UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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þ☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 20172023
Or
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¨☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number: 001-34046
WESTERN GAS PARTNERS, LP
(Exact name of registrant as specified in its charter)
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Delaware | | 26-1075808WESTERN MIDSTREAM PARTNERS, LP |
| WESTERN MIDSTREAM OPERATING, LP |
| (Exact name of registrant as specified in its charter) |
( | | | | | | | | | | | |
| Commission file number: | State or other jurisdiction of incorporation or organization) organization: | | (I.R.S. Employer
Identification No.) : |
| Western Midstream Partners, LP | 001-35753 | Delaware | 46-0967367 |
1201 Lake Robbins Drive
The Woodlands, Texas
Western Midstream Operating, LP | 001-34046 | 77380 |
(Address of principal executive offices)Delaware | | (Zip Code)26-1075808 |
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| Address of principal executive offices: | Zip Code: | Registrant’s telephone number, including area code: |
| Western Midstream Partners, LP | 9950 Woodloch Forest Drive, Suite 2800 | The Woodlands, | Texas | 77380 | (346) | 786-5000 |
| Western Midstream Operating, LP | 9950 Woodloch Forest Drive, Suite 2800 | The Woodlands, | Texas | 77380 | (346) | 786-5000 |
(832) 636-6000
(Registrant’s telephone number, including area code)Securities registered pursuant to Section 12(b) of the Act:
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| Title of each class | Trading symbol | Name of exchange
on which registered | Common units outstanding as of October 26, 2023: |
| Western Midstream Partners, LP | Common units | WES | New York Stock Exchange | 379,516,369 |
| Western Midstream Operating, LP | None | None | None | None |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨
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| Western Midstream Partners, LP | Yes | þ | No | ¨ | |
| Western Midstream Operating, LP | Yes | þ | No | ¨ | |
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-TS-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨
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| Western Midstream Partners, LP | Yes | þ | No | ¨ | |
| Western Midstream Operating, LP | Yes | þ | No | ¨ | |
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-acceleratednon-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-212b-2 of the Exchange Act.
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Western Midstream Partners, LP | Large accelerated filer þAccelerated Filer | Accelerated Filer | Accelerated filer ¨
Non-accelerated Filer | Smaller Reporting Company | Non-accelerated filer ¨
| | Smaller reporting company ¨
| | Emerging growth company ¨ Growth Company |
| þ | ☐ | ☐ | ☐ | (Do not check if a smaller reporting company)☐ |
| Western Midstream Operating, LP | Large Accelerated Filer | Accelerated Filer | Non-accelerated Filer | Smaller Reporting Company | Emerging Growth Company |
| ☐ | ☐ | þ | ☐ | ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.¨
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| Western Midstream Partners, LP | ¨ |
| Western Midstream Operating, LP | ¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-212b-2 of the Exchange Act). Yes ¨ No þ
There were 152,602,105 common units outstanding as of October 30, 2017.
TABLE OF CONTENTS
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| Western Midstream Partners, LP | Yes | ☐ | PAGENo | þ | |
| Western Midstream Operating, LP | Yes | ☐ | No | þ | |
FILING FORMAT
This quarterly report on Form 10-Q is a combined report being filed by two separate registrants: Western Midstream Partners, LP and Western Midstream Operating, LP. Western Midstream Operating, LP is a consolidated subsidiary of Western Midstream Partners, LP that has publicly traded debt, but does not have any publicly traded equity securities. Information contained herein related to any individual registrant is filed by such registrant solely on its own behalf. Each registrant makes no representation as to information relating exclusively to the other registrant.
Part I, Item 1 of this quarterly report includes separate financial statements (i.e., consolidated statements of operations, consolidated balance sheets, consolidated statements of equity and partners’ capital, and consolidated statements of cash flows) for Western Midstream Partners, LP and Western Midstream Operating, LP. The accompanying Notes to Consolidated Financial Statements, which are included under Part I, Item 1 of this quarterly report, and Management’s Discussion and Analysis of Financial Condition and Results of Operations, which is included under Part I, Item 2 of this quarterly report, are presented on a combined basis for each registrant, with any material differences between the registrants disclosed separately.
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| TABLE OF CONTENTS |
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| PART I | | | |
| Item 1. | | |
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| Item 2. | | |
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| Item 3. | | |
| Item 4. | | |
| Item 5. | | |
| PART II | | | |
| Item 1. | | |
| Item 1A. | | |
| Item 2. | | |
| Item 6. | | |
COMMONLY USED TERMSABBREVIATIONS AND DEFINITIONSTERMS
Unless the context otherwise requires, referencesReferences to “we,” “us,” “our,” the “Partnership”“WES,” “the Partnership,” or “Western GasMidstream Partners, LP” refer to Western GasMidstream Partners, LP and its subsidiaries. As used in this Form 10-Q, the terms and definitions below have the following meanings:
Additional DBJV System Interest: The Partnership’s additional 50% interest in the DBJV system acquired from a third party in March 2017.
Affiliates: Subsidiaries of Anadarko, excluding us, but including equity interests in Fort Union, White Cliffs, Rendezvous, the Mont Belvieu JV, TEP, TEG, and FRP.
Anadarko: Anadarko Petroleum Corporation and its subsidiaries, excluding us and our general partner.
Barrel or Bbl: 42 U.S. gallons measured at 60 degrees Fahrenheit.
Bbls/d: Barrels per day.
Board of Directors or Board: The board of directors of our general partner.
Btu: British thermal unit; the approximate amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Chipeta: Chipeta Processing, LLC.
Condensate: A natural gas liquid with a low vapor pressure mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.
COP: Continuous offering programs.
Cryogenic: The process in which liquefied gases are used to bring natural gas volumes to very low temperatures (below approximately -238 degrees Fahrenheit) to separate natural gas liquids from natural gas. Through cryogenic processing, more natural gas liquids are extracted than when traditional refrigeration methods are used.
DBJV: Delaware Basin JV Gathering LLC.
DBJV system: A gathering system and related facilities located in the Delaware Basin in Loving, Ward, Winkler and Reeves Counties in West Texas.
DBM: Delaware Basin Midstream, LLC.
DBM complex: The cryogenic processing plants, gas gathering system, and related facilities and equipment in West Texas that serve production from Reeves, Loving and Culberson Counties, Texas and Eddy and Lea Counties, New Mexico.
DBM water systems: Two produced-water disposal systems in West Texas.
DJ Basin complex: The Platte Valley system, Wattenberg system and Lancaster plant, all of which were combined into a single complex in the first quarter of 2014.
EBITDA: Earnings before interest, taxes, depreciation, and amortization. For a definition of “Adjusted EBITDA,” see the caption Key Performance Metrics under Part I, Item 2 of this Form 10-Q.
Equity investment throughput: Our 14.81% share of average Fort Union throughput, 22% share of average Rendezvous throughput, 10% share of average White Cliffs throughput, 25% share of average Mont Belvieu JV throughput, 20% share of average TEP and TEG throughput and 33.33% share of average FRP throughput.
Exchange Act: The Securities Exchange Act of 1934, as amended.
Fort Union: Fort Union Gas Gathering, LLC.
Fractionation: The process of applying various levels of higher pressure and lower temperature to separate a stream of natural gas liquids into ethane, propane, normal butane, isobutane and natural gasoline for end-use sale.
FRP: Front Range Pipeline LLC.
GAAP: Generally accepted accounting principles in the United States.
General partner: Western Gas Holdings, LLC.
Hydraulic fracturing: The injection of fluids into the wellbore to create fractures in rock formations, stimulating the production of oil or gas.
Imbalance: Imbalances result from (i) differences between gas and NGL volumes nominated by customers and gas and NGL volumes received from those customers and (ii) differences between gas and NGL volumes received from customers and gas and NGL volumes delivered to those customers.
IPO: Initial public offering.
LIBOR: London Interbank Offered Rate.
Marcellus Interest: Our 33.75% interest in the Larry’s Creek, Seely and Warrensville gas gathering systems and related facilities located in northern Pennsylvania. Formerly defined as the “Anadarko-Operated Marcellus Interest”.
MBbls/d: One thousand barrels per day.
MGR: Mountain Gas Resources, LLC.
MGR assets: The Red Desert complex and the Granger straddle plant.
MLP: Master limited partnership.
MMBtu: One million British thermal units.
MMcf: One million cubic feet.
MMcf/d: One million cubic feet per day.
Mont Belvieu JV: Enterprise EF78 LLC.
Natural gas liquid(s) or NGL(s): The combination of ethane, propane, normal butane, isobutane and natural gasolines that, when removed from natural gas, become liquid under various levels of higher pressure and lower temperature.
Non-Operated Marcellus Interest: The 33.75% interest in the Liberty and Rome gas gathering systems and related facilities located in northern Pennsylvania that was transferred to a third party in March 2017 pursuant to the Property Exchange.
Produced water: Byproduct associated with the production of crude oil and natural gas that often contains a number of dissolved solids and other materials found in oil and gas reservoirs.
Property Exchange: The Partnership’s acquisition of the Additional DBJV System Interest from a third party in exchange for the Non-Operated Marcellus Interest and $155.0 million of cash consideration, as further described in our Forms 8-K filed with the SEC on February 9, 2017, and March 23, 2017.
RCF: Our senior unsecured revolving credit facility.
Red Desert complex: The Patrick Draw processing plant, the Red Desert processing plant, associated gathering lines, and related facilities.
Rendezvous: Rendezvous Gas Services, LLC.
Residue: The natural gas remaining after the unprocessed natural gas stream has been processed or treated.
SEC: U.S. Securities and Exchange Commission.
Springfield: Springfield Pipeline LLC.
Springfield interest: Springfield’s 50.1% interest in the Springfield system.
Springfield gas gathering system: A gas gathering system and related facilities located in Dimmit, La Salle, Maverick and Webb Counties in South Texas.
Springfield oil gathering system: An oil gathering system and related facilities located in Dimmit, La Salle, Maverick and Webb Counties in South Texas.
Springfield system: The Springfield gas gathering system and Springfield oil gathering system.
TEFR Interests: The interests in TEP, TEG and FRP.
TEG: Texas Express Gathering LLC.
TEP: Texas Express Pipeline LLC.
WGP:(formerly Western Gas Equity Partners, LP.LP) and its subsidiaries. The following list of abbreviations and terms are used in this document:
White Cliffs: White Cliffs Pipeline, LLC.
2018 Notes: Our 2.600% Senior Notes due 2018. | | | | | | | | |
| Defined Term | | Definition |
| Anadarko | | Anadarko Petroleum Corporation and its subsidiaries, excluding our general partner, which became a wholly owned subsidiary of Occidental on August 8, 2019. |
| Barrel, Bbl, Bbls/d, MBbls/d | | 42 U.S. gallons measured at 60 degrees Fahrenheit, barrels per day, thousand barrels per day. |
| Board | | The board of directors of WES’s general partner. |
| Cactus II | | Cactus II Pipeline LLC, in which we held a 15% interest that we sold in November 2022. |
| Chipeta | | Chipeta Processing, LLC. |
| Condensate | | A natural-gas liquid with a low vapor pressure compared to drip condensate, mainly composed of propane, butane, pentane, and heavier hydrocarbon fractions. |
| DBM | | Delaware Basin Midstream, LLC. |
| DBM water systems | | DBM’s produced-water gathering and disposal systems in West Texas. |
| DJ Basin complex | | The Platte Valley system, Wattenberg system, Lancaster plant, Latham plant, and Wattenberg processing plant. |
| EBITDA | | Earnings before interest, taxes, depreciation, and amortization. For a definition of “Adjusted EBITDA,” see Reconciliation of Non-GAAP Financial Measures under Part I, Item 2 of this Form 10-Q. |
| Exchange Act | | The Securities Exchange Act of 1934, as amended. |
| FRP | | Front Range Pipeline LLC, in which we own a 33.33% interest. |
| GAAP | | Generally accepted accounting principles in the United States. |
| General partner | | Western Midstream Holdings, LLC, the general partner of the Partnership. |
| Imbalance | | Imbalances result from (i) differences between gas and NGLs volumes nominated by customers and gas and NGLs volumes received from those customers and (ii) differences between gas and NGLs volumes received from customers and gas and NGLs volumes delivered to those customers. |
| Marcellus Interest | | The 33.75% interest in the Larry’s Creek, Seely, and Warrensville gas-gathering systems and related facilities located in northern Pennsylvania. |
| Mcf, MMcf, MMcf/d | | Thousand cubic feet, million cubic feet, million cubic feet per day. |
| Meritage | | Meritage Midstream Services II, LLC, which was acquired by the Partnership on October 13, 2023. |
| MGR | | Mountain Gas Resources, LLC, includes the Red Desert complex and the Granger straddle plant. |
| Mi Vida | | Mi Vida JV LLC, in which we own a 50% interest. |
| MLP | | Master limited partnership. |
| Mont Belvieu JV | | Enterprise EF78 LLC, in which we own a 25% interest. |
| Natural-gas liquid(s) or NGL(s) | | The combination of ethane, propane, normal butane, isobutane, and natural gasolines that, when removed from natural gas, become liquid under various levels of pressure and temperature. |
| Occidental | | Occidental Petroleum Corporation and, as the context requires, its subsidiaries, excluding our general partner. |
| Panola | | Panola Pipeline Company, LLC, in which we own a 15% interest. |
| Produced water | | Byproduct associated with the production of crude oil and natural gas that often contains a number of dissolved solids and other materials found in oil and gas reservoirs. |
| Ranch Westex | | Ranch Westex JV LLC, in which we owned a 50% interest through August 2022, and a 100% interest thereafter. |
| RCF | | WES Operating’s $2.0 billion senior unsecured revolving credit facility. |
| Red Bluff Express | | Red Bluff Express Pipeline, LLC, in which we own a 30% interest. |
| Related parties | | Occidental, the Partnership’s equity interests (see Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q), and the Partnership and WES Operating for transactions that eliminate upon consolidation. |
| Rendezvous | | Rendezvous Gas Services, LLC, in which we own a 22% interest. |
| Residue | | The natural gas remaining after the unprocessed natural-gas stream has been processed or treated. |
2021 Notes: Our 5.375% Senior Notes due 2021.
2022 Notes: Our 4.000% Senior Notes due 2022. | | | | | | | | |
| Defined Term | | Definition |
| Saddlehorn | | Saddlehorn Pipeline Company, LLC, in which we own a 20% interest. |
| SEC | | U.S. Securities and Exchange Commission. |
| Services Agreement | | That certain amended and restated Services, Secondment, and Employee Transfer Agreement, dated as of December 31, 2019, by and among Occidental, Anadarko, and WES Operating GP. |
| Springfield system | | The Springfield gas-gathering system and Springfield oil-gathering system. |
| TEFR Interests | | The interests in TEP, TEG, and FRP. |
| TEG | | Texas Express Gathering LLC, in which we own a 20% interest. |
| TEP | | Texas Express Pipeline LLC, in which we own a 20% interest. |
| WES Operating | | Western Midstream Operating, LP, formerly known as Western Gas Partners, LP, and its subsidiaries. |
| WES Operating GP | | Western Midstream Operating GP, LLC, the general partner of WES Operating. |
| West Texas complex | | The DBM complex and DBJV and Haley systems. |
| WGRAH | | WGR Asset Holding Company LLC. |
| White Cliffs | | White Cliffs Pipeline, LLC, in which we own a 10% interest. |
| Whitethorn LLC | | Whitethorn Pipeline Company LLC, in which we own a 20% interest. |
| Whitethorn | | A crude-oil and condensate pipeline, and related storage facilities, owned by Whitethorn LLC. |
| $1.25 billion Purchase Program | | The $1.25 billion buyback program ending December 31, 2024. The common units may be purchased from time to time in the open market at prevailing market prices or in privately negotiated transactions. |
2025 Notes: Our 3.950% Senior Notes due 2025.
2026 Notes: Our 4.650% Senior Notes due 2026.2044 Notes: Our 5.450% Senior Notes due 2044.
$500.0 million COP: The COP contemplated by the registration statement filed with the SEC in July 2017 authorizing the issuance of up to an aggregate of $500.0 million of our common units.
PART I.FINANCIAL INFORMATION (UNAUDITED)
Item 1.Financial Statements
WESTERN GASMIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
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| | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | |
| thousands except per-unit amounts | | 2023 | | 2022 | | 2023 | | 2022 | | |
| Revenues and other | | | | | | | | | | |
| Service revenues – fee based | | $ | 695,547 | | | $ | 666,555 | | | $ | 2,004,920 | | | $ | 1,954,105 | | | |
| Service revenues – product based | | 48,446 | | | 91,356 | | | 142,212 | | | 202,721 | | | |
| Product sales | | 31,652 | | | 79,430 | | | 100,336 | | | 314,755 | | | |
| Other | | 368 | | | 227 | | | 800 | | | 703 | | | |
Total revenues and other (1) | | 776,013 | | | 837,568 | | | 2,248,268 | | | 2,472,284 | | | |
| Equity income, net – related parties | | 35,494 | | | 41,317 | | | 116,839 | | | 139,388 | | | |
| Operating expenses | | | | | | | | | | |
| Cost of product | | 27,590 | | | 106,833 | | | 123,795 | | | 328,237 | | | |
| Operation and maintenance | | 204,434 | | | 190,514 | | | 562,104 | | | 487,643 | | | |
| General and administrative | | 55,050 | | | 48,185 | | | 159,572 | | | 144,635 | | | |
| Property and other taxes | | 14,583 | | | 19,390 | | | 39,961 | | | 60,494 | | | |
| Depreciation and amortization | | 147,363 | | | 156,837 | | | 435,481 | | | 430,455 | | | |
Long-lived asset and other impairments (2) | | 245 | | | 4 | | | 52,880 | | | 94 | | | |
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Total operating expenses (3) | | 449,265 | | | 521,763 | | | 1,373,793 | | | 1,451,558 | | | |
| Gain (loss) on divestiture and other, net | | (1,480) | | | (104) | | | (3,668) | | | (884) | | | |
| Operating income (loss) | | 360,762 | | | 357,018 | | | 987,646 | | | 1,159,230 | | | |
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| Interest expense | | (82,754) | | | (83,106) | | | (250,606) | | | (249,333) | | | |
| Gain (loss) on early extinguishment of debt | | 8,565 | | | — | | | 15,378 | | | 91 | | | |
| Other income (expense), net | | (1,270) | | | 56 | | | 2,817 | | | 117 | | | |
| Income (loss) before income taxes | | 285,303 | | | 273,968 | | | 755,235 | | | 910,105 | | | |
| Income tax expense (benefit) | | 905 | | | 387 | | | 2,980 | | | 3,683 | | | |
| Net income (loss) | | 284,398 | | | 273,581 | | | 752,255 | | | 906,422 | | | |
| Net income (loss) attributable to noncontrolling interests | | 7,102 | | | 7,836 | | | 18,393 | | | 25,643 | | | |
| Net income (loss) attributable to Western Midstream Partners, LP | | $ | 277,296 | | | $ | 265,745 | | | $ | 733,862 | | | $ | 880,779 | | | |
| Limited partners’ interest in net income (loss): | | | | | | | | | | |
| Net income (loss) attributable to Western Midstream Partners, LP | | $ | 277,296 | | | $ | 265,745 | | | $ | 733,862 | | | $ | 880,779 | | | |
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| General partner interest in net (income) loss | | (6,453) | | | (6,244) | | | (16,960) | | | (19,794) | | | |
Limited partners’ interest in net income (loss) (4) | | 270,843 | | | 259,501 | | | 716,902 | | | 860,985 | | | |
Net income (loss) per common unit – basic (4) | | $ | 0.71 | | | $ | 0.67 | | | $ | 1.87 | | | $ | 2.16 | | | |
Net income (loss) per common unit – diluted (4) | | $ | 0.70 | | | $ | 0.66 | | | $ | 1.86 | | | $ | 2.15 | | | |
Weighted-average common units outstanding – basic (4) | | 383,561 | | | 388,906 | | | 384,211 | | | 398,343 | | | |
Weighted-average common units outstanding – diluted (4) | | 384,772 | | | 390,318 | | | 385,344 | | | 399,545 | | | |
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| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| thousands except per-unit amounts | | 2017 | | 2016 | | 2017 | | 2016 |
| Revenues and other – affiliates | | | | | | | | |
| Gathering, processing and transportation | | $ | 157,303 |
| | $ | 189,465 |
| | $ | 484,601 |
| | $ | 563,916 |
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| Natural gas and natural gas liquids sales | | 185,002 |
| | 135,847 |
| | 489,172 |
| | 336,385 |
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| Other | | 8,822 |
| | — |
| | 8,822 |
| | — |
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| Total revenues and other – affiliates | | 351,127 |
| | 325,312 |
| | 982,595 |
| | 900,301 |
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| Revenues and other – third parties | | | | | | | | |
| Gathering, processing and transportation | | 148,884 |
| | 125,727 |
| | 428,835 |
| | 346,416 |
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| Natural gas and natural gas liquids sales | | 74,139 |
| | 28,189 |
| | 201,318 |
| | 43,200 |
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| Other | | 545 |
| | 2,417 |
| | 3,590 |
| | 3,533 |
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| Total revenues and other – third parties | | 223,568 |
| | 156,333 |
| | 633,743 |
| | 393,149 |
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| Total revenues and other | | 574,695 |
| | 481,645 |
| | 1,616,338 |
| | 1,293,450 |
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| Equity income, net – affiliates | | 21,519 |
| | 20,294 |
| | 62,708 |
| | 56,801 |
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| Operating expenses | | | | | | | | |
Cost of product (1) | | 239,223 |
| | 145,643 |
| | 631,859 |
| | 326,959 |
|
Operation and maintenance (1) | | 79,536 |
| | 74,755 |
| | 229,444 |
| | 226,141 |
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General and administrative (1) | | 12,158 |
| | 11,382 |
| | 35,402 |
| | 33,542 |
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| Property and other taxes | | 11,215 |
| | 10,670 |
| | 35,433 |
| | 33,098 |
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| Depreciation and amortization | | 72,539 |
| | 67,246 |
| | 216,272 |
| | 199,646 |
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| Impairments | | 2,159 |
| | 2,392 |
| | 170,079 |
| | 11,313 |
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| Total operating expenses | | 416,830 |
| | 312,088 |
| | 1,318,489 |
| | 830,699 |
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| Gain (loss) on divestiture and other, net | | 72 |
| | (6,230 | ) | | 135,017 |
| | (8,769 | ) |
| Proceeds from business interruption insurance claims | | — |
| | 13,667 |
| | 29,882 |
| | 16,270 |
|
| Operating income (loss) | | 179,456 |
| | 197,288 |
| | 525,456 |
| | 527,053 |
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| Interest income – affiliates | | 4,225 |
| | 4,225 |
| | 12,675 |
| | 12,675 |
|
Interest expense (2) | | (35,544 | ) | | (30,768 | ) | | (106,794 | ) | | (75,687 | ) |
| Other income (expense), net | | 286 |
| | 153 |
| | 969 |
| | 224 |
|
| Income (loss) before income taxes | | 148,423 |
| | 170,898 |
| | 432,306 |
| | 464,265 |
|
| Income tax (benefit) expense | | 510 |
| | 472 |
| | 4,905 |
| | 7,431 |
|
| Net income (loss) | | 147,913 |
| | 170,426 |
| | 427,401 |
| | 456,834 |
|
| Net income attributable to noncontrolling interest | | 4,407 |
| | 2,680 |
| | 8,555 |
| | 8,507 |
|
| Net income (loss) attributable to Western Gas Partners, LP | | $ | 143,506 |
| | $ | 167,746 |
| | $ | 418,846 |
| | $ | 448,327 |
|
| Limited partners’ interest in net income (loss): | | | | | | | | |
| Net income (loss) attributable to Western Gas Partners, LP | | $ | 143,506 |
| | $ | 167,746 |
| | $ | 418,846 |
| | $ | 448,327 |
|
| Pre-acquisition net (income) loss allocated to Anadarko | | — |
| | — |
| | — |
| | (11,326 | ) |
| Series A Preferred units interest in net (income) loss | | — |
| | (25,539 | ) | | (42,373 | ) | | (50,989 | ) |
General partner interest in net (income) loss (3) | | (78,376 | ) | | (60,551 | ) | | (222,903 | ) | | (174,332 | ) |
Common and Class C limited partners’ interest in net income (loss) (3) | | 65,130 |
| | 81,656 |
| | 153,570 |
| | 211,680 |
|
Net income (loss) per common unit – basic and diluted (4) | | $ | 0.38 |
| | $ | 0.54 |
| | $ | 0.91 |
| | $ | 1.39 |
|
(2)See Note 8.
| |
(3)Total operating expenses includes related-party amounts of $(35.8) million and $(53.0) million for the three and nine months ended September 30, 2023, respectively, and $(4.5) million and $(33.3) million for the three and nine months ended September 30, 2022, respectively, all primarily related to changes in imbalance positions. See Note 6. (4)See Note 5. (1)
| Cost of product includes product purchases from Anadarko (as defined in Note 1) of $22.9 million and $60.5 million for the three and nine months ended September 30, 2017, respectively, and $21.3 million and $68.0 million for the three and nine months ended September 30, 2016, respectively. Operation and maintenance includes charges from Anadarko of $18.1 million and $53.7 million for the three and nine months ended September 30, 2017, respectively, and $15.1 million and $50.7 million for the three and nine months ended September 30, 2016, respectively. General and administrative includes charges from Anadarko of $10.1 million and $29.0 million for the three and nine months ended September 30, 2017, respectively, and $9.5 million and $27.6 million for the three and nine months ended September 30, 2016, respectively. See Note 5.
|
| |
(2)
| Includes affiliate (as defined in Note 1) amounts of zero and $(0.1) million for the three and nine months ended September 30, 2017, respectively, and $1.2 million and $12.1 million for the three and nine months ended September 30, 2016, respectively. See Note 2 and Note 9.
|
| |
(3)
| 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.
|
| |
(4)
| See Note 4 for the calculation of net income (loss) per common unit.
|
See accompanying Notes to Consolidated Financial Statements.
6
WESTERN GASMIDSTREAM PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
| | | | | | | | | | | | | | |
| | |
| | | | |
| thousands except number of units | | September 30,
2023 | | December 31,
2022 |
| ASSETS | | | | |
| Current assets | | | | |
| Cash and cash equivalents | | $ | 489,494 | | | $ | 286,656 | |
| Accounts receivable, net | | 614,836 | | | 554,263 | |
| Other current assets | | 31,476 | | | 59,506 | |
| Total current assets | | 1,135,806 | | | 900,425 | |
| Property, plant, and equipment | | | | |
| Cost | | 13,809,080 | | | 13,365,593 | |
| Less accumulated depreciation | | 5,144,678 | | | 4,823,993 | |
| Net property, plant, and equipment | | 8,664,402 | | | 8,541,600 | |
| Goodwill | | 4,783 | | | 4,783 | |
| Other intangible assets | | 689,324 | | | 713,075 | |
| Equity investments | | 915,076 | | | 944,696 | |
Other assets (1) | | 217,163 | | | 167,049 | |
Total assets (2) | | $ | 11,626,554 | | | $ | 11,271,628 | |
| LIABILITIES, EQUITY, AND PARTNERS’ CAPITAL | | | | |
| Current liabilities | | | | |
| Accounts and imbalance payables | | $ | 393,358 | | | $ | 360,562 | |
Short-term debt | | 2,268 | | | 215,780 | |
| Accrued ad valorem taxes | | 50,291 | | | 72,875 | |
| Accrued liabilities | | 189,983 | | | 254,640 | |
| Total current liabilities | | 635,900 | | | 903,857 | |
| Long-term liabilities | | | | |
Long-term debt | | 7,260,051 | | | 6,569,582 | |
| Deferred income taxes | | 15,378 | | | 14,424 | |
| Asset retirement obligations | | 307,945 | | | 290,021 | |
| Other liabilities | | 452,188 | | | 385,629 | |
Total long-term liabilities | | 8,035,562 | | | 7,259,656 | |
Total liabilities (3) | | 8,671,462 | | | 8,163,513 | |
| Equity and partners’ capital | | | | |
| Common units (379,516,369 and 384,070,984 units issued and outstanding at September 30, 2023, and December 31, 2022, respectively) | | 2,821,958 | | | 2,969,604 | |
| General partner units (9,060,641 units issued and outstanding at September 30, 2023, and December 31, 2022) | | 1,678 | | | 2,105 | |
| Total partners’ capital | | 2,823,636 | | | 2,971,709 | |
| Noncontrolling interests | | 131,456 | | | 136,406 | |
| Total equity and partners’ capital | | 2,955,092 | | | 3,108,115 | |
| Total liabilities, equity, and partners’ capital | | $ | 11,626,554 | | | $ | 11,271,628 | |
|
| | | | | | | | |
| thousands except number of units | | September 30,
2017 | | December 31,
2016 |
| ASSETS | | | | |
| Current assets | | | | |
| Cash and cash equivalents | | $ | 152,435 |
| | $ | 357,925 |
|
Accounts receivable, net (1) | | 192,530 |
| | 223,223 |
|
| Other current assets | | 13,381 |
| | 12,866 |
|
| Total current assets | | 358,346 |
| | 594,014 |
|
| Note receivable – Anadarko | | 260,000 |
| | 260,000 |
|
| Property, plant and equipment | | | | |
| Cost | | 7,582,178 |
| | 6,861,942 |
|
| Less accumulated depreciation | | 2,074,464 |
| | 1,812,010 |
|
| Net property, plant and equipment | | 5,507,714 |
| | 5,049,932 |
|
| Goodwill | | 417,610 |
| | 417,610 |
|
| Other intangible assets | | 782,376 |
| | 803,698 |
|
| Equity investments | | 573,622 |
| | 594,208 |
|
| Other assets | | 14,643 |
| | 13,566 |
|
| Total assets | | $ | 7,914,311 |
| | $ | 7,733,028 |
|
| LIABILITIES, EQUITY AND PARTNERS’ CAPITAL | | | | |
| Current liabilities | | | | |
Accounts and imbalance payables (2) | | $ | 302,848 |
| | $ | 247,076 |
|
| Accrued ad valorem taxes | | 33,020 |
| | 23,121 |
|
Accrued liabilities (3) | | 57,496 |
| | 45,108 |
|
| Total current liabilities | | 393,364 |
| | 315,305 |
|
| Long-term debt | | 3,343,886 |
| | 3,091,461 |
|
| Deferred income taxes | | 10,284 |
| | 6,402 |
|
| Asset retirement obligations and other | | 146,248 |
| | 142,641 |
|
Deferred purchase price obligation – Anadarko (4) | | — |
| | 41,440 |
|
| Total long-term liabilities | | 3,500,418 |
| | 3,281,944 |
|
| Total liabilities | | 3,893,782 |
| | 3,597,249 |
|
| Equity and partners’ capital | | | | |
Series A Preferred units (zero and 21,922,831 units issued and outstanding at September 30, 2017, and December 31, 2016, respectively) (5) | | — |
| | 639,545 |
|
| Common units (152,602,105 and 130,671,970 units issued and outstanding at September 30, 2017, and December 31, 2016, respectively) | | 3,012,424 |
| | 2,536,872 |
|
Class C units (12,977,633 and 12,358,123 units issued and outstanding at September 30, 2017, and December 31, 2016, respectively) (6) | | 771,856 |
| | 750,831 |
|
| General partner units (2,583,068 units issued and outstanding at September 30, 2017, and December 31, 2016) | | 172,180 |
| | 143,968 |
|
| Total partners’ capital | | 3,956,460 |
| | 4,071,216 |
|
| Noncontrolling interest | | 64,069 |
| | 64,563 |
|
| Total equity and partners’ capital | | 4,020,529 |
| | 4,135,779 |
|
| Total liabilities, equity and partners’ capital | | $ | 7,914,311 |
| | $ | 7,733,028 |
|
(3)Total liabilities includes related-party amounts of $360.8 million and $312.3 million as of September 30, 2023, and December 31, 2022, respectively. See Note 6.
| |
(1)
| Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $78.4 million and $76.6 million as of September 30, 2017, and December 31, 2016, respectively. Accounts receivable, net as of December 31, 2016, also includes an insurance claim receivable related to an incident at the DBM complex. See Note 1.
|
| |
(2)
| Accounts and imbalance payables includes affiliate amounts of $0.2 million and zero as of September 30, 2017, and December 31, 2016, respectively. |
| |
(3)
| Accrued liabilities includes affiliate amounts of $0.3 million and zero as of September 30, 2017, and December 31, 2016, respectively. |
| |
(5)
| The Series A Preferred units converted into common units on a one-for-one basis in 2017. See Note 4.
|
| |
(6)
| The Class C units will convert into common units on a one-for-one basis on March 1, 2020, unless the Partnership elects to convert such units earlier or Anadarko extends the conversion date. See Note 4.
|
See accompanying Notes to Consolidated Financial Statements.
7
WESTERN GASMIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTSTATEMENTS OF EQUITY AND PARTNERS’ CAPITAL
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Partners’ Capital | | | | |
| thousands | | Common
Units | | General Partner
Units | | Noncontrolling
Interests | | Total |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Balance at December 31, 2022 | | $ | 2,969,604 | | | $ | 2,105 | | | $ | 136,406 | | | $ | 3,108,115 | |
| Net income (loss) | | 198,959 | | | 4,686 | | | 4,696 | | | 208,341 | |
| Distributions to Chipeta noncontrolling interest owner | | — | | | — | | | (2,240) | | | (2,240) | |
| Distributions to noncontrolling interest owner of WES Operating | | — | | | — | | | (4,271) | | | (4,271) | |
| Distributions to Partnership unitholders | | (192,039) | | | (4,530) | | | — | | | (196,569) | |
Unit repurchases (1) | | (7,061) | | | — | | | — | | | (7,061) | |
| | | | | | | | |
Equity-based compensation expense | | 7,199 | | | — | | | — | | | 7,199 | |
| | | | | | | | |
| Other | | (11,950) | | | — | | | — | | | (11,950) | |
| Balance at March 31, 2023 | | $ | 2,964,712 | | | $ | 2,261 | | | $ | 134,591 | | | $ | 3,101,564 | |
| Net income (loss) | | 247,100 | | | 5,821 | | | 6,595 | | | 259,516 | |
| Distributions to Chipeta noncontrolling interest owner | | — | | | — | | | (1,230) | | | (1,230) | |
| Distributions to noncontrolling interest owner of WES Operating | | — | | | — | | | (6,860) | | | (6,860) | |
| Distributions to Partnership unitholders | | (329,227) | | | (7,760) | | | — | | | (336,987) | |
Unit repurchases (1) | | (41) | | | — | | | — | | | (41) | |
| | | | | | | | |
Equity-based compensation expense | | 7,665 | | | — | | | — | | | 7,665 | |
| | | | | | | | |
| Other | | (1,464) | | | — | | | — | | | (1,464) | |
| Balance at June 30, 2023 | | $ | 2,888,745 | | | $ | 322 | | | $ | 133,096 | | | $ | 3,022,163 | |
| Net income (loss) | | 270,843 | | | 6,453 | | | 7,102 | | | 284,398 | |
| Distributions to Chipeta noncontrolling interest owner | | — | | | — | | | (1,613) | | | (1,613) | |
| Distributions to noncontrolling interest owner of WES Operating | | — | | | — | | | (7,129) | | | (7,129) | |
| Distributions to Partnership unitholders | | (216,345) | | | (5,097) | | | — | | | (221,442) | |
Unit repurchases (1) | | (127,500) | | | — | | | — | | | (127,500) | |
| | | | | | | | |
Equity-based compensation expense | | 7,171 | | | — | | | — | | | 7,171 | |
| | | | | | | | |
| Other | | (956) | | | — | | | — | | | (956) | |
| Balance at September 30, 2023 | | $ | 2,821,958 | | | $ | 1,678 | | | $ | 131,456 | | | $ | 2,955,092 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Partners’ Capital | | | | |
| thousands | | Net Investment by Anadarko | | Common Units | | Class C Units | | Series A Preferred Units | | General Partner Units | | Noncontrolling Interest | | Total |
| Balance at December 31, 2016 | | $ | — |
| | $ | 2,536,872 |
| | $ | 750,831 |
| | $ | 639,545 |
| | $ | 143,968 |
| | $ | 64,563 |
| | $ | 4,135,779 |
|
| Net income (loss) | | — |
| | 171,075 |
| | 17,415 |
| | 7,453 |
| | 222,903 |
| | 8,555 |
| | 427,401 |
|
Above-market component of swap agreements with Anadarko (1) | | — |
| | 46,719 |
| | — |
| | — |
| | — |
| | — |
| | 46,719 |
|
Conversion of Series A Preferred units into common units (2) | | — |
| | 686,936 |
| | — |
| | (686,936 | ) | | — |
| | — |
| | — |
|
| Amortization of beneficial conversion feature of Class C units and Series A Preferred units | | — |
| | (65,909 | ) | | 3,610 |
| | 62,299 |
| | — |
| | — |
| | — |
|
| Distributions to noncontrolling interest owner | | — |
| | — |
| | — |
| | — |
| | — |
| | (9,049 | ) | | (9,049 | ) |
| Distributions to unitholders | | — |
| | (372,123 | ) | | — |
| | (22,361 | ) | | (194,778 | ) | | — |
| | (589,262 | ) |
| Acquisitions from affiliates | | (30 | ) | | 30 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Revision to Deferred purchase price obligation – Anadarko (3) | | — |
| | 4,165 |
| | — |
| | — |
| | — |
| | — |
| | 4,165 |
|
| Contributions of equity-based compensation from Anadarko | | — |
| | 3,249 |
| | — |
| | — |
| | 66 |
| | — |
| | 3,315 |
|
| Net pre-acquisition contributions from (distributions to) Anadarko | | 30 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 30 |
|
| Net contributions from (distributions to) Anadarko of other assets | | — |
| | 1,352 |
| | — |
| | — |
| | 21 |
| | — |
| | 1,373 |
|
| Other | | — |
| | 58 |
| | — |
| | — |
| | — |
| | — |
| | 58 |
|
| Balance at September 30, 2017 | | $ | — |
| | $ | 3,012,424 |
| | $ | 771,856 |
| | $ | — |
| | $ | 172,180 |
| | $ | 64,069 |
| | $ | 4,020,529 |
|
See accompanying Notes to Consolidated Financial Statements.
