Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Feb. 17, 2017 | Jun. 30, 2016 | |
Entity Information [Line Items] | |||
Entity Registrant Name | Williams Partners L.P. | ||
Entity Central Index Key | 1,483,096 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2016 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2,016 | ||
Document Fiscal Period Focus | FY | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Partnership Units Outstanding | 955,446,491 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 20,385,447,679 | ||
Class B Units [Member] | |||
Entity Information [Line Items] | |||
Entity Partnership Units Outstanding | 17,065,816 |
Consolidated Statement of Compr
Consolidated Statement of Comprehensive Income (Loss) - USD ($) shares in Thousands, $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Revenues: | |||
Service revenues | $ 5,173 | $ 5,135 | $ 3,888 |
Product sales | 2,318 | 2,196 | 3,521 |
Total revenues | 7,491 | 7,331 | 7,409 |
Costs and expenses: | |||
Product costs | 1,728 | 1,779 | 3,016 |
Operating and maintenance expenses | 1,548 | 1,625 | 1,277 |
Depreciation and amortization expenses | 1,720 | 1,702 | 1,151 |
Selling, general, and administrative expenses | 630 | 684 | 633 |
Impairment of goodwill (Note 17) | 0 | 1,098 | 0 |
Impairment of certain assets (Note 17) | 457 | 145 | 52 |
Net insurance recoveries – Geismar Incident | (7) | (126) | (232) |
Other (income) expense – net | 118 | 41 | (97) |
Total costs and expenses | 6,194 | 6,948 | 5,800 |
Operating income (loss) | 1,297 | 383 | 1,609 |
Equity earnings (losses) | 397 | 335 | 228 |
Impairment of equity-method investments (Note 17) | (430) | (1,359) | 0 |
Other investing income (loss) – net | 29 | 2 | 2 |
Interest incurred | (949) | (864) | (683) |
Interest capitalized | 33 | 53 | 121 |
Other income (expense) – net | 62 | 93 | 36 |
Income (loss) before income taxes | 439 | (1,357) | 1,313 |
Provision (benefit) for income taxes | (80) | 1 | 29 |
Net income (loss) | 519 | (1,358) | 1,284 |
Less: Net income attributable to noncontrolling interests | 88 | 91 | 96 |
Net income (loss) attributable to controlling interests | 431 | (1,449) | 1,188 |
Allocation of net income (loss) for calculation of earnings per common unit: | |||
Net income (loss) attributable to controlling interests | 431 | (1,449) | 1,188 |
Allocation of net income (loss) to general partner | 517 | 384 | 756 |
Allocation of net income (loss) to Class B units | 12 | (46) | 0 |
Allocation of net income (loss) to Class D units | 0 | 68 | 73 |
Allocation of net income (loss) to common units | $ (98) | $ (1,855) | $ 359 |
Basic earnings (loss) per common unit | |||
Basic net income (loss) per common unit | $ (0.17) | $ (3.27) | $ 0.99 |
Basic weighted-average number of common units outstanding (thousands) | 592,519 | 567,275 | 361,968 |
Diluted earnings per common unit: | |||
Diluted net income (loss) per common unit | $ (0.17) | $ (3.27) | $ 0.99 |
Diluted weighted-average number of common units outstanding | 592,519 | 567,275 | 361,968 |
Cash distributions per common unit | $ 3.4 | $ 3.4000 | $ 3.5995 |
Other Comprehensive Income (Loss): | |||
Net unrealized gain (loss) from derivative instruments | $ 5 | $ 6 | $ (1) |
Reclassifications into earnings of net derivative instruments (gain) loss | (3) | (7) | 0 |
Foreign currency translation adjustments | 61 | (173) | (89) |
Reclassification into earnings upon sale of foreign entity | 108 | 0 | 0 |
Other comprehensive income (loss) | 171 | (174) | (90) |
Comprehensive income (loss) | 690 | (1,532) | 1,194 |
Less: Comprehensive income (loss) attributable to noncontrolling interests | 88 | 91 | 96 |
Comprehensive income (loss) attributable to controlling interests | $ 602 | $ (1,623) | $ 1,098 |
Consolidated Balance Sheet
Consolidated Balance Sheet - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Current assets: | ||
Cash and cash equivalents | $ 145 | $ 96 |
Trade accounts and other receivables (net of allowance of $6 at December 31, 2016 and $3 at December 31, 2015) | 926 | 1,026 |
Inventories | 138 | 127 |
Other current assets and deferred charges | 205 | 190 |
Total current assets | 1,414 | 1,439 |
Investments | 6,701 | 7,336 |
Property, plant, and equipment – net | 28,021 | 28,600 |
Intangible assets – net of accumulated amortization | 9,662 | 10,016 |
Regulatory assets, deferred charges, and other | 467 | 479 |
Total assets | 46,265 | 47,870 |
Accounts payable: | ||
Trade | 589 | 648 |
Affiliate | 109 | 141 |
Accrued interest | 258 | 231 |
Asset retirement obligations | 61 | 57 |
Other accrued liabilities | 804 | 469 |
Commercial paper | 93 | 499 |
Long-term debt due within one year | 785 | 176 |
Total current liabilities | 2,699 | 2,221 |
Long-term debt | 17,685 | 19,001 |
Asset retirement obligations | 798 | 857 |
Deferred income tax liabilities | 20 | 119 |
Regulatory liabilities, deferred income, and other | 1,860 | 1,066 |
Contingent liabilities and commitments (Note 18) | ||
Partners’ equity: | ||
Common units (607,064,550 and 588,546,022 units outstanding at December 31, 2016 and 2015, respectively) | 18,300 | 19,730 |
Class B units (16,690,016 and 14,784,015 units outstanding as of December 31, 2016 and 2015, respectively) | 769 | 771 |
General partner | 2,385 | 2,552 |
Accumulated other comprehensive income (loss) | (1) | (172) |
Total partners’ equity | 21,453 | 22,881 |
Noncontrolling interests in consolidated subsidiaries | 1,750 | 1,725 |
Total equity | 23,203 | 24,606 |
Total liabilities and equity | $ 46,265 | $ 47,870 |
Consolidated Balance Sheet (Par
Consolidated Balance Sheet (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Statement of Financial Position [Abstract] | ||
Allowance for trade accounts and other receivables | $ 6 | $ 3 |
Equity: | ||
Common units outstanding | 607,064,550 | 588,546,022 |
Class B units outstanding | 16,690,016 | 14,784,015 |
Consolidated Statement of Chang
Consolidated Statement of Changes in Equity - USD ($) $ in Millions | Total | General Partner | Common UnitsLimited Partners | Class B UnitsLimited Partners | Class D UnitsLimited Partners | Accumulated Other Comprehensive Income (Loss) | Noncontrolling Interests | Total Partners' Equity |
Beginning Balance at Dec. 31, 2013 | $ 11,567 | $ (536) | $ 11,596 | $ 0 | $ 0 | $ 92 | $ 415 | $ 11,152 |
Net income (loss) | 1,284 | 772 | 354 | 0 | 62 | 0 | 96 | 1,188 |
Other comprehensive income (loss) | (90) | 0 | 0 | 0 | 0 | (90) | 0 | (90) |
Cash distributions | (2,448) | (742) | (1,706) | 0 | 0 | 0 | 0 | (2,448) |
Contributions from The Williams Companies, Inc. - net (Note 1) | 18,205 | 10,703 | 0 | 0 | 0 | 0 | 7,502 | 10,703 |
Sales of common units (Note 15) | 55 | 0 | 55 | 0 | 0 | 0 | 0 | 55 |
Issuance of Class D units in common control transactions( Note 1) | 0 | (1,017) | 0 | 0 | 1,017 | 0 | 0 | 0 |
Beneficial conversion feature of Class D units | 0 | 0 | 117 | 0 | (117) | 0 | 0 | 0 |
Amortization of beneficial conversion feature of Class D units (Note 5) | 0 | 0 | (49) | 0 | 49 | 0 | 0 | 0 |
Contributions from general partner | 13 | 13 | 0 | 0 | 0 | 0 | 0 | 13 |
Contributions from noncontrolling interests | 334 | 0 | 0 | 0 | 0 | 0 | 334 | 0 |
Distributions to noncontrolling interests | (243) | 0 | 0 | 0 | 0 | 0 | (243) | 0 |
Other | 8 | 21 | 0 | 0 | 0 | 0 | (13) | 21 |
Net increase (decrease) in equity | 17,118 | 9,750 | (1,229) | 0 | 1,011 | (90) | 7,676 | 9,442 |
Ending Balance at Dec. 31, 2014 | 28,685 | 9,214 | 10,367 | 0 | 1,011 | 2 | 8,091 | 20,594 |
Net income (loss) | (1,358) | 590 | (1,988) | (52) | 1 | 0 | 91 | (1,449) |
Other comprehensive income (loss) | (174) | 0 | 0 | 0 | 0 | (174) | 0 | (174) |
Cash distributions | (2,686) | (691) | (1,995) | 0 | 0 | 0 | 0 | (2,686) |
Contributions from The Williams Companies, Inc. - net (Note 1) | 20 | (6,573) | 12,254 | 823 | 0 | 0 | (6,484) | 6,504 |
Sales of common units (Note 15) | 59 | 0 | 59 | 0 | 0 | 0 | 0 | 59 |
Amortization of beneficial conversion feature of Class D units (Note 5) | 0 | 0 | (68) | 0 | 68 | 0 | 0 | 0 |
Contributions from general partner | 14 | 14 | 0 | 0 | 0 | 0 | 0 | 14 |
Conversion of Class D units to common units (Note 5) | 0 | 0 | 1,080 | 0 | (1,080) | 0 | 0 | 0 |
Contributions from noncontrolling interests | 111 | 0 | 0 | 0 | 0 | 0 | 111 | 0 |
Distributions to noncontrolling interests | (87) | 0 | 0 | 0 | 0 | 0 | (87) | 0 |
Other | 22 | (2) | 21 | 0 | 0 | 0 | 3 | 19 |
Net increase (decrease) in equity | (4,079) | (6,662) | 9,363 | 771 | (1,011) | (174) | (6,366) | 2,287 |
Ending Balance at Dec. 31, 2015 | 24,606 | 2,552 | 19,730 | 771 | 0 | (172) | 1,725 | 22,881 |
Net income (loss) | 519 | 490 | (57) | (2) | 0 | 0 | 88 | 431 |
Other comprehensive income (loss) | 171 | 0 | 0 | 0 | 0 | 171 | 0 | 171 |
Cash distributions | (2,540) | (533) | (2,007) | 0 | 0 | 0 | 0 | (2,540) |
Noncash consideration from The Williams Companies, Inc. (Note 15) | (150) | (150) | 0 | 0 | 0 | 0 | 0 | (150) |
Sales of common units (Note 15) | 624 | 0 | 624 | 0 | 0 | 0 | 0 | 624 |
Contributions from general partner | 26 | 26 | 0 | 0 | 0 | 0 | 0 | 26 |
Contributions from noncontrolling interests | 29 | 0 | 0 | 0 | 0 | 0 | 29 | 0 |
Distributions to noncontrolling interests | (92) | 0 | 0 | 0 | 0 | 0 | (92) | 0 |
Other | 10 | 0 | 10 | 0 | 0 | 0 | 0 | 10 |
Net increase (decrease) in equity | (1,403) | (167) | (1,430) | (2) | 0 | 171 | 25 | (1,428) |
Ending Balance at Dec. 31, 2016 | $ 23,203 | $ 2,385 | $ 18,300 | $ 769 | $ 0 | $ (1) | $ 1,750 | $ 21,453 |
Consolidated Statement of Cash
Consolidated Statement of Cash Flows - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
OPERATING ACTIVITIES: | |||
Net income (loss) | $ 519 | $ (1,358) | $ 1,284 |
Adjustments to reconcile to net cash provided (used) by operating activities: | |||
Depreciation and amortization | 1,720 | 1,702 | 1,151 |
Provision (benefit) for deferred income taxes | (83) | 4 | 25 |
Impairment of goodwill | 0 | 1,098 | 0 |
Impairment of equity-method investments | 430 | 1,359 | 0 |
Impairment of and net (gain) loss on sale of assets and businesses | 481 | 150 | 68 |
Amortization of stock-based awards | 20 | 27 | 9 |
Cash provided (used) by changes in current assets and liabilities: | |||
Accounts and notes receivable | 80 | (67) | (169) |
Inventories | (20) | 105 | (36) |
Other current assets and deferred charges | (2) | 2 | (43) |
Accounts payable | 5 | (128) | (42) |
Accrued liabilities | 503 | (15) | (233) |
Affiliate accounts receivable and payable – net | (37) | 0 | 9 |
Other, including changes in noncurrent assets and liabilities | 322 | (218) | 322 |
Net cash provided (used) by operating activities | 3,938 | 2,661 | 2,345 |
FINANCING ACTIVITIES: | |||
Proceeds from (payments of) commercial paper – net | (409) | (306) | 572 |
Proceeds from long-term debt | 4,248 | 7,675 | 4,386 |
Payments of long-term debt | (4,936) | (4,699) | (1,157) |
Proceeds from sales of common units | 614 | 59 | 55 |
Contributions from general partner | 26 | 14 | 13 |
Distributions to limited partners and general partner | (2,531) | (2,686) | (2,448) |
Distributions to noncontrolling interests | (92) | (87) | (243) |
Contributions from noncontrolling interests | 29 | 111 | 334 |
Contributions from The Williams Companies, Inc. – net | 0 | 20 | 73 |
Payments for debt issuance costs | (9) | (33) | (24) |
Special distribution from Gulfstream | 0 | 396 | 0 |
Contribution to Gulfstream for repayment of debt | (148) | (248) | 0 |
Other – net | 0 | (1) | 24 |
Net cash provided (used) by financing activities | (3,208) | 215 | 1,585 |
INVESTING ACTIVITIES: | |||
Capital expenditures (1) | (1,944) | (2,795) | (3,692) |
Net proceeds from dispositions | 6 | 3 | 34 |
Proceeds from sale of businesses, net of cash divested | 672 | 0 | 0 |
Purchases of businesses, net of cash acquired | 0 | (112) | 0 |
Purchases of and contributions to equity-method investments | (177) | (594) | (468) |
Distributions from unconsolidated affiliates in excess of cumulative earnings | 472 | 404 | 141 |
Other – net | 290 | 143 | 116 |
Net cash provided (used) by investing activities | (681) | (2,951) | (3,869) |
Increase (decrease) in cash and cash equivalents | 49 | (75) | 61 |
Cash and cash equivalents at beginning of year | 96 | 171 | 110 |
Cash and cash equivalents at end of year | 145 | 96 | 171 |
(1) Increases to property, plant, and equipment | (1,871) | (2,649) | (3,571) |
Changes in related accounts payable and accrued liabilities | (73) | (146) | (121) |
Capital expenditures (1) | $ (1,944) | $ (2,795) | $ (3,692) |
General, Description of Busines
General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies [Text Block] | Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies General 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 December 31, 2016, Williams owned an approximate 58 percent limited partner interest, a 2 percent general partner interest, and incentive distribution rights (IDRs) in us. Our operations are located principally in the United States. Financial Repositioning In January 2017, we announced agreements with Williams, wherein Williams permanently waived the general partner’s IDRs and converted its 2 percent general partner interest in us to a non-economic interest in exchange for 289 million newly issued common units. Pursuant to this agreement, Williams also purchased approximately 277 thousand common units for $10 million . Additionally, Williams purchased approximately 59 million common units at a price of $36.08586 per unit in a private placement transaction. According to the terms of this agreement, following our quarterly distribution in February 2017, Williams paid additional consideration of approximately $50 million to us for these units. Following these transactions, Williams owns a 74 percent limited partner interest in us. 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. 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 and are organized into the following reportable segments: Central, Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services. 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 (DBJV) 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 66 percent interest in Cardinal Gas Services, L.L.C. (Cardinal) (a consolidated entity), 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 (Caiman II), and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 41 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. In September 2016, we completed the sale of our Canadian operations. (See Note 3 – Divestiture .)This segment also includes our NGL and natural gas marketing business, storage facilities, 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 Prior to the ACMP Merger, Williams owned certain limited partnership interests in both Pre-merger WPZ and ACMP, as well as 100 percent of the general partners of both partnerships. Due to the ownership of the general partners, Williams controlled both partnerships. Williams’ control of Pre-merger WPZ began with its inception in 2005, while control of ACMP was achieved upon obtaining an additional 50 percent interest in its general partner effective July 1, 2014. Williams previously acquired 50 percent of the ACMP general partner in a separate transaction in 2012. ACMP Merger The ACMP Merger has been accounted for as a combination between entities under common control, with Pre-merger WPZ representing the predecessor entity. As such, the accompanying financial statements represent a continuation of Pre-merger WPZ, the accounting acquirer, except for certain adjustments to give effect to the exchange ratio applied to Pre-merger WPZ’s historically outstanding units. Because the ACMP Merger was between entities under common control, it was treated similar to a pooling of interests whereby the historical results of operations for ACMP were combined with those of Pre-merger WPZ for periods under common control (periods subsequent to July 1, 2014) and the net assets of ACMP were combined at Williams’ historical basis. (See Note 2 – Acquisitions .) Historical earnings of ACMP prior to the ACMP Merger have been presented herein as allocated to either the capital account of the general partner for interests owned by Williams or to noncontrolling interests for interests held by the public. Thus, there was no change in the total amount of historical earnings attributable to common unitholders. In conjunction with the ACMP Merger, the partners’ equity interests in ACMP have been reclassified out of the capital account of the general partner for interests owned by Williams and noncontrolling interests for interests held by the public and into the capital accounts of common and Class B interests as a Contributions from The Williams Companies, Inc. - net within the Consolidated Statement of Changes in Equity . Canada Acquisition In February 2014, Pre-merger WPZ acquired certain Canadian operations from Williams (Canada Acquisition) for total consideration of $56 million of cash (including a $31 million post-closing adjustment paid in the second quarter of 2014), 25,577,521 Pre-merger WPZ Class D limited-partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. In lieu of cash distributions, the Class D units received quarterly distributions of additional paid-in-kind Class D units. This common control acquisition was treated similar to a pooling of interests whereby the historical results of operations were combined with ours for all periods presented and the acquired assets and liabilities were combined with ours at their historical amounts. These Canadian operations are reported in our NGL & Petchem Services segment. In October 2014, a purchase price adjustment was finalized whereby Pre-merger WPZ received $56 million in cash from Williams in the fourth quarter of 2014 and Williams waived $2 million in payments on its IDRs with respect to Pre-merger WPZ’s November 2014 distribution. The Canadian operations previously participated in Williams’ cash management program under a credit agreement with Williams. Net changes in amounts due to/from Williams prior to the Canada Acquisition, along with the cash consideration paid for the Canada Acquisition, are reflected within Contributions from The Williams Companies, Inc. - net within the Consolidated Statement of Changes in Equity . Significant risks and uncertainties We have announced plans to monetize our olefins production plant in Geismar, Louisiana, as well as other select assets that are not core to our strategy. As we pursue these other select asset monetizations, it is possible that we may incur impairments of certain equity-method investments, property, plant, and equipment, and intangible assets. Such impairments could potentially be caused by indications of fair value implied through the monetization process or, in the case of asset dispositions that are part of a broader asset group, the impact of the loss of future estimated cash flows. Summary of Significant Accounting Policies Principles of consolidation The consolidated financial statements include the accounts of all entities that we control and our proportionate interest in the accounts of certain ventures in which we own an undivided interest. Management’s judgment is required to evaluate whether we control an entity. Key areas of that evaluation include: • Determining whether an entity is a variable interest entity (VIE); • Determining whether we are the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that we and our related parties have over those activities through our variable interests; • Identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating whether we are a VIE’s primary beneficiary; • Evaluating whether other owners in entities that are not VIEs are able to effectively participate in significant decisions that would be expected to be made in the ordinary course of business such that we do not have the power to control such entities. We apply the equity method of accounting to investments over which we exercise significant influence but do not control. Common control transactions Entities and assets acquired from Williams and its affiliates are accounted for as common control transactions whereby the net assets acquired are combined with ours at their historical amounts. If any cash consideration transferred to Williams in such a transaction exceeds the carrying value of the net assets acquired, the excess is treated as a capital transaction with our general partner, similar to a dividend. If the carrying value of the net assets acquired exceeds any cash consideration transferred and limited partner units are also issued as consideration, then the limited partner units are recorded at an amount equal to the excess of the carrying value of the net assets acquired over any cash consideration transferred. To the extent that such transactions require prior periods to be recast, historical net equity amounts prior to the transaction date are reflected in the account of the general partner or noncontrolling interests, if applicable. Cash consideration up to the carrying value of net assets acquired is presented as an investing activity in our Consolidated Statement of Cash Flows . Cash consideration in excess of the carrying value of net assets acquired is presented as a financing activity in our Consolidated Statement of Cash Flows . Equity-method investment basis differences Differences between the cost of our equity-method investments and our underlying equity in the net assets of investees are accounted for as if the investees were consolidated subsidiaries. Equity earnings (losses) in the Consolidated Statement of Comprehensive Income (Loss) includes our allocable share of net income (loss) of investees adjusted for any depreciation and amortization, as applicable, associated with basis differences. Use of estimates 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. Significant estimates and assumptions include: • Impairment assessments of investments, property, plant, and equipment, goodwill, and other identifiable intangible assets; • Litigation-related contingencies; • Environmental remediation obligations; • Depreciation and/or amortization of equity-method investment basis differences; • Asset retirement obligations; • Acquisition related purchase price allocations. These estimates are discussed further throughout these notes. Regulatory accounting Transco and Northwest Pipeline are regulated by the Federal Energy Regulatory Commission (FERC). Their rates, which are established by the FERC, are designed to recover the costs of providing the regulated services, and their competitive environment makes it probable that such rates can be charged and collected. Therefore, our management has determined that it is appropriate under Accounting Standards Codification (ASC) Topic 980, “Regulated Operations”, to account for and report regulatory assets and liabilities related to these operations consistent with the economic effect of the way in which their rates are established. Accounting for these operations that are regulated can differ from the accounting requirements for nonregulated operations. For example, for regulated operations, allowance for funds used during construction (AFUDC) represents the estimated cost of debt and equity funds applicable to utility plant in process of construction and is capitalized as a cost of property, plant, and equipment because it constitutes an actual cost of construction under established regulatory practices; nonregulated operations are only allowed to capitalize the cost of debt funds related to construction activities, while a component for equity is prohibited. The components of our regulatory assets and liabilities relate to the effects of deferred taxes on equity funds used during construction, asset retirement obligations, fuel cost differentials, levelized incremental depreciation, negative salvage, and pension and other postretirement benefits. Our current and noncurrent regulatory asset and liability balances for the years ended December 31, 2016 and 2015 are as follows: December 31, 2016 2015 (Millions) Current assets reported within Other current assets and deferred charges $ 91 $ 84 Noncurrent assets reported within Regulatory assets, deferred charges, and other 299 305 Total regulated assets $ 390 $ 389 Current liabilities reported within Other accrued liabilities $ 11 $ 4 Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other 480 409 Total regulated liabilities $ 491 $ 413 Cash and cash equivalents Cash and cash equivalents in the Consolidated Balance Sheet includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired. Accounts receivable Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. We consider receivables past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time full payment is received or collectability is assured. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. Inventories Inventories in the Consolidated Balance Sheet consist of natural gas liquids, olefins, natural gas in underground storage, and materials and supplies and are stated at the lower of cost or market. The cost of inventories is primarily determined using the average-cost method. Property, plant, and equipment Property, plant, and equipment is recorded at cost. We base the carrying value of these assets on estimates, assumptions, and judgments relative to capitalized costs, useful lives, and salvage values. As regulated entities, Northwest Pipeline and Transco provide for depreciation using the straight-line method at FERC-prescribed rates. Depreciation for nonregulated entities is provided primarily on the straight-line method over estimated useful lives, except for certain offshore facilities that apply an accelerated depreciation method. Gains or losses from the ordinary sale or retirement of property, plant, and equipment for regulated pipelines are credited or charged to accumulated depreciation. Other gains or losses are recorded in Other (income) expense – net included in Operating income (loss) in the Consolidated Statement of Comprehensive Income (Loss) . Ordinary maintenance and repair costs are generally expensed as incurred. Costs of major renewals and replacements are capitalized as property, plant, and equipment. We record a liability and increase the basis in the underlying asset for the present value of each expected future asset retirement obligation (ARO) at the time the liability is initially incurred, typically when the asset is acquired or constructed. As regulated entities, Northwest Pipeline and Transco offset the depreciation of the underlying asset that is attributable to capitalized ARO cost to a regulatory asset as management expects to recover these amounts in future rates. We measure changes in the liability due to passage of time by applying an interest rate to the liability balance. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in Operating and maintenance expenses in the Consolidated Statement of Comprehensive Income (Loss) , except for regulated entities, for which the liability is offset by a regulatory asset. The regulatory asset is amortized commensurate with our collection of those costs in rates. Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium. Goodwill Goodwill included within Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet represents the excess of the consideration, plus the fair value of any noncontrolling interest or any previously held equity interest, over the fair value of the net assets acquired. It is not subject to amortization but is evaluated annually as of October 1 for impairment or more frequently if impairment indicators are present that would indicate it is more likely than not that the fair value of the reporting unit is less than its carrying amount. As part of the evaluation, we compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in the amount of the excess. Judgments and assumptions are inherent in our management’s estimates of fair value. Other intangible assets Our identifiable intangible assets included within Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet are primarily related to gas gathering, processing, and fractionation contractual customer relationships. Our intangible assets are amortized on a straight-line basis over the period in which these assets contribute to our cash flows. We evaluate these assets for changes in the expected remaining useful lives and would reflect any changes prospectively through amortization over the revised remaining useful life. Impairment of property, plant, and equipment, other identifiable intangible assets, and investments We evaluate our property, plant, and equipment and other identifiable intangible assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s 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 in the financial statements 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. For assets identified to be disposed of in the future and considered held for sale, we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change. We evaluate our 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. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. 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. Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s or investment’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal. Deferred income We record a liability for deferred income related to cash received from customers in advance of providing our services. Such amounts are generally recognized in revenue upon satisfying our performance obligations, primarily providing services based on units of production or over remaining contractual service periods ranging from 1 to 25 years. Deferred income is reflected within Other accrued liabilities and Regulatory liabilities, deferred income, and other on the Consolidated Balance Sheet . (See Note 13 – Other Accrued Liabilities .) During 2016, we received cash proceeds totaling $820 million associated with restructuring certain gas gathering contracts in the Barnett Shale and Mid-Continent regions. The proceeds were recorded as deferred income and are being amortized into income in 2016 and future periods. In October 2016, we received $104 million of newly constructed assets as part of a noncash investing transaction with a customer for which we provide production handling and other services. The transaction was recorded in Property, plant, and equipment – net and deferred income in the Consolidated Balance Sheet and is being amortized based on units of production through 2024. Due to the noncash nature of this transaction, it is not presented within the Consolidated Statement of Cash Flows . Contingent liabilities We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates. Cash flows from revolving credit facility and commercial paper program Proceeds and payments related to borrowings under our credit facility are reflected in the financing activities in the Consolidated Statement of Cash Flows on a gross basis. Proceeds and payments related to borrowings under our commercial paper program are reflected in the financing activities in the Consolidated Statement of Cash Flows on a net basis, as the outstanding notes generally have maturity dates less than three months from the date of issuance. (See Note 14 – Debt, Banking Arrangements, and Leases .) Derivative instruments and hedging activities We may utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily of swaps, futures, and forward contracts involving short- and long-term purchases and sales of energy commodities. We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, in Other current assets and deferred charges ; Regulatory assets, deferred charges, and other ; Other accrued liabilities ; or Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet . We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk .) The accounting for the changes in fair value of a commodity derivative can be summarized as follows: Derivative Treatment Accounting Method Normal purchases and normal sales exception Accrual accounting Designated in a qualifying hedging relationship Hedge accounting All other derivatives Mark-to-market accounting We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of physical energy commodities. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception. We may also designate a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in Product sales or Product costs in the Consolidated Statement of Comprehensive Income (Loss) . For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in Accumulated other comprehensive income (loss) (AOCI) in the Consolidated Balance Sheet and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in Product sales or Product costs in the Consolidated Statement of Comprehensive Income (Loss) . Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in Product sales or Product costs in the Consolidated Statement of Comprehensive Income (Loss) at that time. The change in likelihood of a forecasted transaction is a judgmental decision that includes qualitative assessments made by management. For commodity derivatives that are not designated in a hedging relationship, and for which we have not elected the normal purchases and normal sales exception, we report changes in fair value currently in Product sales or Product costs in the Consolidated Statement of Comprehensive Income (Loss) . Certain gains and losses on derivative instruments included in the Consolidated Statement of Comprehensive Income (Loss) are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception. Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives for NGL processing activities and which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. Revenue recognition Revenues As a result of the ratemaking process, certain revenues collected by us may be subject to refunds upon the issuance of final orders by t |
