SE-2014.09.30 10Q
Table of Contents


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

ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2014
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 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, 2014: 671,000,273
 
 
 
 
 


Table of Contents


SPECTRA ENERGY CORP
FORM 10-Q FOR THE QUARTER ENDED
September 30, 2014
INDEX
 
 
 
Page
PART I. FINANCIAL INFORMATION
 
Item 1.
 
Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2014 and 2013
 
Condensed Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2014 and 2013
 
Condensed Consolidated Balance Sheets as of September 30, 2014 and December 31, 2013
 
Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2014 and 2013
 
Condensed Consolidated Statements of Equity for the nine months ended September 30, 2014 and 2013
 
Item 2.
Item 3.
Item 4.
 
 
 
PART II. OTHER INFORMATION
 
Item 1.
Item 1A.
Item 6.
 


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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

Table of Contents


PART I. FINANCIAL INFORMATION

Item 1.
Financial Statements.
SPECTRA ENERGY CORP
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In millions, except per-share amounts)
 
 
Three Months
Ended September 30,
 
Nine Months
Ended September 30,
 
2014
 
2013
 
2014
 
2013
Operating Revenues
 
 
 
 
 
 
 
Transportation, storage and processing of natural gas
$
789

 
$
758

 
$
2,456

 
$
2,324

Distribution of natural gas
205

 
202

 
1,140

 
1,110

Sales of natural gas liquids
81

 
82

 
308

 
259

Transportation of crude oil
77

 
71

 
218

 
151

Other
55

 
31

 
181

 
109

Total operating revenues
1,207

 
1,144

 
4,303

 
3,953

Operating Expenses
 
 
 
 
 
 
 
Natural gas and petroleum products purchased
135

 
123

 
872

 
755

Operating, maintenance and other
404

 
403

 
1,172

 
1,145

Depreciation and amortization
201

 
195

 
600

 
577

Property and other taxes
85

 
90

 
300

 
283

Total operating expenses
825

 
811

 
2,944

 
2,760

Operating Income
382

 
333

 
1,359

 
1,193

Other Income and Expenses
 
 
 
 
 
 
 
Equity in earnings of unconsolidated affiliates
91

 
163

 
337

 
345

Other income and expenses, net
24

 
48

 
39

 
103

Total other income and expenses
115

 
211

 
376

 
448

Interest Expense
167

 
167

 
521

 
476

Earnings Before Income Taxes
330

 
377

 
1,214

 
1,165

Income Tax Expense
76

 
85

 
305

 
277

Net Income
254

 
292

 
909

 
888

Net Income—Noncontrolling Interests
53

 
29

 
143

 
86

Net Income—Controlling Interests
$
201

 
$
263

 
$
766

 
$
802

Common Stock Data
 
 
 
 
 
 
 
Weighted-average shares outstanding
 
 
 
 
 
 
 
Basic
671

 
670

 
671

 
669

Diluted
673

 
672

 
672

 
671

Earnings per share
 
 
 
 
 
 
 
Basic and Diluted
$
0.30

 
$
0.39

 
$
1.14

 
$
1.20

Dividends per share
$
0.335

 
$
0.305

 
$
1.005

 
$
0.915









See Notes to Condensed Consolidated Financial Statements.

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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,
 
2014
 
2013
 
2014
 
2013
Net Income
$
254

 
$
292

 
$
909

 
$
888

Other comprehensive income (loss)
 
 
 
 
 
 
 
Foreign currency translation adjustments
(304
)
 
150

 
(329
)
 
(290
)
Unrealized mark-to-market net gain on hedges

 
2

 
3

 
5

Reclassification of cash flow hedges into earnings
2

 
2

 
5

 
6

Pension and benefits impact (net of taxes of $3, $4, $9 and $13, respectively)
6

 
10

 
19

 
31

Other

 
1

 

 
1

Total other comprehensive income (loss)
(296
)
 
165

 
(302
)
 
(247
)
Total Comprehensive Income (Loss), net of tax
(42
)
 
457

 
607

 
641

Less: Comprehensive Income—Noncontrolling Interests
50

 
30

 
139

 
82

Comprehensive Income (Loss)—Controlling Interests
$
(92
)
 
$
427

 
$
468

 
$
559




































See Notes to Condensed Consolidated Financial Statements.

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SPECTRA ENERGY CORP
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)
 
 
September 30,
2014
 
December 31,
2013
ASSETS
 
 
 
 
 
 
 
Current Assets
 
 
 
Cash and cash equivalents
$
221

 
$
201

Receivables, net
1,202

 
1,336

Inventory
446

 
263

Fuel tracker
120

 
28

Other
263

 
253

Total current assets
2,252

 
2,081

 
 
 
 
Investments and Other Assets
 
 
 
Investments in and loans to unconsolidated affiliates
3,008

 
3,043

Goodwill
4,768

 
4,810

Other
370

 
385

Total investments and other assets
8,146

 
8,238

 
 
 
 
Property, Plant and Equipment
 
 
 
Cost
29,137

 
28,456

Less accumulated depreciation and amortization
6,936

 
6,627

Net property, plant and equipment
22,201

 
21,829

 
 
 
 
Regulatory Assets and Deferred Debits
1,402

 
1,385

 
 
 
 
Total Assets
$
34,001

 
$
33,533























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,
2014
 
December 31,
2013
LIABILITIES AND EQUITY
 
 
 
 
 
 
 
Current Liabilities
 
 
 
Accounts payable
$
478

 
$
440

Commercial paper
1,412

 
1,032

Taxes accrued
104

 
72

Interest accrued
150

 
201

Current maturities of long-term debt
220

 
1,197

Other
1,127

 
1,097

Total current liabilities
3,491

 
4,039

 
 
 
 
Long-term Debt
13,072

 
12,488

 
 
 
 
Deferred Credits and Other Liabilities
 
 
 
Deferred income taxes
5,262

 
4,968

Regulatory and other
1,380

 
1,457

Total deferred credits and other liabilities
6,642

 
6,425

 
 
 
 
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 and 670 million shares outstanding at September 30, 2014 and December 31, 2013, respectively
1

 
1

Additional paid-in capital
4,939

 
4,869

Retained earnings
2,473

 
2,383

Accumulated other comprehensive income
943

 
1,241

Total controlling interests
8,356

 
8,494

Noncontrolling interests
2,182

 
1,829

Total equity
10,538

 
10,323

 
 
 
 
Total Liabilities and Equity
$
34,001

 
$
33,533












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,
 
2014
 
2013
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net income
$
909

 
$
888

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization
610

 
587

Deferred income tax expense
283

 
278

Equity in earnings of unconsolidated affiliates
(337
)
 
(345
)
Distributions received from unconsolidated affiliates
280

 
215

Other
(199
)
 
(223
)
Net cash provided by operating activities
1,546

 
1,400

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Capital expenditures
(1,429
)
 
(1,476
)
Investments in and loans to unconsolidated affiliates
(229
)
 
(224
)
Acquisitions, net of cash acquired

 
(1,254
)
Purchases of held-to-maturity securities
(584
)
 
(632
)
Proceeds from sales and maturities of held-to-maturity securities
576

 
623

Purchases of available-for-sale securities
(13
)
 
(5,665
)
Proceeds from sales and maturities of available-for-sale securities
7

 
3,810

Distributions received from unconsolidated affiliates
252

 
17

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

 
2

Net cash used in investing activities
(1,421
)
 
(4,800
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Proceeds from the issuance of long-term debt
1,028

 
3,972

Payments for the redemption of long-term debt
(1,145
)
 
(796
)
Net increase in commercial paper
393

 
803

Distributions to noncontrolling interests
(128
)
 
(104
)
Contributions from noncontrolling interests
139

 

Dividends paid on common stock
(677
)
 
(616
)
Proceeds from the issuances of Spectra Energy Partners, LP common units
277

 
190

Other
11

 
18

Net cash provided by (used in) financing activities
(102
)
 
3,467

Effect of exchange rate changes on cash
(3
)
 
(1
)
Net increase in cash and cash equivalents
20

 
66

Cash and cash equivalents at beginning of period
201

 
94

Cash and cash equivalents at end of period
$
221

 
$
160

Supplemental Disclosures
 
 
 
Property, plant and equipment non-cash accruals
$
125

 
$
107






See Notes to Condensed Consolidated Financial Statements.

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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, 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

 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2012
$
1

 
$
5,297

 
$
2,165

 
$
2,044

 
$
(535
)
 
$
871

 
$
9,843

Net income

 

 
802

 

 

 
86

 
888

Other comprehensive income (loss)

 

 

 
(286
)
 
43

 
(4
)
 
(247
)
Dividends on common stock

 

 
(615
)
 

 

 

 
(615
)
Stock-based compensation

 
13

 

 

 

 

 
13

Distributions to noncontrolling interests

 

 

 

 

 
(104
)
 
(104
)
Spectra Energy common stock issued

 
21

 

 

 

 

 
21

Spectra Energy Partners, LP common units issued

 
38

 

 

 

 
128

 
166

Transfer of interests in Express-Platte to Spectra Energy Partners, LP

 
(53
)
 

 

 

 
84

 
31

Other, net

 
(2
)
 

 

 

 
3

 
1

September 30, 2013
$
1

 
$
5,314

 
$
2,352

 
$
1,758

 
$
(492
)
 
$
1,064

 
$
9,997














See Notes to Condensed Consolidated Financial Statements.

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Table of Contents


SPECTRA ENERGY CORP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. General

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

Nature of Operations. Spectra Energy Corp, through its subsidiaries and equity affiliates, owns and operates a large and diversified portfolio of complementary natural gas-related energy assets, and owns and operates a crude oil pipeline system that connects Canadian and U.S. producers to refineries in the U.S. Rocky Mountain and Midwest regions. We currently operate in three key areas of the natural gas industry: gathering and processing, transmission and storage, and distribution. We provide transmission and storage of natural gas to customers in various regions of the northeastern and southeastern United States, the Maritime Provinces in Canada, the Pacific Northwest in the United States and Canada, and in the province of Ontario, Canada. We also provide natural gas sales and distribution services to retail customers in Ontario, and natural gas gathering and processing services to customers in western Canada. We also own a 50% interest in DCP Midstream, LLC (DCP Midstream), based in Denver, Colorado, one of the leading natural gas gatherers in the United States based on wellhead volumes, and one of the largest U.S. producers and marketers of natural gas liquids (NGLs).

Basis of Presentation. The accompanying Condensed Consolidated Financial Statements include our accounts and the accounts of our majority-owned subsidiaries, after eliminating intercompany transactions and balances. These interim financial statements should be read in conjunction with the consolidated financial statements included in our Annual Report on Form
10-K for the year ended December 31, 2013, and reflect all normal recurring adjustments that are, in our opinion, necessary to fairly present our results of operations and financial position. Amounts reported in the Condensed Consolidated Statements of Operations are not necessarily indicative of amounts expected for the respective annual periods due to the effects of seasonal temperature variations on energy consumption, primarily in our gas distribution operations, as well as changing commodity prices on certain of our processing operations and other factors.

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

In March 2013, we acquired 100% of the ownership interests in the Express-Platte crude oil pipeline system for $1.5 billion, consisting of $1.25 billion in cash and $260 million of acquired debt, before working capital adjustments. The Express-Platte pipeline system, which begins in Hardisty, Alberta, and terminates in Wood River, Illinois, is comprised of both the Express and Platte crude oil pipelines. The Express pipeline carries crude oil to U.S. refining markets in the Rockies area, including Montana, Wyoming, Colorado and Utah. The Platte pipeline, which interconnects with Express pipeline in Casper, Wyoming, transports crude oil predominantly from the Bakken shale and western Canada to refineries in the Midwest. In 2013, subsidiaries of Spectra Energy contributed a 100% interest in the U.S. portion of Express-Platte and sold a 100% ownership interest in the Canadian portion to SEP.


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The following table summarizes the fair values of the assets and liabilities acquired as of the date of the acquisition.
 
