Edgar Filing: Spectra Energy Corp.

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2013

¨	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 March 31, 2013: 669,196,502

SPECTRA ENERGY CORP

FORM 10-Q FOR THE QUARTER ENDED

March 31, 2013

INDEX


		Page

PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)		4

	Condensed Consolidated Statements of Operations for the three months ended March 31, 2013 and 2012		4

	Condensed Consolidated Statements of Comprehensive Income for the three months ended March 31, 2013 and 2012		5

	Condensed Consolidated Balance Sheets as of March 31, 2013 and December 31, 2012		6

	Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2013 and 2012		8

	Condensed Consolidated Statements of Equity for the three months ended March 31, 2013 and 2012		9

	Notes to Condensed Consolidated Financial Statements		10

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

Item 3.	Quantitative and Qualitative Disclosures about Market Risk		43

Item 4.	Controls and Procedures		43

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings		44

Item 1A.	Risk Factors		44

Item 6.	Exhibits		45

	Signatures		46

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 represent management’s intentions, plans, expectations, assumptions and beliefs about future events. 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 are subject to risks, uncertainties and other factors, many of which are outside our control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. Factors used to develop these forward-looking statements and 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 and oil 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 oil 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 and costs 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 and oil transmission and storage, distribution, and gathering and processing facilities;

•

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

•

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

•

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

•

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

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

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements.

SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In millions, except per-share amounts)


	Three Months Ended March 31,
	2013		2012
Operating Revenues
Transportation, storage and processing of natural gas	$	800	$	831
Distribution of natural gas		625		505
Sales of natural gas liquids		112		149
Transportation of crude oil		13		—
Other		39		59

Total operating revenues		1,589		1,544

Operating Expenses
Natural gas and petroleum products purchased		465		433
Operating, maintenance and other		332		321
Depreciation and amortization		186		184
Property and other taxes		100		88

Total operating expenses		1,083		1,026

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

Operating Income		506		519

Other Income and Expenses
Equity in earnings of unconsolidated affiliates		110		118
Other income and expenses, net		33		16

Total other income and expenses		143		134

Interest Expense		149		157

Earnings From Continuing Operations Before Income Taxes		500		496
Income Tax Expense From Continuing Operations		130		137

Income From Continuing Operations		370		359
Income From Discontinued Operations, net of tax		—		2

Net Income		370		361
Net Income—Noncontrolling Interests		30		28

Net Income—Controlling Interests	$	340	$	333

Common Stock Data
Weighted-average shares outstanding
Basic		669		652
Diluted		670		655
Earnings per share from continuing operations
Basic and Diluted	$	0.51	$	0.51
Earnings per share
Basic and Diluted	$	0.51	$	0.51
Dividends per share	$	0.305	$	0.28

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(In millions)


	Three Months Ended March 31,
	2013			2012
Net Income	$	370		$	361

Other comprehensive income (loss)
Foreign currency translation adjustments		(189	)		162
Unrealized mark-to-market net gain on hedges		3			—
Reclassification of cash flow hedges into earnings		2			2
Pension and benefits impact		11			5
Other		1			—

Total other comprehensive income (loss)		(172	)		169

Total Comprehensive Income, net of tax		198			530
Less: Comprehensive Income—Noncontrolling Interests		27			30

Comprehensive Income—Controlling Interests	$	171		$	500

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)


	March 31, 2013		December 31, 2012
ASSETS

Current Assets
Cash and cash equivalents	$	188	$	94
Receivables, net		1,119		970
Inventory		128		309
Other		301		290

Total current assets		1,736		1,663


Investments and Other Assets
Investments in and loans to unconsolidated affiliates		2,801		2,692
Goodwill		4,887		4,513
Other		544		572

Total investments and other assets		8,232		7,777


Property, Plant and Equipment
Cost		27,670		26,257
Less accumulated depreciation and amortization		6,366		6,352

Net property, plant and equipment		21,304		19,905

Regulatory Assets and Deferred Debits		1,266		1,242

Total Assets	$	32,538	$	30,587

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions, except per-share amounts)


	March 31, 2013		December 31, 2012
LIABILITIES AND EQUITY

Current Liabilities
Accounts payable	$	515	$	464
Commercial paper		1,415		1,259
Taxes accrued		89		67
Interest accrued		166		185
Current maturities of long-term debt		747		921
Other		831		895

Total current liabilities		3,763		3,791


Long-term Debt		12,280		10,653


Deferred Credits and Other Liabilities
Deferred income taxes		4,774		4,358
Regulatory and other		1,653		1,684

Total deferred credits and other liabilities		6,427		6,042


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, 669 million and 668 million shares outstanding at March 31, 2013 and December 31, 2012, respectively		1		1
Additional paid-in capital		5,298		5,297
Retained earnings		2,301		2,165
Accumulated other comprehensive income		1,340		1,509

Total controlling interests		8,940		8,972
Noncontrolling interests		870		871

Total equity		9,810		9,843

Total Liabilities and Equity	$	32,538	$	30,587

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY CORP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)


	Three Months Ended March 31,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	370		$	361
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		189			187
Deferred income tax expense		121			74
Equity in earnings of unconsolidated affiliates		(110	)		(118	)
Distributions received from unconsolidated affiliates		79			114
Other		(67	)		(72	)

Net cash provided by operating activities		582			546


CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(426	)		(343	)
Investments in and loans to unconsolidated affiliates		(87	)		—
Acquisitions, net of cash acquired		(1,254	)		(30	)
Purchases of held-to-maturity securities		(293	)		(861	)
Proceeds from sales and maturities of held-to-maturity securities		266			734
Purchases of available-for-sale securities		(612	)		—
Proceeds from sales and maturities of available-for-sale securities		619			14
Distributions received from unconsolidated affiliates		6			5
Other changes in restricted funds		7			79

Net cash used in investing activities		(1,774	)		(402	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt		1,848			—
Payments for the redemption of long-term debt		(495	)		—
Net increase (decrease) in commercial paper		166			(26	)
Distributions to noncontrolling interests		(32	)		(27	)
Dividends paid on common stock		(208	)		(185	)
Other		8			24

Net cash provided by (used in) financing activities		1,287			(214	)

Effect of exchange rate changes on cash		(1	)		1

Net increase (decrease) in cash and cash equivalents		94			(69	)
Cash and cash equivalents at beginning of period		94			174

Cash and cash equivalents at end of period	$	188		$	105

Supplemental Disclosures
Property, plant and equipment non-cash accruals	$	188		$	157

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, 2012	$	1	$	5,297		$	2,165		$	2,044		$	(535	)	$	871		$	9,843
Net income		—		—			340			—			—			30			370
Other comprehensive income (loss)		—		—			—			(186	)		17			(3	)		(172	)
Dividends on common stock		—		—			(205	)		—			—			—			(205	)
Distributions to noncontrolling interests		—		—			—			—			—			(32	)		(32	)
Spectra Energy common stock issued		—		6			—			—			—			—			6
Other, net		—		(5	)		1			—			—			4			—

March 31, 2013	$	1	$	5,298		$	2,301		$	1,858		$	(518	)	$	870		$	9,810


December 31, 2011	$	1	$	4,814		$	1,977		$	1,832		$	(559	)	$	831		$	8,896
Net income		—		—			333			—			—			28			361
Other comprehensive income		—		—			—			160			7			2			169
Dividends on common stock		—		—			(185	)		—			—			—			(185	)
Stock-based compensation		—		(1	)		—			—			—			—			(1	)
Distributions to noncontrolling interests		—		—			—			—			—			(25	)		(25	)
Spectra Energy common stock issued		—		9			—			—			—			—			9

March 31, 2012	$	1	$	4,822		$	2,125		$	1,992		$	(552	)	$	836		$	9,224

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, currently 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. We also own a 50% interest in DCP Midstream, LLC (DCP Midstream), based in Denver, Colorado, one of the leading natural gas gatherers in the United States based on wellhead volumes, and one of the largest U.S. producers and marketers of natural gas liquids (NGLs). In addition, with the first quarter 2013 acquisition of the Express-Platte pipeline system, we own and operate a crude oil pipeline system that connects Canadian and U.S. producers to refineries in the U.S. Rocky Mountain and Midwest regions.

