SE-2015.06.30 10Q
Table of Contents


 
 
 
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549 
 
FORM 10-Q

ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2015
or 
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from              to             
Commission file number 1-33007 
 
SPECTRA ENERGY CORP
(Exact Name of Registrant as Specified in its Charter)
 
Delaware
 
20-5413139
(State or other jurisdiction of incorporation)
 
(IRS Employer Identification No.)
5400 Westheimer Court
Houston, Texas 77056
(Address of principal executive offices, including zip code)
713-627-5400
(Registrant’s telephone number, including area code)
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ý    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  ý    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 the Exchange Act.
Large accelerated filer  ý    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  ý
Number of shares of Common Stock, $0.001 par value, outstanding as of June 30, 2015: 671,363,087
 
 
 
 
 


Table of Contents


SPECTRA ENERGY CORP
FORM 10-Q FOR THE QUARTER ENDED
June 30, 2015
INDEX
 
 
 
Page
PART I. FINANCIAL INFORMATION
 
Item 1.
 
Condensed Consolidated Statements of Operations for the three and six months ended
     June 30, 2015 and 2014
 
Condensed Consolidated Statements of Comprehensive Income for the three and six months ended
     June 30, 2015 and 2014
 
Condensed Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014
 
Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2015 and 2014
 
Condensed Consolidated Statements of Equity for the six months ended June 30, 2015 and 2014
 
Item 2.
Item 3.
Item 4.
 
 
 
PART II. OTHER INFORMATION
 
Item 1.
Item 1A.
Item 6.
 


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Table of Contents



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, provincial, 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.


3

Table of Contents


PART I. FINANCIAL INFORMATION

Item 1.
Financial Statements.
SPECTRA ENERGY CORP
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In millions, except per-share amounts)
 
 
Three Months
Ended June 30,
 
Six Months
Ended June 30,
 
2015
 
2014
 
2015
 
2014
Operating Revenues
 
 
 
 
 
 
 
Transportation, storage and processing of natural gas
$
802

 
$
780

 
$
1,644

 
$
1,667

Distribution of natural gas
238

 
309

 
845

 
935

Sales of natural gas liquids
31

 
40

 
97

 
227

Transportation of crude oil
90

 
70

 
174

 
141

Other
31

 
54

 
55

 
126

Total operating revenues
1,192

 
1,253

 
2,815

 
3,096

Operating Expenses
 
 
 
 
 
 
 
Natural gas and petroleum products purchased
119

 
209

 
551

 
737

Operating, maintenance and other
389

 
405

 
743

 
768

Depreciation and amortization
193

 
199

 
386

 
399

Property and other taxes
85

 
102

 
188

 
215

Total operating expenses
786

 
915

 
1,868

 
2,119

Operating Income
406

 
338

 
947

 
977

Other Income and Expenses
 
 
 
 
 
 
 
Earnings (loss) from equity investments
(189
)
 
85

 
(165
)
 
246

Other income and expenses, net
22

 
6

 
42

 
15

Total other income and expenses
(167
)
 
91

 
(123
)
 
261

Interest Expense
166

 
176

 
325

 
354

Earnings Before Income Taxes
73

 
253

 
499

 
884

Income Tax Expense (Benefit)
(7
)
 
65

 
94

 
229

Net Income
80

 
188

 
405

 
655

Net Income—Noncontrolling Interests
62

 
42

 
120

 
90

Net Income—Controlling Interests
$
18

 
$
146

 
$
285

 
$
565

Common Stock Data
 
 
 
 
 
 
 
Weighted-average shares outstanding
 
 
 
 
 
 
 
Basic
671

 
671

 
671

 
671

Diluted
672

 
673

 
672

 
672

Earnings per share
 
 
 
 
 
 
 
Basic and diluted
$
0.03

 
$
0.22

 
$
0.42

 
$
0.84

Dividends per share
$
0.37

 
$
0.335

 
$
0.74

 
$
0.67










See Notes to Condensed Consolidated Financial Statements.

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Table of Contents


SPECTRA ENERGY CORP
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
(In millions)
 
 
Three Months
Ended June 30,
 
Six Months
Ended June 30,
 
2015
 
2014
 
2015
 
2014
Net Income
$
80

 
$
188

 
$
405

 
$
655

Other comprehensive income (loss):
 
 
 
 
 
 
 
Foreign currency translation adjustments
87

 
223

 
(405
)
 
(25
)
Non-cash mark-to-market net gain on hedges

 
1

 

 
3

Reclassification of cash flow hedges into earnings

 
1

 

 
3

Pension and benefits impact (net of taxes of $2, $3, $5 and $6, respectively)
7

 
6

 
13

 
13

Other
(1
)
 

 

 

Total other comprehensive income (loss)
93

 
231

 
(392
)
 
(6
)
Total Comprehensive Income, net of tax
173

 
419

 
13

 
649

Less: Comprehensive Income—Noncontrolling Interests
64

 
45

 
114

 
89

Comprehensive Income (Loss)—Controlling Interests
$
109

 
$
374

 
$
(101
)
 
$
560













































See Notes to Condensed Consolidated Financial Statements.

5

Table of Contents


SPECTRA ENERGY CORP
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)
 
 
June 30,
2015
 
December 31,
2014
ASSETS
 
 
 
 
 
 
 
Current Assets
 
 
 
Cash and cash equivalents
$
287

 
$
215

Receivables, net
880

 
1,336

Inventory
248

 
313

Fuel tracker
57

 
102

Other
265

 
366

Total current assets
1,737

 
2,332

 
 
 
 
Investments and Other Assets
 
 
 
Investments in and loans to unconsolidated affiliates
2,701

 
2,966

Goodwill
4,615

 
4,714

Other
307

 
327

Total investments and other assets
7,623

 
8,007

 
 
 
 
Property, Plant and Equipment
 
 
 
Cost
29,250

 
29,211

Less accumulated depreciation and amortization
6,969

 
6,904

Net property, plant and equipment
22,281

 
22,307

 
 
 
 
Regulatory Assets and Deferred Debits
1,403

 
1,394

 
 
 
 
Total Assets
$
33,044

 
$
34,040


































See Notes to Condensed Consolidated Financial Statements.

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Table of Contents


SPECTRA ENERGY CORP
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions, except per-share amounts)
 
 
June 30,
2015
 
December 31,
2014
LIABILITIES AND EQUITY
 
 
 
 
 
 
 
Current Liabilities
 
 
 
Accounts payable
$
557

 
$
458

Commercial paper
535

 
1,583

Taxes accrued
108

 
91

Interest accrued
188

 
181

Current maturities of long-term debt
917

 
327

Other
832

 
1,169

Total current liabilities
3,137

 
3,809

 
 
 
 
Long-term Debt
12,783

 
12,769

 
 
 
 
Deferred Credits and Other Liabilities
 
 
 
Deferred income taxes
5,459

 
5,405

Regulatory and other
1,328

 
1,401

Total deferred credits and other liabilities
6,787

 
6,806

 
 
 
 
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, 671 million shares outstanding at June 30, 2015 and December 31, 2014
1

 
1

Additional paid-in capital
4,990

 
4,956

Retained earnings
2,329

 
2,541

Accumulated other comprehensive income
276

 
662

Total controlling interests
7,596

 
8,160

Noncontrolling interests
2,483

 
2,238

Total equity
10,079

 
10,398

 
 
 
 
Total Liabilities and Equity
$
33,044

 
$
34,040












See Notes to Condensed Consolidated Financial Statements.

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Table of Contents


SPECTRA ENERGY CORP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In millions)
 
 
Six Months
Ended June 30,
 
2015
 
2014
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net income
$
405

 
$
655

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization
393

 
405

Deferred income tax expense
25

 
224

(Earnings) loss from equity investments
165

 
(246
)
Distributions received from unconsolidated affiliates
93

 
199

Other
375

 
(28
)
Net cash provided by operating activities
1,456

 
1,209

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Capital expenditures
(989
)
 
(833
)
Investments in and loans to unconsolidated affiliates
(34
)
 
(30
)
Purchases of held-to-maturity securities
(329
)
 
(437
)
Proceeds from sales and maturities of held-to-maturity securities
344

 
453

Purchases of available-for-sale securities

 
(13
)
Proceeds from sales and maturities of available-for-sale securities
1

 
7

Distributions received from unconsolidated affiliates
35

 
242

Other changes in restricted funds
(6
)
 
(1
)
Other
2

 

Net cash used in investing activities
(976
)
 
(612
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Proceeds from the issuance of long-term debt
994

 
712

Payments for the redemption of long-term debt
(39
)
 
(736
)
Net decrease in commercial paper
(1,030
)
 
(256
)
Distributions to noncontrolling interests
(93
)
 
(81
)
Contributions from noncontrolling interests
90

 
112

Proceeds from the issuances of Spectra Energy Partners, LP common units
180

 
191

Dividends paid on common stock
(499
)
 
(453
)
Other
(9
)
 
12

Net cash used in financing activities
(406
)
 
(499
)
Effect of exchange rate changes on cash
(2
)
 
1

Net increase in cash and cash equivalents
72

 
99

Cash and cash equivalents at beginning of period
215

 
201

Cash and cash equivalents at end of period
$
287

 
$
300

Supplemental Disclosures
 
 
 
Property, plant and equipment non-cash accruals
$
197

 
$
118









See Notes to Condensed Consolidated Financial Statements.

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Table of Contents


SPECTRA ENERGY CORP
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(Unaudited)
(In millions)
 
 
Common
Stock
 
Additional
Paid-in
Capital
 
Retained
Earnings
 
Accumulated Other
Comprehensive Income
 
 
 
 
Foreign
Currency
Translation
Adjustments
 
Other
 
Noncontrolling
Interests
 
Total
December 31, 2014
$
1

 
$
4,956

 
$
2,541

 
$
1,016

 
$
(354
)
 
$
2,238

 
$
10,398

Net income

 

 
285

 

 

 
120

 
405

Other comprehensive income (loss)

 

 

 
(399
)
 
13

 
(6
)
 
(392
)
Dividends on common stock

 

 
(498
)
 

 

 

 
(498
)
Stock-based compensation

 
6

 

 

 

 

 
6

Distributions to noncontrolling interests

 

 

 

 

 
(93
)
 
(93
)
Contributions from noncontrolling interests

 

 

 

 

 
90

 
90

Spectra Energy common stock issued

 
1

 

 

 

 

 
1

Spectra Energy Partners, LP common units issued

 
25

 

 

 

 
139

 
164

Other, net

 
2

 
1

 

 

 
(5
)
 
(2
)
June 30, 2015
$
1

 
$
4,990

 
$
2,329

 
$
617

 
$
(341
)
 
$
2,483

 
$
10,079

 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2013
$
1

 
$
4,869

 
$
2,383

 
$
1,557

 
$
(316
)
 
$
1,829

 
$
10,323

Net income

 

 
565

 

 

 
90

 
655

Other comprehensive income (loss)

 

 

 
(24
)
 
19

 
(1
)
 
(6
)
Dividends on common stock

 

 
(451
)
 

 

 

 
(451
)
Stock-based compensation

 
6

 

 

 

 

 
6

Distributions to noncontrolling interests

 

 

 

 

 
(81
)
 
(81
)
Contributions from noncontrolling interests

 

 

 

 

 
112

 
112

Spectra Energy common stock issued

 
9

 

 

 

 

 
9

Spectra Energy Partners, LP common units issued

 
29

 

 

 

 
144

 
173

Transfer of interests in subsidiaries to Spectra Energy Partners, LP

 

 

 

 

 
1

 
1

Other, net

 
5

 

 

 

 
(1
)
 
4

June 30, 2014
$
1

 
$
4,918

 
$
2,497

 
$
1,533

 
$
(297
)
 
$
2,093

 
$
10,745


























See Notes to Condensed Consolidated Financial Statements.

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Table of Contents


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. The term “Spectra Energy Partners” refers to our Spectra Energy Partners operating segment. The term “SEP” refers to Spectra Energy Partners, LP, our master limited partnership.

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, and owns and operates a crude oil pipeline system that connects Canadian and U.S. producers to refineries in the U.S. Rocky Mountain and Midwest regions. We currently operate in three key areas of the natural gas industry: gathering and processing, transmission and storage, and distribution. We provide transmission and storage of natural gas to customers in various regions of the northeastern and southeastern United States, the Maritime Provinces in Canada, 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).

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, 2014, and reflect all normal recurring adjustments that are, in our opinion, necessary to fairly present our results of operations and financial position. Amounts reported in the Condensed Consolidated Statements of Operations are not necessarily indicative of amounts expected for the respective annual periods due to the effects of seasonal temperature variations on energy consumption, primarily in our gas distribution operations, as well as changing commodity prices on certain of our processing operations and other factors.