 
Purchase Price 
Allocation
 
(in millions)
Cash purchase price
$
1,250

Working capital and other purchase adjustments
71

Total
1,321

Cash
67

Receivables
25

Other current assets
9

Property, plant and equipment
1,251

Accounts payable
(18
)
Other current liabilities
(17
)
Deferred credits and other liabilities
(259
)
Long-term debt, including current portion
(260
)
Total assets acquired/liabilities assumed
798

Goodwill
$
523

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

The allocation of the fair values of assets and liabilities acquired related to the acquisition of Express-Platte was finalized in the first quarter of 2014, resulting in the following adjustments to amounts reported as of December 31, 2013: a $60 million decrease in Property, Plant and Equipment, a $1 million decrease in Other Current Assets and a $24 million decrease in Deferred Credits and Other Liabilities, resulting in a $37 million increase in Goodwill.
Pro forma results of operations that reflect the acquisition of Express-Platte as if the acquisition had occurred as of the beginning of 2013 are not presented as they do not materially differ from actual results reported in our Condensed Consolidated Statements of Operations.
3. Business Segments

In November 2013, Spectra Energy contributed substantially all of its remaining U.S. transmission, storage and liquids assets to SEP (the U.S. Assets Dropdown). As a result of this transaction, we realigned our reportable segments structure. Amounts presented herein for 2013 segment information have been recast to conform to our current segment reporting presentation. There were no changes to consolidated data as a result of the recast of our segment information.

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.

The presentation of our 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. It is in this context that our CODM evaluates the Spectra Energy Partners segment as a whole, without regard to any of SEP’s individual businesses. These factors, coupled with a different cost of capital of our other businesses, serve to differentiate how our Spectra Energy Partners segment is managed as compared to how SEP is managed.


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Spectra Energy Partners provides transmission, storage and gathering of natural gas, as well as the transportation of crude oil and natural gas liquids (NGLs) through interstate pipeline systems for customers in various regions of the midwestern, northeastern and southeastern United States 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.”

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 United States and the Maritime Provinces in Canada. This segment conducts business mostly through BC Pipeline, BC Field Services, and the NGL marketing and Canadian Midstream businesses, and Maritimes & Northeast Pipeline Limited Partnership (M&N Canada). BC Pipeline and BC Field Services 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, and recovers and sells condensate. In addition, Field Services 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 located in nine major conventional and non-conventional natural gas producing regions: Mid-Continent, Rocky Mountain, East Texas-North Louisiana, Barnett Shale, Gulf Coast, South Texas, Central Texas, Antrim Shale and Permian Basin. DCP Midstream Partners, LP (DCP Partners) is a publicly-traded master limited partnership, of which DCP Midstream acts as general partner. As of September 30, 2014, DCP Midstream had an approximate 22% 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, 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

 

 

 

 
6

Total consolidated
$
1,207

 
$

 
$
1,207

 
$
201

 
$
330

 
 
 
 
 
 
 
 
 
 
Three Months Ended September 30, 2013
 
 
 
 
 
 
 
 
 
Spectra Energy Partners
$
493

 
$
1

 
$
494

 
$
67

 
$
360

Distribution
264

 

 
264

 
49

 
83

Western Canada Transmission & Processing
386

 
14

 
400

 
69

 
174

Field Services

 

 

 

 
137

Total reportable segments
1,143

 
15

 
1,158

 
185

 
754

Other
1

 
16

 
17

 
10

 
(19
)
Eliminations

 
(31
)
 
(31
)
 

 

Depreciation and amortization

 

 

 

 
195

Interest expense

 

 

 

 
167

Interest income and other

 

 

 

 
4

Total consolidated
$
1,144

 
$

 
$
1,144

 
$
195

 
$
377

 
 
 
 
 
 
 
 
 
 
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

 

 

 

 
11

Total consolidated
$
4,303

 
$

 
$
4,303

 
$
600

 
$
1,214

 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2013
 
 
 
 
 
 
 
 
 
Spectra Energy Partners
$
1,444

 
$
1

 
$
1,445

 
$
193

 
$
1,065

Distribution
1,315

 

 
1,315

 
151

 
418

Western Canada Transmission & Processing
1,187

 
47

 
1,234

 
203

 
521

Field Services

 

 

 

 
271

Total reportable segments
3,946

 
48

 
3,994

 
547

 
2,275

Other
7

 
46

 
53

 
30

 
(62
)
Eliminations

 
(94
)
 
(94
)
 

 

Depreciation and amortization

 

 

 

 
577

Interest expense

 

 

 

 
476

Interest income and other

 

 

 

 
5

Total consolidated
$
3,953

 
$

 
$
3,953

 
$
577

 
$
1,165


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4. Regulatory Matters

Union Gas. In January 2014, Union Gas filed a notice of motion seeking leave to appeal to the Ontario Court of Appeal (Court of Appeal) for the unsuccessful appeal to the Ontario Divisional Court on the OEB’s treatment of 2011 revenues derived from the optimization of our upstream transportation contracts. A decision from the Court of Appeal on the notice of motion was issued in April 2014 granting leave to appeal. In May 2014, Union Gas filed a notice of appeal and a hearing is scheduled for December 2014.

Union Gas filed an application with the OEB in May 2013 for the annual disposition of the 2012 non-commodity deferral account balances. A decision on that application was issued by the OEB in March 2014. Among other things, the OEB determined that revenues derived from the optimization of Union Gas’ upstream transportation contracts in 2012 will be treated as revenues and included in utility earnings instead of a reduction to gas costs. The decision also denied a proposal to recover certain over-refunds to customers and reduced incentive amounts related to Union Gas’ 2011 energy conservation program. As a result of this OEB decision, Union Gas recognized pre-tax income of $10 million in the first quarter of 2014, comprised of a $32 million increase in Transportation, Storage and Processing of Natural Gas revenues, a $15 million decrease in Distribution of Natural Gas revenues and a $7 million decrease in Other revenues on the Condensed Consolidated Statements of Operations. In addition, the decision approved the deferral of pension expense for recovery from customers, resulting in pre-tax income of $7 million, recorded as a reduction in Operating, Maintenance and Other expense in the second quarter of 2014.

In May 2014, Union Gas filed an application with the OEB for the annual disposition of its 2013 non-commodity deferral account balances, excluding the energy conservation deferral accounts for 2012 and 2013 which are expected to be filed by the end of 2014. The combined impact of the 2013 non-commodity deferral account balances is a net payable to customers of approximately $20 million which is primarily reflected as Current Liabilities—Other on the Condensed Consolidated Balance Sheets at September 30, 2014. A settlement agreement was reached on most items in August 2014. A hearing on the remaining unsettled items was held in September 2014 and a decision from the OEB is expected later this year.
5. Income Taxes

Income tax expense was $76 million for the three months ended September 30, 2014, compared with $85 million for the same period in 2013. The lower tax expense was primarily due to lower earnings in 2014, partially offset by favorable tax items in 2013 related to changes in Canadian provincial tax rates and the recognition of certain regulatory tax benefits.

Income tax expense was $305 million for the nine months ended September 30, 2014, compared with $277 million for the same period in 2013. The higher tax expense was primarily attributable to the reversal of tax reserves in the 2013 period as a result of favorable Canadian federal income tax legislation changes as well as changes in Canadian provincial tax rates and the recognition of certain regulatory tax benefits in 2013.

The effective income tax rate was 23% for both the three months ended September 30, 2014 and 2013, and 25% and 24% for the nine-month periods, respectively. The lower effective tax rate in the nine-month period in 2013 was primarily due to the reversal of tax reserves.

There was no material net change in unrecognized tax benefits recorded during the nine-month period ended September 30, 2014. Although uncertain, we believe it is reasonably possible that the total amount of unrecognized tax benefits could decrease by approximately $20 million to $25 million prior to September 30, 2015.

In September 2013, the U.S. Treasury and the Internal Revenue Service (IRS) issued final regulations regarding the deduction and capitalization of expenditures related to tangible property (tangible property regulations). The final IRS regulations apply to amounts paid to acquire, produce, or improve tangible property as well as dispositions of such property and are for tax years beginning on or after January 1, 2014. We are currently evaluating the tangible property regulations and awaiting the release of additional regulations and industry specific guidance. Any changes resulting from the tangible property regulations will affect the timing of deducting expenditures for tax purposes and the impact will be reflected in income tax payable or receivable, deferred taxes and cash paid for income taxes. Our earnings will not be impacted.
6. Earnings per Common Share

Basic earnings per common share (EPS) is computed by dividing net income from controlling interests by the weighted-average number of common shares outstanding during the period. Diluted EPS is computed by dividing net income from controlling interests by the diluted weighted-average number of common shares outstanding during the period. Diluted EPS

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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,
 
 
 
2014
 
2013
 
2014
 
2013
 
 
 
(in millions, except per-share amounts)
 
 
 
 
 
 
 
 
 
 
Net income—controlling interests
$
201

 
$
263

 
$
766

 
$
802

Weighted-average common shares outstanding
 
 
 
 
 
 
 
Basic
671

 
670

 
671

 
669

Diluted
673

 
672

 
672

 
671

Basic and diluted earnings per common share (a)
$
0.30

 
$
0.39

 
$
1.14

 
$
1.20

—————
(a) Quarterly earnings-per-share amounts are stand-alone calculations and may not be additive to full-year amounts due to
rounding.
7. 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, 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

 
 
 
 
 
 
 
 
 
 
June 30, 2013
$
1,609

 
$
(486
)
 
$
(17
)
 
$
(4
)
 
$
1,102

Reclassified to net income

 

 
2

 

 
2

Other AOCI activity
149

 
10

 
1

 
2

 
162

September 30, 2013
$
1,758

 
$
(476
)
 
$
(14
)
 
$
(2
)
 
$
1,266

 
 
 
 
 
 
 
 
 
 
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

 
 
 
 
 
 
 
 
 
 
December 31, 2012
$
2,044

 
$
(507
)
 
$
(23
)
 
$
(5
)
 
$
1,509

Reclassified to net income

 

 
5

 
1

 
6

Other AOCI activity
(286
)
 
31

 
4

 
2

 
(249
)
September 30, 2013
$
1,758

 
$
(476
)
 
$
(14
)
 
$
(2
)
 
$
1,266


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

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8. Inventory

Inventory consists of natural gas and NGLs held in storage for transmission and processing, and also includes materials and supplies. Natural gas inventories primarily relate to the Distribution segment in Canada and are valued at costs approved by the OEB. The difference between the approved price and the actual cost of gas purchased is recorded 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,
2014
 
December 31,
2013
 
(in millions)
Natural gas
$
310

 
$
155

NGLs
58

 
30

Materials and supplies
78

 
78

Total inventory
$
446

 
$
263

9. Investments in and Loans to Unconsolidated Affiliates

Our most significant investment in unconsolidated affiliates is our 50% investment in DCP Midstream, which is accounted for under the equity method of accounting. The following represents summary financial information for DCP Midstream, presented at 100%:
 
 
Three Months
Ended September 30,
 
Nine Months
Ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(in millions)
Operating revenues
$
3,480

 
$
3,068

 
$
10,936

 
$
8,541

Operating expenses
3,281

 
2,823

 
10,313

 
7,944

Operating income
199

 
245

 
623

 
597

Net income
154

 
177

 
449

 
439

Net income attributable to members’ interests
81

 
191

 
335

 
360


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 and $41 million in the third quarters of 2014 and 2013, respectively, and $68 million and $91 million during the nine-month periods ended September 30, 2014 and 2013, respectively, are reflected in Equity in Earnings of Unconsolidated Affiliates in the Condensed Consolidated Statements of Operations.
10. Goodwill

We perform our goodwill impairment test annually and evaluate goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. We completed our annual goodwill impairment test as of April 1, 2014 and no impairments were identified.

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


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The following presents changes in goodwill during 2014:
 
Goodwill
 
(in millions)
December 31, 2013
$
4,810

Acquisition of Express-Platte
37

Foreign currency translation
(79
)
September 30, 2014
$
4,768


See Note 2 for discussion of the acquisition of Express-Platte and an adjustment to Goodwill recorded in the first quarter of 2014 related to the acquisition.
11. Marketable Securities and Restricted Funds

We routinely invest excess cash and various restricted balances in securities such as commercial paper, bankers acceptances, corporate debt securities, treasury bills and money market funds in the United States and Canada. We do not purchase marketable securities for speculative purposes, 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, 2014
 
December 31, 2013
 
(in millions)
Corporate debt securities
$
24

 
$
18

Money market funds
1

 
1

Total available-for-sale securities
$
25

 
$
19


Our AFS securities are classified on the Condensed Consolidated Balance Sheets as follows:
 
 
Estimated Fair Value
 
 
September 30, 2014
 
December 31, 2013
 
 
(in millions)
Restricted funds
 
 
 
Investments and other assets—other
$
1

 
$
1

Non-restricted funds
 
 
 
Current assets—other

 
7

Investments and other assets—other
24

 
11

Total available-for-sale securities
$
25

 
$
19


At September 30, 2014, the weighted-average contractual maturity of outstanding AFS securities was two years.

