Edgar Filing: Spectra Energy Corp.

Form 10-Q for quarterly period ended June 30, 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 June 30, 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 x No ¨

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

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

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

Number of shares of Common Stock, $0.001 par value, outstanding as of July 31, 2009: 645,907,507

SPECTRA ENERGY CORP

FORM 10-Q FOR THE QUARTER ENDED

June 30, 2009

INDEX


		Page
PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)	4

	Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2009 and 2008	4

	Condensed Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008	5

	Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2009 and 2008	7

	Condensed Consolidated Statements of Stockholders’ Equity for the six months ended June 30, 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	41

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	54

Item 4.	Controls and Procedures	54

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	55

Item 1A.	Risk Factors	55

Item 4.	Submission of Matters to a Vote of Security Holders	55

Item 6.	Exhibits	55

	Signatures	57

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 June 30,						Six Months Ended June 30,
	2009			2008			2009		2008
Operating Revenues
Transportation, storage and processing of natural gas	$	622		$	588		$	1,230	$	1,178
Distribution of natural gas		215			296			850		1,026
Sales of natural gas liquids		64			185			173		404
Other		36			64			68		125

Total operating revenues		937			1,133			2,321		2,733

Operating Expenses
Natural gas and petroleum products purchased		153			275			658		896
Operating, maintenance and other		256			335			520		615
Depreciation and amortization		144			148			280		293
Property and other taxes		67			64			131		125

Total operating expenses		620			822			1,589		1,929

Gains on Sales of Other Assets and Other, net		—			32			10		32

Operating Income		317			343			742		836

Other Income and Expenses
Equity in earnings of unconsolidated affiliates		40			243			207		452
Other income and expenses, net		14			10			23		21

Total other income and expenses		54			253			230		473

Interest Expense		146			149			296		307

Earnings From Continuing Operations Before Income Taxes		225			447			676		1,002
Income Tax Expense From Continuing Operations		67			136			206		308

Income From Continuing Operations		158			311			470		694
Income (Loss) From Discontinued Operations, net of tax		(1	)		(2	)		2		1

Net Income		157			309			472		695
Net Income—Noncontrolling Interests		17			14			34		33

Net Income—Controlling Interests	$	140		$	295		$	438	$	662


Common Stock Data
Weighted-average shares outstanding
Basic		645			630			637		631
Diluted		646			633			638		634
Earnings per share from continuing operations
Basic	$	0.22		$	0.47		$	0.69	$	1.05
Diluted	$	0.22		$	0.47		$	0.69	$	1.04
Earnings per share
Basic	$	0.22		$	0.47		$	0.69	$	1.05
Diluted	$	0.22		$	0.47		$	0.69	$	1.04
Dividends per share	$	0.25		$	0.23		$	0.50	$	0.46

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)


	June 30, 2009		December 31, 2008
ASSETS

Current Assets
Cash and cash equivalents	$	301	$	214
Receivables, net		565		795
Inventory		229		279
Other		136		162

Total current assets		1,231		1,450


Investments and Other Assets
Investments in and loans to unconsolidated affiliates		2,214		2,152
Goodwill		3,654		3,381
Other		350		417

Total investments and other assets		6,218		5,950


Property, Plant and Equipment
Cost		18,512		17,569
Less accumulated depreciation and amortization		4,227		3,930

Net property, plant and equipment		14,285		13,639


Regulatory Assets and Deferred Debits		924		885

Total Assets	$	22,658	$	21,924

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions, except per-share amounts)


	June 30, 2009		December 31, 2008
LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities
Accounts payable	$	260	$	285
Short-term borrowings and commercial paper		—		936
Taxes accrued		145		105
Interest accrued		170		158
Current maturities of long-term debt		979		821
Other		771		739

Total current liabilities		2,325		3,044

Long-term Debt		8,605		8,290


Deferred Credits and Other Liabilities
Deferred income taxes		2,952		2,789
Regulatory and other		1,560		1,566

Total deferred credits and other liabilities		4,512		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, 646 million and 611 million shares outstanding at June 30, 2009 and December 31, 2008, respectively		1		1
Additional paid-in capital		4,664		4,104
Retained earnings		1,012		899
Accumulated other comprehensive income		770		536

Total controlling interests		6,447		5,540
Noncontrolling interests		544		470

Total stockholders’ equity		6,991		6,010

Total Liabilities and Stockholders’ Equity	$	22,658	$	21,924

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)


	Six Months Ended June 30,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	472		$	695
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		286			300
Deferred income tax expense		124			35
Equity in earnings of unconsolidated affiliates		(207	)		(452	)
Distributions received from unconsolidated affiliates		39			439
Other		305			124

Net cash provided by operating activities		1,019			1,141


CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(375	)		(608	)
Investments in and loans to unconsolidated affiliates		(51	)		(322	)
Acquisitions, net of cash acquired		(295	)		(274	)
Purchases of available-for-sale securities		—			(880	)
Proceeds from sales and maturities of available-for-sale securities		32			910
Distributions received from unconsolidated affiliates		148			149
Other		(3	)		1

Net cash used in investing activities		(544	)		(1,024	)


CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt		2,219			1,400
Payments for the redemption of long-term debt		(1,902	)		(903	)
Net decrease in short-term borrowings and commercial paper		(936	)		(48	)
Distributions to noncontrolling interests		(136	)		(25	)
Contributions from noncontrolling interests		2			16
Proceeds from the issuance of Spectra Energy common stock		448			—
Proceeds from the issuance of Spectra Energy Partners, LP common units		208			—
Repurchases of Spectra Energy common stock		—			(284	)
Dividends paid on common stock		(314	)		(292	)
Other		9			13

Net cash used in financing activities		(402	)		(123	)

Effect of exchange rate changes on cash		14			1

Net increase (decrease) in cash and cash equivalents		87			(5	)
Cash and cash equivalents at beginning of period		214			94

