10-Q
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 September 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 September 30, 2015: 671,410,743
 
 
 
 
 

Table of Contents


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


2
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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
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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 September 30,
 
Nine Months
Ended September 30,
 
2015
 
2014
 
2015
 
2014
Operating Revenues
 
 
 
 
 
 
 
Transportation, storage and processing of natural gas
$
781

 
$
789

 
$
2,425

 
$
2,456

Distribution of natural gas
160

 
205

 
1,005

 
1,140

Sales of natural gas liquids
41

 
81

 
138

 
308

Transportation of crude oil
93

 
77

 
267

 
218

Other
28

 
55

 
83

 
181

Total operating revenues
1,103

 
1,207

 
3,918

 
4,303

Operating Expenses
 
 
 
 
 
 
 
Natural gas and petroleum products purchased
76

 
135

 
627

 
872

Operating, maintenance and other
364

 
404

 
1,107

 
1,172

Depreciation and amortization
188

 
201

 
574

 
600

Property and other taxes
86

 
85

 
274

 
300

Total operating expenses
714

 
825

 
2,582

 
2,944

Operating Income
389

 
382

 
1,336

 
1,359

Other Income and Expenses
 
 
 
 
 
 
 
Earnings (loss) from equity investments
48

 
91

 
(117
)
 
337

Other income and expenses, net
31

 
24

 
73

 
39

Total other income and expenses
79

 
115

 
(44
)
 
376

Interest Expense
155

 
167

 
480

 
521

Earnings Before Income Taxes
313

 
330

 
812

 
1,214

Income Tax Expense
70

 
76

 
164

 
305

Net Income
243

 
254

 
648

 
909

Net Income—Noncontrolling Interests
69

 
53

 
189

 
143

Net Income—Controlling Interests
$
174

 
$
201

 
$
459

 
$
766

Common Stock Data
 
 
 
 
 
 
 
Weighted-average shares outstanding
 
 
 
 
 
 
 
Basic
671

 
671

 
671

 
671

Diluted
672

 
673

 
672

 
672

Earnings per share
 
 
 
 
 
 
 
Basic and diluted
$
0.26

 
$
0.30

 
$
0.68

 
$
1.14

Dividends per share
$
0.37

 
$
0.335

 
$
1.11

 
$
1.005


See Notes to Condensed Consolidated Financial Statements.
4
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SPECTRA ENERGY CORP
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
(In millions)
 
 
Three Months
Ended September 30,
 
Nine Months
Ended September 30,
 
2015
 
2014
 
2015
 
2014
Net Income
$
243

 
$
254

 
$
648

 
$
909

Other comprehensive income (loss):
 
 
 
 
 
 
 
Foreign currency translation adjustments
(350
)
 
(304
)
 
(755
)
 
(329
)
Non-cash mark-to-market net gain on hedges
—

 
—

 
—

 
3

Reclassification of cash flow hedges into earnings
—

 
2

 
—

 
5

Pension and benefits impact (net of taxes of $3, $3, $8 and $9, respectively)
6

 
6

 
19

 
19

Other
1

 
—

 
1

 
—

Total other comprehensive income (loss)
(343
)
 
(296
)
 
(735
)
 
(302
)
Total Comprehensive Income (Loss), net of tax
(100
)
 
(42
)
 
(87
)
 
607

Less: Comprehensive Income—Noncontrolling Interests
64

 
50

 
178

 
139

Comprehensive Income (Loss)—Controlling Interests
$
(164
)
 
$
(92
)
 
$
(265
)
 
$
468


See Notes to Condensed Consolidated Financial Statements.
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SPECTRA ENERGY CORP
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)
 
 
September 30,
2015
 
December 31,
2014
ASSETS
 
 
 
 
 
 
 
Current Assets
 
 
 
Cash and cash equivalents
$
338

 
$
215

Receivables, net
842

 
1,336

Inventory
344

 
313

Fuel tracker
56

 
102

Other
259

 
366

Total current assets
1,839

 
2,332

 
 
 
 
Investments and Other Assets
 
 
 
Investments in and loans to unconsolidated affiliates
2,741

 
2,966

Goodwill
4,534

 
4,714

Other
338

 
327

Total investments and other assets
7,613

 
8,007

 
 
 
 
Property, Plant and Equipment
 
 
 
Cost
29,303

 
29,211

Less accumulated depreciation and amortization
6,865

 
6,904

Net property, plant and equipment
22,438

 
22,307

 
 
 
 
Regulatory Assets and Deferred Debits
1,369

 
1,394

 
 
 
 
Total Assets
$
33,259

 
$
34,040


See Notes to Condensed Consolidated Financial Statements.
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SPECTRA ENERGY CORP
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions, except per-share amounts)
 
 
September 30,
2015
 
December 31,
2014
LIABILITIES AND EQUITY
 
 
 
 
 
 
 
Current Liabilities
 
 
 
Accounts payable
$
648

 
$
458

Commercial paper
577

 
1,583

Taxes accrued
82

 
91

Interest accrued
141

 
181

Current maturities of long-term debt
766

 
327

Other
1,193

 
1,169

Total current liabilities
3,407

 
3,809

 
 
 
 
Long-term Debt
12,898

 
12,769

 
 
 
 
Deferred Credits and Other Liabilities
 
 
 
Deferred income taxes
5,479

 
5,405

Regulatory and other
1,286

 
1,401

Total deferred credits and other liabilities
6,765

 
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 September 30, 2015 and December 31, 2014
1

 
1

Additional paid-in capital
5,024

 
4,956

Retained earnings
2,253

 
2,541

Accumulated other comprehensive income (loss)
(62
)
 
662

Total controlling interests
7,216

 
8,160

Noncontrolling interests
2,715

 
2,238

Total equity
9,931

 
10,398

 
 
 
 
Total Liabilities and Equity
$
33,259

 
$
34,040


See Notes to Condensed Consolidated Financial Statements.
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SPECTRA ENERGY CORP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In millions)
 
 
Nine Months
Ended September 30,
 
2015
 
2014
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net income
$
648

 
$
909

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization
584

 
610

Deferred income tax expense
78

 
283

(Earnings) loss from equity investments
117

 
(337
)
Distributions received from unconsolidated affiliates
145

 
280

Other
251

 
(199
)
Net cash provided by operating activities
1,823

 
1,546

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Capital expenditures
(1,817
)
 
(1,429
)
Investments in and loans to unconsolidated affiliates
(91
)
 
(229
)
Purchases of held-to-maturity securities
(463
)
 
(584
)
Proceeds from sales and maturities of held-to-maturity securities
457

 
576

Purchases of available-for-sale securities
—

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

 
7

Distributions received from unconsolidated affiliates
441

 
252

Other changes in restricted funds
(24
)
 
(1
)
Other
(7
)
 
—

Net cash used in investing activities
(1,503
)
 
(1,421
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Proceeds from the issuance of long-term debt
1,332

 
1,028

Payments for the redemption of long-term debt
(153
)
 
(1,145
)
Net increase (decrease) in commercial paper
(984
)
 
393

Distributions to noncontrolling interests
(140
)
 
(128
)
Contributions from noncontrolling interests
164

 
139

Proceeds from the issuances of Spectra Energy Partners, LP common units
351

 
277

Dividends paid on common stock
(747
)
 
(677
)
Other
(14
)
 
11

Net cash used in financing activities
(191
)
 
(102
)
Effect of exchange rate changes on cash
(6
)
 
(3
)
Net increase in cash and cash equivalents
123

 
20

Cash and cash equivalents at beginning of period
215

 
201

Cash and cash equivalents at end of period
$
338

 
$
221

Supplemental Disclosures
 
 
 
Property, plant and equipment non-cash accruals
$
276

 
$
125


See Notes to Condensed Consolidated Financial Statements.
8
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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
—

 
—

 
459

 
—

 
—

 
189

 
648

Other comprehensive income (loss)
—

 
—

 
—

 
(744
)
 
20

 
(11
)
 
(735
)
Dividends on common stock
—

 
—

 
(747
)
 
—

 
—

 
—

 
(747
)
Stock-based compensation
—

 
14

 
—

 
—

 
—

 
—

 
14

Distributions to noncontrolling interests
—

 
—

 
—

 
—

 
—

 
(142
)
 
(142
)
Contributions from noncontrolling interests
—

 
—

 
—

 
—

 
—

 
164

 
164

Spectra Energy common stock issued
—

 
2

 
—

 
—

 
—

 
—

 
2

Spectra Energy Partners, LP common units issued
—

 
49

 
—

 
—

 
—

 
281

 
330

Other, net
—

 
3

 
—

 
—

 
—

 
(4
)
 
(1
)
September 30, 2015
$
1

 
$
5,024

 
$
2,253

 
$
272

 
$
(334
)
 
$
2,715

 
$
9,931

 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2013
$
1

 
$
4,869

 
$
2,383

 
$
1,557

 
$
(316
)
 
