Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Feb. 22, 2016 | Jun. 30, 2015 | |
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, 2015 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2,015 | ||
Document Fiscal Period Focus | FY | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Public Float | $ 28,408,143,353 | ||
Entity Partnership Units Outstanding | 588,565,174 | ||
Class B Units [Member] | |||
Entity Information [Line Items] | |||
Entity Partnership Units Outstanding | 15,343,001 |
Consolidated Statement of Compr
Consolidated Statement of Comprehensive Income (Loss) - USD ($) shares in Thousands, $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Revenues: | |||
Service revenues | $ 5,135 | $ 3,888 | $ 2,914 |
Product sales | 2,196 | 3,521 | 3,921 |
Total revenues | 7,331 | 7,409 | 6,835 |
Costs and expenses: | |||
Product costs | 1,779 | 3,016 | 3,027 |
Operating and maintenance expenses | 1,625 | 1,277 | 1,080 |
Depreciation and amortization expenses | 1,702 | 1,151 | 791 |
Selling, general, and administrative expenses | 684 | 633 | 519 |
Impairment of goodwill | 1,098 | 0 | 0 |
Net insurance recoveries – Geismar Incident | (126) | (232) | (40) |
Other (income) expense – net | 186 | (45) | 51 |
Total costs and expenses | 6,948 | 5,800 | 5,428 |
Operating income | 383 | 1,609 | 1,407 |
Equity earnings (losses) | 335 | 228 | 104 |
Impairment of equity-method investments | (1,359) | 0 | 0 |
Other investing income (loss) – net | 2 | 2 | (1) |
Interest incurred | (864) | (683) | (477) |
Interest capitalized | 53 | 121 | 90 |
Other income (expense) – net | 93 | 36 | 26 |
Income (loss) before income taxes | (1,357) | 1,313 | 1,149 |
Provision (benefit) for income taxes | 1 | 29 | 30 |
Net income (loss) | (1,358) | 1,284 | 1,119 |
Less: Net income attributable to noncontrolling interests | 91 | 96 | 3 |
Net income (loss) attributable to controlling interests | (1,449) | 1,188 | 1,116 |
Allocation of net income (loss) for calculation of earnings per common unit: | |||
Net income (loss) attributable to controlling interests | (1,449) | 1,188 | 1,116 |
Allocation of net income (loss) to general partner | 384 | 756 | 505 |
Allocation of net income (loss) to Class B units | (46) | 0 | 0 |
Allocation of net income (loss) to Class D units | 68 | 73 | 0 |
Allocation of net income (loss) to common units | $ (1,855) | $ 359 | $ 611 |
Diluted earnings (loss) per common unit | |||
Net income (loss) per common unit | $ (3.27) | $ 0.99 | $ 1.76 |
Weighted-average number of common units outstanding (thousands) | 567,275 | 361,968 | 346,307 |
Diluted earnings (loss) per common unit | |||
Diluted net income (loss) per common unit | $ 0.25 | $ 0.99 | $ 1.76 |
Diluted weighted-average number of common units outstanding (thousands) | 567,275 | 361,968 | 346,307 |
Cash distributions per common unit | $ 3.4000 | $ 3.5995 | $ 3.4800 |
Other Comprehensive Income (Loss): | |||
Net unrealized gain (loss) from derivative instruments | $ 6 | $ (1) | $ 1 |
Reclassifications into earnings of net derivative instruments (gain) loss | (7) | 0 | 0 |
Foreign currency translation adjustments | (173) | (89) | (56) |
Other comprehensive income (loss) | (174) | (90) | (55) |
Comprehensive income (loss) | (1,532) | 1,194 | 1,064 |
Less: Comprehensive income (loss) attributable to noncontrolling interests | 91 | 96 | 3 |
Comprehensive income (loss) attributable to controlling interests | $ (1,623) | $ 1,098 | $ 1,061 |
Consolidated Balance Sheet
Consolidated Balance Sheet - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Current assets: | ||
Cash and cash equivalents | $ 96 | $ 171 |
Accounts and notes receivable (net of allowance of $3 at December 31, 2015 and $0 at December 31, 2014) | 1,026 | 905 |
Inventories | 127 | 231 |
Other current assets | 190 | 198 |
Total current assets | 1,439 | 1,505 |
Investments | 7,336 | 8,399 |
Property, plant, and equipment – net | 28,600 | 27,322 |
Goodwill | 47 | 1,120 |
Other intangible assets – net of accumulated amortization | 9,969 | 10,451 |
Regulatory assets, deferred charges, and other | 479 | 451 |
Total assets | 47,870 | 49,248 |
Accounts payable: | ||
Trade | 648 | 808 |
Affiliate | 141 | 137 |
Accrued interest | 231 | 215 |
Asset retirement obligations | 57 | 40 |
Other accrued liabilities | 469 | 392 |
Long-term debt due within one year | 176 | 4 |
Commercial paper | 499 | 798 |
Total current liabilities | 2,221 | 2,394 |
Long-term Debt and Capital Lease Obligations | 19,001 | 16,252 |
Asset retirement obligations | 857 | 791 |
Deferred income tax liabilities | 119 | 133 |
Regulatory liabilities, deferred income, and other | $ 1,066 | $ 993 |
Contingent liabilities and commitments (Note 17) | ||
Partners’ equity: | ||
Common units (588,546,022 and 362,556,333 units outstanding at December 31, 2015 and 2014, respectively) | $ 19,730 | $ 10,367 |
Class B units (14,784,015 units outstanding as of December 31, 2015) | 771 | 0 |
Class D units (21,574,035 units outstanding at December 31, 2014) | 0 | 1,011 |
General partner | 2,552 | 9,214 |
Accumulated other comprehensive income (loss) | (172) | 2 |
Total partners’ equity | 22,881 | 20,594 |
Noncontrolling interests in consolidated subsidiaries | 1,725 | 8,091 |
Total equity | 24,606 | 28,685 |
Total liabilities and equity | $ 47,870 | $ 49,248 |
Consolidated Balance Sheet (Par
Consolidated Balance Sheet (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Equity: | ||
Limited partners capital account units outstanding | 588,546,022 | 362,556,333 |
Class B Partners Capital Account Units Outstanding | 14,784,015 | 0 |
Class D Partners Capital Account Units Outstanding | 0 | 21,574,035 |
Allowance for Doubtful Accounts Receivable, Current | $ 3 | $ 0 |
Consolidated Statement of Chang
Consolidated Statement of Changes in Equity - USD ($) $ in Millions | Total | Limited PartnersCommon Units | Limited PartnersCommon Class B [Member] | Limited PartnersClass D [Member] | General Partner | Accumulated Other Comprehensive Income (Loss) | Noncontrolling Interests | Parent [Member] |
Beginning Balance at Dec. 31, 2012 | $ 9,691 | $ 10,372 | $ 0 | $ 0 | $ (842) | $ 147 | $ 14 | $ 9,677 |
Net income (loss) | 1,119 | 660 | 0 | 0 | 456 | 0 | 3 | 1,116 |
Other comprehensive income (loss) | (55) | 0 | 0 | 0 | 0 | (55) | 0 | (55) |
Cash distributions | (1,846) | (1,422) | 0 | 0 | (424) | 0 | 0 | (1,846) |
Contributions from The Williams Companies, Inc - net (Note 1) | 221 | 0 | 0 | 0 | 221 | 0 | 0 | 221 |
Sales of common units (Note 14) | 1,962 | 1,962 | 0 | 0 | 0 | 0 | 0 | 1,962 |
Contributions from general partner | 78 | 0 | 0 | 0 | 78 | 0 | 0 | 78 |
Contributions from noncontrolling interests | 398 | 0 | 0 | 0 | 0 | 0 | 398 | 0 |
Other | (1) | 24 | 0 | 0 | (25) | 0 | 0 | (1) |
Net increase (decrease) in equity | 1,876 | 1,224 | 0 | 0 | 306 | (55) | 401 | 1,475 |
Ending Balance at Dec. 31, 2013 | 11,567 | 11,596 | 0 | 0 | (536) | 92 | 415 | 11,152 |
Net income (loss) | 1,284 | 354 | 0 | 62 | 772 | 0 | 96 | 1,188 |
Other comprehensive income (loss) | (90) | 0 | 0 | 0 | 0 | (90) | 0 | (90) |
Cash distributions | (2,448) | (1,706) | 0 | 0 | (742) | 0 | 0 | (2,448) |
Contributions from The Williams Companies, Inc - net (Note 1) | 18,205 | 0 | 0 | 0 | 10,703 | 0 | 7,502 | 10,703 |
Sales of common units (Note 14) | 55 | 55 | 0 | 0 | 0 | 0 | 0 | 55 |
Issuance of Class D units in common control transaction (Note 1) | 0 | 0 | 0 | 1,017 | (1,017) | 0 | 0 | 0 |
Beneficial conversion feature of Class D units | 0 | 117 | 0 | (117) | 0 | 0 | 0 | 0 |
Amortization of beneficial conversion feature of Class D units (Note 4) | 0 | (49) | 0 | 49 | 0 | 0 | 0 | 0 |
Contributions from general partner | 13 | 0 | 0 | 0 | 13 | 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 | 0 | 0 | 0 | 21 | 0 | (13) | 21 |
Net increase (decrease) in equity | 17,118 | (1,229) | 0 | 1,011 | 9,750 | (90) | 7,676 | 9,442 |
Ending Balance at Dec. 31, 2014 | 28,685 | 10,367 | 0 | 1,011 | 9,214 | 2 | 8,091 | 20,594 |
Net income (loss) | (1,358) | (1,988) | (52) | 1 | 590 | 0 | 91 | (1,449) |
Other comprehensive income (loss) | (174) | 0 | 0 | 0 | 0 | (174) | 0 | (174) |
Cash distributions | (2,686) | (1,995) | 0 | 0 | (691) | 0 | 0 | (2,686) |
Contributions from The Williams Companies, Inc - net (Note 1) | 20 | 12,254 | 823 | 0 | (6,573) | 0 | (6,484) | 6,504 |
Sales of common units (Note 14) | 59 | 59 | 0 | 0 | 0 | 0 | 0 | 59 |
Amortization of beneficial conversion feature of Class D units (Note 4) | 0 | (68) | 0 | 68 | 0 | 0 | 0 | 0 |
Contributions from general partner | 14 | 0 | 0 | 0 | 14 | 0 | 0 | 14 |
Conversion of Class D units to common units (Note 4) | 0 | 1,080 | 0 | (1,080) | 0 | 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 | 21 | 0 | 0 | (2) | 0 | 3 | 19 |
Net increase (decrease) in equity | (4,079) | 9,363 | 771 | (1,011) | (6,662) | (174) | (6,366) | 2,287 |
Ending Balance at Dec. 31, 2015 | $ 24,606 | $ 19,730 | $ 771 | $ 0 | $ 2,552 | $ (172) | $ 1,725 | $ 22,881 |
Consolidated Statement of Cash
Consolidated Statement of Cash Flows - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
OPERATING ACTIVITIES: | |||
Net income (loss) | $ (1,358) | $ 1,284 | $ 1,119 |
Adjustments to reconcile to net cash provided by operating activities: | |||
Depreciation and amortization | 1,702 | 1,151 | 791 |
Provision (benefit) for deferred income taxes | 4 | 25 | 50 |
Impairment of goodwill | 1,098 | 0 | 0 |
Impairment of equity-method investments | 1,359 | 0 | 0 |
Impairment of and net (gain) loss on sale of Property, plant, and equipment | 150 | 68 | 7 |
Amortization of stock-based awards | 27 | 9 | 0 |
Cash provided (used) by changes in current assets and liabilities: | |||
Accounts and notes receivable | (67) | (169) | 21 |
Inventories | 105 | (36) | (17) |
Other current assets and deferred charges | 2 | (43) | 25 |
Accounts payable | (128) | (42) | (32) |
Accrued liabilities | (15) | (233) | 171 |
Affiliate accounts receivable and payable – net | 0 | 9 | (1) |
Other, including changes in noncurrent assets and liabilities | (218) | 322 | 35 |
Net cash provided by operating activities | 2,661 | 2,345 | 2,169 |
FINANCING ACTIVITIES: | |||
Proceeds from (payments of) commercial paper – net | (306) | 572 | 224 |
Proceeds from long-term debt | 7,675 | 4,386 | 2,699 |
Payments of long-term debt | (4,699) | (1,157) | (2,080) |
Proceeds from sales of common units | 59 | 55 | 1,962 |
Contributions from general partner | 14 | 13 | 53 |
Distributions to limited partners and general partner | (2,686) | (2,448) | (1,846) |
Distributions to noncontrolling interests | (87) | (243) | 0 |
Contributions from noncontrolling interests | 111 | 334 | 398 |
Contributions from The Williams Companies, Inc. – net | 20 | 73 | 221 |
Payments for debt issuance costs | (33) | (24) | (12) |
Special distribution from Gulfstream | 396 | 0 | 0 |
Contribution to Gulfstream for repayment of debt | (248) | 0 | 0 |
Other – net | (1) | 24 | (24) |
Net cash provided by financing activities | 215 | 1,585 | 1,595 |
INVESTING ACTIVITIES: | |||
Capital expenditures (1) | (2,795) | (3,692) | (3,316) |
Net proceeds from dispositions | 3 | 34 | 3 |
Purchase of business | (112) | 0 | 0 |
Purchase of business from affiliate | 0 | 0 | 25 |
Purchases of and contributions to equity-method investments | (594) | (468) | (439) |
Other – net | 547 | 257 | (9) |
Net cash used by investing activities | (2,951) | (3,869) | (3,736) |
Increase (decrease) in cash and cash equivalents | (75) | 61 | 28 |
Cash and cash equivalents at beginning of year | 171 | 110 | 82 |
Cash and cash equivalents at end of year | 96 | 171 | 110 |
(1) Increases to property, plant, and equipment | (2,649) | (3,571) | (3,333) |
Changes in related accounts payable and accrued liabilities | (146) | (121) | 17 |
Capital expenditures (1) | $ (2,795) | $ (3,692) | $ (3,316) |
General, Description of Busines
General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2015 | |
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. Williams owns an approximate 58 percent limited partner interest, a 2 percent general partner interest, and incentive distribution rights (IDRs) in us. Our operations are located in the United States and Canada. 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 (Public Unit Exchange). On September 28, 2015, we entered into a Termination Agreement and Release (Termination Agreement), terminating the Public Unit Exchange. Under the terms of the Termination Agreement, Williams is required to pay us a $428 million termination fee, which will settle through a reduction of quarterly incentive distributions payable to Williams (such reduction not to exceed $209 million per quarter). Our November 2015 and February 2016 distributions to Williams were each reduced by $209 million related to this termination fee. Williams’ Merger Agreement with Energy Transfer On September 28, 2015, Williams publicly announced in a press release that it had entered into an Agreement and Plan of Merger (Merger Agreement) with Energy Transfer Equity, L.P. (Energy Transfer) and certain of its affiliates. The Merger Agreement provides that, subject to the satisfaction of customary closing conditions, Williams will be merged with and into the newly formed Energy Transfer Corp LP (ETC) (ETC Merger), with ETC surviving the ETC Merger. Energy Transfer formed ETC as a limited partnership that will be treated as a corporation for U.S. federal income tax purposes. Immediately following the completion of the ETC Merger, ETC will contribute to Energy Transfer all of the assets and liabilities of Williams in exchange for the issuance by Energy Transfer to ETC of a number of Energy Transfer Class E common units equal to the number of ETC common shares issued to Williams stockholders in the ETC Merger. We expect to retain our current name and remain a publicly traded limited partnership following the ETC Merger. ACMP Merger Pursuant to an Agreement and Plan of Merger dated as of October 24, 2014, the general partners of Williams Partners L.P. and Access Midstream Partners, L.P. agreed to combine those businesses and their general partners, with Williams Partners L.P. merging with and into Access Midstream Partners, L.P. and the Access Midstream Partners, L.P. general partner being the surviving general partner (ACMP Merger). Following the completion of the ACMP Merger on February 2, 2015, as further described below, the surviving Access Midstream Partners, L.P. changed its name to Williams Partners L.P. and the name of its general partner was changed to WPZ GP LLC. 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. In accordance with the terms of the ACMP Merger, each ACMP unitholder received 1.06152 ACMP units for each ACMP unit owned immediately prior to the ACMP Merger. Following this pre-merger split ACMP had 202,564,354 common units and 13,725,843 Class B units outstanding. In conjunction with the ACMP Merger, each Pre-merger WPZ common unit held by the public was exchanged for 0.86672 common units of ACMP. Each Pre-merger WPZ common unit held by Williams was exchanged for 0.80036 common units of ACMP. Prior to the closing of the ACMP Merger, the Class D limited partner units of Pre-merger WPZ, all of which were held by Williams, were converted into Pre-merger WPZ common units on a one -for-one basis pursuant to the terms of the partnership agreement of Pre-merger WPZ. All of the general partner interests of Pre-merger WPZ were converted into general partner interests of ACMP such that the general partner interest of ACMP represents 2 percent of the outstanding partnership interest. Description of Business Our operations are located in North America and are organized into the following reportable segments: Access Midstream, Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services. Access Midstream 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, the Marcellus Shale region primarily in Pennsylvania and West Virginia, the Utica Shale region of eastern Ohio, and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware, and Permian basins. Access Midstream also includes a 62 percent equity-method investment in Utica East Ohio Midstream, LLC (UEOM), a 50 percent equity-method investment in the Delaware basin gas gathering system in the Mid-Continent region, and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 45 percent interest in multiple gathering systems in the Marcellus Shale (Appalachia Midstream Investments). Northeast G&P is comprised of our midstream gathering and processing businesses in the Marcellus and Utica shale regions, as well as a 69 percent equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain) and a 58 percent equity-method investment in Caiman Energy II, LLC (Caiman II). 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). Effective during the first quarter of 2015, the operations of the Niobrara Shale region that were formerly within the Access Midstream segment were transferred into the West reportable segment. The prior period amounts and disclosures included herein have been recast for this change. 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 and butylene/butane splitter facility at Redwater, Alberta. This segment also includes our NGL and natural gas marketing business, storage facilities, and an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, and a 50 percent equity-method investment in Overland Pass Pipeline, LLC (OPPL). Basis of Presentation 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 . Other In the first quarter of 2013, Pre-merger WPZ received $25 million in cash from Williams and Williams waived $4 million in payments on its IDRs with respect to Pre-merger WPZ’s May 2013 distribution related to a working capital adjustment associated with a 2012 acquisition. 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, 2015 and 2014 are as follows: December 31, 2015 2014 (Millions) Current assets reported within Other current assets $ 84 $ 81 Noncurrent assets reported within Regulatory assets, deferred charges, and other 305 289 Total regulated assets $ 389 $ 370 Current liabilities reported within Other accrued liabilities $ 4 $ 11 Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other 409 349 Total regulated liabilities $ 413 $ 360 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. Inventory valuation All Inventories in the Consolidated Balance Sheet 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 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 the 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 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 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. 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 13 – 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 physical 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 ; 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 16 – 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 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-te |
Acquisitions
Acquisitions | 12 Months Ended |
Dec. 31, 2015 | |
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, substantially all of which are presented in the Access Midstream segment, 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 was approximately 17 years . The following unaudited pro forma Revenues and Net income attributable to controlling interests for the years ended December 31, 2014 and 2013, are presented as if the ACMP Acquisition had been completed on January 1, 2013. 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 periods indicated, nor do they purport to project Revenues or Net income 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 2013 (Millions) Revenues $ 7,953 $ 7,881 Net income attributable to controlling interests $ 1,376 $ 1,172 Significant adjustments to pro forma Net income 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 Revenues of $781 million and Net income 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 Access Midstream segment and included in Selling, general, and administrative expenses in our Consolidated Statement of Comprehensive Income (Loss) . Direct transaction costs associated with financing commitments were $9 million in 2014 and reported within Interest incurred in our 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 Access Midstream 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, at cost and $32 million of Other 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, at cost , and a decrease of $20 million in Other 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 has agreed to waive approximately $2 million of its IDR payments each quarter through 2017. |
Variable Interest Entities