Cash and cash equivalents at end of period	$	301		$	89

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									Noncontrolling Interests			Total
	Common Stock		Additional Paid-in Capital			Retained Earnings			Foreign Currency Translation Adjustments			Net Gains (Losses) on Cash Flow Hedges			Other			Noncontrolling Interests			Total
December 31, 2008	$	1	$	4,104		$	899		$	881		$	(17	)	$	(328	)	$	470		$	6,010
Net income		—		—			438			—			—			—			34			472
Foreign currency translation adjustments		—		—			—			211			—			—			4			215
Reclassification of cash flow hedges into earnings		—		—			—			—			(4	)		—			—			(4	)
Unrealized mark-to-market net gain on hedges		—		—			—			—			5			—			—			5
Spectra Energy common stock issuance		—		448			—			—			—			—			—			448
Spectra Energy Partners, LP common unit issuance		—		25			—			—			—			—			168			193
Pension and benefits impact of SFAS No. 158		—		—			—			—			—			22			—			22
Reclassification of deferred gain on sale of units of Spectra Energy Partners, LP		—		59			—			—			—			—			—			59
Dividends on common stock		—		—			(325	)		—			—			—			—			(325	)
Stock-based compensation		—		3			—			—			—			—			—			3
Distributions to noncontrolling interests		—		—			—			—			—			—			(140	)		(140	)
Contributions from noncontrolling interests		—		—			—			—			—			—			2			2
Other, net		—		25			—			—			—			—			6			31

June 30, 2009	$	1	$	4,664		$	1,012		$	1,092		$	(16	)	$	(306	)	$	544		$	6,991


December 31, 2007	$	1	$	4,658		$	368		$	2,033		$	(8	)	$	(195	)	$	581		$	7,438
Net income		—		—			662			—			—			—			33			695
Foreign currency translation adjustments		—		—			—			(145	)		—			—			(3	)		(148	)
Unrealized mark-to-market net gain on hedges		—		—			—			—			14			—			—			14
Pension and benefits impact of SFAS No. 158		—		—			—			—			—			26			—			26
Common stock repurchases		—		(284	)		—			—			—			—			—			(284	)
Dividends on common stock		—		—			(292	)		—			—			—			—			(292	)
Stock-based compensation		—		20			—			—			—			—			—			20
Acquisition of Spectra Energy Income Fund		—		—			—			—			—			—			(206	)		(206	)
Distributions to noncontrolling interests		—		—			—			—			—			—			(25	)		(25	)
Contributions from noncontrolling interests		—		—			—			—			—			—			16			16
Other, net		—		11			—			—			—			—			(1	)		10

June 30, 2008	$	1	$	4,405		$	738		$	1,888		$	6		$	(169	)	$	395		$	7,264

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY CORP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. General

The terms “we,” “our,” “us” and “Spectra Energy” as used in this report refer collectively to Spectra Energy Corp and its subsidiaries unless the context suggests otherwise. These terms are used for convenience only and are not intended as a precise description of any separate legal entity within Spectra Energy.

Nature of Operations. Spectra Energy Corp, through its subsidiaries and equity affiliates, owns and operates a large and diversified portfolio of complementary natural gas-related energy assets, operating in three key areas of the natural gas industry: gathering and processing, transmission and storage, and distribution. We provide transportation and storage of natural gas to customers in various regions of the northeastern and southeastern United States, the Maritime Provinces in Canada and the Pacific Northwest in the United States and Canada, and in the province of Ontario, Canada. We also provide natural gas sales and distribution services to retail customers in Ontario, and natural gas gathering and processing services to customers in Western Canada. In addition, we own a 50% interest in DCP Midstream, LLC (DCP Midstream), one of the largest natural gas gatherers and processors in the United States.

Basis of Presentation. The accompanying Condensed Consolidated Financial Statements include our accounts, our majority-owned subsidiaries where we have control and those variable interest entities, if any, where we are the primary beneficiary. These interim financial statements should be read in conjunction with the consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2008, and reflect all normal recurring adjustments that are, in our opinion, necessary to fairly present our results of operations and financial position. Amounts reported in the Condensed Consolidated Statements of Operations are not necessarily indicative of amounts expected for the respective annual periods due to the effects of seasonal temperature variations on energy consumption, primarily in our gas distribution operations, as well as changing commodity prices on certain of our processing operations and other factors.

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

Change in Accounting Policy. We perform our goodwill impairment test annually and evaluate goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. Since the adoption of Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets,” we have performed the annual impairment testing of goodwill using August 31 as the measurement date. Our financial and strategic planning process, including the preparation of long-term cash flow projections, commences in October and typically concludes in January of the following year. These long-term cash flow projections are a key component in performing our annual impairment test of goodwill. This planning cycle has created significant constraints in the availability of both information and human resources needed to provide the appropriate projections to be used in the goodwill impairment test using the August 31 test date. Accordingly, effective with our 2009 annual impairment test, we have changed our goodwill impairment test date from August 31 to April 1. We believe that using the April 1 date will alleviate the information and resource constraints that historically existed during the third quarter and will better coincide with the completion of our long-term financial projections. We believe that this accounting change is to an alternative accounting principle that is preferable under the circumstances and does not result in the delay, acceleration or avoidance of an impairment charge. We have determined that this change in accounting principle does not result in adjustments to our financial statements when applied retrospectively under the requirements of SFAS No. 154, “Accounting Changes and Error Corrections—a replacement of APB Opinion No. 20 and FASB Statement No. 3,” as we did not record any goodwill impairment charges in any of the prior periods presented.

We completed our goodwill impairment test as of April 1, 2009 and no impairments were identified. See Note 11 for further discussion.

Recasts and Reclassifications. We adopted the provisions of SFAS No. 160, “Noncontrolling Interests 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 21 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), a majority-owned subsidiary, was reclassified from Deferred Credits and Other Liabilities—Regulatory and Other to Additional Paid-in Capital on the Consolidated Balance Sheet as of January 1, 2009.

The Condensed Consolidated Statements of Operations for the three and six-month periods ended June 30, 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 6 for further discussion.

