Edgar Filing: Spectra Energy Corp.

Form 10-Q for quarterly period ended June 30, 2012

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, 2012

¨	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

LOGO

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 June 30, 2012: 652,870,488

SPECTRA ENERGY CORP

FORM 10-Q FOR THE QUARTER ENDED

June 30, 2012

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, 2012 and 2011		4

	Condensed Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2012 and 2011		5

	Condensed Consolidated Balance Sheets as of June 30, 2012 and December 31, 2011		6

	Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2012 and 2011		8

	Condensed Consolidated Statements of Equity for the six months ended June 30, 2012 and 2011		9

	Notes to Condensed Consolidated Financial Statements		10

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		35

Item 3.	Quantitative and Qualitative Disclosures about Market Risk		48

Item 4.	Controls and Procedures		48

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings		49

Item 1A.	Risk Factors		49

Item 6.	Exhibits		49

	Signatures		50

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This document includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are based on management’s beliefs and assumptions. These forward-looking statements are identified by terms and phrases such as: anticipate, believe, intend, estimate, expect, continue, should, could, may, plan, project, predict, will, potential, forecast, and similar expressions. Forward-looking statements involve risks and uncertainties that may cause actual results to be materially different from the results predicted. Factors that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

•

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

•

outcomes of litigation and regulatory investigations, proceedings or inquiries;

•

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

•

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

•

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

•

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

•

changes in environmental, safety and other laws and regulations;

•

the development of alternative energy resources;

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

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

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements.

SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In millions, except per-share amounts)


	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Operating Revenues
Transportation, storage and processing of natural gas	$	784	$	773	$	1,615	$	1,564
Distribution of natural gas		240		286		745		893
Sales of natural gas liquids		56		93		205		270
Other		32		36		91		73

Total operating revenues		1,112		1,188		2,656		2,800

Operating Expenses
Natural gas and petroleum products purchased		146		180		579		665
Operating, maintenance and other		334		347		655		661
Depreciation and amortization		185		177		369		352
Property and other taxes		81		82		169		167

Total operating expenses		746		786		1,772		1,845

Gains on Sales of Other Assets and Other, net		1		—		2		4

Operating Income		367		402		886		959

Other Income and Expenses
Equity in earnings of unconsolidated affiliates		91		162		209		268
Other income and expenses, net		18		18		34		24

Total other income and expenses		109		180		243		292

Interest Expense		155		159		312		314

Earnings From Continuing Operations Before Income Taxes		321		423		817		937
Income Tax Expense From Continuing Operations		80		125		217		264

Income From Continuing Operations		241		298		600		673
Income From Discontinued Operations, net of tax		—		9		2		16

Net Income		241		307		602		689
Net Income—Noncontrolling Interests		26		23		54		48

Net Income—Controlling Interests	$	215	$	284	$	548	$	641

Common Stock Data
Weighted-average shares outstanding
Basic		653		650		652		650
Diluted		655		652		655		652
Earnings per share from continuing operations
Basic	$	0.33	$	0.42	$	0.84	$	0.96
Diluted	$	0.33	$	0.42	$	0.83	$	0.96
Earnings per share
Basic	$	0.33	$	0.44	$	0.84	$	0.99
Diluted	$	0.33	$	0.44	$	0.84	$	0.98
Dividends per share	$	0.28	$	0.26	$	0.56	$	0.52

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(In millions)


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012		2011
Net Income	$	241		$	307		$	602	$	689

Other comprehensive income
Foreign currency translation adjustments		(133	)		57			29		248
Unrealized mark-to-market net gain (loss) on hedges		3			(1	)		3		—
Reclassification of cash flow hedges into earnings		2			2			4		5
Pension and benefits impact		18			7			23		15
Other		—			—			—		8

Total other comprehensive income		(110	)		65			59		276

Total Comprehensive Income, net of tax		131			372			661		965
Less: Comprehensive Income—Noncontrolling Interests		24			24			54		52

Comprehensive Income—Controlling Interests	$	107		$	348		$	607	$	913

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)


	June 30, 2012		December 31, 2011
ASSETS

Current Assets
Cash and cash equivalents	$	127	$	174
Receivables, net		715		962
Inventory		307		393
Other		246		235

Total current assets		1,395		1,764


Investments and Other Assets
Investments in and loans to unconsolidated affiliates		2,082		2,064
Goodwill		4,435		4,420
Other		496		530

Total investments and other assets		7,013		7,014


Property, Plant and Equipment
Cost		24,803		23,932
Less accumulated depreciation and amortization		6,005		5,674

Net property, plant and equipment		18,798		18,258

Regulatory Assets and Deferred Debits		1,169		1,102

Total Assets	$	28,375	$	28,138

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions, except per-share amounts)


	June 30, 2012		December 31, 2011
LIABILITIES AND EQUITY

Current Liabilities
Accounts payable	$	458	$	498
Short-term borrowings and commercial paper		1,073		1,052
Taxes accrued		72		82
Interest accrued		186		178
Current maturities of long-term debt		1,030		525
Other		625		766

Total current liabilities		3,444		3,101


Long-term Debt		9,632		10,146


Deferred Credits and Other Liabilities
Deferred income taxes		4,163		3,940
Regulatory and other		1,730		1,797

Total deferred credits and other liabilities		5,893		5,737


Commitments and Contingencies

Preferred Stock of Subsidiaries		258		258


Equity
Preferred stock, $0.001 par, 22 million shares authorized, no shares outstanding		—		—
Common stock, $0.001 par, 1 billion shares authorized, 653 million and 651 million shares outstanding at June 30, 2012 and December 31, 2011, respectively		1		1
Additional paid-in capital		4,830		4,814
Retained earnings		2,156		1,977
Accumulated other comprehensive income		1,332		1,273

Total controlling interests		8,319		8,065
Noncontrolling interests		829		831

Total equity		9,148		8,896

Total Liabilities and Equity	$	28,375	$	28,138

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)


	Six Months Ended June 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	602		$	689
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		375			359
Deferred income tax expense		147			199
Equity in earnings of unconsolidated affiliates		(209	)		(268	)
Distributions received from unconsolidated affiliates		197			201
Other		47			158

Net cash provided by operating activities		1,159			1,338


CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(789	)		(739	)
Investments in and loans to unconsolidated affiliates		—			(4	)
Acquisitions		(30	)		—
Purchases of held-to-maturity securities		(1,490	)		(763	)
Proceeds from sales and maturities of held-to-maturity securities		1,387			733
Purchases of available-for-sale securities		—			(930	)
Proceeds from sales and maturities of available-for-sale securities		21			1,119
Distributions received from unconsolidated affiliates		11			—
Other changes in restricted funds		92			8
Other		6			5

Net cash used in investing activities		(792	)		(571	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt		—			805
Payments for the redemption of long-term debt		(28	)		(494	)
Net increase (decrease) in short-term borrowings and commercial paper		15			(258	)
Net decrease in revolving credit facilities borrowings		—			(258	)
Distributions to noncontrolling interests		(56	)		(47	)
Proceeds from the issuance of Spectra Energy Partners, LP common units		—			213
Dividends paid on common stock		(372	)		(341	)
Other		27			19

Net cash used in financing activities		(414	)		(361	)

Effect of exchange rate changes on cash		—			2

Net increase (decrease) in cash and cash equivalents		(47	)		408
Cash and cash equivalents at beginning of period		174			130

Cash and cash equivalents at end of period	$	127		$	538

Supplemental Disclosures
Property, plant and equipment non-cash accruals	$	182		$	169

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(Unaudited)

(In millions)


	Common Stock		Additional Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income
	Common Stock		Additional Paid-in Capital		Retained Earnings			Foreign Currency Translation Adjustments		Other			Noncontrolling Interests			Total
December 31, 2011	$	1	$	4,814	$	1,977		$	1,832	$	(559	)	$	831		$	8,896
Net income		—		—		548			—		—			54			602
Other comprehensive income		—		—		—			29		30			—			59
Dividends on common stock		—		—		(369	)		—		—			—			(369	)
Stock-based compensation		—		5		—			—		—			—			5
Distributions to noncontrolling interests		—		—		—			—		—			(56	)		(56	)
Spectra Energy common stock issued		—		11		—			—		—			—			11

June 30, 2012	$	1	$	4,830	$	2,156		$	1,861	$	(529	)	$	829		$	9,148


December 31, 2010	$	1	$	4,726	$	1,487		$	2,010	$	(415	)	$	678		$	8,487
Net income		—		—		641			—		—			48			689
Other comprehensive income		—		—		—			244		28			4			276
Dividends on common stock		—		—		(341	)		—		—			—			(341	)
Stock-based compensation		—		27		—			—		—			—			27
Distributions to noncontrolling interests		—		—		—			—		—			(47	)		(47	)
Spectra Energy Partners, LP common units issued		—		38		—			—		—			154			192

June 30, 2011	$	1	$	4,791	$	1,787		$	2,254	$	(387	)	$	837		$	9,283

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY CORP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. General

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

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

Basis of Presentation. The accompanying Condensed Consolidated Financial Statements include our accounts and the accounts of our majority-owned subsidiaries. These interim financial statements should be read in conjunction with the consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2011, 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.

During the third quarter of 2011, we identified errors in our previously issued Condensed Consolidated Statements of Cash Flows related to the accounting for rollovers of outstanding borrowings under our revolving bank credit facilities. These rollovers, which are extensions of borrowings beyond their scheduled due dates that did not involve the exchange of cash, were previously accounted for as cash activities and resulted in the overstatement of both Proceeds from the Issuance of Long-Term Debt and Payments for the Redemption of Long-Term Debt for the six months ended June 30, 2011. Cash and Cash Equivalents and Net Cash Used in Financing Activities as previously reported are not affected by the errors. We evaluated materiality from both a qualitative and a quantitative perspective and concluded that the errors are immaterial to our previously issued Condensed Consolidated Statements of Cash Flows.

In addition to making this correction, effective the third quarter of 2011, we elected to present cash borrowings and repayments under our revolving bank credit facilities on a net basis for all periods presented as Net Decrease in Revolving Credit Facilities Borrowings. As these periodic borrowings and repayments are generally of significant amounts and had terms of 90 days or less, we believe our current presentation provides users with more meaningful and relevant information about our long-term debt financing activities.

The correction and change in presentation reflected on the Condensed Consolidated Statement of Cash Flows are as follows:


	Proceeds From the Issuance of Long-Term Debt			Payments For the Redemption of Long-Term Debt
	(in millions)
Six Months Ended June 30, 2011
As previously reported	$	2,424		$	(2,371	)
Less non-cash activity		(1,567	)		1,567

As corrected		857			(804	)
Less revolving credit facility activity		(52	)		310

Long-term debt activity	$	805		$	(494	)

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

2. Business Segments

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

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

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

Distribution provides retail natural gas distribution service in Ontario, Canada, as well as natural gas transportation and storage services to other utilities and energy market participants. These services are provided by Union Gas Limited (Union Gas), and are primarily subject to the rules and regulations of the Ontario Energy Board (OEB).