Basis of Presentation. The accompanying Condensed Consolidated Financial Statements include our accounts and the accounts of our majority-owned subsidiaries, after eliminating intercompany transactions and balances. 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, 2012, and reflect all normal recurring adjustments that are, in our opinion, necessary to fairly present our results of operations and financial position. Amounts reported in the Condensed Consolidated Statements of Operations are not necessarily indicative of amounts expected for the respective annual periods due to the effects of seasonal temperature variations on energy consumption, primarily in our gas distribution operations, as well as changing commodity prices on certain of our processing operations and other factors.

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

2. Acquisition of Express-Platte

On March 14, 2013, we acquired 100% of the ownership interests in the Express-Platte pipeline system from Borealis Infrastructure, the Ontario Teachers’ Pension Plan and Kinder Morgan Energy Partners for $1.49 billion, consisting of $1.25 billion in cash and $239 million of acquired debt, before working capital adjustments. The Express-Platte pipeline system, which begins in Hardisty, Alberta, and terminates in Wood River, Illinois, is comprised of both the Express and Platte crude oil pipelines. The Express pipeline carries crude oil to U.S. refining markets in the Rockies area, specifically Billings and Laurel, Montana, and Casper, Wyoming. The Platte pipeline, which interconnects with Express pipeline in Casper, transports crude oil predominantly from the Bakken and western Canada to refineries in the Midwest. These assets are a part of our new reportable business segment, “Liquids,” which also includes our one-third ownership interest in DCP Sand Hills Pipeline, LLC (Sand Hills) and DCP Southern Hills Pipeline, LLC (Southern Hills).

The following table summarizes the preliminary fair values of the assets and liabilities acquired as of March 14, 2013. Subsequent adjustments may be recorded upon the completion of the valuation and the final determination of the purchase price allocation.


	Purchase Price Allocation
	(in millions)
Cash purchase price	$	1,250
Working capital and other purchase adjustments		71

Total		1,321

Cash		67
Receivables		21
Other current assets		2
Property, plant and equipment		1,352
Accounts payable		(20	)
Other current liabilities		(14	)
Deferred credits and other liabilities		(302	)
Long-term debt, including current portion		(239	)

Total assets acquired/liabilities assumed		867

Goodwill	$	454

The purchase price is greater than the sum of fair values of the net assets acquired, resulting in goodwill as noted above. The goodwill reflects the value of the strategic location of the crude oil pipeline and the opportunity to grow the business. Goodwill related to the acquisition of Express-Platte is not deductible for income tax purposes.

Pro forma results of operations that reflect the acquisition of Express-Platte as if the acquisition had occurred as of the beginning of the periods in this report are not presented as they do not materially differ from actual results reported in our Condensed Consolidated Statements of Operations.

As of March 31, 2013, Express-Platte debt, including current maturities, totaled $237 million, consisting of $127 million of 7.39% subordinated notes due 2019 and $110 million of 6.09% senior notes due 2020. The notes are secured by the assignment of the Express-Platte transportation receivables and by the Canadian portion of the Express-Platte pipeline system assets.

3. Business Segments

We manage our business in five reportable segments: U.S. Transmission, Distribution, Western Canada Transmission & Processing, Field Services and Liquids. 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 owned 61% by Spectra Energy as of March 31, 2013, 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 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, compresses, treats, processes, transports, stores and sells natural gas. In addition, this segment also produces, fractionates, transports, stores, sells, markets and trades NGLs and condensate. 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.

Liquids, a newly formed segment effective with the March 2013 acquisition of Express-Platte, provides transportation of crude oil and NGLs. The Express pipeline carries crude oil from Alberta, Canada to refining markets in the Rockies area. The Platte pipeline, which interconnects with Express pipeline in Casper, Wyoming, transports crude oil predominantly from the Bakken and western Canada to refineries in the Midwest. These operations are primarily subject to the rules and regulations of the FERC and NEB. The Sand Hills and Southern Hills pipelines, currently under construction by DCP Midstream, will provide NGL transportation from the Permian Basin and Eagle Ford region to the premium NGL markets on the Gulf Coast, and from the Mid-Continent to Mont Belvieu, Texas, respectively. We have direct one-third ownership interests in Sand Hills and Southern Hills. DCP Midstream and Phillips 66 also each own direct one-third ownership interests in the two pipelines. Sand Hills and Southern Hills are subject to the rules and regulations of the FERC.

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

Condensed Consolidated Statements of Operations


	Unaffiliated Revenues		Intersegment Revenues			Total Operating Revenues (a)			Segment EBIT/ Consolidated Earnings from Continuing Operations before Income Taxes (a)
			(in millions)
Three Months Ended March 31, 2013
U.S. Transmission	$	481	$	3		$	484		$	266
Distribution		699		—			699			168
Western Canada Transmission & Processing		393		15			408			111
Field Services		—		—			—			88
Liquids		13		—			13			6

Total reportable segments		1,586		18			1,604			639
Other		3		12			15			(26	)
Eliminations		—		(30	)		(30	)		—
Interest expense		—		—			—			149
Interest income and other (b)		—		—			—			36

Total consolidated	$	1,589	$	—		$	1,589		$	500

Three Months Ended March 31, 2012
U.S. Transmission	$	493	$	2		$	495		$	271
Distribution		597		—			597			151
Western Canada Transmission & Processing		453		13			466			138
Field Services		—		—			—			93
Liquids		—		—			—			—

Total reportable segments		1,543		15			1,558			653
Other		1		20			21			(29	)
Eliminations		—		(35	)		(35	)		—
Interest expense		—		—			—			157
Interest income and other (b)		—		—			—			29

Total consolidated	$	1,544	$	—		$	1,544		$	496

(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.

Condensed Consolidated Balance Sheets


	March 31, 2013			December 31, 2012
	(in millions)
Segment Assets
U.S. Transmission	$	12,895		$	12,630
Distribution		5,632			5,842
Western Canada Transmission & Processing		6,394			6,431
Field Services		1,272			1,235
Liquids (a)		2,503			513

Total reportable segments		28,696			26,651
Other (a)		4,408			4,475
Eliminations		(566	)		(539	)

Total consolidated	$	32,538		$	30,587

(a)	The December 31, 2012 amounts presented for Liquids and Other have been re-cast to reflect the move of our investments in Sand Hills and Southern Hills, totaling $513 million, from Other to Liquids effective with the creation of the Liquids operating segment in the first quarter of 2013.

4. Regulatory Matters

Union Gas. Union Gas’ 2013 distribution rates are set under a cost of service framework since 2012 was the final year in Union Gas’s multi-year incentive regulation framework. Union Gas intends to file its application and evidence for another incentive regulation framework with the OEB during 2013.

In December 2012, Union Gas appealed the OEB’s decision on the disposition of the 2011 non-commodity deferral account balances to the Ontario Divisional Court. The basis of the appeal is impermissible retroactive ratemaking. A hearing is expected later this year.

Union Gas plans to file its application with the OEB in May 2013 for the annual disposition of the 2012 non-commodity deferral account balances. The application will include a proposal that revenues derived from the optimization of upstream transportation contracts in 2012 be treated as optimization revenues and included in utility earnings rather than a reduction to gas costs. Optimization revenues had been classified as utility earnings for 2008, 2009 and 2010, and were reclassified as a reduction to gas costs by the OEB in the 2011 non-commodity deferral account balances proceeding. The net impact on customers for the 2012 non-commodity deferral account balances, including the impact of earnings sharing, would be a receivable of approximately $1 million. If the OEB maintains that the 2012 revenues earned from the optimization of Union Gas’ upstream transportation contracts should be treated as a reduction to gas costs, 90% of which are to be credited to customers, the combined impact on customers would be a refund payable of approximately $17 million, which is reflected in the March 31, 2013 and December 31, 2012 Condensed Consolidated Balance Sheets.

5. Income Taxes

Income tax expense from continuing operations for the three months ended March 31, 2013 was $130 million, compared to $137 million for the same period in 2012. The effective tax rate for income from continuing operations for the three month periods ended March 31, 2013 was 26%, compared to 28% for the same period in 2012. The lower income tax expense and effective tax rate resulted primarily from a lower Canadian effective tax rate due to the recognition of regulatory tax benefits.