2. Acquisitions

Ozark Gas Transmission and Ozark Gas Gathering Systems. 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 in cash. NOARK’s assets consist of 100% ownership interests in Ozark Gas Transmission, L.L.C., a 565-mile Federal Energy Regulatory Commission (FERC) regulated interstate natural gas transmission system, and Ozark Gas Gathering, L.L.C., a 365-mile, fee-based, state-regulated natural gas gathering system. The transaction was initially funded by Spectra Energy Partners with $218 million drawn on its bank credit facility, $70 million borrowed under a credit facility with Spectra Energy and $7 million of cash on hand. This transaction was partially refinanced by Spectra Energy Partners in the second quarter of 2009 through the issuance of 9.8 million limited partner units to the public and 0.2 million general partner units, resulting in net proceeds of $212 million and a reduction of our ownership interest in Spectra Energy Partners from 84% to 74%. Funds from the sale of the partner units were used by Spectra Energy Partners to repay the $70 million owed to Spectra Energy and $142 million of the amount initially drawn on the Spectra Energy Partners bank credit facility.

The following table summarizes the preliminary fair values of the assets acquired and liabilities assumed as of May 4, 2009. Subsequent adjustments may be recorded upon the completion of the valuation and the final determination of the purchase price allocation.


	Purchase Price Allocation
	(in millions)
Purchase price	$	295

Current assets		5
Property, plant and equipment, net		145
Regulatory assets and deferred debits		5
Current liabilities		(3	)
Deferred credits and other liabilities		(1	)

Total assets acquired/liabilities assumed		151

Goodwill	$	144

Pro forma results of operations reflecting the acquisition of NOARK, part of the U.S. Transmission segment, as if it had occurred as of the beginning of the periods presented in this report do not materially differ from actual reported results.

Spectra Energy Income Fund. In May 2008, we acquired the 24.4 million units of the Spectra Energy Income Fund that were held by non-affiliated holders at a purchase price of 11.25 Canadian dollars per unit, for a total purchase price of 279 million Canadian dollars (approximately $274 million).

3. 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 rules and regulations of the FERC.

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 June 30, 2009
U.S. Transmission	$	413	$	1		$	414		$	234
Distribution		284		—			284			40
Western Canada Transmission & Processing		239		—			239			58
Field Services		—		—			—			24

Total reportable segments		936		1			937			356
Other		1		11			12			(12	)
Eliminations		—		(12	)		(12	)		—
Interest expense		—		—			—			(146	)
Interest income and other (b)		—		—			—			27

Total consolidated	$	937	$	—		$	937		$	225


Three Months Ended June 30, 2008
U.S. Transmission	$	399	$	1		$	400		$	244
Distribution		353		—			353			54
Western Canada Transmission & Processing		380		—			380			91
Field Services		—		—			—			216

Total reportable segments		1,132		1			1,133			605
Other		1		11			12			(28	)
Eliminations		—		(12	)		(12	)		—
Interest expense		—		—			—			(149	)
Interest income and other (b)		—		—			—			19

Total consolidated	$	1,133	$	—		$	1,133		$	447


Six Months Ended June 30, 2009
U.S. Transmission	$	816	$	3		$	819		$	451
Distribution		992		—			992			192
Western Canada Transmission & Processing		510		—			510			139
Field Services		—		—			—			174

Total reportable segments		2,318		3			2,321			956
Other		3		21			24			(36	)
Eliminations		—		(24	)		(24	)		—
Interest expense		—		—			—			(296	)
Interest income and other (b)		—		—			—			52

Total consolidated	$	2,321	$	—		$	2,321		$	676


Six Months Ended June 30, 2008
U.S. Transmission	$	801	$	2		$	803		$	470
Distribution		1,153		—			1,153			219
Western Canada Transmission & Processing		777		—			777			220
Field Services		—		—			—			408

Total reportable segments		2,731		2			2,733			1,317
Other		2		19			21			(48	)
Eliminations		—		(21	)		(21	)		—
Interest expense		—		—			—			(307	)
Interest income and other (b)		—		—			—			40

Total consolidated	$	2,733	$	—		$	2,733		$	1,002

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

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

4. 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.

In the second quarter of 2009, we recorded an $11 million charge to Operating Revenues – Distribution of Natural Gas as a result of a settlement with Union Gas’ stakeholders in June 2009 that was subsequently approved by the OEB. The settlement preserves the incentive regulation framework and replaces the provision for a review of the framework with a 90/10 sharing mechanism, in favor of customers, for any utility earnings of 300 basis points or more above the benchmark utility return on equity (ROE) for the year and is retroactive to 2008. The $11 million charge represents the adjustment to credit customers with 90% of Union Gas’ 2008 utility earnings that exceeded the 2008 benchmark utility ROE by 300 basis points.

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 were set to equal the 2008 rates. The final 2009 toll settlement rates were approved by the NEB in April 2009. M&N LP implemented the new rates on a prospective basis effective May 1, 2009 such that the total tolls charged during 2009 will result in revenues equal to those had the new 2009 rates been in effect for the entire year.

Maritimes & Northeast Pipeline, L.L.C. (M&N LLC). On July 1, 2009, M&N LLC filed a rate case with the FERC. The rate case includes the impact of the Phase IV expansion facilities that went into service January 15, 2009 and results in lower recourse rates. The lower recourse rates did not impact the rates negotiated with customers for service, which are charged to customers for over 90% of M&N LLC’s capacity, including the Phase IV expansion facilities.

5. Income Taxes

Income tax expense from continuing operations for the three and six-month periods ended June 30, 2009 was $67 million and $206 million, respectively, compared to $136 million and $308 million in the same periods in 2008, decreasing primarily as a result of lower earnings in 2009.

The effective tax rate for income from continuing operations for the three months ended June 30, 2009 was 29.8% as compared to 30.4% for the same period in 2008. The effective tax rate for income from continuing operations for the six months ended June 30, 2009 was 30.5% as compared to 30.7% for the same period in 2008.

We recognized no material changes in unrecognized tax benefits during the three and six-month periods ended June 30, 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 June 30, 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.

6. 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 periods 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 (Loss) From Discontinued Operations, Net of Tax, in the Condensed Consolidated Statements of Operations.


