EX-99.3 6 wesex993-springfieldrecast.htm EXHIBIT 99.3 Exhibit

EXHIBIT 99.3

Item 8.  Financial Statements and Supplementary Data

WESTERN GAS PARTNERS, LP

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 




WESTERN GAS PARTNERS, LP

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Unitholders
Western Gas Holdings, LLC (as general partner of Western Gas Partners, LP):

We have audited the accompanying consolidated balance sheets of Western Gas Partners, LP (the Partnership) and subsidiaries as of December 31, 2015 and 2014, and the related consolidated statements of income, equity and partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2015. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Western Gas Partners, LP and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP
Houston, Texas
June 10, 2016


2


WESTERN GAS PARTNERS, LP
CONSOLIDATED STATEMENTS OF INCOME
 
 
Year Ended December 31,
thousands except per-unit amounts
 
2015 (1)
 
2014 (1)
 
2013 (1)
Revenues and other – affiliates
 
 
 
 
 
 
Gathering, processing and transportation
 
$
772,361

 
$
615,907

 
$
449,272

Natural gas, natural gas liquids and drip condensate sales
 
447,106

 
582,989

 
502,219

Other
 
1,172

 
5,078

 
6,421

Total revenues and other – affiliates
 
1,220,639

 
1,203,974

 
957,912

Revenues and other – third parties
 
 
 
 
 
 
Gathering, processing and transportation
 
356,477

 
278,127

 
191,813

Natural gas, natural gas liquids and drip condensate sales
 
170,843

 
42,916

 
46,289

Other
 
4,113

 
8,360

 
4,046

Total revenues and other – third parties
 
531,433

 
329,403

 
242,148

Total revenues and other
 
1,752,072

 
1,533,377

 
1,200,060

Equity income, net (2)
 
71,251

 
57,836

 
22,948

Operating expenses
 
 
 
 
 
 
Cost of product (3)
 
528,369

 
458,379

 
377,626

Operation and maintenance (3)
 
331,972

 
293,710

 
235,971

General and administrative (3)
 
41,319

 
38,561

 
34,766

Property and other taxes
 
33,288

 
28,889

 
26,243

Depreciation and amortization
 
272,611

 
211,809

 
172,863

Impairments
 
515,458

 
5,125

 
49,920

Total operating expenses
 
1,723,017

 
1,036,473

 
897,389

Gain (loss) on divestiture and other, net (4)
 
57,024

 
(9
)
 

Operating income (loss)
 
157,330

 
554,731

 
325,619

Interest income – affiliates
 
16,900

 
16,900

 
16,900

Interest expense (5)
 
(113,872
)
 
(76,766
)
 
(51,797
)
Other income (expense), net
 
(619
)
 
864

 
1,837

Income (loss) before income taxes
 
59,739

 
495,729

 
292,559

Income tax (benefit) expense
 
45,532

 
39,061

 
4,315

Net income (loss)
 
14,207

 
456,668

 
288,244

Net income attributable to noncontrolling interest
 
10,101

 
14,025

 
10,816

Net income (loss) attributable to Western Gas Partners, LP
 
$
4,106

 
$
442,643

 
$
277,428

Limited partners’ interest in net income (loss):
 
 
 
 
 
 
Net income (loss) attributable to Western Gas Partners, LP
 
$
4,106

 
$
442,643

 
$
277,428

Pre-acquisition net (income) loss allocated to Anadarko
 
(79,386
)
 
(65,154
)
 
(6,929
)
General partner interest in net (income) loss (6)
 
(180,996
)
 
(120,980
)
 
(69,633
)
Limited partners’ interest in net income (loss) (6)
 
(256,276
)
 
256,509

 
200,866

Net income (loss) per common unit – basic (7)
 
$
(1.95
)
 
$
2.13

 
$
1.83

Net income (loss) per common unit – diluted (7)
 
(1.95
)
 
2.12

 
1.83

 
                                                                                                                                                                                         
(1) 
Financial information for the year ended December 31, 2015, has been recast to include the financial position and results attributable to the Springfield system, and the financial information for the years ended December 31, 2014 and 2013, has been recast to include the financial position and results attributable to the Springfield and DBJV systems. See Note 1 and Note 2.
(2) 
Income earned from equity investments is classified as affiliate. See Note 1.
(3) 
Cost of product includes product purchases from Anadarko (as defined in Note 1) of $167.4 million, $127.9 million and $136.7 million for the years ended December 31, 2015, 2014 and 2013, respectively. Operation and maintenance includes charges from Anadarko of $77.1 million, $71.4 million and $67.3 million for the years ended December 31, 2015, 2014 and 2013, respectively. General and administrative includes charges from Anadarko of $33.9 million, $31.3 million and $28.4 million for the years ended December 31, 2015, 2014 and 2013, respectively. See Note 5.
(4) 
Includes losses related to an incident at the DBM complex for the year ended December 31, 2015. See Note 1.
(5) 
Includes affiliate (as defined in Note 1) interest expense of $14.4 million for the year ended December 31, 2015, and zero for each of the years ended December 31, 2014 and 2013. See Note 2 and Note 12.
(6) 
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.
(7) 
See Note 4 for the calculation of net income (loss) per common unit.

See accompanying Notes to Consolidated Financial Statements.

3


WESTERN GAS PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
 
 
December 31,
thousands except number of units
 
2015 (1)
 
2014 (1)
ASSETS
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
 
$
98,033

 
$
67,054

Accounts receivable, net (2)
 
193,329

 
122,767

Other current assets (3)
 
7,855

 
10,053

Total current assets
 
299,217

 
199,874

Note receivable – Anadarko
 
260,000

 
260,000

Property, plant and equipment
 
 
 
 
Cost
 
6,556,778

 
6,248,577

Less accumulated depreciation
 
1,697,999

 
1,110,722

Net property, plant and equipment
 
4,858,779

 
5,137,855

Goodwill
 
419,186

 
418,587

Other intangible assets
 
832,127

 
884,857

Equity investments
 
618,887

 
634,492

Other assets
 
29,707

 
28,289

Total assets
 
$
7,317,903

 
$
7,563,954

LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
 
 
 
 
Current liabilities
 
 
 
 
Accounts and imbalance payables (4)
 
$
98,661

 
$
89,916

Accrued ad valorem taxes
 
17,808

 
15,043

Accrued liabilities
 
119,019

 
177,120

Total current liabilities
 
235,488

 
282,079

Long-term debt
 
2,707,357

 
2,422,954

Deferred income taxes
 
139,704

 
169,915

Asset retirement obligations and other
 
128,652

 
120,544

Deferred purchase price obligation – Anadarko (5)
 
188,674

 

Total long-term liabilities
 
3,164,387

 
2,713,413

Total liabilities
 
3,399,875

 
2,995,492

Equity and partners’ capital
 
 
 
 
Common units (128,576,965 and 127,695,130 units issued and outstanding at December 31, 2015 and 2014, respectively)
 
2,588,991

 
3,119,714

Class C units (11,411,862 and 10,913,853 units issued and outstanding at December 31, 2015 and 2014, respectively)
 
710,891

 
716,957

General partner units (2,583,068 units issued and outstanding at December 31, 2015 and 2014)
 
120,164

 
105,725

Net investment by Anadarko
 
430,598

 
556,596

Total partners’ capital
 
3,850,644

 
4,498,992

Noncontrolling interest
 
67,384

 
69,470

Total equity and partners’ capital
 
3,918,028

 
4,568,462

Total liabilities, equity and partners’ capital
 
$
7,317,903

 
$
7,563,954

                                                                                                                                                                                    
(1) 
Financial information as of December 31, 2015, has been recast to include the financial position and results attributable to the Springfield system, and the financial information as of December 31, 2014, has been recast to include the financial position and results attributable to the Springfield and DBJV systems. See Note 1 and Note 2.
(2) 
Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $42.7 million and $64.7 million as of December 31, 2015 and 2014, respectively. Accounts receivable, net as of December 31, 2015, also includes an insurance claim receivable related to an incident at the DBM complex. See Note 1.
(3) 
Other current assets includes imbalance receivables from affiliates of zero and $0.2 million as of December 31, 2015 and 2014, respectively.
(4) 
Accounts and imbalance payables includes amounts payable to affiliates of zero and $0.1 million as of December 31, 2015 and 2014, respectively.
(5) 
See Note 2.

See accompanying Notes to Consolidated Financial Statements.

4


WESTERN GAS PARTNERS, LP
CONSOLIDATED STATEMENTS OF EQUITY AND PARTNERS’ CAPITAL
 
 
Partners’ Capital
 
 
 
 
thousands
 
Net
Investment
by Anadarko
 
Common
Units
 
Class C
Units
 
General
Partner 
Units
 
Noncontrolling
Interest
 
Total
Balance at December 31, 2012 (1)
 
$
784,876

 
$
1,957,066

 
$

 
$
52,752

 
$
70,658

 
$
2,865,352

Net income (loss)
 
6,929

 
200,866

 

 
69,633

 
10,816

 
288,244

Issuance of common and general partner units, net of offering expenses
 

 
724,811

 

 
15,775

 

 
740,586

Contributions from noncontrolling interest owner
 

 

 

 

 
2,247

 
2,247

Distributions to noncontrolling interest owner
 

 

 

 

 
(13,127
)
 
(13,127
)
Distributions to unitholders
 

 
(239,157
)
 

 
(59,944
)
 

 
(299,101
)
Acquisitions from affiliates
 
(255,635
)
 
(209,865
)
 

 

 

 
(465,500
)
Contributions of equity-based compensation from Anadarko (2)
 

 
2,865

 

 
58

 

 
2,923

Net pre-acquisition contributions from (distributions to) Anadarko (3)
 
260,031

 

 

 

 

 
260,031

Net distributions to Anadarko of other assets
 

 
(5,738
)
 

 
(117
)
 

 
(5,855
)
Elimination of net deferred tax liabilities
 
46,530

 

 

 

 

 
46,530

Other
 

 
345

 

 

 

 
345

Balance at December 31, 2013 (1)
 
$
842,731

 
$
2,431,193

 
$

 
$
78,157

 
$
70,594

 
$
3,422,675

Net income (loss)
 
65,154

 
254,737

 
1,772

 
120,980

 
14,025

 
456,668

Issuance of common and general partner units, net of offering expenses
 

 
691,417

 

 
13,311

 

 
704,728

Issuance of Class C units
 

 

 
750,000

 

 

 
750,000

Beneficial conversion feature of Class C units
 

 
34,815

 
(34,815
)
 

 

 

Distributions to noncontrolling interest owner
 

 

 

 

 
(15,149
)
 
(15,149
)
Distributions to unitholders
 

 
(302,049
)
 

 
(106,572
)
 

 
(408,621
)
Acquisitions from affiliates
 
(372,784
)
 
16,534

 

 

 

 
(356,250
)
Contributions of equity-based compensation from Anadarko (2)
 

 
3,104

 

 
63

 

 
3,167

Net pre-acquisition contributions from (distributions to) Anadarko (3)
 
(16,692
)
 

 

 

 

 
(16,692
)
Net distributions to Anadarko of other assets
 

 
(10,492
)
 

 
(214
)
 

 
(10,706
)
Elimination of net deferred tax liabilities
 
38,160

 

 

 

 

 
38,160

Other
 
27

 
455

 

 

 

 
482

Balance at December 31, 2014 (1)
 
$
556,596

 
$
3,119,714

 
$
716,957

 
$
105,725

 
$
69,470

 
$
4,568,462

Net income (loss)
 
79,386

 
(238,166
)
 
(18,110
)
 
180,996

 
10,101

 
14,207

Above-market component of swap extensions with Anadarko (4)
 

 
18,449

 

 

 

 
18,449

Issuance of common units, net of offering expenses
 

 
57,353

 

 

 

 
57,353

Amortization of beneficial conversion feature of Class C units
 

 
(12,044
)
 
12,044

 

 

 

Distributions to noncontrolling interest owner
 

 

 

 

 
(12,187
)
 
(12,187
)
Distributions to unitholders
 

 
(378,602
)
 

 
(166,541
)
 

 
(545,143
)
Acquisitions from affiliates
 
(197,562
)
 
23,286

 

 

 

 
(174,276
)
Contributions of equity-based compensation from Anadarko (2)
 

 
3,480

 

 
71

 

 
3,551

Net pre-acquisition contributions from (distributions to) Anadarko
 
(49,801
)
 

 

 

 

 
(49,801
)
Net distributions to Anadarko of other assets
 

 
(4,547
)
 

 
(85
)
 

 
(4,632
)
Elimination of net deferred tax liabilities
 
41,844

 

 

 

 

 
41,844

Other
 
135

 
68

 

 
(2
)
 

 
201

Balance at December 31, 2015 (1)
 
$
430,598

 
$
2,588,991

 
$
710,891

 
$
120,164

 
$
67,384

 
$
3,918,028

                                                                                                                                                                                    
(1) 
Financial information as of December 31, 2015, has been recast to include the financial position and results attributable to the Springfield system, and the financial information as of December 31, 2014, 2013 and 2012, has been recast to include the financial position and results attributable to the Springfield and DBJV systems. See Note 1 and Note 2.
(2) 
Associated with the Anadarko Incentive Plans as defined and described in Note 1 and Note 5.
(3) 
Includes deferred taxes on capitalized interest of $0.3 million and $5.5 million associated with the acquisition of the TEFR Interests (as defined and described in Note 1) for the years ended December 31, 2014 and 2013, respectively.
(4) 
See Note 5.

