Edgar Filing: Spectra Energy Corp.

Form 10-Q for quarterly period ended March 31, 2009

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, 2009

¨	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 ¨ 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, 2009: 644,974,494

SPECTRA ENERGY CORP

FORM 10-Q FOR THE QUARTER ENDED

March 31, 2009

INDEX


		Page
PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)	4

	Condensed Consolidated Statements of Operations for the three months ended March 31, 2009 and 2008	4

	Condensed Consolidated Balance Sheets as of March 31, 2009 and December 31, 2008	5

	Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2009 and 2008	7

	Condensed Consolidated Statements of Stockholders’ Equity for the three months ended March 31, 2009 and 2008	8

	Notes to Condensed Consolidated Financial Statements	9

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	41

Item 4.	Controls and Procedures	41

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	42

Item 1A.	Risk Factors	42

Item 4.	Submission of Matters to a Vote of Security Holders	42

Item 6.	Exhibits	42

	Signatures	43

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,
	2009		2008
Operating Revenues
Transportation, storage and processing of natural gas	$	608	$	590
Distribution of natural gas		635		730
Sales of natural gas liquids		109		219
Other		32		61

Total operating revenues		1,384		1,600

Operating Expenses
Natural gas and petroleum products purchased		505		621
Operating, maintenance and other		264		280
Depreciation and amortization		136		145
Property and other taxes		64		61

Total operating expenses		969		1,107

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

Operating Income		425		493

Other Income and Expenses
Equity in earnings of unconsolidated affiliates		167		209
Other income and expenses, net		9		11

Total other income and expenses		176		220

Interest Expense		150		158

Earnings From Continuing Operations Before Income Taxes		451		555
Income Tax Expense from Continuing Operations		139		172

Income From Continuing Operations		312		383
Income From Discontinued Operations, net of tax		3		3

Net Income		315		386
Net Income—Noncontrolling Interests		17		19

Net Income—Controlling Interests	$	298	$	367


Common Stock Data
Weighted-average shares outstanding
Basic		628		633
Diluted		629		635
Earnings per share from continuing operations
Basic and Diluted	$	0.47	$	0.58
Earnings per share
Basic and Diluted	$	0.47	$	0.58
Dividends per share	$	0.25	$	0.23

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)


	March 31, 2009		December 31, 2008
ASSETS

Current Assets
Cash and cash equivalents	$	221	$	214
Receivables, net		727		795
Inventory		136		279
Other		140		162

Total current assets		1,224		1,450


Investments and Other Assets
Investments in and loans to unconsolidated affiliates		2,327		2,152
Goodwill		3,294		3,381
Other		309		417

Total investments and other assets		5,930		5,950


Property, Plant and Equipment
Cost		17,381		17,569
Less accumulated depreciation and amortization		3,970		3,930

Net property, plant and equipment		13,411		13,639


Regulatory Assets and Deferred Debits		852		885

Total Assets	$	21,417	$	21,924

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions, except per-share amounts)


	March 31, 2009		December 31, 2008
LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities
Accounts payable	$	248	$	285
Short-term borrowings and commercial paper		405		936
Taxes accrued		121		105
Interest accrued		155		158
Current maturities of long-term debt		792		821
Other		638		739

Total current liabilities		2,359		3,044

Long-term Debt		8,031		8,290


Deferred Credits and Other Liabilities
Deferred income taxes		2,862		2,789
Regulatory and other		1,476		1,566

Total deferred credits and other liabilities		4,338		4,355


Commitments and Contingencies

Preferred Stock of Subsidiaries		225		225


Stockholders’ Equity
Preferred stock, $0.001 par, 22 million shares authorized, no shares outstanding		—		—
Common stock, $0.001 par, 1 billion shares authorized, 645 million and 611 million shares outstanding at March 31, 2009 and December 31, 2008, respectively		1		1
Additional paid-in capital		4,621		4,104
Retained earnings		1,034		899
Accumulated other comprehensive income		331		536

Total controlling interests		5,987		5,540
Noncontrolling interests		477		470

Total stockholders’ equity		6,464		6,010

Total Liabilities and Stockholders’ Equity	$	21,417	$	21,924

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)


	Three Months Ended March 31,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	315		$	386
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		140			148
Deferred income tax expense		104			38
Equity in earnings of unconsolidated affiliates		(167	)		(209	)
Distributions received from unconsolidated affiliates		16			123
Other		148			187

Net cash provided by operating activities		556			673


CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(147	)		(245	)
Investments in and loans to unconsolidated affiliates		(29	)		(130	)
Purchases of available-for-sale securities		—			(446	)
Proceeds from sales and maturities of available-for-sale securities		32			438
Distributions received from unconsolidated affiliates		4			7
Other		(2	)		4

Net cash used in investing activities		(142	)		(372	)


CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt		693			310
Payments for the redemption of long-term debt		(852	)		(341	)
Net increase (decrease) in short-term borrowings and commercial paper		(530	)		42
Distributions to noncontrolling interests		(9	)		(14	)
Contributions from noncontrolling interests		2			3
Proceeds from the issuance of common stock		448			—
Dividends paid on common stock		(157	)		(146	)
Other		—			7

Net cash used in financing activities		(405	)		(139	)

Effect of exchange rate changes on cash		(2	)		(4	)

Net increase in cash and cash equivalents		7			158
Cash and cash equivalents at beginning of period		214			94

Cash and cash equivalents at end of period	$	221		$	252

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ 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			Net Losses on Cash Flow Hedges			Other			Noncontrolling Interests			Total
December 31, 2008	$	1	$	4,104		$	899		$	881		$	(17	)	$	(328	)	$	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 of SFAS No. 158		—		—			—			—			—			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		$	(23	)	$	(324	)	$	477		$	6,464


December 31, 2007	$	1	$	4,658		$	368		$	2,033		$	(8	)	$	(195	)	$	581		$	7,438
Net income		—		—			367			—			—			—			19			386
Foreign currency translation adjustments		—		—			—			(166	)		—			—			(7	)		(173	)
Unrealized mark-to-market net loss on hedges		—		—			—			—			(3	)		—			—			(3	)
Pension and benefits impact of SFAS No. 158		—		—			—			—			—			20			—			20
Dividends on common stock		—		—			(146	)		—			—			—			—			(146	)
Stock-based compensation		—		5			—			—			—			—			—			5
Distributions to noncontrolling interests		—		—			—			—			—			—			(14	)		(14	)
Contributions from noncontrolling interests		—		—			—			—			—			—			3			3
Other, net		—		11			—			—			—			—			1			12

March 31, 2008	$	1	$	4,674		$	589		$	1,867		$	(11	)	$	(175	)	$	583		$	7,528

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY CORP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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.

1. General

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% ownership 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, 2008, and reflect all normal recurring adjustments that are, in the opinion of management, 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.

Recasts and Reclassifications. We adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 160, “Noncontrolling Interest in Consolidated Financial Statements,” effective January 1, 2009. When adopting the presentation and disclosure items, retrospective application to conform previously reported financial statements to the new presentation requirements is required. Accordingly, the 2008 data contained in the Condensed Consolidated Financial Statements and the related information contained in this report have been recast to reflect the reporting requirements of SFAS No. 160. See Note 18 for further discussion of SFAS No. 160.