No material net change in unrecognized tax benefits was recognized during the three-month period ended March 31, 2013. Although uncertain, we believe the total amount of unrecognized tax benefits will not materially change prior to March 31, 2014.

6. Discontinued Operations

Discontinued operations in 2012 was mostly comprised of the net effects of a settlement arrangement related to prior liquefied natural gas (LNG) contracts. Purchases and sales of propane under these agreements ended in 2012. See Note 9 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 March 31, 2012
Other	$	57	$	3	$	1	$	2

Total consolidated	$	57	$	3	$	1	$	2

7. Earnings per Common Share

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

The following table presents our basic and diluted EPS calculations:


	Three Months Ended March 31,
	2013		2012
	(in millions, except per-share amounts)
Income from continuing operations, net of tax—controlling interests	$	340	$	331
Income from discontinued operations, net of tax—controlling interests		—		2

Net income—controlling interests	$	340	$	333

Weighted-average common shares outstanding
Basic		669		652
Diluted		670		655
Basic and diluted earnings per common share (a)
Continuing operations	$	0.51	$	0.51
Discontinued operations, net of tax		—		—

Total basic and diluted earnings per common share	$	0.51	$	0.51

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

8. 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 the lower of cost or market, primarily using average cost. The components of inventory are as follows:


	March 31, 2013		December 31, 2012
	(in millions)
Natural gas	$	36	$	200
NGLs		14		31
Materials and supplies		78		78

Total inventory	$	128	$	309

9. Investments in and Loans to Unconsolidated Affiliates

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


	Three Months Ended March 31,
	2013		2012
	(in millions)
Operating revenues	$	2,612	$	2,902
Operating expenses		2,450		2,694
Operating income		162		208
Net income		120		155
Net income attributable to members’ interests		91		144

DCP Midstream recorded gains on sales of common units of DCP Partners in the first quarters of 2013 and 2012 directly to DCP Midstream’s equity. Our proportionate 50% share, totaling $43 million and $21 million, respectively, 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 LNG 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 were $57 million for the three months ended March 31, 2012.

10. Goodwill

The following presents changes in goodwill during 2013:


December 31, 2012	$	4,513
Acquisition of Express-Platte		454
Foreign currency translation		(80	)

March 31, 2013	$	4,887

See Note 2 for discussion of the acquisition of Express-Platte.

Our Empress NGL business, a reporting unit within Western Canada Transmission & Processing, is significantly affected by fluctuations in commodity prices. We updated our Empress NGL reporting unit’s impairment test using recent operational information, financial data and April 1, 2013 commodity prices, and concluded there was no impairment of goodwill related to Empress.

11. 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 funds held for the purpose of Spectra Energy Partners’ capital expenditures and acquisitions, and insurance-related funds, are classified as available-for-sale (AFS) 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 (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. AFS securities are as follows:


	Estimated Fair Value
	March 31, 2013		December 31, 2012
	(in millions)
Corporate debt securities	$	157	$	164
Money market funds		1		1

Total available-for-sale investments	$	158	$	165

At March 31, 2013, the weighted-average contractual maturity of outstanding AFS securities was less than one year.

There were no material gross unrealized holding gains or losses associated with investments in AFS securities at March 31, 2013 or December 31, 2012.

During the fourth quarter of 2012, we invested the proceeds from Spectra Energy Partners’ issuance of common units in AFS marketable securities. These investments, which totaled $136 million as of March 31, 2013 and $141 million as of December 31, 2012, and are classified as Investments and Other Assets—Other on the Consolidated Balance Sheet, are restricted for the purpose of funding Spectra Energy Partners’ capital expenditures and acquisitions. We had an aggregate $137 million of restricted AFS securities as of March 31, 2013 and $142 million as of December 31, 2012 classified as Investments and Other Assets—Other.

HTM Securities. HTM securities are as follows:


	Estimated Fair Value
	March 31, 2013		December 31, 2012
	(in millions)
Canadian government securities	$	206	$	210
Bankers acceptances		77		52

Total held-to-maturity investments	$	283	$	262

Restricted HTM marketable securities of $100 million as of March 31, 2013 and $76 million as of December 31, 2012 are classified as Current Assets—Other, and $183 million as of March 31, 2013 and $186 million as of December 31, 2012, 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. There were sufficient funds held in escrow to fund all future debt service on the M&N LP notes as of March 31, 2013.

At March 31, 2013, the weighted-average contractual maturity of outstanding HTM securities was less than one year.

There were no material gross unrecognized holding gains or losses associated with investments in HTM securities at March 31, 2013 or December 31, 2012.

Other Restricted Funds. In addition to the portions of the AFS and HTM securities that were restricted funds as described above, we had other restricted funds totaling $14 million at March 31, 2013 and $21 million at December 31, 2012 classified as Current Assets—Other. These restricted funds are related to additional amounts for insurance.

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

12. Debt and Credit Facilities

Available Credit Facilities and Restrictive Debt Covenants


	Expiration Date		Total Credit Facilities Capacity		Outstanding at March 31, 2013						Available Credit Facilities Capacity
	Expiration Date		Total Credit Facilities Capacity		Commercial Paper		Letters of Credit		Total		Available Credit Facilities Capacity
Spectra Energy Capital, LLC
Multi-year syndicated (a)		2016	$	1,500	$	792	$	7	$	799	$	701
Westcoast Energy Inc.
Multi-year syndicated (b)		2016		295		67		—		67		228
Union Gas
Multi-year syndicated (c)		2016		393		232		—		232		161
Spectra Energy Partners
Multi-year syndicated (d)		2016		700		324		—		324		376

Total			$	2,888	$	1,415	$	7	$	1,422	$	1,466

(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 61% at March 31, 2013.

(b)	U.S. dollar equivalent at March 31, 2013. 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 50% at March 31, 2013.

(c)

U.S. dollar equivalent at March 31, 2013. 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 March 31, 2013.

(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 March 31, 2013, this ratio was 3.4. 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 March 31, 2013, 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 March 31, 2013, 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 requires 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 capitalization are excluded in the calculation of the ratio. This ratio was 61% at March 31, 2013.

Delayed-draw Term Loan Agreement. In December 2012, Spectra Capital entered into a three-year $1.2 billion unsecured delayed-draw term loan agreement which allowed for up to four borrowings prior to March 1, 2013. The full $1.2 billion available under the agreement was borrowed in the first quarter of 2013. These borrowings are due in 2015 and are classified as Long-Term Debt on the Condensed Consolidated Balance Sheets. Proceeds from borrowings under the term loan were used for general corporate purposes, including acquisitions and to refinance existing indebtedness.

13. Fair Value Measurements

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


Description	Condensed Consolidated Balance Sheet Caption	March 31, 2013
Description	Condensed Consolidated Balance Sheet Caption	Total		Level 1		Level 2		Level 3
		(in millions)
Corporate debt securities	Cash and cash equivalents	$	63	$	—	$	63	$	—
Corporate debt securities	Current assets—other		19		—		19		—
Derivative assets—interest rate swaps	Current assets—other		6		—		6		—
Corporate debt securities	Investments and other assets—other		138		—		138		—
Derivative assets—interest rate swaps	Investments and other assets—other		40		—		40		—
Money market funds	Investments and other assets—other		1		1		—		—

Total Assets		$	267	$	1	$	266	$	—

Derivative liabilities—natural gas purchase contracts	Deferred credits and other liabilities—regulatory and other	$	6	$	—	$	—	$	6
Derivative liabilities—interest rate swaps	Deferred credits and other liabilities—regulatory and other		9		—		9		—

Total Liabilities		$	15	$	—	$	9	$	6


Description	Condensed Consolidated Balance Sheet Caption	December 31, 2012
Description	Condensed Consolidated Balance Sheet Caption	Total		Level 1		Level 2		Level 3
		(in millions)
Corporate debt securities	Cash and cash equivalents	$	52	$	—	$	52	$	—
Corporate debt securities	Current assets—other		16		—		16		—
Derivative assets—interest rate swaps	Current assets—other		13		—		13		—
Corporate debt securities	Investments and other assets—other		148		—		148		—
Derivative assets—interest rate swaps	Investments and other assets—other		48		—		48		—
Money market funds	Investments and other assets—other		1		1		—		—

Total Assets		$	278	$	1	$	277	$	—

Derivative liabilities—natural gas purchase contracts	Deferred credits and other liabilities—regulatory and other	$	9	$	—	$	—	$	9
Derivative liabilities—interest rate swaps	Deferred credits and other liabilities—regulatory and other		12		—		12		—

Total Liabilities		$	21	$	—	$	12	$	9

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


	Three Months Ended March 31,
	2013			2012
	(in millions)
Long-term derivative liabilities
Fair value, beginning of period	$	9		$	14
Total realized/unrealized losses (gains):
Included in earnings		1			(1	)
Included in other comprehensive income		(4	)		2

Fair value, end of period	$	6		$	15

Total losses (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		$	(1	)

Level 1

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

Level 2 Valuation Techniques

Fair values of our financial instruments 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.