	Operating Revenues		Pre-tax Earnings (Loss)			Income Tax Expense (Benefit)			Income (Loss) From Discontinued Operations, Net of Tax
	(in millions)
Three Months Ended June 30, 2009
Other	$	23	$	(1	)	$	—		$	(1	)

Total consolidated	$	23	$	(1	)	$	—		$	(1	)

Three Months Ended June 30, 2008
Western Canada Transmission & Processing	$	8	$	(3	)	$	(1	)	$	(2	)
Other		30		1			1			—

Total consolidated	$	38	$	(2	)	$	—		$	(2	)

Six Months Ended June 30, 2009
Other	$	66	$	3		$	1		$	2

Total consolidated	$	66	$	3		$	1		$	2

Six Months Ended June 30, 2008
Western Canada Transmission & Processing	$	16	$	1		$	—		$	1
Other		30		1			1			—

Total consolidated	$	46	$	2		$	1		$	1

7. Comprehensive Income

Components of comprehensive income are as follows:


	Three Months Ended June 30,					Six Months Ended June 30,
	2009			2008		2009			2008
	(in millions)
Net income	$	157		$	309	$	472		$	695
Other comprehensive income (loss)
Foreign currency translation adjustments		420			25		215			(148	)
Unrealized mark-to-market net gain on hedges (a)		11			17		5			14
Reclassification of cash flow hedges into earnings (b)		(4	)		—		(4	)		—
Pension and benefits impact of SFAS No. 158 (c)		18			6		22			26

Total comprehensive income, net of tax		602			357		710			587
Less: comprehensive income—noncontrolling interests		23			18		38			30

Comprehensive income—controlling interests	$	579		$	339	$	672		$	557

(a)	Net of $6 million and $4 million of tax expense for the three months ended June 30, 2009 and 2008, respectively, and $3 million of tax expense for both the six months ended June 30, 2009 and 2008. See Note 16 for further details of these amounts.

(b)	Net of $4 million tax benefit for both the three and six months ended June 30, 2009. See Note 16 for further details of these amounts.

(c)	Net of $7 million and $1 million of tax expense for the three months ended June 30, 2009 and 2008, respectively, and $9 million of tax expense and $15 million of tax benefits for the six months ended June 30, 2009 and 2008, respectively.

8. Earnings per Common Share

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

The following table presents our basic and diluted EPS calculations:


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009		2008
	(in millions, except per-share amounts)
Income from continuing operations, net of tax—controlling interests	$	141		$	297		$	436	$	663
Income (loss) from discontinued operations, net of tax—controlling interests		(1	)		(2	)		2		(1	)

Net income—controlling interests	$	140		$	295		$	438	$	662


Weighted-average common shares, outstanding
Basic		645			630			637		631
Diluted		646			633			638		634

Basic earnings per common share
Continuing operations	$	0.22		$	0.47		$	0.69	$	1.05
Discontinued operations, net of tax		—			—			—		—

Total basic earnings per common share	$	0.22		$	0.47		$	0.69	$	1.05


Diluted earnings per common share
Continuing operations	$	0.22		$	0.47		$	0.69	$	1.04
Discontinued operations, net of tax		—			—			—		—

Total diluted earnings per common share	$	0.22		$	0.47		$	0.69	$	1.04

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 11 million and six million shares for the three months ended June 30, 2009 and 2008, respectively, and 12 million and six million shares for the six months ended June 30, 2009 and 2008, respectively, were not included in the calculation of diluted EPS because either the option exercise prices were greater than the average market price of the common shares during these periods or performance measures related to the awards had not yet been met.

9. Inventory

Inventory consists primarily of natural gas and NGLs held in storage for transmission and processing, and also includes materials and supplies. Natural gas inventories primarily relate to the Distribution segment in Canada and are valued at costs approved by the OEB. The difference between the approved price and the actual cost of gas purchased is recorded in either accounts receivable or other current liabilities, as appropriate, for future disposition with customers, subject to approval by the OEB. The remaining inventory is recorded at cost, primarily using average cost. The components of inventory are as follows:


	June 30, 2009		December 31, 2008
	(in millions)
Natural gas	$	114	$	180
NGLs		29		16
Materials and supplies		86		83

Total inventory	$	229	$	279

10. Investments in and Loans to Unconsolidated Affiliates

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
	(in millions)
Operating revenues	$	1,806	$	4,831	$	3,733	$	8,877
Operating expenses		1,718		4,475		3,541		8,109
Operating income		88		356		192		768
Net income		22		321		65		698
Net income attributable to members’ interests		50		433		80		816

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 6, we entered into a propane sales agreement with an affiliate of DCP Midstream in the second quarter of 2008. We recorded revenues of $10 million and $14 million in the three months ended June 30, 2009 and 2008, respectively, and $44 million and $14 million in the six months ended June 30, 2009 and 2008, respectively, associated with this agreement, classified within Income (Loss) from Discontinued Operations, Net of Tax.

We have made loans to Steckman Ridge, LP, an equity affiliate, in connection with the construction of its storage facilities. The loan receivable from Steckman Ridge, LP, including accrued interest, totaled $65 million at June 30, 2009 and $45 million at December 31, 2008.

On May 27, 2009, we received a $148 million special distribution from Gulfstream Natural Gas System, L.L.C. (Gulfstream), a 50% owned equity affiliate, from the proceeds of a debt issuance by Gulfstream, of which $144 million was classified as Cash Flows from Investing Activities—Distributions Received From Unconsolidated Affiliates on the Condensed Consolidated Statement of Cash Flows.

11. Goodwill

We completed our annual goodwill impairment test as of April 1, 2009 and no impairments were identified. We primarily use a discounted cash flow analysis to determine fair value for each reporting unit. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in key markets served by our operations, regulatory stability, the ability to renew contracts, commodity prices (where appropriate), and foreign currency exchange rates, as well as other factors that affect our revenue, expense and capital expenditure projections.

The long-term growth rates used for our reporting units reflect continued expansion of our assets, driven by new natural gas supplies such as shale gas in North America and, notwithstanding the current economic downturn, increasing demand for capacity on our pipeline systems. However, even if we assumed a zero growth rate for any reporting unit, there would be no impairment of goodwill.

