Document

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
(Mark One)
      
þ
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2018
 
Or 
  
¨
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)
Delaware
 
26-1075808
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
 
1201 Lake Robbins Drive
The Woodlands, Texas
 
77380
(Address of principal executive offices)
 
(Zip Code)
   
(832) 636-6000
(Registrant’s telephone number, including area code)
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  ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  þ    No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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-2 of the Exchange Act.
Large accelerated filer þ
  
Accelerated filer ¨
  
Non-accelerated filer ¨
  
Smaller reporting company ¨
 
Emerging growth company ¨
 
  
 
 
(Do not check if a smaller reporting company)
 
 
 
 
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.    ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  þ
There were 152,609,285 common units outstanding as of July 30, 2018.




TABLE OF CONTENTS

 
 
 
PAGE
PART I
 
 
 
Item 1.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 2.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 3.
 
Item 4.
PART II
 
 
 
Item 1.
 
Item 1A.
 
Item 2.
 
Item 6.


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COMMONLY USED TERMS AND DEFINITIONS

Unless the context otherwise requires, references to “we,” “us,” “our,” the “Partnership” or “Western Gas Partners, LP” refer to Western Gas 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: Our 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, FRP, Whitethorn and Cactus II.
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: 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.
Cactus II: Cactus II Pipeline LLC.
Chipeta: Chipeta Processing, LLC.
Condensate: A natural gas liquid with a low vapor pressure mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.
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 gathering and 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 Key Performance Metrics under Part I, Item 2 of this Form 10-Q.
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.

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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.
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: Our 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 $1.5 billion 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 gas gathering system: A gas gathering system and related facilities located in Dimmit, La Salle, Maverick and Webb Counties in South Texas.

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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: Western Gas Equity Partners, LP.
White Cliffs: White Cliffs Pipeline, LLC.
Whitethorn LLC: Whitethorn Pipeline Company LLC.
2018 Notes: Our 2.600% Senior Notes due 2018.
2021 Notes: Our 5.375% Senior Notes due 2021.
2022 Notes: Our 4.000% Senior Notes due 2022.
2025 Notes: Our 3.950% Senior Notes due 2025.
2026 Notes: Our 4.650% Senior Notes due 2026.
2028 Notes: Our 4.500% Senior Notes due 2028.
2044 Notes: Our 5.450% Senior Notes due 2044.
2048 Notes: Our 5.300% Senior Notes due 2048.
$500.0 million COP: The continuous offering program that may be undertaken pursuant to the registration statement filed with the SEC in July 2017 for the issuance of up to an aggregate of $500.0 million of our common units.


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PART I.  FINANCIAL INFORMATION (UNAUDITED)

Item 1.  Financial Statements

WESTERN GAS PARTNERS, LP
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
thousands except per-unit amounts
 
2018
 
2017
 
2018
 
2017
Revenues and other – affiliates
 
 
 
 
 
 
 
 
Service revenues – fee based
 
$
192,488

 
$
154,984

 
$
378,489

 
$
327,298

Service revenues – product based
 
285

 

 
527

 

Product sales
 
45,256

 
161,329

 
100,075

 
304,170

Total revenues and other – affiliates
 
238,029

 
316,313

 
479,091

 
631,468

Revenues and other – third parties
 
 
 
 
 
 
 
 
Service revenues – fee based
 
167,056

 
144,451

 
319,474

 
279,951

Service revenues – product based
 
21,820

 

 
44,171

 

Product sales
 
8,821

 
63,495

 
29,939

 
127,179

Other
 
223

 
1,191

 
442

 
3,045

Total revenues and other – third parties
 
197,920

 
209,137

 
394,026

 
410,175

Total revenues and other
 
435,949

 
525,450

 
873,117

 
1,041,643

Equity income, net – affiliates
 
39,218

 
21,728

 
59,642

 
41,189

Operating expenses
 
 
 
 
 
 
 
 
Cost of product (1)
 
68,149

 
203,277

 
145,948

 
392,636

Operation and maintenance (1)
 
100,628

 
76,148

 
188,907

 
149,908

General and administrative (1)
 
14,035

 
10,585

 
28,167

 
23,244

Property and other taxes
 
11,754

 
11,924

 
24,136

 
24,218

Depreciation and amortization
 
78,792

 
74,031

 
155,634

 
143,733

Impairments
 
127,243

 
3,178

 
127,391

 
167,920

Total operating expenses
 
400,601

 
379,143

 
670,183

 
901,659

Gain (loss) on divestiture and other, net (2)
 
170

 
15,458

 
286

 
134,945

Proceeds from business interruption insurance claims
 

 
24,115

 

 
29,882

Operating income (loss)
 
74,736

 
207,608

 
262,862

 
346,000

Interest income – affiliates
 
4,225

 
4,225

 
8,450

 
8,450

Interest expense (3)
 
(44,389
)
 
(35,746
)
 
(83,672
)
 
(71,250
)
Other income (expense), net
 
1,229

 
253

 
2,011

 
683

Income (loss) before income taxes
 
35,801

 
176,340

 
189,651

 
283,883

Income tax (benefit) expense
 
282

 
843

 
1,784

 
4,395

Net income (loss)
 
35,519

 
175,497

 
187,867

 
279,488

Net income attributable to noncontrolling interest
 
2,811

 
2,046

 
5,796

 
4,148

Net income (loss) attributable to Western Gas Partners, LP
 
$
32,708

 
$
173,451

 
$
182,071

 
$
275,340

Limited partners’ interest in net income (loss):
 
 
 
 
 
 
 
 
Net income (loss) attributable to Western Gas Partners, LP
 
$
32,708

 
$
173,451

 
$
182,071

 
$
275,340

Series A Preferred units interest in net (income) loss
 

 
(14,199
)
 

 
(42,373
)
General partner interest in net (income) loss (4)
 
(84,176
)
 
(76,365
)
 
(167,615
)
 
(144,527
)
Common and Class C limited partners’ interest in net income (loss) (4)
 
(51,468
)
 
82,887

 
14,456

 
88,440

Net income (loss) per common unit – basic and diluted (5)
 
$
(0.32
)
 
$
0.49

 
$
0.06

 
$
0.53

 
                                                                                                                                                                                         
(1) 
Cost of product includes product purchases from Anadarko (as defined in Note 1) of $12.6 million and $32.9 million for the three and six months ended June 30, 2018, respectively, and $21.6 million and $37.6 million for the three and six months ended June 30, 2017, respectively. Operation and maintenance includes charges from Anadarko of $23.4 million and $43.7 million for the three and six months ended June 30, 2018, respectively, and $18.5 million and $35.6 million for the three and six months ended June 30, 2017, respectively. General and administrative includes charges from Anadarko of $11.2 million and $22.8 million for the three and six months ended June 30, 2018, respectively, and $9.4 million and $18.9 million for the three and six months ended June 30, 2017, respectively. See Note 6.
(2) 
Includes losses related to an incident at the DBM complex for the six months ended June 30, 2017. See Note 1.
(3) 
Includes affiliate (as defined in Note 1) amounts of zero and $(0.1) million for the three and six months ended June 30, 2017, respectively. See Note 10.
(4) 
Represents net income (loss) earned on and subsequent to the date of acquisition of the Partnership assets (as defined in Note 1). See Note 5.
(5) 
See Note 5 for the calculation of net income (loss) per common unit.

See accompanying Notes to Consolidated Financial Statements.

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WESTERN GAS PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
thousands except number of units
 
June 30, 
 2018
 
December 31, 
 2017
ASSETS
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
 
$
53,235

 
$
78,814

Accounts receivable, net (1)
 
167,175

 
160,432

Other current assets (2)
 
26,728

 
14,816

Total current assets
 
247,138

 
254,062

Note receivable – Anadarko
 
260,000

 
260,000

Property, plant and equipment
 
 
 
 
Cost
 
8,618,993

 
7,864,535

Less accumulated depreciation
 
2,405,419

 
2,133,644

Net property, plant and equipment
 
6,213,574

 
5,730,891

Goodwill
 
416,160

 
416,160

Other intangible assets
 
761,054

 
775,269

Equity investments
 
754,300

 
566,211

Other assets (3)
 
14,384

 
11,757

Total assets
 
$
8,666,610

 
$
8,014,350

LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
 
 
 
 
Current liabilities
 
 
 
 
Accounts and imbalance payables (4)
 
$
331,447

 
$
349,801

Accrued ad valorem taxes
 
26,318

 
26,633

Accrued liabilities (5)
 
131,352

 
47,899

Total current liabilities
 
489,117

 
424,333

Long-term liabilities
 
 
 
 
Long-term debt
 
4,177,353

 
3,464,712

Deferred income taxes
 
8,753

 
7,409

Asset retirement obligations
 
151,412

 
143,394

Other liabilities (6)
 
138,493

 
3,491

Total long-term liabilities
 
4,476,011

 
3,619,006

Total liabilities
 
4,965,128

 
4,043,339

Equity and partners’ capital
 
 
 
 
Common units (152,609,285 and 152,602,105 units issued and outstanding at June 30, 2018, and December 31, 2017, respectively)
 
2,666,799

 
2,950,010

Class C units (13,778,265 and 13,243,883 units issued and outstanding at June 30, 2018, and December 31, 2017, respectively) (7)
 
781,057

 
780,040

General partner units (2,583,068 units issued and outstanding at June 30, 2018, and December 31, 2017)
 
191,564

 
179,232

Total partners’ capital
 
3,639,420

 
3,909,282

Noncontrolling interest
 
62,062

 
61,729

Total equity and partners’ capital
 
3,701,482

 
3,971,011

Total liabilities, equity and partners’ capital
 
$
8,666,610

 
$
8,014,350

                                                                                                                                                                                    
(1) 
Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $16.1 million and $36.3 million as of June 30, 2018, and December 31, 2017, respectively.
(2) 
Other current assets includes affiliate amounts of $9.3 million and zero as of June 30, 2018, and December 31, 2017, respectively.
(3) 
Other assets includes affiliate amounts of $0.2 million and zero as of June 30, 2018, and December 31, 2017, respectively.
(4) 
Accounts and imbalance payables includes affiliate amounts of zero and $0.3 million as of June 30, 2018, and December 31, 2017, respectively.
(5) 
Accrued liabilities includes affiliate amounts of $2.3 million and $0.2 million as of June 30, 2018, and December 31, 2017, respectively.
(6) 
Other liabilities includes affiliate amounts of $48.4 million and $0.7 million as of June 30, 2018, and December 31, 2017, respectively.
(7) 
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 5.

See accompanying Notes to Consolidated Financial Statements.

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WESTERN GAS PARTNERS, LP
CONSOLIDATED STATEMENT OF EQUITY AND PARTNERS’ CAPITAL
(UNAUDITED)
 
 
Partners’ Capital
 
 
 
 
thousands
 
Common
Units
 
Class C
Units
 
General
Partner 
Units
 
Noncontrolling
Interest
 
Total
Balance at December 31, 2017
 
$
2,950,010

 
$
780,040

 
$
179,232

 
$
61,729

 
$
3,971,011

Cumulative effect of accounting change (1)
 
(41,108
)
 
(3,533
)
 
(696
)
 
958

 
(44,379
)
Net income (loss)
 
11,528

 
2,928

 
167,615

 
5,796

 
187,867

Above-market component of swap agreements with Anadarko (2)
 
28,121

 

 

 

 
28,121

Amortization of beneficial conversion feature of Class C units
 
(1,622
)
 
1,622

 

 

 

Distributions to noncontrolling interest owner
 

 

 

 
(6,421
)
 
(6,421
)
Distributions to unitholders
 
(283,077
)
 

 
(154,642
)
 

 
(437,719
)
Contributions of equity-based compensation from Anadarko
 
2,737

 

 
55

 

 
2,792

Other
 
210

 

 

 

 
210

Balance at June 30, 2018
 
$
2,666,799

 
$
781,057

 
$
191,564

 
$
62,062

 
$
3,701,482

                                                                                                                                                                                    
(1) 
See Note 1.
(2) 
See Note 6.

See accompanying Notes to Consolidated Financial Statements.

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WESTERN GAS PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
 
 
Six Months Ended 
 June 30,
thousands
 
2018
 
2017
Cash flows from operating activities
 
 
 
 
Net income (loss)
 
$
187,867

 
$
279,488

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
 
Depreciation and amortization
 
155,634

 
143,733

Impairments
 
127,391

 
167,920

Non-cash equity-based compensation expense
 
3,017

 
2,393

Deferred income taxes
 
1,523

 
3,767

Accretion and amortization of long-term obligations, net
 
2,626

 
2,139

Equity income, net – affiliates
 
(59,642
)
 
(41,189
)
Distributions from equity investment earnings – affiliates
 
48,396

 
42,202

(Gain) loss on divestiture and other, net (1)
 
(286
)
 
(134,945
)
Lower of cost or market inventory adjustments
 
151

 
140

Changes in assets and liabilities:
 
 
 
 
(Increase) decrease in accounts receivable, net
 
(7,009
)
 
9,363

Increase (decrease) in accounts and imbalance payables and accrued liabilities, net
 
40,573

 
(41,975
)
Change in other items, net
 
14,670

 
116

Net cash provided by operating activities
 
514,911


433,152

Cash flows from investing activities
 
 
 
 
Capital expenditures
 
(650,096
)
 
(260,480
)
Contributions in aid of construction costs from affiliates
 

 
1,343

Acquisitions from affiliates
 

 
(3,910
)
Acquisitions from third parties
 
(161,858
)
 
(155,287
)
Investments in equity affiliates
 
(27,490
)
 
(287
)
Distributions from equity investments in excess of cumulative earnings – affiliates
 
12,505

 
9,221

Proceeds from the sale of assets to third parties
 
286

 
23,292

Proceeds from property insurance claims
 

 
22,977

Net cash used in investing activities
 
(826,653
)

(363,131
)
Cash flows from financing activities
 
 
 
 
Borrowings, net of debt issuance costs
 
1,337,539

 
159,989

Repayments of debt
 
(630,000
)
 

Settlement of the Deferred purchase price obligation – Anadarko (2)
 

 
(37,346
)
Increase (decrease) in outstanding checks
 
(5,357
)
 
(2,763
)
Proceeds from the issuance of common units, net of offering expenses
 

 
(183
)
Distributions to unitholders (3)
 
(437,719
)
 
(381,771
)
Distributions to noncontrolling interest owner
 
(6,421
)
 
(6,375
)
Net contributions from (distributions to) Anadarko
 

 
30

Above-market component of swap agreements with Anadarko (3)
 
28,121

 
28,670

Net cash provided by (used in) financing activities
 
286,163


(239,749
)
Net increase (decrease) in cash and cash equivalents
 
(25,579
)

(169,728
)
Cash and cash equivalents at beginning of period
 
78,814

 
357,925

Cash and cash equivalents at end of period
 
$
53,235


$
188,197

Supplemental disclosures
 
 
 
 
Accretion expense and revisions to the Deferred purchase price obligation – Anadarko
 
$

 
$
(4,094
)
Net distributions to (contributions from) Anadarko of other assets
 

 
(376
)
Interest paid, net of capitalized interest
 
62,924

 
68,396

Taxes paid (reimbursements received)
 
(87
)
 
189

Accrued capital expenditures
 
182,212

 
100,038

Fair value of properties and equipment from non-cash third party transactions (2)
 

 
551,453

                                                                                                                                                                                    
(1) 
Includes losses related to an incident at the DBM complex for the six months ended June 30, 2017. See Note 1.
(2) 
See Note 3.
(3) 
See Note 6.


See accompanying Notes to Consolidated Financial Statements.