$
1,829

 
$
10,323

Net income
—

 
—

 
766

 
—

 
—

 
143

 
909

Other comprehensive income (loss)
—

 
—

 
—

 
(325
)
 
27

 
(4
)
 
(302
)
Dividends on common stock
—

 
—

 
(676
)
 
—

 
—

 
—

 
(676
)
Stock-based compensation
—

 
10

 
—

 
—

 
—

 
—

 
10

Distributions to noncontrolling interests
—

 
—

 
—

 
—

 
—

 
(128
)
 
(128
)
Contributions from noncontrolling interests
—

 
—

 
—

 
—

 
—

 
139

 
139

Spectra Energy common stock issued
—

 
10

 
—

 
—

 
—

 
—

 
10

Spectra Energy Partners, LP common units issued
—

 
43

 
—

 
—

 
—

 
206

 
249

Transfer of interests in subsidiaries to Spectra Energy Partners, LP
—

 
—

 
—

 
—

 
—

 
(2
)
 
(2
)
Other, net
—

 
7

 
—

 
—

 
—

 
(1
)
 
6

September 30, 2014
$
1

 
$
4,939

 
$
2,473

 
$
1,232

 
$
(289
)
 
$
2,182

 
$
10,538


See Notes to Condensed Consolidated Financial Statements.
9
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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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, 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 September 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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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 September 30, 2015
 
 
 
 
 
 
 
 
 
Spectra Energy Partners
$
612

 
$
—

 
$
612

 
$
74

 
$
488

Distribution
209

 
—

 
209

 
43

 
70

Western Canada Transmission & Processing
279

 
9

 
288

 
59

 
117

Field Services
—

 
—

 
—

 
—

 
(3
)
Total reportable segments
1,100

 
9

 
1,109

 
176

 
672

Other
3

 
16

 
19

 
12

 
(12
)
Eliminations
—

 
(25
)
 
(25
)
 
—

 
—

Depreciation and amortization
—

 
—

 
—

 
—

 
188

Interest expense
—

 
—

 
—

 
—

 
155

Interest income and other (a)
—

 
—

 
—

 
—

 
(4
)
Total consolidated
$
1,103

 
$
—

 
$
1,103

 
$
188

 
$
313

 
 
 
 
 
 
 
 
 
 
Three Months Ended September 30, 2014
 
 
 
 
 
 
 
 
 
Spectra Energy Partners
$
558

 
$
—

 
$
558

 
$
73

 
$
422

Distribution
260

 
—

 
260

 
49

 
82

Western Canada Transmission & Processing
387

 
30

 
417

 
69

 
156

Field Services
—

 
—

 
—

 
—

 
51

Total reportable segments
1,205

 
30

 
1,235

 
191

 
711

Other
2

 
15

 
17

 
10

 
(19
)
Eliminations
—

 
(45
)
 
(45
)
 
—

 
—

Depreciation and amortization
—

 
—

 
—

 
—

 
201

Interest expense
—

 
—

 
—

 
—

 
167

Interest income and other (a)
—

 
—

 
—

 
—

 
6

Total consolidated
$
1,207

 
$
—

 
$
1,207

 
$
201

 
$
330

 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2015
 
 
 
 
 
 
 
 
 
Spectra Energy Partners
$
1,821

 
$
—

 
$
1,821

 
$
220

 
$
1,421

Distribution
1,161

 
—

 
1,161

 
133

 
360

Western Canada Transmission & Processing
929

 
33

 
962

 
184

 
382

Field Services
—

 
—

 
—

 
—

 
(253
)
Total reportable segments
3,911

 
33

 
3,944

 
537

 
1,910

Other
7

 
47

 
54

 
37

 
(39
)
Eliminations
—

 
(80
)
 
(80
)
 
—

 
—

Depreciation and amortization
—

 
—

 
—

 
—

 
574

Interest expense
—

 
—

 
—

 
—

 
480

Interest income and other (a)
—

 
—

 
—

 
—

 
(5
)
Total consolidated
$
3,918

 
$
—

 
$
3,918

 
$
574

 
$
812

 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2014
 
 
 
 
 
 
 
 
 
Spectra Energy Partners
$
1,670

 
$
—

 
$
1,670

 
$
218

 
$
1,225

Distribution
1,338

 
—

 
1,338

 
146

 
420

Western Canada Transmission & Processing
1,288

 
95

 
1,383

 
204

 
504

Field Services
—

 
—

 
—

 
—

 
235

Total reportable segments
4,296

 
95

 
4,391

 
568

 
2,384

Other
7

 
47

 
54

 
32

 
(60
)
Eliminations
—

 
(142
)
 
(142
)
 
—

 
—

Depreciation and amortization
—

 
—

 
—

 
—

 
600

Interest expense
—

 
—

 
—

 
—

 
521

Interest income and other (a)
—

 
—

 
—

 
—

 
11

Total consolidated
$
4,303

 
$
—

 
$
4,303

 
$
600

 
$
1,214

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

12
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3. Regulatory Matters

Union Gas. In December 2014, Union Gas filed an application with the OEB for the disposition of the 2013 energy conservation deferral and variance account balances. In June 2015, a decision from the OEB was received approving recovery from ratepayers of approximately $8 million effective July 1, 2015.
4. Income Taxes

Income tax expense was $70 million for the three months ended September 30, 2015, compared to $76 million for the same period in 2014. Income tax expense was $164 million for the nine months ended September 30, 2015, compared to $305 million for the same period in 2014. The lower tax expense for the nine months ended September 30, 2015 was primarily attributable to the $74 million tax impact of the loss on investment due to the partial impairment of goodwill at DCP Midstream, lower earnings and the effect of a weaker Canadian dollar.

The effective income tax rate was 22% for the three months ended September 30, 2015 compared to 23% for the same period in 2014. The effective income tax rate was 20% for the nine months ended September 30, 2015, compared to 25% for the same period in 2014. The lower effective income tax rate for the nine months ended September 30, 2015 was primarily attributable to the $74 million tax impact of the loss on investment due to the partial impairment of goodwill at DCP Midstream.

There was a $5 million increase in unrecognized tax benefits recorded during the nine months ended September 30, 2015. Although uncertain, we believe it is reasonably possible that the total amount of unrecognized tax benefits could decrease by approximately $15 million to $20 million prior to September 30, 2016.
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 September 30,
 
Nine Months
Ended September 30,
 
 
 
2015
 
2014
 
2015
 
2014
 
 
 
(in millions, except per-share amounts)
Net income—controlling interests
$
174

 
$
201

 
$
459

 
$
766

Weighted-average common shares outstanding
 
 
 
 

 
 
Basic
671

 
671

 
671

 
671

Diluted
672

 
673

 
672

 
672

Basic and diluted earnings per common share (a)
$
0.26

 
$
0.30

 
$
0.68

 
$
1.14

___________________
(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)
 
 
 
June 30, 2015
$
617

 
$
(338
)
 
$
—

 
$
(3
)
 
$
276

Other AOCI activity
(345
)
 
6

 
—

 
1

 
(338
)
September 30, 2015
$
272

 
$
(332
)
 
$
—

 
$
(2
)
 
$
(62
)
 
 
 
 
 
 
 
 
 
 
June 30, 2014
$
1,533

 
$
(291
)
 
$
(6
)
 
$
—

 
$
1,236

Reclassified to net income
—

 
—

 
2

 
—

 
2

Other AOCI activity
(301
)
 
6

 
—

 
—

 
(295
)
September 30, 2014
$
1,232

 
$
(285
)
 
$
(4
)
 
$
—

 
$
943

 
 
 
 
 
 
 
 
 
 
December 31, 2014
$
1,016

 
$
(351
)
 
$
(3
)
 
$
—

 
$
662

Other AOCI activity
(744
)
 
19

 
3

 
(2
)
 
(724
)
September 30, 2015
$
272

 
$
(332
)
 
$
—

 
$
(2
)
 
$
(62
)
 
 
 
 
 
 
 
 
 
 
December 31, 2013
$
1,557

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

Reclassified to net income
—

 
—

 
4

 
1

 
5

Other AOCI activity
(325
)
 
19

 
3

 
—

 
(303
)
September 30, 2014
$
1,232

 
$
(285
)
 
$
(4
)
 
$
—

 
$
943


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:
 
September 30,
2015
 
December 31,
2014
 
(in millions)
Natural gas
$
226

 
$
211

NGLs
49

 
28

Materials and supplies
69

 
74

Total inventory
$
344

 
$
313


Non-cash charges totaling $8 million in 2015 ($6 million after tax) and $19 million in 2014 ($14 million after tax) were recorded to Natural Gas and Petroleum Products Purchased on the Condensed Consolidated Statements of Operations to reduce propane inventory at our Empress operations at Western Canada Transmission & Processing to estimated net realizable value.