8
8
WESTERN GASMIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF EQUITY AND PARTNERS’ CAPITAL
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Partners’ Capital | | | | |
| thousands | | Common
Units | | General Partner
Units | | Noncontrolling
Interests | | Total |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Balance at December 31, 2021 | | $ | 2,966,955 | | | $ | (8,882) | | | $ | 137,687 | | | $ | 3,095,760 | |
| Net income (loss) | | 301,934 | | | 6,783 | | | 8,953 | | | 317,670 | |
| Distributions to Chipeta noncontrolling interest owner | | — | | | — | | | (1,984) | | | (1,984) | |
| Distributions to noncontrolling interest owner of WES Operating | | — | | | — | | | (2,805) | | | (2,805) | |
| Distributions to Partnership unitholders | | (131,786) | | | (2,963) | | | — | | | (134,749) | |
Unit repurchases (1) | | (5,149) | | | — | | | — | | | (5,149) | |
Contributions of equity-based compensation from Occidental | | 1,949 | | | — | | | — | | | 1,949 | |
Equity-based compensation expense | | 5,794 | | | — | | | — | | | 5,794 | |
| Net contributions from (distributions to) related parties | | 409 | | | — | | | — | | | 409 | |
| Other | | (6,088) | | | — | | | — | | | (6,088) | |
| Balance at March 31, 2022 | | $ | 3,134,018 | | | $ | (5,062) | | | $ | 141,851 | | | $ | 3,270,807 | |
| Net income (loss) | | 299,550 | | | 6,767 | | | 8,854 | | | 315,171 | |
| Distributions to Chipeta noncontrolling interest owner | | — | | | — | | | (1,198) | | | (1,198) | |
| Distributions to noncontrolling interest owner of WES Operating | | — | | | — | | | (6,007) | | | (6,007) | |
| Distributions to Partnership unitholders | | (201,667) | | | (4,530) | | | — | | | (206,197) | |
Unit repurchases (1) | | (74,068) | | | — | | | — | | | (74,068) | |
Contributions of equity-based compensation from Occidental | | 241 | | | — | | | — | | | 241 | |
Equity-based compensation expense | | 6,797 | | | — | | | — | | | 6,797 | |
| Net contributions from (distributions to) related parties | | 375 | | | — | | | — | | | 375 | |
| Other | | (918) | | | — | | | — | | | (918) | |
| Balance at June 30, 2022 | | $ | 3,164,328 | | | $ | (2,825) | | | $ | 143,500 | | | $ | 3,305,003 | |
| Net income (loss) | | 259,501 | | | 6,244 | | | 7,836 | | | 273,581 | |
| Distributions to Chipeta noncontrolling interest owner | | — | | | — | | | (1,838) | | | (1,838) | |
| Distributions to noncontrolling interest owner of WES Operating | | — | | | — | | | (11,365) | | | (11,365) | |
| Distributions to Partnership unitholders | | (193,213) | | | (4,531) | | | — | | | (197,744) | |
Unit repurchases (1) | | (367,858) | | | — | | | — | | | (367,858) | |
Contributions of equity-based compensation from Occidental | | 81 | | | — | | | — | | | 81 | |
Equity-based compensation expense | | 6,383 | | | — | | | — | | | 6,383 | |
| Net contributions from (distributions to) related parties | | 377 | | | — | | | — | | | 377 | |
| Other | | (934) | | | — | | | — | | | (934) | |
| Balance at September 30, 2022 | | $ | 2,868,665 | | | $ | (1,112) | | | $ | 138,133 | | | $ | 3,005,686 | |
(1)See Note 5.
See accompanying Notes to Consolidated Financial Statements.
9
WESTERN MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
| | | | | | | | | | | | | | | | |
| | |
| | | Nine Months Ended
September 30, | | |
| thousands | | 2023 | | 2022 | | |
| Cash flows from operating activities | | | | | | |
| Net income (loss) | | $ | 752,255 | | | $ | 906,422 | | | |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | | |
| Depreciation and amortization | | 435,481 | | | 430,455 | | | |
Long-lived asset and other impairments | | 52,880 | | | 94 | | | |
| | | | | | |
Non-cash equity-based compensation expense | | 22,035 | | | 21,245 | | | |
| Deferred income taxes | | 954 | | | 1,757 | | | |
Accretion and amortization of long-term obligations, net | | 5,977 | | | 5,359 | | | |
| Equity income, net – related parties | | (116,839) | | | (139,388) | | | |
Distributions from equity-investment earnings – related parties | | 115,897 | | | 139,710 | | | |
| (Gain) loss on divestiture and other, net | | 3,668 | | | 884 | | | |
| (Gain) loss on early extinguishment of debt | | (15,378) | | | (91) | | | |
| | | | | | |
| Other | | 371 | | | 299 | | | |
| Changes in assets and liabilities: | | | | | | |
| (Increase) decrease in accounts receivable, net | | (60,573) | | | (212,955) | | | |
| Increase (decrease) in accounts and imbalance payables and accrued liabilities, net | | (87,040) | | | 65,069 | | | |
| Change in other items, net | | 78,346 | | | (6,653) | | | |
| Net cash provided by operating activities | | 1,188,034 | | | 1,212,207 | | | |
| Cash flows from investing activities | | | | | | |
| Capital expenditures | | (536,427) | | | (341,505) | | | |
| | | | | | |
| Acquisitions from third parties | | — | | | (41,018) | | | |
| Contributions to equity investments – related parties | | (1,153) | | | (8,899) | | | |
| Distributions from equity investments in excess of cumulative earnings – related parties | | 31,715 | | | 41,058 | | | |
| | | | | | |
| Proceeds from the sale of assets to third parties | | (60) | | | 1,111 | | | |
| (Increase) decrease in materials and supplies inventory and other | | (32,659) | | | (6,999) | | | |
| Net cash used in investing activities | | (538,584) | | | (356,252) | | | |
| Cash flows from financing activities | | | | | | |
| Borrowings, net of debt issuance costs | | 1,801,011 | | | 1,389,010 | | | |
| Repayments of debt | | (1,317,928) | | | (1,268,548) | | | |
| Increase (decrease) in outstanding checks | | (241) | | | 1,459 | | | |
Distributions to Partnership unitholders (1) | | (754,998) | | | (538,690) | | | |
| Distributions to Chipeta noncontrolling interest owner | | (5,083) | | | (5,020) | | | |
| Distributions to noncontrolling interest owner of WES Operating | | (18,260) | | | (20,177) | | | |
| Net contributions from (distributions to) related parties | | — | | | 1,161 | | | |
Unit repurchases (1) | | (134,602) | | | (447,075) | | | |
| Other | | (16,511) | | | (10,981) | | | |
| Net cash provided by (used in) financing activities | | (446,612) | | | (898,861) | | | |
| Net increase (decrease) in cash and cash equivalents | | 202,838 | | | (42,906) | | | |
| Cash and cash equivalents at beginning of period | | 286,656 | | | 201,999 | | | |
| Cash and cash equivalents at end of period | | $ | 489,494 | | | $ | 159,093 | | | |
| Supplemental disclosures | | | | | | |
| Interest paid, net of capitalized interest | | $ | 278,283 | | | $ | 314,192 | | | |
| Income taxes paid (reimbursements received) | | 1,271 | | | 905 | | | |
| Accrued capital expenditures | | 112,150 | | | 71,955 | | | |
|
| | | | | | | | |
| | | Nine Months Ended September 30, |
| thousands | | 2017 | | 2016 |
| Cash flows from operating activities | | | | |
| Net income (loss) | | $ | 427,401 |
| | $ | 456,834 |
|
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | |
| Depreciation and amortization | | 216,272 |
| | 199,646 |
|
| Impairments | | 170,079 |
| | 11,313 |
|
| Non-cash equity-based compensation expense | | 3,573 |
| | 3,570 |
|
| Deferred income taxes | | 3,882 |
| | 2,321 |
|
| Accretion and amortization of long-term obligations, net | | 3,194 |
| | (9,176 | ) |
| Equity income, net – affiliates | | (62,708 | ) | | (56,801 | ) |
| Distributions from equity investment earnings – affiliates | | 64,313 |
| | 59,671 |
|
| (Gain) loss on divestiture and other, net | | (135,017 | ) | | 8,769 |
|
| Lower of cost or market inventory adjustments | | 140 |
| | 41 |
|
| Changes in assets and liabilities: | | | | |
| (Increase) decrease in accounts receivable, net | | (46,972 | ) | | (41,108 | ) |
| Increase (decrease) in accounts and imbalance payables and accrued liabilities, net | | 4,007 |
| | 24,103 |
|
| Change in other items, net | | (3,065 | ) | | (1,445 | ) |
| Net cash provided by operating activities | | 645,099 |
|
| 657,738 |
|
| Cash flows from investing activities | | | | |
| Capital expenditures | | (419,193 | ) | | (372,725 | ) |
| Contributions in aid of construction costs from affiliates | | 1,386 |
| | 4,927 |
|
| Acquisitions from affiliates | | (3,910 | ) | | (716,465 | ) |
| Acquisitions from third parties | | (155,298 | ) | | — |
|
| Investments in equity affiliates | | (384 | ) | | 139 |
|
| Distributions from equity investments in excess of cumulative earnings – affiliates | | 16,255 |
| | 16,592 |
|
| Proceeds from the sale of assets to affiliates | | — |
| | 623 |
|
| Proceeds from the sale of assets to third parties | | 23,370 |
| | 7,819 |
|
| Proceeds from property insurance claims | | 22,977 |
| | 18,398 |
|
| Net cash used in investing activities | | (514,797 | ) |
| (1,040,692 | ) |
| Cash flows from financing activities | | | | |
| Borrowings, net of debt issuance costs | | 249,989 |
| | 1,094,600 |
|
| Repayments of debt | | — |
| | (880,000 | ) |
Settlement of the Deferred purchase price obligation – Anadarko (1) | | (37,346 | ) | | — |
|
| Increase (decrease) in outstanding checks | | 3,310 |
| | (1,070 | ) |
| Proceeds from the issuance of common units, net of offering expenses | | (183 | ) | | 25,000 |
|
| Proceeds from the issuance of Series A Preferred units, net of offering expenses | | — |
| | 686,937 |
|
Distributions to unitholders (2) | | (589,262 | ) | | (490,289 | ) |
| Distributions to noncontrolling interest owner | | (9,049 | ) | | (11,257 | ) |
| Net contributions from (distributions to) Anadarko | | 30 |
| | (29,335 | ) |
Above-market component of swap agreements with Anadarko (2) | | 46,719 |
| | 34,782 |
|
| Net cash provided by (used in) financing activities | | (335,792 | ) |
| 429,368 |
|
| Net increase (decrease) in cash and cash equivalents | | (205,490 | ) |
| 46,414 |
|
| Cash and cash equivalents at beginning of period | | 357,925 |
| | 98,033 |
|
| Cash and cash equivalents at end of period | | $ | 152,435 |
|
| $ | 144,447 |
|
| Supplemental disclosures | | | | |
Accretion expense and revisions to the Deferred purchase price obligation – Anadarko (1) | | $ | (4,094 | ) | | $ | (172,249 | ) |
| Net distributions to (contributions from) Anadarko of other assets | | (1,373 | ) | | 581 |
|
| Interest paid, net of capitalized interest | | 97,811 |
| | 82,529 |
|
| Taxes paid | | 189 |
| | 67 |
|
| Accrued capital expenditures | | 165,732 |
| | 49,328 |
|
Fair value of properties and equipment from non-cash third party transactions (1) | | 551,453 |
| | — |
|
See accompanying Notes to Consolidated Financial Statements.
10
9
WESTERN GASMIDSTREAM OPERATING, LP
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | |
| thousands | | 2023 | | 2022 | | 2023 | | 2022 | | |
| Revenues and other | | | | | | | | | | |
| Service revenues – fee based | | $ | 695,547 | | | $ | 666,555 | | | $ | 2,004,920 | | | $ | 1,954,105 | | | |
| Service revenues – product based | | 48,446 | | | 91,356 | | | 142,212 | | | 202,721 | | | |
| Product sales | | 31,652 | | | 79,430 | | | 100,336 | | | 314,755 | | | |
| Other | | 368 | | | 227 | | | 800 | | | 703 | | | |
Total revenues and other (1) | | 776,013 | | | 837,568 | | | 2,248,268 | | | 2,472,284 | | | |
| Equity income, net – related parties | | 35,494 | | | 41,317 | | | 116,839 | | | 139,388 | | | |
| Operating expenses | | | | | | | | | | |
| Cost of product | | 27,590 | | | 106,833 | | | 123,795 | | | 328,237 | | | |
| Operation and maintenance | | 204,434 | | | 190,514 | | | 562,104 | | | 487,643 | | | |
| General and administrative | | 54,541 | | | 47,783 | | | 157,645 | | | 142,871 | | | |
| Property and other taxes | | 14,583 | | | 19,390 | | | 39,961 | | | 60,494 | | | |
| Depreciation and amortization | | 147,363 | | | 156,837 | | | 435,481 | | | 430,455 | | | |
Long-lived asset and other impairments (2) | | 245 | | | 4 | | | 52,880 | | | 94 | | | |
| | | | | | | | | | |
Total operating expenses (3) | | 448,756 | | | 521,361 | | | 1,371,866 | | | 1,449,794 | | | |
| Gain (loss) on divestiture and other, net | | (1,480) | | | (104) | | | (3,668) | | | (884) | | | |
| Operating income (loss) | | 361,271 | | | 357,420 | | | 989,573 | | | 1,160,994 | | | |
| | | | | | | | | | |
| Interest expense | | (82,754) | | | (83,106) | | | (250,606) | | | (249,333) | | | |
| Gain (loss) on early extinguishment of debt | | 8,565 | | | — | | | 15,378 | | | 91 | | | |
| Other income (expense), net | | (1,330) | | | 45 | | | 2,603 | | | 99 | | | |
| Income (loss) before income taxes | | 285,752 | | | 274,359 | | | 756,948 | | | 911,851 | | | |
| Income tax expense (benefit) | | 905 | | | 387 | | | 2,980 | | | 3,683 | | | |
| Net income (loss) | | 284,847 | | | 273,972 | | | 753,968 | | | 908,168 | | | |
| Net income (loss) attributable to noncontrolling interest | | 1,432 | | | 2,404 | | | 3,377 | | | 7,627 | | | |
| Net income (loss) attributable to Western Midstream Operating, LP | | $ | 283,415 | | | $ | 271,568 | | | $ | 750,591 | | | $ | 900,541 | | | |
(1)Total revenues and other includes related-party amounts of $463.6 million and $1.4 billion for the three and nine months ended September 30, 2023, respectively, and $476.5 million and $1.4 billion for the three and nine months ended September 30, 2022, respectively. See Note 6.
(2)See Note 8.
(3)Total operating expenses includes related-party amounts of $(35.1) million and $(50.5) million for the three and nine months ended September 30, 2023, respectively, and $(3.7) million and $(30.9) million for the three and nine months ended September 30, 2022, respectively, all primarily related to changes in imbalance positions. See Note 6.
See accompanying Notes to Consolidated Financial Statements.
11
WESTERN MIDSTREAM OPERATING, LP
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
| | | | | | | | | | | | | | |
| | |
| | | | |
| thousands except number of units | | September 30,
2023 | | December 31,
2022 |
| ASSETS | | | | |
| Current assets | | | | |
| Cash and cash equivalents | | $ | 484,453 | | | $ | 286,101 | |
| Accounts receivable, net | | 614,816 | | | 554,263 | |
| Other current assets | | 30,808 | | | 57,291 | |
| Total current assets | | 1,130,077 | | | 897,655 | |
| Property, plant, and equipment | | | | |
| Cost | | 13,809,080 | | | 13,365,593 | |
| Less accumulated depreciation | | 5,144,678 | | | 4,823,993 | |
| Net property, plant, and equipment | | 8,664,402 | | | 8,541,600 | |
| Goodwill | | 4,783 | | | 4,783 | |
| Other intangible assets | | 689,324 | | | 713,075 | |
| Equity investments | | 915,076 | | | 944,696 | |
Other assets (1) | | 215,476 | | | 166,450 | |
Total assets (2) | | $ | 11,619,138 | | | $ | 11,268,259 | |
| LIABILITIES, EQUITY, AND PARTNERS’ CAPITAL | | | | |
| Current liabilities | | | | |
| Accounts and imbalance payables | | $ | 409,156 | | | $ | 404,468 | |
Short-term debt | | 2,268 | | | 215,780 | |
| Accrued ad valorem taxes | | 50,291 | | | 72,875 | |
| Accrued liabilities | | 145,729 | | | 197,289 | |
| | | | |
| Total current liabilities | | 607,444 | | | 890,412 | |
| Long-term liabilities | | | | |
Long-term debt | | 7,260,051 | | | 6,569,582 | |
| Deferred income taxes | | 15,378 | | | 14,424 | |
| Asset retirement obligations | | 307,945 | | | 290,021 | |
| Other liabilities | | 450,497 | | | 383,713 | |
Total long-term liabilities | | 8,033,871 | | | 7,257,740 | |
Total liabilities (3) | | 8,641,315 | | | 8,148,152 | |
| Equity and partners’ capital | | | | |
| Common units (318,675,578 units issued and outstanding at September 30, 2023, and December 31, 2022) | | 2,951,434 | | | 3,092,012 | |
| | | | |
| | | | |
| | | | |
| Total partners’ capital | | 2,951,434 | | | 3,092,012 | |
| Noncontrolling interest | | 26,389 | | | 28,095 | |
| Total equity and partners’ capital | | 2,977,823 | | | 3,120,107 | |
| Total liabilities, equity, and partners’ capital | | $ | 11,619,138 | | | $ | 11,268,259 | |
(1)Other assets includes $6.5 million of NGLs line-fill inventory as of September 30, 2023, and December 31, 2022. Other assets also includes $92.4 million and $60.4 million of materials and supplies inventory as of September 30, 2023, and December 31, 2022, respectively.
(2)Total assets includes related-party amounts of $1.3 billion as of September 30, 2023, and December 31, 2022, which includes related-party Accounts receivable, net of $340.9 million and $313.9 million as of September 30, 2023, and December 31, 2022, respectively. See Note 6.
(3)Total liabilities includes related-party amounts of $376.4 million and $356.0 million as of September 30, 2023, and December 31, 2022, respectively. See Note 6.
See accompanying Notes to Consolidated Financial Statements.
12
WESTERN MIDSTREAM OPERATING, LP
CONSOLIDATED STATEMENTS OF EQUITY AND PARTNERS’ CAPITAL
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | |
| thousands | | Common
Units | | Noncontrolling
Interest | | Total |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| Balance at December 31, 2022 | | $ | 3,092,012 | | | $ | 28,095 | | | $ | 3,120,107 | |
| Net income (loss) | | 208,013 | | | 535 | | | 208,548 | |
| Distributions to Chipeta noncontrolling interest owner | | — | | | (2,240) | | | (2,240) | |
| Distributions to WES Operating unitholders | | (213,513) | | | — | | | (213,513) | |
| | | | | | |
Contributions of equity-based compensation from WES | | 7,058 | | | — | | | 7,058 | |
| | | | | | |
| | | | | | |
| Balance at March 31, 2023 | | $ | 3,093,570 | | | $ | 26,390 | | | $ | 3,119,960 | |
| Net income (loss) | | 259,163 | | | 1,410 | | | 260,573 | |
| Distributions to Chipeta noncontrolling interest owner | | — | | | (1,230) | | | (1,230) | |
| Distributions to WES Operating unitholders | | (342,895) | | | — | | | (342,895) | |
| | | | | | |
Contributions of equity-based compensation from WES | | 7,519 | | | — | | | 7,519 | |
| | | | | | |
| | | | | | |
| Balance at June 30, 2023 | | $ | 3,017,357 | | | $ | 26,570 | | | $ | 3,043,927 | |
| Net income (loss) | | 283,415 | | | 1,432 | | | 284,847 | |
| Distributions to Chipeta noncontrolling interest owner | | — | | | (1,613) | | | (1,613) | |
| Distributions to WES Operating unitholders | | (356,362) | | | — | | | (356,362) | |
| | | | | | |
Contributions of equity-based compensation from WES | | 7,024 | | | — | | | 7,024 | |
| | | | | | |
| Balance at September 30, 2023 | | $ | 2,951,434 | | | $ | 26,389 | | | $ | 2,977,823 | |
See accompanying Notes to Consolidated Financial Statements.
13
WESTERN MIDSTREAM OPERATING, LP
CONSOLIDATED STATEMENTS OF EQUITY AND PARTNERS’ CAPITAL
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | |
| thousands | | Common
Units | | Noncontrolling
Interest | | Total |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| Balance at December 31, 2021 | | $ | 3,063,289 | | | $ | 29,377 | | | $ | 3,092,666 | |
| Net income (loss) | | 315,772 | | | 2,636 | | | 318,408 | |
| Distributions to Chipeta noncontrolling interest owner | | — | | | (1,984) | | | (1,984) | |
| Distributions to WES Operating unitholders | | (140,217) | | | — | | | (140,217) | |
Contributions of equity-based compensation from Occidental | | 1,949 | | | — | | | 1,949 | |
Contributions of equity-based compensation from WES | | 5,663 | | | — | | | 5,663 | |
| Net contributions from (distributions to) related parties | | 409 | | | — | | | 409 | |
| | | | | | |
| Balance at March 31, 2022 | | $ | 3,246,865 | | | $ | 30,029 | | | $ | 3,276,894 | |
| Net income (loss) | | 313,201 | | | 2,587 | | | 315,788 | |
| Distributions to Chipeta noncontrolling interest owner | | — | | | (1,198) | | | (1,198) | |
| Distributions to WES Operating unitholders | | (300,248) | | | — | | | (300,248) | |
Contributions of equity-based compensation from Occidental | | 241 | | | — | | | 241 | |
Contributions of equity-based compensation from WES | | 6,652 | | | — | | | 6,652 | |
| Net contributions from (distributions to) related parties | | 375 | | | — | | | 375 | |
| | | | | | |
| Balance at June 30, 2022 | | $ | 3,267,086 | | | $ | 31,418 | | | $ | 3,298,504 | |
| Net income (loss) | | 271,568 | | | 2,404 | | | 273,972 | |
| Distributions to Chipeta noncontrolling interest owner | | — | | | (1,838) | | | (1,838) | |
| Distributions to WES Operating unitholders | | (568,107) | | | — | | | (568,107) | |
Contributions of equity-based compensation from Occidental | | 81 | | | — | | | 81 | |
Contributions of equity-based compensation from WES | | 6,236 | | | — | | | 6,236 | |
| Net contributions from (distributions to) related parties | | 377 | | | — | | | 377 | |
| Balance at September 30, 2022 | | $ | 2,977,241 | | | $ | 31,984 | | | $ | 3,009,225 | |
See accompanying Notes to Consolidated Financial Statements.
14
WESTERN MIDSTREAM OPERATING, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
| | | | | | | | | | | | | | | | |
| | |
| | | Nine Months Ended
September 30, | | |
| thousands | | 2023 | | 2022 | | |
| Cash flows from operating activities | | | | | | |
| Net income (loss) | | $ | 753,968 | | | $ | 908,168 | | | |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | | |
| Depreciation and amortization | | 435,481 | | | 430,455 | | | |
Long-lived asset and other impairments | | 52,880 | | | 94 | | | |
| | | | | | |
Non-cash equity-based compensation expense | | 21,601 | | | 20,822 | | | |
| Deferred income taxes | | 954 | | | 1,757 | | | |
Accretion and amortization of long-term obligations, net | | 5,977 | | | 5,359 | | | |
| Equity income, net – related parties | | (116,839) | | | (139,388) | | | |
Distributions from equity-investment earnings – related parties | | 115,897 | | | 139,710 | | | |
| (Gain) loss on divestiture and other, net | | 3,668 | | | 884 | | | |
| (Gain) loss on early extinguishment of debt | | (15,378) | | | (91) | | | |
| Other | | 371 | | | 299 | | | |
| Changes in assets and liabilities: | | | | | | |
| (Increase) decrease in accounts receivable, net | | (60,553) | | | (212,955) | | | |
| Increase (decrease) in accounts and imbalance payables and accrued liabilities, net | | (102,048) | | | 55,981 | | | |
| Change in other items, net | | 78,111 | | | (6,666) | | | |
| Net cash provided by operating activities | | 1,174,090 | | | 1,204,429 | | | |
| Cash flows from investing activities | | | | | | |
| Capital expenditures | | (536,427) | | | (341,505) | | | |
| | | | | | |
| Acquisitions from third parties | | — | | | (41,018) | | | |
| Contributions to equity investments – related parties | | (1,153) | | | (8,899) | | | |
| Distributions from equity investments in excess of cumulative earnings – related parties | | 31,715 | | | 41,058 | | | |
| | | | | | |
| Proceeds from the sale of assets to third parties | | (60) | | | 1,111 | | | |
| (Increase) decrease in materials and supplies inventory and other | | (32,659) | | | (6,999) | | | |
| Net cash used in investing activities | | (538,584) | | | (356,252) | | | |
| Cash flows from financing activities | | | | | | |
| Borrowings, net of debt issuance costs | | 1,801,011 | | | 1,389,010 | | | |
| Repayments of debt | | (1,317,928) | | | (1,268,548) | | | |
| Increase (decrease) in outstanding checks | | (244) | | | 1,562 | | | |
Distributions to WES Operating unitholders (1) | | (912,770) | | | (1,008,572) | | | |
| Distributions to Chipeta noncontrolling interest owner | | (5,083) | | | (5,020) | | | |
| Net contributions from (distributions to) related parties | | — | | | 1,161 | | | |
| Other | | (2,140) | | | (3,039) | | | |
| Net cash provided by (used in) financing activities | | (437,154) | | | (893,446) | | | |
| Net increase (decrease) in cash and cash equivalents | | 198,352 | | | (45,269) | | | |
| Cash and cash equivalents at beginning of period | | 286,101 | | | 195,598 | | | |
| Cash and cash equivalents at end of period | | $ | 484,453 | | | $ | 150,329 | | | |
| Supplemental disclosures | | | | | | |
| | | | | | |
| Interest paid, net of capitalized interest | | $ | 278,283 | | | $ | 314,192 | | | |
| Income taxes paid (reimbursements received) | | 1,271 | | | 905 | | | |
| Accrued capital expenditures | | 112,150 | | | 71,955 | | | |
(1)Includes related-party amounts. See Note 6.
See accompanying Notes to Consolidated Financial Statements.
15
WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION
General. Western GasMidstream Partners, LP is a growth-oriented Delaware master limited partnership (“MLP”formed in September 2012. Western Midstream Operating, LP (together with its subsidiaries, “WES Operating”) is a Delaware limited partnership formed by Anadarko Petroleum Corporation in 2007 to acquire, own, develop, and operate midstream energy assets. Western Midstream Partners, LP owns, directly and indirectly, a 98.0% limited partner interest in WES Operating, and directly owns all of the outstanding equity interests of Western Midstream Operating GP, LLC, which holds the entire non-economic general partner interest in WES Operating.
For purposes of these consolidated financial statements, the “Partnership” refers to Western GasMidstream Partners, LP in its individual capacity or to Western Midstream Partners, LP and its subsidiaries.subsidiaries, including Western Midstream Operating GP, LLC and WES Operating, as the context requires. “WES Operating GP” refers to Western Midstream Operating GP, LLC, individually as the general partner of WES Operating. The Partnership’s general partner, Western GasMidstream 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 the Partnership (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 AnadarkoOccidental Petroleum Corporation. “Occidental” refers to Occidental Petroleum Corporation, as the context requires, and its subsidiaries, excluding the general partner. “Anadarko” refers to Anadarko Petroleum Corporation and its subsidiaries, excluding Western Midstream Holdings, LLC. Anadarko became a wholly owned subsidiary of Occidental as a result of Occidental’s acquisition by merger of Anadarko on August 8, 2019. “Related parties” refers to Occidental (see Note 6), the Partnership’s investments accounted for under the equity method of accounting (see Note 7), and 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”WES Operating for transactions that eliminate upon consolidation (see Note 6). 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 natural gas; gathering, stabilizing, and transporting condensate, natural-gas liquids (“NGLs”), and crude oil; and gathering and disposing of produced water. TheIn its capacity as a natural-gas processor, the Partnership provides these midstream services for Anadarko, as well as for third-party producersalso buys and customers.sells natural gas, NGLs, and condensate on behalf of itself and its customers under certain contracts. As of September 30, 2017,2023, the Partnership’s assets and investments consisted of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Wholly
Owned and
Operated | | Operated
Interests | | Non-Operated
Interests | | Equity
Interests | |
Gathering systems (1) | | 17 | | | 2 | | | 3 | | | 1 | | | |
| Treating facilities | | 37 | | | 3 | | | — | | | — | | | |
Natural-gas processing plants/trains | | 25 | | | 3 | | | — | | | 3 | | | |
| NGLs pipelines | | 2 | | | — | | | — | | | 5 | | | |
Natural-gas pipelines | | 6 | | | — | | | — | | | 1 | | | |
Crude-oil pipelines | | 3 | | | 1 | | | — | | | 3 | | | |
|
| | | | | | | | | | | | |
| | | Owned and Operated | | Operated Interests | | Non-Operated Interests | | Equity Interests |
| Gathering systems | | 12 |
| | 3 |
| | 3 |
| | 2 |
|
| Treating facilities | | 19 |
| | 3 |
| | — |
| | 3 |
|
| Natural gas processing plants/trains | | 19 |
| | 5 |
| | — |
| | 2 |
|
| NGL pipelines | | 2 |
| | — |
| | — |
| | 3 |
|
| Natural gas pipelines | | 5 |
| | — |
| | — |
| | — |
|
| Oil pipelines | | — |
| | 1 |
| | — |
| | 1 |
|
These assets and investments are located in Texas, New Mexico, the Rocky Mountains (Colorado, Utah, and Wyoming), North-central Pennsylvania and Texas. During the second quarter of 2017, the Partnership commenced operation of two produced-water disposal systems in West Texas, which are included within Gathering systems in the table above. Train VI, an additional processing plant at the DBM complex, is expected to commence operations during the fourth quarter of 2017.North-central Pennsylvania.
WESTERN GASMIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION (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)
| | |
Marcellus Interest systems | | 33.75 | % |
Newcastle system | | 50 | % |
Springfield system | | 50.1 | % |
Full consolidation | | |
Chipeta (3)
| | 75 | % |
DBJV system (4)
| | 100 | % |
| |
(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. |
| |
(4)
| The Partnership acquired an additional 50% interest in the DBJV system (the “Additional DBJV System Interest”) from a third party on March 17, 2017. See Note 2.
|
The consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”). The consolidated financial statements and include the accounts of the Partnership and entities in which it holds a controlling financial interest.interest, including WES Operating, WES Operating GP, proportionately consolidated interests, and equity investments (see table below). All significant intercompany transactions have been eliminated.
The following table outlines the ownership interests and the accounting method of consolidation used in the consolidated financial statements for entities not wholly owned (see Note 7):
| | | | | | | | |
| | Percentage Interest |
| Full consolidation | | |
Chipeta (1) | | 75.00 | % |
Proportionate consolidation (2) | | |
| Springfield system | | 50.10 | % |
| Marcellus Interest systems | | 33.75 | % |
Equity investments(3) | | |
| Mi Vida JV LLC (“Mi Vida”) | | 50.00 | % |
| Front Range Pipeline LLC (“FRP”) | | 33.33 | % |
| Red Bluff Express Pipeline, LLC (“Red Bluff Express”) | | 30.00 | % |
| Enterprise EF78 LLC (“Mont Belvieu JV”) | | 25.00 | % |
| Rendezvous Gas Services, LLC (“Rendezvous”) | | 22.00 | % |
| Texas Express Pipeline LLC (“TEP”) | | 20.00 | % |
| Texas Express Gathering LLC (“TEG”) | | 20.00 | % |
| Whitethorn Pipeline Company LLC (“Whitethorn LLC”) | | 20.00 | % |
| Saddlehorn Pipeline Company, LLC (“Saddlehorn”) | | 20.00 | % |
| Panola Pipeline Company, LLC (“Panola”) | | 15.00 | % |
| White Cliffs Pipeline, LLC (“White Cliffs”) | | 10.00 | % |
(1)The 25% third-party interest in Chipeta Processing LLC (“Chipeta”) is reflected within noncontrolling interests in the consolidated financial statements. See Noncontrolling interests below.
(2)The Partnership proportionately consolidates its associated share of the assets, liabilities, revenues, and expenses attributable to these assets.
(3)Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method of accounting. “Equity-investment throughput” refers to the Partnership’s share of average throughput for these investments.
Certain information and note disclosures commonly included in annual financial statements have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, the accompanying consolidated financial statements and notes should be read in conjunction with the Partnership’s 20162022 Form 10-K, as filed with the SEC on February 23, 2017.22, 2023. Management believes that the disclosures made are adequate to make the information not misleading.
PresentationThe consolidated financial results of WES Operating are included in the Partnership’s consolidated financial statements. Throughout these notes to consolidated financial statements, and to the extent material, any differences between the consolidated financial results of the Partnership assets.and WES Operating are discussed separately. The term “Partnership assets” includes bothPartnership’s consolidated financial statements differ from those of WES Operating primarily as a result of (i) the assets ownedpresentation of noncontrolling interest ownership (see Noncontrolling interests below), (ii) the elimination of WES Operating GP’s investment in WES Operating with WES Operating GP’s underlying capital account, (iii) the general and the interests accounted for under the equity method (see Note 7)administrative expenses incurred by the Partnership, aswhich are separate from, and in addition to, those incurred by WES Operating, (iv) the inclusion of September 30, 2017. Because Anadarko controlsthe impact of Partnership equity balances and Partnership distributions, and (v) transactions between 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.
WES Operating that eliminate upon consolidation.
WESTERN GASMIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION (CONTINUED)
For those periods requiring recast, the consolidated financial statements for periods prior toPresentation of the Partnership’s acquisition ofassets. The Partnership’s assets include assets owned and ownership interests accounted for by the Partnership assets from Anadarko are prepared from Anadarko’s historical cost-basis accountsunder the equity method of accounting, through its 98.0% partnership interest in WES Operating, as of September 30, 2023 (see Note 7). The Partnership also owns and may not necessarily be indicative ofcontrols 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 toentire non-economic general partner interest in WES Operating GP, and the Partnership’s acquisition of the Partnership assetsgeneral partner is not allocated to the limited partners.owned by Occidental.
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.reasonable methods. 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 furnishedincluded 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.statements.
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,Noncontrolling interests. The Partnership’s noncontrolling interests in the consolidated balance sheetsfinancial statements consist of (i) the 25% third-party interest in Chipeta and presented as capital expenditures(ii) the 2.0% limited partner interest in WES Operating owned by an Occidental subsidiary. WES Operating’s noncontrolling interest in the consolidated financial statements consists of cash flows. With respectthe 25% third-party interest in Chipeta. See Note 5.
Segments. The Partnership’s operations continue to business interruption insurance claims, income is recognized only when cash proceeds are received from insurers,be organized into a single operating segment, the assets of which are presentedgather, compress, treat, process, and transport natural gas; gather, stabilize, and transport condensate, NGLs, and crude oil; and gather and dispose of produced water in the consolidated statements of operations as a component of Operating income (loss).United States.
On December 3, 2015, there was an initial fire and secondary explosion at the processing facility within the Delaware Basin Midstream, LLC (“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. During the quarter ended March 31, 2017, a $5.7 million loss was recorded in Gain (loss) on divestiture and other, net in the consolidated statements of operations, related to a change in the Partnership’s estimate of the amount that would be recovered under the property insurance claim based on further discussions with insurers. During the second quarter of 2017, the Partnership reached a settlement with insurers and final proceeds were received. As of September 30, 2017, and December 31, 2016, the consolidated balance sheets include receivables of zero and $30.0 million, respectively, for the property insurance claim related to the incident at the DBM complex.
Equity-based compensation. During the nine months ended September 30, 2017,2023, the Partnership received $52.9issued 832,707 common units under its long-term incentive plans. Compensation expense was $7.2 million in cash proceeds from insurers in final settlement ofand $22.0 million for the Partnership’s claims related tothree and nine months ended September 30, 2023, respectively, and $6.4 million and $19.0 million for the incident at the DBM complex, including $29.9 million in proceeds from business interruption insurance claimsthree and $23.0 million in proceeds from property insurance claims.nine months ended September 30, 2022, respectively.
WESTERN GASMIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
2. REVENUE FROM CONTRACTS WITH CUSTOMERS
1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION (CONTINUED)
The following table summarizes revenue from contracts with customers:
Recently adopted accounting standards. Accounting Standards Update (“ASU”) 2017-01, Business Combinations (Topic 805): Clarifying | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | |
| thousands | | 2023 | | 2022 | | 2023 | | 2022 | | |
| Revenue from customers | | | | | | | | | | |
| Service revenues – fee based | | $ | 695,547 | | | $ | 666,555 | | | $ | 2,004,920 | | | $ | 1,954,105 | | | |
| Service revenues – product based | | 48,446 | | | 91,356 | | | 142,212 | | | 202,721 | | | |
| Product sales | | 31,652 | | | 79,430 | | | 100,336 | | | 314,755 | | | |
| Total revenue from customers | | 775,645 | | | 837,341 | | 2,247,468 | | | 2,471,581 | | |
| Revenue from other than customers | | | | | | | | | | |
| | | | | | | | | | |
| Other | | 368 | | | 227 | | | 800 | | | 703 | | | |
| Total revenues and other | | $ | 776,013 | | | $ | 837,568 | | | $ | 2,248,268 | | | $ | 2,472,284 | | | |
Contract balances. Receivables from customers, which are included in Accounts receivable, net on the Definitionconsolidated balance sheets were $610.1 million and $545.0 million as of a Business assists in determining whether a transaction should be accounted for as an acquisition or disposal ofSeptember 30, 2023, and December 31, 2022, respectively.
Contract assets or a business. This ASU 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 assets will not be considered a business. If the screen is not met, the assets must include an input and a substantive process that together significantly contributeprimarily relate to the ability to create an output to be considered a business. The Partnership’s adoption of this ASU on January 1, 2017, using a prospective approach, could have a material impact on future consolidated financial statements as goodwill will not be allocated to divestitures or recorded on acquisitions that are not considered 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. The Partnership adopted this ASU on January 1, 2017, using a modified retrospective approach, with no impact to its consolidated financial statements.
New accounting standards issued(i) revenue accrued but not yet adopted.ASU 2016-18, Statement billed under cost-of Cash Flows (Topic 230): Restricted Cash requires an entity-service contracts with fixed and variable fees and (ii) accrued deficiency fees the Partnership expects 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 tocharge customers once the related captionsperformance periods are completed. The following table summarizes activity related to contract assets from contracts with customers:
| | | | | | | | | | |
| | |
| | | | |
| thousands | | | | |
| Contract assets balance at December 31, 2022 | | $ | 22,561 | | | |
Amounts transferred to Accounts receivable, net that were included in the contract assets balance at the beginning of the period (1) | | (4,089) | | | |
Additional estimated revenues recognized (2) | | 6,477 | | | |
| | | | |
| Contract assets balance at September 30, 2023 | | $ | 24,949 | | | |
| | | | |
| | |
| | | | |
| Contract assets at September 30, 2023 | | | | |
| Other current assets | | $ | 7,850 | | | |
| Other assets | | 17,099 | | | |
| Total contract assets from contracts with customers | | $ | 24,949 | | | |
(1)Includes $(1.4) million for the balance sheet whenthree months ended September 30, 2023.
(2)Includes $(0.9) million for 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 will adopt this ASU on January 1, 2018, and does not expect the adoption to have a material impact on its consolidated financial statements.three months ended September 30, 2023.