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WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

General. Western Gas Partners, LP is a growth-oriented Delaware master limited partnership (“MLP”) formed by Anadarko Petroleum Corporation in 2007 to acquire, own, develop and operate midstream assets.
For purposes of these consolidated financial statements, the “Partnership” refers to Western Gas Partners, LP and its subsidiaries. The Partnership’s general partner, Western Gas Holdings, LLC (the “general partner”), is owned by Western Gas Equity Partners, LP (“WGP”), a Delaware MLP formed by Anadarko Petroleum Corporation in September 2012 to own the Partnership’s general partner, as well as a significant limited partner interest in the Partnership. WGP has no independent operations or material assets other than owning the partnership interests in the Partnership (see Holdings of Partnership equity in Note 5). Western Gas Equity Holdings, LLC is WGP’s general partner and is a wholly owned subsidiary of Anadarko Petroleum Corporation. “Anadarko” refers to Anadarko Petroleum Corporation and its subsidiaries, excluding the Partnership and the general partner, and “affiliates” refers to subsidiaries of Anadarko, excluding the Partnership, but including equity interests in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”), Rendezvous Gas Services, LLC (“Rendezvous”), Enterprise EF78 LLC (the “Mont Belvieu JV”), Texas Express Pipeline LLC (“TEP”), Texas Express Gathering LLC (“TEG”), Front Range Pipeline LLC (“FRP”), Whitethorn Pipeline Company LLC (“Whitethorn LLC”) and Cactus II Pipeline LLC (“Cactus II”). See Note 3. 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. In addition, in its capacity as a processor of natural gas, the Partnership also buys and sells natural gas, NGLs and condensate on behalf of itself and as agent for its customers under certain of its contracts. The Partnership provides these midstream services for Anadarko, as well as for third-party producers and customers. As of June 30, 2018, the Partnership’s assets and investments consisted of the following:
 
 
Owned and
Operated
 
Operated
Interests
 
Non-Operated
Interests
 
Equity
Interests
Gathering systems (1)
 
12

 
3

 
3

 
2

Treating facilities
 
19

 
3

 

 
3

Natural gas processing plants/trains
 
20

 
4

 

 
2

NGL pipelines
 
2

 

 

 
3

Natural gas pipelines
 
5

 

 

 

Oil pipelines
 

 
1

 

 
2

                                                                                                                                                                                    
(1) 
Includes the DBM water systems.

These assets and investments are located in the Rocky Mountains (Colorado, Utah and Wyoming), North-central Pennsylvania, Texas and New Mexico. Mentone Train I, a processing train at the DBM complex, is expected to commence operations at the end of the third quarter of 2018.


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WESTERN GAS PARTNERS, 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 for entities not wholly owned:
 
 
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
%
Whitethorn
 
20
%
Cactus II
 
15
%
Proportionate consolidation (2)
 
 
Marcellus Interest systems
 
33.75
%
Newcastle system
 
50
%
Springfield system
 
50.1
%
Full consolidation
 
 
Chipeta (3)
 
75
%
                                                                                                                                                                                                                   
(1) 
Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. “Equity investment throughput” refers to the Partnership’s share of average throughput for these investments.
(2) 
The Partnership proportionately consolidates its associated share of the assets, liabilities, revenues and expenses attributable to these assets.
(3) 
The 25% interest in Chipeta Processing LLC (“Chipeta”) held by a third-party member is reflected within noncontrolling interest in the consolidated financial statements.

The consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”). The consolidated financial statements include the accounts of the Partnership and entities in which it holds a controlling financial interest. All significant intercompany transactions have been eliminated.
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 2017 Form 10-K, as filed with the SEC on February 16, 2018. Management believes that the disclosures made are adequate to make the information not misleading.


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Table of Contents
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION (CONTINUED)

Presentation of Partnership assets. The term “Partnership assets” includes both the assets owned and the interests accounted for under the equity method by the Partnership as of June 30, 2018 (see Note 8). Because Anadarko controls the Partnership through its 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.
For those periods requiring recast, the consolidated financial statements for periods prior to the Partnership’s acquisition of the Partnership assets from Anadarko are prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the Partnership assets during the periods reported. Net income (loss) attributable to the Partnership assets acquired from Anadarko for periods prior to the Partnership’s acquisition of the Partnership assets is not allocated to the limited partners.

Use of estimates. In preparing financial statements in accordance with GAAP, management makes informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. Management evaluates its estimates and related assumptions regularly, using historical experience and other methods considered reasonable. Changes in facts and circumstances or additional information may result in revised estimates and actual results may differ from these estimates. Effects on the business, financial condition and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revisions become known. The information furnished herein reflects all normal recurring adjustments which are, in the opinion of management, necessary for a fair presentation of the consolidated financial statements, and certain prior-period amounts have been reclassified to conform to the current-year presentation.

Shutdown of gathering systems. In May 2018, after assessing a number of factors, with safety and protection of the environment as the primary focus, the Partnership decided to take the Kitty Draw gathering system in Wyoming (part of the Hilight system) and the Third Creek gathering system in Colorado (part of the DJ Basin complex) permanently out of service. Results for the three and six months ended June 30, 2018, reflect (i) an accrual of $10.9 million in anticipated costs associated with the shutdown of the systems, recorded as a reduction in affiliate Product sales in the consolidated statements of operations and (ii) impairment expense of $127.2 million associated with reducing the net book value of the gathering systems and additional asset retirement obligation.

Insurance recoveries. In December 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. During the six months ended June 30, 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. During the six months ended June 30, 2017, the Partnership received $52.9 million in cash proceeds from insurers, including $29.9 million in proceeds from business interruption insurance claims and $23.0 million in proceeds from property insurance claims.

Recently adopted accounting standards. Accounting Standards Update (“ASU”) 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. The Partnership adopted this ASU using a retrospective approach on January 1, 2018, and the adoption did not impact the consolidated financial statements.


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Table of Contents
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION (CONTINUED)

Revenue from contracts with customers (Topic 606). The Partnership adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Topic 606”) on January 1, 2018, using the modified retrospective method applied to contracts that were not completed as of January 1, 2018. The cumulative effect adjustment that was recognized in the opening balance of equity and partners’ capital was a decrease of $44.4 million. The comparative historical financial information has not been adjusted and continues to be reported under Revenue Recognition (Topic 605) (“Topic 605”).
    
Effective January 1, 2018, the Partnership changed its accounting policy for revenue recognition as detailed below:

Fee-based gathering / processing. Under Topic 605, fee revenues were recognized based on the rate in effect for the month of service, even when certain fees were charged on an upfront or limited-term basis. In addition, deficiency fees were charged and recognized only when the customer did not meet the specified delivery minimums for the completed performance period. Under Topic 606, revenues continue to be recognized based on the rate in effect when the fee is either the same rate per unit over the contract term or when the fee escalates and the escalation factor approximates inflation. Under Topic 606, the Partnership recognizes revenue associated with upfront or limited-term fees over the expected period of customer benefit, which is generally the life of the related properties. In addition, deficiency fees are estimated and recognized during the performance period as the services are performed for the customer’s delivered volumes. Under Topic 606, differences between Service revenues – fee based recognized and amounts billed to customers are recognized as contract assets or contract liabilities, as appropriate. This results in a change in the timing of revenue and changes to net income as a result of the revenue contract’s consideration provisions.

Cost of service rate adjustments. Under Topic 605, revenue was recognized based on the amounts billed to customers each period. Under Topic 606, fixed minimum volume commitment demand fees and variable fees that are also billed on these minimum volumes are recognized as Service revenues – fee based on a consistent per-unit rate over the term of the contract. Annual adjustments are made to the cost of service rates charged to customers, and, as a result, a cumulative catch-up revenue adjustment related to the services already provided under the contract may be recorded in future periods, with revenues for the remaining term of the contract recognized on a consistent per-unit rate. Fees received on volumes in excess of the minimum volumes are recognized as Service revenues – fee based as service is provided to the customer based on the billing rate in effect for the performance period. This revenue recognition timing does not affect billings to customers, and differences between amounts billed and revenue recognized are recorded as contract assets or liabilities, as appropriate.

Aid in construction. Under Topic 605, aid in construction reimbursements were reflected as a reduction to property, plant and equipment upon receipt (and a reduction to capital expenditures). Under Topic 606, reimbursement of capital costs received from customers is reflected as a contract liability (deferred revenue) upon receipt. The contract liability is amortized to Service revenues – fee based over the expected period of customer benefit, which is generally the life of the related properties.

Percent-of-proceeds gathering / processing. Under Topic 605, the Partnership recognized cost of product expense when the product was purchased from a producer to whom it provides services, and the Partnership recognized revenue when the product was sold to Anadarko or a third party. Under Topic 606, in some instances, where all or a percentage of the proceeds from the sale must be returned to the producer, the net margin from the purchase and sale transactions is presented net within Service revenues – product based because the Partnership is acting as the producer’s agent in the product sale.


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Table of Contents
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION (CONTINUED)

Noncash consideration - keep-whole and percent-of-product agreements. Under Topic 605, the Partnership recognized revenues only upon the sale of the related products. Under Topic 606, the Partnership recognizes Service revenues – product based for the products received as noncash consideration in exchange for the services provided, with the keep-whole noncash consideration value based on the net value of the NGLs over the replacement residue gas cost. Under Topic 606, revenue from product sales is recognized, along with cost of product expense related to the sale, when the product is sold to Anadarko or a third party.

Wellhead purchase / sale incorporated into gathering / processing. Under Topic 605, the natural gas purchase cost was recognized as cost of product expense and any specified gathering or processing fees charged to the producer were recognized as revenues. Under Topic 606, the fees charged to the producer under this contract type are recognized as adjustments to the amount recognized in cost of product expense instead of revenues when such fees relate to services performed after control of the product transfers to the Partnership.

The following tables summarize the impact of adopting Topic 606 on the impacted line items within the consolidated statements of operations and the consolidated balance sheet. The differences between revenue as reported following Topic 606 and revenue as it would have been reported under Topic 605 are due to the changes described above.
 
 
Three Months Ended 
 June 30, 2018
thousands
 
As Reported
 
Without Adoption of Topic 606
 
Effect of Change
Increase / (Decrease)
Revenues
 
 
 
 
 
 
Service revenues – fee based
 
$
359,544

 
$
358,209

 
$
1,335

Service revenues – product based
 
22,105

 

 
22,105

Product sales
 
54,077

 
319,233

 
(265,156
)
Expenses
 
 
 
 
 


Cost of product
 
68,149

 
312,329

 
(244,180
)
Operation and maintenance
 
100,628

 
100,632

 
(4
)
Depreciation and amortization
 
78,792

 
78,125

 
667

Impairments
 
127,243

 
127,198

 
45

Income tax (benefit) expense
 
282

 
272

 
10

Net income attributable to noncontrolling interest
 
2,811

 
2,054

 
757

Net income (loss) attributable to Western Gas Partners, LP
 
32,708

 
31,719

 
989

 


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WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION (CONTINUED)

 
 
Six Months Ended 
 June 30, 2018
thousands
 
As Reported
 
Without Adoption of Topic 606
 
Effect of Change
Increase / (Decrease)
Revenues
 
 
 
 
 
 
Service revenues – fee based
 
$
697,963

 
$
700,547

 
$
(2,584
)
Service revenues – product based
 
44,698

 

 
44,698

Product sales
 
130,014

 
611,524

 
(481,510
)
Expenses
 
 
 
 
 


Cost of product
 
145,948

 
587,295

 
(441,347
)
Operation and maintenance
 
188,907

 
188,771

 
136

Depreciation and amortization
 
155,634

 
154,278

 
1,356

Impairments
 
127,391

 
127,346

 
45

Income tax (benefit) expense
 
1,784

 
1,781

 
3

Net income attributable to noncontrolling interest
 
5,796

 
4,552

 
1,244

Net income (loss) attributable to Western Gas Partners, LP
 
182,071

 
182,904

 
(833
)
 
 
 
June 30, 2018
thousands
 
As Reported
 
Without Adoption of Topic 606
 
Effect of Change
Increase / (Decrease)
Assets
 
 
 
 
 
 
Other current assets
 
$
26,728

 
$
17,388

 
$
9,340

Net property, plant and equipment
 
6,213,574

 
6,117,733

 
95,841

Other assets
 
14,384

 
14,138

 
246

Liabilities
 
 
 
 
 


Accrued liabilities
 
131,352

 
124,913

 
6,439

Deferred income taxes
 
8,753

 
8,930

 
(177
)
Other liabilities
 
138,493

 
2,810

 
135,683

Equity and partners’ capital
 
 
 
 
 


Total equity and partners’ capital
 
3,701,482

 
3,738,000

 
(36,518
)

New accounting standards issued but not yet adopted. ASU 2016-02, Leases (Topic 842) requires lessees to recognize a lease liability and a right-of-use (“ROU”) asset for all leases, including operating leases, with a term greater than 12 months on the balance sheet. This ASU modifies the definition of a lease and outlines the recognition, measurement, presentation, and disclosure of leasing arrangements by both lessees and lessors. The Partnership plans to make certain elections allowing the Partnership not to reassess contracts that commenced prior to adoption, to continue applying its current accounting policy for land easements and not to recognize ROU assets or lease liabilities for short-term leases. The Partnership continues to review contracts in its portfolio of leased assets to assess the impact of adopting this ASU, which is expected to primarily impact other assets and other liabilities. To facilitate compliance with this ASU, the Partnership is implementing new accounting software and continuing to evaluate its systems, processes and internal controls during 2018. The Partnership will adopt this ASU on January 1, 2019. As permitted by ASU 2018-11, Leases (Topic 842): Targeted Improvements, the Partnership does not expect to adjust comparative period financial statements.


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Table of Contents
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION (CONTINUED)

Revenue and cost of product. Upon adoption of the new revenue recognition standard on January 1, 2018 (discussed in Recently adopted accounting standards), the Partnership changed its accounting policy for revenue recognition as described below.
The Partnership provides gathering, processing, treating, transportation and disposal services pursuant to a variety of contracts. Under these arrangements, the Partnership receives fees and/or retains a percentage of products or a percentage of the proceeds from the sale of the customer’s products. These revenues are included in Service revenues and Product sales in the consolidated statements of operations. Payment is generally received from the customer in the month following the service or delivery of the product. Contracts with customers generally have initial terms ranging from 5 to 10 years.
Service revenues fee based is recognized for fee-based contracts in the month of service based on the volumes delivered by the customer. Producers’ wells or production facilities are connected to the Partnership’s gathering systems for gathering, processing, treating, transportation and disposal of natural gas, NGLs, condensate, crude oil and produced water, as applicable. Revenues are valued based on the rate in effect for the month of service when the fee is either the same rate per unit over the contract term or when the fee escalates and the escalation factor approximates inflation. Deficiency fees charged to customers that do not meet their minimum delivery requirements are recognized as services are performed based on an estimate of the fees that will be billed upon completion of the performance period. Because of its significant upfront capital investment, the Partnership may charge additional service fees to customers for only a portion of the contract term (i.e., for the first year of a contract or until reaching a volume threshold), and these fees are recognized as revenue over the expected period of customer benefit, which is generally the life of the related properties.
The Partnership also receives Service revenues fee based from contracts that have minimum volume commitment demand fees and fees that require periodic rate redeterminations based upon the related facility cost of service. These fees include fixed and variable consideration that are recognized on a consistent per-unit rate over the term of the contract. Annual adjustments are made to the cost of service rates charged to customers, and a cumulative catch-up revenue adjustment related to services already provided to the minimum volumes under the contract may be recorded in future periods, with revenues for the remaining term of the contract recognized on a consistent per-unit rate.
Service revenues product based includes service revenues from percent-of-proceeds gathering and processing contracts that are recognized net of the cost of product for purchases from the Partnership’s customers since it is acting as the agent in the product sale. Keep-whole and percent-of-product agreements result in Service revenues product based being recognized when the natural gas and/or NGLs are received from the customer as noncash consideration for the services provided. Noncash consideration for these services is valued at the time the services are provided. Revenue from product sales is also recognized, along with the cost of product expense related to the sale, when the product received as noncash consideration is sold to either Anadarko or a third party.
The Partnership also purchases natural gas volumes from producers at the wellhead or from a production facility, typically at an index price, and charges the producer fees associated with the downstream gathering and processing services. When the fees relate to services performed after control of the product has transferred to the Partnership, the fees are treated as a reduction of the purchase cost. Revenue from product sales is recognized, along with cost of product expense related to the sale, when the purchased product is sold to either Anadarko or a third party.
The Partnership receives aid in construction reimbursements for certain capital costs necessary to provide services to customers (i.e., connection costs, etc.) under certain service contracts. Aid in construction reimbursements are reflected as a contract liability upon receipt and amortized to Service revenues fee based over the expected period of customer benefit, which is generally the life of the related properties.


