Document and Entity Information
Document and Entity Information - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2016 | Feb. 21, 2017 | Jun. 30, 2016 | |
Document And Entity Information [Abstract] | |||
Trading Symbol | WES | ||
Entity Registrant Name | Western Gas Partners LP | ||
Entity Central Index Key | 1,414,475 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2016 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2,016 | ||
Document Fiscal Period Focus | FY | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Public Float | $ 3.9 | ||
Entity Common Units Outstanding | 130,671,970 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Revenues and Other | ||||
Total revenues and other | $ 1,804,270 | $ 1,752,072 | $ 1,533,377 | |
Equity income, net – affiliates | [1] | 78,717 | 71,251 | 57,836 |
Operating expenses | ||||
Cost of product | [2] | 494,194 | 528,369 | 458,379 |
Operation and maintenance | [2] | 308,010 | 331,972 | 293,710 |
General and administrative | [2] | 45,591 | 41,319 | 38,561 |
Property and other taxes | 40,145 | 33,288 | 28,889 | |
Depreciation and amortization | 272,933 | 272,611 | 211,809 | |
Impairments | 15,535 | 515,458 | 5,125 | |
Total operating expenses | 1,176,408 | 1,723,017 | 1,036,473 | |
Gain (loss) on divestiture and other, net | [3],[4] | (14,641) | 57,024 | (9) |
Proceeds from business interruption insurance claims | 16,270 | 0 | 0 | |
Operating income (loss) | 708,208 | 157,330 | 554,731 | |
Interest income - affiliates | [5] | 16,900 | 16,900 | 16,900 |
Interest expense | [6] | (114,921) | (113,872) | (76,766) |
Other income (expense), net | 479 | (619) | 864 | |
Income (loss) before income taxes | 610,666 | 59,739 | 495,729 | |
Income tax (benefit) expense | 8,372 | 45,532 | 39,061 | |
Net income (loss) | 602,294 | 14,207 | 456,668 | |
Net income attributable to noncontrolling interest | 10,963 | 10,101 | 14,025 | |
Net income (loss) attributable to Western Gas Partners, LP | 591,331 | 4,106 | 442,643 | |
Limited partners' interest in net income (loss): | ||||
Pre-acquisition net (income) loss allocated to Anadarko | (11,326) | (79,386) | (65,154) | |
General partner interest in net (income) loss | [7] | $ (236,561) | $ (180,996) | $ (120,980) |
Net income (loss) per common unit – basic | [8] | $ 1.74 | $ (1.95) | $ 2.13 |
Net income (loss) per common unit – diluted | [8],[9] | $ 1.74 | $ (1.95) | $ 2.12 |
Series A Preferred Units [Member] | ||||
Limited partners' interest in net income (loss): | ||||
Limited partners’ interest in net income (loss) | [7],[10] | $ (76,893) | $ 0 | $ 0 |
Common and Class C Units [Member] | ||||
Limited partners' interest in net income (loss): | ||||
Limited partners’ interest in net income (loss) | [7] | (266,551) | 256,276 | (256,509) |
Affiliates [Member] | ||||
Revenues and Other | ||||
Gathering, processing and transportation | 750,087 | 772,361 | 615,907 | |
Natural gas and natural gas liquids sales | 478,145 | 447,106 | 582,989 | |
Other | 0 | 1,172 | 5,078 | |
Total revenues and other | [1] | 1,228,232 | 1,220,639 | 1,203,974 |
Operating expenses | ||||
Cost of product | [1] | 80,455 | 167,354 | 127,930 |
Operation and maintenance | [11] | 72,330 | 77,061 | 71,386 |
General and administrative | [12] | 38,066 | 33,903 | 31,308 |
Total operating expenses | 190,851 | 278,318 | 230,624 | |
Interest expense | [13] | 7,747 | (14,398) | 0 |
Third Parties [Member] | ||||
Revenues and Other | ||||
Gathering, processing and transportation | 477,762 | 356,477 | 278,127 | |
Natural gas and natural gas liquids sales | 94,168 | 170,843 | 42,916 | |
Other | 4,108 | 4,113 | 8,360 | |
Total revenues and other | 576,038 | 531,433 | 329,403 | |
Operating expenses | ||||
Interest expense | $ (122,668) | $ (99,474) | $ (76,766) | |
[1] | Represents amounts earned or incurred on and subsequent to the date of acquisition of the Partnership assets, as well as amounts earned or incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets, recognized under gathering, treating or processing agreements, and purchase and sale agreements. | |||
[2] | Cost of product includes product purchases from Anadarko (as defined in Note 1) of $80.5 million, $167.4 million and $127.9 million for the years ended December 31, 2016, 2015 and 2014, respectively. Operation and maintenance includes charges from Anadarko of $72.3 million, $77.1 million and $71.4 million for the years ended December 31, 2016, 2015 and 2014, respectively. General and administrative includes charges from Anadarko of $38.1 million, $33.9 million and $31.3 million for the years ended December 31, 2016, 2015 and 2014, respectively. See Note 5. | |||
[3] | Includes losses related to an incident at the DBM complex for the year ended December 31, 2015. See Note 1. | |||
[4] | Includes losses related to an incident at the DBM complex for the year ended December 31, 2015. See Note 1. | |||
[5] | Represents interest income recognized on the note receivable from Anadarko. | |||
[6] | Includes affiliate (as defined in Note 1) amounts of $7.7 million, $(14.4) million and zero for the years ended December 31, 2016, 2015 and 2014, respectively. See Note 2 and Note 12. | |||
[7] | Represents net income (loss) earned on and subsequent to the date of acquisition of the Partnership assets (as defined in Note 1). See Note 4. | |||
[8] | See Note 4 for the calculation of net income (loss) per common unit. | |||
[9] | The impact of Class C units and the conversion of Series A Preferred units would be anti-dilutive for the year ended December 31, 2016, and the impact of Class C units would be anti-dilutive for the year ended December 31, 2015. | |||
[10] | Adjusted to reflect amortization of the beneficial conversion features. | |||
[11] | Represents expenses incurred on and subsequent to the date of the acquisition of the Partnership assets, as well as expenses incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets. | |||
[12] | Represents general and administrative expense incurred on and subsequent to the date of the Partnership’s acquisition of the Partnership assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of the Partnership assets by the Partnership. These amounts include equity-based compensation expense allocated to the Partnership by Anadarko (see WES LTIP and WGP LTIP and Anadarko Incentive Plans within this Note 5) and amounts charged by Anadarko under the omnibus agreement. | |||
[13] | For the years ended December 31, 2016 and 2015, includes amounts related to the Deferred purchase price obligation - Anadarko (see Note 2 and Note 12). |
Consolidated Statements of Ope3
Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Cost of product | [1] | $ 494,194 | $ 528,369 | $ 458,379 |
Operation and maintenance | [1] | 308,010 | 331,972 | 293,710 |
General and administrative | [1] | 45,591 | 41,319 | 38,561 |
Interest expense | [2] | 114,921 | 113,872 | 76,766 |
Affiliates [Member] | ||||
Cost of product | [3] | 80,455 | 167,354 | 127,930 |
Operation and maintenance | [4] | 72,330 | 77,061 | 71,386 |
General and administrative | [5] | 38,066 | 33,903 | 31,308 |
Interest expense | [6] | $ (7,747) | $ 14,398 | $ 0 |
[1] | Cost of product includes product purchases from Anadarko (as defined in Note 1) of $80.5 million, $167.4 million and $127.9 million for the years ended December 31, 2016, 2015 and 2014, respectively. Operation and maintenance includes charges from Anadarko of $72.3 million, $77.1 million and $71.4 million for the years ended December 31, 2016, 2015 and 2014, respectively. General and administrative includes charges from Anadarko of $38.1 million, $33.9 million and $31.3 million for the years ended December 31, 2016, 2015 and 2014, respectively. See Note 5. | |||
[2] | Includes affiliate (as defined in Note 1) amounts of $7.7 million, $(14.4) million and zero for the years ended December 31, 2016, 2015 and 2014, respectively. See Note 2 and Note 12. | |||
[3] | Represents amounts earned or incurred on and subsequent to the date of acquisition of the Partnership assets, as well as amounts earned or incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets, recognized under gathering, treating or processing agreements, and purchase and sale agreements. | |||
[4] | Represents expenses incurred on and subsequent to the date of the acquisition of the Partnership assets, as well as expenses incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets. | |||
[5] | Represents general and administrative expense incurred on and subsequent to the date of the Partnership’s acquisition of the Partnership assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of the Partnership assets by the Partnership. These amounts include equity-based compensation expense allocated to the Partnership by Anadarko (see WES LTIP and WGP LTIP and Anadarko Incentive Plans within this Note 5) and amounts charged by Anadarko under the omnibus agreement. | |||
[6] | For the years ended December 31, 2016 and 2015, includes amounts related to the Deferred purchase price obligation - Anadarko (see Note 2 and Note 12). |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | |
Current assets | |||
Cash and cash equivalents | $ 357,925 | $ 98,033 | |
Accounts receivable, net | [1] | 223,223 | 193,329 |
Other current assets | 12,866 | 7,855 | |
Total current assets | 594,014 | 299,217 | |
Note receivable - Anadarko | 260,000 | 260,000 | |
Property, plant and equipment | |||
Cost | 6,861,942 | 6,556,778 | |
Less accumulated depreciation | 1,812,010 | 1,697,999 | |
Net property, plant and equipment | 5,049,932 | 4,858,779 | |
Goodwill | 417,610 | 419,186 | |
Other intangible assets | 803,698 | 832,127 | |
Equity investments | 594,208 | 618,887 | |
Other assets | 13,566 | 13,001 | |
Total assets | 7,733,028 | 7,301,197 | |
Current liabilities | |||
Accounts and imbalance payables | 123,285 | 98,661 | |
Accrued ad valorem taxes | 23,121 | 17,808 | |
Accrued liabilities | 168,899 | 119,019 | |
Total current liabilities | 315,305 | 235,488 | |
Long-term debt | 3,091,461 | 2,690,651 | |
Deferred income taxes | 6,402 | 139,704 | |
Asset retirement obligations and other | 142,641 | 128,652 | |
Deferred purchase price obligation - Anadarko | [2] | 41,440 | 188,674 |
Total long-term liabilities | 3,281,944 | 3,147,681 | |
Total liabilities | 3,597,249 | 3,383,169 | |
Equity and partners' capital | |||
General partner units (2,583,068 units issued and outstanding at December 31, 2016 and 2015) | 143,968 | 120,164 | |
Net investment by Anadarko | 0 | 430,598 | |
Total partners' capital | 4,071,216 | 3,850,644 | |
Noncontrolling interest | 64,563 | 67,384 | |
Total equity and partners' capital | 4,135,779 | 3,918,028 | |
Total liabilities, equity and partners' capital | 7,733,028 | 7,301,197 | |
Series A Preferred Units [Member] | |||
Equity and partners' capital | |||
Series A Preferred units, Common units and Class C Units | [3] | 639,545 | 0 |
Common Units [Member] | |||
Equity and partners' capital | |||
Series A Preferred units, Common units and Class C Units | 2,536,872 | 2,588,991 | |
Class C Units [Member] | |||
Equity and partners' capital | |||
Series A Preferred units, Common units and Class C Units | [4] | $ 750,831 | $ 710,891 |
[1] | Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $76.6 million and $42.7 million as of December 31, 2016 and 2015, respectively. Accounts receivable, net as of December 31, 2016 and 2015, also includes an insurance claim receivable related to an incident at the DBM complex. See Note 1. | ||
[2] | See Note 2. | ||
[3] | The Series A Preferred units are convertible into common units at the holder’s election on a one-for-one basis at any time after the second anniversary of the issuance date. See Note 4. | ||
[4] | The Class C units will convert into common units on a one-for-one basis on December 31, 2017, unless the Partnership elects to convert such units earlier or Anadarko extends the conversion date. See Note 4. |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | |
General partner units issued | 2,583,068 | 2,583,068 | |
General partner units outstanding | 2,583,068 | 2,583,068 | |
Accounts receivable, net | [1] | $ 223,223 | $ 193,329 |
Affiliates [Member] | |||
Accounts receivable, net | $ 76,600 | $ 42,700 | |
Series A Preferred Units [Member] | |||
Units issued | 21,922,831 | 0 | |
Units outstanding | 21,922,831 | 0 | |
Common Units [Member] | |||
Units issued | 130,671,970 | 128,576,965 | |
Units outstanding | 130,671,970 | 128,576,965 | |
Class C Units [Member] | |||
Units issued | 12,358,123 | 11,411,862 | |
Units outstanding | 12,358,123 | 11,411,862 | |
[1] | Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $76.6 million and $42.7 million as of December 31, 2016 and 2015, respectively. Accounts receivable, net as of December 31, 2016 and 2015, also includes an insurance claim receivable related to an incident at the DBM complex. See Note 1. |
Consolidated Statements of Equi
Consolidated Statements of Equity and Partners' Capital - USD ($) $ in Thousands | Total | Net Investment by Anadarko [Member] | Common Units [Member] | Class C Units [Member] | Series A Preferred Units [Member] | General Partner Units [Member] | Noncontrolling Interest [Member] | |
Balance at Dec. 31, 2013 | $ 3,422,675 | $ 842,731 | $ 2,431,193 | $ 0 | $ 0 | $ 78,157 | $ 70,594 | |
Net income (loss) | 456,668 | 65,154 | 254,737 | 1,772 | 120,980 | 14,025 | ||
Issuance of common and general partner units, net of offering expenses | 704,728 | 691,417 | 13,311 | |||||
Issuance of Class C and Series A Preferred units | 750,000 | 750,000 | ||||||
Beneficial conversion feature of Class C and Series A Preferred units | 0 | 34,815 | (34,815) | |||||
Distributions to noncontrolling interest owner | (15,149) | (15,149) | ||||||
Distributions to unitholders | (408,621) | (302,049) | (106,572) | |||||
Acquisitions from affiliates | (356,250) | (372,784) | 16,534 | |||||
Contributions of equity-based compensation from Anadarko | 3,167 | 3,104 | 63 | |||||
Net pre-acquisition contributions from (distributions to) Anadarko | [1] | (16,692) | (16,692) | |||||
Net distributions to Anadarko of other assets | (10,706) | (10,492) | (214) | |||||
Elimination of net deferred tax liabilities | 38,160 | 38,160 | ||||||
Other | 482 | 27 | 455 | |||||
Balance at Dec. 31, 2014 | 4,568,462 | 556,596 | 3,119,714 | 716,957 | 0 | 105,725 | 69,470 | |
Net income (loss) | 14,207 | 79,386 | (238,166) | (18,110) | 180,996 | 10,101 | ||
Above-market component of swap extensions with Anadarko | [2] | 18,449 | 18,449 | |||||
Issuance of common and general partner units, net of offering expenses | 57,353 | 57,353 | ||||||
Amortization of beneficial conversion feature of Class C units and Series A Preferred units | 0 | (12,044) | 12,044 | |||||
Distributions to noncontrolling interest owner | (12,187) | (12,187) | ||||||
Distributions to unitholders | (545,143) | (378,602) | (166,541) | |||||
Acquisitions from affiliates | (174,276) | (197,562) | 23,286 | |||||
Contributions of equity-based compensation from Anadarko | 3,551 | 3,480 | 71 | |||||
Net pre-acquisition contributions from (distributions to) Anadarko | (49,801) | (49,801) | ||||||
Net distributions to Anadarko of other assets | (4,632) | (4,547) | (85) | |||||
Elimination of net deferred tax liabilities | 41,844 | 41,844 | ||||||
Other | 201 | 135 | 68 | (2) | ||||
Balance at Dec. 31, 2015 | 3,918,028 | 430,598 | 2,588,991 | 710,891 | 0 | 120,164 | 67,384 | |
Net income (loss) | 602,294 | 11,326 | 269,018 | 28,642 | 45,784 | 236,561 | 10,963 | |
Above-market component of swap extensions with Anadarko | [2] | 45,820 | 45,820 | |||||
Issuance of common and general partner units, net of offering expenses | 25,000 | 25,000 | ||||||
Issuance of Class C and Series A Preferred units | 686,937 | 686,937 | ||||||
Beneficial conversion feature of Class C and Series A Preferred units | 0 | 93,409 | (93,409) | |||||
Amortization of beneficial conversion feature of Class C units and Series A Preferred units | 0 | (42,407) | 11,298 | 31,109 | ||||
Distributions to noncontrolling interest owner | (13,784) | (13,784) | ||||||
Distributions to unitholders | (671,938) | (428,231) | (30,876) | (212,831) | ||||
Acquisitions from affiliates | (712,500) | (553,833) | (158,667) | |||||
Revision to Deferred purchase price obligation – Anadarko | [3] | 139,487 | 139,487 | |||||
Contributions of equity-based compensation from Anadarko | 4,214 | 4,131 | 83 | |||||
Net pre-acquisition contributions from (distributions to) Anadarko | (23,491) | (23,491) | ||||||
Net distributions to Anadarko of other assets | (581) | (572) | (9) | |||||
Elimination of net deferred tax liabilities | 135,400 | 135,400 | ||||||
Other | 893 | 893 | ||||||
Balance at Dec. 31, 2016 | $ 4,135,779 | $ 0 | $ 2,536,872 | $ 750,831 | $ 639,545 | $ 143,968 | $ 64,563 | |
[1] | Includes deferred taxes on capitalized interest of $0.3 million associated with the acquisition of the TEFR Interests (as defined and described in Note 1). | |||||||
[2] | See Note 5. | |||||||
[3] | See Note 2. |
Consolidated Statements of Equ7
Consolidated Statements of Equity and Partners' Capital (Parenthetical) $ in Thousands | 12 Months Ended |
Dec. 31, 2014USD ($) | |
Deferred taxes on capitalized interest | $ (38,160) |
Net Investment by Anadarko [Member] | |
Deferred taxes on capitalized interest | (38,160) |
Net Investment by Anadarko [Member] | Capitalized Interest [Member] | |
Deferred taxes on capitalized interest | $ 300 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | |||||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||||
Cash flows from operating activities | ||||||
Net income (loss) | $ 602,294 | $ 14,207 | $ 456,668 | |||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||
Depreciation and amortization | 272,933 | 272,611 | 211,809 | |||
Impairments | 15,535 | 515,458 | 5,125 | |||
Non-cash equity-based compensation expense | 4,735 | 4,188 | 3,920 | |||
Deferred income taxes | 2,555 | 11,346 | 38,682 | |||
Accretion and amortization of long-term obligations, net | (3,789) | 17,698 | 2,736 | |||
Equity income, net – affiliates | [1] | (78,717) | (71,251) | (57,836) | ||
Distributions from equity investment earnings – affiliates | 82,185 | 82,054 | 62,967 | |||
(Gain) loss on divestiture and other, net | [2],[3] | 14,641 | (57,024) | 9 | ||
Lower of cost or market inventory adjustments | 168 | 443 | 0 | |||
Changes in assets and liabilities: | ||||||
(Increase) decrease in accounts receivable, net | (48,947) | (4,371) | 1,399 | |||
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net | 58,359 | 1,006 | (34,980) | |||
Change in other items, net | (4,367) | (720) | 3,996 | |||
Net cash provided by operating activities | 917,585 | 785,645 | 694,495 | |||
Cash flows from investing activities | ||||||
Capital expenditures | (479,993) | (637,964) | (805,005) | |||
Investments in equity affiliates | (27) | (11,442) | (64,278) | |||
Distributions from equity investments in excess of cumulative earnings – affiliates | 21,238 | [4] | 16,244 | [4] | 18,055 | |
Proceeds from property insurance claims | 17,465 | 0 | 0 | |||
Net cash used in investing activities | (1,105,534) | (500,277) | (2,740,175) | |||
Cash flows from financing activities | ||||||
Borrowings, net of debt issuance costs | 1,297,218 | 889,606 | 1,646,878 | |||
Repayments of debt | (900,000) | (610,000) | (650,000) | |||
Increase (decrease) in outstanding checks | 2,079 | (2,666) | 765 | |||
Proceeds from the issuance of common and general partner units, net of offering expenses | 25,000 | 57,353 | 704,489 | |||
Distributions to unitholders | [5] | (671,938) | (545,143) | (408,621) | ||
Distributions to noncontrolling interest owner | (13,784) | (12,187) | (15,149) | |||
Net contributions from (distributions to) Anadarko | (23,491) | (49,801) | (16,392) | |||
Above-market component of swap extensions with Anadarko | [5] | 45,820 | 18,449 | 0 | ||
Net cash provided by (used in) financing activities | 447,841 | (254,389) | 2,011,970 | |||
Net increase (decrease) in cash and cash equivalents | 259,892 | 30,979 | (33,710) | |||
Cash and cash equivalents at beginning of period | 98,033 | 67,054 | 100,764 | |||
Cash and cash equivalents at end of period | 357,925 | 98,033 | 67,054 | |||
Supplemental disclosures | ||||||
Net distributions to (contributions from) Anadarko of other assets | 581 | 4,632 | 10,706 | |||
Interest paid, net of capitalized interest | 106,485 | 94,720 | 67,648 | |||
Taxes paid (reimbursements received) | 838 | 0 | (90) | |||
Capital lease asset transfer | [6] | 0 | 0 | 4,833 | ||
Delaware Basin JV Gathering LLC [Member] | ||||||
Supplemental disclosures | ||||||
Acquisition of DBJV from Anadarko | (147,234) | 174,276 | 0 | |||
Class C Units [Member] | ||||||
Cash flows from financing activities | ||||||
Proceeds from the issuance of Class C and Series A Preferred units | 0 | 0 | 750,000 | |||
Series A Preferred Units [Member] | ||||||
Cash flows from financing activities | ||||||
Proceeds from the issuance of Class C and Series A Preferred units | 686,937 | 0 | 0 | |||
Affiliates [Member] | ||||||
Cash flows from investing activities | ||||||
Contributions in aid of construction costs from affiliates | 6,135 | 461 | 183 | |||
Acquisitions | (716,465) | (10,903) | (379,193) | |||
Proceeds from the sale of assets | 623 | 925 | 402 | |||
Cash flows from financing activities | ||||||
Proceeds from the issuance of common and general partner units, net of offering expenses | [7] | 25,000 | 0 | 0 | ||
Distributions to unitholders | [8] | (382,711) | (314,200) | (234,024) | ||
Third Parties [Member] | ||||||
Cash flows from investing activities | ||||||
Acquisitions | 0 | (3,514) | (1,523,327) | |||
Proceeds from the sale of assets | $ 45,490 | $ 145,916 | $ 12,988 | |||
[1] | Represents amounts earned or incurred on and subsequent to the date of acquisition of the Partnership assets, as well as amounts earned or incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets, recognized under gathering, treating or processing agreements, and purchase and sale agreements. | |||||
[2] | Includes losses related to an incident at the DBM complex for the year ended December 31, 2015. See Note 1. | |||||
[3] | Includes losses related to an incident at the DBM complex for the year ended December 31, 2015. See Note 1. | |||||
[4] | Distributions in excess of cumulative earnings, classified as investing cash flows in the consolidated statements of cash flows, is calculated on an individual investment basis. | |||||
[5] | See Note 5. | |||||
[6] | For the year ended December 31, 2014, represents transfers of $4.6 million from other long-term assets associated with the capital lease component of a processing agreement | |||||
[7] | Represents proceeds from the issuance of 835,841 common units to WGP as partial funding for the acquisition of Springfield (see Note 2). | |||||
[8] | Represents distributions paid under the partnership agreement (see Note 3 and Note 4). |
Consolidated Statements of Cas9
Consolidated Statements of Cash Flows (Parenthetical) $ in Thousands | Dec. 31, 2014USD ($) |
Natural Gas Processing Plant [Member] | |
Property, plant and equipment | $ 4,600 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | General. Western Gas Partners, LP is a growth-oriented Delaware master limited partnership (“MLP”) formed by Anadarko Petroleum Corporation in 2007 to acquire, own, develop and operate midstream energy assets. For purposes of these consolidated financial statements, the “Partnership” refers to Western Gas Partners, LP and its subsidiaries. The Partnership’s general partner, Western Gas Holdings, LLC (the “general partner”), is owned by Western Gas Equity Partners, LP (“WGP”), a Delaware MLP formed by Anadarko Petroleum Corporation in September 2012 to own the Partnership’s general partner, as well as a significant limited partner interest in the Partnership. WGP has no independent operations or material assets other than owning the partnership interests in WES (see Holdings of Partnership equity in Note 4 ). Western Gas Equity Holdings, LLC is WGP’s general partner and is a wholly owned subsidiary of Anadarko Petroleum Corporation. “Anadarko” refers to Anadarko Petroleum Corporation and its subsidiaries, excluding the Partnership and the general partner, and “affiliates” refers to subsidiaries of Anadarko, excluding the Partnership, but including equity interests in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”), Rendezvous Gas Services, LLC (“Rendezvous”), Enterprise EF78 LLC (the “Mont Belvieu JV”), Texas Express Pipeline LLC (“TEP”), Texas Express Gathering LLC (“TEG”) and Front Range Pipeline LLC (“FRP”). The interests in TEP, TEG and FRP are referred to collectively as the “TEFR Interests.” “MGR assets” refers to the Red Desert complex and the Granger straddle plant. The Partnership is engaged in the business of gathering, compressing, treating, processing and transporting of natural gas, and gathering, stabilizing and transporting condensate, NGLs and crude oil. The Partnership is also currently constructing two produced-water disposal systems in West Texas, which are expected to be placed in service during the second quarter of 2017. The Partnership provides these midstream services for Anadarko, as well as for third-party producers and customers. As of December 31, 2016 , the Partnership’s assets and investments consisted of the following (see Note 14 for information regarding events occurring subsequent to December 31, 2016): Owned and Operated Operated Interests Non-Operated Interests Equity Interests Gathering systems 11 4 5 2 Treating facilities 12 12 — 3 Natural gas processing plants/trains 20 5 — 2 NGL pipelines 2 — — 3 Natural gas pipelines 5 — — — Oil pipelines — 1 — 1 These assets and investments are located in the Rocky Mountains (Colorado, Utah and Wyoming), North-central Pennsylvania and Texas. The Partnership commenced operation of Train IV in May 2016 and Train V in October 2016, both of which are processing plants at the DBM complex. 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) Basis of presentation. The following table outlines the Partnership’s ownership interests and the accounting method of consolidation used in the Partnership’s consolidated financial statements: Percentage Interest Equity investments (1) Fort Union 14.81 % White Cliffs 10 % Rendezvous 22 % Mont Belvieu JV 25 % TEP 20 % TEG 20 % FRP 33.33 % Proportionate consolidation (2) Non-Operated Marcellus Interest systems 33.75 % Anadarko-Operated Marcellus Interest systems 33.75 % Newcastle system 50 % DBJV system 50 % Springfield system 50.1 % Full consolidation Chipeta (3) 75 % (1) Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. “Equity investment throughput” refers to the Partnership’s share of average throughput for these investments. (2) The Partnership proportionately consolidates its associated share of the assets, liabilities, revenues and expenses attributable to these assets. (3) The 25% interest in Chipeta Processing LLC (“Chipeta”) held by a third-party member is reflected within noncontrolling interest in the consolidated financial statements. The consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”). The consolidated financial statements include the accounts of the Partnership and entities in which it holds a controlling financial interest. All significant intercompany transactions have been eliminated. Presentation of Partnership assets. The term “Partnership assets” refers to the assets owned and interests accounted for under the equity method (see Note 9 ) by the Partnership as of December 31, 2016 . Because Anadarko controls the Partnership through its ownership and control of WGP, which owns the Partnership’s entire general partner interest, each acquisition of Partnership assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by the Partnership. Further, after an acquisition of Partnership assets from Anadarko, the Partnership may be required to recast its financial statements to include the activities of such Partnership assets from the date of common control. See Note 2 . For those periods requiring recast, the consolidated financial statements for periods prior to the Partnership’s acquisition of the Partnership assets from Anadarko have been prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the Partnership assets during the periods reported. Net income (loss) attributable to the Partnership assets acquired from Anadarko for periods prior to the Partnership’s acquisition of the Partnership assets is not allocated to the limited partners. 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) Use of estimates. In preparing financial statements in accordance with GAAP, management makes informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. Management evaluates its estimates and related assumptions regularly, using historical experience and other methods considered reasonable. Changes in facts and circumstances or additional information may result in revised estimates and actual results may differ from these estimates. Effects on the business, financial condition and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revisions become known. The information furnished herein reflects all normal recurring adjustments which are, in the opinion of management, necessary for a fair presentation of the consolidated financial statements, and certain prior-period amounts have been reclassified to conform to the current-year presentation. Fair value. The fair-value-measurement standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which they are observable. The three levels of the fair value hierarchy are as follows: Level 1 – Inputs represent unadjusted quoted prices in active markets for identical assets or liabilities. Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs). Level 3 – Inputs that are not observable from objective sources, such as management’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in management’s internally developed present value of future cash flows model that underlies the fair value measurement). When a fair value measurement is required and there is not a market-observable price for the asset or liability or a market-observable price for a similar asset or liability, the cost, income, or market valuation approach is used, depending on the quality of information available to support management’s assumptions. The cost approach is based on management’s best estimate of the current asset replacement cost. The income approach uses management’s best assumptions regarding expectations of projected cash flows, and discounts the expected cash flows using a commensurate risk adjusted discount rate. Such evaluations involve a significant amount of judgment, since the results are based on expected future events or conditions, such as sales prices, estimates of future throughput, capital and operating costs and the timing thereof, economic and regulatory climates and other factors. A multiple approach uses management’s best assumptions regarding expectations of projected earnings before interest, taxes, depreciation, and amortization (“EBITDA”) and the multiple of that EBITDA that a buyer would pay to acquire an asset. Management’s estimates of future net cash flows and EBITDA are inherently imprecise because they reflect management’s expectation of future conditions that are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs and other factors, and are consistent with assumptions used in the Partnership’s business plans and investment decisions. Nonfinancial assets and liabilities initially measured at fair value include certain assets and liabilities acquired in a third-party business combination, assets and liabilities exchanged in non-monetary transactions, long-lived assets (asset groups), goodwill and other intangibles, initial recognition of asset retirement obligations, and initial recognition of environmental obligations assumed in a third-party acquisition. Impairment analyses for long-lived assets, goodwill and other intangibles, and the initial recognition of asset retirement obligations and environmental obligations use Level 3 inputs. The fair value of debt reflects any premium or discount for the difference between the stated interest rate and the quarter-end market interest rate, and is based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments. See Note 12 . The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable reported on the consolidated balance sheets approximate fair value due to the short-term nature of these items. 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) Cash equivalents. All highly liquid investments with a maturity of three months or less when purchased are considered to be cash equivalents. Bad-debt reserve. Revenues are primarily from Anadarko, for which no credit limit is maintained. Exposure to bad debts is analyzed on a customer-by-customer basis for its third-party accounts receivable and the Partnership may establish credit limits for significant third-party customers. As of December 31, 2016 and 2015 , bad-debt reserve was immaterial. Imbalances. The consolidated balance sheets include imbalance receivables and payables resulting from differences in volumes received into the Partnership’s systems and volumes delivered by the Partnership to customers’ pipelines. Volumes owed to or by the Partnership that are subject to monthly cash settlement are valued according to the terms of the contract as of the balance sheet dates and reflect market index prices. Other volumes owed to or by the Partnership are valued at the Partnership’s weighted-average cost as of the balance sheet dates and are settled in-kind. As of December 31, 2016 , imbalance receivables and payables were $3.5 million and $3.0 million , respectively. As of December 31, 2015 , imbalance receivables and payables were $2.1 million and $1.6 million , respectively. Net changes in imbalance payables and receivables are reported in cost of product. Inventory. The cost of NGLs inventories is determined by the weighted-average cost method on a location-by-location basis. Inventory is stated at the lower of weighted-average cost or market value and is reported in other current assets in the consolidated balance sheets. See Note 10 . Property, plant and equipment. Property, plant and equipment are generally stated at the lower of historical cost less accumulated depreciation or fair value, if impaired. Because acquisitions of assets from Anadarko are transfers of net assets between entities under common control, the assets acquired from Anadarko are initially recorded at Anadarko’s historic carrying value. The difference between the carrying value of net assets acquired from Anadarko and the consideration paid is recorded as an adjustment to partners’ capital. Assets acquired in a business combination or non-monetary exchange with a third party are initially recorded at fair value. All construction-related direct labor and material costs are capitalized. The cost of renewals and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects that do not extend the useful life or increase the expected output of property, plant and equipment is expensed as incurred. Depreciation is computed using the straight-line method based on estimated useful lives and salvage values of assets. However, subsequent events could cause a change in estimates, thereby impacting future depreciation amounts. Uncertainties that may impact these estimates include, but are not limited to, changes in laws and regulations relating to environmental matters, including air and water quality, restoration and abandonment requirements, economic conditions, and supply and demand in the area. Management evaluates the ability to recover the carrying amount of its long-lived assets to determine whether its long-lived assets have been impaired. Impairments exist when the carrying amount of an asset exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the long-lived asset is not recoverable based on the estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying amount over its estimated fair value, such that the asset’s carrying amount is adjusted to its estimated fair value with an offsetting charge to impairment expense. Refer to Note 7 for a description of impairments recorded during the years ended December 31, 2016 , 2015 and 2014 . 