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 United States (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 U.S., the Maritime Provinces in Canada, the Pacific Northwest in the U.S. 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 U.S. 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, 2015
, 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 U.S., we make estimates and assumptions that affect the amounts reported in the Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements. Although these estimates are based on our best available knowledge at the time, actual results could differ.
2. Business Segments
We manage our business in
four
reportable segments: Spectra Energy Partners, Distribution, Western Canada Transmission & Processing and Field Services. The remainder of our business operations is presented as “Other,” and consists of unallocated corporate costs and employee benefit plan assets and liabilities, 100%-owned captive insurance subsidiaries and other miscellaneous activities.
Our chief operating decision maker (CODM) regularly reviews financial information about each of these segments in deciding how to allocate resources and evaluate performance. There is no aggregation within our reportable business segments.
Spectra Energy’s presentation of its Spectra Energy Partners segment is reflective of the parent-level focus by our CODM, considering the resource allocation and governance provisions associated with SEP’s master limited partnership structure. SEP maintains a capital and cash management structure that is separate from Spectra Energy’s, is self-funding and maintains its own lines of bank credit and cash management accounts. From a Spectra Energy perspective, our CODM evaluates the Spectra Energy Partners segment as a whole, without regard to any of SEP’s individual businesses.
Spectra Energy Partners provides transmission, storage and gathering of natural
gas, as well as the transportation of crude oil through interstate pipeline systems for customers in various regions of the midwestern, northeastern and southern U.S. and Canada.
The natural gas transmission and storage operations are primarily subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC). The crude oil transportation operations are primarily subject to regulation by the FERC in the
U.S.
and the National Energy Board (NEB) in Canada. Our Spectra Energy Partners segment is composed of the operations of SEP, less governance costs, which are included in “Other.”
Distribution provides retail natural gas distribution service in Ontario, Canada, as well as natural gas transmission and storage services to other utilities and energy market participants. These services are provided by Union Gas Limited (Union Gas), and are primarily subject to the rules and regulations of the Ontario Energy Board (OEB).
Western Canada Transmission & Processing provides transmission of natural gas, natural gas gathering and processing services, and NGL extraction, fractionation, transportation, storage and marketing to customers in western Canada, the northern tier of the
U.S.
and the Maritime Provinces in Canada. This segment conducts business mostly through BC Pipeline, BC Field Services, Empress NGL operations (Empress), Canadian Midstream, and Maritimes & Northeast Pipeline Limited Partnership (M&N Canada). BC Pipeline, BC Field Services and M&N Canada operations are primarily subject to the rules and regulations of the NEB. See Note 8 for additional discussion of Empress.
Field Services gathers, compresses, treats, processes, transports, stores and sells natural gas, produces, fractionates, transports, stores and sells NGLs, recovers and sells condensate, and trades and markets natural gas and NGLs. It conducts operations through DCP Midstream, which is owned
50%
by us and
50%
by Phillips 66. DCP Midstream gathers raw natural gas through gathering systems connecting to several interstate and intrastate natural gas and NGL pipeline systems, one natural gas storage facility and one NGL storage facility. DCP Midstream operates in a diverse number of regions, including the Permian Basin, Eagle Ford, Niobrara/DJ Basin and the Midcontinent. DCP Midstream Partners, LP (DCP Partners) is a publicly traded master limited partnership, of which DCP Midstream acts as general partner. As of
June 30, 2016
, DCP Midstream had an approximate
21%
ownership interest in DCP Partners, including DCP Midstream’s limited partner and general partner interests.
Our reportable segments offer different products and services and are managed separately as business units. Management evaluates segment performance based on earnings 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.
Business Segment Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidated Statements of Operations
|
|
Unaffiliated
Revenues
|
|
Intersegment
Revenues
|
|
Total
Operating
Revenues
|
|
Depreciation and Amortization
|
|
Segment EBITDA/
Consolidated
Earnings before
Income Taxes
|
|
(in millions)
|
Three Months Ended June 30, 2016
|
|
|
|
|
|
|
|
|
|
Spectra Energy Partners
|
$
|
618
|
|
|
$
|
—
|
|
|
$
|
618
|
|
|
$
|
78
|
|
|
$
|
471
|
|
Distribution
|
284
|
|
|
—
|
|
|
284
|
|
|
47
|
|
|
104
|
|
Western Canada Transmission & Processing
|
254
|
|
|
4
|
|
|
258
|
|
|
59
|
|
|
97
|
|
Field Services
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(14
|
)
|
Total reportable segments
|
1,156
|
|
|
4
|
|
|
1,160
|
|
|
184
|
|
|
658
|
|
Other
|
3
|
|
|
16
|
|
|
19
|
|
|
12
|
|
|
(36
|
)
|
Eliminations
|
—
|
|
|
(20
|
)
|
|
(20
|
)
|
|
—
|
|
|
—
|
|
Depreciation and amortization
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
196
|
|
Interest expense
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
153
|
|
Total consolidated
|
$
|
1,159
|
|
|
$
|
—
|
|
|
$
|
1,159
|
|
|
$
|
196
|
|
|
$
|
273
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2015
|
|
|
|
|
|
|
|
|
|
Spectra Energy Partners
|
$
|
603
|
|
|
$
|
—
|
|
|
$
|
603
|
|
|
$
|
72
|
|
|
$
|
478
|
|
Distribution
|
290
|
|
|
—
|
|
|
290
|
|
|
45
|
|
|
98
|
|
Western Canada Transmission & Processing
|
297
|
|
|
7
|
|
|
304
|
|
|
63
|
|
|
104
|
|
Field Services
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(233
|
)
|
Total reportable segments
|
1,190
|
|
|
7
|
|
|
1,197
|
|
|
180
|
|
|
447
|
|
Other
|
2
|
|
|
15
|
|
|
17
|
|
|
13
|
|
|
(12
|
)
|
Eliminations
|
—
|
|
|
(22
|
)
|
|
(22
|
)
|
|
—
|
|
|
—
|
|
Depreciation and amortization
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
193
|
|
Interest expense
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
166
|
|
Interest income and other (a)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
Total consolidated
|
$
|
1,192
|
|
|
$
|
—
|
|
|
$
|
1,192
|
|
|
$
|
193
|
|
|
$
|
73
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2016
|
|
|
|
|
|
|
|
|
|
Spectra Energy Partners
|
$
|
1,242
|
|
|
$
|
—
|
|
|
$
|
1,242
|
|
|
$
|
155
|
|
|
$
|
944
|
|
Distribution
|
749
|
|
|
—
|
|
|
749
|
|
|
91
|
|
|
274
|
|
Western Canada Transmission & Processing
|
548
|
|
|
15
|
|
|
563
|
|
|
117
|
|
|
220
|
|
Field Services
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(11
|
)
|
Total reportable segments
|
2,539
|
|
|
15
|
|
|
2,554
|
|
|
363
|
|
|
1,427
|
|
Other
|
4
|
|
|
32
|
|
|
36
|
|
|
26
|
|
|
(55
|
)
|
Eliminations
|
—
|
|
|
(47
|
)
|
|
(47
|
)
|
|
—
|
|
|
—
|
|
Depreciation and amortization
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
389
|
|
Interest expense
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
304
|
|
Interest income and other (a)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
Total consolidated
|
$
|
2,543
|
|
|
$
|
—
|
|
|
$
|
2,543
|
|
|
$
|
389
|
|
|
$
|
681
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2015
|
|
|
|
|
|
|
|
|
|
Spectra Energy Partners
|
$
|
1,209
|
|
|
$
|
—
|
|
|
$
|
1,209
|
|
|
$
|
146
|
|
|
$
|
933
|
|
Distribution
|
952
|
|
|
—
|
|
|
952
|
|
|
90
|
|
|
290
|
|
Western Canada Transmission & Processing
|
650
|
|
|
24
|
|
|
674
|
|
|
125
|
|
|
265
|
|
Field Services
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(250
|
)
|
Total reportable segments
|
2,811
|
|
|
24
|
|
|
2,835
|
|
|
361
|
|
|
1,238
|
|
Other
|
4
|
|
|
31
|
|
|
35
|
|
|
25
|
|
|
(27
|
)
|
Eliminations
|
—
|
|
|
(55
|
)
|
|
(55
|
)
|
|
—
|
|
|
—
|
|
Depreciation and amortization
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
386
|
|
Interest expense
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
325
|
|
Interest income and other (a)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
Total consolidated
|
$
|
2,815
|
|
|
$
|
—
|
|
|
$
|
2,815
|
|
|
$
|
386
|
|
|
$
|
499
|
|
___________________________________
|
|
(a)
|
Includes foreign currency transaction gains and losses related to segment EBITDA.
|
3. Regulatory Matters
Union Gas.
In December 2015, Union Gas filed an application with the OEB for the disposition of the 2014 demand side management (DSM) deferral and variance account balances. As a result of this application, Union Gas has a receivable from customers of approximately
$9 million
as of
June 30, 2016
and
$8 million
as of
December 31, 2015
, which is reflected as Current Assets—Other on the Condensed Consolidated Balance Sheets. In June 2016, the OEB approved Union Gas' application as filed and Union Gas will begin to recover the receivable from ratepayers effective October 1, 2016.
In March 2016, Union Gas filed a Draft Rate Order with the OEB for rates effective January 1, 2016 based on the OEB's February 24, 2016 updated Decision and Order on the 2015-2020 DSM Plan. In May 2016, a decision from the OEB was received approving recovery from ratepayers of approximately
$19 million
effective January 1, 2016 with an implementation date of July 1, 2016.
In April 2016, Union Gas filed an application with the OEB for the annual disposition of the 2015 deferral account balances. As a result, Union Gas has a net receivable from customers of approximately
$18 million
as of
June 30, 2016
and
December 31, 2015
, which is primarily reflected as Current Assets—Other on the Condensed Consolidated Balance Sheets. Union Gas filed a Settlement Proposal with the OEB in July 2016 reflecting a full settlement on all issues in the proceeding. Union Gas is proposing to implement the disposition of the balances on October 1, 2016. A decision from the OEB is expected later this year.
4. Income Taxes
Income tax expense was
$52 million
for the
three months ended June 30, 2016
, compared to an income tax benefit of
$7 million
for the same period in
2015
. Income tax expense was
$150 million
for the
six months ended June 30, 2016
, compared to
$94 million
for the same period in
2015
. The higher tax expense for both periods was primarily due to the
$72 million
tax impact of the loss on investment due to the partial impairment of goodwill at DCP Midstream in 2015, partially offset by tax rate changes in 2016.
The effective income tax rate was
19%
for the
three months
ended
June 30, 2016
, compared to negative
10%
for the same period in
2015
. The effective income tax rate was
22%
for the
six months ended June 30, 2016
, compared to
19%
for the same period in
2015
. The higher effective income tax rate for both periods was primarily due to the
$72 million
tax impact of the loss on investment due to the partial impairment of goodwill at DCP Midstream in 2015, partially offset by tax rate changes in 2016.
There was a
$7 million
increase in unrecognized tax benefits recorded during the
six months
ended
June 30, 2016
. Although uncertain, we believe it is reasonably possible that the total amount of unrecognized tax benefits could decrease by approximately
$30 million
to
$40 million
prior to
June 30,
2017
due to audit settlements and statute of limitations expirations.
5. Earnings per Common Share
Basic earnings per common share (EPS) is computed by dividing net income from controlling interests by the weighted-average number of common shares outstanding during the period. Diluted EPS is computed by dividing net income from controlling interests by the diluted weighted-average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock, such as stock options, stock-based performance unit awards and phantom stock awards, were exercised, settled or converted into common stock.
The following table presents our basic and diluted EPS calculations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended June 30,
|
|
Six Months
Ended June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(in millions, except per-share amounts)
|
Net income—controlling interests
|
$
|
149
|
|
|
$
|
18
|
|
|
$
|
383
|
|
|
$
|
285
|
|
Weighted-average common shares outstanding
|
|
|
|
|
|
|
|
Basic
|
699
|
|
|
671
|
|
|
687
|
|
|
671
|
|
Diluted
|
701
|
|
|
672
|
|
|
688
|
|
|
672
|
|
Basic and diluted earnings per common share (a)
|
$
|
0.21
|
|
|
$
|
0.03
|
|
|
$
|
0.56
|
|
|
$
|
0.42
|
|
___________________
(a) Quarterly earnings per share amounts are stand-alone calculations and may not be additive to full-year amounts due to rounding.
6. Accumulated Other Comprehensive Income (Loss)
The following table presents the net of tax changes in Accumulated Other Comprehensive Income (AOCI) by component, 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 (Loss)
|
|
(in millions)
|
March 31, 2016
|
$
|
376
|
|
|
$
|
(341
|
)
|
|
$
|
—
|
|
|
$
|
(3
|
)
|
|
$
|
32
|
|
Other AOCI activity
|
49
|
|
|
4
|
|
|
—
|
|
|
1
|
|
|
54
|
|
June 30, 2016
|
$
|
425
|
|
|
$
|
(337
|
)
|
|
$
|
—
|
|
|
$
|
(2
|
)
|
|
$
|
86
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2015
|
$
|
532
|
|
|
$
|
(345
|
)
|
|
$
|
—
|
|
|
$
|
(2
|
)
|
|
$
|
185
|
|
Other AOCI activity
|
85
|
|
|
7
|
|
|
—
|
|
|
(1
|
)
|
|
91
|
|
June 30, 2015
|
$
|
617
|
|
|
$
|
(338
|
)
|
|
$
|
—
|
|
|
$
|
(3
|
)
|
|
$
|
276
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015
|
$
|
79
|
|
|
$
|
(346
|
)
|
|
$
|
(3
|
)
|
|
$
|
1
|
|
|
$
|
(269
|
)
|
Other AOCI activity
|
346
|
|
|
9
|
|
|
3
|
|
|
(3
|
)
|
|
355
|
|
June 30, 2016
|
$
|
425
|
|
|
$
|
(337
|
)
|
|
$
|
—
|
|
|
$
|
(2
|
)
|
|
$
|
86
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014
|
$
|
1,016
|
|
|
$
|
(351
|
)
|
|
$
|
(3
|
)
|
|
$
|
—
|
|
|
$
|
662
|
|
Other AOCI activity
|
(399
|
)
|
|
13
|
|
|
3
|
|
|
(3
|
)
|
|
(386
|
)
|
June 30, 2015
|
$
|
617
|
|
|
$
|
(338
|
)
|
|
$
|
—
|
|
|
$
|
(3
|
)
|
|
$
|
276
|
|
7. Inventory
Inventory consists of natural gas and NGLs held in storage for transmission and processing, and also includes materials and supplies. In the second quarter of 2016, Westcoast Energy Inc. (Westcoast) entered into a definitive agreement to sell its ownership interest in Empress which resulted in NGLs being reclassified out of Inventory to Assets Held for Sale on the Condensed Consolidated Balance Sheet as of June 30, 2016. See Note 8 for further discussion. Natural gas inventories primarily relate to the Distribution segment in Canada and are valued at costs approved by the OEB. The difference between the approved price and the actual cost of gas purchased is recorded as either a receivable or a current liability, as appropriate, for future disposition with customers, subject to approval by the OEB. The remaining inventory is recorded at the lower of cost or market, primarily using average cost. The components of inventory are as follows:
|
|
|
|
|
|
|
|
|
|
June 30,
2016
|
|
December 31,
2015
|
|
(in millions)
|
Natural gas
|
$
|
115
|
|
|
$
|
217
|
|
NGLs
|
—
|
|
|
23
|
|
Materials and supplies
|
70
|
|
|
67
|
|
Total inventory
|
$
|
185
|
|
|
$
|
307
|
|
8. Assets Held for Sale
On April 2, 2016, Westcoast entered into a definitive agreement to sell its ownership interest in Empress for a cash purchase price of approximately
200 million
Canadian dollars plus customary closing adjustments. This transaction is expected to close in the second half of 2016. The associated assets and liabilities are included in the Western Canada Transmission & Processing segment and classified as Assets Held for Sale and Liabilities Held for Sale, respectively, on the Condensed Consolidated Balance Sheet as of June 30, 2016.