Prior to the adoption of SFAS No. 160, we accounted for sales of stock by a subsidiary under Staff Accounting Bulletin (SAB) No. 51, “Accounting for Sales of Stock of a Subsidiary.” Under SAB No. 51, companies could elect, via an accounting policy decision, to record a gain on the sale of stock of a subsidiary equal to the amount of proceeds received in excess of the carrying value of the shares. We had elected to treat such excesses as gains in earnings. Effective upon the adoption of SFAS No. 160, sales of stock by a subsidiary are required to be accounted for as equity transactions in those instances where a change in control does not take place, which effectively nullified the SAB No. 51 gain alternative. As a result of the adoption of SFAS No. 160, a $59 million deferred gain associated with the formation of Spectra Energy Partners, LP (Spectra Energy Partners) was reclassified from Deferred Credits and Other Liabilities—Regulatory and Other to Additional Paid-in Capital on the Consolidated Balance Sheet on January 1, 2009.

The Condensed Consolidated Statements of Operations for the three months ended March 31, 2008 and all related information contained in this report have been recast to reflect the operating results of certain natural gas gathering and processing facilities within the Western Canada Transmission & Processing segment as discontinued operations. See Note 5 for further discussion.

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 business units in deciding how to allocate resources and evaluate performance. All of the business units are considered reportable segments under SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information.” 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 Midstream businesses. BC Pipeline’s 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. Field Services 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, after deducting noncontrolling interests related to those profits.

On a segment basis, EBIT excludes discontinued operations, represents all profits from continuing operations (both operating and non-operating) before deducting interest and taxes, and is net of noncontrolling interests related to those profits. 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, 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


Three Months Ended March 31, 2008
U.S. Transmission	$	402	$	1		$	403		$	226
Distribution		800		—			800			165
Western Canada Transmission & Processing		397		—			397			129
Field Services		—		—			—			192

Total reportable segments		1,599		1			1,600			712
Other		1		8			9			(20	)
Eliminations		—		(9	)		(9	)		—
Interest expense		—		—			—			(158	)
Interest income and other (b)		—		—			—			21

Total consolidated	$	1,600	$	—		$	1,600		$	555

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

(b)	Other includes foreign currency transaction gains and losses and the elimination of noncontrolling interests related to EBIT.

3. Regulatory Matters

Union Gas. The OEB issued a decision under the incentive regulation framework in January 2009 providing for slight increases in rates for Union Gas’ small-volume customers and slight decreases for large-volume customers. Beginning April 1, 2009, the new rates were retroactively applied to January 1, 2009.

The incentive regulation framework establishes new rates at the beginning of each year through the use of a pricing formula rather than through the examination of revenue and cost forecasts. The allowed return on equity (ROE) for Union Gas is formula-based and is periodically established by the OEB. The established ROE for 2008 will remain unchanged throughout the five-year incentive regulation period (2008-2012), subject to any changes in the OEB-approved ROE formula or approved regulated capital structure. The incentive regulation framework includes a provision for a review of the pricing mechanism contained in that framework. That review is triggered if there is a variance of 3% or more between Union Gas’ actual utility ROE as normalized for weather and the utility ROE determined by the OEB. Union Gas’ weather-normalized utility ROE for 2008

exceeded the upper review threshold, and accordingly, Union Gas filed for a review by the OEB on April 2, 2009. While we cannot estimate what changes might occur, we currently expect that any changes will not have a material effect on our consolidated future earnings, financial position or cash flows.

Maritimes & Northeast Pipeline Limited Partnership (M&N LP). During 2008, M&N LP operated under an NEB-approved toll settlement that expired December 31, 2008. M&N LP obtained approval to operate under interim rates, effective January 1, 2009, that was set to equal the 2008 rates. The final 2009 toll settlement rates were approved by the NEB in April 2009. M&N LP will implement the new rates on a prospective basis such that the total tolls charged for 2009 will result in revenues equal to those had the new 2009 rates been in effect for the entire year.

4. Income Taxes

Income tax expense from continuing operations for the three months ended March 31, 2009 was $139 million, compared to $172 million reported in the same period in 2008. The decrease was primarily a result of lower earnings in the 2009 period. The effective tax rate for income from continuing operations decreased from 31.0% in the first quarter of 2008 to 30.8 % in the first quarter of 2009.

We recognized no material changes in unrecognized tax benefits during the first quarter of 2009. Although uncertain, we believe it is reasonably possible that the total amount of unrecognized tax benefits could decrease by approximately $28 million prior to March 31, 2010. The anticipated changes in unrecognized tax benefits relate to expiration of statutes of limitations and expected audit settlements focused primarily on classification of certain tax attributes, transfer pricing and income allocation.

5. Discontinued Operations

In December 2008, we closed on the sale of our interests in the Nevis and Brazeau River natural gas gathering and processing facilities, which were part of the Western Canada Transmission & Processing segment. Results of operations of these assets are reflected as discontinued operations in the Condensed Consolidated Statements of Operations for the 2008 period presented.

In June 2008, we entered into a settlement agreement related to certain liquefied natural gas transportation contracts under which our Spectra Energy LNG Sales Inc. subsidiary’s claims were satisfied pursuant to commercial transactions involving the purchase of propane from certain parties. We subsequently entered into associated agreements with an affiliate of DCP Midstream and another party for the sale of these propane volumes. Net purchases and sales of propane under these arrangements are reflected as Other 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		Income From Discontinued Operations, Net of Tax
	(in millions)
Three Months Ended March 31, 2009
Other	$	43	$	4	$	1	$	3

Total consolidated	$	43	$	4	$	1	$	3

Three Months Ended March 31, 2008
Western Canada Transmission & Processing	$	8	$	4	$	1	$	3

Total consolidated	$	8	$	4	$	1	$	3

6. Comprehensive Income

Components of comprehensive income are as follows:


	Three Months Ended March 31,
	2009			2008
	(in millions)
Net income	$	315		$	386
Other comprehensive income
Foreign currency translation adjustments		(205	)		(173	)
Unrealized mark-to-market net loss on hedges (a)		(6	)		(3	)
Pension and benefits impact of SFAS No. 158 (b)		4			20

Total Comprehensive income, net of tax		108			230
Less: Comprehensive income—noncontrolling interests		15			12

Comprehensive income—controlling interests	$	93		$	218

(a)	Net of $3 million and $1 million of net tax benefits for the three months ended March 31, 2009 and 2008, respectively.

(b)	Net of $2 million tax expense and $16 million of net tax benefits for the three months ended March 31, 2009 and 2008, respectively.

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,
	2009		2008
	(in millions, except per-share amounts)
Income from continuing operations, net of tax—controlling interests	$	295	$	366
Income from discontinued operations, net of tax—controlling interests		3		1

Net income—controlling interests	$	298	$	367


Weighted-average common shares outstanding
Basic		628		633
Diluted		629		635

Basic and diluted earnings per common share
Continuing operations	$	0.47	$	0.58
Discontinued operations, net of tax		—		—

Total basic earnings per common share	$	0.47	$	0.58

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 13 million shares for the three months ended March 31, 2009 and nine million shares for the three months ended March 31, 2008 were not included in the calculation of diluted EPS because either the option exercise prices were greater than the average market price of the common shares during these periods or performance measures related to the awards had not yet been met.

8. 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 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, 2009		December 31, 2008
	(in millions)
Natural gas	$	40	$	180
NGLs		16		16
Materials and supplies		80		83

Total inventory	$	136	$	279

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,
	2009		2008
	(in millions)
Operating revenues	$	1,927	$	4,046
Operating expenses		1,823		3,634
Operating income		104		412
Net income		43		377
Net income attributable to members’ interests		30		383

As a result of the adoption of SFAS No. 160 on January 1, 2009, DCP Midstream reclassified to equity certain deferred gains on sales of common units in its master limited partnership, DCP Midstream Partners, LP (DCP Partners). In accordance with Emerging Issues Task Force (EITF) 08-06, “Equity Method Investment Accounting Considerations,” our proportionate 50% share, totaling $135 million, was recorded in Equity in Earnings of Unconsolidated Affiliates in the first quarter of 2009.

