Williams Partners L.P.
Consolidated Balance Sheet
(Unaudited)
|
|
|
|
|
|
|
|
|
|
June 30,
2016
|
|
December 31,
2015
|
|
(Dollars in millions)
|
ASSETS
|
|
|
|
Current assets:
|
|
|
|
Cash and cash equivalents
|
$
|
101
|
|
|
$
|
96
|
|
Trade accounts and notes receivable (net of allowance of $5 at June 30, 2016 and $3 at December 31, 2015)
|
722
|
|
|
1,026
|
|
Inventories
|
122
|
|
|
127
|
|
Assets held for sale (Note 9)
|
932
|
|
|
13
|
|
Other current assets
|
177
|
|
|
177
|
|
Total current assets
|
2,054
|
|
|
1,439
|
|
Investments
|
7,125
|
|
|
7,336
|
|
Property, plant, and equipment, at cost
|
37,673
|
|
|
37,833
|
|
Accumulated depreciation
|
(9,855
|
)
|
|
(9,233
|
)
|
Property, plant, and equipment – net
|
27,818
|
|
|
28,600
|
|
Goodwill
|
47
|
|
|
47
|
|
Other intangible assets – net of accumulated amortization
|
9,791
|
|
|
9,969
|
|
Regulatory assets, deferred charges, and other
|
459
|
|
|
479
|
|
Total assets
|
$
|
47,294
|
|
|
$
|
47,870
|
|
LIABILITIES AND EQUITY
|
|
|
|
Current liabilities:
|
|
|
|
Accounts payable:
|
|
|
|
Trade
|
$
|
679
|
|
|
$
|
648
|
|
Affiliate
|
102
|
|
|
141
|
|
Accrued interest
|
262
|
|
|
231
|
|
Asset retirement obligations
|
68
|
|
|
57
|
|
Liabilities held for sale (Note 9)
|
151
|
|
|
—
|
|
Other accrued liabilities
|
339
|
|
|
469
|
|
Long-term debt due within one year
|
786
|
|
|
176
|
|
Commercial paper
|
196
|
|
|
499
|
|
Total current liabilities
|
2,583
|
|
|
2,221
|
|
Long-term debt
|
19,116
|
|
|
19,001
|
|
Asset retirement obligations
|
849
|
|
|
857
|
|
Deferred income tax liabilities
|
21
|
|
|
119
|
|
Regulatory liabilities, deferred income, and other
|
1,275
|
|
|
1,066
|
|
Contingent liabilities (Note 10)
|
|
|
|
|
Equity:
|
|
|
|
Partners’ equity:
|
|
|
|
Common units (588,625,106 and 588,546,022 units outstanding at June 30, 2016 and December 31, 2015, respectively)
|
18,503
|
|
|
19,730
|
|
Class B units (15,919,628 and 14,784,015 units outstanding at June 30, 2016 and December 31, 2015, respectively)
|
764
|
|
|
771
|
|
General partner
|
2,533
|
|
|
2,552
|
|
Accumulated other comprehensive income (loss)
|
(95
|
)
|
|
(172
|
)
|
Total partners’ equity
|
21,705
|
|
|
22,881
|
|
Noncontrolling interests in consolidated subsidiaries
|
1,745
|
|
|
1,725
|
|
Total equity
|
23,450
|
|
|
24,606
|
|
Total liabilities and equity
|
$
|
47,294
|
|
|
$
|
47,870
|
|
See accompanying notes.
Williams Partners L.P.
Consolidated Statement of Changes in Equity
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners L.P.
|
|
|
|
|
|
Limited Partners
|
|
|
|
|
|
|
|
|
|
|
|
Common
Units
|
|
Class B Units
|
|
General
Partner
|
|
Accumulated
Other
Comprehensive
Income (Loss)
|
|
Total Partners’ Equity
|
|
Noncontrolling
Interests
|
|
Total
Equity
|
|
(Millions)
|
Balance – December 31, 2015
|
$
|
19,730
|
|
|
$
|
771
|
|
|
$
|
2,552
|
|
|
$
|
(172
|
)
|
|
$
|
22,881
|
|
|
$
|
1,725
|
|
|
$
|
24,606
|
|
Net income (loss)
|
(238
|
)
|
|
(7
|
)
|
|
205
|
|
|
—
|
|
|
(40
|
)
|
|
42
|
|
|
2
|
|
Other comprehensive income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
77
|
|
|
77
|
|
|
—
|
|
|
77
|
|
Cash distributions
|
(1,001
|
)
|
|
—
|
|
|
(230
|
)
|
|
—
|
|
|
(1,231
|
)
|
|
—
|
|
|
(1,231
|
)
|
Contributions from general partner
|
—
|
|
|
—
|
|
|
6
|
|
|
—
|
|
|
6
|
|
|
—
|
|
|
6
|
|
Contributions from noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
22
|
|
|
22
|
|
Distributions to noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(45
|
)
|
|
(45
|
)
|
Other
|
12
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12
|
|
|
1
|
|
|
13
|
|
Net increase (decrease) in equity
|
(1,227
|
)
|
|
(7
|
)
|
|
(19
|
)
|
|
77
|
|
|
(1,176
|
)
|
|
20
|
|
|
(1,156
|
)
|
Balance – June 30, 2016
|
$
|
18,503
|
|
|
$
|
764
|
|
|
$
|
2,533
|
|
|
$
|
(95
|
)
|
|
$
|
21,705
|
|
|
$
|
1,745
|
|
|
$
|
23,450
|
|
See accompanying notes.
Williams Partners L.P.
Consolidated Statement of Cash Flows
(Unaudited)
|
|
|
|
|
|
|
|
|
|
Six Months Ended
June 30,
|
|
2016
|
|
2015
|
|
(Millions)
|
OPERATING ACTIVITIES:
|
|
|
|
Net income (loss)
|
$
|
2
|
|
|
$
|
444
|
|
Adjustments to reconcile to net cash provided (used) by operating activities:
|
|
|
|
Depreciation and amortization
|
867
|
|
|
838
|
|
Provision (benefit) for deferred income taxes
|
(80
|
)
|
|
2
|
|
Impairment of equity-method investments
|
112
|
|
|
—
|
|
Impairment of and net (gain) loss on sale of Property, plant, and equipment
|
405
|
|
|
28
|
|
Amortization of stock-based awards
|
14
|
|
|
16
|
|
Cash provided (used) by changes in current assets and liabilities:
|
|
|
|
Accounts and notes receivable
|
297
|
|
|
185
|
|
Inventories
|
—
|
|
|
64
|
|
Other current assets and deferred charges
|
(20
|
)
|
|
(45
|
)
|
Accounts payable
|
24
|
|
|
(38
|
)
|
Accrued liabilities
|
58
|
|
|
(14
|
)
|
Affiliate accounts receivable and payable – net
|
(44
|
)
|
|
42
|
|
Other, including changes in noncurrent assets and liabilities
|
30
|
|
|
(29
|
)
|
Net cash provided (used) by operating activities
|
1,665
|
|
|
1,493
|
|
FINANCING ACTIVITIES:
|
|
|
|
Proceeds from (payments of) commercial paper – net
|
(304
|
)
|
|
942
|
|
Proceeds from long-term debt
|
2,938
|
|
|
4,825
|
|
Payments of long-term debt
|
(2,201
|
)
|
|
(4,007
|
)
|
Contributions from general partner
|
6
|
|
|
4
|
|
Distributions to limited partners and general partner
|
(1,231
|
)
|
|
(1,450
|
)
|
Distributions to noncontrolling interests
|
(45
|
)
|
|
(32
|
)
|
Contributions from noncontrolling interests
|
22
|
|
|
57
|
|
Contributions from The Williams Companies, Inc. – net
|
—
|
|
|
20
|
|
Payments for debt issuance costs
|
(8
|
)
|
|
(29
|
)
|
Contribution to Gulfstream for repayment of debt
|
(148
|
)
|
|
—
|
|
Other – net
|
—
|
|
|
14
|
|
Net cash provided (used) by financing activities
|
(971
|
)
|
|
344
|
|
INVESTING ACTIVITIES:
|
|
|
|
Property, plant, and equipment:
|
|
|
|
Capital expenditures (1)
|
(981
|
)
|
|
(1,450
|
)
|
Net proceeds from dispositions
|
7
|
|
|
6
|
|
Purchases of businesses, net of cash acquired
|
—
|
|
|
(112
|
)
|
Purchases of and contributions to equity-method investments
|
(122
|
)
|
|
(483
|
)
|
Distributions from unconsolidated affiliates in excess of cumulative earnings
|
261
|
|
|
122
|
|
Other – net
|
153
|
|
|
95
|
|
Net cash provided (used) by investing activities
|
(682
|
)
|
|
(1,822
|
)
|
Increase (decrease) in cash and cash equivalents
|
12
|
|
|
15
|
|
Cash and cash equivalents held for sale
|
(7
|
)
|
|
—
|
|
Cash and cash equivalents at beginning of year
|
96
|
|
|
171
|
|
Cash and cash equivalents at end of period
|
$
|
101
|
|
|
$
|
186
|
|
_________
|
|
|
|
(1) Increases to property, plant, and equipment
|
$
|
(983
|
)
|
|
$
|
(1,376
|
)
|
Changes in related accounts payable and accrued liabilities
|
2
|
|
|
(74
|
)
|
Capital expenditures
|
$
|
(981
|
)
|
|
$
|
(1,450
|
)
|
See accompanying notes.
Williams Partners L.P.
Notes to Consolidated Financial Statements
(Unaudited)
Note 1 – General, Description of Business, and Basis of Presentation
General
Our accompanying interim consolidated financial statements do not include all the notes in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto for the year ended December 31, 2015, in Exhibit 99.1 of our Form 8-K dated May 27, 2016. The accompanying unaudited financial statements include all normal recurring adjustments and others that, in the opinion of management, are necessary to present fairly our interim financial statements.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us,” or like terms refer to Williams Partners L.P. and its subsidiaries. Unless the context clearly indicates otherwise, references to “we,” “our,” and “us” include the operations in which we own interests accounted for as equity-method investments that are not consolidated in our financial statements. When we refer to our equity investees by name, we are referring exclusively to their businesses and operations.
We are a Delaware limited partnership whose common units are listed and traded on the New York Stock Exchange. WPZ GP LLC, a Delaware limited liability company wholly owned by The Williams Companies, Inc. (Williams), serves as our general partner. As of
June 30, 2016
, Williams owns an approximate
58 percent
limited partner interest, a
2 percent
general partner interest, and incentive distribution rights (IDRs) in us.
WPZ Public Unit Exchange
On May 12, 2015, we entered into an agreement for a unit-for-stock transaction whereby Williams would have acquired all of our publicly held outstanding common units in exchange for shares of Williams’ common stock (WPZ Public Unit Exchange).
On September 28, 2015, we entered into a Termination Agreement and Release (Termination Agreement), terminating the WPZ Public Unit Exchange. Under the terms of the Termination Agreement, Williams was required to pay us a
$428 million
termination fee, which settled through a reduction of quarterly incentive distributions payable to Williams (such reduction not to exceed
$209 million
per quarter). Our November 2015, February 2016, and May 2016 distributions to Williams were reduced by
$209 million
,
$209 million
, and
$10 million
, respectively, related to this termination fee.
Williams’ Merger Agreement with Energy Transfer
On September 28, 2015, Williams publicly announced in a press release that it had entered into an Agreement and Plan of Merger (Merger Agreement) with Energy Transfer Equity, L.P. (Energy Transfer) and certain of its affiliates. The Merger Agreement provided that, subject to the satisfaction of customary closing conditions, Williams would be merged with and into the newly formed Energy Transfer Corp LP (ETC) (ETC Merger), with ETC surviving the ETC Merger. Energy Transfer formed ETC as a limited partnership that would be treated as a corporation for U.S. federal income tax purposes. Immediately following the completion of the ETC Merger, ETC would contribute to Energy Transfer all of the assets and liabilities of Williams in exchange for the issuance by Energy Transfer to ETC of a number of Energy Transfer Class E common units equal to the number of ETC common shares issued to Williams stockholders in the ETC Merger.
On June 29, 2016, Energy Transfer provided Williams written notice terminating the Merger Agreement, citing the alleged failure of certain conditions under the Merger Agreement.
ACMP Merger
On February 2, 2015, Williams Partners L.P. merged with and into Access Midstream Partners, L.P. (ACMP Merger). For the purpose of these financial statements and notes, Williams Partners L.P. (WPZ) refers to the renamed merged partnership, while Pre-merger Access Midstream Partners, L.P. (ACMP) and Pre-merger Williams Partners L.P. (Pre-merger WPZ) refer to the separate partnerships prior to the consummation of the ACMP Merger and subsequent name change. The net assets of Pre-merger WPZ and ACMP were combined at Williams’ historical basis. Williams’ basis in ACMP reflected its business combination accounting resulting from acquiring control of ACMP on July 1, 2014.
Description of Business
Our operations are located in North America. Effective January 1, 2016, businesses located in the Marcellus and Utica shale plays within the former Access Midstream segment are now managed, and thus presented, within the Northeast G&P segment. The remaining Access Midstream businesses are now presented as the Central segment. As a result, beginning with the reporting of first quarter 2016, our operations are organized into the following reportable segments: Central, Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services. Prior period segment disclosures have been recast for these segment changes.
Central provides domestic gathering, treating, and compression services to producers under long-term, fixed-fee contracts. Its primary operating areas are in the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware, and Permian basins. Central also includes a
50 percent
equity-method investment in the Delaware basin gas gathering system in the Mid-Continent region.
Northeast G&P is comprised of our midstream gathering and processing businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and West Virginia and the Utica Shale region of eastern Ohio, as well as a
62 percent
equity-method investment in Utica East Ohio Midstream, LLC (UEOM), a
69 percent
equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain), a
58 percent
equity-method investment in Caiman Energy II, LLC, and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average
45 percent
interest in multiple gathering systems in the Marcellus Shale (Appalachia Midstream Investments).
Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transcontinental Gas Pipe Line Company, LLC (Transco), and significant natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a
51 percent
interest in Gulfstar One LLC (Gulfstar One) (a consolidated entity), which is a proprietary floating production system, as well as a
50 percent
equity-method investment in Gulfstream Natural Gas System, L.L.C. (Gulfstream), a
41 percent
interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity), which is under development, and a
60 percent
equity-method investment in Discovery Producer Services LLC (Discovery).
West is comprised of our gathering, processing, and treating operations in New Mexico, Colorado, and Wyoming, and our interstate natural gas pipeline, Northwest Pipeline LLC (Northwest Pipeline).
NGL & Petchem Services is comprised of our
88.5 percent
undivided interest in an olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and pipelines in the Gulf Coast region, an oil sands offgas processing plant located near Fort McMurray, Alberta, and a natural gas liquid (NGL)/olefin fractionation facility at Redwater, Alberta. As of
June 30, 2016
, our Canadian operations are classified as held for sale. (See
Note 9 – Fair Value Measurements and Guarantees
.) This segment also includes our NGL and natural gas marketing business, storage facilities, and an undivided
50 percent
interest in an NGL fractionator near Conway, Kansas, and a
50 percent
equity-method investment in Overland Pass Pipeline, LLC (OPPL).
Basis of Presentation
Significant risks and uncertainties
During the second quarter of 2016, we evaluated an asset group within our Central segment for impairment as a result of an increased likelihood of gas gathering contract restructuring with certain producers and lower volume projections. Our assessment included probability-weighted scenarios of undiscounted future cash flows that considered variables including terms of our current contract, as well as potential revised terms of a restructured contract, counterparty performance, and pricing assumptions. This assessment resulted in the undiscounted cash flows slightly exceeding the approximate
$1.6 billion
carrying value of the asset group and no impairment was recorded. The use of different judgments and assumptions associated with the measurement variables noted, particularly the assumed contractual terms, expected volumes, and rates, could result in reduced levels of future cash flows which could result in a significant impairment.