14
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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 September 30,
 
Nine Months
Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions)
Operating revenues
$
1,851

 
$
3,480

 
$
5,763

 
$
10,936

Operating expenses
1,794

 
3,281

 
6,117

 
10,313

Operating income (loss)
57

 
199

 
(354
)
 
623

Net income (loss)
25

 
154

 
(472
)
 
449

Net income (loss) attributable to members’ interests
(6
)
 
81

 
(509
)
 
335


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 $11 million in the third quarter of 2014, and $2 million and $68 million during the nine month periods ending September 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, DCP Midstream performed a goodwill impairment test which was finalized in the third quarter of 2015. 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 $460 million goodwill impairment, which reduced our equity earnings from DCP Midstream by $123 million after-tax for the nine month period ending September 30, 2015.

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

Related Party Transaction

During the third quarter of 2015, Gulfstream Natural Gas System, LLC (Gulfstream) issued unsecured debt of $800 million to fund the repayment of its current debt. Gulfstream distributed $396 million of proceeds to us, which we will contribute back to Gulfstream as its current debt matures, $248 million in the fourth quarter of 2015 and the remaining $148 million in the first half of 2016. At September 30, 2015, our Condensed Consolidated Balance Sheets include $396 million in Current Liabilities—Other related to this matter.

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.


15
Table of Contents


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 and concluded that there was no impairment of goodwill for either business unit.

See Note 8 for discussion related to the partial impairment of goodwill recognized by DCP Midstream.
10. Marketable Securities and Restricted Funds

We routinely invest excess cash and various restricted balances in securities such as commercial paper, bankers acceptances, corporate debt securities, treasury bills and money market funds in the 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
 
September 30,
2015
 
December 31, 2014
 
(in millions)
Corporate debt securities
$
20

 
$
23

Money market funds
—

 
1

Total available-for-sale securities
$
20

 
$
24


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

 
$
1

Non-restricted funds
 
 
 
Current assets—other
14

 
3

Investments and other assets—other
6

 
20

Total available-for-sale securities
$
20

 
$
24


At September 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 September 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
September 30, 2015
 
December 31, 2014
 
 
(in millions)
Bankers acceptances
Current assets—other
$
45

 
$
38

Canadian government securities
Current assets—other
25

 
30

Money market funds
Current assets—other
11

 
3

Canadian government securities
Investments and other assets—other
76

 
101

Total held-to-maturity securities
$
157

 
$
172



16
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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 September 30, 2015.

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

There were no material gross unrecognized holding gains or losses associated with investments in HTM securities at September 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 $12 million at September 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 $29 million at September 30, 2015 and $6 million at December 31, 2014 classified as Investments and Other Assets—Other. $14 million of these restricted funds are related to funds held and collected from customers for Canadian pipeline abandonment in accordance with the NEB’s regulatory requirements and $15 million are related to certain construction projects.

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 September 30, 2015
 
Available
Credit
Facilities
Capacity
 
 
 
 
(in millions)
Spectra Energy Capital, LLC (a)
2019
 
$
1,000

 
$
568

 
$
432

SEP (b)
2019
 
2,000

 
—

 
2,000

Westcoast Energy Inc. (c)
2019
 
300

 
9

 
291

Union Gas (d)
2019
 
376

 
—

 
376

Total
 
 
$
3,676

 
$
577

 
$
3,099

 ___________
(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 September 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 September 30, 2015, this ratio was 3.4 to 1.
(c)
U.S. dollar equivalent at September 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 September 30, 2015.
(d)
U.S. dollar equivalent at September 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 66% at September 30, 2015.

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


17
Table of Contents


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 September 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 September 17, 2015, Union Gas issued 200 million Canadian dollars (approximately $152 million as of the issuance date) of 3.19% unsecured notes due 2025 and 250 million Canadian dollars (approximately $190 million as of the issuance date) of 4.20% unsecured notes due 2044. Net proceeds from the offerings were used to repay a portion of short-term debt, to fund capital expenditures and for general corporate purposes.
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.
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
September 30, 2015
Total
 
Level 1
 
Level 2
 
Level 3
 
 
(in millions)
Corporate debt securities
Cash and cash equivalents
$
251

 
$
—

 
$
251

 
$
—

Corporate debt securities
Current assets—other
14

 
—

 
14

 
—

Commodity derivatives
Current assets—other
45

 
—

 
—

 
45

Interest rate swaps
Current assets—other
1

 
—

 
1

 
—

Commodity derivatives
Investments and other assets—other
8

 
—

 
—

 
8

Corporate debt securities
Investments and other assets—other
6

 
—

 
6

 
—

Interest rate swaps
Investments and other assets—other
56

 
—

 
56

 
—

Total Assets
$
381

 
$
—

 
$
328

 
$
53



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



18
Table of Contents


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 September 30,
 
Nine Months
Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions)
Derivative assets (liabilities)
 
 
 
 
 
 
 
Fair value, beginning of period
$
50

 
$
(9
)
 
$
78

 
$
(3
)
Total gains (losses):
 
 
 
 
 
 
 
Included in earnings
18

 
7

 
27

 
(2
)
Included in other comprehensive income
(4
)
 
1

 
(9
)
 
5

Purchases
(5
)
 
—

 
(2
)
 
—

Settlements
(6
)
 
—

 
(41
)
 
(1
)
Fair value, end of period
$
53

 
$
(1
)
 
$
53

 
$
(1
)
Unrealized gains (losses) relating to instruments held at the end of the period
$
5

 
$
5

 
$
(11
)
 
$
(2
)

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 September 30, 2015 consist of NGL revenue swap contracts related to the Empress assets in Western Canada Transmission & Processing. As of September 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 September 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 $17 million. This calculated amount does not take into account any other changes to the fair value measurement calculation.


19
Table of Contents


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. 
 
September 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)
13,615

 
14,326

 
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.

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 nine months ended September 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 nine months ended September 30, 2015.

Interest Rate Swaps

At September 30, 2015, we had “pay floating—receive fixed” interest rate swaps outstanding with a total notional amount of $2,094 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:
 
September 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
$
57

 
$
—

 
$
57

 
$
24

 
$
—

 
$
24




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Commodity Derivatives

At September 30, 2015, we had commodity mark-to-market derivatives outstanding with a total notional amount of 171 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:
 
September 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
$
136


$
83


$
53

 
$
169

 
$
91

 
$
78

Liabilities
83


83


—

 
91

 
91

 
—


Substantially all of our commodity derivative agreements outstanding at September 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.

Information regarding the impacts of commodity derivatives on our Condensed Consolidated Statements of Operations are as follows:
 
 
 
 
Three Months
Ended September 30,
 
Nine Months
Ended September 30,
Derivatives
 
Condensed Consolidated Statements of Operations Caption
 
2015
 
2014
 
2015
 
2014
 
 
 
 
(in millions)
Commodity derivatives
 
Sales of natural gas liquids
 
$
13

 
$
7

 
$
25

 
$
—


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 September 30, 2015 or December 31, 2014 related to litigation.

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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 September 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 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 September 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 nine months ended September 30, 2015, SEP issued 7.3 million common units to the public under its at-the-market program and approximately 149,000 general partner units to Spectra Energy. Total net proceeds to SEP were $358 million (net proceeds to Spectra Energy were $351 million). In connection with the issuances of the units, a $78 million gain ($49 million net of tax) to Additional Paid-in Capital and a $281 million increase in Equity-Noncontrolling Interests were recorded during the nine months ended September 30, 2015. The issuances decreased Spectra Energy’s ownership in SEP from 82% to 80% at September 30, 2015.

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The following table presents the effects of the issuances of SEP units:
 
Three Months
Ended September 30,
 
Nine Months
Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
        (in millions)
Net income-controlling interests
$
174

 
$
201

 
$
459

 
$
766

Increase in additional paid-in capital resulting from issuances of SEP units
24

 
14

 
49

 
43

Total net income-controlling interests and changes in equity-controlling interests
$
198

 
$
215

 
$
508

 
$
809

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 $16 million to our U.S. retirement plans in both of the nine month periods ended September 30, 2015 and 2014. We made total contributions to the Canadian DC and DB plans of $23 million in the nine months ended September 30, 2015 and $34 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 $29 million to the Canadian plans in 2015.
Qualified and Non-Qualified Pension Plans—Components of Net Periodic Pension Cost
 
Three Months
Ended September 30,
 
Nine Months
Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
                 (in millions)
 
 
U.S.
 
 
 
 
 
 
 
Service cost benefit earned
$
4

 
$
5

 
$
14

 
$
14

Interest cost on projected benefit obligation
6

 
7

 
18

 
19

Expected return on plan assets
(10
)
 
(10
)
 
(31
)
 
(29
)
Amortization of loss
2

 
3

 
7

 
9

Net periodic pension cost
$
2

 
$
5

 
$
8

 
$
13

 
 
 
 
 
 
 
 
Canada
 
 
 
 
 
 
 
Service cost benefit earned
$
8

 
$
7

 
$
24

 
$
22

Interest cost on projected benefit obligation
11

 
13

 
33

 
39

Expected return on plan assets
(16
)
 
(17
)
 
(50
)
 
(52
)
Amortization of loss
6

 
6

 
19

 
17

Amortization of prior service cost
—

 
—

 
1

 
1

Net periodic pension cost
$
9

 
$
9

 
$
27

 
$
27


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.

