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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
  
(Mark One)
      
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2016
 
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      No  

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes      No  

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
  
Accelerated filer
  
Non-accelerated filer
  
Smaller reporting company
 
  
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes      No  

There were 130,671,970 common units outstanding as of July 25, 2016.


Table of Contents

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 below have the following meanings:
Affiliates: Subsidiaries of Anadarko, excluding us, but including equity interests in Fort Union, White Cliffs, Rendezvous, the Mont Belvieu JV, TEP, TEG, and FRP.
Anadarko: Anadarko Petroleum Corporation and its subsidiaries, excluding us and our general partner.
Anadarko-Operated Marcellus Interest: Our 33.75% interest in the Larry’s Creek, Seely and Warrensville gas gathering systems and related facilities located in northern Pennsylvania.
April 2016 Series A units: The 7,892,220 Series A Preferred units issued pursuant to the full exercise of the option granted in connection with the issuance of the March 2016 Series A units.
Barrel or Bbl: 42 U.S. gallons measured at 60 degrees Fahrenheit.
Btu: British thermal unit; the approximate amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Chipeta: Chipeta Processing, LLC.
Condensate: A natural gas liquid with a low vapor pressure mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.
COP: Continuous offering programs.
Cryogenic: The process in which liquefied gases are used to bring natural gas volumes to very low temperatures (below approximately -238 degrees Fahrenheit) to separate natural gas liquids from natural gas. Through cryogenic processing, more natural gas liquids are extracted than when traditional refrigeration methods are used.
DBJV: Delaware Basin JV Gathering LLC.
DBJV system: A gathering system and related facilities located in the Delaware Basin in Loving, Ward, Winkler and Reeves Counties, Texas.
DBM: Delaware Basin Midstream, LLC.
DBM complex: The cryogenic processing plants, gas gathering system, and related facilities and equipment that serve production from Reeves, Loving and Culberson Counties, Texas and Eddy and Lea Counties, New Mexico.
DJ Basin complex: The Platte Valley system, Wattenberg system and Lancaster plant, all of which were combined into a single complex in the first quarter of 2014.
EBITDA: Earnings before interest, taxes, depreciation, and amortization. For a definition of “Adjusted EBITDA,” see the caption Key Performance Metrics under Part I, Item 2 of this Form 10-Q.
Equity investment throughput: Our 14.81% share of average Fort Union throughput, 22% share of average Rendezvous throughput, 10% share of average White Cliffs throughput, 25% share of average Mont Belvieu JV throughput, 20% share of average TEP and TEG throughput and 33.33% share of average FRP throughput.
Exchange Act: The Securities Exchange Act of 1934, as amended.
Fort Union: Fort Union Gas Gathering, LLC.
FRP: Front Range Pipeline LLC.
GAAP: Generally accepted accounting principles in the United States.

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General partner: Western Gas Holdings, LLC.
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.
March 2016 Series A units: The 14,030,611 Series A Preferred units issued in March 2016 in connection with the acquisition of Springfield.
MBbls/d: One thousand barrels per day.
MGR assets: The Red Desert complex, the Granger straddle plant and the 22% interest in Rendezvous.
MICG: MIGC, LLC.
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: Our 33.75% interest in the Liberty and Rome gas gathering systems and related facilities located in northern Pennsylvania.
PIK Class C units: Additional Class C units issued as quarterly distributions to the holder of our Class C units.
RCF: Our senior unsecured revolving credit facility.
Red Desert complex: The Patrick Draw processing plant, the Red Desert processing plant, associated gathering lines, and related facilities.
Rendezvous: Rendezvous Gas Services, LLC.
Residue: The natural gas remaining after the unprocessed natural gas stream has been processed or treated.
SEC: U.S. Securities and Exchange Commission.
Springfield: Springfield Pipeline LLC.
Springfield interest: Springfield’s 50.1% interest in the Springfield system.
Springfield gas gathering system: A gas gathering system and related facilities located in Dimmit, La Salle, Maverick and Webb Counties in South Texas.
Springfield oil gathering system: An oil gathering system and related facilities located in Dimmit, La Salle, Maverick and Webb Counties in South Texas.
Springfield system: Consists of the Springfield gas gathering system and Springfield oil gathering system.
TEFR Interests: The interests in TEP, TEG and FRP.

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TEG: Texas Express Gathering LLC.
TEP: Texas Express Pipeline LLC.
WGP: Western Gas Equity Partners, LP.
White Cliffs: White Cliffs Pipeline, 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.
2044 Notes: Our 5.450% Senior Notes due 2044.
2026 Notes: Our 4.650% Senior Notes due 2026.
$500.0 million COP: The COP contemplated by the registration statement filed with the SEC in August 2014 authorizing 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
 
2016
 
2015 (1)
 
2016
 
2015 (1)
Revenues and other – affiliates
 
 
 
 
 
 
 
 
Gathering, processing and transportation
 
$
186,733

 
$
199,666

 
$
374,451

 
$
387,684

Natural gas and natural gas liquids sales
 
115,672

 
121,613

 
200,538

 
240,353

Other
 

 
132

 

 
302

Total revenues and other – affiliates
 
302,405

 
321,411

 
574,989

 
628,339

Revenues and other – third parties
 
 
 
 
 
 
 
 
Gathering, processing and transportation
 
114,403

 
91,234

 
220,689

 
173,484

Natural gas and natural gas liquids sales
 
11,321

 
52,589

 
15,011

 
99,521

Other
 
535

 
759

 
1,116

 
1,655

Total revenues and other – third parties
 
126,259

 
144,582

 
236,816

 
274,660

Total revenues and other
 
428,664

 
465,993

 
811,805

 
902,999

Equity income, net – affiliates
 
19,693

 
18,941

 
36,507

 
37,161

Operating expenses
 
 
 
 
 
 
 
 
Cost of product (2)
 
104,849

 
147,216

 
181,316

 
286,624

Operation and maintenance (2)
 
75,173

 
77,837

 
151,386

 
154,022

General and administrative (2)
 
10,883

 
9,408

 
22,160

 
20,489

Property and other taxes
 
12,078

 
9,586

 
22,428

 
18,866

Depreciation and amortization
 
67,305

 
68,554

 
132,400

 
137,529

Impairments
 
2,403

 
1,620

 
8,921

 
274,244

Total operating expenses
 
272,691

 
314,221

 
518,611

 
891,774

Gain (loss) on divestiture and other, net
 
(1,907
)
 

 
(2,539
)
 
(6
)
Proceeds from business interruption insurance claims
 
2,603

 

 
2,603

 

Operating income (loss)
 
176,362

 
170,713

 
329,765

 
48,380

Interest income – affiliates
 
4,225

 
4,225

 
8,450

 
8,450

Interest expense (3)
 
(12,883
)
 
(27,604
)
 
(44,919
)
 
(50,564
)
Other income (expense), net
 
(53
)
 
71

 
71

 
142

Income (loss) before income taxes
 
167,651

 
147,405

 
293,367

 
6,408

Income tax (benefit) expense
 
326

 
12,246

 
6,959

 
24,516

Net income (loss)
 
167,325

 
135,159

 
286,408

 
(18,108
)
Net income attributable to noncontrolling interest
 
2,804

 
2,816

 
5,827

 
6,042

Net income (loss) attributable to Western Gas Partners, LP
 
$
164,521

 
$
132,343

 
$
280,581

 
$
(24,150
)
Limited partners’ interest in net income (loss):
 
 
 
 
 
 
 
 
Net income (loss) attributable to Western Gas Partners, LP
 
$
164,521

 
$
132,343

 
$
280,581

 
$
(24,150
)
Pre-acquisition net (income) loss allocated to Anadarko
 

 
(18,719
)
 
(11,326
)
 
(43,758
)
Series A Preferred units interest in net (income) loss (4)
 
(23,121
)
 

 
(25,450
)
 

General partner interest in net (income) loss (4)
 
(58,381
)
 
(45,971
)
 
(113,781
)
 
(83,148
)
Common and Class C limited partners’ interest in net income (loss) (4)
 
83,019

 
67,653

 
130,024

 
(151,056
)
Net income (loss) per common unit – basic and diluted (5)
 
$
0.55

 
$
0.46

 
$
0.86

 
$
(1.14
)
 