There were no material gross unrealized holding gains or losses associated with investments in AFS securities at September 30, 2014 or December 31, 2013.


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HTM Securities. All of our HTM securities are restricted funds and are as follows:
 
 
 
Estimated Fair Value
Description
Condensed Consolidated Balance Sheet Caption
September 30, 2014
 
December 31, 2013
 
 
(in millions)
Bankers acceptances
Current assets—other
$
50

 
$
35

Canadian government securities
Current assets—other
32

 
34

Money market funds
Current assets—other
10

 
3

Canadian government securities
Investments and other assets—other
119

 
131

Bankers acceptances
Investments and other assets—other

 
10

Total held-to-maturity securities
$
211

 
$
213


All of our HTM securities are restricted funds pursuant to certain M&N Canada and Express-Platte 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.

At September 30, 2014, the weighted-average contractual maturity of outstanding HTM securities was one year.

There were no material gross unrecognized holding gains or losses associated with investments in HTM securities at September 30, 2014 or December 31, 2013.

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 $20 million at September 30, 2014 and $19 million at December 31, 2013 classified as Current Assets—Other. These restricted funds are related to additional amounts for the M&N Canada debt service requirements and insurance.

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

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Table of Contents


12. Debt and Credit Facilities
Available Credit Facilities and Restrictive Debt Covenants
 
 
Expiration
Date
 
Total
Credit
Facilities
Capacity
 
Commercial Paper Outstanding at September 30, 2014
 
Available
Credit
Facilities
Capacity
 
 
 
 
(in millions)
Spectra Energy Capital, LLC (a)
2018
 
$
1,000

 
$
377

 
$
623

SEP (b)
2018
 
2,000

 
813

 
1,187

Westcoast Energy Inc. (c)
2016
 
268

 
103

 
165

Union Gas (d)
2016
 
357

 
119

 
238

Total
 
 
$
3,625

 
$
1,412

 
$
2,213

 ___________
(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 57% at September 30, 2014.
(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, 2014, this ratio was 3.9 to 1.
(c)
U.S. dollar equivalent at September 30, 2014. The revolving credit facility is 300 million Canadian dollars and contains a covenant that requires the Westcoast Energy Inc. non-consolidated debt-to-total capitalization ratio to not exceed 75%. The ratio was 48% at September 30, 2014.
(d)
U.S. dollar equivalent at September 30, 2014. The revolving credit facility is 400 million Canadian dollars and contains a covenant that requires the Union Gas debt-to-total capitalization ratio to not exceed 75% and a provision which requires Union Gas to repay all borrowings under the facility for a period of two days during the second quarter of each year. The ratio was 66% at September 30, 2014.

The issuances of commercial paper, letters of credit and revolving borrowings reduce the amount available under the credit facilities. As of September 30, 2014, there were no letters of credit issued or revolving borrowings outstanding under the credit facilities.

Our credit agreements and term loans 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, 2014, we were in compliance with those covenants. In addition, our credit agreements and term loans 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 12, 2014, Westcoast Energy Inc. (Westcoast) issued 350 million Canadian dollars (approximately $316 million as of the issuance date) of 3.43% unsecured notes due 2024. Net proceeds from the offering were used for general corporate purposes.
On June 2, 2014, Union Gas issued 200 million Canadian dollars (approximately $183 million as of the issuance date) of 2.76% unsecured notes due 2021 and 250 million Canadian dollars (approximately $229 million as of the issuance date) of 4.20% unsecured notes due 2044. Net proceeds from the offerings were used for general corporate purposes.
In January 2014, Spectra Energy Capital, LLC (Spectra Capital) borrowed the full $300 million available under its unsecured term loan agreement. Interest on the borrowing is based on LIBOR (London Interbank Offered Rate) and the borrowing is due in 2018. Net proceeds from the borrowing were used for general corporate purposes.

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


Description


Condensed Consolidated Balance Sheet Caption
September 30, 2014
Total
 
Level 1
 
Level 2
 
Level 3
 
 
(in millions)
Corporate debt securities
Cash and cash equivalents
$
82

 
$

 
$
82

 
$

Commodity derivatives
Current assets—other
1

 

 

 
1

Corporate debt securities
Investments and other assets—other
24

 

 
24

 

Interest rate swaps
Investments and other assets—other
14

 

 
14

 

Money market funds
Investments and other assets—other
1

 
1

 

 

Total Assets
$
122

 
$
1

 
$
120

 
$
1

Natural gas purchase contracts
Deferred credits and other liabilities—regulatory and other
$
1

 
$

 
$

 
$
1

Commodity derivatives
Deferred credits and other liabilities—regulatory and other
1

 

 

 
1

Interest rate swaps
Deferred credits and other liabilities—regulatory and other
1

 

 
1

 

Total Liabilities
$
3

 
$

 
$
1

 
$
2



Description


Condensed Consolidated Balance Sheet Caption
December 31, 2013
Total
 
Level 1
 
Level 2
 
Level 3
 
 
(in millions)
Corporate debt securities
Cash and cash equivalents
$
49

 
$

 
$
49

 
$

Corporate debt securities
Current assets—other
7

 

 
7

 

Interest rate swaps
Current assets—other
8

 

 
8

 

Corporate debt securities
Investments and other assets—other
11

 

 
11

 

Interest rate swaps
Investments and other assets—other
15

 

 
15

 

Money market funds
Investments and other assets—other
1

 
1

 

 

Total Assets
$
91

 
$
1

 
$
90

 
$

Natural gas purchase contracts
Deferred credits and other liabilities—regulatory and other
$
3

 
$

 
$

 
$
3

Interest rate swaps
Deferred credits and other liabilities—regulatory and other
6

 

 
6

 

Total Liabilities
$
9

 
$

 
$
6

 
$
3


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,
 
2014
 
2013
 
2014
 
2013
 
(in millions)
Derivative assets (liabilities)
 
 
 
 
 
 
 
Fair value, beginning of period
$
(9
)
 
$
(6
)
 
$
(3
)
 
$
(9
)
Total realized/unrealized gains (losses):
 
 
 
 
 
 
 
Included in earnings
7

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

 
2

 
5

 
6

Settlements

 

 
(1
)
 

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

 
$
(1
)
 
$
(2
)
 
$
(2
)


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Level 1

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

Level 2 Valuation Techniques

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

For interest rate swaps, we utilize data obtained from a third-party source for the determination of fair value. Both the future cash flows for the fixed-leg and floating-leg of our swaps are discounted to present value. In addition, credit default swap rates are used to develop the adjustment for credit risk embedded in our positions. We believe that since some of the inputs and assumptions for the calculations of fair value are derived from observable market data, a Level 2 classification is appropriate.

Level 3 Valuation Techniques

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

For natural gas purchases contracts and commodity derivatives, we utilize data obtained from third-party sources for the determination of fair value. The expected future cash flows arising from our swaps are discounted to present value. In addition, credit default swap rates or historical average credit default rates by credit rating are used to develop the adjustment for credit risk embedded in our positions. As these transactions are limited, we believe a Level 3 classification is appropriate.

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, 2014
 
December 31, 2013
 
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)
13,289

 
14,801

 
13,668

 
14,701

__________
(a)
Included within Investments in and Loans to Unconsolidated Affiliates.
(b)
Excludes unamortized items and fair value hedge carrying value adjustments.

The fair value of our long-term debt is determined based on market-based prices as described in the Level 2 valuation technique described above 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 2014 and 2013 periods, there were no material adjustments to assets and liabilities measured at fair value on a nonrecurring basis.

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14. Risk Management and Hedging Activities

We are exposed to the impact of market fluctuations in the prices of NGLs and natural gas purchased as a result of our investment in DCP Midstream, the ownership of the NGL marketing operations in western Canada and processing 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 interest rate swaps and commodity derivatives described below, we did not have any significant derivatives outstanding during the nine months ended September 30, 2014.

Interest Rate Swaps

At September 30, 2014, we had “pay floating—receive fixed” interest rate swaps outstanding with a total notional amount of $1,212 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, 2014
 
December 31, 2013
 
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
$
14

 
$

 
$
14

 
$
23

 
$
3

 
$
20

Liabilities
1

 

 
1

 
6

 
3

 
3


Commodity Derivatives

Effective January 2014, we instituted a commodity price risk management program at Western Canada Transmission & Processing’s Empress NGL business and elected to not apply cash flow hedge accounting.

At September 30, 2014, we had commodity mark-to-market derivatives outstanding with a total notional amount of 163 million gallons. The longest dated commodity derivative contract we currently have expires in 2017.

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


Gross 
Amounts

Gross
Amounts
Offset

Net Amount Presented in the Condensed Consolidated Balance Sheets
Description
(in millions)
Assets
$
177


$
176


$
1

Liabilities
177


176


1


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

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Information regarding the impacts of commodity derivatives on our Condensed Consolidated Statements of Operations are as follows:
 
 
 
 
Periods Ended September 30, 2014
Derivatives
 
Condensed Consolidated Statement of Operations Caption
 
Three Months
 
Nine Months
 
 
 
 
(in millions)
Commodity derivatives
 
Sales of natural gas liquids
 
$
7

 
$

15. Commitments and Contingencies
Environmental
We are subject to various U.S. federal, state and local laws and regulations, as well as Canadian federal and provincial laws, regarding air and water quality, hazardous and solid waste disposal and other environmental matters. These laws and regulations can change from time to time, imposing new obligations on us.
Like others in the energy industry, we and our affiliates are responsible for environmental remediation at various contaminated sites. These include some properties that are part of our ongoing operations, sites formerly owned or used by us, and sites owned by third parties. Remediation typically involves management of contaminated soils and may involve groundwater remediation. Managed in conjunction with relevant federal, state/provincial and local agencies, activities vary with site conditions and locations, remedial requirements, complexity and sharing of responsibility. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, we or our affiliates could potentially be held responsible for contamination caused by other parties. In some instances, we may share liability associated with contamination with other potentially responsible parties, and may also benefit from 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, 2014 or December 31, 2013 related to litigation.
Other Commitments and Contingencies
See Note 16 for a discussion of guarantees and indemnifications.
16. Guarantees and Indemnifications
We have various financial guarantees and indemnifications which are issued in the normal course of business. As discussed below, these contracts include financial guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. We enter into these arrangements to facilitate a commercial transaction with a third party by enhancing the value of the transaction to the third party. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on our Condensed Consolidated Balance Sheets. The possibility of having to perform under these guarantees and indemnifications is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events.
We have issued performance guarantees to customers and other third parties that guarantee the payment and performance of other parties, including certain non-100%-owned entities. In connection with our spin-off from Duke Energy Corporation (Duke Energy) in 2007, certain guarantees that were previously issued by us were assigned to, or replaced by, Duke Energy as guarantor in 2006. For any remaining guarantees of other Duke Energy obligations, Duke Energy has indemnified us against any losses incurred under these guarantee arrangements. The maximum potential amount of future payments we could have been required to make under these performance guarantees as of September 30, 2014 was approximately $406 million, which has been indemnified by Duke Energy as discussed above. One of these outstanding performance guarantees, which has a

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maximum potential amount of future payment of $201 million, expires in 2028. The remaining guarantees have no contractual expirations.
We have also issued joint and several guarantees to some of the Duke/Fluor Daniel (D/FD) project owners, guaranteeing the performance of D/FD under its engineering, procurement and construction contracts and other contractual commitments in place at the time of our spin-off from Duke Energy. D/FD is one of the entities transferred to Duke Energy in connection with our spin-off. Substantially all of these guarantees have no contractual expiration and no stated maximum amount of future payments that we could be required to make. Fluor Enterprises Inc., as 50% owner in D/FD, issued similar joint and several guarantees to the same D/FD project owners.
Westcoast, 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, 2014, the amounts recorded for the guarantees and indemnifications described above are not material, both individually and in the aggregate.
17. Issuances of SEP Units

During the nine months ended September 30, 2014, SEP issued 5.5 million common units to the public under its at-the-market program, representing limited partner interests, and 113,000 general partner units to Spectra Energy. Total net proceeds to SEP were $283 million (net proceeds to Spectra Energy were $277 million). In connection with the issuances of the units, a $71 million gain ($43 million net of tax) to Additional Paid-in Capital and a $206 million increase in Equity-Noncontrolling Interests were recorded during the nine months ended September 30, 2014. The issuances decreased Spectra Energy’s ownership in SEP from 84% to 82% at September 30, 2014.