23
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Other Post-Retirement Benefit Plans—Components of Net Periodic Benefit Cost 
 
Three Months
Ended September 30,
 
Nine Months
Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions)
U.S.
 
 
 
 
 
 
 
Service cost benefit earned
$
1

 
$
1

 
$
1

 
$
1

Interest cost on accumulated post-retirement benefit obligation
1

 
2

 
5

 
6

Expected return on plan assets
(1
)
 
(1
)
 
(4
)
 
(3
)
Net periodic other post-retirement benefit cost
$
1

 
$
2

 
$
2

 
$
4

 
 
 
 
 
 
 
 
Canada
 
 
 
 
 
 
 
Service cost benefit earned
$
1

 
$
1

 
$
3

 
$
3

Interest cost on accumulated post-retirement benefit obligation
1

 
1

 
3

 
4

Net periodic other post-retirement benefit cost
$
2

 
$
2

 
$
6

 
$
7

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 month periods ended September 30, 2015 and 2014 and $11 million in both of the nine month periods ended September 30, 2015 and 2014 for U.S. employees. We expensed pre-tax employer matching contributions of $2 million and $4 million in the three months ended September 30, 2015 and 2014, respectively, and $8 million and $10 million in the nine months ended September 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 September 30, 2015
 
 
 
 
 
 
 
 
 
Total operating revenues
$
—

 
$
—

 
$
1,105

 
$
(2
)
 
$
1,103

Total operating expenses
2

 
(1
)
 
715

 
(2
)
 
714

Operating income (loss)
(2
)
 
1

 
390

 
—

 
389

Earnings from equity investments
—

 
—

 
48

 
—

 
48

Equity in earnings of consolidated subsidiaries
170

 
307

 
—

 
(477
)
 
—

Other income and expenses, net
—

 
(1
)
 
32

 
—

 
31

Interest expense
—

 
61

 
94

 
—

 
155

Earnings before income taxes
168

 
246

 
376

 
(477
)
 
313

Income tax expense (benefit)
(6
)
 
76

 
—

 
—

 
70

Net income
174

 
170

 
376

 
(477
)
 
243

Net income—noncontrolling interests
—

 
—

 
69

 
—

 
69

Net income—controlling interests
$
174

 
$
170

 
$
307

 
$
(477
)
 
$
174

 
 
 
 
 
 
 
 
 
 
Three Months Ended September 30, 2014
 
 
 
 
 
 
 
 
 
Total operating revenues
—

 
—

 
1,209

 
(2
)
 
1,207

Total operating expenses
1

 
—

 
826

 
(2
)
 
825

Operating income (loss)
(1
)
 
—

 
383

 
—

 
382

Earnings from equity investments
—

 
—

 
91

 
—

 
91

Equity in earnings of consolidated subsidiaries
194

 
329

 
—

 
(523
)
 
—

Other income and expenses, net
(2
)
 
5

 
20

 
1

 
24

Interest expense
—

 
64

 
102

 
1

 
167

Earnings before income taxes
191

 
270

 
392

 
(523
)
 
330

Income tax expense (benefit)
(10
)
 
76

 
10

 
—

 
76

Net income
201

 
194

 
382

 
(523
)
 
254

Net income—noncontrolling interests
—

 
—

 
53

 
—

 
53

Net income—controlling interests
$
201

 
$
194

 
$
329

 
$
(523
)
 
$
201

 
 
 
 
 
 
 
 
 
 

25
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Spectra Energy Corp
Condensed Consolidating Statements of Operations
(Unaudited)
(In millions)

 
Spectra
Energy
Corp
 
Spectra
Capital
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Nine Months Ended September 30, 2015
 
 
 
 
 
 
 
 
 
Total operating revenues
$
—

 
$
—

 
$
3,921

 
$
(3
)
 
$
3,918

Total operating expenses
5

 
(2
)
 
2,582

 
(3
)
 
2,582

Operating income (loss)
(5
)
 
2

 
1,339

 
—

 
1,336

Loss from equity investments
—

 
—

 
(117
)
 
—

 
(117
)
Equity in earnings of consolidated subsidiaries
445

 
790

 
—

 
(1,235
)
 
—

Other income and expenses, net
—

 
(1
)
 
74

 
—

 
73

Interest expense
—

 
183

 
297

 
—

 
480

Earnings before income taxes
440

 
608

 
999

 
(1,235
)
 
812

Income tax expense (benefit)
(19
)
 
163

 
20

 
—

 
164

Net income
459

 
445

 
979

 
(1,235
)
 
648

Net income—noncontrolling interests
—

 
—

 
189

 
—

 
189

Net income—controlling interests
$
459

 
$
445

 
$
790

 
$
(1,235
)
 
$
459

 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2014
 
 
 
 
 
 
 
 
 
Total operating revenues
$
—

 
$
—

 
$
4,306

 
$
(3
)
 
$
4,303

Total operating expenses
5

 
1

 
2,941

 
(3
)
 
2,944

Operating income (loss)
(5
)
 
(1
)
 
1,365

 
—

 
1,359

Earnings from equity investments
—

 
—

 
337

 
—

 
337

Equity in earnings of consolidated subsidiaries
734

 
1,228

 
—

 
(1,962
)
 
—

Other income and expenses, net
(4
)
 
6

 
36

 
1

 
39

Interest expense
—

 
195

 
325

 
1

 
521

Earnings before income taxes
725

 
1,038

 
1,413

 
(1,962
)
 
1,214

Income tax expense (benefit)
(41
)
 
304

 
42

 
—

 
305

Net income
766

 
734

 
1,371

 
(1,962
)
 
909

Net income—noncontrolling interests
—

 
—

 
143

 
—

 
143

Net income—controlling interests
$
766

 
$
734

 
$
1,228

 
$
(1,962
)
 
$
766


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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 September 30, 2015
 
 
 
 
 
 
 
 
 
Net income
$
174

 
$
170

 
$
376

 
$
(477
)
 
$
243

Other comprehensive income (loss)
2

 
1

 
(346
)
 
—

 
(343
)
Total comprehensive income (loss), net of tax
176

 
171

 
30

 
(477
)
 
(100
)
Less: comprehensive income—noncontrolling interests
—

 
—

 
64

 
—

 
64

Comprehensive income (loss)—controlling interests
$
176

 
$
171

 
$
(34
)
 
$
(477
)
 
$
(164
)
 
 
 
 
 
 
 
 
 
 
Three Months Ended September 30, 2014
 
 
 
 
 
 
 
 
 
Net income
$
201

 
$
194

 
$
382

 
$
(523
)
 
$
254

Other comprehensive income (loss)
2

 
1

 
(299
)
 
—

 
(296
)
Total comprehensive income (loss), net of tax
203

 
195

 
83

 
(523
)
 
(42
)
Less: comprehensive income—noncontrolling interests
—

 
—

 
50

 
—

 
50

Comprehensive income (loss)—controlling interests
$
203

 
$
195

 
$
33

 
$
(523
)
 
$
(92
)
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2015
 
 
 
 
 
 
 
 
 
Net income
$
459

 
$
445

 
$
979

 
$
(1,235
)
 
$
648

Other comprehensive income (loss)
5

 
1

 
(741
)
 
—

 
(735
)
Total comprehensive income (loss), net of tax
464

 
446

 
238

 
(1,235
)
 
(87
)
Less: comprehensive income—noncontrolling interests
—

 
—

 
178

 
—

 
178

Comprehensive income (loss)—controlling interests
$
464

 
$
446

 
$
60

 
$
(1,235
)
 
$
(265
)
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2014
 
 
 
 
 
 
 
 
 
Net income
$
766

 
$
734

 
$
1,371

 
$
(1,962
)
 
$
909

Other comprehensive income (loss)
6

 
1

 
(309
)
 
—

 
(302
)
Total comprehensive income, net of tax
772

 
735

 
1,062

 
(1,962
)
 
607

Less: comprehensive income—noncontrolling interests
—

 
—

 
139

 
—

 
139

Comprehensive income—controlling interests
$
772

 
$
735

 
$
923

 
$
(1,962
)
 
$
468




27
Table of Contents


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

 
$
1

 
$
337

 
$
—

 
$
338

Receivables—consolidated subsidiaries
22

 
—

 
9

 
(31
)
 
—

Notes receivable—current—consolidated subsidiaries
—

 
—

 
388

 
(388
)
 
—

Receivables—other
2

 
—

 
840

 
—

 
842

Other current assets
4

 
1

 
654

 
—

 
659

Total current assets
28

 
2

 
2,228

 
(419
)
 