Accumulated other comprehensive income (loss)
Accumulated other comprehensive income (loss)
(AOCI) is substantially comprised of foreign currency translation adjustments. These adjustments did not impact
Net income (loss)
in any of the periods presented.
Accounting standards issued but not yet adopted
In June 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities will be required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. The guidance also requires increased disclosures. The new standard is effective for interim and annual periods beginning after December 15, 2019. Early adoption is permitted. The new standard requires varying transition methods for the different categories of amendments. We are evaluating the impact of the new standard on our consolidated financial statements.
In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. The new standard clarifies the definition of a lease, requires a dual approach to lease classification similar to current lease classifications, and causes lessees to recognize leases on the balance sheet as a lease liability with a corresponding right-of-use asset. The new standard is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. The new standard requires a modified retrospective transition for capital or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements. We are evaluating the impact of the new standard on our consolidated financial statements.
In May 2014, the FASB issued ASU 2014-09 establishing Accounting Standards Codification (ASC) Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard is effective for interim and annual reporting periods beginning after December 15, 2017. ASC 606 allows either full retrospective or modified retrospective transition and early adoption is permitted for annual periods beginning after December 15, 2016. We continue to evaluate both the impact of this new standard on our consolidated financial statements and the transition method we will utilize for adoption.
Note 2 – Variable Interest Entities
As of
June 30, 2016
, we consolidate the following variable interest entities (VIEs):
Gulfstar One
We own a
51 percent
interest in Gulfstar One, a subsidiary that, due to certain risk-sharing provisions in its customer contracts, is a VIE. Gulfstar One includes a proprietary floating-production system, Gulfstar FPS, and associated pipelines which provide production handling and gathering services for the Tubular Bells oil and gas discovery in the eastern deepwater Gulf of Mexico. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Gulfstar One’s economic performance. Construction of an expansion project is underway that will provide production handling and gathering services for the Gunflint oil and gas discovery in the eastern deepwater Gulf of Mexico. The expansion project is expected to be completed in two phases. The first phase went into service in July of 2016 and the second phase is expected to go into service in the fourth quarter of 2016. The current estimate of the total remaining construction cost for the expansion project is approximately
$67 million
, which we expect will be funded with revenues received from customers and capital contributions from us and the other equity partner on a proportional basis.
Constitution
We own a
41 percent
interest in Constitution, a subsidiary that, due to shipper fixed-payment commitments under its long-term firm transportation contracts, is a VIE. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Constitution’s economic performance. We, as construction manager for Constitution, are responsible for constructing the proposed pipeline connecting our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems. The total remaining cost of the project is estimated to be approximately
$687 million
, which we expect will be funded with capital contributions from us and the other equity partners on a proportional basis.
In December 2014, we received approval from the Federal Energy Regulatory Commission to construct and operate the Constitution pipeline. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied a necessary water quality certification for the New York portion of the Constitution pipeline. We remain steadfastly committed to the project, and in May 2016, Constitution appealed the NYSDEC's denial of the certification and filed an action in federal court seeking a declaration that the State of New York's authority to exercise permitting jurisdiction over certain other environmental matters is preempted by federal law. In light of the NYSDEC's denial of the water quality certification and the actions taken to challenge the decision, the project in-service date is targeted as early as the second half of 2018, which assumes that the legal challenge process is satisfactorily and promptly concluded. An unfavorable resolution could result in the impairment of a significant portion of the capitalized project costs, which total
$389 million
on a consolidated basis at June 30, 2016, and are included within
Property, plant, and equipment, at cost
in the
Consolidated Balance Sheet
. Beginning in April 2016, we discontinued capitalization of development costs related to this project. It is also possible that we could incur certain supplier-related costs in the event of a prolonged delay or termination of the project.
Cardinal
We own a
66 percent
interest in Cardinal Gas Services, L.L.C (Cardinal), a subsidiary that provides gathering services for the Utica region and is a VIE due to certain risks shared with customers. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Cardinal’s economic performance. We expect to fund future expansion activity with capital contributions from us and the other equity partner on a proportional basis.
Jackalope
We own a
50 percent
interest in Jackalope Gas Gathering Services, L.L.C (Jackalope), a subsidiary that provides gathering and processing services for the Powder River basin and is a VIE due to certain risks shared with customers. We are the primary beneficiary because we have the power to direct the activities that most significantly impact
Jackalope’s economic performance. We expect to fund future expansion activity with capital contributions from us and the other equity partner on a proportional basis.
The following table presents amounts included in our
Consolidated Balance Sheet
that are for the use or obligation of our consolidated VIEs:
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
2016
|
|
December 31,
2015
|
|
Classification
|
|
(Millions)
|
|
|
Assets (liabilities):
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
66
|
|
|
$
|
70
|
|
|
Cash and cash equivalents
|
Accounts receivable
|
65
|
|
|
71
|
|
|
Trade accounts and notes receivable – net
|
Prepaid assets
|
4
|
|
|
2
|
|
|
Other current assets
|
Property, plant, and equipment
–
net
|
3,069
|
|
|
3,000
|
|
|
Property, plant, and equipment – net
|
Goodwill
|
47
|
|
|
47
|
|
|
Goodwill
|
Other intangible assets
–
net
|
1,410
|
|
|
1,436
|
|
|
Other intangible assets – net of accumulated amortization
|
Accounts payable
|
(71
|
)
|
|
(59
|
)
|
|
Accounts payable – trade
|
Accrued liabilities
|
(3
|
)
|
|
(14
|
)
|
|
Other accrued liabilities
|
Current deferred revenue
|
(63
|
)
|
|
(62
|
)
|
|
Other accrued liabilities
|
Noncurrent asset retirement obligations
|
(95
|
)
|
|
(93
|
)
|
|
Asset retirement obligations
|
Noncurrent deferred revenue associated with customer advance payments
|
(324
|
)
|
|
(331
|
)
|
|
Regulatory liabilities, deferred income, and other
|
Note 3 – Allocation of Net Income (Loss) and Distributions
The allocation of net income (loss) among our general partner, limited partners, and noncontrolling interests is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(Millions)
|
Allocation of net income to general partner:
|
|
|
|
|
|
|
|
Net income (loss)
|
$
|
(77
|
)
|
|
$
|
332
|
|
|
$
|
2
|
|
|
$
|
444
|
|
Net income applicable to pre-merger operations allocated to general partner
|
—
|
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
Net income applicable to noncontrolling interests
|
(13
|
)
|
|
(32
|
)
|
|
(42
|
)
|
|
(55
|
)
|
Costs charged directly to the general partner
|
—
|
|
|
—
|
|
|
—
|
|
|
20
|
|
Income (loss) subject to 2% allocation of general partner interest
|
(90
|
)
|
|
300
|
|
|
(40
|
)
|
|
407
|
|
General partner’s share of net income
|
2
|
%
|
|
2
|
%
|
|
2
|
%
|
|
2
|
%
|
General partner’s allocated share of net income (loss) before items directly allocable to general partner interest
|
(2
|
)
|
|
6
|
|
|
(1
|
)
|
|
8
|
|
Priority allocations, including incentive distributions, paid to general partner
|
201
|
|
|
211
|
|
|
206
|
|
|
423
|
|
Pre-merger net income allocated to general partner interest
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
Costs charged directly to the general partner
|
—
|
|
|
—
|
|
|
—
|
|
|
(20
|
)
|
Net income allocated to general partner’s equity
|
$
|
199
|
|
|
$
|
217
|
|
|
$
|
205
|
|
|
$
|
413
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
$
|
(77
|
)
|
|
$
|
332
|
|
|
$
|
2
|
|
|
$
|
444
|
|
Net income allocated to general partner’s equity
|
199
|
|
|
217
|
|
|
205
|
|
|
413
|
|
Net income (loss) allocated to Class B limited partners’ equity
|
(8
|
)
|
|
2
|
|
|
(7
|
)
|
|
(2
|
)
|
Net income allocated to Class D limited partners’ equity (1)
|
—
|
|
|
—
|
|
|
—
|
|
|
69
|
|
Net income allocated to noncontrolling interests
|
13
|
|
|
32
|
|
|
42
|
|
|
55
|
|
Net income (loss) allocated to common limited partners’ equity
|
$
|
(281
|
)
|
|
$
|
81
|
|
|
$
|
(238
|
)
|
|
$
|
(91
|
)
|
|
|
|
|
|
|
|
|
Adjustments to reconcile
Net income (loss) allocated to common limited partners’ equity
to
Allocation of net income (loss) to common units:
|
|
|
|
|
|
|
|
Incentive distributions paid (2)
|
200
|
|
|
211
|
|
|
201
|
|
|
423
|
|
Incentive distributions declared (2) (3)
|
(210
|
)
|
|
(209
|
)
|
|
(410
|
)
|
|
(421
|
)
|
Impact of unit issuance timing and other
|
2
|
|
|
—
|
|
|
10
|
|
|
—
|
|
Allocation of net income (loss) to common units
|
$
|
(289
|
)
|
|
$
|
83
|
|
|
$
|
(437
|
)
|
|
$
|
(89
|
)
|
|
|
(1)
|
Includes amortization of the beneficial conversion feature associated with the Pre-merger WPZ Class D units of
$68 million
for the six months ended June 30, 2015. See following discussion of Class D units.
|
|
|
(2)
|
Incentive distributions paid
for the 2016 periods and
Incentive distributions declared
for the six months ended June 30, 2016, reflect the waiver associated with the Termination Agreement. (See
Note 1 – General, Description of Business, and Basis of Presentation
.)
|
|
|
(3)
|
The Board of Directors of our general partner declared a cash distribution of
$0.85
per common unit on July 26, 2016, to be paid on August 12, 2016, to unitholders of record at the close of business on August 5, 2016.
|
Class B Units
The Class B units are not entitled to cash distributions. Instead, prior to conversion into common units, the Class B units receive quarterly distributions of additional paid-in-kind Class B units. Effective February 10, 2015, each Class B unit became convertible at the election of either us or the holders of such Class B unit into a common unit on a one-
for-one basis. The Board of Directors of our general partner has authorized the issuance of
395,207
Class B units associated with the second-quarter distribution, to be issued on August 12, 2016.
Class D Units
The Pre-merger WPZ Class D units, issued in February 2014 in conjunction with our acquisition of certain Canadian operations, were issued at a discount to the market price of Pre-merger WPZ’s common units, into which they were convertible. The remaining unamortized balance was recognized in the first quarter of 2015 due to the ACMP Merger. All Pre-merger WPZ Class D units were converted into common units in conjunction with the ACMP Merger.
Note 4 – Investing Activities
Investing Income
The six months ended June 30, 2016, includes other-than-temporary impairment charges of
$59 million
and
$50 million
related to certain equity-method investments in the Delaware basin gas gathering system and Laurel Mountain, respectively (see
Note 9 – Fair Value Measurements and Guarantees
).
Investments
On September 24, 2015, we received a special distribution of
$396 million
from Gulfstream reflecting our proportional share of the proceeds from new debt issued by Gulfstream. The new debt was issued to refinance Gulfstream’s debt maturities. Subsequently, we contributed
$248 million
and
$148 million
to Gulfstream for our proportional share of amounts necessary to fund debt maturities of
$500 million
due on November 1, 2015 and
$300 million
due on June 1, 2016, respectively.
Summarized Results of Operations for Certain Equity-Method Investments
The table below presents aggregated selected income statement data for our investments in Discovery, Gulfstream, and Appalachia Midstream Investments, which are considered significant.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(Millions)
|
Gross revenue
|
$
|
216
|
|
|
$
|
242
|
|
|
$
|
422
|
|
|
$
|
417
|
|
Operating income
|
125
|
|
|
123
|
|
|
244
|
|
|
203
|
|
Net income
|
106
|
|
|
106
|
|
|
204
|
|
|
168
|
|
Note 5 – Other Income and Expenses
The following table presents certain gains or losses reflected in
Other (income) expense – net
within
Costs and expenses
in our
Consolidated Statement of Comprehensive Income (Loss)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(Millions)
|
Atlantic-Gulf
|
|
|
|
|
|
|
|
Amortization of regulatory assets associated with asset retirement obligations
|
$
|
9
|
|
|
$
|
9
|
|
|
$
|
17
|
|
|
$
|
17
|
|
NGL & Petchem Services
|
|
|
|
|
|
|
|
Net foreign currency exchange (gains) losses (1)
|
—
|
|
|
1
|
|
|
11
|
|
|
(4
|
)
|
|
|
(1)
|
Primarily relates to losses incurred on foreign currency transactions and the remeasurement of U.S. dollar denominated current assets and liabilities within our Canadian operations.
|
ACMP Merger and Transition
Six months ended June 30, 2016
Selling, general, and administrative expenses
includes
$5 million
for the
six
months ended
June 30, 2016
, associated with the ACMP Merger and transition. These costs are primarily reflected within the Central segment.
Three and six months ended June 30, 2015
Selling, general, and administrative expenses
includes
$5 million
and
$34 million
for the three and
six
months ended
June 30, 2015
, respectively, primarily related to professional advisory fees and employee transition costs associated with the ACMP Merger and transition. These costs are primarily reflected within the Central segment.
Operating and maintenance expenses
includes
$8 million
and
$12 million
for the three and
six
months ended
June 30, 2015
, respectively, of transition costs from the ACMP Merger within the Central segment.
Interest incurred
includes transaction-related financing costs of
$2 million
for the
six
months ended
June 30, 2015
, from the ACMP Merger.
Geismar Incident
On June 13, 2013, an explosion and fire occurred at our Geismar olefins plant. The incident rendered the facility temporarily inoperable (Geismar Incident). We received
$126 million
of insurance recoveries during the three and
six
months ended
June 30, 2015
, reported within the NGL & Petchem Services segment and reflected as gains in
Net insurance recoveries - Geismar Incident
.
Additional Items
Three and six months ended June 30, 2016
Service revenues
have been reduced by
$15 million
for the six months ended
June 30, 2016
, related to potential refunds associated with a ruling received in certain rate case litigation within the Atlantic-Gulf segment.
Selling, general, and administrative expenses
and
Operating and maintenance expenses
include
$25 million
for the
six
months ended
June 30, 2016
, in severance and other related costs associated with an approximate
10 percent
reduction in workforce in the first quarter of 2016. Amounts by segment are as follows:
|
|
|
|
|
|
Six Months Ended June 30, 2016
|
|
(Millions)
|
Central
|
$
|
6
|
|
Northeast G&P
|
3
|
|
Atlantic-Gulf
|
8
|
|
West
|
4
|
|
NGL & Petchem Services
|
4
|
|
Other income (expense) – net
below
Operating income (loss)
includes
$12 million
and
$29 million
for the three and
six
months ended
June 30, 2016
, respectively, for allowance for equity funds used during construction, within the Atlantic-Gulf segment.
Three and six months ended June 30, 2015
Other income (expense) – net
below
Operating income (loss)
includes
$19 million
and
$36 million
for the three and
six
months ended
June 30, 2015
, respectively, for allowance for equity funds used during construction, within the Atlantic-Gulf segment.
Other income (expense) – net
below
Operating income (loss)
also includes a
$14 million
gain for the three and
six
months ended
June 30, 2015
, resulting from the early retirement of certain debt.
Note 6 – Provision (Benefit) for Income Taxes
The
Provision (benefit) for income taxes
includes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(Millions)
|
Current:
|
|
|
|
|
|
|
|
State
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
1
|
|
Foreign
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
|
1
|
|
|
1
|
|
Deferred:
|
|
|
|
|
|
|
|
State
|
(6
|
)
|
|
(7
|
)
|
|
(4
|
)
|
|
(6
|
)
|
Foreign
|
(75
|
)
|
|
6
|
|
|
(76
|
)
|
|
8
|
|
|
(81
|
)
|
|
(1
|
)
|
|
(80
|
)
|
|
2
|
|
|
|
|
|
|
|
|
|
Provision (benefit) for income taxes
|
$
|
(80
|
)
|
|
$
|
—
|
|
|
$
|
(79
|
)
|
|
$
|
3
|
|
The effective income tax rates for the three and six months ended June 30, 2016, are greater than the federal statutory rate due to the tax effect of a
$341 million
impairment associated with our Canadian operations (see
Note 9 – Fair Value Measurements and Guarantees
) and Texas franchise tax, partially offset by income not subject to U.S. federal tax.