	March 31, 2013				December 31, 2012
	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)		12,982		14,907		11,518		13,539

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

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

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 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 2013 and 2012 periods, there were no material adjustments to assets and liabilities measured at fair value on a nonrecurring basis.

14. 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 the NGL 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 March 31, 2013, we had “pay floating—receive fixed” interest rate swaps outstanding with a total notional principal amount of $1,596 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.

Information about our interest rate swaps that had netting or rights of offset arrangements are as follows:


	Gross Amounts Presented in the Condensed Consolidated Balance Sheets		Amounts Not Offset in the Condensed Consolidated Balance Sheets		Net Amount		Gross Amounts Presented in the Condensed Consolidated Balance Sheets		Amounts Not Offset in the Condensed Consolidated Balance Sheets		Net Amount
Description	March 31, 2013						December 31, 2012
	(in millions)
Assets	$	46	$	5	$	41	$	61	$	7	$	54
Liabilities		9		5		4		12		7		5

As of March 31, 2013, we had an interest rate swap with a counterparty which was in a net liability position of $4 million which could be terminated at any time. In addition, we had an interest rate swap with another counterparty which was in a net liability position of $5 million which could be terminated by the counterparty if one of our credit ratings falls below investment grade.

Other than interest rate swaps described above, we did not have any significant derivatives outstanding during the three months ended March 31, 2013.

15. 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 $12 million as of March 31, 2013 and $13 million as of December 31, 2012. 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 March 31, 2013 or December 31, 2012 related to litigation.

Other Commitments and Contingencies

See Note 16 for a discussion of guarantees and indemnifications.

16. 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 our 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 March 31, 2013 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, 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, litigation and other matters, as well as breaches of representations, warranties and covenants. Typically, claims may be made by third parties for various periods of time depending on the nature of the claim. Our potential exposure under these indemnification agreements can range from a specified amount, such as the purchase price, to an unlimited dollar amount, depending on the nature of the claim and the particular transaction.

We are unable to estimate the total potential amount of future payments under these indemnification agreements due to several factors, such as the unlimited exposure under certain guarantees.

As of March 31, 2013, the amounts recorded for the guarantees and indemnifications described above are not material, both individually and in the aggregate.

17. 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 $5 million to our U.S. retirement plans in the three months ended March 31, 2013 and $6 million for the same period in 2012. We made total contributions to the Canadian plans of $23 million during the three months ended March 31, 2013 and $18 million for the same period in 2012. We anticipate that we will make total contributions of approximately $20 million to the U.S. plans and approximately $95 million to the Canadian plans in 2013.

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


	Three Months Ended March 31,
	2013			2012
	(in millions)
U.S.
Service cost benefit earned	$	5		$	3
Interest cost on projected benefit obligation		5			6
Expected return on plan assets		(8	)		(8	)
Amortization of loss		5			4

Net periodic pension cost	$	7		$	5

Canada
Service cost benefit earned	$	8		$	7
Interest cost on projected benefit obligation		13			13
Expected return on plan assets		(17	)		(15	)
Amortization of loss		9			9

Net periodic pension cost	$	13		$	14

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

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


	Three Months Ended March 31,
	2013			2012
	(in millions)
U.S.
Interest cost on accumulated post-retirement benefit obligation	$	2		$	3
Expected return on plan assets		(1	)		(1	)

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

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

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

Retirement/Savings Plan

We have employee savings plans available to both U.S. and Canadian employees. Employees may participate in a matching contribution where we match a certain percentage 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 during the three months ended March 31, 2013 and $4 million in the same period in 2012 for U.S. employees, and $3 million in both the three-month periods ended March 31, 2013 and 2012 for Canadian employees.

18. 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.

Certain amounts in the condensed consolidating statement of cash flows for the 2012 period, primarily cash flows related to intercompany receivables, payables and advances, have been reclassified to conform to the current period presentation.

Spectra Energy Corp

Condensed Consolidating Statements of Operations

(Unaudited)

(In millions)


	Spectra Energy Corp			Spectra Capital		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Three Months Ended March 31, 2013
Total operating revenues	$	—		$	—	$	1,590	$	(1	)	$	1,589
Total operating expenses		2			—		1,082		(1	)		1,083

Operating income (loss)		(2	)		—		508		—			506
Equity in earnings of unconsolidated affiliates		—			—		110		—			110
Equity in earnings of subsidiaries		337			509		—		(846	)		—
Other income and expenses, net		(2	)		3		32		—			33
Interest expense		—			48		101		—			149

Earnings before income taxes		333			464		549		(846	)		500
Income tax expense (benefit)		(7	)		127		10		—			130

Net income		340			337		539		(846	)		370
Net income—noncontrolling interests		—			—		30		—			30

Net income—controlling interests	$	340		$	337	$	509	$	(846	)	$	340


Three Months Ended March 31, 2012
Total operating revenues	$	—		$	—	$	1,545	$	(1	)	$	1,544
Total operating expenses		2			—		1,025		(1	)		1,026
Gains on sales of other assets and other, net		—			—		1		—			1

Operating income (loss)		(2	)		—		521		—			519
Equity in earnings of unconsolidated affiliates		—			—		118		—			118
Equity in earnings of subsidiaries		329			486		—		(815	)		—
Other income and expenses, net		(1	)		—		17		—			16
Interest expense		—			48		109		—			157

Earnings from continuing operations before income taxes		326			438		547		(815	)		496
Income tax expense (benefit) from continuing operations		(7	)		109		35		—			137

Income from continuing operations		333			329		512		(815	)		359
Income from discontinued operations, net of tax		—			—		2		—			2

Net income		333			329		514		(815	)		361
Net income—noncontrolling interests		—			—		28		—			28

Net income—controlling interests	$	333		$	329	$	486	$	(815	)	$	333

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 March 31, 2013
Net income	$	340	$	337	$	539		$	(846	)	$	370
Other comprehensive income (loss)		4		—		(176	)		—			(172	)

Total comprehensive income, net of tax		344		337		363			(846	)		198
Less: comprehensive income—noncontrolling interests		—		—		27			—			27

Comprehensive income—controlling interests	$	344	$	337	$	336		$	(846	)	$	171


Three Months Ended March 31, 2012
Net income	$	333	$	329	$	514		$	(815	)	$	361
Other comprehensive income		4		1		164			—			169

Total comprehensive income, net of tax		337		330		678			(815	)		530
Less: comprehensive income—noncontrolling interests		—		—		30			—			30

Comprehensive income—controlling interests	$	337	$	330	$	648		$	(815	)	$	500

Spectra Energy Corp

Condensed Consolidating Balance Sheet

March 31, 2013

(Unaudited)

(In millions)


	Spectra Energy Corp		Spectra Capital		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Cash and cash equivalents	$	—	$	2	$	186	$	—		$	188
Receivables—consolidated subsidiaries		157		—		—		(157	)		—
Receivables—other		1		56		1,062		—			1,119
Other current assets		13		17		399		—			429

Total current assets		171		75		1,647		(157	)		1,736
Investments in and loans to unconsolidated affiliates		—		70		2,731		—			2,801
Investments in consolidated subsidiaries		13,195		17,076		—		(30,271	)		—
Advances receivable—consolidated subsidiaries		—		5,503		—		(5,503	)		—
Notes receivable—consolidated subsidiaries		—		—		905		(905	)		—
Goodwill		—		—		4,887		—			4,887
Other assets		39		56		449		—			544
Property, plant and equipment, net		—		—		21,304		—			21,304
Regulatory assets and deferred debits		3		17		1,246		—			1,266