1,839

Investments in and loans to unconsolidated affiliates
—

 
—

 
2,741

 
—

 
2,741

Investments in consolidated subsidiaries
14,371

 
20,206

 
—

 
(34,577
)
 
—

Advances receivable—consolidated subsidiaries
—

 
5,221

 
1,134

 
(6,355
)
 
—

Notes receivable—consolidated subsidiaries
—

 
—

 
2,800

 
(2,800
)
 
—

Goodwill
—

 
—

 
4,534

 
—

 
4,534

Other assets
40

 
35

 
263

 
—

 
338

Net property, plant and equipment
—

 
—

 
22,438

 
—

 
22,438

Regulatory assets and deferred debits
2

 
13

 
1,354

 
—

 
1,369

Total Assets
$
14,441

 
$
25,477

 
$
37,492

 
$
(44,151
)
 
$
33,259

 
 
 
 
 
 
 
 
 
 
Accounts payable
$
4

 
$
2

 
$
642

 
$
—

 
$
648

Accounts payable—consolidated subsidiaries
—

 
31

 
—

 
(31
)
 
—

Commercial paper
—

 
568

 
9

 
—

 
577

Short-term borrowings—consolidated subsidiaries
—

 
388

 
—

 
(388
)
 
—

Taxes accrued
2

 
15

 
65

 
—

 
82

Current maturities of long-term debt
—

 
—

 
766

 
—

 
766

Other current liabilities
79

 
49

 
1,206

 
—

 
1,334

Total current liabilities
85

 
1,053

 
2,688

 
(419
)
 
3,407

Long-term debt
—

 
2,913

 
9,985

 
—

 
12,898

Advances payable—consolidated subsidiaries
6,355

 
—

 
—

 
(6,355
)
 
—

Notes payable—consolidated subsidiaries
—

 
2,800

 
—

 
(2,800
)
 
—

Deferred credits and other liabilities
785

 
4,340

 
1,640

 
—

 
6,765

Preferred stock of subsidiaries
—

 
—

 
258

 
—

 
258

Equity
 
 
 
 
 
 
 
 
 
Controlling interests
7,216

 
14,371

 
20,206

 
(34,577
)
 
7,216

Noncontrolling interests
—

 
—

 
2,715

 
—

 
2,715

Total equity
7,216

 
14,371

 
22,921

 
(34,577
)
 
9,931

Total Liabilities and Equity
$
14,441

 
$
25,477

 
$
37,492

 
$
(44,151
)
 
$
33,259




28
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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
Nine Months Ended September 30, 2015
(Unaudited)
(In millions)

 
Spectra
Energy
Corp
 
Spectra
Capital
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
 
 
 
 
 
 
Net income
$
459

 
$
445

 
$
979

 
$
(1,235
)
 
$
648

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

 
—

 
584

 
—

 
584

Loss from equity investments
—

 
—

 
117

 
—

 
117

Equity in earnings of consolidated subsidiaries
(445
)
 
(790
)
 
—

 
1,235

 
—

Distributions received from unconsolidated affiliates
—

 
—

 
145

 
—

 
145

Other
44

 
109

 
176

 
—

 
329

Net cash provided by (used in) operating activities
58

 
(236
)
 
2,001

 
—

 
1,823

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
 
 
 
 
 
 
Capital expenditures
—

 
—

 
(1,817
)
 
—

 
(1,817
)
Investments in and loans to unconsolidated
affiliates
—

 
—

 
(91
)
 
—

 
(91
)
Purchases of held-to-maturity securities
—

 
—

 
(463
)
 
—

 
(463
)
Proceeds from sales and maturities of held-to-maturity securities
—

 
—

 
457

 
—

 
457

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

 
—

 
1

 
—

 
1

Distributions received from unconsolidated
affiliates
—

 
—

 
441

 
—

 
441

Advances (to) from affiliates
(82
)
 
62

 
—

 
20

 
—

Other changes in restricted funds
—

 
—

 
(24
)
 
—

 
(24
)
Other
—

 
—

 
(7
)
 
—

 
(7
)
Net cash provided by (used in) investing activities
(82
)
 
62

 
(1,503
)
 
20

 
(1,503
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
 
 
 
 
 
 
Proceeds from the issuance of long-term debt
—

 
—

 
1,332

 
—

 
1,332

Payments for the redemption of long-term debt
—

 
—

 
(153
)
 
—

 
(153
)
Net increase (decrease) in commercial paper
—

 
170

 
(1,154
)
 
—

 
(984
)
Distributions to noncontrolling interests
—

 
—

 
(140
)
 
—

 
(140
)
Contributions from noncontrolling interests
—

 
—

 
164

 
—

 
164

Proceeds from the issuance of SEP common units
—

 
—

 
351

 
—

 
351

Dividends paid on common stock
(747
)
 
—

 
—

 
—

 
(747
)
Distributions and advances from (to) affiliates
774

 
4

 
(758
)
 
(20
)
 
—

Other
(3
)
 
—

 
(11
)
 
—

 
(14
)
Net cash provided by (used in) financing activities
24

 
174

 
(369
)
 
(20
)
 
(191
)
Effect of exchange rate changes on cash
—

 
—

 
(6
)
 
—

 
(6
)
Net increase in cash and cash equivalents
—

 
—

 
123

 
—

 
123

Cash and cash equivalents at beginning of period
—

 
1

 
214

 
—

 
215

Cash and cash equivalents at end of period
$
—

 
$
1

 
$
337

 
$
—

 
$
338


30
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Spectra Energy Corp
Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2014
(Unaudited)
(In millions)
 
 
Spectra
Energy
Corp
 
Spectra
Capital
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
 
 
 
 
 
 
Net income
$
766

 
$
734

 
$
1,371

 
$
(1,962
)
 
$
909

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

 
—

 
610

 
—

 
610

Earnings from equity investments
—

 
—

 
(337
)
 
—

 
(337
)
Equity in earnings of consolidated subsidiaries
(734
)
 
(1,228
)
 
—

 
1,962

 
—

Distributions received from unconsolidated affiliates
—

 
—

 
280

 
—

 
280

Other
(16
)
 
259

 
(159
)
 
—

 
84

Net cash provided by (used in) operating activities
16

 
(235
)
 
1,765

 
—

 
1,546

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
 
 
 
 
 
 
Capital expenditures
—

 
—

 
(1,429
)
 
—

 
(1,429
)
Investments in and loans to unconsolidated
affiliates
—

 
—

 
(229
)
 
—

 
(229
)
Purchases of held-to-maturity securities
—

 
—

 
(584
)
 
—

 
(584
)
Proceeds from sales and maturities of held-to-maturity securities
—

 
—

 
576

 
—

 
576

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
—

 
—

 
252

 
—

 
252

Advances from affiliates
93

 
433

 
—

 
(526
)
 
—

Other changes in restricted funds
—

 
—

 
(1
)
 
—

 
(1
)
Net cash provided by (used in) investing activities
93

 
433

 
(1,421
)
 
(526
)
 
(1,421
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
 
 
 
 
 
 
Proceeds from the issuance of long-term debt
—

 
300

 
728

 
—

 
1,028

Payments for the redemption of long-term debt
—

 
(557
)
 
(588
)
 
—

 
(1,145
)
Net increase in commercial paper
—

 
33

 
360

 
—

 
393

Distributions to noncontrolling interests
—

 
—

 
(128
)
 
—

 
(128
)
Contributions from noncontrolling interests
—

 
—

 
139

 
—

 
139

Proceeds from the issuance of SEP common units
—

 
—

 
277

 
—

 
277

Dividends paid on common stock
(677
)
 
—

 
—

 
—

 
(677
)
Distributions and advances from (to) affiliates
558

 
15

 
(1,099
)
 
526

 
—

Other
10

 
—

 
1

 
—

 
11

Net cash used in financing activities
(109
)
 
(209
)
 
(310
)
 
526

 
(102
)
Effect of exchange rate changes on cash
—

 
—

 
(3
)
 
—

 
(3
)
Net increase (decrease) in cash and cash equivalents
—

 
(11
)
 
31

 
—

 
20

Cash and cash equivalents at beginning of period
—

 
12

 
189

 
—

 
201

Cash and cash equivalents at end of period
$
—

 
$
1

 
$
220

 
$
—

 
$
221




31
Table of Contents


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. We intend to early adopt the provisions of this ASU as of December 31, 2015. This ASU is not expected to have a material impact on our consolidated results of operations, financial position, or cash flow.

In July 2015, the FASB issued ASU No. 2015-11, “Inventory (Topic 330): Simplifying the Measurement of Inventory,” which simplifies the subsequent measurement of inventory by requiring inventory to be measured at the lower of cost and net realizable value. This ASU is effective for us January 1, 2016. This ASU is not expected to have a material impact on our consolidated results of operations, financial position or cash flow.