The following table presents the effects of the issuances of SEP units:
 
 
Three Months
Ended September 30,
 
Nine Months
Ended September 30,
 
 
2014
 
2013
 
2014
 
2013
 
 
(in millions)
Net income-controlling interests
 
$
201

 
$
263

 
$
766

 
$
802

Increase in additional paid-in capital resulting from issuances of SEP units
 
14

 

 
43

 
38

Total net income-controlling interests and changes in equity-controlling interests
 
$
215

 
$
263

 
$
809

 
$
840

18. Employee Benefit Plans

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

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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 the nine months ended September 30, 2014 and $21 million in the same period in 2013. We made total contributions to the Canadian DC and DB plans of $34 million in the nine months ended September 30, 2014 and $62 million in the same period in 2013. We anticipate that we will make total contributions of approximately $22 million to the U.S. plans and approximately $45 million to the Canadian plans in 2014.
Qualified and Non-Qualified Pension Plans—Components of Net Periodic Pension Cost
 
 
Three Months
Ended September 30,
 
Nine Months
Ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(in millions)
U.S.
 
 
 
 
 
 
 
Service cost benefit earned
$
5

 
$
5

 
$
14

 
$
14

Interest cost on projected benefit obligation
7

 
5

 
19

 
16

Expected return on plan assets
(10
)
 
(9
)
 
(29
)
 
(25
)
Amortization of loss
3

 
5

 
9

 
15

Net periodic pension cost
$
5

 
$
6

 
$
13

 
$
20

 
 
 
 
 
 
 
 
Canada
 
 
 
 
 
 
 
Service cost benefit earned
$
7

 
$
9

 
$
22

 
$
25

Interest cost on projected benefit obligation
13

 
13

 
39

 
38

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

 
9

 
17

 
27

Amortization of prior service cost

 

 
1

 
1

Net periodic pension cost
$
9

 
$
14

 
$
27

 
$
41


Other Post-Retirement Benefit Plans. We provide certain health care and life insurance benefits for retired employees on a contributory and non-contributory basis. Employees are eligible for these benefits if they have met age and service requirements at retirement, as defined in the plans.
Other Post-Retirement Benefit Plans—Components of Net Periodic Benefit Cost
 
 
Three Months
Ended September 30,
 
Nine Months
Ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(in millions)
U.S.
 
 
 
 
 
 
 
Service cost benefit earned
$
1

 
$
1

 
$
1

 
$
1

Interest cost on accumulated post-retirement benefit obligation
2

 
2

 
6

 
6

Expected return on plan assets
(1
)
 
(1
)
 
(3
)
 
(3
)
Amortization of loss

 

 

 
1

Net periodic other post-retirement benefit cost
$
2

 
$
2

 
$
4

 
$
5

 
 
 
 
 
 
 
 
Canada
 
 
 
 
 
 
 
Service cost benefit earned
$
1

 
$
1

 
$
3

 
$
3

Interest cost on accumulated post-retirement benefit obligation
1

 
2

 
4

 
5

Net periodic other post-retirement benefit cost
$
2

 
$
3

 
$
7

 
$
8


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Retirement/Savings Plan
In addition to the retirement plans described above, we also have defined contribution employee savings plans available to both U.S. and Canadian employees. Employees may participate in a matching contribution where we match a certain percentage of before-tax employee contributions of up to 6% of eligible pay per pay period for U.S. employees and up to 5% of eligible pay per pay period for Canadian employees. We expensed pre-tax employer matching contributions of $4 million and $3 million in the three-month periods ended September 30, 2014 and 2013, respectively, and $11 million and $10 million in the nine-month periods ended September 30, 2014 and 2013, respectively, for U.S. employees. We expensed pre-tax employer matching contributions of $4 million in both the three-month periods ended September 30, 2014 and 2013 and $10 million in both the nine-month periods ended September 30, 2014 and 2013 for Canadian employees.
19. Consolidating Financial Information
Spectra Energy Corp has agreed to fully and unconditionally guarantee the payment of principal and interest under all series of notes outstanding under the Senior Indenture of Spectra Capital, a 100%-owned, consolidated subsidiary. In accordance with Securities and Exchange Commission (SEC) rules, the following condensed consolidating financial information is presented. The information shown for Spectra Energy Corp and Spectra Capital is presented utilizing the equity method of accounting for investments in subsidiaries, as required. The non-guarantor subsidiaries column represents all consolidated subsidiaries of Spectra Capital. This information should be read in conjunction with our accompanying Condensed Consolidated Financial Statements and notes thereto.

Spectra Energy Corp
Condensed Consolidating Statements of Operations
(Unaudited)
(In millions)
 
Spectra
Energy
Corp
 
Spectra
Capital
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
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

Equity in earnings of unconsolidated affiliates

 

 
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

 
 
 
 
 
 
 
 
 
 
Three Months Ended September 30, 2013
 
 
 
 
 
 
 
 
 
Total operating revenues
$

 
$

 
$
1,146

 
$
(2
)
 
$
1,144

Total operating expenses
4

 

 
809

 
(2
)
 
811

Operating income (loss)
(4
)
 

 
337

 

 
333

Equity in earnings of unconsolidated affiliates

 

 
163

 

 
163

Equity in earnings of consolidated subsidiaries
263

 
403

 

 
(666
)
 

Other income and expenses, net
2

 
10

 
36

 

 
48

Interest expense

 
56

 
111

 

 
167

Earnings before income taxes
261

 
357

 
425

 
(666
)
 
377

Income tax expense (benefit)
(2
)
 
94

 
(7
)
 

 
85

Net income
263

 
263

 
432

 
(666
)
 
292

Net income—noncontrolling interests

 

 
29

 

 
29

Net income—controlling interests
$
263

 
$
263

 
$
403

 
$
(666
)
 
$
263



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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, 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

Equity in earnings of unconsolidated affiliates

 

 
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

 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2013
 
 
 
 
 
 
 
 
 
Total operating revenues
$

 
$

 
$
3,956

 
$
(3
)
 
$
3,953

Total operating expenses
7

 

 
2,756

 
(3
)
 
2,760

Operating income (loss)
(7
)
 

 
1,200

 

 
1,193

Equity in earnings of unconsolidated affiliates

 

 
345

 

 
345

Equity in earnings of consolidated subsidiaries
794

 
1,229

 

 
(2,023
)
 

Other income and expenses, net
(1
)
 
14

 
90

 

 
103

Interest expense

 
155

 
321

 

 
476

Earnings before income taxes
786

 
1,088

 
1,314

 
(2,023
)
 
1,165

Income tax expense (benefit)
(16
)
 
294

 
(1
)
 

 
277

Net income
802

 
794

 
1,315

 
(2,023
)
 
888

Net income—noncontrolling interests

 

 
86

 

 
86

Net income—controlling interests
$
802

 
$
794

 
$
1,229

 
$
(2,023
)
 
$
802





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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, 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
)
 
 
 
 
 
 
 
 
 
 
Three Months Ended September 30, 2013
 
 
 
 
 
 
 
 
 
Net income
$
263

 
$
263

 
$
432

 
$
(666
)
 
$
292

Other comprehensive income
4

 
1

 
160

 

 
165

Total comprehensive income, net of tax
267

 
264

 
592

 
(666
)
 
457

Less: comprehensive income—noncontrolling interests

 

 
30

 

 
30

Comprehensive income—controlling interests
$
267

 
$
264

 
$
562

 
$
(666
)
 
$
427


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

 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2013
 
 
 
 
 
 
 
 
 
Net income
$
802

 
$
794

 
$
1,315

 
$
(2,023
)
 
$
888

Other comprehensive income (loss)
11

 
2

 
(260
)
 

 
(247
)
Total comprehensive income, net of tax
813

 
796

 
1,055

 
(2,023
)
 
641

Less: comprehensive income—noncontrolling interests

 

 
82

 

 
82

Comprehensive income—controlling interests
$
813

 
$
796

 
$
973

 
$
(2,023
)
 
$
559




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Spectra Energy Corp
Condensed Consolidating Balance Sheet
September 30, 2014
(Unaudited)
(In millions)
 
 
Spectra
Energy
Corp
 
Spectra
Capital
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Cash and cash equivalents
$

 
$
1

 
$
220

 
$

 
$
221

Receivables—consolidated subsidiaries
14

 

 
14

 
(28
)
 

Receivables—other
1

 

 
1,201

 

 
1,202

Other current assets
13

 
7

 
809

 

 
829

Total current assets
28

 
8

 
2,244

 
(28
)
 
2,252

Investments in and loans to unconsolidated
affiliates

 

 
3,008

 

 
3,008

Investments in consolidated subsidiaries
14,487

 
20,711

 

 
(35,198
)
 

Advances receivable—consolidated subsidiaries

 
4,448

 
914

 
(5,362
)
 

Notes receivable—consolidated subsidiaries

 

 
3,224

 
(3,224
)
 

Goodwill

 

 
4,768

 

 
4,768

Other assets
37

 
26

 
307

 

 
370

Property, plant and equipment, net

 

 
22,201

 

 
22,201

Regulatory assets and deferred debits
2

 
15

 
1,385

 

 
1,402

Total Assets
$
14,554

 
$
25,208

 
$
38,051

 
$
(43,812
)
 
$
34,001

 
 
 
 
 
 
 
 
 
 
Accounts payable—other
$
3

 
$

 
$
475

 
$

 
$
478

Accounts payable—consolidated subsidiaries

 
16

 
12

 
(28
)
 

Commercial paper

 
377

 
1,035

 

 
1,412

Short-term borrowings—consolidated
subsidiaries

 
424

 

 
(424
)
 

Taxes accrued
3

 
21

 
80

 

 
104

Current maturities of long-term debt

 

 
220

 

 
220

Other current liabilities
77

 
47

 
1,153

 

 
1,277

Total current liabilities
83

 
885

 
2,975

 
(452
)
 
3,491

Long-term debt

 
2,893

 
10,179

 

 
13,072

Advances payable—consolidated subsidiaries
5,362

 

 

 
(5,362
)
 

Notes payable—consolidated subsidiaries

 
2,800

 

 
(2,800
)
 

Deferred credits and other liabilities
753

 
4,143

 
1,746

 

 
6,642

Preferred stock of subsidiaries

 

 
258

 

 
258

Equity
 
 
 
 
 
 
 
 
 
Controlling interests
8,356

 
14,487

 
20,711

 
(35,198
)
 
8,356

Noncontrolling interests

 

 
2,182

 

 
2,182

Total equity
8,356

 
14,487

 
22,893

 
(35,198
)
 
10,538

Total Liabilities and Equity
$
14,554

 
$
25,208

 
$
38,051

 
$
(43,812
)
 
$
34,001




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Spectra Energy Corp
Condensed Consolidating Balance Sheet
December 31, 2013
(Unaudited)
(In millions)
 
 
Spectra
Energy
Corp
 
Spectra
Capital
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Cash and cash equivalents
$

 
$
12

 
$
189

 
$

 
$
201

Receivables—consolidated subsidiaries
176

 
394

 

 
(570
)
 

Receivables—other
1

 

 
1,335

 

 
1,336

Other current assets
40

 
15

 
489

 

 
544

Total current assets
217

 
421

 
2,013

 
(570
)
 
2,081

Investments in and loans to unconsolidated
affiliates

 

 
3,043

 

 
3,043

Investments in consolidated subsidiaries
13,244

 
19,403

 

 
(32,647
)
 

Advances receivable—consolidated subsidiaries

 
4,038

 
677

 
(4,715
)
 