As further discussed in Note 5, Spectra Energy entered into a propane sales agreement with an affiliate of DCP Midstream in the second quarter of 2008. During the three months ended March 31, 2009, we recorded revenues of $34 million associated with this agreement, classified within Income From Discontinued Operations, Net of Tax.

10.

Debt and Credit Facilities

Available Credit Facilities and Restrictive Debt Covenants


					Outstanding at March 31, 2009
	Expiration Date	Credit Facilities Capacity			Commercial Paper		Term Loan		Revolving Credit		Letters of Credit		Total
					(in millions)
Spectra Energy Capital, LLC	2012	$	1,500	(a)	$	405	$	—	$	—	$	5	$	410
Westcoast Energy, Inc.	2011		159	(b)		—		—		—		—		—
Union Gas	2012		397	(c)		—		—		—		—		—
Spectra Energy Partners	2012		500	(d)		—		—		240		—		240

Total		$	2,556		$	405	$	—	$	240	$	5	$	650

(a)	Credit facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 65%. Amounts outstanding under the revolving credit facility are classified within Short-Term Borrowings and Commercial Paper on the Condensed Consolidated Balance Sheets.

(b)	U.S. dollar equivalent at March 31, 2009. Credit facility is denominated in Canadian dollars totaling 200 million Canadian dollars and contains a covenant that requires the debt-to-total capitalization ratio to not exceed 75%.

(c)

U.S. dollar equivalent at March 31, 2009. Credit facility is denominated in Canadian dollars totaling 500 million Canadian dollars and contains a covenant that requires the debt-to-total capitalization ratio to not exceed 75% and a provision which requires Union Gas to repay all borrowings under the facility for a period of two days during the second quarter of each year.

(d)	Contains a covenant requiring the borrower to collateralize the term loan with qualifying investment-grade securities in an amount equal to or greater than the outstanding principal amount of the loan. Amounts outstanding under the revolving credit facility are classified within Long-term Debt.

The terms of the Spectra Energy Partners credit facility allow for liquidation of collateral to fund capital expenditures or certain acquisitions provided that an equal amount of term loan is converted to a revolving loan. We had no investments in marketable securities pledged as collateral against the term loan at March 31, 2009 and $32 million of investments pledged at December 31, 2008. These investments are classified as Investments and Other Assets—Other on the Condensed Consolidated Balance Sheets.

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, 2009, 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. None of the debt or credit agreements contain material adverse change clauses.

11. Fair Value Measurements

The following table presents, for each of the fair value hierarchy levels, assets and liabilities that are measured at fair value on a recurring basis:


		March 31, 2009
Description	Balance Sheet Caption	Total		Level 1		Level 2		Level 3
		(in millions)
Available-for-sale securities	Cash and cash equivalents	$	194	$	52	$	142	$	—
Long-term investments	Investments and other assets-other		12		12		—		—
Employee benefit assets	Investments and other assets-other		21		21		—		—
Long-term derivative assets	Investments and other assets-other		26		—		—		26

Total Assets		$	253	$	85	$	142	$	26

Long-term derivative liabilities	Deferred credits and other liabilities-regulatory and other	$	22	$	—	$	22	$	—

Total Liabilities		$	22	$	—	$	22	$	—


		December 31, 2008
Description	Balance Sheet Caption	Total		Level 1		Level 2		Level 3
		(in millions)
Available-for-sale securities	Cash and cash equivalents	$	171	$	66	$	105	$	—
Short-term investments	Current assets-other		13		13		—		—
Short-term derivative assets	Current assets-other		13		—		13		—
Long-term investments	Investments and other assets-other		53		28		25		—
Employee benefit assets	Investments and other assets-other		23		23		—		—
Long-term derivative assets	Investments and other assets-other		89		—		53		36

Total Assets		$	362	$	130	$	196	$	36

Long-term derivative liabilities	Deferred credits and other liabilities-regulatory and other	$	23	$	—	$	23	$	—

Total Liabilities		$	23	$	—	$	23	$	—

The following table reconciles assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3).


	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	)	$	—


	Short-Term Derivative Assets		Short-Term Derivative Liabilities			Long-Term Derivative Assets		Long-Term Derivative Liabilities
	(in millions)
Fair value at December 31, 2007	$	—	$	—		$	47	$	(21	)
Total gains or losses (realized/unrealized):
Included in earnings		—		—			11		(11	)
Included in regulatory assets		50		—			—		—
Included in other comprehensive income		—		(7	)		4		—
Normal purchases and sales election under SFAS No. 133		—		—			—		32
Purchases, issuances and settlements		1		—			—		—

Fair value at March 31, 2008	$	51	$	(7	)	$	62	$	—

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, 2008	$	—	$	—		$	11	$	(11	)

Gains and losses for the three months ended March 31, 2009 and 2008 associated with long-term derivative assets and liabilities are reported in Other Income and Expenses, net on the Condensed Consolidated Statement of Operations and are of offsetting amounts, and as such, have no net impact on the Condensed Consolidated Statements of Operations.

During 2009, 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 international, federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. These 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 March 31, 2009 and $17 million as of December 31, 2008. 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. A second similar class action was also filed in 2006 alleging similar claims and seeking to represent the same class of plaintiffs, but this second case was dismissed without prejudice, and only the first case has moved forward. 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 has 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. We await the Court’s decision.

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 the number of our employees 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, royalty, measurement 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.

We had no material reserves as of March 31, 2009 or December 31, 2008 related to litigation matters in accordance with our best estimate of probable loss as defined by SFAS No. 5, “Accounting for Contingencies.”

Legal costs related to the defense of loss contingencies are expensed as incurred.

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 have been 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, 2009 was approximately $431 million, which has been indemnified by Duke Energy, as discussed above. Approximately $5 million of the performance guarantees expire in 2009 and 2010, with the remaining performance guarantees expiring after 2010 or having 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. In accordance with the D/FD partnership agreement, each of the partners is responsible for 50% of any payments to be made under those guarantees.

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, 2009 was $50 million. These guarantees 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, 2009, 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, Credit Risk and Financial Instruments

We are exposed to the impact of market fluctuations in the prices of NGLs and natural gas marketed and purchased primarily as a result of our investment in DCP Midstream and ownership of the 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 commodity derivatives, primarily within DCP Midstream, such as swaps and options.

Derivative Portfolio Carrying Value as of March 31, 2009


Asset/(Liability)	Maturity in 2009			Maturity in 2010		Maturity in 2011		Maturity in 2012 and Thereafter			Total Carrying Value
	(in millions)
Hedging	$	(1	)	$	4	$	4	$	18		$	25
Undesignated		—			—		—		(21	)		(21	)

Total	$	(1	)	$	4	$	4	$	(3	)	$	4

These amounts represent the combination of amounts presented as assets (liabilities) for unrealized gains and losses on mark-to-market and hedging transactions on our Condensed Consolidated Balance Sheets and do not include derivative positions of DCP Midstream.

Commodity Cash Flow Hedges. Certain of our operations are exposed to market fluctuations in the prices of natural gas and NGLs related to natural gas gathering, distribution, processing and marketing activities. We closely monitor the potential effects of commodity price changes and may choose to enter into contracts to protect margins for a portion of future sales and fuel expenses by using financial commodity instruments, such as swaps, forward contracts and options, as cash flow hedges for natural gas and NGL transactions, primarily within the operations of DCP Midstream and Western Canada Transmission & Processing.

The ineffective portion of commodity cash flow hedges from continuing operations resulted in insignificant amounts and is reported in Other Revenues in the Condensed Consolidated Statements of Operations. For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income (OCI) and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. We are party to natural gas purchase contracts to hedge forecasted purchases. These contracts are for notional amounts of 42 million British thermal units as of March 31, 2009.