In September 2015, the FASB issued ASU No. 2015-16, “Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments,” to simplify accounting for adjustments made to provisional amounts recognized in a business combination and to eliminate the retrospective accounting for those adjustments. This ASU is effective for us January 1, 2016. This ASU is not expected to have a material impact on our consolidated results of operations, financial position or cash flow.
20. Subsequent Events

On October 18, 2015 we entered into a definitive agreement with SEP for the acquisition of SEP’s 33.3% ownership interests in DCP Sand Hills Pipeline, LLC (Sand Hills) and DCP Southern Hills Pipeline, LLC (Southern Hills). In consideration for this transaction, SEP retired 21,560,000 of our limited partner units and 440,000 of our general partner units in SEP. This will result in the reduction of any associated distribution payable to us, beginning in 2016. There will also be a reduction in the aggregate quarterly distributions, if any, to us (as holder of incentive distribution rights), by $4 million per quarter for a period of 12 consecutive quarters commencing with the quarter ending on December 31, 2015 and ending with the quarter ending on September 30, 2018.

On October 18, 2015 we also entered into a definitive agreement with DCP Midstream under which we will contribute the 33.3% interests in Sand Hills and Southern Hills to DCP Midstream.

On October 30, 2015, we completed the closing of both of these transactions.

On November 4, 2015, we contributed our remaining 0.1% interest in Southeast Supply Header, LLC (SESH) to SEP. Total consideration to Spectra Energy was 17,114 newly issued SEP common units. This is the last of three planned transactions related to Spectra Energy contributing all of its remaining U.S. transmission, storage and liquids assets to SEP (the U.S. Assets Dropdown). Also, in connection with this transaction, SEP issued 342 general partner units to Spectra Energy in exchange for the same amount of common units in order to maintain Spectra Energy's 2% general partner interest in SEP.

32
Table of Contents


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 September 30, 2015 and 2014, we reported net income from controlling interests of $174 million and $201 million, respectively. For the nine months ended September 30, 2015 and 2014, we reported net income from controlling interests of $459 million and $766 million, respectively.
The highlights for the three months and nine months ended September 30, 2015 include the following:
•
Spectra Energy Partners’ earnings for the three and nine-month periods benefited mainly from expansions, primarily on Texas Eastern Transmission, LP (Texas Eastern) and higher transportation revenues due to higher tariff rates and volumes on the Express pipeline.
•
Distribution’s earnings for the three and nine-month period decreased due to a weaker Canadian dollar.
•
Western Canada Transmission & Processing’s earnings for the three and nine-month periods decreased mainly due to lower NGL sales prices and a weaker Canadian dollar, partially offset by settlement gains associated with the risk management program at the Empress operations.
•
Field Services’ earnings for the three-month period decreased largely due to lower commodity prices and lower gains associated with the issuance of partnership units by DCP Midstream Partners, LP (DCP Partners), partially offset by asset growth, improved operating efficiencies and other initiatives. For the nine-month period, earnings decreased mainly due to lower commodity prices, a partial impairment of goodwill at DCP Midstream 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 nine months of 2015, we had $1.9 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 September 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. These facilities are used principally as back-stops for commercial paper programs.
RESULTS OF OPERATIONS
 
Three Months
Ended September 30,
 
Nine Months
Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions)
Operating revenues
$
1,103

 
$
1,207

 
$
3,918

 
$
4,303

Operating expenses
714

 
825

 
2,582

 
2,944

Operating income
389

 
382

 
1,336

 
1,359

Other income and expenses
79

 
115

 
(44
)
 
376

Interest expense
155

 
167

 
480

 
521

Earnings before income taxes
313

 
330

 
812

 
1,214

Income tax expense
70

 
76

 
164

 
305

Net income
243

 
254

 
648

 
909

Net income—noncontrolling interests
69

 
53

 
189

 
143

Net income—controlling interests
$
174

 
$
201

 
$
459

 
$
766



33
Table of Contents


Three Months Ended September 30, 2015 Compared to Same Period in 2014
Operating Revenues. The $104 million, or 9%, 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 and sales volumes, partially offset by 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 at Distribution, partially offset by
•
revenues from expansion projects primarily on Texas Eastern, increase in recoveries of electric power and other costs passed through to customers and higher crude oil transportation revenues, as a result of higher tariff rates and higher volumes mainly on the Express pipeline, all at Spectra Energy Partners.
Operating Expenses. The $111 million, or 13%, decrease was driven by:
•
the effects of a weaker Canadian dollar at Distribution and Western Canada Transmission & Processing,
•
decreased volumes of natural gas purchases for extraction and make-up and lower costs of sales at the Empress operations at Western Canada Transmission & Processing and
•
lower natural gas prices passed through to customers at Distribution, partially offset by
•
higher operating costs primarily due to increased electric power and other costs passed through to gas transmission customers at Spectra Energy Partners.
Other Income and Expenses. The $36 million, or 31%, decrease was primarily attributable to lower equity earnings from Field Services mainly due to lower commodity prices, net of favorable results from third-party mark-to-market derivative instruments and NGL trading and marketing, an increase in gains related to the sale of an asset and gathering system, increased gathering and processing margins as a result of asset growth and cost savings 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 and the fourth quarter 2014 dropdown of an additional 24.95% interest in Southeast Supply Header, LLC (SESH) at Spectra Energy Partners.
Interest Expense. The $12 million, or 7%, decrease was mainly due to a weaker Canadian dollar, partially offset by higher average long-term debt balances.
Income Tax Expense. The $6 million decrease was primarily attributable to lower earnings.
The effective tax rate for income from continuing operations was 22% for the three months ended September 30, 2015, compared to 23% for the same period in 2014.
Net Income—Noncontrolling Interests. The $16 million increase was driven primarily by higher earnings from Spectra Energy Partners.
Nine Months Ended September 30, 2015 Compared to Same Period in 2014
Operating Revenues. The $385 million, or 9%, decrease was driven by:
•
the effects of a weaker Canadian dollar at Distribution and Western Canada Transmission & Processing,
•
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 and
•
lower customer usage due to warmer weather and the first quarter 2014 results including regulatory decisions from the OEB that, in aggregate, provided a benefit, net of growth in the number of customers 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 as a result of higher volumes and higher tariff rates mainly on the Express pipeline and an increase in recoveries of electric power and other costs passed through to gas transmission customers, net of lower processing revenues due to lower prices at Spectra Energy Partners.
          

34
Table of Contents


Operating Expenses. The $362 million, or 12%, decrease was driven by:
•
decreased volumes of natural gas purchases for extraction and make-up and lower costs of sales, net of a non-cash charge to reduce the value of propane inventory to net realizable value at June 30 and September 30, 2015 both at the Empress operations, partially offset by overhead reduction costs at Western Canada Transmission & Processing
•
the effects of a weaker Canadian dollar at Distribution and Western Canada Transmission & Processing and
•
lower volumes of natural gas sold due to warmer weather, net of growth in the number of customers at Distribution, 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.
Other Income and Expenses. The $420 million, or 112%, decrease was attributable to lower equity earnings from Field Services mainly due to decreased commodity prices, a partial impairment of goodwill at DCP Midstream 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, favorable results from third-party mark-to-market derivative instruments, a net increase in gains related to the sale of assets 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 and the fourth quarter 2014 dropdown of an additional 24.95% interest in SESH at Spectra Energy Partners.
Interest Expense. The $41 million, or 8%, decrease was mainly due to a weaker Canadian dollar, partially offset by higher average long-term debt balances.
Income Tax Expense. The $141 million decrease was primarily due to the $74 million tax impact of the loss on investment due to the partial 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 20% for the nine months ended September 30, 2015, compared to 25% for the same period in 2014.
Net Income—Noncontrolling Interests. The $46 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.
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.

35
Table of Contents


Segment EBITDA is summarized in the following table. Detailed discussions follow.
EBITDA by Business Segment
 
Three Months
Ended September 30,
 
Nine Months
Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions)
Spectra Energy Partners
$
488

 
$
422

 
$
1,421

 
$
1,225

Distribution
70

 
82

 
360

 
420

Western Canada Transmission & Processing
117

 
156

 
382

 
504

Field Services
(3
)
 
51

 
(253
)
 
235

Total reportable segment EBITDA
672

 
711

 
1,910

 
2,384

Other
(12
)
 
(19
)
 
(39
)
 
(60
)
Total reportable segment and other EBITDA
$
660

 
$
692

 
$
1,871

 
$
2,324

Depreciation and amortization
188

 
201

 
574

 
600

Interest expense
155

 
167

 
480

 
521

Interest income and other (a)
(4
)
 
6

 
(5
)
 
11

Earnings before income taxes
$
313

 
$
330

 
$
812

 
$
1,214

___________
(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 September 30,
 
Nine Months
Ended September 30,
 
2015
 
2014
 
Increase (Decrease)
 
2015
 
2014
 
Increase (Decrease)
 
(in millions, except where noted)
Operating revenues
$
612

 
$
558

 
$
54

 
$
1,821

 
$
1,670

 
$
151

Operating expenses
 
 
 
 
 
 
 
 
 
 
 
        Operating, maintenance and other
207

 
190

 
17

 
606

 
568

 
38

Other income and expenses
83

 
54

 
29

 
206

 
123

 
83

EBITDA
$
488

 
$
422

 
$
66

 
$
1,421

 
$
1,225

 
$
196

Express pipeline revenue receipts, MBbl/d (a)
234

 
221

 
13

 
239

 
217

 
22

Platte PADD II deliveries, MBbl/d
167

 
169

 
(2
)
 
169

 
170

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

Three Months Ended September 30, 2015 Compared to Same Period in 2014
Operating Revenues. The $54 million increase was driven by:
•
a $34 million increase due to expansion projects, primarily on Texas Eastern,
•
a $16 million increase in crude oil transportation revenues, mainly as a result of higher tariff rates and higher volumes on the Express pipeline and
•
a $15 million increase in recoveries of electric power and other costs passed through to gas transmission customers, partially offset by
•
an $11 million decrease in processing revenues primarily due to lower prices, net of volume variance.