As these assets are classified as held for sale, we evaluated the book value compared to the lower of the carrying amounts or fair value less costs to sell. As of June 30, 2016, we determined that the fair value less costs to sell exceeded the carrying amount of the assets held for sale, therefore, no adjustment to book value was necessary. The carrying amounts of the assets and liabilities classified as Assets Held for Sale and Liabilities Held for Sale on our Condensed Consolidated Balance Sheet are as follows:
|
|
|
|
|
|
June 30,
2016
|
|
(in millions)
|
Assets Held for Sale
|
|
Cash and cash equivalents
|
$
|
7
|
|
Receivables, net
|
8
|
|
Inventory
|
28
|
|
Current assets—other
|
7
|
|
Investments and other assets—other
|
11
|
|
Net property, plant and equipment
|
164
|
|
Total assets held for sale
|
$
|
225
|
|
Liabilities Held for Sale
|
|
Accounts payable
|
$
|
9
|
|
Taxes accrued
|
1
|
|
Current liabilities—other
|
6
|
|
Deferred credits and other liabilities—deferred income taxes
|
28
|
|
Deferred credits and other liabilities—regulatory and other
|
12
|
|
Total liabilities held for sale
|
$
|
56
|
|
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 June 30,
|
|
Six Months
Ended June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(in millions)
|
Operating revenues
|
$
|
1,586
|
|
|
$
|
1,869
|
|
|
$
|
3,013
|
|
|
$
|
3,912
|
|
Operating expenses
|
1,592
|
|
|
2,332
|
|
|
2,957
|
|
|
4,323
|
|
Operating income (loss)
|
(6
|
)
|
|
(463
|
)
|
|
56
|
|
|
(411
|
)
|
Net income (loss)
|
(16
|
)
|
|
(491
|
)
|
|
32
|
|
|
(497
|
)
|
Net income (loss) attributable to members’ interests
|
(29
|
)
|
|
(466
|
)
|
|
(18
|
)
|
|
(503
|
)
|
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, totaled
$2 million
during the
six months ended June 30, 2015
and is reflected in Earnings (Loss) From Equity Investments in the Condensed Consolidated Statement of Operations.
During the second quarter of 2015 DCP Midstream recognized a
$427 million
partial goodwill impairment, which reduced our equity earnings from DCP Midstream by
$122 million
after-tax. DCP Midstream finalized the calculation of their goodwill impairment in the third quarter of 2015.
Related Party Transactions
During the third quarter of 2015, Gulfstream Natural Gas System, LLC (Gulfstream) issued unsecured debt of
$800 million
to fund the repayment of its current debt. Gulfstream distributed
$396 million
, our proportionate share of proceeds, to us of which we contributed
$248 million
back to Gulfstream in the fourth quarter of 2015 and the remaining
$148 million
, classified as Cash Flows from Investing Activities—Distribution to Equity Investment, in the second quarter of 2016.
10. Variable Interest Entities
Sabal Trail.
On April 1, 2016, NextEra Energy, Inc. (NextEra) purchased a
9.5%
interest in Sabal Trail Transmission, LLC (Sabal Trail) from SEP. Consideration for this transaction consisted of approximately
$110 million
cash,
$102 million
of which is classified as Cash Flows from Financing Activities—Contributions from Noncontrolling Interests. See Note 11 for additional information related to this transaction. As of June 30, 2016, we have an effective
38.3%
ownership interest in Sabal Trail through our ownership of SEP. Sabal Trail is a joint venture that is constructing a natural gas pipeline to transport natural gas to Florida. Sabal Trail is a variable interest entity (VIE) due to insufficient equity at risk to finance its activities. We determined that we are the primary beneficiary because we direct the activities of Sabal Trail that most significantly impact its economic performance and we consolidate Sabal Trail in our financial statements. The current estimate of the total remaining construction cost is approximately
$1.8 billion
.
The following summarizes assets and liabilities for Sabal Trail as of
June 30, 2016
and
December 31, 2015
:
|
|
|
|
|
|
|
|
|
Condensed Consolidated Balance Sheets Caption
|
June 30,
2016
|
|
December 31,
2015
|
|
(in millions)
|
Assets
|
|
|
|
Current assets
|
$
|
114
|
|
|
$
|
118
|
|
Net property, plant and equipment
|
1,184
|
|
|
773
|
|
Regulatory assets and deferred debits
|
41
|
|
|
25
|
|
Total Assets
|
$
|
1,339
|
|
|
$
|
916
|
|
Liabilities and Equity
|
|
|
|
Current liabilities
|
$
|
90
|
|
|
$
|
84
|
|
Equity
|
1,249
|
|
|
832
|
|
Total Liabilities and Equity
|
$
|
1,339
|
|
|
$
|
916
|
|
Nexus.
We have an effective
38.3%
ownership interest in Nexus Gas Transmission, LLC (Nexus) through our ownership of SEP. Nexus is a joint venture that is constructing a natural gas pipeline from Ohio to Michigan and continuing on to Ontario, Canada. Nexus is a VIE due to insufficient equity at risk to finance its activities. We determined that we are not the primary beneficiary because the power to direct the activities of Nexus that most significantly impact its economic performance is shared. Nexus is accounted for under the equity method. Our maximum exposure to loss is
$1.0 billion
. We have an investment in Nexus of
$205 million
and
$90 million
as of
June 30, 2016
and
December 31, 2015
, respectively, classified as Investments in and Loans to Unconsolidated Affiliates on our Condensed Consolidated Balance Sheets.
11. Intangible Asset
During the first quarter of 2016 SEP entered into a project coordination agreement (PCA) with NextEra, Duke Energy Corporation (Duke Energy) and Williams Partners L.P. In accordance with the agreement, payments will be made, based on SEP’s proportional ownership interest in Sabal Trail, as certain milestones of the project are met. During the first quarter of 2016, the first milestone was achieved and paid, consisting of
$48 million
. On April 1, 2016, NextEra purchased an additional
9.5%
interest in Sabal Trail from SEP, reducing SEP’s ownership interest in Sabal Trail to
50%
. Upon purchase of the additional ownership interest, NextEra reimbursed SEP
$8 million
for NextEra’s proportional share of the first milestone payment, which reduced SEP’s total milestone payments to
$40 million
as of June 30, 2016, both of which are classified as Cash Flows from Investing Activities—Purchase of Intangible, Net. This PCA is an intangible asset and is classified as Investments and Other Assets—Other on our Condensed Consolidated Balance Sheet. The intangible asset will be amortized over a period of
25
years beginning at the time of in-service of Sabal Trail, which is expected to occur during the first half of 2017.
12. 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, 2016 and
no
impairments were identified.
We perform our annual review for goodwill impairment at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete financial information is available, whether segment management regularly reviews the operating results of those components and whether the economic and regulatory characteristics are similar. We determined that our reporting units are equivalent to our reportable segments, except for the reporting units of our Western Canada Transmission & Processing and Spectra Energy Partners reportable segments, which are one level below.
As permitted under accounting guidance on testing goodwill for impairment, we perform either a qualitative assessment or a quantitative assessment of each of our reporting units based on management’s judgment. With respect to our qualitative assessments, we consider events and circumstances specific to us, such as macroeconomic conditions, industry and market considerations, cost factors and overall financial performance, when evaluating whether it is more likely than not that the fair values of our reporting units are less than their respective carrying amounts.
See Note 9 for discussion related to the 2015 partial impairment of goodwill recognized by DCP Midstream.
13. 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, Canadian equity securities, treasury bills and money market funds in the U.S. and Canada. We do not purchase marketable securities for speculative purposes; therefore we do not have any securities classified as trading securities. While we do not routinely sell marketable securities prior to their scheduled maturity dates, some of our investments may be held and restricted for insurance purposes, capital expenditures and NEB regulatory requirements, so these investments are classified as available-for-sale (AFS) marketable securities as they may occasionally be sold prior to their scheduled maturity dates due to the unexpected timing of cash needs. Initial investments in securities are classified as purchases of the respective type of securities (AFS marketable securities or held-to-maturity (HTM) marketable securities). Maturities of securities are classified within proceeds from sales and maturities of securities in the Condensed Consolidated Statements of Cash Flows.
AFS Securities.
AFS Securities are as follows:
|
|
|
|
|
|
|
|
|
|
Estimated Fair Value
|
|
June 30,
2016
|
|
December 31,
2015
|
|
(in millions)
|
Corporate debt securities (a)
|
$
|
15
|
|
|
$
|
31
|
|
Canadian equity securities (b)
|
15
|
|
|
—
|
|
Total available-for-sale securities
|
$
|
30
|
|
|
$
|
31
|
|
___________________________________
|
|
(a)
|
Amounts related to certain construction projects.
|
|
|
(b)
|
Amounts related to restricted funds held and collected from customers of Western Canada Transmission & Processing and Express-Platte for Canadian pipeline abandonment in accordance with the NEB’s regulatory requirements.
|
Our AFS securities are classified on the Condensed Consolidated Balance Sheets as follows:
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Fair Value
|
|
|
June 30,
2016
|
|
December 31,
2015
|
|
|
(in millions)
|
Restricted funds
|
|
|
|
Investments and other assets—other
|
$
|
24
|
|
|
$
|
11
|
|
Non-restricted funds
|
|
|
|
Current assets—other
|
6
|
|
|
20
|
|
Total available-for-sale securities
|
$
|
30
|
|
|
$
|
31
|
|
At
June 30, 2016
, the weighted-average contractual maturity of outstanding AFS securities was less than
one year
.
There were
no
material gross unrealized holding gains or losses associated with investments in AFS securities at
June 30, 2016
or
December 31, 2015
.
HTM Securities.
HTM securities are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Fair Value
|
Description
|
Condensed Consolidated Balance Sheets Caption
|
June 30,
2016
|
|
December 31,
2015
|
|
|
(in millions)
|
Bankers acceptances
|
Current assets—other
|
$
|
28
|
|
|
$
|
30
|
|
Canadian government securities
|
Current assets—other
|
25
|
|
|
24
|
|
Money market funds
|
Current assets—other
|
3
|
|
|
3
|
|
Canadian government securities
|
Investments and other assets—other
|
54
|
|
|
50
|
|
Bankers acceptances
|
Investments and other assets—other
|
—
|
|
|
12
|
|
Total held-to-maturity securities
|
$
|
110
|
|
|
$
|
119
|
|
All of our HTM securities are restricted funds pursuant to certain M&N Canada and Express-Platte (our crude oil pipeline system) debt agreements. The funds restricted for M&N Canada, plus future cash from operations that would otherwise be available for distribution to the partners of M&N Canada, are required to be placed in escrow until the balance in escrow is sufficient to fund all future debt service on the M&N Canada
6.90%
senior secured notes. There are sufficient funds held in escrow to fund all future debt service on these M&N Canada notes as of
June 30, 2016
.
At
June 30, 2016
, the weighted-average contractual maturity of outstanding HTM securities was less than
one year
.
There were
no
material gross unrecognized holding gains or losses associated with investments in HTM securities at
June 30, 2016
or
December 31, 2015
.
Other Restricted Funds
. In addition to the portions of the AFS and HTM securities that were restricted as described above, we had other restricted funds totaling
$12 million
at
June 30, 2016
and
$11 million
at
December 31, 2015
classified as Current Assets—Other on the Condensed Consolidated Balance Sheets. These restricted funds are related to additional amounts for insurance.
We also had other restricted funds totaling
$26 million
at
June 30, 2016
and
$38 million
at
December 31, 2015
classified as Investments and Other Assets—Other
on the Condensed Consolidated Balance Sheets
. Included in these restricted funds are $
16 million
and $
24 million
at
June 30, 2016
and
December 31, 2015
, respectively, related to funds held and collected from customers of Western Canada Transmission & Processing and Express-Platte for Canadian pipeline abandonment in accordance with the NEB’s regulatory requirements and $
10 million
and $
14 million
, respectively, related to
certain construction projects.
Changes in restricted balances are presented within Cash Flows from Investing Activities on our Condensed Consolidated Statements of Cash Flows.
14. Debt and Credit Facilities
Available Credit Facilities and Restrictive Debt Covenants
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expiration
Date
|
|
Total
Credit
Facilities
Capacity
|
|
Commercial Paper Outstanding at June 30, 2016
|
|
Available
Credit
Facilities
Capacity
|
|
|
|
(in millions)
|
Spectra Energy Capital, LLC (a)
|
2021
|
|
$
|
1,000
|
|
|
$
|
363
|
|
|
$
|
637
|
|
SEP (b)
|
2021
|
|
2,500
|
|
|
693
|
|
|
1,807
|
|
Westcoast (c)
|
2021
|
|
310
|
|
|
57
|
|
|
253
|
|
Union Gas (d)
|
2021
|
|
542
|
|
|
—
|
|
|
542
|
|
Total
|
|
|
$
|
4,352
|
|
|
$
|
1,113
|
|
|
$
|
3,239
|
|
_________
|
|
(a)
|
Revolving credit facility contains a covenant requiring the Spectra Energy 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
56%
at
June 30, 2016
.
|
|
|
(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 agreement, of
5.0
to 1 or less. As of
June 30, 2016
, this ratio was
3.5
to 1.
|
|
|
(c)
|
U.S. dollar equivalent at
June 30, 2016
. The revolving credit facility is
400 million
Canadian dollars and contains a covenant that requires the Westcoast non-consolidated debt-to-total capitalization ratio to not exceed
75%
. The ratio was
34%
at
June 30, 2016
.
|
|
|
(d)
|
U.S. dollar equivalent at
June 30, 2016
. The revolving credit facility is
700 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
June 30, 2016
.
|
On April 29, 2016, we amended the Union Gas and SEP revolving credit agreements. The Union Gas revolving credit facility was increased to
700 million
Canadian dollars and the SEP revolving facility was increased to
$2.5 billion
. The expiration of both facilities was extended, with both facilities expiring in
2021
.
On April 29, 2016, we amended the Westcoast and Spectra Energy Capital, LLC (Spectra Capital) revolving credit agreements. The expiration of both credit facilities was extended, with both facilities expiring in
2021
.
The issuances of commercial paper, letters of credit and revolving borrowings reduce the amount available under the credit facilities. As of
June 30, 2016
, there were
no
letters of credit issued or revolving borrowings outstanding under the credit facilities.
Our credit agreements contain various covenants, including the maintenance of certain financial ratios. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of June 30, 2016, we were in compliance with those covenants.
In addition, our credit agreements allow for acceleration of payments or termination of the agreements due to nonpayment, or in some cases, due to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. Our debt and credit agreements do not contain provisions that trigger an acceleration of indebtedness based solely on the occurrence of a material adverse change in our financial condition or results of operations.
Debt Issuances.