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) Insurance recoveries. Involuntary conversions result from the loss of an asset because of some unforeseen event (e.g., destruction due to fire). Some of these events are insurable and result in property damage insurance recovery. Amounts that are received from insurance carriers are net of any deductibles related to the covered event. A receivable is recorded from insurance to the extent a loss is recognized from an involuntary conversion event and the likelihood of recovering such loss is deemed probable. To the extent that any insurance claim receivables are later judged not probable of recovery (e.g., due to new information), such amounts are expensed. A gain on involuntary conversion is recognized when the amount received from insurance exceeds the net book value of the retired asset(s). In addition, gains related to insurance recoveries are not recognized until all contingencies related to such proceeds have been resolved, that is, a cash payment is received from the insurance carrier or there is a binding settlement agreement with the carrier that clearly states that a payment will be made. To the extent that an asset is rebuilt, the associated expenditures are capitalized, as appropriate, in the consolidated balance sheets and presented as capital expenditures in the consolidated statements of cash flows. With respect to business interruption insurance claims, income is recognized only when cash proceeds are received from insurers, which are presented in the consolidated statements of operations as a component of Operating income (loss). On December 3, 2015, there was an initial fire and secondary explosion at the processing facility within the DBM complex. The majority of the damage from the incident was to the liquid handling facilities and the amine treating units at the inlet of the complex. Train II (with capacity of 100 MMcf/d) sustained the most damage of the processing trains and returned to service in December 2016. Train III (with capacity of 200 MMcf/d) experienced minimal damage and returned to full service in May 2016. For the year ended December 31, 2015, $20.3 million of losses were recorded in Gain (loss) on divestiture and other, net in the consolidated statements of operations, related to this involuntary conversion event based on the difference between the net book value of the affected assets and the insurance claim receivable. As of December 31, 2016 and 2015 , the consolidated balance sheets include receivables of $30.0 million and $49.0 million , respectively, for a property insurance claim related to the incident at the DBM complex. As of December 31, 2016 , the Partnership had received $33.8 million in cash proceeds from insurers related to the incident at the DBM complex, including $16.3 million in proceeds from business interruption insurance claims and $17.5 million in proceeds from property insurance claims. Contributions in aid of construction costs from affiliates. On certain of the Partnership’s capital projects, Anadarko is obligated to reimburse the Partnership for all or a portion of project capital expenditures. The majority of such arrangements are associated with projects related to pipeline construction activities and production well tie-ins. The cash receipts resulting from such reimbursements are presented as “Contributions in aid of construction costs from affiliates” within the investing section of the Partnership’s consolidated statements of cash flows. See Note 5 . Capitalized interest. Interest is capitalized as part of the historical cost of constructing assets for significant projects that are in progress. Capitalized interest is determined by multiplying the Partnership’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once the construction of an asset subject to interest capitalization is completed and the asset is placed in service, the associated capitalized interest is expensed through depreciation or impairment, together with other capitalized costs related to that asset. 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) Goodwill. Goodwill is recorded when the purchase price of a business acquired exceeds the fair market value of the tangible and separately measurable intangible net assets. Refer to Note 8 for a discussion of goodwill. Goodwill is evaluated for impairment annually, as of October 1, or more often as facts and circumstances warrant. The Partnership has allocated goodwill on its two reporting units: (i) gathering and processing and (ii) transportation. An initial qualitative assessment is performed prior to proceeding to the comparison of the fair value of each reporting unit to which goodwill has been assigned, to the carrying amount of net assets, including goodwill, of each reporting unit. If concluded, based on qualitative factors, that it is more likely than not that the fair value of the reporting unit exceeds its carrying amount, then goodwill is not impaired, and estimating the fair value of the reporting unit is not necessary. If the carrying amount of the reporting unit exceeds its fair value, based on a hypothetical purchase price allocation, goodwill is written down to its implied fair value through a charge to operating expense. The carrying value of goodwill after such an impairment would represent a Level 3 fair value measurement. Other intangible assets. The Partnership assesses intangible assets, as described in Note 8 , for impairment together with related underlying long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. See Property, plant and equipment within this Note 1 for further discussion of management’s process to evaluate potential impairment of long-lived assets. Asset retirement obligations. Management recognizes a liability based on the estimated costs of retiring tangible long-lived assets. The liability is recognized at fair value, measured using discounted expected future cash outflows for the asset retirement obligation when the obligation originates, which generally is when an asset is acquired or constructed. The carrying amount of the associated asset is increased commensurate with the liability recognized. Over time, the discounted liability is adjusted to its expected settlement value through accretion expense, which is reported within depreciation and amortization in the consolidated statements of operations. Subsequent to the initial recognition, the liability is also adjusted for any changes in the expected value of the retirement obligation (with a corresponding adjustment to property, plant and equipment) until the obligation is settled. Revisions in estimated asset retirement obligations may result from changes in estimated inflation rates, discount rates, asset retirement costs and the estimated timing of settling asset retirement obligations. See Note 11 . Environmental expenditures. The Partnership expenses environmental obligations related to conditions caused by past operations that do not generate current or future revenues. Environmental obligations related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Liabilities are recorded when the necessity for environmental remediation or other potential environmental liabilities becomes probable and the costs can be reasonably estimated. Accruals for estimated losses from environmental remediation obligations are recognized no later than at the time of the completion of the remediation feasibility study. These accruals are adjusted as additional information becomes available or as circumstances change. Costs of future expenditures for environmental-remediation obligations are not discounted to their present value. See Note 13 . Segments. The Partnership’s operations are organized into a single operating segment, the assets of which gather, process, compress, treat and transport Anadarko’s and third-parties’ natural gas, condensate, NGLs and crude oil in the United States. 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) Revenues and cost of product. Under its fee-based gathering, treating and processing arrangements, the Partnership is paid a fixed fee based on the volume and thermal content of natural gas and recognizes revenues for its services in the month such services are performed. Producers’ wells are connected to the Partnership’s gathering systems for delivery of natural gas to the Partnership’s processing or treating plants, where the natural gas is processed to extract NGLs and condensate or treated in order to satisfy pipeline specifications. In some areas, where no processing is required, the producers’ gas is gathered and delivered to pipelines for market delivery. Under cost-of-service gathering agreements, fees are earned for gathering and compression services based on rates calculated in a cost-of-service model and reviewed periodically over the life of the agreements. Under percent-of-proceeds contracts, revenue is recognized when the natural gas, NGLs or condensate is sold. The percentage of the product sale ultimately paid to the producer is recorded as a related cost of product expense. In certain circumstances, the Partnership purchases natural gas volumes at the wellhead for gathering and processing. As a result, the Partnership has volumes of NGLs and condensate to sell and volumes of residue to sell, to use for system fuel or to satisfy keep-whole obligations. In addition, depending upon specific contract terms, condensate and NGLs recovered during gathering and processing are either returned to the producer or retained and sold. Under keep-whole contracts, when condensate or NGLs are retained and sold, producers are kept whole for the condensate or NGL volumes through the receipt of a thermally equivalent volume of residue. The keep-whole contract conveys an economic benefit to the Partnership when the combined value of the individual NGLs is greater in the form of liquids than as a component of the natural gas stream; however, the Partnership is adversely impacted when the value of the NGLs is lower than the value of the natural gas stream including the liquids. The Partnership has commodity price swap agreements with Anadarko to mitigate exposure to a majority of the commodity price risk inherent in our percent-of-proceeds and keep-whole contracts. See Note 5 . Revenue is recognized from the sale of condensate and NGLs upon transfer of title, and related purchases are recorded as cost of product. The Partnership earns transportation revenues through firm contracts that obligate each of its customers to pay a monthly reservation or demand charge regardless of the pipeline capacity used by that customer. An additional commodity usage fee is charged to the customer based on the actual volume of natural gas transported. Transportation revenues are also generated from interruptible contracts pursuant to which a fee is charged to the customer based on volumes transported through the pipeline. Revenues for transportation of natural gas and NGLs are recognized over the period of firm transportation contracts or, in the case of usage fees and interruptible contracts, when the volumes are received into the pipeline. From time to time, certain revenues may be subject to refund pending the outcome of rate matters before the Federal Energy Regulatory Commission (the “FERC”), and refund reserve liabilities are established where appropriate. Proceeds from the sale of residue, NGLs and condensate are reported as revenues from natural gas, natural gas liquids and condensate sales in the consolidated statements of operations. Revenues attributable to the fixed-fee component of gathering and processing contracts as well as demand charges and commodity usage fees on transportation contracts are reported as revenues from gathering, processing and transportation of natural gas and natural gas liquids in the consolidated statements of operations. 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) Equity-based compensation. Phantom unit awards are granted under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (the “WES LTIP”). The WES LTIP was adopted by the general partner of the Partnership and permits the issuance of up to 2,250,000 units, of which 2,120,711 units remained available for future issuance as of December 31, 2016 . Upon vesting of each phantom unit awarded under the WES LTIP, the holder will receive common units of the Partnership or, at the discretion of the Board of Directors of our general partner, (the “Board of Directors”), cash in an amount equal to the market value of common units of the Partnership on the vesting date. Equity-based compensation expense attributable to grants made under the WES LTIP impacts cash flows from operating activities only to the extent cash payments are made to a participant in lieu of issuance of common units to the participant. Stock-based compensation expense attributable to awards granted under the WES LTIP is amortized over the vesting periods applicable to the awards. Additionally, general and administrative expenses include equity-based compensation costs allocated by Anadarko to the Partnership for grants made pursuant to (i) the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan (the “WGP LTIP”) and (ii) the Anadarko Petroleum Corporation 2008 and 2012 Omnibus Incentive Compensation Plans (Anadarko’s plans are referred to collectively as the “Anadarko Incentive Plans”) for all periods presented. Grants made under equity-based compensation plans result in equity-based compensation expense, which is determined by reference to the fair value of equity compensation. For equity-based awards ultimately settled through the issuance of units or stock, the fair value is measured as of the date of the relevant equity grant. Equity-based compensation granted under the WGP LTIP and the Anadarko Incentive Plans does not impact cash flows from operating activities since the offset to compensation expense is recorded as a contribution to partners’ capital in the consolidated financial statements at the time of contribution, when the expense is realized. Income taxes. The Partnership generally is not subject to federal income tax or state income tax other than Texas margin tax on the portion of its income that is apportionable to Texas. Deferred state income taxes are recorded on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. The Partnership routinely assesses the realizability of its deferred tax assets. If the Partnership concludes that it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Federal and state current and deferred income tax expense was recorded on the Partnership assets prior to the Partnership’s acquisition of these assets from Anadarko. For periods beginning on and subsequent to the Partnership’s acquisition of the Partnership assets, the Partnership makes payments to Anadarko pursuant to the tax sharing agreement entered into between Anadarko and the Partnership for its estimated share of taxes from all forms of taxation, excluding taxes imposed by the United States, that are included in any combined or consolidated returns filed by Anadarko. The aggregate difference in the basis of the Partnership’s assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each partner’s tax attributes in the Partnership. The accounting standards for uncertain tax positions defines the criteria an individual tax position must satisfy for any part of the benefit of that position to be recognized in the financial statements. The Partnership had no material uncertain tax positions at December 31, 2016 or 2015 . With respect to assets acquired from Anadarko, the Partnership recorded Anadarko’s historic deferred income taxes for the periods prior to the Partnership’s ownership of the assets. For periods subsequent to the Partnership’s acquisition, the Partnership is not subject to tax except for the Texas margin tax and, accordingly, does not record deferred federal income taxes related to the assets acquired from Anadarko. 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) Net income (loss) per common unit. The Partnership applies the two-class method in determining net income (loss) per unit applicable to master limited partnerships having multiple classes of securities including common units, Class C units, general partner units and incentive distribution rights (“IDRs”). The two-class method is an earnings allocation formula that treats participating securities as having rights to earnings that otherwise would have been available to common unitholders. Under the two-class method, net income (loss) per unit is calculated as if all of the earnings for the period were distributed pursuant to the terms of the relevant contractual arrangement. The accounting guidance provides the methodology for and circumstances under which undistributed earnings are allocated to the general partner, limited partners and IDR holders. For the Partnership, earnings per unit is calculated based on the assumption that the Partnership dis |
Acquisitions and Divestitures
Acquisitions and Divestitures | 12 Months Ended |
Dec. 31, 2016 | |
Property, Plant and Equipment [Abstract] | |
Acquisitions and Divestitures | 2. ACQUISITIONS AND DIVESTITURES The following table presents the acquisitions completed by the Partnership during 2016 , 2015 and 2014 , and identifies the funding sources for such acquisitions. See Note 14 for information regarding events occurring subsequent to December 31, 2016. thousands except unit and percent amounts Acquisition Date Percentage Deferred Purchase Price Obligation - Anadarko Borrowings Cash On Hand Common Units Issued Class C Units Issued to Anadarko Series A Preferred Units Issued TEFR Interests (1) 03/03/2014 Various (1) $ — $ 350,000 $ 6,250 308,490 — — DBM (2) 11/25/2014 100 % — 475,000 298,327 — 10,913,853 — DBJV (3) 03/02/2015 100 % 174,276 — — — — — Springfield (4) 03/14/2016 100 % — 247,500 — 2,089,602 — 14,030,611 (1) The Partnership acquired a 20% interest in each of TEG and TEP and a 33.33% interest in FRP from Anadarko. These assets gather and transport NGLs primarily from the Anadarko and Denver-Julesburg (“DJ”) Basins. The interests in these entities are accounted for under the equity method of accounting. In connection with the issuance of the common units, the Partnership issued 6,296 general partner units to the general partner in exchange for the general partner’s proportionate capital contribution of $0.4 million . (2) The Partnership acquired Nuevo Midstream, LLC (“Nuevo”) from a third party. Following the acquisition, the Partnership changed the name of Nuevo to Delaware Basin Midstream, LLC (“DBM”). The assets acquired include cryogenic processing plants, a gas gathering system, and related facilities and equipment, which are collectively referred to as the “DBM complex” and serve production from Reeves, Loving and Culberson Counties, Texas and Eddy and Lea Counties, New Mexico. See DBM acquisition below for further information, including the final allocation of the purchase price. (3) The Partnership acquired Delaware Basin JV Gathering LLC (“DBJV”) from Anadarko. DBJV owns a 50% interest in a gathering system and related facilities. The DBJV gathering system and related facilities (the “DBJV system”) are located in the Delaware Basin in Loving, Ward, Winkler and Reeves Counties, Texas. The Partnership will make a cash payment on March 31, 2020, to Anadarko as consideration for the acquisition of DBJV. At the acquisition date, the Partnership estimated the future payment would be $282.8 million , the net present value of which was $174.3 million . For further information, including revisions to the estimated future payment, see DBJV acquisition—deferred purchase price obligation - Anadarko below. (4) The Partnership acquired Springfield Pipeline LLC (“Springfield”) from Anadarko for $750.0 million , consisting of $712.5 million in cash and the issuance of 1,253,761 of the Partnership’s common units. Springfield owns a 50.1% interest in an oil gathering system and a gas gathering system, such interest being referred to in this report as the “Springfield interest.” The Springfield oil and gas gathering systems (collectively, the “Springfield system”) are located in Dimmit, La Salle, Maverick and Webb Counties in South Texas. The Partnership financed the cash portion of the acquisition through: (i) borrowings of $247.5 million on the Partnership’s senior unsecured revolving credit facility (“RCF”), (ii) the issuance of 835,841 of the Partnership’s common units to WGP and (iii) the issuance of Series A Preferred units to private investors. See Note 4 for further information regarding the Series A Preferred units. 2. ACQUISITIONS AND DIVESTITURES (CONTINUED) DBJV acquisition - deferred purchase price obligation - Anadarko. The consideration to be paid by the Partnership for the acquisition of DBJV consists of a cash payment to Anadarko due on March 31, 2020. The cash payment will be equal to (a) eight multiplied by the average of the Partnership’s share in the Net Earnings (see definition below) of DBJV for the calendar years 2018 and 2019, less (b) the Partnership’s share of all capital expenditures incurred for DBJV between March 1, 2015, and February 29, 2020. Net Earnings is defined as all revenues less cost of product, operating expenses and property taxes, in each case attributable to DBJV on an accrual basis. As of the acquisition date, the estimated future payment obligation (based on management’s estimate of the Partnership’s share of forecasted Net Earnings and capital expenditures for DBJV) was $282.8 million , which had a net present value of $174.3 million , using a discount rate of 10% . During the year ended December 31, 2016 , the Partnership recognized an aggregate $226.4 million decrease in the estimated future payment obligation, resulting in a net present value of $41.4 million for this obligation at December 31, 2016 , calculated using a discounted cash flow model with a 10% discount rate. The reduction in the value of the deferred purchase price obligation is primarily due to revisions reflecting an increase in the Partnership’s estimate of aggregate capital expenditures to be incurred by DBJV through February 29, 2020, partially offset by an increase in the Partnership’s estimate of 2018 and 2019 Net Earnings. The following table summarizes the financial statement impact of the Deferred purchase price obligation - Anadarko: Deferred purchase price obligation - Anadarko Estimated future payment obligation Balance at March 2, 2015 – Acquisition date $ 174,276 $ 282,807 Accretion expense (1) 14,398 Balance at December 31, 2015 188,674 282,807 Accretion revision (2) (7,747 ) Revision to Deferred purchase price obligation – Anadarko (3) (139,487 ) Balance at December 31, 2016 $ 41,440 $ 56,455 (1) Accretion expense was recorded as a charge to Interest expense on the consolidated statements of operations. (2) Financing-related accretion revisions were recorded in Interest expense on the consolidated statements of operations. (3) Recorded as revisions within Common units on the consolidated balance sheets and consolidated statements of equity and partners’ capital. Hugoton system divestiture. During the fourth quarter of 2016, the Hugoton system, located in Southwest Kansas and Oklahoma, was sold to a third party, resulting in a net loss on sale of $12.0 million recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations. The Partnership allocated $1.6 million in goodwill to this divestiture. Dew and Pinnacle systems divestiture. During the third quarter of 2015, the Dew and Pinnacle systems in East Texas were sold to a third party, resulting in a net gain on sale of $77.3 million recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations. The Partnership allocated $5.1 million in goodwill to this divestiture. |
Partnership Distributions
Partnership Distributions | 12 Months Ended |
Dec. 31, 2016 | |
Distributions Made to Members or Limited Partners [Abstract] | |
Partnership Distributions | 3. PARTNERSHIP DISTRIBUTIONS The partnership agreement requires the Partnership to distribute all of its available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date within 45 days of the end of each quarter. The Board of Directors declared the following cash distributions to the Partnership’s common and general partner unitholders for the periods presented: thousands except per-unit amounts Quarters Ended Total Quarterly Distribution per Unit Total Quarterly Cash Distribution Date of Distribution 2014 March 31 $ 0.625 $ 98,749 May 2014 June 30 0.650 105,655 August 2014 September 30 0.675 111,608 November 2014 December 31 0.700 126,044 February 2015 2015 March 31 $ 0.725 $ 133,203 May 2015 June 30 0.750 139,736 August 2015 September 30 0.775 146,160 November 2015 December 31 0.800 152,588 February 2016 2016 March 31 $ 0.815 $ 158,905 May 2016 June 30 0.830 162,827 August 2016 September 30 0.845 166,742 November 2016 December 31 (1) 0.860 170,657 February 2017 (1) The Board of Directors declared a cash distribution to the Partnership’s unitholders for the fourth quarter of 2016 of $0.860 per unit, or $170.7 million in aggregate, including incentive distributions, but excluding distributions on Class C units (see Class C unit distributions below) and Series A Preferred units (see Series A Preferred unit distributions below). The cash distribution was paid on February 13, 2017 , to unitholders of record at the close of business on February 2, 2017 . Available cash. The amount of available cash (as defined in the partnership agreement) generally is all cash on hand at the end of the quarter, plus, at the discretion of the general partner, working capital borrowings made subsequent to the end of such quarter, less the amount of cash reserves established by the Partnership’s general partner to provide for the proper conduct of the Partnership’s business, including reserves to fund future capital expenditures; to comply with applicable laws, debt instruments or other agreements; or to provide funds for distributions to its unitholders, and to its general partner for any one or more of the next four quarters. Working capital borrowings generally include borrowings made under a credit facility or similar financing arrangement. Working capital borrowings may only be those that, at the time of such borrowings, were intended to be repaid within 12 months. In all cases, working capital borrowings are used solely for working capital purposes or to fund distributions to partners. 3. PARTNERSHIP DISTRIBUTIONS (CONTINUED) Class C unit distributions. The Class C units receive quarterly distributions at a rate equivalent to the Partnership’s common units. The distributions are paid in the form of additional Class C units (“PIK Class C units”) until the scheduled conversion date on December 31, 2017 (unless earlier converted), and the Class C units are disregarded with respect to distributions of the Partnership’s available cash until they are converted to common units. The number of additional PIK Class C units to be issued in connection with a distribution payable on the Class C units is determined by dividing the corresponding distribution attributable to the Class C units by the volume-weighted-average price of the Partnership’s common units for the ten days immediately preceding the payment date for the common unit distribution, less a 6% discount. The Partnership records the PIK Class C unit distributions at fair value at the time of issuance. This Level 2 fair value measurement uses the Partnership’s unit price as a significant input in the determination of the fair value. The Partnership made distributions to APC Midstream Holdings, LLC (“AMH”), the holder of the Class C units, of 946,261 PIK Class C units during 2016 and 498,009 PIK Class C units during 2015. Further, 178,977 PIK Class C units were distributed to AMH in February 2017, for the quarterly distribution period ended December 31, 2016. See Note 4 for further discussion of the Class C units. Series A Preferred unit distributions. As further described in Note 4 , the Partnership issued Series A Preferred units representing limited partner interests in the Partnership to private investors in March 2016 and April 2016. The Series A Preferred unitholders receive quarterly distributions in cash equal to $0.68 per Series A Preferred unit, subject to certain adjustments. The holders of the Series A Preferred units are entitled to certain rights that are senior to the rights of holders of common and Class C units, such as rights to distributions and rights upon liquidation of the Partnership. No payment or distribution on any junior equity security of the Partnership, including common and Class C units, for any quarter is permitted prior to the payment in full of the Series A Preferred unit distribution (including any outstanding arrearages). For the quarter ended December 31, 2016, the Series A Preferred unitholders received an aggregate cash distribution of $14.9 million (paid in February 2017). For the quarter ended September 30, 2016, the Series A Preferred unitholders received an aggregate cash distribution of $14.9 million (paid in November 2016). For the quarter ended June 30, 2016, the Series A Preferred unitholders received an aggregate cash distribution of $14.1 million (paid in August 2016) comprised of a quarterly per unit distribution prorated for the 77 -day period during which 7,892,220 Series A Preferred units were outstanding during the second quarter of 2016 and a full quarterly per unit distribution on 14,030,611 Series A Preferred units. For the quarter ended March 31, 2016, the Series A Preferred unitholders received an aggregate cash distribution of $1.9 million (paid in May 2016), based on the quarterly per unit distribution prorated for the 18 -day period during which 14,030,611 Series A Preferred units were outstanding during the first quarter of 2016. See Note 4 for further discussion of the Series A Preferred units. General partner interest and incentive distribution rights. As of December 31, 2016, the general partner was entitled to 1.5% of all quarterly distributions that the Partnership makes prior to its liquidation and, as the holder of the IDRs, was entitled to incentive distributions at the maximum distribution sharing percentage of 48.0% for all periods presented, after the minimum quarterly distribution and the target distribution levels had been achieved. The maximum distribution sharing percentage of 49.5% does not include any distributions that the general partner may receive on common units that it may acquire. |
Equity and Partners' Capital
Equity and Partners' Capital | 12 Months Ended |
Dec. 31, 2016 | |
Partners' Capital Notes [Abstract] | |
Equity and Partners' Capital | 4. EQUITY AND PARTNERS’ CAPITAL Equity offerings. The Partnership completed the following public offerings of its common units during 2015 and 2014, including through its Continuous Offering Programs (“COP”): thousands except unit and per-unit amounts Common Units Issued GP Units Issued (1) Price Per Unit Underwriting Discount and Other Offering Expenses Net Proceeds 2014 $125.0 million COP (2) 1,133,384 23,132 $ 73.48 $ 1,738 $ 83,245 November 2014 equity offering (3) 8,620,153 153,061 70.85 18,615 602,967 2015 $500.0 million COP (4) 873,525 — $ 66.61 $ 805 $ 57,385 (1) Represents general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution. (2) Represents common and general partner units issued during the year ended December 31, 2014, under the $125.0 million COP. Gross proceeds generated (including the general partner’s proportionate capital contributions) during the year ended December 31, 2014, were $85.0 million . The price per unit in the table above represents an average price for all issuances under the $125.0 million COP during the year ended December 31, 2014. As of December 31, 2014, the Partnership had used all the capacity to issue common units under this registration statement. (3) Includes the issuance of 1,120,153 common units pursuant to the partial exercise of the underwriters’ over-allotment option, the net proceeds from which were $77.0 million . Beginning with this partial exercise, the Partnership’s general partner elected not to make a corresponding capital contribution to maintain its 2.0% interest in the Partnership. (4) Represents common units issued during the year ended December 31, 2015, pursuant to the Partnership’s registration statement filed with the SEC in August 2014 authorizing the issuance of up to an aggregate of $500.0 million of common units (the “$500.0 million COP”). Gross proceeds generated during the three months and year ended December 31, 2015, were zero and $58.2 million , respectively. Commissions paid during the three months and year ended December 31, 2015, were zero and $0.6 million , respectively. The price per unit in the table above represents an average price for all issuances under the $500.0 million COP during the year ended December 31, 2015. The Partnership issued no common units under the $500.0 million COP during the year ended December 31, 2016 . Class C units. In connection with the closing of the DBM acquisition in November 2014, the Partnership issued 10,913,853 Class C units to AMH at a price of $68.72 per unit, generating proceeds of $750.0 million , pursuant to a Unit Purchase Agreement (“UPA”) with Anadarko and AMH. All outstanding Class C units will convert into common units on a one-for-one basis on December 31, 2017, unless the Partnership elects to convert such units earlier or Anadarko extends the conversion date. See Note 14 . The Class C units were issued to partially fund the acquisition of DBM, and the UPA contains an optional redemption feature that provides the Partnership the ability to redeem up to $150.0 million of the Class C units within 10 days of the receipt of cash proceeds from an entity that is not an affiliate of the Partnership or AMH, if these cash proceeds were in relation to (i) the assets of DBM, (ii) the equity interests in DBM or (iii) the equity interests in a subsidiary of the Partnership that owns a majority of the outstanding equity interests in DBM. As of December 31, 2016 , no such proceeds had been received, and no Class C units had been redeemed. The Class C units were issued at a discount to the then-current market price of the common units into which they are convertible. This discount, totaling $34.8 million , represents a beneficial conversion feature, and at issuance, it was reflected as an increase in common unitholders’ capital and a decrease in Class C unitholder capital to reflect the fair value of the Class C units at issuance. The beneficial conversion feature is considered a non-cash distribution that will be recognized from the date of issuance through the date of conversion, resulting in an increase in Class C unitholder capital and a decrease in common unitholders’ capital as amortized. The beneficial conversion feature is amortized assuming a conversion date of December 31, 2017, using the effective yield method. The impact of the beneficial conversion feature amortization is also included in the calculation of earnings per unit. 4. EQUITY AND PARTNERS’ CAPITAL (CONTINUED) Series A Preferred units. In connection with the closing of the Springfield acquisition on March 14, 2016, the Partnership issued 14,030,611 Series A Preferred units (the “March 2016 Series A units”) to private investors for a cash purchase price of $32.00 per unit, generating proceeds of $440.0 million (net of fees and expenses, but including a 2.0% transaction fee paid to the private investors). In April 2016, the Partnership issued an additional 7,892,220 Series A Preferred units (the “April 2016 Series A units”) pursuant to the full exercise of an option granted in connection with the March 2016 Series A units issuance, generating net proceeds of $246.9 million . The Series A Preferred unitholders may convert the Series A Preferred units into common units on a one -for-one basis at any time after the second anniversary of the issuance date, in whole or in part, subject to certain conversion thresholds. Similarly, the Partnership may convert the Series A Preferred units at any time after the third anniversary of the issuance date, in whole or in part, if the closing price of the Partnership’s common units is greater than $48.00 per common unit for 20 of the 30 preceding trading days, and subject to other certain conversion thresholds. In addition, upon certain events involving a change of control, the Series A Preferred unitholders may elect on an individual basis, subject to certain conditions, to (i) convert their Series A Preferred units to common units at the then applicable conversion rate, (ii) if the Partnership is not the surviving entity (or if the Partnership is the surviving entity, but its common units will cease to be listed), require the Partnership to use commercially reasonable efforts to cause the surviving entity in any such transaction to issue a substantially equivalent security (or convert into common units based on a specified formula, if the Partnership is unable to cause such substantially equivalent securities to be issued), (iii) if the Partnership is the surviving entity, continue to hold their Series A Preferred units, or (iv) require the Partnership to redeem the Series A Preferred units at a price per Series A Preferred unit of $32.32 , plus accrued and unpaid distributions to be paid in cash or common units at the discretion of the Partnership. The Series A Preferred unitholders will vote on an as-converted basis with the Partnership’s common unitholders and will have certain other class voting rights with respect to any amendment to the partnership agreement that would adversely affect any rights, preferences or privileges of the Series A Preferred unitholders. In connection with the issuance of the Series A Preferred units, the Partnership entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with the Series A Preferred unit purchasers relating to the registered resale of the common units representing limited partner interests in the Partnership issuable upon conversion of the Series A Preferred units. Pursuant to the Registration Rights Agreement, the Partnership is required to use its commercially reasonable efforts to file and maintain a registration statement for the resale of the converted Series A Preferred units, with such registration statement to become effective no later than March 2018. The March 2016 Series A units and the April 2016 Series A units were issued at a discount to the then-current market price of the common units into which they are convertible. The discount on the March 2016 Series A units, totaling $21.7 million , represents a beneficial conversion feature, and on the date the Preferred Unit Purchase Agreement was signed (the “commitment date”), it was reflected as an increase in common unitholders’ capital and a decrease in Series A Preferred unitholders’ capital to reflect the fair value of the March 2016 Series A units on the commitment date. The discount on the April 2016 Series A units, totaling $71.7 million , also represents a beneficial conversion feature and on the date the option to purchase additional Series A units was exercised (the “notice date”), it was reflected as an increase in common unitholders’ capital and a decrease in Series A Preferred unitholders’ capital to reflect the fair value of the April 2016 Series A units on the notice date. The beneficial conversion features are considered non-cash distributions that will be recognized from each issuance date through the date of earliest conversion, resulting in an increase in Series A Preferred unitholders’ capital and a decrease in common unitholders’ capital as amortized. The beneficial conversion features are amortized assuming a conversion date of March 14, 2018 for the March 2016 Series A units and a conversion date of April 15, 2018 for the April 2016 Series A units, using the effective yield method. 