                                                                                                                                                                                         
(1) 
Financial information has been recast to include the financial position and results attributable to the Springfield interest. See Note 1 and Note 2.
(2) 
Cost of product includes product purchases from Anadarko (as defined in Note 1) of $22.1 million and $46.7 million for the three and six months ended June 30, 2016, respectively, and $53.1 million and $97.0 million for the three and six months ended June 30, 2015, respectively. Operation and maintenance includes charges from Anadarko of $17.7 million and $35.6 million for the three and six months ended June 30, 2016, respectively, and $19.9 million and $36.7 million for the three and six months ended June 30, 2015, respectively. General and administrative includes charges from Anadarko of $9.2 million and $18.1 million for the three and six months ended June 30, 2016, respectively, and $8.1 million and $16.2 million for the three and six months ended June 30, 2015, respectively. See Note 5.
(3) 
Includes affiliate (as defined in Note 1) amounts of $(15.5) million and $(10.9) million for the three and six months ended June 30, 2016, respectively, and $4.2 million and $5.6 million for the three and six months ended June 30, 2015, respectively. See Note 2 and Note 9.
(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 4.
(5) 
See Note 4 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, 
 2016
 
December 31,
2015 (1)
ASSETS
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
 
$
157,767

 
$
98,033

Accounts receivable, net (2)
 
221,795

 
193,329

Other current assets
 
5,691

 
7,855

Total current assets
 
385,253

 
299,217

Note receivable – Anadarko
 
260,000

 
260,000

Property, plant and equipment
 
 
 
 
Cost
 
6,818,174

 
6,556,778

Less accumulated depreciation
 
1,816,030

 
1,697,999

Net property, plant and equipment
 
5,002,144

 
4,858,779

Goodwill
 
419,186

 
419,186

Other intangible assets
 
817,913

 
832,127

Equity investments
 
606,125

 
618,887

Other assets
 
13,481

 
13,001

Total assets
 
$
7,504,102

 
$
7,301,197

LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
 
 
 
 
Current liabilities
 
 
 
 
Accounts and imbalance payables
 
$
90,914

 
$
98,661

Accrued ad valorem taxes
 
20,633

 
17,808

Accrued liabilities
 
130,018

 
119,019

Total current liabilities
 
241,565

 
235,488

Long-term debt
 
2,932,004

 
2,690,651

Deferred income taxes
 
6,020

 
139,704

Asset retirement obligations and other
 
137,139

 
128,652

Deferred purchase price obligation – Anadarko (3)
 
29,150

 
188,674

Total long-term liabilities
 
3,104,313

 
3,147,681

Total liabilities
 
3,345,878

 
3,383,169

Equity and partners’ capital
 
 
 
 
Series A Preferred units (21,922,831 and zero units issued and outstanding at June 30, 2016, and December 31, 2015, respectively) (4)
 
617,094

 

Common units (130,671,970 and 128,576,965 units issued and outstanding at June 30, 2016, and December 31, 2015, respectively)
 
2,613,806

 
2,588,991

Class C units (11,946,008 and 11,411,862 units issued and outstanding at June 30, 2016, and December 31, 2015, respectively) (5)
 
729,731

 
710,891

General partner units (2,583,068 units issued and outstanding at June 30, 2016, and December 31, 2015)
 
131,842

 
120,164

Net investment by Anadarko
 

 
430,598

Total partners’ capital
 
4,092,473

 
3,850,644

Noncontrolling interest
 
65,751

 
67,384

Total equity and partners’ capital
 
4,158,224

 
3,918,028

Total liabilities, equity and partners’ capital
 
$
7,504,102

 
$
7,301,197

                                                                                                                                                                                    
(1) 
Financial information has been recast to include the financial position and results attributable to the Springfield interest. See Note 1 and Note 2.
(2) 
Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $81.3 million and $42.7 million as of June 30, 2016, and December 31, 2015, respectively. Accounts receivable, net as of June 30, 2016, and December 31, 2015, also includes an insurance claim receivable related to an incident at the DBM complex. See Note 1.
(3) 
See Note 2.
(4) 
The Series A Preferred units are convertible into common units at the holder’s election on a one-for-one basis at any time after the second anniversary of the issuance date. See Note 4.
(5) 
The Class C units will convert into common units on a one-for-one basis on December 31, 2017, unless the Partnership elects to convert such units earlier or Anadarko extends the conversion date. See Note 4.

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
 
Net
Investment
by Anadarko
 
Common
Units
 
Class C
Units
 
Series A Preferred Units
 
General
Partner 
Units
 
Noncontrolling
Interest
 
Total
Balance at December 31, 2015 (1)
 
$
430,598

 
$
2,588,991

 
$
710,891

 
$

 
$
120,164

 
$
67,384

 
$
3,918,028

Net income (loss)
 
11,326

 
126,292

 
13,213

 
15,969

 
113,781

 
5,827

 
286,408

Above-market component of swap extensions with Anadarko (2)
 

 
16,365

 

 

 

 

 
16,365

Issuance of common units, net of offering expenses
 

 
25,000

 

 

 

 

 
25,000

Issuance of Series A Preferred units, net of offering expenses
 

 

 

 
686,940

 

 

 
686,940

Beneficial conversion feature of Series A Preferred units
 

 
93,409

 

 
(93,409
)
 

 

 

Amortization of beneficial conversion feature of Class C units and Series A Preferred units
 

 
(15,108
)
 
5,627

 
9,481

 

 

 

Distributions to noncontrolling interest owner
 

 

 

 

 

 
(7,460
)
 
(7,460
)
Distributions to unitholders
 

 
(209,355
)
 

 
(1,887
)
 
(102,138
)
 

 
(313,380
)
Acquisitions from affiliates
 
(549,865
)
 
(162,635
)
 

 

 

 

 
(712,500
)
Revision to Deferred purchase price obligation – Anadarko (3)
 

 
148,600

 

 

 

 

 
148,600

Contributions of equity-based compensation from Anadarko
 

 
2,012

 

 

 
41

 

 
2,053

Net pre-acquisition contributions from (distributions to) Anadarko
 
(27,459
)
 

 

 

 

 

 
(27,459
)
Net distributions to Anadarko of other assets
 

 
(348
)
 

 

 
(6
)
 

 
(354
)
Elimination of net deferred tax liabilities
 
135,400

 

 

 

 

 

 
135,400

Other
 

 
583

 

 

 

 

 
583

Balance at June 30, 2016
 
$

 
$
2,613,806

 
$
729,731

 
$
617,094

 
$
131,842

 
$
65,751

 
$
4,158,224

                                                                                                                                                                                    
(1) 
Financial information has been recast to include the financial position and results attributable to the Springfield interest. See Note 1 and Note 2.
(2) 
See Note 5.
(3) 
See Note 2.

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
 
2016
 
2015 (1)
Cash flows from operating activities
 
 
 
 
Net income (loss)
 
$
286,408

 
$
(18,108
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
 
Depreciation and amortization
 
132,400

 
137,529

Impairments
 
8,921

 
274,244

Non-cash equity-based compensation expense
 
2,391

 
2,130

Deferred income taxes
 
1,980

 
6,382

Accretion and amortization of long-term obligations, net
 
(9,055
)
 
7,070

Equity income, net – affiliates
 
(36,507
)
 
(37,161
)
Distributions from equity investment earnings – affiliates
 
38,519

 
39,034

(Gain) loss on divestiture and other, net
 
2,539

 
6

Changes in assets and liabilities:
 
 
 
 
(Increase) decrease in accounts receivable, net
 
(33,242
)
 
(41,358
)
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net
 
(2,227
)
 
4,407

Change in other items, net
 
1,739

 
(1,854
)
Net cash provided by operating activities
 
393,866


372,321

Cash flows from investing activities
 
 
 
 
Capital expenditures
 
(255,923
)
 
(361,798
)
Contributions in aid of construction costs from affiliates
 
3,854

 

Acquisitions from affiliates
 
(715,199
)
 
(9,056
)
Acquisitions from third parties
 

 
(3,514
)
Investments in equity affiliates
 
139

 
(6,770
)
Distributions from equity investments in excess of cumulative earnings – affiliates
 