Acquisitions
Acquisitions | 12 Months Ended |
Dec. 31, 2016 | |
Business Combinations [Abstract] | |
Acquisitions [Text Block] | Note 2 – Acquisitions ACMP As previously discussed in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies , the net assets of Pre-merger WPZ and ACMP have been combined at Williams’ historical basis. Williams’ basis in ACMP reflects its business combination accounting resulting from acquiring control of ACMP on July 1, 2014 (ACMP Acquisition), which, among other things, requires identifiable assets acquired and liabilities assumed to be measured at their acquisition-date fair values. The valuation techniques used to measure the acquisition-date fair value of ACMP consisted of valuing the limited partner units and general partner interest separately. The limited partner units of ACMP, consisting of common and Class B units, were valued based on ACMP’s closing common unit price at July 1, 2014. The general partner interest, including IDRs, was valued on a noncontrolling basis using an income approach based on a discounted cash flow analysis and a market comparison analysis based on comparable guideline companies and an implied fair value from Williams’ purchase. The following table presents the allocation of the acquisition-date fair value of the major classes of the assets acquired, which are presented primarily in the Central and Northeast G&P segments, liabilities assumed, noncontrolling interest, and equity at July 1, 2014. The fair value of accounts receivable acquired equaled contractual amounts receivable. Changes to the preliminary allocation disclosed in Exhibit 99.1 of the Form 8-K dated May 6, 2015, which were recorded in the first quarter of 2015, reflect an increase of $150 million in Property, plant, and equipment and $25 million in Goodwill , and a decrease of $168 million in Other intangible assets and $7 million in Investments . These adjustments during the measurement period were not considered significant to require retrospective revisions of our financial statements. (Millions) Accounts receivable $ 168 Other current assets 63 Investments 5,865 Property, plant, and equipment 7,165 Goodwill 499 Other intangible assets 8,841 Current liabilities (408 ) Debt (4,052 ) Other noncurrent liabilities (9 ) Noncontrolling interest in ACMP’s subsidiaries (958 ) Noncontrolling interest representing ACMP public unitholders (6,544 ) Equity (10,630 ) Other intangible assets recognized in the acquisition are related to contractual customer relationships from gas gathering agreements with our customers. The basis for determining the value of these intangible assets was estimated future net cash flows to be derived from acquired contractual customer relationships discounted using a risk-adjusted discount rate. These intangible assets are being amortized on a straight-line basis over 30 years during which contractual customer relationships are expected to contribute to our cash flows. As estimated at the time of acquisition, approximately 56 percent of the expected future revenues from these contractual customer relationships were impacted by our ability and intent to renew or renegotiate existing customer contracts. We expense costs incurred to renew or extend the terms of our gas gathering, processing, and fractionation contracts with customers. Based on the estimated future revenues during the current contract periods (as estimated at the time of acquisition), the weighted-average periods to the next renewal or extension of the existing customer contracts were approximately 17 years . The following unaudited pro forma Total revenues and Net income (loss) attributable to controlling interests for the year ended December 31, 2014, are presented as if the ACMP Acquisition had been completed on January 1, 2014. These pro forma amounts are not necessarily indicative of what the actual results would have been if the acquisition had in fact occurred on the date or for the period indicated, nor do they purport to project Total revenues or Net income (loss) attributable to controlling interests for any future periods or as of any date. These amounts do not give effect to any potential cost savings, operating synergies, or revenue enhancements to result from the transactions or the potential costs to achieve these cost savings, operating synergies, and revenue enhancements. December 31, 2014 (Millions) Total revenues $ 7,953 Net income (loss) attributable to controlling interests $ 1,376 Significant adjustments to pro forma Net income (loss) attributable to controlling interests include additional depreciation and amortization expense associated with reflecting the acquired investments, property, plant, and equipment, and other intangible assets at fair value. The adjustments assume estimated useful lives of 30 years . During the year ended December 31, 2014, ACMP contributed Total revenues of $781 million and Net income (loss) attributable to controlling interests of $165 million . Costs incurred by Williams related to this acquisition were $16 million in 2014 and are reported within our Central segment and included in Selling, general, and administrative expenses in the Consolidated Statement of Comprehensive Income (Loss) . Direct transaction costs associated with financing commitments were $9 million in 2014 and reported within Interest incurred in the Consolidated Statement of Comprehensive Income (Loss) . Eagle Ford Gathering System In May 2015, we acquired a gathering system comprised of approximately 140 miles of pipeline and a sour gas compression facility in the Eagle Ford Shale, included in our Central segment, for $112 million . The acquisition was accounted for as a business combination, and the allocation of the acquisition-date fair value of the major classes of assets acquired includes $80 million of Property, plant, and equipment – net and $32 million of Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet . Changes to the preliminary allocation disclosed in the second quarter of 2015 reflect an increase of $20 million in Property, plant, and equipment – net , and a decrease of $20 million in Intangible assets – net of accumulated amortization . UEOM Equity-Method Investment In June 2015, we acquired an additional 13 percent interest in our equity-method investment, UEOM, for $357 million . Following the acquisition we own approximately 62 percent of UEOM. However, we continue to account for this as an equity-method investment because we do not control UEOM due to the significant participatory rights of our partner. In connection with the acquisition of the additional interest, our general partner agreed to waive approximately $2 million of its IDR payments each quarter through 2017. See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies for discussion of agreement with Williams wherein Williams permanently waived IDR payment obligations from us. |
Divestiture
Divestiture | 12 Months Ended |
Dec. 31, 2016 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Divestiture [Text Block] | Note 3 – Divestiture In September 2016, we completed the sale of subsidiaries conducting Canadian operations (such subsidiaries, the disposal group). Consideration received to date totaled $672 million , net of $13 million of cash divested and subject to customary working capital adjustments. Consideration also included $150 million in the form of a waiver of incentive distributions otherwise payable to Williams in the fourth quarter of 2016. The waiver recognizes certain affiliate contracts wherein our Canadian operations provided services to Williams. This noncash transaction is reflected as a decrease in General partner equity in the Consolidated Statement of Changes in Equity . The proceeds were primarily used to reduce borrowings on credit facilities. During the second quarter of 2016, we designated these operations as held for sale. As a result, we measured the fair value of the disposal group as of June 30, 2016, resulting in an impairment charge of $341 million , reflected in Impairment of certain assets in the Consolidated Statement of Comprehensive Income (Loss) . (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk .) During the second half of 2016, we recorded an additional loss of $34 million at our NGL & Petchem Services segment upon completion of the sale, primarily reflecting revisions to the sales price and including an $11 million benefit related to transactions to hedge our foreign currency exchange risk on the Canadian proceeds, reflected in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Comprehensive Income (Loss) . The following table presents the results of operations for the disposal group, excluding the impairment and loss noted above. Years Ended December 31, 2016 2015 (Millions) Income (loss) before income taxes of disposal group $ (9 ) $ 6 |
Variable Interest Entities
Variable Interest Entities | 12 Months Ended |
Dec. 31, 2016 | |
Variable Interest Entity Disclosures [Abstract] | |
Variable Interest Entities [Text Block] | Note 4 – Variable Interest Entities As of December 31, 2016 , we consolidate the following 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. 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 FERC 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. The oral argument before the Second Circuit Court of Appeals regarding the NYSDEC’s denial of Constitution’s application for water quality certification under Section 401 of the Clean Water Act was held on November 16, 2016. We anticipate a decision from the Second Circuit Court of Appeals as early as second quarter 2017. 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 $381 million on a consolidated basis at December 31, 2016, and are included within Property, plant, and equipment – net 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, a subsidiary that provides gathering services for the Utica Shale 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: December 31, 2016 2015 Classification (Millions) Assets (liabilities): Cash and cash equivalents $ 82 $ 70 Cash and cash equivalents Accounts receivable 91 71 Trade accounts and other receivables Prepaid assets 3 2 Other current assets and deferred charges Property, plant, and equipment – net 3,024 3,000 Property, plant, and equipment – net Intangible assets – net 1,431 1,483 Intangible assets – net of accumulated amortization Accounts payable (44 ) (59 ) Accounts payable – trade Accrued liabilities (3 ) (14 ) Other accrued liabilities Current deferred revenue (63 ) (62 ) Other accrued liabilities Noncurrent asset retirement obligations (99 ) (93 ) Asset retirement obligations Noncurrent deferred revenue associated with customer advance payments (324 ) (331 ) Regulatory liabilities, deferred income, and other |
Allocation of Net Income (Loss)
Allocation of Net Income (Loss) and Distributions | 12 Months Ended |
Dec. 31, 2016 | |
Equity [Abstract] | |
Allocation of Net Income and Distributions | Note 5 – 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: Years Ended December 31, 2016 2015 2014 (Millions) Allocation of net income to general partner: Net income (loss) $ 519 $ (1,358 ) $ 1,284 Net income applicable to pre-merger operations allocated to general partner — (2 ) (95 ) Net income applicable to pre-partnership operations allocated to general partner — — (15 ) Net income applicable to noncontrolling interests (88 ) (91 ) (96 ) Costs charged directly to the general partner 1 21 1 Income (loss) subject to 2% allocation of general partner interest 432 (1,430 ) 1,079 General partner’s share of net income 2 % 2 % 2 % General partner’s allocated share of net income (loss) before items directly allocable to general partner interest 9 (29 ) 22 Priority allocations, including incentive distributions, paid to general partner 482 638 641 Pre-merger net income allocated to general partner interest — 2 95 Pre-partnership net income allocated to general partner interest — — 15 Costs charged directly to the general partner (1 ) (21 ) (1 ) Net income allocated to general partner’s equity $ 490 $ 590 $ 772 Net income (loss) $ 519 $ (1,358 ) $ 1,284 Net income allocated to general partner’s equity 490 590 772 Net income (loss) allocated to Class B limited partners’ equity (2 ) (52 ) — Net income allocated to Class D limited partners’ equity (1) — 69 62 Net income allocated to noncontrolling interests 88 91 96 Net income (loss) allocated to common limited partners’ equity $ (57 ) $ (2,056 ) $ 354 Adjustments to reconcile Net income (loss) allocated to common limited partners' equity to Allocation of net income (loss) to common units: Incentive distributions paid 474 633 640 Incentive distributions declared (473 ) (423 ) (626 ) Impact of unit issuance timing and other (2) (42 ) (9 ) (9 ) Allocation of net income (loss) to common units $ (98 ) $ (1,855 ) $ 359 ____________ (1) Includes amortization of the beneficial conversion feature associated with the Pre-merger WPZ Class D units of $68 million and $49 million for the years ended December 31, 2015 and 2014, respectively. See following discussion of Class D units. (2) The 2016 amount includes the effect of units issued and the conversion of the general partner interest in us to a non-economic interest in conjunction with our Financial Repositioning (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies .) Common Units On February 10, 2017, we paid a cash distribution of $0.85 per common unit on our outstanding common units to unitholders of record at the close of business on February 3, 2017. 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. During 2016 and 2015 we issued 1,906,001 and 1,058,172 , respectively, of additional paid-in-kind Class B units associated with quarterly distributions. On February 10, 2017, we issued 375,800 Class B units associated with the fourth-quarter 2016 distribution. Class D Units As previously mentioned (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies ), a portion of the total consideration for the Canada Acquisition was funded through the issuance of Pre-merger WPZ Class D units to an affiliate of our general partner. The Pre-merger WPZ Class D units were issued at a discount to the market price of Pre-merger WPZ’s common units. The discount represented a beneficial conversion feature and is reflected as an increase in the common unit capital account and a decrease in the Class D capital account on the Consolidated Statement of Changes in Equity . This discount was being amortized through the originally expected first quarter 2016 conversion date, resulting in an increase to the Class D capital account and a decrease to the common unit capital account. 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. The Pre-merger WPZ Class D units were not entitled to cash distributions. Instead, prior to conversion into Pre-merger WPZ common units, the Pre-merger WPZ Class D units received quarterly distributions of additional paid-in-kind Pre-merger WPZ Class D units. During 2014, we issued 1,377,893 Pre-merger WPZ Class D units as the paid-in-kind Class D distributions. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2016 | |
Related Party Transactions [Abstract] | |
Related Party Transactions Disclosure [Text Block] | Note 6 – Related Party Transactions Reimbursement of Expenses of Our General Partner The employees of our operated assets are employees of Williams. Williams directly charges us for the payroll and benefit costs associated with operations employees and carries the obligations for many employee-related benefits in its financial statements, including the liabilities related to employee retirement, medical plans, and paid time off. Our share of the costs is charged to us through affiliate billings and reflected in Operating and maintenance expenses in the Consolidated Statement of Comprehensive Income (Loss) and Property, plant, and equipment – net in the Consolidated Balance Sheet . In addition, employees of Williams provide general and administrative services to us, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three-factor formula, which considers revenues; property, plant, and equipment; and payroll. Our share of direct and allocated administrative expenses is reflected in Selling, general, and administrative expenses in the Consolidated Statement of Comprehensive Income (Loss) and Property, plant, and equipment – net in the Consolidated Balance Sheet . In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams. Transactions with Affiliates and Equity-Method Investees Service revenues, in the Consolidated Statement of Comprehensive Income (Loss), includes transportation and fractionation revenues from our expanded NGL/olefins fractionation facility located in Redwater, Alberta. This facility supported Williams’ Horizon liquids extraction plant in Canada until both were sold in September 2016 (see Note 3 – Divestiture ). Product costs , in the Consolidated Statement of Comprehensive Income (Loss) , includes charges for the following types of transactions: • Purchases of NGLs for resale from Discovery; • Payments to OPPL for transportation of NGLs from certain natural gas processing plants; • Purchases of NGLs for resale from Williams’ former Horizon liquids extraction plant in Canada. Summary of the related party transactions discussed in all sections above. Years Ended December 31, 2016 2015 2014 (Millions) Service revenues $ 31 $ — $ — Product costs 181 169 186 Operating and maintenance expenses - employee costs 470 498 413 Selling, general, and administrative expenses: Employee direct costs 344 368 331 Employee allocated costs 160 195 171 HB Construction Company Ltd., a subsidiary of Williams, provided construction services to us until the sale of our Canadian operations in September 2016. Charges for these construction services as well as other capitalized payroll and benefit costs charged by Williams described above were previously capitalized within Property, plant, and equipment – net in the Consolidated Balance Sheet and totaled $103 million and $187 million during 2016 and 2015, respectively. The Accounts payable — affiliate in the Consolidated Balance Sheet represents the payable positions that result from the transactions with affiliates discussed above. We also have $19 million and $12 million in Accounts payable — trade in the Consolidated Balance Sheet with our equity-method investees at December 31, 2016 and 2015, respectively. Operating Agreements with Equity-Method Investees We have operating agreements with certain equity-method investees. These operating agreements typically provide for reimbursement or payment to us for certain direct operational payroll and employee benefit costs, materials, supplies, and other charges and also for management services. Williams supplied a portion of these services, primarily those related to employees since we do not have any employees, to certain equity-method investees. The total charges to equity-method investees for these fees are $66 million , $64 million , and $65 million for the years ended December 31, 2016, 2015, and 2014, respectively. Omnibus Agreement Under this agreement, Williams is obligated to reimburse us for certain items including (i) maintenance capital expenditure amounts incurred by us or our subsidiaries for certain U.S. Department of Transportation projects, up to a maximum of $50 million , and (ii) an amount based on the amortization over time of deferred revenue amounts that relate to cash payments received by Williams prior to the closing of the contribution transaction for services to be rendered by us in the future at the Devils Tower floating production platform. Net amounts received under this agreement for the years ended December 31, 2016, 2015, and 2014 were $11 million , $12 million , and $11 million , respectively. We have a contribution receivable from our general partner of $3 million and $3 million at December 31, 2016 and 2015, respectively, for amounts reimbursable to us under omnibus agreements presented within Total partners’ equity in the Consolidated Balance Sheet . Acquisitions and Equity Issuances Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies includes related party transactions for Financial Repositioning, the ACMP Merger, and the Canada Acquisition. The Canadian operations previously participated in Williams’ cash management program under a credit agreement with Williams. Net changes in amounts due to/from Williams prior to the Canada Acquisition are reflected within Contributions from The Williams Companies, Inc. - net within the Consolidated Statement of Changes in Equity. Note 15 – Partners’ Capital includes related party transactions for a distribution reinvestment program (DRIP) in November 2016 and a private placement transaction in August 2016. Board of Directors A former member of Williams’ Board of Directors, who was elected in 2013 and resigned during 2016, is also the current chairman, president, and chief executive officer of an energy services company that is a customer of ours. We recorded $144 million , $111 million , and $115 million in Service revenues in Consolidated Statement of Comprehensive Income (Loss) from this company for transportation and storage of natural gas for the years ended December 31, 2016, 2015, and 2014, respectively. |
Investing Activities
Investing Activities | 12 Months Ended |
Dec. 31, 2016 | |
Investments [Abstract] | |
Investments [Text Block] | Note 7 – Investing Activities Impairment of equity-method investments The following table presents other-than-temporary impairment charges related to certain equity-method investments. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk .) Years Ended December 31, 2016 2015 (Millions) Northeast G&P Appalachia Midstream Investments $ 294 $ 562 Laurel Mountain 50 45 UEOM — 241 Central DBJV 59 503 Ranch Westex 24 — Other 3 8 $ 430 $ 1,359 Equity earnings (losses) In 2015, we recognized a loss of $19 million associated with our share of underlying property impairments at certain of the Appalachia Midstream Investments. This loss is reported within the Northeast G&P segment. Other investing income (loss) – net In 2016, we recognized a $27 million gain from the sale of an equity-method investment interest in a gathering system that was part of our Appalachia Midstream Investments within the Northeast G&P segment. Investments Ownership Interest at December 31, 2016 December 31, 2016 2015 (Millions) Appalachia Midstream Investments (1) $ 2,062 $ 2,464 UEOM 62% 1,448 1,525 DBJV 50% 988 977 Discovery 60% 572 602 OPPL 50% 430 445 Caiman II 58% 426 418 Laurel Mountain 69% 324 391 Gulfstream 50% 261 293 Other Various 190 221 $ 6,701 $ 7,336 ____________ (1) Includes equity-method investments in multiple gathering systems in the Marcellus Shale with an approximate average 41 percent interest. We have differences between the carrying value of our equity-method investments and the underlying equity in the net assets of the investees of $1.9 billion at December 31, 2016 and $2.4 billion at December 31, 2015. These differences primarily relate to our investments in Appalachia Midstream Investments, DBJV, and UEOM associated with property, plant, and equipment, as well as customer-based intangible assets and goodwill. Purchases of and contributions to equity-method investments We generally fund our portion of significant expansion or development projects of these investees through additional capital contributions. These transactions increased the carrying value of our investments and included: Years Ended December 31, 2016 2015 2014 (Millions) DBJV $ 105 $ 57 $ 20 Appalachia Midstream Investments 28 93 84 Caiman II 22 — 175 UEOM — 357 57 Discovery — 35 106 Other 22 52 26 $ 177 $ 594 $ 468 Dividends and distributions The organizational documents of entities in which we have an equity-method interest generally require distribution of available cash to members on at least a quarterly basis. These transactions reduced the carrying value of our investments and included: Years Ended December 31, 2016 2015 2014 (Millions) Appalachia Midstream Investments $ 211 $ 219 $ 130 Discovery 141 116 36 Gulfstream 100 88 81 UEOM 92 42 — OPPL 69 45 27 Caiman II 40 33 13 DBJV 39 33 — Laurel Mountain 28 31 39 Other 22 26 39 $ 742 $ 633 $ 365 In addition, 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 Financial Position and Results of Operations of All Equity-Method Investments December 31, 2016 2015 (Millions) Assets (liabilities): Current assets $ 508 $ 773 Noncurrent assets 9,695 9,549 Current liabilities (412 ) (633 ) Noncurrent liabilities (1,484 ) (1,450 ) Years Ended December 31, 2016 2015 2014 (Millions) Gross revenue $ 1,883 $ 1,707 $ 1,623 Operating income 799 690 534 Net income 726 611 460 |
Other Income and Expenses
Other Income and Expenses | 12 Months Ended |
Dec. 31, 2016 | |
Other Income and Expenses [Abstract] | |
Other Income and Expenses [Text Block] | Note 8 – Other Income and Expenses The following table presents certain gains or losses reflected in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Comprehensive Income (Loss) : Years Ended December 31, 2016 2015 2014 (Millions) Central Loss related to sale of certain assets $ — $ — $ 10 Northeast G&P Contingency gain settlement (1) — — (154 ) Net gain related to partial acreage dedication release — — (12 ) Atlantic-Gulf Amortization of regulatory assets associated with asset retirement obligations 33 33 33 Accrual of regulatory liability related to overcollection of certain employee expenses 25 20 14 Project development costs related to Constitution (Note 4) 28 — — Gain on asset retirement (11 ) — — NGL & Petchem Services Loss on sale of Canadian operations (Note 3) 34 — — Net foreign currency exchange (gains) losses (2) 10 (10 ) (3 ) __________ (1) In November 2014, we settled a claim arising from the resolution of a contingent gain related to claims associated with the purchase of a business in a prior period. Pursuant to the settlement, we received $154 million in cash, all of which was recognized as a gain in the fourth quarter of 2014. (2) Primarily relates to gains and losses incurred on foreign currency transactions and the remeasurement of U.S. dollar-denominated current assets and liabilities within our former Canadian operations (see Note 3 – Divestiture ). ACMP Acquisition, Merger, and Transition Certain ACMP acquisition, merger, and transition costs included in the Consolidated Statement of Comprehensive Income (Loss) are as follows: • Selling, general, and administrative expenses includes $26 million in 2015 and $27 million in 2014 (including $16 million of acquisition costs) primarily related to professional advisory fees within the Central segment. • Selling, general, and administrative expenses includes $9 million in 2015 and $15 million in 2014 of related employee transition costs within the Central segment. • Operating and maintenance expenses includes $12 million in 2015 and $15 million in 2014 primarily related to employee transition costs within the Central segment. • Interest incurred includes transaction-related financing costs of $2 million in 2015 from the merger and $9 million in 2014 from the acquisition. Additional Items Certain additional items included in the Consolidated Statement of Comprehensive Income (Loss) are as follows: • Service revenues includes $173 million associated with the amortization of deferred income related to the restructuring of certain gas gathering contracts in the Barnett Shale and Mid-Continent regions. Service revenues also includes $58 million , $239 million , and $167 million recognized in the fourth quarter of 2016, 2015, and 2014, respectively, from minimum volume commitment fees in the Barnett Shale and Mid-Continent regions within the Central segment. • Selling, general, and administrative expenses and Operating and maintenance expenses include $37 million in 2016 of severance and other related costs. Amounts by segment are as follows: Year Ended December 31, 2016 (Millions) Central $ 8 Northeast G&P 3 Atlantic-Gulf 8 West 5 NGL & Petchem Services 4 Other 9 • Other income (expense) – net below Operating income (loss) includes $65 million , $76 million ,and $33 million in 2016, 2015, and 2014, respectively, for equity AFUDC within the Atlantic-Gulf segment. • Other income (expense) – net below Operating income (loss) includes a $14 million gain in 2015 resulting from the early retirement of certain debt. |
Provision (Benefit) for Income
Provision (Benefit) for Income Taxes | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Provision (Benefit) for Income Taxes [Text Block] | Note 9 – Provision (Benefit) for Income Taxes The Provision (benefit) for income taxes includes: Years Ended December 31, 2016 2015 2014 (Millions) Current: State $ 2 $ (3 ) $ 3 Foreign 1 — 1 3 (3 ) 4 Deferred: State (1 ) (3 ) 8 Foreign (82 ) 7 17 (83 ) 4 25 Provision (benefit) for income taxes $ (80 ) $ 1 $ 29 Reconciliations from the Provision (benefit) at statutory rate to recorded Provision (benefit) for income taxes are as follows: Years Ended December 31, 2016 2015 2014 (Millions) Provision (benefit) at statutory rate $ 154 $ (475 ) $ 459 Increases (decreases) in taxes resulting from: Income not subject to U.S. federal tax (154 ) 475 (459 ) State income taxes 1 (6 ) 11 Foreign operations — net (81 ) 7 18 Provision (benefit) for income taxes $ (80 ) $ 1 $ 29 The 2016 foreign deferred benefit includes the tax effect of a $341 million impairment associated with the Canadian operations (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk ). 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. Income (loss) before income taxes includes $387 million of foreign loss in 2016, and $1 million and $72 million of foreign income in 2015 and 2014 , respectively. Deferred income tax liabilities, primarily attributable to the taxable temporary differences from property, plant, and equipment, were $20 million and $119 million in 2016 and 2015 , respectively. Cash payments for income taxes (net of refunds) were $3 million in 2016. Cash refunds for income taxes (net of payments) were $4 million and $28 million in 2015 and 2014, respectively. As of December 31, 2016 , we have no unrecognized tax benefits. Tax years after 2012 are subject to examination by the Texas Comptroller. Generally, tax returns for our Canadian entities are open to audit for tax years after 2011 . Tax years 2014 and 2013 are currently under examination. Williams has indemnified us for any adjustments to foreign tax returns filed prior to the Canada Acquisition in 2014. We have indemnified the purchaser of our Canadian operations for any adjustments to foreign tax returns for periods prior to the sale of our Canadian operations in September 2016 (see Note 3 – Divestiture ). |
Benefit Plans
Benefit Plans | 12 Months Ended |
Dec. 31, 2016 | |
Employee Benefits and Share-based Compensation [Abstract] | |