Total Assets	$	13,408	$	22,797	$	33,169	$	(36,836	)	$	32,538


Accounts payable—other	$	5	$	92	$	418	$	—		$	515
Accounts payable—consolidated subsidiaries		—		72		85		(157	)		—
Commercial paper		—		792		623		—			1,415
Short-term borrowings—consolidated subsidiaries		—		905		—		(905	)		—
Accrued taxes payable		9		—		80		—			89
Current maturities of long-term debt		—		398		349		—			747
Other current liabilities		41		92		864		—			997

Total current liabilities		55		2,351		2,419		(1,062	)		3,763
Long-term debt		—		4,240		8,040		—			12,280
Advances payable—consolidated subsidiaries		4,228		—		1,275		(5,503	)		—
Deferred credits and other liabilities		185		3,011		3,231		—			6,427
Preferred stock of subsidiaries		—		—		258		—			258
Equity
Controlling interests		8,940		13,195		17,076		(30,271	)		8,940
Noncontrolling interests		—		—		870		—			870

Total equity		8,940		13,195		17,946		(30,271	)		9,810

Total Liabilities and Equity	$	13,408	$	22,797	$	33,169	$	(36,836	)	$	32,538

Spectra Energy Corp

Condensed Consolidating Balance Sheet

December 31, 2012

(Unaudited)

(In millions)


	Spectra Energy Corp		Spectra Capital		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Cash and cash equivalents	$	—	$	3	$	91	$	—		$	94
Receivables—consolidated subsidiaries		164		—		—		(164	)		—
Receivables—other		1		56		913		—			970
Other current assets		17		23		559		—			599

Total current assets		182		82		1,563		(164	)		1,663
Investments in and loans to unconsolidated affiliates		—		70		2,622		—			2,692
Investments in consolidated subsidiaries		12,974		14,969		—		(27,943	)		—
Advances receivable—consolidated subsidiaries		—		5,658		—		(5,658	)		—
Notes receivable—consolidated subsidiaries		—		—		912		(912	)		—
Goodwill		—		—		4,513		—			4,513
Other assets		39		67		466		—			572
Property, plant and equipment, net		—		—		19,905		—			19,905
Regulatory assets and deferred debits		3		14		1,225		—			1,242

Total Assets	$	13,198	$	20,860	$	31,206	$	(34,677	)	$	30,587


Accounts payable—other	$	4	$	74	$	386	$	—		$	464
Accounts payable—consolidated subsidiaries		—		91		73		(164	)		—
Commercial paper		—		513		746		—			1,259
Short-term borrowings—consolidated subsidiaries		—		912		—		(912	)		—
Accrued taxes payable		10		—		57		—			67
Current maturities of long-term debt		—		744		177		—			921
Other current liabilities		61		106		913		—			1,080

Total current liabilities		75		2,440		2,352		(1,076	)		3,791
Long-term debt		—		2,550		8,103		—			10,653
Advances payable—consolidated subsidiaries		3,957		—		1,701		(5,658	)		—
Deferred credits and other liabilities		194		2,896		2,952		—			6,042
Preferred stock of subsidiaries		—		—		258		—			258
Equity
Controlling interests		8,972		12,974		14,969		(27,943	)		8,972
Noncontrolling interests		—		—		871		—			871

Total equity		8,972		12,974		15,840		(27,943	)		9,843

Total Liabilities and Equity	$	13,198	$	20,860	$	31,206	$	(34,677	)	$	30,587

Spectra Energy Corp

Condensed Consolidating Statement of Cash Flows

Three Months Ended March 31, 2013

(Unaudited)

(In millions)


	Spectra Energy Corp			Spectra Capital			Non-Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	340		$	337		$	539		$	(846	)	$	370
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		—			—			189			—			189
Equity in earnings of unconsolidated affiliates		—			—			(110	)		—			(110	)
Equity in earnings of consolidated subsidiaries		(337	)		(509	)		—			846			—
Distributions received from unconsolidated affiliates		—			—			79			—			79
Other		(79	)		138			(5	)		—			54

Net cash provided by (used in) operating activities		(76	)		(34	)		692			—			582

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		—			—			(426	)		—			(426	)
Investments in and loans to unconsolidated affiliates		—			—			(87	)		—			(87	)
Acquisitions, net of cash acquired		—			—			(1,254	)		—			(1,254	)
Purchases of held-to-maturity securities		—			—			(293	)		—			(293	)
Proceeds from sales and maturities of held-to-maturity securities		—			—			266			—			266
Purchases of available-for-sale securities		—			—			(612	)		—			(612	)
Proceeds from sales and maturities of available-for-sale securities		—			—			619			—			619
Distributions received from unconsolidated affiliates		—			—			6			—			6
Advances to affiliates		—			(289	)		—			289			—
Other changes in restricted funds		—			—			7			—			7

Net cash used in investing activities		—			(289	)		(1,774	)		289			(1,774	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt		—			1,848			—			—			1,848
Payments for the redemption of long-term debt		—			(495	)		—			—			(495	)
Net increase (decrease) in commercial paper		—			279			(113	)		—			166
Net decrease in short-term borrowings—consolidated subsidiaries		—			(7	)		—			7			—
Distributions to noncontrolling interests		—			—			(32	)		—			(32	)
Dividends paid on common stock		(205	)		—			(3	)		—			(208	)
Distributions and advances from (to) affiliates		270			(1,300	)		1,326			(296	)		—
Other		11			(3	)		—			—			8

Net cash provided by financing activities		76			322			1,178			(289	)		1,287

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

Net increase (decrease) in cash and cash equivalents		—			(1	)		95			—			94
Cash and cash equivalents at beginning of period		—			3			91			—			94

Cash and cash equivalents at end of period	$	—		$	2		$	186		$	—		$	188

Spectra Energy Corp

Condensed Consolidating Statements of Cash Flows

Three Months Ended March 31, 2012

(Unaudited)

(In millions)


	Spectra Energy Corp			Spectra Capital			Non-Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	333		$	329		$	514		$	(815	)	$	361
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		—			—			187			—			187
Equity in earnings of unconsolidated affiliates		—			—			(118	)		—			(118	)
Equity in earnings of consolidated subsidiaries		(329	)		(486	)		—			815			—
Distributions received from unconsolidated affiliates		—			—			114			—			114
Other		(55	)		94			(37	)		—			2

Net cash provided by (used in) operating activities		(51	)		(63	)		660			—			546

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		—			—			(343	)		—			(343	)
Acquisitions		—			—			(30	)		—			(30	)
Purchases of held-to-maturity securities		—			—			(861	)		—			(861	)
Proceeds from sales and maturities of held-to-maturity securities		—			—			734			—			734
Proceeds from sales and maturities of available-for-sale securities		—			—			14			—			14
Distributions received from unconsolidated affiliates		—			—			5			—			5
Advances to affiliates		—			(122	)		—			122			—
Other changes in restricted funds		—			—			79			—			79

Net cash used in investing activities		—			(122	)		(402	)		122			(402	)

CASH FLOWS FROM FINANCING ACTIVITIES
Net increase (decrease) in commercial paper		—			85			(111	)		—			(26	)
Distributions to noncontrolling interests		—			—			(27	)		—			(27	)
Dividends paid on common stock		(185	)		—			—			—			(185	)
Distributions and advances from (to) affiliates		213			100			(191	)		(122	)		—
Other		23			—			1			—			24

Net cash provided by (used in) financing activities		51			185			(328	)		(122	)		(214	)

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

Net decrease in cash and cash equivalents		—			—			(69	)		—			(69	)
Cash and cash equivalents at beginning of period		—			2			172			—			174

Cash and cash equivalents at end of period	$	—		$	2		$	103		$	—		$	105

19. New Accounting Pronouncements

There were no significant accounting pronouncements adopted during the three months ended March 31, 2013 that had a material impact on our consolidated results of operations, financial position or cash flows.