The effective income tax rates for the three and six months ended June 30, 2015, are less than the federal statutory rate due to income not subject to U.S. federal tax and the effect of a Texas franchise tax rate decrease, partially offset by taxes on foreign operations. The 2015 state deferred benefit includes
$7 million
related to the impact of a Texas franchise tax rate decrease. The 2015 foreign deferred provision includes
$8 million
related to the impact of an Alberta provincial tax rate increase.
Note 7 – Inventories
|
|
|
|
|
|
|
|
|
|
June 30,
2016
|
|
December 31,
2015
|
|
(Millions)
|
Natural gas liquids, olefins, and natural gas in underground storage
|
$
|
53
|
|
|
$
|
57
|
|
Materials, supplies, and other
|
69
|
|
|
70
|
|
|
$
|
122
|
|
|
$
|
127
|
|
Note 8 – Debt and Banking Arrangements
Long-Term Debt
Issuances and retirements
On January 22, 2016, Transco issued
$1 billion
of
7.85 percent
senior unsecured notes due 2026 to investors in a private debt placement. Transco used the net proceeds to repay debt and to fund capital expenditures. As part of the new issuance, Transco entered into a registration rights agreement with the initial purchasers of the unsecured notes. Transco is obligated to file and consummate a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act of 1933, as amended, within 365 days from closing and to use commercially reasonable efforts to complete the exchange offer. Transco is required to provide a shelf registration statement to cover resales of the notes under certain circumstances. If Transco fails to fulfill these obligations, additional interest will accrue on the affected securities. The rate of additional interest will be
0.25 percent
per annum on the principal amount of the affected securities for the first 90-day period immediately following the occurrence of default, increasing by an additional
0.25 percent
per annum with respect to each subsequent 90-day period thereafter, up to a maximum amount for all such defaults of
0.5 percent
annually. Following the cure of any registration defaults, the accrual of additional interest will cease.
Transco retired
$200 million
of
6.4 percent
senior unsecured notes that matured on April 15, 2016.
Northwest Pipeline retired
$175 million
of
7 percent
senior unsecured notes that matured on June 15, 2016.
Commercial Paper Program
As of June 30, 2016, we had
$196 million
of
Commercial paper
outstanding under our
$3 billion
commercial paper program with a weighted average interest rate of
1.27 percent
.
Credit Facilities
|
|
|
|
|
|
|
|
|
|
June 30, 2016
|
|
Stated Capacity
|
|
Outstanding
|
|
(Millions)
|
Long-term credit facility (1)
|
$
|
3,500
|
|
|
$
|
1,425
|
|
Letters of credit under certain bilateral bank agreements
|
|
|
2
|
|
Short-term credit facility (2)
|
150
|
|
|
—
|
|
|
|
(1)
|
In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program.
|
|
|
(2)
|
This facility expires August 24, 2016.
|
Note 9 – Fair Value Measurements and Guarantees
The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable, commercial paper, and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using
|
|
Carrying
Amount
|
|
Fair
Value
|
|
Quoted
Prices In
Active
Markets for
Identical
Assets
(Level 1)
|
|
Significant
Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
(Millions)
|
Assets (liabilities) at June 30, 2016:
|
|
|
|
|
|
|
|
|
|
Measured on a recurring basis:
|
|
|
|
|
|
|
|
|
|
ARO Trust investments
|
$
|
87
|
|
|
$
|
87
|
|
|
$
|
87
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Energy derivatives assets designated as hedging instruments
|
1
|
|
|
1
|
|
|
—
|
|
|
1
|
|
|
—
|
|
Energy derivatives assets not designated as hedging instruments
|
1
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Energy derivatives liabilities not designated as hedging instruments
|
(6
|
)
|
|
(6
|
)
|
|
(1
|
)
|
|
—
|
|
|
(5
|
)
|
Additional disclosures:
|
|
|
|
|
|
|
|
|
|
Other receivables
|
13
|
|
|
13
|
|
|
13
|
|
|
—
|
|
|
—
|
|
Long-term debt, including current portion (1)
|
(19,900
|
)
|
|
(19,478
|
)
|
|
—
|
|
|
(19,478
|
)
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Assets (liabilities) at December 31, 2015:
|
|
|
|
|
|
|
|
|
|
Measured on a recurring basis:
|
|
|
|
|
|
|
|
|
|
ARO Trust investments
|
$
|
67
|
|
|
$
|
67
|
|
|
$
|
67
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Energy derivatives assets not designated as hedging instruments
|
5
|
|
|
5
|
|
|
—
|
|
|
3
|
|
|
2
|
|
Energy derivatives liabilities not designated as hedging instruments
|
(2
|
)
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
Additional disclosures:
|
|
|
|
|
|
|
|
|
|
Other receivables
|
12
|
|
|
12
|
|
|
10
|
|
|
2
|
|
|
—
|
|
Long-term debt, including current portion (1)
|
(19,176
|
)
|
|
(15,988
|
)
|
|
—
|
|
|
(15,988
|
)
|
|
—
|
|
___________________________________
(1) Excludes capital leases.
Fair Value Methods
We use the following methods and assumptions in estimating the fair value of our financial instruments:
Assets and liabilities measured at fair value on a recurring basis
ARO Trust investments
:
Transco deposits a portion of its collected rates, pursuant to its rate case settlement, into an external trust (ARO Trust) that is specifically designated to fund future asset retirement obligations (ARO). The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market, is classified as available-for-sale, and is reported in
Regulatory assets, deferred charges, and other
in the Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.
Energy derivatives
:
Energy derivatives include commodity based exchange-traded contracts and over-the-counter contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts do not include cash held on deposit in margin
accounts that we have received or remitted to collateralize certain derivative positions. Energy derivatives assets are reported in
Other current assets
and
Regulatory assets, deferred charges, and other
in the Consolidated Balance Sheet. Energy derivatives liabilities are reported in
Other accrued liabilities
and
Regulatory liabilities, deferred income, and other
in the Consolidated Balance Sheet.
Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the
six
months ended
June 30, 2016
or
2015
.
Additional fair value disclosures
Other receivables:
Other receivables primarily consists of margin deposits, which are reported in
Other current assets
in the Consolidated Balance Sheet. The disclosed fair value of our margin deposits is considered to approximate the carrying value generally due to the short-term nature of these items.
Long-term debt
:
The disclosed fair value of our long-term debt is determined by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments.
Nonrecurring fair value measurements
The following table presents impairments associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairments
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
Classification
|
Segment
|
Date of Measurement
|
|
Fair Value
|
|
2016
|
|
2015
|
|
|
|
|
|
(Millions)
|
Surplus equipment (1)
|
Property, plant, and equipment – net
|
Northeast G&P
|
June 30, 2015
|
|
$
|
17
|
|
|
|
|
$
|
20
|
|
Canadian operations (2)
|
Assets held for sale
|
NGL & Petchem Services
|
June 30, 2016
|
|
924
|
|
|
$
|
341
|
|
|
|
Certain gathering operations (3)
|
Property, plant, and equipment – net
|
Central
|
June 30, 2016
|
|
18
|
|
|
48
|
|
|
|
Level 3 fair value measurements of long-lived assets
|
|
|
|
|
|
|
389
|
|
|
20
|
|
Other impairments (4)
|
|
|
|
|
|
|
13
|
|
|
7
|
|
Impairment of long-lived assets
|
|
|
|
|
|
|
$
|
402
|
|
|
$
|
27
|
|
|
|
|
|
|
|
|
|
|
|
Equity-method investments (5)
|
Investments
|
Central and Northeast G&P
|
March 31, 2016
|
|
$
|
1,294
|
|
|
$
|
109
|
|
|
|
Other equity-method investment
|
Investments
|
Central
|
March 31, 2016
|
|
—
|
|
|
3
|
|
|
|
Impairment of equity-method investments
|
|
|
|
|
|
|
$
|
112
|
|
|
|
______________
|
|
(1)
|
Relates to certain surplus equipment. The estimated fair value was determined by a market approach based on our analysis of observable inputs in the principal market.
|
|
|
(2)
|
We have previously announced that our business plan for 2016 includes the expectation of proceeds from planned asset sales and we initiated a marketing process regarding the potential sale of our Canadian operations (disposal group). These assets are being marketed along with other Canadian operations held by Williams. We have received
|
bids during the second quarter from potential purchasers and are in advanced negotiations regarding the sale of these operations. Given the maturation of this process during the second quarter, we have designated these operations as held for sale as of June 30, 2016. As a result, we measured the fair value of the disposal group, resulting in an impairment charge. The estimated fair value was determined by a market approach based primarily on inputs received in the marketing process and reflects our estimate of the potential assumed proceeds related to our Canadian operations. We expect to dispose of our Canadian operations through a sale during the second half of 2016. The following table presents the carrying amounts of the major classes of assets and liabilities included as part of the disposal group, which are presented within
Assets held for sale
and
Liabilities held for sale
on the Consolidated Balance Sheet (and excludes certain insignificant assets held for sale at Central that are not part of this disposal group).
|
|
|
|
|
|
|
|
Carrying Amount
|
|
|
June 30, 2016
|
|
|
(Millions)
|
Assets (liabilities):
|
|
|
Current assets
|
|
$
|
35
|
|
Property, plant, and equipment – net
|
|
1,122
|
|
Other noncurrent assets
|
|
108
|
|
Impairment of disposal group
|
|
(341
|
)
|
|
|
$
|
924
|
|
|
|
|
Current liabilities
|
|
(23
|
)
|
Noncurrent liabilities
|
|
(128
|
)
|
|
|
$
|
(151
|
)
|
The following table presents the results of operations for the disposal group, excluding the impairment noted above.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(Millions)
|
Income (loss) before income taxes of disposal group
|
$
|
(10
|
)
|
|
$
|
(8
|
)
|
|
$
|
(25
|
)
|
|
$
|
3
|
|
|
|
(3)
|
Relates to the certain gathering assets within the Mid-Continent region. The estimated fair value was determined by a market approach based on our analysis of observable inputs in the principal market.
|
|
|
(4)
|
Reflects multiple individually insignificant impairments of other certain assets that may no longer be in use or are surplus in nature for which the fair value was determined to be zero or an insignificant salvage value.
|
|
|
(5)
|
Relates to Central’s equity-method investment in the Delaware basin gas gathering system and Northeast G&P’s equity-method investment in Laurel Mountain. Our carrying values in these equity-method investments had been written down to fair value at December 31, 2015. Our first-quarter 2016 analysis reflected higher discount rates for both of these investments, along with lower natural gas prices for Laurel Mountain. We estimated the fair value of these investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized ranged from
13.0 percent
to
13.3 percent
and reflected increases in our cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses.
|
Guarantees
We are required by our revolving credit agreements to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have no carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim.
Note 10 – Contingent Liabilities
Environmental Matters
We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), and other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of
June 30, 2016
, we have accrued liabilities totaling
$13 million
for these matters, as discussed below. Our accrual reflects the most likely costs of cleanup, which are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. Certain assessment studies are still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Any incremental amount in excess of amounts currently accrued cannot be reasonably estimated at this time due to uncertainty about the actual number of contaminated sites ultimately identified, the actual amount and extent of contamination discovered, and the final cleanup standards mandated by the EPA and other governmental authorities.
The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. More recent rules and rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, new air quality standards for one hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design and operation of storage vessels, pressure valves, and compressors. On October 1, 2015, the EPA issued its new rule regarding National Ambient Air Quality Standards for ground-level ozone, setting a new standard of
70 parts per billion
. We are monitoring the rule’s implementation and evaluating potential impacts to our operations. For these and other new regulations, we are unable to estimate the costs of asset additions or modifications necessary to comply due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.
Our interstate gas pipelines are involved in remediation activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances. These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites. At
June 30, 2016
, we have accrued liabilities of
$6 million
for these costs. We expect that these costs will be recoverable through rates.
We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At
June 30, 2016
, we have accrued liabilities totaling
$7 million
for these costs.
Geismar Incident
On June 13, 2013, an explosion and fire occurred at our Geismar olefins plant and rendered the facility temporarily inoperable. We are addressing the following matters in connection with the Geismar Incident.
On October 21, 2013, the EPA issued an Inspection Report pursuant to the Clean Air Act’s Risk Management Program following its inspection of the facility on June 24 through June 28, 2013. The report notes the EPA’s preliminary determinations about the facility’s documentation regarding process safety, process hazard analysis, as well as operating
procedures, employee training, and other matters. On June 16, 2014, we received a request for information related to the Geismar Incident from the EPA under Section 114 of the Clean Air Act to which we responded on August 13, 2014. The EPA could issue penalties pertaining to final determinations.
Multiple lawsuits, including class actions for alleged offsite impacts, property damage, customer claims, and personal injury, have been filed against us. To date, we have settled certain of the personal injury claims for an aggregate immaterial amount that we have recovered from our insurers. The trial for certain plaintiffs claiming personal injury, that was set to begin on June 15, 2015, in Iberville Parish, Louisiana, has been postponed to September 6, 2016. The court also set trial dates for additional plaintiffs in November 2016 and January and April 2017. We believe it is probable that additional losses will be incurred on some lawsuits, while for others we believe it is only reasonably possible that losses will be incurred. However, due to ongoing litigation involving defenses to liability, the number of individual plaintiffs, limited information as to the nature and extent of all plaintiffs’ damages, and the ultimate outcome of all appeals, we are unable to reliably estimate any such losses at this time. We believe that it is probable that any ultimate losses incurred will be covered by our general liability insurance policy, which has an aggregate limit of
$610 million
applicable to this event and retention (deductible) of
$2 million
per occurrence.
Royalty Matters
Certain of our customers, including one major customer, have been named in various lawsuits alleging underpayment of royalties and claiming, among other things, violations of anti-trust laws and the Racketeer Influenced and Corrupt Organizations Act. We have also been named as a defendant in certain of these cases in Texas, Pennsylvania, and Ohio based on allegations that we improperly participated with that major customer in causing the alleged royalty underpayments. We have also received subpoenas from the United States Department of Justice and the Pennsylvania Attorney General requesting documents relating to the agreements between us and our major customer and calculations of the major customer’s royalty payments. On December 9, 2015, the Pennsylvania Attorney General filed a civil suit against one of our major customers and us alleging breaches of the Pennsylvania Unfair Trade Practices and Consumer Protection Law, and on February 8, 2016, the Pennsylvania Attorney General filed an amended complaint in such civil suit, which omitted us as a party. We believe that the claims asserted are subject to indemnity obligations owed to us by that major customer. Our customer and the plaintiffs in those certain Texas cases in which we are named have reached a settlement, and therefore all claims asserted against us in the Texas cases are being fully dismissed with prejudice. Due to the preliminary status of the remaining cases, we are unable to estimate a range of potential loss at this time.
Stockholder Litigation
On March 7, 2016, a purported unitholder of us filed a putative class action on behalf of certain purchasers of our units in the U.S. District Court in Oklahoma. The action names as defendants, us, Williams, Williams Partners GP LLC, Alan S. Armstrong, and Donald R. Chappel and alleges violations of certain federal securities laws for failure to disclose Energy Transfer’s intention to pursue a purchase of Williams conditioned on Williams not closing the WPZ Public Unit Exchange when announcing the WPZ Public Unit Exchange. The complaint seeks, among other things, damages and an award of costs and attorneys’ fees. The plaintiff must file an amended complaint by August 31, 2016. We cannot reasonably estimate a range of potential loss at this time.