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

Field Services gathers, processes, treats, compresses, transports and stores natural gas. In addition, this segment also fractionates, transports, gathers, treats, processes, stores, markets and trades NGLs. It conducts operations through DCP Midstream, which is owned 50% by us and 50% by Phillips 66. DCP Midstream gathers raw natural gas through gathering systems located in nine major conventional and non-conventional natural gas producing regions: Mid-Continent, Rocky Mountain, East Texas-North Louisiana, Barnett Shale, Gulf Coast, South Texas, Central Texas, Antrim Shale and Permian Basin. DCP Midstream has a 26% ownership interest in DCP Midstream Partners, LP (DCP Partners), a master limited partnership.

During the third quarter of 2011, ConocoPhillips announced plans to separate its business into two stand-alone publicly traded companies. ConocoPhillips’ 50% ownership interest in DCP Midstream was transferred to the new downstream company, Phillips 66, on May 1, 2012. DCP Midstream does not anticipate that the change in ownership will have a material impact on its operations.

Our reportable segments offer different products and services and are managed separately as business units. Management evaluates segment performance based on earnings before interest and taxes (EBIT), which represents earnings from continuing operations (both operating and non-operating) before interest and taxes, net of noncontrolling interests related to those earnings. Cash, cash equivalents and short-term investments are managed centrally, so the associated realized and unrealized gains and losses from foreign currency transactions and interest and dividend income on those balances are excluded from the segments’ EBIT. Transactions between reportable segments are accounted for on the same basis as transactions with unaffiliated third parties.

Business Segment Data


	Unaffiliated Revenues		Intersegment Revenues			Total Operating Revenues (a)			Segment EBIT/ Consolidated Earnings from Continuing Operations before Income Taxes (a)
			(in millions)
Three Months Ended June 30, 2012
U.S. Transmission	$	462	$	2		$	464		$	237
Distribution		322		—			322			75
Western Canada Transmission & Processing		325		4			329			94
Field Services		—		—			—			66

Total reportable segments		1,109		6			1,115			472
Other		3		16			19			(25	)
Eliminations		—		(22	)		(22	)		—
Interest expense		—		—			—			155
Interest income and other (b)		—		—			—			29

Total consolidated	$	1,112	$	—		$	1,112		$	321

Three Months Ended June 30, 2011
U.S. Transmission	$	454	$	3		$	457		$	243
Distribution		375		—			375			88
Western Canada Transmission & Processing		357		14			371			113
Field Services		—		—			—			138

Total reportable segments		1,186		17			1,203			582
Other		2		14			16			(29	)
Eliminations		—		(31	)		(31	)		—
Interest expense		—		—			—			159
Interest income and other (b)		—		—			—			29

Total consolidated	$	1,188	$	—		$	1,188		$	423

Six Months Ended June 30, 2012
U.S. Transmission	$	955	$	4		$	959		$	508
Distribution		919		—			919			226
Western Canada Transmission & Processing		778		17			795			232
Field Services		—		—			—			159

Total reportable segments		2,652		21			2,673			1,125
Other		4		36			40			(54	)
Eliminations		—		(57	)		(57	)		—
Interest expense		—		—			—			312
Interest income and other (b)		—		—			—			58

Total consolidated	$	2,656	$	—		$	2,656		$	817

Six Months Ended June 30, 2011
U.S. Transmission	$	935	$	5		$	940		$	522
Distribution		1,071		—			1,071			255
Western Canada Transmission & Processing		790		20			810			254
Field Services		—		—			—			219

Total reportable segments		2,796		25			2,821			1,250
Other		4		29			33			(53	)
Eliminations		—		(54	)		(54	)		—
Interest expense		—		—			—			314
Interest income and other (b)		—		—			—			54

Total consolidated	$	2,800	$	—		$	2,800		$	937

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

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

3. Regulatory Matters

Union Gas. As 2012 is the final year in Union Gas’ current multi-year incentive regulation framework, Union Gas filed an application with the OEB in November 2011 to set their distribution rates effective January 1, 2013. As part of the 2013 rates hearing process, Union Gas conducted settlement negotiations with its intervening parties. A settlement agreement was reached on most capital and rate base issues, and on all operating costs. That settlement agreement was accepted by the OEB on July 10, 2012. The unsettled issues, including operating revenue, cost of capital and rate design, are the subject of an OEB hearing that commenced on July 10, 2012. A decision on the unsettled issues is expected before the end of the year. Union Gas plans to file their application for a new multi-year incentive regulation framework after receiving the OEB decision on their 2013 rate application. That application is expected to be filed in 2013.

Southeast Supply Header, LLC (SESH). SESH operates under rates approved by the FERC in 2008. That order required SESH to file a Cost and Revenue Study at the end of three years of operations. SESH filed the Cost and Revenue Study on September 6, 2011 and the FERC accepted the filing on July 26, 2012. There was no change to the currently effective rates.

4. Income Taxes

Income tax expense from continuing operations for the three months ended June 30, 2012 was $80 million, compared to $125 million for the same period in 2011. Income tax expense from continuing operations for the six months ended June 30, 2012 was $217 million, compared to $264 million reported for the same period in 2011. The lower income tax expense for the periods resulted from lower earnings from continuing operations and a lower Canadian effective tax rate, partially offset by favorable tax adjustments in 2011.

The effective tax rate for income from continuing operations for the three months ended June 30, 2012 and 2011 were 25% compared to 30%, respectively, and were 27% and 28% for the six-month periods. The lower effective tax rates were primarily due to a lower Canadian effective tax rate.

No material net change in uncertain tax positions was recognized during the six months ended June 30, 2012. Although uncertain, we believe it is reasonably possible that the total amount of uncertain tax positions could increase by approximately $14 million prior to June 30, 2013. The anticipated changes in unrecognized tax benefits relate to expiration of statutes of limitation and expected audit settlements.

5. Discontinued Operations

Discontinued operations is mostly comprised of the net effects of a settlement arrangement related to prior liquefied natural gas contracts. See Note 8 for further discussion.

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


	Revenues		Pre-tax Earnings		Income Tax Expense		Income From Discontinued Operations, Net of Tax
	(in millions)
Three Months Ended June 30, 2012
Other	$	42	$	—	$	—	$	—

Total consolidated	$	42	$	—	$	—	$	—

Three Months Ended June 30, 2011
Other	$	48	$	15	$	6	$	9

Total consolidated	$	48	$	15	$	6	$	9

Six Months Ended June 30, 2012
Other	$	99	$	3	$	1	$	2

Total consolidated	$	99	$	3	$	1	$	2

Six Months Ended June 30, 2011
Other	$	132	$	25	$	9	$	16

Total consolidated	$	132	$	25	$	9	$	16

6. 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.

Weighted-average shares used to calculate diluted EPS include the effect of certain options and restricted stock awards. Certain other options related to approximately five million shares for both the three and six-month periods ended June 30, 2011 were not included in the calculation of diluted EPS because the option exercise prices were greater than the average market price of the shares during these periods.

The following table presents our basic and diluted EPS calculations:


	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(in millions, except per-share amounts)
Income from continuing operations, net of tax—controlling interests	$	215	$	275	$	546	$	625
Income from discontinued operations, net of tax—controlling interests		—		9		2		16

Net income—controlling interests	$	215	$	284	$	548	$	641

Weighted-average common shares outstanding
Basic		653		650		652		650
Diluted		655		652		655		652
Basic earnings per common share (a)
Continuing operations	$	0.33	$	0.42	$	0.84	$	0.96
Discontinued operations, net of tax		—		0.02		—		0.03

Total basic earnings per common share	$	0.33	$	0.44	$	0.84	$	0.99

Diluted earnings per common share (a)
Continuing operations	$	0.33	$	0.42	$	0.83	$	0.96
Discontinued operations, net of tax		—		0.02		0.01		0.02

Total diluted earnings per common share	$	0.33	$	0.44	$	0.84	$	0.98

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

7. Inventory

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


	June 30, 2012		December 31, 2011
	(in millions)
Natural gas	$	164	$	263
NGLs		68		58
Materials and supplies		75		72

Total inventory	$	307	$	393

An $8 million non-cash charge was recorded to Natural Gas and Petroleum Products Purchased on the Condensed Consolidated Statements of Operations ($6 million after tax) in the second quarter of 2012 to reduce propane and butane inventory as of June 30, 2012 at our Empress operations at Western Canada Transmission & Processing to estimated net realizable value.

8. Investments in and Loans to Unconsolidated Affiliates

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(in millions)
Operating revenues	$	2,219	$	3,304	$	5,121	$	6,233
Operating expenses		1,998		2,957		4,692		5,712
Operating income		221		347		429		521
Net income		185		303		340		428
Net income attributable to members’ interests		132		277		276		410

DCP Midstream recorded gains on sales of common units of DCP Partners to equity in the first and second quarters of 2012 and the first quarter of 2011. Our proportionate 50% share, totaling $21 million and $1 million in the first and second quarters of 2012, respectively, and $14 million in the first quarter of 2011, was recorded in Equity in Earnings of Unconsolidated Affiliates in the Condensed Consolidated Statements of Operations.

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

Sales of propane to affiliates of DCP Midstream are as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(in millions)
Sales of propane	$	42	$	48	$	99	$	132

9. Marketable Securities and Restricted Funds

We routinely invest excess cash and various restricted balances in securities such as commercial paper, bankers acceptances, corporate debt securities, treasury bills and money market funds in the United States and Canada. We do not purchase marketable securities for speculative purposes, nor do we routinely sell marketable securities prior to their scheduled maturity dates. Therefore, we do not have any securities classified as trading securities. A portion of our investments of restricted funds, primarily insurance-related funds, are classified as available-for-sale marketable securities as they may occasionally be sold prior to their scheduled maturity dates due to unexpected cash needs. Initial investments in securities are classified as purchases of the respective type of securities (available-for-sale (AFS) marketable securities or held-to-maturity (HTM) marketable securities). Maturities of securities are classified within proceeds from sales and maturities of securities in the Condensed Consolidated Statements of Cash Flows.

AFS Securities. Estimated fair values of AFS securities follow:


	Estimated Fair Value
	June 30, 2012		December 31, 2011
	(in millions)
Corporate debt securities	$	11	$	18
Canadian government securities		—		14
Money market funds		1		3

Total available-for-sale investments	$	12	$	35

We had no restricted AFS securities classified as Current Assets—Other as of June 30, 2012 and $14 million as of December 31, 2011, and $1 million as of June 30, 2012 and $3 million December 31, 2011 classified as Investments and Other Assets—Other. These restricted funds are related to insurance.

At June 30, 2012, the weighted-average contractual maturity of outstanding AFS securities was one year.

There were no gross unrealized holding gains or losses associated with investments in AFS securities at June 30, 2012 or December 31, 2011.

During 2010, we invested a portion of the proceeds from Spectra Energy Partners’ issuance of common units to the public in AFS marketable securities. These investments were pledged as collateral against Spectra Energy Partners’ term loan. Spectra Energy Partners’ term loan was repaid in June 2011 and the related investments were liquidated.