On May 31, 2016, Union Gas issued
250 million
Canadian dollars (approximately
$191 million
as of the issuance date) of
2.81%
unsecured notes due
2026
and
250 million
Canadian dollars (approximately
$191 million
as of the issuance date) of
3.80%
unsecured notes due
2046
. Net proceeds from the offerings were used for repayment of short term debt and debt maturities, capital expenditures and general corporate purposes.
15. Fair Value Measurements
The following presents, for each of the fair value hierarchy levels, assets and liabilities that are measured and recorded at fair value on a recurring basis:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Description
|
Condensed Consolidated Balance Sheet Caption
|
June 30, 2016
|
Total
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
(in millions)
|
Corporate debt securities
|
Cash and cash equivalents
|
$
|
161
|
|
|
$
|
—
|
|
|
$
|
161
|
|
|
$
|
—
|
|
Corporate debt securities
|
Current assets—other
|
6
|
|
|
—
|
|
|
6
|
|
|
—
|
|
Corporate debt securities
|
Investments and other assets—other
|
9
|
|
|
—
|
|
|
9
|
|
|
—
|
|
Interest rate swaps
|
Investments and other assets—other
|
76
|
|
|
—
|
|
|
76
|
|
|
—
|
|
Canadian equity securities
|
Investments and other assets—other
|
15
|
|
|
15
|
|
|
—
|
|
|
—
|
|
Total Assets
|
$
|
267
|
|
|
$
|
15
|
|
|
$
|
252
|
|
|
$
|
—
|
|
Commodity derivatives
|
Liabilities held for sale
|
$
|
2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2
|
|
Total Liabilities
|
$
|
2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Description
|
Condensed Consolidated Balance Sheet Caption
|
December 31, 2015
|
Total
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
(in millions)
|
Corporate debt securities
|
Cash and cash equivalents
|
$
|
137
|
|
|
$
|
—
|
|
|
$
|
137
|
|
|
$
|
—
|
|
Corporate debt securities
|
Current assets—other
|
20
|
|
|
—
|
|
|
20
|
|
|
—
|
|
Commodity derivatives
|
Current assets—other
|
36
|
|
|
—
|
|
|
—
|
|
|
36
|
|
Commodity derivatives
|
Investments and other assets—other
|
5
|
|
|
—
|
|
|
—
|
|
|
5
|
|
Corporate debt securities
|
Investments and other assets—other
|
11
|
|
|
—
|
|
|
11
|
|
|
—
|
|
Interest rate swaps
|
Investments and other assets—other
|
37
|
|
|
—
|
|
|
37
|
|
|
—
|
|
Total Assets
|
$
|
246
|
|
|
$
|
—
|
|
|
$
|
205
|
|
|
$
|
41
|
|
The following presents changes in Level 3 assets and liabilities that are measured at fair value on a recurring basis using significant unobservable inputs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended June 30,
|
|
Six Months
Ended June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(in millions)
|
Derivative assets (liabilities)
|
|
|
|
|
|
|
|
Fair value, beginning of period
|
$
|
10
|
|
|
$
|
49
|
|
|
$
|
41
|
|
|
$
|
78
|
|
Total gains (losses):
|
|
|
|
|
|
|
|
Included in earnings
|
(11
|
)
|
|
3
|
|
|
(15
|
)
|
|
9
|
|
Included in other comprehensive income
|
—
|
|
|
1
|
|
|
1
|
|
|
(5
|
)
|
Purchases
|
—
|
|
|
2
|
|
|
(1
|
)
|
|
3
|
|
Settlements
|
(1
|
)
|
|
(5
|
)
|
|
(28
|
)
|
|
(35
|
)
|
Fair value, end of period
|
$
|
(2
|
)
|
|
$
|
50
|
|
|
$
|
(2
|
)
|
|
$
|
50
|
|
Unrealized losses relating to instruments held at the end of the period
|
$
|
(8
|
)
|
|
$
|
—
|
|
|
$
|
(31
|
)
|
|
$
|
(16
|
)
|
Level 1
Level 1 valuations represent quoted unadjusted prices for identical instruments in active markets.
Level 2 Valuation Techniques
Fair values of our financial instruments that are actively traded in the secondary market, including our long-term debt, are determined based on market-based prices. These valuations may include inputs such as quoted market prices of the exact or similar instruments, broker or dealer quotations, or alternative pricing sources that may include models or matrix pricing tools, with reasonable levels of price transparency.
For interest rate swaps, we utilize data obtained from a third-party source for the determination of fair value. Both the future cash flows for the fixed-leg and floating-leg of our swaps are discounted to present value. In addition, credit default swap
rates are used to develop the adjustment for credit risk embedded in our positions. We believe that since some of the inputs and assumptions for the calculations of fair value are derived from observable market data, a Level 2 classification is appropriate.
Level 3 Valuation Techniques
Level 3 valuation techniques include the use of pricing models, discounted cash flow methodologies or similar techniques where at least one significant model assumption or input is unobservable. Level 3 financial instruments also include those for which the determination of fair value requires significant management judgment or estimation.
The derivative financial instruments reported in Level 3 at
June 30, 2016
consist of NGL revenue swap contracts related to the Empress assets in Western Canada Transmission & Processing. As of
June 30, 2016
, we reported certain of our NGL basis swaps at fair value using Level 3 inputs due to such derivatives not having observable market prices for substantially the full term of the derivative asset or liability. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract length extends into unobservable periods.
The fair value of these NGL basis swaps is determined using a discounted cash flow valuation technique based on a forward commodity basis curve. For these derivatives, the primary input to the valuation model is the forward commodity basis curve, which is based on observable or public data sources and extrapolated when observable prices are not available.
The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives are the forward NGL basis curves, for which a significant portion of the derivative’s term is beyond available forward pricing. At
June 30, 2016
, a
10¢
per gallon movement in underlying forward NGL prices, primarily propane prices, would affect the estimated fair value of our NGL derivatives by
$1 million
. This calculated amount does not take into account any other changes to the fair value measurement calculation.
Financial Instruments
The fair values of financial in
struments that are recorded and carried at book value are summarized in the following table. Judgment is required in interpreting market data to develop the estimates of fair value. These estimates are not necessarily indicative of the amounts we could have realized in current markets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2016
|
|
December 31, 2015
|
|
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)
|
13,638
|
|
|
14,994
|
|
|
13,567
|
|
|
13,891
|
|
__________
|
|
(a)
|
Included within Investments in and Loans to Unconsolidated Affiliates.
|
|
|
(b)
|
Excludes commercial paper, capital leases, unamortized items and fair value hedge carrying value adjustments.
|
The fair value of our long-term debt is determined based on market-based prices as described in the Level 2 valuation technique described above and is classified as Level 2.
The fair values of cash and cash equivalents, restricted cash, short-term investments, accounts receivable, notes receivable—noncurrent, accounts payable and commercial paper are not materially different from their carrying amounts because of the short-term nature of these instruments or because the stated rates approximate market rates.
During the
six months
ended
June 30,
2016
and
2015
, there were
no
material adjustments to assets and liabilities measured at fair value on a nonrecurring basis.
16. Risk Management and Hedging Activities
We are exposed to the impact of market fluctuations in the prices of NGLs and natural gas purchased as a result of our investment in DCP Midstream, the ownership of the NGL marketing operations in western Canada and processing operations associated with our U.S. pipeline assets. Exposure to interest rate risk exists as a result of the issuance of variable and fixed-rate debt and commercial paper. We are exposed to foreign currency risk from our Canadian operations. We employ established policies and procedures to manage our risks associated with these market fluctuations, which may include the use of derivatives, mostly around interest rate and commodity exposures. As of April 2016, we are no longer entering into new contracts under our risk management program at Empress.
DCP Midstream manages their direct exposure to market prices separate from Spectra Energy, and utilizes various risk management strategies, including the use of commodity derivatives.
Other than the interest rate swaps and commodity derivatives as described below, we did not have significant derivatives outstanding during the
six months
ended
June 30, 2016
.
Interest Rate Swaps
At
June 30, 2016
, we had “pay floating—receive fixed” interest rate swaps outstanding with a total notional amount of
$2 billion
to hedge against changes in the fair value of our fixed-rate debt that arise as a result of changes in market interest rates. These swaps also allow us to transform a portion of the underlying interest payments related to our long-term fixed-rate debt securities into variable-rate interest payments in order to achieve our desired mix of fixed and variable-rate debt.
Information about our interest rate swaps that had netting or rights of offset arrangements are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2016
|
|
December 31, 2015
|
|
Gross Amounts
Presented in
the Condensed
Consolidated
Balance Sheet
|
|
Amounts Not
Offset in the
Condensed
Consolidated
Balance Sheet
|
|
Net
Amount
|
|
Gross Amounts
Presented in
the Condensed
Consolidated
Balance Sheet
|
|
Amounts Not
Offset in the
Condensed
Consolidated
Balance Sheet
|
|
Net
Amount
|
Description
|
(in millions)
|
Assets
|
$
|
76
|
|
|
$
|
—
|
|
|
$
|
76
|
|
|
$
|
37
|
|
|
$
|
—
|
|
|
$
|
37
|
|
Commodity Derivatives
At
June 30, 2016
, we had commodity mark-to-market derivatives outstanding with a total notional amount of
110 million
gallons at Empress. The longest dated commodity derivative contract we currently have expires in
2018
.
Information about our commodity derivatives that had netting or rights of offset arrangements are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2016
|
|
December 31, 2015
|
|
Gross
Amounts
|
|
Gross
Amounts
Offset
|
|
Net Amount Presented in the Condensed Consolidated Balance Sheet
|
|
Gross
Amounts
|
|
Gross
Amounts
Offset
|
|
Net Amount Presented in the Condensed Consolidated Balance Sheet
|
Description
|
(in millions)
|
Assets
|
$
|
61
|
|
|
$
|
61
|
|
|
$
|
—
|
|
|
$
|
104
|
|
|
$
|
63
|
|
|
$
|
41
|
|
Liabilities
|
63
|
|
|
61
|
|
|
2
|
|
|
63
|
|
|
63
|
|
|
—
|
|
Substantially all of our commodity derivative agreements outstanding at
June 30, 2016
and
December 31, 2015
have provisions that require collateral to be posted in the amount of the net liability position if one of our credit ratings falls below investment grade.
Information regarding the impacts of commodity derivatives on our Condensed Consolidated Statements of Operations are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended June 30,
|
|
Six Months
Ended June 30,
|
Derivatives
|
Condensed Consolidated Statements of Operations Caption
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
(in millions)
|
Commodity derivatives
|
Sales of natural gas liquids
|
$
|
(11
|
)
|
|
$
|
5
|
|
|
$
|
(16
|
)
|
|
$
|
12
|
|
17. 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, climate change, 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.
Litigation
Litigation and Legal Proceedings.
We are involved in legal, tax and regulatory proceedings in various forums arising in the ordinary course of business, including matters regarding contract and payment claims, some of which involve substantial monetary amounts. We have insurance coverage for certain of these losses should they be incurred. We believe that the final disposition of these proceedings will not have a material effect on our consolidated results of operations, financial position or cash flows.
Legal costs related to the defense of loss contingencies are expensed as incurred. We had
no
material reserves for legal matters recorded as of
June 30, 2016
or
December 31, 2015
related to litigation.
Other Commitments and Contingencies
See Note 18 for a discussion of guarantees and indemnifications.
18. 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 in 2007, certain guarantees that were previously issued by us were assigned to, or replaced by, Duke Energy as guarantor in 2006. For any remaining guarantees of other Duke Energy obligations, Duke Energy has indemnified us against any losses incurred under these guarantee arrangements. The maximum potential amount of future payments we could have been required to make under these performance guarantees as of
June 30, 2016
was approximately
$406 million
, which has been indemnified by Duke Energy as discussed above. One of these outstanding performance guarantees, which has a maximum potential amount of future payment of
$201 million
, expires in
2028
. The remaining guarantees have no contractual expirations.
We have also issued joint and several guarantees to some of the Duke/Fluor Daniel (D/FD) project owners, guaranteeing the performance of D/FD under its engineering, procurement and construction contracts and other contractual commitments in place at the time of our spin-off from Duke Energy. D/FD is one of the entities transferred to Duke Energy in connection with our spin-off. Substantially all of these guarantees have no contractual expiration and no stated maximum amount of future payments that we could be required to make. Fluor Enterprises Inc., as
50%
owner in D/FD, issued similar joint and several guarantees to the same D/FD project owners.
Westcoast, 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.
We have entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These agreements typically cover environmental, litigation and other matters, as well as breaches of representations, warranties and covenants. Typically, claims may be made by third parties for various periods of time, depending on the nature of the claim. Our potential exposure under these indemnification agreements can range from a specified amount, such as the purchase price, to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. We are unable to estimate the total potential amount of future payments under these indemnification agreements due to several factors, such as the unlimited exposure under certain guarantees.
As of
June 30, 2016
, the amounts recorded for the guarantees and indemnifications described above are not material, both individually and in the aggregate.
19. Issuances of Common Stock
On March 1, 2016, we entered into an equity distribution agreement under which we may sell and issue common stock up to an aggregate offering price of
$500 million
. The equity distribution agreement allows us to offer and sell common stock at prices deemed appropriate through sales agents. Sales of common stock under the equity distribution agreement will be made by means of ordinary brokers’ transactions through the facilities of the New York Stock Exchange (NYSE), in block transactions, or as otherwise agreed upon by one or more of the sales agents and us. We intend to use the net proceeds from sales under this at-the-market program for general corporate purposes, including investments in subsidiaries to fund capital expenditures. We issued approximately
12.9 million
of common shares to the public under this program, for total net proceeds of
$383 million
through
June 30, 2016
.
In April 2016, we issued
16.1 million
common shares to the public for net proceeds of approximately
$479 million
. Net proceeds from the offering were used to purchase approximately
10.4 million
common units in SEP. SEP intends to use the proceeds from our unit purchase for general corporate purposes, including the funding of its current expansion capital plan.
20. Issuances of SEP Units
During the
six months
ended
June 30, 2016
, SEP issued
7.0 million
common units to the public under its at-the-market program and approximately
143,000
general partner units to Spectra Energy. Total net proceeds to SEP were
$327 million
(net proceeds to Spectra Energy were
$321 million
).
In April 2016, SEP issued
10.4 million
common units and
0.2 million
general partner units to Spectra Energy in a private placement transaction. See Note 19 for further discussion.
In connection with the issuances of the units, a
$23 million
gain (
$15 million
net of tax) to Additional Paid-in Capital and a
$297 million
increase in Equity—Noncontrolling Interests were recorded during the
six months
ended
June 30, 2016
. The issuances decreased Spectra Energy’s ownership in SEP from
78%
to
77%
at
June 30, 2016
.
The following table presents the effects of the issuances of SEP units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended June 30,
|
|
Six Months
Ended June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(in millions)
|
Net income—controlling interests
|
$
|
149
|
|
|
$
|
18
|
|
|
$
|
383
|
|
|
$
|
285
|
|
Increase in additional paid-in capital resulting from issuances of SEP units
|
7
|
|
|
19
|
|
|
15
|
|
|
25
|
|
Total net income—controlling interests and changes in
equity—controlling interests
|
$
|
156
|
|
|
$
|
37
|
|
|
$
|
398
|
|
|
$
|
310
|
|
21. Employee Benefit Plans
Retirement Plans.