Opal 2014 Incident Subpoena
On July 14, 2016, our subsidiary, Williams Field Services Company, LLC (WFS), received a grand jury subpoena from the U.S. District Court for the District of Wyoming. The subpoena requests documents and information from WFS relating to, among other things, the April 23, 2014, explosion and fire at its natural gas processing facility in Lincoln County, Wyoming, near the town of Opal. We and WFS intend to cooperate fully with this investigation. It is not possible at this time to predict the outcome of this investigation, including whether the investigation will result in any action or proceeding against WFS, or to reasonably estimate any potential loss related thereto. We currently believe that this matter will not have a material adverse effect on our consolidated results of operations, financial position, or liquidity.
Other
In addition to the foregoing, various other proceedings are pending against us which are incidental to our operations.
Summary
We have disclosed all significant matters for which we are unable to reasonably estimate a range of possible loss. We estimate that for all other matters for which we are able to reasonably estimate a range of loss, our aggregate reasonably possible losses beyond amounts accrued are immaterial to our expected future annual results of operations, liquidity, and financial position. These calculations have been made without consideration of any potential recovery from third parties.
Note 11 – Segment Disclosures
Our reportable segments are Central, Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services. (See
Note 1 – General, Description of Business, and Basis of Presentation
.)
Performance Measurement
We evaluate segment operating performance based upon
Modified EBITDA
(earnings before interest, taxes, depreciation, and amortization). This measure represents the basis of our internal financial reporting and is the primary performance measure used by our chief operating decision maker in measuring performance and allocating resources among our reportable segments.
We define
Modified EBITDA
as follows:
|
|
•
|
Net income (loss) before:
|
|
|
◦
|
Provision (benefit) for income taxes;
|
|
|
◦
|
Interest incurred, net of interest capitalized;
|
|
|
◦
|
Equity earnings (losses);
|
|
|
◦
|
Impairment of equity-method investments;
|
|
|
◦
|
Other investing income (loss)
–
net;
|
|
|
◦
|
Impairment of goodwill;
|
|
|
◦
|
Depreciation and amortization expenses;
|
|
|
◦
|
Accretion expense associated with asset retirement obligations for nonregulated operations.
|
|
|
•
|
This measure is further adjusted to include our proportionate share (based on ownership interest) of
Modified EBITDA
from our equity-method investments calculated consistently with the definition described above.
|
The following table reflects the reconciliation of
Segment revenues
to
Total
revenues
as reported in the
Consolidated Statement of Comprehensive Income (Loss)
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Central
|
|
Northeast
G&P
|
|
Atlantic-
Gulf
|
|
West
|
|
NGL &
Petchem
Services
|
|
Eliminations
|
|
Total
|
|
(Millions)
|
Three Months Ended June 30, 2016
|
Segment revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
$
|
255
|
|
|
$
|
199
|
|
|
$
|
447
|
|
|
$
|
255
|
|
|
$
|
54
|
|
|
$
|
—
|
|
|
$
|
1,210
|
|
Internal
|
3
|
|
|
9
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
(13
|
)
|
|
—
|
|
Total service revenues
|
258
|
|
|
208
|
|
|
448
|
|
|
255
|
|
|
54
|
|
|
(13
|
)
|
|
1,210
|
|
Product sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
—
|
|
|
27
|
|
|
63
|
|
|
4
|
|
|
426
|
|
|
—
|
|
|
520
|
|
Internal
|
—
|
|
|
6
|
|
|
42
|
|
|
74
|
|
|
37
|
|
|
(159
|
)
|
|
—
|
|
Total product sales
|
—
|
|
|
33
|
|
|
105
|
|
|
78
|
|
|
463
|
|
|
(159
|
)
|
|
520
|
|
Total revenues
|
$
|
258
|
|
|
$
|
241
|
|
|
$
|
553
|
|
|
$
|
333
|
|
|
$
|
517
|
|
|
$
|
(172
|
)
|
|
$
|
1,730
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2015
|
Segment revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
$
|
260
|
|
|
$
|
214
|
|
|
$
|
465
|
|
|
$
|
258
|
|
|
$
|
34
|
|
|
$
|
—
|
|
|
$
|
1,231
|
|
Internal
|
5
|
|
|
2
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
(8
|
)
|
|
—
|
|
Total service revenues
|
265
|
|
|
216
|
|
|
466
|
|
|
258
|
|
|
34
|
|
|
(8
|
)
|
|
1,231
|
|
Product sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
—
|
|
|
30
|
|
|
83
|
|
|
8
|
|
|
478
|
|
|
—
|
|
|
599
|
|
Internal
|
—
|
|
|
5
|
|
|
42
|
|
|
60
|
|
|
35
|
|
|
(142
|
)
|
|
—
|
|
Total product sales
|
—
|
|
|
35
|
|
|
125
|
|
|
68
|
|
|
513
|
|
|
(142
|
)
|
|
599
|
|
Total revenues
|
$
|
265
|
|
|
$
|
251
|
|
|
$
|
591
|
|
|
$
|
326
|
|
|
$
|
547
|
|
|
$
|
(150
|
)
|
|
$
|
1,830
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2016
|
Segment revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
$
|
507
|
|
|
$
|
407
|
|
|
$
|
912
|
|
|
$
|
518
|
|
|
$
|
92
|
|
|
$
|
—
|
|
|
$
|
2,436
|
|
Internal
|
6
|
|
|
12
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
(20
|
)
|
|
—
|
|
Total service revenues
|
513
|
|
|
419
|
|
|
914
|
|
|
518
|
|
|
92
|
|
|
(20
|
)
|
|
2,436
|
|
Product sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
—
|
|
|
46
|
|
|
100
|
|
|
8
|
|
|
794
|
|
|
—
|
|
|
948
|
|
Internal
|
—
|
|
|
11
|
|
|
74
|
|
|
122
|
|
|
75
|
|
|
(282
|
)
|
|
—
|
|
Total product sales
|
—
|
|
|
57
|
|
|
174
|
|
|
130
|
|
|
869
|
|
|
(282
|
)
|
|
948
|
|
Total revenues
|
$
|
513
|
|
|
$
|
476
|
|
|
$
|
1,088
|
|
|
$
|
648
|
|
|
$
|
961
|
|
|
$
|
(302
|
)
|
|
$
|
3,384
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2015
|
|
|
|
|
Segment revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
$
|
505
|
|
|
$
|
410
|
|
|
$
|
922
|
|
|
$
|
520
|
|
|
$
|
66
|
|
|
$
|
—
|
|
|
$
|
2,423
|
|
Internal
|
12
|
|
|
2
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
(16
|
)
|
|
—
|
|
Total service revenues
|
517
|
|
|
412
|
|
|
924
|
|
|
520
|
|
|
66
|
|
|
(16
|
)
|
|
2,423
|
|
Product sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
—
|
|
|
67
|
|
|
151
|
|
|
16
|
|
|
884
|
|
|
—
|
|
|
1,118
|
|
Internal
|
—
|
|
|
6
|
|
|
95
|
|
|
116
|
|
|
72
|
|
|
(289
|
)
|
|
—
|
|
Total product sales
|
—
|
|
|
73
|
|
|
246
|
|
|
132
|
|
|
956
|
|
|
(289
|
)
|
|
1,118
|
|
Total revenues
|
$
|
517
|
|
|
$
|
485
|
|
|
$
|
1,170
|
|
|
$
|
652
|
|
|
$
|
1,022
|
|
|
$
|
(305
|
)
|
|
$
|
3,541
|
|
The following table reflects the reconciliation of
Modified EBITDA
to
Net income (loss)
as reported in the
Consolidated Statement of Comprehensive Income (Loss)
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(Millions)
|
Modified EBITDA by segment:
|
|
|
|
|
|
|
|
Central
|
$
|
134
|
|
|
$
|
160
|
|
|
$
|
291
|
|
|
$
|
293
|
|
Northeast G&P
|
216
|
|
|
183
|
|
|
430
|
|
|
368
|
|
Atlantic-Gulf
|
357
|
|
|
389
|
|
|
733
|
|
|
724
|
|
West
|
158
|
|
|
150
|
|
|
313
|
|
|
311
|
|
NGL & Petchem Services
|
(261
|
)
|
|
158
|
|
|
(208
|
)
|
|
164
|
|
Other
|
—
|
|
|
13
|
|
|
—
|
|
|
10
|
|
|
604
|
|
|
1,053
|
|
|
1,559
|
|
|
1,870
|
|
Accretion expense associated with asset retirement obligations for nonregulated operations
|
(9
|
)
|
|
(9
|
)
|
|
(16
|
)
|
|
(16
|
)
|
Depreciation and amortization expenses
|
(432
|
)
|
|
(419
|
)
|
|
(867
|
)
|
|
(838
|
)
|
Equity earnings (losses)
|
101
|
|
|
93
|
|
|
198
|
|
|
144
|
|
Impairment of equity-method investments
|
—
|
|
|
—
|
|
|
(112
|
)
|
|
—
|
|
Other investing income (loss) – net
|
1
|
|
|
—
|
|
|
1
|
|
|
1
|
|
Proportional Modified EBITDA of equity-method investments
|
(191
|
)
|
|
(183
|
)
|
|
(380
|
)
|
|
(319
|
)
|
Interest expense
|
(231
|
)
|
|
(203
|
)
|
|
(460
|
)
|
|
(395
|
)
|
(Provision) benefit for income taxes
|
80
|
|
|
—
|
|
|
79
|
|
|
(3
|
)
|
Net income (loss)
|
$
|
(77
|
)
|
|
$
|
332
|
|
|
$
|
2
|
|
|
$
|
444
|
|
The following table reflects
Total assets
by reportable segment.
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
June 30,
2016
|
|
December 31,
2015
|
|
(Millions)
|
Central
|
$
|
13,368
|
|
|
$
|
13,914
|
|
Northeast G&P
|
13,636
|
|
|
13,827
|
|
Atlantic-Gulf
|
13,269
|
|
|
12,171
|
|
West
|
4,771
|
|
|
5,035
|
|
NGL & Petchem Services
|
3,134
|
|
|
3,306
|
|
Other corporate assets
|
115
|
|
|
350
|
|
Eliminations (1)
|
(999
|
)
|
|
(733
|
)
|
Total
|
$
|
47,294
|
|
|
$
|
47,870
|
|
|
|
(1)
|
Eliminations primarily relate to the intercompany accounts and notes receivable generated by our cash management program.
|
Item 2
Management’s Discussion and Analysis of
Financial Condition and Results of Operations
General
We are an energy infrastructure master limited partnership focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas, NGLs, and olefins through our gas pipeline and midstream businesses. WPZ GP LLC, a Delaware limited liability company wholly owned by Williams, is our general partner.
Our interstate natural gas pipeline strategy is to create value by maximizing the utilization of our pipeline capacity by providing high quality, low cost transportation of natural gas to large and growing markets. Our gas pipeline businesses’ interstate transmission and storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have limited near-term impact on these revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.
The ongoing strategy of our midstream operations is to safely and reliably operate large-scale midstream infrastructure where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers. These services include natural gas gathering, processing, treating, and compression, NGL fractionation and transportation, crude oil production handling and transportation, olefin production, marketing services for NGL, oil and natural gas, as well as storage facilities.
Effective January 1, 2016, businesses located in the Marcellus and Utica shale plays within the former Access Midstream segment are now managed, and thus presented, within the Northeast G&P segment. The remaining Access Midstream businesses are now presented as the Central segment. Prior period segment disclosures have been recast for these segment changes. As a result, beginning with the reporting of first-quarter 2016, our reportable segments are Central, Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services, which are comprised of the following businesses:
|
|
•
|
Central provides domestic gathering, treating, and compression services to producers under long-term, fixed-fee contracts. Its primary operating areas are in the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware and Permian basins. Central also includes a 50 percent equity-method investment in the Delaware basin gas gathering system in the Mid-Continent region.
|
|
|
•
|
Northeast G&P is comprised of midstream gathering and processing businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and West Virginia, and the Utica shale region of eastern Ohio, as well as a 69 percent equity-method investment in Laurel Mountain and a 58 percent equity-method investment in Caiman II. Northeast G&P also includes a 62 percent equity-method investment in UEOM and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 45 percent interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).
|
|
|
•
|
Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transco, and significant natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One (a consolidated entity), which is a proprietary floating production system, as well as a 50 percent equity-method investment in Gulfstream, a 60 percent equity-method investment in Discovery, and a 41 percent interest in Constitution (a consolidated entity), which is under development.
|
Management’s Discussion and Analysis (Continued)
|
|
•
|
West is comprised of our gathering, processing and treating operations in New Mexico, Colorado, and Wyoming, and our interstate natural gas pipeline, Northwest Pipeline.
|
|
|
•
|
NGL & Petchem Services is comprised of our 88.5 percent undivided interest in an olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and various petrochemical and feedstock pipelines in the Gulf Coast region, an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility at Redwater, Alberta. As of June 30, 2016, these Canadian operations are considered held for sale (See
Note 9 – Fair Value Measurements and Guarantees
of Notes to Consolidated Financial Statements). This segment also includes an NGL and natural gas marketing business, storage facilities, and an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, and a 50 percent equity-method investment in OPPL.
|
As of
June 30, 2016
, Williams holds an approximate 60 percent interest in us, comprised of an approximate 58 percent limited partner interest and all of our 2 percent general partner interest and IDRs.
Unless indicated otherwise, the following discussion and analysis of results of operations and financial condition and liquidity should be read in conjunction with the consolidated financial statements and notes thereto of this Form 10‑Q and our annual consolidated financial statements and notes thereto in Exhibit 99.1 of our Form 8‑K dated May 27, 2016.
Distributions
On July 26, 2016
,
our general partner’s Board of Directors approved a quarterly distribution to unitholders of
$0.85
per common unit on August 12, 2016, on our outstanding common units to unitholders of record at the close of business on August 5, 2016.
Overview of
Six Months Ended
June 30, 2016
Net income (loss) attributable to controlling interests
for the
six
months ended
June 30, 2016
, decreased
$429 million
compared to the
six
months ended
June 30, 2015
, reflecting impairment charges associated with certain equity-method investments and long-lived assets, the absence of $126 million of insurance recoveries, increased depreciation and amortization expense primarily due to depreciation on new projects placed in service and higher interest incurred, partially offset by an increase in olefins margins associated with our Geismar plant and higher equity earnings at Discovery related to the completion of the Keathley Canyon Connector in 2015. See additional discussion in Results of Operations.
Williams’ Merger Agreement with Energy Transfer
On September 28, 2015, Williams publicly announced in a press release that it had entered into a Merger Agreement with Energy Transfer and certain of its affiliates. The Merger Agreement provided that, subject to the satisfaction of customary closing conditions, Williams would merge with and into the newly formed ETC, with ETC surviving the ETC Merger. Energy Transfer formed ETC as a limited partnership that would be treated as a corporation for U.S. federal income tax purposes. Immediately following the completion of the ETC Merger, ETC would contribute to Energy Transfer all of the assets and liabilities of Williams in exchange for the issuance by Energy Transfer to ETC of a number of Energy Transfer Class E common units equal to the number of ETC common shares issued to Williams stockholders in the ETC Merger.
On June 29, 2016, Energy Transfer provided Williams written notice terminating the Merger Agreement, citing the alleged failure of certain conditions under the Merger Agreement.
NGL & Petchem Services
Redwater expansion
In March 2016, we completed the expansion of our Redwater facilities to provide NGL transportation and fractionation services to Williams associated with its long-term agreement to provide gas processing services to a second
Management’s Discussion and Analysis (Continued)
bitumen upgrader in Canada’s oil sands near Fort McMurray, Alberta. With this capacity increase, additional NGL/olefins mixtures from Williams are fractionated into an ethane/ethylene mix, propane, polymer grade propylene, normal butane, an alkylation feed and condensate under a long-term, fee-based agreement.