As of March 31, 2009, $1 million of pre-tax deferred net loss on derivative instruments related to commodity cash flow hedges were accumulated on the Condensed Consolidated Balance Sheets in Accumulated Other Comprehensive Income (AOCI) and are expected to be recognized in earnings during the next twelve months as the hedged transactions occur. However, due to the volatility of the commodity markets, the corresponding value in AOCI will likely change prior to its reclassification into earnings.

Interest Rate Hedges. Changes in interest rates expose us to risk as a result of our issuance of variable and fixed-rate debt and commercial paper. We manage our interest rate exposure by limiting our variable-rate exposures to percentages of total capitalization and by monitoring the effects of market changes in interest rates. We also enter into financial derivative instruments, including, but not limited to, interest rate swaps and U.S. Treasury lock agreements to manage and mitigate interest rate risk exposure.

For interest rate derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk is recognized in the Condensed Consolidated Statements of Operations. Gains and losses recognized were as follows:


	Three Months Ended March 31,
	2009				2008
	(in millions)
Condensed Consolidated Statements of Operations Caption	Gain (Loss) on Swaps		Gain (Loss) on Borrowings		Gain (Loss) on Swaps			Gain (Loss) on Borrowings
Interest expense	$	—	$	—	$	(5	)	$	4

In January 2009, as a result of low interest rates, we settled existing fixed-to-floating interest rate swaps on $848 million of long-term debt. Gains on the settlements, totaling $67 million, were recorded as follows on the Condensed Consolidated Balance Sheets: $5 million as a reduction to Interest Accrued, $21 million as a reduction to Current Maturities of Long-term Debt and $41 million as a reduction to Long-term Debt. The gains recorded as reductions of debt will be amortized in Interest Expense over the lives of the associated debt. In February 2009, we entered into interest rate swap agreements to mitigate our exposure to variable interest rates on $40 million of loans outstanding under certain revolving loan facilities. As of March 31, 2009, the notional amount of our interest rate swaps was $40 million.

Foreign Currency Hedges. We are exposed to foreign currency risk from investments and operations in international affiliate businesses, which is limited to Canada. To mitigate risks associated with foreign currency fluctuations, contracts may be denominated in or indexed to the U.S. dollar and/or local inflation rates, or investments may be naturally hedged through debt denominated or issued in the foreign currency. We may also use foreign currency derivatives, where possible, to manage risk related to foreign currency fluctuations. There were no foreign currency derivative transactions during the three months ended March 31, 2009 and 2008, respectively. To monitor our currency exchange rate risks, we use sensitivity analysis, which measures the effect of devaluation of the Canadian dollar.

Asset and Liability Derivatives. The locations and amounts of derivative instruments, valued at fair value, in the Condensed Consolidated Balance Sheets follow:


Derivatives Designated as Hedging Instruments	Condensed Consolidated Balance Sheets Caption	March 31, 2009		December 31, 2008
		(in millions)
Asset Derivatives
Natural gas purchase contract	Investments and other assets—other	$	26	$	36

Liability Derivatives
Cash flow hedges	Deferred credits and other liabilities— regulatory and other		1		—

Derivatives Not Designated as Hedging Instruments	Condensed Consolidated Balance Sheets Caption	March 31, 2009		December 31, 2008
		(in millions)
Liability Derivatives
Interest rate swaps	Deferred credits and other liabilities— regulatory and other	$	21	$	23

The effective portions of gains (losses) recognized in AOCI on derivatives follow:


Cash Flow Hedging Derivatives	Three Months Ended March 31,
Cash Flow Hedging Derivatives	2009			2008
	(in millions)
Natural gas purchase contract	$	(7	)	$	4
Cash flow hedges		1			(7	)

Total	$	(6	)	$	(3	)

The ineffective portion of gains (losses) recognized in income on derivatives follows:


Cash Flow Hedging Derivatives	Condensed Consolidated Statements of Operations Caption	Three Months Ended March 31,
Cash Flow Hedging Derivatives		2009			2008
		(in millions)
Natural gas purchase contracts	Other income and expenses, net	$	(1	)	$	—

There were no reclassifications from AOCI into income on our derivative assets and liabilities during the three months ended March 31, 2009 or 2008.

Credit Risk. Our principal customers for natural gas transportation, storage and gathering and processing services are industrial end-users, marketers, exploration and production companies, local distribution companies and utilities located throughout the United States and Canada. We have concentrations of receivables from natural gas utilities and their affiliates, industrial customers and marketers throughout these regions, as well as retail distribution customers in Canada. These concentrations of customers may affect our overall credit risk in that risk factors can negatively affect the credit quality of the entire sector. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We also obtain parental guarantees, cash or letters of credit from customers to provide credit support, where appropriate, based on our financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each transaction.

Included in Other Current Liabilities and Deferred Credits and Other Liabilities—Regulatory and Other are collateral liabilities of $113 million at March 31, 2009 and $121 million at December 31, 2008, which represent cash collateral posted by third parties with us.

15. Sale of Common Stock

On February 13, 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, 2009 and 2008, and do not currently anticipate making contributions to the U.S. plans during the remainder of 2009.

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 contributions to the Canadian qualified DB plans of $9 million and $11 million during the three-month periods ended March 31, 2009 and 2008, respectively. We anticipate that we will make total contributions of approximately $49 million to the Canadian DB plans in 2009. We also made contributions to the Canadian DC plan of $1 million and $2 million during the three-month periods ended March 31, 2009 and 2008, respectively. We anticipate that we will make total contributions of approximately $4 million to the Canadian DC plans in 2009.

Qualified Pension Plans—Components of Net Periodic Pension Cost


	U.S.						Canada
	Three Months Ended March 31,
	2009			2008			2009			2008
	(in millions)
Service cost benefit earned	$	2		$	2		$	3		$	4
Interest cost on projected benefit obligation		7			7			9			10
Expected return on plan assets		(8	)		(9	)		(10	)		(12	)
Amortization of loss		1			1			1			2

Net periodic pension cost	$	2		$	1		$	3		$	4

Non-Qualified Pension Benefits Plans—Components of Net Periodic Pension Cost
	U.S.						Canada
	Three Months Ended March 31,
	2009			2008			2009			2008
	(in millions)
Service cost benefit earned	$	—		$	—		$	—		$	1
Interest cost on projected benefit obligation		—			—			1			1

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

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,
	2009			2008			2009		2008
	(in millions)
Service cost benefit earned	$	—		$	—		$	1	$	1
Interest cost on accumulated post-retirement benefit obligation		4			4			1		1
Expected return on plan assets		(1	)		(1	)		—		—
Amortization of net transition liability		1			1			—		—

Net periodic other post-retirement benefit cost	$	4		$	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 us 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, 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 Statement of Operations

Three Months Ended March 31, 2008

(In millions)


	Spectra Energy Corp			Spectra Capital		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Total operating revenues	$	—		$	—	$	1,600	$	—		$	1,600
Total operating expenses		5			—		1,102		—			1,107

Operating income (loss)		(5	)		—		498		—			493
Equity in earnings of unconsolidated affiliates		—			—		209		—			209
Equity in earnings of subsidiaries		371			552		—		(923	)		—
Other income and expenses, net		(1	)		2		10		—			11
Interest expense		—			58		100		—			158

Earnings from continuing operations before income taxes		365			496		617		(923	)		555
Income tax expense (benefit) from continuing operations		(2	)		125		49		—			172

Income from continuing operations		367			371		568		(923	)		383
Income from discontinued operations, net of tax		—			—		3		—			3