10,611

 
8,538

Proceeds from the sale of assets to affiliates
 
613

 
700

Proceeds from the sale of assets to third parties
 
137

 
22

Proceeds from property insurance claims
 
2,944

 

Net cash used in investing activities
 
(952,824
)

(371,878
)
Cash flows from financing activities
 
 
 
 
Borrowings, net of debt issuance costs
 
530,000

 
769,694

Repayments of debt
 
(290,000
)
 
(520,000
)
Increase (decrease) in outstanding checks
 
(1,314
)
 
(2,938
)
Proceeds from the issuance of common units, net of offering expenses
 
25,000

 
57,376

Proceeds from the issuance of Series A Preferred units, net of offering expenses
 
686,940

 

Distributions to unitholders (2)
 
(313,380
)
 
(259,247
)
Distributions to noncontrolling interest owner
 
(7,460
)
 
(7,175
)
Net contributions from (distributions to) Anadarko
 
(27,459
)
 
(17,439
)
Above-market component of swap extensions with Anadarko (2)
 
16,365

 

Net cash provided by (used in) financing activities
 
618,692


20,271

Net increase (decrease) in cash and cash equivalents
 
59,734


20,714

Cash and cash equivalents at beginning of period
 
98,033

 
67,054

Cash and cash equivalents at end of period
 
$
157,767


$
87,768

Supplemental disclosures
 
 
 
 
Acquisition of DBJV from Anadarko
 
$
(159,524
)
 
$
174,276

Net distributions to (contributions from) Anadarko of other assets
 
354

 
4,540

Interest paid, net of capitalized interest
 
53,973

 
42,165

Taxes paid (reimbursements received)
 
67

 
(138
)
                                                                                                                                                                                    
(1) 
Financial information has been recast to include the financial position and results attributable to the Springfield interest. See Note 1 and Note 2.
(2) 
See Note 5.

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 energy assets.
For purposes of these consolidated financial statements, the “Partnership” refers to Western Gas Partners, LP and its subsidiaries. The Partnership’s general partner, Western Gas Holdings, LLC (the “general partner”), is owned by Western Gas Equity Partners, LP (“WGP”), a Delaware MLP formed by Anadarko Petroleum Corporation in September 2012 to own the Partnership’s general partner, as well as a significant limited partner interest in the Partnership (see Western Gas Equity Partners, LP below). WGP has no independent operations or material assets other than owning the partnership interests in WES (see Holdings of Partnership equity in Note 4). Western Gas Equity Holdings, LLC is WGP’s general partner and is a wholly owned subsidiary of Anadarko Petroleum Corporation. “Anadarko” refers to Anadarko Petroleum Corporation and its subsidiaries, excluding the Partnership and the general partner, and “affiliates” refers to subsidiaries of Anadarko, excluding the Partnership, but including equity interests in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”), Rendezvous Gas Services, LLC (“Rendezvous”), Enterprise EF78 LLC (the “Mont Belvieu JV”), Texas Express Pipeline LLC (“TEP”), Texas Express Gathering LLC (“TEG”) and Front Range Pipeline LLC (“FRP”). The interests in TEP, TEG and FRP are referred to collectively as the “TEFR Interests.” The “MGR assets” include the Red Desert complex, the Granger straddle plant and the interest in Rendezvous.
The Partnership is engaged in the business of gathering, processing, compressing, treating and transporting natural gas, condensate, NGLs and crude oil for Anadarko, as well as for third-party producers and customers. As of June 30, 2016, the Partnership’s assets and investments accounted for under the equity method consisted of the following:
 
 
Owned and
Operated
 
Operated
Interests
 
Non-Operated
Interests
 
Equity
Interests
Gathering systems
 
12

 
4

 
5

 
2

Treating facilities
 
13

 
12

 

 
3

Natural gas processing plants/trains
 
19

 
5

 

 
2

NGL pipelines
 
2

 

 

 
3

Natural gas pipelines
 
5

 

 

 

Oil pipelines
 

 
1

 

 
1


These assets and investments are located in the Rocky Mountains (Colorado, Utah and Wyoming), the Mid-Continent (Kansas and Oklahoma), North-central Pennsylvania and Texas. In May 2016, the Partnership commenced operation of Train IV, a processing plant, at the DBM complex. The Partnership is constructing Train V, an additional processing plant at the DBM complex, with operations expected to commence during the second half of 2016. The Partnership has also made progress payments toward the construction of another cryogenic unit at the DBM complex (Train VI). The Partnership is evaluating when construction of Train VI will start and believe the earliest the plant will be online is the first 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:
 
 
Percentage Interest
Equity investments (1)
 
 
Fort Union
 
14.81
%
White Cliffs
 
10
%
Rendezvous
 
22
%
Mont Belvieu JV
 
25
%
TEP
 
20
%
TEG
 
20
%
FRP
 
33.33
%
Proportionate consolidation (2)
 
 
Non-Operated Marcellus Interest systems
 
33.75
%
Anadarko-Operated Marcellus Interest systems
 
33.75
%
Newcastle system
 
50
%
DBJV system
 
50
%
Springfield system
 
50.1
%
Full consolidation
 
 
Chipeta (3)
 
75
%
                                                                                                                                                                                                                   
(1) 
Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. “Equity investment throughput” refers to the Partnership’s share of average throughput for these investments.
(2) 
The Partnership proportionately consolidates its associated share of the assets, liabilities, revenues and expenses attributable to these assets.
(3) 
The 25% interest in Chipeta Processing LLC (“Chipeta”) held by a third-party member is reflected within noncontrolling interest in the consolidated financial statements.

The consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”). The consolidated financial statements include the accounts of the Partnership and entities in which it holds a controlling financial interest. All significant intercompany transactions have been eliminated.
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.
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 2015 Form 10-K, as filed with the SEC on February 25, 2016, certain sections of which were recast to reflect the results of the Springfield interest in the Partnership’s Current Report on Form 8-K, as filed with the SEC on June 10, 2016. Management believes that the disclosures made are adequate to make the information not misleading.


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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” refers to the assets owned and interests accounted for under the equity method (see Note 7) by the Partnership as of June 30, 2016. Because Anadarko controls the Partnership through its ownership and control of WGP, which owns the Partnership’s entire general partner interest, each acquisition of Partnership assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by the Partnership. Further, after an acquisition of Partnership assets from Anadarko, the Partnership may be required to recast its financial statements to include the activities of such Partnership assets from the date of common control. See Note 2.
For those periods requiring recast, the consolidated financial statements for periods prior to the Partnership’s acquisition of the Partnership assets from Anadarko have been prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the Partnership assets during the periods reported. Net income (loss) attributable to the Partnership assets acquired from Anadarko for periods prior to the Partnership’s acquisition of the Partnership assets is not allocated to the limited partners.

Insurance recoveries. Involuntary conversions result from the loss of an asset because of some unforeseen event (e.g., destruction due to fire). Some of these events are insurable and result in property damage insurance recovery. Amounts the Partnership receives from insurance carriers are net of any deductibles related to the covered event. The Partnership records a receivable from insurance to the extent it recognizes a loss from an involuntary conversion event and the likelihood of recovering such loss is deemed probable. To the extent that any of the Partnership’s insurance claim receivables are later judged not probable of recovery (e.g., due to new information), such amounts are expensed. The Partnership recognizes gains on involuntary conversions when the amount received from insurance exceeds the net book value of the retired asset(s). In addition, the Partnership does not recognize a gain related to insurance recoveries until all contingencies related to such proceeds have been resolved, that is, a non-refundable cash payment is received from the insurance carrier or the Partnership has a binding settlement agreement with the carrier that clearly states that a non-refundable payment will be made. To the extent that an asset is rebuilt, the associated expenditures are capitalized, as appropriate, in the consolidated balance sheets and presented as capital expenditures in the Partnership’s consolidated statements of cash flows. With respect to business interruption insurance claims, the Partnership recognizes income only when non-refundable cash proceeds are received from insurers, which are presented in the Partnership’s consolidated statements of operations as a component of Operating income (loss).
On December 3, 2015, there was an initial fire and secondary explosion at the processing facility within the DBM complex. The majority of the damage from the incident was to the liquid handling facilities and the amine treating units at the inlet of the complex. Train II (with capacity of 100 MMcf/d) sustained the most damage of the processing trains but is expected to be returned to service by the end of 2016. Train III (with capacity of 200 MMcf/d) experienced minimal damage and returned to full service in May 2016. As of June 30, 2016, and December 31, 2015, the consolidated balance sheets include receivables of $44.2 million and $49.0 million, respectively, for a property insurance claim related to the incident at the DBM complex. As of June 30, 2016, the Partnership had received $5.5 million in cash proceeds from insurers related to the incident at the DBM complex, including $2.6 million in proceeds from business interruption insurance claims and $2.9 million in proceeds from property insurance claims.