See accompanying Notes to Consolidated Financial Statements.

5


WESTERN GAS PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
Year Ended December 31,
thousands
 
2015 (1)
 
2014 (1)
 
2013 (1)
Cash flows from operating activities
 
 
 
 
 
 
Net income (loss)
 
$
14,207

 
$
456,668

 
$
288,244

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
 
 
 
Depreciation and amortization
 
272,611

 
211,809

 
172,863

Impairments
 
515,458

 
5,125

 
49,920

Non-cash equity-based compensation expense
 
4,188

 
3,920

 
3,521

Deferred income taxes
 
11,346

 
38,682

 
66,246

Accretion and amortization of long-term obligations, net
 
17,698

 
2,736

 
2,449

Equity income, net (2)
 
(71,251
)
 
(57,836
)
 
(22,948
)
Distributions from equity investment earnings (2)
 
82,054

 
62,967

 
17,698

(Gain) loss on divestiture and other, net (3)
 
(57,024
)
 
9

 

Lower of cost or market inventory adjustments
 
443

 

 

Changes in assets and liabilities:
 
 
 
 
 
 
(Increase) decrease in accounts receivable, net
 
(4,371
)
 
1,399

 
(8,929
)
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net
 
1,006

 
(34,980
)
 
34,319

Change in other items, net
 
(720
)
 
3,996

 
(2,048
)
Net cash provided by operating activities
 
785,645


694,495


601,335

Cash flows from investing activities
 
 
 
 
 
 
Capital expenditures
 
(637,964
)
 
(805,005
)
 
(852,388
)
Contributions in aid of construction costs from affiliates
 
461

 
183

 
617

Acquisitions from affiliates
 
(10,903
)
 
(379,193
)
 
(476,711
)
Acquisitions from third parties
 
(3,514
)
 
(1,523,327
)
 
(240,274
)
Investments in equity affiliates
 
(11,442
)
 
(64,278
)
 
(294,693
)
Distributions from equity investments in excess of cumulative earnings (2)
 
16,244

 
18,055

 
4,438

Proceeds from the sale of assets to affiliates
 
925

 
402

 
85

Proceeds from the sale of assets to third parties
 
145,916

 
12,988

 
14

Net cash used in investing activities
 
(500,277
)

(2,740,175
)

(1,858,912
)
Cash flows from financing activities
 
 
 
 
 
 
Borrowings, net of debt issuance costs
 
889,606

 
1,646,878

 
957,503

Repayments of debt
 
(610,000
)
 
(650,000
)
 
(710,000
)
Increase (decrease) in outstanding checks
 
(2,666
)
 
765

 
(5,543
)
Proceeds from the issuance of common and general partner units, net of offering expenses
 
57,353

 
704,489

 
740,825

Proceeds from the issuance of Class C units
 

 
750,000

 

Distributions to unitholders (4)
 
(545,143
)
 
(408,621
)
 
(299,101
)
Contributions from noncontrolling interest owner
 

 

 
2,247

Distributions to noncontrolling interest owner
 
(12,187
)
 
(15,149
)
 
(13,127
)
Net contributions from Anadarko
 
(49,801
)
 
(16,392
)
 
265,520

Above-market component of swap extensions with Anadarko (4)
 
18,449

 

 

Net cash provided by (used in) financing activities
 
(254,389
)

2,011,970


938,324

Net increase (decrease) in cash and cash equivalents
 
30,979


(33,710
)

(319,253
)
Cash and cash equivalents at beginning of period
 
67,054

 
100,764

 
420,017

Cash and cash equivalents at end of period
 
$
98,033


$
67,054


$
100,764

Supplemental disclosures
 
 
 
 
 
 
Acquisition of DBJV from Anadarko
 
$
174,276

 
$

 
$

Net distributions to (contributions from) Anadarko of other assets
 
4,632

 
10,706

 
5,855

Interest paid, net of capitalized interest
 
94,720

 
67,648

 
47,098

Taxes paid (reimbursements received)
 

 
(90
)
 
552

Capital lease asset transfer (5)
 

 
4,833

 

                                                                                                                                                                                    
(1) 
Financial information for the year ended December 31, 2015, has been recast to include the financial position and results attributable to the Springfield system, and the financial information for the years ended December 31, 2014 and 2013, has been recast to include the financial position and results attributable to the Springfield and DBJV systems. See Note 1 and Note 2.
(2) 
Income earned on, distributions from and contributions to equity investments are classified as affiliate. See Note 1.
(3) 
Includes losses related to an incident at the DBM complex for the year ended December 31, 2015. See Note 1.
(4) 
See Note 5.
(5) 
For the year ended December 31, 2014, represents transfers of $4.6 million from other long-term assets associated with the capital lease component of a processing agreement. See Note 7.

See accompanying Notes to Consolidated Financial Statements.

6


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General. Western Gas Partners, LP is a growth-oriented Delaware master limited partnership 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” or “GP”), is owned by Western Gas Equity Partners, LP (“WGP”), a Delaware master limited partnership 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). 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, and includes 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.” “Equity investment throughput” refers to the Partnership’s 14.81% share of average Fort Union throughput and 22% share of average Rendezvous throughput, but excludes throughput measured in barrels, consisting of the Partnership’s 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. The “DJ Basin complex” refers to the Platte Valley system, Wattenberg system and Lancaster plant, all of which were combined into a single complex in the first quarter of 2014. The “MGR assets” include the Red Desert complex, the Granger straddle plant and the 22% 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 December 31, 2015, the Partnership’s assets, including the Springfield system, and investments accounted for under the equity method (see Basis of presentation and Presentation of Partnership assets below) consisted of the following:
 
 
Owned and
Operated
 
Operated
Interests
 
Non-Operated
Interests
 
Equity
Interests
Gathering systems
 
12

 
4

 
5

 
2

Treating facilities
 
12

 
7

 

 
3

Natural gas processing plants/trains (1)
 
18

 
5

 

 
2

NGL pipelines
 
2

 

 

 
3

Natural gas pipelines
 
4

 

 

 

Oil pipelines
 

 
1

 

 
1

                                                                                                                                                                                    
(1) 
On December 3, 2015, an incident occurred at the DBM complex. See Note 7.

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 June 2015, the Partnership completed the construction and commenced operations of Lancaster Train II, a processing plant located within the DJ Basin complex. In addition, the Partnership is constructing Trains IV and V, both processing plants, at the DBM complex (see Note 2), with operations expected to commence during the first half (Train IV) and second half (Train V) of 2016. The Partnership has also made progress payments towards the construction of another cryogenic unit at our DBM complex (Train VI), with an expected in-service date of mid-2017.


7


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Western Gas Equity Partners, LP. WGP owns the following types of interests in the Partnership: (i) the general partner interest and all of the incentive distribution rights (“IDRs”) in the Partnership, both owned through WGP’s 100% ownership of the Partnership’s general partner and (ii) a significant limited partner interest (see Holdings of Partnership equity in Note 4). WGP has no independent operations or material assets other than owning such partnership interests.

Basis of presentation. 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. 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.
Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. The Partnership proportionately consolidates its share of the assets, liabilities, revenues and expenses attributable to the following systems: (i) 33.75% interests attributable to the Non-Operated Marcellus Interest systems and Anadarko-Operated Marcellus Interest systems, (ii) 50% interests attributable to the Newcastle system and the DBJV system (see Note 2) and (iii) 50.1% interest attributable to the Springfield system (as defined in Note 2) in the accompanying consolidated financial statements. The 25% membership interest in Chipeta Processing LLC (“Chipeta”) held by a third-party member is reflected within noncontrolling interest in the consolidated financial statements for all periods presented.

Adjustments to previously issued financial statements. The Partnership’s consolidated statements of income reflect adjustments for the following amounts, which previously reduced Operation and maintenance expense, to revenues related to Gathering, processing and transportation: (i) $25.0 million for the year ended December 31, 2015 (all of which relates to the six months ended June 30, 2015) and (ii) $39.3 million and $20.5 million for the years ended December 31, 2014 and 2013, respectively. Management determined that the third-party producer reimbursements received for electricity purchased by the Partnership are more appropriately classified as revenues, instead of a reduction to Operation and maintenance expense. This correction of an error has no impact to Net income (loss), cash flows, or any non-GAAP metric the Partnership uses to evaluate its operations and is not considered material to the Partnership’s results of operations for the years ended December 31, 2015, 2014 and 2013. The Partnership has revised its previously reported 2013, 2014 and 2015 consolidated financial statements, and unaudited interim periods therein as applicable, to reflect the reclassification.

Presentation of Partnership assets. The term “Partnership assets” refers to the assets owned, including the Springfield system (as defined in Note 2), and interests accounted for under the equity method (see Note 9) by the Partnership as of December 31, 2015. Because Anadarko controls the Partnership through its ownership and control of WGP, which owns the Partnership’s entire general partner interest, each acquisition of Partnership assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by the Partnership. Further, after an acquisition of Partnership assets from Anadarko, the Partnership may be required to recast its financial statements to include the activities of such Partnership assets from the date of common control. See Note 2.
For those periods requiring recast, the consolidated financial statements for periods prior to the Partnership’s acquisition of the Partnership assets from Anadarko have been prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the Partnership assets during the periods reported. Net income (loss) attributable to the Partnership assets acquired from Anadarko for periods prior to the Partnership’s acquisition of the Partnership assets is not allocated to the limited partners.

Use of estimates. 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 under the particular circumstances. 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.

8


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Fair value. The fair-value-measurement standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which they are observable. The three levels of the fair value hierarchy are as follows:

Level 1 – Inputs represent unadjusted quoted prices in active markets for identical assets or liabilities.

Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).

Level 3 – Inputs that are not observable from objective sources, such as management’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in management’s internally developed present value of future cash flows model that underlies the fair value measurement).

Nonfinancial assets and liabilities initially measured at fair value include certain assets and liabilities acquired in a third-party business combination, assets and liabilities exchanged in non-monetary transactions, long-lived assets (asset groups), goodwill and other intangibles, initial recognition of asset retirement obligations, and initial recognition of environmental obligations assumed in a third-party acquisition. Impairment analyses for long-lived assets, goodwill and other intangibles, and the initial recognition of asset retirement obligations and environmental obligations use Level 3 inputs. When the Partnership is required to measure fair value and there is not a market-observable price for the asset or liability or a market-observable price for a similar asset or liability, the Partnership uses the cost, income, or market valuation approach depending on the quality of information available to support management’s assumptions.
The fair value of debt reflects any premium or discount for the difference between the stated interest rate and the quarter-end market interest rate, and is based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments. See Note 12.
The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable reported on the consolidated balance sheets approximate fair value due to the short-term nature of these items.

Cash equivalents. The Partnership considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.

Bad-debt reserve. The Partnership’s revenues are primarily from Anadarko, for which no credit limit is maintained. The Partnership analyzes its exposure to bad debts on a customer-by-customer basis for its third-party accounts receivable and may establish credit limits for significant third-party customers. As of December 31, 2015 and 2014, the Partnership’s bad-debt reserve was immaterial.

Imbalances. The consolidated balance sheets include imbalance receivables and payables resulting from differences in volumes received into the Partnership’s systems and volumes delivered by the Partnership to customers’ pipelines. Volumes owed to or by the Partnership that are subject to monthly cash settlement are valued according to the terms of the contract as of the balance sheet dates and reflect market index prices. Other volumes owed to or by the Partnership are valued at the Partnership’s weighted-average cost as of the balance sheet dates and are settled in-kind. As of December 31, 2015, imbalance receivables and payables were $2.1 million and $1.6 million, respectively. As of December 31, 2014, imbalance receivables and payables were $0.4 million and $0.7 million, respectively. Net changes in imbalance payables and receivables are reported in cost of product.


9


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Inventory. The cost of NGLs inventories is determined by the weighted-average cost method on a location-by-location basis. Inventory is stated at the lower of weighted-average cost or market value and is reported in other current assets in the consolidated balance sheets. See Note 10.