We have a qualified non-contributory defined benefit (DB) retirement plan for U.S. employees and non-qualified, non-contributory, unfunded defined benefit plans which cover certain current and former U.S. executives. Our Westcoast subsidiary maintains qualified and non-qualified, contributory and non-contributory, DB and defined contribution (DC) retirement plans covering substantially all employees of our Canadian operations.
Our policy is to fund our retirement plans, where applicable, on an actuarial basis to provide assets sufficient to meet benefits to be paid to plan participants or as required by legislation or plan terms. We made contributions of
$11 million
to our U.S. retirement plans in both of the six months ended
June 30, 2016
and
2015
. We made total contributions to the Canadian DC and DB plans of
$13 million
in the
six months
ended
June 30, 2016
and
$16 million
in the same period in
2015
. We anticipate that we will make total contributions of approximately
$22 million
to the U.S. plans and approximately
$26 million
to the Canadian plans in
2016
.
Qualified and Non-Qualified Pension Plans—Components of Net Periodic Pension Cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended June 30,
|
|
Six Months
Ended June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(in millions)
|
U.S.
|
|
|
|
|
|
|
|
Service cost benefit earned
|
$
|
5
|
|
|
$
|
5
|
|
|
$
|
10
|
|
|
$
|
10
|
|
Interest cost on projected benefit obligation
|
6
|
|
|
6
|
|
|
12
|
|
|
12
|
|
Expected return on plan assets
|
(10
|
)
|
|
(11
|
)
|
|
(20
|
)
|
|
(21
|
)
|
Amortization of loss
|
2
|
|
|
3
|
|
|
4
|
|
|
5
|
|
Net periodic pension cost
|
$
|
3
|
|
|
$
|
3
|
|
|
$
|
6
|
|
|
$
|
6
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
|
|
|
|
|
Service cost benefit earned
|
$
|
7
|
|
|
$
|
8
|
|
|
$
|
15
|
|
|
$
|
16
|
|
Interest cost on projected benefit obligation
|
12
|
|
|
11
|
|
|
22
|
|
|
22
|
|
Expected return on plan assets
|
(16
|
)
|
|
(17
|
)
|
|
(32
|
)
|
|
(34
|
)
|
Amortization of loss
|
4
|
|
|
6
|
|
|
9
|
|
|
13
|
|
Amortization of prior service cost
|
1
|
|
|
1
|
|
|
1
|
|
|
1
|
|
Net periodic pension cost
|
$
|
8
|
|
|
$
|
9
|
|
|
$
|
15
|
|
|
$
|
18
|
|
Other Post-Retirement Benefit Plans.
We provide certain health care and life insurance benefits for retired employees on a contributory and non-contributory basis. Employees are eligible for these benefits if they have met age and service requirements at retirement, as defined in the plans.
Other Post-Retirement Benefit Plans—Components of Net Periodic Benefit Cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended June 30,
|
|
Six Months
Ended June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(in millions)
|
U.S.
|
|
|
|
|
|
|
|
Interest cost on accumulated post-retirement benefit obligation
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
4
|
|
|
$
|
4
|
|
Expected return on plan assets
|
(1
|
)
|
|
(2
|
)
|
|
(2
|
)
|
|
(3
|
)
|
Net periodic other post-retirement benefit cost
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
2
|
|
|
$
|
1
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
|
|
|
|
|
Service cost benefit earned
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
2
|
|
Interest cost on accumulated post-retirement benefit obligation
|
1
|
|
|
1
|
|
|
2
|
|
|
2
|
|
Net periodic other post-retirement benefit cost
|
$
|
1
|
|
|
$
|
2
|
|
|
$
|
3
|
|
|
$
|
4
|
|
Retirement/Savings Plan.
In addition to the retirement plans described above, we also have defined contribution employee savings plans available to both U.S. and Canadian employees. Employees may participate in a matching contribution where we match a certain percentage of before-tax employee contributions of up to
6%
of eligible pay per pay period for U.S. employees and up to
5%
of eligible pay per pay period for Canadian employees. We expensed pre-tax employer matching contributions of
$4 million
in both of the three months ended
June 30, 2016
and
2015
, and
$7 million
in both of the six months ended June 30, 2016 and 2015 for U.S. employees. We expensed pre-tax employer matching contributions of
$3 million
and
$2 million
in the three months ended
June 30, 2016
and
2015
, respectively, and
$6 million
and
$5 million
in the six months ended June 30, 2016 and 2015, respectively, for Canadian employees.
22. Condensed Consolidating Financial Information
Spectra Energy Corp has agreed to fully and unconditionally guarantee the payment of principal and interest under all series of notes outstanding under the Senior Indenture of Spectra Capital, a 100%-owned, consolidated subsidiary. In accordance with Securities and Exchange Commission (SEC) rules, the following condensed consolidating financial information is presented. The information shown for Spectra Energy Corp and Spectra Capital is presented utilizing the equity method of accounting for investments in subsidiaries, as required. The non-guarantor subsidiaries column represents all consolidated subsidiaries of Spectra Capital. This information should be read in conjunction with our accompanying Condensed Consolidated Financial Statements and notes thereto.
Spectra Energy Corp
Condensed Consolidating Statements of Operations
(Unaudited)
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Spectra
Energy
Corp
|
|
Spectra
Capital
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
Three Months Ended June 30, 2016
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,159
|
|
|
$
|
—
|
|
|
$
|
1,159
|
|
Total operating expenses
|
2
|
|
|
1
|
|
|
785
|
|
|
—
|
|
|
788
|
|
Operating income (loss)
|
(2
|
)
|
|
(1
|
)
|
|
374
|
|
|
—
|
|
|
371
|
|
Earnings from equity investments
|
—
|
|
|
—
|
|
|
16
|
|
|
—
|
|
|
16
|
|
Equity in earnings of consolidated subsidiaries
|
144
|
|
|
261
|
|
|
—
|
|
|
(405
|
)
|
|
—
|
|
Other income and expenses, net
|
(2
|
)
|
|
—
|
|
|
41
|
|
|
—
|
|
|
39
|
|
Interest expense
|
—
|
|
|
61
|
|
|
92
|
|
|
—
|
|
|
153
|
|
Earnings before income taxes
|
140
|
|
|
199
|
|
|
339
|
|
|
(405
|
)
|
|
273
|
|
Income tax expense (benefit)
|
(9
|
)
|
|
55
|
|
|
6
|
|
|
—
|
|
|
52
|
|
Net income
|
149
|
|
|
144
|
|
|
333
|
|
|
(405
|
)
|
|
221
|
|
Net income—noncontrolling interests
|
—
|
|
|
—
|
|
|
72
|
|
|
—
|
|
|
72
|
|
Net income—controlling interests
|
$
|
149
|
|
|
$
|
144
|
|
|
$
|
261
|
|
|
$
|
(405
|
)
|
|
$
|
149
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2015
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,192
|
|
|
$
|
—
|
|
|
$
|
1,192
|
|
Total operating expenses
|
1
|
|
|
(1
|
)
|
|
786
|
|
|
—
|
|
|
786
|
|
Operating income (loss)
|
(1
|
)
|
|
1
|
|
|
406
|
|
|
—
|
|
|
406
|
|
Loss from equity investments
|
—
|
|
|
—
|
|
|
(189
|
)
|
|
—
|
|
|
(189
|
)
|
Equity in earnings of consolidated subsidiaries
|
12
|
|
|
62
|
|
|
—
|
|
|
(74
|
)
|
|
—
|
|
Other income and expenses, net
|
2
|
|
|
—
|
|
|
20
|
|
|
—
|
|
|
22
|
|
Interest expense
|
—
|
|
|
61
|
|
|
105
|
|
|
—
|
|
|
166
|
|
Earnings before income taxes
|
13
|
|
|
2
|
|
|
132
|
|
|
(74
|
)
|
|
73
|
|
Income tax expense (benefit)
|
(5
|
)
|
|
(10
|
)
|
|
8
|
|
|
—
|
|
|
(7
|
)
|
Net income
|
18
|
|
|
12
|
|
|
124
|
|
|
(74
|
)
|
|
80
|
|
Net income—noncontrolling interests
|
—
|
|
|
—
|
|
|
62
|
|
|
—
|
|
|
62
|
|
Net income—controlling interests
|
$
|
18
|
|
|
$
|
12
|
|
|
$
|
62
|
|
|
$
|
(74
|
)
|
|
$
|
18
|
|
Spectra Energy Corp
Condensed Consolidating Statements of Operations
(Unaudited)
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Spectra
Energy
Corp
|
|
Spectra
Capital
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
Six Months Ended June 30, 2016
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2,544
|
|
|
$
|
(1
|
)
|
|
$
|
2,543
|
|
Total operating expenses
|
5
|
|
|
2
|
|
|
1,672
|
|
|
(1
|
)
|
|
1,678
|
|
Operating income (loss)
|
(5
|
)
|
|
(2
|
)
|
|
872
|
|
|
—
|
|
|
865
|
|
Earnings from equity investments
|
—
|
|
|
—
|
|
|
49
|
|
|
—
|
|
|
49
|
|
Equity in earnings of consolidated subsidiaries
|
371
|
|
|
653
|
|
|
—
|
|
|
(1,024
|
)
|
|
—
|
|
Other income and expenses, net
|
(2
|
)
|
|
—
|
|
|
73
|
|
|
—
|
|
|
71
|
|
Interest expense
|
—
|
|
|
123
|
|
|
181
|
|
|
—
|
|
|
304
|
|
Earnings before income taxes
|
364
|
|
|
528
|
|
|
813
|
|
|
(1,024
|
)
|
|
681
|
|
Income tax expense (benefit)
|
(19
|
)
|
|
157
|
|
|
12
|
|
|
—
|
|
|
150
|
|
Net income
|
383
|
|
|
371
|
|
|
801
|
|
|
(1,024
|
)
|
|
531
|
|
Net income—noncontrolling interests
|
—
|
|
|
—
|
|
|
148
|
|
|
—
|
|
|
148
|
|
Net income—controlling interests
|
$
|
383
|
|
|
$
|
371
|
|
|
$
|
653
|
|
|
$
|
(1,024
|
)
|
|
$
|
383
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2015
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2,816
|
|
|
$
|
(1
|
)
|
|
$
|
2,815
|
|
Total operating expenses
|
3
|
|
|
(1
|
)
|
|
1,867
|
|
|
(1
|
)
|
|
1,868
|
|
Operating income (loss)
|
(3
|
)
|
|
1
|
|
|
949
|
|
|
—
|
|
|
947
|
|
Loss from equity investments
|
—
|
|
|
—
|
|
|
(165
|
)
|
|
—
|
|
|
(165
|
)
|
Equity in earnings of consolidated subsidiaries
|
275
|
|
|
483
|
|
|
—
|
|
|
(758
|
)
|
|
—
|
|
Other income and expenses, net
|
—
|
|
|
—
|
|
|
42
|
|
|
—
|
|
|
42
|
|
Interest expense
|
—
|
|
|
122
|
|
|
203
|
|
|
—
|
|
|
325
|
|
Earnings before income taxes
|
272
|
|
|
362
|
|
|
623
|
|
|
(758
|
)
|
|
499
|
|
Income tax expense (benefit)
|
(13
|
)
|
|
87
|
|
|
20
|
|
|
—
|
|
|
94
|
|
Net income
|
285
|
|
|
275
|
|
|
603
|
|
|
(758
|
)
|
|
405
|
|
Net income—noncontrolling interests
|
—
|
|
|
—
|
|
|
120
|
|
|
—
|
|
|
120
|
|
Net income—controlling interests
|
$
|
285
|
|
|
$
|
275
|
|
|
$
|
483
|
|
|
$
|
(758
|
)
|
|
$
|
285
|
|
Spectra Energy Corp
Condensed Consolidating Statements of Comprehensive Income
(Unaudited)
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Spectra
Energy
Corp
|
|
Spectra
Capital
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
Three Months Ended June 30, 2016
|
|
|
|
|
|
|
|
|
|
Net income
|
$
|
149
|
|
|
$
|
144
|
|
|
$
|
333
|
|
|
$
|
(405
|
)
|
|
$
|
221
|
|
Other comprehensive income
|
1
|
|
|
—
|
|
|
56
|
|
|
—
|
|
|
57
|
|
Total comprehensive income, net of tax
|
150
|
|
|
144
|
|
|
389
|
|
|
(405
|
)
|
|
278
|
|
Less: comprehensive income—noncontrolling interests
|
—
|
|
|
—
|
|
|
75
|
|
|
—
|
|
|
75
|
|
Comprehensive income—controlling interests
|
$
|
150
|
|
|
$
|
144
|
|
|
$
|
314
|
|
|
$
|
(405
|
)
|
|
$
|
203
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2015
|
|
|
|
|
|
|
|
|
|
Net income
|
$
|
18
|
|
|
$
|
12
|
|
|
$
|
124
|
|
|
$
|
(74
|
)
|
|
$
|
80
|
|
Other comprehensive income
|
2
|
|
|
—
|
|
|
91
|
|
|
—
|
|
|
93
|
|
Total comprehensive income, net of tax
|
20
|
|
|
12
|
|
|
215
|
|
|
(74
|
)
|
|
173
|
|
Less: comprehensive income—noncontrolling interests
|
—
|
|
|
—
|
|
|
64
|
|
|
—
|
|
|
64
|
|
Comprehensive income—controlling interests
|
$
|
20
|
|
|
$
|
12
|
|
|
$
|
151
|
|
|
$
|
(74
|
)
|
|
$
|
109
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2016
|
|
|
|
|
|
|
|
|
|
Net income
|
$
|
383
|
|
|
$
|
371
|
|
|
$
|
801
|
|
|
$
|
(1,024
|
)
|
|
$
|
531
|
|
Other comprehensive income
|
2
|
|
|
—
|
|
|
360
|
|
|
—
|
|
|
362
|
|
Total comprehensive income, net of tax
|
385
|
|
|
371
|
|
|
1,161
|
|
|
(1,024
|
)
|
|
893
|
|
Less: comprehensive income—noncontrolling interests
|
—
|
|
|
—
|
|
|
155
|
|
|
—
|
|
|
155
|
|
Comprehensive income—controlling interests
|
$
|
385
|
|
|
$
|
371
|
|
|
$
|
1,006
|
|
|
$
|
(1,024
|
)
|
|
$
|
738
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2015
|
|
|
|
|
|
|
|
|
|
Net income
|
$
|
285
|
|
|
$
|
275
|
|
|
$
|
603
|
|
|
$
|
(758
|
)
|
|
$
|
405
|
|
Other comprehensive income (loss)
|
3
|
|
|
—
|
|
|
(395
|
)
|
|
—
|
|
|
(392
|
)
|
Total comprehensive income, net of tax
|
288
|
|
|
275
|
|
|
208
|
|
|
(758
|
)
|
|
13
|
|
Less: comprehensive income—noncontrolling interests
|
—
|
|
|
—
|
|
|
114
|
|
|
—
|
|
|
114
|
|
Comprehensive income (loss)—controlling interests
|
$
|
288
|
|
|
$
|
275
|
|
|
$
|
94
|
|
|
$
|
(758
|
)
|
|
$
|
(101
|
)
|
Spectra Energy Corp
Condensed Consolidating Balance Sheet
June 30, 2016
(Unaudited)
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Spectra
Energy
Corp
|
|
Spectra
Capital
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
Cash and cash equivalents
|
$
|
—
|
|
|
$
|
2
|
|
|
$
|
238
|
|
|
$
|
—
|
|
|
$
|
240
|
|
Receivables—consolidated subsidiaries
|
12
|
|
|
—
|
|
|
6
|
|
|
(18
|
)
|
|
—
|
|
Notes receivable—current—consolidated subsidiaries
|
—
|
|
|
—
|
|
|
388
|
|
|
(388
|
)
|
|
—
|
|
Receivables—other
|
1
|
|
|
—
|
|
|
707
|
|
|
—
|
|
|
708
|
|
Other current assets
|
12
|
|
|
—
|
|
|
677
|
|
|
—
|
|
|
689
|
|
Total current assets
|
25
|
|
|
2
|
|
|
2,016
|
|
|
(406
|
)
|
|
1,637
|
|
Investments in and loans to unconsolidated affiliates