HTM Securities. Estimated fair values of HTM securities follow:


	Estimated Fair Value
	June 30, 2012		December 31, 2011
	(in millions)
Canadian government securities	$	111	$	107
Bankers acceptances		154		55

Total held-to-maturity investments	$	265	$	162

Restricted HTM marketable securities of $40 million as of June 30, 2012 are classified as Current Assets—Other, and $225 million as of June 30, 2012 and $162 million as of December 31, 2011 are classified as Investments and Other Assets—Other. These securities are restricted funds pursuant to certain Maritimes & Northeast Pipeline Limited Partnership (M&N LP) debt agreements. These funds, plus future cash from operations that would have otherwise been available for distribution to the partners of M&N LP, were required to be placed in escrow until the balance in escrow was sufficient to fund all future debt service on the M&N LP notes. As of June 30, 2012, there were sufficient funds held in escrow to fund all future debt service on the M&N LP notes.

At June 30, 2012, the weighted-average contractual maturity of outstanding HTM securities was less than one year.

There were no gross unrecognized holding gains or losses associated with investments in HTM securities at June 30, 2012 or December 31, 2011.

Other Restricted Funds. In addition to the AFS and HTM securities described above, we had restricted funds totaling $21 million at June 30, 2012 and $35 million at December 31, 2011 classified as Current Assets—Other, and $79 million at December 31, 2011 classified as Investments and Other Assets—Other. These restricted funds are related to additional amounts for the M&N LP debt service requirements and insurance.

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

10. Goodwill

We perform our goodwill impairment test annually and evaluate goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. We completed our annual goodwill impairment test as of April 1, 2012 and no impairments were identified.

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

As permitted under new accounting guidance on testing goodwill for impairment, we performed either a qualitative assessment or a quantitative assessment of each of our reporting units based on management’s judgment. With respect to our qualitative assessments, we considered events and circumstances specific to us, such as macroeconomic conditions, industry and market considerations, cost factors and overall financial performance, when evaluating whether it was more likely than not that the fair values of our reporting units were less than their respective carrying amounts.

In connection with our quantitative assessments, we primarily used a discounted cash flow analysis to determine the fair values of those reporting units. Key assumptions in the determination of fair value included the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporated expected long-term growth rates in key markets served by our operations, regulatory stability, the ability to renew contracts, commodity prices (where appropriate), and foreign currency exchange rates, as well as other factors that affect our reporting units’ revenue, expense and capital expenditure projections.

11. Debt and Credit Facilities

Available Credit Facilities and Restrictive Debt Covenants


	Expiration Date		Total Credit Facilities Capacity		Outstanding at June 30, 2012						Available Credit Facilities Capacity
	Expiration Date		Total Credit Facilities Capacity		Commercial Paper		Letters of Credit		Total		Available Credit Facilities Capacity
			(in millions)
Spectra Energy Capital, LLC (a)
Multi-year syndicated		2016	$	1,500	$	936	$	5	$	941	$	559
Westcoast Energy Inc. (b)
Multi-year syndicated		2016		295		—		—		—		295
Union Gas (c)
Multi-year syndicated		2016		393		97		—		97		296
Spectra Energy Partners (d)
Multi-year syndicated		2016		700		40		—		40		660

Total			$	2,888	$	1,073	$	5	$	1,078	$	1,810

(a)	Credit facility contains a covenant requiring the Spectra Energy Corp consolidated debt-to-total capitalization ratio, as defined in the agreement, to not exceed 65%. This ratio was 58% at June 30, 2012.

(b)	U.S. dollar equivalent at June 30, 2012. The credit facility is 300 million Canadian dollars and contains a covenant that requires the Westcoast Energy Inc. non-consolidated debt-to-total capitalization ratio to not exceed 75%. The ratio was 44% at June 30, 2012.

(c)

U.S. dollar equivalent at June 30, 2012. The credit facility is 400 million Canadian dollars and contains a covenant that requires the Union Gas debt-to-total capitalization ratio to not exceed 75% and a provision which requires Union Gas to repay all borrowings under the facility for a period of two days during the second quarter of each year. The ratio was 65% at June 30, 2012.

(d)

Credit facility contains a covenant that requires Spectra Energy Partners to maintain a ratio of total Debt-to-Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA), as defined in the credit agreement, of 5.0 or less. As of June 30, 2012, this ratio was 2.7. Adjusted EBITDA is a non-GAAP measure. Because Adjusted EBITDA excludes some, but not all, items that affect net income and is defined differently by companies in our industry, Spectra Energy Partners’ definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies. Adjusted EBITDA should not be considered an alternative to net income, operating income, cash from operations or any other measure of financial performance or liquidity presented in accordance with GAAP.

The issuances of commercial paper, letters of credit and revolving borrowings reduce the amounts available under the credit facilities. As of June 30, 2012, there were no revolving borrowings outstanding.

Our credit agreements contain various covenants, including the maintenance of certain financial ratios. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of June 30, 2012, we were in compliance with those covenants. In addition, our credit agreements allow for acceleration of payments or termination of the agreements due to nonpayment, or in some cases, due to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. Our debt and credit agreements do not contain provisions that trigger an acceleration of indebtedness based solely on the occurrence of a material adverse change in our financial condition or results of operations.

As noted above, the terms of the Spectra Energy Capital, LLC (Spectra Capital) credit agreement require our consolidated debt-to-total capitalization ratio, as defined in the agreement, to be 65% or lower. Per the terms of the new agreement, collateralized debt and Spectra Energy Partners’ debt and equity are excluded in the calculation of the ratio. This ratio was 58% at June 30, 2012.

12. Fair Value Measurements

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


Description	Condensed Consolidated Balance Sheet Caption	June 30, 2012
Description	Condensed Consolidated Balance Sheet Caption	Total		Level 1		Level 2		Level 3
		(in millions)
Corporate debt securities	Cash and cash equivalents	$	56	$	—	$	56	$	—
Corporate debt securities	Current assets—other		5		—		5		—
Derivative assets—interest rate swaps	Current assets—other		10		—		10		—
Corporate debt securities	Investments and other assets—other		6		—		6		—
Derivative assets—interest rate swaps	Investments and other assets—other		56		—		56		—
Money market funds	Investments and other assets—other		1		1		—		—

Total Assets		$	134	$	1	$	133	$	—

Derivative liabilities—natural gas purchase contracts	Deferred credits and other liabilities—regulatory and other	$	10	$	—	$	—	$	10
Derivative liabilities—interest rate swaps	Deferred credits and other liabilities—regulatory and other		14		—		14		—

Total Liabilities		$	24	$	—	$	14	$	10



Description	Condensed Consolidated Balance Sheet Caption	December 31, 2011
Description	Condensed Consolidated Balance Sheet Caption	Total		Level 1		Level 2		Level 3
		(in millions)
Corporate debt securities	Cash and cash equivalents	$	49	$	—	$	49	$	—
Canadian government securities	Current assets—other		14		14		—		—
Corporate debt securities	Current assets—other		2		—		2		—
Corporate debt securities	Investments and other assets—other		16		—		16		—
Derivative assets—interest rate swaps	Investments and other assets—other		66		—		66		—
Money market funds	Investments and other assets—other		3		3		—		—

Total Assets		$	150	$	17	$	133	$	—

Derivative liabilities—natural gas purchase contracts	Current liabilities—other	$	1	$	—	$	—	$	1
Derivative liabilities—natural gas purchase contracts	Deferred credits and other liabilities—regulatory and other		13		—		—		13
Derivative liabilities—interest rate swaps	Deferred credits and other liabilities—regulatory and other		16		—		16		—

Total Liabilities		$	30	$	—	$	16	$	14

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in millions)
Long-term derivative assets (liabilities)
Fair value, beginning of period	$	(15	)	$	(6	)	$	(14	)	$	(6	)
Total realized/unrealized gains (losses):
Included in earnings		(1	)		—			—			(1	)
Included in other comprehensive income		5			(2	)		3			(1	)
Settlements		1			—			1			—

Fair value, end of period	$	(10	)	$	(8	)	$	(10	)	$	(8	)

Total gains for the period included in earnings (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets/liabilities held at the end of the period	$	(1	)	$	(2	)	$	—		$	(5	)

Level 1

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

Level 2 Valuation Techniques

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

For interest rate swaps, we utilize data obtained from a third-party source for the determination of fair value. Both the future cash flows for the fixed-leg and floating-leg of our swaps are discounted to present

value. In addition, credit default swap rates are used to develop the adjustment for credit risk embedded in our positions. We believe that since some of the inputs and assumptions for the calculations of fair value are derived from observable market data, a Level 2 classification is appropriate.

Level 3 Valuation Techniques

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

Financial Instruments

The fair values of financial instruments that are recorded and carried at book value are summarized in the following table. Judgment is required in interpreting market data to develop the estimates of fair value. These estimates are not necessarily indicative of the amounts we could have realized in current markets.


	June 30, 2012				December 31, 2011
	Book Value		Approximate Fair Value		Book Value		Approximate Fair Value
	(in millions)
Note receivable—noncurrent (a)	$	71	$	71	$	71	$	71
Long-term debt, including current maturities (b)		10,595		12,514		10,600		12,398

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

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

The fair value of our long-term debt is determined based on market-based prices as described in the Level 2 valuation technique described above.

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

During the 2012 and 2011 periods, there were no material adjustments to assets and liabilities measured at fair value on a nonrecurring basis.

13. Risk Management and Hedging Activities

We are exposed to the impact of market fluctuations in the prices of NGLs and natural gas purchased as a result of our investment in DCP Midstream, and the ownership of NGL processing and marketing operations in western Canada and the processing plants associated with our U.S. pipeline assets. Exposure to interest rate risk exists as a result of the issuance of variable and fixed-rate debt and commercial paper. We are exposed to foreign currency risk from our Canadian operations. We employ established policies and procedures to manage our risks associated with these market fluctuations, which may include the use of derivatives, primarily around interest rate exposures.

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

At June 30, 2012, we had “pay floating—receive fixed” interest rate swaps outstanding with a total notional principal amount of $2,096 million to hedge against changes in the fair value of our fixed-rate debt that arise as a result of changes in market interest rates. These swaps also allow us to transform a portion of the underlying interest payments related to our long-term fixed-rate debt securities into variable-rate interest payments in order to achieve our desired mix of fixed and variable-rate debt.

Other than interest rate swaps described above, we did not have any significant derivatives outstanding during the six months ended June 30, 2012.

14. Commitments and Contingencies

Environmental

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

Like others in the energy industry, we and our affiliates are responsible for environmental remediation at various contaminated sites. These include some properties that are part of our ongoing operations, sites formerly owned or used by us, and sites owned by third parties. Remediation typically involves management of contaminated soils and may involve groundwater remediation. Managed in conjunction with relevant 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 undiscounted liabilities related to extended environmental-related activities totaling $13 million as of June 30, 2012 and $16 million as of December 31, 2011. These liabilities represent provisions for costs associated with remediation activities at some of our current and former sites, as well as other environmental contingent liabilities.

Litigation

Litigation and Legal Proceedings. We are involved in legal, tax and regulatory proceedings in various forums arising in the ordinary course of business, including matters regarding contract and payment claims, some of which involve substantial monetary amounts. We have insurance coverage for certain of these losses should they be incurred. We believe that the final disposition of these proceedings will not have a material effect on our consolidated results of operations, financial position or cash flows.