Property, plant and equipment. Property, plant and equipment are generally stated at the lower of historical cost less accumulated depreciation or fair value, if impaired. Because acquisitions of assets from Anadarko are transfers of net assets between entities under common control, the assets acquired from Anadarko are initially recorded at Anadarko’s historic carrying value. The difference between the carrying value of net assets acquired from Anadarko and the consideration paid is recorded as an adjustment to partners’ capital.
Assets acquired in a business combination or non-monetary exchange with a third party are initially recorded at fair value. All construction-related direct labor and material costs are capitalized. The cost of renewals and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects that do not extend the useful life or increase the expected output of property, plant and equipment is expensed as incurred.
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 income as a component of Operating income (loss). In December 2015, there was an initial fire and secondary explosion at the DBM complex. See Note 7. For the year ended December 31, 2015, the Partnership has recorded $20.3 million of losses in Gain (loss) on divestiture and other, net in the consolidated statements of income, related to this involuntary conversion event based on the difference between the net book value of the affected assets and the insurance claim receivable of $48.5 million.
Depreciation is computed using the straight-line method based on estimated useful lives and salvage values of assets. However, subsequent events could cause a change in estimates, thereby impacting future depreciation amounts. Uncertainties that may impact these estimates include, but are not limited to, changes in laws and regulations relating to environmental matters, including air and water quality, restoration and abandonment requirements, economic conditions, and supply and demand in the area.
Management evaluates the ability to recover the carrying amount of its long-lived assets to determine whether its long-lived assets have been impaired. Impairments exist when the carrying amount of an asset exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the long-lived asset is not recoverable based on the estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying amount over its estimated fair value, such that the asset’s carrying amount is adjusted to its estimated fair value with an offsetting charge to impairment expense. Refer to Note 7 for a description of impairments recorded during the years ended December 31, 2015, 2014 and 2013.


10


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Capitalized interest. Interest is capitalized as part of the historical cost of constructing assets for significant projects that are in progress. Capitalized interest is determined by multiplying the Partnership’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once the construction of an asset subject to interest capitalization is completed and the asset is placed in service, the associated capitalized interest is expensed through depreciation or impairment, together with other capitalized costs related to that asset.

Goodwill. Goodwill is recorded when the purchase price of a business acquired exceeds the fair market value of the tangible and separately measurable intangible net assets. Refer to Note 8 for a discussion of goodwill. The Partnership evaluates goodwill for impairment annually, as of October 1, or more often as facts and circumstances warrant. The Partnership has allocated goodwill on its two reporting units: (i) gathering and processing and (ii) transportation. An initial qualitative assessment is performed prior to proceeding to the comparison of the fair value of each reporting unit to which goodwill has been assigned, to the carrying amount of net assets, including goodwill, of each reporting unit. If the Partnership concludes, based on qualitative factors, that it is more likely than not that the fair value of the reporting unit exceeds its carrying amount, then goodwill is not impaired, and estimating the fair value of the reporting unit is not necessary. If the carrying amount of the reporting unit exceeds its fair value, based on a hypothetical purchase price allocation, goodwill is written down to its implied fair value through a charge to operating expense. The carrying value of goodwill after such an impairment would represent a Level 3 fair value measurement.

Other intangible assets. The Partnership assesses intangible assets, as described in Note 8, for impairment together with related underlying long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. See Property, plant and equipment within this Note 1 for further discussion of management’s process to evaluate potential impairment of long-lived assets.

Asset retirement obligations. Management recognizes a liability based on the estimated costs of retiring tangible long-lived assets. The liability is recognized at fair value, measured using discounted expected future cash outflows for the asset retirement obligation when the obligation originates, which generally is when an asset is acquired or constructed. The carrying amount of the associated asset is increased commensurate with the liability recognized. Over time, the discounted liability is adjusted to its expected settlement value through accretion expense, which is reported within depreciation and amortization in the consolidated statements of income. Subsequent to the initial recognition, the liability is also adjusted for any changes in the expected value of the retirement obligation (with a corresponding adjustment to property, plant and equipment) until the obligation is settled. Revisions in estimated asset retirement obligations may result from changes in estimated inflation rates, discount rates, asset retirement costs and the estimated timing of settling asset retirement obligations. See Note 11.

Environmental expenditures. The Partnership expenses environmental obligations related to conditions caused by past operations that do not generate current or future revenues. Environmental obligations related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Liabilities are recorded when the necessity for environmental remediation or other potential environmental liabilities becomes probable and the costs can be reasonably estimated. Accruals for estimated losses from environmental remediation obligations are recognized no later than at the time of the completion of the remediation feasibility study. These accruals are adjusted as additional information becomes available or as circumstances change. Costs of future expenditures for environmental-remediation obligations are not discounted to their present value. See Note 13.


11


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Segments. The Partnership’s operations are organized into a single operating segment, the assets of which gather, process, compress, treat and transport Anadarko and third-party natural gas, condensate, NGLs and crude oil in the United States.

Revenues and cost of product. Under its fee-based gathering, treating and processing arrangements, the Partnership is paid a fixed fee based on the volume and thermal content of natural gas and recognizes revenues for its services in the month such services are performed. Producers’ wells are connected to the Partnership’s gathering systems for delivery of natural gas to the Partnership’s processing or treating plants, where the natural gas is processed to extract NGLs and condensate or treated in order to satisfy pipeline specifications. In some areas, where no processing is required, the producers’ gas is gathered and delivered to pipelines for market delivery. Under cost-of-service gathering agreements, the Partnership earns fees for gathering and compression services based on rates calculated in a cost-of-service model and reviewed periodically over the life of the agreements. Under percent-of-proceeds contracts, revenue is recognized when the natural gas, NGLs or condensate is sold. The percentage of the product sale ultimately paid to the producer is recorded as a related cost of product expense.
The Partnership purchases natural gas volumes at the wellhead for gathering and processing. As a result, the Partnership has volumes of NGLs and condensate to sell and volumes of residue to either sell, to use for system fuel or to satisfy keep-whole obligations. In addition, depending upon specific contract terms, condensate and NGLs recovered during gathering and processing are either returned to the producer or retained and sold. Under keep-whole contracts, when condensate or NGLs are retained and sold, producers are kept whole for the condensate or NGL volumes through the receipt of a thermally equivalent volume of residue. The keep-whole contract conveys an economic benefit to the Partnership when the combined value of the individual NGLs is greater in the form of liquids than as a component of the natural gas stream; however, the Partnership is adversely impacted when the value of the NGLs is lower than the value of the natural gas stream including the liquids. The Partnership has commodity price swap agreements with Anadarko to mitigate exposure to a majority of the commodity price uncertainty that would otherwise be present as a result of the purchase and sale of natural gas, condensate or NGLs. See Note 5. Revenue is recognized from the sale of condensate and NGLs upon transfer of title, and related purchases are recorded as cost of product.
The Partnership earns transportation revenues through firm contracts that obligate each of its customers to pay a monthly reservation or demand charge regardless of the pipeline capacity used by that customer. An additional commodity usage fee is charged to the customer based on the actual volume of natural gas transported. Transportation revenues are also generated from interruptible contracts pursuant to which a fee is charged to the customer based on volumes transported through the pipeline. Revenues for transportation of natural gas and NGLs are recognized over the period of firm transportation contracts or, in the case of usage fees and interruptible contracts, when the volumes are received into the pipeline. From time to time, certain revenues may be subject to refund pending the outcome of rate matters before the Federal Energy Regulatory Commission (the “FERC”), and refund reserve liabilities are established where appropriate.
Proceeds from the sale of residue, NGLs and condensate are reported as revenues from natural gas, natural gas liquids and condensate sales in the consolidated statements of income. Revenues attributable to the fixed-fee component of gathering and processing contracts as well as demand charges and commodity usage fees on transportation contracts are reported as revenues from gathering, processing and transportation in the consolidated statements of income.


12


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Equity-based compensation. Phantom unit awards are granted under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (the “WES LTIP”). The WES LTIP was adopted by the general partner of the Partnership and permits the issuance of up to 2,250,000 units, of which 2,128,015 units remained available for future issuance as of December 31, 2015. Upon vesting of each phantom unit awarded under the WES LTIP, the holder will receive common units of the Partnership or, at the discretion of the general partner’s Board of Directors, cash in an amount equal to the market value of common units of the Partnership on the vesting date. Equity-based compensation expense attributable to grants made under the WES LTIP impacts the Partnership’s cash flows from operating activities only to the extent cash payments are made to a participant in lieu of issuance of common units to the participant. The Partnership amortizes stock-based compensation expense attributable to awards granted under the WES LTIP over the vesting periods applicable to the awards.
Additionally, the Partnership’s general and administrative expenses include equity-based compensation costs allocated by Anadarko to the Partnership for grants made pursuant to (i) the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan (the “WGP LTIP”) for the years ended December 31, 2015 and 2014 and (ii) the Anadarko Petroleum Corporation 2008 and 2012 Omnibus Incentive Compensation Plans (Anadarko’s plans are referred to collectively as the “Anadarko Incentive Plans”) for all periods presented. Grants made under equity-based compensation plans result in equity-based compensation expense, which is determined by reference to the fair value of equity compensation. For equity-based awards ultimately settled through the issuance of units or stock, the fair value is measured as of the date of the relevant equity grant. Equity-based compensation granted under the WGP LTIP and the Anadarko Incentive Plans does not impact the Partnership’s cash flows from operating activities since the offset to compensation expense is recorded as a contribution to partners’ capital in the consolidated financial statements at the time of contribution, when the expense is realized.

Income taxes. The Partnership generally is not subject to federal income tax or state income tax other than Texas margin tax on the portion of its income that is apportionable to Texas. Deferred state income taxes are recorded on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. The Partnership routinely assesses the realizability of its deferred tax assets. If the Partnership concludes that it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Federal and state current and deferred income tax expense was recorded on the Partnership assets prior to the Partnership’s acquisition of these assets from Anadarko.
For periods beginning on and subsequent to the Partnership’s acquisition of the Partnership assets, the Partnership makes payments to Anadarko pursuant to the tax sharing agreement entered into between Anadarko and the Partnership for its estimated share of taxes from all forms of taxation, excluding taxes imposed by the United States, that are included in any combined or consolidated returns filed by Anadarko. The aggregate difference in the basis of the Partnership’s assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each partner’s tax attributes in the Partnership.
The accounting standards for uncertain tax positions defines the criteria an individual tax position must satisfy for any part of the benefit of that position to be recognized in the financial statements. The Partnership had no material uncertain tax positions at December 31, 2015 or 2014.
With respect to assets acquired from Anadarko, the Partnership recorded Anadarko’s historic deferred income taxes for the periods prior to the Partnership’s ownership of the assets. For periods subsequent to the Partnership’s acquisition, the Partnership is not subject to tax except for the Texas margin tax and, accordingly, does not record deferred federal income taxes related to the assets acquired from Anadarko.


13


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Net income (loss) per common unit. The Partnership applies the two-class method in determining net income (loss) per unit applicable to master limited partnerships having multiple classes of securities including common units, Class C units, general partner units and IDRs. The two-class method is an earnings allocation formula that treats participating securities as having rights to earnings that otherwise would have been available to common unitholders. Under the two-class method, net income (loss) per unit is calculated as if all of the earnings for the period were distributed pursuant to the terms of the relevant contractual arrangement. The accounting guidance provides the methodology for and circumstances under which undistributed earnings are allocated to the general partner, limited partners and IDR holders. For the Partnership, earnings per unit is calculated based on the assumption that the Partnership distributes to its unitholders an amount of cash equal to the net income of the Partnership, notwithstanding the general partner’s ultimate discretion over the amount of cash to be distributed for the period, the existence of other legal or contractual limitations that would prevent distributions of all of the net income for the period or any other economic or practical limitation on the ability to make a full distribution of all of the net income for the period.
The Partnership’s net income (loss) earned on and subsequent to the date of the acquisition of the Partnership assets is allocated to the general partner and the limited partners, including the Class C unitholder, in accordance with their respective weighted-average ownership percentages and, when applicable, giving effect to incentive distributions allocable to the general partner. Specifically, net income equal to the amount of available cash (as defined by the Amended and Restated Agreement of Limited Partnership of the Partnership (the “partnership agreement”)) is allocated to the general partner, common and Class C unitholders consistent with actual cash distributions and capital account allocations, including incentive distributions allocable to the general partner. Undistributed earnings (net income in excess of distributions) or undistributed losses (available cash in excess of net income) are then allocated to the general partner, common unitholders and the Class C unitholder in accordance with their respective weighted-average ownership percentages during each period. Additionally, the Partnership’s net income (loss) allocable to the common unitholders is net of amortization of the beneficial conversion feature related to the Class C units (see Class C units in Note 4). 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. See Note 4.

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. These cash receipts are presented as “Contributions in aid of construction costs from affiliates” within the investing section of the Partnership’s consolidated statements of cash flows. See Note 5.

Recently issued accounting standards. The Financial Accounting Standards Board recently issued the following Accounting Standards Updates (“ASUs”):
ASU 2015-17, Income Taxes (Topic - 740)—Balance Sheet Classification of Deferred Taxes. This ASU requires all deferred tax assets and liabilities, including any related valuation allowance, to be presented in the balance sheet as noncurrent. The early adoption of this ASU using a retrospective approach had no material impact on the Partnership’s consolidated financial statements. See Note 6.


14


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

ASU 2015-06, Earnings Per Share (Topic - 260)—Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions. This ASU contains guidance that addresses the historical earnings per unit presentation for master limited partnerships that apply the two-class method of calculating earnings per unit. When a general partner transfers or “drops down” net assets to a master limited partnership, 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. This ASU is effective for annual and interim periods beginning in 2016 and is required to be adopted using a retrospective approach, with early adoption permitted. While the Partnership believes it is currently in compliance with this ASU, it continues to evaluate the impact of the adoption of this ASU on its consolidated financial statements.
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 will result in a reclassification that will reduce Other assets and Long-term debt by $16.7 million on the Partnership’s consolidated balance sheet at December 31, 2015, when included in future filings.
ASU 2015-02, Consolidation—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. This ASU is effective for annual and interim periods beginning in 2016 and is required to be adopted using a retrospective or modified retrospective approach, with early adoption permitted. The Partnership has 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 purposes. The adoption of this ASU will not have a material impact on the Partnership’s consolidated financial statements.
ASU 2014-09, Revenue from Contracts with Customers. This ASU supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. 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.