Net income		367			371		571		(923	)		386
Net income—noncontrolling interests		—			—		19		—			19

Net income—controlling interests	$	367		$	371	$	552	$	(923	)	$	367

Spectra Energy Corp

Condensed Consolidating Balance Sheet

March 31, 2009

(In millions)


	Spectra Energy Corp			Spectra Capital		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash and cash equivalents	$	—		$	—	$	221		$	—		$	221
Receivables (payables)—consolidated subsidiaries		(27	)		249		(222	)		—			—
Receivables—other		2			7		718			—			727
Other current assets		12			43		221			—			276

Total current assets		(13	)		299		938			—			1,224
Investments in and loans to unconsolidated affiliates		—			375		1,952			—			2,327
Investments in consolidated subsidiaries		7,795			10,852		—			(18,647	)		—
Advances receivable (payable)—consolidated subsidiaries		(1,645	)		2,821		(807	)		(369	)		—
Goodwill		—			—		3,294			—			3,294
Other assets		33			15		261			—			309
Property, plant and equipment, net		—			—		13,411			—			13,411
Regulatory assets and deferred debits		—			14		838			—			852

Total Assets	$	6,170		$	14,376	$	19,887		$	(19,016	)	$	21,417


Accounts payable (receivable)—consolidated subsidiaries	$	—		$	41	$	(41	)	$	—		$	—
Accounts payable—other		2			113		133			—			248
Short-term borrowings and commercial paper		—			774		—			(369	)		405
Accrued taxes payable (receivable)		(48	)		39		130			—			121
Current maturities of long-term debt		—			517		275			—			792
Other current liabilities		10			98		685			—			793

Total current liabilities		(36	)		1,582		1,182			(369	)		2,359
Long-term debt		—			2,982		5,049			—			8,031
Deferred credits and other liabilities		219			2,017		2,102			—			4,338
Preferred stock of subsidiaries		—			—		225			—			225
Total stockholders’ equity		5,987			7,795		11,329			(18,647	)		6,464

Total Liabilities and Stockholders’ Equity	$	6,170		$	14,376	$	19,887		$	(19,016	)	$	21,417

Spectra Energy Corp

Condensed Consolidating Balance Sheet

December 31, 2008

(In millions)


	Spectra Energy Corp			Spectra Capital		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash and cash equivalents	$	—		$	60	$	154		$	—		$	214
Receivables (payables)—consolidated subsidiaries		(25	)		250		(220	)		(5	)		—
Receivables—other		1			11		783			—			795
Other current assets		39			35		367			—			441

Total current assets		15			356		1,084			(5	)		1,450
Investments in and loans to unconsolidated affiliates		—			368		1,784			—			2,152
Investments in consolidated subsidiaries		7,375			10,482		—			(17,857	)		—
Advances receivable (payable)—consolidated subsidiaries		(1,937	)		3,298		(992	)		(369	)		—
Goodwill		—			—		3,381			—			3,381
Other assets		40			66		311			—			417
Property, plant and equipment, net		—			—		13,639			—			13,639
Regulatory assets and deferred debits		1			15		869			—			885

Total Assets	$	5,494		$	14,585	$	20,076		$	(18,231	)	$	21,924


Accounts payable (receivable)—consolidated subsidiaries	$	5		$	41	$	(41	)	$	(5	)	$	—
Accounts payable—other		1			124		160			—			285
Short-term borrowings and commercial paper		—			1,137		168			(369	)		936
Accrued taxes payable (receivable)		(297	)		266		136			—			105
Current maturities of long-term debt		—			648		173			—			821
Other current liabilities		19			106		772			—			897

Total current liabilities		(272	)		2,322		1,368			(374	)		3,044
Long-term debt		—			3,009		5,281			—			8,290
Deferred credits and other liabilities		226			1,879		2,250			—			4,355
Preferred stock of subsidiaries		—			—		225			—			225
Total stockholders’ equity		5,540			7,375		10,952			(17,857	)		6,010

Total Liabilities and Stockholders’ Equity	$	5,494		$	14,585	$	20,076		$	(18,231	)	$	21,924

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 common stock		448			—			—			—			448
Dividends paid on common stock		(157	)		(3	)		—			3			(157	)
Distributions and advances to parent		(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

Spectra Energy Corp

Condensed Consolidating Statements of Cash Flows

Three Months Ended March 31, 2008

(In millions)


	Spectra Energy Corp			Spectra Capital			Non-Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	367		$	371		$	571		$	(923	)	$	386
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		—			—			148			—			148
Equity in earnings of unconsolidated affiliates		—			—			(209	)		—			(209	)
Equity in earnings of subsidiaries		(371	)		(552	)		—			923			—
Distributions received from unconsolidated affiliates		—			—			123			—			123
Other		(27	)		95			157			—			225

Net cash provided by (used in) operating activities		(31	)		(86	)		790			—			673

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		—			—			(245	)		—			(245	)
Investments in and loans to unconsolidated affiliates		—			—			(130	)		—			(130	)
Purchases of available-for-sale securities		—			—			(446	)		—			(446	)
Proceeds from sales and maturities of available-for-sale securities		—			—			438			—			438
Distributions received from unconsolidated affiliates		—			—			7			—			7
Other		—			—			4			—			4

Net cash used in investing activities		—			—			(372	)		—			(372	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt		—			—			310			—			310
Payments for the redemption of long-term debt		—			—			(341	)		—			(341	)
Net increase (decrease) in short-term borrowings and commercial paper		—			279			(237	)		—			42
Distributions to noncontrolling interests		—			—			(14	)		—			(14	)
Contributions from noncontrolling interests		—			—			3			—			3
Dividends paid on common stock		(146	)		(1	)		—			1			(146	)
Distributions and advances to parent		177			(192	)		16			(1	)		—
Other		—			—			7			—			7

Net cash provided by (used in) financing activities		31			86			(256	)		—			(139	)

Effect of exchange rate changes on cash		—			—			(4	)		—			(4	)

Net increase in cash and cash equivalents		—			—			158			—			158
Cash and cash equivalents at beginning of period		—			—			94			—			94

Cash and cash equivalents at end of period	$	—		$	—		$	252		$	—		$	252

18. New Accounting Pronouncements

The following new accounting pronouncements were adopted during the three months ended March 31, 2009:

SFAS No. 157, “Fair Value Measurements.” In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. In February 2008, the FASB issued FASB Staff Position (FSP) No. 157-2, “Effective Date of FASB Statement No. 157,” which delayed the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statement on a recurring basis (at least annually). The adoption of the provisions of SFAS No. 157 on January 1, 2009, for the measurement of our asset retirement obligations did not have any impact on our consolidated results of operations, financial position or cash flows. We expect that the adoption of SFAS No. 157 for our goodwill impairment test purposes will also not have a material impact on our consolidated results of operations, financial position or cash flows.

SFAS No. 141R, “Business Combinations.” In December 2007, the FASB issued SFAS No. 141R which replaces SFAS No. 141, “Business Combinations.” SFAS No. 141R requires the acquiring entity in a business combination to recognize all and only the assets acquired and liabilities assumed in the transaction, establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed, and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. SFAS 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We adopted the provisions of SFAS No. 141R effective January 1, 2009.

SFAS No. 160, “Noncontrolling Interest in Consolidated Financial Statements.” In December 2007, the FASB issued SFAS No. 160 which requires all entities to report noncontrolling (minority) interests in subsidiaries as equity in the consolidated financial statements. SFAS No. 160 eliminates the diversity that existed in accounting for transactions between an entity and noncontrolling interests by requiring they be treated as equity transactions. We adopted the provisions of SFAS No. 160 effective January 1, 2009 as required.