Recently issued accounting standards. The Financial Accounting Standards Board recently issued the following Accounting Standards Updates (“ASUs”):
ASU 2016-02, Leases (Topic - 842). This ASU requires the lessees to recognize a lease liability and a right-of-use asset for all leases, including operating leases, with a term greater than 12 months on the balance sheet and disclose key information about their leasing transactions. This ASU is effective for annual and interim periods beginning in 2019. The Partnership is evaluating the impact of the adoption of this ASU on its 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 (CONTINUED)

ASU 2015-06, Earnings Per Share (Topic - 260)—Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions. This ASU provides guidance for the presentation of historical earnings per unit for MLPs that apply the two-class method of calculating earnings per unit. When a general partner transfers or “drops down” net assets to an MLP, the transaction is accounted for as a transaction between entities under common control, and the statements of operations are adjusted retrospectively to reflect the transaction. This ASU specifies that the historical earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner, and the previously reported earnings per unit of the limited partners should not change as a result of the dropdown transaction. The ASU also requires additional disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two-class method. The Partnership applies the two-class method of calculating earnings per unit as described above (including the allocation of pre-acquisition net income (loss) to the general partner), and discloses the rights to earnings (losses) noted above. As such, there was no impact to the Partnership’s consolidated financial statements upon adoption of this ASU on January 1, 2016.
ASU 2015-03, Interest—Imputation of Interest (Subtopic 835-30)—Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Interest—Imputation of Interest (Subtopic 835-30)—Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. These ASUs require capitalized debt issuance costs, except for those related to revolving credit facilities, to be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, rather than as an asset. The Partnership adopted these ASUs on January 1, 2016, using a retrospective approach. The adoption resulted in a reclassification that reduced Other assets and Long-term debt by $16.7 million on the Partnership’s consolidated balance sheet at December 31, 2015. See Note 9.
ASU 2015-02, Consolidation (Topic 810)—Amendments to the Consolidation Analysis. This ASU amends existing requirements applicable to reporting entities that are required to evaluate consolidation of a legal entity under the variable interest entity (“VIE”) or voting interest entity models. The provisions will affect how limited partnerships and similar entities are assessed for consolidation, including an additional requirement that a limited partnership will be a VIE unless the limited partners have either substantive kick-out or participating rights over the general partner. The Partnership evaluated the impact of the adoption of this ASU on its consolidated financial statements and determined it does not have any entities for which it is the primary beneficiary for accounting and disclosure purposes. As such, the adoption of this ASU on January 1, 2016, did not impact the Partnership’s consolidated financial statements.
ASU 2014-09, Revenue from Contracts with Customers (Topic 606). This ASU supersedes current revenue recognition requirements. The codification was amended through additional ASUs and, as amended, requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. The Partnership is required to adopt the new standard in the first quarter of 2018 using one of two retrospective application methods. The Partnership is continuing to evaluate the provisions of this ASU and has not determined the impact this standard may have on its consolidated financial statements and related disclosures or decided upon the method of adoption.


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

2.  ACQUISITIONS AND DIVESTITURES

The following table presents the acquisitions completed by the Partnership during 2016 and 2015, and identifies the funding sources for such acquisitions:
thousands except unit and percent amounts
 
Acquisition
Date
 
Percentage
Acquired
 
Deferred Purchase Price
Obligation - Anadarko
 
Borrowings
 
Common Units
Issued
 
Series A Preferred Units
DBJV (1)
 
03/02/2015
 
100
%
 
$
174,276

 
$

 

 

Springfield (2)
 
03/14/2016
 
100
%
 

 
247,500

 
2,089,602

 
14,030,611

                                                                                                                                                                                   
(1) 
The Partnership acquired Delaware Basin JV Gathering LLC (“DBJV”) from Anadarko. DBJV owns a 50% interest in a gathering system and related facilities. The DBJV gathering system and related facilities (the “DBJV system”) are located in the Delaware Basin in Loving, Ward, Winkler and Reeves Counties, Texas. The Partnership will make a cash payment on March 31, 2020, to Anadarko as consideration for the acquisition of DBJV. At the acquisition date, the Partnership estimated the future payment would be $282.8 million, the net present value of which was $174.3 million. For further information, including revisions to the estimated future payment, see DBJV acquisition—deferred purchase price obligation - Anadarko below.
(2) 
The Partnership acquired Springfield Pipeline LLC (“Springfield”) from Anadarko for $750.0 million, consisting of $712.5 million in cash and the issuance of 1,253,761 of the Partnership’s common units. Springfield owns a 50.1% interest in an oil gathering system and a gas gathering system, such interest being referred to in this report as the “Springfield interest.” The Springfield oil and gas gathering systems (collectively, the “Springfield system”) are located in Dimmit, La Salle, Maverick and Webb Counties in South Texas. The Partnership financed the cash portion of the acquisition through: (i) borrowings of $247.5 million on the Partnership’s senior unsecured revolving credit facility (“RCF”), (ii) the issuance of 835,841 of the Partnership’s common units to WGP and (iii) the issuance of Series A Preferred units to private investors. See Note 4 for further information regarding the Series A Preferred units.

Springfield acquisition. Because the acquisition of Springfield was a transfer of net assets between entities under common control, the Partnership’s historical financial statements and operational data previously filed with the SEC have been recast in this Form 10-Q to include the results attributable to the Springfield interest as if the Partnership owned Springfield for all periods presented. The consolidated financial statements for periods prior to the Partnership’s acquisition of Springfield have been prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned Springfield during the periods reported.
The following table presents the impact of the Springfield interest on Revenues and other and Net income (loss) as presented in the Partnership’s historical consolidated statements of operations:
 
 
Three Months Ended June 30, 2015
thousands
 
Partnership Historical
 
Springfield Interest
 
Eliminations
 
Combined
Revenues and other
 
$
416,572

 
$
49,438

 
$
(17
)
 
$
465,993

Net income (loss)
 
116,440

 
18,719

 

 
135,159

 
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2015
thousands
 
Partnership Historical
 
Springfield Interest
 
Eliminations
 
Combined
Revenues and other
 
$
804,981

 
$
98,051

 
$
(33
)
 
$
902,999

Net income (loss)
 
(60,124
)
 
42,016

 

 
(18,108
)



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

2.  ACQUISITIONS AND DIVESTITURES (CONTINUED)

DBJV acquisition - deferred purchase price obligation - Anadarko. The consideration to be paid by the Partnership for the acquisition of DBJV consists of a cash payment to Anadarko due on March 31, 2020. The cash payment will be equal to (a) eight multiplied by the average of the Partnership’s share in the Net Earnings (see definition below) of DBJV for the calendar years 2018 and 2019, less (b) the Partnership’s share of all capital expenditures incurred for DBJV between March 1, 2015, and February 29, 2020. Net Earnings is defined as all revenues less cost of product, operating expenses and property taxes, in each case attributable to DBJV on an accrual basis. As of the acquisition date, the estimated future payment obligation (based on management’s estimate of the Partnership’s share of forecasted Net Earnings and capital expenditures for DBJV) was $282.8 million, which had a net present value of $174.3 million, using a discount rate of 10%. As of June 30, 2016, the Partnership recognized a $241.1 million decrease in the estimated future payment obligation, resulting in a net present value of this obligation of $29.2 million, calculated using a discounted cash flow model with a 10% discount rate. The reduction in the value of the deferred purchase price obligation is primarily due to revisions reflecting a decrease in the Partnership’s estimate of 2018 and 2019 Net Earnings and an increase in the Partnership’s estimate of aggregate capital expenditures to be incurred by DBJV through February 29, 2020.
The following table summarizes the financial statement impact of the Deferred purchase price obligation - Anadarko:
 
 
Deferred purchase price obligation - Anadarko
 
Estimated future payment obligation
Balance at March 2, 2015 Acquisition date
 
$
174,276

 
$
282,807

Accretion expense (1)
 
14,398

 
 
Balance at December 31, 2015
 
188,674

 
 
Accretion expense (1)
 
4,537

 
 
Balance at March 31, 2016
 
193,211

 
 
Accretion revision (2)
 
(15,461
)
 
 
Revision to Deferred purchase price obligation – Anadarko (3)
 
(148,600
)
 
 
Balance at June 30, 2016
 
$
29,150

 
$
41,666

                                                                                                                                                                                   
(1) 
Accretion expense was recorded as a charge to Interest expense on the consolidated statements of operations.
(2) 
Interest expense on the consolidated statements of operations includes financing-related accretion revisions of $15.5 million and $10.9 million for the three and six months ended June 30, 2016, respectively.
(3) 
Recorded as revisions within Common units on the consolidated balance sheets and consolidated statement of equity and partners’ capital.