Variable Interest Entities | 12 Months Ended |
Dec. 31, 2015 | |
Variable Interest Entity Disclosures [Abstract] | |
Variable Interest Entities [Text Block] | Note 3 – Variable Interest Entities As of December 31, 2015 , 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. Construction of an expansion project is underway that will provide production handling and gathering services for the Gunflint oil and gas discovery in the eastern deepwater Gulf of Mexico. The expansion project is expected to be in service in the first half of 2016. The current estimate of the total remaining construction cost for the expansion project is approximately $130 million , which we expect will be funded with revenues received from customers and capital contributions from us and the other equity partner on a proportional basis. Constitution We own a 41 percent interest in Constitution , a subsidiary that, due to shipper fixed-payment commitments under its long-term firm transportation contracts, is a VIE. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Constitution’s economic performance. We, as construction manager for Constitution, are responsible for constructing the proposed pipeline connecting our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems. We plan to place the project in service in the fourth quarter of 2016, assuming timely receipt of all necessary regulatory approvals, and estimate the total remaining cost of the project to be approximately $571 million , which we expect will be funded with capital contributions from us and the other equity partners on a proportional basis. Cardinal We own a 66 percent interest in Cardinal Gas Services, L.L.C (Cardinal), a subsidiary that provides gathering services for the Utica region and is a VIE due to certain risks shared with customers. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Cardinal’s economic performance. We expect to fund future expansion activity with capital contributions from us and the other equity partner on a proportional basis. Jackalope We own a 50 percent interest in Jackalope Gas Gathering Services, L.L.C (Jackalope), a subsidiary that provides gathering and processing services for the Powder River basin and is a VIE due to certain risks shared with customers. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Jackalope’s economic performance. We expect to fund future expansion activity with capital contributions from us and the other equity partner on a proportional basis. The following table presents amounts included in our Consolidated Balance Sheet that are for the use or obligation of our consolidated VIEs. December 31, 2015 2014 Classification (Millions) Assets (liabilities): Cash and cash equivalents $ 70 $ 113 Cash and cash equivalents Accounts receivable 71 52 Accounts and notes receivable – net Other current assets 2 3 Other current assets Property, plant, and equipment – net 3,000 2,794 Property, plant, and equipment – net Goodwill 47 103 Goodwill Other intangible assets – net 1,436 1,493 Other intangible assets – net of accumulated amortization Other noncurrent assets — 14 Regulatory assets, deferred charges, and other Accounts payable (59 ) (48 ) Accounts payable – trade Accrued liabilities (14 ) (36 ) Other accrued liabilities Current deferred revenue (62 ) (45 ) Other accrued liabilities Noncurrent deferred income taxes — (13 ) Deferred income tax liabilities Asset retirement obligation (93 ) (94 ) Asset retirement obligations, noncurrent Noncurrent deferred revenue associated with customer advance payments (331 ) (395 ) Regulatory liabilities, deferred income, and other |
Allocation of Net Income (Loss)
Allocation of Net Income (Loss) and Distributions | 12 Months Ended |
Dec. 31, 2015 | |
Equity [Abstract] | |
Allocation of Net Income and Distributions | Note 4 – 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, 2015 2014 2013 (Millions) Allocation of net income to general partner: Net income (loss) $ (1,358 ) $ 1,284 $ 1,119 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 ) (49 ) Net income applicable to noncontrolling interests (91 ) (96 ) (3 ) Costs charged directly to the general partner 21 1 1 Income (loss) subject to 2% allocation of general partner interest (1,430 ) 1,079 1,068 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 (29 ) 22 21 Priority allocations, including incentive distributions, paid to general partner 638 641 387 Pre-merger net income allocated to general partner interest 2 95 — Pre-partnership net income allocated to general partner interest — 15 49 Costs charged directly to the general partner (21 ) (1 ) (1 ) Net income allocated to general partner’s equity $ 590 $ 772 $ 456 Net income (loss) $ (1,358 ) $ 1,284 $ 1,119 Net income allocated to general partner’s equity 590 772 456 Net income (loss) allocated to Class B limited partners’ equity (52 ) — — Net income allocated to Class D limited partners’ equity (1) 69 62 — Net income allocated to noncontrolling interests 91 96 3 Net income (loss) allocated to common limited partners’ equity $ (2,056 ) $ 354 $ 660 Adjustments to reconcile Net income (loss) allocated to common limited partners' equity to Allocation of net income (loss) to common units: Incentive distributions paid 633 640 383 Incentive distributions declared (2) (3) (423 ) (626 ) (432 ) Impact of unit issuance timing and other (9 ) (9 ) — Allocation of net income (loss) to common units $ (1,855 ) $ 359 $ 611 ____________ (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) On February 12, 2016, 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 5, 2016. (3) The 2015 amount reflects the waiver of IDRs associated with the Termination Agreement. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies .) The 2014 amount reflects only the portion of the total incentive distribution associated with the Pre-merger WPZ common units exchanged in the ACMP Merger. Class B Units The Class B units originated under ACMP and 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 2015, we issued a total of 1,058,172 of additional paid-in-kind Class B units associated with quarterly distributions. On February 12, 2016, we issued 558,986 Class B units associated with the fourth-quarter 2015 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. Distributions 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, 2015 | |
Related Party Transactions [Abstract] | |
Related Party Transactions Disclosure [Text Block] | Note 5 – 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 Product costs , in the Consolidated Statement of Comprehensive Income (Loss) , include charges for the following types of transactions with equity-method investees: • Purchases of NGLs for resale from Discovery. • Payments to OPPL for transportation of NGLs from certain natural gas processing plants. Summary of the related party transactions discussed in all sections above. Years Ended December 31, 2015 2014 2013 (Millions) Product costs $ 169 $ 186 $ 147 Operating and maintenance expenses - employee costs 498 413 339 Selling, general, and administrative expenses: Employee direct costs 368 331 270 Employee allocated costs 195 171 169 HB Construction Company Ltd., a subsidiary of Williams, provides construction services to us. Charges for these construction services as well as other capitalized payroll and benefit costs charged by Williams described above are capitalized within Property, plant, and equipment – net in the Consolidated Balance Sheet and totaled $187 million and $81 million during December 2015 and 2014, 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 $12 million and $13 million in Accounts payable — trade in the Consolidated Balance Sheet with our equity-method investees at December 31, 2015 and 2014, 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 gross charges to equity-method investees for these fees included in the Consolidated Statement of Comprehensive Income (Loss) are $64 million , $65 million , and $67 million for the years ended December 31, 2015, 2014, and 2013, 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, 2015, 2014 and 2013 were $12 million , $11 million , and $12 million , respectively. We have a contribution receivable from our general partner of $3 million at December 31, 2015, for amounts reimbursable to us under omnibus agreements presented within Total partners’ equity in the Consolidated Balance Sheet . Acquisitions and Equity Issuances Basis of Presentation in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies includes related party transactions for the ACMP Merger, Canada Acquisition, and Other. 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 14 – Partners’ Capital includes a related party transaction for the sale of Pre-merger WPZ common units to Williams in March 2013. Board of Directors A member of Williams’ Board of Directors, who was elected in 2013, is also the current chairman, president, and chief executive officer of an energy services company that is a customer of ours. We recorded $111 million , $115 million and $131 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, 2015, 2014, and 2013, respectively. |
Investing Activities
Investing Activities | 12 Months Ended |
Dec. 31, 2015 | |
Investments [Abstract] | |
Investments [Text Block] | Note 6 – Investing Activities Impairment of equity-method investments in the Consolidated Statement of Comprehensive Income (Loss) During the third quarter of 2015, we recognized other-than-temporary impairment charges of $458 million and $3 million related to our equity-method investments in the Delaware basin gas gathering system and certain of the Appalachia Midstream Investments, respectively. During the fourth quarter of 2015, we recognized additional impairment charges for these investments of $45 million and $559 million , respectively, as well as impairment charges of $241 million and $45 million associated with our equity-method investments in UEOM and Laurel Mountain, respectively. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk .) Equity earnings (losses) in the Consolidated Statement of Comprehensive Income (Loss) 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 Access Midstream segment. Investments in the Consolidated Balance Sheet December 31, 2015 2014 (Millions) Appalachia Midstream Investments (1) $ 2,464 $ 3,033 UEOM – 62% (2) 1,525 1,411 Delaware basin gas gathering system – 50% 977 1,478 Discovery – 60% 602 602 OPPL – 50% 445 453 Caiman II – 58% 418 432 Laurel Mountain – 69% 391 459 Gulfstream – 50% 293 317 Other 221 214 $ 7,336 $ 8,399 ____________ (1) Includes equity-method investments in multiple gathering systems in the Marcellus Shale with an approximate average 45 percent interest. (2) We acquired an approximate 13 percent additional interest in UEOM in 2015. (See Note 2 – Acquisitions .) We have differences between the carrying value of our equity-method investments and the underlying equity in the net assets of the investees of $2.4 billion at December 31, 2015 and $3.7 billion at December 31, 2014. These differences primarily relate to our investments in Appalachian Midstream Investments, Delaware basin gas gathering system, 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 in the Consolidated Statement of Cash Flows 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, 2015 2014 2013 (Millions) UEOM (1) $ 357 $ 57 $ — Appalachia Midstream Investments 93 84 — Delaware basin gas gathering system 57 20 — Discovery 35 106 193 Caiman II — 175 192 Other 52 26 54 $ 594 $ 468 $ 439 ____________ (1) 2015 includes purchase of additional interest in UEOM. (See Note 2 – Acquisitions .) 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, 2015 2014 2013 (Millions) Appalachia Midstream Investments $ 219 $ 130 $ — Discovery 116 36 12 Gulfstream 88 81 81 OPPL 45 27 27 UEOM 42 — — Caiman II 33 13 — Delaware basin gas gathering system 33 — — Laurel Mountain 31 39 — Other 26 39 34 $ 633 $ 365 $ 154 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 to Gulfstream for our proportional share of amounts necessary to fund debt maturities of $500 million due on November 1, 2015. We also expect to contribute our proportional share of amounts necessary to fund debt maturities of $300 million due on June 1, 2016, as reflected by the accrued liability of $149 million in Other accrued liabilities in the Consolidated Balance Sheet at December 31, 2015. Summarized Financial Position and Results of Operations of All Equity-Method Investments December 31, 2015 2014 (Millions) Assets (liabilities): Current assets $ 773 $ 599 Noncurrent assets 9,549 9,135 Current liabilities (633 ) (850 ) Noncurrent liabilities (1,450 ) (954 ) Years Ended December 31, 2015 2014 2013 (Millions) Gross revenue $ 1,707 $ 1,623 $ 1,333 Operating income 690 534 367 Net income 611 460 291 |
Other Income and Expenses
Other Income and Expenses | 12 Months Ended |
Dec. 31, 2015 | |
Other Income and Expenses [Abstract] | |
Other Income and Expense [Text Block] | Note 7 – Other Income and Expenses The following table presents certain gains or losses reflected in Other (income) expense – net within Costs and expenses in our Consolidated Statement of Comprehensive Income (Loss) : Years Ended December 31, 2015 2014 2013 (Millions) Access Midstream Impairment of certain assets (See Note 16) $ 14 $ 12 $ — Loss related to sale of certain assets — 10 — Northeast G&P Impairment of certain assets (See Note 16) 29 30 — Contingency gain settlement (1) — (154 ) — Net gain related to partial acreage dedication release — (12 ) — Loss associated with a producer claim — — 25 Atlantic-Gulf Amortization of regulatory assets associated with asset retirement obligations 33 33 30 Impairment of certain assets 5 10 — Write-off of the Eminence abandonment regulatory asset not recoverable through rates — (3 ) 12 Insurance recoveries associated with the Eminence abandonment — — (16 ) West Impairment of certain assets (See Note 16) 97 — — __________ (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. Geismar Incident On June 13, 2013, an explosion and fire occurred at our Geismar olefins plant. The incident rendered the facility temporarily inoperable (Geismar Incident). In 2015, 2014, and 2013, we received $126 million , $246 million , and $50 million , respectively, of insurance recoveries related to the Geismar Incident. These amounts are reported within the NGL & Petchem Services segment and reflected as gains in Net insurance recoveries – Geismar Incident in our Consolidated Statement of Comprehensive Income (Loss) . Also, in 2014 and 2013, we incurred $14 million and $10 million , respectively, of covered insurable expenses in excess of our retentions (deductibles) also included in Net insurance recoveries – Geismar Incident and we expensed $13 million within the NGL & Petchem Services segment during 2013 of costs under our insurance deductibles reported in Operating and maintenance expenses in the Consolidated Statement of Comprehensive Income (Loss) . ACMP Acquisition & Merger Certain ACMP Acquisition and ACMP Merger costs included in Selling, general, and administrative expenses , Operating and maintenance expenses , and Interest incurred 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 ACMP Acquisition costs) primarily related to professional advisory fees associated with the ACMP Acquisition and ACMP Merger within the Access Midstream segment. • Selling, general, and administrative expenses includes $9 million in 2015 and $15 million in 2014 of related employee transition costs from the ACMP Merger within the Access Midstream segment. • Operating and maintenance expenses includes $12 million in 2015 and $15 million in 2014 of transition costs from the ACMP Merger within the Access Midstream segment. • Interest incurred includes transaction-related financing costs of $2 million in 2015 from the ACMP Merger and $9 million in 2014 from the ACMP Acquisition. Additional Items Certain items included in Service revenues , Product costs , and Other income (expense) – net below Operating income in the Consolidated Statement of Comprehensive Income (Loss) are as follows: • Service revenues includes $239 million recognized in the fourth quarter of 2015 and $167 million recognized in the fourth quarter of 2014 from minimum volume commitment fees within the Access Midstream segment. • Product costs includes $6 million in 2015 and $27 million in 2014 of inventory adjustments within the NGL & Petchem Services segment. • Other income (expense) – net below Operating income includes $76 million , $33 million , and $19 million for equity AFUDC for 2015, 2014, and 2013, respectively within the Atlantic-Gulf segment. Equity AFUDC increased during 2015 due to the increase in spending on various Transco expansion projects and Constitution. • Other income (expense) – net below Operating income 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, 2015 | |
Income Tax Disclosure [Abstract] | |
Income Tax Disclosure [Text Block] | Note 8 – Provision (Benefit) for Income Taxes The Provision (benefit) for income taxes includes: Years Ended December 31, 2015 2014 2013 (Millions) Current: State $ (3 ) $ 3 $ 2 Foreign — 1 (22 ) (3 ) 4 (20 ) Deferred: State (3 ) 8 15 Foreign 7 17 35 4 25 50 Provision (benefit) for income taxes $ 1 $ 29 $ 30 Reconciliations from the Provision (benefit) at statutory rate to recorded Provision (benefit) for income taxes are as follows: Years Ended December 31, 2015 2014 2013 (Millions) Provision (benefit) at statutory rate $ (475 ) $ 459 $ 402 Increases (decreases) in taxes resulting from: Income not subject to U.S. federal tax 475 (459 ) (402 ) State income taxes (6 ) 11 17 Foreign operations — net 7 18 13 Provision (benefit) for income taxes $ 1 $ 29 $ 30 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. The 2013 state deferred provision includes $14 million related to the impact of a second-quarter 2013 Texas franchise tax law change. Income (loss) before income taxes includes $1 million , $72 million , and $61 million of foreign income in 2015 , 2014 , and 2013 , respectively. Deferred income tax liabilities, primarily attributable to the taxable temporary differences from property, plant, and equipment, were $119 million , $133 million , and $117 million in 2015 , 2014 , and 2013 , respectively. Cash refunds for income taxes (net of payments) were $4 million and $28 million in 2015 and 2014, respectively. Cash payments for income taxes (net of refunds) in 2013 were $2 million . As of December 31, 2015 , we have no material unrecognized tax benefits. Tax years after 2011 are subject to examination by the Texas Comptroller. Generally, tax returns for our Canadian entities are open to audit for tax years after 2010 . Williams has indemnified us for any adjustments to foreign tax returns filed prior to the Canada Acquisition. |
Benefit Plans
Benefit Plans | 12 Months Ended |
Dec. 31, 2015 | |
Employee Benefits and Share-based Compensation [Abstract] | |
Pension and Other Postretirement Benefits Disclosure [Text Block] | Note 9 – 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 2014 pension and other postretirement benefit costs included in the 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 and are included in the 2015 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 2015 , 2014 , and 2013 totaled $43 million , $28 million , and $44 million , respectively. At the total Williams plan level, the pension plans had a projected benefit obligation of $1.5 billion at December 31, 2015 and 2014 . The plans were underfunded by $223 million and $251 million at December 31, 2015 and 2014 , respectively. Postretirement benefits other than pensions Williams provides certain retiree health care and life insurance benefits for eligible participants. We recognized a net periodic postretirement benefit credited to us by Williams of $12 million , $14 million , and $4 million in 2015 , 2014 , and 2013 , respectively. At the total Williams plan level, the postretirement benefit plans had an accumulated postretirement benefit obligation of $202 million and $233 million at December 31, 2015 and 2014 , respectively. The plans were underfunded by $1 million and $25 million at December 31, 2015 and 2014 , 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 We were charged compensation expense of $27 million , $25 million , and $16 million in 2015 , 2014 , and 2013 , respectively, for contributions to these plans. The increase in expense in 2015 and 2014 is primarily due to the impact of the ACMP acquisition. (See Note 2 - Acquisitions.) |
Inventories
Inventories | 12 Months Ended |
Dec. 31, 2015 | |
Inventory Disclosure [Abstract] | |
