increase relating mainly to facilities maintenance, partially caused by timing of scheduled maintenance activities that were different from the prior year.

Depreciation and Amortization. The $10 million increase was driven primarily by a stronger Canadian dollar.

EBIT. The $38 million increase was driven primarily by a stronger Canadian dollar, higher NGL gross margins at the Empress operations, and higher gathering and processing revenues.

Field Services


	Three Months Ended March 31,
	2010		2009		Increase (Decrease)
	(in millions, except where noted)
Equity in earnings of unconsolidated affiliates	$	99	$	150	$	(51	)

EBIT	$	99	$	150	$	(51	)

Natural gas gathered and processed/transported, TBtu/d (a,b)		6.7		7.0		(0.3	)
NGL production, MBbl/d (a,c)		353		331		22
Average natural gas price per MMBtu (d)	$	5.30	$	4.89	$	0.41
Average NGL price per gallon (e)	$	1.09	$	0.57	$	0.52

(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.

EBIT. Lower equity earnings of $51 million were primarily the result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:

•

a $126 million decrease primarily as a result of a gain in 2009 associated with partnership units previously issued by DCP Partners of $135 million,

•

an $11 million decrease in gathering and processing margins due to lower volumes and efficiencies, primarily attributable to the impact of severe weather in 2010 that affected operations,

•

a $10 million decrease due to higher income tax expense primarily reflecting the de-recognition of certain deferred tax assets, and

•

a $3 million decrease due to higher net interest expense as a result of increased debt, partially offset by

•

a $90 million increase from commodity-sensitive processing arrangements due to increased commodity prices,

•

a $5 million increase due to lower operating and maintenance expenses as a result of a reduction of DCP Midstream’s ownership interest in an east Texas processing plant in the second quarter of 2009, and

•

a $4 million increase due to higher NGL trading and marketing gains and derivative timing.

Matters Affecting Future Field Services Results

In the near term, softening of natural gas prices, caused by increased supply, high inventory, reduced demand and the downturn in the economy, are causing a reduction in levels of drilling activity and associated natural gas throughput volumes in certain geographic areas. The impact of these factors will vary across Field Services’ broad geographic locations. Generally, drilling levels increased during the second half of 2009 and the first quarter of 2010; however, they decreased compared to their peak in 2008. Since the peak in 2008, DCP Midstream has experienced lower gas throughput volumes at certain of its natural gas assets due to reduced drilling levels. Throughput volumes could decline further should natural gas prices and drilling levels decline further. DCP Midstream’s long-term view is that as economic conditions improve, natural gas prices will return to a level that would support the relatively higher levels of natural gas-related drilling experienced in past years in the United States, as producers seek to capitalize on their leases and increase their level of natural gas production.

Other


	Three Months Ended March 31,
	2010			2009			Increase (Decrease)
	(in millions)
Operating revenues	$	13		$	12		$	1
Operating expenses		24			32			(8	)

Operating loss		(11	)		(20	)		9
Other income and expenses		(3	)		(4	)		1

EBIT	$	(14	)	$	(24	)	$	10

EBIT. The $10 million increase in EBIT reflects lower corporate costs related to employee benefits and payroll.

LIQUIDITY AND CAPITAL RESOURCES

We will rely primarily upon cash flows from operations and various financing transactions to fund our liquidity and capital requirements for the next 12 months, which may include issuances of short-term and long-term debt. See Note 10 of Notes to Condensed Consolidated Financial Statements and Financing Cash Flows and Liquidity for discussions of available credit facilities and effective shelf registrations. Net working capital was negative $934 million as of March 31, 2010, which included short-term borrowings and commercial paper totaling $185 million and current maturities of long-term debt of $679 million.

Operating Cash Flows

Net cash provided by operating activities decreased $86 million to $470 million for the three months ended March 31, 2010 compared to the same period in 2009, driven mainly by higher tax payments and refunds to customers in 2010, both of which relate to Union Gas gas purchase costs collected in 2009. These were partially offset by increased distributions from unconsolidated affiliates in 2010.

Investing Cash Flows

Cash flows used in investing activities increased $64 million to $206 million in the first three months of 2010 compared to the same period in 2009. This change was driven primarily by the 2009 liquidation of the remaining available-for-sale securities that were held as collateral for Spectra Energy Partners, LP’s term loan.