Legal costs related to the defense of loss contingencies are expensed as incurred. We had no material reserves recorded as of June 30, 2012 or December 31, 2011 related to litigation.

Other Commitments and Contingencies

See Note 15 for a discussion of guarantees and indemnifications.

15. Guarantees and Indemnifications

We have various financial guarantees and indemnifications which are issued in the normal course of business. As discussed below, these contracts include financial guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. We enter into these arrangements to facilitate a commercial transaction with a third party by enhancing the value of the transaction to the third party. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on the Condensed Consolidated Balance Sheets. The possibility of having to perform under these guarantees and indemnifications is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events.

We have issued performance guarantees to customers and other third parties that guarantee the payment and performance of other parties, including certain non-100%-owned entities. In connection with our spin-off from Duke Energy Corporation (Duke Energy) in 2007, certain guarantees that were previously issued by us were assigned to, or replaced by, Duke Energy as guarantor in 2006. For any remaining guarantees of other Duke Energy obligations, Duke Energy has indemnified us against any losses incurred under these guarantee arrangements. The maximum potential amount of future payments we could have been required to make under these performance guarantees as of June 30, 2012 was approximately $406 million, which has been indemnified by Duke Energy as discussed above. One of these outstanding performance guarantees, which has a maximum potential amount of future payment of $201 million, expires in 2028. The remaining guarantees have no contractual expirations.

We have also issued joint and several guarantees to some of the Duke/Fluor Daniel (D/FD) project owners, guaranteeing the performance of D/FD under its engineering, procurement and construction contracts and other contractual commitments in place at the time of our spin-off from Duke Energy. D/FD is one of the entities transferred to Duke Energy in connection with our spin-off. Substantially all of these guarantees have no contractual expiration and no stated maximum amount of future payments that we could be required to make. Fluor Enterprises Inc., as 50% owner in D/FD, has issued similar joint and several guarantees to the same D/FD project owners.

Westcoast Energy Inc. (Westcoast), a 100%-owned subsidiary, has issued performance guarantees to third parties guaranteeing the performance of unconsolidated entities, such as equity method investments, and of entities previously sold by Westcoast to third parties. Those guarantees require Westcoast to make payment to the guaranteed third party upon the failure of such unconsolidated or sold entity to make payment under some of its contractual obligations, such as debt agreements, purchase contracts and leases. Certain guarantees that were previously issued by Westcoast for obligations of entities that remained a part of Duke Energy are considered guarantees of third party performance; however, Duke Energy has indemnified us against any losses incurred under these guarantee arrangements.

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

As of June 30, 2012, the amounts recorded for the guarantees and indemnifications, described above, including the indemnifications by Duke Energy to us, are not material, both individually and in the aggregate.

16. Employee Benefit Plans

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

Our policy is to fund our retirement plans, where applicable, on an actuarial basis to provide assets sufficient to meet benefits to be paid to plan participants or as required by legislation or plan terms. We made contributions of $11 million to our U.S. retirement plans in the six months ended June 30, 2012 and $10 million in the same period in 2011. We made total contributions to the Canadian DC and qualified DB plans of $35 million during the six months ended June 30, 2012 and $36 million in the same period in 2011. We anticipate that we will make total contributions of approximately $25 million to the U.S. plans and approximately $95 million to the Canadian plans in 2012.

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in millions)
U.S.
Service cost benefit earned	$	4		$	4		$	7		$	7
Interest cost on projected benefit obligation		6			7			12			13
Expected return on plan assets		(7	)		(8	)		(15	)		(16	)
Amortization of loss		3			2			7			5

Net periodic pension cost	$	6		$	5		$	11		$	9

Canada
Service cost benefit earned	$	6		$	6		$	13		$	11
Interest cost on projected benefit obligation		12			13			25			27
Expected return on plan assets		(14	)		(13	)		(29	)		(25	)
Amortization of loss		9			8			18			14
Amortization of prior service costs		1			1			1			1

Net periodic pension cost	$	14		$	15		$	28		$	28

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,
	2012			2011			2012			2011
	(in millions)
U.S.
Interest cost on accumulated post-retirement benefit obligation	$	1		$	2		$	4		$	5
Expected return on plan assets		(1	)		(1	)		(2	)		(2	)
Amortization of loss		1			1			1			1

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

Canada
Service cost benefit earned	$	2		$	1		$	4		$	2
Interest cost on accumulated post-retirement benefit obligation		1			2			3			4
Amortization of loss		1			—			1			—

Net periodic other post-retirement benefit cost	$	4		$	3		$	8		$	6

Retirement/Savings Plan

We have employee savings plans available to both U.S. and Canadian employees. Employees may participate in a matching contribution formula where we provide a matching contribution up to 100% of before tax employee contributions, of up to 6% of eligible pay per pay period for U.S. employees and up to 5% of eligible pay per pay period for Canadian employees. We expensed pre-tax employer matching contributions of $3 million in both the three-month periods ended June 30, 2012 and 2011 and $7 million in both the six-month periods ended June 30, 2012 and 2011 for U.S. employees, and $3 million in both the three-month periods ended June 30, 2012 and 2011 and $6 million in both the six-month periods ended June 30, 2012 and 2011 for Canadian employees.

17. Consolidating Financial Information

Spectra Energy Corp has agreed to fully and unconditionally guarantee the payment of principal and interest under all series of notes outstanding under the Senior Indenture of Spectra Capital, a 100%-owned, consolidated subsidiary. In accordance with Securities and Exchange Commission (SEC) rules, the following condensed consolidating financial information is presented. The information shown for Spectra Energy Corp and Spectra Capital is presented utilizing the equity method of accounting for investments in subsidiaries, as required. The non-guarantor subsidiaries column represents all consolidated subsidiaries of Spectra Capital. This information should be read in conjunction with our accompanying Condensed Consolidated Financial Statements and notes thereto.

Spectra Energy Corp

Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2012

(Unaudited)

(In millions)


	Spectra Energy Corp			Spectra Capital		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Total operating revenues	$	—		$	—	$	1,112	$	—		$	1,112
Total operating expenses		6			—		740		—			746
Gains on sales of other assets and other, net		—			—		1		—			1

Operating income (loss)		(6	)		—		373		—			367
Equity in earnings of unconsolidated affiliates		—			—		91		—			91
Equity in earnings of subsidiaries		216			342		—		(558	)		—
Other income and expenses, net		—			1		17		—			18
Interest expense		—			48		107		—			155

Earnings from continuing operations before income taxes		210			295		374		(558	)		321
Income tax expense (benefit) from continuing operations		(6	)		79		7		—			80

Income from continuing operations		216			216		367		(558	)		241
Income (loss) from discontinued operations, net of tax		(1	)		—		1		—			—

Net income		215			216		368		(558	)		241
Net income—noncontrolling interests		—			—		26		—			26

Net income—controlling interests	$	215		$	216	$	342	$	(558	)	$	215

Spectra Energy Corp

Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2011

(Unaudited)

(In millions)


	Spectra Energy Corp			Spectra Capital		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Total operating revenues	$	—		$	—	$	1,188	$	—		$	1,188
Total operating expenses		(3	)		—		789		—			786

Operating income		3			—		399		—			402
Equity in earnings of unconsolidated affiliates		—			—		162		—			162
Equity in earnings of subsidiaries		282			425		—		(707	)		—
Other income and expenses, net		—			6		12		—			18
Interest expense		—			51		108		—			159

Earnings from continuing operations before income taxes		285			380		465		(707	)		423
Income tax expense from continuing operations		1			98		26		—			125

Income from continuing operations		284			282		439		(707	)		298
Income from discontinued operations, net of tax		—			—		9		—			9

Net income		284			282		448		(707	)		307
Net income—noncontrolling interests		—			—		23		—			23

Net income—controlling interests	$	284		$	282	$	425	$	(707	)	$	284

Spectra Energy Corp

Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2012

(Unaudited)

(In millions)


	Spectra Energy Corp			Spectra Capital		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Total operating revenues	$	—		$	—	$	2,657	$	(1	)	$	2,656
Total operating expenses		8			—		1,765		(1	)		1,772
Gains on sales of other assets and other, net		—			—		2		—			2

Operating income (loss)		(8	)		—		894		—			886
Equity in earnings of unconsolidated affiliates		—			—		209		—			209
Equity in earnings of subsidiaries		545			828		—		(1,373	)		—
Other income and expenses, net		(1	)		1		34		—			34
Interest expense		—			96		216		—			312

Earnings from continuing operations before income taxes		536			733		921		(1,373	)		817
Income tax expense (benefit) from continuing operations		(13	)		188		42		—			217

Income from continuing operations		549			545		879		(1,373	)		600
Income (loss) from discontinued operations, net of tax		(1	)		—		3		—			2

Net income		548			545		882		(1,373	)		602
Net income—noncontrolling interests		—			—		54		—			54

Net income—controlling interests	$	548		$	545	$	828	$	(1,373	)	$	548

Spectra Energy Corp

Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2011

(Unaudited)

(In millions)


	Spectra Energy Corp		Spectra Capital		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Total operating revenues	$	—	$	—	$	2,800	$	—		$	2,800
Total operating expenses		—		—		1,845		—			1,845
Gains on sales of other assets and other, net		—		—		4		—			4

Operating income		—		—		959		—			959
Equity in earnings of unconsolidated affiliates		—		—		268		—			268
Equity in earnings of subsidiaries		641		935		—		(1,576	)		—
Other income and expenses, net		—		6		18		—			24
Interest expense		—		99		215		—			314

Earnings from continuing operations before income taxes		641		842		1,030		(1,576	)		937
Income tax expense from continuing operations		—		201		63		—			264

Income from continuing operations		641		641		967		(1,576	)		673
Income from discontinued operations, net of tax		—		—		16		—			16

Net income		641		641		983		(1,576	)		689
Net income—noncontrolling interests		—		—		48		—			48

Net income—controlling interests	$	641	$	641	$	935	$	(1,576	)	$	641

Spectra Energy Corp

Condensed Consolidating Statements of Comprehensive Income

(Unaudited)

(In millions)


	Spectra Energy Corp		Spectra Capital		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Three Months Ended June 30, 2012
Net income	$	215	$	216	$	368		$	(558	)	$	241

Other comprehensive income
Foreign currency translation adjustments		—		—		(133	)		—			(133	)
Unrealized mark-to-market net gain		—		—		3			—			3
Reclassification of cash flow hedges into earnings		—		—		2			—			2
Pension and benefits impact		3		—		15			—			18

Total other comprehensive income (loss)		3		—		(113	)		—			(110	)

Total comprehensive income, net of tax		218		216		255			(558	)		131
Less: comprehensive income—noncontrolling interests		—		—		24			—			24

Comprehensive income—controlling interests	$	218	$	216	$	231		$	(558	)	$	107


Three Months Ended June 30, 2011
Net income	$	284	$	282	$	448		$	(707	)	$	307

Other comprehensive income
Foreign currency translation adjustments		—		—		57			—			57
Unrealized mark-to-market net loss		—		—		(1	)		—			(1	)
Reclassification of cash flow hedges into earnings		—		—		2			—			2
Pension and benefits impact		2		—		5			—			7