15


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


2.  ACQUISITIONS AND DIVESTITURES

In May 2008, concurrently with the closing of the Partnership’s initial public offering (“IPO”), Anadarko contributed to the Partnership the assets and liabilities of Anadarko Gathering Company LLC, Pinnacle Gas Treating LLC, and MIGC LLC. In December 2008, the Partnership completed the acquisition of the Powder River assets from Anadarko, which included (i) the Hilight system, (ii) a 50% interest in the Newcastle system and (iii) a 14.81% membership interest in Fort Union. In July 2009, the Partnership closed on the acquisition of a 51% membership interest in Chipeta from Anadarko. The Partnership closed the acquisitions of Anadarko’s Granger and Wattenberg assets in January 2010 and August 2010, respectively. In September 2010, the Partnership acquired a 10% interest in White Cliffs. The Partnership closed the acquisition of the Platte Valley assets from a third party in February 2011 and the acquisition of the Bison assets from Anadarko in July 2011. In January 2012, the Partnership acquired the MGR assets from Anadarko and in August 2012 Anadarko’s additional Chipeta interest of 24%, bringing the Partnership’s total membership interest in Chipeta to 75%.
The following table presents the acquisitions completed by the Partnership during the years ended December 31, 2015, 2014 and 2013, and identifies the funding sources for such acquisitions:
thousands except unit and percent amounts
 
Acquisition
Date
 
Percentage
Acquired
 
Deferred Purchase Price
Obligation - Anadarko
 
Borrowings
 
Cash
On Hand
 
Common Units
Issued to Anadarko
 
Class C Units
Issued to Anadarko
Non-Operated Marcellus Interest (1)
 
03/01/2013
 
33.75
%
 
$

 
$
250,000

 
$
215,500

 
449,129

 

Anadarko-Operated Marcellus Interest (2)
 
03/08/2013
 
33.75
%
 

 
133,500

 

 

 

Mont Belvieu JV (3)
 
06/05/2013
 
25
%
 

 

 
78,129

 

 

OTTCO (4)
 
09/03/2013
 
100
%
 

 
27,500

 

 

 

TEFR Interests (5)
 
03/03/2014
 
Various (5)

 

 
350,000

 
6,250

 
308,490

 

DBM (6)
 
11/25/2014
 
100
%
 

 
475,000

 
298,327

 

 
10,913,853

DBJV system (7)
 
03/02/2015
 
50
%
 
174,276

 

 

 

 

                                                                                                                                                                                    
(1) 
The Partnership acquired Anadarko’s 33.75% interest (non-operated) (the “Non-Operated Marcellus Interest”) in the Liberty and Rome gas gathering systems (the “Non-Operated Marcellus Interest systems”), serving production from the Marcellus shale in North-central Pennsylvania. In connection with the issuance of the common units, the Partnership’s general partner purchased 9,166 general partner units for consideration of $0.5 million.
(2) 
The Partnership acquired a 33.75% interest (the “Anadarko-Operated Marcellus Interest”) in each of the Larry’s Creek, Seely and Warrensville gas gathering systems (the “Anadarko-Operated Marcellus Interest systems”), which are operated by Anadarko and serve production from the Marcellus shale in North-central Pennsylvania, from a third party. During the third quarter of 2013, the Partnership recorded a $1.1 million decrease in the assets acquired and liabilities assumed in the acquisition, representing the final purchase price allocation.
(3) 
The Partnership acquired a 25% interest in the Mont Belvieu JV, an entity formed to design, construct, and own two fractionation trains located in Mont Belvieu, Texas, from a third party. The interest acquired is accounted for under the equity method of accounting.
(4) 
The Partnership acquired Overland Trail Transmission, LLC (“OTTCO”), a Delaware limited liability company, from a third party. OTTCO owns and operates an intrastate pipeline that connects the Partnership’s Red Desert and Granger complexes in southwestern Wyoming.
(5) 
The Partnership acquired a 20% interest in each of TEG and TEP and a 33.33% interest in FRP from Anadarko. These assets gather and transport NGLs primarily from the Anadarko and Denver-Julesburg (“DJ”) Basins. The interests in these entities are accounted for under the equity method of accounting. In connection with the issuance of the common units, the Partnership issued 6,296 general partner units to the general partner in exchange for the general partner’s proportionate capital contribution of $0.4 million.
(6) 
The Partnership acquired Nuevo Midstream, LLC (“Nuevo”) from a third party. Following the acquisition, the Partnership changed the name of Nuevo to Delaware Basin Midstream, LLC (“DBM”). The assets acquired include cryogenic processing plants, a gas gathering system, and related facilities and equipment, which are collectively referred to as the “DBM complex” and serve production from Reeves, Loving and Culberson Counties, Texas and Eddy and Lea Counties, New Mexico. See DBM acquisition below for further information, including the final allocation of the purchase price.
(7) 
The Partnership acquired Anadarko’s interest in Delaware Basin JV Gathering LLC (“DBJV”), which owns a 50% interest in a gathering system and related facilities (the “DBJV system”). The DBJV system is 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. The Partnership currently estimates the future payment will be $282.8 million, the net present value of which was $174.3 million as of the acquisition date. See DBJV acquisition—Deferred purchase price obligation - Anadarko below.


16


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


2.  ACQUISITIONS AND DIVESTITURES (CONTINUED)

Springfield acquisition. 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 system.” The Springfield oil and gas gathering systems are located in Dimmit, La Salle, Maverick and Webb Counties in South Texas. The acquisition closed on March 14, 2016. See Note 14.

DBJV and Springfield acquisitions. Because the acquisitions of DBJV and Springfield were transfers of net assets between entities under common control, the Partnership’s historical financial statements previously filed with the SEC have been recast in this Form 8-K to include the results attributable to the DBJV and Springfield systems as if the Partnership owned DBJV and Springfield for all periods presented. The consolidated financial statements for periods prior to the Partnership’s acquisition of DBJV and 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 DBJV and Springfield during the periods reported.
The following table presents the impact of the DBJV and Springfield systems on revenues and other, equity income, net and net income (loss) as presented in the Partnership’s historical consolidated statements of income:

 
 
Year Ended December 31, 2015
thousands
 
Partnership Historical
 
DBJV System (1)
 
Springfield
 
Springfield Eliminations
 
Combined
Revenues and other
 
$
1,561,372

 
$

 
$
190,766

 
$
(66
)
 
$
1,752,072

Equity income, net
 
71,251

 

 

 

 
71,251

Net income (loss)
 
(63,437
)
 

 
77,644

 

 
14,207

 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2014
thousands
 
Partnership Historical (2)
 
DBJV System
 
Springfield
 
Springfield Eliminations
 
Combined
Revenues and other
 
$
1,320,756

 
$
62,112

 
$
150,576

 
$
(67
)
 
$
1,533,377

Equity income, net
 
57,836

 

 

 

 
57,836

Net income (loss)
 
390,558

 
17,309

 
48,801

 

 
456,668

 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2013
thousands
 
Partnership Historical (2)
 
DBJV System
 
Springfield
 
Springfield Eliminations
 
Combined
Revenues and other
 
$
1,052,937

 
$
32,545

 
$
114,647

 
$
(69
)
 
$
1,200,060

Equity income, net
 
22,948

 

 

 

 
22,948

Net income (loss)
 
285,443

 
4,096

 
(1,295
)
 

 
288,244

                                                                                                                                                                                    
(1) 
The financial results for the DBJV system for the year ended December 31, 2015 are reflected in the Partnership’s historical financial statements as filed in the Partnership’s 2015 Form 10-K with the SEC on February 25, 2016.
(2) 
See Adjustments to previously issued financial statements in Note 1.


17


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


2.  ACQUISITIONS AND DIVESTITURES (CONTINUED)

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 the DBJV system for the calendar years 2018 and 2019, less (b) the Partnership’s share of all capital expenditures incurred for the DBJV system 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 the DBJV system 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 the DBJV system) was $282.8 million, which had a net present value of $174.3 million, using a discount rate of 10%. As of December 31, 2015, the net present value of this obligation was $188.7 million and has been recorded on the consolidated balance sheet under Deferred purchase price obligation - Anadarko. Accretion expense for the year ended December 31, 2015 was $14.4 million and zero for each of the years ended December 31, 2014 and 2013, and has been recorded as a charge to interest expense. Any subsequent changes to the estimated future payment obligation, if applicable, will be calculated using a discounted cash flow model with a 10% discount rate. Such changes will be recorded as adjustments within Common units on the consolidated balance sheets and consolidated statements of equity and partners’ capital, with accretion adjustments (financing-related) as a result of these changes recorded within interest expense on the consolidated statements of income in the period of the change.

DBM acquisition. The DBM acquisition has been accounted for under the acquisition method of accounting. The assets acquired and liabilities assumed in the DBM acquisition were recorded in the consolidated balance sheet at their estimated fair values as of the acquisition date. Results of operations attributable to the DBM acquisition were included in the Partnership’s consolidated statement of income beginning on the acquisition date in the fourth quarter of 2014.
The following is the final allocation of the purchase price as of December 31, 2015, including $3.5 million of post-closing purchase price adjustments, to the assets acquired and liabilities assumed in the DBM acquisition as of the acquisition date:
thousands
 
 
Current assets
 
$
60,888

Property, plant and equipment
 
467,171

Goodwill
 
284,749

Other intangible assets
 
811,048

Accounts payables
 
(18,621
)
Accrued liabilities
 
(37,360
)
Deferred income taxes
 
(1,342
)
Asset retirement obligations and other
 
(9,060
)
Total purchase price
 
$
1,557,473


The purchase price allocation is based on an assessment of the fair value of the assets acquired and liabilities assumed in the DBM acquisition using inputs that are not observable in the market and thus represent Level 3 inputs. The fair values of the processing plants, gathering system, and related facilities and equipment are based on market and cost approaches. The fair value of the intangible assets was determined using an income approach. Deferred taxes represent the tax effects of differences in the tax basis and acquisition-date fair value of the assets acquired and liabilities assumed.

18


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


2.  ACQUISITIONS AND DIVESTITURES (CONTINUED)

The following table presents pro forma condensed financial information of the Partnership as if the DBM acquisition had occurred on January 1, 2013:
 
 
Year Ended December 31,
thousands except per-unit amounts
 
2014
 
2013
Revenues and other
 
$
1,656,644

 
$
1,277,327

Net income (loss)
 
398,530

 
242,183

Net income (loss) attributable to Western Gas Partners, LP
 
384,505

 
231,367

Net income (loss) per common unit – basic and diluted
 
1.34

 
1.12


The unaudited pro forma information is presented for illustration purposes only and is not necessarily indicative of the operating results that would have occurred had the DBM acquisition been completed at the assumed date, nor is it necessarily indicative of future operating results of the combined entity. The Partnership’s unaudited pro forma information in the table above includes $12.5 million of revenues and other and $10.4 million of operating expenses, excluding depreciation and amortization and impairments, attributable to the DBM complex that are included in the Partnership’s consolidated statement of income for the year ended December 31, 2014. The pro forma adjustments reflect pre-acquisition results of the DBM acquisition including (a) revenues and expenses; (b) depreciation and amortization based on the purchase price allocated to property, plant and equipment and estimated useful lives; (c) amortization of intangible assets (customer contracts assumed in the acquisition); and (d) interest on borrowings under the Partnership’s senior unsecured revolving credit facility (“RCF”) to finance the DBM acquisition. The pro forma adjustments include estimates and assumptions based on currently available information. Management believes the estimates and assumptions are reasonable, and the relative effects of the transaction are properly reflected. The unaudited pro forma information does not reflect any cost savings or other synergies anticipated as a result of the DBM acquisition, nor any future acquisition related expenses.

Gain on divestiture - Dew and Pinnacle systems. During the third quarter of 2015, the Dew and Pinnacle systems in East Texas were sold to a third party for net proceeds of $145.6 million, after closing adjustments, resulting in a net gain on sale of $77.3 million recorded as Gain (loss) on divestiture and other, net in the Partnership’s consolidated statements of income. The Partnership also allocated $5.1 million in goodwill to this divestiture.