4. EQUITY AND PARTNERS’ CAPITAL (CONTINUED) Partnership interests. The Partnership’s common units are listed on the New York Stock Exchange under the symbol “WES.” The following table summarizes the common, Class C, Series A Preferred and general partner units issued during the years ended December 31, 2016 and 2015: Common Units Class C Units Series A Preferred Units General Partner Units Total Balance at December 31, 2014 127,695,130 10,913,853 — 2,583,068 141,192,051 PIK Class C units — 498,009 — — 498,009 Long-Term Incentive Plan award vestings 8,310 — — — 8,310 $500.0 million COP 873,525 — — — 873,525 Balance at December 31, 2015 128,576,965 11,411,862 — 2,583,068 142,571,895 PIK Class C units — 946,261 — — 946,261 Springfield acquisition 2,089,602 — 14,030,611 — 16,120,213 April 2016 Series A units — — 7,892,220 — 7,892,220 Long-Term Incentive Plan award vestings 5,403 — — — 5,403 Balance at December 31, 2016 130,671,970 12,358,123 21,922,831 2,583,068 167,535,992 Holdings of Partnership equity. As of December 31, 2016 , WGP held 50,132,046 common units, representing a 29.9% limited partner interest in the Partnership, and, through its ownership of the general partner, WGP indirectly held 2,583,068 general partner units, representing a 1.5% general partner interest in the Partnership, and 100% of the incentive distribution rights. As of December 31, 2016 , other subsidiaries of Anadarko collectively held 2,011,380 common units and 12,358,123 Class C units, representing an aggregate 8.6% limited partner interest in the Partnership. As of December 31, 2016 , the public held 78,528,544 common units, representing a 46.9% limited partner interest in the Partnership and private investors held 21,922,831 Series A Preferred units, representing a 13.1% limited partner interest in the Partnership. Net income (loss) per unit for common units. Net income (loss) attributable to Western Gas Partners, LP earned on and subsequent to the date of the acquisition of the Partnership assets, net of distributions on the Series A Preferred units and amortization of the Series A Preferred unit beneficial conversion features (see Series A Preferred units above), is allocated to the general partner, the common unitholders and the Class C unitholder, in accordance with their respective weighted-average ownership percentages (exclusive of the Series A Preferred unit limited partnership interest) and, when applicable, giving effect to incentive distributions allocable to the general partner. Specifically, net income equal to the amount of available cash (as defined by the partnership agreement) is allocated to the general partner, common and Class C unitholder consistent with actual cash distributions and capital account allocations, including incentive distributions allocable to the general partner. Undistributed earnings (net income in excess of distributions) or undistributed losses (available cash in excess of net income) are then allocated to the general partner, common unitholders and the Class C unitholder in accordance with their respective weighted-average ownership percentages during each period. Additionally, the allocable limited partners’ interest in net income (loss) is also net of amortization of the beneficial conversion feature related to the Class C units (see Class C units above) and is allocated between the common and Class C unitholders by applying the provisions of the partnership agreement that govern actual cash distributions and capital account allocations, as if all earnings for the period had been distributed. Net income (loss) attributable to the Partnership assets acquired from Anadarko for periods prior to the Partnership’s acquisition of the Partnership assets is not allocated to the limited partners for purposes of calculating net income (loss) per common unit. 4. EQUITY AND PARTNERS’ CAPITAL (CONTINUED) Basic net income (loss) per common unit is calculated by dividing the limited partners’ interest in net income (loss) attributable to common unitholders by the weighted-average number of common units outstanding during the period. The common units issued in connection with acquisitions and equity offerings are included on a weighted-average basis for periods they were outstanding. The Series A Preferred units are not considered a participating security as they only have distribution rights up to the specified per-unit quarterly distribution and have no rights to the Partnership’s undistributed earnings. Because the Class C units participate in distributions with common units according to a predetermined formula (see Note 3 ), they are considered a participating security and are included in the computation of earnings per unit pursuant to the two-class method. The Class C unit participation right results in a non-contingent transfer of value each time the Partnership declares a distribution. Diluted net income (loss) per common unit is calculated by dividing the sum of (i) the limited partners’ interest in net income (loss) attributable to common units adjusted for distributions on the Series A Preferred units and a reallocation of the limited partners’ interest in net income (loss) assuming conversion of the Series A Preferred units into common units, and (ii) the limited partners’ interest in net income (loss) allocable to the Class C units as a participating security, by the sum of the weighted-average number of common units outstanding plus the dilutive effect of (i) the weighted-average number of outstanding Class C units and (ii) the weighted-average number of common units outstanding assuming conversion of the Series A Preferred units. The following table illustrates the Partnership’s calculation of net income (loss) per unit for common units: Year Ended December 31, thousands except per-unit amounts 2016 2015 2014 Net income (loss) attributable to Western Gas Partners, LP $ 591,331 $ 4,106 $ 442,643 Pre-acquisition net (income) loss allocated to Anadarko (11,326 ) (79,386 ) (65,154 ) Series A Preferred units interest in net (income) loss (1) (76,893 ) — — General partner interest in net (income) loss (236,561 ) (180,996 ) (120,980 ) Common and Class C limited partners’ interest in net income (loss) $ 266,551 $ (256,276 ) $ 256,509 Net income (loss) allocable to common units (1) $ 226,611 $ (250,210 ) $ 254,737 Net income (loss) allocable to Class C units (1) 39,940 (6,066 ) 1,772 Common and Class C limited partners’ interest in net income (loss) $ 266,551 $ (256,276 ) $ 256,509 Net income (loss) per unit Common units – basic $ 1.74 $ (1.95 ) $ 2.13 Common units – diluted (2) 1.74 (1.95 ) 2.12 Weighted-average units outstanding Common units – basic 130,253 128,345 119,822 Class C units (2) 11,945 11,114 1,106 Series A Preferred units assuming conversion to common units (2) 16,860 — — Common units - diluted (2) 130,253 128,345 120,928 (1) Adjusted to reflect amortization of the beneficial conversion features. (2) The impact of Class C units and the conversion of Series A Preferred units would be anti-dilutive for the year ended December 31, 2016, and the impact of Class C units would be anti-dilutive for the year ended December 31, 2015. |
Transactions with Affiliates
Transactions with Affiliates | 12 Months Ended |
Dec. 31, 2016 | |
Related Party Fees and Other Arrangements, Limited Liability Company (LLC) or Limited Partnership (LP) [Abstract] | |
Transactions with Affiliates | 5. TRANSACTIONS WITH AFFILIATES Affiliate transactions. Revenues from affiliates include amounts earned by the Partnership from services provided to Anadarko as well as from the sale of residue and NGLs to Anadarko. In addition, the Partnership purchases natural gas from an affiliate of Anadarko pursuant to gas purchase agreements. Operation and maintenance expense includes amounts accrued for or paid to affiliates for the operation of the Partnership assets, whether in providing services to affiliates or to third parties, including field labor, measurement and analysis, and other disbursements. A portion of the Partnership’s general and administrative expenses is paid by Anadarko, which results in affiliate transactions pursuant to the reimbursement provisions of the Partnership’s omnibus agreement. Affiliate expenses do not bear a direct relationship to affiliate revenues, and third-party expenses do not bear a direct relationship to third-party revenues. See Note 2 for further information related to contributions of assets to the Partnership by Anadarko. Cash management. Anadarko operates a cash management system whereby excess cash from most of its subsidiaries’ separate bank accounts is generally swept to centralized accounts. Prior to the Partnership’s acquisition of the Partnership assets, third-party sales and purchases related to such assets were received or paid in cash by Anadarko within its centralized cash management system. The outstanding affiliate balances were entirely settled through an adjustment to net investment by Anadarko in connection with the acquisition of the Partnership assets. Subsequent to the acquisition of Partnership assets from Anadarko, transactions related to such assets are cash-settled directly with third parties and with Anadarko affiliates. Chipeta cash settles its transactions directly with third parties and Anadarko, as well as with the other subsidiaries of the Partnership. Note receivable - Anadarko and Deferred purchase price obligation - Anadarko. Concurrently with the closing of the Partnership’s May 2008 initial public offering, the Partnership loaned $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50% , payable quarterly. The fair value of the note receivable from Anadarko was $313.3 million and $252.3 million at December 31, 2016 and 2015 , respectively. The fair value of the note reflects consideration of credit risk and any premium or discount for the differential between the stated interest rate and quarter-end market interest rate, based on quoted market prices of similar debt instruments. Accordingly, the fair value of the note receivable from Anadarko is measured using Level 2 inputs. The consideration to be paid by the Partnership to Anadarko for the March 2015 acquisition of DBJV consists of a cash payment due on March 31, 2020. See Note 2 and Note 12 . Commodity price swap agreements. The Partnership has commodity price swap agreements with Anadarko to mitigate exposure to a majority of the commodity price risk inherent in its percent-of-proceeds and keep-whole contracts. Notional volumes for each of the commodity price swap agreements are not specifically defined. Instead, the commodity price swap agreements apply to the actual volume of natural gas, condensate and NGLs purchased and sold. The commodity price swap agreements do not satisfy the definition of a derivative financial instrument and, therefore, are not required to be measured at fair value. 5. TRANSACTIONS WITH AFFILIATES (CONTINUED) The following table summarizes gains and losses upon settlement of commodity price swap agreements recognized in the consolidated statements of operations: Year Ended December 31, thousands 2016 2015 2014 Gains (losses) on commodity price swap agreements related to sales: (1) Natural gas sales $ 11,116 $ 45,978 $ 9,494 Natural gas liquids sales 59,918 145,258 113,866 Total 71,034 191,236 123,360 Losses on commodity price swap agreements related to purchases (2) (42,577 ) (124,944 ) (68,492 ) Net gains (losses) on commodity price swap agreements $ 28,457 $ 66,292 $ 54,868 (1) Reported in affiliate Natural gas and natural gas liquids sales in the consolidated statements of operations in the period in which the related sale is recorded. (2) Reported in Cost of product in the consolidated statements of operations in the period in which the related purchase is recorded. Swap extensions - DJ Basin complex, Hugoton system and MGR assets. On June 25, 2015, the Partnership extended its commodity price swap agreements with Anadarko for the DJ Basin complex from July 1, 2015, through December 31, 2015, and for the Hugoton system from October 1, 2015, through December 31, 2015. On December 8, 2015, the commodity price swap agreements with Anadarko for the DJ Basin complex and Hugoton system were further extended from January 1, 2016, through December 31, 2016. On December 1, 2016, the commodity price swap agreements with Anadarko for the DJ Basin complex and the MGR assets were extended from January 1, 2017 through December 31, 2017. Revenues or costs attributable to volumes settled during the respective extension period, at the applicable market price in the tables below, are recognized in the consolidated statements of operations. The Partnership also records a capital contribution from Anadarko in the Partnership’s consolidated statements of equity and partners’ capital for the amount by which the swap price exceeds the applicable market price in the tables below. For the years ended December 31, 2016 and 2015, the capital contributions from Anadarko were $45.8 million and $18.4 million , respectively, attributable to the commodity price swap agreements for the DJ Basin complex and the Hugoton system. The tables below summarize the swap prices for the extension periods compared to the forward market prices as of the various agreement dates. DJ Basin Complex per barrel except natural gas 2015 - 2017 Swap Prices 2015 Market Prices (1) 2016 Market Prices (1) 2017 Market Prices (1) Ethane $ 18.41 $ 1.96 $ 0.60 $ 5.09 Propane 47.08 13.10 10.98 18.85 Isobutane 62.09 19.75 17.23 26.83 Normal butane 54.62 18.99 16.86 26.20 Natural gasoline 72.88 52.59 26.15 41.84 Condensate 76.47 52.59 34.65 45.40 Natural gas (per MMBtu) 5.96 2.75 2.11 3.05 Hugoton System (2) per barrel except natural gas 2015 - 2016 Swap Prices 2015 Market Prices (1) 2016 Market Prices (1) Condensate $ 78.61 $ 32.56 $ 18.81 Natural gas (per MMBtu) 5.50 2.74 2.12 5. TRANSACTIONS WITH AFFILIATES (CONTINUED) MGR Assets per barrel except natural gas 2015 Swap Prices 2016 - 2017 Swap Prices 2017 Market Prices (1) Ethane $ 23.41 $ 23.11 $ 4.08 Propane 52.99 52.90 19.24 Isobutane 74.02 73.89 25.79 Normal butane 65.04 64.93 25.16 Natural gasoline 81.82 81.68 45.01 Condensate 81.82 81.68 53.55 Natural gas (per MMBtu) 4.66 4.87 3.05 (1) Represents the New York Mercantile Exchange forward strip price as of June 25, 2015, December 8, 2015 and December 1, 2016, for the 2015 Market Prices, 2016 Market Prices and 2017 Market Prices, respectively, adjusted for product specification, location, basis and, in the case of NGLs, transportation and fractionation costs. (2) The Hugoton system was sold in October 2016. See Note 2 . Gathering and processing agreements. The Partnership has significant gathering and processing arrangements with affiliates of Anadarko on a majority of its systems. The Partnership’s natural gas gathering, treating and transportation throughput (excluding equity investment throughput) attributable to production owned or controlled by Anadarko was 37% , 53% and 56% for the years ended December 31, 2016, 2015 and 2014, respectively. The Partnership’s natural gas processing throughput (excluding equity investment throughput) attributable to production owned or controlled by Anadarko was 54% , 51% and 57% for the years ended December 31, 2016, 2015 and 2014, respectively. The Partnership’s crude/NGL gathering, treating and transportation throughput (excluding equity investment throughput) attributable to production owned or controlled by Anadarko was 65% for the year ended December 31, 2016, and 100% for each of the years ended December 31, 2015 and 2014. Prior to January 1, 2016, Springfield’s contracts were with a subsidiary of Anadarko who contracted with third parties. Effective January 1, 2016, Springfield’s contracts are with both a subsidiary of Anadarko and third parties directly. Commodity purchase and sale agreements. The Partnership sells a significant amount of its natural gas, condensate and NGLs to Anadarko Energy Services Company (“AESC”), Anadarko’s marketing affiliate. In addition, the Partnership purchases natural gas, condensate and NGLs from AESC pursuant to purchase agreements. The Partnership’s purchase and sale agreements with AESC are generally one-year contracts, subject to annual renewal. Acquisitions from Anadarko. On March 14, 2016, the Partnership acquired Springfield from Anadarko, and on March 2, 2015, the Partnership acquired DBJV from Anadarko. See Note 2 for further information on these acquisitions. 5. TRANSACTIONS WITH AFFILIATES (CONTINUED) Omnibus agreement. Pursuant to the omnibus agreement, Anadarko performs centralized corporate functions for the Partnership, such as legal; accounting; treasury; cash management; investor relations; insurance administration and claims processing; risk management; health, safety and environmental; information technology; human resources; credit; payroll; internal audit; tax; marketing; and midstream administration. Anadarko, in accordance with the partnership and omnibus agreements, determines, in its reasonable discretion, amounts to be reimbursed by the Partnership in exchange for services provided under the omnibus agreement. See Summary of affiliate transactions below. The following table summarizes the amounts the Partnership reimbursed to Anadarko: Year Ended December 31, thousands 2016 2015 2014 General and administrative expenses $ 29,360 $ 22,896 $ 20,249 Public company expenses 8,410 8,950 8,006 Total reimbursement $ 37,770 $ 31,846 $ 28,255 Services and secondment agreement. Pursuant to the services and secondment agreement, specified employees of Anadarko are seconded to the general partner to provide operating, routine maintenance and other services with respect to the assets owned and operated by the Partnership under the direction, supervision and control of the general partner. Pursuant to the services and secondment agreement, the Partnership reimburses Anadarko for services provided by the seconded employees. The initial term of the services and secondment agreement extends through May 2018 and the term will automatically extend for additional twelve-month periods unless either party provides 180 days written notice of termination before the applicable twelve-month period expires. The consolidated financial statements include costs allocated by Anadarko for expenses incurred under the services and secondment agreement for periods including and subsequent to the Partnership’s acquisition of the Partnership assets. Tax sharing agreement. Pursuant to a tax sharing agreement, the Partnership reimburses Anadarko for its estimated share of taxes from all forms of taxation, excluding taxes imposed by the United States. Taxes for which the Partnership reimburses Anadarko include state taxes attributable to the Partnership’s income, which are directly borne by Anadarko through its filing of a combined or consolidated tax return with respect to periods beginning on and subsequent to the acquisition of the Partnership assets from Anadarko. Anadarko may use its own tax attributes to reduce or eliminate the tax liability of its combined or consolidated group, which may include the Partnership as a member. However, under this circumstance, the Partnership nevertheless is required to reimburse Anadarko for its allocable share of taxes that would have been owed had tax attributes not been available to Anadarko. Allocation of costs. For periods prior to the Partnership’s acquisition of the Partnership assets, the consolidated financial statements include costs allocated by Anadarko in the form of a management services fee, which approximated the general and administrative costs incurred by Anadarko attributable to the Partnership assets. This management services fee was allocated to the Partnership based on its proportionate share of Anadarko’s assets and revenues or other contractual arrangements. Management believes these allocation methodologies are reasonable. The employees supporting the Partnership’s operations are employees of Anadarko. Anadarko allocates costs to the Partnership for its share of personnel costs, including costs associated with equity-based compensation plans, non-contributory defined pension and postretirement plans and defined contribution savings plans pursuant to the omnibus agreement and services and secondment agreement. In general, the Partnership’s reimbursement to Anadarko under the omnibus agreement or services and secondment agreements is either (i) on an actual basis for direct expenses Anadarko and the general partner incur on behalf of the Partnership, or (ii) based on an allocation of salaries and related employee benefits between the Partnership, the general partner and Anadarko based on estimates of time spent on each entity’s business and affairs. Most general and administrative expenses charged to the Partnership by Anadarko are attributed to the Partnership on an actual basis, and do not include any mark-up or subsidy component. With respect to allocated costs, management believes the allocation method employed by Anadarko is reasonable. Although it is not practicable to determine what the amount of these direct and allocated costs would be if the Partnership were to directly obtain these services, management believes that aggregate costs charged to the Partnership by Anadarko are reasonable. 5. TRANSACTIONS WITH AFFILIATES (CONTINUED) WES LTIP. The general partner awards phantom units under the WES LTIP primarily to its independent directors, but also from time to time to its executive officers and Anadarko employees performing services for the Partnership. The phantom units awarded to the independent directors vest one year from the grant date, while all other awards are subject to graded vesting over a three -year service period. Compensation expense is recognized over the vesting period and was $0.4 million , $0.5 million and $0.6 million for the years ended December 31, 2016 , 2015 and 2014, respectively. As of December 31, 2016 , there was $0.1 million of unrecognized compensation expense attributable to the outstanding awards under the WES LTIP, all of which will be realized by the Partnership, and which is expected to be recognized over a weighted-average period of 0.3 years. The following table summarizes WES LTIP award activity for the years ended December 31, 2016 , 2015 and 2014 : 2016 2015 2014 Weighted-Average Grant-Date Fair Value Units Weighted-Average Grant-Date Fair Value Units Weighted-Average Grant-Date Fair Value Units Phantom units outstanding at beginning of year $ 68.78 5,477 $ 60.74 9,522 $ 49.47 16,844 Vested 68.78 (5,477 ) 60.69 (9,257 ) 49.55 (13,122 ) Granted 49.30 7,304 69.10 5,212 68.14 5,800 Phantom units outstanding at end of year 49.30 7,304 68.78 5,477 60.74 9,522 WGP LTIP and Anadarko Incentive Plans. For the years ended December 31, 2016 , 2015 and 2014, general and administrative expenses included $5.2 million , $3.9 million and $3.5 million , respectively, of equity-based compensation expense, allocated to the Partnership by Anadarko, for awards granted to the executive officers of the general partner and other employees under the WGP LTIP and the Anadarko Incentive Plans. Of these amounts, $4.2 million , $3.6 million and $3.2 million for the years ended December 31, 2016 , 2015 and 2014, respectively, are reflected as contributions to partners’ capital in the Partnership’s consolidated statements of equity and partners’ capital. As of December 31, 2016 , the Partnership estimated that $10.8 million of estimated unrecognized compensation expense attributable to the Anadarko Incentive Plans will be allocated to the Partnership over a weighted-average period of 2.3 years. Equipment purchases and sales. The following table summarizes the Partnership’s purchases from and sales to Anadarko of pipe and equipment: Year Ended December 31, 2016 2015 2014 2016 2015 2014 thousands Purchases Sales Cash consideration $ 3,965 $ 10,903 $ 22,943 $ 623 $ 925 $ 402 Net carrying value (3,366 ) (6,318 ) (12,210 ) (605 ) (972 ) (375 ) Partners’ capital adjustment $ 599 $ 4,585 $ 10,733 $ 18 $ (47 ) $ 27 Contributions in aid of construction costs from affiliates. On certain of the Partnership’s capital projects, Anadarko is obligated to reimburse the Partnership for all or a portion of project capital expenditures. The majority of such arrangements are associated with projects related to pipeline construction activities and production well tie-ins. The cash receipts resulting from such reimbursements are presented as “Contributions in aid of construction costs from affiliates” within the investing section of the Partnership’s consolidated statements of cash flows. 5. TRANSACTIONS WITH AFFILIATES (CONTINUED) Summary of affiliate transactions. The following table summarizes material affiliate transactions. See Note 2 for discussion of affiliate acquisitions and related funding. Year ended December 31, thousands 2016 2015 2014 Revenues and other (1) $ 1,228,232 $ 1,220,639 $ 1,203,974 Equity income, net – affiliates (1) 78,717 71,251 57,836 Cost of product (1) 80,455 167,354 127,930 Operation and maintenance (2) 72,330 77,061 71,386 General and administrative (3) 38,066 33,903 31,308 Operating expenses 190,851 278,318 230,624 Interest income (4) 16,900 16,900 16,900 Interest expense (5) (7,747 ) 14,398 — Proceeds from the issuance of common units, net of offering expenses (6) 25,000 — — Distributions to unitholders (7) 382,711 314,200 234,024 Above-market component of swap extensions with Anadarko 45,820 18,449 — (1) Represents amounts earned or incurred on and subsequent to the date of acquisition of the Partnership assets, as well as amounts earned or incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets, recognized under gathering, treating or processing agreements, and purchase and sale agreements. (2) Represents expenses incurred on and subsequent to the date of the acquisition of the Partnership assets, as well as expenses incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets. (3) Represents general and administrative expense incurred on and subsequent to the date of the Partnership’s acquisition of the Partnership assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of the Partnership assets by the Partnership. These amounts include equity-based compensation expense allocated to the Partnership by Anadarko (see WES LTIP and WGP LTIP and Anadarko Incentive Plans within this Note 5 ) and amounts charged by Anadarko under the omnibus agreement. (4) Represents interest income recognized on the note receivable from Anadarko. (5) For the years ended December 31, 2016 and 2015, includes amounts related to the Deferred purchase price obligation - Anadarko (see Note 2 and Note 12 ). (6) Represents proceeds from the issuance of 835,841 common units to WGP as partial funding for the acquisition of Springfield (see Note 2 ). (7) Represents distributions paid under the partnership agreement (see Note 3 and Note 4 ). Concentration of credit risk. Anadarko was the only customer from whom revenues exceeded 10% of the Partnership’s consolidated revenues for all periods presented in the consolidated statements of operations. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | 6. INCOME TAXES The components of the Partnership’s income tax expense (benefit) are as follows: Year Ended December 31, thousands 2016 2015 2014 Current income tax expense (benefit) Federal income tax expense (benefit) $ 4,477 $ 32,422 $ (114 ) State income tax expense (benefit) 1,340 1,764 493 Total current income tax expense (benefit) 5,817 34,186 379 Deferred income tax expense (benefit) Federal income tax expense (benefit) 1,622 10,251 35,361 State income tax expense (benefit) 933 1,095 3,321 Total deferred income tax expense (benefit) 2,555 11,346 38,682 Total income tax expense (benefit) $ 8,372 $ 45,532 $ 39,061 Total income taxes differed from the amounts computed by applying the statutory income tax rate to income (loss) before income taxes. The sources of these differences are as follows: Year Ended December 31, thousands except percentages 2016 2015 2014 Income (loss) before income taxes $ 610,666 $ 59,739 $ 495,729 Statutory tax rate — % — % — % Tax computed at statutory rate $ — $ — $ — Adjustments resulting from: Federal taxes on income attributable to Partnership assets pre-acquisition 6,162 42,823 35,716 State taxes on income attributable to Partnership assets pre-acquisition (net of federal benefit) 117 298 864 Texas margin tax expense (benefit) (1) 2,093 2,411 2,481 Income tax expense (benefit) $ 8,372 $ 45,532 $ 39,061 Effective tax rate 1 % 76 % 8 % (1) Includes a reduction of $2.2 million in deferred state income taxes for the year ended December 31, 2015. Texas House Bill 32, signed into law in June 2015, reduced the Texas margin tax rates by 0.25% . The law became effective January 1, 2016. The Partnership is required to include the impact of the law change on its deferred state income taxes in the period enacted. The tax effects of temporary differences that give rise to significant portions of deferred tax assets (liabilities) are as follows: December 31, thousands 2016 2015 Depreciable property $ (4,976 ) $ (138,159 ) Credit carryforwards 498 512 Other intangible assets (1,928 ) (2,070 ) Other 4 13 Net long-term deferred income tax liabilities $ (6,402 ) $ (139,704 ) Credit carryforwards, which are available for use on future income tax returns, consist of $0.5 million of state income tax credits that expire in 2026. |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Dec. 31, 2016 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | 7. PROPERTY, PLANT AND EQUIPMENT A summary of the historical cost of the Partnership’s property, plant and equipment is as follows: December 31, thousands Estimated Useful Life 2016 2015 Land n/a $ 4,012 $ 3,744 Gathering systems and processing complexes 3 to 47 years 6,462,053 6,061,004 Pipelines and equipment 15 to 45 years 139,646 136,290 Assets under construction n/a 226,626 329,887 Other 3 to 40 years 29,605 25,853 Total property, plant and equipment 6,861,942 6,556,778 Accumulated depreciation 1,812,010 1,697,999 Net property, plant and equipment $ 5,049,932 $ 4,858,779 The cost of property classified as “Assets under construction” is excluded from capitalized costs being depreciated. These amounts represent property that is not yet suitable to be placed into productive service as of the respective balance sheet date. Impairments. As of December 31, 2016 , net property, plant and equipment includes impairments of $15.5 million . The Partnership recognized an impairment of $6.1 million at the Newcastle system, which was impaired to its estimated fair value of $3.1 million , using the income approach and Level 3 fair value inputs, due to a reduction in estimated future cash flows caused by the low commodity price environment. Also during 2016, the Partnership recognized impairments of $9.4 million , primarily related to the cancellation of projects at the DJ Basin complex and Springfield and DBJV systems, and the abandonment of compressors at the MIGC system. During 2015, the Partnership recognized impairments of $515.5 million , primarily due to impairments of $280.2 million at the Red Desert complex and $220.9 million at the Hilight system. Using the income approach and Level 3 fair value inputs, the Red Desert complex was impaired to its estimated salvage value of $6.3 million and the Hilight system was impaired to its estimated fair value of $28.8 million . These impairments were triggered by a reduction in estimated future cash flows caused by the low commodity price environment and resulting reduced producer drilling activity and related throughput. Also during 2015, the Partnership recognized impairments of $14.4 million , primarily due to (i) the abandonment of compressors at the MIGC system and (ii) the cancellation of projects at the Non-Operated Marcellus Interest systems and the Brasada, Red Desert and DJ Basin complexes. During 2014, the Partnership recognized impairments of $5.1 million , primarily related to (i) a non-operational plant in the Powder River Basin that was impaired to its estimated salvage value of $2.4 million , using the income approach and Level 3 fair value inputs, (ii) the cancellation of various capital projects by the third-party operator of the Non-Operated Marcellus Interest systems and (iii) a compressor no longer in service at the Hilight system. |
Goodwill and Intangibles
Goodwill and Intangibles | 12 Months Ended |