Total other comprehensive income		2		—		63			—			65

Total comprehensive income, net of tax		286		282		511			(707	)		372
Less: comprehensive income—noncontrolling interests		—		—		24			—			24

Comprehensive income—controlling interests	$	286	$	282	$	487		$	(707	)	$	348

Spectra Energy Corp

Condensed Consolidating Statements of Comprehensive Income

(Unaudited)

(In millions)


	Spectra Energy Corp		Spectra Capital		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Six Months Ended June 30, 2012
Net income	$	548	$	545	$	882	$	(1,373	)	$	602

Other comprehensive income
Foreign currency translation adjustments		—		—		29		—			29
Unrealized mark-to-market net gain		—		—		3		—			3
Reclassification of cash flow hedges into earnings		—		1		3		—			4
Pension and benefits impact		7		—		16		—			23

Total other comprehensive income		7		1		51		—			59

Total comprehensive income, net of tax		555		546		933		(1,373	)		661
Less: comprehensive income—noncontrolling interests		—		—		54		—			54

Comprehensive income—controlling interests	$	555	$	546	$	879	$	(1,373	)	$	607


Six Months Ended June 30, 2011
Net income	$	641	$	641	$	983	$	(1,576	)	$	689

Other comprehensive income
Foreign currency translation adjustments		—		—		248		—			248
Reclassification of cash flow hedges into earnings		—		—		5		—			5
Pension and benefits impact		4		—		11		—			15
Other		—		—		8		—			8

Total other comprehensive income		4		—		272		—			276

Total comprehensive income, net of tax		645		641		1,255		(1,576	)		965
Less: comprehensive income—noncontrolling interests		—		—		52		—			52

Comprehensive income—controlling interests	$	645	$	641	$	1,203	$	(1,576	)	$	913

Spectra Energy Corp

Condensed Consolidating Balance Sheet

June 30, 2012

(Unaudited)

(In millions)


	Spectra Energy Corp			Spectra Capital			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Cash and cash equivalents	$	—		$	1		$	126	$	—		$	127
Receivables (payables)—consolidated subsidiaries		62			(63	)		1		—			—
Receivables—other		3			—			712		—			715
Other current assets		36			12			505		—			553

Total current assets		101			(50	)		1,344		—			1,395
Investments in and loans to unconsolidated affiliates		—			71			2,011		—			2,082
Investments in consolidated subsidiaries		12,345			15,629			—		(27,974	)		—
Advances receivable (payable)—consolidated subsidiaries		(3,936	)		4,380			150		(594	)		—
Goodwill		—			—			4,435		—			4,435
Other assets		42			95			359		—			496
Property, plant and equipment, net		—			—			18,798		—			18,798
Regulatory assets and deferred debits		3			12			1,154		—			1,169

Total Assets	$	8,555		$	20,137		$	28,251	$	(28,568	)	$	28,375


Accounts payable—other	$	2		$	78		$	378	$	—		$	458
Short-term borrowings and commercial paper		—			1,530			137		(594	)		1,073
Accrued taxes payable (receivable)		—			—			72		—			72
Current maturities of long-term debt		—			495			535		—			1,030
Other current liabilities		45			103			663		—			811

Total current liabilities		47			2,206			1,785		(594	)		3,444
Long-term debt		—			2,809			6,823		—			9,632
Deferred credits and other liabilities		189			2,777			2,927		—			5,893
Preferred stock of subsidiaries		—			—			258		—			258
Equity
Controlling interests		8,319			12,345			15,629		(27,974	)		8,319
Noncontrolling interests		—			—			829		—			829

Total equity		8,319			12,345			16,458		(27,974	)		9,148

Total Liabilities and Equity	$	8,555		$	20,137		$	28,251	$	(28,568	)	$	28,375

Spectra Energy Corp

Condensed Consolidating Balance Sheet

December 31, 2011

(Unaudited)

(In millions)


	Spectra Energy Corp			Spectra Capital			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Cash and cash equivalents	$	—		$	2		$	172	$	—		$	174
Receivables (payables)—consolidated subsidiaries		—			(1	)		1		—			—
Receivables—other		—			—			962		—			962
Other current assets		57			5			566		—			628

Total current assets		57			6			1,701		—			1,764
Investments in and loans to unconsolidated affiliates		—			70			1,994		—			2,064
Investments in consolidated subsidiaries		11,720			14,884			—		(26,604	)		—
Advances receivable (payable)—consolidated subsidiaries		(3,534	)		4,116			10		(592	)		—
Goodwill		—			—			4,420		—			4,420
Other assets		42			105			383		—			530
Property, plant and equipment, net		—			—			18,258		—			18,258
Regulatory assets and deferred debits		1			15			1,086		—			1,102

Total Assets	$	8,286		$	19,196		$	27,852	$	(27,196	)	$	28,138


Accounts payable—other	$	3		$	62		$	433	$	—		$	498
Short-term borrowings and commercial paper		—			1,343			301		(592	)		1,052
Accrued taxes payable (receivable)		(46	)		2			126		—			82
Current maturities of long-term debt		—			—			525		—			525
Other current liabilities		76			75			793		—			944

Total current liabilities		33			1,482			2,178		(592	)		3,101
Long-term debt		—			3,311			6,835		—			10,146
Deferred credits and other liabilities		188			2,683			2,866		—			5,737
Preferred stock of subsidiaries		—			—			258		—			258
Equity
Controlling interests		8,065			11,720			14,884		(26,604	)		8,065
Noncontrolling interests		—			—			831		—			831

Total equity		8,065			11,720			15,715		(26,604	)		8,896

Total Liabilities and Equity	$	8,286		$	19,196		$	27,852	$	(27,196	)	$	28,138

Spectra Energy Corp

Condensed Consolidating Statements of Cash Flows

Six Months Ended June 30, 2012

(Unaudited)

(In millions)


	Spectra Energy Corp			Spectra Capital			Non-Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	548		$	545		$	882		$	(1,373	)	$	602
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		—			—			375			—			375
Equity in earnings of unconsolidated affiliates		—			—			(209	)		—			(209	)
Equity in earnings of subsidiaries		(545	)		(828	)		—			1,373			—
Distributions received from unconsolidated affiliates		—			—			197			—			197
Other		(66	)		153			107			—			194

Net cash provided by (used in) operating activities		(63	)		(130	)		1,352			—			1,159

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		—			—			(789	)		—			(789	)
Acquisitions		—			—			(30	)		—			(30	)
Purchases of held-to-maturity securities		—			—			(1,490	)		—			(1,490	)
Proceeds from sales and maturities of held-to-maturity securities		—			—			1,387			—			1,387
Proceeds from sales and maturities of available-for-sale securities		—			—			21			—			21
Distributions received from unconsolidated affiliates		—			—			11			—			11
Other changes in restricted funds		—			—			92			—			92
Other		—			—			6			—			6

Net cash used in investing activities		—			—			(792	)		—			(792	)

CASH FLOWS FROM FINANCING ACTIVITIES
Payments for the redemption of long-term debt		—			—			(28	)		—			(28	)
Net increase (decrease) in short-term borrowings and commercial paper		—			184			(169	)		—			15
Distributions to noncontrolling interests		—			—			(56	)		—			(56	)
Dividends paid on common stock		(372	)		—			—			—			(372	)
Distributions and advances from (to) affiliates		409			(55	)		(354	)		—			—
Other		26			—			1			—			27

Net cash provided by (used in) financing activities		63			129			(606	)		—			(414	)

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

Net decrease in cash and cash equivalents		—			(1	)		(46	)		—			(47	)
Cash and cash equivalents at beginning of period		—			2			172			—			174

Cash and cash equivalents at end of period	$	—		$	1		$	126		$	—		$	127

Spectra Energy Corp

Condensed Consolidating Statements of Cash Flows

Six Months Ended June 30, 2011

(Unaudited)

(In millions)


	Spectra Energy Corp			Spectra Capital			Non-Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	641		$	641		$	983		$	(1,576	)	$	689
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		—			—			359			—			359
Equity in earnings of unconsolidated affiliates		—			—			(268	)		—			(268	)
Equity in earnings of subsidiaries		(641	)		(935	)		—			1,576			—
Distributions received from unconsolidated affiliates		—			—			201			—			201
Other		(37	)		254			140			—			357

Net cash provided by (used in) operating activities		(37	)		(40	)		1,415			—			1,338

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		—			—			(739	)		—			(739	)
Investments in and loans to unconsolidated affiliates		—			—			(4	)		—			(4	)
Purchases of held-to-maturity securities		—			—			(763	)		—			(763	)
Proceeds from sales and maturities of held-to-maturity securities		—			—			733			—			733
Purchases of available-for-sale securities		—			—			(930	)		—			(930	)
Proceeds from sales and maturities of available-for-sale securities		—			—			1,119			—			1,119
Other changes in restricted funds		—			—			8			—			8
Other		—			—			5			—			5

Net cash used in investing activities		—			—			(571	)		—			(571	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt		—			—			805			—			805
Payments for the redemption of long-term debt		—			—			(494	)		—			(494	)
Net decrease in short-term borrowings and commercial paper		—			(132	)		(126	)		—			(258	)
Net increase in revolving credit facilities borrowings		—			—			(258	)		—			(258	)
Distributions to noncontrolling interests		—			—			(47	)		—			(47	)
Proceeds from the issuance of Spectra Energy Partners common units		—			—			213			—			213
Dividends paid on common stock		(341	)		—			—			—			(341	)
Distributions and advances from (to) affiliates		353			173			(526	)		—			—
Other		25			—			(6	)		—			19

Net cash provided by (used in) financing activities		37			41			(439	)		—			(361	)

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

Net increase in cash and cash equivalents		—			1			407			—			408
Cash and cash equivalents at beginning of period		—			—			130			—			130

Cash and cash equivalents at end of period	$	—		$	1		$	537		$	—		$	538

18. New Accounting Pronouncements

There were no significant accounting pronouncements adopted during the six months ended June 30, 2012 that had a material impact on our consolidated results of operations, financial position or cash flows.

19. Subsequent Events

On July 17, 2012, Algonquin Gas Transmission, LLC (Algonquin), issued $350 million aggregate principal amount of 3.51% notes due in 2024. Net proceeds from the offering were used for general corporate purposes.

Item 2.

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

INTRODUCTION

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

Executive Overview

During the first half of 2012, our earnings decreased compared to the same period in 2011 as a result of lower commodity prices at Field Services, extraordinarily warmer weather at Distribution, and higher NGL extraction premiums and lower NGL sales prices related to the Empress operations at Western Canada Transmission & Processing. However, our gathering and processing businesses at Field Services generated higher earnings and our fee-based businesses at U.S. Transmission and Western Canada Transmission & Processing continued to perform well by meeting the needs of our customers and generating strong earnings and operating cash flows from expansion projects.

For the three months ended June 30, 2012 and 2011, we reported net income from controlling interests of $215 million and $284 million, respectively. For the six months ended June 30, 2012 and 2011, we reported net income from controlling interests of $548 million and $641 million, respectively.