Pension and Other Postretirement Benefits Disclosure [Text Block] | Note 10 – Benefit Plans Certain of the benefit costs charged to us by our general partners associated with employees who directly support us are described below. Additionally, allocated corporate expenses from Williams to us also include amounts related to these same employee benefits, which are not included in the amounts presented below. Employees supporting ACMP were not participants in the pension and other postretirement benefit plans sponsored by Williams during 2014. As a result, there are no pension and other postretirement benefit costs included in the 2014 amounts presented below associated with those employees. During 2014, employees supporting ACMP were eligible for defined contribution plans sponsored by the general partner of ACMP. The cost for the employer matching contributions for the period subsequent to July 1, 2014, is included in the defined contribution amount presented below. Effective January 1, 2015, these employees became Williams employees and eligible for certain employee benefit plans sponsored by Williams. Therefore, costs associated with these former ACMP employees are included in the 2015 and 2016 amounts presented below. Defined Benefit Pension Plans Williams has noncontributory defined benefit pension plans (Williams Pension Plan, Williams Inactive Employees Pension Plan, and The Williams Companies Retirement Restoration Plan) that provide pension benefits for its eligible employees. Pension costs charged to us by Williams for 2016 , 2015 , and 2014 totaled $32 million , $43 million , and $28 million , respectively. At the total Williams plan level, the pension plans had a projected benefit obligation of $1.5 billion at December 31, 2016 and 2015 . The plans were underfunded by $212 million and $223 million at December 31, 2016 and 2015 , respectively. Postretirement Benefits Other than Pensions Williams provides subsidized retiree health care and life insurance benefits for certain eligible participants. We recognized a net periodic postretirement benefit credited to us by Williams of $12 million , $12 million , and $14 million in 2016 , 2015 , and 2014 , respectively. At the total Williams plan level, the postretirement benefit plans had an accumulated postretirement benefit obligation of $197 million and $202 million at December 31, 2016 and 2015 , respectively. The plans were overfunded by $11 million and underfunded by $1 million at December 31, 2016 and 2015 , respectively. Any differences between the annual expense and amounts currently being recovered in rates by Transco and Northwest Pipeline are recorded as an adjustment to expense and collected or refunded through future rate adjustments. Defined Contribution Plans Williams maintains defined contribution plans for the benefit of substantially all of its employees. We were charged compensation expense of $24 million , $27 million , and $25 million in 2016 , 2015 , and 2014 , respectively, for contributions to these plans. |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Dec. 31, 2016 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment [Text Block] | Note 11 – Property, Plant and Equipment The following table presents nonregulated and regulated Property, plant, and equipment – net as presented on the Consolidated Balance Sheet for the years ended: Estimated Depreciation Useful Life (1) Rates (1) December 31, (Years) (%) 2016 2015 (Millions) Nonregulated: Natural gas gathering and processing facilities 5 - 40 $ 20,267 $ 20,636 Construction in progress Not applicable 355 740 Other 3 - 45 1,740 1,743 Regulated: Natural gas transmission facilities 1.2 - 6.97 12,692 12,189 Construction in progress Not applicable Not applicable 1,603 941 Other 5 - 45 1.35 - 33.33 1,590 1,584 Total property, plant, and equipment, at cost $ 38,247 $ 37,833 Accumulated depreciation and amortization (10,226 ) (9,233 ) Property, plant, and equipment – net $ 28,021 $ 28,600 _________________ (1) Estimated useful life and depreciation rates are presented as of December 31, 2016 . Depreciation rates and estimated useful lives for regulated assets are prescribed by the FERC. Depreciation and amortization expense for Property, plant, and equipment – net was $1,364 million , $1,348 million , and $944 million in 2016 , 2015 , and 2014 , respectively. Regulated Property, plant, and equipment – net includes approximately $665 million and $706 million at December 31, 2016 and 2015 , respectively, related to amounts in excess of the original cost of the regulated facilities within our gas pipeline businesses as a result of our prior acquisitions. This amount is being amortized over 40 years using the straight-line amortization method. Current FERC policy does not permit recovery through rates for amounts in excess of original cost of construction. Asset Retirement Obligations Our accrued obligations relate to underground storage caverns, offshore platforms and pipelines, fractionation and compression facilities, gas gathering well connections and pipelines, and gas transmission pipelines and facilities. At the end of the useful life of each respective asset, we are legally obligated to plug storage caverns and remove any related surface equipment, to restore land and remove surface equipment at gas processing, fractionation, and compression facilities, to dismantle offshore platforms and appropriately abandon offshore pipelines, to cap certain gathering pipelines at the wellhead connection and remove any related surface equipment, and to remove certain components of gas transmission facilities from the ground. The following table presents the significant changes to our ARO, of which $798 million and $857 million are included in Asset retirement obligations with the remaining portion in Asset retirement obligations under Current liabilities on the Consolidated Balance Sheet at December 31, 2016 and 2015 , respectively. December 31, 2016 2015 (Millions) Beginning balance $ 914 $ 831 Liabilities incurred 21 41 Liabilities settled (8 ) (3 ) Accretion expense 69 60 Revisions (1) (137 ) (15 ) Ending balance $ 859 $ 914 ______________ (1) Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, market risk premiums, discount rates, and the estimated remaining useful life of the assets. The 2016 revisions reflect changes in removal cost estimates, increases in the estimated remaining useful life of certain assets, and decreases in the inflation rate and discount rates used in the annual review process. The 2015 revisions reflect changes in removal cost estimates and the estimated remaining useful life of assets, a decrease in the inflation rate, and increases in the discount rates used in the annual review process. The funds Transco collects through a portion of its rates to fund its ARO are deposited into an external trust account dedicated to funding its ARO (ARO Trust). (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk .) Under its current rate settlement, Transco’s annual funding obligation is approximately $36 million , with installments to be deposited monthly. |
Goodwill and Other Intangible A
Goodwill and Other Intangible Assets | 12 Months Ended |
Dec. 31, 2016 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Goodwill and Intangible Assets Disclosure [Text Block] | Note 12 – Goodwill and Other Intangible Assets Goodwill Changes in the carrying amount of goodwill, included in Intangible assets – net of accumulated amortization , by reportable segment for the periods indicated are as follows: Central Northeast G&P West Total (Millions) December 31, 2014 $ 240 $ 835 $ 45 $ 1,120 Purchase accounting adjustment 10 13 2 25 Impairment (250 ) (848 ) — (1,098 ) December 31, 2015 $ — $ — $ 47 $ 47 December 31, 2016 $ — $ — $ 47 $ 47 Our goodwill is not subject to amortization, but is evaluated at least annually for impairment or more frequently if impairment indicators are present. We did not identify or recognize any impairments to goodwill in connection with our annual evaluation of goodwill for impairment (performed as of October 1) during the years ended December 31, 2016 and 2014 . During 2015, we performed an interim assessment of goodwill within the Central and Northeast G&P segments as of September 30, 2015, and the annual assessment of goodwill within the Northeast G&P and West segments as of October 1, 2015. The estimated fair value of the reporting units evaluated exceeded their carrying amounts, and thus no impairment was identified. We performed an additional goodwill impairment evaluation as of December 31, 2015 , of the goodwill recorded within the Central, Northeast G&P, and West segments. As a result of this evaluation, we recorded goodwill impairment charges totaling $1.098 billion . (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk .) Other Intangible Assets The gross carrying amount and accumulated amortization of other intangible assets, included in Intangible assets – net of accumulated amortization , at December 31 are as follows: 2016 2015 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization (Millions) Contractual customer relationships $ 10,634 $ (1,019 ) $ 10,632 $ (663 ) Other intangible assets primarily relate to gas gathering, processing, and fractionation contractual customer relationships recognized in the ACMP and Eagle Ford acquisitions (see Note 2 – Acquisitions ) as well as previous acquisitions. Other intangible assets are being amortized on a straight-line basis over an initial period of 30 years which represents a portion of the term over which the contractual customer relationships are expected to contribute to our cash flows. We expense costs incurred to renew or extend the terms of our gas gathering, processing, and fractionation contracts with customers. Based on the estimated future revenues during the contract periods (as estimated at the time of the respective acquisition), the weighted-average periods prior to the next renewal or extension of the contractual customer relationships associated with the ACMP and Eagle Ford acquisitions were approximately 17 years and 10 years , respectively. Although a significant portion of the expected future cash flows associated with these contracts are dependent on our ability to renew or extend the arrangements beyond the initial contract periods, these expected future cash flows are significantly influenced by the scope and pace of our producer customers’ drilling programs. Once producer customers’ wells are connected to our gathering infrastructure, their likelihood of switching to another provider before the wells are abandoned is reduced due to the significant capital investment required. The amortization expense related to other intangible assets was $356 million , $353 million , and $207 million in 2016 , 2015 , and 2014 , respectively. The estimated amortization expense for each of the next five succeeding fiscal years is approximately $356 million. |
Other Accrued Liabilities Other
Other Accrued Liabilities Other Accrued Liabilities (Notes) | 12 Months Ended |
Dec. 31, 2016 | |
Other Accrued Liabilities [Abstract] | |
Accounts Payable and Accrued Liabilities Disclosure [Text Block] | Note 13 – Other Accrued Liabilities December 31, 2016 2015 (Millions) Deferred income $ 338 $ 94 Refundable deposits 160 — Special distribution repayable to Gulfstream (See Note 7 - Investing Activities) — 149 Other, including other loss contingencies 306 226 $ 804 $ 469 Deferred income in 2016 includes cash proceeds associated with restructuring certain gas gathering contracts in the Barnett Shale and Mid-Continent regions. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies .) Refundable deposits in 2016 includes receipts to resolve several matters in relation to Transco’s Hillabee Expansion Project. In accordance with the agreement, the member–sponsors of Sabal Trail will pay us an aggregate amount of $240 million in three equal installments as certain milestones of the project are met, of which $160 million was received in 2016. We expect to recognize income associated with these receipts over the term of an underlying contract once the project is in service. |
Debt, Banking Arrangements, and
Debt, Banking Arrangements, and Leases | 12 Months Ended |
Dec. 31, 2016 | |
Debt Disclosure [Abstract] | |
Debt Disclosure [Text Block] | Note 14 – Debt, Banking Arrangements, and Leases Long-Term Debt December 31, 2016 2015 (Millions) Unsecured: Transco: 6.4% Notes due 2016 (1) $ — $ 200 6.05% Notes due 2018 250 250 7.08% Debentures due 2026 8 8 7.25% Debentures due 2026 200 200 7.85% Notes due 2026 1,000 — 5.4% Notes due 2041 375 375 4.45% Notes due 2042 400 400 Northwest Pipeline: 7% Notes due 2016 — 175 5.95% Notes due 2017 185 185 6.05% Notes due 2018 250 250 7.125% Debentures due 2025 85 85 Williams Partners L.P.: 7.25% Notes due 2017 600 600 5.25% Notes due 2020 1,500 1,500 4.125% Notes due 2020 600 600 December 31, 2016 2015 (Millions) 4% Notes due 2021 500 500 3.6% Notes due 2022 1,250 1,250 3.35% Notes due 2022 750 750 6.125% Notes due 2022 750 750 4.5% Notes due 2023 600 600 4.875% Notes due 2023 1,400 1,400 4.3% Notes due 2024 1,000 1,000 4.875% Notes due 2024 750 750 3.9% Notes due 2025 750 750 4% Notes due 2025 750 750 6.3% Notes due 2040 1,250 1,250 5.8% Notes due 2043 400 400 5.4% Notes due 2044 500 500 4.9% Notes due 2045 500 500 5.1% Notes due 2045 1,000 1,000 Term Loan, variable interest rate, due 2018 850 850 Credit facility loans — 1,310 Capital lease obligations — 1 Debt issuance costs (90 ) (91 ) Net unamortized debt premium (discount) 107 129 Long-term debt, including current portion 18,470 19,177 Long-term debt due within one year (785 ) (176 ) Long-term debt $ 17,685 $ 19,001 _____________ (1) Presented as long-term debt at December 31, 2015, due to Transco’s intent and ability to refinance. The terms of our senior unsecured notes are governed by indentures that contain covenants that, among other things, limit: (1) our ability and the ability of our subsidiaries to create liens securing indebtedness and (2) mergers, consolidations, and sales of assets. The indentures also contain customary events of default, upon which the trustee or the holders of the senior unsecured notes may declare all outstanding senior unsecured notes to be due and payable immediately. The following table presents aggregate minimum maturities of long-term debt, excluding net unamortized debt premium (discount), debt issuance costs, and capital lease obligations, for each of the next five years: December 31, (Millions) 2017 $ 785 2018 1,350 2019 — 2020 2,100 2021 500 Issuances and retirements We retired $600 million of 7.25 percent senior unsecured notes that matured on February 1, 2017. 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. On January 22, 2016, Transco, issued $1 billion of 7.85 percent senior unsecured notes due 2026 to investors in a private debt placement. In January 2017, Transco completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended. Transco used the net proceeds to repay debt and to fund capital expenditures. In December 2015, we borrowed $850 million on a variable interest rate loan with certain lenders due 2018. At December 31, 2016, the interest rate was 2.50 percent . We used the proceeds for working capital, capital expenditures, and for general partnership purposes. On April 15, 2015, we paid $783 million , including a redemption premium, to early retire $750 million of 5.875 percent senior notes due 2021 with a carrying value of $797 million . On March 3, 2015, we completed a public offering of $1.25 billion of 3.6 percent senior unsecured notes due 2022, $750 million of 4 percent senior unsecured notes due 2025, and $1 billion of 5.1 percent senior unsecured notes due 2045. We used the net proceeds to repay amounts outstanding under our commercial paper program and credit facility, to fund capital expenditures, and for general partnership purposes. We retired $750 million of 3.8 percent senior unsecured notes that matured on February 15, 2015. Credit Facilities December 31, 2016 Available Outstanding (Millions) Long-term credit facility (1) $ 3,500 $ — Letters of credit under certain bilateral bank agreements 1 __________ (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. Long-term credit facilities Prior to our merger both Pre-merger WPZ and ACMP had separate credit facilities that terminated on February 2, 2015. On February 2, 2015, we along with Transco, Northwest Pipeline, the lenders named therein and an administrative agent entered into the Second Amended & Restated Credit Agreement with aggregate commitments available of $3.5 billion , with up to an additional $500 million increase in aggregate commitments available under certain circumstances. The maturity date of the facility is February 2, 2020. However, the co-borrowers may request up to two extensions of the maturity date each for an additional one year period to allow a maturity date as late as February 2, 2022, under certain circumstances. The agreement allows for swing line loans up to an aggregate amount of $150 million , subject to available capacity under the credit facility, and letters of credit commitments of $1.125 billion . Transco and Northwest Pipeline are each able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers. On December 18, 2015, we along with Transco, Northwest Pipeline, the lenders named therein and an administrative agent entered into the Amendment No. 1 to Second Amended & Restated Credit Agreement modifying the thresholds specified in the covenant related to the maximum ratio of our debt to EBITDA. The agreement governing our credit facility contains the following terms and conditions: • Various covenants may limit, among other things, a borrower’s and its material subsidiaries’ ability to grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, enter into certain restrictive agreements, and allow any material change in the nature of its business. • If an event of default with respect to a borrower occurs under the credit facility, the lenders will be able to terminate the commitments for all borrowers and accelerate the maturity of any loans of the defaulting borrower under the credit facility agreement and exercise other rights and remedies. • Other than swing line loans, each time funds are borrowed, the borrower must choose whether such borrowing will be an alternate base rate borrowing or a Eurodollar borrowing. If such borrowing is an alternate base rate borrowing, interest is calculated on the basis of the greater of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus one half of 1 percent and (c) a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus 1 percent , plus, in the case of each of (a), (b) and (c), an applicable margin. If the borrowing is a Eurodollar borrowing, interest is calculated on the basis of LIBOR for the relevant period plus an applicable margin. Interest on swing line loans is calculated as the sum of the alternate base rate plus an applicable margin. The borrower is required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined for each borrower by reference to a pricing schedule based on such borrower’s senior unsecured long-term debt ratings. Significant financial covenants under the agreement require the ratio of debt to EBITDA, each as defined in the credit facility, be no greater than: • 5.75 to 1, for the quarters ending December 31, 2015, March 31, 2016 and June 30, 2016; • 5.50 to 1, for the quarters ending September 30, 2016 and December 31, 2016; • 5.00 to 1, for the quarter ending March 31, 2017 and each subsequent fiscal quarter, except for the the fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed, in which case the ratio of debt to EBITDA is to be no greater than 5.5 to 1. The ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent for each of Transco and Northwest Pipeline. We are in compliance with these financial covenants as measured at December 31, 2016. As of February 20, 2017, there are no amounts outstanding under our long-term credit facility. Short-term credit facility On August 26, 2015, we entered into a $1.0 billion short-term credit facility. On December 23, 2015, the capacity of this facility decreased to $150 million in conjunction with entering into the $850 million term loan. The $150 million short-term credit facility is no longer available as it expired August 24, 2016. Commercial Paper Program On February 2, 2015, we amended and restated the commercial paper program for the ACMP Merger and to allow a maximum outstanding amount of unsecured commercial paper notes of $3 billion . The maturities of the commercial paper notes vary but may not exceed 397 days from the date of issuance. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or, alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. Proceeds from these notes are used for general partnership purposes, including funding capital expenditures, working capital, and partnership distributions. We classify commercial paper outstanding in Current liabilities in the Consolidated Balance Sheet , as the outstanding notes at December 31, 2016 and December 31, 2015 , have maturity dates less than three months from the date of issuance. At December 31, 2016 , $93 million of Commercial paper was outstanding at a weighted-average interest rate of 1.06 percent . At December 31, 2015 , $499 million of Commercial paper was outstanding at a weighted-average interest rate of 0.92 percent . Cash Payments for Interest (Net of Amounts Capitalized) Cash payments for interest (net of amounts capitalized) were $891 million in 2016, $795 million in 2015, and $499 million in 2014. Leases-Lessee The future minimum annual rentals under noncancelable operating leases, are payable as follows: December 31, (Millions) 2017 $ 48 2018 44 2019 39 2020 34 2021 24 Thereafter 71 Total $ 260 Total rent expense was $59 million in 2016, $62 million in 2015, and $55 million in 2014 and primarily included in Operating and maintenance expenses and Selling, general, and administrative expenses in the Consolidated Statement of Comprehensive Income (Loss) . Other On January 25, 2017, we announced that we will redeem all of our $750 million 6.125 percent senior notes due 2022 on February 23, 2017. |
Partners' Capital
Partners' Capital | 12 Months Ended |
Dec. 31, 2016 | |
Partners' Capital Notes [Abstract] | |
Unit Transactions Disclosure [Text Block] | Note 15 – Partners’ Capital Financial Repositioning In January 2017, we announced agreements with Williams, wherein Williams permanently waived the general partner’s IDRs and converted its 2 percent general partner interest in us to a non-economic interest in exchange for 289 million newly issued common units. Pursuant to this agreement, Williams also purchased approximately 277 thousand common units for $10 million . Additionally, Williams purchased approximately 59 million common units at a price of $36.08586 per unit in a private placement transaction. According to the terms of this agreement, following our quarterly distribution in February 2017, Williams paid additional consideration of approximately $50 million to us for these units. Distribution Reinvestment Program and Other Private Placement Transactions In September 2016, we filed a Form S-3D registration statement with the Securities and Exchange Commission for our new distribution reinvestment program. The DRIP commenced with the quarterly distribution for the quarter ending September 30, 2016. Under the DRIP, registered unitholders may invest all or a portion of their cash distributions in our common units. The price for newly issued common units purchased under the DRIP is the average of the high and low trading prices of our common units for the five trading days immediately preceding the distribution, less a discount rate of 2.5 percent . The November 2016 distribution resulted in 7,891,414 common units issued at a discounted average price of $32.92 per share associated with reinvested distributions of $260 million , of which $250 million related to Williams. In August 2016, we completed an equity issuance of 6,975,446 common units sold to Williams in a private placement. The units were sold for an aggregate purchase price of $250 million . The proceeds were used to repay amounts outstanding under our credit facility and for general partnership purposes. Equity Distribution Agreement Transactions In November 2016, we issued 3,254,958 common units pursuant to an equity distribution agreement between us and certain banks resulting in net proceeds of $115 million . The net proceeds were used for general partnership purposes. We incurred commission fees of approximately $1.2 million associated with these transactions. In January 2016, we issued 18,643 common units pursuant to an equity distribution agreement between us and certain banks. The net proceeds of $414 thousand were used for general partnership purposes. We incurred commission fees of $4 thousand associated with these transactions. In November 2015, we issued 1,790,840 common units pursuant to an equity distribution agreement between us and certain banks. The net proceeds of $59 million were used for general partnership purposes. We incurred commission fees of $592 thousand associated with these transactions. In August 2014, Pre-merger WPZ issued 1,080,448 Pre-merger WPZ common units pursuant to an equity distribution agreement between Pre-merger WPZ and certain banks. The net proceeds of $55 million were used for general partnership purposes. Pre-merger WPZ incurred commission fees of $554 thousand associated with these transactions. Other In 2014, Contributions from The Williams Companies, Inc. – net within the Consolidated Statement of Changes in Equity includes the partners’ equity interests in ACMP as of July 1, 2014, presented within the capital account of the general partner for interests owned by Williams and noncontrolling interests for interests held by the public. Additionally, activity associated with the partners’ equity interests in ACMP during the period under common control until the ACMP Merger date has been presented accordingly within the capital account of the general partner for the interests owned by Williams or noncontrolling interests for interests held by the public. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies .) Limited Partners’ Rights Significant rights of the limited partners include the following: • Right to receive distributions of available cash within 45 days after the end of each quarter. • No limited partner shall have any management control over our business and affairs; the general partner shall conduct, direct and manage our activities. • The general partner may be removed if such removal is approved by the unitholders holding at least 66 2/3 percent of the outstanding units voting as a single class, including units held by our general partner and its affiliates. Incentive Distribution Rights Prior to the previously described Financial Repositioning in January 2017, our general partner was entitled to incentive distributions if the amount we distribute to unitholders with respect to any quarter exceeds specified target levels shown below: Total Quarterly Distribution per unit Unitholders General Partner Minimum Quarterly Distribution $0.3375 98% 2% First Target Distribution Up to $0.388125 98 2 Second Target Distribution Above $0.388125 up to $0.421875 85 15 Third Target Distribution Above $0.421875 up to $0.50625 75 25 Thereafter Above $0.50625 50 50 In the event of liquidation, all property and cash in excess of that required to discharge all liabilities will be distributed to the unitholders and our general partner in proportion to their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation. Issuances of Additional Partnership Securities Our partnership agreement allows us to issue additional partnership securities for any partnership purpose at any time and from time to time for consideration and on terms and conditions as our general partner determines, all without the approval of any limited partners. |
Equity-Based Compensation
Equity-Based Compensation | 12 Months Ended |
Dec. 31, 2016 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Equity-Based Compensation [Text Block] | Note 16 – Equity-Based Compensation Williams’ Plan Information The Williams Companies, Inc. 2007 Incentive Plan (Plan) provides for Williams common-stock-based awards to both employees and nonmanagement directors. The Plan permits the granting of various types of awards including, but not limited to, stock options and restricted stock units. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets being achieved. Williams bills us directly for compensation expense related to stock-based compensation awards based on the fair value of the awards. Operating and maintenance expenses and Selling, general, and administrative expenses include equity-based compensation expense for the years ended December 31, 2016 , 2015 , and 2014 of $20 million , $19 million and $14 million , respectively. Williams Partners’ Plan Information During 2014, certain employees of ACMP’s general partner received equity-based compensation through ACMP’s equity-based compensation program. The fair value of the awards issued was based on the fair market value of the common units on the date of grant. This value is being amortized over the vesting period, which is one to four years from the date of grant. These awards were converted to WPZ equity-based awards in accordance with the terms of the ACMP Merger. No additional grants of restricted common units were awarded through Williams Partners’ equity-based compensation programs in 2016 or 2015, and no additional grants are expected in the future. Operating and maintenance expenses and Selling, general, and administrative expenses include equity-based compensation expense related to Williams Partners’ equity-based compensation program of $16 million , $26 million , and $11 million for the years ended December 31, 2016 , 2015 , and 2014, respectively. As of December 31, 2016 , there was $11 million of unrecognized compensation expense attributable to the outstanding awards, which does not include the effect of estimated forfeitures of $1 million . These amounts are expected to be recognized over a weighted average period of 1.2 years . The following summary reflects nonvested restricted common unit activity for awards issued by Williams Partners and related information for the year ended December 31, 2016 : Restricted Common Units Outstanding Units Weighted- Average Fair Value (Millions) Nonvested at December 31, 2015 1.2 $ 55.93 Forfeited (0.1 ) $ 52.85 Vested (0.5 ) $ 59.09 Nonvested at December 31, 2016 0.6 $ 52.97 |
Fair Value Measurements, Guaran