Inventories [Text Block] | Note 10 – Inventories December 31, 2015 2014 (Millions) Natural gas liquids, olefins, and natural gas in underground storage $ 57 $ 150 Materials, supplies, and other 70 81 $ 127 $ 231 |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Dec. 31, 2015 | |
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) (%) 2015 2014 (Millions) Nonregulated: Natural gas gathering and processing facilities 5 - 40 $ 20,636 $ 18,717 Construction in progress Not applicable 740 2,115 Other 2 - 45 1,743 1,459 Regulated: Natural gas transmission facilities 1.2 - 6.97 12,189 10,867 Construction in progress Not applicable Not applicable 941 985 Other 5 - 45 1.35 - 33.33 1,584 1,336 Total property, plant, and equipment, at cost $ 37,833 $ 35,479 Accumulated depreciation and amortization (9,233 ) (8,157 ) Property, plant, and equipment – net $ 28,600 $ 27,322 ____________ (1) Estimated useful life and depreciation rates are presented as of December 31, 2015 . 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 $1,348 million , $944 million , and $729 million in 2015 , 2014 , and 2013 , respectively. Regulated Property, plant, and equipment – net includes approximately $706 million and $746 million at December 31, 2015 and 2014 , 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 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 $857 million and $791 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, 2015 and 2014 , respectively. December 31, 2015 2014 (Millions) Beginning balance $ 831 $ 561 Liabilities incurred 41 101 Liabilities settled (1) (3 ) (21 ) Accretion expense 60 44 Revisions (2) (15 ) 146 Ending balance $ 914 $ 831 ______________ (1) For 2014, liabilities settled include $7 million related to the abandonment of certain of Transco’s natural gas storage caverns that are associated with a leak in 2010. (2) Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, discount rates, and the estimated remaining useful life of the assets. 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 2014 revisions primarily reflect an increase in the estimated retirement costs for our offshore pipelines, an increase in the inflation rate, and decreases 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 16 – 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, 2015 | |
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 by reportable segment for the periods indicated are as follows: West Access Midstream Northeast G&P Total (Millions) December 31, 2014 $ 45 $ 429 $ 646 $ 1,120 Purchase accounting adjustment 2 23 — 25 Impairment — (452 ) (646 ) (1,098 ) December 31, 2015 $ 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, 2014 and 2013 . During 2015, we performed an interim assessment of certain goodwill within the West, Access Midstream, and Northeast G&P segments as of September 30, 2015, but the estimated fair value of the reporting units evaluated exceeded their carrying amounts and thus no impairment charge was recognized. We performed an additional goodwill impairment evaluation as of December 31, 2015 , of the goodwill recorded within the West, Access Midstream, and Northeast G&P segments. As a result of this evaluation, we recorded goodwill impairment charges totaling $1.098 billion . (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk .) Other Intangible Assets The gross carrying amount and accumulated amortization of Other intangible assets – net of accumulated amortization at December 31 are as follows: 2015 2014 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization (Millions) Contractual customer relationships $ 10,632 $ (663 ) $ 10,761 $ (310 ) Other intangible assets – net of accumulated amortization 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 the 2012 acquisitions from Delphi Midstream Partners, LLC (Laser) and Caiman Energy, LLC (Caiman). The decrease in the gross carrying amount of Other intangible assets – net of accumulated amortization during 2015 is primarily related to the $168 million decrease from the purchase price allocation adjustment recorded for the ACMP acquisition in the first quarter of 2015, partially offset by the $32 million increase due to the Eagle Ford acquisition in the second quarter of 2015 (See Note 2 – Acquisitions ). The 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, Eagle Ford, Laser, and Caiman acquisitions were approximately 17 years , 10 years , 9 years , and 18 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 – net of accumulated amortization was $353 million , $207 million , and $60 million in 2015 , 2014 , and 2013 , respectively. The estimated amortization expense for each of the next five succeeding fiscal years is approximately $354 million. |
Debt, Banking Arrangements, and
Debt, Banking Arrangements, and Leases | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |
Debt Disclosure [Text Block] | Note 13 – Debt, Banking Arrangements, and Leases Long-Term Debt December 31, 2015 2014 (Millions) Unsecured: Transco: 6.4% Notes due 2016 (2) $ 200 $ 200 6.05% Notes due 2018 250 250 7.08% Debentures due 2026 8 8 7.25% Debentures due 2026 200 200 5.4% Notes due 2041 375 375 4.45% Notes due 2042 400 400 Northwest Pipeline: 7% Notes due 2016 175 175 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.: 3.8% Notes due 2015 (1) — 750 7.25% Notes due 2017 600 600 5.25% Notes due 2020 1,500 1,500 4.125% Notes due 2020 600 600 5.875% Notes due 2021 — 750 4% Notes due 2021 500 500 3.6% Notes due 2022 1,250 — 3.35% Notes due 2022 750 750 6.125% Notes due 2022 750 750 4.875% Notes due 2023 1,400 1,400 4.5% Notes due 2023 600 600 4.3% Notes due 2024 1,000 1,000 4.875% Notes due 2024 750 750 3.9% Notes due 2025 750 750 4.0% Notes due 2025 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 — Term Loan, variable interest rate, due 2018 850 — Credit facility loans 1,310 640 Capital lease obligations 1 5 Debt issuance costs (91 ) (74 ) Net unamortized debt premium (discount) 129 207 Long-term debt, including current portion 19,177 16,256 Long-term debt due within one year (176 ) (4 ) Long-term debt $ 19,001 $ 16,252 ______________________________________________________ (1) Presented as long-term debt at December 31, 2014, due to our intent and ability to refinance. (2) 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) 2016 $ 175 2017 785 2018 1,350 2019 — 2020 2,100 Provisions concerning ACMP long-term debt Certain long-term debt originally issued by ACMP totaling $2.9 billion has provisions that would require us to make an offer to repurchase such notes at 101 percent of the principle amount should our credit be downgraded by either Moody’s Investor Service or Standard and Poor’s within a period of ninety days following the completion of the proposed ETC Merger. Issuances and retirements On January 22, 2016, Transco, issued $1 billion of 7.85 percent senior unsecured notes due 2026 to investors in a private debt placement. Transco intends to use 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, 2015 the interest rate was 1.85 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. On June 27, 2014, Pre-merger WPZ completed a public offering of $750 million of 3.9 percent senior unsecured notes due 2025 and $500 million of 4.9 percent senior unsecured notes due 2045. Pre-merger WPZ used the net proceeds to repay amounts outstanding under its commercial paper program, to fund capital expenditures, and for general partnership purposes. On March 4, 2014, Pre-merger WPZ completed a public offering of $1 billion of 4.3 percent senior unsecured notes due 2024 and $500 million of 5.4 percent senior unsecured notes due 2044. Pre-merger WPZ used the net proceeds to repay amounts outstanding under its commercial paper program, to fund capital expenditures, and for general partnership purposes. Credit Facilities December 31, 2015 Available Outstanding (Millions) Long-term credit facility (1) $ 3,500 $ 1,310 Letters of credit under certain bilateral bank agreements 2 Short-term credit facility 150 — __________ (1) In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. 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, 2015. As of February 25, 2016, $925 million is outstanding under our long-term credit facility. Short-Term Credit Facility On February 3, 2015, we entered into a short-term $1.5 billion credit facility and terminated it on March 3, 2015. On August 26, 2015, we entered into a credit agreement providing for a $1.0 billion short-term credit facility with a maturity date of August 24, 2016. On December 23, 2015, the capacity of this facility decreased to $150 million in conjunction with entering into the $850 million term loan. The agreement governing this credit facility contains the following terms and conditions: • This facility becomes available when the aggregate amount of outstanding loans under our long-term credit facility plus outstanding commercial paper borrowings reach a total of $3.5 billion . • Various covenants that limit, among other things, a borrower’s and its respective material subsidiaries’ ability to grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets in certain circumstances, 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 and accelerate the maturity of the loans and exercise other rights and remedies. • Each time funds are borrowed under the credit facility, the borrower may choose from two methods of calculating interest: a fluctuating base rate equal to an alternate base rate plus an applicable margin, or a periodic fixed rate equal to LIBOR 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 by reference to a pricing schedule based on the borrower’s senior unsecured long-term debt ratings. The significant financial covenant requires the ratio of debt to EBITDA, each as defined in the credit agreement, as of the last day of any fiscal quarter to be no greater than 6.0 to 1.0. We are in compliance with these financial covenants as measured at December 31, 2015. 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, 2015 and December 31, 2014 , have maturity dates less than three months from the date of issuance. At December 31, 2015 , $499 million of Commercial paper is outstanding at a weighted average interest rate of 0.92 percent . At December 31, 2014 , $798 million of Commercial paper is 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 $795 million in 2015, $499 million in 2014, and $366 million in 2013. Leases-Lessee The future minimum annual rentals under noncancelable operating leases, are payable as follows: December 31, (Millions) 2016 $ 77 2017 63 2018 46 2019 36 2020 32 Thereafter 99 Total $ 353 Total rent expense was $157 million in 2015, $101 million in 2014, and $51 million in 2013 and primarily included in Operating and maintenance expenses and Selling, general, and administrative expenses in the Consolidated Statement of Comprehensive Income (Loss) . Accounting Standards Issued and Adopted In April 2015, the FASB issued ASU 2015-03 “Interest - Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03). ASU 2015-03 simplifies the presentation of debt issuance costs by requiring such costs be presented as a deduction from the corresponding debt liability. Subsequently, in August 2015, the FASB issued ASU 2015-15 “Interest-Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements-Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting” (ASU 2015-15). In ASU 2015-15 the FASB stated that the guidance in ASU 2015-03 did not address the presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements, and entities are permitted to defer and present debt issuance costs related to line-of-credit arrangements as assets. The standards are effective for financial statements issued for interim and annual reporting periods beginning after December 15, 2015, and require retrospective presentation. Early adoption is permitted. We elected to early adopt these standards for the periods presented. Accordingly, $91 million and $74 million of debt issuance costs as of December 31, 2015 and 2014, respectively, are now reflected as a direct reduction of Long-term debt in our Consolidated Balance Sheet . Debt issuance costs related to our credit facilities are presented in Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet . |
Partners' Capital
Partners' Capital | 12 Months Ended |
Dec. 31, 2015 | |
Partners' Capital Notes [Abstract] | |
Unit Transactions Disclosure [Text Block] | Note 14 – Partners’ Capital 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 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 .) Transactions which occurred prior to the ACMP Merger during 2014 and 2013 are summarized below: 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. In August 2013, Pre-merger WPZ completed an equity issuance of 21,500,000 Pre-merger WPZ common units. Subsequently, the underwriters exercised their option to purchase an additional 3,225,000 Pre-merger WPZ common units. The net proceeds of approximately $1.2 billion were used to repay amounts outstanding under Pre-merger WPZ’s commercial paper program, to fund capital expenditures and for general partnership purposes. In March 2013, Pre-merger WPZ completed an equity issuance of 14,250,000 Pre-merger WPZ common units, including 3,000,000 Pre-merger WPZ common units sold to Williams in a private placement. Subsequently, the underwriters exercised their option to purchase an additional 1,687,500 Pre-merger WPZ common units. The net proceeds of approximately $760 million were used to repay amounts outstanding under Pre-merger WPZ’s credit facility. 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 Our general partner is 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 The table above assumes that the Partnership’s general partner maintains its 2 percent general partner interest, that there are no arrearages on common units, and that the general partner continues to own the IDRs. The maximum distribution sharing percentage of 50 percent includes distributions paid to the general partner on its 2 percent general partner interest and does not include any distributions that the general partner may receive on limited partner units that it owns or may acquire. 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, 2015 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Equity-Based Compensation [Text Block] | Note 15 – 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, 2015 , 2014 , and 2013 of $19 million , $14 million and $12 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 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 $26 million and $11 million for the years ended December 31, 2015 and 2014 , respectively. As of December 31, 2015 , there was $32 million of unrecognized compensation expense attributable to the outstanding awards, which does not include the effect of estimated forfeitures of $4 million . These amounts are expected to be recognized over a weighted average period of 1.8 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, 2015 : Restricted Common Units Outstanding Units Weighted- Average Fair Value (Millions) Nonvested at December 31, 2014 1.3 $ 59.35 Adjustment for unit split in ACMP Merger 0.1 $ — Forfeited (0.1 ) $ 58.05 Vested (0.1 ) $ 59.28 Nonvested at December 31, 2015 1.2 $ 55.93 |
Fair Value Measurements, Guaran
Fair Value Measurements, Guarantees, and Concentration of Credit Risk | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements Guarantees and Concentration of Credit Risk [Text Block] | Note 16 – 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, 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: Notes receivable and other 12 12 10 2 — Long-term debt, including current portion (1) (19,176 ) (15,988 ) — (15,988 ) — Assets (liabilities) at December 31, 2014: Measured on a recurring basis: ARO Trust investments $ 48 $ 48 $ 48 $ — $ — Energy derivatives assets not designated as hedging instruments 3 3 1 — 2 Energy derivatives liabilities not designated as hedging instruments (2 ) (2 ) — — (2 ) Additional disclosures: Notes receivable and other 5 4 — 4 — Long-term debt, including current portion (1) (16,251 ) (16,607 ) — (16,607 ) — ________________ (1) Excludes capital leases. The carrying value has been reduced by $91 million and $74 million of debt acquisition costs at December 31, 2015 and 2014, respectively. (See Note 13 – Debt, Banking Arrangements, and 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 (OTC) contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Energy derivatives assets are reported in Other current assets and Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet . Energy derivatives liabilities are reported in Other accrued liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet . Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the years ended December 31, 2015 or 2014 . Additional fair value disclosures Notes receivable and other : The disclosed fair value of our notes receivable is primarily determined by an income approach which considers the underlying contract amounts and our assessment of our ability to recover these amounts. The current portion is reported in Accounts and notes receivable and Other current assets and the noncurrent portion is reported in Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet . 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. Assets measured at fair value on a nonrecurring basis We performed an interim assessment of the goodwill associated with our Central Region and Northeast Region reporting units within the Access Midstream segment as of September 30, 2015, and 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, 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 noncash charge of $1,098 million . For the West G&P reporting unit, the estimated fair value exceeded the carrying value and no impairment was recorded. Impairments Years Ended December 31, Date of Measurement Fair Value 2015 2014 (Millions) Impairment of certain assets (1) June 30, 2014 $ 46 $ 17 Impairment of certain assets (1) December 31, 2014 32 13 Impairment of certain assets (1) June 30, 2015 17 $ 20 Impairment of certain assets (2) December 31, 2014 1 12 Impairment of certain assets (3) December 31, 2015 13 94 Level 3 fair value measurements of certain assets 114 42 Other impairments (4) 31 10 Total impairments of certain assets $ 145 $ 52 ______________ (1) Reflects impairment charges for our Northeast G&P segment associated with certain surplus equipment. Certain of these assets were previously presented as held for sale, but are now considered held for use and reported in Property, plant, and equipment – net in the Consolidated Balance Sheet at December 31, 2015. The estimated fair value was determined by a market approach based on our analysis of observable inputs in the principal market. These impairment charges are recorded in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Comprehensive Income (Loss) . (2) Reflects impairment charges for our Access Midstream segment associated with certain surplus equipment considered held for sale and reported in Other current assets in the Consolidated Balance Sheet. The estimated fair value was determined by a market approach based on our analysis of observable inputs in the principal market. These impairment charges are recorded in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Comprehensive Income (Loss) . (3) Reflects an impairment charge within our West segment associated with previously capitalized project development costs for a gas processing plant, the completion of which is now considered remote due to unfavorable impact of low natural gas prices on customer drilling activities. These impairment charges are recorded in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Comprehensive Income (Loss) . 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 and is reported in Property, plant, and equipment – net in the Consolidated Balance Sheet. (4) Reflects multiple individually insignificant impairments of other certain assets that may no longer be in use or are surplus in nature for which the fair value was determined to be zero or an insignificant salvage value. These impairment charges are recorded in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Comprehensive Income (Loss) . Date of Measurement Fair Value Impairments (Millions) Impairments of equity-method investments (1) September 30, 2015 $ 1,203 $ 461 Impairments of equity-method investments (2) December 31, 2015 4,017 890 Other impairment of equity-method investment December 31, 2015 58 8 Level 3 fair value measurements of equity-method investments $ 1,359 ______________ (1) Reflects other-than-temporary impairment charges related to Access Midstream’s equity-method investments in the Delaware basin gas gathering system and certain of the Appalachia Midstream Investments reflected within Impairment of equity-method investments in the Consolidated Statement of Comprehensive Income (Loss) . 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 ACMP Acquisition. 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 the Delaware basin gas gathering system 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. (2) Reflects other-than-temporary impairment charges related to Access Midstream’s equity-method investments in the Delaware basin gas gathering system, certain of the Appalachia Midstream Investments, and UEOM, as well as an impairment of Northeast G&P’s Laurel Mountain investment, all reflected within Impairment of equity-method investments in the Consolidated Statement of Comprehensive Income (Loss) . 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 increases in our cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses. During the first quarter of 2016, we have observed further significant decline in the market value of our publicly traded equity. Continuation of this condition and/or further decline in such value will likely require the evaluation of certain of our equity investments for potential impairment at March 31, 2016, including those that were impaired at December 31, 2015. As a result, there is the potential for significant additional noncash impairments of our investments in the future. 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. Accounts and notes receivable The following table summarizes concentration of receivables , net of allowances. December 31, 2015 2014 (Millions) NGLs, natural gas, and related products and services $ 821 $ 728 Transportation of natural gas and related products 202 175 Other 3 2 Total $ 1,026 $ 905 Customers include producers, distribution companies, industrial users, gas marketers and pipelines primarily located in the continental United States and Canada. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. As of December 31, 2015 and 2014, Chesapeake Energy Corporation, and its affiliates, a customer primarily within our Access Midstream segment, accounted for $364 million and $308 million , respectively, of the consolidated Accounts and notes receivable balance. Of this receivable at December 31, 2015, $198 million relates to annual minimum volume commitment fees that were subsequently collected in February 2016. Revenues In 2015 and 2014, Chesapeake Energy Corporation, and its affiliates, a customer primarily within our Access Midstream segment, accounted for 18 percent and 9 percent , respectively, of our consolidated revenues. |