We continue to monitor the effects of the economic downturn that global economies are currently facing on the long-term cost of capital utilized to calculate our reporting unit fair values. However, a 1% increase in the weighted-average cost of capital assumption for any of our reporting units would not result in an impairment of goodwill. Additionally, for our regulated businesses in Canada, if an increase in the cost of capital occurred, the effect on the corresponding reporting unit’s fair value would be ultimately offset by a similar increase in the reporting unit’s regulated revenues since those rates include a component that is based on the reporting unit’s cost of capital.

The following table presents activity within goodwill based on the reporting unit determination.


	December 31, 2008		Increases (a)		June 30, 2009
	(in millions)
U.S. Transmission	$	2,019	$	213	$	2,232
Distribution		727		32		759
Western Canada Transmission & Processing		635		28		663

Total consolidated	$	3,381	$	273	$	3,654

(a)

Increases consist of $144 million of goodwill at U.S. Transmission associated with the May 2009 acquisition of NOARK (See Note 2 for further discussion) and foreign currency translation.

12.

Debt and Credit Facilities

Available Credit Facilities and Restrictive Debt Covenants


					Outstanding at June 30, 2009
	Expiration Date	Credit Facilities Capacity			Commercial Paper		Revolving Loan		Letters of Credit		Total
		(in millions)
Spectra Energy Capital, LLC	2012	$	1,500	(a)	$	—	$	—	$	11	$	11
Westcoast Energy, Inc.	2011		172	(b)		—		—		—		—
Union Gas	2012		430	(c)		—		—		—		—
Spectra Energy Partners	2012		500			—		240		—		240

Total		$	2,602		$	—	$	240	$	11	$	251

(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 June 30, 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 June 30, 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.

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 June 30, 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.

Debt Issuance

On May 14, 2009, M&N LLC, a 78% owned subsidiary, issued $500 million aggregate principal amount of its 7.5% Senior Notes due 2014. Net proceeds from the offering were used to fund cash distributions to its members. Spectra Energy’s share of those cash distributions were used for general corporate purposes.

13. 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:


Description	Balance Sheet Caption	June 30, 2009
Description	Balance Sheet Caption	Total		Level 1		Level 2		Level 3
		(in millions)
Money market instruments	Cash and cash equivalents	$	113	$	—	$	113	$	—
Corporate debt securities	Cash and cash equivalents		132		—		132		—
Long-term derivative assets	Investments and other assets-other		33		—		9		24
Money market funds	Investments and other assets-other		30		30		—		—

Total Assets		$	308	$	30	$	254	$	24

Long-term derivative liabilities	Deferred credits and other liabilities-regulatory and other	$	18	$	—	$	18	$	—

Total Liabilities		$	18	$	—	$	18	$	—


		December 31, 2008
Description	Balance Sheet Caption	Total		Level 1		Level 2		Level 3
		(in millions)
Money market funds	Cash and cash equivalents	$	60	$	60	$	—	$	—
Debt securities issued by foreign governments	Cash and cash equivalents		6		6		—		—
Corporate debt securities	Cash and cash equivalents		105		—		105
Money market funds	Current assets-other		13		13		—		—
Short-term derivative assets	Current assets-other		13		—		13		—
Money market funds	Investments and other assets-other		51		51		—		—
Corporate debt securities	Investments and other assets-other		25		—		25		—
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)
Three Months Ended June 30, 2009
Fair value at March 31, 2009	$	—	$	—	$	26		$	—
Total gains or losses (realized/unrealized):
Included in earnings		—		—		(3	)		—
Included in Investments and Other Assets—Other		—		—		3			—
Included in other comprehensive income		—		—		(2	)		—

Fair value at June 30, 2009	$	—	$	—	$	24		$	—

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 June 30, 2009	$	—	$	—	$	(3	)	$	—


	Short-Term Derivative Assets		Short-Term Derivative Liabilities			Long-Term Derivative Assets			Long-Term Derivative Liabilities
	(in millions)
Three Months Ended June 30, 2008
Fair value at March 31, 2008	$	51	$	(7	)	$	62		$	—
Total gains or losses (realized/unrealized):
Included in earnings		—		—			—			—
Included in regulatory assets		55		—			—			—
Included in other comprehensive income		—		2			17			—
Normal purchases and sales election under SFAS No. 133		—		—			—			—
Purchases, issuances and settlements		2		5			—			—

Fair value at June 30, 2008	$	108	$	—		$	79		$	—

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 June 30, 2008	$	—	$	—		$	—		$	—


Six Months Ended June 30, 2009
Fair value at December 31, 2008	$	—	$	—		$	36		$	—
Total gains or losses (realized/unrealized):
Included in earnings		—		—			(4	)		—
Included in Investments and Other Assets—Other		—		—			1			—
Included in other comprehensive income		—		—			(9	)		—

Fair value at June 30, 2009	$	—	$	—		$	24		$	—

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 June 30, 2009	$	—	$	—		$	(4	)	$	—


Six Months Ended June 30, 2008
Fair value at December 31, 2007	$	—	$	—		$	47		$	(21	)
Total gains or losses (realized/unrealized):
Included in earnings		—		—			11			(11	)
Included in regulatory assets		105		—			—			—
Included in other comprehensive income		—		(5	)		21			—
Normal purchases and sales election under SFAS No. 133		—		—			—			32
Purchases, issuances and settlements		3		5			—			—

Fair value at June 30, 2008	$	108	$	—		$	79		$	—

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 June 30, 2008	$	—	$	—		$	11		$	(11	)

Level 2 Valuation Techniques

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

Level 3 Valuation Techniques

Financial instruments are considered Level 3 when their values are determined using pricing models, discounted cash flow methodologies or similar techniques where at least one significant model assumption or input is unobservable. Level 3 financial instruments also include those for which the determination of fair value requires significant management judgment or estimation.

The fair values of Level 3 derivative instruments are estimated using proprietary valuation models that utilize both market observable and unobservable parameters. The long-term derivative asset and liability is valued using internal valuation models and techniques that include such inputs as forward natural gas and power prices, forward interest rates and foreign currency assumptions. The short-term derivative asset is valued based upon interest rates, natural gas options pricing for current and future months including volatility, foreign exchange fluctuations and swap values.