Fair Value Measurements, Guarantees, and Concentration of Credit Risk | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements Guarantees and Concentration of Credit Risk [Text Block] | Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk 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 December 31, 2016: Measured on a recurring basis: ARO Trust investments $ 96 $ 96 $ 96 $ — $ — Energy derivatives assets designated as hedging instruments 2 2 — 2 — Energy derivatives assets not designated as hedging instruments 1 1 — — 1 Energy derivatives liabilities not designated as hedging instruments (6 ) (6 ) — — (6 ) Additional disclosures: Other receivables 15 15 15 — — Long-term debt, including current portion (18,470 ) (18,907 ) — (18,907 ) — 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 that is specifically designated to fund future asset retirement obligations. 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 deferred charges 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 years ended December 31, 2016 or 2015 . Additional fair value disclosures Other receivables : Other receivables primarily consist of margin deposits, which are reported in Other current assets and deferred charges 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 We performed an interim assessment of the goodwill associated with our Central Region and Northeast Region reporting units within the Central and Northeast G&P segments, respectively, as of September 30, 2015. We performed the annual assessment of goodwill associated with our Northeast G&P and West G&P reporting units as of October 1, 2015. No impairment charges were required following these evaluations. During the fourth quarter of 2015, we observed a significant decline in the market values of WPZ and comparable midstream companies within the industry. This served to reduce our estimate of enterprise value and increased our estimates of discount rates. As a result, we performed an impairment assessment as of December 31, 2015, of the goodwill associated with these reporting units. We estimated the fair value of each reporting unit based on an income approach utilizing discount rates specific to the underlying businesses of each reporting unit. 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. Weighted-average discount rates utilized ranged from approximately 11 percent to 13 percent across the four reporting units. As a result of the increases in discount rates during the fourth quarter of 2015, coupled with certain reductions in estimated future cash flows determined during the same period, the fair values of the Central Region, Northeast Region and Northeast G&P reporting units were determined to be below their respective carrying values. We then calculated the implied fair value of goodwill by performing a hypothetical application of the acquisition method wherein the estimated fair value was allocated to the underlying assets and liabilities of each reporting unit. As a result of these Level 3 measurements, we determined that the previously recorded goodwill associated with each reporting unit was fully impaired, resulting in a fourth-quarter 2015 noncash charge of $1,098 million , reflected in Impairment of goodwill in the Consolidated Statement of Comprehensive Income (Loss) . For the West G&P reporting unit, the estimated fair value exceeded the carrying value and no impairment was recorded. The following table presents impairments of assets and investments associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy. Impairments Years Ended December 31, Classification Segment Date of Measurement Fair Value 2016 2015 2014 (Millions) Surplus equipment (1) Property, plant, and equipment – net Northeast G&P June 30, 2014 $ 46 $ 17 Surplus equipment (1) Property, plant, and equipment – net Northeast G&P December 31, 2014 32 13 Surplus equipment (1) Property, plant, and equipment – net Northeast G&P June 30, 2015 17 $ 20 Surplus equipment (1) Assets held for sale Central December 31, 2014 1 12 Previously capitalized project development costs (2) Property, plant, and equipment – net West December 31, 2015 13 94 Canadian operations (3) Assets held for sale NGL & Petchem Services June 30, 2016 924 $ 341 Certain gathering operations (4) Property, plant, and equipment – net Central June 30, 2016 18 48 Level 3 fair value measurements of certain assets 389 114 42 Other impairments and write-downs (5) 68 31 10 Impairment of certain assets $ 457 $ 145 $ 52 Equity-method investments (6) Investments Central and Northeast G&P September 30, 2015 $ 1,203 $ 461 Equity-method investments (7) Investments Central and Northeast G&P December 31, 2015 4,017 890 Equity-method investments (8) Investments Central and Northeast G&P March 31, 2016 1,294 $ 109 Equity-method investments (9) Investments Central and Northeast G&P December 31, 2016 1,295 318 Other equity-method investment Investments NGL & Petchem Services December 31, 2015 58 8 Other equity-method investment Investments Central March 31, 2016 — 3 Impairment of equity-method investments $ 430 $ 1,359 __________________ (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) Relates to a gas processing plant, the completion of which is considered remote due to unfavorable impact of low natural gas prices on customer drilling activities. The assessed fair value primarily represents the estimated salvage value of certain equipment measured using a market approach based on our analysis of observable inputs in the principal market. (3) Relates to our Canadian operations. We 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 reflected our estimate of the potential assumed proceeds. We disposed of our Canadian operations through a sale during the third quarter of 2016. See Note 3 – Divestiture . (4) Relates to 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. (5) Reflects multiple individually insignificant impairments and write-downs 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. (6) Relates to equity-method investments in DBJV at Central and certain of the Appalachia Midstream Investments at Northeast G&P. The historical carrying value of these investments was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with the acquisition of ACMP. 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 were 11.8 percent and 8.8 percent for DBJV and certain of the Appalachia Midstream Investments, respectively, and reflected our cost of capital as impacted by market conditions, and risks associated with the underlying businesses. (7) Relates to equity-method investments in DBJV at Central and Northeast G&P’s UEOM and Laurel Mountain investments, as well as certain of the Appalachia Midstream Investments. 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 10.8 percent to 14.4 percent and reflected further fourth-quarter 2015 increases in our cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses. (8) Relates to Central’s equity-method investment in DBJV 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. (9) Relates to equity-method investments in Ranch Westex at Central and multiple Appalachia Midstream Investments at Northeast G&P. The historical carrying value of these investments was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with the acquisition of ACMP. We estimated the fair value of these Appalachia Midstream 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, rates, and related capital spending. The discount rate utilized for the Appalachia Midstream Investments evaluation was 10.2 percent and reflected our cost of capital as impacted by market conditions and risks associated with the underlying businesses. In addition to utilizing an income approach, we also considered a market approach for certain Appalachia Midstream Investments and Ranch Westex based on an agreement reached in February 2017 to exchange our interests in DBJV and Ranch Westex for additional interests in certain Appalachia Midstream Investments and cash. 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. Concentration of Credit Risk Cash equivalents Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. Trade accounts and other receivables The following table summarizes concentration of receivables , net of allowances. December 31, 2016 2015 (Millions) NGLs, natural gas, and related products and services $ 736 $ 821 Transportation of natural gas and related products 187 202 Other 3 3 Total $ 926 $ 1,026 Customers include producers, distribution companies, industrial users, gas marketers, and pipelines primarily located in the continental United States. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. Based upon this evaluation, we may obtain collateral to support receivables. As of December 31, 2016 and 2015 , Chesapeake Energy Corporation, and its affiliates (Chesapeake), a customer primarily within our Central, Northeast G&P, and West segments, accounted for $133 million and $364 million , respectively, of the consolidated Trade accounts and other receivables balances. Revenues In 2016 and 2015, Chesapeake accounted for 14 percent and 18 percent , respectively, of our consolidated revenues. |
Contingent Liabilities and Comm
Contingent Liabilities and Commitments | 12 Months Ended |
Dec. 31, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
Contingent Liabilities and Commitments [Text Block] | Note 18 – Contingent Liabilities and Commitments 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 December 31, 2016 , we have accrued liabilities totaling $16 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 December 31, 2016 , we have accrued liabilities of $9 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 December 31, 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 (Geismar Incident). As a result, there were two fatalities and numerous individuals (including employees and contractors) reported injuries. We are addressing the following contingent liabilities 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 first two trials, for nine plaintiffs claiming personal injury, were held in Louisiana state court in Iberville Parish, Louisiana, in September and November 2016. The juries returned adverse verdicts against Williams, our subsidiary Williams Olefins, LLC, and other defendants. The defendants, including us, intend to appeal the verdicts. Trial dates for additional plaintiffs are scheduled in April 2017 and August 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 plaintiffs in the Texas cases reached a settlement, and therefore all claims asserted (or possibly asserted) by any such plaintiffs against us in the Texas cases have been fully dismissed with prejudice. On February 7, 2017, the plaintiffs in the Ohio case voluntarily dismissed the case without 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 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 Equity, L.P.’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 filed an amended complaint on August 31, 2016. On October 17, 2016, we requested the court dismiss the action. We cannot reasonably estimate a range of potential loss at this time. 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. Commitments Commitments for construction and acquisition of property, plant, and equipment are approximately $244 million at December 31, 2016 . |
Segment Disclosures
Segment Disclosures | 12 Months Ended |
Dec. 31, 2016 | |
Segment Reporting [Abstract] | |
Segment Disclosures [Text Block] | Note 19 – Segment Disclosures Our reportable segments are Central, Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies .) 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. Intersegment revenues primarily represent the sale of NGLs from our natural gas processing plants to our marketing business. 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 geographic area data includes Revenues from external customers based on product shipment origin and Long-lived assets based upon physical location: United States Canada Total (Millions) Revenues from external customers: 2016 $ 7,406 $ 85 $ 7,491 2015 7,228 103 7,331 2014 7,212 197 7,409 Long-lived assets: 2016 $ 37,683 $ — $ 37,683 2015 37,586 1,030 38,616 2014 37,798 1,095 38,893 Long-lived assets are comprised of property, plant, and equipment, goodwill, and other intangible assets. The following table reflects the reconciliation of Segment revenues to Total revenues as reported in the Consolidated Statement of Comprehensive Income (Loss) and Other financial information : Central Northeast G&P Atlantic- Gulf West NGL & Petchem Services Eliminations Total (Millions) 2016 Segment revenues: Service revenues External $ 1,228 $ 804 $ 1,939 $ 1,034 $ 168 $ — $ 5,173 Internal 13 34 13 — — (60 ) — Total service revenues 1,241 838 1,952 1,034 168 (60 ) 5,173 Product sales External — 135 244 18 1,921 — 2,318 Internal — 28 205 260 181 (674 ) — Total product sales — 163 449 278 2,102 (674 ) 2,318 Total revenues $ 1,241 $ 1,001 $ 2,401 $ 1,312 $ 2,270 $ (734 ) $ 7,491 Other financial information: Proportional Modified EBITDA of equity-method investments $ 48 $ 362 $ 287 $ — $ 57 $ — $ 754 2015 Segment revenues: Service revenues External $ 1,261 $ 803 $ 1,877 $ 1,055 $ 139 $ — $ 5,135 Internal 26 7 4 — — (37 ) — Total service revenues 1,287 810 1,881 1,055 139 (37 ) 5,135 Product sales External — 109 287 36 1,764 — 2,196 Internal — 18 176 221 157 (572 ) — Total product sales — 127 463 257 1,921 (572 ) 2,196 Total revenues $ 1,287 $ 937 $ 2,344 $ 1,312 $ 2,060 $ (609 ) $ 7,331 Other financial information: Proportional Modified EBITDA of equity-method investments $ 36 $ 349 $ 257 $ — $ 42 $ 15 $ 699 2014 Segment revenues: Service revenues External $ 666 $ 549 $ 1,497 $ 1,050 $ 126 $ — $ 3,888 Internal 12 1 4 — — (17 ) — Total service revenues 678 550 1,501 1,050 126 (17 ) 3,888 Product sales External — 225 499 70 2,727 — 3,521 Internal — 5 354 476 259 (1,094 ) — Total product sales — 230 853 546 2,986 (1,094 ) 3,521 Total revenues $ 678 $ 780 $ 2,354 $ 1,596 $ 3,112 $ (1,111 ) $ 7,409 Other financial information: Proportional Modified EBITDA of equity-method investments $ 25 $ 198 $ 151 $ — $ 50 $ 7 $ 431 The following table reflects the reconciliation of Modified EBITDA to Net income (loss) as reported in the Consolidated Statement of Comprehensive Income (Loss) : Years Ended December 31, 2016 2015 2014 (Millions) Modified EBITDA by segment: Central $ 807 $ 840 $ 419 Northeast G&P 840 753 618 Atlantic-Gulf 1,600 1,523 1,065 West 649 557 823 NGL & Petchem Services (23 ) 321 324 Other (9 ) 9 (5 ) 3,864 4,003 3,244 Accretion expense associated with asset retirement obligations for nonregulated operations (31 ) (28 ) (17 ) Depreciation and amortization expenses (1,720 ) (1,702 ) (1,151 ) Impairment of goodwill — (1,098 ) — Equity earnings (losses) 397 335 228 Impairment of equity-method investments (430 ) (1,359 ) — Other investing income (loss) – net 29 2 2 Proportional Modified EBITDA of equity-method investments (754 ) (699 ) (431 ) Interest expense (916 ) (811 ) (562 ) (Provision) benefit for income taxes 80 (1 ) (29 ) Net income (loss) $ 519 $ (1,358 ) $ 1,284 The following table reflects Total assets , Investments , and Additions to long-lived assets by reportable segments: Total Assets at December 31, Investments at December 31, Additions to Long-Lived Assets at December 31, 2016 2015 2016 2015 2016 2015 2014 (Millions) Central (1) $ 13,129 $ 13,914 $ 1,033 $ 1,050 $ 88 $ 363 $ 13,016 Northeast G&P (1) 13,324 13,827 4,289 4,823 217 560 4,497 Atlantic-Gulf 13,892 12,171 893 959 1,590 1,573 1,593 West (1) 4,715 5,035 — — 124 225 698 NGL & Petchem Services 2,304 3,306 486 504 83 236 601 Other corporate assets 207 350 — — — 3 8 Eliminations (2) (1,306 ) (733 ) — — — — — Total $ 46,265 $ 47,870 $ 6,701 $ 7,336 $ 2,102 $ 2,960 $ 20,413 (1) 2014 Additions to long-lived assets includes the acquisition-date fair value of long-lived assets from the ACMP Acquisition ( Note 2 – Acquisitions ). (2) Eliminations primarily relate to the intercompany accounts receivable generated by our cash management program. |
General, Description of Busin26
General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Principles of consolidation [Policy Text Block] | Principles of consolidation The consolidated financial statements include the accounts of all entities that we control and our proportionate interest in the accounts of certain ventures in which we own an undivided interest. Management’s judgment is required to evaluate whether we control an entity. Key areas of that evaluation include: • Determining whether an entity is a variable interest entity (VIE); • Determining whether we are the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that we and our related parties have over those activities through our variable interests; • Identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating whether we are a VIE’s primary beneficiary; • Evaluating whether other owners in entities that are not VIEs are able to effectively participate in significant decisions that would be expected to be made in the ordinary course of business such that we do not have the power to control such entities. We apply the equity method of accounting to investments over which we exercise significant influence but do not control. |
Common control transactions [Policy Text Block] | Common control transactions Entities and assets acquired from Williams and its affiliates are accounted for as common control transactions whereby the net assets acquired are combined with ours at their historical amounts. If any cash consideration transferred to Williams in such a transaction exceeds the carrying value of the net assets acquired, the excess is treated as a capital transaction with our general partner, similar to a dividend. If the carrying value of the net assets acquired exceeds any cash consideration transferred and limited partner units are also issued as consideration, then the limited partner units are recorded at an amount equal to the excess of the carrying value of the net assets acquired over any cash consideration transferred. To the extent that such transactions require prior periods to be recast, historical net equity amounts prior to the transaction date are reflected in the account of the general partner or noncontrolling interests, if applicable. Cash consideration up to the carrying value of net assets acquired is presented as an investing activity in our Consolidated Statement of Cash Flows . Cash consideration in excess of the carrying value of net assets acquired is presented as a financing activity in our Consolidated Statement of Cash Flows . |
Equity Method Investment Basis Difference Policy [Policy Textblock] | Equity-method investment basis differences Differences between the cost of our equity-method investments and our underlying equity in the net assets of investees are accounted for as if the investees were consolidated subsidiaries. Equity earnings (losses) in the Consolidated Statement of Comprehensive Income (Loss) includes our allocable share of net income (loss) of investees adjusted for any depreciation and amortization, as applicable, associated with basis differences. |
Use of estimates [Policy Text Block] | Use of estimates 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. Significant estimates and assumptions include: • Impairment assessments of investments, property, plant, and equipment, goodwill, and other identifiable intangible assets; • Litigation-related contingencies; • Environmental remediation obligations; • Depreciation and/or amortization of equity-method investment basis differences; • Asset retirement obligations; • Acquisition related purchase price allocations. These estimates are discussed further throughout these notes. |
Regulatory Accounting [Policy Text Block] | Regulatory accounting Transco and Northwest Pipeline are regulated by the Federal Energy Regulatory Commission (FERC). Their rates, which are established by the FERC, are designed to recover the costs of providing the regulated services, and their competitive environment makes it probable that such rates can be charged and collected. Therefore, our management has determined that it is appropriate under Accounting Standards Codification (ASC) Topic 980, “Regulated Operations”, to account for and report regulatory assets and liabilities related to these operations consistent with the economic effect of the way in which their rates are established. Accounting for these operations that are regulated can differ from the accounting requirements for nonregulated operations. For example, for regulated operations, allowance for funds used during construction (AFUDC) represents the estimated cost of debt and equity funds applicable to utility plant in process of construction and is capitalized as a cost of property, plant, and equipment because it constitutes an actual cost of construction under established regulatory practices; nonregulated operations are only allowed to capitalize the cost of debt funds related to construction activities, while a component for equity is prohibited. The components of our regulatory assets and liabilities relate to the effects of deferred taxes on equity funds used during construction, asset retirement obligations, fuel cost differentials, levelized incremental depreciation, negative salvage, and pension and other postretirement benefits. Our current and noncurrent regulatory asset and liability balances for the years ended December 31, 2016 and 2015 are as follows: December 31, 2016 2015 (Millions) Current assets reported within Other current assets and deferred charges $ 91 $ 84 Noncurrent assets reported within Regulatory assets, deferred charges, and other 299 305 Total regulated assets $ 390 $ 389 Current liabilities reported within Other accrued liabilities $ 11 $ 4 Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other 480 409 Total regulated liabilities $ 491 $ 413 |
Cash and cash equivalents [Policy Text Block] | Cash and cash equivalents Cash and cash equivalents in the Consolidated Balance Sheet includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired. |
Accounts receivable [Policy Text Block] | Accounts receivable Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. We consider receivables past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time full payment is received or collectability is assured. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. |
Inventory valuation [Policy Text Block] | Inventories Inventories in the Consolidated Balance Sheet consist of natural gas liquids, olefins, natural gas in underground storage, and materials and supplies and are stated at the lower of cost or market. The cost of inventories is primarily determined using the average-cost method. |
Property, plant, and equipment [Policy Text Block] | Property, plant, and equipment Property, plant, and equipment is recorded at cost. We base the carrying value of these assets on estimates, assumptions, and judgments relative to capitalized costs, useful lives, and salvage values. As regulated entities, Northwest Pipeline and Transco provide for depreciation using the straight-line method at FERC-prescribed rates. Depreciation for nonregulated entities is provided primarily on the straight-line method over estimated useful lives, except for certain offshore facilities that apply an accelerated depreciation method. Gains or losses from the ordinary sale or retirement of property, plant, and equipment for regulated pipelines are credited or charged to accumulated depreciation. Other gains or losses are recorded in Other (income) expense – net included in Operating income (loss) in the Consolidated Statement of Comprehensive Income (Loss) . Ordinary maintenance and repair costs are generally expensed as incurred. Costs of major renewals and replacements are capitalized as property, plant, and equipment. We record a liability and increase the basis in the underlying asset for the present value of each expected future asset retirement obligation (ARO) at the time the liability is initially incurred, typically when the asset is acquired or constructed. As regulated entities, Northwest Pipeline and Transco offset the depreciation of the underlying asset that is attributable to capitalized ARO cost to a regulatory asset as management expects to recover these amounts in future rates. We measure changes in the liability due to passage of time by applying an interest rate to the liability balance. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in Operating and maintenance expenses in the Consolidated Statement of Comprehensive Income (Loss) , except for regulated entities, for which the liability is offset by a regulatory asset. The regulatory asset is amortized commensurate with our collection of those costs in rates. Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium. |
Goodwill [Policy Text Block] | Goodwill Goodwill included within Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet represents the excess of the consideration, plus the fair value of any noncontrolling interest or any previously held equity interest, over the fair value of the net assets acquired. It is not subject to amortization but is evaluated annually as of October 1 for impairment or more frequently if impairment indicators are present that would indicate it is more likely than not that the fair value of the reporting unit is less than its carrying amount. As part of the evaluation, we compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in the amount of the excess. Judgments and assumptions are inherent in our management’s estimates of fair value. |
Other intangible assets [Policy Text Block] | Other intangible assets Our identifiable intangible assets included within Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet are primarily related to gas gathering, processing, and fractionation contractual customer relationships. Our intangible assets are amortized on a straight-line basis over the period in which these assets contribute to our cash flows. We evaluate these assets for changes in the expected remaining useful lives and would reflect any changes prospectively through amortization over the revised remaining useful life. |
Impairment of property, plant, and equipment, other identifiable intangible assets and investments [Policy Text Block] | Impairment of property, plant, and equipment, other identifiable intangible assets, and investments We evaluate our property, plant, and equipment and other identifiable intangible assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s 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 in the financial statements 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. For assets identified to be disposed of in the future and considered held for sale, we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change. We evaluate our 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. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. 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. Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s or investment’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal. |
Deferred revenue [Policy Text Block] | Deferred income We record a liability for deferred income related to cash received from customers in advance of providing our services. Such amounts are generally recognized in revenue upon satisfying our performance obligations, primarily providing services based on units of production or over remaining contractual service periods ranging from 1 to 25 years. Deferred income is reflected within Other accrued liabilities and Regulatory liabilities, deferred income, and other on the Consolidated Balance Sheet . (See Note 13 – Other Accrued Liabilities .) During 2016, we received cash proceeds totaling $820 million associated with restructuring certain gas gathering contracts in the Barnett Shale and Mid-Continent regions. The proceeds were recorded as deferred income and are being amortized into income in 2016 and future periods. In October 2016, we received $104 million of newly constructed assets as part of a noncash investing transaction with a customer for which we provide production handling and other services. The transaction was recorded in Property, plant, and equipment – net and deferred income in the Consolidated Balance Sheet and is being amortized based on units of production through 2024. Due to the noncash nature of this transaction, it is not presented within the Consolidated Statement of Cash Flows . |
Contingent liabilities [Policy Text Block] | Contingent liabilities We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates. |
Cash flows from revolving credit facilities and commercial paper program [Policy Text Block] | Cash flows from revolving credit facility and commercial paper program Proceeds and payments related to borrowings under our credit facility are reflected in the financing activities in the Consolidated Statement of Cash Flows on a gross basis. Proceeds and payments related to borrowings under our commercial paper program are reflected in the financing activities in the Consolidated Statement of Cash Flows on a net basis, as the outstanding notes generally have maturity dates less than three months from the date of issuance. (See Note 14 – Debt, Banking Arrangements, and Leases .) |
Derivative instruments and hedging activities [Policy Text Block] | Derivative instruments and hedging activities We may utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily of swaps, futures, and forward contracts involving short- and long-term purchases and sales of energy commodities. We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, in Other current assets and deferred charges ; Regulatory assets, deferred charges, and other ; Other accrued liabilities ; or Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet . We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk .) The accounting for the changes in fair value of a commodity derivative can be summarized as follows: Derivative Treatment Accounting Method Normal purchases and normal sales exception Accrual accounting Designated in a qualifying hedging relationship Hedge accounting All other derivatives Mark-to-market accounting We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of physical energy commodities. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception. We may also designate a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in Product sales or Product costs in the Consolidated Statement of Comprehensive Income (Loss) . For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in Accumulated other comprehensive income (loss) (AOCI) in the Consolidated Balance Sheet and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in Product sales or Product costs in the Consolidated Statement of Comprehensive Income (Loss) . Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in Product sales or Product costs in the Consolidated Statement of Comprehensive Income (Loss) at that time. The change in likelihood of a forecasted transaction is a judgmental decision that includes qualitative assessments made by management. For commodity derivatives that are not designated in a hedging relationship, and for which we have not elected the normal purchases and normal sales exception, we report changes in fair value currently in Product sales or Product costs in the Consolidated Statement of Comprehensive Income (Loss) . Certain gains and losses on derivative instruments included in the Consolidated Statement of Comprehensive Income (Loss) are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception. Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives for NGL processing activities and which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. |
Revenues [Policy Text Block] | Revenue recognition Revenues As a result of the ratemaking process, certain revenues collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks. Service revenues Revenues from our interstate natural gas pipeline businesses include services pursuant to long-term firm transportation and storage agreements. These agreements provide for a reservation charge based on the volume of contracted capacity and a commodity charge based on the volume of gas delivered, both at rates specified in our FERC tariffs. We recognize revenues for reservation charges ratably over the contract period regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges, from both firm and interruptible transportation services and storage injection and withdrawal services, are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility. Certain revenues from our midstream operations include those derived from natural gas gathering, processing, treating, and compression services and are performed under volumetric-based fee contracts. These revenues are recorded when services have been performed. Certain of our gas gathering and processing agreements have minimum volume commitments. If a customer under such an agreement fails to meet its minimum volume commitment for a specified period, generally measured on an annual basis, it is obligated to pay a contractually determined fee based upon the shortfall between actual production volumes and the minimum volume commitment for that period. The revenue associated with minimum volume commitments is recognized in the period that the actual shortfall is determined and is no longer subject to future reduction or offset, which is generally at the end of the annual period or fourth quarter. Crude oil gathering and transportation revenues and offshore production handling fees are recognized when the services have been performed. Certain offshore production handling contracts contain fixed payment terms that result in the deferral of revenues until such services have been performed or such capacity has been made available. Storage revenues from our midstream operations associated with prepaid contracted storage capacity contracts are recognized on a straight-line basis over the life of the contract as services are provided. Product sales In the course of providing transportation services to customers of our interstate natural gas pipeline businesses, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. The resulting imbalances are primarily settled through the purchase and sale of gas with our customers under terms provided for in our FERC tariffs. Revenue is recognized from the sale of gas upon settlement of the transportation and exchange imbalances. We market NGLs, crude oil, natural gas, and olefins that we purchase from our producer customers as part of the overall service provided to producers. Revenues from marketing NGLs are recognized when the products have been sold and delivered. Under our keep-whole and percent-of-liquids processing contracts, we retain the rights to all or a portion of the NGLs extracted from the producers’ natural gas stream and recognize revenues when the extracted NGLs are sold and delivered. Our domestic olefins business produces olefins from purchased or produced feedstock and we recognize revenues when the olefins are sold and delivered. Our Canadian businesses that were sold in September 2016 had processing and fractionation operations where we retained certain NGLs and olefins from an upgrader’s offgas stream and we recognized revenues when the fractionated products were sold and delivered. |