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

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

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

Spectra Energy's presentation of its Spectra Energy Partners segment is reflective of the parent-level focus by our CODM, considering the resource allocation and governance provisions associated with SEP’s master limited partnership structure. SEP maintains a capital and cash management structure that is separate from Spectra Energy’s, is self-funding and maintains its own lines of bank credit and cash management accounts. From a Spectra Energy perspective, our CODM evaluates the Spectra Energy Partners segment as a whole, without regard to any of SEP’s individual businesses.

Spectra Energy Partners provides transmission, storage and gathering of natural gas, as well as the transportation of crude oil and NGLs through interstate pipeline systems for customers in various regions of the midwestern, northeastern and southern U.S. and Canada. The natural gas transmission and storage operations are primarily subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC). The crude oil transportation operations are primarily subject to regulation by the FERC in the U.S. and the National Energy Board (NEB) in Canada. Our Spectra Energy Partners segment is composed of the operations of SEP, less governance costs, which are included in “Other.”


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Table of Contents


Distribution provides retail natural gas distribution service in Ontario, Canada, as well as natural gas transmission 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 transmission of natural gas, natural gas gathering and processing services, and NGL extraction, fractionation, transportation, storage and marketing to customers in western Canada, the northern tier of the U.S. and the Maritime Provinces in Canada. This segment conducts business mostly through BC Pipeline, BC Field Services, and the NGL marketing and Canadian Midstream businesses, and Maritimes & Northeast Pipeline Limited Partnership (M&N Canada). BC Pipeline and BC Field Services and M&N Canada operations are primarily subject to the rules and regulations of the NEB.

Field Services gathers, compresses, treats, processes, transports, stores and sells natural gas, produces, fractionates, transports, stores and sells NGLs, recovers and sells condensate, and trades and markets natural gas and NGLs. It conducts operations through DCP Midstream, which is owned 50% by us and 50% by Phillips 66. DCP Midstream gathers raw natural gas through gathering systems connecting to several interstate and intrastate natural gas and NGL pipeline systems, one natural gas storage facility and one NGL storage facility. DCP Midstream operates in a diverse number of regions, including the Permian Basin, Eagle Ford, Niobrara/DJ Basin and the Midcontinent. DCP Midstream Partners, LP (DCP Partners) is a publicly traded master limited partnership, of which DCP Midstream acts as general partner. As of June 30, 2015, DCP Midstream had an approximate 21% ownership interest in DCP Partners, including DCP Midstream’s limited partner and general partner interests.

Our reportable segments offer different products and services and are managed separately as business units. Management evaluates segment performance based on earnings from continuing operations before interest, taxes, and depreciation and amortization (EBITDA). Cash, cash equivalents and short-term investments are managed at the parent-company levels, so the associated gains and losses from foreign currency transactions and interest and dividend income are excluded from the segments’ EBITDA. Our segment EBITDA may not be comparable to similarly titled measures of other companies because other companies may not calculate EBITDA in the same manner. Transactions between reportable segments are accounted for on the same basis as transactions with unaffiliated third parties.

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Table of Contents


Business Segment Data
Condensed Consolidated Statements of Operations
 
Unaffiliated
Revenues
 
Intersegment
Revenues
 
Total
Operating
Revenues
 
Depreciation and Amortization
 
Segment EBITDA/
Consolidated
Earnings before
Income Taxes
 
(in millions)
Three Months Ended June 30, 2015
 
 
 
 
 
 
 
 
 
Spectra Energy Partners
$
603

 
$

 
$
603

 
$
72

 
$
478

Distribution
290

 

 
290

 
45

 
98

Western Canada Transmission & Processing
297

 
7

 
304

 
63

 
104

Field Services

 

 

 

 
(233
)
Total reportable segments
1,190

 
7

 
1,197

 
180

 
447

Other
2

 
15

 
17

 
13

 
(12
)
Eliminations

 
(22
)
 
(22
)
 

 

Depreciation and amortization

 

 

 

 
193

Interest expense

 

 

 

 
166

Interest income and other (a)

 

 

 

 
(3
)
Total consolidated
$
1,192

 
$

 
$
1,192

 
$
193

 
$
73

 
 
 
 
 
 
 
 
 
 
Three Months Ended June 30, 2014
 
 
 
 
 
 
 
 
 
Spectra Energy Partners
$
531

 
$

 
$
531

 
$
72

 
$
374

Distribution
360

 

 
360

 
48

 
112

Western Canada Transmission & Processing
360

 
31

 
391

 
68

 
111

Field Services

 

 

 

 
54

Total reportable segments
1,251

 
31

 
1,282

 
188

 
651

Other
2

 
17

 
19

 
11

 
(24
)
Eliminations

 
(48
)
 
(48
)
 

 

Depreciation and amortization

 

 

 

 
199

Interest expense

 

 

 

 
176

Interest income and other (a)

 

 

 

 
1

Total consolidated
$
1,253

 
$

 
$
1,253

 
$
199

 
$
253

 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2015
 
 
 
 
 
 
 
 
 
Spectra Energy Partners
$
1,209

 
$

 
$
1,209

 
$
146

 
$
933

Distribution
952

 

 
952

 
90

 
290

Western Canada Transmission & Processing
650

 
24

 
674

 
125

 
265

Field Services

 

 

 

 
(250
)
Total reportable segments
2,811

 
24

 
2,835

 
361

 
1,238

Other
4

 
31

 
35

 
25

 
(27
)
Eliminations

 
(55
)
 
(55
)
 

 

Depreciation and amortization

 

 

 

 
386

Interest expense

 

 

 

 
325

Interest income and other (a)

 

 

 

 
(1
)
Total consolidated
$
2,815

 
$

 
$
2,815

 
$
386

 
$
499

 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2014
 
 
 
 
 
 
 
 
 
Spectra Energy Partners
$
1,112

 
$

 
$
1,112

 
$
145

 
$
803

Distribution
1,078

 

 
1,078

 
97

 
338

Western Canada Transmission & Processing
901

 
65

 
966

 
135

 
348

Field Services

 

 

 

 
184

Total reportable segments
3,091

 
65

 
3,156

 
377

 
1,673

Other
5

 
32

 
37

 
22

 
(41
)
Eliminations

 
(97
)
 
(97
)
 

 

Depreciation and amortization

 

 

 

 
399

Interest expense

 

 

 

 
354

Interest income and other (a)

 

 

 

 
5

Total consolidated
$
3,096

 
$

 
$
3,096

 
$
399

 
$
884

___________________________________
(a)
Includes foreign currency transaction gains and losses related to segment EBITDA.

12

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3. Regulatory Matters

Union Gas. In 2012, the OEB determined that revenues derived from the optimization of Union Gas’ upstream transportation contracts in 2011 would be treated as a reduction to gas costs rather than being treated as optimization revenues and included in utility earnings. In May 2014, Union Gas filed a notice of appeal to the Ontario Court of Appeal and a hearing was held in December 2014. The appeal was dismissed in June 2015 and no further appeals will be filed.

In December 2014, Union Gas filed an application with the OEB for the disposition of the 2013 energy conservation deferral and variance account balances. As a result of this application, Union Gas has a receivable from customers of approximately $8 million and $9 million at June 30, 2015 and December 31, 2014, respectively, which is reflected as Current AssetsOther on the Condensed Consolidated Balance Sheets. A written hearing concluded in April 2015. In June 2015, a decision from the OEB was received approving recovery from ratepayers effective July 1, 2015.

In April 2015, the OEB issued its decision on Union Gas’ application for an order approving an interruptible liquefied natural gas (LNG) service. The OEB determined that it would not regulate this service, as it was satisfied that there is LNG competition sufficient to protect the public interest and approved the proposed cross charges between the regulated and unregulated services until an application for new rates in 2019 is filed. At this time, Union Gas does not expect any material financial impact as a result of this decision.
4. Income Taxes

Income tax benefit was $7 million for the three months ended June 30, 2015, compared to an income tax expense of $65 million for the same period in 2014. Income tax expense was $94 million for the six months ended June 30, 2015, compared to $229 million for the same period in 2014. The lower tax expense for both periods was primarily due to the $72 million tax impact of the impairment of goodwill at DCP Midstream, lower earnings and the effect of a weaker Canadian dollar.

The effective income tax rate was negative 10% for the three months ended June 30, 2015, compared to 26% for the same period in 2014. The effective income tax rate was 19% for the six months ended June 30, 2015, compared to 26% for the same period in 2014. The lower effective income tax rates in both periods were primarily attributable to the $72 million tax impact of the impairment of goodwill at DCP Midstream.

There was a $6 million increase in unrecognized tax benefits recorded during the six months ended June 30, 2015. Although uncertain, we believe it is reasonably possible that the total amount of unrecognized tax benefits could decrease by approximately $25 million to $30 million prior to June 30, 2016, as a result of the expiration of statutes of limitations and expected audit settlements.
5. Earnings per Common Share

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

The following table presents our basic and diluted EPS calculations:
 
 
 
Three Months
Ended June 30,
 
Six Months
Ended June 30,
 
 
 
2015
 
2014
 
2015
 
2014
 
 
 
(in millions, except per-share amounts)
Net income—controlling interests
$
18

 
$
146

 
$
285

 
$
565

Weighted-average common shares outstanding
 
 
 
 

 
 
Basic
671

 
671

 
671

 
671

Diluted
672

 
673

 
672

 
672

Basic and diluted earnings per common share (a)
$
0.03

 
$
0.22

 
$
0.42

 
$
0.84

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

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6. Accumulated Other Comprehensive Income

The following table presents the net of tax changes in Accumulated Other Comprehensive Income (AOCI) by component and amounts reclassified out of AOCI to Net Income, excluding amounts attributable to noncontrolling interests:
 
Foreign Currency Translation Adjustments
 
Pension
and Post-retirement Benefit Plan Obligations
 
Gas Purchase Contract Hedges
 
Other
 
Total Accumulated Other Comprehensive Income
 
 
 
 
(in millions)
 
 
 
March 31, 2015
$
532


$
(345
)

$


$
(2
)

$
185

Other AOCI activity
85


7




(1
)

91

June 30, 2015
$
617

 
$
(338
)
 
$

 
$
(3
)
 
$
276

 
 
 
 
 
 
 
 
 
 
March 31, 2014
$
1,313

 
$
(297
)
 
$
(7
)
 
$
(1
)
 
$
1,008

Reclassified to net income

 

 

 
1

 
1

Other AOCI activity
220

 
6

 
1

 

 
227

June 30, 2014
$
1,533

 
$
(291
)
 
$
(6
)
 
$

 
$
1,236

 
 
 
 
 
 
 
 
 
 
December 31, 2014
$
1,016

 
$
(351
)
 
$
(3
)
 
$

 
$
662

Other AOCI activity
(399
)
 
13

 
3

 
(3
)
 
(386
)
June 30, 2015
$
617


$
(338
)
 
$


$
(3
)
 
$
276

 
 
 
 
 
 
 
 
 
 
December 31, 2013
$
1,557

 
$
(304
)
 
$
(11
)
 
$
(1
)
 
$
1,241

Reclassified to net income

 

 
2

 
1

 
3

Other AOCI activity
(24
)
 
13

 
3

 

 
(8
)
June 30, 2014
$
1,533

 
$
(291
)
 
$
(6
)
 
$

 
$
1,236


Reclassifications to Net Income are primarily included in Other Income and Expenses, Net on our Condensed Consolidated Statements of Operations.
7. Inventory

Inventory consists of natural gas and NGLs held in storage for transmission and processing, and also includes materials and supplies. Natural gas inventories primarily relate to the Distribution segment in Canada and are valued at costs approved by the OEB. The difference between the approved price and the actual cost of gas purchased is recorded as either a receivable or a current liability, 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:
 
June 30,
2015
 
December 31,
2014
 
(in millions)
Natural gas
$
134

 
$
211

NGLs
42

 
28

Materials and supplies
72

 
74

Total inventory
$
248

 
$
313


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8. Investments in and Loans to Unconsolidated Affiliates

Our most significant investment in unconsolidated affiliates is our 50% investment in DCP Midstream, which is accounted for under the equity method of accounting. The following represents summary financial information for DCP Midstream, presented at 100%:
 
Three Months
Ended June 30,
 
Six Months
Ended June 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions)
Operating revenues
$
1,869

 
$
3,541

 
$
3,912

 
$
7,456

Operating expenses
2,332

 
3,387

 
4,323

 
7,032

Operating income (loss)
(463
)
 
154

 
(411
)
 
424

Net income (loss)
(491
)
 
92

 
(497
)
 
295

Net income (loss) attributable to members’ interests
(466
)
 
89

 
(503
)
 
254


DCP Partners issues, from time to time, limited partner units to the public, which are recorded by DCP Midstream directly to its equity. Our proportionate share of gains from those issuances, totaling $9 million in the second quarter of 2014, and $2 million and $57 million during the six month periods ending June 30, 2015 and 2014, respectively, are reflected in Earnings (Loss) From Equity Investments in the Condensed Consolidated Statements of Operations.