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

3.  PARTNERSHIP DISTRIBUTIONS

The partnership agreement requires the Partnership to distribute all of its available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date within 45 days of the end of each quarter. The Board of Directors of the general partner 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
2015
 
 
 
 
 
 
March 31
 
$
0.725

 
$
133,203

 
May 2015
June 30
 
0.750

 
139,736

 
August 2015
September 30
 
0.775

 
146,160

 
November 2015
December 31
 
0.800

 
152,588

 
February 2016
2016
 
 
 
 
 
 
March 31
 
$
0.815

 
$
158,905

 
May 2016
June 30 (1)
 
0.830

 
162,827

 
August 2016
                                                                                                                                                                                    
(1) 
On July 20, 2016, the Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.830 per unit, or $162.8 million in aggregate, including incentive distributions, but excluding distributions on Class C units (see Class C unit distributions below) and Series A Preferred units (see Series A Preferred unit distributions below). The cash distribution is payable on August 12, 2016, to unitholders of record at the close of business on August 1, 2016.

Class C unit distributions. The Class C units receive quarterly distributions at a rate equivalent to the Partnership’s common units. The distributions are paid in the form of additional Class C units (“PIK Class C units”) until the scheduled conversion date on December 31, 2017 (unless earlier converted), and the Class C units are disregarded with respect to distributions of the Partnership’s available cash until they are converted to common units. The number of additional PIK Class C units to be issued in connection with a distribution payable on the Class C units is determined by dividing the corresponding distribution attributable to the Class C units by the volume-weighted-average price of the Partnership’s common units for the ten days immediately preceding the payment date for the common unit distribution, less a 6% discount. The Partnership records the PIK Class C unit distributions at fair value at the time of issuance. This Level 2 fair value measurement uses the Partnership’s unit price as a significant input in the determination of the fair value. On May 13, 2016, the Partnership distributed 210,562 PIK Class C units to APC Midstream Holdings, LLC (“AMH”), the holder of the Class C units, for the quarterly distribution period ended March 31, 2016, and on February 11, 2016, the Partnership distributed 323,584 PIK Class C units to AMH for the quarterly distribution period ended December 31, 2015.

Series A Preferred unit distributions. As further described in Note 4, the Partnership issued Series A Preferred units representing limited partner interests in the Partnership to private investors in March 2016 and April 2016. The Series A Preferred unitholders receive quarterly distributions in cash equal to $0.68 per Series A Preferred unit, subject to certain adjustments. The holders of the Series A Preferred units are entitled to certain rights that are senior to the rights of holders of common and Class C units, such as rights to distributions and rights upon liquidation of the Partnership. No payment or distribution on any junior equity security of the Partnership, including common and Class C units, for any quarter is permitted prior to the payment in full of the Series A Preferred unit distribution (including any outstanding arrearages). For the quarter ended June 30, 2016, the Series A Preferred unitholders will receive an aggregate cash distribution of $14.1 million comprised of a quarterly per unit distribution prorated for the 77-day period 7,892,220 Series A Preferred units were outstanding during the second quarter of 2016 and a full quarterly per unit distribution on 14,030,611 Series A Preferred units. For the quarter ended March 31, 2016, the Series A Preferred unitholders received an aggregate cash distribution of $1.9 million, based on the quarterly per unit distribution prorated for the 18-day period 14,030,611 Series A Preferred units were outstanding during the first quarter of 2016. See Note 4 for further discussion of the Series A Preferred units.

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

4.  EQUITY AND PARTNERS’ CAPITAL

Equity offerings. Pursuant to the Partnership’s registration statement filed with the SEC in August 2014 authorizing the issuance of up to an aggregate of $500.0 million of common units (“$500.0 million COP”), during the year ended December 31, 2015, the Partnership issued 873,525 common units, at an average price of $66.61, generating proceeds of $57.4 million (net of $0.8 million for the underwriting discount and other offering expenses). Net proceeds were used for general partnership purposes, including funding capital expenditures. Gross proceeds generated during the year ended December 31, 2015, were $58.2 million. Commissions paid during the year ended December 31, 2015, were $0.6 million. The Partnership issued no common units under the $500.0 million COP during the six months ended June 30, 2016.

Class C units. In connection with the closing of the DBM acquisition in November 2014, the Partnership issued 10,913,853 Class C units to AMH at a price of $68.72 per unit, generating proceeds of $750.0 million, pursuant to a Unit Purchase Agreement (“UPA”) with Anadarko and AMH. All outstanding Class C units will convert into common units on a one-for-one basis on December 31, 2017, unless the Partnership elects to convert such units earlier or Anadarko extends the conversion date. The Class C units were issued to partially fund the acquisition of DBM, and the UPA contains an optional redemption feature that provides the Partnership the ability to redeem up to $150.0 million of the Class C units within 10 days of the receipt of cash proceeds from an entity that is not an affiliate of the Partnership or AMH, if these cash proceeds were in relation to (i) the assets of DBM, (ii) the equity interests in DBM or (iii) the equity interests in a subsidiary of the Partnership that owns a majority of the outstanding equity interests in DBM. As of June 30, 2016, no such proceeds had been received, and no Class C units had been redeemed.
The Class C units were issued at a discount to the then-current market price of the common units into which they are convertible. This discount, totaling $34.8 million, represents a beneficial conversion feature, and at issuance, it was reflected as an increase in common unitholders’ capital and a decrease in Class C unitholder capital to reflect the fair value of the Class C units at issuance. The beneficial conversion feature is considered a non-cash distribution that will be recognized from the date of issuance through the date of conversion, resulting in an increase in Class C unitholder capital and a decrease in common unitholders’ capital as amortized. The beneficial conversion feature is amortized assuming a conversion date of December 31, 2017, using the effective yield method. The impact of the beneficial conversion feature amortization is also included in the calculation of earnings per unit.

Series A Preferred units. In connection with the closing of the Springfield acquisition on March 14, 2016, the Partnership issued 14,030,611 Series A Preferred units (the “March 2016 Series A units”) to private investors for a cash purchase price of $32.00 per unit, generating proceeds of $440.0 million (net of fees and expenses, including a 2.0% transaction fee paid to the private investors). In April 2016, the Partnership issued an additional 7,892,220 Series A Preferred units (the “April 2016 Series A units”) pursuant to the full exercise of an option granted in connection with the March 2016 Series A units issuance, generating net proceeds of $246.9 million. The Series A Preferred unitholders may convert the Series A Preferred units into common units on a one-for-one basis at any time after the second anniversary of the issuance date, in whole or in part, subject to certain conversion thresholds. Similarly, the Partnership may convert the Series A Preferred units at any time after the third anniversary of the issuance date, in whole or in part, if the closing price of the Partnership’s common units is greater than $48.00 per common unit for 20 of the 30 preceding trading days, and subject to other certain conversion thresholds. In addition, upon certain events involving a change of control, the Series A Preferred unitholders may elect on an individual basis, subject to certain conditions, to (i) convert their Series A Preferred units to common units at the then applicable conversion rate, (ii) if the Partnership is not the surviving entity (or if the Partnership is the surviving entity, but its common units will cease to be listed), require the Partnership to use commercially reasonable efforts to cause the surviving entity in any such transaction to issue a substantially equivalent security (or convert into common units based on a specified formula, if the Partnership is unable to cause such substantially equivalent securities to be issued), (iii) if the Partnership is the surviving entity, continue to hold their Series A Preferred units, or (iv) require the Partnership to redeem the Series A Preferred units at a price per Series A Preferred unit of $32.32, plus accrued and unpaid distributions to be paid in cash or common units at the discretion of the Partnership.