|
—
|
|
|
—
|
|
|
2,657
|
|
|
—
|
|
|
2,657
|
|
Investments in consolidated subsidiaries
|
14,716
|
|
|
20,229
|
|
|
—
|
|
|
(34,945
|
)
|
|
—
|
|
Advances receivable—consolidated subsidiaries
|
—
|
|
|
5,037
|
|
|
1,331
|
|
|
(6,368
|
)
|
|
—
|
|
Notes receivable—consolidated subsidiaries
|
—
|
|
|
—
|
|
|
2,800
|
|
|
(2,800
|
)
|
|
—
|
|
Goodwill
|
—
|
|
|
—
|
|
|
4,217
|
|
|
—
|
|
|
4,217
|
|
Other assets
|
41
|
|
|
46
|
|
|
286
|
|
|
—
|
|
|
373
|
|
Net property, plant and equipment
|
—
|
|
|
—
|
|
|
24,707
|
|
|
—
|
|
|
24,707
|
|
Regulatory assets and deferred debits
|
3
|
|
|
4
|
|
|
1,449
|
|
|
—
|
|
|
1,456
|
|
Total Assets
|
$
|
14,785
|
|
|
$
|
25,318
|
|
|
$
|
39,463
|
|
|
$
|
(44,519
|
)
|
|
$
|
35,047
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
705
|
|
|
$
|
—
|
|
|
$
|
709
|
|
Accounts payable—consolidated subsidiaries
|
—
|
|
|
15
|
|
|
3
|
|
|
(18
|
)
|
|
—
|
|
Commercial paper
|
—
|
|
|
363
|
|
|
750
|
|
|
—
|
|
|
1,113
|
|
Short-term borrowings—consolidated subsidiaries
|
—
|
|
|
388
|
|
|
—
|
|
|
(388
|
)
|
|
—
|
|
Taxes accrued
|
2
|
|
|
2
|
|
|
76
|
|
|
—
|
|
|
80
|
|
Current maturities of long-term debt
|
—
|
|
|
—
|
|
|
68
|
|
|
—
|
|
|
68
|
|
Other current liabilities
|
62
|
|
|
47
|
|
|
707
|
|
|
—
|
|
|
816
|
|
Total current liabilities
|
66
|
|
|
817
|
|
|
2,309
|
|
|
(406
|
)
|
|
2,786
|
|
Long-term debt
|
—
|
|
|
2,911
|
|
|
10,673
|
|
|
—
|
|
|
13,584
|
|
Advances payable—consolidated subsidiaries
|
6,368
|
|
|
—
|
|
|
—
|
|
|
(6,368
|
)
|
|
—
|
|
Notes payable—consolidated subsidiaries
|
—
|
|
|
2,800
|
|
|
—
|
|
|
(2,800
|
)
|
|
—
|
|
Deferred credits and other liabilities
|
753
|
|
|
4,074
|
|
|
2,288
|
|
|
—
|
|
|
7,115
|
|
Preferred stock of subsidiaries
|
—
|
|
|
—
|
|
|
339
|
|
|
—
|
|
|
339
|
|
Equity
|
|
|
|
|
|
|
|
|
|
Controlling interests
|
7,598
|
|
|
14,716
|
|
|
20,229
|
|
|
(34,945
|
)
|
|
7,598
|
|
Noncontrolling interests
|
—
|
|
|
—
|
|
|
3,625
|
|
|
—
|
|
|
3,625
|
|
Total equity
|
7,598
|
|
|
14,716
|
|
|
23,854
|
|
|
(34,945
|
)
|
|
11,223
|
|
Total Liabilities and Equity
|
$
|
14,785
|
|
|
$
|
25,318
|
|
|
$
|
39,463
|
|
|
$
|
(44,519
|
)
|
|
$
|
35,047
|
|
Spectra Energy Corp
Condensed Consolidating Balance Sheet
December 31, 2015
(Unaudited)
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Spectra
Energy
Corp
|
|
Spectra
Capital
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
Cash and cash equivalents
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
212
|
|
|
$
|
—
|
|
|
$
|
213
|
|
Receivables—consolidated subsidiaries
|
15
|
|
|
6
|
|
|
13
|
|
|
(34
|
)
|
|
—
|
|
Notes receivable—current—consolidated subsidiaries
|
—
|
|
|
—
|
|
|
387
|
|
|
(387
|
)
|
|
—
|
|
Receivables—other
|
2
|
|
|
—
|
|
|
804
|
|
|
—
|
|
|
806
|
|
Other current assets
|
25
|
|
|
—
|
|
|
604
|
|
|
—
|
|
|
629
|
|
Total current assets
|
42
|
|
|
7
|
|
|
2,020
|
|
|
(421
|
)
|
|
1,648
|
|
Investments in and loans to unconsolidated affiliates
|
—
|
|
|
—
|
|
|
2,592
|
|
|
—
|
|
|
2,592
|
|
Investments in consolidated subsidiaries
|
13,919
|
|
|
19,161
|
|
|
—
|
|
|
(33,080
|
)
|
|
—
|
|
Advances receivable—consolidated subsidiaries
|
—
|
|
|
5,273
|
|
|
1,326
|
|
|
(6,599
|
)
|
|
—
|
|
Notes receivable—consolidated subsidiaries
|
—
|
|
|
—
|
|
|
2,800
|
|
|
(2,800
|
)
|
|
—
|
|
Goodwill
|
—
|
|
|
—
|
|
|
4,154
|
|
|
—
|
|
|
4,154
|
|
Other assets
|
41
|
|
|
27
|
|
|
242
|
|
|
—
|
|
|
310
|
|
Net property, plant and equipment
|
—
|
|
|
—
|
|
|
22,918
|
|
|
—
|
|
|
22,918
|
|
Regulatory assets and deferred debits
|
3
|
|
|
3
|
|
|
1,295
|
|
|
—
|
|
|
1,301
|
|
Total Assets
|
$
|
14,005
|
|
|
$
|
24,471
|
|
|
$
|
37,347
|
|
|
$
|
(42,900
|
)
|
|
$
|
32,923
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
$
|
2
|
|
|
$
|
3
|
|
|
$
|
506
|
|
|
$
|
—
|
|
|
$
|
511
|
|
Accounts payable—consolidated subsidiaries
|
4
|
|
|
28
|
|
|
2
|
|
|
(34
|
)
|
|
—
|
|
Commercial paper
|
—
|
|
|
481
|
|
|
631
|
|
|
—
|
|
|
1,112
|
|
Short-term borrowings—consolidated subsidiaries
|
—
|
|
|
387
|
|
|
—
|
|
|
(387
|
)
|
|
—
|
|
Taxes accrued
|
5
|
|
|
—
|
|
|
73
|
|
|
—
|
|
|
78
|
|
Current maturities of long-term debt
|
—
|
|
|
—
|
|
|
652
|
|
|
—
|
|
|
652
|
|
Other current liabilities
|
102
|
|
|
48
|
|
|
889
|
|
|
—
|
|
|
1,039
|
|
Total current liabilities
|
113
|
|
|
947
|
|
|
2,753
|
|
|
(421
|
)
|
|
3,392
|
|
Long-term debt
|
—
|
|
|
2,891
|
|
|
10,001
|
|
|
—
|
|
|
12,892
|
|
Advances payable—consolidated subsidiaries
|
6,599
|
|
|
—
|
|
|
—
|
|
|
(6,599
|
)
|
|
—
|
|
Notes payable—consolidated subsidiaries
|
—
|
|
|
2,800
|
|
|
—
|
|
|
(2,800
|
)
|
|
—
|
|
Deferred credits and other liabilities
|
767
|
|
|
3,914
|
|
|
2,087
|
|
|
—
|
|
|
6,768
|
|
Preferred stock of subsidiaries
|
—
|
|
|
—
|
|
|
339
|
|
|
—
|
|
|
339
|
|
Equity
|
|
|
|
|
|
|
|
|
|
Controlling interests
|
6,526
|
|
|
13,919
|
|
|
19,161
|
|
|
(33,080
|
)
|
|
6,526
|
|
Noncontrolling interests
|
—
|
|
|
—
|
|
|
3,006
|
|
|
—
|
|
|
3,006
|
|
Total equity
|
6,526
|
|
|
13,919
|
|
|
22,167
|
|
|
(33,080
|
)
|
|
9,532
|
|
Total Liabilities and Equity
|
$
|
14,005
|
|
|
$
|
24,471
|
|
|
$
|
37,347
|
|
|
$
|
(42,900
|
)
|
|
$
|
32,923
|
|
Spectra Energy Corp
Condensed Consolidating Statement of Cash Flows
Six Months Ended June 30, 2016
(Unaudited)
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Spectra
Energy
Corp
|
|
Spectra
Capital
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
CASH FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
Net income
|
$
|
383
|
|
|
$
|
371
|
|
|
$
|
801
|
|
|
$
|
(1,024
|
)
|
|
$
|
531
|
|
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
—
|
|
|
—
|
|
|
397
|
|
|
—
|
|
|
397
|
|
Earnings from equity investments
|
—
|
|
|
—
|
|
|
(49
|
)
|
|
—
|
|
|
(49
|
)
|
Equity in earnings of consolidated subsidiaries
|
(371
|
)
|
|
(653
|
)
|
|
—
|
|
|
1,024
|
|
|
—
|
|
Distributions from equity investments
|
—
|
|
|
—
|
|
|
52
|
|
|
—
|
|
|
52
|
|
Other
|
(43
|
)
|
|
216
|
|
|
135
|
|
|
—
|
|
|
308
|
|
Net cash provided by (used in) operating activities
|
(31
|
)
|
|
(66
|
)
|
|
1,336
|
|
|
—
|
|
|
1,239
|
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
—
|
|
|
—
|
|
|
(1,520
|
)
|
|
—
|
|
|
(1,520
|
)
|
Investments in and loans to unconsolidated
affiliates
|
—
|
|
|
—
|
|
|
(112
|
)
|
|
—
|
|
|
(112
|
)
|
Purchase of intangible, net
|
—
|
|
|
—
|
|
|
(40
|
)
|
|
—
|
|
|
(40
|
)
|
Purchases of held-to-maturity securities
|
—
|
|
|
—
|
|
|
(346
|
)
|
|
—
|
|
|
(346
|
)
|
Proceeds from sales and maturities of held-to-maturity securities
|
—
|
|
|
—
|
|
|
364
|
|
|
—
|
|
|
364
|
|
Purchases of available-for-sale securities
|
—
|
|
|
—
|
|
|
(329
|
)
|
|
—
|
|
|
(329
|
)
|
Proceeds from sales and maturities of available-for-sale securities
|
—
|
|
|
—
|
|
|
330
|
|
|
—
|
|
|
330
|
|
Distributions from equity investments
|
—
|
|
|
—
|
|
|
45
|
|
|
—
|
|
|
45
|
|
Distribution to equity investment
|
—
|
|
|
—
|
|
|
(148
|
)
|
|
—
|
|
|
(148
|
)
|
Advances from (to) affiliates
|
(50
|
)
|
|
197
|
|
|
—
|
|
|
(147
|
)
|
|
—
|
|
Other changes in restricted funds
|
—
|
|
|
—
|
|
|
11
|
|
|
—
|
|
|
11
|
|
Other
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
Net cash provided by (used in) investing activities
|
(50
|
)
|
|
197
|
|
|
(1,744
|
)
|
|
(147
|
)
|
|
(1,744
|
)
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
Proceeds from the issuance of long-term debt
|
—
|
|
|
—
|
|
|
382
|
|
|
—
|
|
|
382
|
|
Payments for the redemption of long-term debt
|
—
|
|
|
—
|
|
|
(619
|
)
|
|
—
|
|
|
(619
|
)
|
Net increase (decrease) in commercial paper
|
—
|
|
|
(118
|
)
|
|
95
|
|
|
—
|
|
|
(23
|
)
|
Distributions to noncontrolling interests
|
—
|
|
|
—
|
|
|
(114
|
)
|
|
—
|
|
|
(114
|
)
|
Contributions from noncontrolling interests
|
—
|
|
|
—
|
|
|
278
|
|
|
—
|
|
|
278
|
|
Proceeds from the issuances of Spectra Energy common stock
|
868
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
868
|
|
Proceeds from the issuances of SEP common units
|
—
|
|
|
—
|
|
|
321
|
|
|
—
|
|
|
321
|
|
Dividends paid on common stock
|
(557
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(557
|
)
|
Distributions and advances from (to) affiliates
|
(231
|
)
|
|
(12
|
)
|
|
96
|
|
|
147
|
|
|
—
|
|
Other
|
1
|
|
|
—
|
|
|
(9
|
)
|
|
—
|
|
|
(8
|
)
|
Net cash provided by (used in) financing activities
|
81
|
|
|
(130
|
)
|
|
430
|
|
|
147
|
|
|
528
|
|
Effect of exchange rate changes on cash
|
—
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
4
|
|
Net increase in cash and cash equivalents
|
—
|
|
|
1
|
|
|
26
|
|
|
—
|
|
|
27
|
|
Cash and cash equivalents at beginning of period
|
—
|
|
|
1
|
|
|
212
|
|
|
—
|
|
|
213
|
|
Cash and cash equivalents at end of period
|
$
|
—
|
|
|
$
|
2
|
|
|
$
|
238
|
|
|
$
|
—
|
|
|
$
|
240
|
|
Spectra Energy Corp
Condensed Consolidating Statement of Cash Flows
Six Months Ended June 30, 2015
(Unaudited)
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Spectra
Energy
Corp
|
|
Spectra
Capital
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
CASH FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
Net income
|
$
|
285
|
|
|
$
|
275
|
|
|
$
|
603
|
|
|
$
|
(758
|
)
|
|
$
|
405
|
|
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
—
|
|
|
—
|
|
|
393
|
|
|
—
|
|
|
393
|
|
Loss from equity investments
|
—
|
|
|
—
|
|
|
165
|
|
|
—
|
|
|
165
|
|
Equity in earnings of consolidated subsidiaries
|
(275
|
)
|
|
(483
|
)
|
|
—
|
|
|
758
|
|
|
—
|
|
Distributions from equity investments
|
—
|
|
|
—
|
|
|
93
|
|
|
—
|
|
|
93
|
|
Other
|
30
|
|
|
68
|
|
|
302
|
|
|
—
|
|
|
400
|
|
Net cash provided by (used in) operating activities
|
40
|
|
|
(140
|
)
|
|
1,556
|
|
|
—
|
|
|
1,456
|
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
—
|
|
|
—
|
|
|
(989
|
)
|
|
—
|
|
|
(989
|
)
|
Investments in and loans to unconsolidated
affiliates
|
—
|
|
|
—
|
|
|
(34
|
)
|
|
—
|
|
|
(34
|
)
|
Purchases of held-to-maturity securities
|
—
|
|
|
—
|
|
|
(329
|
)
|
|
—
|
|
|
(329
|
)
|
Proceeds from sales and maturities of held-to-maturity securities
|
—
|
|
|
—
|
|
|
344
|
|
|
—
|
|
|
344
|
|
Proceeds from sales and maturities of available-for-sale securities
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
Distributions from equity investments
|
—
|
|
|
—
|
|
|
35
|
|
|
—
|
|
|
35
|
|
Advances from (to) affiliates
|
(72
|
)
|
|
46
|
|
|
—
|
|
|
26
|
|
|
—
|
|
Other changes in restricted funds
|
—
|
|
|
—
|
|
|
(6
|
)
|
|
—
|
|
|
(6
|
)
|
Other
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
2
|
|
Net cash provided by (used in) investing activities
|
(72
|
)
|
|
46
|
|
|
(976
|
)
|
|
26
|
|
|
(976
|
)
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
Proceeds from the issuance of long-term debt
|
—
|
|
|
—
|
|
|
994
|
|
|
—
|
|
|
994
|
|
Payments for the redemption of long-term debt
|
—
|
|
|
—
|
|
|
(39
|
)
|
|
—
|
|
|
(39
|
)
|
Net increase (decrease) in commercial paper
|
—
|
|
|
99
|
|
|
(1,129
|
)
|
|
—
|
|
|
(1,030
|
)
|
Distributions to noncontrolling interests
|
—
|
|
|
—
|
|
|
(93
|
)
|
|
—
|
|
|
(93
|
)
|
Contributions from noncontrolling interests
|
—
|
|
|
—
|
|
|
90
|
|
|
—
|
|
|
90
|
|
Proceeds from the issuances of SEP common units
|
—
|
|
|
—
|
|
|
180
|
|
|
—
|
|
|
180
|
|
Dividends paid on common stock
|
(499
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(499
|
)
|
Distributions and advances from (to) affiliates
|
532
|
|
|
(4
|
)
|
|
(502
|
)
|
|
(26
|
)
|
|
—
|
|
Other
|
(1
|
)
|
|
—
|
|
|
(8
|
)
|
|
—
|
|
|
(9
|
)
|
Net cash provided by (used in) financing activities
|
32
|
|
|
95
|
|
|
(507
|
)
|
|
(26
|
)
|
|
(406
|
)
|
Effect of exchange rate changes on cash
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
—
|
|
|
(2
|
)
|
Net increase in cash and cash equivalents
|
—
|
|
|
1
|
|
|
71
|
|
|
—
|
|
|
72
|
|
Cash and cash equivalents at beginning of period
|
—
|
|
|
1
|
|
|
214
|
|
|
—
|
|
|
215
|
|
Cash and cash equivalents at end of period
|
$
|
—
|
|
|
$
|
2
|
|
|
$
|
285
|
|
|
$
|
—
|
|
|
$
|
287
|
|
23. New Accounting Pronouncements
In June 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-10,
“Development Stage Entities (Topic 915): Elimination of Certain Financial Reporting Requirements, Including an Amendment to Variable Interest Entities Guidance in Topic 810, Consolidation
,
”
which amends the consolidation guidance around reporting entities that invest in development stage entities. We adopted the consolidation guidance of this amendment on January 1, 2016 and applied it retrospectively with no material effect on our consolidated results of operations, financial position or cash flows. This ASU did result in certain of our entities being classified as Variable Interest Entities. See Note 10 for discussion of our Variable Interest Entities.