Financial Instruments. The fair value of financial instruments, excluding derivatives included elsewhere in this Note and in Note 16, is summarized in the following table. Judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates determined as of June 30, 2009 and December 31, 2008, are not necessarily indicative of the amounts we could have realized in current markets.


	June 30, 2009				December 31, 2008
	Book Value		Approximate Fair Value		Book Value		Approximate Fair Value
	(in millions)
Long-term debt (a)	$	9,584	$	10,022	$	9,111	$	8,996
Long-term SFAS No. 115 securities		10		10		46		46
Other long-term assets		444		438		430		427

(a)	Includes current maturities.

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

During 2009, there were no adjustments to assets and liabilities measured at fair value on a nonrecurring basis.

14. 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 $17 million at both June 30, 2009 and 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 June 30, 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 15 for a discussion of guarantees and indemnifications.

15. Guarantees and Indemnifications

We have various financial guarantees and indemnifications which are issued in the normal course of business. As discussed below, these contracts include financial guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. We enter into these arrangements to facilitate a commercial transaction with a third party by enhancing the value of the transaction to the third party. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on the Condensed Consolidated Balance Sheets. The possibility of having to 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 June 30, 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 June 30, 2009 was $56 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 June 30, 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.

16. 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 June 30, 2009


Asset/(Liability)	Maturity in 2009			Maturity in 2010		Maturity in 2011		Maturity in 2012 and Thereafter			Total Carrying Value
	(in millions)
Hedging	$	(1	)	$	3	$	4	$	27		$	33
Undesignated		—			—		—		(18	)		(18	)

Total	$	(1	)	$	3	$	4	$	9		$	15

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 any 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 is reported in Other Income and Expenses, net 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 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 32 million British thermal units as of June 30, 2009.

As of June 30, 2009, $1 million of pre-tax deferred net losses on derivative instruments related to commodity cash flow hedges were accumulated in Accumulated Other Comprehensive Income (AOCI) on the Condensed Consolidated Balance Sheet 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 June 30,
	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	$	—	$	—	$	2		$	(1	)

	Six Months Ended June 30,
	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	$	—	$	—	$	(3	)	$	3

In the first quarter of 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 in the Condensed Consolidated Balance Sheet: $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 the first half of 2009, we entered into interest rate swap agreements to mitigate our exposure to variable interest rates on $190 million of loans outstanding under certain revolving loan facilities. As of June 30, 2009, the notional amount of our total outstanding interest rate swaps was $190 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 significant foreign currency derivative transactions during the six-month periods ended June 30, 2009 or 2008. 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	June 30, 2009		December 31, 2008
		(in millions)
Asset Derivatives
Natural gas purchase contract	Investments and other assets—other	$	24	$	36
Interest rate swaps	Investments and other assets—other		9		53

Total		$	33	$	89


Derivatives Not Designated as Hedging Instruments	Condensed Consolidated Balance Sheets Caption	June 30, 2009		December 31, 2008
		(in millions)
Liability Derivatives
Interest rate swaps	Deferred credits and other liabilities— regulatory and other	$	18	$	23

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


	Three Months Ended June 30,				Six Months Ended June 30,
Cash Flow Hedging Derivatives	2009		2008		2009		2008
	(in millions)
Natural gas purchase contract	$	8	$	17	$	1	$	21
Interest rate swaps		3		—		4		(7	)

Total	$	11	$	17	$	5	$	14

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

Cash Flow Hedging Derivatives

Condensed Consolidated Statements
of Operations Caption

Three Months Ended
June 30,

Six Months Ended
June 30,

2009

2008

2009

2008

(in millions)

Natural gas purchase contracts

Other income and expenses, net

—

The reclassifications from AOCI into income, net of tax, on our derivative assets and liabilities follow:


	Three Months Ended June 30,					Six Months Ended June 30,
Cash Flow Hedging Derivatives	2009			2008		2009			2008
	(in millions)
Natural gas purchase contract	$	(5	)	$	—	$	(5	)	$	—
Interest rate swaps		1			—		1			—

Total	$	(4	)	$	—	$	(4	)	$	—

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 $85 million at June 30, 2009 and $121 million at December 31, 2008, which represent cash collateral posted by third parties with us.

17. Sales of Common Stock

On February 13, 2009, we issued 32.2 million shares of Spectra Energy 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.

18. Sale of Spectra Energy Partners Partner Units

As previously discussed, in the second quarter of 2009, Spectra Energy Partners issued 9.8 million limited partner units and 0.2 million general partner units in connection with the refinancing of the purchase of NOARK, resulting in net proceeds of $212 million and a reduction of our ownership interest in Spectra Energy Partners from 84% to 74%. See Note 2 for further discussion.

In connection with the sale of the partner units, a $40 million gain ($25 million net of tax) resulting from the dilution of our ownership interest in Spectra Energy Partners was recorded to Additional Paid-in Capital on the Condensed Consolidated Balance Sheet.

The following table reflects Net Income—Controlling Interests and transfers from Noncontrolling Interests related to the sale of the partner units.


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
	(in millions)
Net Income—Controlling Interests	$	140	$	295	$	438	$	662
Increase in Additional Paid-in Capital		25		—		25		—

Total change from Net Income—Controlling Interests and transfers from Noncontrolling Interests	$	165	$	295	$	463	$	662

19. 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 six-month periods ended June 30, 2009 and 2008, and do not currently anticipate making contributions to these 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 $17 million and $18 million during the six-month periods ended June 30, 2009 and 2008, respectively. We anticipate that we will make total contributions of approximately $53 million to the Canadian DB plans in 2009. We also made contributions to the Canadian DC plan of $2 million during each of the six-month periods ended June 30, 2009 and 2008. We anticipate that we will make total contributions of approximately $5 million to the Canadian DC plans in 2009.