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

4.  EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

The Series A Preferred unitholders will vote on an as-converted basis with the Partnership’s common unitholders and will have certain other class voting rights with respect to any amendment to the partnership agreement that would adversely affect any rights, preferences or privileges of the Series A Preferred unitholders. In connection with the issuance of the Series A Preferred units, the Partnership entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with the Series A Preferred unit purchasers relating to the registered resale of the common units representing limited partner interests in the Partnership issuable upon conversion of the Series A Preferred units. Pursuant to the Registration Rights Agreement, the Partnership is required to use its commercially reasonable efforts to file and maintain a registration statement for the resale of the converted Series A Preferred units, with such registration statement to become effective no later than March 2018.
The March 2016 Series A units and the April 2016 Series A units were issued at a discount to the then-current market price of the common units into which they are convertible. The discount on the March 2016 Series A units, totaling $21.7 million, represents a beneficial conversion feature, and on the date the Preferred Unit Purchase Agreement was signed (the “commitment date”), it was reflected as an increase in common unitholders’ capital and a decrease in Series A Preferred unitholders’ capital to reflect the fair value of the March 2016 Series A units on the commitment date. The discount on the April 2016 Series A units, totaling $71.7 million, also represents a beneficial conversion feature and on the date the option to purchase additional Series A units was exercised (the “notice date”), it was reflected as an increase in common unitholders’ capital and a decrease in Series A Preferred unitholders’ capital to reflect the fair value of the April 2016 Series A units on the notice date. The beneficial conversion features are considered non-cash distributions that will be recognized from each issuance date through the date of earliest conversion, resulting in an increase in Series A Preferred unitholders’ capital and a decrease in common unitholders’ capital as amortized. The beneficial conversion features are amortized assuming a conversion date of March 14, 2018 for the March 2016 Series A units and a conversion date of April 15, 2018 for the April 2016 Series A units, using the effective yield method.
    
Partnership interests. The Partnership’s common units are listed on the New York Stock Exchange under the symbol “WES.”
The following table summarizes the common, Class C, Series A Preferred and general partner units issued during the six months ended June 30, 2016:
 
 
Common
Units
 
Class C
Units
 
Series A
Preferred
Units
 
General
Partner
Units
 
Total
Balance at December 31, 2015
 
128,576,965

 
11,411,862

 

 
2,583,068

 
142,571,895

PIK Class C units
 

 
534,146

 

 

 
534,146

Springfield acquisition
 
2,089,602

 

 
14,030,611

 

 
16,120,213

April 2016 Series A units
 

 

 
7,892,220

 

 
7,892,220

Long-Term Incentive Plan award vestings
 
5,403

 

 

 

 
5,403

Balance at June 30, 2016
 
130,671,970


11,946,008


21,922,831

 
2,583,068


167,123,877



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

4.  EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

Holdings of Partnership equity. As of June 30, 2016, WGP held 50,132,046 common units, representing a 30.0% 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, 2016, other subsidiaries of Anadarko held 2,011,380 common units and 11,946,008 Class C units, representing an aggregate 8.4% limited partner interest in the Partnership. As of June 30, 2016, the public held 78,528,544 common units, representing a 47.0% limited partner interest in the Partnership and private investors held 21,922,831 Series A Preferred units, representing a 13.1% limited partner interest in the Partnership.

Net income (loss) per unit for common units. Net income (loss) attributable to Western Gas Partners, LP earned on and subsequent to the date of the acquisition of the Partnership assets, net of distributions on the Series A Preferred units and amortization of the Series A Preferred unit beneficial conversion features (see Series A Preferred units above), is allocated to the general partner, the common unitholders and the Class C unitholder, in accordance with their respective weighted-average ownership percentages (exclusive of the Series A Preferred unit limited partnership interest) and, when applicable, giving effect to incentive distributions allocable to the general partner. The allocable limited partners’ interest in net income (loss) is also net of amortization of the beneficial conversion feature related to the Class C units (see Class C units above) and is allocated between the common and Class C unitholders by applying the provisions of the partnership agreement that govern actual cash distributions and capital account allocations, as if all earnings for the period had been distributed. Net income (loss) attributable to the Partnership assets acquired from Anadarko for periods prior to the Partnership’s acquisition of the Partnership assets is not allocated to the limited partners for purposes of calculating net income (loss) per common unit.
Basic net income (loss) per common unit is calculated by dividing the limited partners’ interest in net income (loss) attributable to common unitholders by the weighted-average number of common units outstanding during the period. The common units issued in connection with acquisitions and equity offerings are included on a weighted-average basis for periods they were outstanding. The Series A Preferred units are not considered a participating security as they only have distribution rights up to the specified per-unit quarterly distribution and have no rights to the Partnership’s undistributed earnings. Because the Class C units participate in distributions with common units according to a predetermined formula (see Note 3), they are considered a participating security and are included in the computation of earnings per unit pursuant to the two-class method. The Class C unit participation right results in a non-contingent transfer of value each time the Partnership declares a distribution. Diluted net income (loss) per common unit is calculated by dividing the sum of (i) the limited partners’ interest in net income (loss) attributable to common units adjusted for distributions on the Series A Preferred units and a reallocation of the limited partners’ interest in net income (loss) assuming conversion of the Series A Preferred units into common units, and (ii) the limited partners’ interest in net income (loss) allocable to the Class C units as a participating security, by the sum of the weighted-average number of common units outstanding plus the dilutive effect of (i) the weighted-average number of outstanding Class C units and (ii) the weighted-average number of common units outstanding assuming conversion of the Series A Preferred units.


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

4.  EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

The following table illustrates the Partnership’s calculation of net income (loss) per unit for common units:
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
thousands except per-unit amounts
 
2016
 
2015
 
2016
 
2015
Net income (loss) attributable to Western Gas Partners, LP
 
$
164,521

 
$
132,343

 
$
280,581

 
$
(24,150
)
Pre-acquisition net (income) loss allocated to Anadarko
 

 
(18,719
)
 
(11,326
)
 
(43,758
)
Series A Preferred units interest in net (income) loss (1)
 
(23,121
)
 

 
(25,450
)
 

General partner interest in net (income) loss
 
(58,381
)
 
(45,971
)
 
(113,781
)
 
(83,148
)
Common and Class C limited partners’ interest in net income (loss)
 
$
83,019

 
$
67,653

 
$
130,024

 
$
(151,056
)
Net income (loss) allocable to common units (1)
 
$
71,622

 
$
59,119

 
$
111,184

 
$
(146,139
)
Net income (loss) allocable to Class C units (1)
 
11,397

 
8,534

 
18,840

 
(4,917
)
Common and Class C limited partners’ interest in net income (loss)
 
$
83,019

 
$
67,653

 
$
130,024

 
$
(151,056
)
Net income (loss) per unit
 
 
 
 
 
 
 
 
Common units – basic and diluted (2)
 
$
0.55

 
$
0.46

 
$
0.86

 
$
(1.14
)
Weighted-average units outstanding
 
 
 
 
 
 
 
 
Common units – basic and diluted
 
130,669

 
128,481

 
129,830

 
128,111

Excluded due to anti-dilutive effect:
 
 
 
 
 
 
 
 
Class C units
 
11,849

 
11,023

 
11,719

 
10,981

Series A Preferred units assuming conversion to common units
 
20,709

 

 
11,742

 

                                                                                                                                                                                    
(1) 
Adjusted to reflect amortization of the beneficial conversion features.
(2) 
The impact of Class C units and the conversion of Series A Preferred units would be anti-dilutive.