Due to the significant downturn in commodity prices over the past three quarters, including further deterioration in the second quarter of 2015, DCP Midstream determined it was more likely than not that the estimated fair values of certain of its goodwill reporting units and certain of DCP Partners goodwill reporting units were below their carrying amount, and performed a goodwill impairment test. The impairment test was based on an internal discounted cash flow model taking into account various observable and non-observable factors, such as prices, volumes, expenses and discount rate. The impairment test resulted in DCP Midstream’s recognition of a $427 million goodwill impairment during the second quarter of 2015, which reduced our equity earnings from DCP Midstream by $122 million after-tax. This impairment represents DCP Midstream’s best estimate pending finalization of the fair value assessments.

Due to the impairment of goodwill recognized by DCP Midstream, we assessed our equity investment in DCP Midstream and determined that no indicators of impairment were noted.

9. Goodwill

We perform our goodwill impairment test annually and evaluate goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. We completed our annual goodwill impairment test as of April 1, 2015 and no impairments were identified.
    
We perform our annual review for goodwill impairment at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete financial information is available, whether segment management regularly reviews the operating results of those components and whether the economic and regulatory characteristics are similar. We determined that our reporting units are equivalent to our reportable segments, except for the reporting units of our Western Canada Transmission & Processing and Spectra Energy Partners reportable segments, which are one level below.
    
As permitted under accounting guidance on testing goodwill for impairment, we perform either a qualitative assessment or a quantitative assessment of each of our reporting units based on management’s judgment. With respect to our qualitative assessments, we consider events and circumstances specific to us, such as macroeconomic conditions, industry and market considerations, cost factors and overall financial performance, when evaluating whether it is more likely than not that the fair values of our reporting units are less than their respective carrying amounts.

Our Empress NGL and BC Field Services businesses, reporting units within Western Canada Transmission & Processing, are affected by commodity prices. We performed our Empress NGL and BC Field Services reporting units’ impairment tests using updated assumptions and financial data and concluded that there was no impairment of goodwill for either business unit.

See Note 8 for discussion related to the impairment of goodwill recognized by DCP Midstream.

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10. Marketable Securities and Restricted Funds

We routinely invest excess cash and various restricted balances in securities such as commercial paper, banker’s acceptances, corporate debt securities, treasury bills and money market funds in the U.S. and Canada. We do not purchase marketable securities for speculative purposes; therefore we do not have any securities classified as trading securities. While we do not routinely sell marketable securities prior to their scheduled maturity dates, some of our investments may be held and restricted for insurance purposes, so these investments are classified as available-for-sale (AFS) marketable securities as they may occasionally be sold prior to their scheduled maturity dates due to the unexpected timing of 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
 
June 30,
2015
 
December 31, 2014
 
(in millions)
Corporate debt securities
$
22

 
$
23

Money market funds

 
1

Total available-for-sale securities
$
22

 
$
24


Our AFS securities are classified on the Condensed Consolidated Balance Sheets as follows:
 
 
Estimated Fair Value
 
 
June 30,
2015
 
December 31, 2014
 
 
(in millions)
Restricted funds
 
 
 
Investments and other assets—other
$

 
$
1

Non-restricted funds
 
 
 
Current assets—other
2

 
3

Investments and other assets—other
20

 
20

Total available-for-sale securities
$
22

 
$
24


At June 30, 2015, 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 June 30, 2015 or December 31, 2014.

HTM Securities. All of our HTM securities are restricted funds and are as follows:
 
 
Estimated Fair Value
Description
Condensed Consolidated Balance Sheets Caption
June 30, 2015
 
December 31, 2014
 
 
(in millions)
Banker’s acceptances
Current assets—other
$
34

 
$
38

Canadian government securities
Current assets—other
27

 
30

Money market funds
Current assets—other
3

 
3

Canadian government securities
Investments and other assets—other
81

 
101

Total held-to-maturity securities
$
145

 
$
172


All of our HTM securities are restricted funds pursuant to certain M&N Canada and Express-Platte (our crude oil pipeline system) debt agreements. The funds restricted for M&N Canada, plus future cash from operations that would otherwise be available for distribution to the partners of M&N Canada, are required to be placed in escrow until the balance in escrow is sufficient to fund all future debt service on the M&N Canada 6.90% senior secured notes. There are sufficient funds held in escrow to fund all future debt service on these M&N Canada notes as of June 30, 2015.

At June 30, 2015, the weighted-average contractual maturity of outstanding HTM securities was less than one year.

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There were no material gross unrecognized holding gains or losses associated with investments in HTM securities at June 30, 2015 or December 31, 2014.

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 $13 million at June 30, 2015 and $13 million at December 31, 2014 classified as Current Assets—Other. These restricted funds are related to additional amounts for insurance. We also had other restricted funds totaling $12 million at June 30, 2015 and $6 million at December 31, 2014 classified as Investments and Other Assets—Other. These restricted funds are related to funds held and collected from customers for Canadian pipeline abandonment in accordance with the NEB’s regulatory requirements.

Changes in restricted balances are presented within Cash Flows from Investing Activities on our Condensed Consolidated Statements of Cash Flows.
11. Debt and Credit Facilities
Available Credit Facilities and Restrictive Debt Covenants  
 
Expiration
Date
 
Total
Credit
Facilities
Capacity
 
Commercial Paper Outstanding at June 30, 2015
 
Available
Credit
Facilities
Capacity
 
 
 
 
(in millions)
Spectra Energy Capital, LLC (a)
2019
 
$
1,000

 
$
497

 
$
503

SEP (b)
2019
 
2,000

 
38

 
1,962

Westcoast Energy Inc. (c)
2019
 
320

 

 
320

Union Gas (d)
2019
 
400

 

 
400

Total
 
 
$
3,720

 
$
535

 
$
3,185

 ___________
(a)
Revolving 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%. Per the terms of the agreement, collateralized debt is excluded from the calculation of the ratio. This ratio was 58% at June 30, 2015.
(b)
Revolving credit facility contains a covenant that requires SEP to maintain a ratio of total Consolidated Indebtedness-to-Consolidated EBITDA, as defined in the credit agreement, of 5.0 to 1 or less. As of June 30, 2015, this ratio was 3.5 to 1.
(c)
U.S. dollar equivalent at June 30, 2015. The revolving credit facility is 400 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 33% at June 30, 2015.
(d)
U.S. dollar equivalent at June 30, 2015. The revolving credit facility is 500 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 64% at June 30, 2015.

The issuances of commercial paper, letters of credit and revolving borrowings reduce the amount available under the credit facilities. As of June 30, 2015, there were no letters of credit issued or revolving borrowings outstanding under the credit facilities.

Our credit agreements contain various covenants, including the maintenance of certain financial ratios. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of June 30, 2015, 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.
Debt Issuances. On March 12, 2015, SEP issued $500 million of 3.50% unsecured notes due 2025 and $500 million of 4.50% unsecured notes due 2045. Net proceeds from the offering were used to repay a portion of outstanding commercial paper, to fund capital expenditures and for general corporate purposes.

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12. 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
June 30, 2015
Total
 
Level 1
 
Level 2
 
Level 3
 
 
(in millions)
Corporate debt securities
Cash and cash equivalents
$
91

 
$

 
$
91

 
$

Corporate debt securities
Current assets—other
2

 

 
2

 

Commodity derivatives
Current assets—other
45

 

 

 
45

Interest rate swaps
Current assets—other
1

 

 
1

 

Commodity derivatives
Investments and other assets—other
5

 

 

 
5

Corporate debt securities
Investments and other assets—other
20

 

 
20

 

Interest rate swaps
Investments and other assets—other
26

 

 
26

 

Total Assets
$
190

 
$

 
$
140

 
$
50



Description


Condensed Consolidated Balance Sheet Caption
December 31, 2014
Total
 
Level 1
 
Level 2
 
Level 3
 
 
(in millions)
Corporate debt securities
Cash and cash equivalents
$
85

 
$

 
$
85

 
$

Corporate debt securities
Current assets—other
3

 

 
3

 

Commodity derivatives
Current assets—other
57

 

 

 
57

Interest rate swaps
Current assets—other
2

 

 
2

 

Commodity derivatives
Investments and other assets—other
21

 

 

 
21

Corporate debt securities
Investments and other assets—other
20

 

 
20

 

Interest rate swaps
Investments and other assets—other
22

 

 
22

 

Money market funds
Investments and other assets—other
1

 
1

 

 

Total Assets
$
211

 
$
1

 
$
132

 
$
78


The following presents changes in Level 3 assets and liabilities that are measured at fair value on a recurring basis using significant unobservable inputs:
 
Three Months
Ended June 30,
 
Six Months
Ended June 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions)
Derivative assets (liabilities)
 
 
 
 
 
 
 
Fair value, beginning of period
$
49

 
$
(5
)
 
$
78

 
$
(3
)
Total gains (losses):
 
 
 
 
 
 
 
Included in earnings
3

 
(5
)
 
9

 
(9
)
Included in other comprehensive income
1

 
1

 
(5
)
 
4

Purchases
2

 

 
3

 

Settlements
(5
)
 

 
(35
)
 
(1
)
Fair value, end of period
$
50

 
$
(9
)
 
$
50

 
$
(9
)
Unrealized gains (losses) relating to instruments held at the end of the period
$

 
$
(4
)
 
$
(16
)
 
$
(7
)


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Table of Contents


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

Level 3 valuation techniques 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.

The derivative financial instruments reported in Level 3 at June 30, 2015 consist of NGL revenue swap contracts related to the Empress assets in Western Canada Transmission & Processing. As of June 30, 2015, we reported certain of our NGL basis swaps at fair value using Level 3 inputs due to such derivatives not having observable market prices for substantially the full term of the derivative asset or liability. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract length extends into unobservable periods.

The fair value of these NGL basis swaps is determined using a discounted cash flow valuation technique based on a forward commodity basis curve. For these derivatives, the primary input to the valuation model is the forward commodity basis curve, which is based on observable or public data sources and extrapolated when observable prices are not available.

The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives are the forward NGL basis curves, for which a significant portion of the derivative’s term is beyond available forward pricing. At June 30, 2015, a 10¢ per gallon movement in underlying forward NGL prices, primarily propane prices, would affect the estimated fair value of our NGL derivatives by $18 million. This calculated amount does not take into account any other changes to the fair value measurement calculation.

Financial Instruments

The fair values of financial instruments that are recorded and carried at book value are summarized in the following table. Judgment is required in interpreting market data to develop the estimates of fair value. These estimates are not necessarily indicative of the amounts we could have realized in current markets. 
 
June 30, 2015
 
December 31, 2014
 
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)
13,673

 
14,683

 
13,060

 
14,446

__________
(a)
Included within Investments in and Loans to Unconsolidated Affiliates.
(b)
Excludes capital leases, 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 and is classified as Level 2.


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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 six months ended June 30, 2015 and 2014, there were no material adjustments to assets and liabilities measured at fair value on a nonrecurring basis.
13. Risk Management and Hedging Activities

We are exposed to the impact of market fluctuations in the prices of NGLs and natural gas purchased as a result of our investment in DCP Midstream, the ownership of the NGL marketing operations in western Canada and processing operations 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, mostly around interest rate and commodity 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.

Other than the interest rate swaps and commodity derivatives as described below, we did not have significant derivatives outstanding during the six months ended June 30, 2015.

Interest Rate Swaps

At June 30, 2015, we had “pay floating—receive fixed” interest rate swaps outstanding with a total notional amount of $2,100 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:
 
June 30, 2015
 
December 31, 2014
 
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
(in millions)
Assets
$
27

 
$

 
$
27

 
$
24

 
$

 
$
24


Commodity Derivatives

At June 30, 2015, we had commodity mark-to-market derivatives outstanding with a total notional amount of 175 million gallons. The longest dated commodity derivative contract we currently have expires in 2018.