16

Table of Contents
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

2. REVENUE FROM CONTRACTS WITH CUSTOMERS

The following table summarizes the Partnership’s revenue from contracts with customers:
thousands
 
Three Months Ended 
 June 30, 2018
 
Six Months Ended 
 June 30, 2018
Revenue from customers
 
 
 
 
Service revenues – fee based
 
$
359,544

 
$
697,963

Service revenues – product based
 
22,105

 
44,698

Product sales
 
55,449

 
132,629

Total revenue from customers
 
437,098

 
875,290

Revenue from other than customers
 
 
 
 
Net gains (losses) on commodity price swap agreements
 
(1,372
)
 
(2,615
)
Other
 
223

 
442

Total revenues and other
 
$
435,949

 
$
873,117

 

Contract balances. Receivables from customers, which are included in Accounts receivable, net on the consolidated balance sheets were $267.1 million and $244.4 million as of June 30, 2018, and December 31, 2017, respectively.
Contract assets primarily relate to accrued deficiency fees the Partnership expects to charge customers once the related performance periods are completed. The following table summarizes the current period activity related to contract assets from contracts with customers:
thousands
 
 
Balance at December 31, 2017
 
$

Cumulative effect of adopting Topic 606
 
5,129

Amounts transferred to Accounts receivable, net from contract assets recognized in the adoption effect (1)
 
(2,677
)
Additional estimated revenues recognized (2)
 
7,134

Balance at June 30, 2018
 
$
9,586

 
 
 
Contract assets at June 30, 2018
 
 
Other current assets
 
$
9,340

Other assets
 
246

Total contract assets from contracts with customers
 
$
9,586

                                                                                                                                                                                    
(1) 
Includes $(0.2) million for the three months ended June 30, 2018.
(2) 
Includes $3.7 million for the three months ended June 30, 2018.


17

Table of Contents
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

2. REVENUE FROM CONTRACTS WITH CUSTOMERS (CONTINUED)

Contract liabilities primarily relate to (i) 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, (ii) fixed and variable fees under cost of service contracts that are received from customers for which revenue recognition is deferred and (iii) aid in construction payments received from customers that must be recognized over the expected period of customer benefit. The following table summarizes the current period activity related to contract liabilities from contracts with customers:
thousands
 
 
Balance at December 31, 2017
 
$

Cumulative effect of adopting Topic 606
 
120,717

Cash received or receivable, excluding revenues recognized during the period (1)
 
41,076

Revenues recognized during the period that were included in the adoption effect (2)
 
(2,009
)
Balance at June 30, 2018
 
$
159,784

 
 
 
Contract liabilities at June 30, 2018
 
 
Accrued liabilities
 
$
24,101

Other liabilities
 
135,683

Total contract liabilities from contracts with customers
 
$
159,784

                                                                                                                                                                                    
(1) 
Includes $12.5 million for the three months ended June 30, 2018.
(2) 
Includes $(1.0) million for the three months ended June 30, 2018.

Transaction price allocated to remaining performance obligations. Revenues expected to be recognized from certain performance obligations that are unsatisfied (or partially unsatisfied) as of June 30, 2018, are reflected in the following table. The Partnership applies the optional exemptions in Topic 606 and does not disclose consideration for remaining performance obligations with an original expected duration of one year or less or for variable consideration related to unsatisfied (or partially unsatisfied) performance obligations. Therefore, the following table represents only a small portion of expected future consolidated revenues from existing contracts as most future revenues from customers are dependent on future variable customer volumes and in some cases variable commodity prices for those volumes.
thousands
 
 
Remainder of 2018
 
$
220,037

2019
 
492,806

2020
 
542,214

2021
 
527,151

2022
 
527,103

Thereafter
 
2,168,028

Total
 
$
4,477,339



18

Table of Contents
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

3. ACQUISITIONS AND DIVESTITURES

Whitethorn LLC acquisition. In June 2018, the Partnership acquired a 20% interest in Whitethorn LLC, which owns the crude oil and condensate pipeline that originates in Midland, Texas and terminates in Sealy, Texas (the “Midland-to-Sealy pipeline”) and related storage facilities (collectively referred to as “Whitethorn”). A third party operates Whitethorn and oversees the related commercial activities. In connection with its investment in Whitethorn, the Partnership will share proportionally in the commercial activities. The Partnership acquired its 20% interest via a $150.6 million net investment, which was funded with cash on hand and is accounted for under the equity method. See Note 8.

Cactus II acquisition. In June 2018, the Partnership acquired a 15% interest in Cactus II, which will own a crude oil pipeline operated by a third party (the “Cactus II pipeline”) connecting West Texas to the Corpus Christi area. The Cactus II pipeline is under construction and expected to become operational in the fourth quarter of 2019. The Partnership acquired its 15% interest from a third party via an $11.3 million net investment, which was funded with cash on hand and is accounted for under the equity method. See Note 8.

Property exchange. On March 17, 2017, the Partnership acquired an additional 50% interest in the Delaware Basin JV Gathering LLC (“DBJV”) system (the “Additional DBJV System Interest”) from a third party in exchange for (a) 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 as the Liberty 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 was reflected as a nonmonetary transaction whereby the acquired Additional DBJV System Interest was recorded at the fair value of the divested Non-Operated Marcellus Interest plus the $155.0 million of cash consideration. The Property Exchange resulted in a net gain of $125.7 million recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations. Results of operations attributable to the Property Exchange were included in the consolidated statements of operations beginning on the acquisition date in the first quarter of 2017.

DBJV acquisition - Deferred purchase price obligation - Anadarko. Prior to the Partnership’s 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 DBJV from Anadarko consisted of a cash payment to Anadarko due on March 31, 2020. In May 2017, the Partnership reached an agreement with Anadarko to settle this obligation with a cash payment to Anadarko of $37.3 million, which was equal to the estimated net present value of the obligation at March 31, 2017.

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 $16.3 million recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations.


19

Table of Contents
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

4. PARTNERSHIP DISTRIBUTIONS

The partnership agreement requires the Partnership to distribute all of its available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date within 45 days of the end of each quarter. The Board of Directors 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
2017
 
 
 
 
 
 
March 31
 
$
0.875

 
$
188,753

 
May 2017
June 30
 
0.890

 
207,491

 
August 2017
September 30
 
0.905

 
212,038

 
November 2017
December 31
 
0.920

 
216,586

 
February 2018
2018
 
 
 
 
 
 
March 31
 
$
0.935

 
$
221,133

 
May 2018
June 30 (1)
 
0.950

 
225,691

 
August 2018
                                                                                                                                                                                    
(1) 
The Board of Directors declared a cash distribution to the Partnership’s unitholders for the second quarter of 2018 of $0.950 per unit, or $225.7 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 August 13, 2018, to unitholders of record at the close of business on August 1, 2018.

Available cash. The amount of available cash (as defined in the partnership agreement) generally is all cash on hand at the end of the quarter, plus, at the discretion of the general partner, working capital borrowings made subsequent to the end of such quarter, less the amount of cash reserves established by the Partnership’s general partner to provide for the proper conduct of the Partnership’s business, including reserves to fund future capital expenditures; to comply with applicable laws, debt instruments or other agreements; or to provide funds for distributions to its unitholders and to its general partner for any one or more of the next four quarters. Working capital borrowings generally include borrowings made under a credit facility or similar financing arrangement. Working capital borrowings may only be those that, at the time of such borrowings, were intended to be repaid within 12 months. In all cases, working capital borrowings are used solely for working capital purposes or to fund distributions to partners.

Class C unit distributions. The Class C units receive quarterly distributions at a rate equivalent to the Partnership’s common units. The distributions are paid in the form of additional Class C units (“PIK Class C units”) until the scheduled conversion date on 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 into common units. The number of additional PIK Class C units to be issued in connection with a distribution payable on the Class C units is determined by dividing the corresponding distribution attributable to the Class C units by the volume-weighted-average price of the Partnership’s common units for the ten days immediately preceding the payment date for the common unit distribution, less a 6% discount. The Partnership records the PIK Class C unit distributions at fair value at the time of issuance. This Level 2 fair value measurement uses the Partnership’s unit price as a significant input in the determination of the fair value. See Note 5 for further discussion of the Class C units.

20

Table of Contents
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

4. PARTNERSHIP DISTRIBUTIONS (CONTINUED)

Series A Preferred unit distributions. As further described in Note 5, the Partnership issued Series A Preferred units representing limited partner interests in 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. On March 1, 2017, 50% of the outstanding Series A Preferred units converted into common units on a one-for-one basis, and on May 2, 2017, all 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. For the quarter ended March 31, 2017, the Series A Preferred unitholders received an aggregate cash distribution of $7.5 million (paid in May 2017).

General partner interest and incentive distribution rights. As of June 30, 2018, 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.

5. EQUITY AND PARTNERS’ CAPITAL

Equity offerings. In July 2017, the Partnership filed a registration statement with the SEC for the issuance of up to an aggregate of $500.0 million of common units pursuant to a new continuous offering program that has not yet been initiated.

Class C units. In November 2014, the Partnership issued 10,913,853 Class C units to APC 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 included in the calculation of earnings per unit.

Series A Preferred units. In 2016, the Partnership issued 21,922,831 Series A Preferred units to private investors. 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, representing a beneficial conversion feature at issuance. The impact of the beneficial conversion feature amortization was included in the calculation of earnings per unit. For the six months ended June 30, 2017, the amortization for the beneficial conversion feature of the Series A Preferred units was $62.3 million.
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 all remaining Series A Preferred units converted into common units on a one-for-one basis on May 2, 2017.

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WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

5. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

Partnership interests. The Partnership’s common units are listed on the New York Stock Exchange under the symbol “WES.”
The following table summarizes the Partnership’s units issued during the six months ended June 30, 2018:
 
 
Common
Units
 
Class C
Units
 
General
Partner
Units
 
Total
Balance at December 31, 2017
 
152,602,105


13,243,883

 
2,583,068


168,429,056

PIK Class C units
 

 
534,382

 

 
534,382

Long-Term Incentive Plan award vestings
 
7,180

 

 

 
7,180

Balance at June 30, 2018
 
152,609,285

 
13,778,265

 
2,583,068

 
168,970,618


Holdings of Partnership equity. As of June 30, 2018, WGP held 50,132,046 common units, representing a 29.7% limited partner interest in the Partnership, and, through its ownership of the general partner, WGP indirectly held 2,583,068 general partner units, representing a 1.5% general partner interest in the Partnership, and 100% of the IDRs. As of June 30, 2018, other subsidiaries of Anadarko collectively held 2,011,380 common units and 13,778,265 Class C units, representing an aggregate 9.3% limited partner interest in the Partnership. As of June 30, 2018, the public held 100,465,859 common units, representing the remaining 59.5% limited partner interest in the Partnership.

Net income (loss) per common unit. 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 4). The common and Class C unitholders’ allocation is equal to their cash distributions plus their respective portions 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-average ownership percentages during each period. 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).


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WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

5. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

Calculation of net income (loss) per unit. Basic net income (loss) per common unit is calculated by dividing the net income (loss) attributable to common unitholders by the weighted-average number of common units outstanding during the period. The common units issued in connection with acquisitions and equity offerings are included on a weighted-average basis for periods they were outstanding. Diluted net income (loss) per common unit is calculated by dividing the sum of (i) the net income (loss) attributable to common units adjusted for distributions on the Series A Preferred units and a reallocation of the common and Class C limited partners’ interest in net income (loss) assuming, prior to the actual conversion, conversion of the Series A Preferred units into common units, and (ii) the net income (loss) attributable to the Class C units as a participating security, by the sum of the weighted-average number of common units outstanding plus the dilutive effect of (i) the weighted-average number of outstanding Class C units and (ii) the weighted-average number of common units outstanding assuming, prior to the actual conversion, conversion of the Series A Preferred units.
The following table illustrates the Partnership’s calculation of net income (loss) per common unit:
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
thousands except per-unit amounts
 
2018
 
2017
 
2018
 
2017
Net income (loss) attributable to Western Gas Partners, LP
 
$
32,708

 
$
173,451

 
$
182,071

 
$
275,340

Series A Preferred units interest in net (income) loss (1)
 

 
(14,199
)
 

 
(42,373
)
General partner interest in net (income) loss
 
(84,176
)
 
(76,365
)
 
(167,615
)
 
(144,527
)
Common and Class C limited partners’ interest in net income (loss)
 
$
(51,468
)
 
$
82,887

 
$
14,456

 
$
88,440

Net income (loss) allocable to common units (1)
 
$
(48,417
)
 
$
73,383

 
$
9,906

 
$
75,097

Net income (loss) allocable to Class C units (1)
 
(3,051
)
 
9,504

 
4,550

 
13,343

Common and Class C limited partners’ interest in net income (loss)
 
$
(51,468
)
 
$
82,887

 
$
14,456

 
$
88,440

Net income (loss) per unit
 
 
 
 
 
 
 
 
Common units – basic and diluted (2)
 
$
(0.32
)
 
$
0.49

 
$
0.06

 
$
0.53

Weighted-average units outstanding
 
 
 
 
 
 
 
 
Common units – basic and diluted
 
152,604

 
148,864

 
152,603

 
141,696

Excluded due to anti-dilutive effect:
 
 
 
 
 
 
 
 
Class C units (2)
 
13,649

 
12,650

 
13,516

 
12,552

Series A Preferred units assuming conversion to common units (2)
 

 
3,734

 

 
10,901

                                                                                                                                                                                    
(1) 
Adjusted to reflect amortization of the beneficial conversion features.
(2) 
The impact of Class C units would be anti-dilutive for all periods presented and the conversion of Series A Preferred units would be anti-dilutive for the three and six months ended June 30, 2017. On March 1, 2017, 50% of the outstanding Series A Preferred units converted into common units on a one-for-one basis, and on May 2, 2017, all remaining Series A Preferred units converted into common units on a one-for-one basis.


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WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

6. TRANSACTIONS WITH AFFILIATES

Affiliate transactions. Revenues from affiliates include amounts earned by the Partnership from services provided to Anadarko as well as from the sale of residue and NGLs to Anadarko. In addition, the Partnership purchases natural gas from an affiliate of Anadarko pursuant to gas purchase agreements. Operation and maintenance expense includes amounts accrued for or paid to affiliates for the operation of the Partnership assets, whether in providing services to affiliates or to third parties, including field labor, measurement and analysis, and other disbursements. A portion of the Partnership’s general and administrative expenses is paid by Anadarko, which results in affiliate transactions pursuant to the reimbursement provisions of the Partnership’s omnibus agreement. Affiliate expenses do not bear a direct relationship to affiliate revenues, and third-party expenses do not bear a direct relationship to third-party revenues.

Cash management. Anadarko operates a cash management system whereby excess cash from most of its subsidiaries’ separate bank accounts is generally swept to centralized accounts. Prior to the Partnership’s acquisition of the Partnership assets, third-party sales and purchases related to such assets were received or paid in cash by Anadarko within its centralized cash management system. The outstanding affiliate balances were entirely settled through an adjustment to net investment by Anadarko in connection with the acquisition of the Partnership assets. Subsequent to the acquisition of Partnership assets from Anadarko, transactions related to such assets are cash-settled directly with third parties and with Anadarko affiliates. Chipeta cash settles its transactions directly with third parties and Anadarko, as well as with the other subsidiaries of the Partnership.

Note receivable - Anadarko. Concurrently with the closing of the Partnership’s May 2008 initial public offering, the Partnership loaned $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%, payable quarterly. The fair value of the note receivable from Anadarko was $304.7 million and $325.2 million at June 30, 2018, and December 31, 2017, 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, percent-of-product 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. The Partnership’s net gains (losses) on commodity price swap agreements were $(1.4) million and $(2.6) million for the three and six months ended June 30, 2018, respectively, and $1.0 million and $0.5 million for the three and six months ended June 30, 2017, respectively, and are reported in the consolidated statements of operations as affiliate Product sales in 2018 and as affiliate Product sales and Cost of product expense in 2017 (see Note 1).