In February 2015, the FASB issued ASU No. 2015-02,
“Consolidation (Topic 810): Amendments to the Consolidation Analysis,”
which makes changes to both the variable interest model and the voting model. These changes required reevaluation of certain entities for consolidation and required us to revise our documentation regarding the consolidation or deconsolidation of such entities. We adopted this standard on January 1, 2016 with no material effect on our consolidated results of operations, financial position or cash flows.
In September 2015, the FASB issued ASU No. 2015-16,
“Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments
,
”
to simplify accounting for adjustments made to provisional amounts recognized in a business combination and to eliminate the retrospective accounting for those adjustments. We adopted this standard on January 1, 2016. The adoption of this standard has not had a material impact on our consolidated results of operations, financial position or cash flow.
In February 2016, the FASB issued ASU No. 2016-02,
“Leases (Topic 842),”
to improve the financial reporting around leasing transactions. The new guidance requires companies to begin recording assets and liabilities arising from those leases classified as operating leases under previous guidance. Furthermore, the new guidance will require significant additional disclosures about the amount, timing and uncertainty of cash flows from leases. Topic 842 retains a distinction between finance leases and operating leases. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the classification criteria for distinguishing between capital leases and operating leases in previous guidance. The result of retaining a distinction between finance leases and operating leases is that under the lessee accounting model in Topic 842, the effect of leases in the statement of comprehensive income and the statement of cash flows is largely unchanged from previous guidance. This ASU is effective for us January 1, 2019. We are currently evaluating this ASU and its potential impact on us.
In March 2016, the FASB issued ASU No. 2016-05,
“Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships,”
which clarifies the hedge accounting impact when there is a change in one of the counterparties to the derivative contract (i.e. novation). This ASU is effective for us January 1, 2017. This ASU is not expected to have a material impact on our consolidated results of operations, financial position or cash flow.
In March 2016, the FASB issued ASU No. 2016-06, “
Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments,”
which simplifies the embedded derivative analysis for debt instruments containing contingent call or put options. This ASU is effective for us January 1, 2017. This ASU is not expected to have a material impact on our consolidated results of operations, financial position or cash flow.
In March 2016, the FASB issued ASU No. 2016-07, “
Investments—Equity Method and Joint Ventures (Topic 323): Simplifying the Transition to the Equity Method of Accounting,”
which eliminates the requirement to apply the equity method of accounting retrospectively when a reporting entity obtains significant influence over a previously held investment. This ASU is effective for us January 1, 2017. We are currently evaluating this ASU and its potential impact on us.
In March 2016, the FASB issued ASU No. 2016-08,
“Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net),”
to clarify implementation guidance on principal versus agent considerations. This ASU is effective for us on January 1, 2018. We are currently evaluating this ASU and its potential impact on us.
In March 2016, the FASB issued ASU No. 2016-09,
“Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting,”
which simplifies several aspects of the accounting for share-based payment award transactions. This ASU is effective for us January 1, 2017. We are currently evaluating this ASU and its potential impact on us.
In April 2016, the FASB issued ASU No. 2016-10,
“Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing,”
to clarify implementation guidance on performance obligations and licensing. This ASU is effective for us on January 1, 2018. We are currently evaluating this ASU and its potential impact on us.
In May 2016, the FASB issued ASU No. 2016-12,
“Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients,”
to clarify implementation guidance on assessing collectibility, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition. This ASU is effective for us on January 1, 2018. We are currently evaluating this ASU and its potential impact on us.
In June 2016, the FASB issued ASU No. 2016-13,
“Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,”
to replace the incurred loss impairment methodology with a methodology that reflects expected credit losses and requires the consideration of a broader range of reasonable and supportable information to inform credit loss estimates. This ASU is effective for us on January 1, 2020. We are currently evaluating this ASU and its potential impact on us.
|
|
|
Item 2.
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
|
INTRODUCTION
Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the accompanying Condensed Consolidated Financial Statements.
Executive Overview
For the
three months ended June 30, 2016
and
2015
, we reported net income from controlling interests of
$149 million
and
$18 million
, respectively. For the
six months ended June 30, 2016
and
2015
, we reported net income from controlling interests of
$383 million
and
$285 million
, respectively.
The highlights for the three months and
six months ended June 30, 2016
include the following:
|
|
•
|
Spectra Energy Partners’ earnings for the three-month period benefited mainly from expansion projects, more than offset by a one-time property tax accrual adjustment in 2015 and by the absence of equity earnings from DCP Sand Hills Pipeline, LLC (Sand Hills) and DCP Southern Hills Pipeline, LLC (Southern Hills) NGL pipelines, which SEP owned until October 2015.
For the six-month period, earnings benefited mainly from expansion projects, more than offset by lower interruptible and short-term firm transportation revenue, a one-time property tax accrual adjustment in 2015 and by the absence of equity earnings from Sand Hills and Southern Hills.
|
|
|
•
|
Distribution’s earnings for the three-month period benefited mainly from incremental earnings from the 2015 Dawn-Parkway expansion project and colder weather, partially offset by a lower Canadian dollar. For the six-month period, earnings decreased mainly due to the effect of a lower Canadian dollar and warmer weather, partially offset by incremental earnings from the 2015 Dawn-Parkway expansion project and lower earnings to be shared with customers.
|
|
|
•
|
Western Canada Transmission & Processing’s earnings for the three and six-month periods decreased mainly due to lower firm gathering and processing revenues, lower earnings at Empress and a lower Canadian dollar, partially offset by lower plant turnaround costs.
|
|
|
•
|
Field Services’ earnings for the three and six-month periods increased mainly due to the 2015 partial impairment of goodwill at DCP Midstream and favorable contract realignment efforts and continued costs savings, partially offset by lower commodity prices.
|
We are conducting an assessment of the Texas Eastern Transmission, LP (Texas Eastern) natural gas transmission system across Pennsylvania and New Jersey. The assessment is the result of a corrective action order from the Pipeline and Hazardous Materials Safety Administration (PHMSA), as well as our own work plan, related to an incident on the system on April 29, 2016 near Delmont, Pennsylvania. This assessment program and the related system repairs are expected to cost approximately $75 million to $100 million. Approximately 90% of this program will be completed in 2016, with the remainder of the work to be performed in 2017. Additional inspections and repairs, if any, will be determined after the completion of this work. Importantly, we expect that by November 1, 2016, we will be in a position to fully meet our customer obligations for the winter season.
In the first six months of
2016
, we had $1.6 billion of capital and investment expenditures. We currently project $4.2 billion of capital and investment expenditures for the full year, including expansion capital expenditures of $3.6 billion. These projections exclude contributions from noncontrolling interests.
We are committed to an investment-grade balance sheet and continued prudent financial management of our capital structure. Therefore, financing growth activities will continue to be based on our strong and growing fee-based earnings and
cash flows as well as the issuances of debt and equity securities. As of
June 30, 2016
, our revolving credit facilities included Spectra Capital’s $1 billion facility, SEP’s $2.5 billion facility, Westcoast’s 400 million Canadian dollar facility and Union Gas’ 700 million Canadian dollar facility. These facilities are used principally as back-stops for commercial paper programs.
RESULTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended June 30,
|
|
Six Months
Ended June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(in millions)
|
Operating revenues
|
$
|
1,159
|
|
|
$
|
1,192
|
|
|
$
|
2,543
|
|
|
$
|
2,815
|
|
Operating expenses
|
788
|
|
|
786
|
|
|
1,678
|
|
|
1,868
|
|
Operating income
|
371
|
|
|
406
|
|
|
865
|
|
|
947
|
|
Other income and expenses
|
55
|
|
|
(167
|
)
|
|
120
|
|
|
(123
|
)
|
Interest expense
|
153
|
|
|
166
|
|
|
304
|
|
|
325
|
|
Earnings before income taxes
|
273
|
|
|
73
|
|
|
681
|
|
|
499
|
|
Income tax expense (benefit)
|
52
|
|
|
(7
|
)
|
|
150
|
|
|
94
|
|
Net income
|
221
|
|
|
80
|
|
|
531
|
|
|
405
|
|
Net income—noncontrolling interests
|
72
|
|
|
62
|
|
|
148
|
|
|
120
|
|
Net income—controlling interests
|
$
|
149
|
|
|
$
|
18
|
|
|
$
|
383
|
|
|
$
|
285
|
|
Three Months Ended June 30, 2016 Compared to Same Period in 2015
Operating Revenues.
The
$33 million
decrease
was driven by:
|
|
•
|
the effects of a lower Canadian dollar at Distribution and Western Canada Transmission & Processing,
|
|
|
•
|
lower firm gathering and processing revenues and a decrease from non-cash mark-to-market commodity-related pricing adjustments and lower settlement gains associated with the risk management program at the Empress operations at Western Canada Transmission & Processing and
|
|
|
•
|
lower natural gas prices passed through to customers, net of higher residential usage due to colder weather at Distribution, partially offset by
|
|
|
•
|
higher revenues from expansion projects at Spectra Energy Partners.
|
Operating Expenses.
The
$2 million
increase
was driven by:
|
|
•
|
higher costs related to expansion projects, higher property tax accruals due to the absence of a 2015 tax benefit and higher pipeline inspection and repair costs at Spectra Energy Partners and
|
|
|
•
|
higher volumes of natural gas sold due to colder weather, net of lower natural gas prices passed through to customers at Distribution, partially offset by
|
|
|
•
|
the effects of a lower Canadian dollar at Distribution and Western Canada Transmission & Processing and
|
|
|
•
|
lower plant turnaround costs at Western Canada Transmission & Processing.
|
Other Income and Expenses
. The
$222 million
increase
was mainly attributable to lower equity losses from Field Services mainly due to the 2015 partial impairment of goodwill at DCP Midstream.
Interest Expense.
The
$13 million
decrease
was mainly due to higher capitalized interest.
Income Tax Expense.
The
$59 million
increase
was primarily attributable to the tax impact of the partial impairment of goodwill at DCP Midstream in 2015, partially offset by tax rate changes in 2016.
The effective tax rate for income from continuing operations was 19% for the three months ended
June 30, 2016
compared to negative 10% for the same period in
2015
.
Net Income—Noncontrolling Interests
. The
$10 million
increase
was driven primarily by higher noncontrolling ownership interests at Spectra Energy Partners.
Six Months Ended June 30, 2016 Compared to Same Period in 2015
Operating Revenues.
The
$272 million
decrease
was driven by:
|
|
•
|
lower usage due to warmer weather and lower natural gas prices passed through to customers at Distribution,
|
|
|
•
|
the effects of a lower Canadian dollar at Distribution and Western Canada Transmission & Processing and
|
|
|
•
|
a decrease from non-cash mark-to-market commodity-related pricing adjustments associated with the risk management program, lower NGL prices at the Empress operations and a decrease in firm gathering and processing revenues at Western Canada Transmission & Processing, partially offset by
|
|
|
•
|
higher revenues from expansion projects at Spectra Energy Partners.
|
Operating Expenses.
The
$190 million
decrease
was driven by:
|
|
•
|
lower volumes of natural gas sold due to warmer weather and lower natural gas prices passed through to customers at Distribution,
|
|
|
•
|
the effects of a lower Canadian dollar at Distribution and Western Canada Transmission & Processing and
|
|
|
•
|
lower costs of sales at the Empress operations and lower plant turnaround costs at Western Canada Transmission & Processing, partially offset by
|
|
|
•
|
higher costs related to expansion projects, pipeline inspection and repair costs and property tax accruals due to the absence of a 2015 tax benefit at Spectra Energy Partners.
|
Other Income and Expenses
. The
$243 million
increase
was mainly attributable to lower equity losses from Field Services mainly due to the 2015 partial impairment of goodwill at DCP Midstream.
Interest Expense.
The
$21 million
decrease
was mainly due to higher capitalized interest and a lower Canadian dollar, partially offset by higher average long-term debt balances.
Income Tax Expense.
The
$56 million
increase
was primarily attributable to the tax impact on the partial impairment of goodwill at DCP Midstream in 2015, partially offset by tax rate changes in 2016.
The effective tax rate for income from continuing operations was 22% for the six months ended
June 30, 2016
compared to 19% for the same period in
2015
.