	Three Months Ended March 31,
	2010		2009
	(in millions)
Capital and Investment Expenditures
U.S. Transmission	$	73	$	99
Distribution		32		34
Western Canada Transmission & Processing		68		37
Other		6		6

Total	$	179	$	176

Capital and investment expenditures for the three months ended March 31, 2010 consisted of $113 million for expansion projects and $66 million for maintenance and other projects.

We continue to project 2010 capital and investment expenditures of approximately $1.6 billion, consisting of approximately $0.7 billion for U.S. Transmission, $0.3 billion for Distribution and $0.6 billion for Western Canada Transmission & Processing. Total projected 2010 capital and investment expenditures include approximately $1.0 billion of expansion capital expenditures and $0.6 billion for maintenance and upgrades of existing plants, pipelines and infrastructure to serve growth. We will 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 $302 million in the first three months of 2010 compared to $405 million in the first three months of 2009. This change was driven primarily by:

•

a $21 million increase in short-term borrowings in 2010 compared to a $530 million decrease in the 2009 period, partially offset by

•

proceeds of $448 million in 2009 from the issuance of Spectra Energy common stock.

Available Credit Facilities and Restrictive Debt Covenants. See Note 10 of Notes to Condensed Consolidated Financial Statements for a discussion of available credit facilities and related financial and other covenants.

The terms of our Spectra Capital credit agreement requires our consolidated debt-to-total-capitalization ratio to be 65% or lower. As of March 31, 2010, this ratio was 55%. Our equity and, as a result, this ratio, are sensitive to significant movement of the Canadian dollar relative to the U.S. dollar due to the significance of our Canadian operations.

Credit Ratings


	Standard and Poor’s	Moody’s Investor Service	Fitch Ratings	DBRS
As of April 30, 2010
Spectra Capital (a)	BBB	Baa2	BBB	n/a
Texas Eastern Transmission, LP (a)	BBB+	Baa1	BBB+	n/a
Westcoast (a)	BBB+	n/a	n/a	A(low)
Union Gas (a)	BBB+	n/a	n/a	A
Maritimes & Northeast Pipeline, L.L.C. (a)	BBB	Baa3	n/a	n/a
Maritimes & Northeast Pipeline Limited Partnership (b)	A	A2/A3	n/a	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, while maintaining the strength of the current balance sheet. These credit ratings could be negatively affected if, as a result of market conditions or other factors, these subsidiaries are unable to maintain the current balance sheet strength or if earnings or cash flow outlooks deteriorate materially.

Dividends. We currently anticipate an average dividend payout ratio over time of approximately 60-65% 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 $0.25 per common share was declared on April 26, 2010 and will be paid on June 14, 2010.

Other Financing Matters. Spectra Energy Corp and Spectra Capital have an automatic 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 $1.3 billion in aggregate. In addition, as of the date of this filing, certain of our subsidiaries in Canada have 800 million Canadian dollars (approximately $788 million) available under shelf registrations for issuances in the Canadian market, of which 400 million expires in August 2010 and 400 million expires in September 2010.

OTHER ISSUES

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, 2009. We believe the exposure to market risk has not changed materially at March 31, 2010.

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, 2010, and, based upon this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective.

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, 2010 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 12 of Notes to Condensed Consolidated Financial Statements.

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, 2009, which could materially affect our financial condition or future results. There were no changes to those risk factors at March 31, 2010.

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:

•

should not in all instances 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;

•

have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;

•

may apply standards of materiality in a way that is different from what may be viewed as material to you or other investors; 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 and are subject to more recent developments.

Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time. 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		Fourth Amendment, dated February 22, 2010, to the Spectra Energy Corp Directors’ Savings Plan.

*†10.2		Fourth Amendment, dated February 22, 2010, to the Spectra Energy Corp Executive Savings 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 Presentaion Linkbase.

*	Filed herewith.

†	Denotes management contract or compensatory plan or arrangement.

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

SIGNATURES

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


				SPECTRA ENERGY CORP

Date: May 7, 2010				/s/ GREGORY L. EBEL
				Gregory L. Ebel
				President and Chief Executive Officer

Date: May 7, 2010				/s/ J. PATRICK REDDY
				J. Patrick Reddy
				Chief Financial Officer

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