Contingent Liabilities and Comm
Contingent Liabilities and Commitments | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Contingent Liabilities [Text Block] | Note 17 – 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, 2015 , we have accrued liabilities totaling $15 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 emission limits, and new air quality standards impacting 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, 2015 , we have accrued liabilities of $8 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, 2015 , we have accrued liabilities totaling $7 million for these costs. Geismar Incident As a result of the previously discussed Geismar Incident, there were two fatalities and numerous individuals (including employees and contractors) reported injuries, which varied from minor to serious. We are addressing the following matters in connection with the Geismar Incident. On October 21, 2013, the EPA issued an Inspection Report pursuant to the Clean Air Act’s Risk Management Program following its inspection of the facility on June 24 through June 28, 2013. The report notes the EPA’s preliminary determinations about the facility’s documentation regarding process safety, process hazard analysis, as well as operating procedures, employee training, and other matters. On June 16, 2014, we received a request for information related to the Geismar Incident from the EPA under Section 114 of the Clean Air Act to which we responded on August 13, 2014. The EPA could issue penalties pertaining to final determinations. Multiple lawsuits, including class actions for alleged offsite impacts, property damage, customer claims, and personal injury, have been filed against us. To date, we have settled certain of the personal injury claims for an aggregate immaterial amount that we have recovered from our insurers. The trial for certain plaintiffs claiming personal injury, that was set to begin on June 15, 2015, in Iberville Parish, Louisiana, has been postponed to September 6, 2016. 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. Due to the preliminary status of the cases, we are unable to estimate a range of liability at this time. Stockholder Litigation In July 2015, a purported stockholder of Williams filed a putative class and derivative action on behalf of Williams in the Court of Chancery of the State of Delaware. The action names as defendants certain members of Williams’ Board of Directors (Individual Defendants), as well as us, and names Williams as a nominal defendant. On December 4, 2015, the plaintiff filed an amended complaint for such action, and we are no longer a party to such lawsuit. 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 $617 million at December 31, 2015 . |
Segment Disclosures
Segment Disclosures | 12 Months Ended |
Dec. 31, 2015 | |
Segment Reporting [Abstract] | |
Segment Disclosures [Text Block] | Note 18 – Segment Disclosures Our reportable segments are Access Midstream, 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 Prior to the first quarter of 2015, we evaluated segment operating performance based upon Segment profit (loss) from operations. Beginning in the first quarter of 2015, 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. Prior period segment disclosures have been recast to reflect this change. 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: 2015 $ 7,228 $ 103 $ 7,331 2014 7,212 197 7,409 2013 6,685 150 6,835 Long-lived assets: 2015 $ 37,586 $ 1,030 $ 38,616 2014 37,798 1,095 38,893 2013 18,776 1,137 19,913 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 . Access Midstream Northeast G&P Atlantic- Gulf West NGL & Petchem Services Eliminations Total (Millions) 2015 Segment revenues: Service revenues External $ 1,523 $ 541 $ 1,877 $ 1,055 $ 139 $ — $ 5,135 Internal — 7 4 — — (11 ) — Total service revenues 1,523 548 1,881 1,055 139 (11 ) 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 $ 1,523 $ 675 $ 2,344 $ 1,312 $ 2,060 $ (583 ) $ 7,331 Other financial information: Proportional Modified EBITDA of equity-method investments $ 338 $ 62 $ 257 $ — $ 42 $ 699 2014 Segment revenues: Service revenues External $ 765 $ 450 $ 1,497 $ 1,050 $ 126 $ — $ 3,888 Internal — 1 4 — — (5 ) — Total service revenues 765 451 1,501 1,050 126 (5 ) 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 $ 765 $ 681 $ 2,354 $ 1,596 $ 3,112 $ (1,099 ) $ 7,409 Other financial information: Proportional Modified EBITDA of equity-method investments $ 178 $ 52 $ 151 $ — $ 50 $ 431 2013 Segment revenues: Service revenues External $ — $ 335 $ 1,414 $ 1,053 $ 112 $ — $ 2,914 Internal — — 10 1 — (11 ) — Total service revenues — 335 1,424 1,054 112 (11 ) 2,914 Product sales External — 166 830 64 2,861 — 3,921 Internal — — 95 708 294 (1,097 ) — Total product sales — 166 925 772 3,155 (1,097 ) 3,921 Total revenues $ — $ 501 $ 2,349 $ 1,826 $ 3,267 $ (1,108 ) $ 6,835 Other financial information: Proportional Modified EBITDA of equity-method investments $ — $ 15 $ 144 $ — $ 50 $ 209 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, 2015 2014 2013 (Millions) Modified EBITDA by segment: Access Midstream $ 1,279 $ 642 $ — Northeast G&P 314 395 114 Atlantic-Gulf 1,523 1,065 1,013 West 557 823 924 NGL & Petchem Services 321 324 395 Other 9 (5 ) 1 4,003 3,244 2,447 Accretion expense associated with asset retirement obligations for nonregulated operations (28 ) (17 ) (14 ) Depreciation and amortization expenses (1,702 ) (1,151 ) (791 ) Impairment of goodwill (1,098 ) — — Equity earnings (losses) 335 228 104 Impairment of equity-method investments (1,359 ) — — Other investing income (loss) – net 2 2 (1 ) Proportional Modified EBITDA of equity-method investments (699 ) (431 ) (209 ) Interest expense (811 ) (562 ) (387 ) (Provision) benefit for income taxes (1 ) (29 ) (30 ) Net income (loss) $ (1,358 ) $ 1,284 $ 1,119 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, 2015 2014 2015 2014 2015 2014 2013 (Millions) Access Midstream (1) $ 21,050 $ 22,470 $ 5,039 $ 6,004 $ 556 $ 16,964 $ — Northeast G&P 6,669 7,314 834 891 367 1,079 1,376 Atlantic-Gulf 12,171 11,114 959 985 1,573 1,593 1,072 West 5,035 5,174 — — 225 168 210 NGL & Petchem Services 3,306 3,510 504 519 236 601 746 Other corporate assets 350 501 — — 3 8 5 Eliminations (2) (711 ) (835 ) — — — — — Total $ 47,870 $ 49,248 $ 7,336 $ 8,399 $ 2,960 $ 20,413 $ 3,409 (1) 2014 Additions to long-lived assets within our Access Midstream segment primarily 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 Busin25
General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 and 2014 are as follows: December 31, 2015 2014 (Millions) Current assets reported within Other current assets $ 84 $ 81 Noncurrent assets reported within Regulatory assets, deferred charges, and other 305 289 Total regulated assets $ 389 $ 370 Current liabilities reported within Other accrued liabilities $ 4 $ 11 Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other 409 349 Total regulated liabilities $ 413 $ 360 |
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] | Inventory valuation All Inventories in the Consolidated Balance Sheet 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 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 the 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 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. |
Other intangible assets [Policy Text Block] | Other intangible assets Our identifiable intangible assets 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. |
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 13 – 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 physical 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 ; 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 16 – 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 a 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 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. 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 business has processing and fractionation operations where we retain certain NGLs and olefins from an upgrader’s offgas stream and we recognize revenues when the fractionated products are 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 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 15 – 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 9 – 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. 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 are computed using the liability method and are 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 unitholders and our general partner. 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 foreign subsidiaries use the Canadian dollar as their functional currency. Assets and liabilities of such foreign subsidiaries are translated at the spot rate in effect at the applicable reporting date, and the combined statements of comprehensive income (loss) are translated into the U.S. dollar at the average exchange rates in effect during the applicable period. The resulting cumulative translation adjustment is recorded as a separate component of AOCI in the Consolidated Balance Sheet . Transactions denominated in currencies other than the functional currency are recorded based on exchange rates at the time such transactions arise. Subsequent changes in exchange rates when the transactions are settled result in transaction gains and losses which are reflected in Other (income) expense – net in the Consolidated Statement of Comprehensive Income (Loss) . Accumulated other comprehensive income (loss) AOCI is substantially comprised of foreign currency translation adjustments. These adjustments did not impact Net income (loss) in any of the periods presented. |
General, Description of Busin26
General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 and 2014 are as follows: December 31, 2015 2014 (Millions) Current assets reported within Other current assets $ 84 $ 81 Noncurrent assets reported within Regulatory assets, deferred charges, and other 305 289 Total regulated assets $ 389 $ 370 Current liabilities reported within Other accrued liabilities $ 4 $ 11 Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other 409 349 Total regulated liabilities $ 413 $ 360 |
Acquisitions (Tables)
Acquisitions (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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, substantially all of which are presented in the Access Midstream segment, 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 Revenues and Net income attributable to controlling interests for the years ended December 31, 2014 and 2013, are presented as if the ACMP Acquisition had been completed on January 1, 2013. 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 periods indicated, nor do they purport to project Revenues or Net income 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 2013 (Millions) Revenues $ 7,953 $ 7,881 Net income attributable to controlling interests $ 1,376 $ 1,172 |
Variable Interest Entities (Tab
Variable Interest Entities (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 2014 Classification (Millions) Assets (liabilities): Cash and cash equivalents $ 70 $ 113 Cash and cash equivalents Accounts receivable 71 52 Accounts and notes receivable – net Other current assets 2 3 Other current assets Property, plant, and equipment – net 3,000 2,794 Property, plant, and equipment – net Goodwill 47 103 Goodwill Other intangible assets – net 1,436 1,493 Other intangible assets – net of accumulated amortization Other noncurrent assets — 14 Regulatory assets, deferred charges, and other Accounts payable (59 ) (48 ) Accounts payable – trade Accrued liabilities (14 ) (36 ) Other accrued liabilities Current deferred revenue (62 ) (45 ) Other accrued liabilities Noncurrent deferred income taxes — (13 ) Deferred income tax liabilities Asset retirement obligation (93 ) (94 ) Asset retirement obligations, noncurrent Noncurrent deferred revenue associated with customer advance payments (331 ) (395 ) Regulatory liabilities, deferred income, and other |
Allocation of Net Income (Los29
Allocation of Net Income (Loss) and Distributions (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 2014 2013 (Millions) Allocation of net income to general partner: Net income (loss) $ (1,358 ) $ 1,284 $ 1,119 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 ) (49 ) Net income applicable to noncontrolling interests (91 ) (96 ) (3 ) Costs charged directly to the general partner 21 1 1 Income (loss) subject to 2% allocation of general partner interest (1,430 ) 1,079 1,068 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 (29 ) 22 21 Priority allocations, including incentive distributions, paid to general partner 638 641 387 Pre-merger net income allocated to general partner interest 2 95 — Pre-partnership net income allocated to general partner interest — 15 49 Costs charged directly to the general partner (21 ) (1 ) (1 ) Net income allocated to general partner’s equity $ 590 $ 772 $ 456 Net income (loss) $ (1,358 ) $ 1,284 $ 1,119 Net income allocated to general partner’s equity 590 772 456 Net income (loss) allocated to Class B limited partners’ equity (52 ) — — Net income allocated to Class D limited partners’ equity (1) 69 62 — Net income allocated to noncontrolling interests 91 96 3 Net income (loss) allocated to common limited partners’ equity $ (2,056 ) $ 354 $ 660 Adjustments to reconcile Net income (loss) allocated to common limited partners' equity to Allocation of net income (loss) to common units: Incentive distributions paid 633 640 383 Incentive distributions declared (2) (3) (423 ) (626 ) (432 ) Impact of unit issuance timing and other (9 ) (9 ) — Allocation of net income (loss) to common units $ (1,855 ) $ 359 $ 611 ____________ (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) On February 12, 2016, 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 5, 2016. (3) The 2015 amount reflects the waiver of IDRs associated with the Termination Agreement. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies .) The 2014 amount reflects only the portion of the total incentive distribution associated with the Pre-merger WPZ common units exchanged in the ACMP Merger. |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 2014 2013 (Millions) Product costs $ 169 $ 186 $ 147 Operating and maintenance expenses - employee costs 498 413 339 Selling, general, and administrative expenses: Employee direct costs 368 331 270 Employee allocated costs 195 171 169 |
Investing Activities (Tables)
Investing Activities (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Investments [Abstract] | |
Investments [Table Text Block] | Note 6 – Investing Activities Impairment of equity-method investments in the Consolidated Statement of Comprehensive Income (Loss) During the third quarter of 2015, we recognized other-than-temporary impairment charges of $458 million and $3 million related to our equity-method investments in the Delaware basin gas gathering system and certain of the Appalachia Midstream Investments, respectively. During the fourth quarter of 2015, we recognized additional impairment charges for these investments of $45 million and $559 million , respectively, as well as impairment charges of $241 million and $45 million associated with our equity-method investments in UEOM and Laurel Mountain, respectively. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk .) Equity earnings (losses) in the Consolidated Statement of Comprehensive Income (Loss) 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 Access Midstream segment. Investments in the Consolidated Balance Sheet December 31, 2015 2014 (Millions) Appalachia Midstream Investments (1) $ 2,464 $ 3,033 UEOM – 62% (2) 1,525 1,411 Delaware basin gas gathering system – 50% 977 1,478 Discovery – 60% 602 602 OPPL – 50% 445 453 Caiman II – 58% 418 432 Laurel Mountain – 69% 391 459 Gulfstream – 50% 293 317 Other 221 214 $ 7,336 $ 8,399 ____________ (1) Includes equity-method investments in multiple gathering systems in the Marcellus Shale with an approximate average 45 percent interest. (2) We acquired an approximate 13 percent additional interest in UEOM in 2015. (See Note 2 – Acquisitions .) |
Contributions [Table Text Block] | Purchases of and contributions to equity-method investments in the Consolidated Statement of Cash Flows 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, 2015 2014 2013 (Millions) UEOM (1) $ 357 $ 57 $ — Appalachia Midstream Investments 93 84 — Delaware basin gas gathering system 57 20 — Discovery 35 106 193 Caiman II — 175 192 Other 52 26 54 $ 594 $ 468 $ 439 ____________ (1) 2015 includes purchase of additional interest in UEOM. (See Note 2 – Acquisitions .) |
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, 2015 2014 2013 (Millions) Appalachia Midstream Investments $ 219 $ 130 $ — Discovery 116 36 12 Gulfstream 88 81 81 OPPL 45 27 27 UEOM 42 — — Caiman II 33 13 — Delaware basin gas gathering system 33 — — Laurel Mountain 31 39 — Other 26 39 34 $ 633 $ 365 $ 154 |
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, 2015 2014 (Millions) Assets (liabilities): Current assets $ 773 $ 599 Noncurrent assets 9,549 9,135 Current liabilities (633 ) (850 ) Noncurrent liabilities (1,450 ) (954 ) Years Ended December 31, 2015 2014 2013 (Millions) Gross revenue $ 1,707 $ 1,623 $ 1,333 Operating income 690 534 367 Net income 611 460 291 |
Other Income and Expenses (Tabl