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WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

6. TRANSACTIONS WITH AFFILIATES (CONTINUED)

Revenues or costs attributable to volumes sold and purchased during 2017 and 2018 for the DJ Basin complex and 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 Anadarko in the Partnership’s consolidated statement of equity and partners’ capital for an amount equal to (i) the amount by which the swap price for product sales exceeds the applicable market price in the tables below, minus (ii) the amount by which the swap price for product purchases exceeds the market price in the tables below. For the six months ended June 30, 2018, the capital contribution from Anadarko was $28.1 million. The tables below summarize the swap prices compared to the forward market prices:
 
 
DJ Basin Complex
per barrel except natural gas
 
2017 - 2018 Swap Prices
 
2017 Market Prices (1)
 
2018 Market Prices (1)
Ethane
 
$
18.41

 
$
5.09

 
$
5.41

Propane
 
47.08

 
18.85

 
28.72

Isobutane
 
62.09

 
26.83

 
32.92

Normal butane
 
54.62

 
26.20

 
32.71

Natural gasoline
 
72.88

 
41.84

 
48.04

Condensate
 
76.47

 
45.40

 
49.36

Natural gas (per MMBtu)
 
5.96

 
3.05

 
2.21


 
 
MGR Assets
per barrel except natural gas
 
2017 - 2018 Swap Prices
 
2017 Market Prices (1)
 
2018 Market Prices (1)
Ethane
 
$
23.11

 
$
4.08

 
$
2.52

Propane
 
52.90

 
19.24

 
25.83

Isobutane
 
73.89

 
25.79

 
30.03

Normal butane
 
64.93

 
25.16

 
29.82

Natural gasoline
 
81.68

 
45.01

 
47.25

Condensate
 
81.68

 
53.55

 
56.76

Natural gas (per MMBtu)
 
4.87

 
3.05

 
2.21

                                                                                                                                                                                    
(1) 
Represents the New York Mercantile Exchange forward strip price as of December 1, 2016, and December 20, 2017, for the 2017 Market Prices and 2018 Market Prices, respectively, 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 owned or controlled by Anadarko was 35% for both the three and six months ended June 30, 2018, and 38% and 34% for the three and six months ended June 30, 2017, respectively. The Partnership’s natural gas processing throughput (excluding equity investment throughput) attributable to production owned or controlled by Anadarko was 35% for both the three and six months ended June 30, 2018, and 39% and 44% for the three and six months ended June 30, 2017, respectively. The Partnership’s crude oil, NGL and produced water gathering, treating, transportation and disposal throughput (excluding equity investment throughput) attributable to production owned or controlled by Anadarko was 72% and 68% for the three and six months ended June 30, 2018, respectively, and 41% and 47% for the three and six months ended June 30, 2017, respectively.


25

Table of Contents
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

6. TRANSACTIONS WITH AFFILIATES (CONTINUED)

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.

WES LTIP. The general partner awards phantom units under the Western Gas Partners, LP 2017 Long-Term Incentive Plan, effective October 17, 2017. Awards granted prior to October 17, 2017, were awarded under the Western Gas Partners, LP 2008 Long-Term Incentive Plan. These awards are primarily granted to its independent directors, but also from time to time to its executive officers and Anadarko employees performing services for the Partnership. The phantom units awarded to the independent directors vest one year from the grant date, while all other awards are subject to graded vesting over a three-year service period. Compensation expense is recognized over the vesting period and was $0.1 million for each of the three months ended June 30, 2018 and 2017, and $0.2 million for each of the six months ended June 30, 2018 and 2017.

Anadarko Incentive Plan. General and administrative expenses included $1.7 million and $3.8 million for the three and six months ended June 30, 2018, respectively, and $0.9 million and $2.1 million for the three and six months ended June 30, 2017, 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 Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan (“Anadarko Incentive Plan”). Of this amount, $2.8 million is reflected as contributions to partners’ capital in the Partnership’s consolidated statement of equity and partners’ capital for the six months ended June 30, 2018.

Purchases. The following table summarizes the Partnership’s purchases from Anadarko of pipe and equipment:
 
 
Six Months Ended June 30,
thousands
 
2018
 
2017
Cash consideration
 
$

 
$
3,910

Payable to affiliate
 
254

 

Net carrying value
 
(254
)
 
(4,286
)
Partners’ capital adjustment
 
$

 
$
(376
)

Contributions in aid of construction costs from affiliates. On certain of the Partnership’s capital projects, Anadarko is obligated to reimburse the Partnership for all or a portion of project capital expenditures. The majority of such arrangements are associated with projects related to pipeline construction activities and production well tie-ins. For periods prior to January 1, 2018, the cash receipts resulting from such reimbursements were presented as “Contributions in aid of construction costs from affiliates” within the investing section of the consolidated statements of cash flows. As discussed in Recently adopted accounting standards in Note 1, upon adoption of Topic 606, affiliate reimbursements of capital costs are reflected as contract liabilities upon receipt, amortized to Service revenues fee based over the expected period of customer benefit, and presented within the operating section of the consolidated statements of cash flows.


26

Table of Contents
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

6. TRANSACTIONS WITH AFFILIATES (CONTINUED)

Summary of affiliate transactions. The following table summarizes material affiliate transactions:
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
thousands
 
2018
 
2017
 
2018
 
2017
Revenues and other (1)
 
$
238,029

 
$
316,313

 
$
479,091

 
$
631,468

Equity income, net – affiliates (1)
 
39,218

 
21,728

 
59,642

 
41,189

Cost of product (1)
 
12,609

 
21,607

 
32,853

 
37,595

Operation and maintenance (2)
 
23,437

 
18,462

 
43,685

 
35,551

General and administrative (3)
 
11,178

 
9,365

 
22,792

 
18,900

Operating expenses
 
47,224

 
49,434

 
99,330

 
92,046

Interest income (4)
 
4,225

 
4,225

 
8,450

 
8,450

Interest expense (5)
 

 

 

 
71

Settlement of the Deferred purchase price obligation – Anadarko (6)
 

 
(37,346
)
 

 
(37,346
)
Distributions to unitholders (7)
 
127,204

 
110,449

 
251,368

 
213,572

Above-market component of swap agreements with Anadarko
 
13,839

 
16,373

 
28,121

 
28,670

                                                                                                                                                                                    
(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 acquisition of 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 Anadarko Incentive Plan within this Note 6).
(4) 
Represents interest income recognized on the note receivable from Anadarko.
(5) 
Includes amounts related to the Deferred purchase price obligation - Anadarko (see Note 3 and Note 10).
(6) 
Represents the cash payment to Anadarko for the settlement of the Deferred purchase price obligation - Anadarko (see Note 3).
(7) 
Represents distributions paid under the partnership agreement (see Note 4 and Note 5).

Concentration of credit risk. Anadarko was the only customer from whom revenues exceeded 10% of the Partnership’s consolidated revenues for all periods presented in the consolidated statements of operations.


27

Table of Contents
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

7. PROPERTY, PLANT AND EQUIPMENT

A summary of the historical cost of property, plant and equipment is as follows:
thousands
 
Estimated Useful Life
 
June 30, 
 2018
 
December 31, 
 2017
Land
 
n/a
 
$
4,653

 
$
4,450

Gathering systems and processing complexes
 
3 to 47 years
 
7,565,998

 
7,113,114

Pipelines and equipment
 
15 to 45 years
 
137,769

 
137,644

Assets under construction
 
n/a
 
879,095

 
579,501

Other
 
3 to 40 years
 
31,478

 
29,826

Total property, plant and equipment
 
 
 
8,618,993

 
7,864,535

Less accumulated depreciation
 
 
 
2,405,419

 
2,133,644

Net property, plant and equipment
 
 
 
$
6,213,574

 
$
5,730,891


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 six months ended June 30, 2018, the Partnership recognized impairments of $127.4 million, including impairments of $120.8 million at the Third Creek gathering system and $6.4 million at the Kitty Draw gathering system. These assets were impaired to their estimated salvage values of $1.0 million and zero, respectively, using the market approach and Level 3 fair value inputs, due to the shutdown of the systems. See Note 1 for further information.
During the year ended December 31, 2017, the Partnership recognized impairments of $178.4 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. The remaining $19.6 million of impairments was primarily related to (i) an $8.2 million impairment due to the cancellation of a plant project at the Hilight system, (ii) 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, (iii) a $3.1 million impairment of the Fort Union equity investment, (iv) 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 (v) the cancellation of a pipeline project in West Texas.


28

Table of Contents
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

8. EQUITY INVESTMENTS

The following table presents the activity in the Partnership’s equity investments for the six months ended June 30, 2018:
thousands
 
Fort
Union
 
White
Cliffs
 
Rendezvous
 
Mont
Belvieu JV
 
TEFR
Interests
 
Whitethorn
 
Cactus II
 
Total
Balance at December 31, 2017
 
$
7,030

 
$
44,945

 
$
42,528

 
$
110,299

 
$
361,409

 
$

 
$

 
$
566,211

Acquisitions
 

 

 

 

 

 
150,563

 
11,295

 
161,858

Investment earnings (loss), net of amortization
 
(444
)
 
5,898

 
439

 
15,200

 
33,037

 
5,512

 

 
59,642

Contributions
 

 
1,278

 

 

 

 
7,069

 
19,127

 
27,474

Capitalized interest
 

 

 

 

 

 

 
16

 
16

Distributions
 
(194
)
 
(5,607
)
 
(1,410
)
 
(15,219
)
 
(25,966
)
 

 

 
(48,396
)
Distributions in excess of cumulative earnings (1)
 
(2,658
)
 
(1,958
)
 
(1,784
)
 
(2,131
)
 
(3,974
)
 

 

 
(12,505
)
Balance at June 30, 2018
 
$
3,734

 
$
44,556

 
$
39,773

 
$
108,149

 
$
364,506

 
$
163,144

 
$
30,438

 
$
754,300

                                                                                                                                                                                   
(1) 
Distributions in excess of cumulative earnings, classified as investing cash flows in the consolidated statements of cash flows, are calculated on an individual investment basis.

9. COMPONENTS OF WORKING CAPITAL

A summary of accounts receivable, net is as follows:
thousands
 
June 30, 2018
 
December 31, 2017
Trade receivables, net
 
$
167,116

 
$
160,387

Other receivables, net
 
59

 
45

Total accounts receivable, net
 
$
167,175

 
$
160,432


A summary of other current assets is as follows:
thousands
 
June 30, 2018
 
December 31, 2017
Natural gas liquids inventory
 
$
9,421

 
$
10,788

Imbalance receivables
 
7,703

 
1,640

Prepaid insurance
 
264

 
2,388

Contract assets
 
9,340

 

Total other current assets
 
$
26,728

 
$
14,816

 
A summary of accrued liabilities is as follows:
thousands
 
June 30, 2018
 
December 31, 2017
Accrued interest expense
 
$
58,753

 
$
40,632

Short-term asset retirement obligations (1)
 
42,312

 
2,304

Short-term remediation and reclamation obligations
 
833

 
833

Income taxes payable
 
2,756

 
2,495

Contract liabilities
 
24,101

 

Other
 
2,597

 
1,635

Total accrued liabilities
 
$
131,352

 
$
47,899

                                                                                                                                                                                   
(1) 
As of June 30, 2018, includes $40.2 million of short-term liabilities incurred related to the shutdowns at the Third Creek and Kitty Draw gathering systems. See Note 1 for further information.

29

Table of Contents
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

10. DEBT AND INTEREST EXPENSE

At June 30, 2018, the Partnership’s debt consisted of 2.600% Senior Notes due 2018 (the “2018 Notes”), 5.375% Senior Notes due 2021 (the “2021 Notes”), 4.000% Senior Notes due 2022 (the “2022 Notes”), 3.950% Senior Notes due 2025 (the “2025 Notes”), 4.650% Senior Notes due 2026 (the “2026 Notes”), 4.500% Senior Notes due 2028 (the “2028 Notes”), 5.450% Senior Notes due 2044 (the “2044 Notes”) and 5.300% Senior Notes due 2048 (the “2048 Notes”).
The following table presents the Partnership’s outstanding debt:
 
 
June 30, 2018
 
December 31, 2017
thousands
 
Principal
 
Carrying
Value
 
Fair
Value (1)
 
Principal
 
Carrying
Value
 
Fair
Value (1)
2018 Notes
 
$
350,000

 
$
349,937

 
$
349,832

 
$
350,000

 
$
349,684

 
$
350,631

2021 Notes
 
500,000

 
496,380

 
520,037

 
500,000

 
495,815

 
530,647

2022 Notes
 
670,000

 
668,962

 
665,356

 
670,000

 
668,849

 
684,043

2025 Notes
 
500,000

 
492,356

 
475,739

 
500,000

 
491,885

 
500,885

2026 Notes
 
500,000

 
495,475

 
492,415

 
500,000

 
495,245

 
520,144

2028 Notes
 
400,000

 
394,399

 
386,234

 

 

 

2044 Notes
 
600,000

 
593,290

 
569,855

 
600,000

 
593,234

 
637,827

2048 Notes
 
700,000

 
686,554

 
651,984

 

 

 

RCF
 

 

 

 
370,000

 
370,000

 
370,000

Total long-term debt
 
$
4,220,000

 
$
4,177,353

 
$
4,111,452

 
$
3,490,000

 
$
3,464,712

 
$
3,594,177

                                                                                                                                                                                    
(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 six months ended June 30, 2018:
thousands
 
Carrying Value
Balance at December 31, 2017
 
$
3,464,712

RCF borrowings
 
260,000

Issuance of 2028 Notes
 
400,000

Issuance of 2048 Notes
 
700,000

Repayments of RCF borrowings
 
(630,000
)
Other
 
(17,359
)
Balance at June 30, 2018
 
$
4,177,353


Senior Notes. The 2018 Notes, which are due in August 2018, were classified as long-term debt on the consolidated balance sheet at June 30, 2018, as the Partnership has the ability and intent to refinance these obligations using long-term debt.
The 2028 Notes and 2048 Notes issued in March 2018 were offered at prices to the public of 99.435% and 99.169%, respectively, of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rates of the 2028 Notes and 2048 Notes are 4.682% and 5.431%, respectively. Interest is paid on each such series semi-annually on March 1 and September 1 of each year, beginning September 1, 2018. The proceeds (net of underwriting discounts, original issue discounts and debt issuance costs) were used to repay amounts outstanding under the senior unsecured revolving credit facility (“RCF”) and for general partnership purposes, including to fund capital expenditures.
At June 30, 2018, the Partnership was in compliance with all covenants under the indentures governing its outstanding notes.


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WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

10. DEBT AND INTEREST EXPENSE (CONTINUED)

Revolving credit facility. In February 2018, the Partnership entered into the five-year $1.5 billion RCF by amending and restating the $1.2 billion credit facility that was originally entered into in February 2014. The RCF is expandable to a maximum of $2.0 billion, matures in February 2023, with options to extend maturity by up to two additional one year increments, and bears interest at the London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 1.00% to 1.50%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c) LIBOR plus 1.00%, in each case plus applicable margins currently ranging from zero to 0.50%, based upon the Partnership’s senior unsecured debt rating. The Partnership is required to pay a quarterly facility fee ranging from 0.125% to 0.250% of the commitment amount (whether used or unused), also based upon its senior unsecured debt rating.
As of June 30, 2018, the Partnership had no outstanding borrowings and $4.6 million in outstanding letters of credit, resulting in $1,495.4 million available borrowing capacity under the RCF. As of June 30, 2018 and 2017, the interest rate on any outstanding RCF borrowings was 3.39% and 2.53%, respectively. The facility fee rate was 0.20% at June 30, 2018 and 2017. At June 30, 2018, the Partnership was in compliance with all covenants under the RCF.

Interest expense. The following table summarizes the amounts included in interest expense:
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
thousands
 
2018
 
2017
 
2018
 
2017
Third parties
 
 
 
 
 
 
 
 
Long-term debt
 
$
(48,394
)
 
$
(35,161
)
 
$
(89,677
)
 
$
(69,780
)
Amortization of debt issuance costs and commitment fees
 
(2,006
)
 
(1,645
)
 
(4,060
)
 
(3,275
)
Capitalized interest
 
6,011

 
1,060

 
10,065

 
1,876

Total interest expense – third parties
 
(44,389
)
 
(35,746
)
 
(83,672
)
 
(71,179
)
Affiliates
 
 
 
 
 
 
 
 
Deferred purchase price obligation – Anadarko (1)
 

 

 

 
(71
)
Total interest expense – affiliates
 

 

 

 
(71
)
Interest expense
 
$
(44,389
)
 
$
(35,746
)
 
$
(83,672
)
 
$
(71,250
)
                                                                                                                                                                                    
(1) 
See Note 3 for a discussion of the Deferred purchase price obligation - Anadarko.