Information about our commodity derivatives that had netting or rights of offset arrangements are as follows:
 
June 30, 2015
 
December 31, 2014


Gross 
Amounts

Gross
Amounts
Offset

Net Amount Presented in the Condensed Consolidated Balance Sheets
 

Gross 
Amounts
 
Gross
Amounts
Offset
 
Net Amount Presented in the Condensed Consolidated Balance Sheets
Description
(in millions)
Assets
$
144


$
94


$
50

 
$
169

 
$
91

 
$
78

Liabilities
94


94



 
91

 
91

 


Substantially all of our commodity derivative agreements outstanding at June 30, 2015 and December 31, 2014 have provisions that require collateral to be posted in the amount of the net liability position if one of our credit ratings falls below investment grade.

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Information regarding the impacts of commodity derivatives on our Condensed Consolidated Statements of Operations are as follows:
 
 
 
 
Three Months
Ended June 30,
 
Six Months
Ended June 30,
Derivatives
 
Condensed Consolidated Statements of Operations Caption
 
2015
 
2014
 
2015
 
2014
 
 
 
 
(in millions)
Commodity derivatives
 
Sales of natural gas liquids
 
$
5

 
$
(4
)
 
$
12

 
$
(7
)
14. Commitments and Contingencies
Environmental
We are subject to various U.S. federal, state and local laws and regulations, as well as Canadian federal and provincial laws, regarding air and water quality, hazardous and solid waste disposal and other environmental matters. These laws and regulations can change from time to time, imposing new obligations on us.
Like others in the energy industry, we and our affiliates are responsible for environmental remediation at various contaminated sites. These include some properties that are part of our ongoing operations, sites formerly owned or used by us, and sites owned by third parties. Remediation typically involves management of contaminated soils and may involve groundwater remediation. Managed in conjunction with relevant federal, state/provincial and local agencies, activities vary with site conditions and locations, remedial requirements, complexity and sharing of responsibility. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, we or our affiliates could potentially be held responsible for contamination caused by other parties. In some instances, we may share liability associated with contamination with other potentially responsible parties, and may also benefit from 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. We believe there are no matters outstanding that upon resolution will have a material effect on our consolidated results of operations, financial position or cash flows.
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 for legal matters recorded as of June 30, 2015 or December 31, 2014 related to litigation.
Other Commitments and Contingencies
See Note 15 for a discussion of guarantees and indemnifications.
15. Guarantees and Indemnifications
We have various financial guarantees and indemnifications which are issued in the normal course of business. As discussed below, these contracts include financial guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. We enter into these arrangements to facilitate a commercial transaction with a third party by enhancing the value of the transaction to the third party. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on 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 June 30, 2015 was approximately $406 million, which has been indemnified by Duke Energy as discussed above. One of these outstanding performance guarantees, which has a

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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 June 30, 2015, the amounts recorded for the guarantees and indemnifications described above are not material, both individually and in the aggregate.
16. Issuances of SEP Units

During the six months ended June 30, 2015, SEP issued 3.6 million common units to the public under its at-the-market program and approximately 74,000 general partner units to Spectra Energy. Total net proceeds to SEP were $184 million (net proceeds to Spectra Energy were $180 million). In connection with the issuances of the units, a $40 million gain ($25 million net of tax) to Additional Paid-in Capital and a $139 million increase in Equity-Noncontrolling Interests were recorded during the six months ended June 30, 2015. The issuances decreased Spectra Energy's ownership in SEP from 82% to 81% at June 30, 2015.

The following table presents the effects of the issuances of SEP units:
 
Three Months
Ended June 30,
 
Six Months
Ended June 30,
 
2015
 
2014
 
2015
 
2014
 
        (in millions)
Net income-controlling interests
$
18

 
$
146

 
$
285

 
$
565

Increase in additional paid-in capital resulting from issuances of SEP units
19

 
19

 
25

 
29

Total net income-controlling interests and changes in equity-controlling interests
$
37

 
$
165

 
$
310

 
$
594


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17. Employee Benefit Plans

Retirement Plans. We have a qualified non-contributory defined benefit (DB) retirement plan for U.S. employees and non-qualified, non-contributory, unfunded defined benefit plans which cover certain current and former U.S. executives. Our Westcoast subsidiary maintains qualified and non-qualified, contributory and non-contributory, DB and defined contribution (DC) retirement plans covering substantially all employees of our Canadian operations.
Our policy is to fund our retirement plans, where applicable, on an actuarial basis to provide assets sufficient to meet benefits to be paid to plan participants or as required by legislation or plan terms. We made contributions of $11 million to our U.S. retirement plans in the six months ended June 30, 2015 and $10 million in the same period in 2014. We made total contributions to the Canadian DC and DB plans of $16 million in the six months ended June 30, 2015 and $26 million in the same period in 2014. We anticipate that we will make total contributions of approximately $22 million to the U.S. plans and approximately $31 million to the Canadian plans in 2015.
Qualified and Non-Qualified Pension Plans—Components of Net Periodic Pension Cost
 
Three Months
Ended June 30,
 
Six Months
Ended June 30,
 
2015
 
2014
 
2015
 
2014
 
                 (in millions)
 
 
U.S.
 
 
 
 
 
 
 
Service cost benefit earned
$
5

 
$
4

 
$
10

 
$
9

Interest cost on projected benefit obligation
6

 
6

 
12

 
12

Expected return on plan assets
(11
)
 
(9
)
 
(21
)
 
(19
)
Amortization of loss
3

 
3

 
5

 
6

Net periodic pension cost
$
3

 
$
4

 
$
6

 
$
8

 
 
 
 
 
 
 
 
Canada
 
 
 
 
 
 
 
Service cost benefit earned
$
8

 
$
8

 
$
16

 
$
15

Interest cost on projected benefit obligation
11

 
13

 
22

 
26

Expected return on plan assets
(17
)
 
(18
)
 
(34
)
 
(35
)
Amortization of loss
6

 
5

 
13

 
11

Amortization of prior service cost
1

 
1

 
1

 
1

Net periodic pension cost
$
9

 
$
9

 
$
18

 
$
18


Other Post-Retirement Benefit Plans. We provide certain health care and life insurance benefits for retired employees on a contributory and non-contributory basis. Employees are eligible for these benefits if they have met age and service requirements at retirement, as defined in the plans.
Other Post-Retirement Benefit Plans—Components of Net Periodic Benefit Cost 
 
Three Months
Ended June 30,
 
Six Months
Ended June 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions)
U.S.
 
 
 
 
 
 
 
Interest cost on accumulated post-retirement benefit obligation
$
2

 
$
2

 
$
4

 
$
4

Expected return on plan assets
(2
)
 
(1
)
 
(3
)
 
(2
)
Net periodic other post-retirement benefit cost
$

 
$
1

 
$
1

 
$
2

 
 
 
 
 
 
 
 
Canada
 
 
 
 
 
 
 
Service cost benefit earned
$
1

 
$
1

 
$
2

 
$
2

Interest cost on accumulated post-retirement benefit obligation
1

 
2

 
2

 
3

Net periodic other post-retirement benefit cost
$
2

 
$
3

 
$
4

 
$
5


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Retirement/Savings Plan
In addition to the retirement plans described above, we also have defined contribution 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 $4 million in both of the three months ended June 30, 2015 and 2014, and $7 million in both of the six months ended June 30, 2015 and 2014 for U.S. employees. We expensed pre-tax employer matching contributions of $2 million and $3 million in the three months ended June 30, 2015 and 2014, respectively, and $5 million and $6 million in the six months ended June 30, 2015 and 2014, respectively, for Canadian employees.

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

Spectra Energy Corp
Condensed Consolidating Statements of Operations
(Unaudited)
(In millions)

 
Spectra
Energy
Corp
 
Spectra
Capital
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Three Months Ended June 30, 2015
 
 
 
 
 
 
 
 
 
Total operating revenues
$

 
$

 
$
1,192

 
$

 
$
1,192

Total operating expenses
1

 
(1
)
 
786

 

 
786

Operating income (loss)
(1
)
 
1

 
406

 

 
406

Loss from equity investments

 

 
(189
)
 

 
(189
)
Equity in earnings of consolidated subsidiaries
12

 
62

 

 
(74
)
 

Other income and expenses, net
2

 

 
20

 

 
22

Interest expense

 
61

 
105

 

 
166

Earnings before income taxes
13

 
2

 
132

 
(74
)
 
73

Income tax expense (benefit)
(5
)
 
(10
)
 
8

 

 
(7
)
Net income
18

 
12

 
124

 
(74
)
 
80

Net income—noncontrolling interests

 

 
62

 

 
62

Net income—controlling interests
$
18

 
$
12

 
$
62

 
$
(74
)
 
$
18

 
 
 
 
 
 
 
 
 
 
Three Months Ended June 30, 2014
 
 
 
 
 
 
 
 
 
Total operating revenues
$

 
$

 
$
1,253

 
$

 
$
1,253

Total operating expenses

 
1

 
914

 

 
915

Operating income (loss)

 
(1
)
 
339

 

 
338

Earnings from equity investments

 

 
85

 

 
85

Equity in earnings of consolidated subsidiaries
125

 
264

 

 
(389
)
 

Other income and expenses, net
(1
)
 

 
7

 

 
6

Interest expense

 
66

 
110

 

 
176

Earnings before income taxes
124

 
197

 
321

 
(389
)
 
253

Income tax expense (benefit)
(22
)
 
72

 
15

 

 
65

Net income
146

 
125

 
306

 
(389
)
 
188

Net income—noncontrolling interests

 

 
42

 

 
42

Net income—controlling interests
$
146

 
$
125

 
$
264

 
$
(389
)
 
$
146

 
 
 
 
 
 
 
 
 
 

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Table of Contents


Spectra Energy Corp
Condensed Consolidating Statements of Operations
(Unaudited)
(In millions)

 
Spectra
Energy
Corp
 
Spectra
Capital
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Six Months Ended June 30, 2015
 
 
 
 
 
 
 
 
 
Total operating revenues
$

 
$

 
$
2,816

 
$
(1
)
 
$
2,815

Total operating expenses
3

 
(1
)
 
1,867

 
(1
)
 
1,868

Operating income (loss)
(3
)
 
1

 
949

 

 
947

Loss from equity investments

 

 
(165
)
 

 
(165
)
Equity in earnings of consolidated subsidiaries
275

 
483

 

 
(758
)
 

Other income and expenses, net

 

 
42

 

 
42

Interest expense

 
122

 
203

 

 
325

Earnings before income taxes
272

 
362

 
623

 
(758
)
 
499

Income tax expense (benefit)
(13
)
 
87

 
20

 

 
94

Net income
285

 
275

 
603

 
(758
)
 
405

Net income—noncontrolling interests

 

 
120

 

 
120

Net income—controlling interests
$
285

 
$
275

 
$
483

 
$
(758
)
 
$
285

 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2014
 
 
 
 
 
 
 
 
 
Total operating revenues
$

 
$

 
$
3,097

 
$
(1
)
 
$
3,096

Total operating expenses
4

 
1

 
2,115

 
(1
)
 
2,119

Operating income (loss)
(4
)
 
(1
)
 
982

 

 
977

Earnings from equity investments

 

 
246

 

 
246

Equity in earnings of consolidated subsidiaries
540

 
899

 

 
(1,439
)
 

Other income and expenses, net
(2
)
 
1

 
16

 

 
15

Interest expense

 
131

 
223

 

 
354

Earnings before income taxes
534

 
768

 
1,021

 
(1,439
)
 
884

Income tax expense (benefit)
(31
)
 
228

 
32

 

 
229

Net income
565

 
540

 
989

 
(1,439
)
 
655

Net income—noncontrolling interests

 

 
90

 

 
90

Net income—controlling interests
$
565

 
$
540

 
$
899

 
$
(1,439
)
 
$
565


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Table of Contents


Spectra Energy Corp
Condensed Consolidating Statements of Comprehensive Income
(Unaudited)
(In millions)

 
Spectra
Energy
Corp
 
Spectra
Capital
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Three Months Ended June 30, 2015
 
 
 
 
 
 
 
 
 
Net income
$
18

 
$
12

 
$
124

 
$
(74
)
 
$
80

Other comprehensive income
2

 

 
91

 

 
93

Total comprehensive income, net of tax
20

 
12

 
215

 
(74
)
 
173

Less: comprehensive income—noncontrolling interests

 

 
64

 

 
64

Comprehensive income—controlling interests
$
20

 
$
12

 
$
151

 
$
(74
)
 
$
109

 
 
 
 
 
 
 
 
 
 
Three Months Ended June 30, 2014
 
 
 
 
 
 
 
 
 
Net income
$
146

 
$
125

 
$
306

 
$
(389
)
 
$
188

Other comprehensive income
2

 

 
229

 

 
231

Total comprehensive income, net of tax
148

 
125

 
535

 
(389
)
 
419

Less: comprehensive income—noncontrolling interests

 