19


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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
2013
 
 
 
 
 
 
March 31
 
$
0.540

 
$
70,143

 
May 2013
June 30
 
0.560

 
79,315

 
August 2013
September 30
 
0.580

 
83,986

 
November 2013
December 31
 
0.600

 
92,609

 
February 2014
2014
 
 
 
 
 
 
March 31
 
$
0.625

 
$
98,749

 
May 2014
June 30
 
0.650

 
105,655

 
August 2014
September 30
 
0.675

 
111,608

 
November 2014
December 31
 
0.700

 
126,044

 
February 2015
2015
 
 
 
 
 
 
March 31
 
$
0.725

 
$
133,203

 
May 2015
June 30
 
0.750

 
139,736

 
August 2015
September 30
 
0.775

 
146,160

 
November 2015
December 31 (1)
 
0.800

 
152,588

 
February 2016
                                                                                                                                                                                    
(1) 
On January 21, 2016, the Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.800 per unit, or $152.6 million in aggregate, including incentive distributions, but excluding distributions on Class C units (see Class C unit distributions below). The cash distribution was paid on February 11, 2016, to unitholders of record at the close of business on February 1, 2016.

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. It is intended that working capital borrowings, at the time of such borrowings, be repaid within 12 months. In all cases, working capital borrowings are used solely for working capital purposes or to fund distributions to partners.


20


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


3.  PARTNERSHIP DISTRIBUTIONS (CONTINUED)

Class C unit distributions. The Class C units receive quarterly distributions at a rate equivalent to the Partnership’s common units. The distributions are paid in the form of additional Class C units (“PIK Class C units”) until the scheduled conversion date on December 31, 2017 (unless earlier converted), and the Class C units are disregarded with respect to distributions of the Partnership’s available cash until they are converted to common units. The number of additional PIK Class C units to be issued in connection with a distribution payable on the Class C units is determined by dividing the corresponding distribution attributable to the Class C units by the volume-weighted-average price of the Partnership’s common units for the ten days immediately preceding the payment date for the common unit distribution, less a 6% discount. The Partnership records the PIK Class C unit distributions at fair value at the time of issuance. This Level 2 fair value measurement uses the Partnership’s unit price as a significant input in the determination of the fair value.
The Partnership issued the following PIK Class C units to APC Midstream Holdings, LLC (“AMH”), the holder of the Class C units, for the periods presented:
thousands except unit amounts
For the Quarters Ended
 
PIK Class C
Units
 
Implied
Fair Value
 
Date of
Distribution
2014
 
 
 
 
 
 
December 31 (1)
 
45,711

 
$
3,072

 
February 2015
2015
 
 
 
 
 
 
March 31
 
118,230

 
$
8,101

 
May 2015
June 30
 
153,020

 
8,721

 
August 2015
September 30
 
181,048

 
9,724

 
November 2015
December 31
 
323,584

 
10,070

 
February 2016
                                                                                                                                                                                    
(1) 
Prorated for the 37-day period the Class C units were outstanding during the fourth quarter of 2014.

General partner interest and incentive distribution rights. As of December 31, 2015, the general partner was entitled to 1.8% of all quarterly distributions that the Partnership makes prior to its liquidation and, as the holder of the IDRs, was entitled to incentive distributions at the maximum distribution sharing percentage of 48.0% for all periods presented, after the minimum quarterly distribution and the target distribution levels had been achieved. The maximum distribution sharing percentage of 49.8% does not include any distributions that the general partner may receive on common units that it may acquire.


21


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


4.  EQUITY AND PARTNERS’ CAPITAL

Equity offerings. The Partnership completed the following public offerings of its common units during 2015, 2014 and 2013, including through its Continuous Offering Programs (“COP”):
thousands except unit and per-unit amounts
 
Common Units
Issued
 
GP Units
Issued (1)
 
Price Per
Unit
 
Underwriting
Discount and
Other Offering
Expenses
 
Net
Proceeds
2013
 
 
 
 
 
 
 
 
 
 
May 2013 equity offering (2)
 
7,015,000

 
143,163

 
$
61.18

 
$
13,203

 
$
424,733

December 2013 equity offering (3)
 
4,800,000

 
97,959

 
61.51

 
9,447

 
291,827

$125.0 million COP (4)
 
685,735

 
13,996

 
60.84

 
965

 
41,603

2014
 
 
 
 
 
 
 
 
 
 
$125.0 million COP (5)
 
1,133,384


23,132


$
73.48


$
1,738


$
83,245

November 2014 equity offering (6)
 
8,620,153

 
153,061

 
70.85

 
18,615

 
602,967

2015
 
 
 
 
 
 
 
 
 
 
$500.0 million COP (7)
 
873,525

 

 
$
66.61

 
$
805

 
$
57,385

                                                                                                                                                                                    
(1) 
Represents general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution.
(2) 
Includes the issuance of 915,000 common units pursuant to the full exercise of the underwriters’ over-allotment option.
(3) 
Includes the issuance of 300,000 common units on January 3, 2014, pursuant to the partial exercise of the underwriters’ over-allotment option. Net proceeds from this partial exercise (including the general partner’s proportionate capital contribution) were $18.1 million.
(4) 
Represents common and general partner units issued during the year ended December 31, 2013, pursuant to the Partnership’s registration statement filed with the SEC in August 2012 authorizing the issuance of up to an aggregate of $125.0 million of common units (the “$125.0 million COP”). Gross proceeds generated (including the general partner’s proportionate capital contributions) during the year ended December 31, 2013, were $42.6 million. The price per unit in the table above represents an average price for all issuances under the $125.0 million COP during the year ended December 31, 2013.
(5) 
Represents common and general partner units issued during the year ended December 31, 2014, under the $125.0 million COP. Gross proceeds generated (including the general partner’s proportionate capital contributions) during the year ended December 31, 2014, were $85.0 million. The price per unit in the table above represents an average price for all issuances under the $125.0 million COP during the year ended December 31, 2014. As of December 31, 2014, the Partnership had used all the capacity to issue common units under this registration statement.
(6) 
Includes the issuance of 1,120,153 common units pursuant to the partial exercise of the underwriters’ over-allotment option, the net proceeds from which were $77.0 million. Beginning with this partial exercise, the Partnership’s general partner elected not to make a corresponding capital contribution to maintain its 2.0% interest in the Partnership.
(7) 
Represents common units issued during the year ended December 31, 2015, pursuant to the Partnership’s registration statement filed with the SEC in August 2014 authorizing the issuance of up to an aggregate of $500.0 million of common units (the “$500.0 million COP”). Gross proceeds generated during the three months and year ended December 31, 2015, were zero and $58.2 million, respectively. Commissions paid during the three months and year ended December 31, 2015, were zero and $0.6 million, respectively. The price per unit in the table above represents an average price for all issuances under the $500.0 million COP during the year ended December 31, 2015.

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 the 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 December 31, 2015, no such proceeds had been received, and no Class C units had been redeemed.


22


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


4.  EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

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 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.

Common, Class C and general partner units. 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 and general partner units issued during the years ended December 31, 2015 and 2014:
 
 
Common
Units
 
Class C
Units
 
General
Partner Units
 
Total
Balance at December 31, 2013
 
117,322,812

 

 
2,394,345

 
119,717,157

December 2013 equity offering
 
300,000

 

 
6,122

 
306,122

WES LTIP award vestings
 
10,291

 

 
112

 
10,403

TEFR Interests acquisition
 
308,490

 

 
6,296

 
314,786

$125.0 million COP
 
1,133,384

 

 
23,132

 
1,156,516

November 2014 equity offering
 
8,620,153

 

 
153,061

 
8,773,214

Class C unit issuance
 

 
10,913,853

 

 
10,913,853

Balance at December 31, 2014
 
127,695,130

 
10,913,853

 
2,583,068

 
141,192,051

PIK Class C units
 

 
498,009

 

 
498,009

WES LTIP award vestings
 
8,310

 

 

 
8,310

$500.0 million COP
 
873,525

 

 

 
873,525

Balance at December 31, 2015
 
128,576,965

 
11,411,862

 
2,583,068

 
142,571,895


Holdings of Partnership equity. As of December 31, 2015, WGP held 49,296,205 common units, representing a 34.6% 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 1.8% general partner interest in the Partnership, and 100% of the IDRs. As of December 31, 2015, other subsidiaries of Anadarko held 757,619 common units and 11,411,862 Class C units, representing an aggregate 8.5% limited partner interest in the Partnership. As of December 31, 2015, the public held 78,523,141 common units, representing a 55.1% limited partner interest in the Partnership.


23


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


4.  EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

Net income (loss) per unit for common units. 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. 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, 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 outstanding Class C units.
The following table illustrates the Partnership’s calculation of net income (loss) per unit for common units:
 
 
Year Ended December 31,
thousands except per-unit amounts
 
2015
 
2014
 
2013
Net income (loss) attributable to Western Gas Partners, LP
 
$
4,106

 
$
442,643

 
$
277,428

Pre-acquisition net (income) loss allocated to Anadarko
 
(79,386
)
 
(65,154
)
 
(6,929
)
General partner interest in net (income) loss
 
(180,996
)
 
(120,980
)
 
(69,633
)
Limited partners’ interest in net income (loss)
 
(256,276
)
 
256,509

 
200,866

Net income (loss) allocable to common units (1)
 
(250,210
)
 
254,737

 
200,866

Net income (loss) allocable to Class C units (1)
 
(6,066
)
 
1,772

 

Limited partners’ interest in net income (loss)
 
$
(256,276
)
 
$
256,509

 
$
200,866

Net income (loss) per unit
 
 
 
 
 
 
Common units - basic
 
$
(1.95
)
 
$
2.13

 
$
1.83

Common units – diluted (2)
 
(1.95
)
 
2.12

 
1.83

Weighted-average units outstanding
 
 
 
 
 
 
Common units – basic
 
128,345

 
119,822

 
109,872

Class C units (2)
 
11,114

 
1,106

 

Common units – diluted
 
139,459

 
120,928

 
109,872

                                                                                                                                                                                    
(1) 
Adjusted to reflect amortization for the beneficial conversion feature. See Class C units above for a discussion of the Class C units.
(2) 
Inclusion of Class C units in the calculation for the year ended December 31, 2015, would have had an anti-dilutive effect.


24


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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, drip condensate 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 IPO, 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 $252.3 million and $317.8 million at December 31, 2015 and 2014, respectively. The fair value of the note reflects consideration of credit risk and any premium or discount for the differential between the stated interest rate and quarter-end market interest rate, based on quoted market prices of similar debt instruments. Accordingly, the fair value of the note receivable from Anadarko is measured using Level 2 inputs.
The consideration to be paid by the Partnership to Anadarko for the March 2015 acquisition of DBJV consists of a cash payment due on March 31, 2020. See Note 2 and Note 12.

Commodity price swap agreements. The Partnership has commodity price swap agreements with Anadarko to mitigate exposure to a majority of the commodity price 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. On December 31, 2014, the Partnership’s commodity price swap agreements for the Hilight and Newcastle systems and the Granger complex (excluding the Granger straddle plant) expired without renewal. 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 December 31, 2015:
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


25


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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 income:
 
 
Year Ended December 31,
thousands
 
2015
 
2014
 
2013
Gains (losses) on commodity price swap agreements related to sales: (1)
 

 
 
 
 
Natural gas sales
 
$
45,978

 
$
9,494

 
$
21,382

Natural gas liquids sales
 
145,258

 
113,866

 
102,076

Total
 
191,236

 
123,360

 
123,458

Losses on commodity price swap agreements related to purchases (2)
 
(124,944
)
 
(68,492
)
 
(85,294
)
Net gains (losses) on commodity price swap agreements
 
$
66,292

 
$
54,868

 
$
38,164

                                                                                                                                                                                    
(1) 
Reported in affiliate natural gas, natural gas liquids and drip condensate sales in the consolidated statements of income in the period in which the related sale is recorded.
(2) 
Reported in cost of product in the consolidated statements of income 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.

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.

26


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

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 income. 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 year ended December 31, 2015, the capital contribution from Anadarko was $18.4 million.

Gas gathering and processing agreements. The Partnership has significant gas 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 53%, 56% and 60% for the years ended December 31, 2015, 2014 and 2013, respectively. The Partnership’s processing throughput (excluding equity investment throughput) attributable to natural gas production owned or controlled by Anadarko was 51%, 57% and 59% for the years ended December 31, 2015, 2014 and 2013, respectively. The Partnership’s gathering, treating and transportation throughput (excluding equity investment throughput) attributable to crude/NGL production owned or controlled by Anadarko was 100% for each of the years ended December 31, 2015, 2014 and 2013.

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.

Omnibus agreement. Pursuant to the omnibus agreement, Anadarko performs centralized corporate functions for the Partnership, such as legal; accounting; treasury; cash management; investor relations; insurance administration and claims processing; risk management; health, safety and environmental; information technology; human resources; credit; payroll; internal audit; tax; marketing; and midstream administration. Anadarko, in accordance with the partnership and omnibus agreements, determines, in its reasonable discretion, amounts to be reimbursed by the Partnership in exchange for services provided under the omnibus agreement. See Summary of affiliate transactions below.
The following table summarizes the amounts the Partnership reimbursed to Anadarko:
 
 
Year Ended December 31,
thousands
 
2015
 
2014
 
2013
General and administrative expenses
 
$
22,896

 
$
20,249

 
$
16,882

Public company expenses
 
8,950

 
8,006

 
7,152

Total reimbursement
 
$
31,846

 
$
28,255

 
$
24,034


Services and secondment agreement. Pursuant to the services and secondment agreement, specified employees of Anadarko are seconded to the general partner to provide operating, routine maintenance and other services with respect to the assets owned and operated by the Partnership under the direction, supervision and control of the general partner. Pursuant to the services and secondment agreement, the Partnership reimburses Anadarko for services provided by the seconded employees. The initial term of the services and secondment agreement extends through May 2018 and the term will automatically extend for additional twelve-month periods unless either party provides 180 days written notice of termination before the applicable twelve-month period expires. The consolidated financial statements include costs allocated by Anadarko for expenses incurred under the services and secondment agreement for periods including and subsequent to the Partnership’s acquisition of the Partnership assets.