Qualified Pension Plans—Components of Net Periodic Pension Cost


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(in millions)
U.S.
Service cost benefit earned	$	3		$	3		$	5		$	5
Interest cost on projected benefit obligation		6			7			13			14
Expected return on plan assets		(8	)		(9	)		(16	)		(18	)
Amortization of loss		1			—			2			1

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


Canada
Service cost benefit earned	$	3		$	4		$	6		$	8
Interest cost on projected benefit obligation		9			10			18			20
Expected return on plan assets		(10	)		(12	)		(20	)		(24	)
Amortization of loss		—			1			1			3
Amortization of prior service costs		1			—			1			—

Net periodic pension cost	$	3		$	3		$	6		$	7

Non-Qualified Pension Benefits Plans—Components of Net Periodic Pension Cost
	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(in millions)
U.S.
Interest cost on projected benefit obligation	$	1		$	1		$	1		$	1

Net periodic pension cost	$	1		$	1		$	1		$	1


Canada
Service cost benefit earned	$	1		$	—		$	1		$	1
Interest cost on projected benefit obligation		1			2			2			3

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

Other Post-Retirement Benefit Plans. We provide certain health care and life insurance benefits for retired employees on a contributory and non-contributory basis. Employees are eligible for these benefits if they have met age and service requirements at retirement, as defined in the plans.

Other Post-Retirement Benefit Plans—Components of Net Periodic Benefit Cost


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(in millions)
U.S.
Interest cost on accumulated post-retirement benefit obligation	$	3		$	3		$	7		$	7
Expected return on plan assets		(2	)		(2	)		(3	)		(3	)
Amortization of net transition liability		2			2			3			3
Amortization of loss		1			1			1			1

Net periodic other post-retirement benefit cost	$	4		$	4		$	8		$	8


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

Net periodic other post-retirement benefit cost	$	1		$	2		$	3		$	4

20. 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 June 30, 2009

(In millions)


	Spectra Energy Corp			Spectra Capital		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Total operating revenues	$	—		$	—	$	937		$	—		$	937
Total operating expenses		(7	)		—		627			—			620
Gains on sales of other assets and other, net		—			—		—			—			—

Operating income		7			—		310			—			317
Equity in earnings of unconsolidated affiliates		—			—		40			—			40
Equity in earnings of subsidiaries		135			215		—			(350	)		—
Other income and expenses, net		—			16		(2	)		—			14
Interest expense		—			52		94			—			146

Earnings from continuing operations before income taxes		142			179		254			(350	)		225
Income tax expense from continuing operations		2			44		21			—			67

Income from continuing operations		140			135		233			(350	)		158
Loss from discontinued operations, net of tax		—			—		(1	)		—			(1	)

Net income		140			135		232			(350	)		157
Net income—noncontrolling interests		—			—		17			—			17

Net income—controlling interests	$	140		$	135	$	215		$	(350	)	$	140

Spectra Energy Corp

Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2008

(In millions)


	Spectra Energy Corp			Spectra Capital			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Total operating revenues	$	—		$	—		$	1,133		$	—		$	1,133
Total operating expenses		5			1			816			—			822
Gains on sales of other assets and other, net		—			—			32			—			32

Operating income (loss)		(5	)		(1	)		349			—			343
Equity in earnings of unconsolidated affiliates		—			—			243			—			243
Equity in earnings of subsidiaries		299			475			—			(774	)		—
Other income and expenses, net		(1	)		4			7			—			10
Interest expense		—			51			98			—			149

Earnings from continuing operations before income taxes		293			427			501			(774	)		447
Income tax expense (benefit) from continuing operations		(2	)		128			10			—			136

Income from continuing operations		295			299			491			(774	)		311
Loss from discontinued operations, net of tax		—			—			(2	)		—			(2	)

Net income		295			299			489			(774	)		309
Net income—noncontrolling interests		—			—			14			—			14

Net income—controlling interests	$	295		$	299		$	475		$	(774	)	$	295

Spectra Energy Corp

Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2009

(In millions)


	Spectra Energy Corp			Spectra Capital			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Total operating revenues	$	—		$	—		$	2,321	$	—		$	2,321
Total operating expenses		5			1			1,583		—			1,589
Gains on sales of other assets and other, net		—			—			10		—			10

Operating income (loss)		(5	)		(1	)		748		—			742
Equity in earnings of unconsolidated affiliates		—			—			207		—			207
Equity in earnings of subsidiaries		441			681			—		(1,122	)		—
Other income and expenses, net		—			23			—		—			23
Interest expense		—			109			187		—			296

Earnings from continuing operations before income taxes		436			594			768		(1,122	)		676
Income tax expense (benefit) from continuing operations		(2	)		153			55		—			206

Income from continuing operations		438			441			713		(1,122	)		470
Income from discontinued operations, net of tax		—			—			2		—			2

Net income		438			441			715		(1,122	)		472
Net income—noncontrolling interests		—			—			34		—			34

Net income—controlling interests	$	438		$	441		$	681	$	(1,122	)	$	438

Spectra Energy Corp

Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2008

(In millions)


	Spectra Energy Corp			Spectra Capital			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Total operating revenues	$	—		$	—		$	2,733	$	—		$	2,733
Total operating expenses		10			1			1,918		—			1,929
Gains on sales of other assets and other, net		—			—			32		—			32

Operating income (loss)		(10	)		(1	)		847		—			836
Equity in earnings of unconsolidated affiliates		—			—			452		—			452
Equity in earnings of subsidiaries		670			1,027			—		(1,697	)		—
Other income and expenses, net		(2	)		6			17		—			21
Interest expense		—			109			198		—			307

Earnings from continuing operations before income taxes		658			923			1,118		(1,697	)		1,002
Income tax expense (benefit) from continuing operations		(4	)		253			59		—			308

Income from continuing operations		662			670			1,059		(1,697	)		694
Income from discontinued operations, net of tax		—			—			1		—			1

Net income		662			670			1,060		(1,697	)		695
Net income—noncontrolling interests		—			—			33		—			33

Net income—controlling interests	$	662		$	670		$	1,027	$	(1,697	)	$	662

Spectra Energy Corp

Condensed Consolidating Balance Sheet

June 30, 2009

(In millions)