20. Subsequent Events

In April 2013, Spectra Energy Partners issued 5.2 million common units to the public, representing limited partner interests, and 0.1 million general partner units to Spectra Energy. Total net proceeds to Spectra Energy Partners were $193 million (net proceeds to Spectra Energy were $190 million) and are restricted for the purposes of funding Spectra Energy Partners’ capital expenditures and acquisitions.

On May 2, 2013, subsidiaries of Spectra Energy entered into definitive agreements with respect to Express-Platte, under which the subsidiaries will contribute a 40% interest in the U.S. portion of Express-Platte to Spectra Energy Partners and sell a 100% ownership interest in the Canadian portion to Spectra Energy Partners. Aggregate consideration for the transactions will be approximately $823 million, consisting of approximately $555 million in cash, $139 million in newly issued Spectra Energy Partners partnership units and $129 million of acquired Express-Platte debt. The transactions are expected to close in the third quarter of 2013, subject to regulatory approval and the satisfaction of customary closing conditions.

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

For the three months ended March 31, 2013 and 2012, we reported net income from controlling interests of $340 million and $333 million, respectively.

The highlights for the three months ended March 31, 2013 include the following:

•

U.S. Transmission experienced lower transportation and storage revenues and higher operating costs, substantially offset by higher earnings from expansion projects at Texas Eastern Transmission, LP (Texas Eastern),

•

Distribution’s earnings benefited from higher customer usage as a result of colder weather and an increase in 2013 rates, partially offset by lower transportation revenues,

•

Western Canada Transmission & Processing’s results reflected lower earnings in the conventional gathering and processing business, driven by anticipated lower contracted volumes and lower interruptible revenues, and lower earnings at Empress due primarily to lower propane sales prices,

•

Field Services earnings decreased mostly due to lower commodity prices and lower gathering and processing margins, partially offset by increased gains associated with the issuance of partnership units by DCP Partners and a reduction in depreciation expense attributable to an increase in the remaining useful lives of gathering, transmission, processing, storage and other assets during the second quarter of 2012, and

•

Liquid’s results primarily reflect the earnings of Express-Platte from the date of acquisition in March 2013.

On March 14, 2013, we closed our acquisition of Express-Platte. Express-Platte forms a significant part of our new reportable business segment, “Liquids,” which also includes our one-third ownership interests in Sand Hills and Southern Hills. See Notes 2 and 3 of Notes to Condensed Consolidated Financial Statements for further discussion.

In the first quarter of 2013, we had $505 million of capital and investment expenditures in addition to the acquisition of Express-Platte. Excluding the acquisition of Express-Platte, we currently project approximately $2.2 billion of capital and investment expenditures for the full year, including expansion capital expenditures of approximately $1.4 billion. Expansion projects for 2013 are on track.

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. We have access to approximately $1.5 billion available under our credit facilities as of March 31, 2013, to be utilized as needed for effective working capital management.

RESULTS OF OPERATIONS


	Three Months Ended March 31,
	2013		2012
	(in millions)
Operating revenues	$	1,589	$	1,544
Operating expenses		1,083		1,026
Gains on sales of other assets and other, net		—		1

Operating income		506		519
Other income and expenses		143		134
Interest expense		149		157

Earnings from continuing operations before income taxes		500		496
Income tax expense from continuing operations		130		137

Income from continuing operations		370		359
Income from discontinued operations, net of tax		—		2

Net income		370		361
Net income—noncontrolling interests		30		28

Net income—controlling interests	$	340	$	333

Operating Revenues. The $45 million, or 3%, increase was driven mainly by:

•

an increase in customer usage of natural gas largely due to weather that was 22% colder than in 2012, growth in the number of customers, an increase in 2013 rates as approved by the OEB and higher natural gas prices passed through to customers at Distribution, partially offset by

•

lower propane sales prices and lower sales volumes of residual natural gas and NGLs at the Empress NGL business and lower gathering and processing revenues due to anticipated lower contracted volumes and lower interruptible revenues at Western Canada Transmission & Processing, and

•

lower transportation revenues, primarily at Texas Eastern, and lower storage revenues, both at U.S. Transmission.

Operating Expenses. The $57 million, or 6%, increase was driven mainly by:

•

an increase in volumes of natural gas sold largely due to colder weather, growth in the number of customers and higher natural gas prices passed through to customers at Distribution, partially offset by

•

decreased volumes of natural gas purchases for extraction and lower input costs caused primarily by lower extraction premiums from the Empress operations at Western Canada Transmission & Processing.

Operating Income. The $13 million, or 3%, decrease was mostly attributable to lower earnings in the conventional gathering and processing business driven by anticipated lower contracted volumes and lower interruptible revenues, and lower NGL earnings primarily due to lower propane sales prices related to the Empress operations at Western Canada Transmission & Processing, and lower transportation and storage revenues at U.S. Transmission. These decreases in operating income were partially offset by an increase in customer usage of natural gas due to colder weather, an increase in 2013 rates at Distribution and the acquisition of Express-Platte in the first quarter of 2013.

Other Income and Expenses. The $9 million increase was attributable to higher allowance for funds used during construction (AFUDC) resulting from increased capital spending on expansion projects at U.S. Transmission, partially offset by lower equity earnings from Field Services. The lower equity earnings were mostly due to lower commodity prices and a decrease in gathering and processing margins, partially offset by an increase in gains associated with the issuance of partnership units by DCP Partners 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.

Interest Expense. The $8 million decrease was primarily due to increased capitalized interest resulting from our investments in Sand Hills and Southern Hills in the fourth quarter of 2012.

Income Tax Expense from Continuing Operations. The $7 million decrease was primarily a result of a lower Canadian effective tax rate. The effective tax rate for income from continuing operations was 26% in the first quarter of 2013 compared to 28% in the first quarter of 2012.

Net Income—Noncontrolling Interests. The $2 million increase was driven by the Spectra Energy Partners public sale of partner units and the transfer of a 38.76% interest in Maritimes & Northeast Pipeline, L.L.C. (M&N LLC) from Spectra Energy to Spectra Energy Partners, both in the fourth quarter of 2012.

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 March 31,
	2013			2012
	(in millions)
U.S. Transmission	$	266		$	271
Distribution		168			151
Western Canada Transmission & Processing		111			138
Field Services		88			93
Liquids		6			—

Total reportable segment EBIT		639			653
Other		(26	)		(29	)

Total reportable segment and other EBIT		613			624
Interest expense		149			157
Interest income and other (a)		36			29

Earnings from continuing operations before income taxes.	$	500		$	496

(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 March 31,
	2013		2012		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	484	$	495	$	(11	)
Operating expenses
Operating, maintenance and other		154		157		(3	)
Depreciation and amortization		72		70		2
Gains on sales of other assets and other, net		—		1		(1	)

Operating income		258		269		(11	)
Other income and expenses		41		31		10
Noncontrolling interests		33		29		4

EBIT	$	266	$	271	$	(5	)

Proportional throughput, TBtu (a)		838		763		75

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

Operating Revenues. The $11 million decrease was driven by:

•

an $11 million decrease from lower transportation revenues primarily at Texas Eastern and lower storage revenues, and

•

a $9 million decrease in recoveries of electric power and other costs passed through to customers, partially offset by

•

a $7 million increase from expansion projects, and

•

a $2 million increase in processing revenues associated with pipeline operations primarily due to higher volumes.

Operating, Maintenance and Other. The $3 million decrease was driven by:

•

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

•

a $5 million increase primarily due to higher employee benefit costs.

Depreciation and Amortization. The $2 million increase was mainly driven by expansion projects and capital expenditures.

Other Income and Expenses. The $10 million increase was primarily due to higher AFUDC resulting from increased capital spending on expansion projects.

Noncontrolling Interests. The $4 million increase was driven by the Spectra Energy Partners public sale of partner units and the transfer of a 38.76% interest in M&N LLC from Spectra Energy to Spectra Energy Partners, both in the fourth quarter of 2012.

EBIT. The $5 million decrease was driven by lower transportation and storage revenues and higher operating costs, substantially offset by higher earnings from expansions at Texas Eastern.