Interest capitalized [Policy Text Block] | Interest capitalized We capitalize interest during construction on major projects with construction periods of at least 3 months and a total project cost in excess of $1 million . Interest is capitalized on borrowed funds and, where regulation by the FERC exists, on internally generated funds (equity AFUDC). The latter is included in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Comprehensive Income (Loss) . The rates used by regulated companies are calculated in accordance with FERC rules. Rates used by nonregulated companies are based on our average interest rate on debt. |
Employee common unit based awards [Policy Text Block] | Employee equity-based awards We recognize compensation expense on employee equity-based awards, net of estimated forfeitures, on a straight-line basis. (See Note 16 – Equity-Based Compensation .) |
Pension and other postretirement benefits [Policy Text Block] | Pension and other postretirement benefits We do not have employees. Certain of the costs charged to us by Williams associated with employees who directly support us include costs related to Williams’ pension and other postretirement benefit plans. (See Note 10 – Benefit Plans .) Although the underlying benefit plans of Williams are single-employer plans, we follow multiemployer plan accounting whereby the amount charged to us, and thus paid by us, is based on our share of net periodic benefit cost. |
Income taxes [Policy Text Block] | Income taxes We generally are not a taxable entity for income tax purposes, with the exception of Texas franchise tax and foreign income taxes associated with our Canadian operations, which were sold in September 2016. Other income taxes are generally borne by individual partners. Net income for financial statement purposes may differ significantly from taxable income of unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregated difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes in us is not available to us. Foreign deferred income taxes associated with our Canadian operations, which were sold in September 2016, have been computed using the liability method and have been provided on all temporary differences between the financial basis and the tax basis of the related assets and liabilities. Our management’s judgment and income tax assumptions are used to determine the levels, if any, of valuation allowances associated with deferred tax assets. |
Earnings (loss) per common unit [Policy Text Block] | Earnings (loss) per common unit We use the two-class method to calculate basic and diluted earnings (loss) per common unit whereby net income (loss), adjusted for items specifically allocated to our general partner, is allocated on a pro-rata basis between ownership interests. Basic and diluted earnings (loss) per common unit are based on the average number of common units outstanding. Diluted earnings (loss) per common unit includes any dilutive effect of nonvested restricted common units determined by the treasury-stock method, unless common unitholders are allocated a loss. |
Foreign Currency Translation [Policy Text Block] | Foreign currency translation Our former foreign subsidiaries used the Canadian dollar as their functional currency. Assets and liabilities of such foreign subsidiaries were translated at the spot rate in effect at the applicable reporting date, and the combined statements of comprehensive income (loss) were translated into the U.S. dollar at the average exchange rates in effect during the applicable period. The resulting cumulative translation adjustment was recorded as a separate component of AOCI in the Consolidated Balance Sheet . Transactions denominated in currencies other than the functional currency were recorded based on exchange rates at the time such transactions arose. Subsequent changes in exchange rates when the transactions were settled resulted in transaction gains and losses which were reflected in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Comprehensive Income (Loss) . All of our Canadian operations were sold in September 2016. |
General, Description of Busin27
General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of Regulatory Assets and Liabilities [Table Text Block] | Our current and noncurrent regulatory asset and liability balances for the years ended December 31, 2016 and 2015 are as follows: December 31, 2016 2015 (Millions) Current assets reported within Other current assets and deferred charges $ 91 $ 84 Noncurrent assets reported within Regulatory assets, deferred charges, and other 299 305 Total regulated assets $ 390 $ 389 Current liabilities reported within Other accrued liabilities $ 11 $ 4 Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other 480 409 Total regulated liabilities $ 491 $ 413 |
Acquisitions (Tables)
Acquisitions (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Business Acquisition [Line Items] | |
Schedule of Business Acquisitions, by Acquisition [Table Text Block] | The following table presents the allocation of the acquisition-date fair value of the major classes of the assets acquired, which are presented primarily in the Central and Northeast G&P segments, liabilities assumed, noncontrolling interest, and equity at July 1, 2014. The fair value of accounts receivable acquired equaled contractual amounts receivable. Changes to the preliminary allocation disclosed in Exhibit 99.1 of the Form 8-K dated May 6, 2015, which were recorded in the first quarter of 2015, reflect an increase of $150 million in Property, plant, and equipment and $25 million in Goodwill , and a decrease of $168 million in Other intangible assets and $7 million in Investments . These adjustments during the measurement period were not considered significant to require retrospective revisions of our financial statements. (Millions) Accounts receivable $ 168 Other current assets 63 Investments 5,865 Property, plant, and equipment 7,165 Goodwill 499 Other intangible assets 8,841 Current liabilities (408 ) Debt (4,052 ) Other noncurrent liabilities (9 ) Noncontrolling interest in ACMP’s subsidiaries (958 ) Noncontrolling interest representing ACMP public unitholders (6,544 ) Equity (10,630 ) |
Business Acquisition, Pro Forma Information [Table Text Block] | The following unaudited pro forma Total revenues and Net income (loss) attributable to controlling interests for the year ended December 31, 2014, are presented as if the ACMP Acquisition had been completed on January 1, 2014. These pro forma amounts are not necessarily indicative of what the actual results would have been if the acquisition had in fact occurred on the date or for the period indicated, nor do they purport to project Total revenues or Net income (loss) attributable to controlling interests for any future periods or as of any date. These amounts do not give effect to any potential cost savings, operating synergies, or revenue enhancements to result from the transactions or the potential costs to achieve these cost savings, operating synergies, and revenue enhancements. December 31, 2014 (Millions) Total revenues $ 7,953 Net income (loss) attributable to controlling interests $ 1,376 |
Divestiture (Tables)
Divestiture (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Schedule of Disposal Group's Income Statement Disclosures [Table Text Block] | The following table presents the results of operations for the disposal group, excluding the impairment and loss noted above. Years Ended December 31, 2016 2015 (Millions) Income (loss) before income taxes of disposal group $ (9 ) $ 6 |
Variable Interest Entities (Tab
Variable Interest Entities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Variable Interest Entity Disclosures [Abstract] | |
Schedule of Variable Interest Entities [Table Text Block] | The following table presents amounts included in our Consolidated Balance Sheet that are for the use or obligation of our consolidated VIEs: December 31, 2016 2015 Classification (Millions) Assets (liabilities): Cash and cash equivalents $ 82 $ 70 Cash and cash equivalents Accounts receivable 91 71 Trade accounts and other receivables Prepaid assets 3 2 Other current assets and deferred charges Property, plant, and equipment – net 3,024 3,000 Property, plant, and equipment – net Intangible assets – net 1,431 1,483 Intangible assets – net of accumulated amortization Accounts payable (44 ) (59 ) Accounts payable – trade Accrued liabilities (3 ) (14 ) Other accrued liabilities Current deferred revenue (63 ) (62 ) Other accrued liabilities Noncurrent asset retirement obligations (99 ) (93 ) Asset retirement obligations Noncurrent deferred revenue associated with customer advance payments (324 ) (331 ) Regulatory liabilities, deferred income, and other |
Allocation of Net Income (Los31
Allocation of Net Income (Loss) and Distributions (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Equity [Abstract] | |
Allocation of net income among our general partner, limited partners, and noncontrolling interests | The allocation of net income (loss) among our general partner, limited partners, and noncontrolling interests is as follows: Years Ended December 31, 2016 2015 2014 (Millions) Allocation of net income to general partner: Net income (loss) $ 519 $ (1,358 ) $ 1,284 Net income applicable to pre-merger operations allocated to general partner — (2 ) (95 ) Net income applicable to pre-partnership operations allocated to general partner — — (15 ) Net income applicable to noncontrolling interests (88 ) (91 ) (96 ) Costs charged directly to the general partner 1 21 1 Income (loss) subject to 2% allocation of general partner interest 432 (1,430 ) 1,079 General partner’s share of net income 2 % 2 % 2 % General partner’s allocated share of net income (loss) before items directly allocable to general partner interest 9 (29 ) 22 Priority allocations, including incentive distributions, paid to general partner 482 638 641 Pre-merger net income allocated to general partner interest — 2 95 Pre-partnership net income allocated to general partner interest — — 15 Costs charged directly to the general partner (1 ) (21 ) (1 ) Net income allocated to general partner’s equity $ 490 $ 590 $ 772 Net income (loss) $ 519 $ (1,358 ) $ 1,284 Net income allocated to general partner’s equity 490 590 772 Net income (loss) allocated to Class B limited partners’ equity (2 ) (52 ) — Net income allocated to Class D limited partners’ equity (1) — 69 62 Net income allocated to noncontrolling interests 88 91 96 Net income (loss) allocated to common limited partners’ equity $ (57 ) $ (2,056 ) $ 354 Adjustments to reconcile Net income (loss) allocated to common limited partners' equity to Allocation of net income (loss) to common units: Incentive distributions paid 474 633 640 Incentive distributions declared (473 ) (423 ) (626 ) Impact of unit issuance timing and other (2) (42 ) (9 ) (9 ) Allocation of net income (loss) to common units $ (98 ) $ (1,855 ) $ 359 ____________ (1) Includes amortization of the beneficial conversion feature associated with the Pre-merger WPZ Class D units of $68 million and $49 million for the years ended December 31, 2015 and 2014, respectively. See following discussion of Class D units. (2) The 2016 amount includes the effect of units issued and the conversion of the general partner interest in us to a non-economic interest in conjunction with our Financial Repositioning (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies .) |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Related Party Transactions [Abstract] | |
Schedule of Related Party Transactions [Table Text Block] | Summary of the related party transactions discussed in all sections above. Years Ended December 31, 2016 2015 2014 (Millions) Service revenues $ 31 $ — $ — Product costs 181 169 186 Operating and maintenance expenses - employee costs 470 498 413 Selling, general, and administrative expenses: Employee direct costs 344 368 331 Employee allocated costs 160 195 171 |
Investing Activities (Tables)
Investing Activities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Investments [Abstract] | |
Impairments [Table Text Block] | Impairment of equity-method investments The following table presents other-than-temporary impairment charges related to certain equity-method investments. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk .) Years Ended December 31, 2016 2015 (Millions) Northeast G&P Appalachia Midstream Investments $ 294 $ 562 Laurel Mountain 50 45 UEOM — 241 Central DBJV 59 503 Ranch Westex 24 — Other 3 8 $ 430 $ 1,359 |
Investments [Table Text Block] | Investments Ownership Interest at December 31, 2016 December 31, 2016 2015 (Millions) Appalachia Midstream Investments (1) $ 2,062 $ 2,464 UEOM 62% 1,448 1,525 DBJV 50% 988 977 Discovery 60% 572 602 OPPL 50% 430 445 Caiman II 58% 426 418 Laurel Mountain 69% 324 391 Gulfstream 50% 261 293 Other Various 190 221 $ 6,701 $ 7,336 ____________ (1) Includes equity-method investments in multiple gathering systems in the Marcellus Shale with an approximate average 41 percent interest. |
Contributions [Table Text Block] | Purchases of and contributions to equity-method investments We generally fund our portion of significant expansion or development projects of these investees through additional capital contributions. These transactions increased the carrying value of our investments and included: Years Ended December 31, 2016 2015 2014 (Millions) DBJV $ 105 $ 57 $ 20 Appalachia Midstream Investments 28 93 84 Caiman II 22 — 175 UEOM — 357 57 Discovery — 35 106 Other 22 52 26 $ 177 $ 594 $ 468 |
Dividends and distributions [Table Text Block] | Dividends and distributions The organizational documents of entities in which we have an equity-method interest generally require distribution of available cash to members on at least a quarterly basis. These transactions reduced the carrying value of our investments and included: Years Ended December 31, 2016 2015 2014 (Millions) Appalachia Midstream Investments $ 211 $ 219 $ 130 Discovery 141 116 36 Gulfstream 100 88 81 UEOM 92 42 — OPPL 69 45 27 Caiman II 40 33 13 DBJV 39 33 — Laurel Mountain 28 31 39 Other 22 26 39 $ 742 $ 633 $ 365 |
Summarized Financial Position and Results of Operations of Equity Method Investments [Table Text Block] | Summarized Financial Position and Results of Operations of All Equity-Method Investments December 31, 2016 2015 (Millions) Assets (liabilities): Current assets $ 508 $ 773 Noncurrent assets 9,695 9,549 Current liabilities (412 ) (633 ) Noncurrent liabilities (1,484 ) (1,450 ) Years Ended December 31, 2016 2015 2014 (Millions) Gross revenue $ 1,883 $ 1,707 $ 1,623 Operating income 799 690 534 Net income 726 611 460 |
Other Income and Expenses (Tabl
Other Income and Expenses (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Other Income and Expenses [Abstract] | |
Schedule of Other Operating Cost and Expense, by Component [Table Text Block] | The following table presents certain gains or losses reflected in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Comprehensive Income (Loss) : Years Ended December 31, 2016 2015 2014 (Millions) Central Loss related to sale of certain assets $ — $ — $ 10 Northeast G&P Contingency gain settlement (1) — — (154 ) Net gain related to partial acreage dedication release — — (12 ) Atlantic-Gulf Amortization of regulatory assets associated with asset retirement obligations 33 33 33 Accrual of regulatory liability related to overcollection of certain employee expenses 25 20 14 Project development costs related to Constitution (Note 4) 28 — — Gain on asset retirement (11 ) — — NGL & Petchem Services Loss on sale of Canadian operations (Note 3) 34 — — Net foreign currency exchange (gains) losses (2) 10 (10 ) (3 ) __________ (1) In November 2014, we settled a claim arising from the resolution of a contingent gain related to claims associated with the purchase of a business in a prior period. Pursuant to the settlement, we received $154 million in cash, all of which was recognized as a gain in the fourth quarter of 2014. (2) Primarily relates to gains and losses incurred on foreign currency transactions and the remeasurement of U.S. dollar-denominated current assets and liabilities within our former Canadian operations (see Note 3 – Divestiture ). |
Restructuring and Related Costs [Table Text Block] | Amounts by segment are as follows: Year Ended December 31, 2016 (Millions) Central $ 8 Northeast G&P 3 Atlantic-Gulf 8 West 5 NGL & Petchem Services 4 Other 9 |
Provision (Benefit) for Incom35
Provision (Benefit) for Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block] | The Provision (benefit) for income taxes includes: Years Ended December 31, 2016 2015 2014 (Millions) Current: State $ 2 $ (3 ) $ 3 Foreign 1 — 1 3 (3 ) 4 Deferred: State (1 ) (3 ) 8 Foreign (82 ) 7 17 (83 ) 4 25 Provision (benefit) for income taxes $ (80 ) $ 1 $ 29 |
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | Reconciliations from the Provision (benefit) at statutory rate to recorded Provision (benefit) for income taxes are as follows: Years Ended December 31, 2016 2015 2014 (Millions) Provision (benefit) at statutory rate $ 154 $ (475 ) $ 459 Increases (decreases) in taxes resulting from: Income not subject to U.S. federal tax (154 ) 475 (459 ) State income taxes 1 (6 ) 11 Foreign operations — net (81 ) 7 18 Provision (benefit) for income taxes $ (80 ) $ 1 $ 29 |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Property, Plant and Equipment [Abstract] | |
Propertyl, Plant, and Equipment [Table Text Block] | The following table presents nonregulated and regulated Property, plant, and equipment – net as presented on the Consolidated Balance Sheet for the years ended: Estimated Depreciation Useful Life (1) Rates (1) December 31, (Years) (%) 2016 2015 (Millions) Nonregulated: Natural gas gathering and processing facilities 5 - 40 $ 20,267 $ 20,636 Construction in progress Not applicable 355 740 Other 3 - 45 1,740 1,743 Regulated: Natural gas transmission facilities 1.2 - 6.97 12,692 12,189 Construction in progress Not applicable Not applicable 1,603 941 Other 5 - 45 1.35 - 33.33 1,590 1,584 Total property, plant, and equipment, at cost $ 38,247 $ 37,833 Accumulated depreciation and amortization (10,226 ) (9,233 ) Property, plant, and equipment – net $ 28,021 $ 28,600 _________________ (1) Estimated useful life and depreciation rates are presented as of December 31, 2016 . Depreciation rates and estimated useful lives for regulated assets are prescribed by the FERC. |
Asset Retirement Obligation [Table Text Block] | The following table presents the significant changes to our ARO, of which $798 million and $857 million are included in Asset retirement obligations with the remaining portion in Asset retirement obligations under Current liabilities on the Consolidated Balance Sheet at December 31, 2016 and 2015 , respectively. December 31, 2016 2015 (Millions) Beginning balance $ 914 $ 831 Liabilities incurred 21 41 Liabilities settled (8 ) (3 ) Accretion expense 69 60 Revisions (1) (137 ) (15 ) Ending balance $ 859 $ 914 ______________ (1) Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, market risk premiums, discount rates, and the estimated remaining useful life of the assets. The 2016 revisions reflect changes in removal cost estimates, increases in the estimated remaining useful life of certain assets, and decreases in the inflation rate and discount rates used in the annual review process. The 2015 revisions reflect changes in removal cost estimates and the estimated remaining useful life of assets, a decrease in the inflation rate, and increases in the discount rates used in the annual review process. |
Goodwill and Other Intangible37
Goodwill and Other Intangible Assets (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Schedule of Goodwill [Table Text Block] | Goodwill Changes in the carrying amount of goodwill, included in Intangible assets – net of accumulated amortization , by reportable segment for the periods indicated are as follows: Central Northeast G&P West Total (Millions) December 31, 2014 $ 240 $ 835 $ 45 $ 1,120 Purchase accounting adjustment 10 13 2 25 Impairment (250 ) (848 ) — (1,098 ) December 31, 2015 $ — $ — $ 47 $ 47 December 31, 2016 $ — $ — $ 47 $ 47 |
Schedule of Finite-Lived Intangible Assets [Table Text Block] | Other Intangible Assets The gross carrying amount and accumulated amortization of other intangible assets, included in Intangible assets – net of accumulated amortization , at December 31 are as follows: 2016 2015 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization (Millions) Contractual customer relationships $ 10,634 $ (1,019 ) $ 10,632 $ (663 ) |
Other Accrued Liabilities Oth38
Other Accrued Liabilities Other Accrued Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Other Accrued Liabilities [Abstract] | |
Schedule of Accrued Liabilities [Table Text Block] | December 31, 2016 2015 (Millions) Deferred income $ 338 $ 94 Refundable deposits 160 — Special distribution repayable to Gulfstream (See Note 7 - Investing Activities) — 149 Other, including other loss contingencies 306 226 $ 804 $ 469 |
Debt, Banking Arrangements, a39
Debt, Banking Arrangements, and Leases (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Debt Disclosure [Abstract] | |
Schedule of Long-term Debt Instruments [Table Text Block] | Long-Term Debt December 31, 2016 2015 (Millions) Unsecured: Transco: 6.4% Notes due 2016 (1) $ — $ 200 6.05% Notes due 2018 250 250 7.08% Debentures due 2026 8 8 7.25% Debentures due 2026 200 200 7.85% Notes due 2026 1,000 — 5.4% Notes due 2041 375 375 4.45% Notes due 2042 400 400 Northwest Pipeline: 7% Notes due 2016 — 175 5.95% Notes due 2017 185 185 6.05% Notes due 2018 250 250 7.125% Debentures due 2025 85 85 Williams Partners L.P.: 7.25% Notes due 2017 600 600 5.25% Notes due 2020 1,500 1,500 4.125% Notes due 2020 600 600 December 31, 2016 2015 (Millions) 4% Notes due 2021 500 500 3.6% Notes due 2022 1,250 1,250 3.35% Notes due 2022 750 750 6.125% Notes due 2022 750 750 4.5% Notes due 2023 600 600 4.875% Notes due 2023 1,400 1,400 4.3% Notes due 2024 1,000 1,000 4.875% Notes due 2024 750 750 3.9% Notes due 2025 750 750 4% Notes due 2025 750 750 6.3% Notes due 2040 1,250 1,250 5.8% Notes due 2043 400 400 5.4% Notes due 2044 500 500 4.9% Notes due 2045 500 500 5.1% Notes due 2045 1,000 1,000 Term Loan, variable interest rate, due 2018 850 850 Credit facility loans — 1,310 Capital lease obligations — 1 Debt issuance costs (90 ) (91 ) Net unamortized debt premium (discount) 107 129 Long-term debt, including current portion 18,470 19,177 Long-term debt due within one year (785 ) (176 ) Long-term debt $ 17,685 $ 19,001 _____________ (1) Presented as long-term debt at December 31, 2015, due to Transco’s intent and ability to refinance. |
Schedule of Maturities of Long-term Debt [Table Text Block] | The following table presents aggregate minimum maturities of long-term debt, excluding net unamortized debt premium (discount), debt issuance costs, and capital lease obligations, for each of the next five years: December 31, (Millions) 2017 $ 785 2018 1,350 2019 — 2020 2,100 2021 500 |
Schedule of Line of Credit Facilities [Table Text Block] | Credit Facilities December 31, 2016 Available Outstanding (Millions) Long-term credit facility (1) $ 3,500 $ — Letters of credit under certain bilateral bank agreements 1 __________ (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. |
Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block] | Leases-Lessee The future minimum annual rentals under noncancelable operating leases, are payable as follows: December 31, (Millions) 2017 $ 48 2018 44 2019 39 2020 34 2021 24 Thereafter 71 Total $ 260 |
Partners' Capital (Tables)
Partners' Capital (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Partners' Capital Notes [Abstract] | |
Incentive Distribution Percentage By Specified Target Level [Table Text Block] | Incentive Distribution Rights Prior to the previously described Financial Repositioning in January 2017, our general partner was entitled to incentive distributions if the amount we distribute to unitholders with respect to any quarter exceeds specified target levels shown below: Total Quarterly Distribution per unit Unitholders General Partner Minimum Quarterly Distribution $0.3375 98% 2% First Target Distribution Up to $0.388125 98 2 Second Target Distribution Above $0.388125 up to $0.421875 85 15 Third Target Distribution Above $0.421875 up to $0.50625 75 25 Thereafter Above $0.50625 50 50 |
Equity-Based Compensation (Tabl
Equity-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Schedule of Nonvested Restricted Stock Units Activity [Table Text Block] | The following summary reflects nonvested restricted common unit activity for awards issued by Williams Partners and related information for the year ended December 31, 2016 : Restricted Common Units Outstanding Units Weighted- Average Fair Value (Millions) Nonvested at December 31, 2015 1.2 $ 55.93 Forfeited (0.1 ) $ 52.85 Vested (0.5 ) $ 59.09 Nonvested at December 31, 2016 0.6 $ 52.97 |
Fair Value Measurements Guarant
Fair Value Measurements Guarantees and Concentration of Credit Risk (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] | 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 December 31, 2016: Measured on a recurring basis: ARO Trust investments $ 96 $ 96 $ 96 $ — $ — Energy derivatives assets designated as hedging instruments 2 2 — 2 — Energy derivatives assets not designated as hedging instruments 1 1 — — 1 Energy derivatives liabilities not designated as hedging instruments (6 ) (6 ) — — (6 ) Additional disclosures: Other receivables 15 15 15 — — Long-term debt, including current portion (18,470 ) (18,907 ) — (18,907 ) — 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 Measurements, Nonrecurring [Table Text Block] | The following table presents impairments of assets and investments associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy. Impairments Years Ended December 31, Classification Segment Date of Measurement Fair Value 2016 2015 2014 (Millions) Surplus equipment (1) Property, plant, and equipment – net Northeast G&P June 30, 2014 $ 46 $ 17 Surplus equipment (1) Property, plant, and equipment – net Northeast G&P December 31, 2014 32 13 Surplus equipment (1) Property, plant, and equipment – net Northeast G&P June 30, 2015 17 $ 20 Surplus equipment (1) Assets held for sale Central December 31, 2014 1 12 Previously capitalized project development costs (2) Property, plant, and equipment – net West December 31, 2015 13 94 Canadian operations (3) Assets held for sale NGL & Petchem Services June 30, 2016 924 $ 341 Certain gathering operations (4) Property, plant, and equipment – net Central June 30, 2016 18 48 Level 3 fair value measurements of certain assets 389 114 42 Other impairments and write-downs (5) 68 31 10 Impairment of certain assets $ 457 $ 145 $ 52 Equity-method investments (6) Investments Central and Northeast G&P September 30, 2015 $ 1,203 $ 461 Equity-method investments (7) Investments Central and Northeast G&P December 31, 2015 4,017 890 Equity-method investments (8) Investments Central and Northeast G&P March 31, 2016 1,294 $ 109 Equity-method investments (9) Investments Central and Northeast G&P December 31, 2016 1,295 318 Other equity-method investment Investments NGL & Petchem Services December 31, 2015 58 8 Other equity-method investment Investments Central March 31, 2016 — 3 Impairment of equity-method investments $ 430 $ 1,359 __________________ (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) Relates to a gas processing plant, the completion of which is considered remote due to unfavorable impact of low natural gas prices on customer drilling activities. The assessed fair value primarily represents the estimated salvage value of certain equipment measured using a market approach based on our analysis of observable inputs in the principal market. (3) Relates to our Canadian operations. We 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 reflected our estimate of the potential assumed proceeds. We disposed of our Canadian operations through a sale during the third quarter of 2016. See Note 3 – Divestiture . (4) Relates to 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. (5) Reflects multiple individually insignificant impairments and write-downs 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. (6) Relates to equity-method investments in DBJV at Central and certain of the Appalachia Midstream Investments at Northeast G&P. The historical carrying value of these investments was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with the acquisition of ACMP. 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 were 11.8 percent and 8.8 percent for DBJV and certain of the Appalachia Midstream Investments, respectively, and reflected our cost of capital as impacted by market conditions, and risks associated with the underlying businesses. (7) Relates to equity-method investments in DBJV at Central and Northeast G&P’s UEOM and Laurel Mountain investments, as well as certain of the Appalachia Midstream Investments. 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 10.8 percent to 14.4 percent and reflected further fourth-quarter 2015 increases in our cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses. (8) Relates to Central’s equity-method investment in DBJV 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. (9) Relates to equity-method investments in Ranch Westex at Central and multiple Appalachia Midstream Investments at Northeast G&P. The historical carrying value of these investments was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with the acquisition of ACMP. We estimated the fair value of these Appalachia Midstream 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, rates, and related capital spending. The discount rate utilized for the Appalachia Midstream Investments evaluation was 10.2 percent and reflected our cost of capital as impacted by market conditions and risks associated with the underlying businesses. In addition to utilizing an income approach, we also considered a market approach for certain Appalachia Midstream Investments and Ranch Westex based on an agreement reached in February 2017 to exchange our interests in DBJV and Ranch Westex for additional interests in certain Appalachia Midstream Investments and cash. |
Concentration of receivables, net of allowances, by product or service [Table Text Block] | Trade accounts and other receivables The following table summarizes concentration of receivables , net of allowances. December 31, 2016 2015 (Millions) NGLs, natural gas, and related products and services $ 736 $ 821 Transportation of natural gas and related products 187 202 Other 3 3 Total $ 926 $ 1,026 |
Segment Disclosures (Tables)
Segment Disclosures (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Segment Reporting [Abstract] | |
Schedule of Revenue from External Customers and Long-Lived Assets, by Geographical Areas [Table Text Block] | The following geographic area data includes Revenues from external customers based on product shipment origin and Long-lived assets based upon physical location: United States Canada Total (Millions) Revenues from external customers: 2016 $ 7,406 $ 85 $ 7,491 2015 7,228 103 7,331 2014 7,212 197 7,409 Long-lived assets: 2016 $ 37,683 $ — $ 37,683 2015 37,586 1,030 38,616 2014 37,798 1,095 38,893 Long-lived assets are comprised of property, plant, and equipment, goodwill, and other intangible assets. |