Notes receivable—consolidated subsidiaries

 

 
3,215

 
(3,215
)
 

Goodwill

 

 
4,810

 

 
4,810

Other assets
39

 
30

 
316

 

 
385

Property, plant and equipment, net

 

 
21,829

 

 
21,829

Regulatory assets and deferred debits
3

 
17

 
1,365

 

 
1,385

Total Assets
$
13,503

 
$
23,909

 
$
37,268

 
$
(41,147
)
 
$
33,533

 
 
 
 
 
 
 
 
 
 
Accounts payable—other
$
4

 
$

 
$
436

 
$

 
$
440

Accounts payable—consolidated subsidiaries
89

 

 
481

 
(570
)
 

Commercial paper

 
344

 
688

 

 
1,032

Short-term borrowings—consolidated
subsidiaries

 
415

 

 
(415
)
 

Taxes accrued
4

 

 
68

 

 
72

Current maturities of long-term debt

 
557

 
640

 

 
1,197

Other current liabilities
81

 
75

 
1,142

 

 
1,298

Total current liabilities
178

 
1,391

 
3,455

 
(985
)
 
4,039

Long-term debt

 
2,605

 
9,883

 

 
12,488

Advances payable—consolidated subsidiaries
4,715

 

 

 
(4,715
)
 

Notes payable—consolidated subsidiaries

 
2,800

 

 
(2,800
)
 

Deferred credits and other liabilities
116

 
3,869

 
2,440

 

 
6,425

Preferred stock of subsidiaries

 

 
258

 

 
258

Equity
 
 
 
 
 
 
 
 
 
Controlling interests
8,494

 
13,244

 
19,403

 
(32,647
)
 
8,494

Noncontrolling interests

 

 
1,829

 

 
1,829

Total equity
8,494

 
13,244

 
21,232

 
(32,647
)
 
10,323

Total Liabilities and Equity
$
13,503

 
$
23,909

 
$
37,268

 
$
(41,147
)
 
$
33,533




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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

Equity in earnings of unconsolidated affiliates

 

 
(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

Dividends paid on common stock
(677
)
 

 

 

 
(677
)
Proceeds from the issuance of SEP common units

 

 
277

 

 
277

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


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Spectra Energy Corp
Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2013
(Unaudited)
(In millions)
 
 
Spectra
Energy
Corp
 
Spectra
Capital
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
 
 
 
 
 
 
Net income
$
802

 
$
794

 
$
1,315

 
$
(2,023
)
 
$
888

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

 

 
587

 

 
587

Equity in earnings of unconsolidated affiliates

 

 
(345
)
 

 
(345
)
Equity in earnings of consolidated subsidiaries
(794
)
 
(1,229
)
 

 
2,023

 

Distributions received from unconsolidated affiliates

 

 
215

 

 
215

Other
(18
)
 
812

 
(739
)
 

 
55

Net cash provided by (used in) operating activities
(10
)
 
377

 
1,033

 

 
1,400

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
 
 
 
 
 
 
Capital expenditures

 

 
(1,476
)
 

 
(1,476
)
Investments in and loans to unconsolidated affiliates

 

 
(224
)
 

 
(224
)
Acquisitions, net of cash acquired

 

 
(1,254
)
 

 
(1,254
)
Purchases of held-to-maturity securities

 

 
(632
)
 

 
(632
)
Proceeds from sales and maturities of held-to-maturity securities

 

 
623

 

 
623

Purchases of available-for-securities

 

 
(5,665
)
 

 
(5,665
)
Proceeds from sales and maturities of available-for-sale securities

 

 
3,810

 

 
3,810

Distributions received from unconsolidated affiliates

 

 
17

 

 
17

Advances from (to) affiliates
153

 
(1,039
)
 

 
886

 

Other changes in restricted funds

 

 
(1
)
 

 
(1
)
Other

 

 
2

 

 
2

Net cash provided by (used in) investing activities
153

 
(1,039
)
 
(4,800
)
 
886

 
(4,800
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
 
 
 
 
 
 
Proceeds from the issuance of long-term debt

 
1,848

 
2,124

 

 
3,972

Payments for the redemption of long-term debt

 
(745
)
 
(51
)
 

 
(796
)
Net increase in commercial paper

 
713

 
90

 

 
803

Net increase in short-term borrowings—consolidated subsidiaries

 
180

 

 
(180
)
 

Distributions to noncontrolling interests

 

 
(104
)
 

 
(104
)
Dividends paid on common stock
(616
)
 

 

 

 
(616
)
Proceeds from the issuance of SEP common units

 

 
190

 

 
190

Distributions and advances from (to) affiliates
447

 
(1,330
)
 
1,589

 
(706
)
 

Other
26

 
(5
)
 
(3
)
 

 
18

Net cash provided by (used in) financing activities
(143
)
 
661

 
3,835

 
(886
)
 
3,467

Effect of exchange rate changes on cash

 

 
(1
)
 

 
(1
)
Net increase (decrease) in cash and cash equivalents

 
(1
)
 
67

 

 
66

Cash and cash equivalents at beginning of period

 
3

 
91

 

 
94

Cash and cash equivalents at end of period
$

 
$
2

 
$
158

 
$

 
$
160


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20. 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. This ASU is effective for us January 1, 2017 and is to be applied retrospectively. We are currently evaluating this ASU and its potential impact on us.

In April 2014, the FASB issued ASU No. 2014-08, “Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.” This ASU revises the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have or will have a major effect on an entity’s operations and financial results, removing the lack of continuing involvement criteria and requiring discontinued operations reporting for the disposal of an equity method investment that meets the definition of discontinued operations. The update also requires expanded disclosures for discontinued operations, and disclosure of pretax profit or loss of certain individually significant components of an entity that do not qualify for discontinued operations reporting. This ASU is effective for us on January 1, 2015 and is to be applied prospectively. We do not expect the adoption of the provisions of this ASU to have any impact on our consolidated results of operations, financial position or cash flows.

In 2013, the FASB issued ASU 2013-11, “Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (a Consensus of the FASB Emerging Issues Task Force),” which was issued to eliminate diversity in practice. This ASU requires entities to net unrecognized tax benefits against all same-jurisdiction net operating losses or tax credit carryforwards that would be used to settle the position with a tax authority. We adopted this standard on January 1, 2014. The adoption of this ASU did not have a material impact on our consolidated results of operations, financial position or cash flows.
21. Subsequent Events

On November 3, 2014, Spectra Energy contributed a 24.95% ownership interest in Southeast Supply Header, LLC (SESH) and a 1% interest in Steckman Ridge, LP to SEP. Total consideration to Spectra Energy was approximately 4.3 million newly issued SEP common units. This is the second of three planned transactions related to the U.S. Assets Dropdown. The remaining transaction, expected to occur in November 2015, will consist of Spectra Energy’s remaining 0.1% interest in SESH. Also, in connection with this transaction, SEP issued approximately 86,000 of newly issued 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.
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.
In November 2013, Spectra Energy completed the U.S. Assets Dropdown to SEP. As a result of this transaction, we realigned our reportable segments structure. Amounts presented herein for 2013 segment information have been recast to conform to our current segment reporting presentation. There were no changes to consolidated data as a result of the recast of our segment information.
Executive Overview
For the three months ended September 30, 2014 and 2013, we reported net income from controlling interests of $201 million and $263 million, respectively. For the nine months ended September 30, 2014 and 2013, we reported net income from controlling interests of $766 million and $802 million, respectively.
The highlights for the three months and nine months ended September 30, 2014 include the following:
Spectra Energy Partners’ earnings for the three-month period benefited mainly from expansion projects primarily at Texas Eastern Transmission, LP (Texas Eastern), higher earnings from the continued ramp up of volumes at DCP Sand Hills Pipeline, LLC (Sand Hills) and DCP Southern Hills Pipeline, LLC (Southern Hills) and higher crude oil transportation revenues as a result of higher contracted volumes on Express and increased tariff rates on both the

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Express and Platte pipelines. For the nine-month period, the increased earnings were driven by expansion projects primarily at Texas Eastern, the acquisition of Express-Platte in March 2013 and higher Express-Platte earnings due to higher contracted volumes and increased tariff rates, higher natural gas transportation revenues as a result of colder weather and higher earnings from Sand Hills and Southern Hills, partially offset by lower storage revenues due to lower contract renewal rates.
Distribution’s earnings for the three-month period decreased slightly mainly due to a weaker Canadian dollar, offset by lower operating and maintenance expense. For the nine-month period, the increase in earnings was mainly due to higher customer usage as a result of colder weather and a favorable decision by the OEB in 2014 primarily regarding certain 2012 revenues realized from the optimization of upstream transportation contracts being treated as utility earnings, substantially offset by a weaker Canadian dollar, lower 2014 distribution rates approved by the OEB and lower transportation revenues primarily due to a settlement received from the termination of a transportation contract in 2013.
Western Canada Transmission & Processing’s earnings for the three-month period decreased, reflecting mainly higher plant turnaround and maintenance costs and a weaker Canadian dollar, partially offset by higher NGL margins due primarily to mark-to-market net gains on commodity derivatives. The decrease in earnings for the nine-month period reflected higher operating and maintenance expense and a weaker Canadian dollar, partially offset by higher earnings from the Empress NGL business due primarily to higher propane prices, higher gathering and processing earnings and higher transmission earnings as a result of higher tolls.
Field Services’ earnings for the three-month period decreased largely due to increased net income attributable to noncontrolling interests as a result of the effect of hedges and growth from dropdowns to DCP Partners, a decrease in gains associated with the issuance of partnership units by DCP Partners, weaker commodity prices, higher operating costs as a result of increased spending on reliability programs, as well as growth in Field Services’ operations, losses on sales of assets and a goodwill impairment charge, partially offset by higher gathering and processing volumes from new assets. The decrease in earnings for the nine-month period was driven by higher operating expense as a result of increased spending on reliability programs, including turnarounds, as well as growth in Field Services’ operations, gains associated with the issuance of partnership units by DCP Partners, higher interest expense, increased net income attributable to noncontrolling interests resulting from the effects of growth in DCP Partners’ operations, net of the effects of dropdown hedges, higher depreciation expense and losses on sales of assets and a goodwill impairment charge, partially offset by higher gathering and processing volumes from new assets, stronger commodity prices, and favorable results from NGL and gas trading and marketing.
We declared a quarterly cash dividend of $0.37 per common share on November 4, 2014, representing an increase of over 10% from the previous quarter’s dividend, payable on December 9, 2014 to shareholders of record at the close of business on November 17, 2014.
For the nine months ended September 30, 2014, we had $1.7 billion of capital and investment expenditures. We currently project $2.3 billion of capital and investment expenditures for the full year, including expansion capital expenditures of $1.3 billion.
We are committed to an investment-grade balance sheet and continued prudent financial management of our capital structure. Therefore, financing these growth activities will continue to be based on our strong and growing fee-based earnings and cash flows as well as the issuances of debt and/or equity securities. As of September 30, 2014, our revolving credit facilities included Spectra Capital’s $1.0 billion facility, SEP’s $2.0 billion facility, Westcoast’s 300 million Canadian dollar facility and Union Gas’ 400 million Canadian dollar facility. These facilities are used principally as back-stops for commercial paper programs.