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 will adopt this ASU on January 1, 2018, and does not expect the adoption 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. The Partnership plans to elect certain practical expedients when implementing the new lease standard, which means the Partnership will not have to reassess the accounting for contracts that commenced prior to adoption. The Partnership has preliminarily determined its portfolio of leased assets and is reviewing all related contracts to determine the impact that adoption will have on its consolidated financial statements. The Partnership is also evaluating the impact of this ASU on its systems, processes, and internal controls. The Partnership will complete its evaluation in 2018 and adopt this new standard on January 1, 2019, using a modified retrospective approach for all comparative periods presented.
WESTERN GASMIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
2. REVENUE FROM CONTRACTS WITH CUSTOMERS
1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION (CONTINUED)
Contract liabilities primarily relate to (i) fixed and variable fees under cost-of-service contracts that are received from customers for which revenue recognition is deferred, (ii) aid-in-construction payments received from customers that must be recognized over the expected period of customer benefit, and (iii) fees that are charged to customers for only a portion of the contract term and must be recognized as revenues over the expected period of customer benefit. The following table summarizes activity related to contract liabilities from contracts with customers:
ASU 2014-09, | | | | | | | | | | |
| | |
| | | | |
| thousands | | | | |
| Contract liabilities balance at December 31, 2022 | | $ | 369,285 | | | |
Cash received or receivable, excluding revenues recognized during the period (1) | | 59,649 | | | |
| | | | |
Revenues recognized that were included in the contract liability balance at the beginning of the period (2) | | (16,859) | | | |
| | | | |
| Contract liabilities balance at September 30, 2023 | | $ | 412,075 | | | |
| | | | |
| | |
| | | | |
| Contract liabilities at September 30, 2023 | | | | |
| Accrued liabilities | | $ | 14,888 | | | |
| Other liabilities | | 397,187 | | | |
| Total contract liabilities from contracts with customers | | $ | 412,075 | | | |
(1)Includes $18.4 million for the three months ended September 30, 2023.
(2)Includes $(3.0) million for the three months ended September 30, 2023.
Transaction price allocated to remaining performance obligations. Revenues expected to be recognized from certain performance obligations that are unsatisfied (or partially unsatisfied) as of September 30, 2023, are presented in the following table. The Partnership applies the optional exemptions in Revenue from Contracts with Customers (Topic 606)supersedes current revenue recognition requirements and requiresdoes not disclose consideration for remaining performance obligations with an entityoriginal expected duration of one year or less or for variable consideration related to recognize revenue when it transfers promised goods or services tounsatisfied (or partially unsatisfied) performance obligations. Therefore, the following table represents only a portion of expected future revenues from existing contracts as most future revenues from customers are dependent on future variable customer volumes and, in an amount that reflects the consideration the entity expects to be entitled to in exchangesome cases, variable commodity prices 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. While the Partnership does not currently expect net income to be materially impacted, it has concluded that it is acting as an agent in the sale of certain volumes on behalf of its customers based on the requirements of the new ASU. This conclusion will result in the reduction of natural gas and natural gas liquids sales revenues and a corresponding reduction to cost of product expense related to its contracts with these customers. In addition, the Partnership expects to recognize revenue for commodities received as noncash consideration in exchange for services provided and revenue and associated cost of product expense for the subsequent sale of those same commodities. This recognition will result in an increase to revenues for gathering and processing activities and cost of product expense with no impact on net income. The Partnership expects to recognize additional revenues for certain customer contributions related to capital cost recoveries that were previously accounted for as a reduction to capitalized property, plant and equipment. The Partnership also expects changes in the timing of recognizing revenue for certain fees due to the fee structure of certain contracts. The Partnership continues to evaluate the impact of these and other provisions of the ASU on its accounting policies, internal controls, and consolidated financial statements. Although the Partnership has not finalized the quantitative impact of the new standard, based on the assessment completed to date, the Partnership does not expect the adoption of this standard will have a material impact on its net income. The Partnership will complete its evaluation during the fourth quarter of 2017 and will adopt this new standard on January 1, 2018, using the modified retrospective method with a cumulative adjustment to equity and partners’ capital.volumes.
| | | | | | | | |
| thousands | | |
| Remainder of 2023 | | $ | 275,996 | |
| 2024 | | 1,147,263 | |
| 2025 | | 1,098,627 | |
| 2026 | | 993,997 | |
| 2027 | | 904,146 | |
| Thereafter | | 2,455,565 | |
| Total | | $ | 6,875,594 | |
WESTERN GASMIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
2.3. ACQUISITIONS AND DIVESTITURES
The following table presents the acquisitions completed by the Partnership during 2017 and 2016, and identifies the funding sources for such acquisitions:
|
| | | | | | | | | | | | | | | | | | | |
| thousands except unit and percent amounts | | Acquisition Date | | Percentage
Acquired | | Borrowings | | Cash On Hand | | Common Units Issued | | Series A Preferred Units Issued |
Springfield system (1) | | 03/14/2016 | | 50.1 | % | | $ | 247,500 |
| | $ | — |
| | 2,089,602 |
| | 14,030,611 |
|
DBJV system (2) | | 03/17/2017 | | 50 | % | | — |
| | 155,000 |
| | — |
| | — |
|
| |
(1)
| 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)
| The Partnership acquired the Additional DBJV System Interest from a third party. See Property exchange below.
|
Property exchange. On March 17, 2017,Ranch Westex. In September 2022, the Partnership acquired the Additional DBJV System Interestremaining 50% interest in Ranch Westex JV LLC (“Ranch Westex”) from a third party in exchange for (a)$40.1 million. Subsequent to the Partnership’s 33.75% non-operated interest in two natural gas gathering systems located in northern Pennsylvania (the “Non-Operated Marcellus Interest”), commonly referred to asacquisition, (i) the LibertyPartnership is the sole owner and Rome systems, and (b) $155.0 million of cash consideration (collectively, the “Property Exchange”). The Partnership previously held a 50% interest in, and operated, the DBJV system.
The Property Exchange is reflected as a nonmonetary transaction whereby the acquired Additional DBJV System Interest is recorded at the fair valueoperator of the divested Non-Operated Marcellus Interest plusasset, (ii) Ranch Westex is no longer accounted for under the $155.0 millionequity method of cash consideration. The Property Exchange resulted in a net gainaccounting, and (iii) the Ranch Westex processing plant is included as part of $125.7 million recorded as Gain (loss) on divestiture and other, net in the consolidated statementsoperations of operations. Results of operations attributablethe West Texas complex.
See also Note 12 for information related to the Property Exchange were included in the Partnership’s consolidated statementacquisition of operations beginningMeritage Midstream Services II, LLC (“Meritage”) that closed on the acquisition date in the first quarter of 2017.October 13, 2023.
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
2. ACQUISITIONS AND DIVESTITURES (CONTINUED)
DBJV acquisition - Deferred purchase price obligation - Anadarko.Prior to the Partnership’sPartnership distributions. Under its partnership agreement, with Anadarko to settle its deferred purchase price obligation early, the consideration that would have been paid by the Partnership for the March 2015 acquisition of Delaware Basin JV Gathering LLC (“DBJV”) from Anadarko, consisted of a cash payment to Anadarko due on March 31, 2020. The cash payment would have been 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 was defined as all revenues less cost of product, operating expenses and property taxes, in each case attributable to DBJV on an accrual basis. In May 2017, the Partnership reached an agreement with Anadarko to settle this obligation whereby the Partnership made a cash payment to Anadarko of $37.3 million, equal to the estimated net present value of the obligation at March 31, 2017.
The following table summarizes the financial statement impact of the Deferred purchase price obligation - Anadarko:
|
| | | | | | | | |
| | | Deferred purchase price obligation - Anadarko | | Estimated future payment obligation (1) |
| Balance at December 31, 2016 | | $ | 41,440 |
| | $ | 56,455 |
|
Accretion expense (2) | | 71 |
| | |
Revision to Deferred purchase price obligation – Anadarko (3) | | (4,165 | ) | | |
| Settlement of the Deferred purchase price obligation – Anadarko | | (37,346 | ) | | |
| Balance at September 30, 2017 | | $ | — |
| | $ | — |
|
| |
(1)
| Calculated using Level 3 inputs. |
| |
(2)
| Accretion expense was recorded as a charge to Interest expense in the consolidated statements of operations. |
| |
(3)
| Recorded as revisions within Common units in the consolidated balance sheet and consolidated statement of equity and partners’ capital. |
Helper and Clawson systems divestiture. During the second quarter of 2017, the Helper and Clawson systems, located in Utah, were sold to a third party, resulting in a net gain on sale of $16.4 million recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations.
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.
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
3. PARTNERSHIP DISTRIBUTIONS
The partnership agreement requires the Partnership to distributedistributes all of its available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date within 4555 days of the end offollowing each quarter. The Board of Directors of the Partnership’s general partner (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 |
| 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 | | 0.860 |
| | 170,657 |
| | February 2017 |
| 2017 | | | | | | |
| March 31 | | $ | 0.875 |
| | $ | 188,753 |
| | May 2017 |
| June 30 | | 0.890 |
| | 207,491 |
| | August 2017 |
September 30 (1) | | 0.905 |
| | 212,038 |
| | November 2017 |
| |
(1)
| The Board of Directors declared a cash distribution to the Partnership’s unitholders for the third quarter of 2017 of $0.905 per unit, or $212.0 million in aggregate, including incentive distributions, but excluding distributions on Class C units (see Class C unit distributions below). The cash distribution is payable on November 13, 2017, to unitholders of record at the close of business on November 2, 2017.
|
Available cash.quarter’s end. The amount of available cash (as(beyond proper reserves 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(i) to fund future capital expenditures; (ii) to comply with applicable laws, debt instruments, or other agreements; or (iii) to provide funds for unitholder 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, werearrangement and are intended to be repaid or refinanced within 12 months. In all cases, working capital borrowings are used solely for working capital purposes or to fund distributions to partners.unitholder distributions.
Class C unit distributions. The Class C units receive quarterlyBoard of Directors of the general partner (the “Board”) declared the following cash 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 March 1, 2020 (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 unitsunitholders for the ten days immediately precedingperiods presented:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
thousands except per-unit amounts Quarters Ended | | Total Quarterly
Per-unit
Distribution | | Total Quarterly
Cash Distribution | | Distribution
Date | | Record
Date |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| 2022 | | | | | | | | |
| March 31 | | $ | 0.500 | | | $ | 206,197 | | | May 13, 2022 | | May 2, 2022 |
| June 30 | | 0.500 | | | 197,744 | | | August 12, 2022 | | August 1, 2022 |
| September 30 | | 0.500 | | | 197,065 | | | November 14, 2022 | | October 31, 2022 |
| December 31 | | 0.500 | | | 196,569 | | | February 13, 2023 | | February 1, 2023 |
| 2023 | | | | | | | | |
March 31 (1) | | $ | 0.856 | | | $ | 336,987 | | | May 15, 2023 | | May 1, 2023 |
| June 30 | | 0.5625 | | | 221,442 | | | August 14, 2023 | | July 31, 2023 |
| September 30 | | 0.5750 | | | 223,432 | | | November 13, 2023 | | November 1, 2023 |
| | | | | | | | |
| | | | | | | | | |
(1)Includes the payment date forregular quarterly distribution of $0.500 per unit, or $196.8 million, as well as the commonEnhanced Distribution of $0.356 per 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. See Note 4 for further discussion of the Class C units.discussed below.
WESTERN GASMIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
3.4. PARTNERSHIP DISTRIBUTIONS (CONTINUED)
Series A Preferred unit distributions. As further described in Note 4,To facilitate the distribution of available cash, during 2022 the Partnership issued Series A Preferred units representingadopted a financial policy that provided for an additional distribution (“Enhanced Distribution”) to be paid in conjunction with the regular first-quarter distribution of the following year (beginning in 2023), in a target amount equal to Free cash flow generated in the prior year after subtracting Free cash flow used for the prior year’s debt repayments, regular-quarter distributions, and unit repurchases. This Enhanced Distribution is subject to Board discretion, the establishment of cash reserves for the proper conduct of the Partnership’s business and is also contingent on the attainment of prior year-end net leverage thresholds (the ratio of total principal debt outstanding less total cash on hand as of the end of such period, as compared to trailing-twelve-months Adjusted EBITDA), after taking the Enhanced Distribution for such prior year into effect. Free cash flow and Adjusted EBITDA are defined under the caption Reconciliation of Non-GAAP Financial Measures within Part I, Item 2 of this Form 10-Q. In April 2023, the Board approved an Enhanced Distribution of $0.356 per unit, or $140.1 million, related to the Partnership’s 2022 performance, which was paid in conjunction with the regular first-quarter 2023 distribution on May 15, 2023.
WES Operating partnership distributions. WES Operating makes quarterly cash distributions to the Partnership and WGR Asset Holding Company LLC (“WGRAH”), a subsidiary of Occidental, in proportion to their share of limited partner interests in WES Operating. See Note 5. WES Operating made and/or declared the Partnership to private investors in 2016. The Series A Preferred unitholders received quarterly distributions in cash equal to $0.68 per Series A Preferred unit, subject to certain adjustments. The following table summarizes the Series A Preferred unitholders’ cash distributions to its limited partners for the periods presented:
|
| | | | | | | | | | | |
thousands except per-unit amounts Quarters Ended | | Total Quarterly Distribution per Unit | | Total Quarterly Cash Distribution | | Date of Distribution |
| 2016 | | | | | | |
March 31 (1) | | $ | 0.68 |
| | $ | 1,887 |
| | May 2016 |
June 30 (2) | | 0.68 |
| | 14,082 |
| | August 2016 |
| September 30 | | 0.68 |
| | 14,907 |
| | November 2016 |
| December 31 | | 0.68 |
| | 14,908 |
| | February 2017 |
| 2017 | | | | | | |
| March 31 | | $ | 0.68 |
| | $ | 7,453 |
| | May 2017 |
| | | | | | | | | | | | | | | | | |
(1)thousands
Quarters Ended | | Total 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.
Cash Distribution | | Distribution
Date |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| 2022 | | | | |
| March 31 | | $ | 213,513 | | | May 2022 |
| June 30 | | 213,513 | | | August 2022 |
| September 30 | | 213,513 | | | November 2022 |
| December 31 | | 213,513 | | | February 2023 |
| 2023 | | | | |
(2)March 31 (1)
| Full quarterly per unit distribution on 14,030,611 Series A Preferred units and 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. | $ | 342,895 | | | May 2023 |
| June 30 | | 226,260 | | | August 2023 |
| September 30 | | 229,446 | | | November 2023 |
| | | | |
(1)Includes amounts related to the Enhanced Distribution discussed above.
On March 1, 2017, 50%
In addition to the distributions above, during the nine months ended September 30, 2023 and 2022, WES Operating made distributions of $130.1 million and $441.3 million, respectively, to the Partnership and WGRAH. The Partnership used its portion of the outstanding Series A Preferred units converted intodistributions to repurchase common units on a one-for-one basis, and on May 2, 2017, the remaining Series A Preferred units converted into common units on a one-for-one basis. Such converted common units were entitled to distributions made to common unitholders with respect to the quarter during which the applicable conversion occurred and did not include a prorated Series A Preferred unit distribution.units. See Note 5.
General partner interest and incentive distribution rights. As of September 30, 2017, 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 incentive distribution rights (“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.
4. EQUITY AND PARTNERS’ CAPITAL
Class C units. In November 2014, the Partnership issued 10,913,853 Class C units to Anadarko Midstream Holdings, LLC (“AMH”), pursuant to a Unit Purchase Agreement with Anadarko and AMH. The Class C units were issued to partially fund the acquisition of DBM.
When issued, the Class C units were scheduled to convert into common units on a one-for-one basis on December 31, 2017. In February 2017, Anadarko elected to extend the conversion date of the Class C units to March 1, 2020. The Partnership can elect to convert the Class C units earlier or Anadarko can extend the conversion date again.
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, 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 is 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 the extended conversion date of March 1, 2020, using the effective yield method. The impact of the beneficial conversion feature amortization is also included in the calculation of earnings per unit.
WESTERN GASMIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
4.5. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)
Series A Preferred units. In 2016, theHoldings of Partnership issued 21,922,831 Series A Preferred units to private investors. Pursuant to an agreement between the Partnership and the holders of the Series A Preferred units, 50% of the Series A Preferred units converted into common units on a one-for-one basis on March 1, 2017, and the remaining Series A Preferred units converted on a one-for-one basis on May 2, 2017. The Partnership has an effective registration statement with the SEC relating to the public resale of the common units issued upon conversion of the Series A Preferred units.
The Series A Preferred units were issued at a discount to the then-current market price of the common units into which they were convertible. This discount, totaling $93.4 million, represented a beneficial conversion feature, and at issuance, 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 Series A Preferred units on the date of issuance. The beneficial conversion feature was considered a non-cash distribution that was recognized from the date of issuance through the date of conversion, resulting in an increase in Series A Preferred unitholders’ capital and a decrease in common unitholders’ capital as amortized. The beneficial conversion feature was amortized using the effective yield method. The impact of the beneficial conversion feature amortization is also included in the calculation of earnings per unit. For the nine months ended September 30, 2017, the amortization for the beneficial conversion feature of the Series A Preferred units was $62.3 million.
Partnership interests.equity. The Partnership’s common units are listed on the New York Stock Exchange under the ticker symbol “WES.”
The following table summarizes the common, Class C, Series A Preferred and general partner units issued during the nine months ended As of September 30, 2017:
|
| | | | | | | | | | | | | | | |
| | | Common Units | | Class C Units | | Series A Preferred Units | | General Partner Units | | Total |
| Balance at December 31, 2016 | | 130,671,970 |
|
| 12,358,123 |
|
| 21,922,831 |
| | 2,583,068 |
|
| 167,535,992 |
|
| PIK Class C units | | — |
| | 619,510 |
| | — |
| | — |
| | 619,510 |
|
| Conversion of Series A Preferred units | | 21,922,831 |
| | — |
| | (21,922,831 | ) | | — |
| | — |
|
| Long-Term Incentive Plan award vestings | | 7,304 |
| | — |
| | — |
| | — |
| | 7,304 |
|
| Balance at September 30, 2017 | | 152,602,105 |
| | 12,977,633 |
| | — |
| | 2,583,068 |
| | 168,162,806 |
|
Holdings of Partnership equity. As of September 30, 2017, WGP2023, Occidental held 50,132,046185,181,578 common units, representing a 29.8%47.7% limited partner interest in the Partnership, and through its ownership of the general partner, WGPOccidental indirectly held 2,583,0689,060,641 general partner units, representing a 1.5%2.3% general partner interest in the Partnership, and 100% of the incentive distribution rights. As of September 30, 2017, other subsidiaries of Anadarko collectivelyPartnership. The public held 2,011,380194,334,791 common units, and 12,977,633 Class C units, representing an aggregate 9.0%a 50.0% limited partner interest in the Partnership.
Partnership equity repurchases.In 2022, the Board authorized the Partnership to buy back up to $1.25 billion of the Partnership’s common units through December 31, 2024 (the “$1.25 billion Purchase Program”). The common units may be purchased from time to time in the open market at prevailing market prices or in privately negotiated transactions. During the nine months ended September 30, 2023, the Partnership repurchased 5,387,322 common units, which includes 5,100,000 common units repurchased from Occidental, for an aggregate purchase price of $134.6 million. During the nine months ended September 30, 2022, the Partnership repurchased 17,982,357 common units, which includes 10,000,000 common units repurchased from Occidental, on the open market for an aggregate purchase price of $447.1 million. The units were canceled immediately upon receipt. As of September 30, 2017,2023, the public held 100,458,679 common units, representingPartnership had an authorized amount of $627.8 million remaining under the program.
Holdings of WES Operating equity. As of September 30, 2023, (i) the Partnership, directly and indirectly through its ownership of WES Operating GP, owned a 59.7%98.0% limited partner interest and the entire non-economic general partner interest in WES Operating and (ii) Occidental, through its ownership of WGRAH, owned a 2.0% limited partner interest in WES Operating, which is reflected as a noncontrolling interest within the Partnership.consolidated financial statements of the Partnership (see Note 1).
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
4. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)
NetPartnership’s net income (loss) per unit for common units. Netunit. The common and general partner unitholders’ allocation of 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 unitholders for purposes of calculating net income (loss) per common unit. Net income (loss) attributable to Western Gas Partners, LP earned on and subsequent to the date of acquisition of the Partnership assets is allocated as follows:
General partner. The general partner’s allocation is equal to cash distributions plus its portion of undistributed earnings or losses. Specifically, net income equal to the amount of available cash (as defined by the partnership agreement) is allocated to the general partner consistent with actual cash distributions and capital account allocations, including incentive distributions. 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 in accordance with its weighted-average ownership percentage during each period.
Series A Preferred unitholders. The Series A Preferred units were not considered a participating security as they only had distribution rights up to the specified per-unit quarterly distribution and had no rights to the Partnership’s undistributed earnings and losses. As such, the Series A Preferred unitholders’ allocation was equal to their cash distribution plus the amortization of the Series A Preferred units beneficial conversion feature (see Series A Preferred units above).
Common and Class C unitholders. The Class C units are considered a participating security because they participate in distributions with common units according to a predetermined formula (see Note 3). The common and Class C unitholders’ allocation is equal to their cash distributions plus their respective portionsallocations of undistributed earnings or losses. Specifically, net income equal to the amount of available cash (as defined by the partnership agreement) is allocated to the common and Class C unitholders consistent with actual cash distributions and capital account allocations. Undistributed earnings or undistributed losses are then allocated to the common and Class C unitholders in accordance with their respective weighted-averageweighted-average ownership percentagespercentage during each period. period using the two-class method.
The common unitholder allocation also includes the impact of the amortization of the Series A Preferred units and Class C units beneficial conversion features. The Class C unitholder allocation is similarly impacted by the amortization of the Class C units beneficial conversion feature (see Class C units above).
Calculation of net income (loss) per unit. BasicPartnership’s 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-averageweighted-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. Diluted net income (loss) per common unit is calculated by dividingincludes the sumeffect of (i)outstanding units issued under the Partnership’s long-term incentive plans.
The following table provides a reconciliation between basic and diluted net income (loss) attributable toper common units adjusted for distributions on the Series A Preferred units and a reallocation of the common and Class C limited partners’ interest inunit:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | |
| thousands except per-unit amounts | | 2023 | | 2022 | | 2023 | | 2022 | | |
| Net income (loss) | | | | | | | | | | |
| Limited partners’ interest in net income (loss) | | $ | 270,843 | | | $ | 259,501 | | | $ | 716,902 | | | $ | 860,985 | | | |
| Weighted-average common units outstanding | | | | | | | | | | |
| Basic | | 383,561 | | | 388,906 | | | 384,211 | | | 398,343 | | | |
| Dilutive effect of non-vested phantom units | | 1,211 | | | 1,412 | | | 1,133 | | | 1,202 | | | |
| Diluted | | 384,772 | | | 390,318 | | | 385,344 | | | 399,545 | | | |
| Excluded due to anti-dilutive effect | | 143 | | | 108 | | | 123 | | | 597 | | | |
| Net income (loss) per common unit | | | | | | | | | | |
| Basic | | $ | 0.71 | | | $ | 0.67 | | | $ | 1.87 | | | $ | 2.16 | | | |
| Diluted | | $ | 0.70 | | | $ | 0.66 | | | $ | 1.86 | | | $ | 2.15 | | | |
WES Operating’s net income (loss) assuming conversion of the Series A Preferred units intoper common units, and (ii) the netunit. Net income (loss) attributable to the Class C units as a participating security, by the sum of the weighted-average number ofper 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 Preferredunit for WES Operating is not calculated because it has no publicly traded units.
WESTERN GASMIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
6. RELATED-PARTY TRANSACTIONS
4. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)
Summary of related-party transactions. The following table illustratestables summarize material related-party transactions included in the Partnership’s calculationconsolidated financial statements:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated statements of operations | | | | | | | | | | |
| | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | |
| thousands | | 2023 | | 2022 | | 2023 | | 2022 | | |
| Revenues and other | | | | | | | | | | |
| Service revenues – fee based | | $ | 454,039 | | | $ | 431,944 | | | $ | 1,300,870 | | | $ | 1,275,474 | | | |
| Service revenues – product based | | (234) | | | 24,246 | | | 14,524 | | | 48,297 | | | |
| Product sales | | 9,818 | | | 20,323 | | | 38,597 | | | 38,232 | | | |
| Total revenues and other | | 463,623 | | | 476,513 | | | 1,353,991 | | | 1,362,003 | | | |
Equity income, net – related parties (1) | | 35,494 | | | 41,317 | | | 116,839 | | | 139,388 | | | |
| Operating expenses | | | | | | | | | | |
Cost of product (2) | | (37,083) | | | (7,771) | | | (56,214) | | | (39,462) | | | |
| Operation and maintenance | | 843 | | | 3,231 | | | 2,493 | | | 3,874 | | | |
General and administrative (3) | | 414 | | | 81 | | | 698 | | | 2,289 | | | |
| Total operating expenses | | (35,826) | | | (4,459) | | | (53,023) | | | (33,299) | | | |
| | | | | | | | | | |
(1)See Note 7.
(2)Includes related-party natural-gas and NGLs imbalances.
(3)Balances for the three and nine months ended September 30, 2022, include equity-based compensation expense allocated to the Partnership by Occidental, which is not reimbursed to Occidental and is reflected as a contribution to partners’ capital in the consolidated statements of net income (loss) per unit for common units:equity and partners’ capital.
| | | | | | | | | | | | | | |
| | | | |
| | |
| | | | |
| Consolidated balance sheets | | | | |
| thousands | | September 30,
2023 | | December 31,
2022 |
| Assets | | | | |
| Accounts receivable, net | | $ | 340,927 | | | $ | 313,937 | |
| Other current assets | | 461 | | | 1,578 | |
Equity investments (1) | | 915,076 | | | 944,696 | |
| Other assets | | 37,880 | | | 29,058 | |
| Total assets | | 1,294,344 | | | 1,289,269 | |
| Liabilities | | | | |
| Accounts and imbalance payables | | 34,307 | | | 32,150 | |
| Accrued liabilities | | 2,974 | | | 11,756 | |
Other liabilities (2) | | 323,562 | | | 268,399 | |
| Total liabilities | | 360,843 | | | 312,305 | |
(1)See Note 7.
(2)Includes contract liabilities from contracts with customers. See Note 2.
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| thousands except per-unit amounts | | 2017 | | 2016 | | 2017 | | 2016 |
| Net income (loss) attributable to Western Gas Partners, LP | | $ | 143,506 |
| | $ | 167,746 |
| | $ | 418,846 |
| | $ | 448,327 |
|
| Pre-acquisition net (income) loss allocated to Anadarko | | — |
| | — |
| | — |
| | (11,326 | ) |
Series A Preferred units interest in net (income) loss (1) | | — |
| | (25,539 | ) | | (42,373 | ) | | (50,989 | ) |
| General partner interest in net (income) loss | | (78,376 | ) | | (60,551 | ) | | (222,903 | ) | | (174,332 | ) |
| Common and Class C limited partners’ interest in net income (loss) | | $ | 65,130 |
| | $ | 81,656 |
| | $ | 153,570 |
| | $ | 211,680 |
|
Net income (loss) allocable to common units (1) | | $ | 57,448 |
| | $ | 70,204 |
| | $ | 132,545 |
| | $ | 181,388 |
|
Net income (loss) allocable to Class C units (1) | | 7,682 |
| | 11,452 |
| | 21,025 |
| | 30,292 |
|
| Common and Class C limited partners’ interest in net income (loss) | | $ | 65,130 |
| | $ | 81,656 |
| | $ | 153,570 |
| | $ | 211,680 |
|
| Net income (loss) per unit | | | | | | | | |
Common units – basic and diluted (2) | | $ | 0.38 |
| | $ | 0.54 |
| | $ | 0.91 |
| | $ | 1.39 |
|
| Weighted-average units outstanding | | | | | | | | |
| Common units – basic and diluted | | 152,602 |
| | 130,672 |
| | 145,371 |
| | 130,112 |
|
| Excluded due to anti-dilutive effect: | | | | | | | | |
Class C units (2) | | 12,873 |
| | 12,063 |
| | 12,660 |
| | 11,835 |
|
Series A Preferred units assuming conversion to common units (2) | | — |
| | 21,923 |
| | 7,227 |
| | 15,160 |
|
| |
(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 all periods presented. As of May 2, 2017, all Series A Preferred units were converted into common units on a one-for-one basis. |
WESTERN GASMIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
6. RELATED-PARTY TRANSACTIONS
5.
| | | | | | | | | | | | | | | | |
| Consolidated statements of cash flows | | | | | | |
| | |
| | Nine Months Ended
September 30, | | |
| thousands | | 2023 | | 2022 | | |
Distributions from equity-investment earnings – related parties | | $ | 115,897 | | | $ | 139,710 | | | |
| | | | | | |
| | | | | | |
| Contributions to equity investments – related parties | | (1,153) | | | (8,899) | | | |
| Distributions from equity investments in excess of cumulative earnings – related parties | | 31,715 | | | 41,058 | | | |
Distributions to Partnership unitholders (1) | | (382,438) | | | (272,797) | | | |
Distributions to WES Operating unitholders (2) | | (18,260) | | | (20,177) | | | |
| Net contributions from (distributions to) related parties | | — | | | 1,161 | | | |
| | | | | | |
| | | | | | |
Unit repurchases from Occidental (3) | | (127,500) | | | (252,500) | | | |
(1)Represents common and general partner unit distributions paid to Occidental pursuant to the partnership agreement of the Partnership (see Note 4 and Note 5).
(2)Represents distributions paid to Occidental, through its ownership of WGRAH, pursuant to WES Operating’s partnership agreement (see Note 4 and Note 5).
(3)Represents common units repurchased from Occidental (see Note 5).
The following tables summarize material related-party transactions for WES Operating (which are included in the Partnership’s consolidated financial statements) to the extent the amounts differ materially from the Partnership’s consolidated financial statements:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated statements of operations | | | | | | | | | | |
| | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | |
| thousands | | 2023 | | 2022 | | 2023 | | 2022 | | |
General and administrative (1) | | $ | 1,137 | | | $ | 795 | | | $ | 3,271 | | | $ | 4,662 | | | |
| | | | | | | | | | |
(1)Includes an intercompany service fee between the Partnership and WES Operating. Balances for the three and nine months ended September 30, 2022, include equity-based compensation expense allocated to WES Operating by Occidental, which is not reimbursed to Occidental and is reflected as a contribution to partners’ capital in the consolidated statements of equity and partners’ capital.
| | | | | | | | | | | | | | |
| | | | |
| | |
| | | | |
| Consolidated balance sheets | | | | |
| thousands | | September 30,
2023 | | December 31,
2022 |
| | | | |
| Other current assets | | $ | 408 | | | $ | 1,487 | |
| Other assets | | 36,193 | | | 28,459 | |
Accounts and imbalance payables (1) | | 50,204 | | | 76,131 | |
| Accrued liabilities | | 2,657 | | | 11,439 | |
(1)Includes balances related to transactions between the Partnership and WES Operating.
WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
6. RELATED-PARTY TRANSACTIONS WITH AFFILIATES
Affiliate transactions. Revenues | | | | | | | | | | | | | | | | | | | | |
| Consolidated statements of cash flows | | | | | | | | | | |
| | | | | | |
| | | | Nine Months Ended
September 30, | | |
| thousands | | | | | | 2023 | | 2022 | | |
Distributions to WES Operating unitholders (1) | | | | | | $ | (912,770) | | | $ | (1,008,572) | | | |
(1)Represents distributions paid to the Partnership and Occidental, through its ownership of WGRAH, pursuant to WES Operating’s partnership agreement. Includes distributions made from affiliatesWES Operating to the Partnership that were used by the Partnership to repurchase common units. See Note 4 and Note 5.
Related-party revenues. Related-party revenues include amounts earned by the Partnership from services provided to Anadarko as well asOccidental and from the sale of residuenatural gas, condensate, and NGLs to Anadarko. In addition,Occidental.
Gathering and processing agreements. The Partnership has significant gathering, processing, and produced-water disposal arrangements with affiliates of Occidental on most of its systems. While Occidental is the contracting counterparty of the Partnership, purchases naturalthese arrangements with Occidental include not just Occidental-produced volumes, but also, in some instances, the volumes of other working-interest owners of Occidental who rely on the Partnership’s facilities and infrastructure to bring their volumes to market. Natural-gas throughput (excluding equity-investment throughput) attributable to production owned or controlled by Occidental was 34% for both the three and nine months ended September 30, 2023, and 35% and 36% for the three and nine months ended September 30, 2022, respectively. Crude-oil and NGLs throughput (excluding equity-investment throughput) attributable to production owned or controlled by Occidental was 87% for both the three and nine months ended September 30, 2023, and 88% for both the three and nine months ended September 30, 2022. Produced-water throughput attributable to production owned or controlled by Occidental was 77% and 78% for the three and nine months ended September 30, 2023, respectively, and 75% and 80% for the three and nine months ended September 30, 2022, respectively.
The Partnership is currently discussing varying interpretations of certain contractual provisions with Occidental regarding the calculation of the cost-of-service rates under an oil-gathering contract related to the Partnership’s DJ Basin oil-gathering system. If such discussions are resolved in a manner adverse to the Partnership, such resolution could have a negative impact on the Partnership’s financial condition and results of operations, including a reduction in rates and a non-cash charge to earnings.
In connection with the sale of its Eagle Ford assets in 2017, Anadarko remained the primary counterparty to the Partnership’s Brasada gas processing agreement and entered into an agency relationship with Sanchez Energy Corporation (“Sanchez”), now Mesquite Energy, Inc. (“Mesquite”), that allowed Mesquite to process gas under such agreement. In December 2021, the Brasada gas processing agreement was assigned from an affiliate of Anadarko to Mesquite effective July 1, 2023. For this reason, Anadarko is not liable for any obligations under the Brasada gas processing agreement after June 30, 2023. For all periods presented, Mesquite performed Anadarko’s obligations under the Brasada gas processing agreement pursuant to its agency arrangement with Anadarko.
Further, in connection with the sale of its Uinta Basin assets in 2020, Kerr McGee Oil & Gas Onshore LP, a subsidiary of Occidental, retained the deficiency payment obligations under a gas purchase agreements. processing agreement at the Chipeta plant. This contingent payment obligation ended as of September 30, 2022.
Marketing Transition Services Agreement. During the year ended December 31, 2020, Occidental provided marketing-related services to certain of the Partnership’s subsidiaries (the “Marketing Transition Services Agreement”). While the Partnership still has some marketing agreements with affiliates of Occidental, on January 1, 2021, the Partnership began marketing and selling substantially all of its crude oil and residue gas, and a majority of its NGLs, directly to third parties.
WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
6. RELATED-PARTY TRANSACTIONS
Related-party expenses. Operation and maintenance expense includes amounts accrued for or paid to affiliatesrelated parties for field-related costs, shared field offices, and easements (see Related-party commercial agreement below) supporting 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.Partnership’s operations at certain assets. A portion of the Partnership’s general and administrative expensesexpense is paid by Anadarko,Occidental, which results in affiliaterelated-party transactions pursuant to the reimbursement provisions of the Partnership’s omnibus agreement. Affiliateand WES Operating’s agreements with Occidental. Cost of product expense includes amounts related to certain continuing marketing arrangements with affiliates of Occidental, related-party imbalances, and transactions with affiliates accounted for under the equity method of accounting. Related-party expenses do not bear ano direct relationship to affiliaterelated-party revenues, and third-partythird-party expenses do not bear ano direct relationship to third-partythird-party revenues. See Note 2
Services Agreement.Occidental performed certain centralized corporate functions for further information relatedthe Partnership and WES Operating pursuant to contributionsthe agreement dated as of assetsDecember 31, 2019, by and among Occidental, Anadarko, and WES Operating GP (“Services Agreement”). Most of the administrative and operational services previously provided by Occidental fully transitioned 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. PriorDecember 31, 2021, with certain limited transition services remaining in place pursuant to the Partnership’s acquisitionterms of the Partnership assets, third-party salesServices Agreement.
Construction reimbursement agreements and purchases and sales with related parties. From time 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 oftime, the Partnership assets. Subsequent to the acquisition of Partnership assets from Anadarko, transactions related to such assets are cash-settled directlyenters into construction reimbursement agreements 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. Concurrently with the closing of the Partnership’s May 2008 initial public offering,Occidental providing that the Partnership loaned $260.0 million to Anadarko in exchangewill manage the construction of certain midstream infrastructure 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 $313.2 million and $313.3 million at September 30, 2017, and December 31, 2016, 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.
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.
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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:
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| thousands | | 2017 | | 2016 | | 2017 | | 2016 |
Gains (losses) on commodity price swap agreements related to sales: (1) | | | | | |
| | |
| Natural gas sales | | $ | 6,284 |
| | $ | 719 |
| | $ | 12,022 |
| | $ | 12,962 |
|
| Natural gas liquids sales | | (7,210 | ) | | 15,939 |
| | (9,680 | ) | | 56,489 |
|
| Total | | (926 | ) | | 16,658 |
| | 2,342 |
| | 69,451 |
|
Gains (losses) on commodity price swap agreements related to purchases (2) | | (117 | ) | | (9,248 | ) | | (2,928 | ) | | (45,032 | ) |
| Net gains (losses) on commodity price swap agreements | | $ | (1,043 | ) | | $ | 7,410 |
| | $ | (586 | ) | | $ | 24,419 |
|
| |
(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. |
Revenues or costs attributable to volumes settled during 2016 and 2017 for the DJ Basin complex and 2017 for the MGR assets are recognized in the consolidated statements of operations at the applicable market price in the tables below. The Partnership also records a capital contribution from AnadarkoOccidental in the Partnership’s consolidated statementareas of equity and partners’ capitaloperation. Such arrangements generally provide for a reimbursement of costs incurred by the amount by which the swap price exceeds the applicable market price in the tables below. The commodity price swap agreement for the Hugoton system was in place until its divestiture in October 2016. For the nine months ended September 30, 2017, the capital contribution from Anadarko was $46.7 million. The tables below summarize the swap prices compared to the forward market prices:
|
| | | | | | | | | | | | |
| | | DJ Basin Complex |
| per barrel except natural gas | | 2016 - 2017 Swap Prices | | 2016 Market Prices (1) | | 2017 Market Prices (1) |
| Ethane | | $ | 18.41 |
| | $ | 0.60 |
| | $ | 5.09 |
|
| Propane | | 47.08 |
| | 10.98 |
| | 18.85 |
|
| Isobutane | | 62.09 |
| | 17.23 |
| | 26.83 |
|
| Normal butane | | 54.62 |
| | 16.86 |
| | 26.20 |
|
| Natural gasoline | | 72.88 |
| | 26.15 |
| | 41.84 |
|
| Condensate | | 76.47 |
| | 34.65 |
| | 45.40 |
|
| Natural gas (per MMBtu) | | 5.96 |
| | 2.11 |
| | 3.05 |
|
| |
(1)
| Represents the New York Mercantile Exchange (“NYMEX”) forward strip price as of December 8, 2015 and December 1, 2016, for the 2016 Market Prices and 2017 Market Prices, respectively, adjusted for product specification, location, basis and, in the case of NGLs, transportation and fractionation costs. |
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
5. TRANSACTIONS WITH AFFILIATES (CONTINUED)
|
| | | | | | | | |
| | | MGR Assets |
| per barrel except natural gas | | 2016 - 2017 Swap Prices | | 2017 Market Prices (1) |
| Ethane | | $ | 23.11 |
| | $ | 4.08 |
|
| Propane | | 52.90 |
| | 19.24 |
|
| Isobutane | | 73.89 |
| | 25.79 |
|
| Normal butane | | 64.93 |
| | 25.16 |
|
| Natural gasoline | | 81.68 |
| | 45.01 |
|
| Condensate | | 81.68 |
| | 53.55 |
|
| Natural gas (per MMBtu) | | 4.87 |
| | 3.05 |
|
| |
(1)
| Represents the NYMEX forward strip price as of December 1, 2016, adjusted for product specification, location, basis and, in the case of NGLs, transportation and fractionation costs. |
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 ownedcost or controlled by Anadarko was 33% and 34% for the three and nine months ended September 30, 2017, respectively, and 37% and 38% for the three and nine months ended September 30, 2016, respectively. The Partnership’s natural gas processing throughput (excluding equity investment throughput) attributable to production owned or controlled by Anadarko was 39% and 42% for the three and nine months ended September 30, 2017, respectively, and 51% and 55% for the three and nine months ended September 30, 2016, respectively. The Partnership’s crude, NGL and produced water gathering, treating and transportation throughput (excluding equity investment throughput) attributable to production owned or controlled by Anadarko was 54% and 50% for the three and nine months ended September 30, 2017, respectively, and 67% and 64% for the three and nine months ended September 30, 2016, respectively.cost-plus basis.