Reconciliation of revenue from segment to consolidated [Table Text Block] | The following table reflects the reconciliation of Segment revenues to Total revenues as reported in the Consolidated Statement of Comprehensive Income (Loss) and Other financial information : Central Northeast G&P Atlantic- Gulf West NGL & Petchem Services Eliminations Total (Millions) 2016 Segment revenues: Service revenues External $ 1,228 $ 804 $ 1,939 $ 1,034 $ 168 $ — $ 5,173 Internal 13 34 13 — — (60 ) — Total service revenues 1,241 838 1,952 1,034 168 (60 ) 5,173 Product sales External — 135 244 18 1,921 — 2,318 Internal — 28 205 260 181 (674 ) — Total product sales — 163 449 278 2,102 (674 ) 2,318 Total revenues $ 1,241 $ 1,001 $ 2,401 $ 1,312 $ 2,270 $ (734 ) $ 7,491 Other financial information: Proportional Modified EBITDA of equity-method investments $ 48 $ 362 $ 287 $ — $ 57 $ — $ 754 2015 Segment revenues: Service revenues External $ 1,261 $ 803 $ 1,877 $ 1,055 $ 139 $ — $ 5,135 Internal 26 7 4 — — (37 ) — Total service revenues 1,287 810 1,881 1,055 139 (37 ) 5,135 Product sales External — 109 287 36 1,764 — 2,196 Internal — 18 176 221 157 (572 ) — Total product sales — 127 463 257 1,921 (572 ) 2,196 Total revenues $ 1,287 $ 937 $ 2,344 $ 1,312 $ 2,060 $ (609 ) $ 7,331 Other financial information: Proportional Modified EBITDA of equity-method investments $ 36 $ 349 $ 257 $ — $ 42 $ 15 $ 699 2014 Segment revenues: Service revenues External $ 666 $ 549 $ 1,497 $ 1,050 $ 126 $ — $ 3,888 Internal 12 1 4 — — (17 ) — Total service revenues 678 550 1,501 1,050 126 (17 ) 3,888 Product sales External — 225 499 70 2,727 — 3,521 Internal — 5 354 476 259 (1,094 ) — Total product sales — 230 853 546 2,986 (1,094 ) 3,521 Total revenues $ 678 $ 780 $ 2,354 $ 1,596 $ 3,112 $ (1,111 ) $ 7,409 Other financial information: Proportional Modified EBITDA of equity-method investments $ 25 $ 198 $ 151 $ — $ 50 $ 7 $ 431 |
Reconciliation of Modified EBITDA to Net Income (Loss) [Table Text Block] | The following table reflects the reconciliation of Modified EBITDA to Net income (loss) as reported in the Consolidated Statement of Comprehensive Income (Loss) : Years Ended December 31, 2016 2015 2014 (Millions) Modified EBITDA by segment: Central $ 807 $ 840 $ 419 Northeast G&P 840 753 618 Atlantic-Gulf 1,600 1,523 1,065 West 649 557 823 NGL & Petchem Services (23 ) 321 324 Other (9 ) 9 (5 ) 3,864 4,003 3,244 Accretion expense associated with asset retirement obligations for nonregulated operations (31 ) (28 ) (17 ) Depreciation and amortization expenses (1,720 ) (1,702 ) (1,151 ) Impairment of goodwill — (1,098 ) — Equity earnings (losses) 397 335 228 Impairment of equity-method investments (430 ) (1,359 ) — Other investing income (loss) – net 29 2 2 Proportional Modified EBITDA of equity-method investments (754 ) (699 ) (431 ) Interest expense (916 ) (811 ) (562 ) (Provision) benefit for income taxes 80 (1 ) (29 ) Net income (loss) $ 519 $ (1,358 ) $ 1,284 |
Total assets and investments by reporting segment [Table Text Block] | The following table reflects Total assets , Investments , and Additions to long-lived assets by reportable segments: Total Assets at December 31, Investments at December 31, Additions to Long-Lived Assets at December 31, 2016 2015 2016 2015 2016 2015 2014 (Millions) Central (1) $ 13,129 $ 13,914 $ 1,033 $ 1,050 $ 88 $ 363 $ 13,016 Northeast G&P (1) 13,324 13,827 4,289 4,823 217 560 4,497 Atlantic-Gulf 13,892 12,171 893 959 1,590 1,573 1,593 West (1) 4,715 5,035 — — 124 225 698 NGL & Petchem Services 2,304 3,306 486 504 83 236 601 Other corporate assets 207 350 — — — 3 8 Eliminations (2) (1,306 ) (733 ) — — — — — Total $ 46,265 $ 47,870 $ 6,701 $ 7,336 $ 2,102 $ 2,960 $ 20,413 (1) 2014 Additions to long-lived assets includes the acquisition-date fair value of long-lived assets from the ACMP Acquisition ( Note 2 – Acquisitions ). (2) Eliminations primarily relate to the intercompany accounts receivable generated by our cash management program. |
General, Description of Busin44
General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Details) - USD ($) $ / shares in Units, $ in Millions | Feb. 10, 2017 | Jan. 09, 2017 | Sep. 28, 2015 | Feb. 10, 2017 | Feb. 03, 2017 | Jan. 31, 2017 | Oct. 31, 2016 | May 31, 2016 | Feb. 29, 2016 | Nov. 30, 2015 | Jun. 30, 2015 | Oct. 31, 2014 | Feb. 28, 2014 | Jun. 30, 2014 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Jul. 01, 2014 | Dec. 31, 2013 |
General and Description Of Business [Abstract] | |||||||||||||||||||
Parent, general partner ownership percentage | 2.00% | 2.00% | 2.00% | ||||||||||||||||
Net Proceeds from Issuance of Common Limited Partners Units | $ 614 | $ 59 | $ 55 | ||||||||||||||||
Goodwill | 47 | 47 | 1,120 | ||||||||||||||||
Regulatory Assets and Liabilities Disclosure [Abstract] | |||||||||||||||||||
Regulatory Assets, Current | 91 | 84 | |||||||||||||||||
Regulatory Assets, Noncurrent | 299 | 305 | |||||||||||||||||
Total regulatory assets | 390 | 389 | |||||||||||||||||
Regulatory Liabilities, Current | 11 | 4 | |||||||||||||||||
Regulatory Liabilities, Noncurrent | 480 | 409 | |||||||||||||||||
Total regulatory liabilities | $ 491 | 413 | |||||||||||||||||
Minimum period of construction for capitalization of interest | 3 months | ||||||||||||||||||
Minimum total project cost for capitalization of interest | $ 1 | ||||||||||||||||||
WPZ Merger Public Unit Exchange [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Termination Fee | $ 428 | ||||||||||||||||||
Maximum Reduction Of Quarterly Incentive Distributions | $ 209 | ||||||||||||||||||
Basis of Presentation [Abstract] | |||||||||||||||||||
Reduction in incentive distribution rights payment | $ 10 | $ 209 | $ 209 | ||||||||||||||||
Canada Acquisition [Member] | |||||||||||||||||||
Basis of Presentation [Abstract] | |||||||||||||||||||
Payments to Acquire Businesses, Gross | $ 56 | $ 31 | |||||||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 25,577,521 | ||||||||||||||||||
Proceeds from Previous Acquisition | $ 56 | ||||||||||||||||||
Reduction in incentive distribution rights payment | $ 2 | ||||||||||||||||||
Utica East Ohio Midstream, LLC [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Equity Method Investment, Ownership Percentage | 62.00% | ||||||||||||||||||
Basis of Presentation [Abstract] | |||||||||||||||||||
Reduction in incentive distribution rights payment | $ 2 | ||||||||||||||||||
Delaware Basin Gas Gathering System [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Equity Method Investment, Ownership Percentage | 50.00% | ||||||||||||||||||
Laurel Mountain Midstream, LLC [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Equity Method Investment, Ownership Percentage | 69.00% | ||||||||||||||||||
Caiman Energy II, LLC [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Equity Method Investment, Ownership Percentage | 58.00% | ||||||||||||||||||
Gulfstream Natural Gas System, L.L.C. [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Equity Method Investment, Ownership Percentage | 50.00% | ||||||||||||||||||
Discovery Producer Services LLC [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Equity Method Investment, Ownership Percentage | 60.00% | ||||||||||||||||||
Overland Pass Pipeline Company LLC [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Equity Method Investment, Ownership Percentage | 50.00% | ||||||||||||||||||
The Williams Companies Inc [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Parent, limited partner ownership percentage | 58.00% | ||||||||||||||||||
Parent, general partner ownership percentage | 2.00% | ||||||||||||||||||
Central [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Goodwill | $ 0 | 0 | 240 | ||||||||||||||||
Central [Member] | Access Midstream Partners Acquisition [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Goodwill | $ 499 | ||||||||||||||||||
Central [Member] | Delaware Basin Gas Gathering System [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Equity Method Investment, Ownership Percentage | 50.00% | ||||||||||||||||||
Northeast G&P [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Goodwill | $ 0 | 0 | 835 | ||||||||||||||||
Northeast G&P [Member] | Utica East Ohio Midstream, LLC [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Equity Method Investment, Ownership Percentage | 62.00% | ||||||||||||||||||
Northeast G&P [Member] | Appalachia Midstream Services, LLC [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Subsidiary, ownership percentage | 41.00% | ||||||||||||||||||
Northeast G&P [Member] | Laurel Mountain Midstream, LLC [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Equity Method Investment, Ownership Percentage | 69.00% | ||||||||||||||||||
Northeast G&P [Member] | Caiman Energy II, LLC [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Equity Method Investment, Ownership Percentage | 58.00% | ||||||||||||||||||
Northeast G&P [Member] | Cardinal Gas Services LLC [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Variable Interest Entity Ownership Percentage | 66.00% | ||||||||||||||||||
Atlantic Gulf [Member] | Gulfstream Natural Gas System, L.L.C. [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Equity Method Investment, Ownership Percentage | 50.00% | ||||||||||||||||||
Atlantic Gulf [Member] | Discovery Producer Services LLC [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Equity Method Investment, Ownership Percentage | 60.00% | ||||||||||||||||||
Atlantic Gulf [Member] | Gulfstar One [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Variable Interest Entity Ownership Percentage | 51.00% | ||||||||||||||||||
Atlantic Gulf [Member] | Constitution Pipeline Company LLC [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Variable Interest Entity Ownership Percentage | 41.00% | ||||||||||||||||||
NGL And Petchem Services [Member] | Geismar [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Subsidiary, ownership percentage | 88.50% | ||||||||||||||||||
NGL And Petchem Services [Member] | Conway Fractionator [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Subsidiary, ownership percentage | 50.00% | ||||||||||||||||||
NGL And Petchem Services [Member] | Overland Pass Pipeline Company LLC [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Equity Method Investment, Ownership Percentage | 50.00% | ||||||||||||||||||
West [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Goodwill | $ 47 | $ 47 | $ 45 | ||||||||||||||||
General Partner [Member] | Access Midstream Partners Acquisition [Member] | |||||||||||||||||||
Basis of Presentation [Abstract] | |||||||||||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 50.00% | 50.00% | |||||||||||||||||
Contracts in Barnett Shale and Mid-Continent regions [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Deferred Revenue, Additions | $ 820 | ||||||||||||||||||
Newly constructed assets [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Deferred Revenue, Additions | $ 104 | ||||||||||||||||||
Financial Repositioning [Member] | Subsequent Event [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Net Proceeds from Issuance of Common Limited Partners Units | $ 50 | $ 10 | |||||||||||||||||
Partners' Capital Account, Units, Sold in Private Placement | 59,000,000 | ||||||||||||||||||
Financial Repositioning [Member] | Subsequent Event [Member] | The Williams Companies Inc [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Parent, limited partner ownership percentage | 74.00% | ||||||||||||||||||
Parent, general partner ownership percentage | 2.00% | ||||||||||||||||||
Partners' Capital Account, Units, Sale of Units | 277,000 | 289,000,000 | |||||||||||||||||
Net Proceeds from Issuance of Common Limited Partners Units | $ 50 | $ 10 | |||||||||||||||||
Partners' Capital Account, Units, Sold in Private Placement | 59,000,000 | ||||||||||||||||||
Shares Issued, Price Per Share | $ 36.08586 | ||||||||||||||||||
Minimum [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Duration Of Period For Deferred Revenue Recognition | 1 year | ||||||||||||||||||
Maximum [Member] | |||||||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||||||
Duration Of Period For Deferred Revenue Recognition | 25 years |
Acquisitions (Details)
Acquisitions (Details) $ in Millions | 1 Months Ended | 3 Months Ended | 6 Months Ended | 12 Months Ended | |||||
Jun. 30, 2015USD ($) | May 31, 2015USD ($) | Sep. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Jul. 02, 2014 | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Jul. 01, 2014USD ($) | |
Business Acquisition [Line Items] | |||||||||
Goodwill, Purchase Accounting Adjustments | $ 25 | ||||||||
Business Acquisition, Purchase Price Allocation [Abstract] | |||||||||
Goodwill | $ 47 | 47 | $ 1,120 | ||||||
Equity Method Investments and Joint Ventures [Abstract] | |||||||||
Payments to Acquire Equity Method Investments | 177 | 594 | 468 | ||||||
Central [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Goodwill, Purchase Accounting Adjustments | 10 | ||||||||
Business Acquisition, Purchase Price Allocation [Abstract] | |||||||||
Goodwill | $ 0 | 0 | 240 | ||||||
Access Midstream Partners Acquisition [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Property, Plant, and Equipment | $ 150 | ||||||||
Goodwill, Purchase Accounting Adjustments | 25 | ||||||||
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Intangibles | (168) | ||||||||
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Investments | $ (7) | ||||||||
Intangible Assets, Net (Excluding Goodwill) [Abstract] | |||||||||
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life | 30 years | ||||||||
Percentage Of Finite Lived Intangible Assets Impacted By Our Intent Or Ability To Renew Or Extend Arrangement | 56.00% | ||||||||
Acquired Finite-lived Intangible Asset, Weighted-Average Period before Renewal or Extension | 17 years | ||||||||
Business Acquisition, Pro Forma Information [Abstract] | |||||||||
Business Acquisition, Pro Forma Revenue | 7,953 | ||||||||
Business Acquisition, Pro Forma Net Income (Loss) | 1,376 | ||||||||
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual | 781 | ||||||||
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual | 165 | ||||||||
Access Midstream Partners Acquisition [Member] | Selling, General and Administrative Expenses [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Business Combination, Acquisition Related Costs | 16 | ||||||||
Access Midstream Partners Acquisition [Member] | Interest Expense [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Business Combination, Acquisition Related Costs | $ 9 | ||||||||
Access Midstream Partners Acquisition [Member] | Pro Forma [Member] | |||||||||
Intangible Assets, Net (Excluding Goodwill) [Abstract] | |||||||||
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life | 30 years | ||||||||
Access Midstream Partners Acquisition [Member] | Central [Member] | |||||||||
Business Acquisition, Purchase Price Allocation [Abstract] | |||||||||
Accounts receivable | $ 168 | ||||||||
Other current assets | 63 | ||||||||
Investments | 5,865 | ||||||||
Property, plant, and equipment | 7,165 | ||||||||
Goodwill | 499 | ||||||||
Other intangible assets | 8,841 | ||||||||
Current liabilities | (408) | ||||||||
Debt | (4,052) | ||||||||
Other noncurrent liabilities | (9) | ||||||||
Equity | (10,630) | ||||||||
Access Midstream Partners Acquisition [Member] | ACMP's subsidiaries [Member] | Central [Member] | |||||||||
Business Acquisition, Purchase Price Allocation [Abstract] | |||||||||
Noncontrolling interest | (958) | ||||||||
Access Midstream Partners Acquisition [Member] | Access Midstream Partners Lp [Member] | Central [Member] | |||||||||
Business Acquisition, Purchase Price Allocation [Abstract] | |||||||||
Noncontrolling interest | $ (6,544) | ||||||||
Eagle Ford Gathering System [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Property, Plant, and Equipment | $ 20 | ||||||||
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Intangibles | $ (20) | ||||||||
Number Of Miles Of Pipeline Acquired | 140 | ||||||||
Payments to Acquire Businesses, Gross | $ 112 | ||||||||
Business Acquisition, Purchase Price Allocation [Abstract] | |||||||||
Property, plant, and equipment | 80 | ||||||||
Other intangible assets | $ 32 | ||||||||
Intangible Assets, Net (Excluding Goodwill) [Abstract] | |||||||||
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life | 30 years | ||||||||
Acquired Finite-lived Intangible Asset, Weighted-Average Period before Renewal or Extension | 10 years | ||||||||
Utica East Ohio Midstream, LLC [Member] | |||||||||
Equity Method Investments and Joint Ventures [Abstract] | |||||||||
Equity Method Investment, Ownership Percentage | 62.00% | ||||||||
Payments to Acquire Equity Method Investments | $ 357 | $ 0 | $ 357 | $ 57 | |||||
Reduction in incentive distribution rights payment | $ 2 | ||||||||
Utica East Ohio Midstream, LLC [Member] | Additional Investment [Member] | |||||||||
Equity Method Investments and Joint Ventures [Abstract] | |||||||||
Equity Method Investment, Ownership Percentage | 13.00% |
Divestiture (Details)
Divestiture (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Jun. 30, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Income Statement and Additional Disclosures by Disposal Groups [Line Items] | |||||
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down | $ 341 | ||||
Canadian Operations [Member] | Disposal Group, Not Discontinued Operations [Member] | |||||
Income Statement and Additional Disclosures by Disposal Groups [Line Items] | |||||
Divested cash of disposal group | 13 | ||||
Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract] | |||||
Income (loss) before income taxes of disposal group | (9) | $ 6 | |||
NGL And Petchem Services [Member] | Other (income) expense - net [Member] | Canadian Operations [Member] | Disposal Group, Not Discontinued Operations [Member] | |||||
Income Statement and Additional Disclosures by Disposal Groups [Line Items] | |||||
Loss on sale of Canadian operations (Note 3) | 34 | $ 0 | $ 0 | ||
Gain (Loss) on Foreign Currency Derivative Instruments Not Designated as Hedging Instruments | 11 | ||||
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | NGL And Petchem Services [Member] | Impairment Of Certain Assets [Member] | Canadian Operations [Member] | |||||
Income Statement and Additional Disclosures by Disposal Groups [Line Items] | |||||
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down | [1] | $ 341 | |||
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | NGL And Petchem Services [Member] | Impairment Of Certain Assets [Member] | Canadian Operations [Member] | Disposal Group, Not Discontinued Operations [Member] | |||||
Income Statement and Additional Disclosures by Disposal Groups [Line Items] | |||||
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down | $ 341 | ||||
Cash Consideration [Member] | Canadian Operations [Member] | Disposal Group, Not Discontinued Operations [Member] | |||||
Income Statement and Additional Disclosures by Disposal Groups [Line Items] | |||||
Disposal Group, Consideration | 672 | ||||
Reduction In Incentive Distribution Rights Payment [Member] | Canadian Operations [Member] | Disposal Group, Not Discontinued Operations [Member] | |||||
Income Statement and Additional Disclosures by Disposal Groups [Line Items] | |||||
Disposal Group, Consideration | $ 150 | ||||
[1] | Relates to our Canadian operations. We 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 reflected our estimate of the potential assumed proceeds. We disposed of our Canadian operations through a sale during the third quarter of 2016. See Note 3 – Divestiture. |
Variable Interest Entities (Det
Variable Interest Entities (Details) - Variable Interest Entity, Primary Beneficiary [Member] - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Cash and cash equivalents [Member] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets | $ 82 | $ 70 |
Accounts receivable [Member] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets | 91 | 71 |
Prepaid assets [Member] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets | 3 | 2 |
Property, plant, and equipment, net [Member] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets | 3,024 | 3,000 |
Intangible assets, net [Member] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets | 1,431 | 1,483 |
Accounts payable [Member] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities | (44) | (59) |
Accrued liabilities [Member] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities | (3) | (14) |
Current deferred revenue [Member] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities | (63) | (62) |
Noncurrent asset retirement obligations [Member] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities | (99) | (93) |
Noncurrent deferred revenue associated with customer advance payments [Member] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities | $ (324) | $ (331) |
Gulfstar One [Member] | ||
Variable Interest Entity [Line Items] | ||
Variable Interest Entity Ownership Percentage | 51.00% | |
Constitution Pipeline Company LLC [Member] | ||
Variable Interest Entity [Line Items] | ||
Variable Interest Entity Ownership Percentage | 41.00% | |
Constitution Pipeline Company LLC [Member] | Estimated Remaining Construction Costs For Variable Interest Entity [Member] | ||
Variable Interest Entity [Line Items] | ||
Estimated remaining construction costs | $ 687 | |
Constitution Pipeline Company LLC [Member] | Property, plant, and equipment, net [Member] | ||
Variable Interest Entity [Line Items] | ||
Capitalized project development costs, Cumulative | $ 381 | |
Cardinal Gas Services LLC [Member] | ||
Variable Interest Entity [Line Items] | ||
Variable Interest Entity Ownership Percentage | 66.00% | |
Jackalope Gas Gathering Services LLC [Member] | ||
Variable Interest Entity [Line Items] | ||
Variable Interest Entity Ownership Percentage | 50.00% |
Allocation of Net Income (Los48
Allocation of Net Income (Loss) and Distributions (Details) - USD ($) $ / shares in Units, $ in Millions | 1 Months Ended | 12 Months Ended | |||||
Feb. 10, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||||
Distributions Made to Members or Limited Partners [Abstract] | |||||||
Amortization of beneficial conversion feature of Class D units | $ 0 | $ 0 | |||||
Allocation of net income to general partner: | |||||||
Net income (loss) | $ 519 | (1,358) | 1,284 | ||||
Net income applicable to pre-merger operations allocated to general partner | 0 | (2) | (95) | ||||
Net income applicable to pre-partnership operations allocated to general partner | 0 | 0 | (15) | ||||
Net income applicable to noncontrolling interests | (88) | (91) | (96) | ||||
Costs charged directly to the general partner | 1 | 21 | 1 | ||||
Income (loss) subject to 2% allocation of general partner interest | $ 432 | $ (1,430) | $ 1,079 | ||||
General partner's share of net income | 2.00% | 2.00% | 2.00% | ||||
General partner's allocated share of net income (loss) before items directly allocable to general partner interest | $ 9 | $ (29) | $ 22 | ||||
Priority Allocations Paid To General Partner | 482 | 638 | 641 | ||||
Pre-merger net income allocated to general partner interest | 0 | 2 | 95 | ||||
Pre-partnership net income allocated to general partner interest | 0 | 0 | 15 | ||||
Costs charged directly to the general partner | (1) | (21) | (1) | ||||
Net income allocated to general partner's equity | 490 | 590 | 772 | ||||
Net income (loss) | 519 | (1,358) | 1,284 | ||||
Net income allocated to general partner's equity | 490 | 590 | 772 | ||||
Net income (loss) allocated to Class B limited partners' equity | (2) | (52) | 0 | ||||
Net income allocated to Class D limited partners' equity | 0 | 69 | [1] | 62 | [1] | ||
Net income applicable to noncontrolling interests | 88 | 91 | 96 | ||||
Net income (loss) allocated to common limited partners' equity | (57) | (2,056) | 354 | ||||
Adjustments to reconcile Net income (loss) allocated to common limited partners' equity to Allocation of net income (loss) to common units | |||||||
Incentive distributions paid | 474 | 633 | 640 | ||||
Incentive distributions declared | (473) | (423) | (626) | ||||
Impact of unit issuance timing and other | (42) | [2] | (9) | (9) | |||
Allocation of net income (loss) to common units | $ (98) | $ (1,855) | 359 | ||||
Subsequent Event [Member] | |||||||
Distributions Made to Members or Limited Partners [Abstract] | |||||||
Per Unit Distribution (Paid) | $ 0.85 | ||||||
Class B Units | |||||||
Distributions Made to Members or Limited Partners [Abstract] | |||||||
Class B Units Issued In Lieu Of Cash Distributions | 1,906,001 | 1,058,172 | |||||
Class B Units | Limited Partner [Member] | |||||||
Distributions Made to Members or Limited Partners [Abstract] | |||||||
Amortization of beneficial conversion feature of Class D units | $ 0 | 0 | |||||
Allocation of net income to general partner: | |||||||
Net income (loss) | $ (2) | (52) | 0 | ||||
Net income (loss) | (2) | (52) | $ 0 | ||||
Class B Units | Subsequent Event [Member] | |||||||
Distributions Made to Members or Limited Partners [Abstract] | |||||||
Class B Units Issued In Lieu Of Cash Distributions | 375,800 | ||||||
Class D [Member] | |||||||
Distributions Made to Members or Limited Partners [Abstract] | |||||||
Class D Units Issued In Lieu Of Cash Distributions | 1,377,893 | ||||||
Class D [Member] | Limited Partner [Member] | |||||||
Distributions Made to Members or Limited Partners [Abstract] | |||||||
Amortization of beneficial conversion feature of Class D units | 68 | $ 49 | |||||
Allocation of net income to general partner: | |||||||
Net income (loss) | 0 | 1 | 62 | ||||
Net income (loss) | $ 0 | $ 1 | $ 62 | ||||
[1] | Includes amortization of the beneficial conversion feature associated with the Pre-merger WPZ Class D units of $68 million and $49 million for the years ended December 31, 2015 and 2014, respectively. See following discussion of Class D units. | ||||||
[2] | The 2016 amount includes the effect of units issued and the conversion of the general partner interest in us to a non-economic interest in conjunction with our Financial Repositioning (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.) |
Related Party Transactions (Det
Related Party Transactions (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Summary of Related Party Transactions Abstract [Line Items] | |||
Service revenues | $ 31 | $ 0 | $ 0 |
Product costs | 181 | 169 | 186 |
Operating and maintenance expenses | 470 | 498 | 413 |
Capitalized Charges From Affiliate | 103 | 187 | |
Accounts payable - trade | 109 | 141 | |
Proceeds | 11 | 12 | 11 |
Contribution receivable | 3 | 3 | |
Employee direct costs [Member] | |||
Summary of Related Party Transactions Abstract [Line Items] | |||
Selling, general, and administrative expenses | 344 | 368 | 331 |
Employee allocated costs [Member] | |||
Summary of Related Party Transactions Abstract [Line Items] | |||
Selling, general, and administrative expenses | 160 | 195 | 171 |
Equity method investees [Member] | |||
Summary of Related Party Transactions Abstract [Line Items] | |||
Accounts payable - trade | 19 | 12 | |
Management Fees Revenue | 66 | 64 | 65 |
Common management [Member] | |||
Summary of Related Party Transactions Abstract [Line Items] | |||
Service revenues | 144 | $ 111 | $ 115 |
Reimbursable maintenance costs for certain government projects [Member] | |||
Summary of Related Party Transactions Abstract [Line Items] | |||
Maximum potential obligation | $ 50 |
Investing Activities (Details)
Investing Activities (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | |||
Jun. 30, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Schedule of Equity Method Investments [Line Items] | |||||
Impairment of equity-method investments | $ 430 | $ 1,359 | $ 0 | ||
Equity earnings (losses) | 397 | 335 | 228 | ||
Equity-method investments | 6,701 | 7,336 | |||
Equity-method investment, difference between carrying amount and underlying equity | 1,900 | 2,400 | |||
Equity-method investment, payments to purchase or contributions | 177 | 594 | 468 | ||
Equity-method investment, dividends or distributions | 742 | 633 | 365 | ||
Special distribution from equity-method investment | 0 | 396 | 0 | ||
Summarized Financial Position of Equity Method Investments | |||||
Current assets | 508 | 773 | |||
Noncurrent assets | 9,695 | 9,549 | |||
Current liabilities | (412) | (633) | |||
Noncurrent liabilities | (1,484) | (1,450) | |||
Summarized Results of Operations of Equity Method Investments | |||||
Gross revenue | 1,883 | 1,707 | 1,623 | ||
Operating income | 799 | 690 | 534 | ||
Net income | 726 | 611 | 460 | ||
Delaware Basin Gas Gathering System [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Impairment of equity-method investments | 59 | 503 | |||
Equity-method investments | $ 988 | 977 | |||
Equity-method investment, ownership percentage | 50.00% | ||||
Equity-method investment, payments to purchase or contributions | $ 105 | 57 | 20 | ||
Equity-method investment, dividends or distributions | 39 | 33 | 0 | ||
Ranch Westex JV LLC [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Impairment of equity-method investments | 24 | 0 | |||
Appalachia Midstream Investments [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Impairment of equity-method investments | 294 | 562 | |||
Equity earnings (losses) | (19) | ||||
Gain on sale of equity-method investment | 27 | ||||
Equity-method investments | [1] | $ 2,062 | 2,464 | ||
Equity-method investment, ownership percentage | 41.00% | ||||
Equity-method investment, payments to purchase or contributions | $ 28 | 93 | 84 | ||
Equity-method investment, dividends or distributions | 211 | 219 | 130 | ||
Utica East Ohio Midstream, LLC [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Impairment of equity-method investments | 0 | 241 | |||
Equity-method investments | $ 1,448 | 1,525 | |||
Equity-method investment, ownership percentage | 62.00% | ||||
Equity-method investment, payments to purchase or contributions | $ 357 | $ 0 | 357 | 57 | |
Equity-method investment, dividends or distributions | 92 | 42 | 0 | ||
Discovery Producer Services LLC [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Equity-method investments | $ 572 | 602 | |||
Equity-method investment, ownership percentage | 60.00% | ||||
Equity-method investment, payments to purchase or contributions | $ 0 | 35 | 106 | ||
Equity-method investment, dividends or distributions | 141 | 116 | 36 | ||
Laurel Mountain Midstream, LLC [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Impairment of equity-method investments | 50 | 45 | |||
Equity-method investments | $ 324 | 391 | |||
Equity-method investment, ownership percentage | 69.00% | ||||
Equity-method investment, dividends or distributions | $ 28 | 31 | 39 | ||
Overland Pass Pipeline Company LLC [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Equity-method investments | $ 430 | 445 | |||
Equity-method investment, ownership percentage | 50.00% | ||||
Equity-method investment, dividends or distributions | $ 69 | 45 | 27 | ||
Caiman Energy II LLC [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Equity-method investments | $ 426 | 418 | |||
Equity-method investment, ownership percentage | 58.00% | ||||
Equity-method investment, payments to purchase or contributions | $ 22 | 0 | 175 | ||
Equity-method investment, dividends or distributions | 40 | 33 | 13 | ||
Gulfstream Natural Gas System, L.L.C. [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Equity-method investments | $ 261 | 293 | |||
Equity-method investment, ownership percentage | 50.00% | ||||
Equity-method investment, dividends or distributions | $ 100 | 88 | 81 | ||
Special distribution from equity-method investment | 396 | ||||
Contribution to equity-method investment for repayment of debt | 148 | 248 | |||
Other [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Impairment of equity-method investments | 3 | 8 | |||
Equity-method investments | 190 | 221 | |||
Equity-method investment, payments to purchase or contributions | 22 | 52 | 26 | ||