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WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

11. COMMITMENTS AND CONTINGENCIES

Litigation and legal proceedings. In February 2017, DBJV, at the time a 50/50 joint venture between a third party and the Partnership, initiated an arbitration against SWEPI LP (“SWEPI”) for breach of a 2007 gas gathering agreement between it and DBJV (the “GGA”). Specifically, DBJV seeks to collect approximately $194.2 million in gathering fees under the GGA for the period January 1, 2016 to July 1, 2017. SWEPI disputes DBJV’s calculation of the cost of service based rate and filed a counterclaim for $14.9 million alleging overpayment of fees under the GGA for the years 2013 through 2015. The final arbitration hearing concluded on June 27, 2018, and the Partnership expects to receive a decision by the end of the third quarter of 2018. Under the terms of the Property Exchange, the Partnership’s former joint venture partner in DBJV will owe 50% of any amounts to be paid, and have a right to 50% of any amounts received, by the Partnership as a result of this arbitration proceeding. Pursuant to an agreement between the parties, if the arbitrators determine that DBJV is owed an amount of money by SWEPI for underpaid gathering fees for the period from January 1, 2016 to July 1, 2017, that amount will be paid to DBJV over five years as a supplemental gathering fee under the currently effective gas gathering agreement between the parties. Any other amounts owed by either party will be paid in cash within ninety days of the conclusion of the arbitration. As part of the adoption of Topic 606 (see Note 1), during the first quarter of 2018, the Partnership recorded a $7.5 million contract liability and reduced total equity and partners’ capital related to the counterclaim for the years 2013 through 2015 under the GGA revenue contract. Any amounts awarded to DBJV under the arbitration would be recognized in the period the arbitration decision is received. Management does not believe the outcome of this proceeding will have a materially unfavorable effect on the Partnership’s financial condition, results of operations or cash flows.
In addition, 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 could have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows.

Other commitments. The Partnership has short-term payment obligations, or commitments, related to its capital spending programs, as well as those of its unconsolidated affiliates, the majority of which is expected to be paid in the next twelve months. These commitments relate primarily to construction and expansion projects at the DBJV system and the DJ Basin and DBM complexes.

Lease commitments. Anadarko, on behalf of the Partnership, has entered into lease arrangements for corporate offices, shared field offices and equipment supporting the Partnership’s operations, for which Anadarko charges the Partnership lease expense. The leases for the corporate offices and shared field offices extend through 2028 and 2033, respectively. Lease expense charged to the Partnership associated with these lease arrangements was $12.2 million and $25.9 million for the three and six months ended June 30, 2018, respectively, and $12.2 million and $20.7 million for the three and six months ended June 30, 2017, respectively.


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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, which are included under Part I, Item 1 of this quarterly report, as well as our historical consolidated financial statements, and the notes thereto, which are included under Part II, Item 8 of our 2017 Form 10-K as filed with the SEC on February 16, 2018.

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-looking statements concerning our operations, economic performance and financial condition. These forward-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” 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” information.
Although we and our general partner believe that the expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give any assurance that such expectations will prove to have been correct. These forward-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:

our ability to pay distributions to our unitholders;

our and Anadarko’s assumptions about the energy market;

future throughput (including Anadarko production) that 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 or 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-proceeds, percent-of-product and keep-whole contracts through the extension of our commodity price swap agreements with Anadarko, or otherwise;

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, including those that limit Anadarko and other producers’ hydraulic fracturing or other oil and natural gas operations;


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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;

the creditworthiness of Anadarko or our other counterparties, including financial institutions, operating partners, and other parties;

changes in Anadarko’s capital program, strategy or desired areas of focus;

our commitments to capital projects;

our ability to use the RCF;

our ability to repay debt;

conflicts of interest among us, our general partner, WGP and its general partner, and affiliates, including Anadarko;

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 Anadarko or third parties, and Anadarko’s ability to generate an inventory of assets suitable for acquisition;

non-payment or non-performance of Anadarko or other significant customers, including under our gathering, processing, transportation and disposal agreements and our $260.0 million note receivable from Anadarko;

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 related to Anadarko’s operations in Colorado, and continued or additional disruptions in operations that may occur as Anadarko and we comply with regulatory orders or other state or local changes in laws or regulations in Colorado; 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 2017 Form 10-K, and in our quarterly reports on Form 10-Q, and in our other public filings and press releases.

The risk 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-looking statement. Except as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.


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EXECUTIVE SUMMARY

We are a growth-oriented Delaware MLP formed by Anadarko to acquire, own, develop and operate midstream assets. We currently own or have investments in assets located in the Rocky Mountains (Colorado, Utah and Wyoming), North-central Pennsylvania, Texas and New Mexico. We are 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 addition, in our capacity as a processor of natural gas, we also buy and sell natural gas, NGLs and condensate on behalf of ourselves and as agent for our customers under certain of our contracts. We provide these midstream services for Anadarko, as well as for third-party producers and customers. As of June 30, 2018, our assets and investments consisted of the following:
 
 
Owned and
Operated
 
Operated
Interests
 
Non-Operated
Interests
 
Equity
Interests
Gathering systems (1)
 
12

 
3

 
3

 
2

Treating facilities
 
19

 
3

 

 
3

Natural gas processing plants/trains
 
20

 
4

 

 
2

NGL pipelines
 
2

 

 

 
3

Natural gas pipelines
 
5

 

 

 

Oil pipelines
 

 
1

 

 
2

                                                                                                                                                                                    
(1) 
Includes the DBM water systems.

Significant financial and operational events during the six months ended June 30, 2018, included the following:

In June 2018, we acquired a 20% interest in Whitethorn and a 15% interest in Cactus II, both from third parties. See Acquisitions and Divestitures below for additional information.

In March 2018, we completed an offering of $400.0 million aggregate principal amount of 2028 Notes and $700.0 million aggregate principal amount of 2048 Notes. The net proceeds were used to repay amounts outstanding under the RCF and for general partnership purposes, including to fund capital expenditures. See Liquidity and Capital Resources within this Item 2 for additional information.

In February 2018, we entered into the five-year $1.5 billion (expandable to $2.0 billion) RCF by amending and restating the $1.2 billion credit facility originally entered into in February 2014. See Liquidity and Capital Resources within this Item 2 for additional information.

We raised our distribution to $0.950 per unit for the second quarter of 2018, representing a 2% increase over the distribution for the first quarter of 2018 and a 7% increase over the distribution for the second quarter of 2017.

Throughput attributable to Western Gas Partners, LP for natural gas assets totaled 3,794 MMcf/d for the three months ended June 30, 2018, representing a 9% increase compared to the same period in 2017. Throughput attributable to Western Gas Partners, LP for natural gas assets totaled 3,711 MMcf/d for the six months ended June 30, 2018, which was approximately the same compared to the same period in 2017.

Throughput for crude oil, NGL and produced water assets totaled 343 MBbls/d and 301 MBbls/d for the three and six months ended June 30, 2018, respectively, representing an 88% and 71% increase, respectively, compared to the same periods in 2017.

Operating income (loss) was $74.7 million and $262.9 million for the three and six months ended June 30, 2018, respectively, representing a 64% and 24% decrease, respectively, compared to the same periods in 2017.


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Adjusted gross margin for natural gas assets (as defined under the caption Key Performance Metrics within this Item 2) averaged $0.95 per Mcf and $0.98 per Mcf for the three and six months ended June 30, 2018, respectively, representing a 1% and 10% increase, respectively, compared to the same periods in 2017.

Adjusted gross margin for crude oil, NGL and produced water assets (as defined under the caption Key Performance Metrics within this Item 2) averaged $1.56 per Bbl and $1.68 per Bbl for the three and six months ended June 30, 2018, respectively, representing a 27% and 19% decrease, respectively, compared to the same periods in 2017.

Significant Item Affecting Comparability. On January 1, 2018, we adopted Revenue from Contracts with Customers (Topic 606) (“Topic 606”). The comparative historical financial information has not been adjusted and continues to be reported under Revenue Recognition (Topic 605). The following tables summarize the impact of adopting Topic 606 on the consolidated statements of operations:
 
 
Three Months Ended 
 June 30, 2018
thousands
 
As Reported
 
Without Adoption of Topic 606
 
Effect of Change
Increase / (Decrease)
Revenues
 
 
 
 
 
 
Service revenues – fee based
 
$
359,544

 
$
358,209

 
$
1,335

Service revenues – product based
 
22,105

 

 
22,105

Product sales
 
54,077

 
319,233

 
(265,156
)
Expenses
 
 
 
 
 
 
Cost of product
 
68,149

 
312,329

 
(244,180
)
Operation and maintenance
 
100,628

 
100,632

 
(4
)
Depreciation and amortization
 
78,792

 
78,125

 
667

Impairments
 
127,243

 
127,198

 
45

Income tax (benefit) expense
 
282

 
272

 
10

 
 
 
Six Months Ended 
 June 30, 2018
thousands
 
As Reported
 
Without Adoption of Topic 606
 
Effect of Change
Increase / (Decrease)
Revenues
 
 
 
 
 
 
Service revenues – fee based
 
$
697,963

 
$
700,547

 
$
(2,584
)
Service revenues – product based
 
44,698

 

 
44,698

Product sales
 
130,014

 
611,524

 
(481,510
)
Expenses
 
 
 
 
 


Cost of product
 
145,948

 
587,295

 
(441,347
)
Operation and maintenance
 
188,907

 
188,771

 
136

Depreciation and amortization
 
155,634

 
154,278

 
1,356

Impairments
 
127,391

 
127,346

 
45

Income tax (benefit) expense
 
1,784

 
1,781

 
3

 

For more information on the adoption of Topic 606, 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.


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ACQUISITIONS AND DIVESTITURES

Whitethorn LLC acquisition. In June 2018, we acquired a 20% interest in Whitethorn LLC, which owns the crude oil and condensate pipeline that originates in Midland, Texas and terminates in Sealy, Texas (the “Midland-to-Sealy pipeline”) and related storage facilities (collectively referred to as “Whitethorn”). A third party operates Whitethorn and oversees the related commercial activities. In connection with our investment in Whitethorn, we will share proportionally in the commercial activities. We acquired our 20% interest via a $150.6 million net investment, which was funded with cash on hand and is accounted for under the equity method. See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Cactus II acquisition. In June 2018, we acquired a 15% interest in Cactus II, which will own a crude oil pipeline operated by a third party (the “Cactus II pipeline”) connecting West Texas to the Corpus Christi area. The Cactus II pipeline is under construction and expected to become operational in the fourth quarter of 2019. We acquired our 15% interest from a third party via an $11.3 million net investment, which was funded with cash on hand and is accounted for under the equity method. See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Property exchange. On March 17, 2017, 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% interest in, and operated, the DBJV system. The Property Exchange resulted in a net gain of $125.7 million recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations. See Note 3—Acquisitions and Divestitures 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 to a third party, resulting in a net gain on sale of $16.3 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 interests accounted for under the equity method by us as of June 30, 2018 (see Note 8—Equity Investments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q). Because Anadarko controls us through its control of WGP, which owns the entire interest in our general partner, 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 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. 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.
For those periods requiring recast, the consolidated financial statements for periods prior to our acquisition of the Partnership assets from Anadarko have been prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if we had owned the Partnership assets during the periods reported. For ease of reference, we refer to the historical financial results of the Partnership assets prior to our acquisitions from Anadarko as being “our” historical financial results.

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 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 all remaining Series A Preferred units converted into common units on a one-for-one basis on May 2, 2017. See Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.


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RESULTS OF OPERATIONS

OPERATING RESULTS

The following tables and discussion present a summary of our results of operations:
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
thousands
 
2018
 
2017
 
2018
 
2017
Total revenues and other (1)
 
$
435,949

 
$
525,450

 
$
873,117

 
$
1,041,643

Equity income, net – affiliates
 
39,218

 
21,728

 
59,642

 
41,189

Total operating expenses (1)
 
400,601

 
379,143

 
670,183

 
901,659

Gain (loss) on divestiture and other, net
 
170

 
15,458

 
286

 
134,945

Proceeds from business interruption insurance claims (2)
 

 
24,115

 

 
29,882

Operating income (loss)
 
74,736

 
207,608

 
262,862

 
346,000

Interest income – affiliates
 
4,225

 
4,225

 
8,450

 
8,450

Interest expense
 
(44,389
)
 
(35,746
)
 
(83,672
)
 
(71,250
)
Other income (expense), net
 
1,229

 
253

 
2,011

 
683

Income (loss) before income taxes
 
35,801

 
176,340

 
189,651

 
283,883

Income tax (benefit) expense
 
282

 
843

 
1,784

 
4,395

Net income (loss)
 
35,519

 
175,497

 
187,867

 
279,488

Net income attributable to noncontrolling interest
 
2,811

 
2,046

 
5,796

 
4,148

Net income (loss) attributable to Western Gas Partners, LP
 
$
32,708

 
$
173,451

 
$
182,071

 
$
275,340

Key performance metrics (3)
 
 
 
 
 
 
 
 
Adjusted gross margin
 
$
378,293

 
$
333,548

 
$
746,839

 
$
665,104

Adjusted EBITDA
 
271,659

 
274,835

 
543,778

 
529,829

Distributable cash flow
 
221,799

 
247,225

 
453,235

 
463,728

                                                                                                                                                                                    
(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 Significant Item Affecting Comparability within this Item 2 and Note 6—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, Adjusted EBITDA 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 June 30, 2018” refer to the comparison of the three months ended June 30, 2018, to the three months ended June 30, 2017; any increases or decreases “for the six months ended June 30, 2018” refer to the comparison of the six months ended June 30, 2018, to the six months ended June 30, 2017; and any increases or decreases “for the three and six months ended June 30, 2018” refer to the comparison of these 2018 periods to the corresponding three and six month periods ended June 30, 2017.



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Throughput
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,

 
2018
 
2017
 
Inc/
(Dec)
 
2018
 
2017
 
Inc/
(Dec)
Throughput for natural gas assets (MMcf/d)
 
 
 
 
 
 
 
 
 
 
 
 
Gathering, treating and transportation
 
887

 
866

 
2
 %
 
852

 
1,155

 
(26
)%
Processing
 
2,860

 
2,555

 
12
 %
 
2,808

 
2,498

 
12
 %
Equity investment (1)
 
141

 
158

 
(11
)%
 
146

 
160

 
(9
)%
Total throughput for natural gas assets
 
3,888

 
3,579

 
9
 %
 
3,806

 
3,813

 
 %
Throughput attributable to noncontrolling interest for natural gas assets
 
94

 
107

 
(12
)%
 
95

 
108

 
(12
)%
Total throughput attributable to Western Gas Partners, LP for natural gas assets
 
3,794

 
3,472

 
9
 %
 
3,711

 
3,705

 
 %
Throughput for crude oil, NGL and produced water assets (MBbls/d)
 
 
 
 
 
 
 
 
 
 
 
 
Gathering, treating, transportation and disposal
 
145

 
50

 
190
 %
 
134

 
47

 
185
 %
Equity investment (2)
 
198

 
132

 
50
 %
 
167

 
129

 
29
 %
Total throughput for crude oil, NGL and produced water assets
 
343

 
182

 
88
 %
 
301

 
176

 
71
 %
                                                                                                                                                                                    
(1) 
Represents our 14.81% share of average Fort Union throughput and 22% share of average Rendezvous throughput.
(2) 
Represents our 10% share of average White Cliffs throughput, 25% share of average Mont Belvieu JV throughput, 20% share of average TEG and TEP throughput, 33.33% share of average FRP throughput and 20% share of average Whitethorn throughput.

Natural gas assets

Gathering, treating and transportation throughput increased by 21 MMcf/d for the three months ended June 30, 2018, primarily due to (i) increased production in the areas around the DBJV system (increase of 48 MMcf/d) and (ii) increased throughput at the Bison facility due to a new contract effective April 2018 (increase of 35 MMcf/d). These increases were partially offset by (i) the sale of the Helper and Clawson systems in June 2017 (decrease of 33 MMcf/d), (ii) lower throughput at the MIGC system (decrease of 18 MMcf/d) and (iii) lower throughput at the Haley system due to decreased production in the area (decrease of 13 MMcf/d).
Gathering, treating and transportation throughput decreased by 303 MMcf/d for the six months ended June 30, 2018, primarily due to (i) the Property Exchange in March 2017 (decrease of 241 MMcf/d), (ii) the sale of the Helper and Clawson systems in June 2017 (decrease of 33 MMcf/d) and (iii) lower throughput at the MIGC system (decrease of 11 MMcf/d).
Processing throughput increased by 305 MMcf/d and 310 MMcf/d for the three and six months ended June 30, 2018, respectively, primarily due to (i) increased production in the areas around the DJ Basin and DBM complexes, (ii) the start-up of Train VI at the DBM complex in December 2017 and (iii) increased throughput at the MGR assets due to downtime at the nearby Granger straddle plant in 2017. These increases were partially offset by lower throughput at the Chipeta complex due to the expiration and non-renewal of a contract in September 2017.
Equity investment throughput decreased by 17 MMcf/d and 14 MMcf/d for the three and six months ended June 30, 2018, respectively, primarily due to decreased throughput at the Fort Union and Rendezvous systems due to production declines in the area, as well as throughput being diverted from the Fort Union system to other nearby systems.