Dec. 31, 2016 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Goodwill and Intangibles | 8. GOODWILL AND INTANGIBLES Goodwill. Goodwill is recorded when the purchase price of a business acquired exceeds the fair market value of the tangible and separately measurable intangible net assets. In addition, goodwill represents the allocated portion of Anadarko’s midstream goodwill attributed to the Partnership assets acquired from Anadarko. The carrying value of Anadarko’s midstream goodwill represents the excess of the purchase price paid to a third-party entity over the estimated fair value of the identifiable assets acquired and liabilities assumed by Anadarko. Accordingly, the Partnership’s allocated goodwill balance does not represent, and in some cases is significantly different from, the difference between the consideration the Partnership paid for its acquisitions from Anadarko and the fair value of such net assets on their respective acquisition dates. Goodwill is evaluated for impairment annually (see Note 1 ). Estimating the fair value of the reporting units was not necessary based on the qualitative evaluation as of October 1, 2016 , and no goodwill impairment has been recognized in these consolidated financial statements. Procedures were also performed in the fourth quarter of 2016 to review any changes in circumstances subsequent to the annual test, including changes in commodity prices. These procedures also indicated no impairment. Other intangible assets. The intangible asset balance in the consolidated balance sheets includes the fair value, net of amortization, of (i) contracts assumed by the Partnership in connection with the Platte Valley acquisition in February 2011, which are being amortized on a straight-line basis over 50 years , (ii) interconnect agreements at Chipeta entered into in November 2012, which are being amortized on a straight-line basis over 10 years , and (iii) contracts assumed by the Partnership in connection with the DBM acquisition in November 2014, which are being amortized on a straight-line basis over 30 years . The Partnership assesses intangible assets for impairment together with related underlying long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. See Property, plant and equipment in Note 1 for further discussion of management’s process to evaluate potential impairment of long-lived assets. No intangible asset impairment has been recognized in these consolidated financial statements. The following table presents the gross carrying amount and accumulated amortization of other intangible assets: December 31, thousands 2016 2015 Gross carrying amount $ 868,035 $ 868,035 Accumulated amortization (64,337 ) (35,908 ) Other intangible assets $ 803,698 $ 832,127 Amortization expense for intangible assets was $28.4 million , $28.2 million and $4.3 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. An estimated $28.4 million of intangible asset amortization will be recorded for each of the next five years. |
Equity Investments
Equity Investments | 12 Months Ended |
Dec. 31, 2016 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Equity Investments | 9. EQUITY INVESTMENTS The following table presents the activity in the Partnership’s equity investments for the years ended December 31, 2016 and 2015: Equity Investments thousands Fort (1) White (2) Rendezvous (3) Mont (4) TEG (5) TEP (6) FRP (7) Total Balance at December 31, 2014 $ 25,933 $ 44,315 $ 56,336 $ 121,337 $ 16,790 $ 198,793 $ 170,988 $ 634,492 Investment earnings (loss), net of amortization (3,200 ) 14,770 2,292 23,570 586 16,088 17,145 71,251 Contributions — 8,512 — (432 ) — 1,880 1,482 11,442 Distributions (5,611 ) (14,188 ) (4,233 ) (24,248 ) (803 ) (16,340 ) (16,631 ) (82,054 ) Distributions in excess of cumulative earnings (8) — (2,970 ) (3,482 ) (3,138 ) (290 ) (5,618 ) (746 ) (16,244 ) Balance at December 31, 2015 $ 17,122 $ 50,439 $ 50,913 $ 117,089 $ 16,283 $ 194,803 $ 172,238 $ 618,887 Investment earnings (loss), net of amortization 608 13,858 1,931 26,204 708 16,683 18,725 78,717 Contributions — 441 — — 166 (580 ) — 27 Distributions (1,543 ) (13,277 ) (3,873 ) (26,243 ) (730 ) (16,934 ) (19,585 ) (82,185 ) Distributions in excess of cumulative earnings (8) (3,354 ) (4,142 ) (2,232 ) (4,245 ) (581 ) (4,778 ) (1,906 ) (21,238 ) Balance at December 31, 2016 $ 12,833 $ 47,319 $ 46,739 $ 112,805 $ 15,846 $ 189,194 $ 169,472 $ 594,208 (1) The Partnership has a 14.81% interest in Fort Union, a joint venture that owns a gathering pipeline and treating facilities in the Powder River Basin. Anadarko is the construction manager and physical operator of the Fort Union facilities. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the owners’ firm gathering agreements, require 65% or unanimous approval of the owners. (2) The Partnership has a 10% interest in White Cliffs, a limited liability company that owns a crude oil pipeline that originates in Platteville, Colorado and terminates in Cushing, Oklahoma. The third-party majority owner is the manager of the White Cliffs operations. Certain business decisions, including, but not limited to, approval of annual budgets and decisions with respect to significant expenditures, contractual commitments, acquisitions, material financings, dispositions of assets or admitting new members, require more than 75% approval of the members. (3) The Partnership has a 22% interest in Rendezvous, a limited liability company that operates gas gathering facilities in Southwestern Wyoming. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the members’ gas servicing agreements, require unanimous approval of the members. (4) The Partnership has a 25% interest in the Mont Belvieu JV, an entity formed to design, construct, and own two fractionation trains located in Mont Belvieu, Texas. A third party is the operator of the Mont Belvieu JV fractionation trains. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require 50% or unanimous approval of the owners. (5) The Partnership has a 20% interest in TEG, an entity that consists of two NGL gathering systems that link natural gas processing plants to TEP. Enbridge Midcoast Energy, LP (“Enbridge”) is the operator of the two gathering systems. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the delegation, creation, appointment, or removal of officer positions require more than 50% approval of the members. (6) The Partnership has a 20% interest in TEP, which consists of an NGL pipeline that originates in Skellytown, Texas and extends to Mont Belvieu, Texas. Enterprise Products Operating LLC (“Enterprise”) is the operator of TEP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than 50% approval of the members. (7) The Partnership has a 33.33% interest in the FRP, an NGL pipeline that extends from Weld County, Colorado to Skellytown, Texas. Enterprise is the operator of FRP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than 50% approval of the members. (8) Distributions in excess of cumulative earnings, classified as investing cash flows in the consolidated statements of cash flows, is calculated on an individual investment basis. 9. EQUITY INVESTMENTS (CONTINUED) The investment balance at December 31, 2016 , includes $38.2 million for the purchase price allocated to the investment in Rendezvous in excess of the historic cost basis of Western Gas Resources, Inc. (“WGRI”), the entity that previously owned the interest in Rendezvous, which Anadarko acquired in August 2006. This excess balance is attributable to the difference between the fair value and book value of such gathering and treating facilities (at the time WGRI was acquired by Anadarko) and is being amortized over the remaining estimated useful life of those facilities. The investment balance in White Cliffs at December 31, 2016 , is $7.5 million less than the Partnership’s underlying equity in White Cliffs’ net assets, primarily due to the Partnership recording the acquisition of its initial 0.4% interest in White Cliffs at Anadarko’s historic carrying value. This difference is being amortized to equity income, net – affiliates over the remaining estimated useful life of the White Cliffs pipeline. During the year ended December 31, 2015, an impairment loss was recognized by the operator of Fort Union. The Partnership’s 14.81% share of the impairment loss was $9.5 million recorded in Equity income, net – affiliates in the consolidated statements of operations. Management evaluates its equity investments for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value that is other than temporary. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether the investment has been impaired. Management assesses the fair value of equity investments using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third-party comparable sales and discounted cash flow models. If the estimated fair value is less than the carrying value, the excess of the carrying value over the estimated fair value is recognized as an impairment loss. The following tables present the summarized combined financial information for the Partnership’s equity investments (amounts represent 100% of investee financial information): Year Ended December 31, thousands 2016 2015 2014 Consolidated Statements of Income Revenues $ 687,554 $ 667,554 $ 548,629 Operating income 428,454 359,899 336,188 Net income 427,511 359,443 333,705 December 31, thousands 2016 2015 Consolidated Balance Sheets Current assets $ 118,472 $ 154,937 Property, plant and equipment, net 2,626,466 2,716,078 Other assets 39,802 43,713 Total assets $ 2,784,740 $ 2,914,728 Current liabilities 63,468 78,116 Non-current liabilities 6,662 9,072 Equity 2,714,610 2,827,540 Total liabilities and equity $ 2,784,740 $ 2,914,728 |
Components of Working Capital
Components of Working Capital | 12 Months Ended |
Dec. 31, 2016 | |
Components Of Working Capital [Abstract] | |
Components of Working Capital | 10. COMPONENTS OF WORKING CAPITAL A summary of accounts receivable, net is as follows: December 31, thousands 2016 2015 Trade receivables, net $ 192,808 $ 143,557 Other receivables, net 30,415 49,772 Total accounts receivable, net $ 223,223 $ 193,329 A summary of other current assets is as follows: December 31, thousands 2016 2015 Natural gas liquids inventory $ 7,126 $ 2,403 Imbalance receivables 3,483 2,122 Prepaid insurance 2,257 2,296 Other — 1,034 Total other current assets $ 12,866 $ 7,855 A summary of accrued liabilities is as follows: December 31, thousands 2016 2015 Accrued capital expenditures $ 79,253 $ 61,454 Accrued plant purchases 44,538 16,425 Accrued interest expense 39,826 26,194 Short-term asset retirement obligations 3,114 3,677 Short-term remediation and reclamation obligations 630 1,136 Income taxes payable 1,006 770 Other 532 9,363 Total accrued liabilities $ 168,899 $ 119,019 |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | 11. ASSET RETIREMENT OBLIGATIONS The following table provides a summary of changes in asset retirement obligations: Year Ended December 31, thousands 2016 2015 Carrying amount of asset retirement obligations at beginning of year $ 130,631 $ 119,855 Liabilities incurred 5,515 9,490 Liabilities settled (10,650 ) (7,905 ) Accretion expense 6,794 6,381 Revisions in estimated liabilities 10,117 2,810 Carrying amount of asset retirement obligations at end of year $ 142,407 $ 130,631 The liabilities incurred for the year ended December 31, 2016 , represented additions in asset retirement obligations primarily due to capital expansions at the DJ Basin and DBM complexes and the DBJV system. Revisions in estimated liabilities for the year ended December 31, 2016 , are related to (i) changes in expected settlement costs and timing primarily at the MGR assets, Granger complex and the Hilight and Springfield systems, and (ii) changes in property lives primarily at the DJ Basin and DBM complexes and the Hilight, Springfield and Haley systems. The liabilities incurred for the year ended December 31, 2015 , represented additions in asset retirement obligations primarily due to capital expansions at the DJ Basin, Granger and Brasada complexes and the Hilight and Non-Operated Marcellus Interest systems. Revisions in estimated liabilities for the year ended December 31, 2015 , are related to (i) changes in expected timing of settlement primarily at the DBM and DJ Basin complexes and Hugoton and DBJV systems, and (ii) changes in property lives primarily at the Granger, Brasada and Red Desert complexes and the Hilight and Non-Operated Marcellus Interest systems. |
Debt and Interest Expense
Debt and Interest Expense | 12 Months Ended |
Dec. 31, 2016 | |
Debt Instruments [Abstract] | |
Debt and Interest Expense | 12. DEBT AND INTEREST EXPENSE At December 31, 2016 , the Partnership’s debt consisted of 5.375% Senior Notes due 2021 (the “2021 Notes”), 4.000% Senior Notes due 2022 (the “2022 Notes”), 2.600% Senior Notes due 2018 (the “2018 Notes”), 5.450% Senior Notes due 2044 (the “2044 Notes”), 3.950% Senior Notes due 2025 (the “2025 Notes”), and 4.650% Senior Notes due 2026 (the “2026 Notes”). The following table presents the Partnership’s outstanding debt as of December 31, 2016 and 2015: December 31, 2016 December 31, 2015 thousands Principal Carrying Value Fair Value (1) Principal Carrying Value Fair Value (1) 2021 Notes $ 500,000 $ 494,734 $ 536,252 $ 500,000 $ 493,711 $ 513,645 2022 Notes 670,000 668,634 681,723 670,000 668,432 595,744 2018 Notes 350,000 349,188 351,531 350,000 348,706 339,293 2044 Notes 600,000 593,132 615,753 400,000 389,707 321,499 2025 Notes 500,000 490,971 492,499 500,000 490,095 422,285 2026 Notes 500,000 494,802 518,441 — — — RCF — — — 300,000 300,000 300,000 Total long-term debt $ 3,120,000 $ 3,091,461 $ 3,196,199 $ 2,720,000 $ 2,690,651 $ 2,492,466 (1) Fair value is measured using the market approach and Level 2 inputs. 12. DEBT AND INTEREST EXPENSE (CONTINUED) Debt activity. The following table presents the debt activity of the Partnership for the years ended December 31, 2016 and 2015: thousands Carrying Value Balance at December 31, 2014 $ 2,408,785 RCF borrowings 400,000 Issuance of 2025 Notes 500,000 Repayments of RCF borrowings (610,000 ) Other (8,134 ) Balance at December 31, 2015 $ 2,690,651 RCF borrowings 600,000 Issuance of 2026 Notes 500,000 Issuance of 2044 Notes 200,000 Repayments of RCF borrowings (900,000 ) Other 810 Balance at December 31, 2016 $ 3,091,461 Senior Notes. In October 2016, the Partnership issued an additional $200.0 million in aggregate principal amount of 2044 Notes at a price to the public of 102.776% of the face amount plus accrued interest from October 1, 2016 to the settlement date. These notes were offered as additional notes under the indenture governing the 2044 Notes issued in March 2014 and are treated as a single class of securities with the 2044 Notes under such indenture. Including the effects of (i) the issuance premium for the October 2016 offering of the 2044 Notes, (ii) the issuance discount for the March 2014 offering of the 2044 Notes and (iii) the underwriting discounts, the effective interest rate of the 2044 Notes is 5.530% . Proceeds (net of underwriting discount of $1.8 million and debt issuance costs and excluding accrued interest from October 1, 2016 to the settlement date) were used to repay amounts then outstanding under the RCF and for general partnership purposes, including capital expenditures. The 2026 Notes issued in July 2016 were offered at a price to the public of 99.796% of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rate of the 2026 Notes is 4.787% . Interest is paid semi-annually on January 1 and July 1 of each year. Proceeds (net of underwriting discount of $3.1 million , original issue discount and debt issuance costs) were used to repay a portion of the amount outstanding under the RCF. The 2025 Notes issued in June 2015 were offered at a price to the public of 98.789% of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rate of the 2025 Notes is 4.205% . Interest is paid semi-annually on June 1 and December 1 of each year. Proceeds (net of underwriting discount of $3.3 million , original issue discount and debt issuance costs) were used to repay a portion of the amount outstanding under the RCF. At December 31, 2016 , the Partnership was in compliance with all covenants under the indentures governing its outstanding notes. Revolving credit facility. The $1.2 billion RCF, which is expandable to a maximum of $1.5 billion , bears interest at the London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 0.975% to 1.45% , or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.5% , or (c) LIBOR plus 1% , in each case plus applicable margins currently ranging from zero to 0.45% , based upon the Partnership’s senior unsecured debt rating. In December 2016, the RCF was amended to extend the maturity date from February 2019 to February 2020. The Partnership is required to pay a quarterly facility fee currently ranging from 0.15% to 0.30% of the commitment amount (whether used or unused), based upon the Partnership’s senior unsecured debt rating. The facility fee rate was 0.20% at December 31, 2016 and 2015 . 12. DEBT AND INTEREST EXPENSE (CONTINUED) As of December 31, 2016 , the Partnership had no outstanding RCF borrowings and $4.9 million in outstanding letters of credit, resulting in $1.195 billion available for borrowing under the RCF. As of December 31, 2016 and 2015 , the interest rate on the outstanding RCF borrowings was zero and 1.73% , respectively. At December 31, 2016 , the Partnership was in compliance with all covenants under the RCF. All notes and obligations under the RCF are recourse to the Partnership’s general partner. The Partnership’s general partner is indemnified by wholly owned subsidiaries of Anadarko against any claims made against the general partner for the Partnership’s long-term debt and/or borrowings under the RCF. Interest rate agreements. In June 2016, the Partnership entered into a U.S. Treasury rate lock agreement to mitigate the risk of rising interest rates on existing variable-rate debt expected to be refinanced during the third quarter of 2016. The rate lock agreement was not designated as a cash flow hedge and was settled in June 2016 upon the offering of the 2026 Notes that closed in July 2016. The Partnership realized a loss of $0.2 million at settlement, which is included in Other income (expense), net in the Partnership’s consolidated statements of operations. Interest expense. The following table summarizes the amounts included in interest expense: Year Ended December 31, thousands 2016 2015 2014 Third parties Long-term debt $ 121,832 $ 102,058 $ 81,495 Amortization of debt issuance costs and commitment fees 6,398 5,734 5,103 Capitalized interest (5,562 ) (8,318 ) (9,832 ) Total interest expense – third parties 122,668 99,474 76,766 Affiliates Deferred purchase price obligation – Anadarko (1) (7,747 ) 14,398 — Total interest expense – affiliates (7,747 ) 14,398 — Interest expense $ 114,921 $ 113,872 $ 76,766 (1) See Note 2 for a discussion of the Deferred purchase price obligation - Anadarko. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | 13. COMMITMENTS AND CONTINGENCIES Environmental obligations. The Partnership is subject to various environmental-remediation obligations arising from federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. As of December 31, 2016 and 2015, the consolidated balance sheets included $2.2 million and $2.6 million , respectively, of liabilities for remediation and reclamation obligations. The current portion of these amounts is included in Accrued liabilities and the long-term portion of these amounts is included in Asset retirement obligations and other. The recorded obligations do not include any anticipated insurance recoveries. The majority of payments related to these obligations are expected to be made over the next five years. Management regularly monitors the remediation and reclamation process and the liabilities recorded and believes that the amounts reflected in the Partnership’s recorded environmental obligations are adequate to fund remedial actions to comply with present laws and regulations, and that the ultimate liability for these matters, if any, will not differ materially from recorded amounts nor materially affect the Partnership’s overall results of operations, cash flows or financial condition. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental issues will not be discovered. See Note 10 and Note 11 . Litigation and legal proceedings. From time to time, the Partnership is involved in legal, tax, regulatory and other proceedings in various forums regarding performance, contracts and other matters that arise in the ordinary course of business. Management is not aware of any such proceeding the final disposition of which could have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows. Other commitments. The Partnership has short-term payment obligations, or commitments, related to its capital spending programs, as well as those of its unconsolidated affiliates. As of December 31, 2016 , the Partnership had unconditional payment obligations for services to be rendered or products to be delivered in connection with its capital projects of $50.9 million , the majority of which is expected to be paid in the next twelve months. These commitments relate primarily to the construction of Train VI at the DBM complex, expansion projects at the DBJV system and the DBM complex and the construction of two produced-water disposal systems in West Texas. Lease commitments. Anadarko, on behalf of the Partnership, has entered into lease agreements for corporate offices, shared field offices and a warehouse supporting the Partnership’s operations, for which Anadarko charges the Partnership rent. The leases for the corporate offices and shared field offices extend through 2017 and 2019, respectively, and the lease for the warehouse extends through February 2017. Rent expense associated with the office, warehouse and equipment leases was $35.9 million , $34.1 million and $25.9 million for the years ended December 31, 2016 , 2015 and 2014, respectively. The amounts in the table below represent existing contractual operating lease obligations as of December 31, 2016 , that may be assigned or otherwise charged to the Partnership pursuant to the reimbursement provisions of the omnibus agreement: thousands Operating Leases 2017 $ 7,322 2018 898 2019 764 2020 122 2021 — Thereafter — Total $ 9,106 |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2016 | |
Subsequent Events [Abstract] | |
Subsequent Events | 14. SUBSEQUENT EVENTS On February 9, 2017, the Partnership entered into an agreement with Williams Partners L.P. (“WPZ”) whereby the Partnership will acquire WPZ’s 50% non-operated interest in the DBJV system in exchange for the Partnership’s 33.75% interest in the Non-Operated Marcellus Interest systems and $155.0 million in cash. The Partnership currently holds a 50% interest in, and operates, the DBJV system. The Partnership expects to fund the cash consideration through borrowings under its RCF and to close the transaction, subject to standard closing conditions and adjustments, in the first quarter of 2017. Effective February 13, 2017, Donald R. Sinclair resigned from his positions as President and Chief Executive Officer and as a member of the Board of Directors of the Partnership’s general partner. Also on February 13, 2017, the Board of Directors appointed Benjamin M. Fink to be President and Chief Executive Officer of the Partnership’s general partner and also appointed him to the Board of Directors. In addition, on February 13, 2017, the Board of Directors appointed Craig W. Collins as Senior Vice President and Chief Operating Officer of the general partner and Philip H. Peacock as Senior Vice President, General Counsel and Corporate Secretary of the general partner. On February 21, 2017, Anadarko notified the Partnership that it elected to defer the conversion date of the Class C units from December 31, 2017 to March 1, 2020. Pursuant to a Consent and Conversion Agreement (the “Conversion Agreement”), dated February 22, 2017, among the Partnership and the holders of the Series A Preferred units, the Partnership and the holders of the Series A Preferred units have agreed to convert on a one-for-one basis 50% of the outstanding Series A Preferred units into WES common units effective as of February 23, 2017, and convert the remaining Series A Preferred units on May 2, 2017 (collectively, the “Early Conversion”). The WES common units to be issued in connection with the Early Conversion will be undertaken in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof. In connection with the Early Conversion, the Partnership (i) agreed to amend the registration rights agreement with the holders of the Series A Preferred units through the Conversion Agreement and use its commercially reasonable efforts to file a registration statement by March 10, 2017, to permit the public resale of the WES common units received by the holders of the Series A Preferred units and for such registration statement to be declared effective no later than March 14, 2018, and (ii) entered into an amendment to the Partnership’s limited partnership agreement (the “Second LPA Amendment”) on February 22, 2017, for certain matters related to the tax basis of the WES common units received in the Early Conversion. |
Summary of Significant Accoun24
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Consolidation policy | Basis of presentation. The following table outlines the Partnership’s ownership interests and the accounting method of consolidation used in the Partnership’s consolidated financial statements: Percentage Interest Equity investments (1) Fort Union 14.81 % White Cliffs 10 % Rendezvous 22 % Mont Belvieu JV 25 % TEP 20 % TEG 20 % FRP 33.33 % Proportionate consolidation (2) Non-Operated Marcellus Interest systems 33.75 % Anadarko-Operated Marcellus Interest systems 33.75 % Newcastle system 50 % DBJV system 50 % Springfield system 50.1 % Full consolidation Chipeta (3) 75 % (1) Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. “Equity investment throughput” refers to the Partnership’s share of average throughput for these investments. (2) The Partnership proportionately consolidates its associated share of the assets, liabilities, revenues and expenses attributable to these assets. (3) The 25% interest in Chipeta Processing LLC (“Chipeta”) held by a third-party member is reflected within noncontrolling interest in the consolidated financial statements. The consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”). The consolidated financial statements include the accounts of the Partnership and entities in which it holds a controlling financial interest. All significant intercompany transactions have been eliminated. |
Business combinations policy | Presentation of Partnership assets. The term “Partnership assets” refers to the assets owned and interests accounted for under the equity method (see Note 9 ) by the Partnership as of December 31, 2016 . Because Anadarko controls the Partnership through its ownership and control of WGP, which owns the Partnership’s entire general partner interest, each acquisition of Partnership assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by the Partnership. Further, after an acquisition of Partnership assets from Anadarko, the Partnership may be required to recast its financial statements to include the activities of such Partnership assets from the date of common control. See Note 2 . For those periods requiring recast, the consolidated financial statements for periods prior to the Partnership’s acquisition of the Partnership assets from Anadarko have been prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the Partnership assets during the periods reported. Net income (loss) attributable to the Partnership assets acquired from Anadarko for periods prior to the Partnership’s acquisition of the Partnership assets is not allocated to the limited partners. |
Use of estimates policy | Use of estimates. In preparing financial statements in accordance with GAAP, management makes informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. Management evaluates its estimates and related assumptions regularly, using historical experience and other methods considered reasonable. Changes in facts and circumstances or additional information may result in revised estimates and actual results may differ from these estimates. Effects on the business, financial condition and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revisions become known. The information furnished herein reflects all normal recurring adjustments which are, in the opinion of management, necessary for a fair presentation of the consolidated financial statements, and certain prior-period amounts have been reclassified to conform to the current-year presentation. |
Fair value policy | Fair value. The fair-value-measurement standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which they are observable. The three levels of the fair value hierarchy are as follows: Level 1 – Inputs represent unadjusted quoted prices in active markets for identical assets or liabilities. Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs). Level 3 – Inputs that are not observable from objective sources, such as management’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in management’s internally developed present value of future cash flows model that underlies the fair value measurement). When a fair value measurement is required and there is not a market-observable price for the asset or liability or a market-observable price for a similar asset or liability, the cost, income, or market valuation approach is used, depending on the quality of information available to support management’s assumptions. The cost approach is based on management’s best estimate of the current asset replacement cost. The income approach uses management’s best assumptions regarding expectations of projected cash flows, and discounts the expected cash flows using a commensurate risk adjusted discount rate. Such evaluations involve a significant amount of judgment, since the results are based on expected future events or conditions, such as sales prices, estimates of future throughput, capital and operating costs and the timing thereof, economic and regulatory climates and other factors. A multiple approach uses management’s best assumptions regarding expectations of projected earnings before interest, taxes, depreciation, and amortization (“EBITDA”) and the multiple of that EBITDA that a buyer would pay to acquire an asset. Management’s estimates of future net cash flows and EBITDA are inherently imprecise because they reflect management’s expectation of future conditions that are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs and other factors, and are consistent with assumptions used in the Partnership’s business plans and investment decisions. Nonfinancial assets and liabilities initially measured at fair value include certain assets and liabilities acquired in a third-party business combination, assets and liabilities exchanged in non-monetary transactions, long-lived assets (asset groups), goodwill and other intangibles, initial recognition of asset retirement obligations, and initial recognition of environmental obligations assumed in a third-party acquisition. Impairment analyses for long-lived assets, goodwill and other intangibles, and the initial recognition of asset retirement obligations and environmental obligations use Level 3 inputs. The fair value of debt reflects any premium or discount for the difference between the stated interest rate and the quarter-end market interest rate, and is based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments. See Note 12 . The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable reported on the consolidated balance sheets approximate fair value due to the short-term nature of these items. |
Cash equivalents policy | Cash equivalents. All highly liquid investments with a maturity of three months or less when purchased are considered to be cash equivalents. |
Bad-debt reserve policy | Bad-debt reserve. Revenues are primarily from Anadarko, for which no credit limit is maintained. Exposure to bad debts is analyzed on a customer-by-customer basis for its third-party accounts receivable and the Partnership may establish credit limits for significant third-party customers. As of December 31, 2016 and 2015 , bad-debt reserve was immaterial. |
Imbalances policy | Imbalances. The consolidated balance sheets include imbalance receivables and payables resulting from differences in volumes received into the Partnership’s systems and volumes delivered by the Partnership to customers’ pipelines. Volumes owed to or by the Partnership that are subject to monthly cash settlement are valued according to the terms of the contract as of the balance sheet dates and reflect market index prices. Other volumes owed to or by the Partnership are valued at the Partnership’s weighted-average cost as of the balance sheet dates and are settled in-kind. As of December 31, 2016 , imbalance receivables and payables were $3.5 million and $3.0 million , respectively. As of December 31, 2015 , imbalance receivables and payables were $2.1 million and $1.6 million , respectively. Net changes in imbalance payables and receivables are reported in cost of product. |
Inventory policy | Inventory. The cost of NGLs inventories is determined by the weighted-average cost method on a location-by-location basis. Inventory is stated at the lower of weighted-average cost or market value and is reported in other current assets in the consolidated balance sheets. See Note 10 . |
Property, plant and equipment policy | Property, plant and equipment. Property, plant and equipment are generally stated at the lower of historical cost less accumulated depreciation or fair value, if impaired. Because acquisitions of assets from Anadarko are transfers of net assets between entities under common control, the assets acquired from Anadarko are initially recorded at Anadarko’s historic carrying value. The difference between the carrying value of net assets acquired from Anadarko and the consideration paid is recorded as an adjustment to partners’ capital. Assets acquired in a business combination or non-monetary exchange with a third party are initially recorded at fair value. All construction-related direct labor and material costs are capitalized. The cost of renewals and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects that do not extend the useful life or increase the expected output of property, plant and equipment is expensed as incurred. Depreciation is computed using the straight-line method based on estimated useful lives and salvage values of assets. However, subsequent events could cause a change in estimates, thereby impacting future depreciation amounts. Uncertainties that may impact these estimates include, but are not limited to, changes in laws and regulations relating to environmental matters, including air and water quality, restoration and abandonment requirements, economic conditions, and supply and demand in the area. Management evaluates the ability to recover the carrying amount of its long-lived assets to determine whether its long-lived assets have been impaired. Impairments exist when the carrying amount of an asset exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the long-lived asset is not recoverable based on the estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying amount over its estimated fair value, such that the asset’s carrying amount is adjusted to its estimated fair value with an offsetting charge to impairment expense. Refer to Note 7 for a description of impairments recorded during the years ended December 31, 2016 , 2015 and 2014 . 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) Insurance recoveries. Involuntary conversions result from the loss of an asset because of some unforeseen event (e.g., destruction due to fire). Some of these events are insurable and result in property damage insurance recovery. Amounts that are received from insurance carriers are net of any deductibles related to the covered event. A receivable is recorded from insurance to the extent a loss is recognized from an involuntary conversion event and the likelihood of recovering such loss is deemed probable. To the extent that any insurance claim receivables are later judged not probable of recovery (e.g., due to new information), such amounts are expensed. A gain on involuntary conversion is recognized when the amount received from insurance exceeds the net book value of the retired asset(s). In addition, gains related to insurance recoveries are not recognized until all contingencies related to such proceeds have been resolved, that is, a cash payment is received from the insurance carrier or there is a binding settlement agreement with the carrier that clearly states that a payment will be made. To the extent that an asset is rebuilt, the associated expenditures are capitalized, as appropriate, in the consolidated balance sheets and presented as capital expenditures in the consolidated statements of cash flows. With respect to business interruption insurance claims, income is recognized only when cash proceeds are received from insurers, which are presented in the consolidated statements of operations as a component of Operating income (loss). On December 3, 2015, there was an initial fire and secondary explosion at the processing facility within the DBM complex. The majority of the damage from the incident was to the liquid handling facilities and the amine treating units at the inlet of the complex. Train II (with capacity of 100 MMcf/d) sustained the most damage of the processing trains and returned to service in December 2016. Train III (with capacity of 200 MMcf/d) experienced minimal damage and returned to full service in May 2016. For the year ended December 31, 2015, $20.3 million of losses were recorded in Gain (loss) on divestiture and other, net in the consolidated statements of operations, related to this involuntary conversion event based on the difference between the net book value of the affected assets and the insurance claim receivable. As of December 31, 2016 and 2015 , the consolidated balance sheets include receivables of $30.0 million and $49.0 million , respectively, for a property insurance claim related to the incident at the DBM complex. As of December 31, 2016 , the Partnership had received $33.8 million in cash proceeds from insurers related to the incident at the DBM complex, including $16.3 million in proceeds from business interruption insurance claims and $17.5 million in proceeds from property insurance claims. Contributions in aid of construction costs from affiliates. On certain of the Partnership’s capital projects, Anadarko is obligated to reimburse the Partnership for all or a portion of project capital expenditures. The majority of such arrangements are associated with projects related to pipeline construction activities and production well tie-ins. The cash receipts resulting from such reimbursements are presented as “Contributions in aid of construction costs from affiliates” within the investing section of the Partnership’s consolidated statements of cash flows. See Note 5 . |