Net Income—Noncontrolling Interests
. The
$28 million
increase
was driven primarily by higher noncontrolling ownership interests at Spectra Energy Partners.
For a more detailed discussion of earnings drivers, see the segment discussions that follow.
Segment Results
Management evaluates segment performance based on EBITDA. Cash, cash equivalents and short-term investments are managed at the parent-company levels, so the gains and losses from foreign currency transactions and interest and dividend income are excluded from the segments’ EBITDA. We consider segment EBITDA to be a good indicator of each segment’s operating performance from its operations, as it represents the results of our operations without regard to financing methods or capital structures. Our segment EBITDA may not be comparable to similarly titled measures of other companies because other companies may not calculate EBITDA in the same manner.
Segment EBITDA is summarized in the following table. Detailed discussions follow.
EBITDA by Business Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended June 30,
|
|
Six Months
Ended June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(in millions)
|
Spectra Energy Partners
|
$
|
471
|
|
|
$
|
478
|
|
|
$
|
944
|
|
|
$
|
933
|
|
Distribution
|
104
|
|
|
98
|
|
|
274
|
|
|
290
|
|
Western Canada Transmission & Processing
|
97
|
|
|
104
|
|
|
220
|
|
|
265
|
|
Field Services
|
(14
|
)
|
|
(233
|
)
|
|
(11
|
)
|
|
(250
|
)
|
Total reportable segment EBITDA
|
658
|
|
|
447
|
|
|
1,427
|
|
|
1,238
|
|
Other
|
(36
|
)
|
|
(12
|
)
|
|
(55
|
)
|
|
(27
|
)
|
Total reportable segment and other EBITDA
|
$
|
622
|
|
|
$
|
435
|
|
|
$
|
1,372
|
|
|
$
|
1,211
|
|
Depreciation and amortization
|
196
|
|
|
193
|
|
|
389
|
|
|
386
|
|
Interest expense
|
153
|
|
|
166
|
|
|
304
|
|
|
325
|
|
Interest income and other (a)
|
—
|
|
|
(3
|
)
|
|
2
|
|
|
(1
|
)
|
Earnings before income taxes
|
$
|
273
|
|
|
$
|
73
|
|
|
$
|
681
|
|
|
$
|
499
|
|
___________
|
|
(a)
|
Includes foreign currency transaction gains and losses related to segment EBITDA.
|
The amounts discussed below include intercompany transactions that are eliminated in the Condensed Consolidated Financial Statements.
Spectra Energy Partners
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended June 30,
|
|
Six Months
Ended June 30,
|
|
2016
|
|
2015
|
|
Increase
(Decrease)
|
|
2016
|
|
2015
|
|
Increase
(Decrease)
|
|
(in millions, except where noted)
|
Operating revenues
|
$
|
618
|
|
|
$
|
603
|
|
|
$
|
15
|
|
|
$
|
1,242
|
|
|
$
|
1,209
|
|
|
$
|
33
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
Operating, maintenance and other
|
216
|
|
|
192
|
|
|
24
|
|
|
421
|
|
|
399
|
|
|
22
|
|
Other income and expenses
|
69
|
|
|
67
|
|
|
2
|
|
|
123
|
|
|
123
|
|
|
—
|
|
EBITDA
|
$
|
471
|
|
|
$
|
478
|
|
|
$
|
(7
|
)
|
|
$
|
944
|
|
|
$
|
933
|
|
|
$
|
11
|
|
Express pipeline revenue receipts, MBbl/d (a)
|
233
|
|
|
235
|
|
|
(2
|
)
|
|
233
|
|
|
242
|
|
|
(9
|
)
|
Platte PADD II deliveries, MBbl/d
|
143
|
|
|
172
|
|
|
(29
|
)
|
|
132
|
|
|
170
|
|
|
(38
|
)
|
___________
|
|
(a)
|
Thousand barrels per day.
|
Three Months Ended June 30, 2016 Compared to Same Period in 2015
Operating Revenues.
The
$15 million
increase
was driven by:
|
|
•
|
a $29 million increase due to expansion projects primarily on Texas Eastern and
|
|
|
•
|
a $3 million increase in storage revenues due to new contracts at higher rates, partially offset by
|
|
|
•
|
a $5 million decrease in recoveries of electric power and other costs passed through to gas transmission customers,
|
|
|
•
|
a $4 million decrease in processing revenues primarily due to volumes and lower prices,
|
|
|
•
|
a $4 million decrease in crude oil transportation revenues, as a result of lower Platte pipeline volumes, partially offset by increased tariff rates mainly on the Express pipeline and
|
|
|
•
|
a $4 million decrease in natural gas transportation revenues mainly from short-term firm transportation on Texas Eastern.
|
Operating, Maintenance and Other.
The
$24 million
increase
was driven by:
|
|
•
|
a $16 million increase in expansion project costs,
|
|
|
•
|
a $9 million increase in property taxes due to the benefit recognized in 2015 and
|
|
|
•
|
a $6 million increase due to pipeline inspection and repair costs related to the Texas Eastern incident near Delmont, PA, partially offset by
|
|
|
•
|
a $5 million decrease in electric power and other costs passed through to gas transmission customers and
|
|
|
•
|
a $3 million decrease in power costs due to lower usage in 2016 on the Express and Platte pipelines.
|
Other Income and Expenses.
Relatively flat year over year and included:
|
|
•
|
a $17 million increase primarily due to higher AFUDC from higher capital spending on expansion projects, offset by
|
|
|
•
|
an $18 million decrease primarily due to the absence of equity earnings from Sand Hills and Southern Hills owned until October 2015.
|
Six Months Ended June 30, 2016 Compared to Same Period in 2015
Operating Revenues.
The
$33 million
increase
was driven by:
|
|
•
|
a $57 million increase due to expansion projects, primarily on Texas Eastern, partially offset by
|
|
|
•
|
a $10 million decrease in natural gas transportation revenues mainly from interruptible transportation on Texas Eastern and Maritimes and Northeast, L.L.C. and short-term firm transportation on Algonquin Gas Transmission, LLC,
|
|
|
•
|
a $9 million decrease in recoveries of electric power and other costs passed through to gas transmission customers,
|
|
|
•
|
a $4 million decrease in processing revenues primarily due to lower prices and volumes and
|
|
|
•
|
a $4 million decrease in crude oil transportation revenues, as a result of lower volumes on the Platte and Express pipelines, substantially offset by increased tariff rates mainly on the Express pipeline.
|
Operating, Maintenance and Other.
The
$22 million
increase
was driven by:
|
|
•
|
a $31 million increase in expansion project costs,
|
|
|
•
|
a $6 million increase due to pipeline inspection and repair costs related to the Texas Eastern incident near Delmont, PA and
|
|
|
•
|
a $5 million increase in property taxes due to the benefit recognized in 2015, partially offset by
|
|
|
•
|
a $9 million decrease due to a prior year non-cash impairment charge on Ozark Gas Gathering,
|
|
|
•
|
a $9 million decrease in electric power and other costs passed through to gas transmission customers and
|
|
|
•
|
a $6 million decrease in power costs due to lower usage in 2016 on the Express and Platte pipelines.
|
Other Income and Expenses.
Relatively flat year over year and included:
|
|
•
|
a $24 million increase primarily due to higher AFUDC from higher capital spending on expansion projects, offset by
|
|
|
•
|
a $31 million decrease in equity earnings primarily due to the absence of equity earnings from Sand Hills and Southern Hills owned until October 2015.
|
Distribution
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended June 30,
|
|
Six Months
Ended June 30,
|
|
2016
|
|
2015
|
|
Increase
(Decrease)
|
|
2016
|
|
2015
|
|
Increase
(Decrease)
|
|
(in millions, except where noted)
|
Operating revenues
|
$
|
284
|
|
|
$
|
290
|
|
|
$
|
(6
|
)
|
|
$
|
749
|
|
|
$
|
952
|
|
|
$
|
(203
|
)
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas purchased
|
91
|
|
|
103
|
|
|
(12
|
)
|
|
306
|
|
|
486
|
|
|
(180
|
)
|
Operating, maintenance and other
|
89
|
|
|
90
|
|
|
(1
|
)
|
|
171
|
|
|
176
|
|
|
(5
|
)
|
Other income and expenses
|
—
|
|
|
1
|
|
|
(1
|
)
|
|
2
|
|
|
—
|
|
|
2
|
|
EBITDA
|
$
|
104
|
|
|
$
|
98
|
|
|
$
|
6
|
|
|
$
|
274
|
|
|
$
|
290
|
|
|
$
|
(16
|
)
|
Number of customers, thousands
|
|
|
|
|
|
|
1,446
|
|
|
1,425
|
|
|
21
|
|
Heating degree days, Fahrenheit
|
1,032
|
|
|
866
|
|
|
166
|
|
|
4,347
|
|
|
5,125
|
|
|
(778
|
)
|
Pipeline throughput, TBtu (a)
|
155
|
|
|
132
|
|
|
23
|
|
|
385
|
|
|
460
|
|
|
(75
|
)
|
Canadian dollar exchange rate, average
|
1.29
|
|
|
1.23
|
|
|
0.06
|
|
|
1.33
|
|
|
1.23
|
|
|
0.10
|
|
___________
|
|
(a)
|
Trillion British thermal units.
|
Three Months Ended June 30, 2016 Compared to Same Period in 2015
Operating Revenues.
The
$6 million
decrease
was driven by:
|
|
•
|
a $15 million decrease resulting from a lower Canadian dollar,
|
|
|
•
|
a $12 million decrease from lower natural gas prices passed through to customers. Prices charged to customers are adjusted quarterly based on the 12 month New York Mercantile Exchange (NYMEX) forecast and
|
|
|
•
|
a $7 million decrease in industrial market usage, partially offset by
|
|
|
•
|
a $19 million increase in residential customer usage of natural gas primarily due to colder weather in 2016,
|
|
|
•
|
a $5 million increase from the 2015 Dawn-Parkway expansion project and
|
|
|
•
|
a $4 million increase from growth in the number of customers.
|
Natural Gas Purchased
. The
$12 million
decrease
was driven by:
|
|
•
|
a $12 million decrease from lower natural gas prices passed through to customers,
|
|
|
•
|
a $7 million decrease in industrial market usage and
|
|
|
•
|
a $4 million decrease resulting from a lower Canadian dollar, partially offset by
|
|
|
•
|
a $10 million increase due to higher volumes of natural gas sold to residential customers primarily due to colder weather and
|
|
|
•
|
a $3 million increase from growth in the number of customers.
|
Six Months Ended June 30, 2016 Compared to Same Period in 2015
Operating Revenues.
The
$203 million
decrease
was driven by:
|
|
•
|
a $98 million decrease in residential customer usage of natural gas primarily due to warmer weather in 2016,
|
|
|
•
|
a $78 million decrease from lower natural gas prices passed through to customers. Prices charged to customers are adjusted quarterly based on the 12 month New York Mercantile Exchange (NYMEX) forecast,
|
|
|
•
|
a $67 million decrease resulting from a lower Canadian dollar and
|
|
|
•
|
a $9 million decrease in industrial market usage, partially offset by
|
|
|
•
|
a $22 million increase from growth in the number of customers,
|
|
|
•
|
an $11 million increase from lower utility earnings to be shared with customers in accordance with the incentive regulation framework,
|
|
|
•
|
an $11 million increase from the 2015 Dawn-Parkway expansion project,
|
|
|
•
|
a $5 million increase in rates primarily due to increased DSM program charges and
|
|
|
•
|
a $5 million increase in storage revenue primarily due to higher storage pricing.
|
Natural Gas Purchased
. The
$180 million
decrease
was driven by:
|
|
•
|
an $80 million decrease due to lower volumes of natural gas sold to residential customers primarily due to warmer weather,
|
|
|
•
|
a $79 million decrease from lower natural gas prices passed through to customers,
|
|
|
•
|
a $29 million decrease resulting from a lower Canadian dollar and
|
|
|
•
|
a $9 million decrease in industrial market usage, partially offset by
|
|
|
•
|
an $18 million increase from growth in the number of customers.
|
Operating, Maintenance and Other
. The $
5 million
decrease
was driven by:
|
|
•
|
a $13 million decrease resulting from a lower Canadian dollar, partially offset by
|
|
|
•
|
a $6 million increase in operating and maintenance expenses primarily due to higher employee related costs and increased DSM program charges.
|
Western Canada Transmission & Processing
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended June 30,
|
|
Six Months
Ended June 30,
|
|
2016
|
|
2015
|
|
Increase
(Decrease)
|
|
2016
|
|
2015
|
|
Increase
(Decrease)
|
|
(in millions, except where noted)
|
Operating revenues
|
$
|
258
|
|
|
$
|
304
|
|
|
$
|
(46
|
)
|
|
$
|
563
|
|
|
$
|
674
|
|
|
$
|
(111
|
)
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas and petroleum products purchased
|
15
|
|
|
25
|
|
|
(10
|
)
|
|
63
|
|
|
92
|
|
|
(29
|
)
|
Operating, maintenance and other
|
148
|
|
|
174
|
|
|
(26
|
)
|
|
285
|
|
|
321
|
|
|
(36
|
)
|
Other income and expenses
|
2
|
|
|
(1
|
)
|
|
3
|
|
|
5
|
|
|
4
|
|
|
1
|
|
EBITDA
|
$
|
97
|
|
|
$
|
104
|
|
|
$
|
(7
|
)
|
|
$
|
220
|
|
|
$
|
265
|
|
|
$
|
(45
|
)
|
Pipeline throughput, TBtu
|
214
|
|
|
220
|
|
|
(6
|
)
|
|
466
|
|
|
476
|
|
|
(10
|
)
|
Volumes processed, TBtu
|
163
|
|
|
156
|
|
|
7
|
|
|
339
|
|
|
336
|
|
|
3
|
|
Canadian dollar exchange rate, average
|
1.29
|
|
|
1.23
|
|
|
0.06
|
|
|
1.33
|
|
|
1.23
|
|
|
0.10
|
|
Three Months Ended June 30, 2016 Compared to Same Period in 2015
Operating Revenues.
The
$46 million
decrease
was driven by:
|
|
•
|
a $14 million decrease in firm gathering and processing revenues,
|
|
|
•
|
a $12 million decrease resulting from a lower Canadian dollar,
|
|
|
•
|
a $12 million decrease arising from changes in non-cash mark-to-market commodity-related pricing adjustments associated with the risk management program at the Empress operations and
|
|
|
•
|
a $5 million decrease resulting from lower settlement gains associated with the risk management program at the Empress operations.
|
Natural Gas and Petroleum Products Purchased.
The
$10 million
decrease
was driven by:
|
|
•
|
a $5 million non-cash charge to reduce the value of propane inventory at the Empress operations to net realizable value at June 30, 2015 and
|
|
|
•
|
a $4 million decrease primarily as a result of lower costs of NGL sales at the Empress operations.
|
Operating, Maintenance and Other.
The
$26 million
decrease
was driven by:
|
|
•
|
a $17 million decrease in plant turnaround costs and
|
|
|
•
|
a $7 million decrease resulting from a lower Canadian dollar.
|
Six Months Ended June 30, 2016 Compared to Same Period in 2015
Operating Revenues.