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Table of Contents

Crude oil, NGL and produced water assets

Gathering, treating, transportation and disposal throughput increased by 95 MBbls/d and 87 MBbls/d for the three and six months ended June 30, 2018, respectively, primarily due to increased throughput from the DBM water systems, which commenced operation during the second quarter of 2017.
Equity investment throughput increased by 66 MBbls/d and 38 MBbls/d for the three and six months ended June 30, 2018, respectively, primarily due to (i) the acquisition of the interest in Whitethorn in June 2018 and (ii) increased volumes on FRP and TEP as a result of increased NGL production in the DJ Basin area.

Service Revenues
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
thousands except percentages
 
2018
 
2017
 
Inc/
(Dec)
 
2018
 
2017
 
Inc/
(Dec)
Service revenues – fee based
 
$
359,544

 
$
299,435

 
20
%
 
$
697,963

 
$
607,249

 
15
%
Service revenues – product based
 
22,105

 

 
NM

 
44,698

 

 
NM

 Total service revenues
 
$
381,649

 
$
299,435

 
27
%
 
$
742,661

 
$
607,249

 
22
%
                                                                                                                                                                                    
NM-Not Meaningful

Service revenues – fee based increased by $60.1 million for the three months ended June 30, 2018, primarily due to increases of (i) $35.6 million at the DJ Basin complex due to increased throughput ($26.7 million) and a higher processing fee ($8.9 million) due to a new contract effective August 2017, (ii) $16.8 million at the DBM complex due to increased throughput and (iii) $8.9 million and $4.5 million at the DBM water and DBJV systems, respectively, due to increased throughput. These increases were partially offset by decreases of (i) $3.3 million at the Chipeta complex due to decreases in throughput and deficiency fees and (ii) $2.5 million at the Springfield system due to a lower cost of service rate.
Service revenues – fee based increased by $90.7 million for the six months ended June 30, 2018, primarily due to increases of (i) $62.0 million at the DJ Basin complex due to increased throughput ($42.6 million) and a higher processing fee ($19.4 million) due to a new contract effective August 2017, (ii) $33.8 million at the DBM complex due to increased throughput and (iii) $15.8 million at the DBM water systems, which commenced operation during the second quarter of 2017. These increases were partially offset by decreases of (i) $6.8 million at the Springfield system due to a lower cost of service rate, (ii) $5.5 million at the Chipeta complex due to decreases in throughput and deficiency fees and (iii) $3.8 million due to the Property Exchange in March 2017.
Service revenues – product based increased by $22.1 million and $44.7 million for the three and six months ended June 30, 2018, respectively, due to the adoption of Topic 606 as discussed under Significant Item Affecting Comparability within this Item 2. Under Topic 606, certain of our customer agreements result in revenues being recognized when the natural gas and/or NGLs are received from the customer as noncash consideration for the services provided. In addition, retained proceeds from sales of customer products where we are acting as their agent are included in Service revenues – product based.


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Table of Contents

Product Sales
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
thousands except percentages and
per-unit amounts
 
2018
 
2017
 
Inc/
(Dec)
 
2018
 
2017
 
Inc/
(Dec)
Natural gas sales (1)
 
$
11,210

 
$
92,946

 
(88
)%
 
$
39,578

 
$
172,861

 
(77
)%
Natural gas liquids sales (1)
 
42,867

 
131,878

 
(67
)%
 
90,436

 
258,488

 
(65
)%
Total Product sales
 
$
54,077

 
$
224,824

 
(76
)%
 
$
130,014

 
$
431,349

 
(70
)%
Gross average sales price per unit (1):
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas (per Mcf)
 
$
1.91

 
$
2.95

 
(35
)%
 
$
2.14

 
$
3.00

 
(29
)%
Natural gas liquids (per Bbl)
 
28.04

 
19.98

 
40
 %
 
27.98

 
20.87

 
34
 %
                                                                                                                                                                                    
(1) 
Includes the effects of commodity price swap agreements for the MGR assets and DJ Basin complex, excluding the amounts considered above market with respect to these swap agreements that were recorded as capital contributions in the consolidated statement of equity and partners’ capital. See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Natural gas sales decreased by $81.7 million for the three months ended June 30, 2018, primarily due to decreases of (i) $56.2 million from the adoption of Topic 606 as discussed under Significant Item Affecting Comparability within this Item 2, (ii) $5.2 million due to a decrease in average price and $9.3 million due to a system shutdown, both at the Hilight system (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) and (iii) $6.8 million at the DBM complex due to a decrease in average price, partially offset by an increase in volumes sold.
Natural gas sales decreased by $133.3 million for the six months ended June 30, 2018, primarily due to decreases of (i) $124.3 million from the adoption of Topic 606 as discussed under Significant Item Affecting Comparability within this Item 2 and (ii) $5.9 million due to a decrease in average price and $9.3 million due to a system shutdown, both at the Hilight system (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). These decreases were partially offset by an increase of $7.0 million at the DBM complex due to an increase in volumes sold, partially offset by a decrease in average price.
NGLs sales decreased by $89.0 million and $168.1 million for the three and six months ended June 30, 2018, respectively, primarily due to decreases of $209.0 million and $357.2 million, respectively, from the adoption of Topic 606 as discussed under Significant Item Affecting Comparability within this Item 2. These decreases were partially offset by increases of (i) $90.8 million and $137.3 million, respectively, at the DBM complex due to an increase in average price and volumes sold, (ii) $14.3 million and $24.4 million, respectively, at the DJ Basin complex due to an increase in the swap market price and volumes sold, (iii) $5.3 million and $9.3 million, respectively, at the Brasada complex due to volumes sold under a new sales agreement beginning January 1, 2018, and (iv) $3.0 million and $4.7 million, respectively, at the Chipeta complex due to an increase in average price and volumes sold. In addition, for the six months ended June 30, 2018, NGL sales increased by $4.0 million at the DBM water systems, which commenced operation during the second quarter of 2017.

Equity Income, Net – Affiliates

 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
thousands except percentages
 
2018
 
2017
 
Inc/
(Dec)
 
2018
 
2017
 
Inc/
(Dec)
Equity income, net – affiliates
 
$
39,218

 
$
21,728

 
80
%
 
$
59,642

 
$
41,189

 
45
%

For the three and six months ended June 30, 2018, equity income, net – affiliates increased by $17.5 million and $18.5 million, respectively, primarily due to (i) increased volumes at the TEFR Interests and (ii) the acquisition of the interest in Whitethorn in June 2018. These increases were partially offset by a decrease in volumes at the Fort Union system.
    

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Table of Contents

Cost of Product and Operation and Maintenance Expenses
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
thousands except percentages
 
2018
 
2017
 
Inc/
(Dec)
 
2018
 
2017
 
Inc/
(Dec)
NGL purchases (1)
 
$
42,905

 
$
114,607

 
(63
)%
 
$
84,507

 
$
222,980

 
(62
)%
Residue purchases (1)
 
19,794

 
87,807

 
(77
)%
 
47,072

 
166,123

 
(72
)%
Other
 
5,450

 
863

 
NM

 
14,369

 
3,533

 
NM

Cost of product
 
68,149

 
203,277

 
(66
)%
 
145,948

 
392,636

 
(63
)%
Operation and maintenance
 
100,628

 
76,148

 
32
 %
 
188,907

 
149,908

 
26
 %
Total Cost of product and Operation and maintenance expenses
 
$
168,777

 
$
279,425

 
(40
)%
 
$
334,855

 
$
542,544

 
(38
)%
                                                                                                                                                                                    
(1) 
For the three and six months ended June 30, 2017, includes the effects of commodity price swap agreements for the MGR assets and DJ Basin complex, excluding the amounts considered above market with respect to these swap agreements that were recorded as capital contributions in the consolidated statement of equity and partners’ capital. See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

NGL purchases decreased by $71.7 million and $138.5 million for the three and six months ended June 30, 2018, respectively, primarily due to decreases of $188.8 million and $318.6 million, respectively, from the adoption of Topic 606 as discussed under Significant Item Affecting Comparability within this Item 2, partially offset by increases of (i) $92.5 million and $133.4 million, respectively, at the DBM complex due to an increase in average price and volumes purchased, (ii) $14.7 million and $26.4 million, respectively, at the DJ Basin complex due to an increase in average price and volumes purchased, and (iii) $4.7 million and $8.2 million, respectively, at the Brasada complex due to volumes purchased under a new purchase agreement beginning January 1, 2018.
Residue purchases decreased by $68.0 million for the three months ended June 30, 2018, primarily due to decreases of (i) $52.0 million from the adoption of Topic 606 as discussed under Significant Item Affecting Comparability within this Item 2, (ii) $8.1 million at the DBM complex due to a decrease in average price, partially offset by an increase in volumes purchased, and (iii) $4.6 million at the Hilight system due to a decrease in average price.
Residue purchases decreased by $119.1 million for the six months ended June 30, 2018, primarily due to decreases of (i) $115.9 million from the adoption of Topic 606 as discussed under Significant Item Affecting Comparability within this Item 2 and (ii) $4.5 million at the Hilight system due to a decrease in average price. These decreases were partially offset by an increase of $4.4 million at the DBM complex due to an increase in volumes purchased.
Other items increased by $4.6 million and $10.8 million for the three and six months ended June 30, 2018, respectively, primarily due to increases of $8.1 million and $15.2 million, respectively, at the DJ Basin complex due to changes in affiliate contract terms in August 2017, partially offset by decreases of $3.4 million and $6.8 million, respectively, from the adoption of Topic 606 as discussed under Significant Item Affecting Comparability within this Item 2.
Operation and maintenance expense increased by $24.5 million for the three months ended June 30, 2018, primarily due to increases of (i) $8.3 million at the DJ Basin complex primarily due to increases in utilities expense and surface maintenance and plant repairs, (ii) $8.1 million at the DBM complex primarily due to increases in surface maintenance and plant repairs, utilities expense, chemicals and treating services, and salaries and wages, and (iii) $3.7 million at the DBJV system primarily due to increases in surface maintenance and plant repairs and salaries and wages.
Operation and maintenance expense increased by $39.0 million for the six months ended June 30, 2018, primarily due to increases of (i) $13.1 million at the DJ Basin complex primarily due to increases in utilities expense, surface maintenance and plant repairs, and salaries and wages, (ii) $12.9 million at the DBM complex primarily due to increases in equipment rentals, utilities expense, surface maintenance and plant repairs, and salaries and wages, (iii) $6.7 million due to the Property Exchange in March 2017 and (iv) $2.6 million at the DBM water systems, which commenced operation during the second quarter of 2017.

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Table of Contents

Other Operating Expenses
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
thousands except percentages
 
2018
 
2017
 
Inc/
(Dec)
 
2018
 
2017
 
Inc/
(Dec)
General and administrative
 
$
14,035

 
$
10,585

 
33
 %
 
$
28,167

 
$
23,244

 
21
 %
Property and other taxes
 
11,754

 
11,924

 
(1
)%
 
24,136

 
24,218

 
 %
Depreciation and amortization
 
78,792

 
74,031

 
6
 %
 
155,634

 
143,733

 
8
 %
Impairments
 
127,243

 
3,178

 
NM

 
127,391

 
167,920

 
(24
)%
Total other operating expenses
 
$
231,824

 
$
99,718

 
132
 %
 
$
335,328

 
$
359,115

 
(7
)%

General and administrative expenses increased by $3.5 million and $4.9 million for the three and six months ended June 30, 2018, respectively, primarily due to increases in (i) legal and consulting fees incurred in connection with the arbitration against SWEPI LP (see Note 11—Commitments and Contingencies in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q) and (ii) personnel costs for which we reimbursed Anadarko pursuant to our omnibus agreement. For the six months ended June 30, 2018, these increases were partially offset by a decrease in bad debt expense.
Depreciation and amortization expense increased by $4.8 million for the three months ended June 30, 2018, primarily due to depreciation expense increases of $1.7 million and $1.5 million related to capital projects being placed into service at the DBM complex and the DBJV system, respectively.
Depreciation and amortization expense increased by $11.9 million for the six months ended June 30, 2018, primarily due to depreciation expense increases of (i) $8.1 million due to the Property Exchange in March 2017 and capital projects being placed into service at the DBJV system and (ii) $3.7 million related to capital projects being placed into service at the DBM complex. These increases were partially offset by a decrease of $2.1 million at the Granger complex due to an impairment recorded in the first quarter of 2017.
Impairment expense for the three and six months ended June 30, 2018, was primarily due to impairments of $120.8 million at the Third Creek gathering system and $6.4 million at the Kitty Draw gathering system. 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.
Impairment expense for the three months ended June 30, 2017, was primarily due to an impairment of $3.1 million at the Fort Union system.
Impairment expense for the six months ended June 30, 2017, included (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 and (iv) the cancellation of a pipeline project in West Texas. For further information on impairment expense for the periods presented, see Note 7—Property, Plant and Equipment in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.


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Table of Contents

Interest Income – Affiliates and Interest Expense

 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
thousands except percentages
 
2018
 
2017
 
Inc/
(Dec)
 
2018
 
2017
 
Inc/
(Dec)
Note receivable – Anadarko
 
$
4,225

 
$
4,225

 
%
 
$
8,450

 
$
8,450

 
 %
Interest income – affiliates
 
$
4,225

 
$
4,225

 
%
 
$
8,450

 
$
8,450

 
 %
Third parties
 
 
 
 
 
 
 
 
 
 
 
 
Long-term debt
 
$
(48,394
)
 
$
(35,161
)
 
38
%
 
$
(89,677
)
 
$
(69,780
)
 
29
 %
Amortization of debt issuance costs and commitment fees
 
(2,006
)
 
(1,645
)
 
22
%
 
(4,060
)
 
(3,275
)
 
24
 %
Capitalized interest
 
6,011

 
1,060

 
NM

 
10,065

 
1,876

 
NM

Affiliates
 
 
 
 
 
 
 
 
 
 
 
 
Deferred purchase price obligation – Anadarko (1)
 

 

 
%
 

 
(71
)
 
(100
)%
Interest expense
 
$
(44,389
)
 
$
(35,746
)
 
24
%
 
$
(83,672
)
 
$
(71,250
)
 
17
 %
                                                                                                                                                                                    
(1) 
See Note 3—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 $8.6 million and $12.4 million for the three and six months ended June 30, 2018, respectively, primarily due to (i) $9.3 million and $12.3 million, respectively, of interest incurred on the 2048 Notes issued in March 2018 and (ii) $4.5 million and $6.0 million, respectively, of interest incurred on the 2028 Notes issued in March 2018. In addition, for the six months ended June 30, 2018, there was a $1.7 million increase in interest incurred on the RCF. These increases were partially offset by increases in capitalized interest of $5.0 million and $8.2 million for the three and six months ended June 30, 2018, respectively, primarily due to continued construction and expansion at the DJ Basin complex, DBJV system and DBM complex, including construction of the Mentone plant beginning in the fourth quarter of 2017.

Income Tax (Benefit) Expense

 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
thousands except percentages
 
2018
 
2017
 
Inc/
(Dec)
 
2018
 
2017
 
Inc/
(Dec)
Income (loss) before income taxes
 
$
35,801

 
$
176,340

 
(80
)%
 
$
189,651

 
$
283,883

 
(33
)%
Income tax (benefit) expense
 
282

 
843

 
(67
)%
 
1,784

 
4,395

 
(59
)%
Effective tax rate
 
1
%
 
%
 


 
1
%
 
2
%
 



We are not a taxable entity for U.S. federal income tax purposes. However, our income apportionable to Texas is subject to Texas margin tax. For all periods presented, the variance from the federal statutory rate, which is zero percent as a non-taxable entity, was primarily due to our share of Texas margin tax.