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 (see Note 2).
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
5. TRANSACTIONS WITH AFFILIATES (CONTINUED)
WES LTIP. The general partner awards phantom units under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (“WES LTIP”) primarily to its independent directors, but alsoAdditionally, 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 $0.1 million for each of the three months ended September 30, 2017 and 2016, and $0.3 million for each of the nine months ended September 30, 2017 and 2016.
WGP LTIP and Anadarko Incentive Plan. General and administrative expenses included $1.2 million and $3.2 million for the three and nine months ended September 30, 2017, respectively, and $1.4 million and $3.7 million for the three and nine months ended September 30, 2016, 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 Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan (“WGP LTIP”) and the Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan (“Anadarko Incentive Plan”). Of this amount, $3.3 million is reflected as contributions to partners’ capital in the Partnership’s consolidated statement of equity and partners’ capital for the nine months ended September 30, 2017.
Equipment purchases and sales. The following table summarizes the Partnership’s purchases from and sales to Anadarko of pipe and equipment:
|
| | | | | | | | | | | | | | | | |
| | | Nine Months Ended September 30, |
| | | 2017 | | 2016 | | 2017 | | 2016 |
| thousands | | Purchases | | Sales |
| Cash consideration | | $ | 3,910 |
| | $ | 3,965 |
| | $ | — |
| | $ | 623 |
|
| Net carrying value | | (5,283 | ) | | (3,366 | ) | | — |
| | (605 | ) |
| Partners’ capital adjustment | | $ | (1,373 | ) | | $ | 599 |
| | $ | — |
| | $ | 18 |
|
Contributions in aid of construction costs from affiliates. On certainsupport of the Partnership’s capital projects, Anadarko is obligated to reimbursebusiness, the Partnership for allpurchases and sells equipment, inventory, and other miscellaneous assets from or a portionto Occidental or its affiliates.
Related-party commercial agreement. During the first quarter of project capital expenditures. The majority2021, an affiliate of such arrangements are associated with projects related to pipeline construction activitiesOccidental 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 sectioncertain wholly owned subsidiaries of the Partnership’sPartnership entered into a Commercial Understanding Agreement (“CUA”). Under the CUA, certain West Texas surface-use and salt-water disposal agreements were amended to reduce usage fees owed by the Partnership in exchange for the forgiveness of certain deficiency fees owed by Occidental and other unrelated contractual amendments. The present value of the reduced usage fees under the CUA was $30.0 million at the time the agreement was executed. Also, as a result of the amendments under the CUA, these agreements are classified as operating leases and a $30.0 million right-of-use (“ROU”) asset, included in Other assets on the consolidated statementsbalance sheets, was recognized during the first quarter of cash flows.2021. The ROU asset is being amortized to Operation and maintenance expense through 2038, the remaining term of the agreements.
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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.
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| thousands | | 2017 | | 2016 | | 2017 | | 2016 |
Revenues and other (1) | | $ | 351,127 |
| | $ | 325,312 |
| | $ | 982,595 |
| | $ | 900,301 |
|
Equity income, net – affiliates (1) | | 21,519 |
| | 20,294 |
| | 62,708 |
| | 56,801 |
|
Cost of product (1) | | 22,902 |
| | 21,254 |
| | 60,497 |
| | 67,979 |
|
Operation and maintenance (2) | | 18,110 |
| | 15,052 |
| | 53,661 |
| | 50,688 |
|
General and administrative (3) | | 10,140 |
| | 9,453 |
| | 29,040 |
| | 27,574 |
|
| Operating expenses | | 51,152 |
| | 45,759 |
| | 143,198 |
| | 146,241 |
|
Interest income (4) | | 4,225 |
| | 4,225 |
| | 12,675 |
| | 12,675 |
|
Interest expense (5) | | — |
| | (1,173 | ) | | 71 |
| | (12,097 | ) |
Settlement of the Deferred purchase price obligation – Anadarko (6) | | — |
| | — |
| | (37,346 | ) | | — |
|
Proceeds from the issuance of common units, net of offering expenses (7) | | — |
| | — |
| | — |
| | 25,000 |
|
Distributions to unitholders (8) | | 118,082 |
| | 97,648 |
| | 331,654 |
| | 282,326 |
|
| Above-market component of swap agreements with Anadarko | | 18,049 |
| | 18,417 |
| | 46,719 |
| | 34,782 |
|
| |
(1)
| Represents amounts earned or incurred on and subsequent to the date of the acquisition of 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 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 Plan within this Note 5).
|
| |
(4)
| Represents interest income recognized on the note receivable from Anadarko. |
| |
(5)
| Includes amounts related to the Deferred purchase price obligation - Anadarko (see Note 2 and Note 9).
|
| |
(6)
| Represents the cash payment to Anadarko for the settlement of the Deferred purchase price obligation - Anadarko (see Note 2).
|
| |
(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).
|
Concentration of credit risk. AnadarkoCustomer concentration. Occidental was the only customer from whomwhich revenues exceeded 10% of the Partnership’s consolidated revenues for all periods presented in the consolidated statements of operations.
WESTERN GASMIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
6. PROPERTY, PLANT AND EQUIPMENT
A summary of the historical cost of the Partnership’s property, plant and equipment is as follows:
|
| | | | | | | | | | |
| thousands | | Estimated Useful Life | | September 30, 2017 | | December 31, 2016 |
| Land | | n/a | | $ | 4,271 |
| | $ | 4,012 |
|
| Gathering systems and processing complexes | | 3 to 47 years | | 6,972,302 |
| | 6,462,053 |
|
| Pipelines and equipment | | 15 to 45 years | | 139,344 |
| | 139,646 |
|
| Assets under construction | | n/a | | 434,432 |
| | 226,626 |
|
| Other | | 3 to 40 years | | 31,829 |
| | 29,605 |
|
| Total property, plant and equipment | | | | 7,582,178 |
| | 6,861,942 |
|
| Accumulated depreciation | | | | 2,074,464 |
| | 1,812,010 |
|
| Net property, plant and equipment | | | | $ | 5,507,714 |
| | $ | 5,049,932 |
|
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.During the nine months ended September 30, 2017, the Partnership recognized impairments of $170.1 million, including an impairment of $158.8 million at the Granger complex, which was impaired to its estimated fair value of $48.5 million using the income approach and Level 3 fair value inputs, due to a reduced throughput fee as a result of a producer’s bankruptcy. Also during the period, the Partnership recognized additional impairments of $11.3 million, primarily related to (i) a $3.7 million impairment at the Granger straddle plant, which was impaired to its estimated salvage value of $0.6 million using the income approach and Level 3 fair value inputs, (ii) a $3.1 million impairment of the Fort Union equity investment (see Note 7), (iii) a $2.0 million impairment of an idle facility in northeast Wyoming, which was impaired to its estimated salvage value of $0.4 million using the market approach and Level 3 fair value inputs, and (iv) the cancellation of a pipeline project in West Texas.
During 2016, the Partnership recognized impairments of $15.5 million, including 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.
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
7. EQUITY INVESTMENTS
The following table presents the activity infinancial statement impact of the Partnership’s equity investments for the nine months ended September 30, 2017:2023:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Equity Investments |
| thousands | Fort
Union | | White
Cliffs | | Rendezvous | | Mont
Belvieu JV | | TEG | | TEP | | FRP | | Total |
| Balance at December 31, 2016 | $ | 12,833 |
| | $ | 47,319 |
| | $ | 46,739 |
| | $ | 112,805 |
| | $ | 15,846 |
| | $ | 189,194 |
| | $ | 169,472 |
| | $ | 594,208 |
|
| Investment earnings (loss), net of amortization | 2,964 |
| | 9,984 |
| | 840 |
| | 20,430 |
| | 2,325 |
| | 13,332 |
| | 12,833 |
| | 62,708 |
|
Impairment expense (1) | (3,110 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (3,110 | ) |
| Contributions | — |
| | 277 |
| | — |
| | — |
| | — |
| | 107 |
| | — |
| | 384 |
|
| Distributions | (3,359 | ) | | (9,548 | ) | | (2,296 | ) | | (20,459 | ) | | (2,167 | ) | | (13,520 | ) | | (12,964 | ) | | (64,313 | ) |
Distributions in excess of cumulative earnings (2) | (1,662 | ) | | (2,325 | ) | | (1,616 | ) | | (2,316 | ) | | — |
| | (6,091 | ) | | (2,245 | ) | | (16,255 | ) |
| Balance at September 30, 2017 | $ | 7,666 |
| | $ | 45,707 |
| | $ | 43,667 |
| | $ | 110,460 |
| | $ | 16,004 |
| | $ | 183,022 |
| | $ | 167,096 |
| | $ | 573,622 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| thousands | | Balance at December 31, 2022 | | | | | | Equity
income, net | | Contributions | | Distributions | | Distributions in excess of cumulative earnings (1) | | | | Balance at September 30, 2023 |
| White Cliffs | | $ | 16,095 | | | | | | | $ | 1,495 | | | $ | — | | | $ | (1,120) | | | $ | (2,387) | | | | | $ | 14,083 | |
| Rendezvous | | 16,114 | | | | | | | (1,976) | | | — | | | (469) | | | (1,598) | | | | | 12,071 | |
| Mont Belvieu JV | | 91,310 | | | | | | | 16,549 | | | — | | | (16,577) | | | (3,103) | | | | | 88,179 | |
| TEG | | 15,856 | | | | | | | 3,183 | | | 700 | | | (3,200) | | | (976) | | | | | 15,563 | |
| TEP | | 184,687 | | | | | | | 28,579 | | | — | | | (28,767) | | | (9,239) | | | | | 175,260 | |
| FRP | | 192,716 | | | | | | | 34,785 | | | — | | | (34,916) | | | (4,447) | | | | | 188,138 | |
| Whitethorn LLC | | 146,595 | | | | | | | (3,295) | | | 132 | | | 3,579 | | | (1,083) | | | | | 145,928 | |
| Saddlehorn | | 104,191 | | | | | | | 17,597 | | | — | | | (17,253) | | | (2,722) | | | | | 101,813 | |
| Panola | | 19,311 | | | | | | | 1,844 | | | — | | | (1,974) | | | (169) | | | | | 19,012 | |
| Mi Vida | | 48,862 | | | | | | | 7,212 | | | — | | | (4,334) | | | (4,357) | | | | | 47,383 | |
| Red Bluff Express | | 108,959 | | | | | | | 10,866 | | | 321 | | | (10,866) | | | (1,634) | | | | | 107,646 | |
| Total | | $ | 944,696 | | | | | | | $ | 116,839 | | | $ | 1,153 | | | $ | (115,897) | | | $ | (31,715) | | | | | $ | 915,076 | |
| |
(1)
| Recorded in Impairments in the consolidated statements of operations. |
| |
(2)
| (1)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. |
The investment balance in Fort Union at September 30, 2017, is $3.1 million less than the Partnership’s underlying equity in Fort Union’s net assets due to an impairment loss recognized by the Partnership in the second quarterconsolidated statements of 2017 for its cash flows, are calculated on an individual-investment in Fort Union. This investment was impaired to its estimated fair value of $8.5 million, using the income approach and Level 3 fair value inputs.basis.
WESTERN GASMIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
8. PROPERTY, PLANT, AND EQUIPMENT
8.
A summary of the historical cost of property, plant, and equipment is as follows:
| | | | | | | | | | | | | | | | | | | | |
| | | | |
| | | | | | |
| thousands | | Estimated Useful Life | | September 30,
2023 | | December 31,
2022 |
| Land | | N/A | | $ | 11,383 | | | $ | 10,982 | |
| Gathering systems – pipelines | | 30 years | | 5,447,406 | | | 5,519,592 | |
| Gathering systems – compressors | | 15 years | | 2,369,219 | | | 2,266,410 | |
| Processing complexes and treating facilities | | 25 years | | 3,452,289 | | | 3,419,201 | |
| Transportation pipeline and equipment | | 3 to 48 years | | 192,289 | | | 174,241 | |
Produced-water disposal systems | | 20 years | | 1,063,184 | | | 932,627 | |
| Assets under construction | | N/A | | 443,272 | | | 263,353 | |
| Other | | 3 to 40 years | | 830,038 | | | 779,187 | |
| Total property, plant, and equipment | | | | 13,809,080 | | | 13,365,593 | |
| Less accumulated depreciation | | | | 5,144,678 | | | 4,823,993 | |
| Net property, plant, and equipment | | | | $ | 8,664,402 | | | $ | 8,541,600 | |
“Assets under construction” represents property that is not yet placed into productive service as of the respective balance sheet date and is excluded from capitalized costs being depreciated.
Long-lived asset impairments. During the nine months ended September 30, 2023, the Partnership recognized a long-lived asset impairment of $52.1 million for assets located in the Rockies due to a reduction in estimated future cash flows resulting from a contract termination notice received in the first quarter of 2023. This asset was impaired to its estimated fair value of $22.8 million. The fair value was measured using the income approach and Level-3 fair value inputs. The income approach was based on the Partnership’s projected future earnings before interest, taxes, depreciation, and amortization (“EBITDA”) and free cash flows, which requires significant assumptions including, among others, future throughput volumes based on current expectations of producer activity and operating costs.
WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
9. SELECTED COMPONENTS OF WORKING CAPITAL
A summary of accounts receivable, net is as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | The Partnership | | WES Operating |
| | | | |
| | | | | | | | |
| thousands | | September 30,
2023 | | December 31,
2022 | | September 30,
2023 | | December 31,
2022 |
| Trade receivables, net | | $ | 614,493 | | | $ | 548,859 | | | $ | 614,493 | | | $ | 548,859 | |
| Other receivables, net | | 343 | | | 5,404 | | | 323 | | | 5,404 | |
| Total accounts receivable, net | | $ | 614,836 | | | $ | 554,263 | | | $ | 614,816 | | | $ | 554,263 | |
|
| | | | | | | | |
| thousands | | September 30, 2017 | | December 31, 2016 |
| Trade receivables, net | | $ | 192,487 |
| | $ | 192,808 |
|
| Other receivables, net | | 43 |
| | 30,415 |
|
| Total accounts receivable, net | | $ | 192,530 |
| | $ | 223,223 |
|
A summary of other current assets is as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | The Partnership | | WES Operating |
| | | | |
| | | | | | | | |
| thousands | | September 30,
2023 | | December 31,
2022 | | September 30,
2023 | | December 31,
2022 |
| NGLs inventory | | $ | 3,019 | | | $ | 3,797 | | | $ | 3,019 | | | $ | 3,797 | |
| Imbalance receivables | | 3,659 | | | 32,658 | | | 3,659 | | | 32,658 | |
| Prepaid insurance | | 2,453 | | | 13,262 | | | 1,840 | | | 11,139 | |
| Contract assets | | 7,850 | | | 3,381 | | | 7,850 | | | 3,381 | |
| Other | | 14,495 | | | 6,408 | | | 14,440 | | | 6,316 | |
| Total other current assets | | $ | 31,476 | | | $ | 59,506 | | | $ | 30,808 | | | $ | 57,291 | |
|
| | | | | | | | |
| thousands | | September 30, 2017 | | December 31, 2016 |
| Natural gas liquids inventory | | $ | 8,459 |
| | $ | 7,126 |
|
| Imbalance receivables | | 2,103 |
| | 3,483 |
|
| Prepaid insurance | | 2,819 |
| | 2,257 |
|
| Total other current assets | | $ | 13,381 |
| | $ | 12,866 |
|
A summary of accrued liabilities is as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | The Partnership | | WES Operating |
| | | | |
| | | | | | | | |
| thousands | | September 30,
2023 | | December 31,
2022 | | September 30,
2023 | | December 31,
2022 |
| Accrued interest expense | | $ | 78,154 | | | $ | 110,486 | | | $ | 78,154 | | | $ | 110,486 | |
Short-term asset retirement obligations | | 3,453 | | | 10,493 | | | 3,453 | | | 10,493 | |
Short-term remediation and reclamation obligations | | 6,061 | | | 5,383 | | | 6,061 | | | 5,383 | |
| Income taxes payable | | 4,453 | | | 2,428 | | | 4,453 | | | 2,428 | |
| Contract liabilities | | 14,888 | | | 20,903 | | | 14,888 | | | 20,903 | |
| Accrued payroll and benefits | | 42,595 | | | 44,855 | | | — | | | — | |
| Other | | 40,379 | | | 60,092 | | | 38,720 | | | 47,596 | |
| Total accrued liabilities | | $ | 189,983 | | | $ | 254,640 | | | $ | 145,729 | | | $ | 197,289 | |
|
| | | | | | | | |
| thousands | | September 30, 2017 | | December 31, 2016 |
| Accrued interest expense | | $ | 45,616 |
| | $ | 39,826 |
|
| Short-term asset retirement obligations | | 3,976 |
| | 3,114 |
|
| Short-term remediation and reclamation obligations | | 630 |
| | 630 |
|
| Income taxes payable | | 1,024 |
| | 1,006 |
|
| Other | | 6,250 |
| | 532 |
|
| Total accrued liabilities | | $ | 57,496 |
| | $ | 45,108 |
|
WESTERN GASMIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
9.10. DEBT AND INTEREST EXPENSE
At September 30, 2017,WES Operating is the Partnership’sborrower for all outstanding 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”), 4.650% Senior Notes due 2026 (the “2026 Notes”) and borrowings onis expected to be the RCF.
borrower for all future debt issuances. The following table presents the Partnership’s outstanding debt as of September 30, 2017,debt:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | September 30, 2023 | | December 31, 2022 |
| thousands | | Principal | | Carrying
Value | | Fair Value (1) | | Principal | | Carrying
Value | | Fair Value (1) |
Short-term debt | | | | | | | | | | | | |
Floating-Rate Senior Notes due 2023 | | $ | — | | | $ | — | | | $ | — | | | $ | 213,138 | | | $ | 213,121 | | | $ | 214,823 | |
| | | | | | | | | | | | |
| Finance lease liabilities | | 2,268 | | | 2,268 | | | 2,268 | | | 2,659 | | | 2,659 | | | 2,659 | |
Total short-term debt | | $ | 2,268 | | | $ | 2,268 | | | $ | 2,268 | | | $ | 215,797 | | | $ | 215,780 | | | $ | 217,482 | |
| | | | | | | | | | | | |
Long-term debt | | | | | | | | | | | | |
| 3.100% Senior Notes due 2025 | | $ | 666,481 | | | $ | 664,844 | | | $ | 638,729 | | | $ | 730,706 | | | $ | 727,953 | | | $ | 692,491 | |
| 3.950% Senior Notes due 2025 | | 349,163 | | | 347,730 | | | 335,675 | | | 399,163 | | | 396,825 | | | 379,107 | |
| 4.650% Senior Notes due 2026 | | 467,204 | | | 465,566 | | | 448,890 | | | 474,242 | | | 472,161 | | | 452,201 | |
| 4.500% Senior Notes due 2028 | | 357,094 | | | 354,533 | | | 332,283 | | | 400,000 | | | 396,698 | | | 368,346 | |
| 4.750% Senior Notes due 2028 | | 382,888 | | | 380,644 | | | 358,230 | | | 400,000 | | | 397,340 | | | 368,141 | |
| 6.350% Senior Notes due 2029 | | 600,000 | | | 593,081 | | | 601,962 | | | — | | | — | | | — | |
| 4.050% Senior Notes due 2030 | | 1,104,593 | | | 1,097,358 | | | 964,553 | | | 1,200,000 | | | 1,191,345 | | | 1,053,038 | |
| 6.150% Senior Notes due 2033 | | 750,000 | | | 740,947 | | | 724,425 | | | — | | | — | | | — | |
| 5.450% Senior Notes due 2044 | | 600,000 | | | 593,992 | | | 484,524 | | | 600,000 | | | 593,878 | | | 503,742 | |
| 5.300% Senior Notes due 2048 | | 700,000 | | | 687,674 | | | 548,429 | | | 700,000 | | | 687,494 | | | 580,570 | |
| 5.500% Senior Notes due 2048 | | 350,000 | | | 342,880 | | | 278,674 | | | 350,000 | | | 342,783 | | | 291,194 | |
| 5.250% Senior Notes due 2050 | | 1,000,000 | | | 984,136 | | | 775,000 | | | 1,000,000 | | | 983,945 | | | 829,804 | |
| RCF | | — | | | — | | | — | | | 375,000 | | | 375,000 | | | 375,000 | |
| Finance lease liabilities | | 6,666 | | | 6,666 | | | 6,666 | | | 4,160 | | | 4,160 | | | 4,160 | |
Total long-term debt | | $ | 7,334,089 | | | $ | 7,260,051 | | | $ | 6,498,040 | | | $ | 6,633,271 | | | $ | 6,569,582 | | | $ | 5,897,794 | |
| | | | | | | | | | | | |
(1)Fair value is measured using the market approach and December 31, 2016:Level-2 fair value inputs.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | September 30, 2017 | | December 31, 2016 |
| thousands | | Principal | | Carrying Value | | Fair Value (1) | | Principal | | Carrying Value | | Fair Value (1) |
| 2021 Notes | | $ | 500,000 |
| | $ | 495,541 |
| | $ | 536,712 |
| | $ | 500,000 |
| | $ | 494,734 |
| | $ | 536,252 |
|
| 2022 Notes | | 670,000 |
| | 668,795 |
| | 693,789 |
| | 670,000 |
| | 668,634 |
| | 681,723 |
|
| 2018 Notes | | 350,000 |
| | 349,558 |
| | 351,770 |
| | 350,000 |
| | 349,188 |
| | 351,531 |
|
| 2044 Notes | | 600,000 |
| | 593,206 |
| | 634,283 |
| | 600,000 |
| | 593,132 |
| | 615,753 |
|
| 2025 Notes | | 500,000 |
| | 491,653 |
| | 503,322 |
| | 500,000 |
| | 490,971 |
| | 492,499 |
|
| 2026 Notes | | 500,000 |
| | 495,133 |
| | 525,069 |
| | 500,000 |
| | 494,802 |
| | 518,441 |
|
| RCF | | 250,000 |
| | 250,000 |
| | 250,000 |
| | — |
| | — |
| | — |
|
| Total long-term debt | | $ | 3,370,000 |
| | $ | 3,343,886 |
| | $ | 3,494,945 |
| | $ | 3,120,000 |
| | $ | 3,091,461 |
| | $ | 3,196,199 |
|
| |
(1)
| Fair value is measured using the market approach and Level 2 inputs. |
Debt activity. The following table presents the debt activity of the Partnership for the nine months ended September 30, 2017:
|
| | | | |
| thousands | | Carrying Value |
| Balance at December 31, 2016 | | $ | 3,091,461 |
|
| RCF borrowings | | 250,000 |
|
| Other | | 2,425 |
|
| Balance at September 30, 2017 | | $ | 3,343,886 |
|
Senior Notes. The 2018 Notes, which are due in August 2018, were classified as long-term debt on the consolidated balance sheet at September 30, 2017, as the Partnership has the ability and intent to refinance these obligations using long-term debt. At September 30, 2017, the Partnership was in compliance with all covenants under the indentures governing its outstanding notes.
Revolving credit facility. As of September 30, 2017, the Partnership had $250.0 million of outstanding RCF borrowings and $4.6 million in outstanding letters of credit, resulting in $945.4 million available for borrowing under the RCF, which matures in February 2020. As of September 30, 2017 and 2016, the interest rate on the outstanding RCF borrowings was 2.54% and 1.82%, respectively. The facility fee rate was 0.20% at September 30, 2017 and 2016. At September 30, 2017, the Partnership was in compliance with all covenants under the RCF.
WESTERN GASMIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
9.10. DEBT AND INTEREST EXPENSE (CONTINUED)
Debt activity. The following table presents the debt activity for the nine months ended September 30, 2023:
| | | | | | | | |
| thousands | | Carrying Value |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| Balance at December 31, 2022 | | $ | 6,785,362 | |
| RCF borrowings | | 470,000 | |
| Repayments of RCF borrowings | | (845,000) | |
| Issuance of 6.350% Senior Notes due 2029 | | 600,000 | |
| Issuance of 6.150% Senior Notes due 2033 | | 750,000 | |
| Repayment of Floating-Rate Senior Notes due 2023 | | (213,138) | |
| Repayment of 3.100% Senior Notes due 2025 | | (64,225) | |
| Repayment of 3.950% Senior Notes due 2025 | | (50,000) | |
| Repayment of 4.650% Senior Notes due 2026 | | (7,038) | |
| Repayment of 4.500% Senior Notes due 2028 | | (42,906) | |
| Repayment of 4.750% Senior Notes due 2028 | | (17,112) | |
| Repayment of 4.050% Senior Notes due 2030 | | (95,407) | |
| Finance lease liabilities | | 2,115 | |
| Other | | (10,332) | |
| Balance at September 30, 2023 | | $ | 7,262,319 | |
WES Operating Senior Notes. WES Operating issued the Fixed-Rate 3.100% Senior Notes due 2025, 4.050% Senior Notes due 2030, 5.250% Senior Notes due 2050, and the Floating-Rate Senior Notes due 2023 in January 2020. Including the effects of the issuance prices, underwriting discounts, and interest-rate adjustments, the effective interest rates of the Senior Notes due 2025, 2030, and 2050, were 3.290%, 4.169%, and 5.363%, respectively, at September 30, 2023, and were 3.790%, 4.671%, and 5.869%, respectively, at September 30, 2022. The effective interest rate of these notes is subject to adjustment from time to time due to a change in credit rating.
During the third quarter of 2023, WES Operating completed the public offering of $600.0 million in aggregate principal amount of 6.350% Senior Notes due 2029. Interest is payable semi-annually on January 15th and July 15th of each year, with the initial interest payment being due on January 15, 2024. Net proceeds from the offering were used to fund a portion of the aggregate purchase price for the Meritage acquisition (see Note 12), to pay related costs and expenses, and for general partnership purposes.
During the second quarter of 2023, WES Operating completed the public offering of $750.0 million in aggregate principal amount of 6.150% Senior Notes due 2033. Interest is payable semi-annually on April 1st and October 1st of each year, with the initial interest payment being due on October 1, 2023. Net proceeds from the offering were used to repay borrowings under the RCF and for general partnership purposes.
During the nine months ended September 30, 2023, WES Operating purchased and retired $276.7 million of certain of its senior notes via open-market repurchases and redeemed the total principal amount outstanding on the Floating-Rate Senior Notes due 2023 at par value with cash on hand (see Debt activity above). For the three and nine months ended September 30, 2023, a gain of $8.6 million and $15.4 million, respectively, was recognized for the early retirement of portions of these notes.
During the second quarter of 2022, WES Operating (i) redeemed the total principal amount outstanding of the 4.000% Senior Notes due 2022 at par value and (ii) purchased and retired $1.4 million of the 3.100% Senior Notes due 2025 via open-market repurchases.
As of September 30, 2023, WES Operating was in compliance with all covenants under the relevant governing indentures.
WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
10. DEBT AND INTEREST EXPENSE
Revolving credit facility. In April 2023, WES Operating (i) repaid all then-outstanding borrowings under its senior unsecured revolving credit facility (“RCF”) with proceeds from the 6.150% Senior Notes due 2033 offering, and (ii) entered into an amendment to its RCF to, among other things, extend the maturity date to April 2028 and provide for a maximum borrowing capacity up to $2.0 billion, expandable to a maximum of $2.5 billion, through the maturity date.
As of September 30, 2023, there were no outstanding borrowings and $5.1 million of outstanding letters of credit, resulting in $2.0 billion of available borrowing capacity under the RCF. As of September 30, 2023 and 2022, the interest rate on any outstanding RCF borrowings was 6.62% and 4.65%, respectively. The facility-fee rate was 0.20% and 0.25% at September 30, 2023 and 2022, respectively. As of September 30, 2023, WES Operating was in compliance with all covenants under the RCF.
Interest expense. The following table summarizes the amounts included in interest expense:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | |
| thousands | | 2023 | | 2022 | | 2023 | | 2022 | | |
| | | | | | | | | | |
Long-term and short-term debt | | $ | (83,177) | | | $ | (81,554) | | | $ | (249,416) | | | $ | (243,559) | | | |
| Finance lease liabilities | | (223) | | | (23) | | | (616) | | | (96) | | | |
| Commitment fees and amortization of debt-related costs | | (2,904) | | | (3,049) | | | (9,199) | | | (9,149) | | | |
| Capitalized interest | | 3,550 | | | 1,520 | | | 8,625 | | | 3,471 | | | |
| | | | | | | | | | |
| Interest expense | | $ | (82,754) | | | $ | (83,106) | | | $ | (250,606) | | | $ | (249,333) | | | |
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| thousands | | 2017 | | 2016 | | 2017 | | 2016 |
| Third parties | | | | | | | | |
| Long-term debt | | $ | (35,992 | ) | | $ | (31,612 | ) | | $ | (105,772 | ) | | $ | (87,711 | ) |
| Amortization of debt issuance costs and commitment fees | | (1,667 | ) | | (1,672 | ) | | (4,942 | ) | | (4,747 | ) |
| Capitalized interest | | 2,115 |
| | 1,343 |
| | 3,991 |
| | 4,674 |
|
| Total interest expense – third parties | | (35,544 | ) | | (31,941 | ) | | (106,723 | ) | | (87,784 | ) |
| Affiliates | | | | | | | | |
Deferred purchase price obligation – Anadarko (1) | | — |
| | 1,173 |
| | (71 | ) | | 12,097 |
|
| Total interest expense – affiliates | | — |
| | 1,173 |
| | (71 | ) | | 12,097 |
|
| Interest expense | | $ | (35,544 | ) | | $ | (30,768 | ) | | $ | (106,794 | ) | | $ | (75,687 | ) |
| |
(1)
| See Note 2 for a discussion of the Deferred purchase price obligation - Anadarko.
|
10.11. 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 September 30, 2023, and December 31, 2022, the consolidated balance sheets included $9.5 million and $7.4 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 Other liabilities. The majority of payments related to these obligations are expected to be made over the next year. See Note 9.
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 for which 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, that include, among other things, a revolving credit facility, other third-party long-term debt, obligations related to itsthe Partnership’s capital spending programs, as well as those of its unconsolidated affiliates. As of September 30, 2017, the Partnership had unconditionalpipeline and offload commitments, and various operating and finance leases. The payment obligations for servicesrelated to be rendered or products to be delivered in connection with itsthe Partnership’s capital projects of $143.3 million,spending programs, the majority of which is expected to be paid in the next twelve months. These commitments12 months, primarily relate primarily to expansion, construction, and asset-integrity projects at the DBJVWest Texas complex, DBM water systems, DBM oil system, and the DJ Basin and DBM complexes.complex.
Lease commitments. Anadarko, on behalf
WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
12. SUBSEQUENT EVENTS
Meritage. On October 13, 2023, the Partnership has entered into lease arrangementsclosed on the acquisition of Meritage for corporate offices, shared field offices and a warehouse supporting$885.0 million (subject to certain customary post-closing adjustments) funded with cash, including proceeds from the Partnership’s operations, $600.0 million senior note issuance in September 2023 (see Note 10) and equipment leases for which Anadarko chargesborrowings on the Partnership rent.RCF. The leasesacquisition expands the Partnership’s existing Powder River Basin asset base, increasing total natural-gas processing capacity in that region to 440 MMcf/d and includes a FERC regulated NGL pipeline that connects to the processing facility. Due to the timing, the initial purchase price accounting for the corporate offices and shared field offices extend through 2028 and 2033, respectively, andtransaction was not yet complete at the lease for the warehouse expired in February 2017.time of filing.
Rent expense associated with office, warehouse and equipment leases was $11.3 million and $30.7 million for the three and nine months ended September 30, 2017, respectively, and $8.9 million and $26.2 million for the three and nine months ended September 30, 2016, respectively.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion analyzes our financial condition and results of operations and should be read in conjunction with the Consolidated Financial Statements and Notes to Consolidated Financial Statements, wherein WES Operating is fully consolidated, and which are included under Part I, Item 1 of this quarterly report, as well as ourand the historical consolidated financial statements, and the notes thereto, which are included under Part II, Item 8 of our 2016the 2022 Form 10-K as filed with the SEC on February 23, 2017.22, 2023.
The Partnership’s assets include assets owned and ownership interests accounted for by us under the equity method of accounting, through our 98.0% partnership interest in WES Operating, as of September 30, 2023 (see Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q). We also own and control the entire non-economic general partner interest in WES Operating GP, and our general partner is owned by Occidental.
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
We have made in this Form 10-Q, and may from time to time make in other public filings, press releases, and statements by management, forward-lookingforward-looking statements concerning our operations, economic performance, and financial condition. These forward-lookingforward-looking statements include statements preceded by, followed by, or that otherwise include the words “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should”“should,” or similar expressions or variations on such expressions. These statements discuss future expectations, contain projections of results of operations or financial condition, or include other “forward-looking”“forward-looking” information.
Although we and our general partner believe that the expectations reflected in such forward-lookingour forward-looking statements are reasonable, neither we nor our general partner can giveprovide any assurance that such expectations will prove to have been correct. These forward-lookingforward-looking statements involve risks and uncertainties. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following:
•benefits of the Meritage acquisition;
•our ability to pay distributions to our unitholders;unitholders and the amount of such distributions;
•our and Anadarko’s assumptions about the energy market;
•future throughput (including AnadarkoOccidental production) whichthat is gathered or processed by, or transported through, our assets;
•our operating results;
•competitive conditions;
•technology;
•the availability of capital resources to fund acquisitions, capital expenditures, and other contractual obligations, and our ability to access those resources from Anadarko orfinancing through the debt or equity capital markets;
•the supply of, demand for, and price of oil, natural gas, NGLs, and related products or services;
our ability to mitigate exposure to the •commodity-price risks inherent in our percent-of-proceedspercent-of-proceeds, percent-of-product, keep-whole, and keep-whole contracts through the extension of our commodity price swap agreements with Anadarko, or otherwise;fixed-recovery processing contracts;
•weather and natural disasters;
•inflation;
•the availability of goods and services;
•general economic conditions, internationally, domestically, or in the jurisdictions in which we are doing business;
•federal, state, and local laws and state-approved voter ballot initiatives, including those laws or ballot initiatives that limit Anadarko and other producers’ hydraulic-fracturing activities or other oil and natural-gas development or operations;
•environmental liabilities;
•legislative or regulatory changes, including changes affecting our status as a partnership for federal income tax purposes;
•changes in the financial or operational condition of Anadarko;Occidental;
•the creditworthiness of AnadarkoOccidental or our other counterparties, including financial institutions, operating partners, and other parties;
•changes in Anadarko’sOccidental’s capital program, corporate strategy, or other desired areas of focus;
•our commitments to capital projects;
•our ability to use ouraccess liquidity under the RCF;
•our ability to repay debt;
•the resolution of litigation or other disputes;
•conflicts of interest among us and our general partner WGP and its general partner,related parties, including Occidental, with respect to, among other things, the allocation of capital and affiliates, including Anadarko;operational and administrative costs and our future business opportunities;
•our ability to maintain and/or obtain rights to operate our assets on land owned by third parties;
•our ability to acquire assets on acceptable terms from Anadarkothird parties;
•non-payment or third parties, and Anadarko’s ability to generate an inventorynon-performance of assets suitable for acquisition;
non-payment or non-performance of Anadarko or other significant customers, including under our gathering, processing, transportation, and transportation agreements and our $260.0 million note receivable from Anadarko;disposal agreements;
•the timing, amount, and terms of future issuances of equity and debt securities;
•the outcome of pending and future regulatory, legislative, or other proceedings or investigations, including the investigation by the National Transportation Safety Board (“NTSB”), related to Anadarko’s operations in Colorado, and continued or additional disruptions in operations that may occur as Anadarkowe and weour customers comply with any regulatory orders or other state or local changes in laws or regulations in Colorado;regulations;
•cyber attacks or security breaches; and
•other factors discussed below, in “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates” included in our 2016the 2022 Form 10-K, and10-K, in our quarterly reports on Form 10-Q,10-Q, and in our other public filings and press releases.
The riskRisk factors and other factors noted throughout or incorporated by reference in this Form 10-Q could cause actual results to differ materially from those contained in any forward-lookingforward-looking statement. Except as required by law, we undertake no obligation to publicly update or revise any forward-lookingforward-looking statements, whether as a result of new information, future events, or otherwise.