The highlights for the three months and six months ended June 30, 2012 include the following:

•

U.S. Transmission’s earnings were lower mainly due to lower processing revenues, expected lower storage revenues and accelerated software amortization costs, partially offset by higher earnings from expansion projects,

•

Distribution’s earnings decreased mostly due to lower customer usage as a result of warmer weather, a weaker Canadian dollar and expected lower storage revenues, partially offset by higher short-term transportation services and lower operating fuel costs,

•

Western Canada Transmission & Processing earnings were lower as a result of lower earnings at the Empress NGL business due mainly to lower NGL sales prices and higher first quarter 2012 NGL extraction premiums, partially offset by higher gathering and processing earnings from expansions, and

•

Field Services earnings decreased mostly due to lower commodity prices, partially offset by higher gathering and processing volumes from expansion projects and the absence of severe weather which restricted volumes in 2011, and a reduction in depreciation expense attributable to an increase in the remaining useful lives of fixed assets.

In the first six months of 2012, we had $789 million of capital and investment expenditures excluding the payment of $30 million of the purchase price previously withheld for the acquisition of Bobcat Gas Storage (Bobcat) in 2010, which we have classified as acquisition expenditures. We project approximately $2.4 billion of capital and investment expenditures for the full year, including expansion capital of approximately $1.7 billion. Expansion projects for 2012 are on track and we expect that our capital spending will be significantly higher throughout the remainder of the year.

We are committed to an investment-grade balance sheet and continued prudent financial management of our capitalization structure. Therefore, financing these growth activities will continue to be based on our strong and growing fee-based earnings and cash flows as well as the issuance of long-term debt. In 2012, we plan to issue approximately $1.9 billion of combined long-term debt and commercial paper, including the refinancing of approximately $500 million of long-term debt maturities. We have access to $1.8 billion available under our credit facilities as of June 30, 2012, to be utilized as needed for effective working capital management.

RESULTS OF OPERATIONS


	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(in millions)
Operating revenues	$	1,112	$	1,188	$	2,656	$	2,800
Operating expenses		746		786		1,772		1,845
Gains on sales of other assets and other, net		1		—		2		4

Operating income		367		402		886		959
Other income and expenses		109		180		243		292
Interest expense		155		159		312		314

Earnings from continuing operations before income taxes		321		423		817		937
Income tax expense from continuing operations		80		125		217		264

Income from continuing operations		241		298		600		673
Income from discontinued operations, net of tax		—		9		2		16

Net income		241		307		602		689
Net income—noncontrolling interests		26		23		54		48

Net income—controlling interests	$	215	$	284	$	548	$	641

Three and Six Months Ended June 30, 2012 Compared to Same Periods in 2011

Operating Revenues. Operating revenues for the three and six months ended June 30, 2012 decreased by $76 million, or 6%, and $144 million, or 5%, respectively, compared to the same periods in 2011. The decreases were driven by:

•

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

•

lower NGL sales volumes resulting from warmer weather, and lower NGL sales prices associated with the Empress operations at Western Canada Transmission & Processing, and

•

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

•

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

•

increased sales volumes of residual natural gas related to the Empress operations in the first quarter of 2012 at Western Canada Transmission & Processing.

Operating Expenses. Operating expenses for the three and six months ended June 30, 2012 decreased by $40 million, or 5%, and $73 million, or 4%, respectively, compared to the same periods in 2011. The decreases were driven by:

•

a decrease in volumes of natural gas sold largely due to warmer weather and lower natural gas prices passed through to customers at Distribution, and

•

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

•

lower volumes of make-up gas purchases at Empress as a result of lower NGL production due to warmer weather, and expected lower plant maintenance costs, partially offset by higher natural gas purchases for extraction due to volumes and increased costs due primarily to higher extraction premiums, both in the first quarter of 2012, at Western Canada Transmission & Processing.

Operating Income. Operating income for the three and six months ended June 30, 2012 decreased by $35 million, or 9%, and $73 million, or 8%, respectively, compared to the same periods in 2011. The decreases were attributable to lower customer usage of natural gas due to warmer weather at Distribution and lower NGL earnings mainly due to higher NGL extraction premiums and lower NGL sales prices at Western Canada Transmission & Processing, partially offset by expansion projects at Western Canada Transmission & Processing and U.S. Transmission.

Other Income and Expenses. Other income and expenses for the three and six months ended June 30, 2012 decreased by $71 million, or 39%, and $49 million, or 17%, respectively, compared to the same periods in 2011. The decreases were attributable to lower equity earnings from Field Services mostly due to lower commodity prices, partially offset by an increase in gathering and processing margins as a result of higher volumes due to expansions in 2012 and the impact of severe weather in the first quarter of 2011, and a reduction in depreciation expense attributable to an increase of the remaining useful lives of DCP Midstream’s gathering, transmission, processing, storage and other assets during the second quarter of 2012. In addition, the lower equity earnings from Field Services were slightly offset by higher allowance for funds used during construction (AFUDC) due to increased capital spending on expansion projects at Western Canada Transmission & Processing.

Income Tax Expense from Continuing Operations. Income tax expense from continuing operations for the three and six months ended June 30, 2012 decreased by $45 million and $47 million, respectively, compared to the same periods in 2011. The decreases were attributable to lower earnings from continuing operations and a lower Canadian effective tax rate, partially offset by favorable tax adjustments in 2011.

The effective tax rates for income from continuing operations for the three-month periods ended June 30, 2012 and June 30, 2011 were 25% and 30%, respectively, and 27% and 28% for six-month periods. The lower effective tax rates were primarily due to a lower Canadian effective tax rate.

Income from Discontinued Operations, Net of Tax. Income from discontinued operations, net of tax for the three and six months ended June 30, 2012 decreased by $9 million and $14 million, respectively, compared to the same periods in 2011. The decreases were primarily attributable to lower income from propane deliveries in 2012 as a result of a final settlement of these activities in the second quarter of 2012.

Net Income—Noncontrolling Interests. Net income from noncontrolling interests for the three and six months ended June 30, 2012 increased by $3 million and $6 million, respectively, compared to the same periods in 2011. The increases were driven by an increase in noncontrolling ownership interests resulting from the Spectra Energy Partners public sales of additional partner units in June 2011, and higher earnings from Spectra Energy Partners, primarily as a result of the acquisition of Big Sandy in July 2011.

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

Segment Results

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

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

EBIT by Business Segment


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in millions)
U.S. Transmission	$	237		$	243		$	508		$	522
Distribution		75			88			226			255
Western Canada Transmission & Processing		94			113			232			254
Field Services		66			138			159			219

Total reportable segment EBIT		472			582			1,125			1,250
Other		(25	)		(29	)		(54	)		(53	)

Total reportable segment and other EBIT		447			553			1,071			1,197
Interest expense		155			159			312			314
Interest income and other (a)		29			29			58			54

Earnings from continuing operations before income taxes.	$	321		$	423		$	817		$	937

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

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

U.S. Transmission


	Three Months Ended June 30,							Six Months Ended June 30,
	2012		2011		Increase (Decrease)			2012		2011		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	464	$	457	$	7		$	959	$	940	$	19
Operating expenses
Operating, maintenance and other		162		156		6			319		302		17
Depreciation and amortization		71		67		4			141		134		7
Gains on sales of other assets and other, net		2		—		2			3		4		(1	)

Operating income		233		234		(1	)		502		508		(6	)
Other income and expenses		32		32		—			63		63		—
Noncontrolling interests		28		23		5			57		49		8

EBIT	$	237	$	243	$	(6	)	$	508	$	522	$	(14	)

Proportional throughput, TBtu (a)		612		623		(11	)		1,375		1,426		(51	)

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

Three Months Ended June 30, 2012 Compared to Same Period in 2011

Operating Revenues. The $7 million increase was driven by:

•

an $18 million increase from expansion projects and the acquisition of Big Sandy in July 2011, and

•

a $4 million increase in recoveries of electric power and other costs passed through to customers, partially offset by

•

an $8 million decrease in processing revenues associated with pipeline operations primarily due to lower prices, and

•

a $7 million decrease from expected lower storage revenues.

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

•

a $4 million increase in electric power and other costs passed through to customers, and

•

a $4 million increase primarily due to accelerated software amortization costs.

Depreciation and Amortization. The $4 million increase was driven by expansion projects and the acquisition of Big Sandy.

Noncontrolling Interests. The $5 million increase was driven by an increase in noncontrolling ownership interests resulting from the Spectra Energy Partners public sales of additional partner units in June 2011, and higher earnings from Spectra Energy Partners, primarily as a result of the acquisition of Big Sandy.

EBIT. The $6 million decrease was mostly driven by lower processing revenues, expected lower storage revenues and accelerated software amortization costs, partially offset by increased earnings from expansions.

Six Months Ended June 30, 2012 Compared to Same Period in 2011

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

•

a $37 million increase from expansion projects and the acquisition of Big Sandy, and

•

an $11 million increase in recoveries of electric power and other costs passed through to customers, partially offset by

•

an $18 million decrease from expected lower storage revenues, lower rates on M&N LP and contract reductions at Ozark Gas Transmission L.L.C., and

•

a $9 million decrease in processing revenues associated with pipeline operations caused by lower volumes and prices.

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

•

a $10 million increase in electric power and other costs passed through to customers, and

•

an $8 million increase primarily due to accelerated software amortization costs.

Depreciation and Amortization. The $7 million increase was driven by expansion projects and the acquisition of Big Sandy.

Noncontrolling Interests. The $8 million increase was driven by an increase in noncontrolling ownership interests resulting from the Spectra Energy Partners public sales of additional partner units in June 2011, and higher earnings from Spectra Energy Partners, primarily as a result of the acquisition of Big Sandy.

EBIT. The $14 million decrease was driven by lower processing revenues, expected lower storage revenues, lower rates at M&N LP, contract reductions at Ozark Gas Transmission, L.L.C. and accelerated software amortization costs, partially offset by increased earnings from expansions.

Distribution


	Three Months Ended June 30,							Six Months Ended June 30,
	2012		2011		Increase (Decrease)			2012		2011		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	322	$	375	$	(53	)	$	919	$	1,071	$	(152	)
Operating expenses
Natural gas purchased		89		127		(38	)		375		496		(121	)
Operating, maintenance and other		106		107		(1	)		213		214		(1	)
Depreciation and amortization		52		53		(1	)		105		106		(1	)

EBIT	$	75	$	88	$	(13	)	$	226	$	255	$	(29	)

Number of customers, thousands									1,367		1,348		19
Heating degree days, Fahrenheit		807		930		(123	)		3,699		4,702		(1,003	)
Pipeline throughput, TBtu		159		156		3			426		487		(61	)
Canadian dollar exchange rate, average		1.01		0.97		0.04			1.01		0.98		0.03

Three Months Ended June 30, 2012 Compared to Same Period in 2011

Operating Revenues. The $53 million decrease was driven by:

•

a $27 million decrease from lower natural gas prices passed through to customers. Prices charged to customers are adjusted quarterly based on the 12 month New York Mercantile Exchange (NYMEX) forecast,

•

a $14 million decrease in customer usage of natural gas primarily due to weather that was more than 13% warmer than in 2011,

•

a $14 million decrease resulting from a weaker Canadian dollar, and

•

a $7 million decrease primarily due to lower short-term storage revenues as a result of an unfavorable regulatory decision affecting 2010 and 2011 storage revenues, partially offset by

•

a $7 million increase in short-term transportation service.