When adopting the presentation and disclosure items, retrospective application to conform previously reported financial statements to the new presentation requirements is required. Changes to reflect the new measurement guidance for increases or decreases in ownership and other changes must be done prospectively. The new requirements for noncontrolling interests, results of operations and comprehensive income of subsidiaries change the presentation of operating results, related per-share information, and equity. SFAS No. 160 requires net income and comprehensive income to be displayed for both the controlling and the noncontrolling interests. Additional required disclosures and reconciliations include a separate schedule that shows the effects of any transactions with the noncontrolling interests on the equity attributable to the controlling interest.

As discussed in Note 1, a deferred gain associated with the formation of Spectra Energy Partners totaling $59 million was reclassified from Deferred Credits and Other Liabilities—Regulatory and Other to Additional Paid-in Capital on the Consolidated Balance Sheets upon the adoption of SFAS No. 160 on January 1, 2009.

In November 2008, the FASB ratified EITF 08-6 which addresses certain effects of SFAS No. 141R and SFAS No. 160 on an entity’s accounting for equity-method investments. The consensus indicates, among other things, that transaction costs for an investment should be included in the cost of the equity-method investment (and not expensed) and shares subsequently issued by the equity-method investee that reduce the investor’s ownership percentage should be accounted for as if the investor had sold a proportionate share of its investment, with gains or losses recorded through earnings. For us, EITF 08-6 was effective for transactions occurring after December 31, 2008.

As discussed in Note 9, a $135 million increase to Equity in Earnings of Unconsolidated Affiliates was recorded in the first quarter of 2009 related to DCP Midstream’s reclassification of certain deferred gains on sales of common units in its master limited partnership to equity as a result of their adoption of SFAS No. 160.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133.” In March 2008, the FASB issued SFAS No. 161 which amends and expands the disclosure requirements for SFAS No. 133 with the intent to provide users of financial statements an enhanced understanding of how and why derivative instruments are used, how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. We adopted the provisions of SFAS No.161 effective January 1, 2009 as required. See Note 14 for the disclosures required by SFAS No. 161.

FSP No. FAS 142-3, “Determination of the Useful Life of Intangible Assets.” In April 2008, the FASB issued FSP No. FAS 142-3 which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets.” The adoption of the provisions FSP No. FAS 142-3 on January 1, 2009 had no impact on our consolidated results of operations, financial position or cash flows.

EITF 07- 01, “Accounting for Collaborative Arrangements.” In December 2007, the FASB ratified a consensus reached by the EITF to define collaborative arrangements and to establish reporting requirements for transactions between participants in a collaborative arrangement and between participants in the arrangement and third parties. A collaborative arrangement is a contractual arrangement that involves a joint operating activity. These arrangements involve two (or more) parties who are both (a) active participants in the activity and (b) exposed to significant risks and rewards dependent on the commercial success of the activity. An entity should report the effects of applying EITF 07-01 as a change in accounting principle through retrospective application to all prior periods presented for all arrangements existing as of the effective date. The adoption of the provisions of EITF 07-01 on January 1, 2009 had no impact on our consolidated results of operations, financial position or cash flows.

EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities.” In June 2008, the FASB issued EITF 03-6-1 which addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing EPS under the two-class method. The adoption of EITF 03-6-1 on January 1, 2009 had no material affect on our computation of EPS.

The following new accounting pronouncements have been issued, but have not yet been adopted as of March 31, 2009:

FSP No. FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets.” In December 2008, the FASB issued FSP No. FAS 132(R)-1 which requires additional disclosures about plan assets for sponsors of defined benefit pension and postretirement plans including expanded information regarding investment strategies, major categories of plan assets and concentrations of risk within plan assets. Additionally, this FSP requires disclosures similar to those required under SFAS No. 157 with respect to the fair value of plan assets such as the inputs and valuation techniques used to measure fair value and information with respect to classification of plan assets in terms of the hierarchy of the source of information used to determine their value. The disclosures under this FSP are required for annual periods ending after December 15, 2009. We are currently evaluating the requirements of these additional disclosures.

19. Subsequent Event

On May 4, 2009, Spectra Energy Partners acquired all of the ownership interests of NOARK Pipeline System, Limited Partnership (NOARK) from Atlas Pipeline Partners, L.P. (Atlas) for approximately $295 million.

NOARK’s assets consist of 100% ownership interest in Ozark Gas Transmission, L.L.C., a 565-mile FERC regulated interstate natural gas transmission pipeline system, and Ozark Gas Gathering, L.L.C., a 365-mile, fee-based, state regulated natural gas gathering system. The transaction was funded by Spectra Energy Partners with $218 million drawn on Spectra Energy Partners’ available bank credit facilities, $70 million borrowed under a credit facility with Spectra Energy and $7 million of cash on hand. Spectra Energy Partners expects long-term financing for the transaction to be a combination of debt and equity consistent with its current and targeted capital structure.

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. As previously discussed, the 2008 data contained in the Condensed Consolidated Financial Statements and the related information presented in this report has been recast to reflect the reporting requirements of SFAS No. 160, which was adopted January 1, 2009. In addition, the Condensed Consolidated Statements of Operations and related information and discussions for the 2008 period have been recast to reflect the operating results of certain Western Canada Transmission & Processing natural gas gathering and processing facilities as discontinued operations. See Notes 5 and 18 of Notes to Condensed Consolidated Financial Statements for further discussion.

Executive Overview

For the three months ended March 31, 2009 and 2008, we reported net income from controlling interests of $298 million and $367 million, respectively. The decrease is due to lower earnings from Field Services and Western Canada Transmission & Processing as a result of lower NGL prices, which correlate to lower crude oil prices during the first three months of 2009. Crude oil averaged $43 per barrel for the three months ended March 31, 2009 versus $98 per barrel during the same period in 2008. The decrease in earnings was partially offset by the recognition of a $135 million deferred gain ($85 million after-tax) in 2009 associated with partnership units previously issued by DCP Partners.

The highlights for the three months ended March 31, 2009 include:

•

U.S. Transmission’s earnings decreased due primarily to lower margins from gas processing, partially offset by an increase from expansion projects placed into service in late 2008,

•

Distribution results reflect a weaker Canadian dollar, partially offset by higher storage and transportation revenues,

•

Western Canada Transmission & Processing earnings decreased primarily as a result of lower NGL prices related to the Empress processing plant and a weaker Canadian dollar, partially offset by higher gathering and processing revenues,

•

Field Services earnings reflect lower NGL and natural gas prices in 2009, partially offset by the recognition of a deferred gain associated with partnership units previously issued by DCP Partners, and

•

results for Other decreased primarily due to an overall increase in the cost of benefits in 2009.

In the first quarter of 2009, we reported $176 million of capital and investment expenditures. Approximately $1 billion is projected for the full year and includes expansion capital of approximately $500 million.

On February 13, 2009, in order to further protect our capitalization structure against a potential extreme decline in the Canadian dollar, we issued 32.2 million shares of our common stock and received net proceeds of $448 million.

As of March 31, 2009, we continue to have ongoing access to approximately $2.6 billion in credit facilities and expect to continue to utilize commercial paper and revolving lines of credit, as needed, to fund liquidity needs throughout 2009.

As previously discussed, on May 4, 2009, Spectra Energy Partners acquired all of the ownership interests of NOARK from Atlas for approximately $295 million. See Note 19 of Notes to Condensed Consolidated Financial Statements for further discussion.