Equity-method investment, dividends or distributions | 22 | 26 | $ 39 | ||
Equity-method investment debt due November 1, 2015 [Member] | Gulfstream Natural Gas System, L.L.C. [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Equity-method investment debt | $ 500 | ||||
Equity-method investment debt due June 1, 2016 [Member] | Gulfstream Natural Gas System, L.L.C. [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Equity-method investment debt | $ 300 | ||||
[1] | Includes equity-method investments in multiple gathering systems in the Marcellus Shale with an approximate average 41 percent interest. |
Other Income and Expenses (Deta
Other Income and Expenses (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Segment Reporting Information [Line Items] | ||||
Gain on asset retirement | [1] | $ 137 | $ 15 | |
Other (income) expense - net [Member] | Central [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Loss related to sale of certain assets | 0 | 0 | $ 10 | |
Other (income) expense - net [Member] | Northeast G&P [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Contingency gain settlement (1) | [2] | 0 | 0 | (154) |
Net gain related to partial acreage dedication release | 0 | 0 | (12) | |
Other (income) expense - net [Member] | Atlantic Gulf [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Amortization of regulatory assets associated with asset retirement obligations | 33 | 33 | 33 | |
Accrual of regulatory liability related to overcollection of certain employee expenses | 25 | 20 | 14 | |
Project development costs related to Constitution (Note 4) | 28 | 0 | 0 | |
Gain on asset retirement | (11) | 0 | 0 | |
Other (income) expense - net [Member] | NGL And Petchem Services [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Net foreign currency exchange (gains) losses (2) | [3] | 10 | (10) | (3) |
Selling, general, and administrative expenses [Member] | Central [Member] | Acquisition and Merger [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Business combination, acquisition related costs | 26 | 27 | ||
Selling, general, and administrative expenses [Member] | Central [Member] | Acquisition [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Business combination, acquisition related costs | 16 | |||
Selling, general, and administrative expenses [Member] | Central [Member] | Transition costs [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Business combination, integration related costs | 9 | 15 | ||
Operating and maintenance expenses [Member] | Central [Member] | Transition costs [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Business combination, integration related costs | 12 | 15 | ||
Interest incurred [Member] | Acquisition [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Business combination, acquisition related costs | 9 | |||
Interest incurred [Member] | Merger [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Business combination, acquisition related costs | 2 | |||
Service revenues [Member] | Central [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Deferred Revenue, Revenue Recognized | 173 | |||
Minimum volume commitment fees | 58 | 239 | 167 | |
Selling, general, and administrative expenses and Operating and maintenance expenses [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Severance and other related costs | 37 | |||
Selling, general, and administrative expenses and Operating and maintenance expenses [Member] | Central [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Severance and other related costs | 8 | |||
Selling, general, and administrative expenses and Operating and maintenance expenses [Member] | Northeast G&P [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Severance and other related costs | 3 | |||
Selling, general, and administrative expenses and Operating and maintenance expenses [Member] | Atlantic Gulf [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Severance and other related costs | 8 | |||
Selling, general, and administrative expenses and Operating and maintenance expenses [Member] | West [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Severance and other related costs | 5 | |||
Selling, general, and administrative expenses and Operating and maintenance expenses [Member] | NGL And Petchem Services [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Severance and other related costs | 4 | |||
Selling, general, and administrative expenses and Operating and maintenance expenses [Member] | Other [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Severance and other related costs | 9 | |||
Other income (expense) - net [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Gain on extinguishment of debt | 14 | |||
Other income (expense) - net [Member] | Atlantic Gulf [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Allowance for funds used during construction, capitalized cost of equity | 65 | 76 | 33 | |
Disposal Group, Not Discontinued Operations [Member] | Canadian Operations [Member] | Other (income) expense - net [Member] | NGL And Petchem Services [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Loss on sale of Canadian operations (Note 3) | $ 34 | $ 0 | $ 0 | |
[1] | Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, market risk premiums, discount rates, and the estimated remaining useful life of the assets. The 2016 revisions reflect changes in removal cost estimates, increases in the estimated remaining useful life of certain assets, and decreases in the inflation rate and discount rates used in the annual review process. The 2015 revisions reflect changes in removal cost estimates and the estimated remaining useful life of assets, a decrease in the inflation rate, and increases in the discount rates used in the annual review process. | |||
[2] | In November 2014, we settled a claim arising from the resolution of a contingent gain related to claims associated with the purchase of a business in a prior period. Pursuant to the settlement, we received $154 million in cash, all of which was recognized as a gain in the fourth quarter of 2014. | |||
[3] | Primarily relates to gains and losses incurred on foreign currency transactions and the remeasurement of U.S. dollar-denominated current assets and liabilities within our former Canadian operations (see Note 3 – Divestiture). |
Provision (Benefit) Table (Deta
Provision (Benefit) Table (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Current: | |||
State | $ 2 | $ (3) | $ 3 |
Foreign | 1 | 0 | 1 |
Total | 3 | (3) | 4 |
Deferred: | |||
State | (1) | (3) | 8 |
Foreign | (82) | 7 | 17 |
Total | (83) | 4 | 25 |
Provision (benefit) for income taxes | $ (80) | 1 | $ 29 |
TEXAS | |||
Deferred: | |||
State | (7) | ||
Alberta Provincial Tax [Member] | |||
Deferred: | |||
Foreign | $ 8 |
Reconciliations To Recorded Pro
Reconciliations To Recorded Provision for Income Taxes (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Effective Income Tax Rate Reconciliation, Amount [Abstract] | |||
Provision (benefit) at statutory rate | $ 154 | $ (475) | $ 459 |
Increases (decreases) in taxes resulting from: | |||
Income not subject to U.S. federal tax | (154) | 475 | (459) |
State income taxes | 1 | (6) | 11 |
Foreign operations — net | (81) | 7 | 18 |
Provision (benefit) for income taxes | $ (80) | $ 1 | $ 29 |
Provision (Benefit) for Incom54
Provision (Benefit) for Income Taxes (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Provision (Benefit) for Income Taxes [Abstract] | |||
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down | $ 341 | ||
Income (Loss) from Continuing Operations before Income Taxes, Foreign | (387) | $ 1 | $ 72 |
Deferred Tax Liabilities, Gross | 20 | 119 | |
Income Taxes Paid, Net | 3 | $ (4) | $ (28) |
Unrecognized Tax Benefits | $ 0 |
Benefit Plans (Details)
Benefit Plans (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Benefit Plan Disclosure [Line Items] | |||
Defined Contribution Plan, Cost Recognized | $ 24 | $ 27 | $ 25 |
Pension Expense | 32 | 43 | 28 |
Other Postretirement Benefit Cost (Credit) | (12) | (12) | $ (14) |
Pension Benefits [Member] | |||
Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Benefit Obligation | 1,500 | 1,500 | |
Defined Benefit Plan, Funded Status of Plan | (212) | (223) | |
Other Postretirement Benefits [Member] | |||
Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Benefit Obligation | 197 | 202 | |
Defined Benefit Plan, Funded Status of Plan | $ 11 | $ (1) |
Property, Plant and Equipment56
Property, Plant and Equipment (Details PPE) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Property, Plant and Equipment | ||||
Property, plant, and equipment, at cost | $ 38,247 | $ 37,833 | ||
Accumulated depreciation and amortization | (10,226) | (9,233) | ||
Property, plant, and equipment - net | 28,021 | 28,600 | ||
Depreciation and amortization expenses | 1,364 | 1,348 | $ 944 | |
Nonregulated [Member] | Natural gas gathering and processing facilities [Member] | ||||
Property, Plant and Equipment | ||||
Property, plant, and equipment, at cost | $ 20,267 | 20,636 | ||
Nonregulated [Member] | Natural gas gathering and processing facilities [Member] | Minimum [Member] | ||||
Property, Plant and Equipment | ||||
Property, Plant and Equipment, Useful Life | [1] | 5 years | ||
Nonregulated [Member] | Natural gas gathering and processing facilities [Member] | Maximum [Member] | ||||
Property, Plant and Equipment | ||||
Property, Plant and Equipment, Useful Life | [1] | 40 years | ||
Nonregulated [Member] | Construction in Progress [Member] | ||||
Property, Plant and Equipment | ||||
Property, plant, and equipment, at cost | $ 355 | 740 | ||
Nonregulated [Member] | Other Capitalized Property Plant and Equipment [Member] | ||||
Property, Plant and Equipment | ||||
Property, plant, and equipment, at cost | $ 1,740 | 1,743 | ||
Nonregulated [Member] | Other Capitalized Property Plant and Equipment [Member] | Minimum [Member] | ||||
Property, Plant and Equipment | ||||
Property, Plant and Equipment, Useful Life | [1] | 3 years | ||
Nonregulated [Member] | Other Capitalized Property Plant and Equipment [Member] | Maximum [Member] | ||||
Property, Plant and Equipment | ||||
Property, Plant and Equipment, Useful Life | [1] | 45 years | ||
Regulated [Member] | Natural gas transmission facilities [Member] | ||||
Property, Plant and Equipment | ||||
Property, plant, and equipment, at cost | $ 12,692 | 12,189 | ||
Regulated [Member] | Natural gas transmission facilities [Member] | Minimum [Member] | ||||
Property, Plant and Equipment | ||||
Regulated Property, Plant, and Equipment, Depreciation Rate | [1] | 1.20% | ||
Regulated [Member] | Natural gas transmission facilities [Member] | Maximum [Member] | ||||
Property, Plant and Equipment | ||||
Regulated Property, Plant, and Equipment, Depreciation Rate | [1] | 6.97% | ||
Regulated [Member] | Construction in Progress [Member] | ||||
Property, Plant and Equipment | ||||
Property, plant, and equipment, at cost | $ 1,603 | 941 | ||
Regulated [Member] | Other Capitalized Property Plant and Equipment [Member] | ||||
Property, Plant and Equipment | ||||
Property, plant, and equipment, at cost | $ 1,590 | 1,584 | ||
Regulated [Member] | Other Capitalized Property Plant and Equipment [Member] | Minimum [Member] | ||||
Property, Plant and Equipment | ||||
Property, Plant and Equipment, Useful Life | [1] | 5 years | ||
Regulated Property, Plant, and Equipment, Depreciation Rate | [1] | 1.35% | ||
Regulated [Member] | Other Capitalized Property Plant and Equipment [Member] | Maximum [Member] | ||||
Property, Plant and Equipment | ||||
Property, Plant and Equipment, Useful Life | [1] | 45 years | ||
Regulated Property, Plant, and Equipment, Depreciation Rate | [1] | 33.33% | ||
Regulated [Member] | Acquisition Adjustment of Regulated Facilities [Member] | ||||
Property, Plant and Equipment | ||||
Property, Plant and Equipment, Plant Acquisition Adjustments for Intangible Utility Plants | $ 665 | $ 706 | ||
Period of straight-line amortization | 40 years | |||
[1] | Estimated useful life and depreciation rates are presented as of December 31, 2016. Depreciation rates and estimated useful lives for regulated assets are prescribed by the FERC. |
Property, Plant, and Equipment
Property, Plant, and Equipment (Details ARO) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | ||
Asset Retirement Obligation | |||
Asset Retirement Obligations, Noncurrent | $ 798 | $ 857 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Beginning balance | 914 | 831 | |
Liabilities incurred | 21 | 41 | |
Liabilities settled | (8) | (3) | |
Accretion expense | 69 | 60 | |
Revisions (1) | [1] | (137) | (15) |
Ending balance | 859 | $ 914 | |
Asset Retirement Obligation Costs [Member] | |||
Unusual or Infrequent Item, or Both [Line Items] | |||
Transco's annual funding commitment for ARO | $ 36 | ||
[1] | Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, market risk premiums, discount rates, and the estimated remaining useful life of the assets. The 2016 revisions reflect changes in removal cost estimates, increases in the estimated remaining useful life of certain assets, and decreases in the inflation rate and discount rates used in the annual review process. The 2015 revisions reflect changes in removal cost estimates and the estimated remaining useful life of assets, a decrease in the inflation rate, and increases in the discount rates used in the annual review process. |
Goodwill (Details)
Goodwill (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Goodwill [Line Items] | ||||
Goodwill | $ 47 | $ 47 | $ 47 | $ 1,120 |
Goodwill, purchase accounting adjustments | 25 | |||
Impairment of goodwill | (1,098) | 0 | (1,098) | 0 |
Central [Member] | ||||
Goodwill [Line Items] | ||||
Goodwill | 0 | 0 | 0 | 240 |
Goodwill, purchase accounting adjustments | 10 | |||
Impairment of goodwill | (250) | |||
Northeast G&P [Member] | ||||
Goodwill [Line Items] | ||||
Goodwill | 0 | 0 | 0 | 835 |
Goodwill, purchase accounting adjustments | 13 | |||
Impairment of goodwill | (848) | |||
West [Member] | ||||
Goodwill [Line Items] | ||||
Goodwill | $ 47 | $ 47 | 47 | $ 45 |
Goodwill, purchase accounting adjustments | 2 | |||
Impairment of goodwill | $ 0 |
Other Intangible Assets (Detail
Other Intangible Assets (Details) - USD ($) $ in Millions | 1 Months Ended | 6 Months Ended | 12 Months Ended | ||
May 31, 2015 | Jul. 02, 2014 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Finite-Lived Intangible Assets [Line Items] | |||||
Amortization of Intangible Assets | $ 356 | $ 353 | $ 207 | ||
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months | 356 | ||||
Finite-Lived Intangible Assets, Amortization Expense, Year Two | 356 | ||||
Finite-Lived Intangible Assets, Amortization Expense, Year Three | 356 | ||||
Finite-Lived Intangible Assets, Amortization Expense, Year Four | 356 | ||||
Finite-Lived Intangible Assets, Amortization Expense, Year Five | 356 | ||||
Contractual customer relationships [Member] | |||||
Finite-Lived Intangible Assets [Line Items] | |||||
Finite-Lived Intangible Assets, Gross | 10,634 | 10,632 | |||
Finite-Lived Intangible Assets, Accumulated Amortization | $ (1,019) | $ (663) | |||
Access Midstream Partners Acquisition [Member] | |||||
Finite-Lived Intangible Assets [Line Items] | |||||
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life | 30 years | ||||
Acquired Finite-lived Intangible Asset, Weighted-Average Period before Renewal or Extension | 17 years | ||||
Eagle Ford Gathering System [Member] | |||||
Finite-Lived Intangible Assets [Line Items] | |||||
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life | 30 years | ||||
Acquired Finite-lived Intangible Asset, Weighted-Average Period before Renewal or Extension | 10 years |
Other Accrued Liabilities (Deta
Other Accrued Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Other Accrued Liabilities [Abstract] | ||
Deferred income | $ 338 | $ 94 |
Refundable deposits | 160 | 0 |
Special distribution repayable to Gulfstream (See Note 7 - Investing Activities) | 0 | 149 |
Other, including other loss contingencies | 306 | 226 |
Other accrued liabilities | $ 804 | $ 469 |
Other Accrued Liabilities Oth61
Other Accrued Liabilities Other Accrued Liabilities Narrative (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Other Accrued Liabilities [Abstract] | |
Customer refundable fees, contracted | $ 240 |
Customer refundable fees, proceeds | $ 160 |
Long-Term Debt (Details)
Long-Term Debt (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Jun. 15, 2016 | Apr. 15, 2016 | Jan. 22, 2016 | Dec. 31, 2015 | Apr. 15, 2015 | Mar. 03, 2015 | ||
Debt Instrument [Line Items] | |||||||||
Capital Lease Obligations | $ 0 | $ 1 | |||||||
Debt issuance costs | (90) | (91) | |||||||
Net unamortized debt premium (discount) | 107 | 129 | |||||||
Long-term debt, including current portion | 18,470 | 19,177 | |||||||
Long-term debt due within one year | (785) | (176) | |||||||
Long-term debt | 17,685 | 19,001 | |||||||
Transcontinental Gas Pipe Line Company, LLC [Member] | 6.4% Senior Unsecured Notes due 2016 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | 0 | $ 200 | [1] | ||||||
Long-term debt interest rate | 6.40% | 6.40% | |||||||
Transcontinental Gas Pipe Line Company, LLC [Member] | 6.05% Senior Unsecured Notes due 2018 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 250 | $ 250 | |||||||
Long-term debt interest rate | 6.05% | ||||||||
Transcontinental Gas Pipe Line Company, LLC [Member] | 7.08% Debentures due 2026 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 8 | 8 | |||||||
Long-term debt interest rate | 7.08% | ||||||||
Transcontinental Gas Pipe Line Company, LLC [Member] | 7.25% Debentures due 2026 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 200 | 200 | |||||||
Long-term debt interest rate | 7.25% | ||||||||
Transcontinental Gas Pipe Line Company, LLC [Member] | 7.85% Senior Unsecured Notes Due 2026 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 1,000 | 0 | |||||||
Long-term debt interest rate | 7.85% | 7.85% | |||||||
Transcontinental Gas Pipe Line Company, LLC [Member] | 5.4% Senior Unsecured Notes due 2041 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 375 | 375 | |||||||
Long-term debt interest rate | 5.40% | ||||||||
Transcontinental Gas Pipe Line Company, LLC [Member] | 4.45% Senior Unsecured Notes due 2042 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 400 | 400 | |||||||
Long-term debt interest rate | 4.45% | ||||||||
Northwest Pipeline LLC [Member] | 6.05% Senior Unsecured Notes due 2018 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 250 | 250 | |||||||
Long-term debt interest rate | 6.05% | ||||||||
Northwest Pipeline LLC [Member] | 7% Senior Unsecured Notes due 2016 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 0 | 175 | |||||||
Long-term debt interest rate | 7.00% | 7.00% | |||||||
Northwest Pipeline LLC [Member] | 5.95% Senior Unsecured Notes due 2017 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 185 | 185 | |||||||
Long-term debt interest rate | 5.95% | ||||||||
Northwest Pipeline LLC [Member] | 7.125% Debentures due 2025 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 85 | 85 | |||||||
Long-term debt interest rate | 7.125% | ||||||||
Williams Partners L.P. [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Credit facility loans | $ 0 | [2] | 1,310 | ||||||
Williams Partners L.P. [Member] | 7.25% Senior Unsecured Notes due 2017 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 600 | 600 | |||||||
Long-term debt interest rate | 7.25% | ||||||||
Williams Partners L.P. [Member] | 5.25% Senior Unsecured Notes due 2020 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 1,500 | 1,500 | |||||||
Long-term debt interest rate | 5.25% | ||||||||
Williams Partners L.P. [Member] | 4.125% Senior Unsecured Notes due 2020 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 600 | 600 | |||||||
Long-term debt interest rate | 4.125% | ||||||||
Williams Partners L.P. [Member] | 5.875% Senior Unsecured Notes due 2021 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt interest rate | 5.875% | ||||||||
Williams Partners L.P. [Member] | 4% Senior Unsecured Notes due 2021 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 500 | 500 | |||||||
Long-term debt interest rate | 4.00% | ||||||||
Williams Partners L.P. [Member] | 3.6% Senior Unsecured Notes due 2022 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 1,250 | 1,250 | |||||||
Long-term debt interest rate | 3.60% | 3.60% | |||||||
Williams Partners L.P. [Member] | 3.35% Senior Unsecured Notes due 2022 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 750 | 750 | |||||||
Long-term debt interest rate | 3.35% | ||||||||
Williams Partners L.P. [Member] | 6.125% Senior Unsecured Notes due 2022 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 750 | 750 | |||||||
Long-term debt interest rate | 6.125% | ||||||||
Williams Partners L.P. [Member] | 4.5% Senior Unsecured Notes due 2023 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 600 | 600 | |||||||
Long-term debt interest rate | 4.50% | ||||||||
Williams Partners L.P. [Member] | 4.875% Senior Unsecured Notes due 2023 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 1,400 | 1,400 | |||||||
Long-term debt interest rate | 4.875% | ||||||||
Williams Partners L.P. [Member] | 4.3% Senior Unsecured Notes Due 2024 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 1,000 | 1,000 | |||||||
Long-term debt interest rate | 4.30% | ||||||||
Williams Partners L.P. [Member] | 4.875% Senior Unsecured Notes due 2024 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 750 | 750 | |||||||
Long-term debt interest rate | 4.875% | ||||||||
Williams Partners L.P. [Member] | 3.9% Senior Unsecured Notes due 2025 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 750 | 750 | |||||||
Long-term debt interest rate | 3.90% | ||||||||
Williams Partners L.P. [Member] | 4% Senior Unsecured Notes due 2025 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 750 | 750 | |||||||
Long-term debt interest rate | 4.00% | 4.00% | |||||||
Williams Partners L.P. [Member] | 6.3% Senior Unsecured Notes due 2040 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 1,250 | 1,250 | |||||||
Long-term debt interest rate | 6.30% | ||||||||
Williams Partners L.P. [Member] | 5.8% Senior Unsecured Notes due 2043 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 400 | 400 | |||||||
Long-term debt interest rate | 5.80% | ||||||||
Williams Partners L.P. [Member] | 5.4% Senior Unsecured Notes Due 2044 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 500 | 500 | |||||||
Long-term debt interest rate | 5.40% | ||||||||
Williams Partners L.P. [Member] | 4.9% Senior Unsecured Notes due 2045 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 500 | 500 | |||||||
Long-term debt interest rate | 4.90% | ||||||||
Williams Partners L.P. [Member] | 5.1% Senior Unsecured Notes due 2045 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 1,000 | 1,000 | |||||||
Long-term debt interest rate | 5.10% | 5.10% | |||||||
Williams Partners L.P. [Member] | Variable Interest Term Loan due 2018 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 850 | $ 850 | |||||||
Long-term debt interest rate | 2.50% | ||||||||
[1] | Presented as long-term debt at December 31, 2015, due to Transco’s intent and ability to refinance. | ||||||||
[2] | 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. |
Long-Term Debt Maturities (Deta
Long-Term Debt Maturities (Details) $ in Millions | Dec. 31, 2016USD ($) |
Long-term Debt, by Maturity [Abstract] | |
2,017 | $ 785 |
2,018 | 1,350 |
2,019 | 0 |
2,020 | 2,100 |
2,021 | $ 500 |
Long-Term Debt Issuances and Re
Long-Term Debt Issuances and Retirements (Details) - USD ($) $ in Millions | Feb. 01, 2017 | Jun. 15, 2016 | Apr. 15, 2016 | Apr. 15, 2015 | Feb. 15, 2015 | Jan. 25, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Jan. 22, 2016 | Dec. 23, 2015 | Mar. 03, 2015 |
Debt Instrument [Line Items] | ||||||||||||
Repayments of Long-term Debt | $ 4,936 | $ 4,699 | $ 1,157 | |||||||||
Transcontinental Gas PipeLine Company, LLC [Member] | 6.4% Senior Unsecured Notes due 2016 [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term debt retired | $ 200 | |||||||||||
Long-term debt interest rate | 6.40% | 6.40% | ||||||||||
Transcontinental Gas PipeLine Company, LLC [Member] | 7.85% Senior Unsecured Notes Due 2026 [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term debt face amount | $ 1,000 | |||||||||||
Long-term debt interest rate | 7.85% | 7.85% | ||||||||||
Northwest Pipeline LLC [Member] | 7% Senior Unsecured Notes due 2016 [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term debt retired | $ 175 | |||||||||||
Long-term debt interest rate | 7.00% | 7.00% | ||||||||||
Williams Partners L. P. [Member] | Variable Interest Term Loan due 2018 [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term debt face amount | $ 850 | |||||||||||
Long-term debt interest rate | 2.50% | |||||||||||
Williams Partners L. P. [Member] | 3.8% Senior Unsecured Notes due 2015 [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term debt retired | $ 750 | |||||||||||
Long-term debt interest rate | 3.80% | |||||||||||
Williams Partners L. P. [Member] | 3.9% Senior Unsecured Notes due 2025 [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term debt interest rate | 3.90% | |||||||||||
Williams Partners L. P. [Member] | 4.9% Senior Unsecured Notes due 2045 [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term debt interest rate | 4.90% | |||||||||||
Williams Partners L. P. [Member] | 4.3% Senior Unsecured Notes Due 2024 [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term debt interest rate | 4.30% | |||||||||||
Williams Partners L. P. [Member] | 5.4% Senior Unsecured Notes Due 2044 [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term debt interest rate | 5.40% | |||||||||||
Williams Partners L. P. [Member] | 5.875% Senior Unsecured Notes due 2021 [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term debt retired | $ 750 | |||||||||||
Long-term debt interest rate | 5.875% | |||||||||||
Long-term Debt, Current Maturities | $ 797 | |||||||||||
Repayments of Long-term Debt | $ 783 | |||||||||||
Williams Partners L. P. [Member] | 3.6% Senior Unsecured Notes due 2022 [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term debt face amount | $ 1,250 | |||||||||||
Long-term debt interest rate | 3.60% | 3.60% | ||||||||||
Williams Partners L. P. [Member] | 4% Senior Unsecured Notes due 2025 [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term debt face amount | $ 750 | |||||||||||
Long-term debt interest rate | 4.00% | 4.00% | ||||||||||
Williams Partners L. P. [Member] | 5.1% Senior Unsecured Notes due 2045 [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term debt face amount | $ 1,000 | |||||||||||
Long-term debt interest rate | 5.10% | 5.10% | ||||||||||
Williams Partners L. P. [Member] | 6.125% Senior Unsecured Notes due 2022 [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term debt interest rate | 6.125% | |||||||||||
Williams Partners L. P. [Member] | 6.125% Senior Unsecured Notes due 2022 [Member] | Subsequent Event [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term debt retired | $ 750 | |||||||||||
Long-term debt interest rate | 6.125% | |||||||||||
Williams Partners L. P. [Member] | 7.25% Senior Unsecured Notes due 2017 [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term debt interest rate | 7.25% | |||||||||||
Williams Partners L. P. [Member] | 7.25% Senior Unsecured Notes due 2017 [Member] | Subsequent Event [Member] | ||||||||||||
Debt Instrument [Line Items] | ||||||||||||
Long-term debt retired | $ 600 | |||||||||||
Long-term debt interest rate | 7.25% |
Credit Facility and Commercial
Credit Facility and Commercial Paper (Details) - USD ($) $ in Millions | Dec. 18, 2015 | Dec. 31, 2016 | Feb. 20, 2017 | Dec. 31, 2015 | Dec. 23, 2015 | Aug. 26, 2015 | Feb. 02, 2015 | |
Credit Facility and Commercial Paper [Line Items] | ||||||||
Commercial paper, outstanding | $ 93 | $ 499 | ||||||
Northwest Pipeline LLC [Member] | ||||||||
Credit Facility and Commercial Paper [Line Items] | ||||||||
Credit facility, capacity | $ 500 | |||||||
Maximum ratio of debt to capitalization | 65.00% | |||||||
Transcontinental Gas PipeLine Company, LLC [Member] | ||||||||
Credit Facility and Commercial Paper [Line Items] | ||||||||
Credit facility, capacity | 500 | |||||||
Maximum ratio of debt to capitalization | 65.00% | |||||||
Williams Partners L. P. [Member] | ||||||||
Credit Facility and Commercial Paper [Line Items] | ||||||||
Credit facility, capacity | 3,500 | [1] | 3,500 | |||||
Credit facility, loans outstanding | 0 | [1] | 1,310 | |||||
Additional amount by which credit facility can be increased | 500 | |||||||
Williams Partners L. P. [Member] | Subsequent Event [Member] | ||||||||
Credit Facility and Commercial Paper [Line Items] | ||||||||
Credit facility, loans outstanding | $ 0 | |||||||
Williams Partners L. P. [Member] | Rate addition to federal funds effective rate [Member] | ||||||||
Credit Facility and Commercial Paper [Line Items] | ||||||||
Credit facility, basis spread on variable rate | 0.50% | |||||||
Williams Partners L. P. [Member] | Rate addition to London interbank offered rate (LIBOR) [Member] | ||||||||
Credit Facility and Commercial Paper [Line Items] | ||||||||
Credit facility, basis spread on variable rate | 1.00% | |||||||
Williams Partners L. P. [Member] | Swingline Loan [Member] | ||||||||
Credit Facility and Commercial Paper [Line Items] | ||||||||
Credit facility, capacity | 150 | |||||||
Williams Partners L. P. [Member] | Commercial Paper [Member] | ||||||||
Credit Facility and Commercial Paper [Line Items] | ||||||||
Credit facility, capacity | 3,000 | |||||||
Commercial paper, outstanding | $ 93 | $ 499 | ||||||
Commercial paper, weighted average interest rate | 1.06% | 0.92% | ||||||
Commercial paper, maximum maturity | 397 days | |||||||
Williams Partners L. P. [Member] | Letter of Credit [Member] | ||||||||
Credit Facility and Commercial Paper [Line Items] | ||||||||
Credit facility, capacity | $ 1,125 | |||||||
Williams Partners L. P. [Member] | Letters Of Credit Under Certain Bilateral Bank Agreements [Member] | ||||||||
Credit Facility and Commercial Paper [Line Items] | ||||||||
Credit facility, letters of credit outstanding | $ 1 | |||||||
Williams Partners L. P. [Member] | Short-term facility [Member] | ||||||||
Credit Facility and Commercial Paper [Line Items] | ||||||||
Credit facility, capacity | $ 150 | $ 1,000 | ||||||
Dec 2015, Mar & Jun 2016 [Member] | Williams Partners L. P. [Member] | ||||||||
Credit Facility and Commercial Paper [Line Items] | ||||||||
Maximum ratio of debt to EBITDA | 5.75 | |||||||
Sep & Dec 2016 [Member] | Williams Partners L. P. [Member] | ||||||||
Credit Facility and Commercial Paper [Line Items] | ||||||||
Maximum ratio of debt to EBITDA | 5.50 | |||||||
Mar 2017 & Subsequent Quarters [Member] | Williams Partners L. P. [Member] | ||||||||
Credit Facility and Commercial Paper [Line Items] | ||||||||
Maximum ratio of debt to EBITDA | 5 | |||||||
Acquisition [Member] | Williams Partners L. P. [Member] | ||||||||
Credit Facility and Commercial Paper [Line Items] | ||||||||
Maximum ratio of debt to EBITDA after acquisition | 5.5 | |||||||
Variable Interest Term Loan due 2018 [Member] | Williams Partners L. P. [Member] | ||||||||
Credit Facility and Commercial Paper [Line Items] | ||||||||
Debt Instrument, Face Amount | $ 850 | |||||||
[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. |
Cash Payments For Interest (Net
Cash Payments For Interest (Net of Amounts Capitalized) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Debt Disclosure [Abstract] | |||
Cash payments for interest (net of amounts capitalized) | $ 891 | $ 795 | $ 499 |
Leases-Lessee (Details)
Leases-Lessee (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract] | |||
2,017 | $ 48 | ||
2,018 | 44 | ||
2,019 | 39 | ||
2,020 | 34 | ||
2,021 | 24 | ||
Thereafter | 71 | ||
Total | 260 | ||
Operating leases [Abstract] | |||
Total rent expense | $ 59 | $ 62 | $ 55 |
Partners' Capital (Details Text
Partners' Capital (Details Textuals) - USD ($) $ / shares in Units, $ in Thousands | Feb. 10, 2017 | Jan. 09, 2017 | Feb. 03, 2017 | Jan. 31, 2017 | Nov. 30, 2016 | Aug. 31, 2016 | Jan. 31, 2016 | Nov. 30, 2015 | Aug. 31, 2014 | Sep. 30, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Business Acquisition [Line Items] | |||||||||||||