Other Income and Expenses (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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 our Consolidated Statement of Comprehensive Income (Loss) : Years Ended December 31, 2015 2014 2013 (Millions) Access Midstream Impairment of certain assets (See Note 16) $ 14 $ 12 $ — Loss related to sale of certain assets — 10 — Northeast G&P Impairment of certain assets (See Note 16) 29 30 — Contingency gain settlement (1) — (154 ) — Net gain related to partial acreage dedication release — (12 ) — Loss associated with a producer claim — — 25 Atlantic-Gulf Amortization of regulatory assets associated with asset retirement obligations 33 33 30 Impairment of certain assets 5 10 — Write-off of the Eminence abandonment regulatory asset not recoverable through rates — (3 ) 12 Insurance recoveries associated with the Eminence abandonment — — (16 ) West Impairment of certain assets (See Note 16) 97 — — __________ (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. |
Provision (Benefit) for Incom33
Provision (Benefit) for Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 2014 2013 (Millions) Current: State $ (3 ) $ 3 $ 2 Foreign — 1 (22 ) (3 ) 4 (20 ) Deferred: State (3 ) 8 15 Foreign 7 17 35 4 25 50 Provision (benefit) for income taxes $ 1 $ 29 $ 30 |
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, 2015 2014 2013 (Millions) Provision (benefit) at statutory rate $ (475 ) $ 459 $ 402 Increases (decreases) in taxes resulting from: Income not subject to U.S. federal tax 475 (459 ) (402 ) State income taxes (6 ) 11 17 Foreign operations — net 7 18 13 Provision (benefit) for income taxes $ 1 $ 29 $ 30 |
Inventories (Tables)
Inventories (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Inventory Disclosure [Abstract] | |
Inventories [Table Text Block] | December 31, 2015 2014 (Millions) Natural gas liquids, olefins, and natural gas in underground storage $ 57 $ 150 Materials, supplies, and other 70 81 $ 127 $ 231 |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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) (%) 2015 2014 (Millions) Nonregulated: Natural gas gathering and processing facilities 5 - 40 $ 20,636 $ 18,717 Construction in progress Not applicable 740 2,115 Other 2 - 45 1,743 1,459 Regulated: Natural gas transmission facilities 1.2 - 6.97 12,189 10,867 Construction in progress Not applicable Not applicable 941 985 Other 5 - 45 1.35 - 33.33 1,584 1,336 Total property, plant, and equipment, at cost $ 37,833 $ 35,479 Accumulated depreciation and amortization (9,233 ) (8,157 ) Property, plant, and equipment – net $ 28,600 $ 27,322 ____________ (1) Estimated useful life and depreciation rates are presented as of December 31, 2015 . 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 $857 million and $791 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, 2015 and 2014 , respectively. December 31, 2015 2014 (Millions) Beginning balance $ 831 $ 561 Liabilities incurred 41 101 Liabilities settled (1) (3 ) (21 ) Accretion expense 60 44 Revisions (2) (15 ) 146 Ending balance $ 914 $ 831 ______________ (1) For 2014, liabilities settled include $7 million related to the abandonment of certain of Transco’s natural gas storage caverns that are associated with a leak in 2010. (2) Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, discount rates, and the estimated remaining useful life of the assets. 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 2014 revisions primarily reflect an increase in the estimated retirement costs for our offshore pipelines, an increase in the inflation rate, and decreases in the discount rates used in the annual review process. |
Goodwill and Other Intangible36
Goodwill and Other Intangible Assets (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Schedule of Goodwill [Table Text Block] | Changes in the carrying amount of goodwill by reportable segment for the periods indicated are as follows: West Access Midstream Northeast G&P Total (Millions) December 31, 2014 $ 45 $ 429 $ 646 $ 1,120 Purchase accounting adjustment 2 23 — 25 Impairment — (452 ) (646 ) (1,098 ) December 31, 2015 $ 47 $ — $ — $ 47 |
Schedule of Finite-Lived Intangible Assets [Table Text Block] | The gross carrying amount and accumulated amortization of Other intangible assets – net of accumulated amortization at December 31 are as follows: 2015 2014 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization (Millions) Contractual customer relationships $ 10,632 $ (663 ) $ 10,761 $ (310 ) |
Debt, Banking Arrangements, a37
Debt, Banking Arrangements, and Leases (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |
Schedule of Long-term Debt Instruments [Table Text Block] | Long-Term Debt December 31, 2015 2014 (Millions) Unsecured: Transco: 6.4% Notes due 2016 (2) $ 200 $ 200 6.05% Notes due 2018 250 250 7.08% Debentures due 2026 8 8 7.25% Debentures due 2026 200 200 5.4% Notes due 2041 375 375 4.45% Notes due 2042 400 400 Northwest Pipeline: 7% Notes due 2016 175 175 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.: 3.8% Notes due 2015 (1) — 750 7.25% Notes due 2017 600 600 5.25% Notes due 2020 1,500 1,500 4.125% Notes due 2020 600 600 5.875% Notes due 2021 — 750 4% Notes due 2021 500 500 3.6% Notes due 2022 1,250 — 3.35% Notes due 2022 750 750 6.125% Notes due 2022 750 750 4.875% Notes due 2023 1,400 1,400 4.5% Notes due 2023 600 600 4.3% Notes due 2024 1,000 1,000 4.875% Notes due 2024 750 750 3.9% Notes due 2025 750 750 4.0% Notes due 2025 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 — Term Loan, variable interest rate, due 2018 850 — Credit facility loans 1,310 640 Capital lease obligations 1 5 Debt issuance costs (91 ) (74 ) Net unamortized debt premium (discount) 129 207 Long-term debt, including current portion 19,177 16,256 Long-term debt due within one year (176 ) (4 ) Long-term debt $ 19,001 $ 16,252 ______________________________________________________ (1) Presented as long-term debt at December 31, 2014, due to our intent and ability to refinance. (2) 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) 2016 $ 175 2017 785 2018 1,350 2019 — 2020 2,100 |
Schedule of Line of Credit Facilities [Table Text Block] | Credit Facilities December 31, 2015 Available Outstanding (Millions) Long-term credit facility (1) $ 3,500 $ 1,310 Letters of credit under certain bilateral bank agreements 2 Short-term credit facility 150 — __________ (1) In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. |
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) 2016 $ 77 2017 63 2018 46 2019 36 2020 32 Thereafter 99 Total $ 353 |
Partners' Capital (Tables)
Partners' Capital (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Partners' Capital Notes [Abstract] | |
Incentive Distribution Percentage By Specified Target Level [Table Text Block] | Incentive Distribution Rights Our general partner is 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, 2015 | |
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, 2015 : Restricted Common Units Outstanding Units Weighted- Average Fair Value (Millions) Nonvested at December 31, 2014 1.3 $ 59.35 Adjustment for unit split in ACMP Merger 0.1 $ — Forfeited (0.1 ) $ 58.05 Vested (0.1 ) $ 59.28 Nonvested at December 31, 2015 1.2 $ 55.93 |
Fair Value Measurements Guarant
Fair Value Measurements Guarantees and Concentration of Credit Risk (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] | 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, 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: Notes receivable and other 12 12 10 2 — Long-term debt, including current portion (1) (19,176 ) (15,988 ) — (15,988 ) — Assets (liabilities) at December 31, 2014: Measured on a recurring basis: ARO Trust investments $ 48 $ 48 $ 48 $ — $ — Energy derivatives assets not designated as hedging instruments 3 3 1 — 2 Energy derivatives liabilities not designated as hedging instruments (2 ) (2 ) — — (2 ) Additional disclosures: Notes receivable and other 5 4 — 4 — Long-term debt, including current portion (1) (16,251 ) (16,607 ) — (16,607 ) — ________________ (1) Excludes capital leases. The carrying value has been reduced by $91 million and $74 million of debt acquisition costs at December 31, 2015 and 2014, respectively. (See Note 13 – Debt, Banking Arrangements, and Leases .) |
Concentration of receivables, net of allowances, by product or service [Table Text Block] | The following table summarizes concentration of receivables , net of allowances. December 31, 2015 2014 (Millions) NGLs, natural gas, and related products and services $ 821 $ 728 Transportation of natural gas and related products 202 175 Other 3 2 Total $ 1,026 $ 905 |
Property, plant, and equipment, net [Member] | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |
Fair Value Measurements, Nonrecurring [Table Text Block] | Impairments Years Ended December 31, Date of Measurement Fair Value 2015 2014 (Millions) Impairment of certain assets (1) June 30, 2014 $ 46 $ 17 Impairment of certain assets (1) December 31, 2014 32 13 Impairment of certain assets (1) June 30, 2015 17 $ 20 Impairment of certain assets (2) December 31, 2014 1 12 Impairment of certain assets (3) December 31, 2015 13 94 Level 3 fair value measurements of certain assets 114 42 Other impairments (4) 31 10 Total impairments of certain assets $ 145 $ 52 ______________ (1) Reflects impairment charges for our Northeast G&P segment associated with certain surplus equipment. Certain of these assets were previously presented as held for sale, but are now considered held for use and reported in Property, plant, and equipment – net in the Consolidated Balance Sheet at December 31, 2015. The estimated fair value was determined by a market approach based on our analysis of observable inputs in the principal market. These impairment charges are recorded in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Comprehensive Income (Loss) . (2) Reflects impairment charges for our Access Midstream segment associated with certain surplus equipment considered held for sale and reported in Other current assets in the Consolidated Balance Sheet. The estimated fair value was determined by a market approach based on our analysis of observable inputs in the principal market. These impairment charges are recorded in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Comprehensive Income (Loss) . (3) Reflects an impairment charge within our West segment associated with previously capitalized project development costs for a gas processing plant, the completion of which is now considered remote due to unfavorable impact of low natural gas prices on customer drilling activities. These impairment charges are recorded in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Comprehensive Income (Loss) . 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 and is reported in Property, plant, and equipment – net in the Consolidated Balance Sheet. (4) Reflects multiple individually insignificant impairments of other certain assets that may no longer be in use or are surplus in nature for which the fair value was determined to be zero or an insignificant salvage value. These impairment charges are recorded in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Comprehensive Income (Loss) . |
Investments [Member] | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |
Fair Value Measurements, Nonrecurring [Table Text Block] | Date of Measurement Fair Value Impairments (Millions) Impairments of equity-method investments (1) September 30, 2015 $ 1,203 $ 461 Impairments of equity-method investments (2) December 31, 2015 4,017 890 Other impairment of equity-method investment December 31, 2015 58 8 Level 3 fair value measurements of equity-method investments $ 1,359 ______________ (1) Reflects other-than-temporary impairment charges related to Access Midstream’s equity-method investments in the Delaware basin gas gathering system and certain of the Appalachia Midstream Investments reflected within Impairment of equity-method investments in the Consolidated Statement of Comprehensive Income (Loss) . 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 ACMP Acquisition. 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 the Delaware basin gas gathering system 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. (2) Reflects other-than-temporary impairment charges related to Access Midstream’s equity-method investments in the Delaware basin gas gathering system, certain of the Appalachia Midstream Investments, and UEOM, as well as an impairment of Northeast G&P’s Laurel Mountain investment, all reflected within Impairment of equity-method investments in the Consolidated Statement of Comprehensive Income (Loss) . 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 increases in our cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses. |
Segment Disclosures (Tables)
Segment Disclosures (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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: 2015 $ 7,228 $ 103 $ 7,331 2014 7,212 197 7,409 2013 6,685 150 6,835 Long-lived assets: 2015 $ 37,586 $ 1,030 $ 38,616 2014 37,798 1,095 38,893 2013 18,776 1,137 19,913 Long-lived assets are comprised of property, plant, and equipment, goodwill, and other intangible assets. |
Reconciliation of segment revenues [Table Text Block] | Access Midstream Northeast G&P Atlantic- Gulf West NGL & Petchem Services Eliminations Total (Millions) 2015 Segment revenues: Service revenues External $ 1,523 $ 541 $ 1,877 $ 1,055 $ 139 $ — $ 5,135 Internal — 7 4 — — (11 ) — Total service revenues 1,523 548 1,881 1,055 139 (11 ) 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 $ 1,523 $ 675 $ 2,344 $ 1,312 $ 2,060 $ (583 ) $ 7,331 Other financial information: Proportional Modified EBITDA of equity-method investments $ 338 $ 62 $ 257 $ — $ 42 $ 699 2014 Segment revenues: Service revenues External $ 765 $ 450 $ 1,497 $ 1,050 $ 126 $ — $ 3,888 Internal — 1 4 — — (5 ) — Total service revenues 765 451 1,501 1,050 126 (5 ) 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 $ 765 $ 681 $ 2,354 $ 1,596 $ 3,112 $ (1,099 ) $ 7,409 Other financial information: Proportional Modified EBITDA of equity-method investments $ 178 $ 52 $ 151 $ — $ 50 $ 431 2013 Segment revenues: Service revenues External $ — $ 335 $ 1,414 $ 1,053 $ 112 $ — $ 2,914 Internal — — 10 1 — (11 ) — Total service revenues — 335 1,424 1,054 112 (11 ) 2,914 Product sales External — 166 830 64 2,861 — 3,921 Internal — — 95 708 294 (1,097 ) — Total product sales — 166 925 772 3,155 (1,097 ) 3,921 Total revenues $ — $ 501 $ 2,349 $ 1,826 $ 3,267 $ (1,108 ) $ 6,835 Other financial information: Proportional Modified EBITDA of equity-method investments $ — $ 15 $ 144 $ — $ 50 $ 209 |
Reconciliation of Modified EBITDA from Segments to Consolidated [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, 2015 2014 2013 (Millions) Modified EBITDA by segment: Access Midstream $ 1,279 $ 642 $ — Northeast G&P 314 395 114 Atlantic-Gulf 1,523 1,065 1,013 West 557 823 924 NGL & Petchem Services 321 324 395 Other 9 (5 ) 1 4,003 3,244 2,447 Accretion expense associated with asset retirement obligations for nonregulated operations (28 ) (17 ) (14 ) Depreciation and amortization expenses (1,702 ) (1,151 ) (791 ) Impairment of goodwill (1,098 ) — — Equity earnings (losses) 335 228 104 Impairment of equity-method investments (1,359 ) — — Other investing income (loss) – net 2 2 (1 ) Proportional Modified EBITDA of equity-method investments (699 ) (431 ) (209 ) Interest expense (811 ) (562 ) (387 ) (Provision) benefit for income taxes (1 ) (29 ) (30 ) Net income (loss) $ (1,358 ) $ 1,284 $ 1,119 |
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, 2015 2014 2015 2014 2015 2014 2013 (Millions) Access Midstream (1) $ 21,050 $ 22,470 $ 5,039 $ 6,004 $ 556 $ 16,964 $ — Northeast G&P 6,669 7,314 834 891 367 1,079 1,376 Atlantic-Gulf 12,171 11,114 959 985 1,573 1,593 1,072 West 5,035 5,174 — — 225 168 210 NGL & Petchem Services 3,306 3,510 504 519 236 601 746 Other corporate assets 350 501 — — 3 8 5 Eliminations (2) (711 ) (835 ) — — — — — Total $ 47,870 $ 49,248 $ 7,336 $ 8,399 $ 2,960 $ 20,413 $ 3,409 (1) 2014 Additions to long-lived assets within our Access Midstream segment primarily 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 Busin42
General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Details) $ in Millions | Sep. 28, 2015USD ($) | Feb. 02, 2015shares | Feb. 26, 2016USD ($) | Nov. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Oct. 31, 2014USD ($) | Feb. 28, 2014USD ($)shares | Jun. 30, 2014USD ($) | Mar. 31, 2013USD ($) | Jul. 02, 2014 | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013 | Jul. 01, 2014 | Dec. 31, 2012 |
General and Description Of Business [Abstract] | |||||||||||||||
Parent, general partner ownership percentage | 2.00% | 2.00% | 2.00% | ||||||||||||
Regulatory Assets and Liabilities Disclosure [Abstract] | |||||||||||||||
Regulatory Assets, Current | $ 84 | $ 81 | |||||||||||||
Regulatory Assets, Noncurrent | 305 | 289 | |||||||||||||
Total regulatory assets | 389 | 370 | |||||||||||||
Regulatory Liabilities, Current | 4 | 11 | |||||||||||||
Regulatory Liabilities, Noncurrent | 409 | 349 | |||||||||||||
Total regulatory liabilities | $ 413 | $ 360 | |||||||||||||
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 | $ 209 | ||||||||||||||
Access Midstream Partners Acquisition [Member] | ACMP Units Into WPZ Units [Member] | |||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||
Conversion Ratio | 1.06152 | ||||||||||||||
Access Midstream Partners Acquisition [Member] | Publicly Held Pre-merger WPZ Common Units into ACMP Common Units [Member] | |||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||
Conversion Ratio | 0.86672 | ||||||||||||||
Access Midstream Partners Acquisition [Member] | Privately Held Pre-merger WPZ Units Into ACMP Common Units [Member] | |||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||
Conversion Ratio | 0.80036 | ||||||||||||||
Access Midstream Partners Acquisition [Member] | Class D Pre-merger WPZ Units Into WPZ Common Units [Member] | |||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||
Conversion Ratio | 1 | ||||||||||||||
Access Midstream Partners Acquisition [Member] | General Partner [Member] | |||||||||||||||
Basis of Presentation [Abstract] | |||||||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 50.00% | 50.00% | |||||||||||||
Canada Acquisition [Member] | |||||||||||||||
Basis of Presentation [Abstract] | |||||||||||||||
Payments to Acquire Businesses, Gross | $ 56 | $ 31 | |||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 25,577,521 | ||||||||||||||
Proceeds from Previous Acquisition | $ 56 | ||||||||||||||
Reduction in incentive distribution rights payment | $ 2 | ||||||||||||||
Geismar Acquisition [Member] | |||||||||||||||
Basis of Presentation [Abstract] | |||||||||||||||
Proceeds from Previous Acquisition | $ 25 | ||||||||||||||
Reduction in incentive distribution rights payment | $ 4 | ||||||||||||||
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% | ||||||||||||||
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% | ||||||||||||||
Williams Partners L. P. [Member] | General Partner [Member] | |||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||
Parent, general partner ownership percentage | 100.00% | ||||||||||||||
Access Midstream Partners Lp [Member] | General Partner [Member] | |||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||
Parent, general partner ownership percentage | 100.00% | ||||||||||||||
Access Midstream [Member] | Utica East Ohio Midstream, LLC [Member] | |||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||
Equity Method Investment, Ownership Percentage | 62.00% | ||||||||||||||
Access Midstream [Member] | Delaware Basin Gas Gathering System [Member] | |||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||
Equity Method Investment, Ownership Percentage | 50.00% | ||||||||||||||
Access Midstream [Member] | Appalachia Midstream Services, LLC [Member] | |||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||
Subsidiary, ownership percentage | 45.00% | ||||||||||||||
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% | ||||||||||||||
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% | ||||||||||||||
Subsequent Event [Member] | WPZ Merger Public Unit Exchange [Member] | |||||||||||||||
Basis of Presentation [Abstract] | |||||||||||||||
Reduction in incentive distribution rights payment | $ 209 | ||||||||||||||
Common Units [Member] | Access Midstream Partners Acquisition [Member] | ACMP Units Into WPZ Units [Member] | |||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||
Shares Converted | shares | 202,564,354 | ||||||||||||||
Class B Units [Member] | Access Midstream Partners Acquisition [Member] | ACMP Units Into WPZ Units [Member] | |||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||
Shares Converted | shares | 13,725,843 | ||||||||||||||
General Partner [Member] | Access Midstream Partners Acquisition [Member] | |||||||||||||||
General and Description Of Business [Abstract] | |||||||||||||||
Parent, general partner ownership percentage | 2.00% |