Capitalized interest policy | Capitalized interest. Interest is capitalized as part of the historical cost of constructing assets for significant projects that are in progress. Capitalized interest is determined by multiplying the Partnership’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once the construction of an asset subject to interest capitalization is completed and the asset is placed in service, the associated capitalized interest is expensed through depreciation or impairment, together with other capitalized costs related to that asset. |
Goodwill policy | Goodwill. Goodwill is recorded when the purchase price of a business acquired exceeds the fair market value of the tangible and separately measurable intangible net assets. Refer to Note 8 for a discussion of goodwill. Goodwill is evaluated for impairment annually, as of October 1, or more often as facts and circumstances warrant. The Partnership has allocated goodwill on its two reporting units: (i) gathering and processing and (ii) transportation. An initial qualitative assessment is performed prior to proceeding to the comparison of the fair value of each reporting unit to which goodwill has been assigned, to the carrying amount of net assets, including goodwill, of each reporting unit. If concluded, based on qualitative factors, that it is more likely than not that the fair value of the reporting unit exceeds its carrying amount, then goodwill is not impaired, and estimating the fair value of the reporting unit is not necessary. If the carrying amount of the reporting unit exceeds its fair value, based on a hypothetical purchase price allocation, goodwill is written down to its implied fair value through a charge to operating expense. The carrying value of goodwill after such an impairment would represent a Level 3 fair value measurement. |
Other intangible assets policy | Other intangible assets. The Partnership assesses intangible assets, as described in Note 8 , for impairment together with related underlying long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. See Property, plant and equipment within this Note 1 for further discussion of management’s process to evaluate potential impairment of long-lived assets. |
Asset retirement obligations and environmental expenditures policy | Asset retirement obligations. Management recognizes a liability based on the estimated costs of retiring tangible long-lived assets. The liability is recognized at fair value, measured using discounted expected future cash outflows for the asset retirement obligation when the obligation originates, which generally is when an asset is acquired or constructed. The carrying amount of the associated asset is increased commensurate with the liability recognized. Over time, the discounted liability is adjusted to its expected settlement value through accretion expense, which is reported within depreciation and amortization in the consolidated statements of operations. Subsequent to the initial recognition, the liability is also adjusted for any changes in the expected value of the retirement obligation (with a corresponding adjustment to property, plant and equipment) until the obligation is settled. Revisions in estimated asset retirement obligations may result from changes in estimated inflation rates, discount rates, asset retirement costs and the estimated timing of settling asset retirement obligations. See Note 11 . Environmental expenditures. The Partnership expenses environmental obligations related to conditions caused by past operations that do not generate current or future revenues. Environmental obligations related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Liabilities are recorded when the necessity for environmental remediation or other potential environmental liabilities becomes probable and the costs can be reasonably estimated. Accruals for estimated losses from environmental remediation obligations are recognized no later than at the time of the completion of the remediation feasibility study. These accruals are adjusted as additional information becomes available or as circumstances change. Costs of future expenditures for environmental-remediation obligations are not discounted to their present value. See Note 13 . |
Segments policy | Segments. The Partnership’s operations are organized into a single operating segment, the assets of which gather, process, compress, treat and transport Anadarko’s and third-parties’ natural gas, condensate, NGLs and crude oil in the United States. |
Revenues and cost of product policy | Revenues and cost of product. Under its fee-based gathering, treating and processing arrangements, the Partnership is paid a fixed fee based on the volume and thermal content of natural gas and recognizes revenues for its services in the month such services are performed. Producers’ wells are connected to the Partnership’s gathering systems for delivery of natural gas to the Partnership’s processing or treating plants, where the natural gas is processed to extract NGLs and condensate or treated in order to satisfy pipeline specifications. In some areas, where no processing is required, the producers’ gas is gathered and delivered to pipelines for market delivery. Under cost-of-service gathering agreements, fees are earned for gathering and compression services based on rates calculated in a cost-of-service model and reviewed periodically over the life of the agreements. Under percent-of-proceeds contracts, revenue is recognized when the natural gas, NGLs or condensate is sold. The percentage of the product sale ultimately paid to the producer is recorded as a related cost of product expense. In certain circumstances, the Partnership purchases natural gas volumes at the wellhead for gathering and processing. As a result, the Partnership has volumes of NGLs and condensate to sell and volumes of residue to sell, to use for system fuel or to satisfy keep-whole obligations. In addition, depending upon specific contract terms, condensate and NGLs recovered during gathering and processing are either returned to the producer or retained and sold. Under keep-whole contracts, when condensate or NGLs are retained and sold, producers are kept whole for the condensate or NGL volumes through the receipt of a thermally equivalent volume of residue. The keep-whole contract conveys an economic benefit to the Partnership when the combined value of the individual NGLs is greater in the form of liquids than as a component of the natural gas stream; however, the Partnership is adversely impacted when the value of the NGLs is lower than the value of the natural gas stream including the liquids. The Partnership has commodity price swap agreements with Anadarko to mitigate exposure to a majority of the commodity price risk inherent in our percent-of-proceeds and keep-whole contracts. See Note 5 . Revenue is recognized from the sale of condensate and NGLs upon transfer of title, and related purchases are recorded as cost of product. The Partnership earns transportation revenues through firm contracts that obligate each of its customers to pay a monthly reservation or demand charge regardless of the pipeline capacity used by that customer. An additional commodity usage fee is charged to the customer based on the actual volume of natural gas transported. Transportation revenues are also generated from interruptible contracts pursuant to which a fee is charged to the customer based on volumes transported through the pipeline. Revenues for transportation of natural gas and NGLs are recognized over the period of firm transportation contracts or, in the case of usage fees and interruptible contracts, when the volumes are received into the pipeline. From time to time, certain revenues may be subject to refund pending the outcome of rate matters before the Federal Energy Regulatory Commission (the “FERC”), and refund reserve liabilities are established where appropriate. Proceeds from the sale of residue, NGLs and condensate are reported as revenues from natural gas, natural gas liquids and condensate sales in the consolidated statements of operations. Revenues attributable to the fixed-fee component of gathering and processing contracts as well as demand charges and commodity usage fees on transportation contracts are reported as revenues from gathering, processing and transportation of natural gas and natural gas liquids in the consolidated statements of operations. |
Equity-based compensation policy | Equity-based compensation. Phantom unit awards are granted under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (the “WES LTIP”). The WES LTIP was adopted by the general partner of the Partnership and permits the issuance of up to 2,250,000 units, of which 2,120,711 units remained available for future issuance as of December 31, 2016 . Upon vesting of each phantom unit awarded under the WES LTIP, the holder will receive common units of the Partnership or, at the discretion of the Board of Directors of our general partner, (the “Board of Directors”), cash in an amount equal to the market value of common units of the Partnership on the vesting date. Equity-based compensation expense attributable to grants made under the WES LTIP impacts cash flows from operating activities only to the extent cash payments are made to a participant in lieu of issuance of common units to the participant. Stock-based compensation expense attributable to awards granted under the WES LTIP is amortized over the vesting periods applicable to the awards. Additionally, general and administrative expenses include equity-based compensation costs allocated by Anadarko to the Partnership for grants made pursuant to (i) the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan (the “WGP LTIP”) and (ii) the Anadarko Petroleum Corporation 2008 and 2012 Omnibus Incentive Compensation Plans (Anadarko’s plans are referred to collectively as the “Anadarko Incentive Plans”) for all periods presented. Grants made under equity-based compensation plans result in equity-based compensation expense, which is determined by reference to the fair value of equity compensation. For equity-based awards ultimately settled through the issuance of units or stock, the fair value is measured as of the date of the relevant equity grant. Equity-based compensation granted under the WGP LTIP and the Anadarko Incentive Plans does not impact cash flows from operating activities since the offset to compensation expense is recorded as a contribution to partners’ capital in the consolidated financial statements at the time of contribution, when the expense is realized. |
Income taxes policy | Income taxes. The Partnership generally is not subject to federal income tax or state income tax other than Texas margin tax on the portion of its income that is apportionable to Texas. Deferred state income taxes are recorded on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. The Partnership routinely assesses the realizability of its deferred tax assets. If the Partnership concludes that it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Federal and state current and deferred income tax expense was recorded on the Partnership assets prior to the Partnership’s acquisition of these assets from Anadarko. For periods beginning on and subsequent to the Partnership’s acquisition of the Partnership assets, the Partnership makes payments to Anadarko pursuant to the tax sharing agreement entered into between Anadarko and the Partnership for its estimated share of taxes from all forms of taxation, excluding taxes imposed by the United States, that are included in any combined or consolidated returns filed by Anadarko. The aggregate difference in the basis of the Partnership’s assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each partner’s tax attributes in the Partnership. The accounting standards for uncertain tax positions defines the criteria an individual tax position must satisfy for any part of the benefit of that position to be recognized in the financial statements. The Partnership had no material uncertain tax positions at December 31, 2016 or 2015 . With respect to assets acquired from Anadarko, the Partnership recorded Anadarko’s historic deferred income taxes for the periods prior to the Partnership’s ownership of the assets. For periods subsequent to the Partnership’s acquisition, the Partnership is not subject to tax except for the Texas margin tax and, accordingly, does not record deferred federal income taxes related to the assets acquired from Anadarko. |
Net income (loss) per common unit policy | Net income (loss) per unit for common units. Net income (loss) attributable to Western Gas Partners, LP earned on and subsequent to the date of the acquisition of the Partnership assets, net of distributions on the Series A Preferred units and amortization of the Series A Preferred unit beneficial conversion features (see Series A Preferred units above), is allocated to the general partner, the common unitholders and the Class C unitholder, in accordance with their respective weighted-average ownership percentages (exclusive of the Series A Preferred unit limited partnership interest) and, when applicable, giving effect to incentive distributions allocable to the general partner. Specifically, net income equal to the amount of available cash (as defined by the partnership agreement) is allocated to the general partner, common and Class C unitholder consistent with actual cash distributions and capital account allocations, including incentive distributions allocable to the general partner. Undistributed earnings (net income in excess of distributions) or undistributed losses (available cash in excess of net income) are then allocated to the general partner, common unitholders and the Class C unitholder in accordance with their respective weighted-average ownership percentages during each period. Additionally, the allocable limited partners’ interest in net income (loss) is also net of amortization of the beneficial conversion feature related to the Class C units (see Class C units above) and is allocated between the common and Class C unitholders by applying the provisions of the partnership agreement that govern actual cash distributions and capital account allocations, as if all earnings for the period had been distributed. Net income (loss) attributable to the Partnership assets acquired from Anadarko for periods prior to the Partnership’s acquisition of the Partnership assets is not allocated to the limited partners for purposes of calculating net income (loss) per common unit. Basic net income (loss) per common unit is calculated by dividing the limited partners’ interest in net income (loss) attributable to common unitholders by the weighted-average number of common units outstanding during the period. The common units issued in connection with acquisitions and equity offerings are included on a weighted-average basis for periods they were outstanding. The Series A Preferred units are not considered a participating security as they only have distribution rights up to the specified per-unit quarterly distribution and have no rights to the Partnership’s undistributed earnings. Because the Class C units participate in distributions with common units according to a predetermined formula (see Note 3 ), they are considered a participating security and are included in the computation of earnings per unit pursuant to the two-class method. The Class C unit participation right results in a non-contingent transfer of value each time the Partnership declares a distribution. Diluted net income (loss) per common unit is calculated by dividing the sum of (i) the limited partners’ interest in net income (loss) attributable to common units adjusted for distributions on the Series A Preferred units and a reallocation of the limited partners’ interest in net income (loss) assuming conversion of the Series A Preferred units into common units, and (ii) the limited partners’ interest in net income (loss) allocable to the Class C units as a participating security, by the sum of the weighted-average number of common units outstanding plus the dilutive effect of (i) the weighted-average number of outstanding Class C units and (ii) the weighted-average number of common units outstanding assuming conversion of the Series A Preferred units. |
New issued accounting standards policy | Recently adopted accounting standards. Accounting Standards Update (“ASU”) 2017-04, Intangibles—Goodwill and Other (Topic 350) eliminates Step 2 from the goodwill impairment test in an effort to simplify the subsequent measurement of goodwill. It is effective for annual and interim periods beginning in 2020 and is required to be adopted using a prospective approach, with early adoption permitted for goodwill impairment tests performed after January 1, 2017. The Partnership adopted this ASU on January 1, 2017, and it will only be applicable to the extent that the Partnership determines its goodwill is impaired. ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business assists in determining whether a transaction should be accounted for as an acquisition or disposal of assets or as a business. It provides a screen that when substantially all of the fair value of the gross assets acquired, or disposed of, are concentrated in a single identifiable asset, or a group of similar identifiable assets, the set will not be considered a business. If the screen is not met, a set must include an input and a substantive process that together significantly contribute to the ability to create an output to be considered a business. This ASU is effective for annual and interim periods beginning in 2018 and is required to be adopted using a prospective approach, with early adoption permitted for transactions not previously reported in issued financial statements. The Partnership adopted this ASU on January 1, 2017, and expects it could have a material impact on future consolidated financial statements as goodwill would not be allocated to divestitures or recorded for acquisitions that are not considered to be businesses. ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory requires an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs and eliminates the exception for an intra-entity transfer of an asset other than inventory. This ASU is effective for annual and interim periods beginning in 2018 and is required to be adopted using a modified retrospective approach, with early adoption permitted. The Partnership adopted this ASU on January 1, 2017, with no impact to its consolidated financial statements. ASU 2015-06, Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions provides guidance for the presentation of historical earnings per unit for MLPs that apply the two-class method of calculating earnings per unit. When a general partner transfers or “drops down” net assets to an MLP, the transaction is accounted for as a transaction between entities under common control, and the statements of operations are adjusted retrospectively to reflect the transaction. This ASU specifies that the historical earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner, and the previously reported earnings per unit of the limited partners should not change as a result of the dropdown transaction. The ASU also requires additional disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two-class method. The Partnership applies the two-class method of calculating earnings per unit as described above (including the allocation of pre-acquisition net income (loss) to the general partner), and discloses the rights to earnings (losses) noted above. As such, there was no impact to the Partnership’s consolidated financial statements upon adoption of this ASU on January 1, 2016. 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) ASU 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Interest—Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements require capitalized debt issuance costs, except for those related to revolving credit facilities, to be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, rather than as an asset. The Partnership adopted these ASUs on January 1, 2016, using a retrospective approach. The adoption resulted in a reclassification that reduced Other assets and Long-term debt by $16.7 million on the Partnership’s consolidated balance sheet at December 31, 2015. See Note 9 . ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis amends existing requirements applicable to reporting entities that are required to evaluate consolidation of a legal entity under the variable interest entity (“VIE”) or voting interest entity models. The provisions will affect how limited partnerships and similar entities are assessed for consolidation, including an additional requirement that a limited partnership will be a VIE unless the limited partners have either substantive kick-out or participating rights over the general partner. The Partnership evaluated the impact of the adoption of this ASU on its consolidated financial statements and determined it does not have any entities for which it is the primary beneficiary for accounting and disclosure purposes. As such, the adoption of this ASU on January 1, 2016, did not impact the Partnership’s consolidated financial statements. New accounting standards issued but not yet adopted. ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. This ASU is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach, with early adoption permitted. The Partnership is evaluating the impact of the adoption of this ASU on its consolidated financial statements. ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments provides clarification on how certain cash receipts and cash payments are presented and classified on the statement of cash flows. This ASU is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach if practicable, with early adoption permitted. The Partnership does not expect the adoption of this ASU to have a material impact on its consolidated statement of cash flows. ASU 2016-02, Leases (Topic 842) requires lessees to recognize a lease liability and a right-of-use asset for all leases, including operating leases, with a term greater than 12 months on the balance sheet. The provisions of ASU 2016-02 also modify the definition of a lease and outline the requirements for recognition, measurement, presentation and disclosure of leasing arrangements by both lessees and lessors. This ASU is effective for annual and interim periods beginning after December 15, 2018. The Partnership is currently analyzing its portfolio of contracts to assess the impact future adoption of this ASU may have on its consolidated financial statements. ASU 2014-09, Revenue from Contracts with Customers (Topic 606) supersedes current revenue recognition requirements and requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows from contracts with customers. The Partnership has completed an initial review of contracts in each of its revenue streams and is developing accounting policies to address the provisions of the ASU. The Partnership is currently analyzing whether total revenues and total expenses may increase as a result of recognizing both revenue for noncash consideration for services provided and revenue and associated cost of product for the subsequent sale of commodities received as such noncash consideration. The Partnership continues to evaluate the impact of this and other provisions of the ASU on accounting policies, internal controls and consolidated financial statements and related disclosures, and has not finalized any estimates of the potential impacts. The Partnership will adopt the new standard on January 1, 2018, using the modified retrospective method with a cumulative adjustment to equity and partners’ capital. |
Equity method investments policy | Management evaluates its equity investments for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value that is other than temporary. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether the investment has been impaired. Management assesses the fair value of equity investments using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third-party comparable sales and discounted cash flow models. If the estimated fair value is less than the carrying value, the excess of the carrying value over the estimated fair value is recognized as an impairment loss. |
Summary of Significant Accoun25
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Assets and Investments Table | As of December 31, 2016 , the Partnership’s assets and investments consisted of the following (see Note 14 for information regarding events occurring subsequent to December 31, 2016): Owned and Operated Operated Interests Non-Operated Interests Equity Interests Gathering systems 11 4 5 2 Treating facilities 12 12 — 3 Natural gas processing plants/trains 20 5 — 2 NGL pipelines 2 — — 3 Natural gas pipelines 5 — — — Oil pipelines — 1 — 1 |
Ownership Interest and Method of Consolidation Table | The following table outlines the Partnership’s ownership interests and the accounting method of consolidation used in the Partnership’s consolidated financial statements: Percentage Interest Equity investments (1) Fort Union 14.81 % White Cliffs 10 % Rendezvous 22 % Mont Belvieu JV 25 % TEP 20 % TEG 20 % FRP 33.33 % Proportionate consolidation (2) Non-Operated Marcellus Interest systems 33.75 % Anadarko-Operated Marcellus Interest systems 33.75 % Newcastle system 50 % DBJV system 50 % Springfield system 50.1 % Full consolidation Chipeta (3) 75 % (1) Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. “Equity investment throughput” refers to the Partnership’s share of average throughput for these investments. (2) The Partnership proportionately consolidates its associated share of the assets, liabilities, revenues and expenses attributable to these assets. (3) The 25% interest in Chipeta Processing LLC (“Chipeta”) held by a third-party member is reflected within noncontrolling interest in the consolidated financial statements. |
Acquisitions and Divestitures (
Acquisitions and Divestitures (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Property, Plant and Equipment [Abstract] | |
Acquisitions Table | The following table presents the acquisitions completed by the Partnership during 2016 , 2015 and 2014 , and identifies the funding sources for such acquisitions. See Note 14 for information regarding events occurring subsequent to December 31, 2016. thousands except unit and percent amounts Acquisition Date Percentage Deferred Purchase Price Obligation - Anadarko Borrowings Cash On Hand Common Units Issued Class C Units Issued to Anadarko Series A Preferred Units Issued TEFR Interests (1) 03/03/2014 Various (1) $ — $ 350,000 $ 6,250 308,490 — — DBM (2) 11/25/2014 100 % — 475,000 298,327 — 10,913,853 — DBJV (3) 03/02/2015 100 % 174,276 — — — — — Springfield (4) 03/14/2016 100 % — 247,500 — 2,089,602 — 14,030,611 (1) The Partnership acquired a 20% interest in each of TEG and TEP and a 33.33% interest in FRP from Anadarko. These assets gather and transport NGLs primarily from the Anadarko and Denver-Julesburg (“DJ”) Basins. The interests in these entities are accounted for under the equity method of accounting. In connection with the issuance of the common units, the Partnership issued 6,296 general partner units to the general partner in exchange for the general partner’s proportionate capital contribution of $0.4 million . (2) The Partnership acquired Nuevo Midstream, LLC (“Nuevo”) from a third party. Following the acquisition, the Partnership changed the name of Nuevo to Delaware Basin Midstream, LLC (“DBM”). The assets acquired include cryogenic processing plants, a gas gathering system, and related facilities and equipment, which are collectively referred to as the “DBM complex” and serve production from Reeves, Loving and Culberson Counties, Texas and Eddy and Lea Counties, New Mexico. See DBM acquisition below for further information, including the final allocation of the purchase price. (3) The Partnership acquired Delaware Basin JV Gathering LLC (“DBJV”) from Anadarko. DBJV owns a 50% interest in a gathering system and related facilities. The DBJV gathering system and related facilities (the “DBJV system”) are located in the Delaware Basin in Loving, Ward, Winkler and Reeves Counties, Texas. The Partnership will make a cash payment on March 31, 2020, to Anadarko as consideration for the acquisition of DBJV. At the acquisition date, the Partnership estimated the future payment would be $282.8 million , the net present value of which was $174.3 million . For further information, including revisions to the estimated future payment, see DBJV acquisition—deferred purchase price obligation - Anadarko below. (4) The Partnership acquired Springfield Pipeline LLC (“Springfield”) from Anadarko for $750.0 million , consisting of $712.5 million in cash and the issuance of 1,253,761 of the Partnership’s common units. Springfield owns a 50.1% interest in an oil gathering system and a gas gathering system, such interest being referred to in this report as the “Springfield interest.” The Springfield oil and gas gathering systems (collectively, the “Springfield system”) are located in Dimmit, La Salle, Maverick and Webb Counties in South Texas. The Partnership financed the cash portion of the acquisition through: (i) borrowings of $247.5 million on the Partnership’s senior unsecured revolving credit facility (“RCF”), (ii) the issuance of 835,841 of the Partnership’s common units to WGP and (iii) the issuance of Series A Preferred units to private investors. See Note 4 for further information regarding the Series A Preferred units. |
Impact of Deferred Purchase Price Obligation Table | The following table summarizes the financial statement impact of the Deferred purchase price obligation - Anadarko: Deferred purchase price obligation - Anadarko Estimated future payment obligation Balance at March 2, 2015 – Acquisition date $ 174,276 $ 282,807 Accretion expense (1) 14,398 Balance at December 31, 2015 188,674 282,807 Accretion revision (2) (7,747 ) Revision to Deferred purchase price obligation – Anadarko (3) (139,487 ) Balance at December 31, 2016 $ 41,440 $ 56,455 (1) Accretion expense was recorded as a charge to Interest expense on the consolidated statements of operations. (2) Financing-related accretion revisions were recorded in Interest expense on the consolidated statements of operations. (3) Recorded as revisions within Common units on the consolidated balance sheets and consolidated statements of equity and partners’ capital. |
Partnership Distributions (Tabl
Partnership Distributions (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Distributions Made to Members or Limited Partners [Abstract] | |
Cash Distributions Table | The Board of Directors declared the following cash distributions to the Partnership’s common and general partner unitholders for the periods presented: thousands except per-unit amounts Quarters Ended Total Quarterly Distribution per Unit Total Quarterly Cash Distribution Date of Distribution 2014 March 31 $ 0.625 $ 98,749 May 2014 June 30 0.650 105,655 August 2014 September 30 0.675 111,608 November 2014 December 31 0.700 126,044 February 2015 2015 March 31 $ 0.725 $ 133,203 May 2015 June 30 0.750 139,736 August 2015 September 30 0.775 146,160 November 2015 December 31 0.800 152,588 February 2016 2016 March 31 $ 0.815 $ 158,905 May 2016 June 30 0.830 162,827 August 2016 September 30 0.845 166,742 November 2016 December 31 (1) 0.860 170,657 February 2017 (1) The Board of Directors declared a cash distribution to the Partnership’s unitholders for the fourth quarter of 2016 of $0.860 per unit, or $170.7 million in aggregate, including incentive distributions, but excluding distributions on Class C units (see Class C unit distributions below) and Series A Preferred units (see Series A Preferred unit distributions below). The cash distribution was paid on February 13, 2017 , to unitholders of record at the close of business on February 2, 2017 . |
Equity and Partners' Capital (T
Equity and Partners' Capital (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Partners' Capital Notes [Abstract] | |
Equity Offerings Table | The Partnership completed the following public offerings of its common units during 2015 and 2014, including through its Continuous Offering Programs (“COP”): thousands except unit and per-unit amounts Common Units Issued GP Units Issued (1) Price Per Unit Underwriting Discount and Other Offering Expenses Net Proceeds 2014 $125.0 million COP (2) 1,133,384 23,132 $ 73.48 $ 1,738 $ 83,245 November 2014 equity offering (3) 8,620,153 153,061 70.85 18,615 602,967 2015 $500.0 million COP (4) 873,525 — $ 66.61 $ 805 $ 57,385 (1) Represents general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution. (2) Represents common and general partner units issued during the year ended December 31, 2014, under the $125.0 million COP. Gross proceeds generated (including the general partner’s proportionate capital contributions) during the year ended December 31, 2014, were $85.0 million . The price per unit in the table above represents an average price for all issuances under the $125.0 million COP during the year ended December 31, 2014. As of December 31, 2014, the Partnership had used all the capacity to issue common units under this registration statement. (3) Includes the issuance of 1,120,153 common units pursuant to the partial exercise of the underwriters’ over-allotment option, the net proceeds from which were $77.0 million . Beginning with this partial exercise, the Partnership’s general partner elected not to make a corresponding capital contribution to maintain its 2.0% interest in the Partnership. (4) Represents common units issued during the year ended December 31, 2015, pursuant to the Partnership’s registration statement filed with the SEC in August 2014 authorizing the issuance of up to an aggregate of $500.0 million of common units (the “$500.0 million COP”). Gross proceeds generated during the three months and year ended December 31, 2015, were zero and $58.2 million , respectively. Commissions paid during the three months and year ended December 31, 2015, were zero and $0.6 million , respectively. The price per unit in the table above represents an average price for all issuances under the $500.0 million COP during the year ended December 31, 2015. |
Partnership Interests Table | The following table summarizes the common, Class C, Series A Preferred and general partner units issued during the years ended December 31, 2016 and 2015: Common Units Class C Units Series A Preferred Units General Partner Units Total Balance at December 31, 2014 127,695,130 10,913,853 — 2,583,068 141,192,051 PIK Class C units — 498,009 — — 498,009 Long-Term Incentive Plan award vestings 8,310 — — — 8,310 $500.0 million COP 873,525 — — — 873,525 Balance at December 31, 2015 128,576,965 11,411,862 — 2,583,068 142,571,895 PIK Class C units — 946,261 — — 946,261 Springfield acquisition 2,089,602 — 14,030,611 — 16,120,213 April 2016 Series A units — — 7,892,220 — 7,892,220 Long-Term Incentive Plan award vestings 5,403 — — — 5,403 Balance at December 31, 2016 130,671,970 12,358,123 21,922,831 2,583,068 167,535,992 |