EXECUTIVE SUMMARY
We are a growth-oriented Delaware MLP formed by Anadarko to acquire, own, develop and operate midstream energy assets. We currently own or have investments in assets located in the Rocky Mountains (Colorado, Utah and Wyoming), North-central Pennsylvania and Texas. We arecompany organized as a publicly traded partnership, engaged in the business of gathering, compressing, treating, processing, and transporting natural gas; gathering, stabilizing, and transporting condensate, NGLs, and crude oil; and gathering and disposing of produced water. In our capacity as a natural-gas processor, we also buy and sell natural gas, NGLs, and condensate on behalf of ourselves and our customers under certain contracts. To provide superior midstream service, we focus on ensuring the reliability and performance of our systems, creating sustainable cost efficiencies, enhancing our safety culture, and protecting the environment. We provide these midstream services for Anadarko, as well as for third-party producersown or have investments in assets located in Texas, New Mexico, the Rocky Mountains (Colorado, Utah, and customers.Wyoming), and North-central Pennsylvania. As of September 30, 2017,2023, our assets and investments consisted of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Wholly
Owned and
Operated | | Operated
Interests | | Non-Operated
Interests | | Equity
Interests |
Gathering systems (1) | | 17 | | | 2 | | | 3 | | | 1 | |
| Treating facilities | | 37 | | | 3 | | | — | | | — | |
Natural-gas processing plants/trains | | 25 | | | 3 | | | — | | | 3 | |
| NGLs pipelines | | 2 | | | — | | | — | | | 5 | |
Natural-gas pipelines | | 6 | | | — | | | — | | | 1 | |
Crude-oil pipelines | | 3 | | | 1 | | | — | | | 3 | |
|
| | | | | | | | | | | | |
| | | Owned and Operated | | Operated Interests | | Non-Operated Interests | | Equity Interests |
| Gathering systems | | 12 |
| | 3 |
| | 3 |
| | 2 |
|
| Treating facilities | | 19 |
| | 3 |
| | — |
| | 3 |
|
| Natural gas processing plants/trains | | 19 |
| | 5 |
| | — |
| | 2 |
|
| NGL pipelines | | 2 |
| | — |
| | — |
| | 3 |
|
| Natural gas pipelines | | 5 |
| | — |
| | — |
| | — |
|
| Oil pipelines | | — |
| | 1 |
| | — |
| | 1 |
|
Significant financial and operational events during the nine months ended September 30, 2017,2023, included the following:
In March 2017, we acquired•WES Operating completed the Additional DBJV System Interestpublic offering of $600.0 million in aggregate principal amount of 6.350% Senior Notes due 2029. Net proceeds from the offering were used to fund a third party in exchangeportion of the aggregate purchase price for the Non-Operated Marcellus InterestMeritage acquisition, to pay related costs and $155.0 million of cash consideration, resulting in a net gain of $125.7 million.expenses, and for general partnership purposes. See AcquisitionsLiquidity and DivestituresCapital Resources within this Item 2 for additional information.
In May 2017,•On October 13, 2023, we reached an agreement with Anadarkoclosed on the acquisition of Meritage for $885.0 million (subject to settle the outstanding Deferred purchase price obligation - Anadarko, whereby we made a cash payment to Anadarko of $37.3 million during the second quarter of 2017.
On March 1, 2017, 50% of the outstanding Series A Preferred units converted into common units on a one-for-one basis,certain customary post-closing adjustments). See Acquisitions and on May 2, 2017, the remaining Series A Preferred units converted into common units on a one-for-one basis. See Equity OfferingsDivestitures within this Item 2 for additional information.
During•WES Operating completed the second quarterpublic offering of 2017, we commenced operation$750.0 million in aggregate principal amount of 6.150% Senior Notes due 2033. Net proceeds from this offering were used to repay borrowings under the DBM water systems (included within Gathering systems in the table above).
In June 2017, we closed on the sale of our HelperRCF and Clawson systems, which resulted in a net gain on divestiture of $16.4 million.for general partnership purposes. See AcquisitionsLiquidity and DivestituresCapital Resources within this Item 2 for additional information.
In February 2017, Anadarko elected to extend•WES Operating redeemed the conversion date$213.1 million total principal amount outstanding of the Class C unitsFloating-Rate Senior Notes due 2023 at par value with cash on hand.
•WES Operating purchased and retired $276.7 million of certain of its senior notes via open-market repurchases.
•Our third-quarter 2023 per-unit distribution of $0.5750 increased $0.0125 from December 31, 2017, to March 1, 2020.the second-quarter 2023 per-unit distribution of $0.5625.
We received $52.9•The Board approved an Enhanced Distribution of $0.356 per unit, or $140.1 million, in cash proceeds from insurers in final settlement of our claims related to the incidentour 2022 performance. This Enhanced Distribution was paid, along with our regular first-quarter 2023 distribution, on May 15, 2023, to our unitholders of record at the DBM complex, including $29.9 millionclose of business on May 1, 2023.
•We repurchased 5,387,322 common units, which includes 5,100,000 common units repurchased from Occidental, for business interruption insurance claims and $23.0 million for property insurance claims. See Liquidity and Capital Resources within this Item 2 for additional information.
an aggregate purchase price of $134.6 million.
We raised our distribution to $0.905 per unit for the third quarter of 2017, representing a 2% increase over the distribution for the second quarter of 2017 and a 7% increase over the distribution for the third quarter of 2016.
Throughput•Natural-gas throughput attributable to Western Gas Partners, LP for natural gas assetsWES totaled 3,4274,484 MMcf/d and 3,6104,283 MMcf/d for the three and nine months ended September 30, 2017,2023, respectively, representing a 16%5% increase and 8% decrease, respectively,a 2% increase compared to the same periods in 2016.three months ended June 30, 2023, and nine months ended September 30, 2022, respectively.
Throughput for crude, NGL
•Crude-oil and produced water assetsNGLs throughput attributable to WES totaled 209667 MBbls/d and 187635 MBbls/d for the three and nine months ended September 30, 2017,2023, respectively, representing a 13%7% increase and 1% increase, respectively, a 7% decreasecompared to the same periods in 2016.three months ended June 30, 2023, and nine months ended September 30, 2022, respectively.
Operating income (loss) was $179.5•Produced-water throughput attributable to WES totaled 1,079 MBbls/d and 994 MBbls/d for the three and nine months ended September 30, 2023, respectively, representing a 14% increase and a 20% increase compared to the three months ended June 30, 2023, and nine months ended September 30, 2022, respectively.
•Gross margin totaled $601.1 million and $525.5$1,689.0 million for the three and nine months ended September 30, 2017,2023, respectively, representing a 9% decreaseincrease and 0% change, respectively,a 1% decrease compared to the same periods in 2016.three months ended June 30, 2023, and nine months ended September 30, 2022, respectively. See Reconciliation of Non-GAAP Financial Measures within this Item 2.
•Adjusted gross margin attributable to Western Gas Partners, LP for natural-gas assets (as defined under the caption Key Performance MetricsReconciliation of Non-GAAP Financial Measures within this Item 2) averaged $0.97$1.26 per Mcf and $0.92$1.27 per Mcf for the three and nine months ended September 30, 2017,2023, respectively, representing an 18% and 12% increase, respectively,no change compared to the same periods in 2016.
three months ended June 30, 2023, and a 5% decrease compared to the nine months ended September 30, 2022.
•Adjusted gross margin for crude NGL-oil and produced waterNGLs assets (as defined under the caption Key Performance MetricsReconciliation of Non-GAAP Financial Measures within this Item 2) averaged $2.03$2.27 per Bbl and $2.05$2.49 per Bbl for the three and nine months ended September 30, 2017,2023, respectively, representing an 8%a 12% decrease and a 2% decrease, respectively,increase compared to the samethree months ended June 30, 2023, and nine months ended September 30, 2022, respectively.
•Adjusted gross margin for produced-water assets (as defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 2) averaged $0.84 per Bbl and $0.83 per Bbl for the three and nine months ended September 30, 2023, respectively, representing a 1% increase and a 12% decrease compared to the three months ended June 30, 2023, and nine months ended September 30, 2022, respectively.
The following table provides additional information on throughput for the periods in 2016.presented below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| | Three Months Ended | | Nine Months Ended | | | | |
| | | | | | | | |
| | September 30, 2023 | | June 30, 2023 | | Inc/
(Dec) | | September 30, 2023 | | September 30, 2022 | | Inc/
(Dec) | | | | |
| Throughput for natural-gas assets (MMcf/d) |
| Delaware Basin | | 1,674 | | | 1,592 | | | 5 | % | | 1,612 | | | 1,452 | | | 11 | % | | | | |
| DJ Basin | | 1,331 | | | 1,309 | | | 2 | % | | 1,316 | | | 1,328 | | | (1) | % | | | | |
| Equity investments | | 495 | | | 454 | | | 9 | % | | 458 | | | 490 | | | (7) | % | | | | |
| Other | | 1,151 | | | 1,061 | | | 8 | % | | 1,053 | | | 1,088 | | | (3) | % | | | | |
Total throughput for natural-gas assets | | 4,651 | | | 4,416 | | | 5 | % | | 4,439 | | | 4,358 | | | 2 | % | | | | |
| Throughput for crude-oil and NGLs assets (MBbls/d) |
| Delaware Basin | | 220 | | | 208 | | | 6 | % | | 211 | | | 196 | | | 8 | % | | | | |
| DJ Basin | | 68 | | | 66 | | | 3 | % | | 68 | | | 84 | | | (19) | % | | | | |
| Equity investments | | 347 | | | 323 | | | 7 | % | | 328 | | | 382 | | | (14) | % | | | | |
| Other | | 46 | | | 42 | | | 10 | % | | 41 | | | 38 | | | 8 | % | | | | |
Total throughput for crude-oil and NGLs assets | | 681 | | | 639 | | | 7 | % | | 648 | | | 700 | | | (7) | % | | | | |
| Throughput for produced-water assets (MBbls/d) |
| Delaware Basin | | 1,101 | | | 963 | | | 14 | % | | 1,014 | | | 848 | | | 20 | % | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Total throughput for produced-water assets | | 1,101 | | | 963 | | | 14 | % | | 1,014 | | | 848 | | | 20 | % | | | | |
| | | | | | | | | | | | | | | | |
Anadarko’s Colorado Response. Following a home explosionOUTLOOK
We expect our business to be affected by the below-described key trends and uncertainties. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove incorrect, our actual results may vary materially from expected results.
Impact of producer activity. Our business is primarily driven by the level of production of crude oil and natural gas by producers in Firestone, Colorado in April 2017, Anadarko took precautionary measuresour areas of operation. This activity, however, can be impacted negatively by, among other things, commodity-price fluctuations and operational challenges. Fluctuating crude-oil, natural-gas, and NGLs prices can reduce the level of our customers’ activities and change the allocation of capital within their own asset portfolios. Such fluctuations can also impact us directly to shut in all operated vertical wellsthe extent we take ownership of and sell certain volumes at the tailgate of our plants for our own account. During 2020, oil and natural-gas prices were negatively impacted by the worldwide macroeconomic downturn that followed the global outbreak of COVID-19. In 2021, prices began to increase and in the DJ Basinfirst quarter of 2022, commodity prices increased significantly in connection with the war in Ukraine. For example, the New York Mercantile Exchange (“NYMEX”) West Texas Intermediate crude-oil daily settlement prices during 2022 ranged from a high of $123.70 per barrel in March 2022 to conduct additional inspections. It subsequently testeda low of $71.02 per barrel in December 2022, and permanently plugged, abandoned, and capped all one-inch return lines associated with these wells. In May 2017,prices during the Colorado Oil & Gas Conservation Commission (“COGCC”) issuednine months ended September 30, 2023, ranged from a two-phase Noticelow of $66.74 per barrel in March 2023 to Operators (“NTO”) requiring all operators to inventory and integrity test existing flowlines within 1,000 feeta high of $93.68 per barrel in September 2023. Similar disruptions could occur as a building unit and abandon all inactive flowlines in such areas. During the third quarter, Anadarko substantially completed the requirementsconsequence of the NTO. In August 2017, following a three-month reviewcurrent conflict in the Middle East. The extent and duration of oil and gas operations, the Governor of Colorado announced several policy initiatives designed to enhance public safety, which are to be implemented over the next several months through rulemaking or legislation. Anadarko continues to work cooperatively with state regulators and others and is also cooperating with the NTSB in its investigation related to the incident.
Significant Item Affecting Comparability. 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 was to the liquid handling facilitiescommodity-price volatility, and the amine treating units atassociated direct and indirect impact on our business, cannot be predicted. To address the inletrisks posed by fluctuating commodity prices, we intend to continue evaluating the relevant price environments and adjust our capital spending plans to reflect our customers’ anticipated activity levels, while maintaining appropriate liquidity and financial flexibility.
Additionally, even when the commodity-price environments are favorable, our customers must manage numerous operational challenges, including severe weather disruptions, downstream and produced-water takeaway constraints, seismicity concerns, new regulatory requirements, and the ability to optimize the efficiency and results of large, complex drilling programs. Our producers’ ability to mitigate or manage such challenges can have a significant impact on the complex. Train II (with capacity of 100 MMcf/d) sustained the most damage of the processing trains and returnedvolumes available for us to service in December 2016. Train III (with capacitythe short term. For this reason, we strive to work proactively with our customers whenever possible to provide high levels of 200 MMcf/d)reliability on our systems and help them meet these operational challenges as they arise.
Impact of inflation and supply-chain disruptions. The U.S. economy has recently experienced minimal damage and returnedsignificant inflation relative to full servicehistorical precedent, from, among other things, supply-chain disruptions caused by, or governmental stimulus or fiscal policies adopted in May 2016. For ease of reference throughout the remainder of this Management’s Discussion and Analysis, the damageresponse to, the processing facilityCOVID-19 crisis and resulting lackin connection with the war in Ukraine. More specifically, the bottlenecks and disruptions from the lingering effects of processing capacitythe COVID-19 crisis have caused difficulties within the U.S. and associatedglobal supply chains, creating logistical delays along with labor shortages. Continued inflation has raised our costs for labor, materials, fuel, and services, which has increased our operating costs and capital expenditures. Increases in inflationary pressure could materially and negatively impact our financial statement impact is referredresults. To the extent permitted by regulations and escalation provisions in certain of our existing agreements, we have the ability to as the “DBM outage.” See Note 1—Descriptionrecover a portion of Business and Basis of Presentationincreased costs in the Notesform of higher fees.
Impact of interest rates. Short- and long-term interest rates increased during 2022, and have continued to Consolidated Financial Statementsincrease during 2023, resulting in increased interest expense on RCF borrowings. Any future increases in interest rates likely will result in additional increases in financing costs. As with other yield-oriented securities, our unit price could be impacted by our implied distribution yield relative to market interest rates. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest-rate environment could have an adverse impact on our unit price and our ability to issue additional equity, or increase the cost of issuing equity, to make acquisitions, to reduce debt, or for other purposes. However, we expect our cost of capital to remain competitive, as our competitors face similar interest-rate dynamics.
ACQUISITIONS AND DIVESTITURES
Meritage. On October 13, 2023, we closed on the acquisition of Meritage for $885.0 million (subject to certain customary post-closing adjustments) funded with cash, including proceeds from our $600.0 million senior note issuance in September 2023and borrowings on the RCF. See Note 12—Subsequent Events and Note 10—Debt and Interest Expense under Part I, Item 1 of this Form 10-Q.
ACQUISITIONS AND DIVESTITURES
Acquisitions. The following table presents the acquisitions completed during 2017 and 2016, and identifies the funding sources for such acquisitions. See Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
|
| | | | | | | | | | | | | | | | | | | |
| thousands except unit and percent amounts | | Acquisition Date | | Percentage
Acquired | | Borrowings | | Cash On Hand | | Common Units Issued | | Series A Preferred Units Issued |
Springfield system (1) | | 03/14/2016 | | 50.1 | % | | $ | 247,500 |
| | $ | — |
| | 2,089,602 |
| | 14,030,611 |
|
DBJV system (2) | | 03/17/2017 | | 50 | % | | — |
| | 155,000 |
| | — |
| | — |
|
| |
(1)
| We acquired Springfield from Anadarko for $750.0 million, consisting of $712.5 million in cash and the issuance of 1,253,761 of our common units. Springfield owns a 50.1% interest in the Springfield system. We financed the cash portion of the acquisition through: (i) borrowings of $247.5 million on our RCF, (ii) the issuance of 835,841 of our common units to WGP and (iii) the issuance of Series A Preferred units to private investors. See Note 4—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for further information regarding the Series A Preferred units.
|
| |
(2)
| We acquired the Additional DBJV System Interest from a third party. See Property exchange below.
|
Property exchange. On March 17, 2017,Cactus II. In November 2022, we acquired the Additional DBJV System Interest from a third party in exchange for the Non-Operated Marcellus Interest and $155.0 million of cash consideration. We previously held a 50%sold our 15.00% interest in and operated,Cactus II to two third parties for $264.8 million, which includes a $1.8 million pro-rata distribution through closing. Total proceeds were received during the DBJV system. The Property Exchange resultedfourth quarter of 2022, resulting in a net gain on sale of $125.7$109.9 million that was recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations. See Note 2—Acquisitions and Divestitures
Ranch Westex. In September 2022, we acquired the remaining 50% interest in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
Divestitures. During the second quarter of 2017, the Helper and Clawson systems, located in Utah, were sold toRanch Westex from a third party resulting in a net gain on salefor $40.1 million. Subsequent to the acquisition, (i) we are the sole owner and operator of $16.4 million recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations.
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.
Presentation of Partnership assets.The term “Partnership assets” includes both the assets owned and the interestsasset, (ii) Ranch Westex is no longer accounted for under the equity method (see Note 7—Equity Investments inof accounting, and (iii) the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q) by usRanch Westex processing plant is included as of September 30, 2017. Because Anadarko controls us through its ownership and control of WGP, which owns the entire interest in our general partner, each of our acquisitions of Partnership assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets we acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by us (see Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q). Further, after an acquisition of Partnership assets from Anadarko, we may be required to recast our financial statements to include the activities of such Partnership assets from the date of common control.
EQUITY OFFERINGS
Series A Preferred units. In 2016, we issued 21,922,831 Series A Preferred units to private investors. Pursuant to an agreement between us and the holderspart of the Series A Preferred units, 50%operations of the Series A Preferred units converted into common units on a one-for-one basis on March 1, 2017, and the remaining Series A Preferred units converted on a one-for-one basis on May 2, 2017. See Note 4—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.West Texas complex.
RESULTS OF OPERATIONS
OPERATING RESULTS
The following tables and discussion present a summary of our results of operations:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
| | Three Months Ended | | Nine Months Ended |
| | | | | | |
| thousands | | September 30, 2023 | | June 30, 2023 | | September 30, 2023 | | September 30, 2022 | | |
Total revenues and other (1) | | $ | 776,013 | | | $ | 738,273 | | | $ | 2,248,268 | | | $ | 2,472,284 | | | |
| Equity income, net – related parties | | 35,494 | | | 42,324 | | | 116,839 | | | 139,388 | | | |
Total operating expenses (1) | | 449,265 | | | 443,855 | | | 1,373,793 | | | 1,451,558 | | | |
| Gain (loss) on divestiture and other, net | | (1,480) | | | (70) | | | (3,668) | | | (884) | | | |
| Operating income (loss) | | 360,762 | | | 336,672 | | | 987,646 | | | 1,159,230 | | | |
| Interest expense | | (82,754) | | | (86,182) | | | (250,606) | | | (249,333) | | | |
| Gain (loss) on early extinguishment of debt | | 8,565 | | | 6,813 | | | 15,378 | | | 91 | | | |
| Other income (expense), net | | (1,270) | | | 2,872 | | | 2,817 | | | 117 | | | |
| Income (loss) before income taxes | | 285,303 | | | 260,175 | | | 755,235 | | | 910,105 | | | |
| Income tax expense (benefit) | | 905 | | | 659 | | | 2,980 | | | 3,683 | | | |
| Net income (loss) | | 284,398 | | | 259,516 | | | 752,255 | | | 906,422 | | | |
| Net income (loss) attributable to noncontrolling interests | | 7,102 | | | 6,595 | | | 18,393 | | | 25,643 | | | |
Net income (loss) attributable to Western Midstream Partners, LP (2) | | $ | 277,296 | | | $ | 252,921 | | | $ | 733,862 | | | $ | 880,779 | | | |
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| thousands | | 2017 | | 2016 | | 2017 | | 2016 |
Total revenues and other (1) | | $ | 574,695 |
| | $ | 481,645 |
| | $ | 1,616,338 |
| | $ | 1,293,450 |
|
| Equity income, net – affiliates | | 21,519 |
| | 20,294 |
| | 62,708 |
| | 56,801 |
|
Total operating expenses (1) | | 416,830 |
| | 312,088 |
| | 1,318,489 |
| | 830,699 |
|
| Gain (loss) on divestiture and other, net | | 72 |
| | (6,230 | ) | | 135,017 |
| | (8,769 | ) |
Proceeds from business interruption insurance claims (2) | | — |
| | 13,667 |
| | 29,882 |
| | 16,270 |
|
| Operating income (loss) | | 179,456 |
| | 197,288 |
| | 525,456 |
| | 527,053 |
|
| Interest income – affiliates | | 4,225 |
| | 4,225 |
| | 12,675 |
| | 12,675 |
|
| Interest expense | | (35,544 | ) | | (30,768 | ) | | (106,794 | ) | | (75,687 | ) |
| Other income (expense), net | | 286 |
| | 153 |
| | 969 |
| | 224 |
|
| Income (loss) before income taxes | | 148,423 |
| | 170,898 |
| | 432,306 |
| | 464,265 |
|
| Income tax (benefit) expense | | 510 |
| | 472 |
| | 4,905 |
| | 7,431 |
|
| Net income (loss) | | 147,913 |
| | 170,426 |
| | 427,401 |
| | 456,834 |
|
| Net income attributable to noncontrolling interest | | 4,407 |
| | 2,680 |
| | 8,555 |
| | 8,507 |
|
| Net income (loss) attributable to Western Gas Partners, LP | | $ | 143,506 |
| | $ | 167,746 |
| | $ | 418,846 |
| | $ | 448,327 |
|
Key performance metrics (3) | | | | | | | | |
| Adjusted gross margin attributable to Western Gas Partners, LP | | $ | 344,416 |
| | $ | 343,981 |
| | $ | 1,009,520 |
| | $ | 984,459 |
|
| Adjusted EBITDA attributable to Western Gas Partners, LP | | 257,835 |
| | 278,170 |
| | 787,664 |
| | 759,834 |
|
| Distributable cash flow | | 231,859 |
| | 237,315 |
| | 695,587 |
| | 628,602 |
|
| |
(1)
| Revenues and other include amounts earned from services provided to our affiliates, as well as from the sale of residue and NGLs to our affiliates. Operating expenses include amounts charged by our affiliates for services as well as reimbursement of amounts paid by affiliates to third parties on our behalf. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
|
| |
(2)
| See Note 1—Description of Business and Basis of Presentation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
|
| |
(3)
| Adjusted gross margin attributable to Western Gas Partners, LP, Adjusted EBITDA attributable to Western Gas Partners, LP and Distributable cash flow are defined under the caption Key Performance Metrics within this Item 2. For reconciliations of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with GAAP, see Key Performance Metrics–Reconciliation of non-GAAP measures within this Item 2.
|
For purposes of the following discussion, any increases or decreases “for the three months ended September 30, 2017”2023” refer to the comparison of the three months ended September 30, 2017,2023, to the three months ended SeptemberJune 30, 2016;2023; and any increases or decreases “for the nine months ended September 30, 2017”2023” refer to the comparison of the nine months ended September 30, 2017,2023, to the nine months ended September 30, 2016;2022.
Throughput
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
| | | Three Months Ended | | Nine Months Ended | | | | |
| | | | | | | | |
| | September 30, 2023 | | June 30, 2023 | | Inc/
(Dec) | | September 30, 2023 | | September 30, 2022 | | Inc/
(Dec) | | | | |
| Throughput for natural-gas assets (MMcf/d) |
| Gathering, treating, and transportation | | 457 | | | 395 | | | 16 | % | | 407 | | | 411 | | | (1) | % | | | | |
| Processing | | 3,699 | | | 3,567 | | | 4 | % | | 3,574 | | | 3,457 | | | 3 | % | | | | |
Equity investments (1) | | 495 | | | 454 | | | 9 | % | | 458 | | | 490 | | | (7) | % | | | | |
| Total throughput | | 4,651 | | | 4,416 | | | 5 | % | | 4,439 | | | 4,358 | | | 2 | % | | | | |
Throughput attributable to noncontrolling interests (2) | | 167 | | | 162 | | | 3 | % | | 156 | | | 157 | | | (1) | % | | | | |
Total throughput attributable to WES for natural-gas assets | | 4,484 | | | 4,254 | | | 5 | % | | 4,283 | | | 4,201 | | | 2 | % | | | | |
| Throughput for crude-oil and NGLs assets (MBbls/d) |
| Gathering, treating, and transportation | | 334 | | | 316 | | | 6 | % | | 320 | | | 318 | | | 1 | % | | | | |
Equity investments (1) | | 347 | | | 323 | | | 7 | % | | 328 | | | 382 | | | (14) | % | | | | |
| Total throughput | | 681 | | | 639 | | | 7 | % | | 648 | | | 700 | | | (7) | % | | | | |
Throughput attributable to noncontrolling interests (2) | | 14 | | | 13 | | | 8 | % | | 13 | | | 14 | | | (7) | % | | | | |
Total throughput attributable to WES for crude-oil and NGLs assets | | 667 | | | 626 | | | 7 | % | | 635 | | | 686 | | | (7) | % | | | | |
| Throughput for produced-water assets (MBbls/d) |
| Gathering and disposal | | 1,101 | | | 963 | | | 14 | % | | 1,014 | | | 848 | | | 20 | % | | | | |
Throughput attributable to noncontrolling interests (2) | | 22 | | | 20 | | | 10 | % | | 20 | | | 17 | | | 18 | % | | | | |
Total throughput attributable to WES for produced-water assets | | 1,079 | | | 943 | | | 14 | % | | 994 | | | 831 | | | 20 | % | | | | |
(1)Represents our share of average throughput for investments accounted for under the equity method of accounting.
(2)For all periods presented, includes (i) the 2.0% limited partner interest in WES Operating owned by an Occidental subsidiary and any increases or decreases “for(ii) for natural-gas assets, the 25% third-party interest in Chipeta, which collectively represent WES’s noncontrolling interests.
Natural-gas assets
Total throughput attributable to WES for natural-gas assets increased by 230 MMcf/d for the three months ended September 30, 2023, primarily due to (i) higher volumes at the West Texas complex, DJ Basin complex, and Marcellus Interest systems due to increased production in the area, (ii) higher volumes on the Red Bluff Express pipeline due to the addition of a new delivery point onto the pipeline, (iii) higher volumes at the Brasada complex due to downstream issues which caused volumes to be diverted away from the plant and maintenance activities in the second quarter of 2023, (iv) higher volumes at the Springfield gas-gathering system due to new third-party production, and (v) higher volumes at the MIGC system and Mi Vida plant.
Total throughput attributable to WES for natural-gas assets increased by 82 MMcf/d for the nine months ended September 30, 2017” refer to the comparison of these 2017 periods to the corresponding three and nine month periods ended September 30, 2016.
|
| | | | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| | 2017 | | 2016 | | Inc/
(Dec) | | 2017 | | 2016 | | Inc/ (Dec) |
| Throughput for natural gas assets (MMcf/d) | | | | | | | | | | | | |
| Gathering, treating and transportation | | 784 |
| | 1,562 |
| | (50 | )% | | 1,029 |
| | 1,556 |
| | (34 | )% |
| Processing | | 2,588 |
| | 2,448 |
| | 6 | % | | 2,528 |
| | 2,301 |
| | 10 | % |
Equity investment (1) | | 159 |
| | 179 |
| | (11 | )% | | 160 |
| | 178 |
| | (10 | )% |
| Total throughput for natural gas assets | | 3,531 |
| | 4,189 |
| | (16 | )% | | 3,717 |
| | 4,035 |
| | (8 | )% |
| Throughput attributable to noncontrolling interest for natural gas assets | | 104 |
| | 119 |
| | (13 | )% | | 107 |
| | 127 |
| | (16 | )% |
| Total throughput attributable to Western Gas Partners, LP for natural gas assets | | 3,427 |
| | 4,070 |
| | (16 | )% | | 3,610 |
| | 3,908 |
| | (8 | )% |
| Throughput for crude, NGL and produced water assets (MBbls/d) | | | | | | | | | | | | |
| Gathering, treating and transportation | | 77 |
| | 58 |
| | 33 | % | | 57 |
| | 59 |
| | (3 | )% |
Equity investment (2) | | 132 |
| | 127 |
| | 4 | % | | 130 |
| | 126 |
| | 3 | % |
| Total throughput for crude, NGL and produced water assets | | 209 |
| | 185 |
| | 13 | % | | 187 |
| | 185 |
| | 1 | % |
| |
(1)
| Represents our 14.81% share of average Fort Union throughput and our 22% share of average Rendezvous throughput. |
| |
(2)
| Represents our 10% share of average White Cliffs throughput, our 25% share of average Mont Belvieu JV throughput, our 20% share of average TEG and TEP throughput, and our 33.33% share of average FRP throughput. |
Natural gas assets
Gathering, treating and transportation throughput decreased by 778 MMcf/d and 527 MMcf/d for the three and nine months ended September 30, 2017, respectively,2023, primarily due to higher volumes at the Property ExchangeWest Texas complex due to increased production in March 2017 (decreases of 594 MMcf/d and 341 MMcf/d, respectively),the area. This increase was offset partially by (i) lower volumes due to production declines in the areas around the Marcellus Interest (decreasessystems and DJ Basin complex, (ii) decreased volumes at the Ranch Westex plant, which we acquired in the third quarter of 38 MMcf/d2022 and 52 MMcf/d, respectively) and Springfield gas gathering systems (decreases of 40 MMcf/d and 47 MMcf/d, respectively), and the saleis included as part of the Hugoton system in October 2016 (decreases of 52 MMcf/d and 54 MMcf/d, respectively).
Processing throughput increased by 140 MMcf/d and 227 MMcf/d for the three and nine months ended September 30, 2017, respectively, primarily dueWest Texas complex subsequent to the DBM outage in 2016acquisition, and the start-up of Train IV and Train V at the DBM complex in May 2016 and October 2016, respectively. These increases were partially offset by production declines in the areas around the Chipeta complex and MGR assets.
Equity investment throughput decreased by 20 MMcf/d and 18 MMcf/d for the three and nine months ended September 30, 2017, respectively, due to decreased throughput at the Rendezvous and Fort Union systems(iii) lower volumes due to production declines and extended winter weather conditions during the first quarter of 2023 in areas around the area.Granger complex.
Crude, NGL
Crude-oil and produced waterNGLs assets
Gathering, treatingTotal throughput attributable to WES for crude-oil and transportation throughputNGLs assets increased by 1941 MBbls/d for the three months ended September 30, 2017,2023, primarily due to (i) higher volumes on the start-up of operationsWhitethorn pipeline and (ii) higher volumes at the DBM water systems during the second quarter of 2017, partially offset by decreased throughput at the Springfield oil gathering system due toresulting from increased production declines in the area.
Gathering, treatingTotal throughput attributable to WES for crude-oil and transportation throughputNGLs assets decreased by 251 MBbls/d for the nine months ended September 30, 2017,2023, primarily due to decreased throughput(i) lower volumes on the Cactus II pipeline, which was sold in the fourth quarter of 2022, and (ii) lower volumes at the SpringfieldDJ Basin oil gathering system due toresulting from production declines in the area,area. These decreases were offset partially offset by throughput from(i) increased volumes on the Whitethorn pipeline and (ii) higher volumes at the DBM oil system resulting from increased production in the area.
Produced-water assets
Total throughput attributable to WES for produced-water systems that commenced operation during the second quarter of 2017.
Equity investment throughputassets increased by 5136 MBbls/d and 4163 MBbls/d for the three and nine months ended September 30, 2017,2023, respectively, primarily due to increased volumes on FRP and TEG as a result of increased NGL production and an increase at the Mont Belvieu JV due to higher inlet throughput. These increases were partially offsetproduction and new third-party connections brought online during 2023.
Service Revenues
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
| | | Three Months Ended | | Nine Months Ended | | | | |
| | | | | | | | |
| thousands except percentages | | September 30, 2023 | | June 30, 2023 | | Inc/
(Dec) | | September 30, 2023 | | September 30, 2022 | | Inc/
(Dec) | | | | |
| Service revenues – fee based | | $ | 695,547 | | | $ | 661,506 | | | 5 | % | | $ | 2,004,920 | | | $ | 1,954,105 | | | 3 | % | | | | |
| Service revenues – product based | | 48,446 | | | 46,956 | | | 3 | % | | 142,212 | | | 202,721 | | | (30) | % | | | | |
| Total service revenues | | $ | 743,993 | | | $ | 708,462 | | | 5 | % | | $ | 2,147,132 | | | $ | 2,156,826 | | | — | % | | | | |
Service revenues – fee based
Service revenues – fee based increased by decreased throughput at White Cliffs as a result of a competitive pipeline commencing service in September 2016.
Gathering, Processing and Transportation Revenues
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| thousands except percentages | | 2017 | | 2016 | | Inc/ (Dec) | | 2017 | | 2016 | | Inc/ (Dec) |
| Gathering, processing and transportation revenues | | $ | 306,187 |
| | $ | 315,192 |
| | (3 | )% | | $ | 913,436 |
| | $ | 910,332 |
| | — | % |
Revenues from gathering, processing and transportation decreased by $9.0$34.0 million for the three months ended September 30, 2017,2023, primarily due to decreasesincreases of (i) $15.4 million due to the Property Exchange in March 2017, (ii) $7.4$17.8 million at the Springfield system, $2.6 million at the ChipetaWest Texas complex resulting from increased throughput, electricity-related rates billed to customers, and $1.6 million at the Marcellus Interest systems in each case due to throughput decreases, (iii) $4.7 million due to the sale of the Hugoton system in October 2016 and (iv) $2.8 million at the Granger complex due to a lower processing fee. These decreases were partially offset by increases of (i) $16.2deficiency fees, (ii) $11.3 million at the DBM complexwater systems due to increased throughput (see Operating Results–Throughput within this Item 2), (ii) $8.5and higher average fees, (iii) $4.5 million at the DJ Basin complex due to increased throughput and a higher throughput feedeficiency fees, and (iii)(iv) $3.0 million at the DBM water systems that commenced operation duringoil system due to increased throughput, partially offset by decreased deficiency fees. These increases were partially offset by a decrease of $6.5 million at the second quarter of 2017.Brasada complex due to a change in contract terms effective July 1, 2023.
Revenues from gathering, processing and transportationService revenues – fee based increased by $3.1$50.8 million for the nine months ended September 30, 2017,2023, primarily due to increases of (i) $72.6$74.8 million at the West Texas complex as a result of increased throughput, electricity-related rates billed to customers, and deficiency fees, (ii) $10.4 million at the DBM water systems due to increased throughput, partially offset by decreased deficiency fees, (iii) $8.9 million at the DBM oil system due to increased throughput, and (iv) $7.6 million at the DJ Basin complex due to increased deficiency fees and electricity-related rates billed to customers, partially offset by decreased throughput. These increases were partially offset by decreases of (i) $15.5 million at the DJ Basin oil system due to decreased throughput, (ii) $13.9 million at the Chipeta complex due to decreased deficiency fees, (iii) $8.5 million at the Springfield system primarily due to decreased demand-fee revenue, partially offset by increased throughput, (iv) $5.9 million at the Brasada complex due to a change in contract terms effective July 1, 2023, and (v) $5.2 million at the Marcellus Interest systems due to decreased throughput.
Service revenues – product based
Service revenues – product based decreased by $60.5 million for the nine months ended September 30, 2023, primarily due to decreases of (i) $24.6 million at the West Texas complex due to decreased average prices, volumes sold, and electricity-related rates billed to customers, (ii) $13.6 million and $5.9 million at the DJ Basin complex and Hilight system, respectively, due to decreased average prices, (iii) $7.7 million and $5.1 million at the Red Desert and Granger complexes, respectively, due to decreased average prices and volumes sold, and (iv) $2.8 million at the Chipeta complex due to decreased volumes sold.
Product Sales
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
| | Three Months Ended | | Nine Months Ended | | | | |
| | | | | | | | |
| thousands except percentages and per-unit amounts | | September 30, 2023 | | June 30, 2023 | | Inc/
(Dec) | | September 30, 2023 | | September 30, 2022 | | Inc/
(Dec) | | | | |
Natural-gas sales | | $ | 16,454 | | | $ | 7,237 | | | 127 | % | | $ | 26,466 | | | $ | 101,475 | | | (74) | % | | | | |
| NGLs sales | | 15,198 | | | 22,422 | | | (32) | % | | 73,870 | | | 213,280 | | | (65) | % | | | | |
| Total Product sales | | $ | 31,652 | | | $ | 29,659 | | | 7 | % | | $ | 100,336 | | | $ | 314,755 | | | (68) | % | | | | |
Per-unit gross average sales price: | | | | | | | | | | | | | | | | |
| Natural gas (per Mcf) | | $ | 1.91 | | | $ | 1.33 | | | 44 | % | | $ | 1.67 | | | $ | 6.28 | | | (73) | % | | | | |
| NGLs (per Bbl) | | 27.64 | | | 23.65 | | | 17 | % | | 26.65 | | | 44.43 | | | (40) | % | | | | |
Natural-gas sales
Natural-gas sales increased by $9.2 million for the three months ended September 30, 2023, primarily due to an increase of $10.1 million at the West Texas complex due to increased average prices and volumes sold.
Natural-gas sales decreased by $75.0 million for the nine months ended September 30, 2023, primarily due to decreases of (i) $71.0 million at the West Texas complex due to decreased average prices, partially offset by higher volumes sold, and (ii) $14.3 million at the Red Desert complex due to decreased average prices and volumes sold. These decreases were partially offset by an increase of $10.3 million at the DJ Basin complex as a result of higher average prices and volumes sold.
NGLs sales
NGLs sales decreased by $7.2 million for the three months ended September 30, 2023, primarily due to a decrease of $13.1 million at the West Texas complex due to changes in contract mix and decreased volumes sold. This decrease was partially offset by increases of (i) $2.0 million at the DJ Basin complex due to increased average prices and (ii) $1.7 million at DBM water systems due to increased volumes sold.
NGLs sales decreased by $139.4 million for the nine months ended September 30, 2023, primarily due to decreases of (i) $93.0 million, $21.6 million, $8.7 million, and $3.2 million at the West Texas, Chipeta, Granger, and Red Desert complexes, respectively, due to decreased average prices and volumes sold, and (ii) $7.5 million at the Brasada complex due to a contract expiration in the third quarter of 2022.
Equity Income, Net – Related Parties
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
| | Three Months Ended | | Nine Months Ended | | | | |
| | | | | | | | |
| thousands except percentages | | September 30, 2023 | | June 30, 2023 | | Inc/
(Dec) | | September 30, 2023 | | September 30, 2022 | | Inc/
(Dec) | | | | |
| Equity income, net – related parties | | $ | 35,494 | | | $ | 42,324 | | | (16) | % | | $ | 116,839 | | | $ | 139,388 | | | (16) | % | | | | |
Equity income, net – related parties decreased by $6.8 million for the three months ended September 30, 2023, primarily due to decreases of $4.8 million and $2.1 million at Mont Belvieu JV and TEG, respectively.
Equity income, net – related parties decreased by $22.5 million for the nine months ended September 30, 2023, primarily due to decreases of (i) $10.9 million at Cactus II due to the divestiture of our interest in the fourth quarter of 2022 (see Operating Results–ThroughputAcquisitions and Divestitures within this Item 2), (ii) $5.1 million and $3.9 million at Mont Belvieu JV and TEP, respectively, and (iii) $3.4 million at Ranch Westex, which we acquired in the third quarter of 2022 and is included as part of the West Texas complex subsequent to the acquisition (see Acquisitions and Divestitures within this Item 2).