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, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | Jul. 01, 2014USD ($) | ||||
Business Acquisition, Purchase Price Allocation [Abstract] | ||||||||||||
Goodwill | $ 47 | $ 1,120 | ||||||||||
Equity Method Investments and Joint Ventures [Abstract] | ||||||||||||
Payments to Acquire Equity Method Investments | 594 | 468 | $ 439 | |||||||||
Access Midstream [Member] | ||||||||||||
Business Acquisition, Purchase Price Allocation [Abstract] | ||||||||||||
Goodwill | $ 0 | 429 | ||||||||||
Access Midstream Partners Acquisition [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Property, Plant, and Equipment | $ 150 | |||||||||||
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Goodwill | 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 | 7,881 | ||||||||||
Business Acquisition, Pro Forma Net Income (Loss) | 1,376 | 1,172 | ||||||||||
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] | Access Midstream [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] | Access Midstream [Member] | ||||||||||||
Business Acquisition, Purchase Price Allocation [Abstract] | ||||||||||||
Noncontrolling interest | (958) | |||||||||||
Access Midstream Partners Acquisition [Member] | Access Midstream Partners Lp [Member] | Access Midstream [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 | $ 357 | [1] | $ 57 | [1] | $ 0 | [1] | |||||
Reduction in incentive distribution rights payment | $ 2 | |||||||||||
Utica East Ohio Midstream, LLC [Member] | Access Midstream [Member] | ||||||||||||
Equity Method Investments and Joint Ventures [Abstract] | ||||||||||||
Equity Method Investment, Ownership Percentage | 62.00% | |||||||||||
Utica East Ohio Midstream, LLC [Member] | Additional Investment [Member] | ||||||||||||
Equity Method Investments and Joint Ventures [Abstract] | ||||||||||||
Equity Method Investment, Ownership Percentage | 13.00% | 13.00% | ||||||||||
[1] | 2015 includes purchase of additional interest in UEOM. (See Note 2 – Acquisitions.) |
Variable Interest Entities (Det
Variable Interest Entities (Details) - Variable Interest Entity, Primary Beneficiary [Member] - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Cash and cash equivalents [Member] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets | $ 70 | $ 113 |
Accounts receivable [Member] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets | 71 | 52 |
Other current assets [Member] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets | 2 | 3 |
Property, plant, and equipment, net [Member] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets | 3,000 | 2,794 |
Goodwill [Member] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets | 47 | 103 |
Intangible assets, net [Member] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets | 1,436 | 1,493 |
Other noncurrent assets [Member] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets | 0 | 14 |
Accounts payable [Member] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities | (59) | (48) |
Accrued liabilities [Member] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities | (14) | (36) |
Current deferred revenue [Member] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities | (62) | (45) |
Noncurrent deferred income taxes [Member] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities | 0 | (13) |
Asset retirement obligation [Member] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities | (93) | (94) |
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 | $ (331) | $ (395) |
Gulfstar One [Member] | ||
Variable Interest Entity [Line Items] | ||
Variable Interest Entity Ownership Percentage | 51.00% | |
Gulfstar One [Member] | Estimated Remaining Construction Costs For Variable Interest Entity [Member] | ||
Variable Interest Entity [Line Items] | ||
Estimated remaining construction costs | $ 130 | |
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 | $ 571 | |
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 (Los45
Allocation of Net Income (Loss) and Distributions (Details) - USD ($) $ / shares in Units, $ in Millions | 1 Months Ended | 12 Months Ended | |||
Feb. 12, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
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) | (1,358) | 1,284 | $ 1,119 | ||
Net income applicable to pre-merger operations allocated to general partner | (2) | (95) | 0 | ||
Net income applicable to pre-partnership operations allocated to general partner | 0 | (15) | (49) | ||
Net income applicable to noncontrolling interests | (91) | (96) | (3) | ||
Costs charged directly to the general partner | 21 | 1 | 1 | ||
Income (loss) subject to 2% allocation of general partner interest | $ (1,430) | $ 1,079 | $ 1,068 | ||
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 | $ (29) | $ 22 | $ 21 | ||
Priority allocations, including incentive distributions, paid to general partner | 638 | 641 | 387 | ||
Pre-merger net income allocated to general partner interest | 2 | 95 | 0 | ||
Pre-partnership net income allocated to general partner interest | 0 | 15 | 49 | ||
Costs charged directly to the general partner | (21) | (1) | (1) | ||
Net income allocated to general partner's equity | 590 | 772 | 456 | ||
Net income (loss) | (1,358) | 1,284 | 1,119 | ||
Net income allocated to general partner's equity | 590 | 772 | 456 | ||
Net income (loss) allocated to Class B limited partners' equity | (52) | 0 | 0 | ||
Net income allocated to Class D limited partners' equity | [1] | 69 | 62 | 0 | |
Net income applicable to noncontrolling interests | 91 | 96 | 3 | ||
Net income (loss) allocated to common limited partners' equity | (2,056) | 354 | 660 | ||
Adjustments to reconcile Net income (loss) allocated to common limited partners' equity to Allocation of net income (loss) to common units | |||||
Incentive distributions paid | 633 | 640 | 383 | ||
Incentive distributions declared | [2],[3] | (423) | (626) | (432) | |
Impact of unit issuance timing and other | (9) | (9) | 0 | ||
Allocation of net income (loss) to common units | $ (1,855) | 359 | $ 611 | ||
Subsequent Event [Member] | |||||
Distributions Made to Members or Limited Partners [Abstract] | |||||
Per Unit Distribution (Paid) | $ 0.85 | ||||
Class B [Member] | |||||
Distributions Made to Members or Limited Partners [Abstract] | |||||
Class B Units Issued In Lieu Of Cash Distributions | 1,058,172 | ||||
Class B [Member] | Subsequent Event [Member] | |||||
Distributions Made to Members or Limited Partners [Abstract] | |||||
Class B Units Issued In Lieu Of Cash Distributions | 558,986 | ||||
Class D [Member] | |||||
Distributions Made to Members or Limited Partners [Abstract] | |||||
Amortization of beneficial conversion feature of Class D units | $ 68 | $ 49 | |||
Class D Units Issued In Lieu Of Cash Distributions | 1,377,893 | ||||
[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] | On February 12, 2016, we paid a cash distribution of $0.85 per common unit on our outstanding common units to unitholders of record at the close of business on February 5, 2016. | ||||
[3] | The 2015 amount reflects the waiver of IDRs associated with the Termination Agreement. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.) The 2014 amount reflects only the portion of the total incentive distribution associated with the Pre-merger WPZ common units exchanged in the ACMP Merger. |
Related Party Transactions (Det
Related Party Transactions (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Summary of Related Party Transactions Abstract [Line Items] | |||
Product costs | $ 169 | $ 186 | $ 147 |
Operating and maintenance expenses | 498 | 413 | 339 |
Capitalized Charges From Affiliate | 187 | 81 | |
Accounts payable - affiliate | 141 | 137 | |
Proceeds | 12 | 11 | 12 |
Contribution receivable | 3 | ||
Employee direct costs [Member] | |||
Summary of Related Party Transactions Abstract [Line Items] | |||
Selling, general, and administrative expenses | 368 | 331 | 270 |
Employee allocated costs [Member] | |||
Summary of Related Party Transactions Abstract [Line Items] | |||
Selling, general, and administrative expenses | 195 | 171 | 169 |
Equity method investees [Member] | |||
Summary of Related Party Transactions Abstract [Line Items] | |||
Accounts payable - affiliate | 12 | 13 | |
Service costs | 64 | 65 | 67 |
Common management [Member] | |||
Summary of Related Party Transactions Abstract [Line Items] | |||
Revenue | 111 | $ 115 | $ 131 |
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 | 3 Months Ended | 12 Months Ended | |||||||
Jun. 30, 2015 | Dec. 31, 2015 | Sep. 30, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Impairment of equity-method investments | $ 1,359 | $ 0 | $ 0 | |||||||
Income (Loss) from Equity Method Investments | (335) | (228) | (104) | |||||||
Contribution to equity-method investment for repayment of debt | 248 | 0 | 0 | |||||||
Investments | $ 7,336 | 7,336 | 8,399 | |||||||
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity | 2,400 | 2,400 | 3,700 | |||||||
Equity Method Investment, payments to purchase or contributions | 594 | 468 | 439 | |||||||
Equity Method Investment, dividends or distributions | 633 | 365 | 154 | |||||||
Special distribution from equity-method investment | 396 | 0 | 0 | |||||||
Summarized Financial Position of Equity Method Investments | ||||||||||
Current assets | 773 | 773 | 599 | |||||||
Noncurrent assets | 9,549 | 9,549 | 9,135 | |||||||
Current liabilities | (633) | (633) | (850) | |||||||
Noncurrent liabilities | (1,450) | (1,450) | (954) | |||||||
Summarized Results of Operations of Equity Method Investments | ||||||||||
Gross revenue | 1,707 | 1,623 | 1,333 | |||||||
Operating income | 690 | 534 | 367 | |||||||
Net income | 611 | 460 | 291 | |||||||
Delaware Basin Gas Gathering System [Member] | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Investments | $ 977 | $ 977 | 1,478 | |||||||
Investment, Ownership Percentage | 50.00% | 50.00% | ||||||||
Equity Method Investment, payments to purchase or contributions | $ 57 | 20 | 0 | |||||||
Equity Method Investment, dividends or distributions | 33 | 0 | 0 | |||||||
Appalachia Midstream Investments [Member] | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Investments | [1] | $ 2,464 | $ 2,464 | 3,033 | ||||||
Investment, Ownership Percentage | 45.00% | 45.00% | ||||||||
Equity Method Investment, payments to purchase or contributions | $ 93 | 84 | 0 | |||||||
Equity Method Investment, dividends or distributions | 219 | 130 | 0 | |||||||
Utica East Ohio Midstream, LLC [Member] | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Investments | [2] | $ 1,525 | $ 1,525 | 1,411 | ||||||
Investment, Ownership Percentage | 62.00% | 62.00% | ||||||||
Equity Method Investment, payments to purchase or contributions | $ 357 | $ 357 | [3] | 57 | [3] | 0 | [3] | |||
Equity Method Investment, dividends or distributions | 42 | 0 | 0 | |||||||
Discovery Producer Services LLC [Member] | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Investments | $ 602 | $ 602 | 602 | |||||||
Investment, Ownership Percentage | 60.00% | 60.00% | ||||||||
Equity Method Investment, payments to purchase or contributions | $ 35 | 106 | 193 | |||||||
Equity Method Investment, dividends or distributions | 116 | 36 | 12 | |||||||
Laurel Mountain Midstream, LLC [Member] | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Investments | $ 391 | $ 391 | 459 | |||||||
Investment, Ownership Percentage | 69.00% | 69.00% | ||||||||
Equity Method Investment, dividends or distributions | $ 31 | 39 | 0 | |||||||
Overland Pass Pipeline Company LLC [Member] | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Investments | $ 445 | $ 445 | 453 | |||||||
Investment, Ownership Percentage | 50.00% | 50.00% | ||||||||
Equity Method Investment, dividends or distributions | $ 45 | 27 | 27 | |||||||
Caiman Energy II LLC [Member] | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Investments | $ 418 | $ 418 | 432 | |||||||
Investment, Ownership Percentage | 58.00% | 58.00% | ||||||||
Equity Method Investment, payments to purchase or contributions | $ 0 | 175 | 192 | |||||||
Equity Method Investment, dividends or distributions | 33 | 13 | 0 | |||||||
Gulfstream Natural Gas System, L.L.C. [Member] | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Contribution to equity-method investment for repayment of debt | 248 | |||||||||
Investments | $ 293 | $ 293 | 317 | |||||||
Investment, Ownership Percentage | 50.00% | 50.00% | ||||||||
Equity Method Investment, dividends or distributions | $ 88 | 81 | 81 | |||||||
Special distribution from equity-method investment | 396 | |||||||||
Special distribution repayable to equity-method investment | $ 149 | 149 | ||||||||
Other [Member] | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Investments | 221 | 221 | 214 | |||||||
Equity Method Investment, payments to purchase or contributions | 52 | 26 | 54 | |||||||
Equity Method Investment, dividends or distributions | 26 | $ 39 | $ 34 | |||||||
Impairment Of Equity-Method Investments [Member] | Delaware Basin Gas Gathering System [Member] | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Impairment of equity-method investments | 45 | $ 458 | ||||||||
Impairment Of Equity-Method Investments [Member] | Appalachia Midstream Investments [Member] | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Impairment of equity-method investments | 559 | $ 3 | ||||||||
Impairment Of Equity-Method Investments [Member] | Utica East Ohio Midstream, LLC [Member] | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Impairment of equity-method investments | 241 | |||||||||
Impairment Of Equity-Method Investments [Member] | Laurel Mountain Midstream, LLC [Member] | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Impairment of equity-method investments | $ 45 | |||||||||
Income Loss From Equity Method Investment [Member] | Appalachia Midstream Investments [Member] | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Income (Loss) from Equity Method Investments | $ 19 | |||||||||
Additional Investment [Member] | Utica East Ohio Midstream, LLC [Member] | ||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||
Investment, Ownership Percentage | 13.00% | 13.00% | 13.00% | |||||||
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 | $ 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 | $ 300 | ||||||||
[1] | Includes equity-method investments in multiple gathering systems in the Marcellus Shale with an approximate average 45 percent interest. | |||||||||
[2] | We acquired an approximate 13 percent additional interest in UEOM in 2015. (See Note 2 – Acquisitions.) | |||||||||
[3] | 2015 includes purchase of additional interest in UEOM. (See Note 2 – Acquisitions.) |
Other Income and Expenses (Deta
Other Income and Expenses (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Other (income) expense - net [Member] | Access Midstream [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Impairment of certain assets | $ 14 | $ 12 | $ 0 | |
Loss related to sale of certain assets | 0 | 10 | 0 | |
Other (income) expense - net [Member] | Northeast G&P [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Impairment of certain assets | 29 | 30 | 0 | |
Contingency gain settlement | [1] | 0 | (154) | 0 |
Net gain related to acreage dedication release | 0 | (12) | 0 | |
Other (income) expense - net [Member] | Northeast G&P [Member] | Producer claim [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Loss associated with a producer claim | 0 | 0 | 25 | |
Other (income) expense - net [Member] | Atlantic-Gulf [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Impairment of certain assets | 5 | 10 | 0 | |
Amortization of regulatory asset associated with asset retirement obligations | 33 | 33 | 30 | |
Other (income) expense - net [Member] | Atlantic-Gulf [Member] | Asset Impairment for Regulatory Action [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Impairment of certain assets | 0 | (3) | 12 | |
Insurance recoveries | 0 | 0 | (16) | |
Other (income) expense - net [Member] | West [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Impairment of certain assets | 97 | 0 | 0 | |
Net insurance recoveries - Geismar Incident [Member] | NGL & Petchem Services [Member] | Geismar Incident [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Insurance recoveries | (126) | (246) | (50) | |
Insurable expenses in excess of our deductibles | 14 | 10 | ||
Selling, general, and administrative expenses [Member] | Access Midstream [Member] | Acquisition and Merger [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Business combination, acquisition related costs | 26 | 27 | ||
Selling, general, and administrative expenses [Member] | Access Midstream [Member] | Acquisition [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Business combination, acquisition related costs | 16 | |||
Selling, general, and administrative expenses [Member] | Access Midstream [Member] | Transition costs [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Business combination, integration related costs | 9 | 15 | ||
Operating and maintenance expenses [Member] | Access Midstream [Member] | Transition costs [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Business combination, integration related costs | 12 | 15 | ||
Operating and maintenance expenses [Member] | NGL & Petchem Services [Member] | Geismar Incident [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Insurance deductible expense | 13 | |||
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] | Access Midstream [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Minimum volume commitment fees | 239 | 167 | ||
Product costs [Member] | NGL & Petchem Services [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Inventory Write-down | 6 | 27 | ||
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 | $ 76 | $ 33 | $ 19 | |
[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 $154 million in cash, all of which was recognized as a gain in the fourth quarter of 2014. |
Provision (Benefit) Table (Deta
Provision (Benefit) Table (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Current: | |||
State | $ (3) | $ 3 | $ 2 |
Foreign | 0 | 1 | (22) |
Total | (3) | 4 | (20) |
Deferred: | |||
State | (3) | 8 | 15 |
Foreign | 7 | 17 | 35 |
Total | 4 | 25 | 50 |
Provision (benefit) for income taxes | $ 1 | $ 29 | $ 30 |
Reconciliations To Recorded Pro
Reconciliations To Recorded Provision for Income Taxes (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Effective Income Tax Rate Reconciliation, Amount [Abstract] | |||
Provision (benefit) at statutory rate | $ (475) | $ 459 | $ 402 |
Increases (decreases) in taxes resulting from: | |||
Income not subject to U.S. federal tax | 475 | (459) | (402) |
State income taxes | (6) | 11 | 17 |
Foreign operations — net | 7 | 18 | 13 |
Provision (benefit) for income taxes | $ 1 | $ 29 | $ 30 |
Provision (Benefit) for Incom51
Provision (Benefit) for Income Taxes (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Income Tax Contingency [Line Items] | |||
State | $ (3) | $ 8 | $ 15 |
Foreign | 7 | 17 | 35 |
Provision (Benefit) for Income Taxes [Abstract] | |||
Income (Loss) from Continuing Operations before Income Taxes, Foreign | 1 | 72 | 61 |
Deferred Tax Liabilities, Gross | 119 | 133 | 117 |
Income Taxes Paid, Net | (4) | $ (28) | 2 |
Unrecognized Tax Benefits | 0 | ||
TEXAS | |||
Income Tax Contingency [Line Items] | |||
State | 7 | $ 14 | |
Alberta Provincial Tax [Domain] | |||
Income Tax Contingency [Line Items] | |||
Foreign | $ 8 |
Benefit Plans (Details)
Benefit Plans (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Contribution Plan, Cost Recognized | $ 27 | $ 25 | $ 16 |
Pension Expense | 43 | 28 | 44 |
Other Postretirement Benefit Cost (Credit) | (12) | (14) | $ (4) |
Pension Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Benefit Obligation | 1,500 | 1,500 | |
Defined Benefit Plan, Funded Status of Plan | (223) | (251) | |
Other Postretirement Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Benefit Obligation | 202 | 233 | |
Defined Benefit Plan, Funded Status of Plan | $ (1) | $ (25) |
Inventories (Details)
Inventories (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Inventory Net [Abstract] | ||
Natural gas liquids, olefins, and natural gas in underground storage | $ 57 | $ 150 |
Materials, supplies, and other | 70 | 81 |
Total Inventories | $ 127 | $ 231 |
Property, Plant and Equipment54
Property, Plant and Equipment (Details PPE) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Property, Plant and Equipment | ||||
Property, plant, and equipment, at cost | $ 37,833 | $ 35,479 | ||