Calculation of Net Income (Loss) Per Unit Table | The following table illustrates the Partnership’s calculation of net income (loss) per unit for common units: Year Ended December 31, thousands except per-unit amounts 2016 2015 2014 Net income (loss) attributable to Western Gas Partners, LP $ 591,331 $ 4,106 $ 442,643 Pre-acquisition net (income) loss allocated to Anadarko (11,326 ) (79,386 ) (65,154 ) Series A Preferred units interest in net (income) loss (1) (76,893 ) — — General partner interest in net (income) loss (236,561 ) (180,996 ) (120,980 ) Common and Class C limited partners’ interest in net income (loss) $ 266,551 $ (256,276 ) $ 256,509 Net income (loss) allocable to common units (1) $ 226,611 $ (250,210 ) $ 254,737 Net income (loss) allocable to Class C units (1) 39,940 (6,066 ) 1,772 Common and Class C limited partners’ interest in net income (loss) $ 266,551 $ (256,276 ) $ 256,509 Net income (loss) per unit Common units – basic $ 1.74 $ (1.95 ) $ 2.13 Common units – diluted (2) 1.74 (1.95 ) 2.12 Weighted-average units outstanding Common units – basic 130,253 128,345 119,822 Class C units (2) 11,945 11,114 1,106 Series A Preferred units assuming conversion to common units (2) 16,860 — — Common units - diluted (2) 130,253 128,345 120,928 (1) Adjusted to reflect amortization of the beneficial conversion features. (2) The impact of Class C units and the conversion of Series A Preferred units would be anti-dilutive for the year ended December 31, 2016, and the impact of Class C units would be anti-dilutive for the year ended December 31, 2015. |
Transactions with Affiliates (T
Transactions with Affiliates (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Related Party Fees and Other Arrangements, Limited Liability Company (LLC) or Limited Partnership (LP) [Abstract] | |
Gains (Losses) on Commodity Price Swap Agreements Table | The following table summarizes gains and losses upon settlement of commodity price swap agreements recognized in the consolidated statements of operations: Year Ended December 31, thousands 2016 2015 2014 Gains (losses) on commodity price swap agreements related to sales: (1) Natural gas sales $ 11,116 $ 45,978 $ 9,494 Natural gas liquids sales 59,918 145,258 113,866 Total 71,034 191,236 123,360 Losses on commodity price swap agreements related to purchases (2) (42,577 ) (124,944 ) (68,492 ) Net gains (losses) on commodity price swap agreements $ 28,457 $ 66,292 $ 54,868 (1) Reported in affiliate Natural gas and natural gas liquids sales in the consolidated statements of operations in the period in which the related sale is recorded. (2) Reported in Cost of product in the consolidated statements of operations in the period in which the related purchase is recorded. |
Commodity Price Swap Agreements Extensions Tables | The tables below summarize the swap prices for the extension periods compared to the forward market prices as of the various agreement dates. DJ Basin Complex per barrel except natural gas 2015 - 2017 Swap Prices 2015 Market Prices (1) 2016 Market Prices (1) 2017 Market Prices (1) Ethane $ 18.41 $ 1.96 $ 0.60 $ 5.09 Propane 47.08 13.10 10.98 18.85 Isobutane 62.09 19.75 17.23 26.83 Normal butane 54.62 18.99 16.86 26.20 Natural gasoline 72.88 52.59 26.15 41.84 Condensate 76.47 52.59 34.65 45.40 Natural gas (per MMBtu) 5.96 2.75 2.11 3.05 Hugoton System (2) per barrel except natural gas 2015 - 2016 Swap Prices 2015 Market Prices (1) 2016 Market Prices (1) Condensate $ 78.61 $ 32.56 $ 18.81 Natural gas (per MMBtu) 5.50 2.74 2.12 5. TRANSACTIONS WITH AFFILIATES (CONTINUED) MGR Assets per barrel except natural gas 2015 Swap Prices 2016 - 2017 Swap Prices 2017 Market Prices (1) Ethane $ 23.41 $ 23.11 $ 4.08 Propane 52.99 52.90 19.24 Isobutane 74.02 73.89 25.79 Normal butane 65.04 64.93 25.16 Natural gasoline 81.82 81.68 45.01 Condensate 81.82 81.68 53.55 Natural gas (per MMBtu) 4.66 4.87 3.05 (1) Represents the New York Mercantile Exchange forward strip price as of June 25, 2015, December 8, 2015 and December 1, 2016, for the 2015 Market Prices, 2016 Market Prices and 2017 Market Prices, respectively, adjusted for product specification, location, basis and, in the case of NGLs, transportation and fractionation costs. (2) The Hugoton system was sold in October 2016. See Note 2 . |
LTIP Award Activity Table | The following table summarizes WES LTIP award activity for the years ended December 31, 2016 , 2015 and 2014 : 2016 2015 2014 Weighted-Average Grant-Date Fair Value Units Weighted-Average Grant-Date Fair Value Units Weighted-Average Grant-Date Fair Value Units Phantom units outstanding at beginning of year $ 68.78 5,477 $ 60.74 9,522 $ 49.47 16,844 Vested 68.78 (5,477 ) 60.69 (9,257 ) 49.55 (13,122 ) Granted 49.30 7,304 69.10 5,212 68.14 5,800 Phantom units outstanding at end of year 49.30 7,304 68.78 5,477 60.74 9,522 |
Related Party Transactions Tables | The following table summarizes the amounts the Partnership reimbursed to Anadarko: Year Ended December 31, thousands 2016 2015 2014 General and administrative expenses $ 29,360 $ 22,896 $ 20,249 Public company expenses 8,410 8,950 8,006 Total reimbursement $ 37,770 $ 31,846 $ 28,255 The following table summarizes the Partnership’s purchases from and sales to Anadarko of pipe and equipment: Year Ended December 31, 2016 2015 2014 2016 2015 2014 thousands Purchases Sales Cash consideration $ 3,965 $ 10,903 $ 22,943 $ 623 $ 925 $ 402 Net carrying value (3,366 ) (6,318 ) (12,210 ) (605 ) (972 ) (375 ) Partners’ capital adjustment $ 599 $ 4,585 $ 10,733 $ 18 $ (47 ) $ 27 The following table summarizes material affiliate transactions. See Note 2 for discussion of affiliate acquisitions and related funding. Year ended December 31, thousands 2016 2015 2014 Revenues and other (1) $ 1,228,232 $ 1,220,639 $ 1,203,974 Equity income, net – affiliates (1) 78,717 71,251 57,836 Cost of product (1) 80,455 167,354 127,930 Operation and maintenance (2) 72,330 77,061 71,386 General and administrative (3) 38,066 33,903 31,308 Operating expenses 190,851 278,318 230,624 Interest income (4) 16,900 16,900 16,900 Interest expense (5) (7,747 ) 14,398 — Proceeds from the issuance of common units, net of offering expenses (6) 25,000 — — Distributions to unitholders (7) 382,711 314,200 234,024 Above-market component of swap extensions with Anadarko 45,820 18,449 — (1) Represents amounts earned or incurred on and subsequent to the date of acquisition of the Partnership assets, as well as amounts earned or incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets, recognized under gathering, treating or processing agreements, and purchase and sale agreements. (2) Represents expenses incurred on and subsequent to the date of the acquisition of the Partnership assets, as well as expenses incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets. (3) Represents general and administrative expense incurred on and subsequent to the date of the Partnership’s acquisition of the Partnership assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of the Partnership assets by the Partnership. These amounts include equity-based compensation expense allocated to the Partnership by Anadarko (see WES LTIP and WGP LTIP and Anadarko Incentive Plans within this Note 5 ). (4) Represents interest income recognized on the note receivable from Anadarko. (5) For the years ended December 31, 2016 and 2015, includes amounts related to the Deferred purchase price obligation - Anadarko (see Note 2 and Note 12 ). (6) Represents proceeds from the issuance of 835,841 common units to WGP as partial funding for the acquisition of Springfield (see Note 2 ). (7) Represents distributions paid under the partnership agreement (see Note 3 and Note 4 ). |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Components of Income Tax Expense (Benefit) Table | The components of the Partnership’s income tax expense (benefit) are as follows: Year Ended December 31, thousands 2016 2015 2014 Current income tax expense (benefit) Federal income tax expense (benefit) $ 4,477 $ 32,422 $ (114 ) State income tax expense (benefit) 1,340 1,764 493 Total current income tax expense (benefit) 5,817 34,186 379 Deferred income tax expense (benefit) Federal income tax expense (benefit) 1,622 10,251 35,361 State income tax expense (benefit) 933 1,095 3,321 Total deferred income tax expense (benefit) 2,555 11,346 38,682 Total income tax expense (benefit) $ 8,372 $ 45,532 $ 39,061 |
Tax Rate Reconciliation Table | Total income taxes differed from the amounts computed by applying the statutory income tax rate to income (loss) before income taxes. The sources of these differences are as follows: Year Ended December 31, thousands except percentages 2016 2015 2014 Income (loss) before income taxes $ 610,666 $ 59,739 $ 495,729 Statutory tax rate — % — % — % Tax computed at statutory rate $ — $ — $ — Adjustments resulting from: Federal taxes on income attributable to Partnership assets pre-acquisition 6,162 42,823 35,716 State taxes on income attributable to Partnership assets pre-acquisition (net of federal benefit) 117 298 864 Texas margin tax expense (benefit) (1) 2,093 2,411 2,481 Income tax expense (benefit) $ 8,372 $ 45,532 $ 39,061 Effective tax rate 1 % 76 % 8 % (1) Includes a reduction of $2.2 million in deferred state income taxes for the year ended December 31, 2015. Texas House Bill 32, signed into law in June 2015, reduced the Texas margin tax rates by 0.25% . The law became effective January 1, 2016. The Partnership is required to include the impact of the law change on its deferred state income taxes in the period enacted. |
Income Tax Temporary Differences Table | The tax effects of temporary differences that give rise to significant portions of deferred tax assets (liabilities) are as follows: December 31, thousands 2016 2015 Depreciable property $ (4,976 ) $ (138,159 ) Credit carryforwards 498 512 Other intangible assets (1,928 ) (2,070 ) Other 4 13 Net long-term deferred income tax liabilities $ (6,402 ) $ (139,704 ) |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment Table | A summary of the historical cost of the Partnership’s property, plant and equipment is as follows: December 31, thousands Estimated Useful Life 2016 2015 Land n/a $ 4,012 $ 3,744 Gathering systems and processing complexes 3 to 47 years 6,462,053 6,061,004 Pipelines and equipment 15 to 45 years 139,646 136,290 Assets under construction n/a 226,626 329,887 Other 3 to 40 years 29,605 25,853 Total property, plant and equipment 6,861,942 6,556,778 Accumulated depreciation 1,812,010 1,697,999 Net property, plant and equipment $ 5,049,932 $ 4,858,779 |
Goodwill and Intangibles (Table
Goodwill and Intangibles (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Other Intangible Assets Table | The following table presents the gross carrying amount and accumulated amortization of other intangible assets: December 31, thousands 2016 2015 Gross carrying amount $ 868,035 $ 868,035 Accumulated amortization (64,337 ) (35,908 ) Other intangible assets $ 803,698 $ 832,127 |
Equity Investments (Tables)
Equity Investments (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Equity Investments Table | The following table presents the activity in the Partnership’s equity investments for the years ended December 31, 2016 and 2015: Equity Investments thousands Fort (1) White (2) Rendezvous (3) Mont (4) TEG (5) TEP (6) FRP (7) Total Balance at December 31, 2014 $ 25,933 $ 44,315 $ 56,336 $ 121,337 $ 16,790 $ 198,793 $ 170,988 $ 634,492 Investment earnings (loss), net of amortization (3,200 ) 14,770 2,292 23,570 586 16,088 17,145 71,251 Contributions — 8,512 — (432 ) — 1,880 1,482 11,442 Distributions (5,611 ) (14,188 ) (4,233 ) (24,248 ) (803 ) (16,340 ) (16,631 ) (82,054 ) Distributions in excess of cumulative earnings (8) — (2,970 ) (3,482 ) (3,138 ) (290 ) (5,618 ) (746 ) (16,244 ) Balance at December 31, 2015 $ 17,122 $ 50,439 $ 50,913 $ 117,089 $ 16,283 $ 194,803 $ 172,238 $ 618,887 Investment earnings (loss), net of amortization 608 13,858 1,931 26,204 708 16,683 18,725 78,717 Contributions — 441 — — 166 (580 ) — 27 Distributions (1,543 ) (13,277 ) (3,873 ) (26,243 ) (730 ) (16,934 ) (19,585 ) (82,185 ) Distributions in excess of cumulative earnings (8) (3,354 ) (4,142 ) (2,232 ) (4,245 ) (581 ) (4,778 ) (1,906 ) (21,238 ) Balance at December 31, 2016 $ 12,833 $ 47,319 $ 46,739 $ 112,805 $ 15,846 $ 189,194 $ 169,472 $ 594,208 (1) The Partnership has a 14.81% interest in Fort Union, a joint venture that owns a gathering pipeline and treating facilities in the Powder River Basin. Anadarko is the construction manager and physical operator of the Fort Union facilities. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the owners’ firm gathering agreements, require 65% or unanimous approval of the owners. (2) The Partnership has a 10% interest in White Cliffs, a limited liability company that owns a crude oil pipeline that originates in Platteville, Colorado and terminates in Cushing, Oklahoma. The third-party majority owner is the manager of the White Cliffs operations. Certain business decisions, including, but not limited to, approval of annual budgets and decisions with respect to significant expenditures, contractual commitments, acquisitions, material financings, dispositions of assets or admitting new members, require more than 75% approval of the members. (3) The Partnership has a 22% interest in Rendezvous, a limited liability company that operates gas gathering facilities in Southwestern Wyoming. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the members’ gas servicing agreements, require unanimous approval of the members. (4) The Partnership has a 25% interest in the Mont Belvieu JV, an entity formed to design, construct, and own two fractionation trains located in Mont Belvieu, Texas. A third party is the operator of the Mont Belvieu JV fractionation trains. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require 50% or unanimous approval of the owners. (5) The Partnership has a 20% interest in TEG, an entity that consists of two NGL gathering systems that link natural gas processing plants to TEP. Enbridge Midcoast Energy, LP (“Enbridge”) is the operator of the two gathering systems. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the delegation, creation, appointment, or removal of officer positions require more than 50% approval of the members. (6) The Partnership has a 20% interest in TEP, which consists of an NGL pipeline that originates in Skellytown, Texas and extends to Mont Belvieu, Texas. Enterprise Products Operating LLC (“Enterprise”) is the operator of TEP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than 50% approval of the members. (7) The Partnership has a 33.33% interest in the FRP, an NGL pipeline that extends from Weld County, Colorado to Skellytown, Texas. Enterprise is the operator of FRP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than 50% approval of the members. (8) Distributions in excess of cumulative earnings, classified as investing cash flows in the consolidated statements of cash flows, is calculated on an individual investment basis. |
Summarized Equity Investments Financial Information Presented at 100 Percent Tables | The following tables present the summarized combined financial information for the Partnership’s equity investments (amounts represent 100% of investee financial information): Year Ended December 31, thousands 2016 2015 2014 Consolidated Statements of Income Revenues $ 687,554 $ 667,554 $ 548,629 Operating income 428,454 359,899 336,188 Net income 427,511 359,443 333,705 December 31, thousands 2016 2015 Consolidated Balance Sheets Current assets $ 118,472 $ 154,937 Property, plant and equipment, net 2,626,466 2,716,078 Other assets 39,802 43,713 Total assets $ 2,784,740 $ 2,914,728 Current liabilities 63,468 78,116 Non-current liabilities 6,662 9,072 Equity 2,714,610 2,827,540 Total liabilities and equity $ 2,784,740 $ 2,914,728 |
Components of Working Capital (
Components of Working Capital (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Components Of Working Capital [Abstract] | |
Accounts Receivable, Net Table | A summary of accounts receivable, net is as follows: December 31, thousands 2016 2015 Trade receivables, net $ 192,808 $ 143,557 Other receivables, net 30,415 49,772 Total accounts receivable, net $ 223,223 $ 193,329 |
Other Current Assets Table | A summary of other current assets is as follows: December 31, thousands 2016 2015 Natural gas liquids inventory $ 7,126 $ 2,403 Imbalance receivables 3,483 2,122 Prepaid insurance 2,257 2,296 Other — 1,034 Total other current assets $ 12,866 $ 7,855 |
Accrued Liabilities Table | A summary of accrued liabilities is as follows: December 31, thousands 2016 2015 Accrued capital expenditures $ 79,253 $ 61,454 Accrued plant purchases 44,538 16,425 Accrued interest expense 39,826 26,194 Short-term asset retirement obligations 3,114 3,677 Short-term remediation and reclamation obligations 630 1,136 Income taxes payable 1,006 770 Other 532 9,363 Total accrued liabilities $ 168,899 $ 119,019 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations Table | The following table provides a summary of changes in asset retirement obligations: Year Ended December 31, thousands 2016 2015 Carrying amount of asset retirement obligations at beginning of year $ 130,631 $ 119,855 Liabilities incurred 5,515 9,490 Liabilities settled (10,650 ) (7,905 ) Accretion expense 6,794 6,381 Revisions in estimated liabilities 10,117 2,810 Carrying amount of asset retirement obligations at end of year $ 142,407 $ 130,631 |
Debt and Interest Expense (Tabl
Debt and Interest Expense (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Debt Instruments [Abstract] | |
Debt Outstanding and Debt Activity Tables | The following table presents the Partnership’s outstanding debt as of December 31, 2016 and 2015: December 31, 2016 December 31, 2015 thousands Principal Carrying Value Fair Value (1) Principal Carrying Value Fair Value (1) 2021 Notes $ 500,000 $ 494,734 $ 536,252 $ 500,000 $ 493,711 $ 513,645 2022 Notes 670,000 668,634 681,723 670,000 668,432 595,744 2018 Notes 350,000 349,188 351,531 350,000 348,706 339,293 2044 Notes 600,000 593,132 615,753 400,000 389,707 321,499 2025 Notes 500,000 490,971 492,499 500,000 490,095 422,285 2026 Notes 500,000 494,802 518,441 — — — RCF — — — 300,000 300,000 300,000 Total long-term debt $ 3,120,000 $ 3,091,461 $ 3,196,199 $ 2,720,000 $ 2,690,651 $ 2,492,466 (1) Fair value is measured using the market approach and Level 2 inputs. 12. DEBT AND INTEREST EXPENSE (CONTINUED) Debt activity. The following table presents the debt activity of the Partnership for the years ended December 31, 2016 and 2015: thousands Carrying Value Balance at December 31, 2014 $ 2,408,785 RCF borrowings 400,000 Issuance of 2025 Notes 500,000 Repayments of RCF borrowings (610,000 ) Other (8,134 ) Balance at December 31, 2015 $ 2,690,651 RCF borrowings 600,000 Issuance of 2026 Notes 500,000 Issuance of 2044 Notes 200,000 Repayments of RCF borrowings (900,000 ) Other 810 Balance at December 31, 2016 $ 3,091,461 |
Interest Expense Table | The following table summarizes the amounts included in interest expense: Year Ended December 31, thousands 2016 2015 2014 Third parties Long-term debt $ 121,832 $ 102,058 $ 81,495 Amortization of debt issuance costs and commitment fees 6,398 5,734 5,103 Capitalized interest (5,562 ) (8,318 ) (9,832 ) Total interest expense – third parties 122,668 99,474 76,766 Affiliates Deferred purchase price obligation – Anadarko (1) (7,747 ) 14,398 — Total interest expense – affiliates (7,747 ) 14,398 — Interest expense $ 114,921 $ 113,872 $ 76,766 (1) See Note 2 for a discussion of the Deferred purchase price obligation - Anadarko. |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
Operating Lease Obligations Table | The amounts in the table below represent existing contractual operating lease obligations as of December 31, 2016 , that may be assigned or otherwise charged to the Partnership pursuant to the reimbursement provisions of the omnibus agreement: thousands Operating Leases 2017 $ 7,322 2018 898 2019 764 2020 122 2021 — Thereafter — Total $ 9,106 |
Summary of Significant Accoun38
Summary of Significant Accounting Policies - Assets and Investments Table (Details) | Dec. 31, 2016unit |
Operated [Member] | Gathering Systems [Member] | |
Assets [Line Items] | |
Assets, number of units | 11 |
Operated [Member] | Treating Facilities [Member] | |
Assets [Line Items] | |
Assets, number of units | 12 |
Operated [Member] | Natural Gas Processing Plants/Trains [Member] | |
Assets [Line Items] | |
Assets, number of units | 20 |
Operated [Member] | Natural Gas Liquids Pipelines [Member] | |
Assets [Line Items] | |
Assets, number of units | 2 |
Operated [Member] | Natural Gas Pipelines [Member] | |
Assets [Line Items] | |
Assets, number of units | 5 |
Operated Interests [Member] | Gathering Systems [Member] | |
Assets [Line Items] | |
Assets, number of units | 4 |
Operated Interests [Member] | Treating Facilities [Member] | |
Assets [Line Items] | |
Assets, number of units | 12 |
Operated Interests [Member] | Natural Gas Processing Plants/Trains [Member] | |
Assets [Line Items] | |
Assets, number of units | 5 |
Operated Interests [Member] | Oil Pipelines [Member] | |
Assets [Line Items] | |
Assets, number of units | 1 |
Non-Operated Interests [Member] | Gathering Systems [Member] | |
Assets [Line Items] | |
Assets, number of units | 5 |
Equity Interests [Member] | Gathering Systems [Member] | |
Assets [Line Items] | |
Assets, number of units | 2 |
Equity Interests [Member] | Treating Facilities [Member] | |
Assets [Line Items] | |
Assets, number of units | 3 |
Equity Interests [Member] | Natural Gas Processing Plants/Trains [Member] | |
Assets [Line Items] | |
Assets, number of units | 2 |
Equity Interests [Member] | Natural Gas Liquids Pipelines [Member] | |
Assets [Line Items] | |
Assets, number of units | 3 |
Equity Interests [Member] | Oil Pipelines [Member] | |
Assets [Line Items] | |
Assets, number of units | 1 |
Summary of Significant Accoun39
Summary of Significant Accounting Policies - Ownership Interest and Method of Consolidation Table (Details) | 12 Months Ended | |
Dec. 31, 2016 | ||
Chipeta Processing LLC [Member] | ||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | ||
Ownership interest by noncontrolling interest owner | 25.00% | |
Equity Investments [Member] | Fort Union [Member] | ||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | ||
Percentage ownership interest | 14.81% | [1] |
Equity Investments [Member] | White Cliffs [Member] | ||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | ||
Percentage ownership interest | 10.00% | [1] |
Equity Investments [Member] | Rendezvous [Member] | ||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | ||
Percentage ownership interest | 22.00% | [1] |
Equity Investments [Member] | Mont Belvieu JV [Member] | ||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | ||
Percentage ownership interest | 25.00% | [1] |
Equity Investments [Member] | Texas Express Pipeline LLC [Member] | ||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | ||
Percentage ownership interest | 20.00% | [1] |
Equity Investments [Member] | Texas Express Gathering LLC [Member] | ||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | ||
Percentage ownership interest | 20.00% | [1] |
Equity Investments [Member] | Front Range Pipeline LLC [Member] | ||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | ||
Percentage ownership interest | 33.33% | [1] |
Proportionate Consolidation [Member] | Non-Operated Marcellus Interest [Member] | ||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | ||
Percentage ownership interest | 33.75% | [2] |
Proportionate Consolidation [Member] | Anadarko-Operated Marcellus Interest [Member] | ||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | ||
Percentage ownership interest | 33.75% | [2] |
Proportionate Consolidation [Member] | Newcastle [Member] | ||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | ||
Percentage ownership interest | 50.00% | [2] |
Proportionate Consolidation [Member] | Delaware Basin JV Gathering LLC [Member] | ||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | ||
Percentage ownership interest | 50.00% | [2] |
Proportionate Consolidation [Member] | Springfield Pipeline LLC [Member] | ||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | ||
Percentage ownership interest | 50.10% | [2] |
Full Consolidation [Member] | Chipeta Processing LLC [Member] | ||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | ||
Percentage ownership interest | 75.00% | [3] |
[1] | Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. “Equity investment throughput” refers to the Partnership’s share of average throughput for these investments. | |
[2] | The Partnership proportionately consolidates its associated share of the assets, liabilities, revenues and expenses attributable to these assets. | |
[3] | The 25% interest in Chipeta Processing LLC (“Chipeta”) held by a third-party member is reflected within noncontrolling interest in the consolidated financial statements. |
Summary of Significant Accoun40
Summary of Significant Accounting Policies - Additional Information (Details) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016USD ($)Mcf / dshares | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | ||
Imbalance receivables | $ 3,483 | $ 2,122 | ||
Imbalance payables | 3,000 | 1,600 | ||
Loss on divestiture and other, net | [1],[2] | 14,641 | (57,024) | $ 9 |
Proceeds from property insurance claims | 17,465 | 0 | 0 | |
Other assets | (13,566) | (13,001) | ||
Long-term debt | $ (3,091,461) | (2,690,651) | $ (2,408,785) | |
New Accounting Standard Adjustment [Member] | Accounting Standards Update 2015-03 [Member] | ||||
Other assets | 16,700 | |||
Long-term debt | 16,700 | |||
Western Gas Partners Long Term Incentive Plan [Member] | ||||
Units authorized under LTIP | shares | 2,250,000 | |||
Units available under LTIP | shares | 2,120,711 | |||
Delaware Basin Midstream Complex [Member] | ||||
Loss on divestiture and other, net | 20,300 | |||
Property insurance claim receivable | $ 30,000 | $ 49,000 | ||
Proceeds from insurance claims, total | 33,800 | |||
Proceeds from business interruption insurance claims | 16,270 | |||
Proceeds from property insurance claims | $ 17,465 | |||
Delaware Basin Midstream Complex [Member] | Train II [Member] | ||||
Plant capacity | Mcf / d | 100,000 | |||
Delaware Basin Midstream Complex [Member] | Train III [Member] | ||||
Plant capacity | Mcf / d | 200,000 | |||
[1] | Includes losses related to an incident at the DBM complex for the year ended December 31, 2015. See Note 1. | |||
[2] | Includes losses related to an incident at the DBM complex for the year ended December 31, 2015. See Note 1. |
Acquisitions and Divestitures -
Acquisitions and Divestitures - Acquisitions Table (Details) - USD ($) $ in Thousands | Mar. 14, 2016 | Mar. 02, 2015 | Nov. 25, 2014 | Mar. 03, 2014 | Nov. 30, 2014 | Dec. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Business Acquisition [Line Items] | |||||||||||
Borrowings - long-term debt | $ 1,297,218 | $ 889,606 | $ 1,646,878 | ||||||||
Units issued | 946,261 | 498,009 | |||||||||
Deferred purchase price obligation - Anadarko, present value | [1] | $ 41,440 | $ 41,440 | $ 188,674 | |||||||
General partner units issued | 2,583,068 | 2,583,068 | 2,583,068 | ||||||||
Revolving Credit Facility [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Borrowings - revolving credit facility | $ 600,000 | $ 400,000 | |||||||||
Affiliates [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Cash on hand | $ 716,465 | $ 10,903 | 379,193 | ||||||||
Class C Units [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Units issued | 178,977 | 946,261 | 498,009 | ||||||||
Proceeds from the issuance of units | $ 750,000 | $ 0 | $ 0 | 750,000 | |||||||
Series A Preferred Units [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Proceeds from the issuance of units | $ 440,000 | 686,937 | 0 | $ 0 | |||||||
General Partner [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Units issued | [2],[3] | 153,061 | |||||||||
Texas Express And Front Range [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Borrowings - long-term debt | [4] | $ 350,000 | |||||||||
Cash on hand | [4] | $ 6,250 | |||||||||
General partner units issued | 6,296 | ||||||||||
Texas Express And Front Range [Member] | Common Units [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Common units issued | [4] | 308,490 | |||||||||
Texas Express And Front Range [Member] | General Partner [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Proceeds from the issuance of units | $ 400 | ||||||||||
Delaware Basin Midstream LLC [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Borrowings - long-term debt | [5] | $ 475,000 | |||||||||
Cash on hand | [5] | $ 298,327 | |||||||||
Percentage acquired | [5] | 100.00% | |||||||||
Delaware Basin Midstream LLC [Member] | Class C Units [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Units issued | [5] | 10,913,853 | |||||||||
Delaware Basin JV Gathering LLC [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Percentage acquired | [6] | 100.00% | |||||||||
Delaware Basin JV Gathering LLC [Member] | Delaware Basin JV Gathering System [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Percentage acquired | 50.00% | ||||||||||
Delaware Basin JV Gathering LLC [Member] | Deferred Purchase Price Obligation - Anadarko [Member] | Affiliates [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Deferred purchase price obligation - Anadarko, present value | $ 174,276 | [6] | $ 41,440 | 41,440 | 188,674 | ||||||
Deferred purchase price obligation - Anadarko, future value | $ 282,807 | $ 56,455 | $ 56,455 | $ 282,807 | |||||||
Springfield Pipeline LLC [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Common units issued | 16,120,213 | ||||||||||
Percentage acquired | [7] | 100.00% | |||||||||
Acquisition price | $ 750,000 | ||||||||||
Cash payment for acquisition | $ 712,500 | ||||||||||
Springfield Pipeline LLC [Member] | Springfield System [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Percentage acquired | 50.10% | ||||||||||
Springfield Pipeline LLC [Member] | Revolving Credit Facility [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Borrowings - revolving credit facility | [7] | $ 247,500 | |||||||||
Springfield Pipeline LLC [Member] | Common Units [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Common units issued | 2,089,602 | ||||||||||
Units issued | [7] | 2,089,602 | |||||||||
Springfield Pipeline LLC [Member] | Common Units [Member] | Anadarko [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Units issued | 1,253,761 | ||||||||||
Springfield Pipeline LLC [Member] | Common Units [Member] | Western Gas Equity Partners, LP [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Units issued | 835,841 | ||||||||||
Springfield Pipeline LLC [Member] | Series A Preferred Units [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Common units issued | 14,030,611 | ||||||||||
Units issued | [7] | 14,030,611 | |||||||||
Texas Express Pipeline LLC [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Percentage acquired | [8] | 20.00% | |||||||||
Texas Express Gathering LLC [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Percentage acquired | 20.00% | ||||||||||
Front Range Pipeline LLC [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Percentage acquired | [8] | 33.33% | |||||||||
[1] | See Note 2. | ||||||||||
[2] | Includes the issuance of 1,120,153 common units pursuant to the partial exercise of the underwriters’ over-allotment option, the net proceeds from which were $77.0 million. Beginning with this partial exercise, the Partnership’s general partner elected not to make a corresponding capital contribution to maintain its 2.0% interest in the Partnership. | ||||||||||
[3] | Represents general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution. | ||||||||||
[4] | The Partnership acquired a 20% interest in each of TEG and TEP and a 33.33% interest in FRP from Anadarko. These assets gather and transport NGLs primarily from the Anadarko and Denver-Julesburg (“DJ”) Basins. The interests in these entities are accounted for under the equity method of accounting. In connection with the issuance of the common units, the Partnership issued 6,296 general partner units to the general partner in exchange for the general partner’s proportionate capital contribution of $0.4 million. | ||||||||||
[5] | The Partnership acquired Nuevo Midstream, LLC (“Nuevo”) from a third party. Following the acquisition, the Partnership changed the name of Nuevo to Delaware Basin Midstream, LLC (“DBM”). The assets acquired include cryogenic processing plants, a gas gathering system, and related facilities and equipment, which are collectively referred to as the “DBM complex” and serve production from Reeves, Loving and Culberson Counties, Texas and Eddy and Lea Counties, New Mexico. See DBM acquisition below for further information, including the final allocation of the purchase price. | ||||||||||
[6] | The Partnership acquired Delaware Basin JV Gathering LLC (“DBJV”) from Anadarko. DBJV owns a 50% interest in a gathering system and related facilities. The DBJV gathering system and related facilities (the “DBJV system”) are located in the Delaware Basin in Loving, Ward, Winkler and Reeves Counties, Texas. The Partnership will make a cash payment on March 31, 2020, to Anadarko as consideration for the acquisition of DBJV. At the acquisition date, the Partnership estimated the future payment would be $282.8 million, the net present value of which was $174.3 million. For further information, including revisions to the estimated future payment, see DBJV acquisition—deferred purchase price obligation - Anadarko below. | ||||||||||
[7] | The Partnership acquired Springfield Pipeline LLC (“Springfield”) from Anadarko for $750.0 million, consisting of $712.5 million in cash and the issuance of 1,253,761 of the Partnership’s common units. Springfield owns a 50.1% interest in an oil gathering system and a gas gathering system, such interest being referred to in this report as the “Springfield interest.” The Springfield oil and gas gathering systems (collectively, the “Springfield system”) are located in Dimmit, La Salle, Maverick and Webb Counties in South Texas. The Partnership financed the cash portion of the acquisition through: (i) borrowings of $247.5 million on the Partnership’s senior unsecured revolving credit facility (“RCF”), (ii) the issuance of 835,841 of the Partnership’s common units to WGP and (iii) the issuance of Series A Preferred units to private investors. See Note 4 for further information regarding the Series A Preferred units. | ||||||||||
[8] | Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. “Equity investment throughput” refers to the Partnership’s share of average throughput for these investments. |
Acquisitions and Divestitures42
Acquisitions and Divestitures - Impact of the Deferred Purchase Price Obligation - Anadarko Table (Details) - USD ($) $ in Thousands | 12 Months Ended | |||||||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Mar. 02, 2015 | |||||
Property, Plant and Equipment [Line Items] | ||||||||
Deferred purchase price obligation - Anadarko, present value | [1] | $ 41,440 | $ 188,674 | |||||
Affiliates [Member] | Deferred Purchase Price Obligation - Anadarko [Member] | ||||||||
Property, Plant and Equipment [Line Items] | ||||||||
Accretion expense | [2] | (7,747) | 14,398 | $ 0 | ||||
Affiliates [Member] | Delaware Basin JV Gathering LLC [Member] | Deferred Purchase Price Obligation - Anadarko [Member] | ||||||||
Property, Plant and Equipment [Line Items] | ||||||||
Deferred purchase price obligation - Anadarko, present value | 41,440 | 188,674 | $ 174,276 | [3] | ||||
Accretion expense | (7,747) | [4] | 14,398 | [5] | ||||
Revision to Deferred purchase price obligation – Anadarko | [6] | (139,487) | ||||||
Deferred purchase price obligation - Anadarko, future value | $ 56,455 | $ 282,807 | $ 282,807 | |||||
[1] | See Note 2. | |||||||
[2] | See Note 2 for a discussion of the Deferred purchase price obligation - Anadarko. | |||||||