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RESULTS OF OPERATIONS
 
Three Months
Ended September 30,
 
Nine Months
Ended September 30,
 
2014
 
2013
 
2014
 
2013
 
(in millions)
Operating revenues
$
1,207

 
$
1,144

 
$
4,303

 
$
3,953

Operating expenses
825

 
811

 
2,944

 
2,760

Operating income
382

 
333

 
1,359

 
1,193

Other income and expenses
115

 
211

 
376

 
448

Interest expense
167

 
167

 
521

 
476

Earnings before income taxes
330

 
377

 
1,214

 
1,165

Income tax expense
76

 
85

 
305

 
277

Net income
254

 
292

 
909

 
888

Net income—noncontrolling interests
53

 
29

 
143

 
86

Net income—controlling interests
$
201

 
$
263

 
$
766

 
$
802

Three Months Ended September 30, 2014 Compared to Same Period in 2013
Operating Revenues. The $63 million, or 6%, increase was driven by:
revenues from expansion projects, primarily at Texas Eastern and higher crude oil transportation revenues as a result of higher contracted volumes on Express and increased tariff rates on both the Express and Platte pipelines at Spectra Energy Partners,
higher sales volumes of residual natural gas at the Empress operations and unrealized mark-to-market net gains on commodity derivatives associated with the Empress NGL business at Western Canada Transmission & Processing, and
higher natural gas prices passed through to customers and an increase from growth in the number of customers at Distribution, partially offset by
the effects of a weaker Canadian dollar at Distribution and Western Canada Transmission & Processing.
Operating Expenses. The $14 million, or 2%, increase was driven by:
increased volumes of natural gas purchases for extraction and make-up at the Empress operations, higher plant turnaround and maintenance costs, and higher Empress plant fuel costs due primarily to higher prices at Western Canada Transmission & Processing, and
increased natural gas prices passed through to customers, growth in the number of customers and higher operating fuel costs, net of decreased operating and maintenance expense primarily driven by lower employee benefits costs at Distribution, partially offset by
lower corporate costs, primarily transaction costs related to the U.S. Assets Dropdown in 2013, and
the effects of a weaker Canadian dollar at Distribution and Western Canada Transmission & Processing.
Operating Income. The $49 million, or 15%, increase was due mainly to higher earnings from expansion projects primarily at Texas Eastern and higher crude oil transportation revenues at Express-Platte as a result of higher contracted volumes and increased tariff rates at Spectra Energy Partners, partially offset by turnaround and maintenance expense, net of higher NGL margins due primarily to unrealized mark-to-market net gains on commodity derivatives at Western Canada Transmission & Processing, higher operating fuel costs, net of lower operating and maintenance expense at Distribution, and the effects of a weaker Canadian dollar at Distribution and Western Canada Transmission & Processing.
Other Income and Expenses. The $96 million, or 45%, decrease was due to lower equity earnings from Field Services mainly due to increased net income attributable to noncontrolling interests as a result of the effect of hedges and growth from dropdowns to DCP Partners, decreased gains associated with issuances of partnership units by DCP Partners, losses on sales of assets and a goodwill impairment charge, lower commodity prices and higher operating expense due to increased spending on reliability programs, as well as growth, net of higher gathering and processing volumes as a result of asset growth in Field Services’ operations. The decrease was also due to lower allowance for funds used during construction (AFUDC) as a result of decreased capital spending on expansion projects, partially offset by higher earnings from the continued ramp up of volumes on Sand Hills and Southern Hills at Spectra Energy Partners.

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Interest Expense. Interest expense remained the same as 2013. Lower capitalized interest from projects placed in service in 2013 and higher debt balances attributable to the debt issued in late September 2013 by SEP, primarily related to the U.S Assets Dropdown, were offset by a weaker Canadian dollar.
Income Tax Expense. The $9 million decrease was mainly attributable to lower earnings in 2014 partially offset by changes in Canadian provincial tax rates and the recognition of certain regulatory tax benefits in 2013.  
The effective income tax rate was 23% for both the three-month periods ended September 30, 2014 and 2013.
Net Income—Noncontrolling Interests. The $24 million increase was driven by higher earnings from Spectra Energy Partners, partially offset by the effects of a decrease in the average ownership percentage of SEP held by the public, primarily as a result of the issuance of SEP partnership units to Spectra Energy in November 2013 in association with the U.S. Assets Dropdown.
Nine Months Ended September 30, 2014 Compared to Same Period in 2013
Operating Revenues. The $350 million, or 9%, increase was driven by:
revenues from expansion projects primarily at Texas Eastern, the acquisition of Express-Platte in March 2013 and higher crude oil transportation revenues due to higher contracted volumes on Express and increased tariff rates on both the Express and Platte pipelines, and higher natural gas transportation revenues due to colder weather, net of lower gas storage revenues due to lower contract renewal rates at Spectra Energy Partners,
higher sales volumes of residual natural gas and higher propane sales prices at the Empress operations, an increase in gathering and processing revenues from new facilities in unconventional development areas, higher transmission revenues as a result of higher tolls and higher interruptible transmission revenues from a new supply source connected to the M&N Canada system at Western Canada Transmission & Processing, and
higher customer usage of natural gas as a result of colder weather, growth in the number of customers and a favorable decision by the OEB in 2014 primarily regarding certain 2012 revenues realized from the optimization of upstream transportation contracts being treated as utility earnings, net of lower 2014 distribution rates approved by the OEB and lower transportation revenues due to a settlement received from the termination of a transportation contract in 2013 at Distribution, partially offset by
the effects of a weaker Canadian dollar at Distribution and Western Canada Transmission & Processing.
Operating Expenses. The $184 million, or 7%, increase was driven by:
increased volumes of natural gas purchases for extraction and make-up at the Empress operations, higher operating and maintenance costs, increased costs passed through to customers at M&N Canada and higher plant fuel costs due to higher prices at the Empress operations at Western Canada Transmission & Processing,
expansion projects, primarily at Texas Eastern, and the acquisition of Express-Platte, net of lower operating expenses, including transaction costs related to the U.S. Assets Dropdown at Spectra Energy Partners, and
increased volumes of natural gas sold due to colder weather and growth in the number of customers, net of the deferral of pension expense approved by the OEB for recovery from customers at Distribution, partially offset by
the effects of a weaker Canadian dollar at Distribution and Western Canada Transmission & Processing.
Operating Income. The $166 million, or 14%, increase was driven by higher earnings from expansion projects primarily at Texas Eastern and the acquisition of Express-Platte in March 2013 and higher Express-Platte earnings due to higher contracted volumes on Express and increased tariff rates on both the Express and Platte pipelines, net of higher operating and maintenance expense at Spectra Energy Partners, increased earnings from the Empress NGL business due primarily to higher propane sales prices, net of higher operating and maintenance costs at Western Canada Transmission & Processing and higher customer usage of natural gas as a result of colder weather and a favorable decision by the OEB in 2014 primarily regarding certain 2012 revenues realized from the optimization of upstream transportation contracts being treated as utility earnings, net of lower distribution rates and transportation revenues at Distribution, partially offset by the effects of a weaker Canadian dollar at Distribution and Western Canada Transmission & Processing.
Other Income and Expenses. The $72 million, or 16%, decrease was attributable to lower equity earnings from Field Services mainly due to higher operating expense due to increased spending on reliability programs, including turnarounds, as well as growth, decreased gains associated with issuances of partnership units by DCP Partners, higher interest expense, increased net income attributable to noncontrolling interests resulting from the effects of growth in DCP Partners’ operations, net of the effects of dropdown hedges, losses on sales of assets and a goodwill impairment charge, higher depreciation as a

36

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result of growth, net of higher gathering and processing volumes as a result of asset growth, higher commodity prices and favorable results from NGL and gas trading and marketing, net of DCP Partners’ third-party mark-to-market activity. The decrease was also attributable to lower AFUDC due to decreased capital spending on expansion projects, net of higher earnings from Sand Hills and Southern Hills at Spectra Energy Partners.
Interest Expense. The $45 million, or 9%, increase was mainly due to lower capitalized interest from projects placed in service in 2013 and higher debt balances attributable to debt issued by SEP in late September 2013, primarily related to the U.S. Assets Dropdown, partially offset by a weaker Canadian dollar.
Income Tax Expense. The $28 million increase was mainly attributable to the reversal of tax reserves in the 2013 period as a result of favorable Canadian federal income tax legislation changes as well as changes in Canadian provincial tax rates and the recognition of certain regulatory tax benefits in 2013.
The effective income tax rate for the nine months ended September 30, 2014 and 2013 was 25% and 24%, respectively. The lower effective tax rate in 2013 was primarily due to the reversal of tax reserves.
Net Income—Noncontrolling Interests. The $57 million increase was driven by higher earnings from Spectra Energy Partners, partially offset by the effects of a decrease in the average ownership percentage of SEP held by the public, primarily as a result of the issuance of SEP partnership units to Spectra Energy in November 2013 associated with the U.S. Assets Dropdown.
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.
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,
 
2014
 
2013
 
2014
 
2013
 
(in millions)
Spectra Energy Partners
$
422

 
$
360

 
$
1,225

 
$
1,065

Distribution
82

 
83

 
420

 
418

Western Canada Transmission & Processing
156

 
174

 
504

 
521

Field Services
51

 
137

 
235

 
271

Total reportable segment EBITDA
711

 
754

 
2,384

 
2,275

Other
(19
)
 
(19
)
 
(60
)
 
(62
)
Total reportable segment and other EBITDA
692

 
735

 
2,324

 
2,213

Depreciation and amortization
201

 
195

 
600

 
577

Interest expense
167

 
167

 
521

 
476

Interest income and other
6

 
4

 
11

 
5

Earnings before income taxes
$
330

 
$
377

 
$
1,214

 
$
1,165

The amounts discussed below include intercompany transactions that are eliminated in the Condensed Consolidated Financial Statements.

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Spectra Energy Partners
 
Three Months
Ended September 30,
 
Nine Months
Ended September 30,
 
2014
 
2013
 
Increase (Decrease)
 
2014
 
2013
 
Increase (Decrease)
 
(in millions, except where noted)
Operating revenues
$
558

 
$
494

 
$
64

 
$
1,670

 
$
1,445

 
$
225

Operating expenses
 
 
 
 
 
 
 
 
 
 
 
        Operating, maintenance and other
190

 
191

 
(1
)
 
568

 
524

 
44

Other income and expenses
54

 
57

 
(3
)
 
123

 
144

 
(21
)
EBITDA
$
422

 
$
360

 
$
62

 
$
1,225

 
$
1,065

 
$
160

Express pipeline revenue receipts, MBbl/d (a,b)
221

 
210

 
11

 
217

 
209

 
8

Platte PADD II deliveries, MBbl/d (b)
169

 
173

 
(4
)
 
170

 
169

 
1

___________
(a)
Thousand barrels per day.
(b)
2013 data includes only activity since March 14, 2013, the date of the acquisition of Express-Platte.
Three Months Ended September 30, 2014 Compared to Same Period in 2013
Operating Revenues. The $64 million increase was driven by:
a $45 million increase due to expansion projects, primarily at Texas Eastern,
a $12 million increase due to higher processing revenues,
a $5 million increase in crude oil transportation revenues as a result of higher contracted volumes on Express and increased tariff rates on both the Express and Platte pipelines,
a $4 million increase due to higher natural gas transportation revenues as a result of new contracts mainly at Texas Eastern and Algonquin Gas Transmission, LLC, and
a $3 million increase in recoveries of electric power and other costs passed through to customers, partially offset by
a $7 million decrease in gas storage revenues due to lower contract renewal rates.
Operating, Maintenance and Other. The $1 million decrease was driven by:
a $10 million decrease primarily from transaction costs related to the U.S. Assets Dropdown in 2013, and
a $7 million decrease primarily in ad valorem taxes, partially offset by
a $7 million increase from expansion projects, primarily at Texas Eastern,
a $5 million increase from support services and other costs, and
a $3 million increase in electric power and other costs passed through to customers.
Other Income and Expenses. The $3 million decrease was primarily due to lower AFUDC resulting from decreased capital spending on expansion projects, partially offset by higher equity earnings from the continued ramp up of volumes on Sand Hills and Southern Hills.
EBITDA. The $62 million increase was driven by expansions, primarily at Texas Eastern, higher earnings from the continued ramp up of volumes at Sand Hills and Southern Hills, higher processing revenues and higher crude oil transportation revenues as a result of higher contracted volumes on Express and increased tariff rates on both the Express and Platte pipelines.
Nine Months Ended September 30, 2014 Compared to Same Period in 2013
Operating Revenues. The $225 million increase was driven by:
a $130 million increase due to expansion projects, primarily at Texas Eastern,
a $68 million increase primarily due to the acquisition of Express-Platte,
a $30 million increase due to higher natural gas transportation revenues from higher demand, primarily as a result of colder weather,