Natural Gas Purchased. The $38 million decrease was driven by:

•

a $27 million decrease from lower natural gas prices passed through to customers,

•

an $11 million decrease due to lower volumes of natural gas sold primarily due to warmer weather, and

•

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

Operating, maintenance and other. The $1 million decrease was driven by:

•

a $5 million decrease resulting from a weaker Canadian dollar, partially offset by

•

a $4 million increase in operating costs.

EBIT. The $13 million decrease was mostly the result of lower short-term storage revenues, a weaker Canadian dollar and lower customer usage due to warmer weather, partially offset by higher short-term transportation services.

Six Months Ended June 30, 2012 Compared to Same Period in 2011

Operating Revenues. The $152 million decrease was driven by:

•

a $99 million decrease in customer usage of natural gas primarily due to weather that was more than 21% warmer than in 2011,

•

a $42 million decrease from lower natural gas prices passed through to customers. Prices charged to customers are adjusted quarterly based on the 12 month NYMEX forecast,

•

a $23 million decrease resulting from a weaker Canadian dollar, and

•

a $9 million decrease primarily due to lower short-term storage revenues as a result of an unfavorable regulatory decision affecting 2010 and 2011 storage revenues, partially offset by

•

an $11 million increase in short-term transportation service.

•

an $8 million increase from growth in the number of customers.

Natural Gas Purchased. The $121 million decrease was driven by:

•

a $70 million decrease due to lower volumes of natural gas sold primarily due to warmer weather,

•

a $42 million decrease from lower natural gas prices passed through to customers,

•

an $8 million decrease resulting from a weaker Canadian dollar, and

•

a $6 million decrease in operating fuel costs, partially offset by

•

a $5 million increase from growth in the number of customers.

Operating, maintenance and other. The $1 million decrease was driven by:

•

a $6 million decrease resulting from a weaker Canadian dollar, partially offset by

•

a $5 million increase in operating costs.

EBIT. The $29 million decrease was largely the result of lower customer usage due to warmer weather, a weaker Canadian dollar and lower short-term storage revenue, partially offset by higher short-term transportation services and lower operating fuel costs.

Western Canada Transmission & Processing


	Three Months Ended June 30,							Six Months Ended June 30,
	2012		2011		Increase (Decrease)			2012		2011		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	329	$	371	$	(42	)	$	795	$	810	$	(15	)
Operating expenses
Natural gas and petroleum products purchased		62		67		(5	)		223		189		34
Operating, maintenance and other		133		147		(14	)		264		280		(16	)
Depreciation and amortization		48		48		—			95		94		1

Operating income		86		109		(23	)		213		247		(34	)
Other income and expenses		8		4		4			19		7		12

EBIT	$	94	$	113	$	(19	)	$	232	$	254	$	(22	)

Pipeline throughput, TBtu		155		166		(11	)		332		349		(17	)
Volumes processed, TBtu		160		174		(14	)		339		350		(11	)
Empress inlet volumes, TBtu		109		129		(20	)		280		310		(30	)
Canadian dollar exchange rate, average		1.01		0.97		0.04			1.01		0.98		0.03

Three Months Ended June 30, 2012 Compared to Same Period in 2011

Operating Revenues. The $42 million decrease was driven by:

•

a $22 million decrease due to lower NGL sales prices associated with the Empress operations,

•

a $14 million decrease due to lower NGL sales volumes associated with the Empress operations primarily as a result of warmer weather, and

•

a $14 million decrease as a result of a weaker Canadian dollar, partially offset by

•

a $9 million increase in gathering and processing revenues primarily due to contracted volumes from expansions associated with non-conventional supply discoveries in the Fort Nelson area.

Natural Gas and Petroleum Products Purchased. The $5 million decrease was driven by:

•

a $5 million decrease in natural gas purchases for extraction at Empress, primarily due to decreased volumes,

•

a $5 million decrease due primarily to lower volumes of make-up gas purchases at Empress as a result of lower NGL production, and

•

a $3 million decrease due to a weaker Canadian dollar, partially offset by

•

an $8 million non-cash charge in the second quarter of 2012 to reduce the book value of propane and butane inventory at our Empress operations to estimated net realizable value.

Operating, Maintenance and Other. The $14 million decrease was driven by:

•

a $17 million decrease due primarily to expected plant maintenance costs in the second quarter of 2011 that did not recur in the 2012 period, and

•

a $6 million decrease due to a weaker Canadian dollar, partially offset by

•

a $5 million increase in project development costs.

Other Income and Expenses. The $4 million increase was driven primarily by higher AFUDC resulting from increased capital spending on expansion projects.

EBIT. The $19 million decrease was driven by lower earnings at the Empress NGL business due mainly to lower NGL sales prices and an adjustment to reduce the book value of propane and butane inventory, both driven by lower commodity prices. This was partially offset by improved results in the gathering and processing business, mainly driven by higher contracted volumes from expansions in the Horn River area of British Columbia and expected lower plant maintenance costs.

Six Months Ended June 30, 2012 Compared to Same Period in 2011

Operating Revenues. The $15 million decrease was driven by:

•

a $35 million decrease due to lower NGL sales prices associated with the Empress operations,

•

a $27 million decrease due to lower NGL sales volumes associated with the Empress operations primarily as a result of warmer weather, and

•

a $21 million decrease as a result of a weaker Canadian dollar, substantially offset by

•

a $27 million increase in gathering and processing revenues due primarily to contracted volumes from expansions associated with non-conventional supply discoveries in the Fort Nelson area,

•

a $24 million increase due primarily to higher sales volumes of residual natural gas at the Empress operations,

•

an $11 million increase in transmission revenue, and

•

a $5 million increase from recovery of carbon and other non-income tax expense from customers.

Natural Gas and Petroleum Products Purchased. The $34 million increase was driven by:

•

a $31 million increase in natural gas purchases for extraction at Empress primarily due to increased volumes,

•

a $13 million increase as a result of higher costs of natural gas purchased for the Empress facility caused primarily by higher extraction premiums, and

•

an $8 million non-cash charge to reduce the book value of propane and butane inventory at our Empress operations as described above, partially offset by

•

a $13 million decrease due primarily to lower volumes of make-up gas purchases at Empress as a result of lower NGL production, and

•

a $5 million decrease due to a weaker Canadian dollar.

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

•

a $16 million decrease due primarily to expected plant turnaround costs in the second quarter of 2011 that did not recur in the 2012 period, and

•

an $8 million decrease due to a weaker Canadian dollar, partially offset by

•

a $5 million increase in project development costs, and

•

a $5 million increase in carbon and other non-income tax expense.

Other Income and Expenses. The $12 million increase was driven primarily by higher AFUDC resulting from increased capital spending on expansion projects.

EBIT. The $22 million decrease was driven by lower earnings at the Empress NGL business, including an adjustment to reduce the book value of propane and butane inventory, partially offset by higher gathering and processing earnings from expansions.

Matters Affecting Future Western Canada Transmission & Processing Results

An $8 million non-cash charge ($6 million after tax) was recorded in the second quarter of 2012 to reduce the book value of propane and butane inventory as of June 30, 2012 at our Empress operations to estimated net realizable value. If estimated future prices for propane and butane increase by December 31, 2012, write-downs previously recorded, in part or in full, may be reversed. Conversely, if estimated future prices were to decline further, additional write-downs could be required on volumes held at June 30, 2012 or produced during the remainder of 2012.

Field Services


	Three Months Ended June 30,							Six Months Ended June 30,
	2012		2011		Increase (Decrease)			2012		2011		Increase (Decrease)
	(in millions, except where noted)
Equity in earnings of unconsolidated affiliates	$	66	$	138	$	(72	)	$	159	$	219	$	(60	)

EBIT	$	66	$	138	$	(72	)	$	159	$	219	$	(60	)

Natural gas gathered and processed/transported, TBtu/d (a,b)		7.0		6.9		0.1			7.1		6.8		0.3
NGL production, MBbl/d (a,c)		392		377		15			402		367		35
Average natural gas price per MMBtu (d)	$	2.22	$	4.31	$	(2.09	)	$	2.48	$	4.21	$	(1.73	)
Average NGL price per gallon (e)	$	0.77	$	1.24	$	(0.47	)	$	0.89	$	1.19	$	(0.30	)
Average crude oil price per barrel (f)	$	93.46	$	102.56	$	(9.10	)	$	98.15	$	98.33	$	(0.18	)

(a)	Reflects 100% of volumes.

(b)	Trillion British thermal units per day.

(c)	Thousand barrels per day.

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

(e)	Does not reflect results of commodity hedges.

(f)	Average price based on NYMEX calendar month.

Three Months Ended June 30, 2012 Compared to Same Period in 2011

EBIT. Lower equity earnings of $72 million were mainly the result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:

•

a $92 million decrease from commodity-sensitive processing arrangements due to decreased commodity prices, and

•

an $18 million decrease attributable to unfavorable results from NGL and gas marketing, partially offset by

•

a $22 million increase due to lower operating expenses primarily attributable to decreased depreciation expense as a result of changes to the remaining useful lives of DCP Midstream’s gathering, transmission, processing, storage and other assets during the second quarter of 2012. The key contributing factor to the change is an increase in estimated remaining economically recoverable commodity reserves, resulting from advances in extraction processes as well as improved technology used to locate reserves,

•

a $9 million increase in gathering and processing volumes, attributable to expansion projects and growth across certain geographic regions.

Six Months Ended June 30, 2012 Compared to Same Period in 2011

EBIT. Lower equity earnings of $60 million were mainly the result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:

•

a $116 million decrease from commodity-sensitive processing arrangements due to decreased commodity prices, and

•

a $14 million decrease attributable to unfavorable results from NGL and gas marketing, partially offset by

•

a $37 million increase in gathering and processing volumes, as a result of expansion projects and growth across certain geographic regions and the absence of severe weather which caused wellhead freeze-offs which shut in gas wells and reduced recoveries in 2011,

•

a $16 million increase due to lower operating expenses primarily attributable to decreased depreciation expense as a result of changes to the remaining useful lives of DCP Midstream’s gathering, transmission, processing, storage and other assets during the second quarter of 2012 as described above.

•

a $7 million increase in gains associated with the issuance of partnership units by DCP Partners, and

•

a $7 million increase in earnings from DCP Partners as a result of mark-to-market gains on derivative instruments used to protect distributable cash flows and decreased depreciation expense as a result of an adjustment to the remaining useful lives of DCP Partners’ gathering, transmission, processing, storage and other assets during the second quarter of 2012 as described above.

Other


	Three Months Ended June 30,								Six Months Ended June 30,
	2012			2011			Increase (Decrease)		2012			2011			Increase (Decrease)
	(in millions)
Operating revenues	$	19		$	16		$	3	$	40		$	33		$	7
Operating expenses		44			44			—		93			83			10

Operating loss		(25	)		(28	)		3		(53	)		(50	)		(3	)
Other income and expenses		—			(1	)		1		(1	)		(3	)		2

EBIT	$	(25	)	$	(29	)	$	4	$	(54	)	$	(53	)	$	(1	)

Three Months Ended June 30, 2012 Compared to Same Period in 2011

EBIT. The $4 million increase in EBIT reflects lower corporate costs.