Volatile Commodity Prices
NGL per-unit margins were approximately 24 percent lower in the first
six months
of 2016 compared to the same period of 2015. The primary drivers for the six-month comparative period decrease was a 17 percent decline
in
per-unit
non
-
ethane prices and to a change in the relative mix of NGL products produced, which has shifted to a higher proportion of lower-margin ethane products
.
The decrease in per-unit non-ethane prices was partially offset by an approximately 30 percent decline in per-unit natural gas feedstock prices. NGL per-unit margins were approximately 29 percent higher for the quarter ending June 30, 2016, compared to the quarter ending March 31, 2016. The improvement in NGL per-unit margins between the second and first quarter of 2016 was due to a 39 percent improvement in non-ethane prices in the quarter ending June 30, 2016, compared to the quarter ending March 31, 2016.
NGL margins are defined as NGL revenues less any applicable Btu replacement cost, plant fuel, and third-party transportation and fractionation. Per-unit NGL margins are calculated based on sales of our own equity volumes at the processing plants. Our equity volumes include NGLs where we own the rights to the value from NGLs recovered at our plants under both “keep-whole” processing agreements, where we have the obligation to replace the lost heating value with natural gas, and “percent-of-liquids” agreements whereby we receive a portion of the extracted liquids with no obligation to replace the lost heating value.
The following graph illustrates the effects of margin volatility and NGL production and sales volumes, as well as the margin differential between ethane and non-ethane products and the relative mix of those products.
The potential impact of commodity price volatility on our business for the remainder of 2016 is further discussed in the following Company Outlook.
Management’s Discussion and Analysis (Continued)
Company Outlook
Our strategy is to provide large-scale energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas and natural gas products that exists in North America. We seek to accomplish this through further developing our scale positions in current key markets and basins and entering new demand driven growth markets and basins where we can become the large-scale service provider. We will continue to maintain a strong commitment to safety, environmental stewardship, operational excellence, and customer satisfaction. We believe that accomplishing these goals will position us to deliver safe and reliable service to our customers and an attractive return to our unitholders.
We expect commodity prices to remain challenged and costs of capital to remain sharply higher for the remainder of 2016 as compared to 2015. Anticipating these conditions, our business plan for 2016 includes significant reductions in capital investment and expenses, including the workforce reductions previously discussed in
Note 5 – Other Income and Expenses
of Notes to Consolidated Financial Statements, from our previous plans. In addition, we expect proceeds from the planned sale of our Canadian operations during 2016.
Our growth capital and investment expenditures in 2016 are expected to total $1.9 billion. Approximately $1.3 billion of our growth capital funding needs include Transco expansions and other interstate pipeline growth projects, most of which are fully contracted with firm transportation agreements. The remaining non-interstate pipeline growth capital spending in 2016 primarily reflects investment in gathering and processing systems limited to known new producer volumes, including volumes that support Transco expansion projects in addition to wells drilled and completed awaiting connecting infrastructure. We also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments.
As previously discussed, we have announced a quarterly distribution of $0.85 per common unit, or $3.40 annually. Additionally, we expect to implement a distribution reinvestment program (DRIP). The program is expected to enhance our ability to maintain our distribution, while providing us with the flexibility to reduce debt and maintain our investment grade ratings.
Fee-based businesses are a significant component of our portfolio and serve to somewhat reduce the influence of commodity price fluctuations on our operating results and cash flows. However, producer activities are being impacted by lower energy commodity prices, which are affecting our gathering volumes. The credit profiles of certain of our producer customers are increasingly challenged by the current market conditions. These conditions may ultimately result in a further reduction of our gathering volumes. Such reductions as well as further or prolonged declines in energy commodity prices may also result in noncash impairments of our assets.
We have been approached by certain customers seeking to revise certain of our gathering and processing contracts, due in part to the low energy commodity price environment. In these situations, we generally seek to reasonably consider customer needs while maintaining or improving the overall value of our contracts. Any such revisions may impact the level and timing of expected future cash flows, requiring that we evaluate the recoverability of the underlying assets, which could result in noncash impairments.
Commodity margins are highly dependent upon regional supply/demand balances of natural gas as they relate to NGL margins, while olefins are impacted by global supply and demand fundamentals. We anticipate the following trends in energy commodity prices in 2016, compared to 2015 that may impact our operating results and cash flows:
|
|
•
|
Natural gas prices are expected to be lower;
|
|
|
•
|
NGL prices are expected to be somewhat consistent;
|
|
|
•
|
Olefins prices, including propylene, ethylene, and the overall ethylene crack spread, are expected to be lower.
|
In 2016, we anticipate our operating results will include increases from our fee-based businesses placed in service in 2015 and those anticipated to be placed in service in 2016, increases in our olefins volumes associated with a full year of operations at our Geismar plant following its 2015 repair and expansion, and lower operating and general and administrative expenses associated with cost reduction initiatives.
Management’s Discussion and Analysis (Continued)
Potential risks and obstacles that could impact the execution of our plan include:
|
|
•
|
Downgrade of our investment grade credit ratings and associated increase in cost of borrowings;
|
|
|
•
|
Higher cost of capital and/or limited availability of capital due to a change in our financial condition, interest rates, and/or market or industry conditions;
|
|
|
•
|
Counterparty credit and performance risk, including that of Chesapeake Energy Corporation and its affiliates;
|
|
|
•
|
Lower than anticipated proceeds from planned asset sales;
|
|
|
•
|
Lower than anticipated energy commodity prices and margins;
|
|
|
•
|
Lower than anticipated volumes from third parties served by our midstream business;
|
|
|
•
|
Unexpected significant increases in capital expenditures or delays in capital project execution;
|
|
|
•
|
Changes in the political and regulatory environments including the risk of delay in permits needed for regulatory projects;
|
|
|
•
|
Unexpected delay or inability to execute the DRIP;
|
|
|
•
|
General economic, financial markets, or further industry downturn;
|
|
|
•
|
Lower than expected levels of cash flow from operations;
|
|
|
•
|
Physical damages to facilities, including damage to offshore facilities by named windstorms;
|
|
|
•
|
Reduced availability of insurance coverage.
|
We continue to address these risks through maintaining a strong financial position and liquidity, as well as through managing a diversified portfolio of energy infrastructure assets which continue to serve key markets and basins in North America.
Expansion Projects
Our ongoing major expansion projects include the following:
Central
Eagle Ford
We plan to expand our gathering infrastructure in the Eagle Ford region in order to meet our customers’ production plans. The expansion of the gathering infrastructure includes the addition of new facilities, well connections, and gathering pipeline to the existing systems.
Northeast G&P
Oak Grove Expansion
We plan to expand our processing capacity at our Oak Grove facility by adding a second 200 MMcf/d cryogenic natural gas processing plant, which, based on our customers’ needs, is expected to be placed into service in 2020.
Management’s Discussion and Analysis (Continued)
Gathering System Expansion
We will continue to expand the gathering systems in the Marcellus and Utica shale regions that are needed to meet our customers’ production plans. The expansion of the gathering infrastructure includes additional compression and gathering pipeline to the existing system.
Atlantic-Gulf
Constitution Pipeline
In December 2014, we received approval from the FERC to construct and operate the jointly owned Constitution pipeline, which will have an expected capacity of 650 Mdth/d. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied a necessary water quality certification for the New York portion of the pipeline. We remain steadfastly committed to the project, and in May 2016, Constitution appealed the NYSDEC’s denial of the certification and filed an action in federal court seeking a declaration that the State of New York’s authority to exercise permitting jurisdiction over certain other environmental matters is preempted by federal law. (See Note 2 - Variable Interest Entities of Notes to Consolidated Financial Statments.) We currently own 41 percent of Constitution with three other parties holding 25 percent, 24 percent, and 10 percent, respectively. We will be the operator of Constitution. The 126-mile Constitution pipeline will connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York, as well as to a local distribution company serving New York and Pennsylvania. In light of the NYSDEC’s denial of the water quality certification and the actions taken to challenge the decision, the target in-service date has been revised to as early as the second half of 2018, which assumes that the legal challenge process is satisfactorily and promptly concluded.
Garden State
In April 2016, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 210 in New Jersey to a new interconnection on our Trenton Woodbury Lateral in New Jersey. The project will be constructed in phases and is expected to increase capacity by 180 Mdth/d. We plan to place the initial phase of the project into service during the first half of 2017 and the remaining portion in the fourth quarter of 2017, assuming timely receipt of all necessary regulatory approvals.
Norphlet Project
In March 2016, we announced that we have reached an agreement to provide deepwater gas gathering services to the Appomattox development in the Gulf of Mexico. The project will provide offshore gas gathering services to our existing Transco lateral, which will provide transmission services onshore to our Mobile Bay processing facility. We also plan to make modifications to our Main Pass 261 Platform to install an alternate delivery route from the platform, as well as modifications to our Mobile Bay processing facility. The project is scheduled to go into service during the fourth quarter of 2019.
Hillabee
In February 2016, the FERC issued a certificate order for the initial phases of Transco’s Hillabee Expansion Project (Hillabee). The project involves an expansion of Transco’s existing natural gas transmission system from Station 85 in west central Alabama to a proposed new interconnection with the Sabal Trail project in Alabama. Hillabee will be constructed in phases, and all of the project expansion capacity will be leased to Sabal Trail. We plan to place the initial phases of Hillabee into service as early as the second quarter of 2017 and during the second quarter of 2020, assuming timely receipt of all necessary regulatory approvals, and together they are expected to increase capacity by 1,025 Mdth/d.
In March 2016, we entered into an agreement with the member-sponsors of Sabal Trail to resolve several matters. In accordance with the agreement, the member-sponsors will pay us an aggregate amount of $240 million in three equal installments as certain milestones of the project are met. The first $80 million payment was received
Management’s Discussion and Analysis (Continued)
in March 2016. We expect to recognize income associated with these receipts over the term of the capacity lease agreement.
Gulf Trace
In October 2015, we received approval from the FERC to expand Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from Station 65 in St. Helena Parish, Louisiana to a new interconnection with Sabine Pass Liquefaction in Cameron Parish, Louisiana. We plan to place the project into service during the first quarter of 2017 and it is expected to increase capacity by 1,200 Mdth/d.
New York Bay Expansion
In July 2016, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Pennsylvania to the Rockaway Delivery Lateral transfer point and the Narrows meter station in Richmond County, New York. We plan to place the project into service during the fourth quarter of 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 115 Mdth/d.
Rock Springs
In March 2015, we received approval from the FERC to expand Transco’s existing natural gas transmission system from New Jersey to a proposed generation facility in Maryland. We placed the project into service on August 1, 2016 and it increased capacity by 192 Mdth/d.
Atlantic Sunrise
In March 2015, we filed an application with the FERC to expand Transco’s existing natural gas transmission system along with greenfield facilities to provide incremental firm transportation capacity from the northeastern Marcellus producing area to markets along Transco’s mainline as far south as Station 85 in west central Alabama. We plan to place the project into service as early as late 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 1,700 Mdth/d.
Virginia Southside II
In July 2016, we received approval from the FERC to expand Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from Station 210 in New Jersey and Station 165 in Virginia to a new lateral extending from our Brunswick Lateral in Virginia. We plan to place the project into service during the fourth quarter of 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 250 Mdth/d.
Dalton
In March 2015, we filed an application with the FERC to expand Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from Station 210 in New Jersey to markets in northwest Georgia. We plan to place the project into service in 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 448 Mdth/d.
Critical Accounting Estimates
Goodwill
During the first quarter of 2016 we observed a significant decline in the market value of WPZ. As a result, we evaluated our goodwill associated with the West G&P reporting unit for impairment.
Goodwill
for the West G&P reporting unit was $47 million at both June 30, 2016, and December 31, 2015. We estimated the fair value of the West G&P reporting unit based on an income approach utilizing discount rates specific to the underlying business. These discount rates considered variables unique to each business, including equity yields of comparable midstream businesses, expectations for future growth, and customer performance considerations. The weighted-average discount rate utilized
Management’s Discussion and Analysis (Continued)
was 11.6 percent. Our analysis indicated that the fair value of the West G&P reporting unit exceeded its book value by approximately $262 million, or 10 percent, at the end of the first quarter. We estimated that an overall increase in the discount rate utilized of 250 basis points would have resulted in a potential impairment of goodwill for this reporting unit.
We did not perform an interim assessment at the end of the second quarter of 2016 as our weighted-average cost of capital and equity yields of comparable midstream businesses, which drive discount rates, decreased compared to last quarter and no additional indicators of potential impairment were present.
Judgments and assumptions are inherent in our estimates of future cash flows, discount rates, and market measures utilized. The use of alternate judgments and assumptions could result in a different calculation of fair value, which could ultimately result in the recognition of an impairment charge in the consolidated financial statements.
Equity-Method Investments
In response to declining market conditions in the first quarter of 2016, we assessed whether the carrying amounts of certain of our equity-method investments exceeded their fair value. As a result, we recognized other-than-temporary impairment charges of $59 million and $50 million in the first quarter related to our equity-method investments in the Delaware basin gas gathering system (DBJV) and Laurel Mountain (LMM), respectively. Our carrying values in these equity-method investments had been written down to fair value at December 31, 2015. Our first-quarter analysis reflected higher discount rates for both DBJV and LMM, along with lower natural gas prices for LMM.
We estimated the fair value of these investments using an income approach and discount rates ranging from 13.0 percent to 13.3 percent. These discount rates considered variables unique to each business area, including equity yields of comparable midstream businesses, expectations for future growth and customer performance considerations.
We estimated that an overall increase in the discount rates utilized of 50 basis points would have resulted in additional impairment charges on our at-risk equity-method investments of approximately $104 million.
Judgments and assumptions are inherent in our estimates of future cash flows, discount rates, and market measures utilized. The use of alternate judgments and assumptions could result in a different calculation of fair value, which could ultimately result in the recognition of a different impairment charge in the consolidated financial statements.
During second quarter the discount rates decreased significantly and no impairments were recognized.
At June 30, 2016, our Consolidated Balance Sheet includes approximately $7.1 billion of investments that are accounted for under the equity-method of accounting. We evaluate these investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. We continue to monitor our equity-method investments for any indications that the carrying value may have experienced an other-than-temporary decline in value. When evidence of a loss in value has occurred, we compare our estimate of the fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. We generally estimate the fair value of our investments using an income approach where significant judgments and assumptions include expected future cash flows and the appropriate discount rate. In some cases, we may utilize a form of market approach to estimate the fair value of our investments.
If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment charge. Events or changes in circumstances that may be indicative of an other-than-temporary decline in value will vary by investment, but may include:
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•
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A significant or sustained decline in the market value of an investee;
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•
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Lower than expected cash distributions from investees;
|
Management’s Discussion and Analysis (Continued)
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•
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Significant asset impairments or operating losses recognized by investees;
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•
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Significant delays in or lack of producer development or significant declines in producer volumes in markets served by investees;
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•
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Significant delays in or failure to complete significant growth projects of investees.
|
Constitution Pipeline Capitalized Project Costs
As of June 30, 2016,
Property, plant, and equipment, at cost
in our Consolidated Balance Sheet includes approximately $389 million of capitalized project costs for Constitution, for which we are the construction manager and own a 41 percent consolidated interest. In December 2014, we received approval from the FERC to construct and operate this jointly owned pipeline. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied a necessary water quality certification for the New York portion of the Constitution pipeline. We remain steadfastly committed to the project, and in May 2016, Constitution appealed the NYSDEC's denial of the certification and filed an action in federal court seeking a declaration that the State of New York's authority to exercise permitting jurisdiction over certain other environmental matters is preempted by federal law.
As a result of the denial by the NYSDEC, we evaluated the capitalized project costs for impairment as of March 31, 2016, and determined that no impairment was necessary. Our evaluation considered probability-weighted scenarios of undiscounted future net cash flows, including a scenario assuming successful resolution with the NYSDEC and construction of the pipeline, as well as a scenario where the project does not proceed. We continue to monitor the capitalized project costs associated with Constitution for potential impairment.