20

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

5.  TRANSACTIONS WITH AFFILIATES

Affiliate transactions. Revenues from affiliates include amounts earned by the Partnership from services provided to Anadarko as well as from the sale of residue and NGLs to Anadarko. In addition, the Partnership purchases natural gas from an affiliate of Anadarko pursuant to gas purchase agreements. Operation and maintenance expense includes amounts accrued for or paid to affiliates for the operation of the Partnership assets, whether in providing services to affiliates or to third parties, including field labor, measurement and analysis, and other disbursements. A portion of the Partnership’s general and administrative expenses is paid by Anadarko, which results in affiliate transactions pursuant to the reimbursement provisions of the Partnership’s omnibus agreement. Affiliate expenses do not bear a direct relationship to affiliate revenues, and third-party expenses do not bear a direct relationship to third-party revenues. See Note 2 for further information related to contributions of assets to the Partnership by Anadarko.

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

Note receivable - Anadarko and Deferred purchase price obligation - Anadarko. Concurrently with the closing of the Partnership’s May 2008 initial public offering, the Partnership loaned $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%, payable quarterly. The fair value of the note receivable from Anadarko was $301.5 million and $252.3 million at June 30, 2016, and December 31, 2015, respectively. The fair value of the note reflects consideration of credit risk and any premium or discount for the differential between the stated interest rate and quarter-end market interest rate, based on quoted market prices of similar debt instruments. Accordingly, the fair value of the note receivable from Anadarko is measured using Level 2 inputs.
The consideration to be paid by the Partnership to Anadarko for the March 2015 acquisition of DBJV consists of a cash payment due on March 31, 2020. See Note 2 and Note 9.

Commodity price swap agreements. The Partnership has commodity price swap agreements with Anadarko to mitigate exposure to a majority of the commodity price volatility that would otherwise be present as a result of the purchase and sale of natural gas, condensate or NGLs. 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 outstanding commodity price swap agreements for the Hugoton system, MGR assets and DJ Basin complex expire in December 2016. 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.
Below is a summary of the fixed price ranges on all of the Partnership’s outstanding commodity price swap agreements as of June 30, 2016:
per barrel except natural gas
 
2016
Ethane
 
$
18.41

23.11

Propane
 
47.08

52.90

Isobutane
 
62.09

73.89

Normal butane
 
54.62

64.93

Natural gasoline
 
72.88

81.68

Condensate
 
76.47

81.68

Natural gas (per MMBtu)
 
4.87

5.96



21

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

5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

The following table summarizes gains and losses upon settlement of commodity price swap agreements recognized in the consolidated statements of operations:
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
thousands
 
2016
 
2015
 
2016
 
2015
Gains (losses) on commodity price swap agreements related to sales: (1)
 
 
 
 
 

 
 
Natural gas sales
 
$
5,202

 
$
22,344

 
$
12,243

 
$
33,326

Natural gas liquids sales
 
20,480

 
38,297

 
40,550

 
82,729

Total
 
25,682

 
60,641

 
52,793

 
116,055

Losses on commodity price swap agreements related to purchases (2)
 
(16,913
)
 
(41,720
)
 
(35,784
)
 
(75,899
)
Net gains (losses) on commodity price swap agreements
 
$
8,769

 
$
18,921

 
$
17,009

 
$
40,156

                                                                                                                                                                                    
(1) 
Reported in affiliate Natural gas and natural gas liquids sales in the consolidated statements of operations in the period in which the related sale is recorded.
(2) 
Reported in Cost of product in the consolidated statements of operations in the period in which the related purchase is recorded.

DJ Basin complex and Hugoton system swap extensions. On June 25, 2015, the Partnership extended its commodity price swap agreements with Anadarko for the DJ Basin complex from July 1, 2015, through December 31, 2015, and for the Hugoton system from October 1, 2015, through December 31, 2015. The table below summarizes the swap prices for the extension period compared to the forward market prices as of the agreement date, June 25, 2015.
 
 
DJ Basin Complex
 
Hugoton System
per barrel except natural gas
 
2015 Swap Prices
 
Market Prices (1)
 
2015 Swap Prices
 
Market Prices (1)
Ethane
 
$
18.41

 
$
1.96

 
 
Propane
 
47.08

 
13.10

 
 
Isobutane
 
62.09

 
19.75

 
 
Normal butane
 
54.62

 
18.99

 
 
Natural gasoline
 
72.88

 
52.59

 
 
Condensate
 
76.47

 
52.59

 
$
78.61

 
$
32.56

Natural gas (per MMBtu)
 
5.96

 
2.75

 
5.50

 
2.74

                                                                                                                                                                                    
(1) 
Represents the New York Mercantile Exchange (“NYMEX”) forward strip price as of June 25, 2015, adjusted for product specification, location, basis and, in the case of NGLs, transportation and fractionation costs.


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

5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

On December 8, 2015, the commodity price swap agreements with Anadarko for the DJ Basin complex and Hugoton system were further extended from January 1, 2016, through December 31, 2016. The table below summarizes the swap prices for the extension period compared to the forward market prices as of the agreement date, December 8, 2015.
 
 
DJ Basin Complex
 
Hugoton System
per barrel except natural gas
 
2016 Swap Prices
 
Market Prices (1)
 
2016 Swap Prices
 
Market Prices (1)
Ethane
 
$
18.41

 
$
0.60

 
 
Propane
 
47.08

 
10.98

 
 
Isobutane
 
62.09

 
17.23

 
 
Normal butane
 
54.62

 
16.86

 
 
Natural gasoline
 
72.88

 
26.15

 
 
Condensate
 
76.47

 
34.65

 
$
78.61

 
$
18.81

Natural gas (per MMBtu)
 
5.96

 
2.11

 
5.50

 
2.12

                                                                                                                                                                                    
(1) 
Represents the NYMEX forward strip price as of December 8, 2015, adjusted for product specification, location, basis and, in the case of NGLs, transportation and fractionation costs.

Revenues or costs attributable to volumes settled during the respective extension period, at the applicable market price in the above tables, will be recognized in the consolidated statements of operations. The Partnership will also record a capital contribution from Anadarko in the Partnership’s consolidated statement of equity and partners’ capital for the amount by which the swap price exceeds the applicable market price in the above tables. For the six months ended June 30, 2016, the capital contribution from Anadarko was $16.4 million.

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 gathering, treating and transportation throughput (excluding equity investment throughput) attributable to natural gas production owned or controlled by Anadarko was 39% and 38% for the three and six months ended June 30, 2016, respectively, and 56% for the three and six months ended June 30, 2015. The Partnership’s processing throughput (excluding equity investment throughput) attributable to natural gas production owned or controlled by Anadarko was 55% and 58% for the three and six months ended June 30, 2016, respectively, and 52% for the three and six months ended June 30, 2015. The Partnership’s gathering, treating and transportation throughput (excluding equity investment throughput) attributable to crude/NGL production owned or controlled by Anadarko was 64% for the three and six months ended June 30, 2016, and 100% for the three and six months ended June 30, 2015. Prior to January 1, 2016, Springfield’s contracts were with a subsidiary of Anadarko who contracted with third parties. Effective January 1, 2016, Springfield’s contracts are with both a subsidiary of Anadarko and third parties directly.

Commodity purchase and sale agreements. The Partnership sells a significant amount of its natural gas, condensate and NGLs to Anadarko Energy Services Company (“AESC”), Anadarko’s marketing affiliate. In addition, the Partnership purchases natural gas, condensate and NGLs from AESC pursuant to purchase agreements. The Partnership’s purchase and sale agreements with AESC are generally one-year contracts, subject to annual renewal.


23

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

5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

Acquisitions from Anadarko. On March 14, 2016, the Partnership acquired Springfield from Anadarko, and on March 2, 2015, the Partnership acquired DBJV from Anadarko. See Note 2 for further information on these acquisitions.

WES LTIP. The general partner awards phantom units under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (“WES LTIP”) primarily to its independent directors, but 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, 2016 and 2015, and $0.2 million for each of the six months ended June 30, 2016 and 2015.

WGP LTIP and Anadarko Incentive Plans. General and administrative expenses included $1.1 million and $2.4 million for the three and six months ended June 30, 2016, respectively, and $1.0 million and $2.0 million for the three and six months ended June 30, 2015, respectively, of equity-based compensation expense, allocated to the Partnership by Anadarko, for awards granted to the executive officers of the general partner and other employees under the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan (“WGP LTIP”) and the Anadarko Petroleum Corporation 2008 and 2012 Omnibus Incentive Compensation Plans (referred to collectively as the “Anadarko Incentive Plans”). Of this amount, $2.1 million is reflected as a contribution to partners’ capital in the Partnership’s consolidated statement of equity and partners’ capital for the six months ended June 30, 2016.