Tax sharing agreement. Pursuant to a tax sharing agreement, the Partnership reimburses Anadarko for its estimated share of applicable state taxes. These taxes include income taxes attributable to the Partnership’s income which are directly borne by Anadarko through its filing of a combined or consolidated tax return with respect to periods beginning on and subsequent to the acquisition of the Partnership assets from Anadarko. Anadarko may use its own tax attributes to reduce or eliminate the tax liability of its combined or consolidated group, which may include the Partnership as a member. However, under this circumstance, the Partnership nevertheless is required to reimburse Anadarko for its allocable share of taxes that would have been owed had tax attributes not been available to Anadarko.

27


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

Allocation of costs. For periods prior to the Partnership’s acquisition of the Partnership assets, the consolidated financial statements include costs allocated by Anadarko in the form of a management services fee, which approximated the general and administrative costs incurred by Anadarko attributable to the Partnership assets. This management services fee was allocated to the Partnership based on its proportionate share of Anadarko’s assets and revenues or other contractual arrangements. Management believes these allocation methodologies are reasonable.
The employees supporting the Partnership’s operations are employees of Anadarko. Anadarko allocates costs to the Partnership for its share of personnel costs, including costs associated with equity-based compensation plans, non-contributory defined pension and postretirement plans, defined contribution savings plan pursuant to the omnibus agreement and services and secondment agreement. In general, the Partnership’s reimbursement to Anadarko under the omnibus agreement or services and secondment agreements is either (i) on an actual basis for direct expenses Anadarko and the general partner incur on behalf of the Partnership, or (ii) based on an allocation of salaries and related employee benefits between the Partnership, the general partner and Anadarko based on estimates of time spent on each entity’s business and affairs. Most general and administrative expenses charged to the Partnership by Anadarko are attributed to the Partnership on an actual basis, and do not include any mark-up or subsidy component. With respect to allocated costs, management believes the allocation method employed by Anadarko is reasonable. Although it is not practicable to determine what the amount of these direct and allocated costs would be if the Partnership were to directly obtain these services, management believes that aggregate costs charged to the Partnership by Anadarko are reasonable.

WES LTIP. The general partner awards phantom units under the WES LTIP primarily to its independent directors, but also from time to time to its executive officers and Anadarko employees performing services for the Partnership. The phantom units awarded to the independent directors vest one year from the grant date, while all other awards are subject to graded vesting over a three-year service period. Compensation expense is recognized over the vesting period and was $0.5 million for the year ended December 31, 2015, and $0.6 million for each of the years ended December 31, 2014 and 2013. As of December 31, 2015, there was $0.1 million of unrecognized compensation expense attributable to the outstanding awards under the WES LTIP, all of which will be realized by the Partnership, and which is expected to be recognized over a weighted-average period of 0.4 years.
The following table summarizes WES LTIP award activity for the years ended December 31, 2015, 2014 and 2013:
 
2015
 
2014
 
2013
 
Weighted-Average Grant-Date Fair Value
 
Units
 
Weighted-Average Grant-Date Fair Value
 
Units
 
Weighted-Average Grant-Date Fair Value
 
Units
Phantom units outstanding at beginning of year
$
60.74

 
9,522

 
$
49.47

 
16,844

 
$
41.77

 
25,619

Vested
60.69

 
(9,257
)
 
49.55

 
(13,122
)
 
41.28

 
(14,695
)
Granted
69.10

 
5,212

 
68.14

 
5,800

 
62.49

 
5,920

Phantom units outstanding at end of year
68.78

 
5,477

 
60.74

 
9,522

 
49.47

 
16,844


WGP LTIP and Anadarko Incentive Plans. For the years ended December 31, 2015, 2014 and 2013, general and administrative expenses included $3.9 million, $3.5 million and $3.0 million, respectively, of equity-based compensation expense, allocated to the Partnership by Anadarko, for awards granted to the executive officers of the general partner and other employees under the WGP LTIP and the Anadarko Incentive Plans. Of these amounts, $3.6 million, $3.2 million and $2.9 million for the years ended December 31, 2015, 2014 and 2013, respectively, are reflected as contributions to partners’ capital in the Partnership’s consolidated statements of equity and partners’ capital. As of December 31, 2015, the Partnership estimated that $7.3 million of estimated unrecognized compensation expense attributable to the WGP LTIP and the Anadarko Incentive Plans will be allocated to the Partnership over a weighted-average period of 2.0 years.

28


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

Equipment purchases and sales. The following table summarizes the Partnership’s purchases from and sales to Anadarko of pipe and equipment:
 
 
Year Ended December 31,
 
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
thousands
 
Purchases
 
Sales
Cash consideration
 
$
10,903

 
$
22,943

 
$
11,211

 
$
925

 
$
402

 
$
85

Net carrying value
 
6,318

 
12,210

 
5,309

 
972

 
375

 
38

Partners’ capital adjustment
 
$
4,585

 
$
10,733

 
$
5,902

 
$
(47
)
 
$
27

 
$
47


Contributions in aid of construction costs from affiliates. In 2013, a subsidiary of Anadarko entered into an aid in construction agreement with the Partnership, whereby the Partnership constructed five receipt-point facilities at the Brasada complex that serve the Anadarko subsidiary. Such subsidiary reimbursed the Partnership for costs associated with construction of the receipt points. These reimbursements are presented within the investing section of the Partnership’s consolidated statements of cash flows as “Contributions in aid of construction costs from affiliates.”

Summary of affiliate transactions. The following table summarizes affiliate transactions, which include revenue from affiliates, reimbursement of operating expenses and purchases of natural gas:
 
 
Year ended December 31,
thousands
 
2015
 
2014
 
2013
Revenues and other (1)
 
$
1,220,639

 
$
1,203,974

 
$
957,912

Equity income, net (1)
 
71,251

 
57,836

 
22,948

Cost of product (1)
 
167,354

 
127,930

 
136,696

Operation and maintenance (2)
 
77,061

 
71,386

 
67,308

General and administrative (3)
 
33,903

 
31,308

 
28,369

Operating expenses
 
278,318

 
230,624

 
232,373

Interest income (4)
 
16,900

 
16,900

 
16,900

Interest expense (5)
 
14,398

 

 

Distributions to unitholders (6)
 
314,200

 
234,024

 
169,150

Above-market component of swap extensions with Anadarko
 
18,449

 

 

                                                                                                                                                                                    
(1) 
Represents amounts earned or incurred on and subsequent to the date of acquisition of the Partnership assets, as well as amounts earned or incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets, recognized under gathering, treating or processing agreements, and purchase and sale agreements.
(2) 
Represents expenses incurred on and subsequent to the date of the acquisition of the Partnership assets, as well as expenses incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets.
(3) 
Represents general and administrative expense incurred on and subsequent to the date of the Partnership’s acquisition of the Partnership assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of the Partnership assets by the Partnership. These amounts include equity-based compensation expense allocated to the Partnership by Anadarko (see WES LTIP and WGP LTIP and Anadarko Incentive Plans within this Note 5).
(4) 
Represents interest income recognized on the note receivable from Anadarko.
(5) 
For the year ended December 31, 2015, includes accretion expense recognized on the Deferred purchase price obligation - Anadarko for the acquisition of DBJV (see Note 2 and Note 12).
(6) 
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 income.

29


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


6.  INCOME TAXES

The components of the Partnership’s income tax expense (benefit) are as follows:
 
 
Year Ended December 31,
thousands
 
2015
 
2014
 
2013
Current income tax expense (benefit)
 
 
 
 
 
 
Federal income tax expense (benefit)
 
$
32,422

 
$
(114
)
 
$
(62,104
)
State income tax expense (benefit)
 
1,764

 
493

 
173

Total current income tax expense (benefit)
 
34,186

 
379

 
(61,931
)
Deferred income tax expense (benefit)
 
 
 
 
 
 
Federal income tax expense (benefit)
 
10,251

 
35,361

 
66,390

State income tax expense (benefit)
 
1,095

 
3,321

 
(144
)
Total deferred income tax expense (benefit)
 
11,346

 
38,682

 
66,246

Total income tax expense (benefit)
 
$
45,532

 
$
39,061

 
$
4,315


Total income taxes differed from the amounts computed by applying the statutory income tax rate to income (loss) before income taxes. The sources of these differences are as follows:
 
 
Year Ended December 31,
thousands except percentages
 
2015
 
2014
 
2013
Income (loss) before income taxes
 
$
59,739

 
$
495,729

 
$
292,559

Statutory tax rate
 
%
 
%
 
%
Tax computed at statutory rate
 
$

 
$

 
$

Adjustments resulting from:
 
 
 
 
 
 
Federal taxes on income attributable to Partnership assets pre-acquisition
 
42,823

 
35,716

 
4,822

State taxes on income attributable to Partnership assets pre-acquisition (net of federal benefit)
 
298

 
864

 
852

Texas margin tax expense (benefit) (1)
 
2,411

 
2,481

 
(1,359
)
Income tax expense (benefit)
 
$
45,532

 
$
39,061

 
$
4,315

Effective tax rate
 
76
%
 
8
%
 
1
%
                                                                                                                                                                                    
(1) 
Includes a reduction of $2.2 million in deferred state income taxes. Texas House Bill 32, signed into law in June 2015, reduced the Texas margin tax rates by 0.25%. The law became effective January 1, 2016. The Partnership is required to include the impact of the law change on its deferred state income taxes in the period enacted.

The tax effects of temporary differences that give rise to significant portions of deferred tax assets (liabilities) are as follows:
 
 
December 31,
thousands
 
2015
 
2014
Depreciable property
 
$
(138,159
)
 
$
(168,998
)
Credit carryforwards
 
512

 
526

Other intangible assets
 
(2,070
)
 
(1,450
)
Other
 
13

 
7

Net long-term deferred income tax liabilities
 
$
(139,704
)
 
$
(169,915
)

Credit carryforwards, which are available for use on future income tax returns, consist of $0.5 million of state income tax credits that expire in 2026.

30


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


7.  PROPERTY, PLANT AND EQUIPMENT

A summary of the historical cost of the Partnership’s property, plant and equipment is as follows:
 
 
 
 
December 31,
thousands
 
Estimated Useful Life
 
2015
 
2014
Land
 
n/a
 
$
3,744

 
$
3,437

Gathering systems
 
3 to 47 years
 
6,061,004

 
5,559,369

Pipelines and equipment
 
15 to 45 years
 
136,290

 
151,107

Assets under construction
 
n/a
 
329,887

 
512,269

Other
 
3 to 40 years
 
25,853

 
22,395

Total property, plant and equipment
 
 
 
6,556,778

 
6,248,577

Accumulated depreciation
 
 
 
1,697,999

 
1,110,722

Net property, plant and equipment
 
 
 
$
4,858,779

 
$
5,137,855


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.
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 sustained the most damage of the processing trains but is expected to be returned to service by the end of 2016. Train III experienced minimal damage and is expected to be able to accept limited deliveries of gas in April 2016, and return to full service by the end of the second quarter of 2016, along with new liquid handling and amine treating facilities. The Partnership recognized a gross loss resulting from this damage of $68.8 million. See Note 1.
Also during 2015, the Partnership recognized impairments of $515.5 million, primarily due to impairments of $280.2 million at the Red Desert complex and $220.9 million at the Hilight system. Using the income approach and Level 3 fair value inputs, the Red Desert complex was impaired to its estimated salvage value of $6.3 million and the Hilight system was impaired to its estimated fair value of $28.8 million. These impairments were triggered by a reduction in estimated future cash flows caused by the low commodity price environment and resulting reduced producer drilling activity and related throughput. Also during this period, the Partnership recognized impairments of $14.4 million, primarily due to (i) the abandonment of compressors at the MIGC system and (ii) the cancellation of projects at the Non-Operated Marcellus Interest systems, the DBJV system and the Brasada, Red Desert and DJ Basin complexes. Prolonged low or further declines in commodity prices and changes to producers’ drilling plans in response to lower prices could result in additional impairments in future periods.
During 2014, the Partnership recognized impairments of $5.1 million, primarily related to a non-operational plant in the Powder River Basin that was impaired to its estimated salvage value of $2.4 million, using the income approach and Level 3 fair value inputs, the cancellation of various capital projects by the third-party operator of the Non-Operated Marcellus Interest systems and a compressor no longer in service at the Hilight system.
During 2013, the Partnership recognized a $49.9 million impairment, primarily due to an impairment of $48.7 million at the Springfield system related to a gathering system that was impaired to its estimated fair value of $14.4 million prior to the disposition of such gathering system by Springfield in 2014, using the income approach and Level 3 fair value inputs. This impairment was triggered by a reduction in estimated future cash flows caused by downward reserve revisions by producers based on lease expirations and the decision to suspend a drilling program in the area. Also during this period, the Partnership recognized impairments related to the cancellation of various capital projects by the third-party operator of the Non-Operated Marcellus Interest systems.
At December 31, 2013, other long-term assets includes $4.6 million of unguaranteed residual value related to the capital lease component of a processing agreement assumed in connection with the acquisition of the Granger straddle plant as a part of the MGR acquisition in January 2012. This agreement, in which the Partnership was the lessor, was replaced effective April 1, 2014, with a gas conditioning agreement that does not satisfy criteria required for lease classification. As such, during the second quarter of 2014, the $4.6 million capital lease asset was reclassified from other long-term assets to property, plant and equipment and commenced depreciation.