Long-lived Assets
We evaluate our property, plant, and equipment and other identifiable intangible assets for impairment when events or changes in circumstances indicate, in our judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred and we may apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.
During the second quarter of 2016, we evaluated an asset group within our Central segment for impairment as a result of an increased likelihood of gas gathering contract restructuring with certain producers and lower volume projections. Our assessment included probability-weighted scenarios of undiscounted future cash flows that considered variables including terms of our current contract, as well as potential revised terms of a restructured contract, counterparty performance, and pricing assumptions. This assessment resulted in the undiscounted cash flows slightly exceeding the approximate $1.6 billion carrying value of the asset group and no impairment was recorded. The use of different judgments and assumptions associated with the measurement variables noted, particularly the assumed contractual terms, expected volumes, and rates, could result in reduced levels of future cash flows which could result in a significant impairment.
Also, during the second quarter of 2016, certain Mid-Continent gas gathering systems were assessed for impairment due to a potential disposition of those systems in the future. Based on market observed information for these gas gathering systems, these assets were written down to their fair value. As a result, we recognized a pre-tax impairment of $48 million in the Central segment.
We have previously announced that our business plan for 2016 includes the expectation of proceeds from planned asset sales and we initiated a marketing process regarding the potential sale of our Canadian operations. These assets are being marketed along with other Canadian operations held by Williams. We have received bids during the second quarter from potential purchasers and are in advanced negotiations regarding the sale of these operations. Given the
Management’s Discussion and Analysis (Continued)
maturation of this process during the second quarter, we have designated these operations as held for sale at June 30, 2016 (see
Note 9 – Fair Value Measurements and Guarantees
of Notes to Consolidated Financial Statements). As a result, we measured the fair value of these assets, resulting in a pre-tax impairment charge of $341 million in our NGL & Petchem Services segment during the second quarter of 2016. The estimated fair value was determined by a market approach based primarily on inputs received in the marketing process and reflects our estimate of the potential assumed proceeds related to our Canadian operations. Future changes to the estimated or ultimate sales proceeds may result in changes to the level of impairments or a gain or loss on the sale.
Management’s Discussion and Analysis (Continued)
Results of Operations
Consolidated Overview
The following table and discussion is a summary of our consolidated results of operations for the
three and six
months ended
June 30, 2016
, compared to the
three and six
months ended
June 30, 2015
. The results of operations by segment are discussed in further detail following this consolidated overview discussion.
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Three Months Ended
June 30,
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Six Months Ended
June 30,
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2016
|
|
2015
|
|
$ Change*
|
|
% Change*
|
|
2016
|
|
2015
|
|
$ Change*
|
|
% Change*
|
|
(Millions)
|
|
|
|
|
|
(Millions)
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service revenues
|
$
|
1,210
|
|
|
$
|
1,231
|
|
|
-21
|
|
|
-2
|
%
|
|
$
|
2,436
|
|
|
$
|
2,423
|
|
|
+13
|
|
|
+1
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%
|
Product sales
|
520
|
|
|
599
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|
|
-79
|
|
|
-13
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%
|
|
948
|
|
|
1,118
|
|
|
-170
|
|
|
-15
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%
|
Total revenues
|
1,730
|
|
|
1,830
|
|
|
|
|
|
|
3,384
|
|
|
3,541
|
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|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
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|
|
|
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|
|
Product costs
|
393
|
|
|
494
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|
|
+101
|
|
|
+20
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%
|
|
710
|
|
|
957
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|
|
+247
|
|
|
+26
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%
|
Operating and maintenance expenses
|
386
|
|
|
431
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|
|
+45
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|
|
+10
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%
|
|
768
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|
|
811
|
|
|
+43
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|
|
+5
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%
|
Depreciation and amortization expenses
|
432
|
|
|
419
|
|
|
-13
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|
|
-3
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%
|
|
867
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|
|
838
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|
|
-29
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|
|
-3
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%
|
Selling, general, and administrative expenses
|
139
|
|
|
164
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|
|
+25
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|
|
+15
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%
|
|
320
|
|
|
357
|
|
|
+37
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|
|
+10
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%
|
Net insurance recoveries – Geismar Incident
|
—
|
|
|
(126
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)
|
|
-126
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|
|
-100
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%
|
|
—
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|
|
(126
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)
|
|
-126
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|
|
-100
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%
|
Impairment of long-lived assets
|
396
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|
|
24
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|
|
-372
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NM
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|
|
402
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|
|
27
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|
|
-375
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|
|
NM
|
|
Other (income) expense – net
|
24
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|
|
14
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|
|
-10
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|
|
-71
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%
|
|
48
|
|
|
28
|
|
|
-20
|
|
|
-71
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%
|
Total costs and expenses
|
1,770
|
|
|
1,420
|
|
|
|
|
|
|
3,115
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|
|
2,892
|
|
|
|
|
|
Operating income (loss)
|
(40
|
)
|
|
410
|
|
|
|
|
|
|
269
|
|
|
649
|
|
|
|
|
|
Equity earnings (losses)
|
101
|
|
|
93
|
|
|
+8
|
|
|
+9
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%
|
|
198
|
|
|
144
|
|
|
+54
|
|
|
+38
|
%
|
Impairment of equity-method investments
|
—
|
|
|
—
|
|
|
—
|
|
|
—
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%
|
|
(112
|
)
|
|
—
|
|
|
-112
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|
|
NM
|
|
Other investing income (loss) – net
|
1
|
|
|
—
|
|
|
+1
|
|
|
NM
|
|
|
1
|
|
|
1
|
|
|
—
|
|
|
—
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%
|
Interest expense
|
(231
|
)
|
|
(203
|
)
|
|
-28
|
|
|
-14
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%
|
|
(460
|
)
|
|
(395
|
)
|
|
-65
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|
|
-16
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%
|
Other income (expense) – net
|
12
|
|
|
32
|
|
|
-20
|
|
|
-63
|
%
|
|
27
|
|
|
48
|
|
|
-21
|
|
|
-44
|
%
|
Income (loss) before income taxes
|
(157
|
)
|
|
332
|
|
|
|
|
|
|
(77
|
)
|
|
447
|
|
|
|
|
|
Provision (benefit) for income taxes
|
(80
|
)
|
|
—
|
|
|
+80
|
|
|
NM
|
|
|
(79
|
)
|
|
3
|
|
|
+82
|
|
|
NM
|
|
Net income (loss)
|
(77
|
)
|
|
332
|
|
|
|
|
|
|
2
|
|
|
444
|
|
|
|
|
|
Less: Net income attributable to noncontrolling interests
|
13
|
|
|
32
|
|
|
+19
|
|
|
+59
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%
|
|
42
|
|
|
55
|
|
|
+13
|
|
|
+24
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%
|
Net income (loss) attributable to controlling interests
|
$
|
(90
|
)
|
|
$
|
300
|
|
|
|
|
|
|
$
|
(40
|
)
|
|
$
|
389
|
|
|
|
|
|
|
|
*
|
+ = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200.
|
Management’s Discussion and Analysis (Continued)
Three months ended
June 30, 2016
vs. three months ended
June 30, 2015
Service revenues
declined primarily due to a decrease at Gulfstar One related to lower volumes, including the impact of suspending operations in order to facilitate the tie-in of the Gunflint expansion, and lower fee revenues in Ohio Valley Midstream primarily due to continued producer shut-ins and lower rates. These decreases were partially offset by an increase in Transco’s natural gas transportation fee revenues primarily associated with expansion projects placed in service in 2015 and 2016 and new transportation and fractionation revenue associated with Williams’ Horizon liquids extraction plant that went into service in March 2016.
Product sales
decreased due to reduced marketing revenues primarily associated with lower NGL volumes and prices, lower olefin sales, and lower revenues from our equity NGLs primarily due to a decrease in per-unit prices, partially offset by slightly higher volumes. The decrease in olefin sales reflects lower revenues from our RGP Splitter and our Canadian operations, mostly driven by lower volumes due primarily to the shut-down and evacuation of our liquids extraction plant because of the wild fires in the Fort McMurray area during May and June, as well as a longer period of planned maintenance in 2016 and lower per-unit propylene prices at the RGP Splitter. These decreases were partially offset by an increase in olefin sales associated with the Geismar plant operating at higher production levels in 2016.
The decrease in
Product costs
includes lower marketing purchases primarily due to lower volumes and per-unit costs, lower olefin feedstock purchases, and lower natural gas purchases associated with the production of equity NGLs primarily due to lower natural gas prices, partially offset by higher volumes. The decline in olefin feedstock purchases is primarily due to lower per-unit feedstock costs and lower volumes at our RGP Splitter, partially offset by higher costs at our Geismar plant that has operated at higher production levels in 2016.
Operating and maintenance expenses
reflect decreases in primarily labor-related and outside service costs resulting from our first-quarter 2016 workforce reductions and cost containment efforts, as well as the absence of ACMP transition costs recognized in 2015, partially offset by higher general maintenance and pipeline testing at Transco.
Depreciation and amortization expenses
increased primarily due to depreciation on new Transco projects placed in service.
Selling, general, and administrative expenses
decreased primarily due to lower labor-related costs resulting from our first-quarter 2016 workforce reductions and cost containment efforts, as well as the absence of ACMP transition costs recognized in 2015.
Net insurance recoveries – Geismar Incident
decreased reflecting the absence of $126 million of insurance proceeds received in the second quarter of 2015.
Impairment of long-lived assets
reflects 2016 impairments of our Canadian operations and certain Mid-Continent assets (see
Note 9 – Fair Value Measurements and Guarantees
of Notes to Consolidated Financial Statements). Impairments recognized in 2015 relate primarily to surplus equipment write-offs.
Operating income (loss)
changed unfavorably primarily related to the impairments of long-lived assets in 2016 and the absence of insurance proceeds received in the second quarter of 2015, partially offset by lower operating and maintenance and general and administrative expenses primarily associated with cost containment efforts.
Interest expense
increased due to higher
Interest incurred
of
$24 million primarily attributable to new debt issuances in 2016 and 2015, partially offset by lower interest due to 2015 and 2016 debt retirements. (See
Note 8 – Debt and Banking Arrangements
of Notes to Consolidated Financial Statements.)
Other (income) expense – net
below
Operating income (loss)
changed unfavorably primarily due to the absence of a $14 million gain on early debt retirement in 2015 and a decrease in allowance for equity funds used during construction (AFUDC) due to decreased spending on Constitution.
Management’s Discussion and Analysis (Continued)
Provision (benefit) for income taxes
favorable change includes a foreign tax benefit associated with our Canadian operations. See Note 6 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both periods.
Net income attributable to noncontrolling interests
decreased primarily due to the reduction of Gulfstar One earnings.
Six months ended
June 30, 2016
vs. six months ended
June 30, 2015
Service revenues
increased primarily due to expansion projects placed in service in 2015 and 2016, including new transportation and fractionation revenue associated with Williams’ Horizon liquids extraction plant. These increases were partially offset by a decrease related to lower volumes attributable to suspending operations in order to facilitate the tie-in of the Gunflint expansion and a decrease in storage revenues at Transco.
Product sales
decreased due to reduced marketing revenues primarily associated with lower prices across most products and lower volumes, as well as a reduction in revenues from our equity NGLs primarily related to a decrease in NGL prices. Partially offsetting these decreases are higher olefin sales from our Geismar plant reflecting increased volumes as a result of the plant operating at higher production levels in 2016, partially offset by lower olefin sales from our RGP Splitter and our Canadian operations associated with lower volumes and per-unit sales prices.
The decrease in
Product costs
includes lower marketing purchases primarily associated with a decline in per-unit costs across most products and lower volumes, reduced natural gas purchases associated with the production of equity NGLs primarily due to lower natural gas prices, and lower olefin feedstock purchases. The decline in olefin feedstock purchases is primarily associated with lower per-unit per unit feedstock costs and volumes at the RGP Splitter, partially offset by an increase in olefin feedstock purchases at our Geismar plant reflecting increased volumes resulting from higher production levels in 2016.
Operating and maintenance expenses
decreased due to lower labor-related and outside service costs resulting from our first-quarter 2016 workforce reductions and cost containment efforts, as well as the absence of ACMP transition-related costs recognized in 2015, partially offset by $14 million of severance and related costs recognized in 2016 associated with workforce reductions and higher general maintenance and pipeline testing at Transco.
Depreciation and amortization expenses
increased primarily due to depreciation on new Transco projects placed in service.
Selling, general, and administrative expenses
decreased primarily due to the absence of ACMP merger and transition- related costs recognized in 2015 and lower labor-related costs resulting from our first-quarter 2016 workforce reductions and cost containment efforts, partially offset by $11 million of severance and related costs recognized in 2016 associated with workforce reductions.
Net insurance recoveries – Geismar Incident
decreased reflecting the absence of $126 million of insurance proceeds received in the second quarter of 2015.
Impairment of long-lived assets
reflects 2016 impairments of our Canadian operations and certain Mid-Continent assets. (See
Note 9 – Fair Value Measurements and Guarantees
of Notes to Consolidated Financial Statements). Impairments recognized in 2015 relate primarily to surplus equipment write-offs.
Other (income) expense – net
within
Operating income (loss)
includes an unfavorable change primarily related to losses incurred on foreign currency transactions and the remeasurement of U.S. dollar denominated current assets and liabilities within our Canadian operations.
Operating income (loss)
changed unfavorably primarily due impairments in 2016, the absence of insurance proceeds received in the second quarter of 2015, and higher depreciation expenses related to new projects placed in service. These decreases were partially offset by higher olefin margins related to the Geismar plant operating at higher production levels in 2016, lower costs related to the merger and integration of ACMP, and lower operating and maintenance and general and administrative expenses partly associated with cost containment efforts.
Management’s Discussion and Analysis (Continued)
Equity earnings (losses)
changed favorably primarily due to a $26 million increase at Discovery related to the completion of the Keathley Canyon Connector in the first quarter of 2015. Additionally, OPPL increased $10 million, UEOM contributed $9 million, and Laurel Mountain contributed $9 million.
Impairment of equity-method investments
reflects first-quarter 2016 impairment charges associated with certain equity-method investments. (See
Note 4 – Investing Activities
of Notes to Consolidated Financial Statements.)
Interest expense
increased due to higher
Interest incurred
of
$55 million primarily attributable to new debt issuances in 2016 and 2015 as well as lower
Interest capitalized
of $10 million mostly related to construction projects that have been placed into service, partially offset by lower interest due to 2015 and 2016 debt retirements. (See
Note 8 – Debt and Banking Arrangements
of Notes to Consolidated Financial Statements.)
Other (income) expense – net
below
Operating income (loss)
changed unfavorably primarily due to the absence of a $14 million gain on early debt retirement in 2015 and a decrease in AFUDC due to decreased spending on Constitution.
Provision (benefit) for income taxes
favorable change includes a foreign tax benefit associated with our Canadian operations. See Note 6 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both periods.
Net income attributable to noncontrolling interests
decreased primarily due to the reduction of Gulfstar One earnings.
Period-Over-Period Operating Results – Segments
We evaluate segment operating performance based upon
Modified EBITDA
.
Note 11 – Segment Disclosures
of Notes to Consolidated Financial Statements includes a reconciliation of this non-GAAP measure to
Net income (loss)
. Management uses
Modified EBITDA
because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of our assets.
Modified EBITDA
should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP.