Accumulated depreciation and amortization | (9,233) | (8,157) | ||
Property, plant, and equipment - net | 28,600 | 27,322 | ||
Depreciation and amortization | 1,348 | 944 | $ 729 | |
Nonregulated [Member] | Natural gas gathering and processing facilities [Member] | ||||
Property, Plant and Equipment | ||||
Property, plant, and equipment, at cost | $ 20,636 | 18,717 | ||
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 | $ 740 | 2,115 | ||
Nonregulated [Member] | Other Capitalized Property Plant and Equipment [Member] | ||||
Property, Plant and Equipment | ||||
Property, plant, and equipment, at cost | $ 1,743 | 1,459 | ||
Nonregulated [Member] | Other Capitalized Property Plant and Equipment [Member] | Minimum [Member] | ||||
Property, Plant and Equipment | ||||
Property, Plant and Equipment, Useful Life | [1] | 2 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 | $ 12,189 | 10,867 | ||
Regulated [Member] | Natural gas transmission facilities [Member] | Minimum [Member] | ||||
Property, Plant and Equipment | ||||
Property, Plant and Equipment, Useful Life | [1] | 5 years | ||
Regulated Property, Plant, and Equipment, Depreciation Rate | [1] | 1.20% | ||
Regulated [Member] | Natural gas transmission facilities [Member] | Maximum [Member] | ||||
Property, Plant and Equipment | ||||
Property, Plant and Equipment, Useful Life | [1] | 45 years | ||
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 | $ 941 | 985 | ||
Regulated [Member] | Other Capitalized Property Plant and Equipment [Member] | ||||
Property, Plant and Equipment | ||||
Property, plant, and equipment, at cost | $ 1,584 | 1,336 | ||
Regulated [Member] | Other Capitalized Property Plant and Equipment [Member] | Minimum [Member] | ||||
Property, Plant and Equipment | ||||
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 | ||||
Regulated Property, Plant, and Equipment, Depreciation Rate | [1] | 33.33% | ||
Regulated [Member] | Excess Of Original Cost Of Regulated Facilities [Member] | ||||
Property, Plant and Equipment | ||||
Property, plant, and equipment - net | $ 706 | $ 746 | ||
Period of straight-line amortization | 40 years | |||
[1] | Estimated useful life and depreciation rates are presented as of December 31, 2015. 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, 2015 | Dec. 31, 2014 | ||
Asset Retirement Obligation | |||
Asset Retirement Obligations, Noncurrent | $ 857 | $ 791 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Beginning balance | 831 | 561 | |
Liabilities incurred | 41 | 101 | |
Liabilities settled | [1] | (3) | (21) |
Accretion expense | 60 | 44 | |
Revisions | [2] | (15) | 146 |
Ending balance | 914 | 831 | |
Charges Related To Leak At Underground Natural Gas Storage Facility [Member] | |||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Liabilities settled | $ (7) | ||
Asset Retirement Obligation Costs [Member] | |||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Transco's annual funding commitment for ARO | $ 36 | ||
[1] | For 2014, liabilities settled include $7 million related to the abandonment of certain of Transco’s natural gas storage caverns that are associated with a leak in 2010. | ||
[2] | Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, discount rates, and the estimated remaining useful life of the assets. The 2015 revisions reflect changes in removal cost estimates and the estimated remaining useful life of assets, a decrease in the inflation rate, and increases in the discount rates used in the annual review process. The 2014 revisions primarily reflect an increase in the estimated retirement costs for our offshore pipelines, an increase in the inflation rate, and decreases in the discount rates used in the annual review process. |
Goodwill (Details)
Goodwill (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Goodwill [Line Items] | ||||
Goodwill, beginning of period | $ 1,120 | |||
Goodwill, Purchase Accounting Adjustments | 25 | |||
Impairment of goodwill | $ (1,098) | (1,098) | $ 0 | $ 0 |
Goodwill, end of period | 47 | 47 | 1,120 | |
West [Member] | ||||
Goodwill [Line Items] | ||||
Goodwill, beginning of period | 45 | |||
Goodwill, Purchase Accounting Adjustments | 2 | |||
Impairment of goodwill | 0 | |||
Goodwill, end of period | 47 | 47 | 45 | |
Access Midstream [Member] | ||||
Goodwill [Line Items] | ||||
Goodwill, beginning of period | 429 | |||
Goodwill, Purchase Accounting Adjustments | 23 | |||
Impairment of goodwill | (452) | |||
Goodwill, end of period | 0 | 0 | 429 | |
Northeast G&P [Member] | ||||
Goodwill [Line Items] | ||||
Goodwill, beginning of period | 646 | |||
Goodwill, Purchase Accounting Adjustments | 0 | |||
Impairment of goodwill | (646) | |||
Goodwill, end of period | $ 0 | $ 0 | $ 646 |
Other Intangible Assets (Detail
Other Intangible Assets (Details) - USD ($) $ in Millions | 1 Months Ended | 2 Months Ended | 3 Months Ended | 4 Months Ended | 6 Months Ended | 12 Months Ended | |||
May. 31, 2015 | Feb. 17, 2012 | Sep. 30, 2015 | Mar. 31, 2015 | Apr. 27, 2012 | Jul. 02, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Finite-Lived Intangible Assets [Line Items] | |||||||||
Amortization of Intangible Assets | $ 353 | $ 207 | $ 60 | ||||||
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months | 354 | ||||||||
Finite-Lived Intangible Assets, Amortization Expense, Year Two | 354 | ||||||||
Finite-Lived Intangible Assets, Amortization Expense, Year Three | 354 | ||||||||
Finite-Lived Intangible Assets, Amortization Expense, Year Four | 354 | ||||||||
Finite-Lived Intangible Assets, Amortization Expense, Year Five | 354 | ||||||||
Contractual customer relationships [Member] | |||||||||
Finite-Lived Intangible Assets [Line Items] | |||||||||
Finite-Lived Intangible Assets, Gross | 10,632 | 10,761 | |||||||
Finite-Lived Intangible Assets, Accumulated Amortization | $ (663) | $ (310) | |||||||
Access Midstream Partners Acquisition [Member] | |||||||||
Finite-Lived Intangible Assets [Line Items] | |||||||||
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Intangibles | $ (168) | ||||||||
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] | |||||||||
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Intangibles | $ (20) | ||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles | $ 32 | ||||||||
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 | ||||||||
Laser 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 | 9 years | ||||||||
Caiman 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 | 18 years |
Long-Term Debt (Details)
Long-Term Debt (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 23, 2015 | Dec. 31, 2014 | Jun. 27, 2014 | Mar. 04, 2014 | |
Debt Instrument [Line Items] | ||||||
Capital Lease Obligations | $ 1 | $ 5 | ||||
Debt issuance costs | (91) | (74) | ||||
Net unamortized debt premium (discount) | 129 | 207 | ||||
Long-term debt, including current portion | 19,177 | 16,256 | ||||
Long-term Debt and Capital Lease Obligations, Current | (176) | (4) | ||||
Long-term debt | 19,001 | 16,252 | ||||
Transcontinental Gas Pipe Line Company, LLC [Member] | 6.4% Senior Unsecured Notes due 2016 [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt | [1] | $ 200 | 200 | |||
Long-term debt interest rate | 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] | 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 | $ 175 | 175 | ||||
Long-term debt interest rate | 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 | $ 1,310 | 640 | ||||
Williams Partners L.P. [Member] | 3.8% Senior Unsecured Notes due 2015 [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt | [2] | $ 0 | 750 | |||
Long-term debt interest rate | 3.80% | |||||
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 | $ 0 | 750 | ||||
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 | 0 | ||||
Long-term debt interest rate | 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] | 4.875% 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] | 4.5% 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] | 4.3% Senior Unsecured Notes Due 2024 [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt | $ 1,000 | 1,000 | ||||
Long-term debt interest rate | 4.30% | 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% | 3.90% | ||||
Williams Partners L.P. [Member] | 4% Senior Unsecured Notes due 2025 [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt | $ 750 | 0 | ||||
Long-term debt interest rate | 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% | 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% | 4.90% | ||||
Williams Partners L.P. [Member] | 5.1% Senior Unsecured Notes due 2045 [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt | $ 1,000 | 0 | ||||
Long-term debt interest rate | 5.10% | |||||
Williams Partners L.P. [Member] | Variable Interest Term Loan due 2018 [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt | $ 850 | $ 850 | $ 0 | |||
Long-term debt interest rate | 1.8531% | |||||
[1] | Presented as long-term debt at December 31, 2015, due to Transco’s intent and ability to refinance. | |||||
[2] | Presented as long-term debt at December 31, 2014, due to our intent and ability to refinance. |
Long-Term Debt Maturities (Deta
Long-Term Debt Maturities (Details) $ in Millions | Dec. 31, 2015USD ($) |
Long-term Debt, by Maturity [Abstract] | |
2,016 | $ 175 |
2,017 | 785 |
2,018 | 1,350 |
2,019 | 0 |
2,020 | $ 2,100 |
Long Term Debt Change Of Contro
Long Term Debt Change Of Control Provision (Details) - Access Midstream Partners Lp [Member] $ in Billions | Dec. 31, 2015USD ($) |
Change Of Control Payment Percentage [Line Items] | |
Debt Instrument, Face Amount | $ 2.9 |
Change Of Control Payment Percentage | 101.00% |
Long-Term Debt Issuances and Re
Long-Term Debt Issuances and Retirements (Details) - USD ($) $ in Millions | Apr. 15, 2015 | Feb. 15, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Jan. 22, 2016 | Dec. 23, 2015 | Mar. 03, 2015 | Jun. 27, 2014 | Mar. 04, 2014 | |
Debt Instrument [Line Items] | |||||||||||
Repayments of Long-term Debt | $ 4,699 | $ 1,157 | $ 2,080 | ||||||||
Transcontinental Gas PipeLine Company, LLC [Member] | 7.85% Senior Unsecured Notes Due 2026 [Member] | Subsequent Event [Member] | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Long-term debt face amount | $ 1,000 | ||||||||||
Long-term debt interest rate | 7.85% | ||||||||||
Williams Partners L. P. [Member] | Variable Interest Term Loan due 2018 [Member] | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Long-term debt | $ 850 | 0 | $ 850 | ||||||||
Long-term debt interest rate | 1.8531% | ||||||||||
Williams Partners L. P. [Member] | 3.8% Senior Unsecured Notes due 2015 [Member] | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Long-term debt | [1] | $ 0 | 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 | $ 750 | 750 | |||||||||
Long-term debt face amount | $ 750 | ||||||||||
Long-term debt interest rate | 3.90% | 3.90% | |||||||||
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 face amount | $ 500 | ||||||||||
Long-term debt interest rate | 4.90% | 4.90% | |||||||||
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 face amount | $ 1,000 | ||||||||||
Long-term debt interest rate | 4.30% | 4.30% | |||||||||
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 face amount | $ 500 | ||||||||||
Long-term debt interest rate | 5.40% | 5.40% | |||||||||
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] | 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] | 5.875% Senior Unsecured Notes due 2021 [Member] | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Long-term debt | $ 0 | 750 | |||||||||
Long-term debt interest rate | 5.875% | ||||||||||
Williams Partners L. P. [Member] | 3.6% Senior Unsecured Notes due 2022 [Member] | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Long-term debt | $ 1,250 | 0 | |||||||||
Long-term debt interest rate | 3.60% | ||||||||||
Williams Partners L. P. [Member] | 4% Senior Unsecured Notes due 2025 [Member] | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Long-term debt | $ 750 | 0 | |||||||||
Long-term debt interest rate | 4.00% | ||||||||||
Williams Partners L. P. [Member] | 5.1% Senior Unsecured Notes due 2045 [Member] | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Long-term debt | $ 1,000 | $ 0 | |||||||||
Long-term debt interest rate | 5.10% | ||||||||||
Williams Partners L.P. [Member] | Variable Interest Term Loan due 2018 [Member] | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Long-term debt | $ 850 | ||||||||||
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] | 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% | ||||||||||
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% | ||||||||||
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% | ||||||||||
[1] | Presented as long-term debt at December 31, 2014, due to our intent and ability to refinance. |
Credit Facility and Commercial
Credit Facility and Commercial Paper (Details) $ in Millions | Dec. 18, 2015 | Aug. 26, 2015USD ($) | Feb. 02, 2015USD ($) | Dec. 31, 2015USD ($) | Feb. 25, 2016USD ($) | Dec. 23, 2015USD ($) | Mar. 03, 2015USD ($) | Dec. 31, 2014USD ($) | ||
Credit Facility and Commercial Paper [Line Items] | ||||||||||
Commercial paper, outstanding | $ 499 | $ 798 | ||||||||
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 | $ 3,500 | 3,500 | [1] | ||||||
Credit facility, loans outstanding | [1] | 1,310 | ||||||||
Additional amount by which credit facility can be increased | $ 500 | |||||||||
Maximum ratio of debt to EBITDA | 6 | |||||||||
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 | $ 499 | $ 798 | ||||||||
Commercial paper, weighted average interest rate | 0.92% | 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 | $ 2 | |||||||||
Williams Partners L.P. [Member] | Short-term facility [Member] | ||||||||||
Credit Facility and Commercial Paper [Line Items] | ||||||||||
Credit facility, capacity | $ 1,000 | 150 | $ 150 | $ 1,500 | ||||||
Credit facility, loans outstanding | 0 | |||||||||
Williams Partners L. P. [Member] | ||||||||||
Credit Facility and Commercial Paper [Line Items] | ||||||||||
Credit facility, loans outstanding | 1,310 | $ 640 | ||||||||
Williams Partners L. P. [Member] | Subsequent Event [Member] | ||||||||||
Credit Facility and Commercial Paper [Line Items] | ||||||||||
Credit facility, loans outstanding | $ 925 | |||||||||
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 | |||||||||
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] | ||||||||||
Long-term debt | 850 | |||||||||
Variable Interest Term Loan due 2018 [Member] | Williams Partners L. P. [Member] | ||||||||||
Credit Facility and Commercial Paper [Line Items] | ||||||||||
Long-term debt | $ 850 | $ 850 | $ 0 | |||||||
[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, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Debt Disclosure [Abstract] | |||
Cash payments for interest (net of amounts capitalized) | $ 795 | $ 499 | $ 366 |
Leases-Lessee (Details)
Leases-Lessee (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract] | |||
2,016 | $ 77 | ||
2,017 | 63 | ||
2,018 | 46 | ||
2,019 | 36 | ||
2,020 | 32 | ||
Thereafter | 99 | ||
Total | 353 | ||
Operating leases [Abstract] | |||
Total rent expense | $ 157 | $ 101 | $ 51 |
Debt, Banking Arrangements, a65
Debt, Banking Arrangements, and Leases Accounting standards issued and adopted (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Accounting standards issued and adobted [Abstract] | ||
Debt issuance costs | $ 91 | $ 74 |
Partners' Capital (Details Text
Partners' Capital (Details Textuals) - USD ($) $ in Thousands | 1 Months Ended | 12 Months Ended | ||||||
Jan. 31, 2016 | Nov. 30, 2015 | Aug. 31, 2014 | Aug. 31, 2013 | Mar. 31, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Business Acquisition [Line Items] | ||||||||
Partners' Capital Account, Units, Sale of Units | 1,790,840 | 1,080,448 | 14,250,000 | |||||
Offering Costs, Partnership Interests | $ 592 | $ 554 | ||||||
Net Proceeds from Issuance of Common Limited Partners Units | $ 59,000 | $ 55,000 | $ 1,200,000 | $ 760,000 | $ 59,000 | $ 55,000 | $ 1,962,000 | |
Parent, general partner ownership percentage | 2.00% | 2.00% | 2.00% | |||||
Partners' Capital Account, Units, Sold in Public Offering | 21,500,000 | |||||||
Partners' Capital Account, Units, Sold in Private Placement | 3,000,000 | |||||||
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% | |||||||
Option on Securities [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Partners' Capital Account, Units, Sold in Public Offering | 3,225,000 | 1,687,500 | ||||||
Williams Companies Inc [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Parent, general partner ownership percentage | 2.00% | |||||||
Subsequent Event [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Partners' Capital Account, Units, Sale of Units | 18,643 | |||||||
Offering Costs, Partnership Interests | $ 4 | |||||||
Net Proceeds from Issuance of Common Limited Partners Units | $ 414 |
Partners' Capital Incentive Dis
Partners' Capital Incentive Distributions Quarterly Target Amount (Details) | 12 Months Ended |
Dec. 31, 2015$ / 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, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Williams Companies Incentive Plan [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Allocated Share-based Compensation Expense | $ 19 | $ 14 | $ 12 |
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 | $ 26 | $ 11 | |
Grants, Units | 0 | ||
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Share-based Awards Other than Options | $ 32 | ||
Estimated forfeitures under employee stock-based awards | $ 4 | ||
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition | 1 year 10 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 | 1.3 | ||
Adjustment for unit split in ACMP Merger, Units | 0.1 | ||
Forfeited, Units | (0.1) | ||
Vested, Units | (0.1) | ||
Nonvested at end of period,Units | 1.2 | 1.3 | |
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 | $ 59.35 | ||
Adjustment for unit split in ACMP Merger, Weighted Average Grant Date Fair Value | 0 | ||
Forfeited, Weighted Average Grant Date Fair Value | 58.05 | ||
Vested, Weighted Average Grant Date Fair Value | 59.28 | ||
Nonvested at end of period, Weighted Average Grant Date Fair Value | $ 55.93 | $ 59.35 | |
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, 2015 | Dec. 31, 2014 | |
Measured on a recurring basis: | |||
Unamortized debt issuance expense | $ 91 | $ 74 | |
Additional disclosures: | |||
Fair Value, Assets, Level 1 to Level 2 Transfers, Amount | 0 | 0 | |
Fair Value, Assets, Level 2 to Level 1 Transfers, Amount | 0 | 0 | |
Carrying Amount [Member] | |||
Additional disclosures: | |||
Notes receivable and other | 12 | 5 | |
Long-term debt, including current portion | [1] | (19,176) | (16,251) |
Fair Value [Member] | |||
Additional disclosures: | |||
Notes receivable and other | 12 | 4 | |
Long-term debt, including current portion | [1] | (15,988) | (16,607) |
Level 1 [Member] | |||
Additional disclosures: | |||
Notes receivable and other | 10 | 0 | |
Long-term debt, including current portion | [1] | 0 | 0 |
Level 2 [Member] | |||
Additional disclosures: | |||
Notes receivable and other | 2 | 4 | |
Long-term debt, including current portion | [1] | (15,988) | (16,607) |
Level 3 [Member] | |||
Additional disclosures: | |||
Notes receivable and other | 0 | 0 | |
Long-term debt, including current portion | [1] | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Carrying Amount [Member] | |||
Measured on a recurring basis: | |||
ARO Trust investments | 67 | 48 | |
Fair Value, Measurements, Recurring [Member] | Carrying Amount [Member] | Not Designated as Hedging Instrument [Member] | |||
Measured on a recurring basis: | |||
Energy derivative assets | 5 | 3 | |
Energy derivative liabilities | (2) | (2) | |
Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | |||
Measured on a recurring basis: | |||
ARO Trust investments | 67 | 48 | |
Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Not Designated as Hedging Instrument [Member] | |||
Measured on a recurring basis: | |||
Energy derivative assets | 5 | 3 | |
Energy derivative liabilities | (2) | (2) | |
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | |||
Measured on a recurring basis: | |||
ARO Trust investments | 67 | 48 | |
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Not Designated as Hedging Instrument [Member] | |||
Measured on a recurring basis: | |||
Energy derivative assets | 0 | 1 | |
Energy derivative 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] | Not Designated as Hedging Instrument [Member] | |||
Measured on a recurring basis: | |||