Cost of Product and Operation and Maintenance Expenses
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
| | Three Months Ended | | Nine Months Ended | | | | |
| | | | | | | | |
| thousands except percentages | | September 30, 2023 | | June 30, 2023 | | Inc/
(Dec) | | September 30, 2023 | | September 30, 2022 | | Inc/
(Dec) | | | | |
| Residue purchases | | $ | 2,880 | | | $ | 6,066 | | | (53) | % | | $ | 24,584 | | | $ | 142,959 | | | (83) | % | | | | |
| NGLs purchases | | 50,394 | | | 48,942 | | | 3 | % | | 151,165 | | | 263,014 | | | (43) | % | | | | |
| Other | | (25,684) | | | (10,262) | | | (150) | % | | (51,954) | | | (77,736) | | | 33 | % | | | | |
| Cost of product | | 27,590 | | | 44,746 | | | (38) | % | | 123,795 | | | 328,237 | | | (62) | % | | | | |
| Operation and maintenance | | 204,434 | | | 183,431 | | | 11 | % | | 562,104 | | | 487,643 | | | 15 | % | | | | |
| Total Cost of product and Operation and maintenance expenses | | $ | 232,024 | | | $ | 228,177 | | | 2 | % | | $ | 685,899 | | | $ | 815,880 | | | (16) | % | | | | |
Residue purchases
Residue purchases decreased by $118.4 million for the nine months ended September 30, 2023, primarily due to decreases of (i) $75.0 million at the West Texas complex attributable to changes in contract mix during 2022 and lower average prices, (ii) $14.9 million and $12.2 million at the Chipeta and Red Desert complexes, respectively, due to decreased volumes purchased and lower average prices, and (iii) $9.0 million at the DJ Basin complex primarily due to lower average prices.
NGLs purchases
NGLs purchases decreased by $111.8 million for the nine months ended September 30, 2023, primarily due to decreases of (i) $66.8 million, $5.2 million, and $5.2 million at the West Texas, Chipeta, and Granger complexes, respectively, primarily due to lower average prices and volumes purchased, (ii) $23.1 million at the DJ Basin complex due to increased throughput and a higher throughput feelower average prices, and (iii) $4.1$7.7 million at the DBM water systems that commenced operation during the second quarter of 2017. These increases were partially offset by decreases of (i) $25.7 million at the Springfield system, $10.8 million at the Chipeta complex and $7.6 million at the Marcellus Interest systems in each case due to throughput decreases, (ii) $28.5 million due to the Property Exchange in March 2017, (iii) $14.4 million due to the sale of the Hugoton system in October 2016 and (iv) $7.0 million at the GrangerBrasada complex due to a lower processing fee.
Natural Gas and Natural Gas Liquids Sales
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| thousands except percentages and per-unit amounts | | 2017 | | 2016 | | Inc/ (Dec) | | 2017 | | 2016 | | Inc/ (Dec) |
Natural gas sales (1) | | $ | 100,395 |
| | $ | 72,658 |
| | 38 | % | | $ | 273,256 |
| | $ | 155,251 |
| | 76 | % |
Natural gas liquids sales (1) | | 158,746 |
| | 91,378 |
| | 74 | % | | 417,234 |
| | 224,334 |
| | 86 | % |
| Total | | $ | 259,141 |
| | $ | 164,036 |
| | 58 | % | | $ | 690,490 |
| | $ | 379,585 |
| | 82 | % |
Average price per unit (1): | | | | | | | | | | | | |
| Natural gas (per Mcf) | | $ | 2.89 |
| | $ | 2.70 |
| | 7 | % | | $ | 2.96 |
| | $ | 2.41 |
| | 23 | % |
| Natural gas liquids (per Bbl) | | 22.99 |
| | 19.10 |
| | 20 | % | | 21.63 |
| | 19.45 |
| | 11 | % |
| |
(1)
| Excludes amounts considered above market with respect to our swap agreements for the MGR assets, DJ Basin complex and Hugoton system (until its divestiture in October 2016) that were recorded as capital contributions in the consolidated statement of equity and partners’ capital. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
|
For the three and nine months ended September 30, 2017, average natural gas and NGL prices included the effects of commodity price swap agreements attributable to sales for the MGR assets and DJ Basin complex. For the three and nine months ended September 30, 2016, average natural gas and NGL prices included the effects of commodity price swap agreements attributable to sales for the Hugoton system, MGR assets and DJ Basin complex. See Note 5—Transactions with Affiliatescontract expiration in the Notes to Consolidated Financial Statements under Part I, Item 1third quarter of this Form 10-Q.2022.
The increase in natural gas sales
Other items
Other items decreased by $15.4 million for the three months ended September 30, 2017, was2023, primarily due to increasesdecreases of (i) $15.6$12.0 million at the West Texas complex due to changes in imbalance positions, partially offset by higher electricity-related costs, and (ii) $3.8 million at the DJ Basin complex due to an increasechanges in the swap market price and volumes sold and (ii) $14.8 million at the DBM complex due to an increase in volumes sold (see Operating Results–Throughput within this Item 2). These increases were partially offsetimbalance positions.
Other items increased by a decrease of $3.0 million at the MGR assets due to the partial equity treatment of the above-market swap agreement beginning January 1, 2017.
The increase in natural gas sales of $118.0$25.8 million for the nine months ended September 30, 2017, was2023, primarily due to increases of (i) $75.2 million at the DBM complex due to an increase in average price and volumes sold (see Operating Results–Throughput within this Item 2), (ii) $44.3of $39.5 million at the DJ Basin complex due to anchanges in imbalance positions. This increase in the swap market price and volumes sold and (iii) $4.8was partially offset by decreases of (i) $6.2 million at the Hilight systemWest Texas complex due to an increasechanges in average price. These increases wereimbalance positions, partially offset by a decrease of $9.2higher electricity-related and offload costs, and (ii) $3.7 million and $1.9 million at the MGR assets dueRed Desert complex and MIGC system, respectively, attributable to the partial equity treatment of the above-market swap agreement beginning January 1, 2017.changes in imbalance positions.
The increase in NGLs sales of $67.4 million
Operation and $192.9maintenance expense
Operation and maintenance expense increased by $21.0 million for the three and nine months ended September 30, 2017, respectively, was2023, primarily due to increases of (i) $62.7$14.1 million in utility expense, (ii) $3.7 million for maintenance and $184.5 million, respectively, at the DBM complex due to an increase in average price and volumes sold (see Operating Results–Throughput within this Item 2), (ii) $15.9 million and $38.1 million, respectively, at the DJ Basin complex due to an increase in the swap market price and volumes soldrepair expense, and (iii) $3.3$2.8 million attributable to higher contract labor and $11.3 million, respectively, at the Hilight system due to an increase in average price. These increases were partially offset by decreases during the threeconsulting expense.
Operation and nine months ended September 30, 2017, of $17.7 million and $49.9 million, respectively, at the MGR assets due to the partial equity treatment of the above-market swap agreement beginning January 1, 2017.
Other Revenues
|
| | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| thousands except percentages | | 2017 | | 2016 | | Inc/ (Dec) | | 2017 | | 2016 | | Inc/ (Dec) |
| Other revenues | | $ | 9,367 |
| | $ | 2,417 |
| | NM | | $ | 12,412 |
| | $ | 3,533 |
| | NM |
NM-Not Meaningful
For the three and nine months ended September 30, 2017, other revenuesmaintenance expense increased by $7.0$74.5 million and $8.9 million, respectively, primarily due to deficiency fees at the Chipeta complex.
Equity Income, Net – Affiliates
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| thousands except percentages | | 2017 | | 2016 | | Inc/ (Dec) | | 2017 | | 2016 | | Inc/ (Dec) |
| Equity income, net – affiliates | | $ | 21,519 |
| | $ | 20,294 |
| | 6 | % | | $ | 62,708 |
| | $ | 56,801 |
| | 10 | % |
For the three and nine months ended September 30, 2017, equity income, net – affiliates increased by $1.2 million and $5.9 million, respectively, primarily due to an increase in equity income from the Mont Belvieu JV due to increased volumes processed. In addition, for the nine months ended September 30, 2017, equity income, net – affiliates increased due to our 14.81% share of an impairment loss determined by the managing partner of Fort Union in the first quarter of 2016.
Cost of Product and Operation and Maintenance Expenses
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| thousands except percentages | | 2017 | | 2016 | | Inc/ (Dec) | | 2017 | | 2016 | | Inc/ (Dec) |
NGL purchases (1) | | $ | 136,636 |
| | $ | 66,822 |
| | 104 | % | | $ | 359,616 |
| | $ | 149,547 |
| | 140 | % |
Residue purchases (1) | | 90,264 |
| | 70,376 |
| | 28 | % | | 256,387 |
| | 156,774 |
| | 64 | % |
| Other | | 12,323 |
| | 8,445 |
| | 46 | % | | 15,856 |
| | 20,638 |
| | (23 | )% |
| Cost of product | | 239,223 |
| | 145,643 |
| | 64 | % | | 631,859 |
| | 326,959 |
| | 93 | % |
| Operation and maintenance | | 79,536 |
| | 74,755 |
| | 6 | % | | 229,444 |
| | 226,141 |
| | 1 | % |
| Total cost of product and operation and maintenance expenses | | $ | 318,759 |
| | $ | 220,398 |
| | 45 | % | | $ | 861,303 |
| | $ | 553,100 |
| | 56 | % |
| |
(1)
| Excludes amounts considered above market with respect to our swap agreements for the MGR assets, DJ Basin complex and Hugoton system (until its divestiture in October 2016) that were recorded as capital contributions in the consolidated statement of equity and partners’ capital. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
|
Cost of product expense for the three and nine months ended September 30, 2017, included the effects of commodity price swap agreements attributable to purchases for the MGR assets and DJ Basin complex. Cost of product expense for the three and nine months ended September 30, 2016, included the effects of commodity price swap agreements attributable to purchases for the Hugoton system, MGR assets and DJ Basin complex. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
NGL purchases increased by $69.8 million and $210.1 million for the three and nine months ended September 30, 2017, respectively,2023, primarily due to increases of (i) $61.4$27.9 million for maintenance and $177.1repair expense, (ii) $19.5 million respectively, at the DBM complex duefor salaries and wages costs, (iii) $7.5 million in utility expense, (iv) $5.5 million in land-related costs, (v) $4.8 million attributable to an increasehigher contract labor and consulting expense, (vi) $4.6 million in average pricewater-disposal costs, and volumes purchased (see (vii) $3.6 million in higher equipment rental costs.
Other Operating Results–Throughput within this Item 2), (ii) $13.2 millionExpenses
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
| | Three Months Ended | | Nine Months Ended | | | | |
| | | | | | | | |
| thousands except percentages | | September 30, 2023 | | June 30, 2023 | | Inc/
(Dec) | | September 30, 2023 | | September 30, 2022 | | Inc/
(Dec) | | | | |
| General and administrative | | $ | 55,050 | | | $ | 53,405 | | | 3 | % | | $ | 159,572 | | | $ | 144,635 | | | 10 | % | | | | |
| Property and other taxes | | 14,583 | | | 18,547 | | | (21) | % | | 39,961 | | | 60,494 | | | (34) | % | | | | |
| Depreciation and amortization | | 147,363 | | | 143,492 | | | 3 | % | | 435,481 | | | 430,455 | | | 1 | % | | | | |
Long-lived asset and other impairments | | 245 | | | 234 | | | 5 | % | | 52,880 | | | 94 | | | NM | | | | |
| | | | | | | | | | | | | | | | |
| Total other operating expenses | | $ | 217,241 | | | $ | 215,678 | | | 1 | % | | $ | 687,894 | | | $ | 635,678 | | | 8 | % | | | | |
NM—Not meaningful
General and $43.2 million, respectively, at the DJ Basin complex due to an increase in the swap market priceadministrative expenses
General and volumes purchased and (iii) $2.7 million and $9.2 million, respectively, at the Hilight system due to an increase in average price, partially offset by a decrease in volumes purchased. These increases were partially offset by decreases during the three and nine months ended September 30, 2017, of $9.5 million and $26.6 million, respectively, at the MGR assets due to the partial equity treatment of the above-market swap agreement beginning January 1, 2017.
Residue purchasesadministrative expenses increased by $19.9$14.9 million and $99.6 million for the three and nine months ended September 30, 2017, respectively, primarily due to increases of (i) $12.6 million and $68.7 million, respectively, at the DBM complex due to an increase in average price and volumes purchased (see Operating Results–Throughput within this Item 2) and (ii) $12.3 million and $36.5 million, respectively, at the DJ Basin complex due to an increase in the swap market price and volumes purchased. In addition, for the nine months ended September 30, 2017, there was an increase2023, primarily due to increases of $4.6(i) $6.3 million in corporate-related costs, primarily related to information technology costs, (ii) $3.9 million in personnel costs, and (iii) $3.2 million in contract and consulting costs.
Property and other taxes
Property and other taxes decreased by $4.0 million for the three months ended September 30, 2023, primarily due to lower property tax values at the Hilight system due to an increase in average price. These increases were partially offsetDJ Basin and West Texas complexes.
Property and other taxes decreased by decreases during$20.5 million for the three and nine months ended September 30, 2017,2023, primarily due to decreases in the ad valorem property tax accrual during 2023 related to the finalization of $3.9 million and $12.0 million, respectively,2022 assessments at the MGR assets due to the partial equity treatmentDJ Basin complex.
Other itemsDepreciation and amortization expense
Depreciation and amortization expense increased by $3.9 million for the three months ended September 30, 2017,2023, primarily due to changes in affiliate contract termsresulting from capital projects being placed into service and asset retirement obligation revisions at the DJ Basin complex. Other items decreasedWest Texas complex and DBM water systems.
Depreciation and amortization expense increased by $4.8$5.0 million for the nine months ended September 30, 2017,2023, primarily due to fees paid in 2016increases of (i) $8.9 million and $5.1 million at the West Texas complex and DBM water systems, respectively, primarily resulting from capital projects being placed into service, and (ii) $5.4 million related to depreciation for rerouting volumes due to the DBM outage,capitalized information technology implementation costs. These increases were offset partially offset by changes in affiliate contract termsa decrease of $13.3 million at the DJ Basin complex primarily due to acceleration of depreciation expense during 2022.
Long-lived asset and other impairment expense
Long-lived asset and other impairment expense for the nine months ended September 30, 2023, was primarily due to a $52.1 million impairment for assets located in 2017.the Rockies.
OperationFor further information on Long-lived asset and maintenanceother impairment expense, increasedsee Note 8—Property, Plant, and Equipment in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
Interest Expense
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
| | Three Months Ended | | Nine Months Ended |
| | | | | | | | |
| thousands except percentages | | September 30, 2023 | | June 30, 2023 | | Inc/
(Dec) | | September 30, 2023 | | September 30, 2022 | | Inc/
(Dec) | | | | |
Long-term and short-term debt | | $ | (83,177) | | | $ | (85,088) | | | (2) | % | | $ | (249,416) | | | $ | (243,559) | | | 2 | % | | | | |
| Finance lease liabilities | | (223) | | | (230) | | | (3) | % | | (616) | | | (96) | | | NM | | | | |
| Commitment fees and amortization of debt-related costs | | (2,904) | | | (3,414) | | | (15) | % | | (9,199) | | | (9,149) | | | 1 | % | | | | |
| Capitalized interest | | 3,550 | | | 2,550 | | | 39 | % | | 8,625 | | | 3,471 | | | 148 | % | | | | |
| | | | | | | | | | | | | | | | |
| Interest expense | | $ | (82,754) | | | $ | (86,182) | | | (4) | % | | $ | (250,606) | | | $ | (249,333) | | | 1 | % | | | | |
Interest expense
Interest expense decreased by $4.8$3.4 million for the three months ended September 30, 2017,2023, primarily due to increasesdecreases of (i) $2.6$3.7 million due to credit-rating related interest rate changes and lower outstanding balances on certain senior notes, and (ii) $1.0 million due to higher capitalized interest. These decreases were offset partially by an increase of $0.7 million primarily due to higher outstanding borrowings under the Property Exchange in March 2017, (ii) $1.4 million in utilities expense primarily atRCF during the DJ Basin and DBM complexes and (iii) $1.4 million in salaries and wages primarily at the Springfield system. Operation and maintenancethird quarter of 2023.
Interest expense increased by $3.3$1.3 million for the nine months ended September 30, 2017,2023, primarily due to an increaseincreases of $3.0(i) $23.0 million of interest incurred on the 6.150% Senior Notes due 2033 that were issued during the second quarter of 2023 and (ii) $1.7 million primarily due to higher outstanding borrowings and average interest rates on the RCF during 2023. These increases were offset partially by decreases of (i) $10.0 million due to credit-rating related interest rate changes and lower outstanding balances on certain senior notes, (ii) $5.2 million due to higher capitalized interest, (iii) $5.1 million due to the Property Exchange in March 2017.redemption of the total principal amount outstanding of the 4.000% Senior Notes due 2022 during the second quarter of 2022, and (iv) $3.9 million due to the redemption of the total principal amount outstanding of the Floating-Rate Senior Notes due 2023 during the first quarter of 2023.
See Liquidity and Capital Resources—Debt and credit facilities within this Item 2.
Other Operating ExpensesIncome (Expense), Net
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
| | Three Months Ended | | Nine Months Ended |
| | | | | | | | |
| thousands except percentages | | September 30, 2023 | | June 30, 2023 | | Inc/
(Dec) | | September 30, 2023 | | September 30, 2022 | | Inc/
(Dec) | | | | |
| Other income (expense), net | | $ | (1,270) | | | $ | 2,872 | | | (144)% | | $ | 2,817 | | | $ | 117 | | | NM | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| thousands except percentages | | 2017 | | 2016 | | Inc/ (Dec) | | 2017 | | 2016 | | Inc/ (Dec) |
| General and administrative | | $ | 12,158 |
| | $ | 11,382 |
| | 7 | % | | $ | 35,402 |
| | $ | 33,542 |
| | 6 | % |
| Property and other taxes | | 11,215 |
| | 10,670 |
| | 5 | % | | 35,433 |
| | 33,098 |
| | 7 | % |
| Depreciation and amortization | | 72,539 |
| | 67,246 |
| | 8 | % | | 216,272 |
| | 199,646 |
| | 8 | % |
| Impairments | | 2,159 |
| | 2,392 |
| | (10 | )% | | 170,079 |
| | 11,313 |
| | NM |
|
| Total other operating expenses | | $ | 98,071 |
| | $ | 91,690 |
| | 7 | % | | $ | 457,186 |
| | $ | 277,599 |
| | 65 | % |
NM-Not Meaningful
General and administrative expenses increasedOther income (expense), net decreased by $0.8 million and $1.9 million for the three and nine months ended September 30, 2017, respectively, primarily due to increases in personnel costs for which we reimbursed Anadarko pursuant to our omnibus agreement and bad debt expense, partially offset by decreases in legal and consulting fees.
Property and other taxes increased by $0.5$4.1 million for the three months ended September 30, 2017,2023, primarily due to an ad valoreminterest accrued in the third quarter of 2023 related to a sales tax increase at the DJ Basin complex, partially offset by a decrease at the DBM complex. Property and other taxesaudit.
Other income (expense), net increased by $2.3$2.7 million for the nine months ended September 30, 2017,2023, primarily due to ad valorem tax increases at the DBM complexinterest income earned resulting from higher interest rates and DBJV system.
Depreciationcash and amortization expense increased by $5.3 million and $16.6 million for the three and nine months ended September 30, 2017, respectively, primarily due to depreciation expense increases of (i) $5.2 million and $10.3 million, respectively, due to the Property Exchange in March 2017, (ii) $2.4 million and $9.1 million, respectively, related to capital projects at the DBM complex and (iii) $2.8 million and $8.4 million, respectively, at the Bison facility due to a change in the estimated property life. These increases werecash equivalent balances throughout 2023, partially offset by decreases during the three and nine months ended September 30, 2017, of (i) $1.4 million and $5.4 million, respectively, due to the sale of the Hugoton system in October 2016, (ii) $2.4 million and $4.9 million, respectively, at the Granger complex due to an impairment recordedinterest accrued in the firstthird quarter of 2017 (see impairment expense below) and (iii) $1.6 million and $2.4 million, respectively, at the DJ Basin complex due2023 related to a change in estimated salvage values.sales tax audit.
Impairment expense decreased by $0.2 million for the three months ended September 30, 2017, primarily due to a $2.0 million impairment of an idle facility in northeast Wyoming (see Note 6—Property, Plant and Equipment in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q), as compared to impairments in 2016 primarily related to the cancellation of projects at the DBJV and Marcellus Interest systems.
Impairment expense increased by $158.8 million for the nine months ended September 30, 2017, primarily due to the following items occurring in 2017 (i) a $158.8 million impairment at the Granger complex, (ii) a $3.7 million impairment at the Granger straddle plant, (iii) a $3.1 million impairment at the Fort Union system, (iv) a $2.0 million impairment of an idle facility in northeast Wyoming and (v) the cancellation of a pipeline project in West Texas. Impairment expense for the nine months ended September 30, 2016, was primarily due to (i) a $6.1 million impairment at the Newcastle system, (ii) the cancellation of projects at the DJ Basin complex and DBJV system and (iii) the abandonment of compressors at the MIGC system. See Note 6—Property, Plant and Equipment in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
Interest Income – Affiliates and Interest Expense |
| | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| thousands except percentages | | 2017 | | 2016 | | Inc/ (Dec) | | 2017 | | 2016 | | Inc/ (Dec) |
| Note receivable – Anadarko | | $ | 4,225 |
| | $ | 4,225 |
| | — | % | | $ | 12,675 |
| | $ | 12,675 |
| | — | % |
| Interest income – affiliates | | $ | 4,225 |
| | $ | 4,225 |
| | — | % | | $ | 12,675 |
| | $ | 12,675 |
| | — | % |
| Third parties | | | | | | | | | | | | |
| Long-term debt | | $ | (35,992 | ) | | $ | (31,612 | ) | | 14 | % | | $ | (105,772 | ) | | $ | (87,711 | ) | | 21 | % |
| Amortization of debt issuance costs and commitment fees | | (1,667 | ) | | (1,672 | ) | | — | % | | (4,942 | ) | | (4,747 | ) | | 4 | % |
| Capitalized interest | | 2,115 |
| | 1,343 |
| | 57 | % | | 3,991 |
| | 4,674 |
| | (15 | )% |
| Affiliates | | | | | | | | | | | | |
Deferred purchase price obligation – Anadarko (1) | | — |
| | 1,173 |
| | (100 | )% | | (71 | ) | | 12,097 |
| | (101 | )% |
| Interest expense | | $ | (35,544 | ) | | $ | (30,768 | ) | | 16 | % | | $ | (106,794 | ) | | $ | (75,687 | ) | | 41 | % |
| |
(1)
| See Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for a discussion of the Deferred purchase price obligation - Anadarko.
|
Interest expense increased by $4.8 million and $31.1 million for the three and nine months ended September 30, 2017, respectively, primarily due to (i) accretion revisions in 2016 recorded as reductions to interest expense for the Deferred purchase price obligation - Anadarko (see Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q), (ii) interest incurred on the 2026 Notes issued in July 2016 and (iii) interest incurred on the additional 2044 Notes issued in October 2016. These increases were partially offset during the nine months ended September 30, 2017, by additional interest incurred on the RCF in 2016 as a result of higher outstanding borrowings. Capitalized interest increased by $0.8 million for the three months ended September 30, 2017, primarily due to the construction of Train VI beginning in the fourth quarter of 2016 and the purchase of long-lead items associated with the Mentone plant, partially offset by a decrease primarily due to the completion of Train V in October 2016, all located at the DBM complex. Capitalized interest decreased by $0.7 million for the nine months ended September 30, 2017, primarily due to the completion of Trains IV and V in May 2016 and October 2016, respectively, partially offset by an increase due to the construction of Train VI beginning in the fourth quarter of 2016 and the purchase of long-lead items associated with the Mentone plant, all located at the DBM complex. See Note 9—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
Income Tax Expense (Benefit) Expense |
| | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| thousands except percentages | | 2017 | | 2016 | | Inc/
(Dec) | | 2017 | | 2016 | | Inc/
(Dec) |
| Income (loss) before income taxes | | $ | 148,423 |
| | $ | 170,898 |
| | (13 | )% | | $ | 432,306 |
| | $ | 464,265 |
| | (7 | )% |
| Income tax (benefit) expense | | 510 |
| | 472 |
| | 8 | % | | 4,905 |
| | 7,431 |
| | (34 | )% |
| Effective tax rate | | — | % | | — | % | |
| | 1 | % | | 2 | % | |
|
|
We are not a taxable entity for U.S. federal income tax purposes.purposes; therefore, our federal statutory rate is zero percent. However, our income apportionable to Texas is subject to Texas margin tax. For the nine months ended September 30, 2016, the variance from the federal statutory rate was primarily due to federal and state taxes on pre-acquisition income attributable to Partnership assets acquired from Anadarko, and our share
Income attributable to the Springfield system prior to and including February 2016 was subject to federal and state income tax. Income earned on the Springfield system for periods subsequent to February 2016 was only subject to Texas margin tax on income apportionable to Texas.
KEY PERFORMANCE METRICS
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| thousands except percentages and per-unit amounts | | 2017 | | 2016 | | Inc/ (Dec) | | 2017 | | 2016 | | Inc/ (Dec) |
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets (1) | | $ | 305,337 |
| | $ | 306,393 |
| | — | % | | $ | 904,620 |
| | $ | 877,583 |
| | 3 | % |
Adjusted gross margin for crude, NGL and produced water assets (2) | | 39,079 |
| | 37,588 |
| | 4 | % | | 104,900 |
| | 106,876 |
| | (2 | )% |
Adjusted gross margin attributable to Western Gas Partners, LP (3) | | 344,416 |
| | 343,981 |
| | — | % | | 1,009,520 |
| | 984,459 |
| | 3 | % |
Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets (4) | | 0.97 |
| | 0.82 |
| | 18 | % | | 0.92 |
| | 0.82 |
| | 12 | % |
Adjusted gross margin per Bbl for crude, NGL and produced water assets (5) | | 2.03 |
| | 2.20 |
| | (8 | )% | | 2.05 |
| | 2.10 |
| | (2 | )% |
Adjusted EBITDA attributable to Western Gas Partners, LP (3) | | 257,835 |
| | 278,170 |
| | (7 | )% | | 787,664 |
| | 759,834 |
| | 4 | % |
Distributable cash flow (3) | | 231,859 |
| | 237,315 |
| | (2 | )% | | 695,587 |
| | 628,602 |
| | 11 | % |
| |
(1)
| Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets is calculated as total revenues and other for natural gas assets, less reimbursements for electricity-related expenses recorded as revenue and cost of product for natural gas assets, plus distributions from our equity investments in Fort Union and Rendezvous, and excluding the noncontrolling interest owner’s proportionate share of revenue and cost of product. See the reconciliation of Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets to its most comparable GAAP measure below. |
| |
(2)
| Adjusted gross margin for crude, NGL and produced water assets is calculated as total revenues and other for crude, NGL and produced water assets, less reimbursements for electricity-related expenses recorded as revenue and cost of product for crude, NGL and produced water assets, plus distributions from our equity investments in White Cliffs, the Mont Belvieu JV, and the TEFR Interests. See the reconciliation of Adjusted gross margin for crude, NGL and produced water assets to its most comparable GAAP measure below. |
| |
(3)
| For a reconciliation of Adjusted gross margin attributable to Western Gas Partners, LP, Adjusted EBITDA attributable to Western Gas Partners, LP and Distributable cash flow to the most directly comparable financial measure calculated and presented in accordance with GAAP, see the descriptions below. |
| |
(4)
| Average for period. Calculated as Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets, divided by total throughput (MMcf/d) attributable to Western Gas Partners, LP for natural gas assets. |
| |
(5)
| Average for period. Calculated as Adjusted gross margin for crude, NGL and produced water assets, divided by total throughput (MBbls/d) for crude, NGL and produced water assets. |
Adjusted gross margin attributable to Western Gas Partners, LP. margin. We define Adjusted gross margin attributable to Western GasMidstream Partners, LP (“Adjusted gross margin”) as total revenues and other (less reimbursements for electricity-related expenses recorded as revenue), less cost of product, and reimbursements for electricity-related expenses recorded as revenue, plus distributions from equity investments, and excluding the noncontrolling interest owner’sowners’ proportionate share of revenuerevenues and cost of product. We believe Adjusted gross margin is an important performance measure of the coreour operations’ profitability of our operations, as well as our operatingand performance as compared to that of other companies in the midstream industry. Cost of product expenses include (i) costs associated with the purchase of natural gas and NGLs pursuant to our industry.
percent-of-proceeds, percent-of-product, and keep-whole contracts, (ii) costs associated with the valuation of gas and NGLs imbalances, (iii) costs associated with our obligations under certain contracts to redeliver a volume of natural gas to shippers, which is thermally equivalent to condensate retained by us and sold to third parties, and (iv) costs associated with our offload commitments with third parties providing firm-processing capacity. The electricity-related expenses included in our Adjusted gross margin increaseddefinition relate to pass-through expenses that are reimbursed by $0.4 millioncertain customers (recorded as revenue with an offset recorded as Operation and $25.1 million for the three and nine months ended September 30, 2017, respectively, primarily due to (i) an increase in throughput at the DBM complex, (ii) an increase in processed volumes at the DJ Basin complex and (iii) the start-up of operations at the DBM water systems during the second quarter of 2017. These increases were partially offset by decreases from (i) the Property Exchange in March 2017, (ii) lower throughput at the Springfield and Marcellus Interest systems, (iii) the partial equity treatment of the above-market swap agreement at the MGR assets beginning January 1, 2017, and (iv) the sale of the Hugoton system in October 2016.maintenance expense).
To facilitate investor and industry analyst comparisons between us and our peers, we also disclose Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets and Adjusted gross margin per Bbl for crude, NGL and produced water assets. Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets increased by $0.15 and $0.10 for the three and nine months ended September 30, 2017, respectively, primarily due to the Property Exchange in March 2017 and increased throughput at the DBM complex. Adjusted gross margin per Bbl for crude, NGL and produced water assets decreased by $0.17 for the three months ended September 30, 2017, primarily due to (i) lower throughput at the Springfield oil gathering system, (ii) lower distributions received from the Mont Belvieu JV and (iii) the start-up of operations at the DBM water systems during the second quarter of 2017. Adjusted gross margin per Bbl for crude, NGL and produced water assets decreased by $0.05 for the nine months ended September 30, 2017, primarily due to (i) lower throughput at the Springfield oil gathering system and (ii) the start-up of operations at the DBM water systems during the second quarter of 2017. These decreases were partially offset during the three and nine months ended September 30, 2017, by higher distributions received from TEP.
Adjusted EBITDA attributable to Western Gas Partners, LP. EBITDA. We define Adjusted EBITDA attributable to Western GasMidstream Partners, LP (“Adjusted EBITDA”) as net income (loss) attributable to Western Gas Partners, LP,, plus (i) distributions from equity investments, non-cash equity-based(ii) non-cash equity-based compensation expense, (iii) interest expense, (iv) income tax expense, (v) depreciation and amortization, (vi) impairments, and (vii) other expense (including lower of cost or market inventory adjustments recorded in cost of product), less (i) gain (loss) on divestiture and other, net, (ii) gain (loss) on early extinguishment of debt, (iii) income from equity investments, (iv) interest income, (v) income tax benefit, (vi) other income, and other income.(vii) the noncontrolling interest owners’ proportionate share of revenues and expenses. We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations and that Adjusted EBITDA is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures, and make distributions. Adjusted EBITDA is a supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, commercial banks, and rating agencies, use, among other measures, to assess the following, among other measures:following:
•our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to financing methods, capital structure, or historical cost basis;
•the ability of our assets to generate cash flow to make distributions; and
•the viability of acquisitions and capital expenditure projectsexpenditures and the returns on investment of various investment opportunities.
Adjusted EBITDA decreasedFree cash flow.We define “Free cash flow” as net cash provided by $20.3 million for the three months ended September 30, 2017, primarily dueoperating activities less total capital expenditures and contributions to a $93.6 million increase in cost of product (net of lower of cost or market inventory adjustments), a $13.7 million decrease in business interruption proceeds, a $4.8 million increase in operation and maintenance expenses, and a $1.7 million increase in net income attributable to noncontrolling interest. These amounts were partially offset by a $93.1 million increase in total revenues and other and a $2.0 million increase inequity investments, plus distributions from equity investments.
Adjusted EBITDA increased by $27.8 million for the nine months ended September 30, 2017, primarily due to a $322.9 million increaseinvestments in total revenues and other, a $13.6 million increase in business interruption proceeds and a $4.3 million increase in distributions from equity investments. These amounts were partially offset by a $304.8 million increase in costexcess of product (net of lower of cost or market inventory adjustments), a $3.3 million increase in operation and maintenance expenses, a $2.4 million increase in general and administrative expenses excluding non-cash equity-based compensation expense, and a $2.3 million increase in property and other tax expense.
Distributable cash flow. We define “Distributable cash flow” as Adjusted EBITDA, plus interest income and the net settlement amounts from the sale and/or purchase of natural gas, condensate and NGLs under our commodity price swap agreements to the extent such amounts are not recognized as Adjusted EBITDA, less net cash paid (or to be paid) for interest expense (including amortization of deferred debt issuance costs originally paid in cash, offset by non-cash capitalized interest), maintenance capital expenditures, Series A Preferred unit distributions and income taxes. We compare Distributablecumulative earnings. Management considers Free cash flow to the cash distributions we expect to pay our unitholders. Using this measure, management can quickly compute the Coverage ratio of distributable cash flow to planned cash distributions. We believe Distributablean appropriate metric for assessing capital discipline, cost efficiency, and balance-sheet strength. Although Free cash flow is useful to investors because this measurement isthe metric used by many companies, analysts and others in the industry as a performance measurement tool to evaluate our operating and financial performance and compare it with the performance of other publicly traded partnerships.
While Distributable cash flow is a measure we use to assess ourWES’s ability to make distributions to our unitholders, itthis measure should not be viewed as indicative of the actual amount of cash that we haveis available for distributions or that we plan to distributeplanned for distributions for a given period. Furthermore, to the extent DistributableInstead, Free cash flow includes realized amounts recorded as capital contributions from Anadarko attributable to activity under our commodity price swap agreements, it is not a reflection of our ability to generate cash from operations.
Distributable cash flow decreased by $5.5 million for the three months ended September 30, 2017, primarily due to a $20.3 million decrease in Adjusted EBITDA and a $4.4 million increase in net cash paid for interest expense. These amounts were partially offset by a $14.9 million decrease in Series A Preferred unit distributions and a $4.7 million decrease in cash paid for maintenance capital expenditures.
Distributable cash flow increased by $67.0 million for the nine months ended September 30, 2017, primarily due to a $27.8 million increase in Adjusted EBITDA, a $23.4 million decrease in Series A Preferred unit distributions, a $22.2 million decrease in cash paid for maintenance capital expenditures and an $11.9 million increase in the above-market componentshould be considered indicative of the swap agreements with Anadarko. These amounts were partially offset by an $18.3 million increase in netamount of cash paidthat is available for interest expense.distributions, debt repayments, and other general partnership purposes.
Adjusted gross margin, Adjusted EBITDA, and DistributableFree cash flow are not defined in GAAP. The GAAP measure used by us that is most directly comparable to Adjusted gross margin is operatinggross margin. Net income (loss), while net income (loss) attributable to Western Gas Partners, LP and net cash provided by operating activities are the GAAP measures used by us that are most directly comparable to Adjusted EBITDA. The GAAP measure used by us that is most directly comparable to DistributableFree cash flow is net income (loss) attributable to Western Gas Partners, LP.cash provided by operating activities. Our non-GAAPnon-GAAP financial measures of Adjusted gross margin, Adjusted EBITDA, and DistributableFree cash flow should not be considered as alternatives to the GAAP measures of operatinggross margin, net income (loss), net income (loss) attributable to Western Gas Partners, LP, net cash provided by operating activities, or any other measure of financial performance presented in accordance with GAAP. Adjusted gross margin, Adjusted EBITDA, and DistributableFree cash flow have important limitations as analytical tools because they exclude some, but not all, items that affect operatinggross margin, net income (loss), net income (loss) attributable to Western Gas Partners, LP and net cash provided by operating activities. Adjusted gross margin, Adjusted EBITDA, and DistributableFree cash flow should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Our definitions of Adjusted gross margin, Adjusted EBITDA, and DistributableFree cash flow may not be comparable to similarly titled measures of other companies in our industry, thereby diminishing their utility.utility as comparative measures.
Management compensates for the limitations of Adjusted gross margin, Adjusted EBITDA, and DistributableFree cash flow as analytical tools by reviewing the comparable GAAP measures, understanding the differences between Adjusted gross margin, Adjusted EBITDA, and DistributableFree cash flow compared to (as applicable) operatinggross margin, net income (loss), net income (loss) attributable to Western Gas Partners, LP and net cash provided by operating activities, and incorporating this knowledge into its decision-makingdecision-making processes. We believe that investors benefit from having access to the same financial measures that our management usesconsiders in evaluating our operating results.
The following tables present (a)(i) a reconciliation of the GAAP financial measure of operating income (loss)gross margin to the non-GAAPnon-GAAP financial measure of Adjusted gross margin, (b)(ii) a reconciliation of the GAAP financial measures of net income (loss) attributable to Western Gas Partners, LP and net cash provided by operating activities to the non-GAAPnon-GAAP financial measure of Adjusted EBITDA, and (c)(iii) a reconciliation of the GAAP financial measure of net income (loss) attributable to Western Gas Partners, LPcash provided by operating activities to the non-GAAPnon-GAAP financial measure of DistributableFree cash flow:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | |
| | Three Months Ended | | Nine Months Ended |
| | | | | | |
| thousands | | September 30, 2023 | | June 30, 2023 | | September 30, 2023 | | September 30, 2022 | | |
| Reconciliation of Gross margin to Adjusted gross margin | | |
| Total revenues and other | | $ | 776,013 | | | $ | 738,273 | | | $ | 2,248,268 | | | $ | 2,472,284 | | | |
| Less: | | | | | | | | | | |
| Cost of product | | 27,590 | | | 44,746 | | | 123,795 | | | 328,237 | | | |
| Depreciation and amortization | | 147,363 | | | 143,492 | | | 435,481 | | | 430,455 | | | |
| Gross margin | | 601,060 | | | 550,035 | | | 1,688,992 | | | 1,713,592 | | | |
| Add: | | | | | | | | | | |
| Distributions from equity investments | | 41,562 | | | 54,075 | | | 147,612 | | | 180,768 | | | |
| Depreciation and amortization | | 147,363 | | | 143,492 | | | 435,481 | | | 430,455 | | | |
| Less: | | | | | | | | | | |
| Reimbursed electricity-related charges recorded as revenues | | 29,981 | | | 23,286 | | | 76,836 | | | 58,187 | | | |
Adjusted gross margin attributable to noncontrolling interests (1) | | 18,095 | | | 16,914 | | | 50,783 | | | 56,142 | | | |
| Adjusted gross margin | | $ | 741,909 | | | $ | 707,402 | | | $ | 2,144,466 | | | $ | 2,210,486 | | | |
(1)For all periods presented, includes (i) the 25% third-party interest in Chipeta and (ii) the 2.0% limited partner interest in WES Operating owned by an Occidental subsidiary, which collectively represent WES’s noncontrolling interests.