31


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


8.  GOODWILL AND INTANGIBLES

Goodwill. Goodwill is recorded when the purchase price of a business acquired exceeds the fair market value of the tangible and separately measurable intangible net assets. In addition, goodwill represents the allocated portion of Anadarko’s midstream goodwill attributed to the Partnership assets acquired from Anadarko. The carrying value of Anadarko’s midstream goodwill represents the excess of the purchase price paid to a third-party entity over the estimated fair value of the identifiable assets acquired and liabilities assumed by Anadarko. Accordingly, the Partnership’s allocated goodwill balance does not represent, and in some cases is significantly different from, the difference between the consideration the Partnership paid for its acquisitions from Anadarko and the fair value of such net assets on their respective acquisition dates.
The Partnership evaluates goodwill for impairment annually (see Note 1). Estimating the fair value of the Partnership’s reporting units was not necessary based on the qualitative evaluation as of October 1, 2015, and no goodwill impairment has been recognized in these consolidated financial statements. Procedures were also performed in the fourth quarter of 2015 to review any changes in circumstances subsequent to the annual test, including changes in commodity prices. These procedures also indicated no impairment.

Other intangible assets. The intangible asset balance in the consolidated balance sheets includes the fair value, net of amortization, of (i) contracts assumed by the Partnership in connection with the Platte Valley acquisition in February 2011, which are being amortized on a straight-line basis over 50 years, (ii) interconnect agreements at Chipeta entered into in November 2012, which are being amortized on a straight-line basis over 10 years, and (iii) contracts assumed by the Partnership in connection with the DBM acquisition in November 2014, which are being amortized on a straight-line basis over 30 years.
The Partnership assesses intangible assets for impairment together with related underlying long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. See Property, plant and equipment in Note 1 for further discussion of management’s process to evaluate potential impairment of long-lived assets. No intangible asset impairment has been recognized in these consolidated financial statements.
The following table presents the gross carrying amount and accumulated amortization of other intangible assets:
 
 
December 31,
thousands
 
2015
 
2014
Gross carrying amount
 
$
868,035

 
$
892,555

Accumulated amortization
 
(35,908
)
 
(7,698
)
Other intangible assets
 
$
832,127

 
$
884,857


Amortization expense for intangible assets was $28.2 million, $4.3 million and $1.4 million for the years ended December 31, 2015, 2014 and 2013, respectively. The Partnership estimates that it will record $28.4 million of intangible asset amortization for each of the next five years.


32


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


9.  EQUITY INVESTMENTS

The following table presents the activity in the Partnership’s equity investments for the years ended December 31, 2015 and 2014:
 
Equity Investments
thousands
Fort
Union
(1)
 
White
Cliffs
(2)
 
Rendezvous (3)
 
Mont
Belvieu JV
(4)
 
TEG (5)
 
TEP (6)
 
FRP (7)
 
Total
Balance at December 31, 2013
$
25,172

 
$
35,039

 
$
60,928

 
$
122,480

 
$
16,649

 
$
197,731

 
$
135,401

 
$
593,400

Investment earnings (loss), net of amortization
6,344

 
11,912

 
1,729

 
29,029

 
650

 
6,108

 
2,064

 
57,836

Contributions

 
10,456

 

 
3,957

 
352

 
6,623

 
42,033

 
63,421

Capitalized interest

 

 

 

 

 

 
857

 
857

Distributions
(5,583
)
 
(11,330
)
 
(3,669
)
 
(34,129
)
 
(523
)
 
(5,622
)
 
(2,111
)
 
(62,967
)
Distributions in excess of cumulative earnings (8)

 
(1,762
)
 
(2,652
)
 

 
(338
)
 
(6,047
)
 
(7,256
)
 
(18,055
)
Balance at December 31, 2014
$
25,933

 
$
44,315

 
$
56,336

 
$
121,337

 
$
16,790

 
$
198,793

 
$
170,988

 
$
634,492

Investment earnings (loss), net of amortization
(3,200
)
 
14,770

 
2,292

 
23,570

 
586

 
16,088

 
17,145

 
71,251

Contributions

 
8,512

 

 
(432
)
 

 
1,880

 
1,482

 
11,442

Distributions
(5,611
)
 
(14,188
)
 
(4,233
)
 
(24,248
)
 
(803
)
 
(16,340
)
 
(16,631
)
 
(82,054
)
Distributions in excess of cumulative earnings (8)

 
(2,970
)
 
(3,482
)
 
(3,138
)
 
(290
)
 
(5,618
)
 
(746
)
 
(16,244
)
Balance at December 31, 2015
$
17,122

 
$
50,439

 
$
50,913

 
$
117,089

 
$
16,283

 
$
194,803

 
$
172,238

 
$
618,887

                                                                                                                                                                                   
(1) 
The Partnership has a 14.81% interest in Fort Union, a joint venture that owns a gathering pipeline and treating facilities in the Powder River Basin. Anadarko is the construction manager and physical operator of the Fort Union facilities. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the owners’ firm gathering agreements, require 65% or unanimous approval of the owners.
(2) 
The Partnership has a 10% interest in White Cliffs, a limited liability company that owns a crude oil pipeline that originates in Platteville, Colorado and terminates in Cushing, Oklahoma. The third-party majority owner is the manager of the White Cliffs operations. Certain business decisions, including, but not limited to, approval of annual budgets and decisions with respect to significant expenditures, contractual commitments, acquisitions, material financings, dispositions of assets or admitting new members, require more than 75% approval of the members.
(3) 
The Partnership has a 22% interest in Rendezvous, a limited liability company that operates gas gathering facilities in Southwestern Wyoming. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the members’ gas servicing agreements, require unanimous approval of the members.
(4) 
The Partnership has a 25% interest in the Mont Belvieu JV, an entity formed to design, construct, and own two fractionation trains located in Mont Belvieu, Texas. A third party is the operator of the Mont Belvieu JV fractionation trains. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require 50% or unanimous approval of the owners.
(5) 
The Partnership has a 20% interest in TEG, an entity that consists of two NGL gathering systems that link natural gas processing plants to TEP. Enbridge Midcoast Energy, LP (“Enbridge”) is the operator of the two gathering systems. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the delegation, creation, appointment, or removal of officer positions require more than 50% approval of the members.
(6) 
The Partnership has a 20% interest in TEP, which consists of an NGL pipeline that originates in Skellytown, Texas and extends to Mont Belvieu, Texas. Enterprise Products Operating LLC (“Enterprise”) is the operator of TEP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than 50% approval of the members.
(7) 
The Partnership has a 33.33% interest in the FRP, an NGL pipeline that extends from Weld County, Colorado to Skellytown, Texas. Enterprise is the operator of FRP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than 50% approval of the members.
(8) 
Distributions in excess of cumulative earnings, classified as investing cash flows in the consolidated statements of cash flows, is calculated on an individual investment basis.


33


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


9.  EQUITY INVESTMENTS (CONTINUED)

During the year ended December 31, 2015, an impairment loss was recognized by the managing partner of Fort Union. The Partnership’s 14.81% share of the impairment loss was $9.5 million recorded in Equity income, net in the consolidated statements of income.
The investment balance at December 31, 2015, includes $40.1 million for the purchase price allocated to the investment in Rendezvous in excess of the historic cost basis of Western Gas Resources, Inc. (“WGRI”), the entity that previously owned the interest in Rendezvous, which Anadarko acquired in August 2006. This excess balance is attributable to the difference between the fair value and book value of such gathering and treating facilities (at the time WGRI was acquired by Anadarko) and is being amortized over the remaining estimated useful life of those facilities.
The investment balance in White Cliffs at December 31, 2015, is $8.1 million less than the Partnership’s underlying equity in White Cliffs’ net assets, primarily due to the Partnership recording the acquisition of its initial 0.4% interest in White Cliffs at Anadarko’s historic carrying value. This difference is being amortized to equity income, net over the remaining estimated useful life of the White Cliffs pipeline.
Management evaluates its equity investments for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value that is other than temporary. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether the investment has been impaired. Management assesses the fair value of equity investments using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third-party comparable sales and discounted cash flow models. If the estimated fair value is less than the carrying value, the excess of the carrying value over the estimated fair value is recognized as an impairment loss.
The following tables present the summarized combined financial information for the Partnership’s equity investments (amounts represent 100% of investee financial information):
 
 
Year Ended December 31,
thousands
 
2015
 
2014
 
2013
Consolidated Statements of Income
 
 
 
 
 
 
Revenues
 
$
668,797

 
$
548,629

 
$
261,705

Operating income
 
381,616

 
336,188

 
171,496

Net income
 
381,161

 
333,705

 
170,175

 
 
December 31,
thousands
 
2015
 
2014
Consolidated Balance Sheets
 
 
 
 
Current assets
 
$
156,180

 
$
141,781

Property, plant and equipment, net
 
2,736,553

 
2,814,336

Other assets
 
43,713

 
48,799

Total assets
 
$
2,936,446

 
$
3,004,916

Current liabilities
 
78,116

 
95,102

Non-current liabilities
 
9,072

 
22,615

Equity
 
2,849,258

 
2,887,199

Total liabilities and equity
 
$
2,936,446

 
$
3,004,916




34


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


10.  COMPONENTS OF WORKING CAPITAL

A summary of accounts receivable, net is as follows:
 
 
December 31,
thousands
 
2015
 
2014
Trade receivables, net
 
$
143,557

 
$
119,170

Other receivables, net
 
49,772

 
3,597

Total accounts receivable, net
 
$
193,329

 
$
122,767


A summary of other current assets is as follows:
 
 
December 31,
thousands
 
2015
 
2014
Natural gas liquids inventory
 
$
2,403

 
$
5,316

Imbalance receivables
 
2,122

 
415

Prepaid insurance
 
2,296

 
2,443

Other
 
1,034

 
1,879

Total other current assets
 
$
7,855

 
$
10,053


A summary of accrued liabilities is as follows:
 
 
December 31,
thousands
 
2015
 
2014
Accrued capital expenditures
 
$
61,454

 
$
132,911

Accrued plant purchases
 
16,425

 
14,023

Accrued interest expense
 
26,194

 
24,741

Short-term asset retirement obligations
 
3,677

 
1,497

Short-term remediation and reclamation obligations
 
1,136

 
475

Income taxes payable
 
770

 
207

Other
 
9,363

 
3,266

Total accrued liabilities
 
$
119,019

 
$
177,120



35


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


11.  ASSET RETIREMENT OBLIGATIONS

The following table provides a summary of changes in asset retirement obligations:
 
 
Year Ended December 31,
thousands
 
2015
 
2014
Carrying amount of asset retirement obligations at beginning of year
 
$
119,855

 
$
82,563

Liabilities incurred
 
9,490

 
14,469

Liabilities settled
 
(7,905
)
 
(4,941
)
Accretion expense
 
6,381

 
5,122

Revisions in estimated liabilities
 
2,810

 
22,642

Carrying amount of asset retirement obligations at end of year
 
$
130,631

 
$
119,855


The liabilities incurred for the year ended December 31, 2015, represented additions in asset retirement obligations primarily due to capital expansions at the DJ Basin, Granger and Brasada complexes and the Hilight and Non-Operated Marcellus Interest systems. Revisions in estimated liabilities for the year ended December 31, 2015, are related to (i) changes in expected timing of settlement primarily at the DBM and DJ Basin complexes and Hugoton and DBJV systems, and (ii) changes in property lives primarily at the Granger, Brasada and Red Desert complexes and the Hilight and Non-Operated Marcellus Interest systems.
The liabilities incurred for the year ended December 31, 2014, increased primarily due to the acquisition of DBM in the fourth quarter of 2014 and continued capital expansion at the DJ Basin complex. Revisions in estimated liabilities for the year ended December 31, 2014, are related to changes in property lives and changes in the expected timing of settlement, primarily at the DJ Basin complex, Granger complex, Hugoton and Hilight systems, MIGC, OTTCO, Brasada complex and Non-Operated Marcellus Interest systems; as well as changes in cost estimates associated with the abandonment of pipe and equipment skids, and compressors at the Springfield system.