Equipment purchases and sales. The following table summarizes the Partnership’s purchases from and sales to Anadarko of pipe and equipment:
 
 
Six Months Ended June 30,
 
 
2016
 
2015
 
2016
 
2015
thousands
 
Purchases
 
Sales
Cash consideration
 
$
2,699

 
$
9,056

 
$
613

 
$
700

Net carrying value
 
2,328

 
4,182

 
596

 
366

Partners’ capital adjustment
 
$
371

 
$
4,874

 
$
17

 
$
334



24

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

5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

Summary of affiliate transactions. The following table summarizes material affiliate transactions. See Note 2 for discussion of affiliate acquisitions and related funding.
 
 
Three Months Ended 
 June 30,
 
Six Months Ended 
 June 30,
thousands
 
2016
 
2015
 
2016
 
2015
Revenues and other (1)
 
$
302,405

 
$
321,411

 
$
574,989

 
$
628,339

Equity income, net – affiliates (1)
 
19,693

 
18,941

 
36,507

 
37,161

Cost of product (1)
 
22,145

 
53,062

 
46,725

 
96,957

Operation and maintenance (2)
 
17,661

 
19,854

 
35,636

 
36,671

General and administrative (3)
 
9,169

 
8,060

 
18,121

 
16,195

Operating expenses
 
48,975

 
80,976

 
100,482

 
149,823

Interest income (4)
 
4,225

 
4,225

 
8,450

 
8,450

Interest expense (5)
 
(15,461
)
 
4,190

 
(10,924
)
 
5,610

Proceeds from the issuance of common units, net of offering expenses (6)
 

 

 
25,000

 

Distributions to unitholders (7)
 
94,909

 
76,353

 
184,678

 
148,048

Above-market component of swap extensions with Anadarko
 
9,552

 

 
16,365

 

                                                                                                                                                                                    
(1) 
Represents amounts earned or incurred on and subsequent to the date of acquisition of the Partnership assets, as well as amounts earned or incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets, recognized under gathering, treating or processing agreements, and purchase and sale agreements.
(2) 
Represents expenses incurred on and subsequent to the date of the acquisition of the Partnership assets, as well as expenses incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets.
(3) 
Represents general and administrative expense incurred on and subsequent to the date of the Partnership’s acquisition of the Partnership assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of the Partnership assets by the Partnership. These amounts include equity-based compensation expense allocated to the Partnership by Anadarko (see WES LTIP and WGP LTIP and Anadarko Incentive Plans within this Note 5).
(4) 
Represents interest income recognized on the note receivable from Anadarko.
(5) 
For the three and six months ended June 30, 2016, includes accretion revisions to the Deferred purchase price obligation - Anadarko (see Note 2 and Note 9).
(6) 
Represents proceeds from the issuance of 835,841 common units to WGP as partial funding for the acquisition of Springfield (see Note 2).
(7) 
Represents distributions paid under the partnership agreement (see Note 3 and Note 4).

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


25

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

6.  PROPERTY, PLANT AND EQUIPMENT

A summary of the historical cost of the Partnership’s property, plant and equipment is as follows:
thousands
 
Estimated Useful Life
 
June 30, 2016
 
December 31, 2015
Land
 
n/a
 
$
3,946

 
$
3,744

Gathering systems
 
3 to 47 years
 
6,409,489

 
6,061,004

Pipelines and equipment
 
15 to 45 years
 
135,319

 
136,290

Assets under construction
 
n/a
 
239,617

 
329,887

Other
 
3 to 40 years
 
29,803

 
25,853

Total property, plant and equipment
 
 
 
6,818,174

 
6,556,778

Accumulated depreciation
 
 
 
1,816,030

 
1,697,999

Net property, plant and equipment
 
 
 
$
5,002,144

 
$
4,858,779


The cost of property classified as “Assets under construction” is excluded from capitalized costs being depreciated. These amounts represent property that is not yet suitable to be placed into productive service as of the respective balance sheet date.
As of June 30, 2016, net property, plant and equipment includes impairments of $8.9 million, primarily due to an impairment of $6.1 million at the Newcastle system. This asset was impaired to its estimated fair value of $3.1 million, using the income approach and Level 3 fair value inputs, due to a reduction in estimated future cash flows caused by the low commodity price environment. Also during this period, the Partnership recognized impairments of $2.4 million, primarily related to the abandonment of compressors at the MIGC system.

7.  EQUITY INVESTMENTS

The following table presents the activity in the Partnership’s equity investments for the six months ended June 30, 2016:
 
Equity Investments
thousands
Fort
Union
 
White
Cliffs
 
Rendezvous
 
Mont
Belvieu JV
 
TEG
 
TEP
 
FRP
 
Total
Balance at December 31, 2015
$
17,122

 
$
50,439

 
$
50,913

 
$
117,089

 
$
16,283

 
$
194,803

 
$
172,238

 
$
618,887

Investment earnings (loss), net of amortization
(1,360
)
 
7,164

 
949

 
12,686

 
343

 
7,766

 
8,959

 
36,507

Contributions

 
441

 

 

 

 
(580
)
 

 
(139
)
Distributions

 
(6,873
)
 
(1,364
)
 
(12,303
)
 
(354
)
 
(7,892
)
 
(9,733
)
 
(38,519
)
Distributions in excess of cumulative earnings (1)
(3,354
)
 
(2,100
)
 
(1,541
)
 
(172
)
 
(188
)
 
(2,918
)
 
(338
)
 
(10,611
)
Balance at June 30, 2016
$
12,408

 
$
49,071

 
$
48,957

 
$
117,300

 
$
16,084

 
$
191,179

 
$
171,126

 
$
606,125

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

During the six months ended June 30, 2016, an impairment loss was recognized by the managing partner of Fort Union. The Partnership’s 14.81% share of the impairment loss was $3.0 million, which was recorded in Equity income, net – affiliates in the consolidated statements of operations.


26

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

8.  COMPONENTS OF WORKING CAPITAL

A summary of accounts receivable, net is as follows:
thousands
 
June 30, 2016
 
December 31, 2015
Trade receivables, net
 
$
177,507

 
$
143,557

Other receivables, net
 
44,288

 
49,772

Total accounts receivable, net
 
$
221,795

 
$
193,329


A summary of other current assets is as follows:
thousands
 
June 30, 2016
 
December 31, 2015
Natural gas liquids inventory
 
$
4,032

 
$
2,403

Imbalance receivables
 
1,359

 
2,122

Prepaid insurance
 
300

 
2,296

Other
 

 
1,034

Total other current assets
 
$
5,691

 
$
7,855


A summary of accrued liabilities is as follows:
thousands
 
June 30, 2016
 
December 31, 2015
Accrued capital expenditures
 
$
70,725

 
$
61,454

Accrued plant purchases
 
27,149

 
16,425

Accrued interest expense
 
26,200

 
26,194

Short-term asset retirement obligations
 
2,713

 
3,677

Short-term remediation and reclamation obligations
 
1,136

 
1,136

Income taxes payable
 
1,127

 
770

Other
 
968

 
9,363

Total accrued liabilities
 
$
130,018

 
$
119,019



27

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

9.  DEBT AND INTEREST EXPENSE

At June 30, 2016, the Partnership’s debt consisted of 5.375% Senior Notes due 2021 (the “2021 Notes”), 4.000% Senior Notes due 2022 (the “2022 Notes”), 2.600% Senior Notes due 2018 (the “2018 Notes”), 5.450% Senior Notes due 2044 (the “2044 Notes”), 3.950% Senior Notes due 2025 (the “2025 Notes”), and borrowings on the RCF.
The following table presents the Partnership’s outstanding debt as of June 30, 2016, and December 31, 2015:
 
 
June 30, 2016
 
December 31, 2015
thousands
 
Principal
 
Carrying
Value
 
Fair
Value (1)
 
Principal
 
Carrying
Value
 
Fair
Value