Six Months Ended June 30, 2012 Compared to Same Period in 2011

EBIT. The EBIT results are comparable period over period.

Impairment of Goodwill

In connection with our quantitative assessments, we primarily used a discounted cash flow analysis to determine fair values of those reporting units. The long-term growth rates used for the reporting units that we quantitatively assessed reflect continued expansion of our assets, driven by new natural gas supplies such as shale gas in North America and increasing demand for natural gas transportation capacity on our pipeline systems primarily as a result of forecasted growth in natural gas-fired power plants. We assumed a weighted average long-term growth rate of 2.9% for our 2012 quantitative goodwill impairment analysis. Had we assumed a 100 basis point lower growth rate for each of the reporting units that we quantitatively assessed, there would have been no impairment of goodwill. We continue to monitor the effects of the global economic downturn with respect to the long-term cost of capital utilized to calculate our reporting units’ fair values. For our 2012 quantitative goodwill impairment analysis, we assumed weighted-average costs of capital ranging from 5.5% to 6.3% that market participants would use. Had we assumed a 100 basis point increase in the weighted-average cost of capital for each of the reporting units that we quantitatively assessed, there would have been no impairment of goodwill. For our regulated businesses in Canada, if an increase in the cost of capital occurred, we assumed that the effect on the corresponding reporting unit’s fair value would be ultimately offset by a similar increase in the reporting unit’s regulated revenues since those rates include a component that is based on the reporting unit’s cost of capital.

Based on the results of our annual impairment testing, no indicators of impairment were noted and the fair values of the reporting units that we quantitatively assessed at April 1, 2012 (our testing date) were substantially in excess of their respective carrying values. No triggering events or changes in circumstances occurred during the period April 1, 2012 through June 30, 2012 that would warrant re-testing for goodwill impairment.

LIQUIDITY AND CAPITAL RESOURCES

As of June 30, 2012, we had negative working capital of $2,049 million. This balance includes short-term borrowings and commercial paper totaling $1,073 million and current maturities of long-term debt of $1,030 million. We will rely upon cash flows from operations and various financing transactions, which may include issuances of short-term and long-term debt, to fund our liquidity and capital requirements for the next 12 months. We have access to four revolving credit facilities, with total combined capital commitments of approximately $2.9 billion, with approximately $1.8 billion available at June 30, 2012. These facilities are used principally as back-stops for commercial paper programs or for the issuance of letters of credit. At Union Gas, we primarily use commercial paper to support short-term working capital fluctuations. At Spectra Capital, Spectra Energy Partners and Westcoast, we primarily use commercial paper for temporary funding of capital expenditures. We also utilize commercial paper, other variable-rate debt and interest rate swaps to achieve our desired mix of fixed and variable-rate debt. See Note 11 of Notes to Condensed Consolidated Financial Statements for a discussion of available credit facilities and Financing Cash Flows and Liquidity for a discussion of effective shelf registrations.

Operating Cash Flows

Net cash provided by operating activities decreased $179 million to $1,159 million for the six months ended June 30, 2012 compared to the same period in 2011, driven mostly by working capital changes, including lower accounts payable and higher tax payments in 2012, and lower earnings in 2012.

Investing Cash Flows

Net cash used in investing activities increased $221 million to $792 million in the first six months of 2012 compared to the same period in 2011. This change was driven by net sales of Spectra Energy Partners’ AFS marketable securities in 2011, increased capital expenditures and payment in 2012 of $30 million previously withheld from the purchase price consideration of the acquisition of Bobcat in 2010.


	Six Months Ended June 30,
	2012		2011
	(in millions)
Capital and Investment Expenditures
U.S. Transmission (a)	$	335	$	294
Distribution		96		117
Western Canada Transmission & Processing		327		313
Other		31		19

Total	$	789	$	743

(a)

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

Capital and investment expenditures for the six months ended June 30, 2012 consisted of $530 million for expansion projects and $259 million for maintenance and other projects.

We project 2012 capital and investment expenditures of approximately $2.4 billion, consisting of approximately $1.2 billion for U.S. Transmission, $0.3 billion for Distribution and $0.9 billion for Western Canada Transmission & Processing. Total projected 2012 capital and investment expenditures include approximately $1.7 billion of expansion capital expenditures and $0.7 billion for maintenance and upgrades of existing plants, pipelines and infrastructure to serve growth. We continue to assess short and long-term market requirements and adjust our capital plans as required.

Financing Cash Flows and Liquidity

During 2011, we identified certain immaterial errors in our previously issued Condensed Consolidated Statements of Cash Flows related to the accounting for rollovers of outstanding borrowings under our revolving bank credit facilities. The following discussion reflects the correction of these immaterial errors and also a change in the presentation of cash borrowings and repayments under these facilities. See Note 1 of Notes to Condensed Consolidated Financial Statements for further discussion.

Net cash used in financing activities totaled $414 million in the first six months of 2012 compared to $361 million used in the first six months of 2011. This change was driven by:

•

proceeds of $213 million in 2011 from the issuance of Spectra Energy Partners’ common units used to fund a portion of the acquisition of Big Sandy in July 2011,

•

$28 million of net debt retirements in 2012 compared to $53 million of net debt issuances, including net revolving credit facility borrowings, in 2011, and

•

a $31 million increase in dividends paid on common stock in 2012, driven primarily by higher per-share dividend rates, partially offset by

•

a $15 million increase in short-term borrowings and commercial paper outstanding in 2012 compared to a $258 million decrease in the 2011 period.

Available Credit Facilities and Restrictive Debt Covenants. See Note 11 of Notes to Condensed Consolidated Financial Statements for a discussion of available credit facilities and related financial and other covenants.

The terms of our Spectra Capital credit agreement require our consolidated debt-to-total-capitalization ratio, as defined in the agreement, to be 65% or lower. Per the terms of the agreement, collateralized debt and Spectra Energy Partners’ debt and equity are excluded in the calculation of the ratio. As of June 30, 2012, this ratio was 58%. Our equity and, as a result, this ratio, are sensitive to significant movements of the Canadian dollar relative to the U.S. dollar due to the significance of our Canadian operations. Based on the strength of our total capitalization as of June 30, 2012, it is unlikely that a material adverse effect would occur as a result of a weakened Canadian dollar.

Credit Ratings


	Standard & Poor’s	Moody’s Investors Service	Fitch Ratings	DBRS
As of June 30, 2012
Spectra Capital (a)	BBB	Baa2	BBB	n/a
Texas Eastern Transmission, LP (a)	BBB+	Baa1	BBB+	n/a
Westcoast (a)	BBB+	n/a	n/a	A (low)
Union Gas (a)	BBB+	n/a	n/a	A
Maritimes & Northeast Pipeline, L.L.C. (a)	BBB-	Baa3	n/a	n/a
M&N LP (b)	A	A2/A3	n/a	A
Spectra Energy Partners (a)	BBB	Baa3	BBB	n/a

(a)	Represents senior unsecured credit rating.

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

n/a	Indicates not applicable.

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

Dividends. Our near-term objective is to increase our dividend by at least $0.08 per year and to continue paying cash dividends in the future. In the long-term, we anticipate paying dividends at an average payout ratio level of between 60%-65% of our net income from controlling interests per share of common stock. The actual payout ratio, however, may vary from year to year depending on earnings levels. We expect to continue our policy of paying regular cash dividends. The declaration and payment of dividends are subject to the sole discretion of our Board of Directors and will depend upon many factors, including the financial condition, earnings and capital requirements of our operating subsidiaries, covenants associated with certain debt obligations, legal requirements, regulatory constraints and other factors deemed relevant by our Board of Directors. A dividend of $0.28 per common share was declared on July 9, 2012 and will be paid on September 10, 2012.

Other Financing Matters. On July 17, 2012, Algonquin issued $350 million aggregate principal amount of 3.51% notes due in 2024. Net proceeds from the offering were used for general corporate purposes.

Spectra Energy Corp and Spectra Capital have an effective shelf registration statement on file with the SEC to register the issuance of unspecified amounts of various equity and debt securities, respectively. Spectra Energy Partners also has an effective shelf registration statement on file with the SEC to register the issuance of limited partner common units and various debt securities. In addition, as of June 30, 2012, certain of our subsidiaries in Canada have 1.2 billion Canadian dollars (approximately $1.2 billion) available for issuance in the Canadian market under debt shelf prospectuses that expire in October 2012. These subsidiaries intend to replace their expiring debt shelf prospectuses with similar prospectuses.

OTHER ISSUES

New Accounting Pronouncements. There were no significant accounting pronouncements adopted during the six months ended June 30, 2012 that had a material impact on our consolidated results of operations, financial position or cash flows.

Item 3.

Quantitative and Qualitative Disclosures about Market Risk.

Our exposure to market risk is described in Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2011. We believe our exposure to market risk has not changed materially since then.

Item 4.

Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

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

Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2012, and, based upon this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended June 30, 2012 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings.

We have no material pending legal proceedings that are required to be disclosed hereunder. For information regarding other legal proceedings, including regulatory and environmental matters, see Notes 3 and 14 of Notes to Condensed Consolidated Financial Statements, which information is incorporated by reference into this Part II.

Item 1A.

Risk Factors.

In addition to the other information set forth in this report, careful consideration should be given to the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2011, which could materially affect our financial condition or future results. There have been no material changes to those risk factors.

Item 6.

Exhibits.

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

•

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

•

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

•

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

•

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

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

(a) Exhibits


Exhibit Number

3.1		Certificate of Amendment to the Amended and Restated Certificate of Incorporation of Spectra Energy Corp (filed as Exhibit No. 3.1 to Form 8-K of Spectra Energy Corp on May 7, 2012).

3.2		Second Amended and Restated By-Laws of Spectra Energy Corp (filed as Exhibit No. 3.2 to Form 8-K of Spectra Energy Corp on May 7, 2012).

*10.1		Spectra Energy Corp Executive Savings Plan, as amended and restated.

*10.2		Spectra Energy Corp Directors’ Savings Plan, as amended and restated.

*10.3		Spectra Energy Corp Executive Cash Balance Plan, as amended and restated.

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

*31.2		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*32.1		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*32.2		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*101.INS		XBRL Instance Document.

*101.SCH		XBRL Taxonomy Extension Schema.

*101.CAL		XBRL Taxonomy Extension Calculation Linkbase.

*101.DEF		XBRL Taxonomy Extension Definition Linkbase.

*101.LAB		XBRL Taxonomy Extension Label Linkbase.

*101.PRE		XBRL Taxonomy Extension Presentation Linkbase.

*	Filed herewith.

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

SIGNATURES

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


						SPECTRA ENERGY CORP

Date: August 8, 2012						/s/ Gregory L. Ebel
						Gregory L. Ebel
						President and Chief Executive Officer

Date: August 8, 2012						/s/ J. Patrick Reddy
						J. Patrick Reddy
						Chief Financial Officer