The
$111 million
decrease
was driven by:
|
|
•
|
a $46 million decrease resulting from a lower Canadian dollar,
|
|
|
•
|
a $25 million decrease arising from changes in non-cash mark-to-market commodity-related pricing adjustments associated with the risk management program at the Empress operations,
|
|
|
•
|
a $21 million decrease due to lower NGL prices associated with the Empress operations and
|
|
|
•
|
a $17 million decrease in firm gathering and processing revenues.
|
Natural Gas and Petroleum Products Purchased.
The
$29 million
decrease
was driven by:
|
|
•
|
a $23 million decrease primarily as a result of lower costs of NGL sales at the Empress facility and
|
|
|
•
|
a $6 million decrease resulting from a lower Canadian dollar.
|
Operating, Maintenance and Other.
The
$36 million
decrease
was driven by:
|
|
•
|
a $21 million decrease in plant turnaround costs and
|
|
|
•
|
a $21 million decrease resulting from a lower Canadian dollar.
|
Field Services
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended June 30,
|
|
Six Months
Ended June 30,
|
|
2016
|
|
2015
|
|
Increase
(Decrease)
|
|
2016
|
|
2015
|
|
Increase
(Decrease)
|
|
(in millions, except where noted)
|
Earnings (loss) from equity investments
|
$
|
(14
|
)
|
|
$
|
(233
|
)
|
|
$
|
219
|
|
|
$
|
(11
|
)
|
|
$
|
(250
|
)
|
|
$
|
239
|
|
EBITDA
|
$
|
(14
|
)
|
|
$
|
(233
|
)
|
|
$
|
219
|
|
|
$
|
(11
|
)
|
|
$
|
(250
|
)
|
|
$
|
239
|
|
Natural gas gathered and processed/transported, TBtu/d (a,b)
|
6.7
|
|
|
7.0
|
|
|
(0.3
|
)
|
|
6.8
|
|
|
7.1
|
|
|
(0.3
|
)
|
NGL production, MBbl/d (a)
|
416
|
|
|
408
|
|
|
8
|
|
|
399
|
|
|
404
|
|
|
(5
|
)
|
Average natural gas price per MMBtu (c,d)
|
$
|
1.95
|
|
|
$
|
2.64
|
|
|
$
|
(0.69
|
)
|
|
$
|
2.02
|
|
|
$
|
2.81
|
|
|
$
|
(0.79
|
)
|
Average NGL price per gallon (e)
|
$
|
0.46
|
|
|
$
|
0.48
|
|
|
$
|
(0.02
|
)
|
|
$
|
0.41
|
|
|
$
|
0.48
|
|
|
$
|
(0.07
|
)
|
Average crude oil price per barrel (f)
|
$
|
45.64
|
|
|
$
|
57.94
|
|
|
$
|
(12.30
|
)
|
|
$
|
39.54
|
|
|
$
|
53.29
|
|
|
$
|
(13.75
|
)
|
___________
|
|
(a)
|
Reflects 100% of volumes.
|
|
|
(b)
|
Trillion British thermal units per day.
|
|
|
(c)
|
Average price based on NYMEX Henry Hub.
|
|
|
(d)
|
Million British thermal units.
|
|
|
(e)
|
Does not reflect results of commodity hedges.
|
|
|
(f)
|
Average price based on NYMEX calendar month.
|
Three Months Ended June 30, 2016 Compared to Same Period in 2015
EBITDA
increased
$219 million
mainly as a result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:
|
|
•
|
a $213 million increase primarily as a result of the 2015 partial impairment of goodwill at DCP Midstream,
|
|
|
•
|
a $24 million increase in gathering and processing margins primarily as a result of asset growth and favorable contract realignment and
|
|
|
•
|
an $11 million increase due to favorable results from NGL pipelines, partially offset by
|
|
|
•
|
a $19 million decrease resulting from increased net income attributable to noncontrolling interests primarily as a result of asset growth and prior year asset impairments and
|
|
|
•
|
a $15 million decrease from commodity-sensitive processing arrangements primarily due to decreased natural gas and crude oil prices.
|
Six Months Ended June 30, 2016 Compared to Same Period in 2015
EBITDA
increased
$239 million
mainly as a result of the following variances, each representing our 50% ownership portion of the earnings drivers at DCP Midstream:
|
|
•
|
a $213 million increase primarily as a result of the 2015 partial impairment of goodwill at DCP Midstream,
|
|
|
•
|
a $49 million increase in gathering and processing margins primarily as a result of asset growth and favorable contract realignment,
|
|
|
•
|
a $45 million increase primarily as a result of a producer settlement and
|
|
|
•
|
a $23 million increase due to favorable results from NGL pipelines, partially offset by unfavorable results from wholesale propane, partially offset by
|
|
|
•
|
a $49 million decrease from commodity-sensitive processing arrangements primarily due to decreased natural gas and crude oil prices and
|
|
|
•
|
a $22 million decrease resulting from increased net income attributable to noncontrolling interests primarily as a result of asset growth and prior year asset impairments.
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended June 30,
|
|
Six Months
Ended June 30,
|
|
2016
|
|
2015
|
|
Increase
(Decrease)
|
|
2016
|
|
2015
|
|
Increase
(Decrease)
|
|
(in millions)
|
Operating revenues
|
$
|
19
|
|
|
$
|
17
|
|
|
$
|
2
|
|
|
$
|
36
|
|
|
$
|
35
|
|
|
$
|
1
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
Operating, maintenance and other
|
53
|
|
|
30
|
|
|
23
|
|
|
90
|
|
|
62
|
|
|
28
|
|
Other income and expenses
|
(2
|
)
|
|
1
|
|
|
(3
|
)
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
EBITDA
|
$
|
(36
|
)
|
|
$
|
(12
|
)
|
|
$
|
(24
|
)
|
|
$
|
(55
|
)
|
|
$
|
(27
|
)
|
|
$
|
(28
|
)
|
Three Months Ended June 30, 2016 Compared to Same Period in 2015
EBITDA.
The
$24 million
decrease
was driven by:
|
|
•
|
a $10 million decrease due to captive insurance general liability reserve related to the Texas Eastern incident near Delmont, PA and
|
|
|
•
|
a $10 million decrease due to higher employee benefit costs.
|
Six Months Ended June 30, 2016 Compared to Same Period in 2015
EBITDA.
The
$28 million
decrease
was driven by:
|
|
•
|
a $14 million decrease due to higher employee benefit costs and
|
|
|
•
|
a $10 million decrease due to captive insurance general liability reserve related to the Texas Eastern incident near Delmont, PA.
|
Impairment of Goodwill
As permitted under accounting guidance on testing goodwill for impairment, we perform either a qualitative assessment or a quantitative assessment of each of our reporting units based on management’s judgment. With respect to our qualitative assessments, we consider events and circumstances specific to us, such as macroeconomic conditions, industry and market considerations, cost factors and overall financial performance, when evaluating whether it is more likely than not that the fair values of our reporting units are less than their respective carrying amounts.
In connection with our quantitative assessments, we primarily use a discounted cash flow analysis to determine fair values of those reporting units. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in key markets served by our operations, regulatory stability, the ability to renew contracts, commodity prices (where appropriate) and foreign currency exchange rates, as well as other factors that affect our reporting units’ revenue, expense and capital expenditure projections.
We performed either a quantitative assessment or a qualitative assessment for all of our reporting units to determine whether it is more likely than not that the respective fair values of these reporting units are less than their carrying amounts, including goodwill as of April 1, 2016 (our annual testing date). Based on the results of our annual goodwill impairment testing, no indicators of impairment were noted and the fair values of the reporting units that we assessed at April 1, 2016 were substantially in excess of their respective carrying values.
No triggering events have occurred with our reporting units since the April 1, 2016 test that would warrant re-testing for goodwill impairment.
LIQUIDITY AND CAPITAL RESOURCES
As of
June 30, 2016
, we had negative working capital of
$1,149 million
. This balance includes commercial paper liabilities totaling
$1,113 million
and accrued interest of
$181 million
. We will rely upon cash flows from operations and various financing transactions, which may include debt and/or equity issuances, to fund our liquidity and capital requirements for the next 12 months. SEP is expected to be self-funding through its cash flows from operations, use of its revolving credit facility and its access to capital markets. We receive cash distributions from SEP in accordance with the partnership agreement, which considers our level of ownership and incentive distribution rights.
As of
June 30, 2016
, our four revolving credit facilities included Spectra Capital’s $1.0 billion facility, SEP’s $2.5 billion facility, Westcoast’s 400 million Canadian dollar facility and Union Gas’ 700 million Canadian dollar facility, with available capacity of
$1.8 billion
under SEP’s credit facility and
$1.4 billion
under our other subsidiaries’ credit facilities. These facilities are used principally as back-stops for commercial paper programs. At Spectra Capital, SEP and Westcoast, we primarily use commercial paper for temporary funding of capital expenditures. At Union Gas, we primarily use commercial paper for temporary funding of capital expenditures and 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 14 of Notes to Condensed Consolidated Financial Statements for a discussion of available credit facilities and Financing Cash Flows and Liquidity for a discussion of effective shelf registrations.
Cash Flow Analysis
The following table summarizes the changes in cash flows for each of the periods presented:
|
|
|
|
|
|
|
|
|
|
Six Months
Ended June 30,
|
|
2016
|
|
2015
|
Net cash provided by (used in):
|
(in millions)
|
Operating activities
|
$
|
1,239
|
|
|
$
|
1,456
|
|
Investing activities
|
(1,744
|
)
|
|
(976
|
)
|
Financing activities
|
528
|
|
|
(406
|
)
|
Effect of exchange rate changes on cash
|
4
|
|
|
(2
|
)
|
Net increase in cash and cash equivalents
|
27
|
|
|
72
|
|
Cash and cash equivalents at beginning of period
|
213
|
|
|
215
|
|
Cash and cash equivalents at end of period
|
$
|
240
|
|
|
$
|
287
|
|
Operating Cash Flows
Net cash provided by operating activities decreased $
217 million
to
$1,239 million
in the
six months
ended
June 30, 2016
compared to the same period in
2015
, driven mostly by changes in working capital.
Investing Cash Flows
Net cash used in investing activities increased
$768 million
to
$1,744 million
in the
six months
ended
June 30, 2016
compared to the same period in
2015
. This change was driven mainly by an increase in capital and investment expenditures.
|
|
|
|
|
|
|
|
|
|
Six Months
Ended June 30,
|
|
2016
|
|
2015
|
Capital and Investment Expenditures
|
(in millions)
|
Spectra Energy Partners
|
$
|
1,135
|
|
|
$
|
638
|
|
Distribution
|
341
|
|
|
207
|
|
Western Canada Transmission & Processing
|
133
|
|
|
149
|
|
Total reportable segments
|
1,609
|
|
|
994
|
|
Other
|
23
|
|
|
29
|
|
Total consolidated
|
$
|
1,632
|
|
|
$
|
1,023
|
|
Capital and investment expenditures for the
six months
ended
June 30, 2016
consisted of $1,388 million for expansion projects and $244 million for maintenance.
We project
2016
capital and investment expenditures of approximately $4.2 billion, consisting of approximately $2.7 billion for SEP, $0.9 billion for Distribution and $0.6 billion for Western Canada Transmission & Processing. Total projected
2016
capital and investment expenditures include approximately $3.6 billion of expansion capital expenditures and $0.6 billion for maintenance and upgrades of existing plants, pipelines and infrastructure to serve growth. These projections exclude contributions from noncontrolling interests.
Financing Cash Flows and Liquidity
Net cash provided by financing activities increased
$934 million
to
$528 million
for the
six months
ended
June 30, 2016
compared to the same period in
2015
. This change was mainly driven by $868 million from Spectra Energy's common stock issuance proceeds in 2016.
Spectra Energy Common Stock Issuances.
On March 1, 2016, we entered into an equity distribution agreement under which we may sell and issue common stock up to an aggregate offering price of $500 million. The equity distribution agreement allows us to offer and sell common stock at prices deemed appropriate through sales agents. Sales of common stock under the equity distribution agreement will be made by means of ordinary brokers’ transactions through the facilities of the NYSE, in block transactions, or as otherwise agreed upon by one or more of the sales agents and us. We intend to use the net proceeds from sales under this at-the-market program for general corporate purposes, including investments in subsidiaries to
fund capital expenditures. We issued approximately
12.9 million
of common shares to the public under this program, for total net proceeds of
$383 million
through June 30, 2016.
In April 2016, we issued 16.1 million common shares to the public for net proceeds of approximately $479 million. Net proceeds from the offering were used to purchase approximately 10.4 million common units in SEP. SEP intends to use the proceeds from our unit purchase for general corporate purposes, including the funding of its current expansion capital plan.
SEP Common Unit Issuances.
During the
six months
ended
June 30, 2016
, SEP issued
7.0 million
common units to the public under its at-the-market program and approximately
143,000
general partner units to Spectra Energy. Total net proceeds to SEP were
$327 million
(net proceeds to Spectra Energy were
$321 million
). In April 2016, SEP issued
10.4 million
common units and
0.2 million
general partner units to Spectra Energy in a private placement transaction. In connection with the issuances of the units, a
$23 million
gain (
$15 million
net of tax) to Additional Paid-in Capital and a
$297 million
increase in Equity—Noncontrolling Interests were recorded during the
six months
ended
June 30, 2016
. The issuances decreased Spectra Energy’s ownership in SEP from
78%
to
77%
at
June 30, 2016
. In 2016, SEP has issued 7.8 million common units to the public and approximately 160,000 general partner units to Spectra Energy, for total net proceeds to SEP of $365 million (net proceeds to Spectra Energy were $358 million) through its at-the-market program.
Available Credit Facilities and Restrictive Debt Covenants.
See Note 14 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. This ratio was
56%
at
June 30, 2016
. Our equity and, as a result, this ratio, is sensitive to significant movements of the Canadian dollar relative to the U.S. dollar due to the significance of our Canadian operations. Based on the strength of our total capitalization as of
June 30, 2016
, however, it is not likely that a material adverse effect would occur as a result of a weakened Canadian dollar.
Dividends.
Our near-term objective is to increase our cash dividend by $0.14 per share, per year, through 2018. 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 $0.405 per common share on July 5, 2016 payable on September 7, 2016 to shareholders of record at the close of business on August 12, 2016.
Debt Issuances.
On May 31, 2016, Union Gas issued 250 million Canadian dollars (approximately $191 million as of the issuance date) of 2.81% unsecured notes due 2026 and 250 million Canadian dollars (approximately $191 million as of the issuance date) of 3.80% unsecured notes due 2046. Net proceeds from the offerings were used for repayment of short term debt and debt maturities, capital expenditures and general corporate purposes.
Other Financing Matters
. Spectra Energy Corp, Spectra Capital and SEP have effective shelf registration statements on file with the SEC to register the issuance of unlimited amounts of various equity and debt securities. SEP also has $620 million available as of
June 30, 2016
for the issuance of limited partner common units under another effective shelf registration statement on file with the SEC related to its at-the-market program. Westcoast and Union Gas have an aggregate 1.2 billion Canadian dollars (approximately $929 million) available as of
June 30, 2016
for the issuance of debt securities in the Canadian market under their medium term note shelf prospectuses.
On March 18, 2016, Westcoast filed a new 1 billion Canadian dollar short form base shelf prospectus, which provides for the issuance of first preferred shares. As of the date of this filing, Westcoast has 1 billion Canadian dollars (approximately $774 million) available for the issuance of preferred shares under this prospectus, which expires on April 18, 2018.
OTHER ISSUES
New Accounting Pronouncements
. See Note 23 of Notes to Condensed Consolidated Financial Statements for discussion.