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Table of Contents

KEY PERFORMANCE METRICS
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
thousands except percentages and per-unit amounts
 
2018
 
2017
 
Inc/
(Dec)
 
2018
 
2017
 
Inc/
(Dec)
Adjusted gross margin for natural gas assets (1)
 
$
329,653

 
$
297,778

 
11
 %
 
$
655,525

 
$
599,283

 
9
 %
Adjusted gross margin for crude oil, NGL and produced water assets (2)
 
48,640

 
35,770

 
36
 %
 
91,314

 
65,821

 
39
 %
Adjusted gross margin (3)
 
378,293

 
333,548

 
13
 %
 
746,839

 
665,104

 
12
 %
Adjusted gross margin per Mcf for natural gas assets (4)
 
0.95

 
0.94

 
1
 %
 
0.98

 
0.89

 
10
 %
Adjusted gross margin per Bbl for crude oil, NGL and produced water assets (5)
 
1.56

 
2.15

 
(27
)%
 
1.68

 
2.07

 
(19
)%
Adjusted EBITDA (3)
 
271,659

 
274,835

 
(1
)%
 
543,778

 
529,829

 
3
 %
Distributable cash flow (3)
 
221,799

 
247,225

 
(10
)%
 
453,235

 
463,728

 
(2
)%
                                                                                                                                                                                    
(1) 
Adjusted gross margin for natural gas assets is calculated as total revenues and other for natural gas assets (less reimbursements for electricity-related expenses recorded as revenue), less 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 for natural gas assets to its most comparable GAAP measure below.
(2) 
Adjusted gross margin for crude oil, NGL and produced water assets is calculated as total revenues and other for crude oil, NGL and produced water assets (less reimbursements for electricity-related expenses recorded as revenue), less cost of product for crude oil, NGL and produced water assets, and plus distributions from our equity investments in White Cliffs, the Mont Belvieu JV, the TEFR Interests and Whitethorn. See the reconciliation of Adjusted gross margin for crude oil, NGL and produced water assets to its most comparable GAAP measure below.
(3) 
For a reconciliation of Adjusted gross margin, Adjusted EBITDA and Distributable cash flow to the most directly comparable financial measure calculated and presented in accordance with GAAP, see the description below.
(4) 
Average for period. Calculated as Adjusted gross margin 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 oil, NGL and produced water assets, divided by total throughput (MBbls/d) for crude oil, NGL and produced water assets.

Adjusted gross margin. We define Adjusted gross margin attributable to Western Gas Partners, LP (“Adjusted gross margin”) as total revenues and other (less reimbursements for electricity-related expenses recorded as revenue), less cost of product, plus distributions from equity investments, and excluding the noncontrolling interest owner’s proportionate share of revenue and cost of product. We believe Adjusted gross margin is an important performance measure of the core profitability of our operations, as well as our operating performance as compared to that of other companies in the midstream industry.
Adjusted gross margin increased by $44.7 million for the three months ended June 30, 2018, primarily due to (i) increased throughput and a higher processing fee at the DJ Basin complex and (ii) increased throughput at the DBM complex and DBM water and DBJV systems. These increases were partially offset by decreases due to (i) a system shutdown at the Hilight system (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) and (ii) a lower cost of service rate at the Springfield system.
Adjusted gross margin increased by $81.7 million for the six months ended June 30, 2018, primarily due to (i) increased throughput and a higher processing fee at the DJ Basin complex, (ii) increased throughput at the DBM complex and (iii) the start-up of the DBM water systems during the second quarter of 2017. These increases were partially offset by decreases due to (i) a system shutdown at the Hilight system (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), (ii) a lower cost of service rate at the Springfield system and (iii) the Property Exchange in March 2017.


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Table of Contents

To facilitate investor and industry analyst comparisons between us and our peers, we also disclose Adjusted gross margin per Mcf for natural gas assets and Adjusted gross margin per Bbl for crude oil, NGL and produced water assets. Adjusted gross margin per Mcf for natural gas assets increased by $0.01 for the three months ended June 30, 2018, primarily due to increased throughput at the DBM complex. Adjusted gross margin per Mcf for natural gas assets increased by $0.09 for the six months ended June 30, 2018, primarily due to (i) the Property Exchange in March 2017 and (ii) increased throughput at the DBM complex, which has a higher-than-average margin as compared to our other natural gas assets.
Adjusted gross margin per Bbl for crude oil, NGL and produced water assets decreased by $0.59 for the three months ended June 30, 2018, primarily due to (i) increased throughput at the DBM water systems, which have lower margins than our crude oil and NGL assets, and (ii) a lower cost of service rate at the Springfield oil gathering system. These decreases were partially offset by higher distributions received from TEP.
Adjusted gross margin per Bbl for crude oil, NGL and produced water assets decreased by $0.39 for the six months ended June 30, 2018, primarily due to (i) the start-up of the DBM water systems during the second quarter of 2017, which have lower margins than our crude oil and NGL assets, and (ii) a lower cost of service rate at the Springfield oil gathering system. These decreases were partially offset by higher distributions received from the TEFR Interests and the Mont Belvieu JV.

Adjusted EBITDA. We define Adjusted EBITDA attributable to Western Gas Partners, LP (“Adjusted EBITDA”) as net income (loss) attributable to Western Gas Partners, LP, plus distributions from equity investments, non-cash equity-based compensation expense, interest expense, income tax expense, depreciation and amortization, impairments, and other expense (including lower of cost or market inventory adjustments recorded in cost of product), less gain (loss) on divestiture and other, net, income from equity investments, interest income, income tax benefit, and other income. 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 to assess the following, among other measures:

our operating performance as compared to other publicly traded partnerships in the midstream 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 projects and the returns on investment of various investment opportunities.

Adjusted EBITDA decreased by $3.2 million for the three months ended June 30, 2018, primarily due to (i) an $89.5 million decrease in total revenues and other, (ii) a $24.5 million increase in operation and maintenance expenses, (iii) a $24.1 million decrease in business interruption proceeds and (iv) a $2.6 million increase in general and administrative expenses excluding non-cash equity-based compensation expense. These amounts were partially offset by (i) a $135.0 million decrease in cost of product (net of lower of cost or market inventory adjustments) and (ii) a $3.1 million increase in distributions from equity investments.
Adjusted EBITDA increased by $13.9 million for the six months ended June 30, 2018, primarily due to (i) a $246.7 million decrease in cost of product (net of lower of cost or market inventory adjustments) and (ii) a $9.5 million increase in distributions from equity investments. These amounts were partially offset by (i) a $168.5 million decrease in total revenues and other, (ii) a $39.0 million increase in operation and maintenance expenses, (iii) a $29.9 million decrease in business interruption proceeds and (iv) a $3.1 million increase in general and administrative expenses excluding non-cash equity-based compensation expense.


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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 Service revenues – fee based recognized in Adjusted EBITDA (less than) in excess of customer billings, 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 Distributable 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 Distributable cash flow is useful to investors because this measurement is 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 our ability to make distributions to our unitholders, it should not be viewed as indicative of the actual amount of cash that we have available for distributions or that we plan to distribute for a given period. Furthermore, to the extent Distributable 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 $25.4 million for the three months ended June 30, 2018, primarily due to (i) a $13.6 million increase in net cash paid for interest expense, (ii) a $9.5 million increase in cash paid for maintenance capital expenditures, (iii) a $3.2 million decrease in Adjusted EBITDA and (iv) a $2.5 million decrease in the above-market component of the swap agreements with Anadarko. These amounts were partially offset by $3.4 million of customer billings in excess of the amount recognized as Service revenues - fee based.
Distributable cash flow decreased by $10.5 million for the six months ended June 30, 2018, primarily due to (i) a $20.7 million increase in net cash paid for interest expense and (ii) a $14.8 million increase in cash paid for maintenance capital expenditures. These amounts were partially offset by (i) a $13.9 million increase in Adjusted EBITDA, (ii) a $7.5 million decrease in Series A Preferred unit distributions and (iii) $3.9 million of customer billings in excess of the amount recognized as Service revenues - fee based.

Reconciliation of non-GAAP measures. Adjusted gross margin, Adjusted EBITDA and Distributable cash flow are not defined in GAAP. The GAAP measure used by us that is most directly comparable to Adjusted gross margin is operating 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 Distributable cash flow is net income (loss) attributable to Western Gas Partners, LP. Our non-GAAP financial measures of Adjusted gross margin, Adjusted EBITDA and Distributable cash flow should not be considered as alternatives to the GAAP measures of operating 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 Distributable cash flow have important limitations as analytical tools because they exclude some, but not all, items that affect operating income (loss), net income (loss) attributable to Western Gas Partners, LP and net cash provided by operating activities. Adjusted gross margin, Adjusted EBITDA and Distributable 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 Distributable cash flow may not be comparable to similarly titled measures of other companies in our industry, thereby diminishing their utility.

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Management compensates for the limitations of Adjusted gross margin, Adjusted EBITDA and Distributable cash flow as analytical tools by reviewing the comparable GAAP measures, understanding the differences between Adjusted gross margin, Adjusted EBITDA and Distributable cash flow compared to (as applicable) operating 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-making processes. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results.
The following tables present (a) a reconciliation of the GAAP financial measure of operating income (loss) to the non-GAAP financial measure of Adjusted gross margin, (b) 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-GAAP financial measure of Adjusted EBITDA and (c) a reconciliation of the GAAP financial measure of net income (loss) attributable to Western Gas Partners, LP to the non-GAAP financial measure of Distributable cash flow:
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
thousands
 
2018
 
2017
 
2018
 
2017
Reconciliation of Operating income (loss) to Adjusted gross margin
 
 
 
 
 
 
 
 
Operating income (loss)
 
$
74,736

 
$
207,608


$
262,862


$
346,000

Add:
 
 
 
 
 
 
 
 
Distributions from equity investments
 
31,947

 
28,856

 
60,901

 
51,423

Operation and maintenance
 
100,628

 
76,148

 
188,907

 
149,908

General and administrative
 
14,035

 
10,585

 
28,167

 
23,244

Property and other taxes
 
11,754

 
11,924

 
24,136

 
24,218

Depreciation and amortization
 
78,792

 
74,031

 
155,634

 
143,733

Impairments
 
127,243

 
3,178

 
127,391

 
167,920

Less:
 
 
 
 
 
 
 
 
Gain (loss) on divestiture and other, net
 
170

 
15,458

 
286

 
134,945

Proceeds from business interruption insurance claims
 

 
24,115

 

 
29,882

Equity income, net – affiliates
 
39,218

 
21,728

 
59,642

 
41,189

Reimbursed electricity-related charges recorded as revenues
 
17,231

 
14,046

 
32,684

 
28,015

Adjusted gross margin attributable to noncontrolling interest
 
4,223

 
3,435

 
8,547

 
7,311

Adjusted gross margin
 
$
378,293

 
$
333,548

 
$
746,839

 
$
665,104

Adjusted gross margin for natural gas assets
 
$
329,653

 
$
297,778

 
$
655,525

 
$
599,283

Adjusted gross margin for crude oil, NGL and produced water assets
 
48,640

 
35,770

 
91,314

 
65,821



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Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
thousands
 
2018
 
2017
 
2018
 
2017
Reconciliation of Net income (loss) attributable to Western Gas Partners, LP to Adjusted EBITDA
 
 
 
 
 
 
 
 
Net income (loss) attributable to Western Gas Partners, LP
 
$
32,708

 
$
173,451

 
$
182,071

 
$
275,340

Add:
 
 
 
 
 
 
 
 
Distributions from equity investments
 
31,947

 
28,856

 
60,901

 
51,423

Non-cash equity-based compensation expense
 
1,852

 
975

 
4,004

 
2,221

Interest expense
 
44,389

 
35,746

 
83,672

 
71,250

Income tax expense
 
282

 
843

 
1,784

 
4,395

Depreciation and amortization (1)
 
78,066

 
73,352

 
154,182

 
142,401

Impairments
 
127,243

 
3,178

 
127,391

 
167,920

Other expense (1)
 
8

 
95

 
151

 
140

Less:
 
 
 
 
 
 
 
 
Gain (loss) on divestiture and other, net
 
170

 
15,458

 
286

 
134,945

Equity income, net – affiliates
 
39,218

 
21,728

 
59,642

 
41,189

Interest income – affiliates
 
4,225

 
4,225

 
8,450

 
8,450

Other income (1)
 
1,223

 
250

 
2,000

 
677

Adjusted EBITDA
 
$
271,659

 
$
274,835

 
$
543,778

 
$
529,829

Reconciliation of Net cash provided by operating activities to Adjusted EBITDA
 
 
 
 
 
 
 
 
Net cash provided by operating activities
 
$
273,315

 
$
240,536

 
$
514,911

 
$
433,152

Interest (income) expense, net
 
40,164

 
31,521

 
75,222

 
62,800

Uncontributed cash-based compensation awards
 
398

 
(209
)
 
987

 
(172
)
Accretion and amortization of long-term obligations, net
 
(1,248
)
 
(1,038
)
 
(2,626
)
 
(2,139
)
Current income tax (benefit) expense
 
90

 
204

 
261

 
628

Other (income) expense, net
 
(1,229
)
 
(253
)
 
(2,011
)
 
(683
)
Distributions from equity investments in excess of cumulative earnings – affiliates
 
4,492

 
5,768

 
12,505

 
9,221

Changes in assets and liabilities:
 
 
 
 
 
 
 
 
Accounts receivable, net
 
(21,639
)
 
(10,876
)
 
7,009

 
(9,363
)
Accounts and imbalance payables and accrued liabilities, net
 
(13,498
)
 
12,035

 
(40,573
)
 
41,975

Other items, net
 
(5,655
)
 
(131
)
 
(14,670
)
 
(116
)
Adjusted EBITDA attributable to noncontrolling interest
 
(3,531
)
 
(2,722
)
 
(7,237
)
 
(5,474
)
Adjusted EBITDA
 
$
271,659

 
$
274,835

 
$
543,778

 
$
529,829

Cash flow information of Western Gas Partners, LP
 
 
 
 
 
 
 
 
Net cash provided by operating activities
 
 
 
 
 
$
514,911

 
$
433,152

Net cash used in investing activities
 
 
 
 
 
(826,653
)
 
(363,131
)
Net cash provided by (used in) financing activities
 
 
 
 
 
286,163

 
(239,749
)
                                                                                                                                                                                    
(1) 
Includes our 75% share of depreciation and amortization; other expense; and other income attributable to the Chipeta complex.



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Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
thousands except Coverage ratio
 
2018
 
2017
 
2018
 
2017
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
 
$
32,708

 
$
173,451

 
$
182,071

 
$
275,340

Add:
 
 
 
 
 
 
 
 
Distributions from equity investments
 
31,947

 
28,856

 
60,901

 
51,423

Non-cash equity-based compensation expense
 
1,852

 
975

 
4,004

 
2,221

Non-cash settled interest expense, net (1)
 

 

 

 
71

Income tax (benefit) expense
 
282

 
843

 
1,784

 
4,395

Depreciation and amortization (2)
 
78,066

 
73,352

 
154,182

 
142,401

Impairments
 
127,243

 
3,178

 
127,391

 
167,920

Above-market component of swap agreements with Anadarko (3)
 
13,839

 
16,373

 
28,121

 
28,670

Other expense (2)
 
8

 
95

 
151

 
140

Less:
 
 
 
 
 
 
 
 
Recognized Service revenues – fee based (less than) in excess of customer billings (4)
 
(3,367
)
 

 
(3,861
)
 

Gain (loss) on divestiture and other, net
 
170

 
15,458

 
286

 
134,945

Equity income, net – affiliates
 
39,218

 
21,728

 
59,642

 
41,189

Cash paid for maintenance capital expenditures (2)
 
20,891

 
11,402

 
37,325

 
22,524

Capitalized interest
 
6,011

 
1,060

 
10,065

 
1,876

Cash paid for (reimbursement of) income taxes
 

 

 
(87
)
 
189

Series A Preferred unit distributions
 

 

 

 
7,453

Other income (2)
 
1,223

 
250

 
2,000

 
677

Distributable cash flow
 
$
221,799

 
$
247,225

 
$
453,235

 
$
463,728

Distributions declared (5)
 
 
 
 
 
 
 
 
Limited partners – common units
 
$
144,979

 
 
 
$
287,662

 
 
General partner
 
80,712

 
 
 
159,162

 
 
Total
 
$
225,691

 
 
 
$
446,824

 
 
Coverage ratio
 
0.98

x
 
 
1.01

x
 
                                                                                                                                                                                    
(1) 
Includes amounts related to the Deferred purchase price obligation - Anadarko. See Note 3—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 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
(4) 
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.
(5) 
Reflects cash distributions of $0.950 and $1.885 per unit declared for the three and six months ended June 30, 2018, respectively.