[3] | The Partnership acquired Delaware Basin JV Gathering LLC (“DBJV”) from Anadarko. DBJV owns a 50% interest in a gathering system and related facilities. The DBJV gathering system and related facilities (the “DBJV system”) are located in the Delaware Basin in Loving, Ward, Winkler and Reeves Counties, Texas. The Partnership will make a cash payment on March 31, 2020, to Anadarko as consideration for the acquisition of DBJV. At the acquisition date, the Partnership estimated the future payment would be $282.8 million, the net present value of which was $174.3 million. For further information, including revisions to the estimated future payment, see DBJV acquisition—deferred purchase price obligation - Anadarko below. | |||||||
[4] | Financing-related accretion revisions were recorded in Interest expense on the consolidated statements of operations. | |||||||
[5] | Accretion expense was recorded as a charge to Interest expense on the consolidated statements of operations. | |||||||
[6] | Recorded as revisions within Common units on the consolidated balance sheets and consolidated statements of equity and partners’ capital. |
Acquisitions and Divestitures43
Acquisitions and Divestitures - Additional Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2016 | Dec. 31, 2015 | Mar. 02, 2015 | |||
Property, Plant and Equipment [Line Items] | |||||
Deferred purchase price obligation - Anadarko, present value | [1] | $ 41,440 | $ 188,674 | ||
Hugoton System [Member] | |||||
Property, Plant and Equipment [Line Items] | |||||
Gain (loss) on sale of assets | (12,000) | ||||
Goodwill allocated to divestiture | 1,600 | ||||
Dew And Pinnacle Systems [Member] | |||||
Property, Plant and Equipment [Line Items] | |||||
Gain (loss) on sale of assets | 77,300 | ||||
Goodwill allocated to divestiture | 5,100 | ||||
Delaware Basin JV Gathering LLC [Member] | Deferred Purchase Price Obligation - Anadarko [Member] | Affiliates [Member] | |||||
Property, Plant and Equipment [Line Items] | |||||
Deferred purchase price obligation - Anadarko, future value | 56,455 | 282,807 | $ 282,807 | ||
Deferred purchase price obligation - Anadarko, present value | $ 41,440 | $ 188,674 | $ 174,276 | [2] | |
Discount rate percentage | 10.00% | ||||
Deferred purchase price obligation to Anadarko - future value change | $ 226,400 | ||||
[1] | See Note 2. | ||||
[2] | The Partnership acquired Delaware Basin JV Gathering LLC (“DBJV”) from Anadarko. DBJV owns a 50% interest in a gathering system and related facilities. The DBJV gathering system and related facilities (the “DBJV system”) are located in the Delaware Basin in Loving, Ward, Winkler and Reeves Counties, Texas. The Partnership will make a cash payment on March 31, 2020, to Anadarko as consideration for the acquisition of DBJV. At the acquisition date, the Partnership estimated the future payment would be $282.8 million, the net present value of which was $174.3 million. For further information, including revisions to the estimated future payment, see DBJV acquisition—deferred purchase price obligation - Anadarko below. |
Partnership Distributions - Cas
Partnership Distributions - Cash Distributions Table (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | ||||||||||||
Dec. 31, 2016 | [1] | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | |
Distributions Made to Members or Limited Partners [Abstract] | |||||||||||||
Total quarterly distribution per unit | $ 0.860 | $ 0.845 | $ 0.830 | $ 0.815 | $ 0.800 | $ 0.775 | $ 0.750 | $ 0.725 | $ 0.700 | $ 0.675 | $ 0.650 | $ 0.625 | |
Total quarterly cash distribution | $ 170,657 | $ 166,742 | $ 162,827 | $ 158,905 | $ 152,588 | $ 146,160 | $ 139,736 | $ 133,203 | $ 126,044 | $ 111,608 | $ 105,655 | $ 98,749 | |
[1] | The Board of Directors declared a cash distribution to the Partnership’s unitholders for the fourth quarter of 2016 of $0.860 per unit, or $170.7 million in aggregate, including incentive distributions, but excluding distributions on Class C units (see Class C unit distributions below) and Series A Preferred units (see Series A Preferred unit distributions below). The cash distribution was paid on February 13, 2017, to unitholders of record at the close of business on February 2, 2017. |
Partnership Distributions - Add
Partnership Distributions - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions | Mar. 14, 2016 | Apr. 30, 2016 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 |
Distribution Made to Limited Partner [Line Items] | ||||||||
Partnership agreement day requirement of distribution of available cash | 45 days | |||||||
Units issued | 946,261 | 498,009 | ||||||
Incentive distributions percentage | 48.00% | |||||||
Minimum [Member] | ||||||||
Distribution Made to Limited Partner [Line Items] | ||||||||
Distribution sharing percentage | 1.50% | |||||||
Maximum [Member] | ||||||||
Distribution Made to Limited Partner [Line Items] | ||||||||
Distribution sharing percentage | 49.50% | |||||||
Private Investor [Member] | Over-Allotment Option [Member] | ||||||||
Distribution Made to Limited Partner [Line Items] | ||||||||
Units issued | 7,892,220 | |||||||
Class C Units [Member] | ||||||||
Distribution Made to Limited Partner [Line Items] | ||||||||
Discount rate percentage | 6.00% | |||||||
Units issued | 178,977 | 946,261 | 498,009 | |||||
Series A Preferred Units [Member] | ||||||||
Distribution Made to Limited Partner [Line Items] | ||||||||
Series A Preferred units quarterly distribution per unit | $ 0.68 | |||||||
Series A Preferred units quarterly cash distribution | $ 14.9 | $ 14.9 | $ 14.1 | $ 1.9 | ||||
Number of days in prorated period | 77 days | 18 days | ||||||
Series A Preferred Units [Member] | Private Investor [Member] | ||||||||
Distribution Made to Limited Partner [Line Items] | ||||||||
Units issued | 14,030,611 | 14,030,611 | ||||||
Series A Preferred Units [Member] | Private Investor [Member] | Over-Allotment Option [Member] | ||||||||
Distribution Made to Limited Partner [Line Items] | ||||||||
Units issued | 7,892,220 | 7,892,220 | 7,892,220 |
Equity and Partners' Capital -
Equity and Partners' Capital - Equity Offerings Table (Details) - USD ($) | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||||
Nov. 30, 2014 | Dec. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Aug. 31, 2014 | Aug. 31, 2012 | |||
Capital Unit [Line Items] | |||||||||
Units issued | 946,261 | 498,009 | |||||||
Price per unit | [1] | $ 70.85 | |||||||
Underwriting discount and other offering expenses | [1] | $ 18,615,000 | |||||||
Net proceeds | [1] | $ 602,967,000 | |||||||
General partner's interest | 2.00% | ||||||||
Over-Allotment Option [Member] | |||||||||
Capital Unit [Line Items] | |||||||||
Net proceeds | $ 77,000,000 | ||||||||
125 Million COP [Member] | |||||||||
Capital Unit [Line Items] | |||||||||
Average price per unit | [2] | $ 73.48 | |||||||
Underwriting discount and other offering expenses | [2] | $ 1,738,000 | |||||||
Net proceeds | [2] | 83,245,000 | |||||||
Maximum aggregate principal of common units | $ 125,000,000 | ||||||||
Gross proceeds | $ 85,000,000 | ||||||||
500 Million COP [Member] | |||||||||
Capital Unit [Line Items] | |||||||||
Common units issued | 873,525 | ||||||||
Average price per unit | [3] | $ 66.61 | |||||||
Underwriting discount and other offering expenses | [3] | $ 805,000 | $ 805,000 | ||||||
Net proceeds | [3] | 57,385,000 | |||||||
Maximum aggregate principal of common units | $ 500,000,000 | ||||||||
Gross proceeds | 0 | 58,200,000 | |||||||
Commissions paid | $ 0 | $ 600,000 | |||||||
Common Units [Member] | |||||||||
Capital Unit [Line Items] | |||||||||
Common units issued | [1] | 8,620,153 | |||||||
Common Units [Member] | Over-Allotment Option [Member] | |||||||||
Capital Unit [Line Items] | |||||||||
Common units issued | 1,120,153 | ||||||||
Common Units [Member] | 125 Million COP [Member] | |||||||||
Capital Unit [Line Items] | |||||||||
Common units issued | [2] | 1,133,384 | |||||||
Common Units [Member] | 500 Million COP [Member] | |||||||||
Capital Unit [Line Items] | |||||||||
Common units issued | 0 | 873,525 | [3] | ||||||
General Partner [Member] | |||||||||
Capital Unit [Line Items] | |||||||||
Units issued | [1],[4] | 153,061 | |||||||
General Partner [Member] | 125 Million COP [Member] | |||||||||
Capital Unit [Line Items] | |||||||||
Units issued | [2],[4] | 23,132 | |||||||
[1] | Includes the issuance of 1,120,153 common units pursuant to the partial exercise of the underwriters’ over-allotment option, the net proceeds from which were $77.0 million. Beginning with this partial exercise, the Partnership’s general partner elected not to make a corresponding capital contribution to maintain its 2.0% interest in the Partnership. | ||||||||
[2] | Represents common and general partner units issued during the year ended December 31, 2014, under the $125.0 million COP. Gross proceeds generated (including the general partner’s proportionate capital contributions) during the year ended December 31, 2014, were $85.0 million. The price per unit in the table above represents an average price for all issuances under the $125.0 million COP during the year ended December 31, 2014. As of December 31, 2014, the Partnership had used all the capacity to issue common units under this registration statement. | ||||||||
[3] | Represents common units issued during the year ended December 31, 2015, pursuant to the Partnership’s registration statement filed with the SEC in August 2014 authorizing the issuance of up to an aggregate of $500.0 million of common units (the “$500.0 million COP”). Gross proceeds generated during the three months and year ended December 31, 2015, were zero and $58.2 million, respectively. Commissions paid during the three months and year ended December 31, 2015, were zero and $0.6 million, respectively. The price per unit in the table above represents an average price for all issuances under the $500.0 million COP during the year ended December 31, 2015. | ||||||||
[4] | Represents general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution. |
Equity and Partners' Capital 47
Equity and Partners' Capital - Partnership Interests Table (Details) - shares | Mar. 14, 2016 | Apr. 30, 2016 | Nov. 30, 2014 | Dec. 31, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Capital Unit [Line Items] | ||||||||||
Balance | 142,571,895 | 142,571,895 | 141,192,051 | |||||||
Units issued | 946,261 | 498,009 | ||||||||
Long-Term Incentive Plan award vestings | 5,403 | 8,310 | ||||||||
Balance | 167,535,992 | 167,535,992 | 142,571,895 | |||||||
Over-Allotment Option [Member] | Private Investor [Member] | ||||||||||
Capital Unit [Line Items] | ||||||||||
Units issued | 7,892,220 | |||||||||
Springfield Pipeline LLC [Member] | ||||||||||
Capital Unit [Line Items] | ||||||||||
Acquisition | 16,120,213 | |||||||||
500 Million COP [Member] | ||||||||||
Capital Unit [Line Items] | ||||||||||
Common units issued | 873,525 | |||||||||
Common Units [Member] | ||||||||||
Capital Unit [Line Items] | ||||||||||
Balance | 128,576,965 | 128,576,965 | 127,695,130 | |||||||
Long-Term Incentive Plan award vestings | 5,403 | 8,310 | ||||||||
Common units issued | [1] | 8,620,153 | ||||||||
Balance | 130,671,970 | 130,671,970 | 128,576,965 | |||||||
Common Units [Member] | Over-Allotment Option [Member] | ||||||||||
Capital Unit [Line Items] | ||||||||||
Common units issued | 1,120,153 | |||||||||
Common Units [Member] | Springfield Pipeline LLC [Member] | ||||||||||
Capital Unit [Line Items] | ||||||||||
Units issued | [2] | 2,089,602 | ||||||||
Acquisition | 2,089,602 | |||||||||
Common Units [Member] | 500 Million COP [Member] | ||||||||||
Capital Unit [Line Items] | ||||||||||
Common units issued | 0 | 873,525 | [3] | |||||||
Class C Units [Member] | ||||||||||
Capital Unit [Line Items] | ||||||||||
Balance | 11,411,862 | 11,411,862 | 10,913,853 | |||||||
Units issued | 178,977 | 946,261 | 498,009 | |||||||
Balance | 12,358,123 | 12,358,123 | 11,411,862 | |||||||
Series A Preferred Units [Member] | ||||||||||
Capital Unit [Line Items] | ||||||||||
Balance | 0 | 0 | 0 | |||||||
Balance | 21,922,831 | 21,922,831 | 0 | |||||||
Series A Preferred Units [Member] | Private Investor [Member] | ||||||||||
Capital Unit [Line Items] | ||||||||||
Units issued | 14,030,611 | 14,030,611 | ||||||||
Series A Preferred Units [Member] | Over-Allotment Option [Member] | Private Investor [Member] | ||||||||||
Capital Unit [Line Items] | ||||||||||
Units issued | 7,892,220 | 7,892,220 | 7,892,220 | |||||||
Series A Preferred Units [Member] | Springfield Pipeline LLC [Member] | ||||||||||
Capital Unit [Line Items] | ||||||||||
Units issued | [2] | 14,030,611 | ||||||||
Acquisition | 14,030,611 | |||||||||
General Partner [Member] | ||||||||||
Capital Unit [Line Items] | ||||||||||
Balance | 2,583,068 | 2,583,068 | 2,583,068 | |||||||
Units issued | [1],[4] | 153,061 | ||||||||
Balance | 2,583,068 | 2,583,068 | 2,583,068 | |||||||
[1] | Includes the issuance of 1,120,153 common units pursuant to the partial exercise of the underwriters’ over-allotment option, the net proceeds from which were $77.0 million. Beginning with this partial exercise, the Partnership’s general partner elected not to make a corresponding capital contribution to maintain its 2.0% interest in the Partnership. | |||||||||
[2] | The Partnership acquired Springfield Pipeline LLC (“Springfield”) from Anadarko for $750.0 million, consisting of $712.5 million in cash and the issuance of 1,253,761 of the Partnership’s common units. Springfield owns a 50.1% interest in an oil gathering system and a gas gathering system, such interest being referred to in this report as the “Springfield interest.” The Springfield oil and gas gathering systems (collectively, the “Springfield system”) are located in Dimmit, La Salle, Maverick and Webb Counties in South Texas. The Partnership financed the cash portion of the acquisition through: (i) borrowings of $247.5 million on the Partnership’s senior unsecured revolving credit facility (“RCF”), (ii) the issuance of 835,841 of the Partnership’s common units to WGP and (iii) the issuance of Series A Preferred units to private investors. See Note 4 for further information regarding the Series A Preferred units. | |||||||||
[3] | Represents common units issued during the year ended December 31, 2015, pursuant to the Partnership’s registration statement filed with the SEC in August 2014 authorizing the issuance of up to an aggregate of $500.0 million of common units (the “$500.0 million COP”). Gross proceeds generated during the three months and year ended December 31, 2015, were zero and $58.2 million, respectively. Commissions paid during the three months and year ended December 31, 2015, were zero and $0.6 million, respectively. The price per unit in the table above represents an average price for all issuances under the $500.0 million COP during the year ended December 31, 2015. | |||||||||
[4] | Represents general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution. |
Equity and Partners' Capital 48
Equity and Partners' Capital - Calculation of Net Income (Loss) Per Unit Table (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Earnings Per Unit [Line Items] | ||||
Net income (loss) attributable to Western Gas Partners, LP | $ 591,331 | $ 4,106 | $ 442,643 | |
Pre-acquisition net (income) loss allocated to Anadarko | (11,326) | (79,386) | (65,154) | |
General partner interest in net (income) loss | [1] | $ (236,561) | $ (180,996) | $ (120,980) |
Net income (loss) per common unit – basic | [2] | $ 1.74 | $ (1.95) | $ 2.13 |
Net income (loss) per common unit – diluted | [2],[3] | $ 1.74 | $ (1.95) | $ 2.12 |
Series A Preferred Units [Member] | ||||
Earnings Per Unit [Line Items] | ||||
Limited partners’ interest in net income (loss) | [1],[4] | $ 76,893 | $ 0 | $ 0 |
Anti-dilutive units excluded from computation of earnings per unit | [3] | 16,860 | 0 | 0 |
Common and Class C Units [Member] | ||||
Earnings Per Unit [Line Items] | ||||
Limited partners’ interest in net income (loss) | [1] | $ 266,551 | $ (256,276) | $ 256,509 |
Common Units [Member] | ||||
Earnings Per Unit [Line Items] | ||||
Limited partners’ interest in net income (loss) | [4] | $ 226,611 | $ (250,210) | $ 254,737 |
Weighted-average units outstanding - basic | 130,253 | 128,345 | 119,822 | |
Weighted average units outstanding - diluted | [3] | 130,253 | 128,345 | 120,928 |
Class C Units [Member] | ||||
Earnings Per Unit [Line Items] | ||||
Limited partners’ interest in net income (loss) | [4] | $ 39,940 | $ (6,066) | $ 1,772 |
Anti-dilutive units excluded from computation of earnings per unit | [3] | 11,945 | 11,114 | 1,106 |
[1] | Represents net income (loss) earned on and subsequent to the date of acquisition of the Partnership assets (as defined in Note 1). See Note 4. | |||
[2] | See Note 4 for the calculation of net income (loss) per common unit. | |||
[3] | The impact of Class C units and the conversion of Series A Preferred units would be anti-dilutive for the year ended December 31, 2016, and the impact of Class C units would be anti-dilutive for the year ended December 31, 2015. | |||
[4] | Adjusted to reflect amortization of the beneficial conversion features. |
Equity and Partners' Capital 49
Equity and Partners' Capital - Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands | Mar. 14, 2016 | Apr. 30, 2016 | Nov. 30, 2014 | Dec. 31, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Aug. 31, 2014 | ||
Schedule Of Investments [Line Items] | ||||||||||||
Units issued | 946,261 | 498,009 | ||||||||||
Price per unit | [1] | $ 70.85 | ||||||||||
Beneficial conversion feature | $ 0 | $ 0 | ||||||||||
General partner units owned | 2,583,068 | 2,583,068 | 2,583,068 | |||||||||
General partner's interest | 2.00% | |||||||||||
Private Investor [Member] | Over-Allotment Option [Member] | ||||||||||||
Schedule Of Investments [Line Items] | ||||||||||||
Units issued | 7,892,220 | |||||||||||
Western Gas Equity Partners, LP [Member] | ||||||||||||
Schedule Of Investments [Line Items] | ||||||||||||
General partner units owned | 2,583,068 | 2,583,068 | ||||||||||
General partner's interest | 1.50% | |||||||||||
Common Units [Member] | ||||||||||||
Schedule Of Investments [Line Items] | ||||||||||||
Common units issued | [1] | 8,620,153 | ||||||||||
Limited partner units owned | 130,671,970 | 130,671,970 | 128,576,965 | |||||||||
Common Units [Member] | Over-Allotment Option [Member] | ||||||||||||
Schedule Of Investments [Line Items] | ||||||||||||
Common units issued | 1,120,153 | |||||||||||
Common Units [Member] | Other Subsidiaries Of Anadarko [Member] | ||||||||||||
Schedule Of Investments [Line Items] | ||||||||||||
Limited partner units owned | 2,011,380 | 2,011,380 | ||||||||||
Common Units [Member] | Western Gas Equity Partners, LP [Member] | ||||||||||||
Schedule Of Investments [Line Items] | ||||||||||||
Limited partner units owned | 50,132,046 | 50,132,046 | ||||||||||
Limited partner ownership interest | 29.90% | |||||||||||
Common Units [Member] | Public [Member] | ||||||||||||
Schedule Of Investments [Line Items] | ||||||||||||
Limited partner units owned | 78,528,544 | 78,528,544 | ||||||||||
Limited partner ownership interest | 46.90% | |||||||||||
Class C Units [Member] | ||||||||||||
Schedule Of Investments [Line Items] | ||||||||||||
Units issued | 178,977 | 946,261 | 498,009 | |||||||||
Price per unit | $ 68.72 | |||||||||||
Proceeds from the issuance of units | $ 750,000 | $ 0 | $ 0 | 750,000 | ||||||||
Beneficial conversion feature | 34,800 | |||||||||||
Limited partner units owned | 12,358,123 | 12,358,123 | 11,411,862 | |||||||||
Class C Units [Member] | Other Subsidiaries Of Anadarko [Member] | ||||||||||||
Schedule Of Investments [Line Items] | ||||||||||||
Units issued | 10,913,853 | |||||||||||
Limited partner units owned | 12,358,123 | 12,358,123 | ||||||||||
Class C Units [Member] | Maximum [Member] | ||||||||||||
Schedule Of Investments [Line Items] | ||||||||||||
Redeemable option on units | $ 150,000 | |||||||||||
Series A Preferred Units [Member] | ||||||||||||
Schedule Of Investments [Line Items] | ||||||||||||
Price per unit | $ 32 | |||||||||||
Proceeds from the issuance of units | $ 440,000 | $ 686,937 | $ 0 | $ 0 | ||||||||
Beneficial conversion feature | $ 21,700 | |||||||||||
Transaction fee | 2.00% | |||||||||||
Series A Preferred units, units issued upon conversion | 1 | 1 | ||||||||||
Minimum common unit closing price for conversion | $ 48 | $ 48 | ||||||||||
Limited partner units owned | 21,922,831 | 21,922,831 | 0 | |||||||||
Series A Preferred Units [Member] | Over-Allotment Option [Member] | ||||||||||||
Schedule Of Investments [Line Items] | ||||||||||||
Proceeds from the issuance of units | $ 246,900 | |||||||||||
Beneficial conversion feature | $ 71,700 | |||||||||||
Series A Preferred Units [Member] | Private Investor [Member] | ||||||||||||
Schedule Of Investments [Line Items] | ||||||||||||
Units issued | 14,030,611 | 14,030,611 | ||||||||||
Limited partner units owned | 21,922,831 | 21,922,831 | ||||||||||
Limited partner ownership interest | 13.10% | |||||||||||
Series A Preferred Units [Member] | Private Investor [Member] | Over-Allotment Option [Member] | ||||||||||||
Schedule Of Investments [Line Items] | ||||||||||||
Units issued | 7,892,220 | 7,892,220 | 7,892,220 | |||||||||
Series A Preferred Units [Member] | Change In Control [Member] | ||||||||||||
Schedule Of Investments [Line Items] | ||||||||||||
Redemption price per unit | $ 32.32 | $ 32.32 | ||||||||||
Incentive Distribution Rights [Member] | Western Gas Equity Partners, LP [Member] | ||||||||||||
Schedule Of Investments [Line Items] | ||||||||||||
General partner's interest | 100.00% | |||||||||||
Common and Class C Units [Member] | Other Subsidiaries Of Anadarko [Member] | ||||||||||||
Schedule Of Investments [Line Items] | ||||||||||||
Limited partner ownership interest | 8.60% | |||||||||||
500 Million COP [Member] | ||||||||||||
Schedule Of Investments [Line Items] | ||||||||||||
Common units issued | 873,525 | |||||||||||
Maximum aggregate principal of common units | $ 500,000 | |||||||||||
500 Million COP [Member] | Common Units [Member] | ||||||||||||
Schedule Of Investments [Line Items] | ||||||||||||
Common units issued | 0 | 873,525 | [2] | |||||||||
[1] | Includes the issuance of 1,120,153 common units pursuant to the partial exercise of the underwriters’ over-allotment option, the net proceeds from which were $77.0 million. Beginning with this partial exercise, the Partnership’s general partner elected not to make a corresponding capital contribution to maintain its 2.0% interest in the Partnership. | |||||||||||
[2] | Represents common units issued during the year ended December 31, 2015, pursuant to the Partnership’s registration statement filed with the SEC in August 2014 authorizing the issuance of up to an aggregate of $500.0 million of common units (the “$500.0 million COP”). Gross proceeds generated during the three months and year ended December 31, 2015, were zero and $58.2 million, respectively. Commissions paid during the three months and year ended December 31, 2015, were zero and $0.6 million, respectively. The price per unit in the table above represents an average price for all issuances under the $500.0 million COP during the year ended December 31, 2015. |
Transactions with Affiliates -
Transactions with Affiliates - Gains (Losses) on Commodity Price Swap Agreements Table (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Gains (losses) on commodity price swap agreements related to sales and purchases | ||||
Gains (losses) on commodity price swap agreements | $ 28,457 | $ 66,292 | $ 54,868 | |
Sales [Member] | ||||
Gains (losses) on commodity price swap agreements related to sales and purchases | ||||
Gains (losses) on commodity price swap agreements | [1] | 71,034 | 191,236 | 123,360 |
Sales [Member] | Natural Gas [Member] | ||||
Gains (losses) on commodity price swap agreements related to sales and purchases | ||||
Gains (losses) on commodity price swap agreements | [1] | 11,116 | 45,978 | 9,494 |
Sales [Member] | Natural Gas Liquids [Member] | ||||
Gains (losses) on commodity price swap agreements related to sales and purchases | ||||
Gains (losses) on commodity price swap agreements | [1] | 59,918 | 145,258 | 113,866 |
Purchases [Member] | ||||
Gains (losses) on commodity price swap agreements related to sales and purchases | ||||
Gains (losses) on commodity price swap agreements | [2] | $ (42,577) | $ (124,944) | $ (68,492) |
[1] | Reported in affiliate Natural gas and natural gas liquids sales in the consolidated statements of operations in the period in which the related sale is recorded. | |||
[2] | Reported in Cost of product in the consolidated statements of operations in the period in which the related purchase is recorded. |
Transactions with Affiliates 51
Transactions with Affiliates - Commodity Price Swap Agreements Extensions Tables (Details) | Dec. 01, 2016$ / MMBTU$ / bbl | Dec. 31, 2015$ / MMBTU$ / bbl | Dec. 08, 2015$ / MMBTU$ / bbl | Jun. 25, 2015$ / MMBTU$ / bbl | |
DJ Basin Complex [Member] | Years 2015 - 2017 [Member] | Ethane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity swap fixed price | 18.41 | ||||
DJ Basin Complex [Member] | Years 2015 - 2017 [Member] | Propane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity swap fixed price | 47.08 | ||||
DJ Basin Complex [Member] | Years 2015 - 2017 [Member] | Isobutane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity swap fixed price | 62.09 | ||||
DJ Basin Complex [Member] | Years 2015 - 2017 [Member] | Normal butane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity swap fixed price | 54.62 | ||||
DJ Basin Complex [Member] | Years 2015 - 2017 [Member] | Natural gasoline [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity swap fixed price | 72.88 | ||||
DJ Basin Complex [Member] | Years 2015 - 2017 [Member] | Condensate [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity swap fixed price | 76.47 | ||||
DJ Basin Complex [Member] | Years 2015 - 2017 [Member] | Natural gas (per MMBtu) [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity swap fixed price | $ / MMBTU | 5.96 | ||||
DJ Basin Complex [Member] | Year 2015 [Member] | Ethane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | [1] | 1.96 | |||
DJ Basin Complex [Member] | Year 2015 [Member] | Propane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | [1] | 13.10 | |||
DJ Basin Complex [Member] | Year 2015 [Member] | Isobutane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | [1] | 19.75 | |||
DJ Basin Complex [Member] | Year 2015 [Member] | Normal butane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | [1] | 18.99 | |||
DJ Basin Complex [Member] | Year 2015 [Member] | Natural gasoline [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | [1] | 52.59 | |||
DJ Basin Complex [Member] | Year 2015 [Member] | Condensate [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | [1] | 52.59 | |||
DJ Basin Complex [Member] | Year 2015 [Member] | Natural gas (per MMBtu) [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | $ / MMBTU | [1] | 2.75 | |||
DJ Basin Complex [Member] | Year 2016 [Member] | Ethane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | [1] | 0.60 | |||
DJ Basin Complex [Member] | Year 2016 [Member] | Propane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | [1] | 10.98 | |||
DJ Basin Complex [Member] | Year 2016 [Member] | Isobutane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | [1] | 17.23 | |||
DJ Basin Complex [Member] | Year 2016 [Member] | Normal butane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | [1] | 16.86 | |||
DJ Basin Complex [Member] | Year 2016 [Member] | Natural gasoline [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | [1] | 26.15 | |||
DJ Basin Complex [Member] | Year 2016 [Member] | Condensate [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | [1] | 34.65 | |||
DJ Basin Complex [Member] | Year 2016 [Member] | Natural gas (per MMBtu) [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | $ / MMBTU | [1] | 2.11 | |||
DJ Basin Complex [Member] | Year 2017 [Member] | Ethane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | [1] | 5.09 | |||
DJ Basin Complex [Member] | Year 2017 [Member] | Propane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | [1] | 18.85 | |||
DJ Basin Complex [Member] | Year 2017 [Member] | Isobutane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | [1] | 26.83 | |||
DJ Basin Complex [Member] | Year 2017 [Member] | Normal butane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | [1] | 26.20 | |||
DJ Basin Complex [Member] | Year 2017 [Member] | Natural gasoline [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | [1] | 41.84 | |||
DJ Basin Complex [Member] | Year 2017 [Member] | Condensate [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | [1] | 45.40 | |||
DJ Basin Complex [Member] | Year 2017 [Member] | Natural gas (per MMBtu) [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | $ / MMBTU | [1] | 3.05 | |||
Hugoton System [Member] | Year 2015 [Member] | Condensate [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | [1],[2] | 32.56 | |||
Hugoton System [Member] | Year 2015 [Member] | Natural gas (per MMBtu) [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | $ / MMBTU | [1],[2] | 2.74 | |||
Hugoton System [Member] | Year 2016 [Member] | Condensate [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | [1],[2] | 18.81 | |||
Hugoton System [Member] | Year 2016 [Member] | Natural gas (per MMBtu) [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | $ / MMBTU | [1],[2] | 2.12 | |||
Hugoton System [Member] | Years 2015 - 2016 [Member] | Condensate [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity swap fixed price | [2] | 78.61 | |||
Hugoton System [Member] | Years 2015 - 2016 [Member] | Natural gas (per MMBtu) [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity swap fixed price | $ / MMBTU | [2] | 5.50 | |||
MGR Assets [Member] | Year 2015 [Member] | Ethane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity swap fixed price | 23.41 | ||||
MGR Assets [Member] | Year 2015 [Member] | Propane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity swap fixed price | 52.99 | ||||
MGR Assets [Member] | Year 2015 [Member] | Isobutane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity swap fixed price | 74.02 | ||||
MGR Assets [Member] | Year 2015 [Member] | Normal butane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity swap fixed price | 65.04 | ||||
MGR Assets [Member] | Year 2015 [Member] | Natural gasoline [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity swap fixed price | 81.82 | ||||
MGR Assets [Member] | Year 2015 [Member] | Condensate [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity swap fixed price | 81.82 | ||||
MGR Assets [Member] | Year 2015 [Member] | Natural gas (per MMBtu) [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity swap fixed price | $ / MMBTU | 4.66 | ||||
MGR Assets [Member] | Year 2017 [Member] | Ethane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | [1] | 4.08 | |||
MGR Assets [Member] | Year 2017 [Member] | Propane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | [1] | 19.24 | |||
MGR Assets [Member] | Year 2017 [Member] | Isobutane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | [1] | 25.79 | |||
MGR Assets [Member] | Year 2017 [Member] | Normal butane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | [1] | 25.16 | |||
MGR Assets [Member] | Year 2017 [Member] | Natural gasoline [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | [1] | 45.01 | |||
MGR Assets [Member] | Year 2017 [Member] | Condensate [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | [1] | 53.55 | |||
MGR Assets [Member] | Year 2017 [Member] | Natural gas (per MMBtu) [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity market price | $ / MMBTU | [1] | 3.05 | |||
MGR Assets [Member] | Years 2016 - 2017 [Member] | Ethane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity swap fixed price | 23.11 | ||||
MGR Assets [Member] | Years 2016 - 2017 [Member] | Propane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity swap fixed price | 52.90 | ||||
MGR Assets [Member] | Years 2016 - 2017 [Member] | Isobutane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity swap fixed price | 73.89 | ||||
MGR Assets [Member] | Years 2016 - 2017 [Member] | Normal butane [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity swap fixed price | 64.93 | ||||
MGR Assets [Member] | Years 2016 - 2017 [Member] | Natural gasoline [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity swap fixed price | 81.68 | ||||
MGR Assets [Member] | Years 2016 - 2017 [Member] | Condensate [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity swap fixed price | 81.68 | ||||
MGR Assets [Member] | Years 2016 - 2017 [Member] | Natural gas (per MMBtu) [Member] | |||||
Commodity Price Risk Swap [Line Items] | |||||
Commodity swap fixed price | $ / MMBTU | 4.87 | ||||
[1] | Represents the New York Mercantile Exchange forward strip price as of June 25, 2015, December 8, 2015 and December 1, 2016, for the 2015 Market Prices, 2016 Market Prices and 2017 Market Prices, respectively, adjusted for product specification, location, basis and, in the case of NGLs, transportation and fractionation costs. | ||||
[2] | The Hugoton system was sold in October 2016. See Note 2. |
Transactions with Affiliates -
Transactions with Affiliates - Omnibus Agreement Table (Details) - Omnibus Agreement [Member] - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Related Party Transaction [Line Items] | |||
Allocated costs from Anadarko | $ 37,770 | $ 31,846 | $ 28,255 |
General and Administrative Expense [Member] | |||
Related Party Transaction [Line Items] | |||
Allocated costs from Anadarko | 29,360 | 22,896 | 20,249 |
Public Company Expenses [Member] | |||
Related Party Transaction [Line Items] | |||
Allocated costs from Anadarko | $ 8,410 | $ 8,950 | $ 8,006 |
Transactions with Affiliates 53
Transactions with Affiliates - LTIP Award Activity Table (Details) - $ / shares | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Related Party Fees and Other Arrangements, Limited Liability Company (LLC) or Limited Partnership (LP) [Abstract] | |||
Value per unit of phantom units outstanding at beginning of year | $ 68.78 | $ 60.74 | $ 49.47 |
Value per unit of phantom units vested during the period | 68.78 | 60.69 | 49.55 |
Value per unit of phantom units granted during the period | 49.30 | 69.10 | 68.14 |
Value per unit of phantom units outstanding at end of year | $ 49.30 | $ 68.78 | $ 60.74 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Phantom units outstanding at beginning of year | 5,477 | 9,522 | 16,844 |
Phantom units vested | (5,477) | (9,257) | (13,122) |
Phantom units granted | 7,304 | 5,212 | 5,800 |
Phantom units outstanding at end of year | 7,304 | 5,477 | 9,522 |
Transactions with Affiliates 54
Transactions with Affiliates - Equipment Purchases and Sales Table (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Related Party Transaction [Line Items] | |||
Partners’ capital adjustment | $ 581 | $ 4,632 | $ 10,706 |
Affiliates [Member] | Purchases [Member] | |||
Related Party Transaction [Line Items] | |||
Cash consideration - purchases | 3,965 | 10,903 | 22,943 |
Net carrying value | (3,366) | (6,318) | (12,210) |
Partners’ capital adjustment | 599 | 4,585 | 10,733 |
Affiliates [Member] | Sales [Member] | |||
Related Party Transaction [Line Items] | |||
Cash consideration - sales | 623 | 925 | 402 |
Net carrying value | (605) | (972) | (375) |
Partners’ capital adjustment | $ (18) | $ 47 | $ (27) |
Transactions with Affiliates 55
Transactions with Affiliates - Summary of Affiliate Transactions Table (Details) - USD ($) $ in Thousands | Mar. 14, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Related Party Transaction [Line Items] | |||||
Revenues and other | $ 1,804,270 | $ 1,752,072 | $ 1,533,377 | ||
Equity income, net – affiliates | [1] | 78,717 | 71,251 | 57,836 | |
Cost of product | [2] | 494,194 | 528,369 | 458,379 | |
Operation and maintenance | [2] | 308,010 | 331,972 | 293,710 | |
General and administrative | [2] | 45,591 | 41,319 | 38,561 | |
Operating expenses | 1,176,408 | 1,723,017 | 1,036,473 | ||
Interest income | [3] | 16,900 | 16,900 | 16,900 | |
Interest expense | [4] | 114,921 | 113,872 | 76,766 | |
Proceeds from the issuance of common and general partner units, net of offering expenses | 25,000 | 57,353 | 704,489 | ||
Distributions to unitholders | [5] | 671,938 | 545,143 | 408,621 | |
Above-market component of swap extensions with Anadarko | [5] | $ 45,820 | $ 18,449 | 0 | |
Units issued | 946,261 | 498,009 | |||
Springfield Pipeline LLC [Member] | Common Units [Member] | |||||