36
Table of Contents


Operating, Maintenance and Other. The $17 million increase was primarily driven by an increase in electric power and other costs passed through to gas transmission customers.
Other Income and Expenses. The $29 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 fourth quarter 2014 dropdown of an additional 24.95% interest in SESH.
Nine Months Ended September 30, 2015 Compared to Same Period in 2014
Operating Revenues. The $151 million increase was driven by:
•
a $99 million increase due to expansion projects, primarily on Texas Eastern and East Tennessee,
•
a $48 million increase in crude oil transportation revenues as a result of higher volumes and increased tariff rates mainly on the Express pipeline and
•
a $46 million increase in recoveries of electric power and other costs passed through to gas transmission customers, partially offset by
•
an $18 million decrease in processing revenues primarily due to lower prices,
•
a $9 million decrease in natural gas transportation revenues mainly from firm margin and interruptible transportation on Texas Eastern and other revenue on East Tennessee, net of higher firm transportation on Algonquin Gas Transmission, L.L.C. and
•
a $7 million decrease in inventory settlement revenues due to sales of excess tank oil in 2014 and lower oil prices on the Express and Platte pipelines.
Operating, Maintenance and Other. The $38 million increase was driven by:
•
a $46 million increase in electric power and other costs passed through to gas transmission customers,
•
a $9 million increase due to the non-cash impairment charge on Ozark Gas Gathering and
•
a $6 million increase primarily in power costs due to higher usage in 2015 net of lower rates on the Express pipeline, partially offset by
•
a $15 million decrease due to lower ad valorem tax accruals,
•
a $7 million decrease in employee benefit costs and
•
a $6 million decrease from project developments expenses in 2014.
Other Income and Expenses. The $83 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 fourth quarter 2014 dropdown of an additional 24.95% interest in SESH.
Distribution 
 
Three Months
Ended September 30,
 
Nine Months
Ended September 30,
 
2015
 
2014
 
Increase (Decrease)
 
2015
 
2014
 
Increase (Decrease)
 
(in millions, except where noted)
Operating revenues
$
209

 
$
260

 
$
(51
)
 
$
1,161

 
$
1,338

 
$
(177
)
Operating expenses
 
 
 
 
 
 
 
 
 
 
 
        Natural gas purchased
53

 
78

 
(25
)
 
539

 
618

 
(79
)
        Operating, maintenance and other
86

 
100

 
(14
)
 
262

 
299

 
(37
)
Other income and expenses
—

 
—

 
—

 
—

 
(1
)
 
1

EBITDA
$
70

 
$
82

 
$
(12
)
 
$
360

 
$
420

 
$
(60
)
Number of customers, thousands
 
 
 
 
 
 
1,429

 
1,410

 
19

Heating degree days, Fahrenheit
245

 
354

 
(109
)
 
5,370

 
5,584

 
(214
)
Pipeline throughput, TBtu (a)
134

 
121

 
13

 
594

 
536

 
58

Canadian dollar exchange rate, average
1.31

 
1.09

 
0.22

 
1.26

 
1.09

 
0.17

___________
(a)
Trillion British thermal units.

37
Table of Contents


Three Months Ended September 30, 2015 Compared to Same Period in 2014
Operating Revenues. The $51 million decrease was driven by:
•
a $42 million decrease resulting from a weaker Canadian dollar and
•
a $13 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.
Natural Gas Purchased. The $25 million decrease was driven by:
•
a $13 million decrease from lower natural gas prices passed through to customers and
•
an $11 million decrease resulting from a weaker Canadian dollar.
Operating, Maintenance and Other. The $14 million decrease was primarily due to the weaker Canadian dollar.
Nine Months Ended September 30, 2015 Compared to Same Period in 2014
Operating Revenues. The $177 million decrease was driven by:
•
a $160 million decrease resulting from a weaker Canadian dollar,
•
a $38 million decrease in residential customer usage of natural gas partially due to weather that was warmer than in 2014 and
•
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 $19 million increase from growth in the number of customers.
Natural Gas Purchased. The $79 million decrease was driven by:
•
a $71 million decrease resulting from a weaker Canadian dollar and
•
a $35 million decrease due to lower volumes of natural gas sold to residential customers partially due to warmer weather, partially offset by
•
an $11 million increase from growth in the number of customers.
Operating, Maintenance and Other. The $37 million decrease was primarily due to the weaker Canadian dollar.
Western Canada Transmission & Processing
 
Three Months
Ended September 30,
 
Nine Months
Ended September 30,
 
2015
 
2014
 
Increase (Decrease)
 
2015
 
2014
 
Increase (Decrease)
 
(in millions, except where noted)
Operating revenues
$
288

 
$
417

 
$
(129
)
 
$
962

 
$
1,383

 
$
(421
)
Operating expenses
 
 
 
 
 
 
 
 
 
 
 
        Natural gas and petroleum products purchased
32

 
87

 
(55
)
 
124

 
352

 
(228
)
        Operating, maintenance and other
141

 
174

 
(33
)
 
462

 
528

 
(66
)
Other income and expenses
2

 
—

 
2

 
6

 
1

 
5

EBITDA
$
117

 
$
156

 
$
(39
)
 
$
382

 
$
504

 
$
(122
)
Pipeline throughput, TBtu
213

 
219

 
(6
)
 
689

 
685

 
4

Volumes processed, TBtu
157

 
179

 
(22
)
 
493

 
531

 
(38
)
Canadian dollar exchange rate, average
1.31

 
1.09

 
0.22

 
1.26

 
1.09

 
0.17


Three Months Ended September 30, 2015 Compared to Same Period in 2014
Operating Revenues. The $129 million decrease was driven by:
•
a $58 million decrease resulting from a weaker Canadian dollar,
•
a $34 million decrease due primarily to lower sales volumes of residual natural gas at the Empress operations,

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•
a $23 million decrease due to lower NGL prices associated with the Empress operations and
•
an $18 million decrease in sales volumes of NGLs at the Empress operations, partially offset by
•
an $8 million increase from settlement gains associated with the risk management program implemented in 2014 at the Empress operations.
Natural Gas and Petroleum Products Purchased. The $55 million decrease was driven by:
•
a $45 million decrease due primarily to lower volumes of natural gas purchases for extraction and make-up at the Empress operations,
•
a $9 million decrease primarily as a result of lower costs of sales at the Empress facility and
•
a $7 million decrease resulting from a weaker Canadian dollar, partially offset by
•
a $4 million non-cash charge to reduce the value of propane inventory at the Empress operations to net realizable value at September 30, 2015.
Operating, Maintenance and Other. The $33 million decrease was primarily driven by a weaker Canadian dollar.
Nine Months Ended September 30, 2015 Compared to Same Period in 2014
Operating Revenues. The $421 million decrease was driven by:
•
a $143 million decrease resulting from a weaker Canadian dollar,
•
a $128 million decrease due to lower NGL prices associated with the Empress operations,
•
a $124 million decrease due primarily to lower sales volumes of residual natural gas at the Empress operations,
•
a $51 million decrease in sales volumes of NGLs at the Empress operations,
•
an $18 million decrease in transmission revenues due to lower interruptible transmission revenues and lower tolls charged to customers at M&N Canada and
•
a $16 million decrease arising from non-cash mark-to-market losses associated with the risk management program at the Empress operations, partially offset by
•
a $47 million increase from settlement gains associated with the risk management program at the Empress operations and
•
an $8 million increase in gathering and processing revenues due primarily to higher volumes.
Natural Gas and Petroleum Products Purchased. The $228 million decrease was driven by:
•
a $176 million decrease due primarily to lower volumes of natural gas purchases for extraction and make-up at the Empress operations,
•
a $46 million decrease primarily as a result of lower costs of sales at the Empress facility and
•
an $18 million decrease resulting from a weaker Canadian dollar, partially offset by
•
a $9 million non-cash charge to reduce the value of propane inventory at the Empress operations to net realizable value at September 30, 2015.
Operating, Maintenance and Other. The $66 million decrease was driven by:
•
a $68 million decrease resulting from a weaker Canadian dollar and
•
a $6 million decrease in plant turnaround costs, partially offset by
•
an $11 million increase due to overhead reduction costs.
 