Central
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(Millions)
|
Service revenues
|
$
|
258
|
|
|
$
|
265
|
|
|
$
|
513
|
|
|
$
|
517
|
|
|
|
|
|
|
|
|
|
Segment costs and expenses
|
(88
|
)
|
|
(112
|
)
|
|
(196
|
)
|
|
(239
|
)
|
Impairment of long-lived assets
|
(48
|
)
|
|
(3
|
)
|
|
(47
|
)
|
|
(3
|
)
|
Proportional Modified EBITDA of equity-method investments
|
12
|
|
|
10
|
|
|
21
|
|
|
18
|
|
Central Modified EBITDA
|
$
|
134
|
|
|
$
|
160
|
|
|
$
|
291
|
|
|
$
|
293
|
|
Three months ended
June 30, 2016
vs. three months ended
June 30, 2015
Modified EBITDA
decreased primarily due to a $48 million impairment of certain Mid-Continent gathering assets in 2016, partially offset by a decrease in
Segment costs and expenses
related to the decrease in labor-related and outside service costs resulting from our first quarter workforce reductions and ongoing cost containment efforts.
Service revenues
decreased slightly primarily due to lower volumes in the Barnett and Anadarko areas, partially offset by higher rates and volumes in the Haynesville area primarily attributable to a new contract executed in 2015.
Segment costs and expenses
decreased primarily due to a decrease in labor-related and outside service costs resulting from our first quarter workforce reductions and ongoing cost containment efforts, as well as the absence of ACMP
Management’s Discussion and Analysis (Continued)
Merger and transition expenses in 2016.
Impairment of long-lived assets
increased primarily due to a $48 million impairment of certain Mid-Continent gathering assets in 2016.
Six months ended
June 30, 2016
vs. six months ended
June 30, 2015
Modified EBITDA
decreased slightly primarily due to a $48 million impairment of certain Mid-Continent gathering assets in 2016, offset by a decrease in
Segment costs and expenses
related to lower labor-related and outside service costs resulting from our first quarter workforce reductions and ongoing cost containment efforts as well as a decrease in ACMP Merger and transition expenses in 2016.
Segment costs and expenses
decreased primarily due to a $38 million decrease in ACMP Merger and transition expenses and lower labor-related and outside service costs resulting from our first quarter workforce reductions and ongoing cost containment efforts.
Impairment of long-lived assets
increased primarily due to a $48 million impairment of certain Mid-Continent gathering assets in 2016.
Northeast G&P
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(Millions)
|
Service revenues
|
$
|
208
|
|
|
$
|
216
|
|
|
$
|
419
|
|
|
$
|
412
|
|
Product sales
|
33
|
|
|
35
|
|
|
57
|
|
|
73
|
|
Segment revenues
|
241
|
|
|
251
|
|
|
476
|
|
|
485
|
|
|
|
|
|
|
|
|
|
Product costs
|
(34
|
)
|
|
(33
|
)
|
|
(55
|
)
|
|
(70
|
)
|
Other segment costs and expenses
|
(83
|
)
|
|
(108
|
)
|
|
(176
|
)
|
|
(193
|
)
|
Impairment of long-lived assets
|
(4
|
)
|
|
(21
|
)
|
|
(8
|
)
|
|
(24
|
)
|
Proportional Modified EBITDA of equity-method investments
|
96
|
|
|
94
|
|
|
193
|
|
|
170
|
|
Northeast G&P Modified EBITDA
|
$
|
216
|
|
|
$
|
183
|
|
|
$
|
430
|
|
|
$
|
368
|
|
Three months ended June 30, 2016
vs.
three months ended June 30, 2015
Modified EBITDA
increased primarily due to lower operating and maintenance expenses and lower impairment charges.
Service revenues
decreased due to a decline in gathering and processing fee-based revenues from our Ohio Valley Midstream operations associated with producer shut-ins and lower rates, partially offset by an increase in gathering revenues in the Susquehanna Supply Hub primarily due to higher volumes.
Other segment costs and expenses
decreased primarily due to a $20 million decrease in operating and maintenance expenses primarily resulting from lower costs related to supplies, outside services, and repairs.
Impairment of long-lived assets
changed favorably primarily due to the absence of $20 million of impairment charges associated with certain surplus equipment within our Ohio Valley Midstream business in 2015. (See
Note 9 – Fair Value Measurements and Guarantees
of Notes to Consolidated Financial Statements.)
Management’s Discussion and Analysis (Continued)
Six months ended June 30, 2016
vs.
six months ended June 30, 2015
Modified EBITDA
increased primarily due to lower operating and maintenance expenses and lower impairment charges, as well as improvements in
Proportional Modified EBITDA of equity-method investments
driven by higher volumes and the absence of certain impairments from 2015.
Service revenues
include an increase in Utica Shale gathering revenues primarily due to growth in volumes associated with new well connects and also an increase in Susquehanna Supply Hub gathering revenues resulting from fewer producer shut-ins associated with improved regional natural gas prices. In addition, fee-based revenues increased due to increased reimbursements for management services from certain equity-method investees, partially offset by a decline from our Ohio Valley Midstream operations associated with producer shut-ins and lower rates.
Product sales
decreased primarily due to an $18 million decline in marketing sales in the Ohio Valley Midstream business, comprised primarily of a $14 million decline associated with a 22 percent decrease in non-ethane volumes and a $6 million decrease reflecting a 12 percent decline in non-ethane per-unit marketing sales prices. The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above as
Product costs
.
Other segment costs and expenses
decreased primarily due to a $19 million decrease in operating and maintenance expenses primarily resulting from lower costs related to supplies, outside services, and repairs.
Impairment of long-lived assets
changed favorably primarily due to the absence of $20 million of impairment charges associated with certain surplus equipment within our Ohio Valley Midstream business in 2015. (See
Note 9 – Fair Value Measurements and Guarantees
of Notes to Consolidated Financial Statements.)
Proportional Modified EBITDA of equity-method investments
improved primarily due to a $12 million increase from UEOM associated with higher volumes and an increase in our ownership percentage, a $12 million increase from Caiman II resulting from higher volumes due to assets placed into service in 2015, and a $10 million increase from Laurel Mountain primarily due to the absence of impairments incurred during 2015. These increases were partially offset by a $12 million decrease from Appalachian Midstream Investments primarily due to lower fee revenues driven by lower rates.
Atlantic-Gulf
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(Millions)
|
Service revenues
|
$
|
448
|
|
|
$
|
466
|
|
|
$
|
914
|
|
|
$
|
924
|
|
Product sales
|
105
|
|
|
125
|
|
|
174
|
|
|
246
|
|
Segment revenues
|
553
|
|
|
591
|
|
|
1,088
|
|
|
1,170
|
|
|
|
|
|
|
|
|
|
Product costs
|
(97
|
)
|
|
(119
|
)
|
|
(161
|
)
|
|
(232
|
)
|
Other segment costs and expenses
|
(167
|
)
|
|
(150
|
)
|
|
(327
|
)
|
|
(319
|
)
|
Impairment of long-lived assets
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
Proportional Modified EBITDA of equity-method investments
|
68
|
|
|
67
|
|
|
134
|
|
|
105
|
|
Atlantic-Gulf Modified EBITDA
|
$
|
357
|
|
|
$
|
389
|
|
|
$
|
733
|
|
|
$
|
724
|
|
|
|
|
|
|
|
|
|
NGL margin
|
$
|
7
|
|
|
$
|
5
|
|
|
$
|
12
|
|
|
$
|
12
|
|
Three months ended June 30, 2016
vs.
three months ended June 30, 2015
Modified EBITDA
decreased primarily due to lower service revenues and higher segment costs and expenses.
Service revenues
decreased primarily due to a $32 million decrease in Eastern Gulf Coast fee revenues primarily due to lower volumes, including the impact of suspending operations in order to facilitate the tie-in of the Gunflint
Management’s Discussion and Analysis (Continued)
expansion at Gulfstar One. This decrease was partially offset by a $19 million increase in Transco’s natural gas transportation fee revenues primarily associated with expansion projects placed in service in 2015 and 2016.
Product sales
and
Product costs
decreased primarily due to a $16 million decrease in system management gas sales from Transco. System management gas sales are offset in
Product costs
and, therefore, have no impact on
Modified EBITDA.
Other segment costs and expenses
increased due to higher operating expenses primarily related to higher contract services for hydrostatic testing, safety, and general maintenance at Transco. In addition, project development costs are higher as we discontinued capitalization of these costs at Constitution beginning in April 2016, and equity AFUDC also changed unfavorably associated with a decrease in spending on Constitution. These increases were partially offset by lower general and administrative expenses driven by first-quarter 2016 workforce reductions and ongoing cost containment efforts.
Six months ended June 30, 2016
vs.
six months ended June 30, 2015
Modified EBITDA
increased primarily due to higher earnings at Discovery due to the completion of the Keathley Canyon Connector in the first quarter of 2015, partially offset by lower service revenues and higher segment costs and expenses.
Service revenues
decreased primarily due to a $42 million decrease in Eastern Gulf Coast fee revenues primarily related to lower volumes, including the impact of suspending operations in order to facilitate the tie-in of the Gunflint expansion at Gulfstar One and 2016 producers’ operational issues, a $15 million decrease in Transco’s storage revenue related to potential refunds associated with a ruling received in certain rate case litigation in 2016, and an $8 million decrease in Western Gulf Coast fee revenues primarily related to lower volumes associated with producer maintenance in 2016 and natural declines in certain production areas. These decreases are partially offset by a $55 million increase in Transco’s natural gas transportation fee revenues primarily associated with expansion projects placed in service in 2015 and 2016, partially offset by lower volume-based transportation services revenues.
Product sales
decreased primarily due to:
|
|
•
|
A $47 million decrease in crude oil and NGL marketing revenues. Crude oil marketing sales decreased $27 million associated with 27 percent lower crude oil per barrel sales prices and 6 percent lower volumes. NGL marketing sales decreased $20 million associated with 17 percent lower non-ethane per-unit sales prices and 17 percent lower non-ethane sales volumes. These changes in marketing revenues are offset by similar changes in marketing purchases;
|
|
|
•
|
A $22 million decrease in system management gas sales from Transco. System management gas sales are offset in
Product costs
and, therefore, have no impact on
Modified EBITDA.
|
Product costs
decreased primarily due to:
|
|
•
|
A $51 million decrease in marketing purchases (substantially offset in
Product sales
);
|
|
|
•
|
A $22 million decrease in system management gas costs (offset in
Product sales
)
.
|
Other segment costs and expenses
includes higher project development costs as we discontinued capitalization of these costs at Constitution beginning in April 2016, and equity AFUDC also changed unfavorably associated with a decrease in spending on Constitution. In addition, operating expenses increased primarily due to higher contract services for hydrostatic testing, safety, and general maintenance and operating taxes at Transco, and $8 million of first-quarter 2016 severance and related costs recognized associated with workforce reductions. These increases are partially offset by $14 million lower general and administrative expenses driven by first-quarter 2016 workforce reductions and ongoing cost containment efforts, as well as a favorable change in the deferral of asset retirement obligation-related depreciation to a regulatory asset.
Management’s Discussion and Analysis (Continued)
The increase in
Proportional Modified EBITDA of equity-method investments
is primarily due to a $28 million increase from Discovery primarily due to higher fee revenues attributable to the completion of the Keathley Canyon Connector in the first quarter of 2015.
West
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(Millions)
|
Service revenues
|
$
|
255
|
|
|
$
|
258
|
|
|
$
|
518
|
|
|
$
|
520
|
|
Product sales
|
78
|
|
|
68
|
|
|
130
|
|
|
132
|
|
Segment revenues
|
333
|
|
|
326
|
|
|
648
|
|
|
652
|
|
|
|
|
|
|
|
|
|
Product costs
|
(43
|
)
|
|
(37
|
)
|
|
(74
|
)
|
|
(73
|
)
|
Other segment costs and expenses
|
(131
|
)
|
|
(139
|
)
|
|
(258
|
)
|
|
(268
|
)
|
Impairment of long-lived assets
|
(1
|
)
|
|
—
|
|
|
(3
|
)
|
|
—
|
|
West Modified EBITDA
|
$
|
158
|
|
|
$
|
150
|
|
|
$
|
313
|
|
|
$
|
311
|
|
|
|
|
|
|
|
|
|
NGL margin
|
$
|
33
|
|
|
$
|
29
|
|
|
$
|
53
|
|
|
$
|
54
|
|
Three months ended June 30, 2016
vs.
three months ended June 30, 2015
Modified EBITDA
increased due to reduced expenses associated with workforce reductions, lower major maintenance and operating charges and increased NGL margins associated with lower gas prices and higher volumes.
Service revenues
decreased primarily due to a $7 million reduction associated with reduced gathering volumes in the Piceance region and reduced gathering rates and volumes in the Four Corners region. Partially offsetting these reductions are increased gathering and processing revenues of $6 million associated with higher gathering and processing rates in our Niobrara operations.
Product sales
increased primarily due to a $6 million increase in revenues associated with our equity NGLs due to increased ethane and non-ethane volumes. Additionally, NGL marketing revenue increased $6 million due to increased non-ethane volumes (offset in
Product costs
).
Product costs
increased primarily due to a $6 million increase in NGL marketing purchases (offset in
Product sales
), partially offset by a 25 percent decline in the per-unit cost of natural gas.
Other segment costs and expenses
decreased due to lower labor-related costs driven by first-quarter 2016 workforce reductions and lower major maintenance and operating charges.
Six months ended June 30, 2016
vs.
six months ended June 30, 2015
Modified EBITDA
increased due to lower costs associated with workforce reductions and major maintenance and operating charges. Partially offsetting these items were reductions in revenues.
Service revenues
decreased due to a $12 million reduction associated with reduced gathering volumes in the Piceance region and reduced gathering rates and volumes in the Four Corners region. Offsetting these reductions is increased gathering and processing revenues of $12 million associated with higher gathering and processing rates in our Niobrara operations.
Product sales
decreased primarily due to a $5 million decrease in revenues from our equity NGLs associated with 18 percent lower average per-unit non-ethane sales prices. Other product sales declined approximately $4 million. Partially offsetting these reductions is increased marketing revenues of $7 million due to increased non-ethane volumes (offset in
Product costs).
Management’s Discussion and Analysis (Continued)
Product costs
increased slightly primarily due to a $7 million increase in NGL marketing purchases (offset in
Product sales)
partially offset by a $4 million reduction associated with the production of equity NGLs primarily due to lower natural gas prices.
Other segment costs and expenses
decreased due to lower labor-related costs driven by first-quarter 2016 workforce reductions and lower major maintenance and operating charges.
NGL & Petchem Services
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
(Millions)
|
Service revenues
|
$
|
54
|
|
|
$
|
34
|
|
|
$
|
92
|
|
|
$
|
66
|
|
Product sales
|
463
|
|
|
513
|
|
|
869
|
|
|
956
|
|
Segment revenues
|
517
|
|
|
547
|
|
|
961
|
|
|
1,022
|
|
|
|
|
|
|
|
|
|
Product costs
|
(387
|
)
|
|
(448
|
)
|
|
(712
|
)
|
|
(872
|
)
|
Other segment costs and expenses
|
(63
|
)
|
|
(76
|
)
|
|
(146
|
)
|
|
(132
|
)
|
Net insurance recoveries – Geismar Incident
|
—
|
|
|
126
|
|
|
—
|
|
|
126
|
|
Impairment of long-lived assets
|
(343
|
)
|
|
—
|
|
|
(343
|
)
|
|
—
|
|
Proportional Modified EBITDA of equity-method investments
|
15
|
|
|
9
|
|
|
32
|
|
|
20
|
|
NGL & Petchem Services Modified EBITDA
|
$
|
(261
|
)
|
|
$
|
158
|
|
|
$
|
(208
|
)
|
|
$
|
164
|
|
|
|
|
|
|
|
|
|
Olefins margin
|
$
|
74
|
|
|
$
|
61
|
|
|
$
|
145
|
|
|
$
|
70
|
|
NGL margin
|
1
|
|
|
2
|
|
|
6
|
|
|
11
|
|
Three months ended June 30, 2016
vs.
three months ended June 30, 2015
Modified EBITDA
decreased primarily due to the impairment of our Canadian operations held for sale and the absence of insurance proceeds related to the Geismar Incident that we received in 2015, partially offset by higher service revenues associated with the expansion of our Redwater facilities, and higher olefin margins. The increase in olefin margins is comprised of a $15 million increase at the RGP Splitter due to favorable feedstock prices, a $12 million increase at Geismar due to higher production levels in 2016 than in 2015, partially offset by unfavorable margins in Canada.