	Spectra Energy Corp			Spectra Capital		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash and cash equivalents	$	—		$	3	$	298		$	—		$	301
Receivables (payables)—consolidated subsidiaries		(9	)		248		(223	)		(16	)		—
Receivables—other		—			3		562			—			565
Other current assets		7			27		331			—			365

Total current assets		(2	)		281		968			(16	)		1,231
Investments in and loans to unconsolidated affiliates		—			391		1,823			—			2,214
Investments in consolidated subsidiaries		8,388			11,455		—			(19,843	)		—
Advances receivable (payable)—consolidated subsidiaries		(1,762	)		2,371		(262	)		(347	)		—
Goodwill		—			—		3,654			—			3,654
Other assets		35			22		293			—			350
Property, plant and equipment, net		—			—		14,285			—			14,285
Regulatory assets and deferred debits		1			14		909			—			924

Total Assets	$	6,660		$	14,534	$	21,670		$	(20,206	)	$	22,658


Accounts payable (receivable)—consolidated subsidiaries	$	—		$	41	$	(25	)	$	(16	)	$	—
Accounts payable—other		6			72		182			—			260
Short-term borrowings and commercial paper		—			347		—			(347	)		—
Accrued taxes payable (receivable)		(51	)		49		147			—			145
Current maturities of long-term debt		—			498		481			—			979
Other current liabilities		40			101		800			—			941

Total current liabilities		(5	)		1,108		1,585			(363	)		2,325
Long-term debt		—			2,979		5,626			—			8,605
Deferred credits and other liabilities		218			2,059		2,235			—			4,512
Preferred stock of subsidiaries		—			—		225			—			225
Total stockholders’ equity		6,447			8,388		11,999			(19,843	)		6,991

Total Liabilities and Stockholders’ Equity	$	6,660		$	14,534	$	21,670		$	(20,206	)	$	22,658

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

Six Months Ended June 30, 2009

(In millions)


	Spectra Energy Corp			Spectra Capital			Non-Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	438		$	441		$	715		$	(1,122	)	$	472
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		—			—			286			—			286
Equity in earnings of unconsolidated affiliates		—			—			(207	)		—			(207	)
Equity in earnings of subsidiaries		(441	)		(681	)		—			1,122			—
Distributions received from unconsolidated affiliates		—			—			39			—			39
Other		53			200			176			—			429

Net cash provided by (used in) operating activities		50			(40	)		1,009			—			1,019

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		—			—			(375	)		—			(375	)
Investments in and loans to unconsolidated affiliates		—			(23	)		(28	)		—			(51	)
Acquisition of NOARK		—			—			(295	)		—			(295	)
Proceeds from sales and maturities of available-for-sale securities		—			—			32			—			32
Distributions received from unconsolidated affiliates		—			—			148			—			148
Other		—			—			(3	)		—			(3	)

Net cash used in investing activities		—			(23	)		(521	)		—			(544	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt		—			—			2,219			—			2,219
Payments for the redemption of long-term debt		—			(163	)		(1,739	)		—			(1,902	)
Net decrease in short-term borrowings and commercial paper		—			(768	)		(168	)		—			(936	)
Distributions to noncontrolling interests		—			—			(136	)		—			(136	)
Contributions from noncontrolling interests		—			—			2			—			2
Proceeds from the issuance of Spectra Energy common stock		448			—			—			—			448
Proceeds from the issuance of Spectra Energy Partners, LP common units		—			—			208			—			208
Dividends paid on common stock		(314	)		(8	)		—			8			(314	)
Distributions and advances to parent		(196	)		945			(741	)		(8	)		—
Other		12			—			(3	)		—			9

Net cash provided by (used in) financing activities		(50	)		6			(358	)		—			(402	)

Effect of exchange rate changes on cash		—			—			14			—			14

Net increase (decrease) in cash and cash equivalents		—			(57	)		144			—			87
Cash and cash equivalents at beginning of period		—			60			154			—			214

Cash and cash equivalents at end of period	$	—		$	3		$	298		$	—		$	301

Spectra Energy Corp

Condensed Consolidating Statements of Cash Flows

Six Months Ended June 30, 2008

(In millions)


	Spectra Energy Corp			Spectra Capital			Non-Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	662		$	670		$	1,060		$	(1,697	)	$	695
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		—			—			300			—			300
Equity in earnings of unconsolidated affiliates		—			—			(452	)		—			(452	)
Equity in earnings of subsidiaries		(670	)		(1,027	)		—			1,697			—
Distributions received from unconsolidated affiliates		—			—			439			—			439
Other		(179	)		292			46			—			159

Net cash provided by (used in) operating activities		(187	)		(65	)		1,393			—			1,141

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		—			—			(608	)		—			(608	)
Investments in and loans to unconsolidated affiliates		—			(105	)		(217	)		—			(322	)
Acquisition of Spectra Energy Income Fund		—			—			(274	)		—			(274	)
Purchases of available-for-sale securities		—			—			(880	)		—			(880	)
Proceeds from sales and maturities of available-for-sale securities		—			—			910			—			910
Distributions received from unconsolidated affiliates		—			—			149			—			149
Other		—			—			1			—			1

Net cash used in investing activities		—			(105	)		(919	)		—			(1,024	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt		—			500			900			—			1,400
Payments for the redemption of long-term debt		—			—			(903	)		—			(903	)
Net increase (decrease) in short-term borrowings and commercial paper		—			105			(153	)		—			(48	)
Distributions to noncontrolling interests		—			—			(25	)		—			(25	)
Contributions from noncontrolling interests		—			—			16			—			16
Repurchases of Spectra Energy common stock		(284	)		—			—			—			(284	)
Dividends paid on common stock		(292	)		(7	)		—			7			(292	)
Distributions and advances to parent		763			(428	)		(328	)		(7	)		—
Other		—			—			13			—			13

Net cash provided by (used in) financing activities		187			170			(480	)		—			(123	)

Effect of exchange rate changes on cash		—			—			1			—			1

Net decrease in cash and cash equivalents		—			—			(5	)		—			(5	)
Cash and cash equivalents at beginning of period	<

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