Related Party Transaction [Line Items] | |||||
Units issued | [6] | 2,089,602 | |||
Affiliates [Member] | |||||
Related Party Transaction [Line Items] | |||||
Revenues and other | [1] | $ 1,228,232 | $ 1,220,639 | 1,203,974 | |
Cost of product | [1] | 80,455 | 167,354 | 127,930 | |
Operation and maintenance | [7] | 72,330 | 77,061 | 71,386 | |
General and administrative | [8] | 38,066 | 33,903 | 31,308 | |
Operating expenses | 190,851 | 278,318 | 230,624 | ||
Interest expense | [9] | (7,747) | 14,398 | 0 | |
Proceeds from the issuance of common and general partner units, net of offering expenses | [10] | 25,000 | 0 | 0 | |
Distributions to unitholders | [11] | $ 382,711 | $ 314,200 | $ 234,024 | |
Western Gas Equity Partners, LP [Member] | Springfield Pipeline LLC [Member] | Common Units [Member] | |||||
Related Party Transaction [Line Items] | |||||
Units issued | 835,841 | ||||
[1] | Represents amounts earned or incurred on and subsequent to the date of acquisition of the Partnership assets, as well as amounts earned or incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets, recognized under gathering, treating or processing agreements, and purchase and sale agreements. | ||||
[2] | Cost of product includes product purchases from Anadarko (as defined in Note 1) of $80.5 million, $167.4 million and $127.9 million for the years ended December 31, 2016, 2015 and 2014, respectively. Operation and maintenance includes charges from Anadarko of $72.3 million, $77.1 million and $71.4 million for the years ended December 31, 2016, 2015 and 2014, respectively. General and administrative includes charges from Anadarko of $38.1 million, $33.9 million and $31.3 million for the years ended December 31, 2016, 2015 and 2014, respectively. See Note 5. | ||||
[3] | Represents interest income recognized on the note receivable from Anadarko. | ||||
[4] | Includes affiliate (as defined in Note 1) amounts of $7.7 million, $(14.4) million and zero for the years ended December 31, 2016, 2015 and 2014, respectively. See Note 2 and Note 12. | ||||
[5] | See Note 5. | ||||
[6] | The Partnership acquired Springfield Pipeline LLC (“Springfield”) from Anadarko for $750.0 million, consisting of $712.5 million in cash and the issuance of 1,253,761 of the Partnership’s common units. Springfield owns a 50.1% interest in an oil gathering system and a gas gathering system, such interest being referred to in this report as the “Springfield interest.” The Springfield oil and gas gathering systems (collectively, the “Springfield system”) are located in Dimmit, La Salle, Maverick and Webb Counties in South Texas. The Partnership financed the cash portion of the acquisition through: (i) borrowings of $247.5 million on the Partnership’s senior unsecured revolving credit facility (“RCF”), (ii) the issuance of 835,841 of the Partnership’s common units to WGP and (iii) the issuance of Series A Preferred units to private investors. See Note 4 for further information regarding the Series A Preferred units. | ||||
[7] | Represents expenses incurred on and subsequent to the date of the acquisition of the Partnership assets, as well as expenses incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets. | ||||
[8] | Represents general and administrative expense incurred on and subsequent to the date of the Partnership’s acquisition of the Partnership assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of the Partnership assets by the Partnership. These amounts include equity-based compensation expense allocated to the Partnership by Anadarko (see WES LTIP and WGP LTIP and Anadarko Incentive Plans within this Note 5) and amounts charged by Anadarko under the omnibus agreement. | ||||
[9] | For the years ended December 31, 2016 and 2015, includes amounts related to the Deferred purchase price obligation - Anadarko (see Note 2 and Note 12). | ||||
[10] | Represents proceeds from the issuance of 835,841 common units to WGP as partial funding for the acquisition of Springfield (see Note 2). | ||||
[11] | Represents distributions paid under the partnership agreement (see Note 3 and Note 4). |
Transactions with Affiliates 56
Transactions with Affiliates - Additional Information (Details) - USD ($) | 1 Months Ended | 12 Months Ended | |||
May 31, 2008 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Related Party Transaction [Line Items] | |||||
Note receivable - Anadarko | $ 260,000,000 | $ 260,000,000 | |||
Above-market component of swap extensions with Anadarko | [1] | 45,820,000 | 18,449,000 | ||
Contributions of equity-based compensation from Anadarko | $ 4,214,000 | 3,551,000 | $ 3,167,000 | ||
Western Gas Partners Long Term Incentive Plan [Member] | |||||
Related Party Transaction [Line Items] | |||||
Units vesting period | 3 years | ||||
Equity-based compensation expense | $ 400,000 | 500,000 | 600,000 | ||
Unvested equity-based compensation expense | $ 100,000 | ||||
Weighted-average term of unvested awards | 3 months | ||||
Western Gas Equity Partners Long Term Incentive Plan [Member] | Anadarko Incentive Plans [Member] | |||||
Related Party Transaction [Line Items] | |||||
Equity-based compensation expense | $ 5,200,000 | 3,900,000 | 3,500,000 | ||
Unvested equity-based compensation expense | $ 10,800,000 | ||||
Weighted-average term of unvested awards | 2 years 3 months | ||||
Contributions of equity-based compensation from Anadarko | $ 4,200,000 | $ 3,600,000 | $ 3,200,000 | ||
Natural Gas [Member] | Gathering, Treating and Transportation [Member] | |||||
Related Party Transaction [Line Items] | |||||
Affiliate throughput percent | 37.00% | 53.00% | 56.00% | ||
Natural Gas [Member] | Processing [Member] | |||||
Related Party Transaction [Line Items] | |||||
Affiliate throughput percent | 54.00% | 51.00% | 57.00% | ||
Crude Oil and NGL [Member] | Gathering, Treating and Transportation [Member] | |||||
Related Party Transaction [Line Items] | |||||
Affiliate throughput percent | 65.00% | 100.00% | 100.00% | ||
Affiliates [Member] | |||||
Related Party Transaction [Line Items] | |||||
Note receivable - Anadarko | $ 260,000,000 | ||||
Note receivable, due date | May 14, 2038 | ||||
Fixed annual rate for note receivable bearing interest | 6.50% | ||||
Affiliates [Member] | Level 2 Inputs [Member] | Market Approach Valuation Technique [Member] | |||||
Related Party Transaction [Line Items] | |||||
Fair value of the note receivable | $ 313,300,000 | $ 252,300,000 | |||
Independent Director [Member] | Western Gas Partners Long Term Incentive Plan [Member] | |||||
Related Party Transaction [Line Items] | |||||
Units vesting period | 1 year | ||||
[1] | See Note 5. |
Income Taxes - Components of In
Income Taxes - Components of Income Tax Expense (Benefit) Table (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Current income tax expense (benefit) | |||
Federal income tax expense (benefit) | $ 4,477 | $ 32,422 | $ (114) |
State income tax expense (benefit) | 1,340 | 1,764 | 493 |
Total current income tax expense (benefit) | 5,817 | 34,186 | 379 |
Deferred income tax expense (benefit) | |||
Federal income tax expense (benefit) | 1,622 | 10,251 | 35,361 |
State income tax expense (benefit) | 933 | 1,095 | 3,321 |
Total deferred income tax expense (benefit) | 2,555 | 11,346 | 38,682 |
Total income tax expense (benefit) | $ 8,372 | $ 45,532 | $ 39,061 |
Income Taxes - Tax Rate Reconci
Income Taxes - Tax Rate Reconciliation Table (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Related Party Transaction [Line Items] | |||
Income (loss) before income taxes | $ 610,666 | $ 59,739 | $ 495,729 |
Statutory tax rate | 0.00% | 0.00% | 0.00% |
Adjustments resulting from: | |||
Federal taxes on income | $ 0 | $ 0 | $ 0 |
State taxes on income (net of federal benefit) and Texas margin tax expense (benefit) | 2,093 | 2,411 | 2,481 |
Income tax expense (benefit) | $ 8,372 | $ 45,532 | $ 39,061 |
Effective tax rate | 1.00% | 76.00% | 8.00% |
Change in deferred state income taxes | $ 2,200 | ||
Change in Texas margin tax rates | 0.25% | ||
Pre Acquisition From Parent [Member] | |||
Adjustments resulting from: | |||
Federal taxes on income | $ 6,162 | $ 42,823 | $ 35,716 |
State taxes on income (net of federal benefit) and Texas margin tax expense (benefit) | $ 117 | $ 298 | $ 864 |
Income Taxes - Income Tax Tempo
Income Taxes - Income Tax Temporary Differences Table (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Income Tax Disclosure [Abstract] | ||
Depreciable property | $ (4,976) | $ (138,159) |
Credit carryforwards | 498 | 512 |
Other intangible assets | (1,928) | (2,070) |
Other | 4 | 13 |
Net long-term deferred income tax liabilities | $ (6,402) | $ (139,704) |
Income Taxes - Additional Infor
Income Taxes - Additional Information (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | ||
Credit carryforwards | $ 498 | $ 512 |
Tax credit carryforward, expiration date | Dec. 31, 2026 |
Property, Plant and Equipment -
Property, Plant and Equipment - Historical Cost Table (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment | $ 6,861,942 | $ 6,556,778 |
Accumulated depreciation | 1,812,010 | 1,697,999 |
Net property, plant and equipment | 5,049,932 | 4,858,779 |
Land [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment | 4,012 | 3,744 |
Gathering Systems and Processing Complexes [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment | $ 6,462,053 | 6,061,004 |
Gathering Systems and Processing Complexes [Member] | Minimum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful life | 3 years | |
Gathering Systems and Processing Complexes [Member] | Maximum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful life | 47 years | |
Pipelines and Equipment [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment | $ 139,646 | 136,290 |
Pipelines and Equipment [Member] | Minimum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful life | 15 years | |
Pipelines and Equipment [Member] | Maximum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful life | 45 years | |
Assets Under Construction [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment | $ 226,626 | 329,887 |
Other [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment | $ 29,605 | $ 25,853 |
Other [Member] | Minimum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful life | 3 years | |
Other [Member] | Maximum [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful life | 40 years |
Property, Plant and Equipment62
Property, Plant and Equipment - Additional Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Property, Plant and Equipment [Line Items] | |||
Impairments | $ 15,535 | $ 515,458 | $ 5,125 |
Newcastle System [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Impairments | 6,100 | ||
Newcastle System [Member] | Fair Value Measurements Nonrecurring [Member] | Level 3 Inputs [Member] | Income Approach Valuation Technique [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Estimated fair value | 3,100 | ||
Equipment [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Impairments | $ 9,400 | 14,400 | |
Equipment [Member] | Fair Value Measurements Nonrecurring [Member] | Level 3 Inputs [Member] | Income Approach Valuation Technique [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Estimated salvage value | $ 2,400 | ||
Red Desert Complex [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Impairments | 280,200 | ||
Red Desert Complex [Member] | Fair Value Measurements Nonrecurring [Member] | Level 3 Inputs [Member] | Income Approach Valuation Technique [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Estimated salvage value | 6,300 | ||
Hilight System [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Impairments | 220,900 | ||
Hilight System [Member] | Fair Value Measurements Nonrecurring [Member] | Level 3 Inputs [Member] | Income Approach Valuation Technique [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Estimated fair value | $ 28,800 |
Goodwill and Intangibles - Othe
Goodwill and Intangibles - Other Intangible Assets Table (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Goodwill and Intangible Assets Disclosure [Abstract] | ||
Gross carrying amount | $ 868,035 | $ 868,035 |
Accumulated amortization | (64,337) | (35,908) |
Other intangible assets | $ 803,698 | $ 832,127 |
Goodwill and Intangibles - Addi
Goodwill and Intangibles - Additional Information (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Finite-Lived Intangible Assets [Line Items] | |||
Goodwill impairment | $ 0 | ||
Amortization expense for intangible assets | 28,400,000 | $ 28,200,000 | $ 4,300,000 |
Estimated amortization expense for intangible assets in 2017 | 28,400,000 | ||
Estimated amortization expense for intangible assets in 2018 | 28,400,000 | ||
Estimated amortization expense for intangible assets in 2019 | 28,400,000 | ||
Estimated amortization expense for intangible assets in 2020 | 28,400,000 | ||
Estimated amortization expense for intangible assets in 2021 | $ 28,400,000 | ||
Platte Valley [Member] | |||
Finite-Lived Intangible Assets [Line Items] | |||
Straight-line basis of amortization | 50 years | ||
Chipeta Processing LLC [Member] | |||
Finite-Lived Intangible Assets [Line Items] | |||
Straight-line basis of amortization | 10 years | ||
Delaware Basin Midstream LLC [Member] | |||
Finite-Lived Intangible Assets [Line Items] | |||
Straight-line basis of amortization | 30 years |
Equity Investments - Equity Inv
Equity Investments - Equity Investments Table (Details) - USD ($) $ in Thousands | 12 Months Ended | |||||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||||
Schedule of Equity Method Investments [Line Items] | ||||||
Balance | $ 618,887 | $ 634,492 | ||||
Investment earnings (loss), net of amortization | [1] | 78,717 | 71,251 | $ 57,836 | ||
Contributions | 27 | 11,442 | 64,278 | |||
Distributions | (82,185) | (82,054) | (62,967) | |||
Distributions in excess of cumulative earnings | (21,238) | [2] | (16,244) | [2] | (18,055) | |
Balance | 594,208 | 618,887 | 634,492 | |||
Fort Union [Member] | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Balance | [3] | 17,122 | 25,933 | |||
Investment earnings (loss), net of amortization | [3] | 608 | (3,200) | |||
Contributions | [3] | 0 | 0 | |||
Distributions | [3] | (1,543) | (5,611) | |||
Distributions in excess of cumulative earnings | [2],[3] | (3,354) | 0 | |||
Balance | [3] | $ 12,833 | 17,122 | 25,933 | ||
Equity investment ownership | 14.81% | |||||
Approval percentage | 65.00% | |||||
White Cliffs [Member] | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Balance | [4] | $ 50,439 | 44,315 | |||
Investment earnings (loss), net of amortization | [4] | 13,858 | 14,770 | |||
Contributions | [4] | 441 | 8,512 | |||
Distributions | [4] | (13,277) | (14,188) | |||
Distributions in excess of cumulative earnings | [2],[4] | (4,142) | (2,970) | |||
Balance | [4] | $ 47,319 | 50,439 | 44,315 | ||
Equity investment ownership | 10.00% | |||||
Approval percentage | 75.00% | |||||
Rendezvous [Member] | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Balance | [5] | $ 50,913 | 56,336 | |||
Investment earnings (loss), net of amortization | [5] | 1,931 | 2,292 | |||
Contributions | [5] | 0 | 0 | |||
Distributions | [5] | (3,873) | (4,233) | |||
Distributions in excess of cumulative earnings | [2],[5] | (2,232) | (3,482) | |||
Balance | [5] | $ 46,739 | 50,913 | 56,336 | ||
Equity investment ownership | 22.00% | |||||
Approval percentage | 100.00% | |||||
Mont Belvieu JV [Member] | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Balance | [6] | $ 117,089 | 121,337 | |||
Investment earnings (loss), net of amortization | [6] | 26,204 | 23,570 | |||
Contributions | [6] | 0 | (432) | |||
Distributions | [6] | (26,243) | (24,248) | |||
Distributions in excess of cumulative earnings | [2],[6] | (4,245) | (3,138) | |||
Balance | [6] | $ 112,805 | 117,089 | 121,337 | ||
Equity investment ownership | 25.00% | |||||
Approval percentage | 50.00% | |||||
Mont Belvieu JV [Member] | Fractionation Train [Member] | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Assets, number of units | 2 | |||||
Texas Express Gathering LLC [Member] | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Balance | [7] | $ 16,283 | 16,790 | |||
Investment earnings (loss), net of amortization | [7] | 708 | 586 | |||
Contributions | [7] | 166 | 0 | |||
Distributions | [7] | (730) | (803) | |||
Distributions in excess of cumulative earnings | [2],[7] | (581) | (290) | |||
Balance | [7] | $ 15,846 | 16,283 | 16,790 | ||
Equity investment ownership | 20.00% | |||||
Approval percentage | 50.00% | |||||
Texas Express Gathering LLC [Member] | Natural Gas Liquids Gathering System [Member] | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Assets, number of units | 2 | |||||
Texas Express Pipeline LLC [Member] | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Balance | [8] | $ 194,803 | 198,793 | |||
Investment earnings (loss), net of amortization | [8] | 16,683 | 16,088 | |||
Contributions | [8] | (580) | 1,880 | |||
Distributions | [8] | (16,934) | (16,340) | |||
Distributions in excess of cumulative earnings | [2],[8] | (4,778) | (5,618) | |||
Balance | [8] | $ 189,194 | 194,803 | 198,793 | ||
Equity investment ownership | 20.00% | |||||
Approval percentage | 50.00% | |||||
Front Range Pipeline LLC [Member] | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Balance | [9] | $ 172,238 | 170,988 | |||
Investment earnings (loss), net of amortization | [9] | 18,725 | 17,145 | |||
Contributions | [9] | 0 | 1,482 | |||
Distributions | [9] | (19,585) | (16,631) | |||
Distributions in excess of cumulative earnings | [2],[9] | (1,906) | (746) | |||
Balance | [9] | $ 169,472 | $ 172,238 | $ 170,988 | ||
Equity investment ownership | 33.33% | |||||
Approval percentage | 50.00% | |||||
[1] | Represents amounts earned or incurred on and subsequent to the date of acquisition of the Partnership assets, as well as amounts earned or incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets, recognized under gathering, treating or processing agreements, and purchase and sale agreements. | |||||
[2] | Distributions in excess of cumulative earnings, classified as investing cash flows in the consolidated statements of cash flows, is calculated on an individual investment basis. | |||||
[3] | The Partnership has a 14.81% interest in Fort Union, a joint venture that owns a gathering pipeline and treating facilities in the Powder River Basin. Anadarko is the construction manager and physical operator of the Fort Union facilities. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the owners’ firm gathering agreements, require 65% or unanimous approval of the owners. | |||||
[4] | The Partnership has a 10% interest in White Cliffs, a limited liability company that owns a crude oil pipeline that originates in Platteville, Colorado and terminates in Cushing, Oklahoma. The third-party majority owner is the manager of the White Cliffs operations. Certain business decisions, including, but not limited to, approval of annual budgets and decisions with respect to significant expenditures, contractual commitments, acquisitions, material financings, dispositions of assets or admitting new members, require more than 75% approval of the members. | |||||
[5] | The Partnership has a 22% interest in Rendezvous, a limited liability company that operates gas gathering facilities in Southwestern Wyoming. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the members’ gas servicing agreements, require unanimous approval of the members. | |||||
[6] | The Partnership has a 25% interest in the Mont Belvieu JV, an entity formed to design, construct, and own two fractionation trains located in Mont Belvieu, Texas. A third party is the operator of the Mont Belvieu JV fractionation trains. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require 50% or unanimous approval of the owners. | |||||
[7] | The Partnership has a 20% interest in TEG, an entity that consists of two NGL gathering systems that link natural gas processing plants to TEP. Enbridge Midcoast Energy, LP (“Enbridge”) is the operator of the two gathering systems. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the delegation, creation, appointment, or removal of officer positions require more than 50% approval of the members. | |||||
[8] | The Partnership has a 20% interest in TEP, which consists of an NGL pipeline that originates in Skellytown, Texas and extends to Mont Belvieu, Texas. Enterprise Products Operating LLC (“Enterprise”) is the operator of TEP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than 50% approval of the members. | |||||
[9] | The Partnership has a 33.33% interest in the FRP, an NGL pipeline that extends from Weld County, Colorado to Skellytown, Texas. Enterprise is the operator of FRP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than 50% approval of the members. |
Equity Investments - Summarized
Equity Investments - Summarized Combined Financial Data For Equity Investments - Income Statement Table (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Equity Method Investments and Joint Ventures [Abstract] | |||
Revenues | $ 687,554 | $ 667,554 | $ 548,629 |
Operating income | 428,454 | 359,899 | 336,188 |
Net income | $ 427,511 | $ 359,443 | $ 333,705 |
Equity Investments - Summariz67
Equity Investments - Summarized Combined Financial Data For Equity Investments - Balance Sheet Table (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Equity Method Investments and Joint Ventures [Abstract] | ||
Current assets | $ 118,472 | $ 154,937 |
Property, plant and equipment, net | 2,626,466 | 2,716,078 |
Other assets | 39,802 | 43,713 |
Total assets | 2,784,740 | 2,914,728 |
Current liabilities | 63,468 | 78,116 |
Non-current liabilities | 6,662 | 9,072 |
Equity | 2,714,610 | 2,827,540 |
Total liabilities and equity | $ 2,784,740 | $ 2,914,728 |
Equity Investments - Additional
Equity Investments - Additional Information (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2016 | |
Rendezvous [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity investment difference between carrying and underlying value | $ 38.2 | |
Equity investment ownership | 22.00% | |
White Cliffs [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity investment difference between carrying and underlying value | $ (7.5) | |
Equity investment ownership | 10.00% | |
White Cliffs [Member] | Affiliates [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity investment ownership | 0.40% | |
Fort Union [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity investment ownership | 14.81% | |
Equity investment impairment loss | $ 9.5 |
Components of Working Capital -
Components of Working Capital - Accounts Receivable, Net Table (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | |
Receivables [Abstract] | |||
Trade receivables, net | $ 192,808 | $ 143,557 | |
Other receivables, net | 30,415 | 49,772 | |
Total accounts receivable, net | [1] | $ 223,223 | $ 193,329 |
[1] | Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $76.6 million and $42.7 million as of December 31, 2016 and 2015, respectively. Accounts receivable, net as of December 31, 2016 and 2015, also includes an insurance claim receivable related to an incident at the DBM complex. See Note 1. |
Components of Working Capital70
Components of Working Capital - Other Current Assets Table (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Other Current Assets [Line Items] | ||
Natural gas liquids inventory | $ 7,126 | $ 2,403 |
Imbalance receivables | 3,483 | 2,122 |
Prepaid insurance | 2,257 | 2,296 |
Other | 0 | 1,034 |
Total other current assets | $ 12,866 | $ 7,855 |
Components of Working Capital71
Components of Working Capital - Accrued Liabilities Table (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Accrued Liabilities [Line Items] | ||
Accrued interest expense | $ 39,826 | $ 26,194 |
Short-term asset retirement obligations | 3,114 | 3,677 |
Short-term remediation and reclamation obligations | 630 | 1,136 |
Income taxes payable | 1,006 | 770 |
Total accrued liabilities | 168,899 | 119,019 |
Accrued Capital Expenditures [Member] | ||
Accrued Liabilities [Line Items] | ||
Other accrued liabilities | 79,253 | 61,454 |
Accrued Plant Purchases [Member] | ||
Accrued Liabilities [Line Items] | ||
Other accrued liabilities | 44,538 | 16,425 |
Other Accrued Liabilities [Member] | ||
Accrued Liabilities [Line Items] | ||
Other accrued liabilities | $ 532 | $ 9,363 |
Asset Retirement Obligations -
Asset Retirement Obligations - Asset Retirement Obligations Table (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Carrying amount of asset retirement obligations at beginning of year | $ 130,631 | $ 119,855 |
Liabilities incurred | 5,515 | 9,490 |
Liabilities settled | (10,650) | (7,905) |
Accretion expense | 6,794 | 6,381 |
Revisions in estimated liabilities | 10,117 | 2,810 |
Carrying amount of asset retirement obligations at end of year | $ 142,407 | $ 130,631 |
Debt and Interest Expense - Deb
Debt and Interest Expense - Debt Outstanding Table (Details) - USD ($) | Dec. 31, 2016 | Oct. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Debt Instrument [Line Items] | |||||
Total long-term debt principal | $ 3,120,000,000 | $ 2,720,000,000 | |||
Carrying value | 3,091,461,000 | 2,690,651,000 | $ 2,408,785,000 | ||
Market Approach Valuation Technique [Member] | Level 2 Inputs [Member] | |||||
Debt Instrument [Line Items] | |||||
Fair value | [1] | 3,196,199,000 | 2,492,466,000 | ||
Revolving Credit Facility [Member] | |||||
Debt Instrument [Line Items] | |||||
Principal | 0 | 300,000,000 | |||
Carrying value | 0 | 300,000,000 | |||
Revolving Credit Facility [Member] | Market Approach Valuation Technique [Member] | Level 2 Inputs [Member] | |||||
Debt Instrument [Line Items] | |||||
Fair value | [1] | 0 | 300,000,000 | ||
Senior Notes [Member] | 5.375% Senior Notes due 2021 [Member] | |||||
Debt Instrument [Line Items] | |||||
Principal | 500,000,000 | 500,000,000 | |||
Carrying value | 494,734,000 | 493,711,000 | |||
Senior Notes [Member] | 5.375% Senior Notes due 2021 [Member] | Market Approach Valuation Technique [Member] | Level 2 Inputs [Member] | |||||
Debt Instrument [Line Items] | |||||
Fair value | [1] | 536,252,000 | 513,645,000 | ||
Senior Notes [Member] | 4.000% Senior Notes due 2022 [Member] | |||||
Debt Instrument [Line Items] | |||||
Principal | 670,000,000 | 670,000,000 | |||
Carrying value | 668,634,000 | 668,432,000 | |||
Senior Notes [Member] | 4.000% Senior Notes due 2022 [Member] | Market Approach Valuation Technique [Member] | Level 2 Inputs [Member] | |||||
Debt Instrument [Line Items] | |||||
Fair value | [1] | 681,723,000 | 595,744,000 | ||
Senior Notes [Member] | 2.600% Senior Notes due 2018 [Member] | |||||
Debt Instrument [Line Items] | |||||
Principal | 350,000,000 | 350,000,000 | |||
Carrying value | 349,188,000 | 348,706,000 | |||
Senior Notes [Member] | 2.600% Senior Notes due 2018 [Member] | Market Approach Valuation Technique [Member] | Level 2 Inputs [Member] | |||||
Debt Instrument [Line Items] | |||||
Fair value | [1] | 351,531,000 | 339,293,000 | ||
Senior Notes [Member] | 5.450% Senior Notes due 2044 [Member] | |||||
Debt Instrument [Line Items] | |||||
Principal | 600,000,000 | $ 200,000,000 | 400,000,000 | ||
Carrying value | 593,132,000 | 389,707,000 | |||
Senior Notes [Member] | 5.450% Senior Notes due 2044 [Member] | Market Approach Valuation Technique [Member] | Level 2 Inputs [Member] | |||||
Debt Instrument [Line Items] | |||||
Fair value | [1] | 615,753,000 | 321,499,000 | ||
Senior Notes [Member] | 3.950% Senior Notes due 2025 [Member] | |||||
Debt Instrument [Line Items] | |||||
Principal | 500,000,000 | 500,000,000 | |||
Carrying value | 490,971,000 | 490,095,000 | |||
Senior Notes [Member] | 3.950% Senior Notes due 2025 [Member] | Market Approach Valuation Technique [Member] | Level 2 Inputs [Member] | |||||
Debt Instrument [Line Items] | |||||
Fair value | [1] | 492,499,000 | 422,285,000 | ||
Senior Notes [Member] | 4.650% Senior Notes due 2026 [Member] | |||||
Debt Instrument [Line Items] | |||||
Principal | 500,000,000 | 0 | |||
Carrying value | 494,802,000 | 0 | |||
Senior Notes [Member] | 4.650% Senior Notes due 2026 [Member] | Market Approach Valuation Technique [Member] | Level 2 Inputs [Member] | |||||
Debt Instrument [Line Items] | |||||
Fair value | [1] | $ 518,441,000 | $ 0 | ||
[1] | Fair value is measured using the market approach and Level 2 inputs. |
Debt and Interest Expense - D74
Debt and Interest Expense - Debt Activity Table (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Debt Instrument [Line Items] | ||
Beginning balance | $ 2,690,651 | $ 2,408,785 |
Other | 810 | (8,134) |
Ending balance | 3,091,461 | 2,690,651 |
Senior Notes [Member] | 3.950% Senior Notes due 2025 [Member] | ||
Debt Instrument [Line Items] | ||
Beginning balance | 490,095 | |
Issuance of Senior Notes | 500,000 | |
Ending balance | 490,971 | 490,095 |
Senior Notes [Member] | 4.650% Senior Notes due 2026 [Member] | ||
Debt Instrument [Line Items] | ||
Beginning balance | 0 | |
Issuance of Senior Notes | 500,000 | |
Ending balance | 494,802 | 0 |
Senior Notes [Member] | 5.450% Senior Notes due 2044 [Member] | ||
Debt Instrument [Line Items] | ||
Beginning balance | 389,707 | |
Issuance of Senior Notes | 200,000 | |
Ending balance | 593,132 | 389,707 |
Revolving Credit Facility [Member] | ||
Debt Instrument [Line Items] | ||
Beginning balance | 300,000 | |
RCF borrowings | 600,000 | 400,000 |
Repayments of RCF borrowings | (900,000) | (610,000) |
Ending balance | $ 0 | $ 300,000 |
Debt and Interest Expense - Int
Debt and Interest Expense - Interest Expense Table (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Debt Instrument [Line Items] | ||||
Interest expense | [1] | $ 114,921 | $ 113,872 | $ 76,766 |
Third Parties [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term debt | 121,832 | 102,058 | 81,495 | |
Amortization of debt issuance costs and commitment fees | 6,398 | 5,734 | 5,103 | |
Capitalized interest | (5,562) | (8,318) | (9,832) | |
Interest expense | 122,668 | 99,474 | 76,766 | |
Affiliates [Member] | ||||
Debt Instrument [Line Items] | ||||
Interest expense | [2] | (7,747) | 14,398 | 0 |
Affiliates [Member] | Deferred Purchase Price Obligation - Anadarko [Member] | ||||
Debt Instrument [Line Items] | ||||
Deferred purchase price obligation - Anadarko | [3] | $ (7,747) | $ 14,398 | $ 0 |
[1] | Includes affiliate (as defined in Note 1) amounts of $7.7 million, $(14.4) million and zero for the years ended December 31, 2016, 2015 and 2014, respectively. See Note 2 and Note 12. | |||
[2] | For the years ended December 31, 2016 and 2015, includes amounts related to the Deferred purchase price obligation - Anadarko (see Note 2 and Note 12). | |||
[3] | See Note 2 for a discussion of the Deferred purchase price obligation - Anadarko. |
Debt and Interest Expense - Add
Debt and Interest Expense - Additional Information (Details) - USD ($) | Oct. 31, 2016 | Jul. 31, 2016 | Jun. 30, 2015 | Dec. 31, 2016 | Dec. 31, 2015 |
Treasury Lock [Member] | |||||
Debt Instrument [Line Items] | |||||
Realized loss on terminated U.S. Treasury rate lock agreement | $ 200,000 | ||||
Revolving Credit Facility [Member] | |||||
Debt Instrument [Line Items] | |||||
Principal | 0 | $ 300,000,000 | |||
Facility, maximum borrowing capacity | 1,200,000,000 | ||||
Facility, expandable maximum borrowing capacity | $ 1,500,000,000 | ||||
Facility, interest rate at period end | 0.00% | 1.73% | |||
Facility, fee rate | 0.20% | 0.20% | |||
Facility, outstanding borrowings | $ 0 | ||||
Outstanding letters of credit | 4,900,000 | ||||
Facility, available borrowing capacity | $ 1,195,000,000 | ||||
Facility, expiration date | Feb. 26, 2020 | ||||
Minimum [Member] | Revolving Credit Facility [Member] | |||||
Debt Instrument [Line Items] | |||||
Facility, fee rate | 0.15% | ||||
Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member] | Revolving Credit Facility [Member] | |||||
Debt Instrument [Line Items] | |||||
Applicable margin added | 0.975% | ||||
Minimum [Member] | Base Rate [Member] | Revolving Credit Facility [Member] | |||||
Debt Instrument [Line Items] | |||||
Applicable margin added | 0.00% | ||||
Maximum [Member] | Revolving Credit Facility [Member] | |||||
Debt Instrument [Line Items] | |||||
Facility, fee rate | 0.30% | ||||
Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member] | Revolving Credit Facility [Member] | |||||
Debt Instrument [Line Items] | |||||
Applicable margin added | 1.45% | ||||
Maximum [Member] | Base Rate [Member] | Revolving Credit Facility [Member] | |||||
Debt Instrument [Line Items] | |||||
Applicable margin added | 0.45% | ||||
Alternate Base Rate [Member] | London Interbank Offered Rate (LIBOR) [Member] | Revolving Credit Facility [Member] | |||||
Debt Instrument [Line Items] | |||||
Applicable margin added | 1.00% | ||||
Alternate Base Rate [Member] | Percentage Above Federal Funds Effective Rate [Member] | Revolving Credit Facility [Member] | |||||
Debt Instrument [Line Items] | |||||
Applicable margin added | 0.50% | ||||
Senior Notes [Member] | 5.375% Senior Notes due 2021 [Member] | |||||
Debt Instrument [Line Items] | |||||
Fixed interest rate | 5.375% | ||||
Principal | $ 500,000,000 | $ 500,000,000 | |||
Debt instrument, maturity date | Jun. 1, 2021 | ||||
Senior Notes [Member] | 4.000% Senior Notes due 2022 [Member] | |||||
Debt Instrument [Line Items] | |||||
Fixed interest rate | 4.00% | ||||
Principal | $ 670,000,000 | 670,000,000 | |||
Debt instrument, maturity date | Jul. 1, 2022 | ||||
Senior Notes [Member] | 2.600% Senior Notes due 2018 [Member] | |||||
Debt Instrument [Line Items] | |||||
Fixed interest rate | 2.60% | ||||
Principal | $ 350,000,000 | 350,000,000 | |||
Debt instrument, maturity date | Aug. 15, 2018 | ||||
Senior Notes [Member] | 5.450% Senior Notes due 2044 [Member] | |||||
Debt Instrument [Line Items] | |||||
Fixed interest rate | 5.45% | ||||
Principal | $ 200,000,000 | $ 600,000,000 | 400,000,000 | ||
Debt instrument, maturity date | Apr. 1, 2044 | ||||
Offering percent | 102.776% | ||||
Effective interest rate | 5.53% | ||||
Underwriting discount | $ 1,800,000 | ||||
Senior Notes [Member] | 3.950% Senior Notes due 2025 [Member] | |||||
Debt Instrument [Line Items] | |||||
Fixed interest rate | 3.95% | ||||
Principal | $ 500,000,000 | 500,000,000 | |||
Debt instrument, maturity date | Jun. 1, 2025 | ||||
Offering percent | 98.789% | ||||
Effective interest rate | 4.205% | ||||
Underwriting discount | $ 3,300,000 | ||||
Senior Notes [Member] | 4.650% Senior Notes due 2026 [Member] | |||||
Debt Instrument [Line Items] | |||||
Fixed interest rate | 4.65% | ||||
Principal | $ 500,000,000 | $ 0 | |||
Debt instrument, maturity date | Jul. 1, 2026 | ||||
Offering percent | 99.796% | ||||
Effective interest rate | 4.787% | ||||
Underwriting discount | $ 3,100,000 |
Commitments and Contingencies -
Commitments and Contingencies - Operating Lease Obligations Table (Details) $ in Thousands | Dec. 31, 2016USD ($) |
Commitments and Contingencies Disclosure [Abstract] | |
2,017 | $ 7,322 |
2,018 | 898 |
2,019 | 764 |
2,020 | 122 |
2,021 | 0 |
Thereafter | 0 |
Total | $ 9,106 |
Commitments and Contingencies78
Commitments and Contingencies - Additional Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Commitments and Contingencies Disclosure [Abstract] | |||
Liability for remediation and reclamation obligations | $ 2.2 | $ 2.6 | |
Committed capital | 50.9 | ||
Rent expense associated with office, warehouse and equipment leases | $ 35.9 | $ 34.1 | $ 25.9 |
Subsequent Events - Additional
Subsequent Events - Additional Information (Details) - Subsequent Event [Member] - USD ($) $ in Millions | Feb. 22, 2017 | Feb. 09, 2017 | |
Subsequent Event [Line Items] | |||
Cash payment | $ 155 | ||
Series A Preferred Units [Member] | Series A Preferred Units February 2017 Conversion [Member] | |||
Subsequent Event [Line Items] | |||
Series A Preferred units, percentage converted | 50.00% | ||
Series A Preferred Units [Member] | Series A Preferred Units May 2017 Conversion [Member] | |||
Subsequent Event [Line Items] | |||
Series A Preferred units, percentage converted | 50.00% | ||
Delaware Basin JV Gathering LLC [Member] | |||
Subsequent Event [Line Items] | |||
Percentage ownership interest acquired from a third party | 50.00% | ||
Percentage ownership interest | 50.00% | ||
Non-Operated Marcellus Interest [Member] | |||
Subsequent Event [Line Items] | |||
Percentage ownership interest | [1] | 33.75% | |
[1] | The Partnership proportionately consolidates its associated share of the assets, liabilities, revenues and expenses attributable to these assets. |