Service revenues
improved primarily due to the expansion of our Redwater facilities in March 2016 to provide transportation and fractionation services associated with the Williams Horizon liquids extraction plant.
Product sales
decreased
primarily due to:
|
|
•
|
A $22 million decrease in marketing revenues primarily due to lower non-ethane prices (substantially offset by lower
Product costs
);
|
|
|
•
|
A $15 million decrease in Canadian NGL sales revenues primarily due to lower volumes, including $10 million lower ethane volumes due primarily to the shut-down and evacuation of our liquids extraction plant because of wild fires in the Fort McMurray area during May and June, as well as a longer period of planned maintenance in 2016;
|
|
|
•
|
An $11 million decrease in olefin sales reflecting a $22 million decrease from our RGP Splitter and a $17 million decrease from our Canadian operations, partially offset by $28 million in higher sales from our Geismar plant. The decrease in sales for Canada and the RGP Splitter are primarily due to lower volumes, as well as 20 percent lower propylene prices at the RGP Splitter. Canadian volumes declined due to previously discussed operational issues and longer periods of planned maintenance. The increase in sales at the Geismar plant is
|
Management’s Discussion and Analysis (Continued)
due to a $62 million increase in volumes as the plant is operating at higher production levels in 2016 than in 2015, partially offset by $34 million in primarily lower ethylene prices.
Product costs
decreased primarily due to:
|
|
•
|
An $18 million decrease in marketing product costs primarily due to lower non-ethane per-unit costs (more than offset by lower
Product sales
);
|
|
|
•
|
A $14 million decrease in NGL product costs reflecting lower volumes and a decline in the price of natural gas associated with the production of equity NGLs;
|
|
|
•
|
A $24 million decrease in olefin feedstock purchases primarily comprised of $36 million lower costs at our RGP Splitter, partially offset by $16 million in higher cost at our Geismar plant. The decrease in costs at our RGP Splitter is due to $24 million in lower per-unit costs and $12 million in lower volumes. The increase in costs at our Geismar plant is comprised of $21 million in higher volumes resulting from the plant’s higher production levels in 2016 than in 2015, partially offset by $5 million in lower ethane per-unit prices.
|
The decrease in
Other segment costs and expenses
is primarily due to lower contract services and labor-related expenses reflecting higher costs incurred in 2015 associated with the start-up of the Geismar plant, as well as certain reduced maintenance activities at our storage facilities in 2016.
Net insurance recoveries - Geismar Incident
decreased $126 million as insurance proceeds were received in 2015, while no proceeds were received in 2016.
Impairment of long-lived assets
reflects the second quarter 2016 impairment of our Canadian operations as these assets are held for sale as of June 30, 2016 (see
Note 9 – Fair Value Measurements and Guarantees
).
Six months ended June 30, 2016
vs.
six months ended June 30, 2015
Modified EBITDA
decreased in 2016 compared to 2015 primarily due to the impairment of our Canadian operations held for sale and lower insurance proceeds related to the Geismar Incident, partially offset by higher olefin margins driven by higher production levels at the Geismar facility in 2016 than in 2015 and higher service revenues associated with the expansion of our Redwater facilities.
Service revenues
improved primarily due the expansion of our Redwater facilities in March 2016 to provide transportation and fractionation services associated with the Williams Horizon liquids extraction plant.
Product sales
decreased primarily due to:
|
|
•
|
A $111 million decrease in marketing revenues primarily due to lower prices across all products, partially offset by higher natural gas, polymer-grade propylene, and non-ethane volumes (offset in
Product costs
).
|
|
|
•
|
A $26 million decrease in Canadian NGL sales revenues comprised of a $17 million decrease associated with lower volumes and a $9 million decrease associated with lower prices across all products. The lower volumes are associated with previously discussed wild fires in the area and longer periods of planned maintenance, while prices reflect 22 percent lower ethane prices and 52 percent lower propane prices.
|
|
|
•
|
A $54 million increase in olefin sales comprised of a $124 million increase from our Geismar plant that returned to service in late March 2015, partially offset by a $41 million decrease from our RGP Splitter and a $29 million decrease in our Canadian operations. The increase at Geismar includes $213 million associated with increased volumes as a result of the plant operating at higher production levels in 2016 than when production resumed in March 2015, partially offset by $89 million in lower per-unit sales prices. The decrease in olefin sales associated with the RGP Splitter and our Canadian operations are associated with both lower volumes and lower per-unit sales prices.
|
Management’s Discussion and Analysis (Continued)
Product costs
decreased primarily due to:
|
|
•
|
A $111 million decrease in marketing product costs primarily due to lower per-unit costs associated with all products, partially offset by higher natural gas, polymer-grade propylene, and non-ethane volumes (offset by lower
Product sales
).
|
|
|
•
|
A $21 million decrease in NGL product costs due to a $13 million decrease in primarily propane and ethane volumes and an $8 million decrease reflecting the decline in the price of natural gas associated with the production of equity NGLs.
|
|
|
•
|
A $21 million decrease in olefin feedstock purchases is primarily comprised of $67 million in lower purchases at our RGP splitter, partially offset by $52 million of higher purchases due to increased volumes at our Geismar plant resulting from higher productions levels. The lower costs at the RGP splitter are comprised of $51 million in lower per-unit feedstock costs and $16 million in lower propylene volumes.
|
The increase in
Other segment costs and expenses
includes a $15 million unfavorable change in foreign currency exchange that primarily relates to losses on foreign currency transactions and the remeasurement of U.S. dollar denominated current assets and liabilities within our Canadian operations.
Net insurance recoveries - Geismar Incident
decreased $126 million as insurance proceeds were received in 2015, while no proceeds were received in 2016.
Impairment of long-lived assets
reflects the 2016 impairment of our Canadian operations as these assets are held for sale as of June 30, 2016 (see
Note 9 – Fair Value Measurements and Guarantees
).
The increase in
Proportional modified EBITDA of equity-method investments
reflects a $10 million improvement at OPPL due primarily to higher Bakken transportation volumes.
Management’s Discussion and Analysis (Continued)
Management’s Discussion and Analysis of Financial Condition and Liquidity
Outlook
We continue to transition to an overall business mix that is increasingly fee-based. Although our cash flows are impacted by fluctuations in energy commodity prices, that impact is somewhat mitigated by certain of our cash flow streams that are not directly impacted by short-term commodity price movements, including:
|
|
•
|
Firm demand and capacity reservation transportation revenues under long-term contracts;
|
|
|
•
|
Fee-based revenues from certain gathering and processing services.
|
However, we are indirectly exposed to longer duration depressed energy commodity prices and the related impact on drilling activities and volumes available for gathering and processing services.
We believe we have, or have access to, the financial resources and liquidity necessary to meet our requirements for working capital, capital and investment expenditures, unitholder distributions, and debt service payments while maintaining a sufficient level of liquidity. In particular, as previously discussed in Company Outlook, our expected growth capital and investment expenditures total approximately $1.9 billion in 2016. We retain the flexibility to adjust planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities. We expect proceeds from the planned sale of our Canadian operations during 2016.
Liquidity
Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2016. Our internal and external sources of consolidated liquidity include:
|
|
•
|
Cash and cash equivalents on hand;
|
|
|
•
|
Cash generated from operations, including cash distributions from our equity-method investees;
|
|
|
•
|
Cash proceeds from issuances of debt and/or equity securities, including issuances under our equity distribution agreement;
|
|
|
•
|
New distribution reinvestment program (DRIP);
|
|
|
•
|
Use of our credit facilities and/or commercial paper program;
|
|
|
•
|
Transco’s January 2016 debt issuance described further below;
|
|
|
•
|
Proceeds from planned sale of Canadian operations.
|
We anticipate our more significant uses of cash to be:
|
|
•
|
Working capital requirements;
|
|
|
•
|
Maintenance and expansion capital and investment expenditures;
|
|
|
•
|
Interest on our long-term debt;
|
|
|
•
|
Repayment of current debt maturities;
|
|
|
•
|
Quarterly distributions to our unitholders and general partner, including IDRs.
|
Management’s Discussion and Analysis (Continued)
We expect to implement a DRIP in the third quarter of 2016. Williams has announced that it plans to reinvest approximately $1.7 billion in us through 2017. Williams plans to reinvest $500 million in 2016, including $250 million in the third quarter via a private purchase of common units, with the balance reinvested via the DRIP. The remaining $1.2 billion is planned to be reinvested in 2017 via the DRIP.
Potential risks associated with our planned levels of liquidity discussed above include those previously discussed in Company Outlook.
As of
June 30, 2016
, we had a working capital deficit (current liabilities, inclusive of
$196 million
in
Commercial paper
outstanding and
$786 million
in
Long-term debt due within one year
, in excess of current assets) of $529 million. Our available liquidity is as follows:
|
|
|
|
|
Available Liquidity
|
June 30, 2016
|
|
(Millions)
|
Cash and cash equivalents
|
$
|
101
|
|
Capacity available under our $3.5 billion credit facility, less amounts outstanding under our $3 billion commercial paper program (1)
|
1,879
|
|
Capacity available under our short-term credit facility (2)
|
150
|
|
|
$
|
2,130
|
|
|
|
(1)
|
In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. Through
June 30, 2016
, the highest amount outstanding under our commercial paper program and credit facility during 2016 was $1.856 billion. At
June 30, 2016
, we were in compliance with the financial covenants associated with this credit facility. See
Note 8 – Debt and Banking Arrangements
of Notes to Consolidated Financial Statements for additional information on our commercial paper program. Borrowing capacity available under our $3.5 billion credit facility as of July 29, 2016, was $1.888 billion.
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(2)
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Borrowing capacity available under this facility as of July 29, 2016, was $150 million. This facility expires on August 24, 2016.
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On September 24, 2015, we received a special distribution of $396 million from Gulfstream reflecting our proportional share of the proceeds from new debt issued by Gulfstream. The new debt was issued to refinance Gulfstream’s debt maturities. Subsequently, we contributed $248 million and $148 million to Gulfstream for our proportional share of amounts necessary to fund debt maturities of $500 million due on November 1, 2015, and $300 million due on June 1, 2016, respectively.
Incentive Distribution Rights
Williams has agreed to temporarily waive incentive distributions of approximately $2 million per quarter in connection with our acquisition of 13 percent additional interest in UEOM on June 10, 2015. The waiver will continue through the quarter ending September 30, 2017.
Williams was required to pay us a $428 million termination fee associated with the Termination Agreement (as described in
Note 1 – General, Description of Business, and Basis of Presentation
of Notes to Consolidated Financial Statements), which settled through a reduction of quarterly incentive distributions payable to Williams (such reduction not to exceed $209 million per quarter). The November 2015, February 2016, and May 2016 distributions to Williams were reduced by $209 million, $209 million, and $10 million, respectively, related to this termination fee.
Debt Issuances and Retirements
Northwest Pipeline retired $175 million of 7 percent senior unsecured notes that matured on June 15, 2016.
Transco retired $200 million of 6.4 percent senior unsecured notes that matured on April 15, 2016.
Management’s Discussion and Analysis (Continued)
On January 22, 2016, Transco issued $1 billion of 7.85 percent senior unsecured notes due 2026 to investors in a private debt placement. Transco used the net proceeds from the offering to repay debt and to fund capital expenditures.
Shelf Registration
In February 2015, we filed a shelf registration statement, as a well-known seasoned issuer and we also filed a shelf registration statement for the offer and sale from time to time of common units representing limited partner interests in us having an aggregate offering price of up to $1 billion. These sales are to be made over a period of time and from time to time in transactions at prices which are market prices prevailing at the time of sale, prices related to market price, or at negotiated prices. Such sales are to be made pursuant to an equity distribution agreement between us and certain banks who may act as sales agents or purchase for their own accounts as principals. From February 2015 through
June 30, 2016
, we have received net proceeds of approximately $59 million from equity issued under this registration.
Distributions from Equity-Method Investees
The organizational documents of entities in which we have an equity-method investment generally require distribution of their available cash to their members on a quarterly basis. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses.
Credit Ratings
Our ability to borrow money is impacted by our credit ratings. Our current ratings are as follows:
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Rating Agency
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Outlook
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Senior Unsecured
Debt Rating
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Corporate Credit Rating
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S&P Global Ratings
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Negative
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BBB-
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BBB-
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Moody’s Investors Service
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Negative
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Baa3
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N/A
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Fitch Ratings
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Stable
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BBB-
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N/A
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As of
June 30, 2016
, we estimated that a downgrade to a rating below investment grade could require us to post up to $455 million in additional collateral with third parties.
Cash Distributions to Unitholders
The Board of Directors of our general partner declared a cash distribution of
$0.85
per common unit on July 26, 2016
, to be paid on August 12, 2016, to unitholders of record at the close of business on August 5, 2016.
Sources (Uses) of Cash
The following table summarizes the increase (decrease) in cash and cash equivalents for each of the periods presented:
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Six Months Ended
June 30,
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2016
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2015
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(Millions)
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Net cash provided (used) by:
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Operating activities
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$
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1,665
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$
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1,493
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Financing activities
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(971
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)
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344
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Investing activities
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(682
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)
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(1,822
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)
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Increase (decrease) in cash and cash equivalents
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$
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12
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$
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15
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Operating activities
The factors that determine operating activities are largely the same as those that affect
Net income (loss)
, with the exception of noncash items such as
Depreciation and amortization
,
Impairment of equity-method investments
, and
Management’s Discussion and Analysis (Continued)
Impairment of and net (gain) loss on sale of Property, plant, and equipment
.
Our
Net cash provided (used) by operating activities
in 2016 increased from 2015 primarily due to net favorable changes in operating working capital and cash received related to Hillabee (see Expansion Projects).
Financing activities
Significant transactions include:
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•
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$304 million
in
2016
of net payments of commercial paper;
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•
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$942 million
in
2015
of net proceeds from commercial paper;
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•
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$998 million in
2016
and $2.992 billion in
2015
net received from our debt offerings;
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•
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$375 million in
2016
and $1.533 billion in
2015
paid on our debt retirements;
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•
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$1.94 billion in
2016
and $1.832 billion in
2015
received from our credit facility borrowings;
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•
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$1.825 billion in
2016
and $2.472 billion in
2015
paid on our credit facility borrowings;
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•
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$1.231 billion, including $808 million to Williams, in
2016
and $1.45 billion, including $1.03 billion to Williams, in
2015
related to quarterly cash distributions paid to limited partner unitholders and the general partner;
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•
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$148 million in
2016
paid in contribution to Gulfstream for repayment of debt;
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•
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$22 million in
2016
and $57 million in
2015
received in contributions from noncontrolling interests.
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Investing activities
Significant transactions include:
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•
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Capital expenditures of
$981 million
in
2016
and $1.45 billion in
2015
;
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•
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$112 million in 2015 paid to purchase a gathering system comprised of approximately 140 miles of pipeline and a sour gas compression facility in the Eagle Ford shale;
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•
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Purchases of and contributions to our equity-method investments of
$122 million
in
2016
and
$483 million
in
2015
;
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•
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Distributions from unconsolidated affiliates in excess of cumulative earnings of
$261 million
in
2016
and
$122 million
in
2015
.
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Off-Balance Sheet Arrangements and Guarantees of Debt or Other Commitments
We have various other guarantees and commitments which are disclosed in
Note 2 – Variable Interest Entities
,
Note 8 – Debt and Banking Arrangements
,
Note 9 – Fair Value Measurements and Guarantees
, and
Note 10 – Contingent Liabilities
of Notes to Consolidated Financial Statements. We do not believe these guarantees and commitments or the possible fulfillment of them will prevent us from meeting our liquidity needs.
Item 3