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a $9 million increase primarily in crude oil transportation revenues as a result of higher contracted volumes on Express and increased tariff rates on both the Express and Platte pipelines, and
a $5 million increase due to higher processing revenues, partially offset by
an $18 million decrease in gas storage revenues due to lower contract renewal rates.
Operating, Maintenance and Other. The $44 million increase was driven by:
a $30 million increase from expansion projects, primarily at Texas Eastern,
a $25 million increase due to the acquisition of Express-Platte, and
a $4 million increase from project development costs expensed in 2014, partially offset by
a $10 million decrease primarily from transaction costs related to the U.S. Assets Dropdown in 2013, and
a $7 million decrease primarily in ad valorem taxes.
Other Income and Expenses. The $21 million decrease was mainly due to lower AFUDC resulting from decreased capital spending on expansion projects, partially offset by higher equity earnings from Sand Hills and Southern Hills.
EBITDA. The $160 million increase was driven by expansions, primarily at Texas Eastern, the acquisition of Express-Platte and higher crude oil transportation revenues as a result of higher contracted volumes on Express and increased tariff rates on both the Express and Platte pipelines, higher natural gas transportation revenues from higher demand, primarily as a result of colder weather, and higher equity earnings from Sand Hills and Southern Hills, partially offset by lower gas storage revenues due to lower contract renewal rates.
Distribution 
 
Three Months
Ended September 30,
 
Nine Months
Ended September 30,
 
2014
 
2013
 
Increase (Decrease)
 
2014
 
2013
 
Increase (Decrease)
 
(in millions, except where noted)
Operating revenues
$
260

 
$
264

 
$
(4
)
 
$
1,338

 
$
1,315

 
$
23

Operating expenses
 
 
 
 
 
 
 
 
 
 
 
        Natural gas purchased
78

 
70

 
8

 
618

 
567

 
51

        Operating, maintenance and other
100

 
111

 
(11
)
 
299

 
330

 
(31
)
Other income and expenses

 

 

 
(1
)
 

 
(1
)
EBITDA
$
82

 
$
83

 
$
(1
)
 
$
420

 
$
418

 
$
2

Number of customers, thousands
 
 
 
 
 
 
1,410

 
1,390

 
20

Heating degree days, Fahrenheit
354

 
356

 
(2
)
 
5,584

 
4,844

 
740

Pipeline throughput, TBtu (a)
121

 
157

 
(36
)
 
536

 
666

 
(130
)
Canadian dollar exchange rate, average
1.09

 
1.04

 
0.05

 
1.09

 
1.02

 
0.07

___________
(a)
Trillion British thermal units.
Three Months Ended September 30, 2014 Compared to Same Period in 2013
Operating Revenues. The $4 million decrease was driven by:
a $13 million decrease resulting from a weaker Canadian dollar, mostly offset by
a $7 million increase from higher natural gas prices passed through to customers. Prices charged to customers are adjusted quarterly based on the 12 month New York Mercantile Exchange (NYMEX) forecast, and
a $4 million increase from growth in the number of customers.
Natural Gas Purchased. The $8 million increase was driven by:
a $7 million increase from higher natural gas prices passed through to customers, and
a $2 million increase from growth in the number of customers, partially offset by
a $4 million decrease resulting from a weaker Canadian dollar.

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Operating, Maintenance and Other. The $11 million decrease was driven by:
a $7 million decrease resulting from a weaker Canadian dollar, and
a $5 million decrease primarily due to lower employee benefits costs.
EBITDA. The $1 million decrease was largely the result of a weaker Canadian dollar and higher operating fuel costs, mostly offset by lower operating and maintenance expense.
Nine Months Ended September 30, 2014 Compared to Same Period in 2013
Operating Revenues. The $23 million increase was driven by:
a $107 million increase in customer usage of natural gas primarily due to weather that was more than 15% colder than in 2013,
a $25 million increase from growth in the number of customers,
a $10 million increase, net of earnings sharing, as a result of a decision by the OEB in March 2014 primarily regarding certain 2012 revenues realized from the optimization of upstream transportation contracts being treated as utility earnings,
a $9 million increase in industrial market usage, and
a $7 million increase from higher natural gas prices passed through to customers, partially offset by
a $105 million decrease resulting from a weaker Canadian dollar,
a $10 million decrease primarily due to lower 2014 distribution rates approved by the OEB,
a $9 million decrease in transportation revenues primarily due to a settlement received from the termination of a transportation contract in 2013 and lower long-term transportation revenues,
a $6 million decrease in storage revenues primarily due to lower storage prices, and
a $6 million decrease due to 2014 earnings to be shared with customers in accordance with the new incentive regulation framework.
Natural Gas Purchased. The $51 million increase was driven by:
a $77 million increase due to higher volumes of natural gas sold primarily due to colder weather,
a $19 million increase from growth in the number of customers,
a $7 million increase from higher natural gas prices passed through to customers, and
a $7 million increase in industrial market usage, partially offset by
a $51 million decrease resulting from a weaker Canadian dollar.
Operating, Maintenance and Other. The $31 million decrease was driven by:
a $21 million decrease resulting from a weaker Canadian dollar, and
a $7 million decrease resulting from the deferral of pension expense approved by the OEB for recovery from customers.
EBITDA. The $2 million increase was largely the result of higher customer usage due to colder weather, the impact of a decision by the OEB in March 2014 primarily regarding certain 2012 revenues realized from the optimization of upstream transportation contracts being treated as utility earnings, lower pension expense and increased customer growth, mostly offset by a weaker Canadian dollar, lower 2014 distribution rates approved by the OEB and lower transportation and storage revenues.

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Western Canada Transmission & Processing
 
Three Months
Ended September 30,
 
Nine Months
Ended September 30,
 
2014
 
2013
 
Increase (Decrease)
 
2014
 
2013
 
Increase (Decrease)
 
(in millions, except where noted)
Operating revenues
$
417

 
$
400

 
$
17

 
$
1,383

 
$
1,234

 
$
149

Operating expenses
 
 
 
 
 
 
 
 
 
 
 
        Natural gas and petroleum products purchased
87

 
68

 
19

 
352

 
238

 
114

        Operating, maintenance and other
174

 
156

 
18

 
528

 
482

 
46

Other income and expenses

 
(2
)
 
2

 
1

 
7

 
(6
)
EBITDA
$
156

 
$
174

 
$
(18
)
 
$
504

 
$
521

 
$
(17
)
Pipeline throughput, TBtu
219

 
190

 
29

 
685

 
563

 
122

Volumes processed, TBtu
179

 
168

 
11

 
531

 
500

 
31

Canadian dollar exchange rate, average
1.09

 
1.04

 
0.05

 
1.09

 
1.02

 
0.07

Three Months Ended September 30, 2014 Compared to Same Period in 2013
Operating Revenues. The $17 million increase was driven by:
a $30 million increase due primarily to higher sales volumes of residual natural gas at the Empress operations, and
a $7 million increase due to unrealized mark-to-market net gains on commodity derivatives associated with the Empress NGL business, partially offset by
a $20 million decrease as a result of a weaker Canadian dollar.
Natural Gas and Petroleum Products Purchased. The $19 million increase was driven by:
a $27 million increase due primarily to higher volumes of natural gas purchases for extraction and make-up at Empress, partially offset by
a $5 million decrease as a result of a weaker Canadian dollar and
a $3 million decrease primarily as a result of lower costs of NGL purchases at the Empress facility.
Operating, Maintenance and Other. The $18 million increase was driven by:
a $15 million increase in plant turnaround and repair costs,
a $4 million increase in maintenance expense,
a $4 million increase in Empress plant fuel costs due primarily to higher prices, and
a $4 million increase in project development costs and labor costs, partially offset by
an $8 million decrease as a result of a weaker Canadian dollar.
EBITDA. The $18 million decrease was due mainly to higher plant turnaround costs and the effect of a weaker Canadian dollar, partially offset by higher NGL margins resulting primarily from unrealized mark-to-market net gains on commodity derivatives.
Nine Months Ended September 30, 2014 Compared to Same Period in 2013
Operating Revenues. The $149 million increase was driven by:
a $119 million increase due primarily to higher sales volumes of residual natural gas at the Empress operations,
a $78 million increase due mostly to higher propane prices associated with the Empress NGL business,
a $20 million increase in gathering and processing revenues from new facilities at Horn River and Montney unconventional development areas,
a $15 million increase in transmission revenues due primarily to higher tolls at BC Pipeline, and
an $11 million increase primarily in interruptible transmission revenues due to a new supply source connected to the M&N Canada system, partially offset by

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a $100 million decrease as a result of a weaker Canadian dollar.
Natural Gas and Petroleum Products Purchased. The $114 million increase was driven by:
a $134 million increase due primarily to higher volumes of natural gas purchases for extraction and make-up at Empress, and
a $5 million increase primarily as a result of higher costs of NGL purchases at the Empress facility, partially offset by
a $27 million decrease as a result of a weaker Canadian dollar.
Operating, Maintenance and Other. The $46 million increase was driven by:
a $35 million increase in plant turnaround and repair costs,
a $12 million increase in maintenance expense,
an $11 million increase primarily in costs passed through to customers at M&N Canada,
an $8 million increase in Empress plant fuel costs due primarily to higher prices,
a $5 million increase in operating costs of new facilities, and
a $5 million increase in cost of service for the BC Pipeline transmission business, partially offset by
a $36 million decrease as a result of a weaker Canadian dollar.
Other Income and Expenses. The $6 million decrease was driven primarily by lower AFUDC resulting from decreased capital spending on expansion projects.
EBITDA. The $17 million decrease was driven by higher operating and maintenance expense and the effect of a weaker Canadian dollar, substantially offset by higher earnings at the Empress NGL business due primarily to higher propane prices, higher gathering and processing earnings from expansion and transmission earnings due to higher tolls.
Field Services
 
Three Months
Ended September 30,
 
Nine Months
Ended September 30,
 
2014
 
2013
 
Increase (Decrease)
 
2014
 
2013
 
Increase (Decrease)
 
(in millions, except where noted)
Equity in earnings of unconsolidated affiliates
$
51

 
$
137

 
$
(86
)
 
$
235

 
$
271

 
$
(36
)
EBITDA
$
51

 
$
137

 
$
(86
)
 
$
235

 
$
271

 
$
(36
)
Natural gas gathered and processed/transported, TBtu/d (a,b)
7.5

 
7.4

 
0.1

 
7.3

 
7.1

 
0.2

NGL production, MBbl/d (a)
471

 
442

 
29

 
456

 
417

 
39

Average natural gas price per MMBtu (c,d)
$
4.06

 
$
3.58

 
$
0.48

 
$
4.55

 
$
3.67

 
$
0.88

Average NGL price per gallon (e)
$
0.90

 
$
0.90

 
$

 
$
0.96

 
$
0.87

 
$
0.09

Average crude oil price per barrel (f)
$
97.24

 
$
105.82

 
$
(8.58
)
 
$
99.64

 
$
98.23

 
$
1.41

___________
(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. 2013 NGL prices have been revised to reflect the impact of ethane rejection.
(f)
Average price based on NYMEX calendar month.
Three Months Ended September 30, 2014 Compared to Same Period in 2013
EBITDA. Lower equity earnings of $86 million were mainly the result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:
a $44 million decrease primarily as a result of increased net income attributable to noncontrolling interests as a result of the effect of dropdown hedges at DCP Partners, where DCP Midstream acts as counterparty, and growth from dropdowns,

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a $30 million decrease in gains associated with issuances of partnership units by DCP Partners in 2014 compared to 2013,
an $18 million decrease primarily as a result of losses on sales of assets and a goodwill impairment charge,
a $14 million decrease from commodity-sensitive processing arrangements due to decreased crude oil prices, net of increased natural gas prices, and
a $14 million decrease primarily attributable to higher operating expenses as a result of increased spending on reliability programs, as well as growth in Field Services’ operations, partially offset by
a $27 million increase in gathering and processing margins primarily due to higher volumes as a result of asset growth, and
an $8 million increase attributable to DCP Partners’ third-party mark-to-market activity, net of unfavorable results from NGL trading and gas marketing.
Nine Months Ended September 30, 2014 Compared to Same Period in 2013
EBITDA. Lower equity earnings of $36 million were mainly the result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:
a $46 million decrease primarily attributable to higher operating expenses as a result of increased spending on reliability programs, including turnarounds, as well as growth in Field Services’ operations,
a $23 million decrease in gains associated with issuances of partnership units by DCP Partners in 2014 compared to 2013,
a $22 million decrease mainly due to higher interest expense as a result of higher interest rates from newly issued debt and lower capitalized interest as a result of certain projects which were placed in service in 2013,
an $18 million decrease resulting from increased net income attributable to noncontrolling interests as a result of the the effects of growth in DCP Partners’ operations, net of the effects of dropdown hedges and higher costs and expenses,
an $18 million decrease primarily as a result of losses on sales of assets and a goodwill impairment charge in the third quarter of 2014, and
a $16 million decrease primarily attributable to higher depreciation expense as a result of growth, partially offset by
a $53 million increase in gathering and processing margins primarily due to higher volumes as a result of asset growth,
a $30 million increase from commodity-sensitive processing arrangements due to higher NGL, natural gas and crude oil prices, and
a $24 million increase attributable to favorable results from NGL and gas trading and marketing, net of unfavorable DCP Partners’ third-party mark-to-market activity.