Distribution


	Three Months Ended March 31,
	2013		2012		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	699	$	597	$	102
Operating expenses
Natural gas purchased		369		286		83
Operating, maintenance and other		111		107		4
Depreciation and amortization		51		53		(2	)

EBIT	$	168	$	151	$	17

Number of customers, thousands		1,382		1,363		19
Heating degree days, Fahrenheit		3,525		2,893		632
Pipeline throughput, TBtu		314		267		47
Canadian dollar exchange rate, average		1.01		1.00		0.01

Operating Revenues. The $102 million increase was driven by:

•

a $75 million increase in customer usage of natural gas primarily due to weather that was 22% colder than the same period in 2012,

•

a $16 million increase from growth in the number of customers,

•

a $16 million increase from higher distribution rates in accordance with an OEB rate order effective January 1, 2013, and

•

a $12 million increase from higher 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, partially offset by

•

a $9 million decrease as a result of the sharing of revenues realized from the optimization of upstream transportation contracts in accordance with the OEB rate order effective January 1, 2013.

Natural Gas Purchased. The $83 million increase was driven by:

•

a $56 million increase due to higher volumes of natural gas sold primarily due to colder weather,

•

a $14 million increase from growth in the number of customers, and

•

a $12 million increase from higher natural gas prices passed through to customers.

Operating, Maintenance and Other. The $4 million increase was primarily driven by higher employee benefit costs.

EBIT. The $17 million increase was largely the result of higher customer usage due to colder weather and an increase in 2013 rates as approved by the OEB, partially offset by lower transportation revenues.

Western Canada Transmission & Processing


	Three Months Ended March 31,
	2013		2012		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	408	$	466	$	(58	)
Operating expenses
Natural gas and petroleum products purchased		111		161		(50	)
Operating, maintenance and other		143		131		12
Depreciation and amortization		52		47		5

Operating income		102		127		(25	)
Other income and expenses		9		11		(2	)

EBIT	$	111	$	138	$	(27	)

Pipeline throughput, TBtu		184		177		7
Volumes processed, TBtu		175		179		(4	)
Empress inlet volumes, TBtu		121		171		(50	)
Canadian dollar exchange rate, average		1.01		1.00		0.01

Operating Revenues. The $58 million decrease was driven by:

•

a $20 million decrease due to lower propane sales prices associated with the Empress NGL business,

•

a $17 million decrease due primarily to lower sales volumes of residual natural gas at the Empress operations,

•

a $16 million decrease in NGL sales volumes at Empress caused primarily by reduced customer demand for butane and normal butane, and

•

a $12 million decrease in gathering and processing revenues due primarily to anticipated lower contracted volumes and lower interruptible revenues, partially offset by

•

a $6 million increase in transmission revenues due primarily to expansion, and

•

a $3 million increase in carbon and other non-income tax expense from customers.

Natural Gas and Petroleum Products Purchased. The $50 million decrease was driven by:

•

a $21 million decrease in volumes of natural gas purchases for extraction at Empress,

•

a $20 million decrease as a result of lower input costs for the Empress facility caused primarily by lower extraction premiums, and

•

a $7 million decrease in volumes of make-up gas purchases at Empress primarily as a result of lower plant inlet volumes.

Operating, Maintenance and Other. The $12 million increase was driven by:

•

an $8 million increase due primarily to higher maintenance costs partially due to scheduling, and

•

a $3 million increase in carbon and other non-income tax expense.

Depreciation and Amortization. The $5 million increase was driven mainly by expansion projects placed in service and maintenance capital incurred.

Other Income and Expenses. The $2 million decrease was driven primarily by lower AFUDC resulting from decreased capital spending on expansion projects that are in progress.

EBIT. The $27 million decrease was driven mainly by lower earnings in the conventional gathering and processing business driven by anticipated lower contracted volumes and lower interruptible revenues, and lower earnings at the Empress NGL business due primarily to lower propane sales prices.

Matters Affecting Future Western Canada Transmission & Processing Results

Certain commodity prices, specifically NGLs, have fluctuated in 2012 and 2013, and are generally lower than prior year levels. Our Empress NGL business is significantly affected by fluctuations in commodity prices. We updated our Empress NGL reporting unit’s impairment test using recent operational information, financial data and April 1, 2013 commodity prices, and concluded there was no impairment of goodwill. The updated fair value of our Empress NGL reporting unit was substantially in excess of its carrying value as of April 1, 2013. Should NGL prices decline significantly from recent levels and further reduce earnings at the Empress NGL business, this could result in a triggering event that would warrant a re-testing of impairment for goodwill relating to the Empress NGL reporting unit, which could result in an impairment.

Field Services


	Three Months Ended March 31,
	2013		2012		Increase (Decrease)
	(in millions, except where noted)
Equity in earnings of unconsolidated affiliates	$	88	$	93	$	(5	)

EBIT	$	88	$	93	$	(5	)

Natural gas gathered and processed/transported, TBtu/d (a,b)		6.9		7.2		(0.3	)
NGL production, MBbl/d (a,c)		396		412		(16	)
Average natural gas price per MMBtu (d,e)	$	3.34	$	2.74	$	0.60
Average NGL price per gallon (f)	$	0.74	$	1.00	$	(0.26	)
Average crude oil price per barrel (g)	$	94.66	$	102.84	$	(8.18	)

(a)	Reflects 100% of volumes.

(b)	Trillion British thermal units per day.

(c)	Thousand barrels per day.

(d)	Average price based on NYMEX Henry Hub.

(e)	Million British thermal units.

(f)	Does not reflect results of commodity hedges.

(g)	Average price based on NYMEX calendar month.

EBIT. Lower equity earnings of $5 million were mainly the result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:

•

a $35 million decrease from commodity-sensitive processing arrangements due to decreased NGL and crude oil prices, net of increased natural gas prices,

•

a $12 million decrease in gathering and processing margins attributable to weather and third-party outages in 2013, lower recoveries and efficiencies, and unfavorable volumes in certain of DCP Midstream’s geographic regions due to volume decline, and

•

an $11 million decrease attributable to unfavorable results from gas and NGL marketing, partially offset by

•

a $22 million increase in gains associated with the issuance of partnership units by DCP Partners in 2013 compared to 2012,

•

a $20 million increase due 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 commodity reserves,

•

a $6 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 growth, and

•

a $5 million increase attributable to a decreased interest expense due to higher capitalized interest in 2013, and decreased income tax expense.

Liquids


	Three Months Ended March 31,
	2013			2012		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	13		$	—	$	13
Operating expenses
Operating, maintenance and other		5			—		5
Depreciation and amortization		1			—		1

Operating income		7			—		7
Other income and expenses		(1	)		—		(1	)

EBIT	$	6		$	—	$	6

Express pipeline receipts, MBbl/d		207			—		207
Platte total pipeline deliveries, MBbl/d		212			—		212
Platte PADD II deliveries, MBbl/d		167			—		167
Canadian dollar exchange rate, average		1.01			—		1.01

Express-Platte, acquired in March 2013, forms a significant part of the Liquids segment, along with our direct equity investments in Sand Hills and Southern Hills.

EBIT. The $6 million increase was primarily the earnings of Express-Platte from the date of acquisition.

Other


	Three Months Ended March 31,
	2013			2012			Increase (Decrease)
	(in millions)
Operating revenues	$	15		$	21		$	(6	)
Operating expenses		44			49			(5	)

Operating loss		(29	)		(28	)		(1	)
Other income and expenses		3			(1	)		4

EBIT	$	(26	)	$	(29	)	$	3

EBIT. The $3 million increase reflects lower corporate costs, including employee benefit costs.

LIQUIDITY AND CAPITAL RESOURCES

As of March 31, 2013, we had negative working capital of $2,027 million. This balance includes commercial paper totaling $1,415 million and current maturities of long-term debt of $747 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 $2,888 million, with $1,466 million available at March 31, 2013. 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 12 of Notes to Condensed Consolidated Financial Statements for a discussion of available credit facilities and Financing Cash Flows and Liquidity for a discussion of effective shelf registrations.

Operating Cash Flows

Net cash provided by operating activities increased $36 million to $582 million for the three months ended March 31, 2013 compared to the same period in 2012, driven mostly by higher deferred taxes in 2013, partially offset by lower distributions received from DCP Midstream.

Investing Cash Flows

Net cash used in investing activities increased $1,372 million to $1,774 million in the first three months of 2013 compared to the same period in 2012. This change was driven primarily by the acquisition of Express-Platte in 2013.