Energy derivative assets | 3 | 0 | |
Energy derivative 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] | Not Designated as Hedging Instrument [Member] | |||
Measured on a recurring basis: | |||
Energy derivative assets | 2 | 2 | |
Energy derivative liabilities | $ (2) | $ (2) | |
[1] | Excludes capital leases. The carrying value has been reduced by $91 million and $74 million of debt acquisition costs at December 31, 2015 and 2014, respectively. (See Note 13 – Debt, Banking Arrangements, and Leases.) |
Fair Value Measurements Nonrecu
Fair Value Measurements Nonrecurring Measurements (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Dec. 31, 2014 | Jun. 30, 2014 | Sep. 30, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||
Impairment of goodwill | $ 1,098 | $ 1,098 | $ 0 | $ 0 | ||||||||||
Impairment of equity-method investments | 1,359 | 0 | $ 0 | |||||||||||
Northeast G&P [Member] | ||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||
Impairment of goodwill | 646 | |||||||||||||
Access Midstream [Member] | ||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||
Impairment of goodwill | 452 | |||||||||||||
West [Member] | ||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||
Impairment of goodwill | 0 | |||||||||||||
Goodwill [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | ||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||
Impairment of goodwill | $ 1,098 | $ 0 | ||||||||||||
Goodwill [Member] | 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% | |||||||||||||
Goodwill [Member] | 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% | |||||||||||||
Goodwill [Member] | 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 Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||
Impairment of certain assets | 145 | 52 | ||||||||||||
Property, plant, and equipment, net [Member] | Fair Value, Measurements, Nonrecurring [Member] | ||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||
Impairment of certain assets | [1] | 31 | 10 | |||||||||||
Property, plant, and equipment, net [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | ||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||
Impairment of certain assets | 114 | 42 | ||||||||||||
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 | |||||||||
Impairment of certain assets | [2] | $ 20 | 13 | $ 17 | ||||||||||
Property, plant, and equipment, net [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Access Midstream [Member] | ||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||
Assets Held-for-sale, Long Lived, Fair Value Disclosure | [3] | 1 | $ 1 | |||||||||||
Impairment of Long-Lived Assets to be Disposed of | [3] | $ 12 | ||||||||||||
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 | [4] | 13 | 13 | |||||||||||
Impairment of certain assets | [4] | 94 | ||||||||||||
Investments [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | ||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||
Impairment of equity-method investments | 1,359 | |||||||||||||
Investments [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Access Midstream [Member] | ||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||
Investments, Fair Value Disclosure | 4,017 | [5] | $ 1,203 | [6] | $ 1,203 | [6] | 4,017 | [5] | ||||||
Impairment of equity-method investments | $ 890 | [5] | $ 461 | [6] | ||||||||||
Investments [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Access Midstream [Member] | Minimum [Member] | ||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||
Fair Value Inputs, Discount Rate | 10.80% | |||||||||||||
Investments [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Access Midstream [Member] | Maximum [Member] | ||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||
Fair Value Inputs, Discount Rate | 14.40% | |||||||||||||
Investments [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Delaware Basin Gas Gathering System [Member] | Access Midstream [Member] | ||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||
Fair Value Inputs, Discount Rate | 11.80% | |||||||||||||
Investments [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Appalachia Midstream Investments [Member] | Access Midstream [Member] | ||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||
Fair Value Inputs, Discount Rate | 8.80% | |||||||||||||
Investments [Member] | Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Other Investments [Member] | ||||||||||||||
Fair Value Assets Measured On Nonrecurring Basis [Abstract] | ||||||||||||||
Investments, Fair Value Disclosure | $ 58 | $ 58 | ||||||||||||
Impairment of equity-method investments | $ 8 | |||||||||||||
[1] | Reflects multiple individually insignificant impairments of other certain assets that may no longer be in use or are surplus in nature for which the fair value was determined to be zero or an insignificant salvage value. These impairment charges are recorded in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Comprehensive Income (Loss). | |||||||||||||
[2] | Reflects impairment charges for our Northeast G&P segment associated with certain surplus equipment. Certain of these assets were previously presented as held for sale, but are now considered held for use and reported in Property, plant, and equipment – net in the Consolidated Balance Sheet at December 31, 2015. The estimated fair value was determined by a market approach based on our analysis of observable inputs in the principal market. These impairment charges are recorded in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Comprehensive Income (Loss). | |||||||||||||
[3] | Reflects impairment charges for our Access Midstream segment associated with certain surplus equipment considered held for sale and reported in Other current assets in the Consolidated Balance Sheet. The estimated fair value was determined by a market approach based on our analysis of observable inputs in the principal market. These impairment charges are recorded in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Comprehensive Income (Loss). | |||||||||||||
[4] | Reflects an impairment charge within our West segment associated with previously capitalized project development costs for a gas processing plant, the completion of which is now considered remote due to unfavorable impact of low natural gas prices on customer drilling activities. These impairment charges are recorded in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Comprehensive Income (Loss). 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 and is reported in Property, plant, and equipment – net in the Consolidated Balance Sheet. | |||||||||||||
[5] | Reflects other-than-temporary impairment charges related to Access Midstream’s equity-method investments in the Delaware basin gas gathering system, certain of the Appalachia Midstream Investments, and UEOM, as well as an impairment of Northeast G&P’s Laurel Mountain investment, all reflected within Impairment of equity-method investments in the Consolidated Statement of Comprehensive Income (Loss). 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 increases in our cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses. | |||||||||||||
[6] | Reflects other-than-temporary impairment charges related to Access Midstream’s equity-method investments in the Delaware basin gas gathering system and certain of the Appalachia Midstream Investments reflected within Impairment of equity-method investments in the Consolidated Statement of Comprehensive Income (Loss). 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 ACMP Acquisition. 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 the Delaware basin gas gathering system 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. |
Fair Value Measurements Concent
Fair Value Measurements Concentration of Credit Risk (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Accounts and Notes Receivable | ||
Accounts and notes receivable, net | $ 1,026 | $ 905 |
NGLs, natural gas, and related products and services [Member] | ||
Accounts and Notes Receivable | ||
Accounts and notes receivable, net | 821 | 728 |
Transportation of natural gas and related products [Member] | ||
Accounts and Notes Receivable | ||
Accounts and notes receivable, net | 202 | 175 |
Other Receivable [Member] | ||
Accounts and Notes Receivable | ||
Accounts and notes receivable, net | 3 | 2 |
Chesapeake Energy Corporation [Member] | Customer Concentration Risk [Member] | Accounts receivable [Member] | ||
Accounts and Notes Receivable | ||
Accounts and notes receivable, net | $ 364 | $ 308 |
Chesapeake Energy Corporation [Member] | Customer Concentration Risk [Member] | Sales Revenue, Net [Member] | Access Midstream [Member] | ||
Revenues | ||
Consolidated revenue, major customer, percentage | 18.00% | 9.00% |
Chesapeake Energy Corporation [Member] | Minimum Volume Commitment [Member] | Customer Concentration Risk [Member] | Williams Partners [Member] | ||
Accounts and Notes Receivable | ||
Accounts and notes receivable, net | $ 198 |
Contingent Liabilities and Co72
Contingent Liabilities and Commitments (Details) $ in Millions | Dec. 31, 2015USD ($) |
Contingent Liabilities [Line Items] | |
Accrued environmental loss liabilities | $ 15 |
Capital Addition Purchase Commitments [Member] | |
Contingent Liabilities [Line Items] | |
Commitments For Construction And Acquisition Of Property Plant And Equipment | 617 |
Gas Pipeline [Member] | |
Contingent Liabilities [Line Items] | |
Accrued environmental loss liabilities | 8 |
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 Annual Limit of Insurance | 610 |
Insurance Deductibles | $ 2 |
Segment Disclosures Geographic
Segment Disclosures Geographic Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Revenues from External Customers and Long-Lived Assets [Line Items] | |||
Revenues from external customers | $ 7,331 | $ 7,409 | $ 6,835 |
Long-lived assets | 38,616 | 38,893 | 19,913 |
United States [Member] | |||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||
Revenues from external customers | 7,228 | 7,212 | 6,685 |
Long-lived assets | 37,586 | 37,798 | 18,776 |
Canada [Member] | |||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||
Revenues from external customers | 103 | 197 | 150 |
Long-lived assets | $ 1,030 | $ 1,095 | $ 1,137 |
Segment Disclosures Recon from
Segment Disclosures Recon from Segment to Consolidated - Revenues (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | $ 7,331 | $ 7,409 | $ 6,835 |
Other financial information: | |||
Proportional Modified EBITDA of equity-method investments | 699 | 431 | 209 |
Service [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 5,135 | 3,888 | 2,914 |
Product [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 2,196 | 3,521 | 3,921 |
Eliminations [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | (583) | (1,099) | (1,108) |
Eliminations [Member] | Service [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | (11) | (5) | (11) |
Eliminations [Member] | Product [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | (572) | (1,094) | (1,097) |
Access Midstream [Member] | Service [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 1,523 | 765 | 0 |
Access Midstream [Member] | Product [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 0 | 0 | 0 |
Access Midstream [Member] | Operating Segments [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 1,523 | 765 | 0 |
Other financial information: | |||
Proportional Modified EBITDA of equity-method investments | 338 | 178 | 0 |
Access Midstream [Member] | Operating Segments [Member] | Service [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 1,523 | 765 | 0 |
Access Midstream [Member] | Operating Segments [Member] | Product [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 0 | 0 | 0 |
Access Midstream [Member] | Eliminations [Member] | Service [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 0 | 0 | 0 |
Access Midstream [Member] | Eliminations [Member] | Product [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 0 | 0 | 0 |
Northeast G And P [Member] | Service [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 541 | 450 | 335 |
Northeast G And P [Member] | Product [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 109 | 225 | 166 |
Northeast G And P [Member] | Operating Segments [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 675 | 681 | 501 |
Other financial information: | |||
Proportional Modified EBITDA of equity-method investments | 62 | 52 | 15 |
Northeast G And P [Member] | Operating Segments [Member] | Service [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 548 | 451 | 335 |
Northeast G And P [Member] | Operating Segments [Member] | Product [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 127 | 230 | 166 |
Northeast G And P [Member] | Eliminations [Member] | Service [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | (7) | (1) | 0 |
Northeast G And P [Member] | Eliminations [Member] | Product [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | (18) | (5) | 0 |
Atlantic Gulf [Member] | Service [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 1,877 | 1,497 | 1,414 |
Atlantic Gulf [Member] | Product [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 287 | 499 | 830 |
Atlantic Gulf [Member] | Operating Segments [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 2,344 | 2,354 | 2,349 |
Other financial information: | |||
Proportional Modified EBITDA of equity-method investments | 257 | 151 | 144 |
Atlantic Gulf [Member] | Operating Segments [Member] | Service [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 1,881 | 1,501 | 1,424 |
Atlantic Gulf [Member] | Operating Segments [Member] | Product [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 463 | 853 | 925 |
Atlantic Gulf [Member] | Eliminations [Member] | Service [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | (4) | (4) | (10) |
Atlantic Gulf [Member] | Eliminations [Member] | Product [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | (176) | (354) | (95) |
West [Member] | Service [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 1,055 | 1,050 | 1,053 |
West [Member] | Product [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 36 | 70 | 64 |
West [Member] | Operating Segments [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 1,312 | 1,596 | 1,826 |
Other financial information: | |||
Proportional Modified EBITDA of equity-method investments | 0 | 0 | 0 |
West [Member] | Operating Segments [Member] | Service [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 1,055 | 1,050 | 1,054 |
West [Member] | Operating Segments [Member] | Product [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 257 | 546 | 772 |
West [Member] | Eliminations [Member] | Service [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 0 | 0 | (1) |
West [Member] | Eliminations [Member] | Product [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | (221) | (476) | (708) |
NGL And Petchem Services [Member] | Service [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 139 | 126 | 112 |
NGL And Petchem Services [Member] | Product [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 1,764 | 2,727 | 2,861 |
NGL And Petchem Services [Member] | Operating Segments [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 2,060 | 3,112 | 3,267 |
Other financial information: | |||
Proportional Modified EBITDA of equity-method investments | 42 | 50 | 50 |
NGL And Petchem Services [Member] | Operating Segments [Member] | Service [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 139 | 126 | 112 |
NGL And Petchem Services [Member] | Operating Segments [Member] | Product [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 1,921 | 2,986 | 3,155 |
NGL And Petchem Services [Member] | Eliminations [Member] | Service [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | 0 | 0 | 0 |
NGL And Petchem Services [Member] | Eliminations [Member] | Product [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Revenues | $ (157) | $ (259) | $ (294) |
Segment Disclosures Recon fro75
Segment Disclosures Recon from Segment to Consolidated - Modified EBITDA (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Reconciliation of Modified EBITDA to Net Income (Loss) | ||||
Modified EBITDA | $ 4,003 | $ 3,244 | $ 2,447 | |
Asset Retirement Obligation Accretion Expense For Nonregulated Operations | (28) | (17) | (14) | |
Depreciation and amortization expenses | (1,702) | (1,151) | (791) | |
Impairment of goodwill | $ (1,098) | (1,098) | 0 | 0 |
Equity earnings (losses) | 335 | 228 | 104 | |
Impairment of equity-method investments | (1,359) | 0 | 0 | |
Other investing income (loss) – net | 2 | 2 | (1) | |
Proportional Modified EBITDA of equity-method investments | (699) | (431) | (209) | |
Interest Expense | (811) | (562) | (387) | |
(Provision) benefit for income taxes | (1) | (29) | (30) | |
Net income (loss) | (1,358) | 1,284 | 1,119 | |
Access Midstream [Member] | ||||
Reconciliation of Modified EBITDA to Net Income (Loss) | ||||
Impairment of goodwill | (452) | |||
Northeast G&P [Member] | ||||
Reconciliation of Modified EBITDA to Net Income (Loss) | ||||
Impairment of goodwill | (646) | |||
West [Member] | ||||
Reconciliation of Modified EBITDA to Net Income (Loss) | ||||
Impairment of goodwill | 0 | |||
Operating Segments [Member] | Access Midstream [Member] | ||||
Reconciliation of Modified EBITDA to Net Income (Loss) | ||||
Modified EBITDA | 1,279 | 642 | 0 | |
Proportional Modified EBITDA of equity-method investments | (338) | (178) | 0 | |
Operating Segments [Member] | Northeast G&P [Member] | ||||
Reconciliation of Modified EBITDA to Net Income (Loss) | ||||
Modified EBITDA | 314 | 395 | 114 | |
Proportional Modified EBITDA of equity-method investments | (62) | (52) | (15) | |
Operating Segments [Member] | Atlantic-Gulf [Member] | ||||
Reconciliation of Modified EBITDA to Net Income (Loss) | ||||
Modified EBITDA | 1,523 | 1,065 | 1,013 | |
Proportional Modified EBITDA of equity-method investments | (257) | (151) | (144) | |
Operating Segments [Member] | West [Member] | ||||
Reconciliation of Modified EBITDA to Net Income (Loss) | ||||
Modified EBITDA | 557 | 823 | 924 | |
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 | 321 | 324 | 395 | |
Proportional Modified EBITDA of equity-method investments | (42) | (50) | (50) | |
Corporate, Non-Segment [Member] | ||||
Reconciliation of Modified EBITDA to Net Income (Loss) | ||||
Modified EBITDA | $ 9 | $ (5) | $ 1 |
Segment Disclosures Recon fro76
Segment Disclosures Recon from Segment to Consolidated - Assets and Invesetments (Details) - USD ($) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |||
Segment Reporting, Asset Reconciling Item [Line Items] | |||||
Total assets | $ 47,870 | $ 49,248 | |||
Investments | 7,336 | 8,399 | |||
Additions to long-lived assets | 2,960 | 20,413 | $ 3,409 | ||
Operating Segments [Member] | Access Midstream [Member] | |||||
Segment Reporting, Asset Reconciling Item [Line Items] | |||||
Total assets | 21,050 | 22,470 | |||
Investments | 5,039 | 6,004 | |||
Additions to long-lived assets | 556 | 16,964 | [1] | 0 | |
Operating Segments [Member] | Northeast G And P [Member] | |||||
Segment Reporting, Asset Reconciling Item [Line Items] | |||||
Total assets | 6,669 | 7,314 | |||
Investments | 834 | 891 | |||
Additions to long-lived assets | 367 | 1,079 | 1,376 | ||
Operating Segments [Member] | Atlantic Gulf [Member] | |||||
Segment Reporting, Asset Reconciling Item [Line Items] | |||||
Total assets | 12,171 | 11,114 | |||
Investments | 959 | 985 | |||
Additions to long-lived assets | 1,573 | 1,593 | 1,072 | ||
Operating Segments [Member] | West [Member] | |||||
Segment Reporting, Asset Reconciling Item [Line Items] | |||||
Total assets | 5,035 | 5,174 | |||
Investments | 0 | 0 | |||
Additions to long-lived assets | 225 | 168 | 210 | ||
Operating Segments [Member] | NGL And Petchem Services [Member] | |||||
Segment Reporting, Asset Reconciling Item [Line Items] | |||||
Total assets | 3,306 | 3,510 | |||
Investments | 504 | 519 | |||
Additions to long-lived assets | 236 | 601 | 746 | ||
Corporate, Non-Segment [Member] | |||||
Segment Reporting, Asset Reconciling Item [Line Items] | |||||
Total assets | 350 | 501 | |||
Investments | 0 | 0 | |||
Additions to long-lived assets | 3 | 8 | 5 | ||
Eliminations [Member] | |||||
Segment Reporting, Asset Reconciling Item [Line Items] | |||||
Total assets | [2] | (711) | (835) | ||
Investments | 0 | 0 | |||
Additions to long-lived assets | $ 0 | $ 0 | $ 0 | ||
[1] | 2014 Additions to long-lived assets within our Access Midstream segment primarily 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. |