 
45

 

 
45

Comprehensive income—controlling interests
$
148

 
$
125

 
$
490

 
$
(389
)
 
$
374

 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2015
 
 
 
 
 
 
 
 
 
Net income
$
285

 
$
275

 
$
603

 
$
(758
)
 
$
405

Other comprehensive income (loss)
3

 

 
(395
)
 

 
(392
)
Total comprehensive income, net of tax
288

 
275

 
208

 
(758
)
 
13

Less: comprehensive income—noncontrolling interests

 

 
114

 

 
114

Comprehensive income (loss)—controlling interests
$
288

 
$
275

 
$
94

 
$
(758
)
 
$
(101
)
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2014
 
 
 
 
 
 
 
 
 
Net income
$
565

 
$
540

 
$
989

 
$
(1,439
)
 
$
655

Other comprehensive income (loss)
4

 

 
(10
)
 

 
(6
)
Total comprehensive income, net of tax
569

 
540

 
979

 
(1,439
)
 
649

Less: comprehensive income—noncontrolling interests

 

 
89

 

 
89

Comprehensive income—controlling interests
$
569

 
$
540

 
$
890

 
$
(1,439
)
 
$
560




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Table of Contents


Spectra Energy Corp
Condensed Consolidating Balance Sheet
June 30, 2015
(Unaudited)
(In millions)
 
 
Spectra
Energy
Corp
 
Spectra
Capital
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Cash and cash equivalents
$

 
$
2

 
$
285

 
$

 
$
287

Receivables—consolidated subsidiaries
10

 

 
18

 
(28
)
 

Notes receivable—current—consolidated subsidiaries

 

 
388

 
(388
)
 

Receivables—other
2

 

 
878

 

 
880

Other current assets
8

 
1

 
561

 

 
570

Total current assets
20

 
3

 
2,130

 
(416
)
 
1,737

Investments in and loans to unconsolidated affiliates

 

 
2,701

 

 
2,701

Investments in consolidated subsidiaries
14,515

 
20,198

 

 
(34,713
)
 

Advances receivable—consolidated subsidiaries

 
5,212

 
901

 
(6,113
)
 

Notes receivable—consolidated subsidiaries

 

 
2,800

 
(2,800
)
 

Goodwill

 

 
4,615

 

 
4,615

Other assets
41

 
23

 
243

 

 
307

Net property, plant and equipment

 

 
22,281

 

 
22,281

Regulatory assets and deferred debits
2

 
14

 
1,387

 

 
1,403

Total Assets
$
14,578

 
$
25,450

 
$
37,058

 
$
(44,042
)
 
$
33,044

 
 
 
 
 
 
 
 
 
 
Accounts payable
$
3

 
$
4

 
$
550

 
$

 
$
557

Accounts payable—consolidated subsidiaries

 
23

 
5

 
(28
)
 

Commercial paper

 
497

 
38

 

 
535

Short-term borrowings—consolidated subsidiaries

 
388

 

 
(388
)
 

Taxes accrued
5

 
18

 
85

 

 
108

Current maturities of long-term debt

 

 
917

 

 
917

Other current liabilities
69

 
53

 
898

 

 
1,020

Total current liabilities
77

 
983

 
2,493

 
(416
)
 
3,137

Long-term debt

 
2,900

 
9,883

 

 
12,783

Advances payable—consolidated subsidiaries
6,113

 

 

 
(6,113
)
 

Notes payable—consolidated subsidiaries

 
2,800

 

 
(2,800
)
 

Deferred credits and other liabilities
792

 
4,252

 
1,743

 

 
6,787

Preferred stock of subsidiaries

 

 
258

 

 
258

Equity
 
 
 
 
 
 
 
 
 
Controlling interests
7,596

 
14,515

 
20,198

 
(34,713
)
 
7,596

Noncontrolling interests

 

 
2,483

 

 
2,483

Total equity
7,596

 
14,515

 
22,681

 
(34,713
)
 
10,079

Total Liabilities and Equity
$
14,578

 
$
25,450

 
$
37,058

 
$
(44,042
)
 
$
33,044




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Table of Contents


Spectra Energy Corp
Condensed Consolidating Balance Sheet
December 31, 2014 
(Unaudited)
(In millions)
 
 
Spectra
Energy
Corp
 
Spectra
Capital
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Cash and cash equivalents
$

 
$
1

 
$
214

 
$

 
$
215

Receivables—consolidated subsidiaries
18

 

 
11

 
(29
)
 

Notes receivable—current—consolidated subsidiaries

 

 
398

 
(398
)
 

Receivables—other
2

 

 
1,334

 

 
1,336

Other current assets
71

 
2

 
708

 

 
781

Total current assets
91

 
3

 
2,665

 
(427
)
 
2,332

Investments in and loans to unconsolidated affiliates

 

 
2,966

 

 
2,966

Investments in consolidated subsidiaries
14,531

 
20,562

 

 
(35,093
)
 

Advances receivable—consolidated subsidiaries

 
4,683

 
898

 
(5,581
)
 

Notes receivable—consolidated subsidiaries

 

 
2,800

 
(2,800
)
 

Goodwill

 

 
4,714

 

 
4,714

Other assets
38

 
22

 
267

 

 
327

Net property, plant and equipment

 

 
22,307

 

 
22,307

Regulatory assets and deferred debits
4

 
15

 
1,375

 

 
1,394

Total Assets
$
14,664

 
$
25,285

 
$
37,992

 
$
(43,901
)
 
$
34,040

 
 
 
 
 
 
 
 
 
 
Accounts payable
$
3

 
$

 
$
455

 
$

 
$
458

Accounts payable—consolidated subsidiaries

 
17

 
12

 
(29
)
 

Commercial paper

 
398

 
1,185

 

 
1,583

Short-term borrowings—consolidated subsidiaries

 
398

 

 
(398
)
 

Taxes accrued
5

 

 
86

 

 
91

Current maturities of long-term debt

 

 
327

 

 
327

Other current liabilities
96

 
54

 
1,200

 

 
1,350

Total current liabilities
104

 
867

 
3,265

 
(427
)
 
3,809

Long-term debt

 
2,900

 
9,869

 

 
12,769

Advances payable—consolidated subsidiaries
5,581

 

 

 
(5,581
)
 

Notes payable—consolidated subsidiaries

 
2,800

 

 
(2,800
)
 

Deferred credits and other liabilities
819

 
4,187

 
1,800

 

 
6,806

Preferred stock of subsidiaries

 

 
258

 

 
258

Equity
 
 
 
 
 
 
 
 
 
Controlling interests
8,160

 
14,531

 
20,562

 
(35,093
)
 
8,160

Noncontrolling interests

 

 
2,238

 

 
2,238

Total equity
8,160

 
14,531

 
22,800

 
(35,093
)
 
10,398

Total Liabilities and Equity
$
14,664

 
$
25,285

 
$
37,992

 
$
(43,901
)
 
$
34,040




29

Table of Contents


Spectra Energy Corp
Condensed Consolidating Statement of Cash Flows
Six Months Ended June 30, 2015
(Unaudited)
(In millions)

 
Spectra
Energy
Corp
 
Spectra
Capital
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
 
 
 
 
 
 
Net income
$
285

 
$
275

 
$
603

 
$
(758
)
 
$
405

Adjustments to reconcile net income to net cash provided by (used in) operating activities:
 
 
 
 
 
 
 
 
 
Depreciation and amortization

 

 
393

 

 
393

Loss from equity investments

 

 
165

 

 
165

Equity in earnings of consolidated subsidiaries
(275
)
 
(483
)
 

 
758

 

Distributions received from unconsolidated affiliates

 

 
93

 

 
93

Other
30

 
68

 
302

 

 
400

Net cash provided by (used in) operating activities
40

 
(140
)
 
1,556

 

 
1,456

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
 
 
 
 
 
 
Capital expenditures

 

 
(989
)
 

 
(989
)
Investments in and loans to unconsolidated
affiliates

 

 
(34
)
 

 
(34
)
Purchases of held-to-maturity securities

 

 
(329
)
 

 
(329
)
Proceeds from sales and maturities of held-to-maturity securities

 

 
344

 

 
344

Proceeds from sales and maturities of available-for-sale securities

 

 
1

 

 
1

Distributions received from unconsolidated
affiliates

 

 
35

 

 
35

Advances (to) from affiliates
(72
)
 
46

 

 
26

 

Other changes in restricted funds

 

 
(6
)
 

 
(6
)
Other

 
 
 
2

 
 
 
2

Net cash provided by (used in) investing activities
(72
)
 
46

 
(976
)
 
26

 
(976
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
 
 
 
 
 
 
Proceeds from the issuance of long-term debt

 

 
994

 

 
994

Payments for the redemption of long-term debt

 

 
(39
)
 

 
(39
)
Net increase (decrease) in commercial paper

 
99

 
(1,129
)
 

 
(1,030
)
Distributions to noncontrolling interests

 

 
(93
)
 

 
(93
)
Contributions from noncontrolling interests

 

 
90

 

 
90

Proceeds from the issuance of SEP common units

 

 
180

 

 
180

Dividends paid on common stock
(499
)
 

 

 

 
(499
)
Distributions and advances from (to) affiliates
532

 
(4
)
 
(502
)
 
(26
)
 

Other
(1
)
 

 
(8
)
 

 
(9
)
Net cash provided by (used in) financing activities
32

 
95

 
(507
)
 
(26
)
 
(406
)
Effect of exchange rate changes on cash

 

 
(2
)
 

 
(2
)
Net increase in cash and cash equivalents

 
1

 
71

 

 
72

Cash and cash equivalents at beginning of period

 
1

 
214

 

 
215

Cash and cash equivalents at end of period
$

 
$
2

 
$
285

 
$

 
$
287


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Spectra Energy Corp
Condensed Consolidating Statement of Cash Flows
Six Months Ended June 30, 2014
(Unaudited)
(In millions)
 
 
Spectra
Energy
Corp
 
Spectra
Capital
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
 
 
 
 
 
 
Net income
$
565

 
$
540

 
$
989

 
$
(1,439
)
 
$
655

Adjustments to reconcile net income to net cash provided by (used in) operating activities:
 
 
 
 
 
 
 
 
 
Depreciation and amortization

 

 
405

 

 
405

Earnings from equity investments

 

 
(246
)
 

 
(246
)
Equity in earnings of consolidated subsidiaries
(540
)
 
(899
)
 

 
1,439

 

Distributions received from unconsolidated affiliates

 

 
199

 

 
199

Other
(36
)
 
229

 
3

 

 
196

Net cash provided by (used in) operating activities
(11
)
 
(130
)
 
1,350

 

 
1,209

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
 
 
 
 
 
 
Capital expenditures

 

 
(833
)
 

 
(833
)
Investments in and loans to unconsolidated
affiliates

 

 
(30
)
 

 
(30
)
Purchases of held-to-maturity securities

 

 
(437
)
 

 
(437
)
Proceeds from sales and maturities of held-to-maturity securities

 

 
453

 

 
453

Purchases of available-for-sale securities

 

 
(13
)
 

 
(13
)
Proceeds from sales and maturities of available-for-sale securities

 

 
7

 

 
7

Distributions received from unconsolidated
affiliates

 

 
242

 

 
242

Advances from affiliates
85

 
91

 

 
(176
)
 

Other changes in restricted funds

 

 
(1
)
 

 
(1
)
Net cash provided by (used in) investing activities
85

 
91

 
(612
)
 
(176
)
 
(612
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
 
 
 
 
 
 
Proceeds from the issuance of long-term debt

 
300

 
412

 

 
712

Payments for the redemption of long-term debt

 
(148
)
 
(588
)
 

 
(736
)
Net decrease in commercial paper

 
(124
)
 
(132
)
 

 
(256
)
Distributions to noncontrolling interests

 

 
(81
)
 

 
(81
)
Contributions from noncontrolling interests

 

 
112

 

 
112

Proceeds from the issuance of SEP common units

 

 
191

 

 
191

Dividends paid on common stock
(453
)
 

 

 

 
(453
)
Distributions and advances from (to) affiliates
366

 
1

 
(543
)
 
176

 

Other
13

 

 
(1
)
 

 
12

Net cash provided by (used in) financing activities
(74
)
 
29

 
(630
)
 
176

 
(499
)
Effect of exchange rate changes on cash

 

 
1

 

 
1

Net increase (decrease) in cash and cash equivalents

 
(10
)
 
109

 

 
99

Cash and cash equivalents at beginning of period

 
12

 
189

 

 
201

Cash and cash equivalents at end of period
$

 
$
2

 
$
298

 
$

 
$
300


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19. New Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, “Revenue from Contracts with Customers (Topic 606), which supersedes the revenue recognition requirements of “Revenue Recognition (Topic 605)” and clarifies the principles of recognizing revenue. In July 2015, the FASB decided to defer the effective date of the new revenue standard for one year and to permit entities to early adopt the standard as of the original effective date. This ASU is effective for us January 1, 2018. We are currently evaluating this ASU and its potential impact on us.