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Field Services
 
Three Months
Ended September 30,
 
Nine Months
Ended September 30,
 
2015
 
2014
 
Increase (Decrease)
 
2015
 
2014
 
Increase (Decrease)
 
(in millions, except where noted)
Earnings (loss) from equity investments
$
(3
)
 
$
51

 
$
(54
)
 
$
(253
)
 
$
235

 
$
(488
)
EBITDA
$
(3
)
 
$
51

 
$
(54
)
 
$
(253
)
 
$
235

 
$
(488
)
Natural gas gathered and processed/transported, TBtu/d (a,b)
7.3

 
7.5

 
(0.2
)
 
7.1

 
7.3

 
(0.2
)
NGL production, MBbl/d (a)
421

 
471

 
(50
)
 
410

 
456

 
(46
)
Average natural gas price per MMBtu (c,d)
$
2.77

 
$
4.06

 
$
(1.29
)
 
$
2.80

 
$
4.55

 
$
(1.75
)
Average NGL price per gallon (e)
$
0.42

 
$
0.90

 
$
(0.48
)
 
$
0.46

 
$
0.96

 
$
(0.50
)
Average crude oil price per barrel (f)
$
46.43

 
$
97.24

 
$
(50.81
)
 
$
51.00

 
$
99.64

 
$
(48.64
)
___________
(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 September 30, 2015 Compared to Same Period in 2014
EBITDA. Lower equity earnings of $54 million were mainly the result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:
•
a $123 million decrease from commodity-sensitive processing arrangements, due to decreased NGL, crude oil and natural gas prices, partially offset by
•
a $31 million increase due to 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 natural gas and NGL trading and marketing, including growth from ownership interests in NGL pipelines, largely due to the ramp-up and expansion on Sand Hills,
•
a $30 million increase in gains related to the sale of a non-core gas processing plant and gathering system and
•
an $11 million increase in gathering and processing margins as a result of asset growth, partially offset by volume declines in certain geographic regions.
Nine Months Ended September 30, 2015 Compared to Same Period in 2014
EBITDA. Lower equity earnings of $488 million were mainly the result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:
•
a $371 million decrease from commodity-sensitive processing arrangements, due to decreased NGL, crude oil and natural gas prices,
•
a $188 million decrease primarily as a result of a partial impairment of goodwill. This impairment was due to the significant downturn in commodity prices in recent quarters and
•
a $66 million decrease in gains associated with the issuance of partnership units by DCP Partners in 2015 compared to 2014, partially offset by
•
a $58 million increase in gathering and processing margins as a result of asset growth, partially offset by volume declines in certain geographic regions,
•
a $43 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 ownership interests in NGL pipelines, largely due to the ramp-up and expansion on Sand Hills,


40
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•
a $25 million increase as a result of gains related to the sale of a non-core gas processing plant and gathering system and its interest in Dover-Hennessey, and the prior year loss on the interest in Main Pass Oil and Gathering Company, partially offset by a loss related to the sale of its interest in the Benedum processing plant and gathering system in 2015 and
•
a $22 million increase primarily attributable to lower operating expenses as a result of cost savings initiatives in operations.
Other
 
Three Months
Ended September 30,
 
Nine Months
Ended September 30,
 
2015
 
2014
 
Increase (Decrease)
 
2015
 
2014
 
Increase (Decrease)
 
(in millions)
Operating revenues
$
19

 
$
17

 
$
2

 
$
54

 
$
54

 
$
—

Operating expenses
 
 
 
 
 
 
 
 
 
 
 
        Operating, maintenance and other
32

 
39

 
(7
)
 
94

 
120

 
(26
)
Other income and expenses
1

 
3

 
(2
)
 
1

 
6

 
(5
)
EBITDA
$
(12
)
 
$
(19
)
 
$
7

 
$
(39
)
 
$
(60
)
 
$
21


Three and Nine Months Ended September 30, 2015 Compared to Same Periods in 2014
EBITDA. Both the $7 million and $21 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 announced overhead reductions at Western Canada Transmission & Processing.

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.


41
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We believe the assumptions used in our analyses are appropriate and result in reasonable estimates of the fair 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.

Due to the significant downturn in commodity prices, DCP Midstream performed a goodwill impairment test which was finalized in the third quarter of 2015. 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 $460 million goodwill impairment, which reduced our equity earnings from DCP Midstream by $123 million after-tax for the nine month period ending September 30, 2015.

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 September 30, 2015, we had negative working capital of $1,568 million. This balance includes a payable to an unconsolidated affiliate of $396 million, commercial paper liabilities totaling $577 million and current maturities of long-term debt of $766 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 September 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 $2.0 billion under SEP’s credit facility and $1.1 billion 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.
Cash Flow Analysis
The following table summarizes the changes in cash flows for each of the periods presented:
 
Nine Months
Ended September 30,
 
2015
 
2014
Net cash provided by (used in):
(in millions)
Operating activities
$
1,823

 
$
1,546

Investing activities
(1,503
)
 
(1,421
)
Financing activities
(191
)
 
(102
)
Effect of exchange rate changes on cash
(6
)
 
(3
)
Net increase in cash and cash equivalents
123

 
20

Cash and cash equivalents at beginning of the period
215

 
201

Cash and cash equivalents at end of the period
$
338

 
$
221


42
Table of Contents



Operating Cash Flows
Net cash provided by operating activities increased $277 million to $1,823 million in the nine months ended September 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 $82 million to $1,503 million in the nine months ended September 30, 2015 compared to the same period in 2014. This change was driven by:
•
a $250 million net increase in capital and investment expenditures, partially offset by
•
a $396 million distribution received from Gulfstream with proceeds from a Gulfstream debt offering in 2015 compared to a $200 million distribution from SESH with proceeds from a SESH debt offering in 2014.
 
 
Nine Months
Ended September 30,
 
 
2015
 
2014
Capital and Investment Expenditures
 
(in millions)
Spectra Energy Partners
 
$
1,252

 
$
889

Distribution
 
374

 
261

Western Canada Transmission & Processing
 
241

 
385

Total reportable segments
 
1,867

 
1,535

Other
 
41

 
123

Total consolidated
 
$
1,908

 
$
1,658

Capital and investment expenditures for the nine months ended September 30, 2015 consisted of $1,433 million for expansion projects and $475 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.
Financing Cash Flows and Liquidity
Net cash used in financing activities increased $89 million to $191 million for the nine months ended September 30, 2015 compared to the same period in 2014. This change was driven by:
•
commercial paper redemptions of $984 million in 2015, compared to commercial paper issuances of $393 million in 2014, partially offset by
•
$1,179 million of net proceeds from long-term debt in 2015, compared to net repayments of long-term debt of $117 million in 2014.
On September 17, 2015, Union Gas issued 200 million Canadian dollars (approximately $152 million as of the issuance date) of 3.19% unsecured notes due 2025 and 250 million Canadian dollars (approximately $190 million as of the issuance date) of 4.20% unsecured notes due 2044. Net proceeds from the offerings were used to repay a portion of short-term debt, to fund capital expenditures and for general corporate purposes.
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 nine months ended September 30, 2015, SEP issued 7.3 million common units to the public under its at-the-market program and approximately 149,000 general partner units to Spectra Energy. Total net proceeds to SEP were $358 million (net proceeds to Spectra Energy were $351 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 9.6 million common units to the public and 197,000 general partner units to Spectra Energy, for total net proceeds to SEP of $458 million (net proceeds to Spectra Energy were $449 million).

43
Table of Contents


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 September 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 September 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 October 8, 2015 payable on December 8, 2015 to shareholders at close of business on November 13, 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 $184 million available as of September 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 2.1 billion Canadian dollars (approximately $1.5 billion) available as of September 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.
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 September 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 September 30, 2015 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

44
Table of Contents


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.

(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.

45
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The total amount of securities of the registrant or its subsidiaries authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10% of the total assets of the registrant and its subsidiaries on a consolidated basis. The registrant agrees, upon request of the Securities and Exchange Commission, to furnish copies of any or all of such instruments to it.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SPECTRA ENERGY CORP
 
 
 
 
Date: November 5, 2015
 
 
 
 
 
/s/ Gregory L. Ebel
 
 
 
 
 
 
Gregory L. Ebel
 
 
 
 
 
 
President and Chief Executive Officer
 
 
 
 
Date: November 5, 2015
 
 
 
 
 
/s/ J. Patrick Reddy
 
 
 
 
 
 
J. Patrick Reddy
 
 
 
 
 
 
Chief Financial Officer

46