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| thousands | | 2017 | | 2016 | | 2017 | | 2016 |
| Reconciliation of Operating income (loss) to Adjusted gross margin attributable to Western Gas Partners, LP | | | | | | | | |
| Operating income (loss) | | $ | 179,456 |
| | $ | 197,288 |
|
| $ | 525,456 |
|
| $ | 527,053 |
|
| Add: | | | | | | | | |
| Distributions from equity investments | | 29,145 |
| | 27,133 |
| | 80,568 |
| | 76,263 |
|
| Operation and maintenance | | 79,536 |
| | 74,755 |
| | 229,444 |
| | 226,141 |
|
| General and administrative | | 12,158 |
| | 11,382 |
| | 35,402 |
| | 33,542 |
|
| Property and other taxes | | 11,215 |
| | 10,670 |
| | 35,433 |
| | 33,098 |
|
| Depreciation and amortization | | 72,539 |
| | 67,246 |
| | 216,272 |
| | 199,646 |
|
| Impairments | | 2,159 |
| | 2,392 |
| | 170,079 |
| | 11,313 |
|
| Less: | | | | | | | | |
| Gain (loss) on divestiture and other, net | | 72 |
| | (6,230 | ) | | 135,017 |
| | (8,769 | ) |
| Proceeds from business interruption insurance claims | | — |
| | 13,667 |
| | 29,882 |
| | 16,270 |
|
| Equity income, net – affiliates | | 21,519 |
| | 20,294 |
| | 62,708 |
| | 56,801 |
|
| Reimbursed electricity-related charges recorded as revenues | | 14,323 |
| | 15,170 |
| | 42,338 |
| | 45,707 |
|
| Adjusted gross margin attributable to noncontrolling interest | | 5,878 |
| | 3,984 |
| | 13,189 |
| | 12,588 |
|
| Adjusted gross margin attributable to Western Gas Partners, LP | | $ | 344,416 |
| | $ | 343,981 |
| | $ | 1,009,520 |
| | $ | 984,459 |
|
| Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets | | $ | 305,337 |
| | $ | 306,393 |
| | $ | 904,620 |
| | $ | 877,583 |
|
| Adjusted gross margin for crude, NGL and produced water assets | | 39,079 |
| | 37,588 |
| | 104,900 |
| | 106,876 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | |
| | Three Months Ended | | Nine Months Ended |
| | | | | | |
| thousands except per-unit amounts | | September 30, 2023 | | June 30, 2023 | | September 30, 2023 | | September 30, 2022 | | |
| Gross margin | | | | | | | | | | |
Gross margin for natural-gas assets (1) | | $ | 450,130 | | | $ | 409,634 | | | $ | 1,253,437 | | | $ | 1,273,689 | | | |
Gross margin for crude-oil and NGLs assets (1) | | 87,911 | | | 88,024 | | | 265,216 | | | 270,716 | | | |
Gross margin for produced-water assets (1) | | 70,353 | | | 59,130 | | | 189,032 | | | 184,085 | | | |
Per-Mcf Gross margin for natural-gas assets (2) | | 1.05 | | | 1.02 | | | 1.03 | | | 1.07 | | | |
Per-Bbl Gross margin for crude-oil and NGLs assets (2) | | 1.40 | | | 1.51 | | | 1.50 | | | 1.42 | | | |
Per-Bbl Gross margin for produced-water assets (2) | | 0.69 | | | 0.68 | | | 0.68 | | | 0.80 | | | |
| Adjusted gross margin | | | | | | | | | | |
Adjusted gross margin for natural-gas assets | | $ | 518,765 | | | $ | 489,476 | | | $ | 1,488,250 | | | $ | 1,539,009 | | | |
Adjusted gross margin for crude-oil and NGLs assets | | 139,430 | | | 147,036 | | | 432,043 | | | 457,158 | | | |
Adjusted gross margin for produced-water assets | | 83,714 | | | 70,890 | | | 224,173 | | | 214,319 | | | |
Per-Mcf Adjusted gross margin for natural-gas assets (3) | | 1.26 | | | 1.26 | | | 1.27 | | | 1.34 | | | |
Per-Bbl Adjusted gross margin for crude-oil and NGLs assets (3) | | 2.27 | | | 2.58 | | | 2.49 | | | 2.44 | | | |
Per-Bbl Adjusted gross margin for produced-water assets (3) | | 0.84 | | | 0.83 | | | 0.83 | | | 0.94 | | | |
(1)Excludes corporate-level depreciation and amortization.
(2)Average for period. Calculated as Gross margin for natural-gas assets, crude-oil and NGLs assets, or produced-water assets, divided by the respective total throughput (MMcf or MBbls) for natural-gas assets, crude-oil and NGLs assets, or produced-water assets.
(3)Average for period. Calculated as Adjusted gross margin for natural-gas assets, crude-oil and NGLs assets, or produced-water assets, divided by the respective total throughput (MMcf or MBbls) attributable to WES for natural-gas assets, crude-oil and NGLs assets, or produced-water assets.
| | | | | | | | | | | | | Three Months Ended | | Nine Months Ended |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | |
| thousands | | 2017 | | 2016 | | 2017 | | 2016 | thousands | | September 30, 2023 | | June 30, 2023 | | September 30, 2023 | | September 30, 2022 | |
| Reconciliation of Net income (loss) attributable to Western Gas Partners, LP to Adjusted EBITDA attributable to Western Gas Partners, LP | | | | | | | | | |
| Net income (loss) attributable to Western Gas Partners, LP | | $ | 143,506 |
| | $ | 167,746 |
| | $ | 418,846 |
| | $ | 448,327 |
| |
| Reconciliation of Net income (loss) to Adjusted EBITDA | | Reconciliation of Net income (loss) to Adjusted EBITDA |
| Net income (loss) | | Net income (loss) | | $ | 284,398 | | | $ | 259,516 | | | $ | 752,255 | | | $ | 906,422 | | |
| Add: | | | | | | | | | Add: | | |
| Distributions from equity investments | | 29,145 |
| | 27,133 |
| | 80,568 |
| | 76,263 |
| Distributions from equity investments | | 41,562 | | | 54,075 | | | 147,612 | | | 180,768 | | |
| Non-cash equity-based compensation expense | | 1,258 |
| | 1,469 |
| | 3,479 |
| | 4,018 |
| |
Non-cash equity-based compensation expense | | Non-cash equity-based compensation expense | | 7,171 | | | 7,665 | | | 22,035 | | | 21,245 | | |
| Interest expense | | 35,544 |
| | 30,768 |
| | 106,794 |
| | 75,687 |
| Interest expense | | 82,754 | | | 86,182 | | | 250,606 | | | 249,333 | | |
| Income tax expense | | 510 |
| | 472 |
| | 4,905 |
| | 7,431 |
| Income tax expense | | 905 | | | 659 | | | 2,980 | | | 3,683 | | |
Depreciation and amortization (1) | | 71,812 |
| | 66,589 |
| | 214,213 |
| | 197,678 |
| |
| Depreciation and amortization | | Depreciation and amortization | | 147,363 | | | 143,492 | | | 435,481 | | | 430,455 | | |
| Impairments | | 2,159 |
| | 2,392 |
| | 170,079 |
| | 11,313 |
| Impairments | | 245 | | | 234 | | | 52,880 | | | 94 | | |
Other expense (1) | | — |
| | 40 |
| | 140 |
| | 96 |
| |
| Other expense | | Other expense | | 1,269 | | | 199 | | | 1,668 | | | 346 | | |
| Less: | | | | | | | | | Less: | | |
| Gain (loss) on divestiture and other, net | | 72 |
| | (6,230 | ) | | 135,017 |
| | (8,769 | ) | Gain (loss) on divestiture and other, net | | (1,480) | | | (70) | | | (3,668) | | | (884) | | |
| Equity income, net – affiliates | | 21,519 |
| | 20,294 |
| | 62,708 |
| | 56,801 |
| |
| Interest income – affiliates | | 4,225 |
| | 4,225 |
| | 12,675 |
| | 12,675 |
| |
Other income (1) | | 283 |
| | 150 |
| | 960 |
| | 272 |
| |
| Adjusted EBITDA attributable to Western Gas Partners, LP | | $ | 257,835 |
| | $ | 278,170 |
| | $ | 787,664 |
| | $ | 759,834 |
| |
| Reconciliation of Net cash provided by operating activities to Adjusted EBITDA attributable to Western Gas Partners, LP | | | | | | | | | |
| Gain (loss) on early extinguishment of debt | | Gain (loss) on early extinguishment of debt | | 8,565 | | | 6,813 | | | 15,378 | | | 91 | | |
| Equity income, net – related parties | | Equity income, net – related parties | | 35,494 | | | 42,324 | | | 116,839 | | | 139,388 | | |
| | Other income | | Other income | | 27 | | | 2,872 | | | 4,114 | | | 164 | | |
| Adjusted EBITDA attributable to noncontrolling interests (1) | | Adjusted EBITDA attributable to noncontrolling interests (1) | | 12,134 | | | 11,737 | | | 34,886 | | | 41,395 | | |
| Adjusted EBITDA | | Adjusted EBITDA | | $ | 510,927 | | | $ | 488,346 | | | $ | 1,497,968 | | | $ | 1,612,192 | | |
| Reconciliation of Net cash provided by operating activities to Adjusted EBITDA | | Reconciliation of Net cash provided by operating activities to Adjusted EBITDA |
| Net cash provided by operating activities | | $ | 211,947 |
| | $ | 263,872 |
| | $ | 645,099 |
| | $ | 657,738 |
| Net cash provided by operating activities | | $ | 394,787 | | | $ | 490,823 | | | $ | 1,188,034 | | | $ | 1,212,207 | | |
| Interest (income) expense, net | | 31,319 |
| | 26,543 |
| | 94,119 |
| | 63,012 |
| Interest (income) expense, net | | 82,754 | | | 86,182 | | | 250,606 | | | 249,333 | | |
| Uncontributed cash-based compensation awards | | 78 |
| | 290 |
| | (94 | ) | | 448 |
| |
| Accretion and amortization of long-term obligations, net | | (1,055 | ) | | 121 |
| | (3,194 | ) | | 9,176 |
| |
| Current income tax (benefit) expense | | 395 |
| | 131 |
| | 1,023 |
| | 5,110 |
| |
Accretion and amortization of long-term obligations, net | | Accretion and amortization of long-term obligations, net | | (1,882) | | | (2,403) | | | (5,977) | | | (5,359) | | |
| Current income tax expense (benefit) | | Current income tax expense (benefit) | | 806 | | | 728 | | | 2,026 | | | 1,926 | | |
| Other (income) expense, net | | (286 | ) | | (153 | ) | | (969 | ) | | (224 | ) | Other (income) expense, net | | 1,270 | | | (2,872) | | | (2,817) | | | (117) | | |
| Distributions from equity investments in excess of cumulative earnings – affiliates | | 7,034 |
| | 5,981 |
| | 16,255 |
| | 16,592 |
| |
| Changes in operating working capital: | | | | | | | | | |
| | Distributions from equity investments in excess of cumulative earnings – related parties | | Distributions from equity investments in excess of cumulative earnings – related parties | | 8,536 | | | 10,813 | | | 31,715 | | | 41,058 | | |
| Changes in assets and liabilities: | | Changes in assets and liabilities: | | |
| Accounts receivable, net | | 56,335 |
| | 7,866 |
| | 46,972 |
| | 41,108 |
| Accounts receivable, net | | 60,614 | | | (4,078) | | | 60,573 | | | 212,955 | | |
| Accounts and imbalance payables and accrued liabilities, net | | (45,982 | ) | | (26,330 | ) | | (4,007 | ) | | (24,103 | ) | Accounts and imbalance payables and accrued liabilities, net | | (12,535) | | | (36,885) | | | 87,040 | | | (65,069) | | |
| Other | | 3,181 |
| | 3,184 |
| | 3,065 |
| | 1,445 |
| |
| Adjusted EBITDA attributable to noncontrolling interest | | (5,131 | ) | | (3,335 | ) | | (10,605 | ) | | (10,468 | ) | |
| Adjusted EBITDA attributable to Western Gas Partners, LP | | $ | 257,835 |
| | $ | 278,170 |
| | $ | 787,664 |
| | $ | 759,834 |
| |
| Cash flow information of Western Gas Partners, LP | | | | | | | | | |
| Other items, net | | Other items, net | | (11,289) | | | (42,225) | | | (78,346) | | | 6,653 | | |
Adjusted EBITDA attributable to noncontrolling interests (1) | | Adjusted EBITDA attributable to noncontrolling interests (1) | | (12,134) | | | (11,737) | | | (34,886) | | | (41,395) | | |
| Adjusted EBITDA | | Adjusted EBITDA | | $ | 510,927 | | | $ | 488,346 | | | $ | 1,497,968 | | | $ | 1,612,192 | | |
| Cash flow information | | Cash flow information |
| Net cash provided by operating activities | | | | | | $ | 645,099 |
| | $ | 657,738 |
| Net cash provided by operating activities | | $ | 394,787 | | | $ | 490,823 | | | $ | 1,188,034 | | | $ | 1,212,207 | | |
| Net cash used in investing activities | | | | | | (514,797 | ) | | (1,040,692 | ) | Net cash used in investing activities | | (207,916) | | | (151,490) | | | (538,584) | | | (356,252) | | |
| Net cash provided by (used in) financing activities | | | | | | (335,792 | ) | | 429,368 |
| Net cash provided by (used in) financing activities | | 88,670 | | | (238,025) | | | (446,612) | | | (898,861) | | |
(1)For all periods presented, includes (i) the 25% third-party interest in Chipeta and (ii) the 2.0% limited partner interest in WES Operating owned by an Occidental subsidiary, which collectively represent WES’s noncontrolling interests.
| |
(1)
| Includes our 75% share of depreciation and amortization; other expense; and other income attributable to the Chipeta complex. |
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| thousands except Coverage ratio | | 2017 | | 2016 | | 2017 | | 2016 |
| Reconciliation of Net income (loss) attributable to Western Gas Partners, LP to Distributable cash flow and calculation of the Coverage ratio | | | | | | | | |
| Net income (loss) attributable to Western Gas Partners, LP | | $ | 143,506 |
| | $ | 167,746 |
| | $ | 418,846 |
| | $ | 448,327 |
|
| Add: | | | | | | | | |
| Distributions from equity investments | | 29,145 |
| | 27,133 |
| | 80,568 |
| | 76,263 |
|
| Non-cash equity-based compensation expense | | 1,258 |
| | 1,469 |
| | 3,479 |
| | 4,018 |
|
Non-cash settled - interest expense, net (1) | | — |
| | (1,173 | ) | | 71 |
| | (12,097 | ) |
| Income tax (benefit) expense | | 510 |
| | 472 |
| | 4,905 |
| | 7,431 |
|
Depreciation and amortization (2) | | 71,812 |
| | 66,589 |
| | 214,213 |
| | 197,678 |
|
| Impairments | | 2,159 |
| | 2,392 |
| | 170,079 |
| | 11,313 |
|
Above-market component of swap agreements with Anadarko (3) | | 18,049 |
| | 18,417 |
| | 46,719 |
| | 34,782 |
|
Other expense (2) | | — |
| | 40 |
| | 140 |
| | 96 |
|
| Less: | | | | | | | | |
| Gain (loss) on divestiture and other, net | | 72 |
| | (6,230 | ) | | 135,017 |
| | (8,769 | ) |
| Equity income, net – affiliates | | 21,519 |
| | 20,294 |
| | 62,708 |
| | 56,801 |
|
Cash paid for maintenance capital expenditures (2) | | 10,591 |
| | 15,306 |
| | 33,115 |
| | 55,288 |
|
| Capitalized interest | | 2,115 |
| | 1,343 |
| | 3,991 |
| | 4,674 |
|
| Cash paid for (reimbursement of) income taxes | | — |
| | — |
| | 189 |
| | 67 |
|
| Series A Preferred unit distributions | | — |
| | 14,907 |
| | 7,453 |
| | 30,876 |
|
Other income (2) | | 283 |
| | 150 |
| | 960 |
| | 272 |
|
| Distributable cash flow | | $ | 231,859 |
| | $ | 237,315 |
| | $ | 695,587 |
| | $ | 628,602 |
|
Distributions declared (4) | | | | | | | | |
| Limited partners – common units | | $ | 138,105 |
| | | | $ | 397,850 |
| | |
| General partner | | 73,933 |
| | | | 210,432 |
| | |
| Total | | $ | 212,038 |
| | | | $ | 608,282 |
| | |
| Coverage ratio | | 1.09 |
| x | | | 1.14 |
| x | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | |
| | Three Months Ended | | Nine Months Ended | | |
| | | | | | |
| thousands | | September 30, 2023 | | June 30, 2023 | | September 30, 2023 | | September 30, 2022 | | |
| Reconciliation of Net cash provided by operating activities to Free cash flow |
| Net cash provided by operating activities | | $ | 394,787 | | | $ | 490,823 | | | $ | 1,188,034 | | | $ | 1,212,207 | | | |
| Less: | | | | | | | | | | |
| Capital expenditures | | 201,857 | | | 161,482 | | | 536,427 | | | 341,505 | | | |
| Contributions to equity investments – related parties | | 1,021 | | | 22 | | | 1,153 | | | 8,899 | | | |
| Add: | | | | | | | | | | |
| Distributions from equity investments in excess of cumulative earnings – related parties | | 8,536 | | | 10,813 | | | 31,715 | | | 41,058 | | | |
| Free cash flow | | $ | 200,445 | | | $ | 340,132 | | | $ | 682,169 | | | $ | 902,861 | | | |
| Cash flow information | | | | | | | | | | |
| Net cash provided by operating activities | | $ | 394,787 | | | $ | 490,823 | | | $ | 1,188,034 | | | $ | 1,212,207 | | | |
| Net cash used in investing activities | | (207,916) | | | (151,490) | | | (538,584) | | | (356,252) | | | |
| Net cash provided by (used in) financing activities | | 88,670 | | | (238,025) | | | (446,612) | | | (898,861) | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| |
(1)
| Includes amounts related to the Deferred purchase price obligation - Anadarko. See Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
|
| |
(2)
| Includes our 75% share of depreciation and amortization; other expense; cash paid for maintenance capital expenditures; and other income attributable to the Chipeta complex. |
| |
(3)
| See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
|
| |
(4)
| Reflects cash distributions of $0.905 and $2.670 per unit declared for the three and nine months ended September 30, 2017, respectively. |
Gross margin. Refer to Operating Results within this Item 2 for a discussion of the components of Gross margin as compared to the prior periods, including Service Revenues, Product Sales, Cost of Product (Residue purchases, NGLs purchases, and Other items), and Other Operating Expenses (Depreciation and amortization expense).
Gross margin increased by $51.0 million for the three months ended September 30, 2023, due to (i) a $37.7 million increase in total revenues and other and (ii) a $17.2 million decrease in cost of product. These amounts were offset partially by a $3.9 million increase in depreciation and amortization.
Gross margin decreased by $24.6 million for the nine months ended September 30, 2023, due to (i) a $224.0 million decrease in total revenues and other and (ii) a $5.0 million increase in depreciation and amortization. These amounts were offset partially by a $204.4 million decrease in cost of product.
Net income (loss). Refer to Operating Results within this Item 2 for a discussion of the primary components of Net income (loss) as compared to the prior periods.
Net income (loss) increased by $24.9 million for the three months ended September 30, 2023, primarily due to a $37.7 million increase in total revenues and other. This increase was offset partially by (i) a $6.8 million decrease in equity income, net – related parties and (ii) a $4.1 million decrease in other income (expense), net.
Net income (loss) decreased by $154.2 million for the nine months ended September 30, 2023, primarily due to (i) a $224.0 million decrease in total revenues and other and (ii) a $22.5 million decrease in equity income, net – related parties. These amounts were offset partially by (i) a $77.8 million decrease in total operating expenses and (ii) a $15.3 million increase in gain (loss) on early extinguishment of debt.
Net cash provided by operating activities. Refer to Historical cash flow within this Item 2 for a discussion of the primary components of Net cash provided by operating activities as compared to the prior periods.
KEY PERFORMANCE METRICS
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
| | Three Months Ended | | Nine Months Ended | | | | |
| | | | | | | | |
| thousands except percentages and per-unit amounts | | September 30, 2023 | | June 30, 2023 | | Inc/
(Dec) | | September 30, 2023 | | September 30, 2022 | | Inc/
(Dec) | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| Adjusted gross margin | | $ | 741,909 | | | $ | 707,402 | | | 5 | % | | $ | 2,144,466 | | | $ | 2,210,486 | | | (3) | % | | | | |
Per-Mcf Adjusted gross margin for natural-gas assets (1) | | 1.26 | | | 1.26 | | | — | % | | 1.27 | | | 1.34 | | | (5) | % | | | | |
Per-Bbl Adjusted gross margin for crude-oil and NGLs assets (1) | | 2.27 | | | 2.58 | | | (12) | % | | 2.49 | | | 2.44 | | | 2 | % | | | | |
Per-Bbl Adjusted gross margin for produced-water assets (1) | | 0.84 | | | 0.83 | | | 1 | % | | 0.83 | | | 0.94 | | | (12) | % | | | | |
| Adjusted EBITDA | | 510,927 | | | 488,346 | | | 5 | % | | 1,497,968 | | | 1,612,192 | | | (7) | % | | | | |
| Free cash flow | | 200,445 | | | 340,132 | | | (41) | % | | 682,169 | | | 902,861 | | | (24) | % | | | | |
(1)Average for period. Calculated as Adjusted gross margin for natural-gas assets, crude-oil and NGLs assets, or produced-water assets, divided by the respective total throughput (MMcf or MBbls) attributable to WES for natural-gas assets, crude-oil and NGLs assets, or produced-water assets.
Adjusted gross margin. Adjusted gross margin increased by $34.5 million for the three months ended September 30, 2023, primarily due to (i) increased throughput and deficiency fees at the West Texas complex, and (ii) increased throughput at the DBM water systems and DJ Basin complex. These increases were partially offset by (i) decreased processing fees at the Brasada complex and (ii) a decrease in distributions from Mi Vida and Mont Belvieu JV.
Adjusted gross margin decreased by $66.0 million for the nine months ended September 30, 2023, primarily due to (i) a decrease in distributions from Cactus II, which was sold in the fourth quarter of 2022, (ii) decreased deficiency fees and throughput at the Chipeta complex, (iii) decreased throughput at the DJ Basin oil system and Granger complex, (iv) a decrease in distributions from Ranch Westex, which was acquired in the third quarter of 2022 and is included in the West Texas complex subsequent to the acquisition, and (v) decreased throughput partially offset by increased deficiency fees at the DJ Basin complex. These decreases were partially offset by (i) increased throughput at the West Texas complex and (ii) increased throughput, partially offset by decreased deficiency fees at the DBM water systems.
Per-Mcf Adjusted gross margin for natural-gas assets decreased by $0.07 for the nine months ended September 30, 2023, primarily due to lower commodity prices and contract mix, partially offset by increased throughput at the West Texas complex.
Per-Bbl Adjusted gross margin for crude-oil and NGLs assets decreased by $0.31 for the three months ended September 30, 2023, primarily due to (i) a decrease in distributions, coupled with an increase in throughput from Whitethorn LLC, which has a lower-than-average per-Bbl margin as compared to our other crude-oil and NGLs assets, and (ii) decreases in distributions from TEP and Mont Belvieu JV.
Per-Bbl Adjusted gross margin for crude-oil and NGLs assets increased by $0.05 for the nine months ended September 30, 2023, primarily due to (i) decreases in throughput and distributions from Cactus II, which was sold in the fourth quarter of 2022 and had lower-than-average per-Bbl margin as compared to our other crude-oil and NGLs assets and (ii) increases in distributions from FRP and TEP. These increases were partially offset by (i) decreases in distributions from Whitethorn LLC and Mont Belvieu JV, and (ii) decreases in throughput at the DJ Basin oil system which has a higher-than-average per-Bbl margin as compared to our other crude-oil and NGLs assets.
Per-Bbl Adjusted gross margin for produced-water assets decreased by $0.11 for the nine months ended September 30, 2023, primarily due to a lower average fee resulting from a cost-of-service rate redetermination effective January 1, 2023, and lower deficiency fee revenues.
Adjusted EBITDA. Adjusted EBITDA increased by $22.6 million for the three months ended September 30, 2023, primarily due to (i) a $37.7 million increase in total revenues and other, (ii) a $16.9 million decrease in cost of product (net of lower of cost or market inventory adjustments), and (iii) a $4.0 million decrease in property and other taxes. These amounts were offset partially by (i) a $21.0 million increase in operation and maintenance expenses and (ii) a $12.5 million decrease in distributions from equity investments.
Adjusted EBITDA decreased by $114.2 million for the nine months ended September 30, 2023, primarily due to (i) a $224.0 million decrease in total revenues and other, (ii) a $74.5 million increase in operation and maintenance expenses, (iii) a $33.2 million decrease in distributions from equity investments, and (iv) a $14.1 million increase in general and administrative expenses excluding non-cash equity-based compensation expense. These amounts were offset partially by (i) a $204.5 million decrease in cost of product (net of lower of cost or market inventory adjustments) and (ii) a $20.5 million decrease in property and other taxes.
Free cash flow.Free cash flow decreased by $139.7 million for the three months ended September 30, 2023, primarily due to (i) a $96.0 million decrease in net cash provided by operating activities and (ii) a $40.4 million increase in capital expenditures.
Free cash flow decreased by $220.7 million for the nine months ended September 30, 2023, primarily due to a $194.9 million increase in capital expenditures (ii) a $24.2 million decrease in net cash provided by operating activities, and (iii) a $9.3 million decrease in distributions from equity investments in excess of cumulative earnings. These amounts were offset partially by a $7.7 million decrease in contributions to equity investments.
See Capital Expenditures and Historical Cash Flow within this Item 2 for further information.
LIQUIDITY AND CAPITAL RESOURCES
Our primary cash requirements are for acquisitionsuses include equity and debt service, operating expenses, and capital expenditures, debt service, customary operating expenses, quarterly distributions to our limited partners and general partner, and distributions to our noncontrolling interest owner.expenditures. Our sources of liquidity as of September 30, 2017,2023, included cash and cash equivalents, cash flows generated from operations, interest income on our $260.0 million note receivable from Anadarko, available borrowing capacity under ourthe RCF, and potential issuances of additional equity or debt securities. We believe that cash flows generated from these sources will be sufficient to satisfy our short-termshort-term working capital requirements and long-term maintenancelong-term capital-expenditure and expansion capital expendituredebt-service requirements.
The amount of future distributions to unitholders will depend on our results of operations, financial condition, capital requirements and other factors, including the extension of our commodity price swap agreements, and will be determined by the Board of Directors on a quarterly basis. Due toUnder our cash distribution policy, we expect to rely on external financing sources, including equity and debt issuances, to fund expansion capital expenditures and future acquisitions. However, to limit interest expense, we may use operating cash flows to fund expansion capital expenditures or acquisitions, which could result in subsequent borrowings under our RCF to pay distributions or fund other short-term working capital requirements.
During the second quarter of 2017, we reached a settlement with insurers related to the insurance claim filed for the incident at the DBM complex and final proceeds were received. Recoveries from the business interruption claim related to the DBM outage were recognized as income when cash proceeds were received from insurers. During the nine months ended September 30, 2017, we received $52.9 million in cash proceeds from insurers in final settlement of our claims related to the incident at the DBM complex, including $29.9 million for business interruption insurance claims and $23.0 million for property insurance claims (see Note 1—Description of Business and Basis of Presentation in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q).
Our partnership agreement, requires that we distribute all of our available cash (as(beyond proper reserves as defined in theour partnership agreement) within 55 days following each quarter’s end. Our cash flow and resulting ability to unitholders of recordmake cash distributions are dependent on the applicable record date within 45 days ofour ability to generate cash flow from operations. Generally, our available cash is our cash on hand at the end of eacha quarter after the payment of our expenses and the establishment of cash reserves and cash on hand resulting from working capital borrowings made after the end of the quarter. We have madeThe general partner establishes cash reserves to provide for the proper conduct of our business, including (i) to fund future capital expenditures, (ii) to comply with applicable laws, debt instruments, or other agreements, or (iii) to provide funds for unitholder distributions to our unitholders each quarter since our IPO and have increased our quarterly distribution each quarter sincefor any one or more of the second quarter of 2009.next four quarters. The Board of Directors declared a cash distribution to our unitholders for the third quarter of 20172023 of $0.905$0.5750 per unit, a 2.2% increase from the prior quarter, or $212.0$223.4 million in aggregate, including incentive distributions, but excluding distributions on Class C units.the aggregate. The cash distribution is payable on November 13, 2017,2023, to our unitholders of record at the close of business on November 2, 2017. In connection1, 2023.
To facilitate the distribution of available cash, during 2022 we adopted a financial policy that provided for an additional distribution (“Enhanced Distribution”) to be paid in conjunction with the closingregular first-quarter distribution of the DBM acquisitionfollowing year (beginning in November 2014, we issued Class C units that will receive distributions2023), in a target amount equal to Free cash flow generated in the formprior year after subtracting Free cash flow used for the prior year’s debt repayments, regular-quarter distributions, and unit repurchases. This Enhanced Distribution is subject to Board discretion, the establishment of additional Class Ccash reserves for the proper conduct of our business and is also contingent on the attainment of prior year-end net leverage thresholds (the ratio of our total principal debt outstanding less total cash on hand as of the end of such period, as compared to our trailing-twelve-months Adjusted EBITDA), after taking the Enhanced Distribution for such prior year into effect. Free cash flow and Adjusted EBITDA are defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 2. In April 2023, the Board approved an Enhanced Distribution of $0.356 per unit, or $140.1 million, related to our 2022 performance, which was paid in conjunction with our regular first-quarter 2023 distribution on May 15, 2023.
In 2022, we announced a common-unit buyback program of up to $1.25 billion through December 31, 2024. The common units until March 1, 2020, unless earlier converted (see Note 3—Partnership Distributionsmay be purchased from time to time in the Notesopen market at prevailing market prices or in privately negotiated transactions. The timing and amount of purchases under the program will be determined based on ongoing assessments of capital needs, our financial performance, the market price of our common units, and other factors, including organic growth and acquisition opportunities and general market conditions. The program does not obligate us to Consolidated Financial Statementspurchase any specific dollar amount or number of units and may be suspended or discontinued at any time. During the nine months ended September 30, 2023, we repurchased 5,387,322 common units, which includes 5,100,000 common units repurchased from Occidental, for an aggregate purchase price of $134.6 million. The units were canceled immediately upon receipt. As of September 30, 2023, we had an authorized amount of $627.8 million remaining under Part I, Item 1the program.
For the year ended December 31, 2023, capital expenditures are expected to range between $700.0 million to $800.0 million (accrual-based, includes equity investments, excludes capitalized interest, and excludes capital expenditures associated with the 25% third-party interest in Chipeta), representing a $125.0 million increase to the midpoint of this Form 10-Q). The Class C unit distribution, if paidour previously announced guidance in cash, would have been $11.7 million forFebruary 2023. Total-year capital expenditures guidance includes capital expenditures attributable to (i) a portion of Mentone Train III, (ii) a portion of the third quarterNorth Loving plant, a new 250 MMcf/d cryogenic processing plant in the North Loving area of 2017.our West Texas complex that was sanctioned in May 2023, and (iii) additional expansion capital needed to support new commercial activity.
Management continuously monitors our leverage position and coordinatesother financial projections to manage the capital structure according to long-term objectives. We may, from time to time, seek to retire, rearrange, or amend some or all of our capital expenditure program, quarterly distributionsoutstanding debt or financing agreements through cash purchases, exchanges, open-market repurchases, privately negotiated transactions, tender offers, or otherwise. Such transactions, if any, will depend on prevailing market conditions, our liquidity position and acquisition strategy with our expected cash flowsrequirements, contractual restrictions, and projected debt-repayment schedule. We will continue to evaluate funding alternatives, including additional borrowingsother factors and the issuance of debt or equity securities, to secure funds as needed or to refinance outstanding debt balances with longer term notes. To facilitate a potential debt or equity securities issuance, we have the ability to sell securities under our shelf registration statements.amounts involved may be material. Our ability to generate cash flows is subject to a number of factors, some of which are beyond our control. Read Risk Factors under Part II, Item 1A of this Form 10-Q.
Working capital. As of September 30, 2017, we had a $35.0 million working capital deficit, which we define as the amount by which current liabilities exceed current assets. Working capital is an indication of our liquidity and potential needneeds for short-termshort-term funding. Our workingWorking capital requirements are driven by changes in accounts receivable and accounts payable and other factors such as credit extended to, and the timing of collections from, our customers, and the level and timing of our spending for acquisitions, maintenance, and expansion activity. Our workingother capital deficit as of September 30, 2017, was primarily due to the costs incurred related to continued construction and expansion at the DBM and DJ Basin complexes and the DBJV system.activities. As of September 30, 2017,2023, we had $945.4a $499.9 million working capital surplus, which we define as the amount by which current assets exceed current liabilities. As of September 30, 2023, there was $2.0 billion available for borrowing under ourthe RCF. See Note 9—Selected Components of Working Capital and Note 10—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
Capital expenditures. Our business is capital intensive, requiring significant investment to maintain and improve existing facilities or to develop new midstream infrastructure. We categorize capitalCapital expenditures as either of the following:
include maintenance capital expenditures, which include those expenditures required to maintain the existing operating capacity and service capability of our assets, such as to replace system components and equipment that have been subject to significant use over time, become obsolete or reached the end of their useful lives, to remain in compliance with regulatory or legal requirements or to complete additional well connections to maintain existing system throughput and related cash flows (for fiscal year 2017, the general partner’s Board of Directors has approved Estimated Maintenance Capital Expenditures (as defined in our partnership agreement) of $18.0 million per quarter); or
expansion capital expenditures, which include expenditures to construct new midstream infrastructure and those expenditures incurred to extend the useful lives of our assets, reduce costs, increase revenues, or increase system throughput or capacity from current levels, including well connections that increase existing system throughput.
levels.
Capital expenditures in the consolidated statements of cash flows reflect capital expenditures on a cash basis, when payments are made. Capital incurred is presented on an accrual basis. Capital expenditures as presented in the consolidated statements of cash flows and capital incurred were as follows:
| | | | | | | | | | | | | | | | |
| | Nine Months Ended
September 30, |
| | |
| thousands | | 2023 | | 2022 | | |
| Acquisitions | | $ | — | | | $ | 41,018 | | | |
Capital expenditures (1) | | 536,427 | | | 341,505 | | | |
Capital incurred (1) | | 566,224 | | | 377,650 | | | |
|
| | | | | | | | |
| | | Nine Months Ended
September 30, |
| thousands | | 2017 | | 2016 |
| Acquisitions | | $ | 159,208 |
| | $ | 716,465 |
|
| | | | | |
| Expansion capital expenditures | | $ | 384,416 |
| | $ | 312,505 |
|
| Maintenance capital expenditures | | 33,391 |
| | 55,293 |
|
Total capital expenditures (1) (2) | | $ | 417,807 |
| | $ | 367,798 |
|
| | | | | |
Capital incurred (2) | | $ | 504,286 |
| | $ | 355,674 |
|
| |
(1)
| Capital expenditures for the nine months ended September 30, 2017 and 2016, are presented net of $1.4 million and $4.9 million, respectively, of contributions in aid of construction costs from affiliates. |
| |
(2)
| For the nine months ended September 30, 2017 and 2016, included $4.0 million and $4.7 million, respectively, of capitalized interest. |
Acquisitions during 2017 includedfor the Additional DBJV System Interest and equipment purchases from Anadarko. Acquisitions during 2016 included Springfield and equipment purchases from Anadarko. See Note 2—nine months ended September 30, 2022, include the acquisition of the remaining 50% interest in Ranch Westex (see Acquisitions and Divestitures and Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I,within this Item 1 of this Form 10-Q.2).
Capital expenditures excluding acquisitions, increased by $50.0$194.9 million for the nine months ended September 30, 2017. Expansion capital expenditures increased by $71.9 million (including a $0.7 million decrease in capitalized interest) for the nine months ended September 30, 2017,2023, primarily due to an increaseincreases of (i) $70.4$91.2 million at the DBJVWest Texas complex, primarily attributable to facility expansion, including ongoing construction of Mentone Train III and engineering and equipment milestone payments for the North Loving Plant, and pipeline projects, (ii) $71.4 million at the DBM water systems due to construction of additional water-disposal wells and facilities, pipeline build-out, and replacement projects, (iii) $30.5 million at the DBM oil system, primarily related to an increase in pipeline, oil treating, and $23.7oil pumping projects, and (iv) $8.1 million at the DJ Basin complex, bothoil system due to pipe and compression projects and (ii) an increase of $50.9 million due to the construction of the DBM water system. These increases were partially offset by decreases of $60.3 million at the DBM complex and $9.9 million at the Haley system. Maintenance capital expenditures decreased by $21.9 million for the nine months ended September 30, 2017, primarily at the DBM complex due to repairs made in 2016 as a result of the DBM outage and at the Non-Operated Marcellus Interest systems due to the Property Exchange in March 2017.pipeline projects.
We have updated our estimated total capital expenditures for the year ending December 31, 2017, (including our 75% share of Chipeta’s capital expenditures and excluding acquisitions) from an originally reported $900.0 million to $1.0 billion, to a current range of $800.0 million to $850.0 million. We have also updated our estimated maintenance capital expenditures from an originally reported $60.0 million to $80.0 million, to a current range of $50.0 million to $55.0 million. Based on the midpoint of the ranges, the total capital expenditure and maintenance capital expenditure estimates represent decreases of 13% and 25%, respectively, from the initial 2017 estimates due to increased capital efficiency and shifting capital spending into later periods.
Historical cash flow. The following table and discussion present a summary of our net cash flows provided by (used in) operating, activities, investing, activities and financing activities:
| | | | | | | | | | | | | | | | |
| | Nine Months Ended
September 30, | | |
| | |
| thousands | | 2023 | | 2022 | | |
| Net cash provided by (used in): | | | | | | |
| Operating activities | | $ | 1,188,034 | | | $ | 1,212,207 | | | |
| Investing activities | | (538,584) | | | (356,252) | | | |
| Financing activities | | (446,612) | | | (898,861) | | | |
| Net increase (decrease) in cash and cash equivalents | | $ | 202,838 | | | $ | (42,906) | | | |
|
| | | | | | | | |
| | | Nine Months Ended
September 30, |
| thousands | | 2017 | | 2016 |
| Net cash provided by (used in): | | | | |
| Operating activities | | $ | 645,099 |
| | $ | 657,738 |
|
| Investing activities | | (514,797 | ) | | (1,040,692 | ) |
| Financing activities | | (335,792 | ) | | 429,368 |
|
| Net increase (decrease) in cash and cash equivalents | | $ | (205,490 | ) | | $ | 46,414 |
|
Operating Activitiesactivities. Net cash provided by operating activities decreased for the nine months ended September 30, 2017, decreased2023, primarily due to (i) lower cash operating income, (ii) lower distributions from equity investments, and (iii) higher interest expense. These increases were partially offset by the impact of changes in working capital items. Also,assets and liabilities. Refer to Operating Results within this Item 2 for a discussion of our results of operations as compared to the prior period, refer to Operating Results within this Item 2.periods.