	Three Months Ended March 31,
	2013		2012
	(in millions)
Capital and Investment Expenditures
U.S. Transmission (a)	$	218	$	117
Distribution		37		38
Western Canada Transmission & Processing		165		174
Liquids (b)		75		—
Other		10		14

Total	$	505	$	343

(a)

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

(b)

Excludes the $1,254 million net cash outlay for the acquisition of Express-Platte in March 2013.

Capital and investment expenditures for the three months ended March 31, 2013 consisted of $413 million for expansion projects and $92 million for maintenance and other projects.

Excluding the acquisition of Express-Platte discussed below, we project 2013 capital and investment expenditures of approximately $2.2 billion, consisting of approximately $1.0 billion for U.S. Transmission, $0.4 billion for Distribution, $0.5 billion for Western Canada Transmission & Processing, $0.3 billion for Liquids. Total projected 2013 capital and investment expenditures include approximately $1.4 billion of expansion capital expenditures and $0.8 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.

On March 14, 2013, we acquired Express-Platte for $1.49 billion, consisting of $1.25 billion in cash and $239 million of acquired debt, before working capital adjustments. The acquisition was primarily funded through the issuance of stock and debt. See Note 2 of Notes to Condensed Consolidated Financial Statements for further discussion of the acquisition of Express-Platte.

Financing Cash Flows and Liquidity

Net cash provided by financing activities totaled $1,287 million in the first three months of 2013 compared to $214 million used in financing activities in the same period of 2012. This change was driven by:

•

a $1,353 million increase in net long-term debt issuances in 2013, primarily used to fund the acquisition of Express-Platte, and

•

a $166 million increase in the proceeds from commercial paper issued in 2013 compared to a $26 million decrease in 2012.

On February 28, 2013, Spectra Capital issued $650 million aggregate principal amount of 3.3% notes due in 2023. Net proceeds from the offering were used to refinance the $495 million of our 6.25% notes that matured on February 15, 2013, repay commercial paper, fund capital expenditures and for other general corporate purposes.

In the first quarter of 2013, Spectra Capital borrowed the full $1.2 billion available under an unsecured delayed-draw term loan agreement which allowed for up to four borrowings prior to March 1, 2013. These borrowings are due in 2015. Proceeds from the borrowings were used for general corporate purposes, including acquisitions and to refinance existing indebtedness.

Available Credit Facilities and Restrictive Debt Covenants. See Note 12 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 March 31, 2013, this ratio was 61%. Our equity and, as a result, this ratio, are sensitive to significant movements of the Canadian dollar relative to the U.S. dollar due to the significance of our Canadian operations. Based on the strength of our total capitalization as of March 31, 2013, it is unlikely that a material adverse effect would occur as a result of a weakened Canadian dollar.

Dividends. Our near-term objective is to increase our cash dividend by at least $0.08 per year through 2014. In the long-term, we anticipate paying dividends at an average payout level of approximately 65% of our net income from controlling interests per share of common stock. The actual payout level, 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. We declared a quarterly cash dividend of $0.305 per common share on April 29, 2013 payable on June 10, 2013 to shareholders of record at the close of business on May 10, 2013.

Other Financing Matters. Spectra Energy Corp and Spectra Capital have an effective shelf registration statement on file with the SEC to register the issuance of unspecified amounts of various equity and debt securities, and Spectra Energy Partners has an effective shelf registration statement on file with the SEC to register the issuance of unspecified amounts of limited partner common units and various debt securities. In addition, as of March 31, 2013, Westcoast and Union Gas have an aggregate 1.4 billion Canadian dollars (approximately $1.3 billion) available for the issuance of debt securities in the Canadian market under debt shelf prospectuses.

OTHER ISSUES

New Accounting Pronouncements. There were no significant accounting pronouncements adopted during the three months ended March 31, 2013 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, 2012. We believe our exposure to market risk has not changed materially since then.

Item 4.

Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

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

Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as of March 31, 2013, and, based upon this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended March 31, 2013 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 4 and 15 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, 2012, which could materially affect our financial condition or future results. Other than the risk factors below, there have been no material changes to those risk factors.

Reductions in demand for natural gas and oil, and low market prices of commodities adversely affect our operations and cash flows.

Our regulated businesses are generally economically stable and are not significantly affected in the short-term by changing commodity prices. However, all of our businesses can be negatively affected in the long term by sustained downturns in the economy or long-term conservation efforts, which could affect long-term demand and market prices for natural gas, oil and NGLs, all of which are beyond our control and could impair the ability to meet long-term goals.

Most of our revenues are based on regulated tariff rates, which include the recovery of certain fuel costs. However, lower overall economic output would cause a decline in the volume of natural gas transported and distributed or gathered and processed at our plants, and a decline in the volumes of oil transported, resulting in lower earnings and cash flows. This decline would primarily affect distribution revenues in the short term. Transmission revenues could be affected by long-term economic declines that result in the non-renewal of long-term contracts at the time of expiration. Lower demand for natural gas and oil, and lower prices for natural gas, oil and NGLs could result from multiple factors that affect the markets where we operate, including:

•

weather conditions, such as abnormally mild winter or summer weather that cause lower energy usage for heating or cooling purposes, respectively;

•

supply of and demand for energy commodities, including any decreases in the production of natural gas and oil which could negatively affect our processing and transmission businesses due to lower throughput;

•

capacity and transmission service into, or out of, our markets; and

•

petrochemical demand for NGLs.

The lack of availability of natural gas and oil resources may cause customers to seek alternative energy resources, which could materially affect our revenues, earnings and cash flows.

Our natural gas and oil businesses are dependent on the continued availability of natural gas and oil production and reserves. Prices for natural gas and oil, regulatory limitations on the development of natural gas and oil supplies, or a shift in supply sources could adversely affect development of additional reserves and production that are accessible by our pipeline, gathering, processing and distribution assets. Lack of commercial quantities of natural gas and oil available to these assets could cause customers to seek alternative energy resources, thereby reducing their reliance on our services, which in turn would materially affect our revenues, earnings and cash flows.

Gathering and processing, natural gas transmission and storage, crude oil transportation and storage, and gas distribution activities involve numerous risks that may result in accidents or otherwise affect our operations.

There are a variety of hazards and operating risks inherent in natural gas gathering and processing, transmission, storage, and distribution activities, and crude oil transportation and storage, such as leaks, explosions, mechanical problems, activities of third parties and damage to pipelines, facilities and equipment caused by hurricanes, tornadoes, floods, fires and other natural disasters, that could cause substantial financial losses. In addition, these risks could result in significant injury, loss of life, significant damage to property, environmental pollution and impairment of operations, any of which could result in substantial losses. For pipeline and storage assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damage resulting from these risks could be greater. We do not maintain insurance coverage against all of these risks and losses, and any insurance coverage we might maintain may not fully cover the damages caused by those risks and losses. Therefore, should any of these risks materialize, it could have a material effect on our business, earnings, financial condition and cash flows.

Item 6.

Exhibits.

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

•

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

•

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

•

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

•

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

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

(a) Exhibits


Exhibit Number

4.1		Sixteenth Supplement Indenture, dated as of February 28, 2013, between Spectra Energy Capital, LLC, Spectra Energy Corp and The Bank of New York Mellon Trust Company, N.A. (filed as Exhibit No. 4.1 to Form 8-K on February 28, 2013).

*+10.1		Form of Phantom Stock Award Agreement (2013) pursuant to the Spectra Energy Corp 2007 Long-Term Incentive Plan.

*+10.2		Form of Performance Award Agreement (cash) (2013) pursuant to the Spectra Energy Corp 2007 Long-Term Incentive Plan.

*+10.3		Form of Performance Award Agreement (stock) (2013) pursuant to the Spectra Energy Corp 2007 Long-Term Incentive Plan.

*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.

+	Denotes management contract or compensatory plan or arrangement.

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

SIGNATURES

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


						SPECTRA ENERGY CORP

Date: May 8, 2013						/s/ Gregory L. Ebel
						Gregory L. Ebel
						President and Chief Executive Officer

Date: May 8, 2013						/s/ J. Patrick Reddy
						J. Patrick Reddy
						Chief Financial Officer