12.  DEBT AND INTEREST EXPENSE

At December 31, 2015, 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 December 31, 2015 and 2014:
 
 
December 31, 2015
 
December 31, 2014
thousands
 
Principal
 
Carrying
Value
 
Fair
Value (1)
 
Principal
 
Carrying
Value
 
Fair
Value (1)
2021 Notes
 
$
500,000

 
$
496,285

 
$
513,645

 
$
500,000

 
$
495,714

 
$
549,530

2022 Notes
 
670,000

 
672,572

 
595,744

 
670,000

 
672,930

 
681,942

2018 Notes
 
350,000

 
350,348

 
339,293

 
350,000

 
350,474

 
352,162

2044 Notes
 
400,000

 
393,923

 
321,499

 
400,000

 
393,836

 
417,619

2025 Notes
 
500,000

 
494,229

 
422,285

 

 

 

RCF
 
300,000

 
300,000

 
300,000

 
510,000

 
510,000

 
510,000

Total long-term debt
 
$
2,720,000

 
$
2,707,357

 
$
2,492,466

 
$
2,430,000

 
$
2,422,954

 
$
2,511,253

                                                                                                                                                                                    
(1) 
Fair value is measured using the market approach and Level 2 inputs.


36


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


12.  DEBT AND INTEREST EXPENSE (CONTINUED)

Debt activity. The following table presents the debt activity of the Partnership for the years ended December 31, 2015 and 2014:
thousands
 
Carrying Value
Balance at December 31, 2013
 
$
1,418,169

RCF borrowings
 
1,160,000

Issuance of 2044 Notes
 
400,000

Issuance of 2018 Notes
 
100,000

Repayments of RCF borrowings
 
(650,000
)
Other
 
(5,215
)
Balance at December 31, 2014
 
$
2,422,954

RCF borrowings
 
400,000

Issuance of 2025 Notes
 
500,000

Repayments of RCF borrowings
 
(610,000
)
Other
 
(5,597
)
Balance at December 31, 2015
 
$
2,707,357


Senior Notes. The 2025 Notes issued in June 2015 were offered at a price to the public of 98.789% of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rate of the 2025 Notes is 4.205%. Interest is paid semi-annually on June 1 and December 1 of each year. Proceeds (net of underwriting discount of $3.3 million, original issue discount and debt issuance costs) were used to repay a portion of the amount outstanding under the RCF.
The 2044 Notes issued in March 2014 were offered at a price to the public of 98.443% of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rate of the 2044 Notes is 5.633%. Interest is paid semi-annually on April 1 and October 1 of each year. Proceeds (net of underwriting discount of $3.5 million, original issue discount and debt issuance costs) were used to repay amounts then outstanding under the RCF and for general partnership purposes.
The 2018 Notes issued in March 2014 were offered at a price to the public of 100.857% of the face amount. Including the effects of the issuance premium for the March 2014 offering, the issuance discount for the August 2013 offering of 2018 Notes and underwriting discounts, the effective interest rate of the 2018 Notes is 2.743%. Interest is paid semi-annually on February 15 and August 15 of each year. Proceeds (net of underwriting discount of $0.6 million, original issue premium and debt issuance costs) were used to repay amounts then outstanding under the RCF and for general partnership purposes.
At December 31, 2015, the Partnership was in compliance with all covenants under the indentures governing its outstanding notes.


37


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


12.  DEBT AND INTEREST EXPENSE (CONTINUED)

Revolving credit facility. The $1.2 billion RCF, which is expandable to a maximum of $1.5 billion, matures in February 2019 and bears interest at London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 0.975% to 1.45%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.5%, or (c) LIBOR plus 1%, in each case plus applicable margins currently ranging from zero to 0.45%, based upon the Partnership’s senior unsecured debt rating. The interest rate on the RCF was 1.73% and 1.47% at December 31, 2015 and 2014, respectively. The Partnership is required to pay a quarterly facility fee currently ranging from 0.15% to 0.30% of the commitment amount (whether used or unused), based upon the Partnership’s senior unsecured debt rating. The facility fee rate was 0.20% at December 31, 2015 and 2014.
As of December 31, 2015, the Partnership had $300.0 million of outstanding borrowings, $6.4 million in outstanding letters of credit and $893.6 million available for borrowing under the RCF. At December 31, 2015, the Partnership was in compliance with all covenants under the RCF.
The 2021 Notes, 2022 Notes, 2018 Notes, 2044 Notes, 2025 Notes and obligations under the RCF are recourse to the Partnership’s general partner. The Partnership’s general partner is indemnified by a wholly owned subsidiary of Anadarko, WGRI, against any claims made against the general partner under the 2022 Notes, 2021 Notes, and/or the RCF.
In connection with the acquisitions of the Non-Operated Marcellus Interest, the Anadarko-Operated Marcellus Interest and the TEFR Interests, the Partnership’s general partner and other wholly owned subsidiaries of Anadarko entered into indemnification agreements, whereby such subsidiaries agreed to indemnify the Partnership’s general partner for any recourse liability it may have for RCF borrowings, or other debt financing, attributable to the acquisitions of the Non-Operated Marcellus Interest, the Anadarko-Operated Marcellus Interest and the TEFR Interests. These indemnification agreements apply to the 2044 Notes, 2018 Notes and/or RCF borrowings outstanding related to the aforementioned acquisitions.
The Partnership’s general partner, the other indemnifying subsidiaries of Anadarko and WGRI also amended and restated the indemnity agreements between them to (i) conform language among all the indemnification agreements and (ii) reduce the amount for which WGRI would indemnify the Partnership’s general partner by an amount equal to any amounts payable to the Partnership’s general partner under the indemnification agreements related to the acquisitions of the Non-Operated Marcellus Interest, the Anadarko-Operated Marcellus Interest and the TEFR Interests.

Interest expense. The following table summarizes the amounts included in interest expense:
 
 
Year Ended December 31,
thousands
 
2015
 
2014
 
2013
Third parties
 
 
 
 
 
 
Long-term debt
 
$
102,058

 
$
81,495

 
$
59,293

Amortization of debt issuance costs and commitment fees
 
5,734

 
5,103

 
4,449

Capitalized interest
 
(8,318
)
 
(9,832
)
 
(11,945
)
Total interest expense – third parties
 
99,474

 
76,766

 
51,797

Affiliates
 
 
 
 
 
 
Deferred purchase price obligation – Anadarko (1)
 
14,398

 

 

Total interest expense – affiliates
 
14,398

 

 

Interest expense
 
$
113,872

 
$
76,766

 
$
51,797

                                                                                                                                                                                    
(1) 
See Note 2 for a discussion of the accretion and net present value of the Deferred purchase price obligation - Anadarko.


38


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


13.  COMMITMENTS AND CONTINGENCIES

Environmental obligations. The Partnership is subject to various environmental-remediation obligations arising from federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. As of December 31, 2015 and 2014, the consolidated balance sheets included $2.6 million and $2.0 million, respectively, of liabilities for remediation and reclamation obligations. The current portion of these amounts is included in Accrued liabilities and the long-term portion of these amounts is included in Asset retirement obligations and other. The recorded obligations do not include any anticipated insurance recoveries. The majority of payments related to these obligations are expected to be made over the next five years. Management regularly monitors the remediation and reclamation process and the liabilities recorded and believes that the amounts reflected in the Partnership’s recorded environmental obligations are adequate to fund remedial actions to comply with present laws and regulations, and that the ultimate liability for these matters, if any, will not differ materially from recorded amounts nor materially affect the Partnership’s overall results of operations, cash flows or financial condition. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental issues will not be discovered. See Note 10 and Note 11.

Litigation and legal proceedings. In March 2011, DCP Midstream, LP (“DCP”) filed a lawsuit against Anadarko and others, including a Partnership subsidiary, Kerr-McGee Gathering, LLC, in Weld County District Court (the “Court”) in Colorado, alleging that Anadarko diverted gas from DCP’s gathering and processing facilities in breach of certain dedication agreements. In addition to various claims against Anadarko, DCP is claiming unjust enrichment and other damages against Kerr-McGee Gathering, LLC, the entity that holds the Wattenberg assets (located within the DJ Basin complex). Anadarko countersued DCP asserting that DCP has not properly allocated values and charges to Anadarko for the gas that DCP gathers and/or processes, and seeks a judgment that DCP has no valid gathering or processing rights to much of the gas production it is claiming, in addition to other claims. In January 2016, the parties entered into a settlement of these matters and the lawsuit was dismissed in February 2016 with no cash impact to the Partnership.
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 the final disposition of which could have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows.

Other commitments. The Partnership has short-term payment obligations, or commitments, related to its capital spending programs, as well as those of its unconsolidated affiliates. As of December 31, 2015, the Partnership had unconditional payment obligations for services to be rendered or products to be delivered in connection with its capital projects of $45.0 million, the majority of which is expected to be paid in the next twelve months. These commitments relate primarily to the construction of Trains IV and V at the DBM complex, progress payments made towards the construction of Train VI, also at the DBM complex, and expansion projects at the DBJV system and the DJ Basin complex.

Lease commitments. Anadarko, on behalf of the Partnership, has entered into lease agreements for corporate offices, shared field offices and a warehouse supporting the Partnership’s operations, for which Anadarko charges the Partnership rent. The leases for the corporate offices and shared field offices extend through 2017 and 2018, respectively, and the lease for the warehouse extends through February 2017.
Rent expense associated with the office, warehouse and equipment leases was $34.1 million, $25.9 million and $22.3 million for the years ended December 31, 2015, 2014 and 2013, respectively.


39


WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


13.  COMMITMENTS AND CONTINGENCIES (CONTINUED)

The amounts in the table below represent existing contractual operating lease obligations as of December 31, 2015, that may be assigned or otherwise charged to the Partnership pursuant to the reimbursement provisions of the omnibus agreement:
thousands
Operating Leases
2016
$
9,076

2017
7,756

2018
733

2019
624

2020
122

Thereafter

Total
$
18,311


14.  SUBSEQUENT EVENTS

On March 14, 2016, the Partnership acquired Anadarko’s 100% interest in Springfield (see Note 2). The Partnership financed the acquisition of Springfield through the issuance of $449.0 million in aggregate amount of 8.5% perpetual convertible preferred units to private investors at a price of $32.00 per unit, the issuance of 1,253,761 and 835,841 of the Partnership’s common units at a price of $29.91 per common unit to Anadarko and WGP, respectively, and the borrowing of $247.5 million on the RCF. The convertible preferred units issuance included an over-allotment feature that resulted in the issuance of an additional $252.6 million in aggregate amount of such convertible preferred units in April 2016, the net proceeds from which were used to pay down RCF borrowings. Total net proceeds from the issuance of the convertible preferred units, including the units issued in connection with the over-allotment option, were $687.5 million. Additionally, the convertible preferred units will pay a distribution of $2.72 per year and, subject to certain limitations and adjustments, become convertible into the Partnership’s common units on a one-for-one basis on the second anniversary of the issuance of such convertible preferred units. WGP funded its WES unit purchase by drawing on a secured revolving credit facility that closed on the closing date of the Springfield acquisition.


40


WESTERN GAS PARTNERS, LP
SUPPLEMENTAL QUARTERLY INFORMATION
(UNAUDITED)

The following table presents a summary of the Partnership’s operating results by quarter for the years ended December 31, 2015 and 2014. The Partnership’s operating results reflect the operations of the Partnership assets (as defined in Note 1—Summary of Significant Accounting Policies) from the dates of common control, unless otherwise noted. See Note 1—Summary of Significant Accounting Policies and Note 2—Acquisitions and Divestitures.
thousands except per-unit amounts
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
2015
 
 
 
 
 
 
 
Total revenues and other
$
437,006

 
$
465,993

 
$
432,515

 
$
416,558

Equity income, net
18,220

 
18,941

 
21,976

 
12,114

Gain (loss) on divestiture and other, net
(6
)
 

 
77,254

 
(20,224
)
Operating income (loss) (1)
(122,333
)
 
170,713

 
226,432

 
(117,482
)
Net income (loss) (1)
(153,267
)
 
135,159

 
186,325

 
(154,010
)
Net income (loss) attributable to Western Gas Partners, LP (1)
(156,493
)
 
132,343

 
184,137

 
(155,881
)
Net income (loss) per common unit – basic and diluted (1) (2)
(1.61
)
 
0.46

 
0.79

 
(1.60
)
2014
 
 
 
 
 
 
 
Total revenues and other
$
334,197

 
$
393,273

 
$
399,126

 
$
406,781

Equity income, net
9,251

 
13,008

 
19,063

 
16,514

Operating income (loss)
121,520

 
138,276

 
154,587

 
140,348

Net income (loss)
104,821

 
113,318

 
126,546

 
111,983

Net income (loss) attributable to Western Gas Partners, LP
101,129

 
109,869

 
122,682

 
108,963

Net income (loss) per common unit – basic and diluted (2)
0.54

 
0.57

 
0.60

 
0.42

                                                                                                                                                                                    
(1) 
Includes impairments at the Red Desert complex in the first and fourth quarters of 2015 and at the Hilight system in the fourth quarter of 2015. See Note 7—Property, Plant and Equipment.
(2) 
Represents net income (loss) earned on and subsequent to the acquisition of the Partnership assets (as defined in Note 1—Summary of Significant Accounting Policies).


41