RESULTS OF OPERATIONS


	Three Months Ended March 31,
	2009		2008
	(in millions)
Operating revenues	$	1,384	$	1,600
Operating expenses		969		1,107
Gains on sales of other assets and other, net		10		—

Operating income		425		493
Other income and expenses		176		220
Interest expense		150		158

Earnings from continuing operations before income taxes		451		555
Income tax expense from continuing operations		139		172

Income from continuing operations		312		383
Income from discontinued operations, net of tax		3		3

Net income		315		386
Net income—noncontrolling interests		17		19

Net income—controlling interests	$	298	$	367

Operating Revenues. The $216 million, or 14%, decrease was driven primarily by:

•

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

•

lower NGL prices associated with the Empress operations at Western Canada Transmission & Processing, partially offset by

•

higher natural gas prices passed through to customers without a mark-up, growth in the number of customers and higher storage and transportation revenues at Distribution.

Operating Expenses. The $138 million, or 12%, decrease was driven primarily by:

•

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

•

lower prices of natural gas purchased for the Empress facility, partially offset by

•

higher natural gas prices passed through to customers without a mark-up and growth in the number of customers at Distribution.

Operating Income. The $68 million, or 14%, decrease was driven primarily by lower NGL product prices associated with the Empress operations at Western Canada Transmission & Processing and a weaker Canadian dollar, partially offset by higher storage and transportation revenues at Distribution.

Other Income and Expenses. The $44 million decrease was attributable to lower equity in earnings from Field Services, reflecting primarily lower commodity prices, partially offset by a gain associated with partnership units previously issued by DCP Partners.

Income Tax Expense from Continuing Operations. The $33 million decrease relates primarily to lower earnings in the first quarter of 2009. The effective tax rate was 30.8% in the first quarter of 2009 compared with 31.0% in the first quarter of 2008.

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, after deducting noncontrolling interests related to those profits. On a segment basis, EBIT excludes discontinued operations, represents all profits from continuing operations (both operating and non-operating) before deducting interest and taxes, and is net of noncontrolling interests related to those profits. 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 interests in operations without regard to financing methods or capital structures.

Our segment EBIT may not be comparable to similarly titled measures of another company because other entities 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,
	2009			2008
	(in millions)
U.S. Transmission	$	217		$	226
Distribution		152			165
Western Canada Transmission & Processing		81			129
Field Services		150			192

Total reportable segment EBIT		600			712
Other		(24	)		(20	)

Total reportable segment and other EBIT		576			692
Interest expense		(150	)		(158	)
Interest income and other (a)		25			21

Earnings from continuing operations before income taxes	$	451		$	555

(a)	Other includes foreign currency transaction gains and losses and the elimination of the noncontrolling interests related to EBIT.

Noncontrolling interests as presented in the following segment-level discussions includes only noncontrolling interests related to EBIT of non-wholly owned entities. 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,
	2009		2008		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	405	$	403	$	2
Operating expenses
Operating, maintenance and other		143		126		17
Depreciation and amortization		59		58		1
Gains on sales of other assets and other, net		10		—		10

Operating income		213		219		(6	)
Other income and expenses		20		21		(1	)
Noncontrolling interests		16		14		2

EBIT	$	217	$	226	$	(9	)

Proportional throughput, TBtu (a)		713		636		77

(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 $2 million increase was driven primarily by:

•

a $25 million increase from expansion projects placed in service in late 2008, and

•

a $15 million increase in transportation and storage revenues due to increased firm storage contracts and recoveries of fuel and electric power costs through transportation revenues, partially offset by

•

a $29 million decrease in processing revenues associated with pipeline operations, caused by both lower prices and volumes, and

•

a $7 million decrease resulting from a weaker Canadian dollar, related to M&N LP.

Operating, Maintenance and Other. The $17 million increase was driven primarily by:

•

a $12 million increase in operating costs including fuel, utilities and software costs, and

•

a $5 million increase in ad valorem taxes, primarily as a result of business expansion projects and capital assets placed in service in late 2008.

Gains on Sales of Other Assets, net. The $10 million recognized in 2009 reflects a customer settlement resulting from the cancellation of a capital project.

EBIT. The $9 million decrease reflects a decrease in processing revenues, partially offset by higher earnings from expansion projects.

Distribution


	Three Months Ended March 31,
	2009		2008		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	708	$	800	$	(92	)
Operating expenses
Natural gas purchased		435		492		(57	)
Operating, maintenance and other		81		97		(16	)
Depreciation and amortization		40		47		(7	)

Operating income		152		164		(12	)
Other income and expenses		—		1		(1	)

EBIT	$	152	$	165	$	(13	)

Number of customers, thousands		1,312		1,293		19
Heating degree days, Fahrenheit		3,698		3,651		47
Pipeline throughput, TBtu		327		327		—

Operating Revenues. The $92 million decrease was driven primarily by:

•

a $167 million decrease resulting from a weaker Canadian dollar, and

•

a $33 million decrease in customer usage of natural gas, partially offset by

•

a $59 million increase from higher natural gas prices passed through to customers without a mark-up,

•

a $24 million increase due to growth in the number of customers, and

•

a $23 million increase in storage and transportation revenues attributable to growth of the storage system and an increase in short-term transportation services provided to customers.

Natural Gas Purchased. The $57 million decrease was driven primarily by:

•

a $102 million decrease resulting from a weaker Canadian dollar, and

•

a $34 million decrease in customer usage of natural gas, partially offset by

•

a $59 million increase from higher natural gas prices passed through to customers without a mark-up, and

•

a $21 million increase due to growth in the number of customers.

Operating, Maintenance and Other. The $16 million decrease was driven primarily by a weaker Canadian dollar.

Depreciation and Amortization. The $7 million decrease was driven primarily by a weaker Canadian dollar.

EBIT. The $13 million decrease was primarily attributable to a weaker Canadian dollar, partially offset by higher storage and transportation revenues during the period.

Western Canada Transmission & Processing


	Three Months Ended March 31,
	2009		2008		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	271	$	397	$	(126	)
Operating expenses
Natural gas and petroleum products purchased		71		130		(59	)
Operating, maintenance and other		88		104		(16	)
Depreciation and amortization		32		36		(4	)

Operating income		80		127		(47	)
Other income and expenses		1		3		(2	)
Noncontrolling interests		—		1		(1	)

EBIT	$	81	$	129	$	(48	)

Pipeline throughput, TBtu		162		162		—
Volumes processed, TBtu		167		173		(6	)
Empress inlet volumes, TBtu		211		217		(6	)

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

•

an $83 million decrease due to lower NGL product prices associated with the Empress operations, and

•

a $64 million decrease as a result of a weaker Canadian dollar, partially offset by

•

a $12 million increase resulting primarily from higher gathering and processing revenues due to higher firm volumes.

Natural Gas and Petroleum Products Purchased. The $59 million decrease was driven primarily by:

•

a $43 million decrease arising from lower prices of natural gas purchased for the Empress facility, and

•

a $16 million decrease caused by a weaker Canadian dollar.

Operating, Maintenance and Other. The $16 million decrease was driven primarily by:

•

a $26 million decrease caused by a weaker Canadian dollar, partially offset by

•

an $8 million increase in costs relating mainly to carbon taxes.

Depreciation and Amortization. The $4 million decrease was driven primarily by a weaker Canadian dollar.

EBIT. The $48 million decrease was driven primarily by lower NGL product prices that negatively impacted the Empress operations, as well as a weaker Canadian dollar.