In February 2015, the FASB issued ASU No. 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis,” which makes changes to both the variable interest model and the voting model. These changes will require re-evaluation of certain entities for consolidation and will require us to revise our documentation regarding the consolidation or deconsolidation of such entities. ASU No. 2015-02 is effective for us January 1, 2016. We are currently evaluating this ASU and its potential impact on us.

In April 2015, the FASB issued ASU No. 2015-03, “Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,” which requires that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, rather than as a deferred charge asset. ASU No. 2015-03 is effective for us January 1, 2016 and is to be applied retrospectively. Early application is permitted. This ASU is not expected to have a material impact on our consolidated results of operations, financial position or cash flow.
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 June 30, 2015 and 2014, we reported net income from controlling interests of $18 million and $146 million, respectively. For the six months ended June 30, 2015 and 2014, we reported net income from controlling interests of $285 million and $565 million, respectively.
The highlights for the three months and six months ended June 30, 2015 include the following:
Spectra Energy Partners’ earnings for the three and six-month periods benefited mainly from expansions, primarily on Texas Eastern Transmission, LP (Texas Eastern), lower operating costs and higher earnings from equity investments.
Distribution’s earnings for the three-month period decreased mainly due to a weaker Canadian dollar. For the six-month period, earnings decreased due to a weaker Canadian dollar and the first quarter 2014 results including regulatory decisions from the OEB that, in aggregate, provided a benefit.
Western Canada Transmission & Processing’s earnings for the three-month period decreased mainly due to a weaker Canadian dollar and overhead reduction costs, partially offset by favorable results at the Empress operations due in large part to the 2014 plant turnaround. The decrease in earnings for the six-month period was mainly due to lower NGL sales prices, net of settlement gains associated with the risk management program at the Empress operations, a weaker Canadian dollar and overhead reduction costs.
Field Services’ earnings for the three-month period decreased largely due to an impairment of goodwill at DCP Midstream and lower commodity prices, partially offset by asset growth and improved operating efficiencies and other initiatives. For the six-month period, earnings decreased mainly due to an impairment of goodwill at DCP Midstream, lower commodity prices and lower gains associated with the issuance of partnership units by DCP Partners, partially offset by asset growth, improved operating efficiencies and other initiatives.
In the first six months of 2015, we had $1.0 billion of capital and investment expenditures. We currently project $3.5 billion of capital and investment expenditures for the full year, including expansion capital expenditures of $2.8 billion.
We are committed to an investment-grade balance sheet and continued prudent financial management of our capital structure. Therefore, financing growth activities will continue to be based on our strong and growing fee-based earnings and cash flows as well as the issuances of debt and equity securities. As of June 30, 2015, our revolving credit facilities included

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Spectra Capital’s $1.0 billion facility, SEP’s $2.0 billion facility, Westcoast’s 400 million Canadian dollar facility and Union Gas’ 500 million Canadian dollar facility. These facilities are used principally as back-stops for commercial paper programs.
RESULTS OF OPERATIONS
 
Three Months
Ended June 30,
 
Six Months
Ended June 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions)
Operating revenues
$
1,192

 
$
1,253

 
$
2,815

 
$
3,096

Operating expenses
786

 
915

 
1,868

 
2,119

Operating income
406

 
338

 
947

 
977

Other income and expenses
(167
)
 
91

 
(123
)
 
261

Interest expense
166

 
176

 
325

 
354

Earnings before income taxes
73

 
253

 
499

 
884

Income tax expense (benefit)
(7
)
 
65

 
94

 
229

Net income
80

 
188

 
405

 
655

Net income—noncontrolling interests
62

 
42

 
120

 
90

Net income—controlling interests
$
18

 
$
146

 
$
285

 
$
565

Three Months Ended June 30, 2015 Compared to Same Period in 2014
Operating Revenues. The $61 million, or 5%, decrease was driven by:
the effects of a weaker Canadian dollar at Distribution and Western Canada Transmission & Processing,
lower sales volumes of residual natural gas and lower NGL prices, net of higher NGL sales volumes due to the 2014 plant turnaround and an increase from settlement gains associated with the risk management program at the Empress operations at Western Canada Transmission & Processing and
lower natural gas prices passed through to customers and lower customer usage of natural gas primarily due to warmer weather, at Distribution, partially offset by
revenues from expansion projects primarily on Texas Eastern and East Tennessee Natural Gas, LLC (East Tennessee), higher crude oil transportation revenues mainly as a result of higher contracted volumes and higher tariff revenues mainly at the Express pipeline, all at Spectra Energy Partners.
Operating Expenses. The $129 million, or 14%, decrease was driven by:
decreased volumes of natural gas purchases for extraction and make-up and lower costs of sales at the Empress operations, net of overhead reduction costs at Western Canada Transmission & Processing,
the effects of a weaker Canadian dollar at Distribution and Western Canada Transmission & Processing,
lower volumes of natural gas sold due to warmer weather, net of higher operating fuel costs at Distribution and
lower operating costs primarily due to ad valorem tax accruals at Spectra Energy Partners.
Other Income and Expenses. The $258 million, or 284%, decrease was attributable to lower equity earnings from Field Services mainly due to an impairment of goodwill at DCP Midstream and lower commodity prices, net of increased gathering and processing margins as a result of asset growth and improved operating efficiencies and other initiatives. These decreases were partially offset by higher allowance for funds used during construction (AFUDC) resulting from higher capital spending and higher equity earnings from DCP Sand Hills Pipeline, LLC (Sand Hills) as a result of higher volumes at Spectra Energy Partners.
Interest Expense. The $10 million, or 6%, decrease was mainly due to a weaker Canadian dollar.
Income Tax Expense. The $72 million decrease was primarily attributable to the tax impact on the impairment of goodwill at DCP Midstream.
The effective tax rate for income from continuing operations was negative 10% for the three months ended June 30, 2015, compared to 26% for the same period in 2014.

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Net Income—Noncontrolling Interests. The $20 million increase was driven primarily by higher earnings from Spectra Energy Partners.
Six Months Ended June 30, 2015 Compared to Same Period in 2014
Operating Revenues. The $281 million, or 9%, decrease was driven by:
lower NGL prices and sales volumes, lower sales volumes of residual natural gas, net of an increase from settlement gains associated with the risk management program at the Empress operations at Western Canada Transmission & Processing,
the effects of a weaker Canadian dollar at Distribution and Western Canada Transmission & Processing and
lower customer usage due to warmer weather, the first quarter 2014 results including regulatory decisions from the OEB that, in aggregate, provided a benefit and growth in the number of customers at Distribution, partially offset by
revenues from expansion projects primarily on Texas Eastern and East Tennessee, higher crude oil transportation revenues mainly as a result of higher contracted volumes and higher tariff revenues mainly at the Express pipeline and an increase in recoveries of electric power and other costs passed through to gas transmission customers, net of lower other transportation revenues on East Tennessee and interruptible transportation on Texas Eastern at Spectra Energy Partners.
Operating Expenses. The $251 million, or 12%, decrease was driven by:
decreased volumes of natural gas purchases for extraction and make-up and lower costs of sales at the Empress operations, net of overhead reduction costs at Western Canada Transmission & Processing and
the effects of a weaker Canadian dollar at Distribution and Western Canada Transmission & Processing, partially offset by
increased electric power and other costs passed through to gas transmission customers and a non-cash impairment charge on Ozark Gas Gathering, L.L.C. (Ozark Gas Gathering), net of lower ad valorem tax accruals at Spectra Energy Partners and
higher natural gas prices passed through to customers and growth in the number of customers, net of lower volumes of natural gas sold due to warmer weather at Distribution.
Other Income and Expenses. The $384 million, or 147%, decrease was attributable to lower equity earnings from Field Services mainly due to an impairment of goodwill at DCP Midstream, decreased commodity prices and lower gains associated with the issuance of partnership units by DCP Partners, net of increased gathering and processing margins as a result of asset growth and higher volumes in certain geographic regions, and improved operating efficiencies. These decreases were partially offset by higher AFUDC resulting from higher capital spending and higher equity earnings from Sand Hills as a result of higher volumes at Spectra Energy Partners.
Interest Expense. The $29 million, or 8%, decrease was mainly due to a weaker Canadian dollar and lower average long-term debt balances and rates.
Income Tax Expense.The $135 million decrease was primarily due to the $72 million tax impact on the impairment of goodwill at DCP Midstream, lower earnings and the effect of a weaker Canadian dollar.
The effective tax rate for income from continuing operations was 19% for the six months ended June 30, 2015, compared to 26% for the same period in 2014.
Net Income—Noncontrolling Interests. The $30 million increase was driven primarily by higher earnings from Spectra Energy Partners.
For a more detailed discussion of earnings drivers, see the segment discussions that follow.

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Table of Contents


Segment Results
Management evaluates segment performance based on EBITDA. Cash, cash equivalents and short-term investments are managed at the parent-company levels, so the gains and losses from foreign currency transactions and interest and dividend income are excluded from the segments’ EBITDA. We consider segment EBITDA to be a good indicator of each segment’s operating performance from its continuing operations, as it represents the results of our operations without regard to financing methods or capital structures. Our segment EBITDA may not be comparable to similarly titled measures of other companies because other companies may not calculate EBITDA in the same manner.
Segment EBITDA is summarized in the following table. Detailed discussions follow.
EBITDA by Business Segment
 
Three Months
Ended June 30,
 
Six Months
Ended June 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions)
Spectra Energy Partners
$
478

 
$
374

 
$
933

 
$
803

Distribution
98

 
112

 
290

 
338

Western Canada Transmission & Processing
104

 
111

 
265

 
348

Field Services
(233
)
 
54

 
(250
)
 
184

Total reportable segment EBITDA
447

 
651

 
1,238

 
1,673

Other
(12
)
 
(24
)
 
(27
)
 
(41
)
Total reportable segment and other EBITDA
435

 
627

 
1,211

 
1,632

Depreciation and amortization
193

 
199

 
386

 
399

Interest expense
166

 
176

 
325

 
354

Interest income and other (a)
(3
)
 
1

 
(1
)
 
5

Earnings before income taxes
$
73

 
$
253

 
$
499

 
$
884

___________
(a)
Includes foreign currency transaction gains and losses related to segment EBITDA.
The amounts discussed below include intercompany transactions that are eliminated in the Condensed Consolidated Financial Statements.
Spectra Energy Partners
 
Three Months
Ended June 30,
 
Six Months
Ended June 30,
 
2015
 
2014
 
Increase (Decrease)
 
2015
 
2014
 
Increase (Decrease)
 
(in millions, except where noted)
Operating revenues
$
603

 
$
531

 
$
72

 
$
1,209

 
$
1,112

 
$
97

Operating expenses
 
 
 
 
 
 
 
 
 
 
 
        Operating, maintenance and other
192

 
193

 
(1
)
 
399

 
378

 
21

Other income and expenses
67

 
36

 
31

 
123

 
69

 
54

EBITDA
$
478

 
$
374

 
$
104

 
$
933

 
$
803

 
$
130

Express pipeline revenue receipts, MBbl/d (a)
235

 
204

 
31

 
242

 
214

 
28

Platte PADD II deliveries, MBbl/d
172

 
176

 
(4
)
 
170

 
171

 
(1
)
___________
(a)
Thousand barrels per day.







35

Table of Contents


Three Months Ended June 30, 2015 Compared to Same Period in 2014
Operating Revenues. The $72 million increase was driven by:
a $32 million increase due to expansion projects, primarily on Texas Eastern and East Tennessee,
a $20 million increase in crude oil transportation revenues as a result of higher volumes and higher tariff revenues mainly at the Express pipeline and
a $17 million increase in recoveries of electric power and other costs passed through to gas transmission customers.
Operating, Maintenance and Other. The $1 million decrease was driven by:
a $17 million decrease primarily due to ad valorem tax accruals, offset by
a $17 million increase in electric power and other costs passed through to gas transmission customers.
Other Income and Expenses. The $31 million increase was primarily due to higher AFUDC resulting from higher capital spending and higher equity earnings from Sand Hills as a result of higher volumes and the dropdown of an additional 24.95% interest in Southeast Supply Header, LLC (SESH).
Six Months Ended June 30, 2015 Compared to Same Period in 2014
Operating Revenues. The $97 million increase was driven by:
a $65 million increase due to expansion projects, primarily on Texas Eastern and East Tennessee,
a $33 million increase in crude oil transportation revenues as a result of higher volumes and tariff rates mainly on the Express pipeline and
a $31 million increase in recoveries of electric power and other costs passed through to gas transmission customers, partially offset by
an $11 million net decrease in natural gas transportation revenues mainly from other revenue on East Tennessee and interruptible transportation on Texas Eastern.
Operating, Maintenance and Other. The $21 million increase was driven by:
a $31 million increase in electric power and other costs passed through to gas transmission customers and
a $9 million increase due to the non-cash impairment charge on Ozark Gas Gathering, partially offset by
a $21 million decrease due to ad valorem tax accruals.
Other Income and Expenses. The $54 million increase was primarily due to higher AFUDC resulting from higher capital spending and higher equity earnings from Sand Hills as a result of higher volumes and the dropdown of an additional 24.95% interest in SESH.