Investing Activitiesactivities. Net cash used in investing activities for the nine months ended September 30, 2017,2023, primarily included the following:
•$417.8536.4 million of capital expenditures, net of $1.4 million of contributions in aid of construction costs from affiliates, primarily related to construction, expansion, and expansionasset-integrity projects at the West Texas complex, DBM water systems, DBM oil system, and DJ Basin complexes and the DBJV system;complex;
•$155.332.7 million of cash consideration paid as part of the Property Exchange;increases to materials and supplies inventory; and
•$3.931.7 million of cash paid for equipment purchases from Anadarko;
$23.3 million of net proceeds from the sale of the Helper and Clawson systems in Utah;
$23.0 million of proceeds from property insurance claims attributable to the DBM outage; and
$16.3 million of distributions received from equity investments in excess of cumulative earnings.
Net cash used in investing activities for the nine months ended September 30, 2016,2022, primarily included the following:
•$341.5 million of capital expenditures, primarily related to construction, expansion, and asset-integrity projects at the West Texas complex, DBM water systems, DJ Basin complex, and DBM oil system;
•$712.541.0 million of cash paid for the acquisition of Springfield;the remaining 50% interest in Ranch Westex (see Acquisitions and Divestitures within this Item 2);
•$367.88.9 million of capital expenditures, net of $4.9contributions primarily paid to Red Bluff Express;
•$7.0 million of contributions in aid of construction costs from affiliates, primarily relatedincreases to plant constructionmaterials and expansion at the DBMsupplies inventory; and DJ Basin complexes and the DBJV system;
•$4.041.1 million of cash paid for equipment purchases from Anadarko;
$16.6 million of distributions received from equity investments in excess of cumulative earnings; andearnings.
$18.4 million of proceeds from property insurance claims attributable to the DBM outage.
Financing Activitiesactivities. Net cash used in financing activities for the nine months ended September 30, 2017,2023, primarily included the following:
•$845.0 million of repayments of outstanding borrowings under the RCF;
•$589.3778.3 million of distributions paid to our unitholders;WES unitholders and noncontrolling interest owners;
•$37.3259.8 million to purchase and retire portions of certain of WES Operating’s senior notes via open-market repurchases;
•$213.1 million to redeem the total principal amount outstanding on the Floating-Rate Senior Notes due 2023 at par value;
•$134.6 million of unit repurchases;
•$740.6 million of net proceeds from the 6.150% Senior Notes due 2033 issued in April 2023, which were used to repay borrowings under the RCF and for general partnership purposes;
•$595.1 million of net proceeds from the 6.350% Senior Notes due 2029 issued in September 2023, which were used to fund a portion of the aggregate purchase price for the Meritage acquisition, to pay related costs and expenses, and for general partnership purposes; and
•$470.0 million of borrowings under the RCF, which were used for general partnership purposes.
Net cash used in financing activities for the nine months ended September 30, 2022, primarily included the following:
•$765.0 million of repayments of outstanding borrowings under the RCF;
•$538.7 million of distributions paid to Anadarko forWES unitholders;
•$502.2 million to redeem the settlementtotal principal amount outstanding of the Deferred purchase price obligation - Anadarko;WES Operating’s 4.000% Senior Notes due 2022;
•$9.0447.1 million of unit repurchases;
•$20.2 million of distributions paid to the noncontrolling interest owner of Chipeta;WES Operating;
•$250.0 million of borrowings under our RCF, which were used for general partnership purposes; and
$46.7 million of capital contribution from Anadarko related to the above-market component of swap agreements.
Net cash provided by financing activities for the nine months ended September 30, 2016, included the following:
$880.0 million of repayments of outstanding borrowings under our RCF;
$490.3 million of distributions paid to our unitholders;
$29.3 million of net distributions paid to Anadarko representing pre-acquisition intercompany transactions attributable to Springfield;
$11.35.0 million of distributions paid to the noncontrolling interest owner of Chipeta;
•$600.01,390.0 million of borrowings under ourthe RCF, which were used to fund a portion of the Springfield acquisition and for general partnership purposes including funding capital expenditures;and to redeem portions of certain of WES Operating’s senior notes; and
•$494.61.5 million of net proceeds from the 2026 Notes offeringincreases in July 2016, after underwriting and original issue discounts and offering costs, alloutstanding checks.
$440.0 million of net proceeds from the issuance of 14,030,611 Series A Preferred units in March 2016, all of which was used to fund a portion of the acquisition of Springfield;
$246.9 million of net proceeds from the issuance of 7,892,220 Series A Preferred units in April 2016, all of which was used to pay down amounts borrowed under our RCF in connection with the acquisition of Springfield;
$25.0 million of net proceeds from the sale of common units to WGP, all of which was used to fund a portion of the acquisition of Springfield; and
$34.8 million of capital contribution from Anadarko related to the above-market component of swap agreements.
Debt and credit facility. Atfacilities. As of September 30, 2017, our2023, the carrying value of outstanding debt consistedwas $7.3 billion, we have no borrowings due within the next year, and have $2.0 billion of $500.0available borrowing capacity under WES Operating’s $2.0 billion RCF.
During the nine months ended September 30, 2023, WES Operating (i) completed the public offering of $600.0 million in aggregate principal amount of 6.350% Senior Notes due 2029, (ii) completed the 2021 Notes, $670.0public offering of $750.0 million in aggregate principal amount of 6.150% Senior Notes due 2033, (iii) entered into an amendment to our RCF to, among other things, extend the 2022 Notes, $350.0maturity date to April 2028 and provide for a maximum borrowing capacity up to $2.0 billion, expandable to a maximum of $2.5 billion, through the maturity date, (iv) purchased and retired $276.7 million aggregateof certain of its senior notes via open-market repurchases, and (v) redeemed the total principal amount outstanding on the Floating-Rate Senior Notes due 2023 at par value with cash on hand.
In May 2023, Fitch Ratings upgraded WES Operating’s long-term debt from “BB+” to “BBB-.” WES Operating’s senior unsecured debt ratings is now investment grade at Standard and Poor’s, Moody’s Investors Services, and Fitch Ratings. As a result of the 2018 Notes, $600.0upgrade, annualized borrowing costs will decrease by $6.9 million aggregate principal amount ofon WES Operating’s senior notes that are subject to effective interest-rate adjustments from a change in credit rating.
For additional information on our senior notes and the 2044 Notes, $500.0 million aggregate principal amount of the 2025 Notes, $500.0 million aggregate principal amount of the 2026 Notes and $250.0 million of borrowings outstanding under our RCF. As of September 30, 2017, the carrying value of our outstanding debt was $3.3 billion. See RCF, see Note 9—10—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
Senior Notes. The 2018 Notes, which are due in August 2018, were classified as long-term debt on the consolidated balance sheet at September 30, 2017, as we
Offload commitments. We have the ability and intent to refinance these obligations using long-term debt. At September 30, 2017, we were in complianceentered into offload agreements with all covenants under the indentures governing our outstanding notes.
Revolving credit facility. third parties providing firm-processing capacity through 2025. As of September 30, 2017,2023, we had $250.0have future minimum payments under offload agreements totaling $4.8 million for the remainder of outstanding RCF borrowings2023 and $4.6a total of $11.6 million in outstanding lettersyears thereafter.
Pipeline commitments. We have entered into transportation contracts with volume commitments on multiple pipelines through 2033. As of credit, resulting in $945.4 million available for borrowing under the RCF, which matures in February 2020. At September 30, 2017, the interest rate on the RCF was 2.54%, the facility fee rate was 0.20% and2023, we were in compliance with all covenants under the RCF.
Deferred purchase price obligation - Anadarko.Prior to our agreement with Anadarko to settle our deferred purchase price obligation early, the consideration that would have been paidestimated future minimum-volume-commitment fees totaling $1.6 million for the March 2015 acquisitionremainder of DBJV from Anadarko, consisted2023, and a total of a cash payment to Anadarko due on March 31, 2020. The cash payment would have been equal to (a) eight multiplied by the average of our share$51.6 million in the Net Earnings (see definition below) of DBJV for the calendar years 2018 and 2019, less (b) our share of all capital expenditures incurred for DBJV between March 1, 2015, and February 29, 2020. Net Earnings was defined as all revenues less cost of product, operating expenses and property taxes, in each case attributable to DBJV on an accrual basis. In May 2017, we reached an agreement with Anadarko to settle this obligation whereby we made a cash payment to Anadarko of $37.3 million, equal to the estimated net present value of the obligation at March 31, 2017. See Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.thereafter.
Securities. We may issue an indeterminate amount of common units and various debt securities under our effective shelf registration statement on file with the SEC. We may also issue common units under the $500.0 million COP, in amounts, at prices and on terms to be determined by market conditions and other factors at the time of our offerings.
We have an effective registration statement with the SEC relating to the public resale of the common units issued upon conversion of the Series A Preferred units. See Note 4—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for a discussion of the Series A Preferred units.
Credit risk. We bear credit risk represented by ourthrough exposure to non-paymentnon-payment or non-performancenon-performance by our counterparties, including Anadarko,Occidental, financial institutions, customers, and other parties. Generally, non-paymentnon-payment or non-performancenon-performance results from a customer’s inability to satisfy payables to us for services rendered, minimum-volume-commitment deficiency payments owed, or volumes owed pursuant to gas imbalancegas- or NGLs-imbalance agreements. We examine and monitor the creditworthiness of third-party customers and may establish credit limits for third-party customers.
We are dependent upon a single producer, Anadarko, for a substantial portion of our volumes (excluding our equity investment throughput), and we do not maintain a credit limit with respect to Anadarko. Consequently, we are subject to the risk of non-paymentnon-payment or late payment by Anadarkoproducers for gathering, processing, transportation, and transportation feesdisposal fees. Additionally, we continue to evaluate counterparty credit risk and, for proceeds from the sale of residue, NGLs and condensatein certain circumstances, are exercising our rights to Anadarko.request adequate assurance.
We expect our exposure to the concentrated risk of non-paymentnon-payment or non-performancenon-performance to continue for as long as we remain substantially dependent on Anadarko forour commercial relationships with Occidental generate a significant portion of our revenues. Additionally, we are exposedWhile Occidental is our contracting counterparty, gathering and processing arrangements with affiliates of Occidental on most of our systems include not just Occidental-produced volumes, but also, in some instances, the volumes of other working-interest owners of Occidental who rely on our facilities and infrastructure to credit risk on the note receivable from Anadarko. We are also partybring their volumes to agreements with Anadarko under which Anadarko is required to indemnify us for certain environmental claims, losses arising from rights-of-way claims, failures to obtain required consents or governmental permits and income taxes with respect to the assets acquired from Anadarko. Finally, we have entered into various commodity price swap agreements with Anadarko in order to reduce our exposure to a majority of the commodity price risk inherent in our percent-of-proceeds and keep-whole contracts, and are subject to performance risk thereunder.market. See Note 5—6—Related-Party Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
Our ability to make cash distributions to our unitholders may be adversely impacted if AnadarkoOccidental becomes unable to perform under the terms of our gathering, processing, transportation, and transportation agreements, natural gas and NGL purchase agreements, Anadarko’s note payable to us, our omnibus agreement, the services and secondment agreement, contribution agreements or the commodity price swapdisposal agreements.
CONTRACTUAL OBLIGATIONS
ITEMS AFFECTING THE COMPARABILITY OF FINANCIAL RESULTS WITH WES OPERATING
Our contractual obligationsconsolidated financial statements include among other things,the consolidated financial results of WES Operating. Our results of operations do not differ materially from the results of operations and cash flows of WES Operating, which are reconciled below.
Reconciliation of net income (loss). The differences between net income (loss) attributable to WES and WES Operating are reconciled as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
| | Three Months Ended | | Nine Months Ended |
| | | | | | |
| thousands | | September 30, 2023 | | June 30, 2023 | | September 30, 2023 | | September 30, 2022 | | |
| Net income (loss) attributable to WES | | $ | 277,296 | | | $ | 252,921 | | | $ | 733,862 | | | $ | 880,779 | | | |
Limited partner interest in WES Operating not held by WES (1) | | 5,670 | | | 5,185 | | | 15,016 | | | 18,016 | | | |
General and administrative expenses (2) | | 509 | | | 1,186 | | | 1,927 | | | 1,764 | | | |
| Other income (expense), net | | (60) | | | (129) | | | (214) | | | (18) | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Net income (loss) attributable to WES Operating | | $ | 283,415 | | | $ | 259,163 | | | $ | 750,591 | | | $ | 900,541 | | | |
(1)Represents the portion of net income (loss) allocated to the limited partner interest in WES Operating not held by WES. A subsidiary of Occidental held a revolving credit facility, other third-party long-term debt, capital obligations related2.0% limited partner interest in WES Operating for all periods presented.
(2)Represents general and administrative expenses incurred by WES separate from, and in addition to, our expansion projectsthose incurred by WES Operating.
Reconciliation of net cash provided by (used in) operating and variousfinancing activities. The differences between net cash provided by (used in) operating leases. Referand financing activities for WES and WES Operating are reconciled as follows:
| | | | | | | | | | | | | | | | |
| | |
| | Nine Months Ended
September 30, | | |
| thousands | | 2023 | | 2022 | | |
| WES net cash provided by operating activities | | $ | 1,188,034 | | | $ | 1,212,207 | | | |
General and administrative expenses (1) | | 1,927 | | | 1,764 | | | |
Non-cash equity-based compensation expense | | (434) | | | (423) | | | |
| Changes in working capital | | (15,223) | | | (9,101) | | | |
| Other income (expense), net | | (214) | | | (18) | | | |
| | | | | | |
| | | | | | |
| WES Operating net cash provided by operating activities | | $ | 1,174,090 | | | $ | 1,204,429 | | | |
| | | | | | |
| WES net cash provided by (used in) financing activities | | $ | (446,612) | | | $ | (898,861) | | | |
Distributions to WES unitholders (2) | | 754,998 | | | 538,690 | | | |
Distributions to WES from WES Operating (3) | | (894,510) | | | (988,395) | | | |
| Increase (decrease) in outstanding checks | | (3) | | | 103 | | | |
| Unit repurchases | | 134,602 | | | 447,075 | | | |
| Other | | 14,371 | | | 7,942 | | | |
| WES Operating net cash provided by (used in) financing activities | | $ | (437,154) | | | $ | (893,446) | | | |
(1)Represents general and administrative expenses incurred by WES separate from, and in addition to, those incurred by WES Operating.
(2)Represents distributions to WES common unitholders paid under WES’s partnership agreement. See Note 9—Debt4—Partnership Distributions and Interest ExpenseNote 5—Equity and Note 10—Commitments and ContingenciesPartners’ Capital in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for an update10-Q.
(3)Difference attributable to our contractual obligations aselimination in consolidation of September 30, 2017, including, but not limited to, increases in committed capital.
OFF-BALANCE SHEET ARRANGEMENTS
We do not have any off-balance sheet arrangements other than operating leasesWES Operating’s distributions on partnership interests owned by WES. See Note 4—Partnership Distributions and standby letters of credit. The information pertaining to operating leasesNote 5—Equity and our standby letters of credit required for this item is provided under Note 10—Commitments and Contingencies and Note 9—Debt and Interest Expense, respectively, includedPartners’ Capital in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
RECENT ACCOUNTING DEVELOPMENTS
Noncontrolling interest. WES Operating’s noncontrolling interest consists of the 25% third-party interest in Chipeta. See Note 1—Description of Business and Basis of Presentation in the Notes to Consolidated Financial Statementsunder Part I, Item 1 of this Form 10-Q.
WES Operating distributions. WES Operating distributes all of its available cash on a quarterly basis to WES Operating unitholders in proportion to their share of limited partner interests in WES Operating. See Note 4—Partnership Distributions in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
CRITICAL ACCOUNTING ESTIMATES
The preparation of consolidated financial statements in accordance with GAAP requires management to make informed judgments and estimates that affect the amounts of assets and liabilities as of the date of the financial statements and the amounts of revenues and expenses recognized during the periods reported. There have been no significant changes to our critical accounting estimates from those disclosed in our annual report on Form 10-K for the fiscal year ended December 31, 2022.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity priceCommodity-price risk. Certain ofThere have been no significant changes to our processing services are providedcommodity-price risk discussion from the disclosure set forth under percent-of-proceeds and keep-whole agreementsPart II, Item 7A in which Anadarko is typically responsibleour Form 10-K for the marketing of the natural gas, condensate and NGLs. Under percent-of-proceeds agreements, we receive a specified percentage of the net proceeds from the sale of residue and/or NGLs. Under keep-whole agreements, we keep 100% of the NGLs produced and the processed natural gas, or value of the natural gas, is returned to the producer, and since some of the gas is used and removed during processing, we compensate the producer for the amount of gas used and removed in processing by supplying additional gas or by paying an agreed-upon value for the gas used.
To mitigate our exposure to a majority of the commodity price risk inherent in our percent-of-proceeds and keep-whole contracts, we currently have in place commodity price swap agreements with Anadarko covering activity at the DJ Basin complex and the MGR assets. On December 1, 2016, we renewed these commodity price swap agreements throughyear ended December 31, 2017, with an effective date of January 1, 2017. See Note 5—Transactions with Affiliates2022, except as noted below and in the Notes to Consolidated Financial StatementsOutlook under Part I, Item 12 of this Form 10-Q.
We consider our exposure to commodity price risk associated withFor the above-described arrangements to be minimal given the existence of the commodity price swap agreements with Anadarko and the relatively small amountnine months ended September 30, 2023, 95% of our operating income (loss) that is impacted by changes in market prices. Accordingly, we do not expect that awellhead natural-gas volume (excluding equity investments) and 100% of our crude-oil and produced-water throughput (excluding equity investments) were serviced under fee-based contracts. A 10% increase or decrease in commodity prices would not have a material impact on our operating income (loss), financial condition, or cash flows for the next twelve12 months, excluding the effect of imbalances described below.imbalances.
We bear a limited degree of commodity price risk with respect to settlement of our natural gas imbalances that arise from differences in gas volumes received into our systems and gas volumes delivered by us to customers, as well as instances where our actual liquids recovery or fuel usage varies from the contractually stipulated amounts. Natural gas volumes owed to or by us that are subject to monthly cash settlement are valued according to the terms of the contract as of the balance sheet dates, and generally reflect market index prices. Other natural gas volumes owed to or by us are valued at our weighted-average cost of natural gas as of the balance sheet dates and are settled in-kind. Our exposure to the impact of changes in commodity prices on outstanding imbalances depends on the timing of settlement of the imbalances.
Interest rateInterest-rate risk. In June 2017, the The Federal Open Market Committee raised theincreased its target range seven times for the federal funds rate from 3/4 to one percent to one to 1 1/4 percent. This increase,in 2022 and anyincreased its target range four times during the nine months ended September 30, 2023. Any future increases in the federal funds rate likely will ultimately result in an increase in our financing costs. As of September 30, 2017, we2023, WES Operating had $250.0 million ofno outstanding borrowings under the RCF (which bearsthat bear interest at a rate based on LIBORthe Secured Overnight Financing Rate (“SOFR”) or at our option, an alternative base rate). Arate at WES Operating’s option. While a 10% change in LIBORthe applicable benchmark interest rate would have resulted in a nominal change in net income (loss) andnot materially impact interest expense on our outstanding borrowings at September 30, 2023, it would impact the fair value of the borrowings under the RCF at September 30, 2017.senior notes.
WeAdditional variable-rate debt may incur additional variable-rate debtbe issued in the future, either under ourthe RCF or other financing sources, including commercial bankpaper borrowings or debt issuances.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures. The Chief Executive Officer and Chief Financial Officer of the Partnership’sWES’s general partner and WES Operating GP (for purposes of this Item 4, “Management”) performed an evaluation of the Partnership’sWES’s and WES Operating’s disclosure controls and procedures as defined in Rules 13a-15(e)13a-15(e) and 15d-15(e)15d-15(e) of the Exchange Act. OurWES’s and WES Operating’s disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we fileare filed or submitsubmitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC, and to ensure that the information required to be disclosed by us in the reports that we fileare filed or submitsubmitted under the Exchange Act is accumulated and communicated to our management, including ourthe principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, Management concluded that the Partnership’sWES’s and WES Operating’s disclosure controls and procedures were effective as of September 30, 2017.2023.
Changes in Internal Control Over Financial Reporting. There has On April 1, 2023, WES and WES Operating implemented a new Enterprise Resource Planning (“ERP”) system. As a result of this implementation, certain internal controls over financial reporting have been automated, modified, or implemented to address the new environment associated with the implementation of this type of system. While WES and WES Operating believe that this system will strengthen the internal control system, there are inherent risks in implementing any new system and WES and WES Operating will continue to evaluate these control changes as part of their assessments of internal control over financial reporting. Other than the ERP implementation, there have been no changechanges in ourWES or WES Operating’s internal control over financial reporting that occurred during the quarter ended September 30, 2023, that materially affected, or are reasonably likely to materially affect, WES or WES Operating’s internal control over financial reporting during the quarter ended September 30, 2017, that has materially affected, or is reasonably likely to materially affect, the Partnership’s internal control over financial reporting.most recent fiscal quarter.
PART II.OTHER INFORMATION
Item 1. Legal Proceedings
Kerr-McGee Gathering LLC (“KMGG”), a wholly owned subsidiary of the Partnership, is currently in negotiations with the U.S. Environmental Protection Agency (the “EPA”) and the Department of Justice with respect to alleged non-compliance with the leak detection and repair requirements of the federal Clean Air Act at its Fort Lupton facility in the DJ Basin complex.
Also,On October 29, 2020, WGR Operating, LP another(“WGR”), on behalf of itself and derivatively on behalf of Mont Belvieu JV, filed suit against Enterprise Products Operating, LLC (“Enterprise”) and Mont Belvieu JV (as a nominal defendant) in the District Court of Harris County, Texas. Our lawsuit seeks a declaratory judgment regarding proper revenue allocation as set forth in the Operating Agreement between Mont Belvieu JV (of which WGR is a 25% owner) and Enterprise (the “Operating Agreement”) related to fractionation trains at the Mont Belvieu complex in Chambers County, Texas. Specifically, the Operating Agreement sets forth a revenue allocation structure, whereby revenue would be allocated to the various fracs at the Mont Belvieu complex in sequential order, with Fracs VII and VIII (which are owned by Mont Belvieu JV) following Fracs I through VI, but preceding any “Later Frac Facilities.” Subsequent to the construction of Fracs VII and VIII, Enterprise built Fracs IX, X, and XI, which it wholly owned subsidiaryowns, and has treated such subsequent fracs as outside the Mont Belvieu revenue allocation. We do not believe Enterprise’s attempt to bypass the agreed-to revenue allocation is proper under the parties’ agreements and now seek judicial determination. We currently sue only for declaratory judgment to avoid potential future damages. We cannot make any assurances regarding the ultimate outcome of this proceeding and its resulting impact on WGR or WES.
On November 22, 2022, WGR filed suit against Enterprise Crude Oil LLC (“ECO”) in the District Court of Harris County, Texas. Our lawsuit alleges that ECO breached a contract related to the Whitethorn joint venture pursuant to which ECO must share with WGR certain of the Partnership, is currentlyprofits and losses generated by ECO’s hydrocarbon trading activity conducted utilizing the Whitethorn pipeline. Specifically, we claim that ECO has engaged in negotiations withtrades knowing that the EPA with respectrevenue to alleged non-compliance withbe realized would be less than the leak detectionminimum floor set under the contract and repair requirementshas failed to allocate revenues and expenses as prescribed by the contract, resulting in improper losses to WGR. Enterprise has filed a counterclaim to our lawsuit, alleging that, between 2017 and 2019, it had mistakenly overpaid WGR approximately $12.0 million in trading profits and seeking recovery of such amount. We also claim that Enterprise Crude Pipeline LLC, as operator of the federal Clean Air Act at its Granger, Wyoming facility. Although managementWhitethorn pipeline, failed to act as a reasonable and prudent operator of the Whitethorn pipeline and for the sole benefit of the Whitethorn joint venture as contractually required. We cannot predictmake any assurances regarding the ultimate outcome of settlement discussions in these matters, management believes that it is reasonably likely a resolution of these matters will result in a finethis proceeding and its resulting impact on WGR or penalty for each matter in excess of $100,000.WES.
Except as discussed above, we are not a party to any legal, regulatory, or administrative proceedings other than proceedings arising in the ordinary course of our business. Management believes that there are no such proceedings for which a final disposition could have a material adverse effect on our results of operations, cash flows, or financial condition, or for which disclosure is otherwise required by Item 103 of Regulation S-K.S-K.
Item 1A. Risk Factors
Security holders and potential investors in our securities should carefully consider the risk factorsfactor included below and those set forth under Part I, Item 1A in our Form 10-K10-K for the year ended December 31, 2016,2022, together with all of the other information included in this document, and in our other public filings, press releases, and public discussions with managementmanagement.
We may fail to successfully combine our business with the assets and business of Meritage, which could have an adverse impact on our future results.
The Meritage acquisition closed on October 13, 2023. The integration of these acquired assets involve potential risks, including the Partnership. Additionally,failure to realize expected profitability, growth, or accretion; environmental or regulatory compliance matters or liabilities; diversion of management’s attention from our existing business; and the incurrence of unanticipated liabilities and costs for a full discussionwhich indemnification is unavailable or inadequate.
If any of the risks associated with Anadarko’s business, see Item 1A under Part I in Anadarko’s Form 10-K for the year ended December 31, 2016, Anadarko’s quarterly reports on Form 10-Q and Anadarko’sdescribed above or other public filings, press releases and public discussions with Anadarko management. Weanticipated or unanticipated liabilities were to materialize, it could have identified these risk factors as important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us oran adverse effect on our behalf.business, financial condition, and results of operations.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Series A Preferred units. In connectionThe following table sets forth information with the early conversionrespect to repurchases made by WES of the Series A Preferred units intoits common units on a one-for-one basis on March 1, 2017, and May 2, 2017, we issued 10,961,415 and 10,961,416in the open market or in privately negotiated transactions under the $1.25 billion Purchase Program during the third quarter of 2023:
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| Period | | Total number of units purchased | | Average price paid per unit | | Total number of units purchased as part of publicly announced plans or programs (1) | | Approximate dollar value of units that may yet be purchased under the plans or programs (1) |
| July 1-31, 2023 | | — | | | $ | — | | | — | | | $ | 755,307,310 | |
| August 1-31, 2023 | | — | | | — | | | — | | | 755,307,310 | |
| September 1-30, 2023 | | 5,100,000 | | | 25.00 | | | 5,100,000 | | | 627,807,310 | |
| Total | | 5,100,000 | | | 25.00 | | | 5,100,000 | | | |
______________________________________________________________________________________(1)In 2022, the Board authorized WES to buy back up to $1.25 billion of our common units respectively, in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Section 4(a)(2) thereof.
PIK Class C units. During the nine months ended September 30, 2017, in connection with the quarterly distribution for the Class C units, we issued the following additional Class C units (“PIK Class C units”) to APC Midstream Holdings, LLC, a subsidiary of Anadarko and the holder of the Class C units:
|
| | | | | | | | | |
thousands except unit amounts Quarters Ended | | PIK Class C Units | | Implied Fair Value | | Date of
Distribution |
| 2016 | | | | | | |
| December 31 | | 178,977 |
| | $ | 10,719 |
| | February 2017 |
| 2017 | | | | | | |
| March 31 | | 206,218 |
| | $ | 12,355 |
| | May 2017 |
| June 30 | | 234,315 |
| | 13,206 |
| | August 2017 |
No proceeds were received as consideration for the issuance of the PIK Class C units. The PIK Class C units were issued in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act. All outstanding Class C units will convert into common units on a one-for-one basis on March 1, 2020, unless we elect to convert such units earlier or Anadarko extends the conversion date. For more information, see through December 31, 2024. See Note 4—5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.10-Q for additional details.
Item 5. Other Information
Insider Trading Arrangements
Rule 10b5-1 under the Exchange Act provides an affirmative defense that enables prearranged transactions in securities in a manner that avoids concerns about initiating transactions at a future date while possibly in possession of material nonpublic information. Our Insider Trading Policy permits our directors and executive officers to enter into trading plans designed to comply with Rule 10b5-1. During the three months ended September 30, 2023, none of our executive officers or directors adopted or terminated a Rule 10b5-1 trading plan or adopted or terminated a non-Rule 10b5-1 trading arrangement (as defined in Item 408(c) of Regulation S-K).
Item 6. Exhibits
Exhibits designated by an asterisk (*) are filed herewith and those designated with asterisks (**) are furnished herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.
Exhibit Index
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Exhibit
Number | | | Description |
| # | 2. | 1 | | | Contribution Agreement and Agreement and Plan of Merger, dated as of November 7, 2018, by and among Anadarko Petroleum Corporation, Anadarko E&P Onshore LLC, APC Midstream Holdings, LLC, Western Gas Equity Partners, LP, Western Gas Equity Holdings, LLC, Western Gas Partners, LP, Western Gas Holdings, LLC, Clarity Merger Sub, LLC, WGR Asset Holding Company LLC, WGR Operating, LP, Kerr-McGee Gathering LLC, Kerr-McGee Worldwide Corporation and Delaware Basin Midstream, LLC (incorporated by reference to Exhibit 2.1 to Western Gas Equity Partners, LP’s Current Report on Form 8-K filed on November 8, 2018, File No. 001-35753). |
| 3. | 1 | | | |
| 3. | 2 | | | |
| 3. | 3 | | | |
| 3. | 4 | | | |
| 3. | 5 | | | |
| 3. | 6 | | | |
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| 3. | 8 | | | |
| 3. | 9 | | | |
| 3. | 10 | | | |
| 3. | 11 | | | |
| 3. | 12 | | | |
| 3. | 13 | | | |
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Exhibit
Number | | | Description |
| 4. | 1 | | | |
| 4. | 2 | | | Indenture, dated as of May 18, 2011, among Western Gas Partners, LP, as Issuer, the Subsidiary Guarantors named therein, as Guarantors, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046). |
| 4. | 3 | | | First Supplemental Indenture, dated as of May 18, 2011, among Western Gas Partners, LP, as Issuer, the Subsidiary Guarantors named therein, as Guarantors, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046). |
| 4. | 4 | | | Fourth Supplemental Indenture, dated as of June 28, 2012, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 28, 2012, File No. 001-34046). |
| 4. | 5 | | | |
| 4. | 6 | | | Sixth Supplemental Indenture, dated as of March 20, 2014, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 20, 2014, File No. 001-34046). |
| 4. | 7 | | | |
| 4. | 8 | | | Seventh Supplemental Indenture, dated as of June 4, 2015, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 4, 2015, File No. 001-34046). |
| 4. | 9 | | | |
| 4. | 10 | | | Eighth Supplemental Indenture, dated as of July 12, 2016, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 12, 2016, File No. 001-34046). |
| 4. | 11 | | | |
| 4. | 12 | | | Ninth Supplemental Indenture, dated as of March 2, 2018, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 2, 2018, File No. 001-34046). |
| 4. | 13 | | | |
| 4. | 14 | | | |
| 4. | 15 | | | Tenth Supplemental Indenture, dated as of August 9, 2018, by and between Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 9, 2018, File No. 001-34046). |
| 4. | 16 | | | |
| 4. | 17 | | | |
| 4. | 18 | | | Eleventh Supplemental Indenture, dated as of January 13, 2020, by and between Western Midstream Operating, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on January 13, 2020, File No. 001-34046). |
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Exhibit
Number | | | Description |
| 4. | 19 | | | |
| 4. | 20 | | | |
| 4. | 21 | | | |
| 4. | 22 | | | |
| 4. | 23 | | | Twelfth Supplemental Indenture, dated as of April 4, 2023, by and between Western Midstream Operating, LP, as Issuer, and Computershare Trust Company, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on April 5, 2023, File No. 001-34046). |
| 4. | 24 | | | |
| 4. | 25 | | | Thirteenth Supplemental Indenture, dated as of September 29, 2023, by and between Western Midstream Operating, LP, as Issuer, and Computershare Trust Company, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on September 29, 2023, File No. 001-34046). |
| 4. | 26 | | | |
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| * | 31. | 1 | | | |
| * | 31. | 2 | | | |
| * | 31. | 3 | | | |
| * | 31. | 4 | | | |
| ** | 32. | 1 | | | |
| ** | 32. | 2 | | | |
| * | 101. | INS | | | XBRL Instance Document (the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document) |
| * | 101. | SCH | | | Inline XBRL Schema Document |
| * | 101. | CAL | | | Inline XBRL Calculation Linkbase Document |
| * | 101. | DEF | | | Inline XBRL Definition Linkbase Document |
| * | 101. | LAB | | | Inline XBRL Label Linkbase Document |
| * | 101. | PRE | | | Inline XBRL Presentation Linkbase Document |
| * | 104 | | | | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |
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Exhibit
Number
| | Description |
2.1# | | Contribution, Conveyance and Assumption Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, Anadarko Petroleum Corporation, WGR Holdings, LLC, Western Gas Resources, Inc., WGR Asset Holding Company LLC, Western Gas Operating, LLC and WGR Operating, LP, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046). |
2.2# | | Contribution Agreement, dated as of November 11, 2008, by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on November 13, 2008, File No. 001-34046). |
2.3# | | Contribution Agreement, dated as of July 10, 2009, by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, Anadarko Uintah Midstream, LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, WES GP, Inc., Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 23, 2009, File No. 001-34046). |
2.4# | | Contribution Agreement, dated as of January 29, 2010 by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, Mountain Gas Resources LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, WES GP, Inc., Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on February 3, 2010 File No. 001-34046). |
2.5# | | Contribution Agreement, dated as of July 30, 2010, by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, WES GP, Inc., Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 5, 2010, File No. 001-34046). |
2.6# | | |
2.7# | | Contribution Agreement, dated as of December 15, 2011, by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, WES GP, Inc., Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 15, 2011, File No. 001-34046). |
2.8# | | Contribution Agreement, dated as of February 27, 2013, by and among Anadarko Marcellus Midstream, L.L.C., Western Gas Partners, LP, Western Gas Operating, LLC, WGR Operating, LP, Anadarko Petroleum Corporation and Anadarko E&P Onshore LLC (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2013, File No. 001-34046). |
2.9# | | Contribution Agreement, dated as of February 27, 2014, by and among WGR Asset Holding Company LLC, APC Midstream Holdings, LLC, Western Gas Partners, LP, Western Gas Operating, LLC, WGR Operating, LP and Anadarko Petroleum Corporation (incorporated by reference to Exhibit 2.9 to Western Gas Partners, LP’s Annual Report on Form 10-K filed on February 28, 2014, File No. 001-34046). |
2.10# | | |
2.11# | | Purchase and Sale Agreement, dated as of March 2, 2015, by and among WGR Asset Holding Company LLC, Delaware Basin Midstream, LLC, Western Gas Partners, LP, and Anadarko Petroleum Corporation (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 3, 2015, File No. 001-34046). |
|
| | |
Exhibit
Number
| | Description |
2.12# | | |
2.13# | | Contribution Agreement, dated as of February 24, 2016, by and among WGR Asset Holding Company, LLC, APC Midstream Holdings, LLC, Western Gas Partners, LP, Western Gas Operating, LLC, WGR Operating, LP and Anadarko Petroleum Corporation (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 1, 2016, File No. 001-34046). |
2.14# | | Interest Swap and Purchase Agreement, dated February 9, 2017, among Western Gas Partners, LP, WGR Operating, LP, Delaware Basin JV Gathering, LLC, Williams Partners L.P., Williams Midstream Gas Services LLC and Appalachia Midstream Services, L.L.C. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on February 9, 2017, File No. 001-34046). |
3.1 | | |
3.2 | | |
3.3 | | |
3.4 | | |
3.5 | | |
3.6 | | |
4.1 | | |
4.2 | | Indenture, dated as of May 18, 2011, among Western Gas Partners, LP, as Issuer, the Subsidiary Guarantors named therein, as Guarantors, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046). |
4.3 | | First Supplemental Indenture, dated as of May 18, 2011, among Western Gas Partners, LP, as Issuer, the Subsidiary Guarantors named therein, as Guarantors, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046). |
4.4 | | |
4.5 | | Fourth Supplemental Indenture, dated as of June 28, 2012, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 28, 2012, File No. 001-34046). |
4.6 | | |
4.7 | | Fifth Supplemental Indenture, dated as of August 14, 2013, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 14, 2013, File No. 001-34046). |
|
| | |
Exhibit
Number
| | Description |
4.8 | | |
4.9 | | Sixth Supplemental Indenture, dated as of March 20, 2014, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 20, 2014, File No. 001-34046). |
4.10 | | |
4.11 | | Seventh Supplemental Indenture, dated as of June 4, 2015, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 4, 2015, File No. 001-34046). |
4.12 | | |
4.13 | | Eighth Supplemental Indenture, dated as of July 12, 2016, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 12, 2016, File No. 001-34046). |
4.14 | | |
4.15 | | |
4.16 | | |
31.1* | | |
31.2* | | |
32.1** | | |
101.INS* | | XBRL Instance Document |
101.SCH* | | XBRL Schema Document |
101.CAL* | | XBRL Calculation Linkbase Document |
101.DEF* | | XBRL Definition Linkbase Document |
101.LAB* | | XBRL Label Linkbase Document |
101.PRE* | | XBRL Presentation Linkbase Document |
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| |
# | |
| # | Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted schedule to the Securities and Exchange Commission upon request. |
| |
| |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorized.
| | | | | |
| WESTERN MIDSTREAM PARTNERS, LP |
| |
| November 1, 2023 | WESTERN GAS PARTNERS, LP |
| /s/ Michael P. Ure |
November 1, 2017 | |
| |
| /s/ Benjamin M. Fink |
| Benjamin M. FinkMichael P. Ure
President and Chief Executive Officer Western GasMidstream Holdings, LLC (as general partner of Western GasMidstream Partners, LP) |
| |
November 1, 20172023 | |
| /s/ Kristen S. Shults |
| /s/ Jaime R. Casas |
| Jaime R. CasasKristen S. Shults
Senior Vice President and Chief Financial Officer and Treasurer Western GasMidstream Holdings, LLC (as general partner of Western GasMidstream Partners, LP) |
| |
| |
| WESTERN MIDSTREAM OPERATING, LP |
| |
| November 1, 2023 | |
| /s/ Michael P. Ure |
| Michael P. Ure President and Chief Executive Officer Western Midstream Operating GP, LLC (as general partner of Western Midstream Operating, LP) |
| |
| November 1, 2023 | |
| /s/ Kristen S. Shults |
| Kristen S. Shults Senior Vice President and Chief Financial Officer Western Midstream Operating GP, LLC (as general partner of Western Midstream Operating, LP) |