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LIQUIDITY AND CAPITAL RESOURCES

Our primary cash requirements are for acquisitions and capital expenditures, debt service, customary operating expenses, quarterly distributions to our limited partners and general partner, and distributions to our noncontrolling interest owner. Our sources of liquidity as of June 30, 2018, 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 the RCF, and issuances of additional equity or debt securities. We believe that cash flows generated from these sources will be sufficient to satisfy our short-term working capital requirements and long-term maintenance and expansion capital expenditure 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 to 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 the RCF to pay distributions or fund other short-term working capital requirements.
Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date within 45 days of the end of each quarter. We have made cash distributions to our unitholders each quarter since our IPO and have increased our quarterly distribution each quarter since the second quarter of 2009. The Board of Directors declared a cash distribution to our unitholders for the second quarter of 2018 of $0.950 per unit, or $225.7 million in aggregate, including incentive distributions, but excluding distributions on Class C units. The cash distribution is payable on August 13, 2018, to unitholders of record at the close of business on August 1, 2018. In connection with the closing of the DBM acquisition in November 2014, we issued Class C units that will receive distributions in the form of additional Class C units until March 1, 2020, unless earlier converted (see Note 4—Partnership Distributions in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q). The Class C unit distribution, if paid in cash, would have been $13.1 million for the second quarter of 2018.
Management continuously monitors our leverage position and coordinates our capital expenditure program, quarterly distributions and acquisition strategy with our expected cash flows and projected debt-repayment schedule. We will continue to evaluate funding alternatives, including additional borrowings 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 potential debt or equity securities offerings, we have the ability to sell securities under our shelf registration statements. 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 June 30, 2018, we had a $242.0 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 need for short-term funding. Our working capital requirements are driven by changes in accounts receivable and accounts payable and factors such as credit extended to, and the timing of collections from, our customers, and the level and timing of our spending for maintenance and expansion activity. Our working capital deficit as of June 30, 2018, was primarily due to (i) the costs incurred related to continued construction and expansion at the DBJV system and the DBM and DJ Basin complexes and (ii) system shutdowns at the Hilight system and DJ Basin complex. 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. As of June 30, 2018, we had $1,495.4 million available for borrowing under the RCF. See Note 10—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.


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Capital expenditures. Our business is capital intensive, requiring significant investment to maintain and improve existing facilities or develop new midstream infrastructure. We categorize capital expenditures as either of the following:
 
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 2018, the general partner’s Board of Directors has approved Estimated Maintenance Capital Expenditures (as defined in our partnership agreement) of $19.5 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.

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:
 
 
Six Months Ended 
 June 30,
thousands
 
2018
 
2017
Acquisitions
 
$
161,858

 
$
159,197

 
 
 
 
 
Expansion capital expenditures
 
$
612,755

 
$
236,538

Maintenance capital expenditures
 
37,341

 
22,599

Total capital expenditures (1) (2)
 
$
650,096

 
$
259,137

 
 
 
 
 
Capital incurred (2)
 
$
627,999

 
$
279,921

                                                                                                                                                                                     
(1) 
Capital expenditures for the six months ended June 30, 2017, are presented net of $1.3 million of contributions in aid of construction costs from affiliates.
(2) 
For the six months ended June 30, 2018 and 2017, included $10.1 million and $1.9 million, respectively, of capitalized interest.

Acquisitions during 2018 included a 20% interest in Whitethorn and a 15% interest in Cactus II. Acquisitions during 2017 included the Additional DBJV System Interest and equipment purchases from Anadarko. See Note 3—Acquisitions and Divestitures and Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
Capital expenditures, excluding acquisitions, increased by $391.0 million for the six months ended June 30, 2018. Expansion capital expenditures increased by $376.2 million (including an $8.2 million increase in capitalized interest) for the six months ended June 30, 2018, primarily due to increases of $285.4 million at the DBJV system, $132.3 million at the DJ Basin complex and $13.7 million at the Haley system, primarily due to pipe, compression and processing projects. These increases were partially offset by decreases of (i) $36.8 million at the DBM water systems, which commenced operation during the second quarter of 2017 and (ii) $21.7 million at the DBM complex due to the start-up of Train VI in December 2017. Maintenance capital expenditures increased by $14.7 million for the six months ended June 30, 2018, primarily due to increases at the DJ Basin complex and DBJV system.
During the first quarter of 2018, we updated our estimated total capital expenditures for the year ending December 31, 2018, (including equity investments and our 75% share of Chipeta’s capital expenditures, but excluding acquisitions) from an originally reported $1.0 billion to $1.1 billion, to a current range of $1.35 billion to $1.45 billion to reflect our acquisition of a 20% interest in Whitethorn and a 15% interest in Cactus II.


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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:
 
 
Six Months Ended 
 June 30,
thousands
 
2018
 
2017
Net cash provided by (used in):
 
 
 
 
Operating activities
 
$
514,911

 
$
433,152

Investing activities
 
(826,653
)
 
(363,131
)
Financing activities
 
286,163

 
(239,749
)
Net increase (decrease) in cash and cash equivalents
 
$
(25,579
)
 
$
(169,728
)

Operating Activities. Net cash provided by operating activities for the six months ended June 30, 2018, increased primarily due to the impact of changes in working capital items. Refer to Operating Results within this Item 2 for a discussion of our results of operations as compared to the prior periods.

Investing Activities. Net cash used in investing activities for the six months ended June 30, 2018, included the following:

$650.1 million of capital expenditures, primarily related to construction and expansion at the DBJV system and the DBM and DJ Basin complexes;

$161.9 million of cash paid for the acquisitions of the interests in Whitethorn and Cactus II;

$27.5 million of capital contributions paid to Cactus II, Whitethorn and White Cliffs for construction activities; and

$12.5 million of distributions received from equity investments in excess of cumulative earnings.

Net cash used in investing activities for the six months ended June 30, 2017, included the following:

$259.1 million of capital expenditures, net of $1.3 million of contributions in aid of construction costs from affiliates, primarily related to plant construction and expansion at the DBM complex and DBJV system; and purchases of long lead items related to the future construction of the Mentone plant, all located in West Texas;

$155.3 million of cash consideration paid as part of the Property Exchange;

$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 incident at the DBM complex in 2015;

$9.2 million of distributions received from equity investments in excess of cumulative earnings; and

$3.9 million of cash paid for equipment purchases from Anadarko.

Financing Activities. Net cash provided by financing activities for the six months ended June 30, 2018, included the following:

$1.08 billion of net proceeds from the offering of the 2028 Notes and 2048 Notes in March 2018, after underwriting and original issue discounts and offering costs, which were or will be used to repay amounts outstanding under the RCF and for general partnership purposes, including to fund capital expenditures;

$630.0 million of repayments of outstanding borrowings under the RCF;

$437.7 million of distributions paid to our unitholders;

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$256.8 million of borrowings under the RCF, net of extension costs, which were used for general partnership purposes, including to fund capital expenditures;

$28.1 million of capital contributions from Anadarko related to the above-market component of swap agreements; and

$6.4 million of distributions paid to the noncontrolling interest owner of Chipeta.

Net cash used in financing activities for the six months ended June 30, 2017, included the following:

$381.8 million of distributions paid to our unitholders;

$160.0 million of borrowings under our RCF, which were used for general partnership purposes;

$37.3 million of cash paid to Anadarko for the settlement of the Deferred purchase price obligation - Anadarko;

$28.7 million of capital contributions from Anadarko related to the above-market component of swap agreements; and

$6.4 million of distributions paid to the noncontrolling interest owner of Chipeta.

Debt and credit facility. At June 30, 2018, our debt consisted of $350.0 million aggregate principal amount of the 2018 Notes, $500.0 million aggregate principal amount of the 2021 Notes, $670.0 million aggregate principal amount of the 2022 Notes, $500.0 million aggregate principal amount of the 2025 Notes, $500.0 million aggregate principal amount of the 2026 Notes, $400.0 million aggregate principal amount of the 2028 Notes, $600.0 million aggregate principal amount of the 2044 Notes and $700.0 million aggregate principal amount of the 2048 Notes. As of June 30, 2018, the carrying value of our outstanding debt was $4.2 billion. See Note 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 June 30, 2018, as we have the ability and intent to refinance these obligations using long-term debt.
The 2028 Notes and 2048 Notes issued in March 2018 were offered at prices to the public of 99.435% and 99.169%, respectively, of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rates of the 2028 Notes and 2048 Notes are 4.682% and 5.431%, respectively. Interest is paid on each such series semi-annually on March 1 and September 1 of each year, beginning September 1, 2018. The proceeds (net of underwriting discounts, original issue discounts and debt issuance costs) were used to repay amounts outstanding under the RCF and for general partnership purposes, including to fund capital expenditures.
At June 30, 2018, we were in compliance with all covenants under the indentures governing our outstanding notes.

Revolving credit facility. In February 2018, we entered into the five-year $1.5 billion RCF by amending and restating the $1.2 billion credit facility that was originally entered into in February 2014. The RCF is expandable to a maximum of $2.0 billion, matures in February 2023, with options to extend maturity by up to two additional one year increments, and bears interest at LIBOR, plus applicable margins ranging from 1.00% to 1.50%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c) LIBOR plus 1.00%, in each case plus applicable margins currently ranging from zero to 0.50%, based upon our senior unsecured debt rating. We are required to pay a quarterly facility fee ranging from 0.125% to 0.250% of the commitment amount (whether used or unused), also based upon our senior unsecured debt rating.
As of June 30, 2018, we had no outstanding borrowings and $4.6 million in outstanding letters of credit, resulting in $1,495.4 million available for borrowing under the RCF. At June 30, 2018, the interest rate on the RCF was 3.39% and the facility fee rate was 0.20%. At June 30, 2018, we were in compliance with all covenants under the RCF.

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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 offering. As of June 30, 2018, we had issued no common units under the registration statement associated with the $500.0 million COP.

Credit risk. We bear credit risk represented by our exposure to non-payment or non-performance by our counterparties, including Anadarko, financial institutions, customers and other parties. Generally, non-payment or non-performance results from a customer’s inability to satisfy payables to us for services rendered or volumes owed pursuant to gas imbalance agreements. We examine and monitor the creditworthiness of third-party customers and may establish credit limits for third-party customers.
We do not, however, maintain a credit limit with respect to Anadarko. Consequently, we are subject to the risk of non-payment or late payment by Anadarko for gathering, processing, transportation and disposal fees and for proceeds from the sale of residue, NGLs and condensate to Anadarko.
We expect our exposure to concentrated risk of non-payment or non-performance to continue for as long as we remain substantially dependent on Anadarko for our revenues. Additionally, we are exposed to credit risk on the note receivable from Anadarko. We are also party 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, percent-of-product and keep-whole contracts, and are subject to performance risk thereunder. See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
Our ability to make distributions to our unitholders may be adversely impacted if Anadarko becomes unable to perform under the terms of our gathering, processing, transportation and disposal agreements, our natural gas and NGL purchase agreements, Anadarko’s note payable to us, our omnibus agreement, the services and secondment agreement, the contribution agreements or the commodity price swap agreements.

CONTRACTUAL OBLIGATIONS

Our contractual obligations include, among other things, a revolving credit facility, other third-party long-term debt, capital obligations related to our expansion projects and various operating leases. Refer to Note 10—Debt and Interest Expense and Note 11—Commitments and Contingencies in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for an update to our contractual obligations as of June 30, 2018.

OFF-BALANCE SHEET ARRANGEMENTS

We do not have any off-balance sheet arrangements other than operating leases and standby letters of credit. The information pertaining to operating leases and our standby letters of credit required for this item is provided under Note 11—Commitments and Contingencies and Note 10—Debt and Interest Expense, respectively, included in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

RECENT ACCOUNTING DEVELOPMENTS

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.


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Item 3.  Quantitative and Qualitative Disclosures About Market Risk

Commodity price risk. Certain of our processing services are provided under percent-of-proceeds and keep-whole agreements in which Anadarko is typically responsible 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 a majority of our exposure to the commodity price risk inherent in our percent-of-proceeds, percent-of-product 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 20, 2017, we renewed these commodity price swap agreements through December 31, 2018, with an effective date of January 1, 2018. See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
We consider our exposure to commodity price risk associated with the above-described arrangements to be minimal given the existence of the commodity price swap agreements with Anadarko resulting in the relatively small amount of our operating income (loss) that is impacted by changes in market prices. Accordingly, we do not expect that a 10% increase or decrease in commodity prices would have a material impact on our operating income (loss), financial condition or cash flows for the next twelve months, excluding the effect of imbalances described below.
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 rate risk. The Federal Open Market Committee raised its target range for the federal funds rate three separate times during 2017 and twice in 2018. These increases, and any future increases, in the federal funds rate will ultimately result in an increase in our financing costs. As of June 30, 2018, we had no outstanding borrowings under the RCF (which bears interest at a rate based on LIBOR or, at our option, an alternative base rate). A 10% change in LIBOR would have resulted in no change in net income (loss) and the fair value of the borrowings under the RCF at June 30, 2018.
We may incur additional variable-rate debt in the future, either under the RCF or other financing sources, including commercial bank 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’s general partner (for purposes of this Item 4, “Management”) performed an evaluation of the Partnership’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit 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 reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our 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’s disclosure controls and procedures were effective as of June 30, 2018.

Changes in Internal Control Over Financial Reporting. There were no changes in our internal control over financial reporting during the quarter ended June 30, 2018, that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.


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PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings

Kerr-McGee Gathering LLC, 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 (“LDAR requirements”) at its Fort Lupton facility in the DJ Basin complex and WGR Operating, LP, another wholly owned subsidiary of the Partnership, is in negotiations with the EPA with respect to alleged non-compliance with LDAR requirements at its Granger, Wyoming facility. Although management cannot predict the outcome of settlement discussions in these matters, management believes that it is reasonably likely a resolution of these matters will result in a fine or penalty for each matter in excess of $100,000. Additionally, in May 2018, DBM, a wholly owned subsidiary of the Partnership, entered into a consent agreement and final order with the EPA with respect to alleged noncompliance with certain Risk Management Plan regulations under the Clean Air Act at the DBM complex and agreed to pay a penalty of $226,000.
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.

Item 1A.  Risk Factors

Security holders and potential investors in our securities should carefully consider the risk factors set forth under Part I, Item 1A in our Form 10-K for the year ended December 31, 2017, together with all of the other information included in this document, and in our other public filings, press releases and public discussions with management of the Partnership. Additionally, for a full discussion 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, 2017, Anadarko’s quarterly reports on Form 10-Q and Anadarko’s other public filings, press releases and public discussions with Anadarko management. We 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 or on our behalf.

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

PIK Class C units. During the six months ended June 30, 2018, 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
2017
 
 
 
 
 
 
December 31
 
261,394

 
$
13,674

 
February 2018
2018
 
 
 
 
 
 
March 31
 
272,988

 
$
12,901

 
May 2018

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 Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.


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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
Number
 
Description
2.1#
 
2.2#
 
2.3#
 
2.4#
 
2.5#
 
2.6#
 
2.7#
 
2.8#
 
2.9#
 
2.10#
 
2.11#
 
2.12#
 

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Exhibit
Number
 
Description
2.13#
 
2.14#
 
3.1
 
3.2
 
3.3
 
3.4
 
3.5
 
3.6
 
3.7
 
4.1
 
4.2
 
4.3
 
4.4
 
4.5
 
4.6
 
4.7
 
4.8
 
4.9
 

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Exhibit
Number
 
Description
4.10
 
4.11
 
4.12
 
4.13
 
4.14
 
4.15
 
4.16
 
4.17
 
4.18
 
4.19
 
10.1*†
 
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
                                                                                                                                                                                    
#
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.
Portions of this exhibit, which was previously filed with the Securities and Exchange Commission, were omitted pursuant to a request for confidential treatment. The omitted portions were filed separately with the Securities and Exchange Commission.


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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 GAS PARTNERS, LP
 
 
August 1, 2018
 
 
 
 
/s/ Benjamin M. Fink
 
Benjamin M. Fink
President and Chief Executive Officer
Western Gas Holdings, LLC
(as general partner of Western Gas Partners, LP)
 
 
August 1, 2018
 
 
 
 
/s/ Jaime R. Casas
 
Jaime R. Casas
Senior Vice President, Chief Financial Officer and Treasurer
Western Gas Holdings, LLC
(as general partner of Western Gas Partners, LP)


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