36

Table of Contents


Distribution 
 
Three Months
Ended June 30,
 
Six Months
Ended June 30,
 
2015
 
2014
 
Increase (Decrease)
 
2015
 
2014
 
Increase (Decrease)
 
(in millions, except where noted)
Operating revenues
$
290

 
$
360

 
$
(70
)
 
$
952

 
$
1,078

 
$
(126
)
Operating expenses
 
 
 
 
 
 
 
 
 
 
 
        Natural gas purchased
103

 
152

 
(49
)
 
486

 
540

 
(54
)
        Operating, maintenance and other
90

 
96

 
(6
)
 
176

 
199

 
(23
)
Other income and expenses
1

 

 
1

 

 
(1
)
 
1

EBITDA
$
98

 
$
112

 
$
(14
)
 
$
290

 
$
338

 
$
(48
)
Number of customers, thousands
 
 
 
 
 
 
1,425

 
1,405

 
20

Heating degree days, Fahrenheit
866

 
979

 
(113
)
 
5,125

 
5,230

 
(105
)
Pipeline throughput, TBtu (a)
132

 
121

 
11

 
460

 
415

 
45

Canadian dollar exchange rate, average
1.23

 
1.09

 
0.14

 
1.23

 
1.10

 
0.13

___________
(a)
Trillion British thermal units.

Three Months Ended June 30, 2015 Compared to Same Period in 2014
Operating Revenues. The $70 million decrease was driven by:
a $36 million decrease resulting from a weaker Canadian dollar,
a $29 million decrease from lower natural gas prices passed through to customers. Prices charged to customers are adjusted quarterly based on the 12 month New York Mercantile Exchange (NYMEX) forecast and
a $20 million decrease in customer usage of natural gas primarily due to weather that was warmer than in 2014.
Natural Gas Purchased. The $49 million decrease was driven by:
a $29 million decrease from lower natural gas prices passed through to customers,
a $20 million decrease due to lower volumes of natural gas sold primarily due to warmer weather and
a $13 million decrease resulting from a weaker Canadian dollar, partially offset by
a $10 million increase in operating fuel costs primarily due to gas measurement variances.
Operating, Maintenance and Other. The $6 million decrease was mainly driven by the weaker Canadian dollar.
Six Months Ended June 30, 2015 Compared to Same Period in 2014
Operating Revenues. The $126 million decrease was driven by:
a $118 million decrease resulting from a weaker Canadian dollar,
a $23 million decrease in customer usage of natural gas primarily due to weather that was warmer than in 2014,
a $10 million decrease, net of 2012 earnings sharing, primarily as a result of the first quarter 2014 results including regulatory decisions from the OEB that, in aggregate, provided a benefit, partially offset by
a $17 million increase from higher natural gas prices passed through to customers. Prices charged to customers are adjusted quarterly based on the 12 month NYMEX forecast and
a $15 million increase from growth in the number of customers.
Natural Gas Purchased. The $54 million decrease was driven by:
a $60 million decrease resulting from a weaker Canadian dollar and
a $20 million decrease due to lower volumes of natural gas sold primarily due to warmer weather, partially offset by
a $17 million increase from higher natural gas prices passed through to customers and

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Table of Contents


a $10 million increase from growth in the number of customers.
Operating, Maintenance and Other. The $23 million decrease was primarily driven by the weaker Canadian dollar.
Western Canada Transmission & Processing
 
Three Months
Ended June 30,
 
Six Months
Ended June 30,
 
2015
 
2014
 
Increase (Decrease)
 
2015
 
2014
 
Increase (Decrease)
 
(in millions, except where noted)
Operating revenues
$
304

 
$
391

 
$
(87
)
 
$
674

 
$
966

 
$
(292
)
Operating expenses

 

 
 
 
 
 
 
 
 
        Natural gas and petroleum products purchased
25

 
91

 
(66
)
 
92

 
265

 
(173
)
        Operating, maintenance and other
174

 
189

 
(15
)
 
321

 
354

 
(33
)
Other income and expenses
(1
)
 

 
(1
)
 
4

 
1

 
3

EBITDA
$
104

 
$
111

 
$
(7
)
 
$
265

 
$
348

 
$
(83
)
Pipeline throughput, TBtu
220

 
224

 
(4
)
 
476

 
466

 
10

Volumes processed, TBtu
156

 
175

 
(19
)
 
336

 
352

 
(16
)
Canadian dollar exchange rate, average
1.23

 
1.09

 
0.14

 
1.23

 
1.10

 
0.13


Three Months Ended June 30, 2015 Compared to Same Period in 2014
Operating Revenues. The $87 million decrease was driven by:
a $47 million decrease due primarily to lower sales volumes of residual natural gas at the Empress operations,
a $39 million decrease resulting from a weaker Canadian dollar and
a $23 million decrease due to lower NGL prices associated with the Empress operations, partially offset by
an $8 million increase in sales volumes of NGLs at the Empress operations due mostly to the 2014 plant turnaround,
a $7 million increase from settlement gains associated with the risk management program at the Empress operations,
a $5 million increase in carbon and other non-income tax expense recovered from customers and
a $4 million increase arising from non-cash mark-to-market gains associated with the risk management program implemented in 2014 at the Empress operations.
Natural Gas and Petroleum Products Purchased. The $66 million decrease was driven by:
a $55 million decrease due primarily to lower volumes of natural gas purchases for extraction and make-up at the Empress operations and
a $13 million decrease primarily as a result of lower costs of sales at the Empress facility, partially offset by
a $5 million non-cash charge to reduce the value of propane inventory at the Empress operations to net realizable value at June 30, 2015.
Operating, Maintenance and Other. The $15 million decrease was driven by:
a $21 million decrease resulting from a weaker Canadian dollar and
a $10 million decrease in plant turnaround costs, partially offset by
an $11 million increase due to overhead reduction costs.

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Table of Contents


Six Months Ended June 30, 2015 Compared to Same Period in 2014
Operating Revenues. The $292 million decrease was driven by:
a $105 million decrease due to lower NGL prices associated with the Empress operations,
a $90 million decrease due primarily to lower sales volumes of residual natural gas at the Empress operations,
an $85 million decrease resulting from a weaker Canadian dollar,
a $33 million decrease in sales volumes of NGLs at the Empress operations,
an $18 million decrease arising from non-cash mark-to-market losses associated with the risk management program implemented in 2014 at the Empress operations and
a $15 million decrease in transmission revenues due to lower interruptible transmission revenues and lower tolls charged to customers at M&N Canada, partially offset by
a $39 million increase from settlement gains associated with the risk management program at the Empress operations and
a $9 million increase in gathering and processing revenues due primarily to higher volumes.
Natural Gas and Petroleum Products Purchased. The $173 million decrease was driven by:
a $131 million decrease due primarily to lower volumes of natural gas purchases for extraction and make-up at the Empress operations,
a $37 million decrease primarily as a result of lower costs of sales at the Empress facility and
an $11 million decrease resulting from a weaker Canadian dollar.
Operating, Maintenance and Other. The $33 million decrease was driven by:
a $39 million decrease resulting from a weaker Canadian dollar,
a $12 million decrease primarily in costs passed through to customers at M&N Canada and
a $6 million decrease in plant turnaround costs, partially offset by
an $11 million increase due to overhead reduction costs.
Other Income and Expenses. The $3 million increase was driven primarily by higher earnings from equity investments.

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Table of Contents


Field Services
 
Three Months
Ended June 30,
 
Six Months
Ended June 30,
 
2015
 
2014
 
Increase (Decrease)
 
2015
 
2014
 
Increase (Decrease)
 
(in millions, except where noted)
Earnings (loss) from equity investments
$
(233
)
 
$
54

 
$
(287
)
 
$
(250
)
 
$
184

 
$
(434
)
EBITDA
$
(233
)
 
$
54

 
$
(287
)
 
$
(250
)
 
$
184

 
$
(434
)
Natural gas gathered and processed/transported, TBtu/d (a,b)
7.0

 
7.3

 
(0.3
)
 
7.1

 
7.2

 
(0.1
)
NGL production, MBbl/d (a)
408

 
452

 
(44
)
 
404

 
449

 
(45
)
Average natural gas price per MMBtu (c,d)
$
2.64

 
$
4.67

 
$
(2.03
)
 
$
2.81

 
$
4.80

 
$
(1.99
)
Average NGL price per gallon (e)
$
0.48

 
$
0.93

 
$
(0.45
)
 
$
0.48

 
$
1.00

 
$
(0.52
)
Average crude oil price per barrel (f)
$
57.94

 
$
102.99

 
$
(45.05
)
 
$
53.29

 
$
100.84

 
$
(47.55
)
___________
(a)
Reflects 100% of volumes.
(b)
Trillion British thermal units per day.
(c)
Average price based on NYMEX Henry Hub.
(d)
Million British thermal units.
(e)
Does not reflect results of commodity hedges.
(f)
Average price based on NYMEX calendar month.

Three Months Ended June 30, 2015 Compared to Same Period in 2014
EBITDA. Lower equity earnings of $287 million were mainly the result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:
a $194 million decrease due to an impairment of goodwill at DCP Midstream. This impairment was due to the significant downturn in commodity prices over the past three quarters, including further deterioration in the second quarter of 2015,
a $120 million decrease from commodity-sensitive processing arrangements, due to decreased NGL, crude oil and natural gas prices,
a $12 million decrease primarily as a result of a loss on the sale of Field Services’ interest in its Benedum processing plant and gathering system and
a $9 million decrease in gains associated with the issuance of partnership units by DCP Partners in 2015 compared to 2014, partially offset by
a $26 million increase in gathering and processing margins as a result of asset growth and higher volumes in certain of our geographic regions,
a $16 million increase as a result of DCP Partners’ favorable results from third-party mark-to-market on derivative instruments used to mitigate a portion of its expected commodity cash flow risk and favorable results from the Sand Hills and Front Range Pipeline LLC (Front Range) NGL pipelines and
a $16 million increase primarily attributable to lower operating expenses as a result of improved operating efficiencies and other initiatives.
Six Months Ended June 30, 2015 Compared to Same Period in 2014
EBITDA. Lower equity earnings of $434 million were mainly the result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:
a $248 million decrease from commodity-sensitive processing arrangements, due to decreased NGL, crude oil and natural gas prices,
a $194 million decrease due to an impairment of goodwill at DCP Midstream. This impairment was due to the significant downturn in commodity prices over the past three quarters, including further deterioration in the second quarter of 2015,

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a $55 million decrease in gains associated with the issuance of partnership units by DCP Partners in 2015 compared to 2014 and
an $8 million decrease primarily as a result of a loss on the sale of Field Services’ interest in its Benedum processing plant and gathering system offset by a gain on sale of its interest in Dover-Hennessey, partially offset by
a $47 million increase in gathering and processing margins as a result of asset growth and higher volumes in certain of our geographic regions,
a $21 million increase primarily attributable lower operating expenses as a result of cost savings initiatives in operations and
a $12 million increase as a result of DCP Partners’ favorable results from third-party mark-to-market on derivative instruments used to mitigate a portion of its expected commodity cash flow risk and favorable results from the Sand Hills and Front Range NGL pipelines.
Other
 
Three Months
Ended June 30,
 
Six Months
Ended June 30,
 
2015
 
2014
 
Increase (Decrease)
 
2015
 
2014
 
Increase (Decrease)
 
(in millions)
Operating revenues
$
17

 
$
19

 
$
(2
)
 
$
35

 
$
37

 
$
(2
)
Operating expenses
 
 


 
 
 
 
 
 
 
 
        Operating, maintenance and other
30

 
43

 
(13
)
 
62

 
81

 
(19
)
Other income and expenses
1

 

 
1

 

 
3

 
(3
)
EBITDA
$
(12
)
 
$
(24
)
 
$
12

 
$
(27
)
 
$
(41
)
 
$
14


Three and Six Months Ended June 30, 2015 Compared to Same Periods in 2014
EBITDA. Both the $12 million and $14 million increases, respectively, reflect lower employee benefit costs.
Impairment of Goodwill
As permitted under accounting guidance on testing goodwill for impairment, we perform either a qualitative assessment or a quantitative assessment of each of our reporting units based on management’s judgment. With respect to our qualitative assessments, we consider events and circumstances specific to us, such as macroeconomic conditions, industry and market considerations, cost factors and overall financial performance, when evaluating whether it is more likely than not that the fair values of our reporting units are less than their respective carrying amounts.