Net Proceeds from Issuance of Common Limited Partners Units | $ 614,000 | $ 59,000 | $ 55,000 | ||||||||||
Parent, general partner ownership percentage | 2.00% | 2.00% | 2.00% | ||||||||||
Days after the end of each quarter to receive cash distributions | 45 days | ||||||||||||
Percentage of outstanding units voting as a single class to remove general partner | 66.67% | ||||||||||||
Dividend Reinvestment Program [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Shares Issued, Price Per Share | $ 32.92 | ||||||||||||
Private Placement [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Net Proceeds from Issuance of Common Limited Partners Units | $ 250,000 | ||||||||||||
Partners' Capital Account, Units, Sold in Private Placement | 6,975,446 | ||||||||||||
Equity Distribution Agreement [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Partners' Capital Account, Units, Sale of Units | 3,254,958 | 18,643 | 1,790,840 | 1,080,448 | |||||||||
Offering Costs, Partnership Interests | $ 1,200 | $ 4 | $ 592 | $ 554 | |||||||||
Net Proceeds from Issuance of Common Limited Partners Units | 115,000 | $ 414 | $ 59,000 | $ 55,000 | |||||||||
Subsequent Event [Member] | Financial Repositioning [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Net Proceeds from Issuance of Common Limited Partners Units | $ 50,000 | $ 10,000 | |||||||||||
Partners' Capital Account, Units, Sold in Private Placement | 59,000,000 | ||||||||||||
Williams Companies Inc [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Parent, general partner ownership percentage | 2.00% | ||||||||||||
Williams Companies Inc [Member] | Dividend Reinvestment Program [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Net Proceeds from Issuance of Common Limited Partners Units | 250,000 | ||||||||||||
Williams Companies Inc [Member] | Subsequent Event [Member] | Financial Repositioning [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Partners' Capital Account, Units, Sale of Units | 277,000 | 289,000,000 | |||||||||||
Net Proceeds from Issuance of Common Limited Partners Units | $ 50,000 | $ 10,000 | |||||||||||
Parent, general partner ownership percentage | 2.00% | ||||||||||||
Partners' Capital Account, Units, Sold in Private Placement | 59,000,000 | ||||||||||||
Shares Issued, Price Per Share | $ 36.08586 | ||||||||||||
Financial Repositioning [Member] | Subsequent Event [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Partners' Capital Account, Units, Sale of Units | 277,000 | 289,000,000 | |||||||||||
Dividend Reinvestment Program [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Net Proceeds from Issuance of Common Limited Partners Units | $ 260,000 | ||||||||||||
Partners' Capital Account, Units, Sold in Private Placement | 7,891,414 | ||||||||||||
Duration Of Trading Days | 5 days | ||||||||||||
Discount Rate For Shares Purchased | 2.50% |
Partners' Capital Incentive Dis
Partners' Capital Incentive Distributions Quarterly Target Amount (Details) | 12 Months Ended |
Dec. 31, 2016$ / shares | |
Minimum Quarterly Distribution Per Unit [Member] | |
Incentive Distribution Target Amount Per Unit [Line Items] | |
Unitholders | 98.00% |
General Partner | 2.00% |
Quarterly Distribution Target Amount | $ 0.3375 |
First Target Distribution [Member] | |
Incentive Distribution Target Amount Per Unit [Line Items] | |
Unitholders | 98.00% |
General Partner | 2.00% |
First Target Distribution [Member] | Minimum [Member] | |
Incentive Distribution Target Amount Per Unit [Line Items] | |
Quarterly Distribution Target Amount | $ 0.3375 |
First Target Distribution [Member] | Maximum [Member] | |
Incentive Distribution Target Amount Per Unit [Line Items] | |
Quarterly Distribution Target Amount | $ 0.388125 |
Second Target Distribution [Member] | |
Incentive Distribution Target Amount Per Unit [Line Items] | |
Unitholders | 85.00% |
General Partner | 15.00% |
Second Target Distribution [Member] | Minimum [Member] | |
Incentive Distribution Target Amount Per Unit [Line Items] | |
Quarterly Distribution Target Amount | $ 0.388125 |
Second Target Distribution [Member] | Maximum [Member] | |
Incentive Distribution Target Amount Per Unit [Line Items] | |
Quarterly Distribution Target Amount | $ 0.421875 |
Third Target Distribution [Member] | |
Incentive Distribution Target Amount Per Unit [Line Items] | |
Unitholders | 75.00% |
General Partner | 25.00% |
Third Target Distribution [Member] | Minimum [Member] | |
Incentive Distribution Target Amount Per Unit [Line Items] | |
Quarterly Distribution Target Amount | $ 0.421875 |
Third Target Distribution [Member] | Maximum [Member] | |
Incentive Distribution Target Amount Per Unit [Line Items] | |
Quarterly Distribution Target Amount | $ 0.50625 |
Thereafter [Member] | |
Incentive Distribution Target Amount Per Unit [Line Items] | |
Unitholders | 50.00% |
General Partner | 50.00% |
Thereafter [Member] | Minimum [Member] | |
Incentive Distribution Target Amount Per Unit [Line Items] | |
Quarterly Distribution Target Amount | $ 0.50625 |
Equity-Based Compensation (Deta
Equity-Based Compensation (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Williams Companies Incentive Plan [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Allocated Share-based Compensation Expense | $ 20 | $ 19 | $ 14 |
Williams Partners Long Term Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Allocated Share-based Compensation Expense | $ 16 | $ 26 | $ 11 |
Grants, Units | 0 | 0 | |
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Share-based Awards Other than Options | $ 11 | ||
Estimated forfeitures under employee stock-based awards | $ 1 | ||
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition | 1 year 2 months | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Nonvested at beginning of period, Units | 1.2 | ||
Forfeited, Units | (0.1) | ||
Vested, Units | (0.5) | ||
Nonvested at end of period,Units | 0.6 | 1.2 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |||
Nonvested at beginning of period, Weighted Average Grant Date Fair Value | $ 55.93 | ||
Forfeited, Weighted Average Grant Date Fair Value | 52.85 | ||
Vested, Weighted Average Grant Date Fair Value | 59.09 | ||
Nonvested at end of period, Weighted Average Grant Date Fair Value | $ 52.97 | $ 55.93 | |
Williams Partners Long Term Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member] | Minimum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period | 1 year | ||
Williams Partners Long Term Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member] | Maximum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period | 4 years |
Fair Value Measurements Recurri
Fair Value Measurements Recurring Measurements and Additional (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | |
Additional disclosures: | |||
Fair Value, Level 1 to Level 2 Transfers, Amount | $ 0 | $ 0 | |
Fair Value, Level 2 to Level 1 Transfers, Amount | 0 | 0 | |
Carrying Amount [Member] | |||
Additional disclosures: | |||
Other receivables | 15 | 12 | |
Long-term debt, including current portion | (18,470) | (19,176) | [1] |
Fair Value [Member] | |||
Additional disclosures: | |||
Other receivables | 15 | 12 | |
Long-term debt, including current portion | (18,907) | (15,988) | [1] |
Level 1 [Member] | |||
Additional disclosures: | |||
Other receivables | 15 | 10 | |
Long-term debt, including current portion | 0 | 0 | [1] |
Level 2 [Member] | |||
Additional disclosures: | |||
Other receivables | 0 | 2 | |
Long-term debt, including current portion | (18,907) | (15,988) | [1] |
Level 3 [Member] | |||
Additional disclosures: | |||
Other receivables | 0 | 0 | |
Long-term debt, including current portion | 0 | 0 | [1] |
Fair Value, Measurements, Recurring [Member] | Carrying Amount [Member] | |||
Measured on a recurring basis: | |||
ARO Trust investments | 96 | 67 | |
Fair Value, Measurements, Recurring [Member] | Carrying Amount [Member] | Designated as Hedging Instrument [Member] | |||
Measured on a recurring basis: | |||
Energy derivatives assets | 2 | ||
Fair Value, Measurements, Recurring [Member] | Carrying Amount [Member] | Not Designated as Hedging Instrument [Member] | |||
Measured on a recurring basis: | |||
Energy derivatives assets | 1 | 5 | |
Energy derivatives liabilities | (6) | (2) | |
Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | |||
Measured on a recurring basis: | |||
ARO Trust investments | 96 | 67 | |
Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Designated as Hedging Instrument [Member] | |||
Measured on a recurring basis: | |||
Energy derivatives assets | 2 | ||
Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Not Designated as Hedging Instrument [Member] | |||
Measured on a recurring basis: | |||
Energy derivatives assets | 1 | 5 | |
Energy derivatives liabilities | (6) | (2) | |
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | |||
Measured on a recurring basis: | |||
ARO Trust investments | 96 | 67 | |
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Designated as Hedging Instrument [Member] | |||
Measured on a recurring basis: | |||
Energy derivatives assets | 0 | ||
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Not Designated as Hedging Instrument [Member] | |||
Measured on a recurring basis: | |||
Energy derivatives assets | 0 | 0 | |
Energy derivatives liabilities | 0 | 0 | |
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | |||
Measured on a recurring basis: | |||
ARO Trust investments | 0 | 0 | |
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Designated as Hedging Instrument [Member] | |||
Measured on a recurring basis: | |||
Energy derivatives assets | 2 | ||
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Not Designated as Hedging Instrument [Member] | |||
Measured on a recurring basis: | |||
Energy derivatives assets | 0 | 3 | |
Energy derivatives liabilities | 0 | 0 | |
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | |||
Measured on a recurring basis: | |||
ARO Trust investments | 0 | 0 | |
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Designated as Hedging Instrument [Member] | |||
Measured on a recurring basis: | |||
Energy derivatives assets | 0 | ||
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Not Designated as Hedging Instrument [Member] | |||
Measured on a recurring basis: | |||
Energy derivatives assets | 1 | 2 | |
Energy derivatives liabilities | $ (6) | $ (2) | |
[1] | Excludes capital leases. |
Fair Value Measurements Nonrecu
Fair Value Measurements Nonrecurring Measurements (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||||||||||||||||
Dec. 31, 2016 | [4] | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Dec. 31, 2014 | Jun. 30, 2014 | Sep. 30, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Impairment of goodwill | $ 1,098 | $ 0 | $ 1,098 | $ 0 | ||||||||||||||||
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down | 341 | |||||||||||||||||||
Impairment of certain assets | 457 | 145 | 52 | |||||||||||||||||
Impairment of equity-method investments | 430 | 1,359 | 0 | |||||||||||||||||
Central [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Impairment of goodwill | 250 | |||||||||||||||||||
Northeast G&P [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Impairment of goodwill | 848 | |||||||||||||||||||
West [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Impairment of goodwill | 0 | |||||||||||||||||||
Delaware Basin Gas Gathering System [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Impairment of equity-method investments | 59 | 503 | ||||||||||||||||||
Appalachia Midstream Investments [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Impairment of equity-method investments | 294 | 562 | ||||||||||||||||||
Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Impairment of goodwill | $ 0 | |||||||||||||||||||
Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Minimum [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Fair Value Inputs, Discount Rate | 11.00% | |||||||||||||||||||
Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Maximum [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Fair Value Inputs, Discount Rate | 13.00% | |||||||||||||||||||
Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | West G & P [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Impairment of goodwill | $ 0 | |||||||||||||||||||
Property, plant, and equipment, net [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Central [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Property, Plant, and Equipment, Fair Value Disclosure | [1] | $ 18 | ||||||||||||||||||
Property, plant, and equipment, net [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Northeast G&P [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Property, Plant, and Equipment, Fair Value Disclosure | [2] | $ 17 | $ 32 | $ 46 | 32 | |||||||||||||||
Property, plant, and equipment, net [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | West [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Property, Plant, and Equipment, Fair Value Disclosure | [3] | 13 | 13 | |||||||||||||||||
Assets Held For Sale [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Central [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Assets Held-for-sale, Long Lived, Fair Value Disclosure | [2] | 1 | 1 | |||||||||||||||||
Investments [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Central And Northeast G&P [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Investments, Fair Value Disclosure | $ 1,295 | $ 1,294 | [5] | $ 4,017 | [6] | $ 1,203 | [7] | $ 1,203 | [7] | 1,295 | [4] | 4,017 | [6] | |||||||
Investments [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Central And Northeast G&P [Member] | Minimum [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Fair Value Inputs, Discount Rate | 13.00% | [5] | 10.80% | [6] | ||||||||||||||||
Investments [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Central And Northeast G&P [Member] | Maximum [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Fair Value Inputs, Discount Rate | 13.30% | [5] | 14.40% | [6] | ||||||||||||||||
Investments [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Central [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Investments, Fair Value Disclosure | $ 0 | |||||||||||||||||||
Investments [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | NGL And Petchem Services [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Investments, Fair Value Disclosure | $ 58 | 58 | ||||||||||||||||||
Investments [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Delaware Basin Gas Gathering System [Member] | Central And Northeast G&P [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Fair Value Inputs, Discount Rate | [7] | 11.80% | ||||||||||||||||||
Investments [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Appalachia Midstream Investments [Member] | Central And Northeast G&P [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Fair Value Inputs, Discount Rate | 10.20% | 8.80% | [7] | |||||||||||||||||
Canadian Operations [Member] | Assets Held For Sale [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | NGL And Petchem Services [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Assets Held-for-sale, Long Lived, Fair Value Disclosure | [8] | 924 | ||||||||||||||||||
Impairment Of Goodwill [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Impairment of goodwill | 1,098 | |||||||||||||||||||
Impairment Of Certain Assets [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Impairment of certain assets | 457 | 145 | 52 | |||||||||||||||||
Impairment Of Certain Assets [Member] | Fair Value, Measurements, Nonrecurring [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Impairment of certain assets | [9] | 68 | 31 | 10 | ||||||||||||||||
Impairment Of Certain Assets [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Impairment of certain assets | 389 | 114 | $ 42 | |||||||||||||||||
Impairment Of Certain Assets [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Central [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Impairment of certain assets | [1] | 48 | ||||||||||||||||||
Impairment of Long-Lived Assets to be Disposed of | [2] | 12 | ||||||||||||||||||
Impairment Of Certain Assets [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Northeast G&P [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Impairment of certain assets | [2] | $ 20 | $ 13 | $ 17 | ||||||||||||||||
Impairment Of Certain Assets [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | West [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Impairment of certain assets | [3] | 94 | ||||||||||||||||||
Impairment Of Certain Assets [Member] | Canadian Operations [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | NGL And Petchem Services [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down | [8] | $ 341 | ||||||||||||||||||
Impairment Of Equity-Method Investments [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Impairment of equity-method investments | $ 430 | $ 1,359 | ||||||||||||||||||
Impairment Of Equity-Method Investments [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Central And Northeast G&P [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Impairment of equity-method investments | $ 318 | 109 | [5] | 890 | [6] | $ 461 | [7] | |||||||||||||
Impairment Of Equity-Method Investments [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Central [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Impairment of equity-method investments | $ 3 | |||||||||||||||||||
Impairment Of Equity-Method Investments [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | NGL And Petchem Services [Member] | ||||||||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||||||||
Impairment of equity-method investments | $ 8 | |||||||||||||||||||
[1] | Relates to 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. | |||||||||||||||||||
[2] | 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. | |||||||||||||||||||
[3] | Relates to a gas processing plant, the completion of which is considered remote due to unfavorable impact of low natural gas prices on customer drilling activities. The assessed fair value primarily represents the estimated salvage value of certain equipment measured using a market approach based on our analysis of observable inputs in the principal market | |||||||||||||||||||
[4] | Relates to equity-method investments in Ranch Westex at Central and multiple Appalachia Midstream Investments at Northeast G&P. The historical carrying value of these investments was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with the acquisition of ACMP. We estimated the fair value of these Appalachia Midstream 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, rates, and related capital spending. The discount rate utilized for the Appalachia Midstream Investments evaluation was 10.2 percent and reflected our cost of capital as impacted by market conditions and risks associated with the underlying businesses. In addition to utilizing an income approach, we also considered a market approach for certain Appalachia Midstream Investments and Ranch Westex based on an agreement reached in February 2017 to exchange our interests in DBJV and Ranch Westex for additional interests in certain Appalachia Midstream Investments and cash. | |||||||||||||||||||
[5] | Relates to Central’s equity-method investment in DBJV 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. | |||||||||||||||||||
[6] | Relates to equity-method investments in DBJV at Central and Northeast G&P’s UEOM and Laurel Mountain investments, as well as certain of the Appalachia Midstream Investments. 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 10.8 percent to 14.4 percent and reflected further fourth-quarter 2015 increases in our cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses. | |||||||||||||||||||
[7] | Relates to equity-method investments in DBJV at Central and certain of the Appalachia Midstream Investments at Northeast G&P. The historical carrying value of these investments was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with the acquisition of ACMP. 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 were 11.8 percent and 8.8 percent for DBJV and certain of the Appalachia Midstream Investments, respectively, and reflected our cost of capital as impacted by market conditions, and risks associated with the underlying businesses. | |||||||||||||||||||
[8] | Relates to our Canadian operations. We 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 reflected our estimate of the potential assumed proceeds. We disposed of our Canadian operations through a sale during the third quarter of 2016. See Note 3 – Divestiture. | |||||||||||||||||||
[9] | Reflects multiple individually insignificant impairments and write-downs 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. |
Fair Value Measurements Concent
Fair Value Measurements Concentration of Credit Risk (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Concentration Risk [Line Items] | ||
Trade accounts and other receivables | $ 926 | $ 1,026 |
NGLs, natural gas, and related products and services [Member] | ||
Concentration Risk [Line Items] | ||
Trade accounts and other receivables | 736 | 821 |
Transportation of natural gas and related products [Member] | ||
Concentration Risk [Line Items] | ||
Trade accounts and other receivables | 187 | 202 |
Other Receivable [Member] | ||
Concentration Risk [Line Items] | ||
Trade accounts and other receivables | 3 | 3 |
Chesapeake Energy Corporation [Member] | Customer Concentration Risk [Member] | Accounts receivable [Member] | Central, Northeast G&P, and West [Member] | ||
Concentration Risk [Line Items] | ||
Trade accounts and other receivables | $ 133 | $ 364 |
Chesapeake Energy Corporation [Member] | Customer Concentration Risk [Member] | Sales Revenue, Net [Member] | Central, Northeast G&P, and West [Member] | ||
Concentration Risk [Line Items] | ||
Consolidated revenue, major customer, percentage | 14.00% | 18.00% |
Contingent Liabilities and Co74
Contingent Liabilities and Commitments (Details) $ in Millions | Dec. 31, 2016USD ($) |
Contingent Liabilities [Line Items] | |
Accrued environmental loss liabilities | $ 16 |
Capital Addition Purchase Commitments [Member] | |
Contingent Liabilities [Line Items] | |
Commitments for construction and acquisition of property, plant, and equipment | 244 |
Gas Pipeline [Member] | |
Contingent Liabilities [Line Items] | |
Accrued environmental loss liabilities | 9 |
Natural gas underground storage facilities [Member] | |
Contingent Liabilities [Line Items] | |
Accrued environmental loss liabilities | 7 |
NGL And Petchem Services [Member] | General Liability Coverage [Member] | Geismar Incident [Member] | |
Contingent Liabilities [Line Items] | |
Aggregate limit of insurance | 610 |
Insurance deductibles | $ 2 |
Segment Disclosures Geographic
Segment Disclosures Geographic Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Revenues from External Customers and Long-Lived Assets [Line Items] | |||
Revenues from external customers | $ 7,491 | $ 7,331 | $ 7,409 |
Long-lived assets | 37,683 | 38,616 | 38,893 |
United States [Member] | |||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||
Revenues from external customers | 7,406 | 7,228 | 7,212 |
Long-lived assets | 37,683 | 37,586 | 37,798 |
Canada [Member] | |||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||
Revenues from external customers | 85 | 103 | 197 |
Long-lived assets | $ 0 | $ 1,030 | $ 1,095 |
Segment Disclosures Recon from
Segment Disclosures Recon from Segment to Consolidated - Revenues (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Segment revenues [Line Items] | |||
Service revenues | $ 5,173 | $ 5,135 | $ 3,888 |
Product sales | 2,318 | 2,196 | 3,521 |
Total revenues | 7,491 | 7,331 | 7,409 |
Other financial information: | |||
Proportional Modified EBITDA of equity-method investments | 754 | 699 | 431 |
Intersegment Eliminations [Member] | |||
Segment revenues [Line Items] | |||
Service revenues | (60) | (37) | (17) |
Product sales | (674) | (572) | (1,094) |
Total revenues | (734) | (609) | (1,111) |
Other financial information: | |||
Proportional Modified EBITDA of equity-method investments | 0 | 15 | 7 |
Central [Member] | |||
Segment revenues [Line Items] | |||
Service revenues | 1,228 | 1,261 | 666 |
Product sales | 0 | 0 | 0 |
Central [Member] | Intersegment Eliminations [Member] | |||
Segment revenues [Line Items] | |||
Service revenues | (13) | (26) | (12) |
Product sales | 0 | 0 | 0 |
Central [Member] | Operating Segments [Member] | |||
Segment revenues [Line Items] | |||
Service revenues | 1,241 | 1,287 | 678 |
Product sales | 0 | 0 | 0 |
Total revenues | 1,241 | 1,287 | 678 |
Other financial information: | |||
Proportional Modified EBITDA of equity-method investments | 48 | 36 | 25 |
Northeast G&P [Member] | |||
Segment revenues [Line Items] | |||
Service revenues | 804 | 803 | 549 |
Product sales | 135 | 109 | 225 |
Northeast G&P [Member] | Intersegment Eliminations [Member] | |||
Segment revenues [Line Items] | |||
Service revenues | (34) | (7) | (1) |
Product sales | (28) | (18) | (5) |
Northeast G&P [Member] | Operating Segments [Member] | |||
Segment revenues [Line Items] | |||
Service revenues | 838 | 810 | 550 |
Product sales | 163 | 127 | 230 |
Total revenues | 1,001 | 937 | 780 |
Other financial information: | |||
Proportional Modified EBITDA of equity-method investments | 362 | 349 | 198 |
Atlantic Gulf [Member] | |||
Segment revenues [Line Items] | |||
Service revenues | 1,939 | 1,877 | 1,497 |
Product sales | 244 | 287 | 499 |
Atlantic Gulf [Member] | Intersegment Eliminations [Member] | |||
Segment revenues [Line Items] | |||
Service revenues | (13) | (4) | (4) |
Product sales | (205) | (176) | (354) |
Atlantic Gulf [Member] | Operating Segments [Member] | |||
Segment revenues [Line Items] | |||
Service revenues | 1,952 | 1,881 | 1,501 |
Product sales | 449 | 463 | 853 |
Total revenues | 2,401 | 2,344 | 2,354 |
Other financial information: | |||
Proportional Modified EBITDA of equity-method investments | 287 | 257 | 151 |
West [Member] | |||
Segment revenues [Line Items] | |||
Service revenues | 1,034 | 1,055 | 1,050 |
Product sales | 18 | 36 | 70 |
West [Member] | Intersegment Eliminations [Member] | |||
Segment revenues [Line Items] | |||
Service revenues | 0 | 0 | 0 |
Product sales | (260) | (221) | (476) |
West [Member] | Operating Segments [Member] | |||
Segment revenues [Line Items] | |||
Service revenues | 1,034 | 1,055 | 1,050 |
Product sales | 278 | 257 | 546 |
Total revenues | 1,312 | 1,312 | 1,596 |
Other financial information: | |||
Proportional Modified EBITDA of equity-method investments | 0 | 0 | 0 |
NGL And Petchem Services [Member] | |||
Segment revenues [Line Items] | |||
Service revenues | 168 | 139 | 126 |
Product sales | 1,921 | 1,764 | 2,727 |
NGL And Petchem Services [Member] | Intersegment Eliminations [Member] | |||
Segment revenues [Line Items] | |||
Service revenues | 0 | 0 | 0 |
Product sales | (181) | (157) | (259) |
NGL And Petchem Services [Member] | Operating Segments [Member] | |||
Segment revenues [Line Items] | |||
Service revenues | 168 | 139 | 126 |
Product sales | 2,102 | 1,921 | 2,986 |
Total revenues | 2,270 | 2,060 | 3,112 |
Other financial information: | |||
Proportional Modified EBITDA of equity-method investments | $ 57 | $ 42 | $ 50 |
Segment Disclosures Recon fro77
Segment Disclosures Recon from Modified EBITDA to Net Income (Loss) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Reconciliation of Modified EBITDA to Net Income (Loss) | ||||
Modified EBITDA Earnings Loss | $ 3,864 | $ 4,003 | $ 3,244 | |
Accretion expense associated with asset retirement obligations for nonregulated operations | (31) | (28) | (17) | |
Depreciation and amortization expenses | (1,720) | (1,702) | (1,151) | |
Impairment of goodwill | $ (1,098) | 0 | (1,098) | 0 |
Equity earnings (losses) | 397 | 335 | 228 | |
Impairment of equity-method investments (Note 17) | (430) | (1,359) | 0 | |
Other investing income (loss) – net | 29 | 2 | 2 | |
Proportional Modified EBITDA of equity-method investments | (754) | (699) | (431) | |
Interest Expense | (916) | (811) | (562) | |
(Provision) benefit for income taxes | 80 | (1) | (29) | |
Net income (loss) | 519 | (1,358) | 1,284 | |
Central [Member] | ||||
Reconciliation of Modified EBITDA to Net Income (Loss) | ||||
Impairment of goodwill | (250) | |||
Northeast G&P [Member] | ||||
Reconciliation of Modified EBITDA to Net Income (Loss) | ||||
Impairment of goodwill | (848) | |||
West [Member] | ||||
Reconciliation of Modified EBITDA to Net Income (Loss) | ||||
Impairment of goodwill | 0 | |||
Operating Segments [Member] | Central [Member] | ||||
Reconciliation of Modified EBITDA to Net Income (Loss) | ||||
Modified EBITDA Earnings Loss | 807 | 840 | 419 | |
Proportional Modified EBITDA of equity-method investments | (48) | (36) | (25) | |
Operating Segments [Member] | Northeast G&P [Member] | ||||
Reconciliation of Modified EBITDA to Net Income (Loss) | ||||
Modified EBITDA Earnings Loss | 840 | 753 | 618 | |
Proportional Modified EBITDA of equity-method investments | (362) | (349) | (198) | |
Operating Segments [Member] | Atlantic-Gulf [Member] | ||||
Reconciliation of Modified EBITDA to Net Income (Loss) | ||||
Modified EBITDA Earnings Loss | 1,600 | 1,523 | 1,065 | |
Proportional Modified EBITDA of equity-method investments | (287) | (257) | (151) | |
Operating Segments [Member] | West [Member] | ||||
Reconciliation of Modified EBITDA to Net Income (Loss) | ||||
Modified EBITDA Earnings Loss | 649 | 557 | 823 | |
Proportional Modified EBITDA of equity-method investments | 0 | 0 | 0 | |
Operating Segments [Member] | NGL & Petchem Services [Member] | ||||
Reconciliation of Modified EBITDA to Net Income (Loss) | ||||
Modified EBITDA Earnings Loss | (23) | 321 | 324 | |
Proportional Modified EBITDA of equity-method investments | (57) | (42) | (50) | |
Other [Member] | ||||
Reconciliation of Modified EBITDA to Net Income (Loss) | ||||
Modified EBITDA Earnings Loss | $ (9) | $ 9 | $ (5) |
Segment Disclosures Recon fro78
Segment Disclosures Recon from Segment to Consolidated - Assets and Invesetments (Details) - USD ($) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |||
Segment Reporting, Asset Reconciling Item [Line Items] | |||||
Total assets | $ 46,265 | $ 47,870 | |||
Investments | 6,701 | 7,336 | |||
Additions to long-lived assets | 2,102 | 2,960 | $ 20,413 | ||
Operating Segments [Member] | Central [Member] | |||||
Segment Reporting, Asset Reconciling Item [Line Items] | |||||
Total assets | 13,129 | 13,914 | |||
Investments | 1,033 | 1,050 | |||
Additions to long-lived assets | 88 | 363 | 13,016 | [1] | |
Operating Segments [Member] | Northeast G&P [Member] | |||||
Segment Reporting, Asset Reconciling Item [Line Items] | |||||
Total assets | 13,324 | 13,827 | |||
Investments | 4,289 | 4,823 | |||
Additions to long-lived assets | 217 | 560 | 4,497 | [1] | |
Operating Segments [Member] | Atlantic Gulf [Member] | |||||
Segment Reporting, Asset Reconciling Item [Line Items] | |||||
Total assets | 13,892 | 12,171 | |||
Investments | 893 | 959 | |||
Additions to long-lived assets | 1,590 | 1,573 | 1,593 | ||
Operating Segments [Member] | West [Member] | |||||
Segment Reporting, Asset Reconciling Item [Line Items] | |||||
Total assets | 4,715 | 5,035 | |||
Investments | 0 | 0 | |||
Additions to long-lived assets | 124 | 225 | 698 | [1] | |
Operating Segments [Member] | NGL And Petchem Services [Member] | |||||
Segment Reporting, Asset Reconciling Item [Line Items] | |||||
Total assets | 2,304 | 3,306 | |||
Investments | 486 | 504 | |||
Additions to long-lived assets | 83 | 236 | 601 | ||
Other [Member] | |||||
Segment Reporting, Asset Reconciling Item [Line Items] | |||||
Total assets | 207 | 350 | |||
Investments | 0 | 0 | |||
Additions to long-lived assets | 0 | 3 | 8 | ||
Intersegment Eliminations [Member] | |||||
Segment Reporting, Asset Reconciling Item [Line Items] | |||||
Total assets | [2] | (1,306) | (733) | ||
Investments | 0 | 0 | |||
Additions to long-lived assets | $ 0 | $ 0 | $ 0 | ||
[1] | 2014 Additions to long-lived assets includes the acquisition-date fair value of long-lived assets from the ACMP Acquisition (Note 2 – Acquisitions). | ||||
[2] | Eliminations primarily relate to the intercompany accounts receivable generated by our cash management program. |