Other
 
Three Months
Ended September 30,
 
Nine Months
Ended September 30,
 
2014
 
2013
 
Increase (Decrease)
 
2014
 
2013
 
Increase (Decrease)
 
(in millions)
Operating revenues
$
17

 
$
17

 
$

 
$
54

 
$
53

 
$
1

Operating expenses
 
 
 
 
 
 
 
 
 
 
 
        Operating, maintenance and other
39

 
51

 
(12
)
 
120

 
136

 
(16
)
Other income and expenses
3

 
15

 
(12
)
 
6

 
21

 
(15
)
EBITDA
$
(19
)
 
$
(19
)
 
$

 
$
(60
)
 
$
(62
)
 
$
2


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Three Months Ended September 30, 2014 Compared to Same Period in 2013
Operating, Maintenance and Other. The $12 million decrease was driven primarily by lower transaction costs.
Other Income and Expenses. The $12 million decrease was driven primarily by a 2013 benefit from the reversal of an uncertain tax position related to matters prior to the spin-off of Spectra Energy from Duke Energy Corporation (Duke Energy) in 2007.
EBITDA. EBITDA remained the same and reflects lower transaction costs, offset by a 2013 benefit from the reversal of an uncertain tax position related to matters prior to the spin-off of Spectra Energy from Duke Energy.
Nine Months Ended September 30, 2014 Compared to Same Period in 2013
Operating, Maintenance and Other. The $16 million decrease was driven mainly by lower transaction and employee benefit costs.
Other Income and Expenses. The $15 million decrease was driven primarily by a 2013 benefit from the reversal of an uncertain tax position related to matters prior to the spin-off of Spectra Energy from Duke Energy.
EBITDA. The $2 million increase reflects lower transaction costs and employee benefit costs, mostly offset by a 2013 benefit from the reversal of an uncertain tax position related to matters prior to the spin-off of Spectra Energy from Duke Energy.
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. The long-term growth rates used for the reporting units that we quantitatively assessed reflect continued expansion of our assets, driven by new natural gas supplies such as shale gas in North America and increasing demand for natural gas transportation capacity on our pipeline systems primarily as a result of forecasted growth in natural gas-fired power plants and increasing demand for crude oil and NGL transportation capacity on our pipeline systems. 

We performed a test on all our reporting units for our test of goodwill impairment as of April 1, 2014. 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, 2014 (our testing date) were substantially in excess of their respective carrying values.
LIQUIDITY AND CAPITAL RESOURCES
As of September 30, 2014, we had negative working capital of $1,239 million. This balance includes commercial paper liabilities totaling $1,412 million and current maturities of long-term debt of $220 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, 2014, our revolving credit facilities included Spectra Capital’s $1.0 billion facility, SEP’s $2.0 billion facility, Westcoast’s 300 million Canadian dollar facility and Union Gas’ 400 million Canadian dollar facility, with available capacity of $1,187 million under SEP’s credit facility and $1,026 million under our other subsidiaries’ credit facilities. These facilities are used principally as back-stops for commercial paper programs. At Spectra Capital, SEP and Westcoast, we primarily use commercial paper for temporary funding of capital expenditures. At Union Gas, we primarily use commercial paper to support short-term working capital fluctuations. We also utilize commercial paper, other variable-rate debt and interest rate swaps to achieve our desired mix of fixed and variable-rate debt. See Note 12 of Notes to Condensed Consolidated Financial Statements for a discussion of available credit facilities and Financing Cash Flows and Liquidity for a discussion of effective shelf registrations.

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Cash Flow Analysis
The following table summarizes the changes in cash flows for each of the periods presented:
 
Nine Months
Ended September 30,
 
2014
 
2013
Net cash provided by (used in):
(in millions)
Operating activities
$
1,546

 
$
1,400

Investing activities
(1,421
)
 
(4,800
)
Financing activities
(102
)
 
3,467

Effect of exchange rate changes on cash
(3
)
 
(1
)
Net increase in cash and cash equivalents
20

 
66

Cash and cash equivalents at beginning of the period
201

 
94

Cash and cash equivalents at end of the period
$
221

 
$
160


Operating Cash Flows
Net cash provided by operating activities increased $146 million to $1,546 million for the nine months ended September 30, 2014 compared to the same period in 2013, driven mostly by distributions from unconsolidated affiliates and higher earnings.
 
Investing Cash Flows
Net cash used in investing activities decreased $3,379 million to $1,421 million in the nine months ended September 30, 2014 compared to the same period in 2013. This change was driven by:
$1,855 million of net purchases of AFS securities in 2013, primarily from proceeds from SEP’s issuance of long-term debt,
a $1,254 million net cash outlay for the acquisition of Express-Platte in 2013,
a $235 million increase in distributions received from unconsolidated affiliates in 2014, comprised mostly of a $200 million distribution from SESH with proceeds from a SESH debt offering, and
a $42 million decrease in capital and investment expenditures in 2014. Capital and investment expenditures in 2014 included a $189 million investment in SESH, used by SESH to retire debt.
 
 
Nine Months
Ended September 30,
 
 
2014
 
2013
Capital and Investment Expenditures
 
(in millions)
Spectra Energy Partners (a,b)
 
$
889

 
$
992

Distribution
 
261

 
238

Western Canada Transmission & Processing
 
385

 
439

Total reportable segments
 
1,535

 
1,669

Other
 
123

 
31

Total consolidated
 
$
1,658

 
$
1,700

___________
(a)
Excludes a $1,254 million net cash outlay for the acquisition of Express-Platte in 2013.
(b)
Excludes reimbursements from noncontrolling interests of $47 million in 2014.
Capital and investment expenditures for the nine months ended September 30, 2014 consisted of $1,016 million for expansion projects, $453 million for maintenance and other projects and a $189 million investment in SESH ($94 million at Spectra Energy Partners and $95 million at “Other”). SESH used the funds along with its funds received from its other partners, to retire maturing debt.
We project 2014 capital and investment expenditures of approximately $2.3 billion, consisting of approximately $1.3 billion for Spectra Energy Partners, $0.5 billion for Distribution, $0.4 billion for Western Canada Transmission & Processing and $0.1 billion for “Other.” Total projected 2014 capital and investment expenditures include approximately $1.3 billion of expansion capital expenditures, $0.8 billion for maintenance and upgrades of existing plants, pipelines and infrastructure to

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serve growth, and a $189 million capital contribution made to SESH in connection with a SESH debt retirement. We continue to assess short and long-term market requirements and adjust our capital plans as required.
Financing Cash Flows and Liquidity
Net cash used in financing activities totaled $102 million in the nine months ended September 30, 2014 compared to $3,467 million provided by financing activities in the same period of 2013. This change was driven by:
$117 million of net redemptions of long-term debt in 2014 compared to $3,176 million of net issuances in 2013 which were mostly used to fund the acquisition of Express-Platte and the U.S. Assets Dropdown, and
a $410 million net decrease in commercial paper issuances in 2014 compared to 2013, partially offset by
$139 million of contributions from noncontrolling interests in 2014.

In January 2014, Spectra Capital borrowed the full $300 million available under its unsecured term loan agreement. Interest on the borrowing is based on LIBOR and the borrowing is due in 2018. Net proceeds from the borrowing were used for general corporate purposes.

On June 2, 2014, Union Gas issued 200 million Canadian dollars (approximately $183 million as of the issuance date) of 2.76% unsecured notes due 2021 and 250 million Canadian dollars (approximately $229 million as of the issuance date) of 4.20% unsecured notes due 2044. Net proceeds from the offerings were used for general corporate purposes.

On September 12, 2014, Westcoast issued 350 million Canadian dollars (approximately $316 million as of the issuance date) of 3.43% unsecured notes due 2024. Net proceeds from the offering were used for general corporate purposes.

During the nine months ended September 30, 2014, SEP issued 5.5 million common units to the public under its at-the-market program, representing limited partner interests, and 113,000 general partner units to Spectra Energy. Total net proceeds to SEP were $283 million (net proceeds to Spectra Energy were $277 million). The net proceeds were used for SEP’s general partnership purposes, which may have included debt repayments, future acquisitions, capital expenditures and/or additions to working capital. In 2014 through the date of this report, SEP has issued 5.6 million common units to the public and 116,000 general partner units to Spectra Energy, for total net proceeds to SEP of $289 million (net proceeds to Spectra Energy were $283 million).
Available Credit Facilities and Restrictive Debt Covenants. See Note 12 of Notes to Condensed Consolidated Financial Statements for a discussion of available credit facilities and related financial and other covenants.
The terms of our Spectra Capital credit agreement 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, 2014, this ratio was 57%. 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, 2014, 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 at least $0.12 per year through 2016. 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 November 4, 2014, representing an increase of over 10% from the previous quarter’s dividend, payable on December 9, 2014 to shareholders of record at the close of business on November 17, 2014.

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 and various debt securities. SEP also has $195 million available as of September 30, 2014 for the issuance of limited partner common units and various debt securities under another effective shelf registration statement on file with the SEC related to its continuous offering program. Westcoast and Union Gas have an aggregate 300 million Canadian dollars (approximately $268 million) available as of September 30, 2014 for the issuance of debt securities in the Canadian market under debt shelf prospectuses.


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OTHER ISSUES
New Accounting Pronouncements. See Note 20 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, 2013. We believe our exposure to market risk has not changed materially since then.
Item 4.
Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized, and reported within the time periods specified by the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2014, 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, 2014 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1.
Legal Proceedings.
We have no material pending legal proceedings that are required to be disclosed hereunder. For information regarding other legal proceedings, including regulatory and environmental matters, see Notes 4 and 15 of Notes to Condensed Consolidated Financial Statements, which information is incorporated by reference into this Part II.
Item 1A.
Risk Factors.
In addition to the other information set forth in this report, careful consideration should be given to the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013 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;

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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
 
 
 
 
 
*10.1
 
Fifth Amendment, dated September 9, 2014, to Second Amended and Restated Limited Liability Company Agreement of DCP Midstream, LLC, by and between Phillips Gas Company and Spectra Energy DEFS Holding II, LLC and Spectra Energy DEFS Holding Corp.
 
 
 
  *31.1
 
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
  *31.2
 
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
  *32.1
 
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
  *32.2
 
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
*101.INS
 
XBRL Instance Document.
 
 
*101.SCH
 
XBRL Taxonomy Extension Schema.
 
 
*101.CAL
 
XBRL Taxonomy Extension Calculation Linkbase.
 
 
*101.DEF
 
XBRL Taxonomy Extension Definition Linkbase.
 
 
*101.LAB
 
XBRL Taxonomy Extension Label Linkbase.
 
 
*101.PRE
 
XBRL Taxonomy Extension Presentation Linkbase.
 
 
 
*
Filed herewith.
The total amount of securities of the registrant or its subsidiaries authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10% of the total assets of the registrant and its subsidiaries on a consolidated basis. The registrant agrees, upon request of the Securities and Exchange Commission, to furnish copies of any or all of such instruments to it.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SPECTRA ENERGY CORP
 
 
 
 
Date: November 6, 2014
 
 
 
 
 
/s/    Gregory L. Ebel        
 
 
 
 
 
 
Gregory L. Ebel
 
 
 
 
 
 
President and Chief Executive Officer
 
 
 
 
Date: November 6, 2014
 
 
 
 
 
/s/    J. Patrick Reddy        
 
 
 
 
 
 
J. Patrick Reddy
 
 
 
 
 
 
Chief Financial Officer

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