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

We performed either a quantitative assessment or a qualitative assessment for all of our reporting units to determine whether it is more likely than not that the respective fair values of these reporting units are less than their carrying amounts, including goodwill as of April 1, 2015 (our annual testing date). Based on the results of our annual goodwill impairment testing, no indicators of impairment were noted and the fair values of the reporting units that we assessed at April 1, 2015 were substantially in excess of their respective carrying values, except for BC Field Services.

Our BC Field Services business is comprised of gathering and processing assets that, while fee based, can see volumetric impacts over the long term due to changes in commodity prices, specifically natural gas prices. Upon completion of our testing, it was determined that BC Field Services reporting unit’s fair value exceeded its carrying value by 9%. The BC Field Services reporting unit has been assigned $292 million of our total goodwill. In our quantitative assessments, our cash flow forecasts were updated to reflect the impact of the recently announced overhead reductions at Western Canada Transmission & Processing. We believe the assumptions used in our analyses are appropriate and result in reasonable estimates of the fair

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values of our reporting units. However, the assumptions used are subject to uncertainty, and declines in the future performance or cash flows of our reporting units, changing business conditions, further sustained declines in commodity prices or increases to our weighted average cost of capital assumptions may result in the recognition of impairment charges, which could be significant.

Certain commodity prices, specifically NGL prices, have fluctuated throughout 2014 and 2015 and are lower, on average, than historical levels. Our Empress NGL reporting unit is significantly affected by fluctuations in NGL commodity prices. Results of our April 1, 2015 quantitative assessment determined that Empress NGL reporting unit’s fair value was substantially in excess of carrying value. Additionally, we have a commodity hedging program at Empress which economically hedges a significant portion of their NGL sales and related make-up gas purchases, which mitigates the effects of short-term commodity price fluctuations. However, should realized NGL prices decline significantly from recent levels for a sustained period, this could result in a triggering event that would warrant testing for the impairment of goodwill relating to the Empress NGL reporting unit, which could result in an impairment.

Due to the significant downturn in commodity prices over the past three quarters, including further deterioration in the second quarter of 2015, DCP Midstream determined it was more likely than not the estimated fair values of certain of its goodwill reporting units and certain of DCP Midstream Partners, LP (DCP Partners) goodwill reporting units were below their carrying amount, and performed a goodwill impairment test. The impairment test was based on an internal discounted cash flow model taking into account various observable and non-observable factors, such as prices, volumes, expenses and discount rate. The impairment test resulted in DCP Midstream’s recognition of a $427 million goodwill impairment during the second quarter of 2015, which reduced our equity earnings from DCP Midstream by $122 million after-tax. This impairment represents DCP Midstream’s best estimate pending finalization of the fair value assessments. Due to the impairment of goodwill recognized by DCP Midstream, we assessed our equity investment in DCP Midstream and determined that no indicators of impairment were noted.

No triggering events have occurred with our reporting units since the April 1, 2015 test that would warrant re-testing for goodwill impairment.
LIQUIDITY AND CAPITAL RESOURCES
As of June 30, 2015, we had negative working capital of $1,400 million. This balance includes commercial paper liabilities totaling $535 million and current maturities of long-term debt of $917 million. We will rely upon cash flows from operations and various financing transactions, which may include debt and/or equity issuances, to fund our liquidity and capital requirements for the next 12 months. SEP is expected to be self-funding through its cash flows from operations, use of its revolving credit facility and its access to capital markets. We receive cash distributions from SEP in accordance with the partnership agreement, which considers our level of ownership and incentive distribution rights.
As of June 30, 2015, our revolving credit facilities included Spectra Capital’s $1.0 billion facility, SEP’s $2.0 billion facility, Westcoast’s 400 million Canadian dollar facility and Union Gas’ 500 million Canadian dollar facility, with available capacity of $1,962 million under SEP’s credit facility and $1,223 million under our other subsidiaries’ credit facilities. These facilities are used principally as back-stops for commercial paper programs. At Spectra Capital, SEP and Westcoast, we primarily use commercial paper for temporary funding of capital expenditures. At Union Gas, we primarily use commercial paper to support short-term working capital fluctuations. We also utilize commercial paper, other variable-rate debt and interest rate swaps to achieve our desired mix of fixed and variable-rate debt. See Note 11 of Notes to Condensed Consolidated Financial Statements for a discussion of available credit facilities and Financing Cash Flows and Liquidity for a discussion of effective shelf registrations.

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Cash Flow Analysis
The following table summarizes the changes in cash flows for each of the periods presented:
 
Six Months
Ended June 30,
 
2015
 
2014
Net cash provided by (used in):
(in millions)
Operating activities
$
1,456

 
$
1,209

Investing activities
(976
)
 
(612
)
Financing activities
(406
)
 
(499
)
Effect of exchange rate changes on cash
(2
)
 
1

Net increase in cash and cash equivalents
72

 
99

Cash and cash equivalents at beginning of the period
215

 
201

Cash and cash equivalents at end of the period
$
287

 
$
300


Operating Cash Flows
Net cash provided by operating activities increased $247 million to $1,456 million in the six months ended June 30, 2015 compared to the same period in 2014, driven mostly by changes in working capital, partially offset by lower earnings.
 
Investing Cash Flows
Net cash used in investing activities increased $364 million to $976 million in the six months ended June 30, 2015 compared to the same period in 2014. This change was driven by:
a $160 million net increase in capital and investment expenditures and
a $207 million decrease in distributions received from unconsolidated affiliates, comprised mostly of a 2014 distribution from SESH with proceeds from a SESH debt offering.
 
 
Six Months
Ended June 30,
 
 
2015
 
2014
Capital and Investment Expenditures
 
(in millions)
Spectra Energy Partners (a)
 
$
638

 
$
444

Distribution
 
207

 
131

Western Canada Transmission & Processing
 
149

 
270

Total reportable segments
 
994

 
845

Other
 
29

 
18

Total consolidated
 
$
1,023

 
$
863

_______________________
(a) Excludes reimbursements from noncontrolling interest of $58 million in 2015.
Capital and investment expenditures for the six months ended June 30, 2015 consisted of $760 million for expansion projects and $263 million for maintenance.
We project 2015 capital and investment expenditures of approximately $3.5 billion, consisting of approximately $2.5 billion for Spectra Energy Partners, $0.6 billion for Distribution and $0.4 billion for Western Canada Transmission & Processing. Total projected 2015 capital and investment expenditures include approximately $2.8 billion of expansion capital expenditures and $0.7 billion for maintenance and upgrades of existing plants, pipelines and infrastructure to serve growth.

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Financing Cash Flows and Liquidity
Net cash used in financing activities decreased $93 million to $406 million for the six months ended June 30, 2015 compared to the same period in 2014. This change was driven by:
a $979 million increase in net proceeds from long term debt, primarily due to the issuance of SEP long-term debt in 2015, which was used primarily to pay down $774 million of commercial paper and
$32 million from Duke Energy for a 7.5% equity share in Sabal Trail Transmission, LLC, included in contributions from noncontrolling interest, partially offset by
a $54 million decrease in contributions from noncontrolling interest and
a $46 million increase in dividends paid on common stock.

On March 12, 2015, SEP issued $500 million of 3.50% unsecured notes due 2025 and $500 million of 4.50% unsecured notes due 2045. Net proceeds from the offering were used to repay a portion of outstanding commercial paper, to fund capital expenditures and for general corporate purposes.
During the six months ended June 30, 2015, SEP issued 3.6 million common units to the public under its at-the-market program and approximately 74,000 general partner units to Spectra Energy. Total net proceeds to SEP were $184 million (net proceeds to Spectra Energy were $180 million). The net proceeds were used for SEP’s general partnership purposes, which may have included debt repayments, capital expenditures and/or additions to working capital. In 2015, SEP has issued 7.2 million common units to the public and 147,000 general partner units to Spectra Energy, for total net proceeds to SEP of $353 million (net proceeds to Spectra Energy were $346 million).
Available Credit Facilities and Restrictive Debt Covenants. See Note 11 of Notes to Condensed Consolidated Financial Statements for a discussion of available credit facilities and related financial and other covenants.
The terms of our Spectra Capital credit agreement and term loan require our consolidated debt-to-total-capitalization ratio, as defined in the agreements, to be 65% or lower. Per the terms of the agreements, collateralized debt is excluded from the calculation of the ratio. As of June 30, 2015, this ratio was 58%. Our equity and, as a result, this ratio, is sensitive to significant movements of the Canadian dollar relative to the U.S. dollar due to the significance of our Canadian operations. Based on the strength of our total capitalization as of June 30, 2015, however, it is not likely 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 $0.14 per share, per year, through 2017. 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 $0.37 per common share on July 7, 2015 payable on September 9, 2015 to shareholders at close of business on August 12, 2015.
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. SEP has an effective shelf registration statement on file with the SEC to register the issuance of unspecified amounts of limited partner common units. SEP also has $357 million available as of June 30, 2015 for the issuance of limited partner common units under another effective shelf registration statement on file with the SEC related to its at-the-market program. Westcoast and Union Gas have an aggregate 2.5 billion Canadian dollars (approximately $2.0 billion) available as of June 30, 2015 for the issuance of debt securities in the Canadian market under debt shelf prospectuses.

OTHER ISSUES
New Accounting Pronouncements. See Note 19 of Notes to Condensed Consolidated Financial Statements for discussion.
Item 3.
Quantitative and Qualitative Disclosures about Market Risk.
Our exposure to market risk is described in Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2014. We believe our exposure to market risk has not changed materially since then.

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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 Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2015, and based upon this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended June 30, 2015 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1.
Legal Proceedings.
We have no material pending legal proceedings that are required to be disclosed hereunder. For information regarding other legal proceedings, including regulatory and environmental matters, see Notes 3 and 14 of Notes to Condensed Consolidated Financial Statements, which information is incorporated by reference into this Part II.
Item 1A.
Risk Factors.
In addition to the other information set forth in this report, careful consideration should be given to the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2014 which could materially affect our financial condition or future results. There have been no material changes to those risk factors.
Item 6.
Exhibits.
Any agreements included as exhibits to this Form 10-Q may contain representations and warranties by each of the parties to the applicable agreement. These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and:
were not intended to be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;
may have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement;
may apply contract standards of “materiality” that are different from “materiality” under the applicable securities laws; and
were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement.
We acknowledge that, notwithstanding the inclusion of the foregoing cautionary statements, we are responsible for considering whether additional specific disclosures of material information regarding material contractual provisions are required to make the statements in this Form 10-Q not misleading.

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(a) Exhibits
Exhibit
Number
 
 
 
 
 
  *31.1
 
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
  *31.2
 
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
  *32.1
 
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
  *32.2
 
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
*101.INS
 
XBRL Instance Document.
 
 
*101.SCH
 
XBRL Taxonomy Extension Schema.
 
 
*101.CAL
 
XBRL Taxonomy Extension Calculation Linkbase.
 
 
*101.DEF
 
XBRL Taxonomy Extension Definition Linkbase.
 
 
*101.LAB
 
XBRL Taxonomy Extension Label Linkbase.
 
 
*101.PRE
 
XBRL Taxonomy Extension Presentation Linkbase.
 
 
 
*
Filed herewith.
The total amount of securities of the registrant or its subsidiaries authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10% of the total assets of the registrant and its subsidiaries on a consolidated basis. The registrant agrees, upon request of the Securities and Exchange Commission, to furnish copies of any or all of such instruments to it.

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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SPECTRA ENERGY CORP
 
 
 
 
Date: August 6, 2015
 
 
 
 
 
/s/    Gregory L. Ebel    
 
 
 
 
 
 
Gregory L. Ebel
 
 
 
 
 
 
President and Chief Executive Officer
 
 
 
 
Date: August 6, 2015
 
 
 
 
 
/s/    J. Patrick Reddy        
 
 
 
 
 
 
J. Patrick Reddy
 
 
 
 
 
 
Chief Financial Officer

47