Field Services


	Three Months Ended March 31,
	2009		2008			Increase (Decrease)
	(in millions, except where noted)
Operating expenses	$	—	$	(1	)	$	1

Operating income		—		1			(1	)
Equity in earnings of unconsolidated affiliates		150		191			(41	)

EBIT	$	150	$	192		$	(42	)

Natural gas gathered and processed/transported, TBtu/d (a,b)		7.0		7.2			(0.2	)
NGL production, MBbl/d (a,c)		331		380			(49	)
Average natural gas price per MMBtu (d)	$	4.89	$	8.03		$	(3.14	)
Average NGL price per gallon (e)	$	0.57	$	1.34		$	(0.77	)

(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 $41 million were primarily the result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:

•

a $173 million decrease from commodity-sensitive processing arrangements, due to decreased commodity prices,

•

a $22 million decrease in gathering and processing margins primarily attributable to lower volumes associated with plant outages, and lower recoveries and efficiencies, and

•

an $8 million decrease due to higher net interest expense resulting from the increased debt associated with growth and acquisitions in 2008, partially offset by

•

a $135 million gain associated with partnership units previously issued by DCP Partners,

•

an $18 million increase in marketing margins related to higher NGL trading results and derivatives timing,

•

a $6 million increase in earnings from DCP Partners primarily as a result of mark-to-market gains on hedges used to protect distributable cash flows, and

•

a $3 million increase primarily as a result of lower operating and maintenance expenses due to cost reduction initiatives, partially offset by higher depreciation expense as a result of capital spending and acquisitions in 2008.

Other


	Three Months Ended March 31,
	2009			2008			Increase (Decrease)
	(in millions)
Operating revenues	$	12		$	9		$	3
Operating expenses		32			28			4

Operating loss		(20	)		(19	)		(1	)
Other income and expenses		(4	)		(1	)		(3	)

EBIT	$	(24	)	$	(20	)	$	(4	)

EBIT. The $4 million increase in net costs reflects an overall increase in the cost of employee benefits in 2009.

LIQUIDITY AND CAPITAL RESOURCES

Net working capital was negative $1,135 million as of March 31, 2009, which included short-term borrowings and commercial paper totaling $405 million and current maturities of long-term debt of $792 million. We will rely primarily upon cash flows from operations and additional financing transactions to fund our liquidity and capital requirements for the next 12 months including issuances of short-term and long-term debt. See Financing Cash Flows and Liquidity for discussions of effective shelf registrations and available credit facilities.

Operating Cash Flows

Net cash provided by operating activities decreased $117 million to $556 million for the three months ended March 31, 2009 compared to the same period in 2008, driven mainly by a $107 million decrease in distributions received from unconsolidated affiliates in 2009, primarily from DCP Midstream, and lower earnings.

Investing Cash Flows

Cash flows used in investing activities decreased $230 million to $142 million in the first three months of 2009 compared to the same period in 2008. This change was driven primarily by a $199 million decrease in capital and investment expenditures in 2009 as a result of projects that were placed into service in 2008 and early 2009 and planned reduced capital expansion levels for 2009 compared to 2008.


	Three Months Ended March 31,
	2009		2008
	(in millions)
Capital and Investment Expenditures
U.S. Transmission	$	99	$	272
Distribution		34		63
Western Canada Transmission & Processing		37		32
Other		6		8

Total	$	176	$	375

Capital and investment expenditures for the three months ended March 31, 2009 consisted of $119 million for expansion projects and $57 million for maintenance and other projects.

We continue to project 2009 capital and investment expenditures of approximately $1.0 billion, excluding the acquisition of NOARK, consisting of approximately $400 million for U.S. Transmission, $200 million for Distribution and $400 million for Western Canada Transmission & Processing. Total projected 2009 capital and investment expenditures include approximately $500 million of expansion capital expenditures and $500 million 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. We anticipate placing approximately $650 million of capital expansion projects into service in 2009.

Financing Cash Flows and Liquidity

Our consolidated capital structure includes long-term debt, short-term borrowings, commercial paper and preferred stock of subsidiaries. As of March 31, 2009, our capital structure was 58% debt, 38% common equity of controlling interests and 4% noncontrolling interests and preferred stock of subsidiaries.

Net cash used in financing activities totaled $405 million in the first three months of 2009 compared to $139 million in the first three months of 2008. This change was driven primarily by:

•

$530 million decrease in short-term borrowings in 2009 compared to a $42 million increase in the 2008 period, and

•

$159 million net payments of long-term debt in 2009 compared to $31 million in 2008, partially offset by

•

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

As previously discussed, on February 13, 2009, in order to further protect our capitalization structure against a potential extreme decline in the Canadian dollar, 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.

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, 2009, this ratio was 58%. Our equity and, as a result, this ratio, are sensitive to significant weakening of the Canadian dollar due to the significance of our Canadian operations.

Credit Ratings


	Standard and Poor’s	Moody’s Investor Service	Dominion Bond Rating Service
As of April 30, 2009
Spectra Capital (a)	BBB	Baa1	Not applicable
Texas Eastern Transmission, LP (a)	BBB+	A3	Not applicable
Westcoast (a)	BBB+	Not applicable	A (low)
Union Gas (a)	BBB+	Not applicable	A
Maritimes & Northeast Pipeline, L.L.C. (a)	BBB	Baa3	Not applicable
Maritimes & Northeast Pipeline Limited Partnership (b)	A	A2	A

(a)	Represents senior unsecured credit rating.

(b)	Represents senior secured credit rating.

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, they are unable to maintain the current balance sheet strength or if earnings or cash flow outlooks deteriorate materially.

On April 28, 2009, Standard & Poor’s affirmed Spectra Energy Corp’s long-term credit rating at “BBB+” (investment grade) and lowered its outlook from “stable” to “negative,” citing concerns over the impact of low commodity prices. Spectra Capital’s and Texas Eastern Transmission, LP’s outlooks were also lowered to “negative” at that time.

Dividends. We currently anticipate an average dividend payout ratio over time of approximately 60% of estimated annual net income from controlling interests per share of common stock and expect to continue our policy of paying regular cash dividends. The actual payout ratio, however, may vary from year to year depending on earnings levels. 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 3, 2009 and will be paid on June 15, 2009.

Other Financing Matters. We have automatic shelf registration statements on file with the SEC to register the issuance of unspecified amounts of various equity and debt securities. In addition, as of the date of this filing, certain of our subsidiaries had 800 million Canadian dollars (approximately $635 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.

As previously discussed, on May 4, 2009, Spectra Energy Partners acquired all of the ownership interests of NOARK from Atlas for approximately $295 million. The transaction was funded by Spectra Energy Partners with $218 million drawn on Spectra Energy Partners’ available bank credit facilities, $70 million borrowed under a credit facility with Spectra Energy and $7 million of cash on hand. Spectra Energy Partners expects long-term financing for the transaction to be a combination of debt and equity consistent with its current and targeted capital structure. See Note 19 of Notes to Condensed Consolidated Financial Statements for further discussion.

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, 2008. We believe the exposure to market risk has not changed materially at March 31, 2009.

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, 2009, 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

As previously reported, the Board of Directors appointed J. Patrick Reddy to the position of Chief Financial Officer of Spectra Energy, effective January 1, 2009. Mr. Reddy replaced Gregory L. Ebel as Chief Financial Officer, who was appointed President and Chief Executive Officer of Spectra Energy effective January 1, 2009, the date of Fred J. Fowler’s retirement.

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, 2009 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, see Note 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, 2008, which could materially affect our financial condition or future results. There were no changes to those risk factors at March 31, 2009.

Item 4.

Submission of Matters to a Vote of Security Holders.

None.

Item 6.

Exhibits.

(a) Exhibits


Exhibit Number
*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.

*	Filed herewith.

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

SIGNATURES

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


				SPECTRA ENERGY CORP

Date: May 8, 2009				/s/ GREGORY L. EBEL
				Gregory L. Ebel
				President and Chief Executive Officer

Date: May 8, 2009				/s/ J. PATRICK REDDY
				J. Patrick Reddy
				Chief Financial Officer