Edgar Filing: Western Gas Partners LP

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10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q/A

(Amendment No. 1)

(Mark One)


☑	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2015


☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 001-34046

WESTERN GAS PARTNERS, LP

(Exact name of registrant as specified in its charter)



Delaware		26-1075808
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1201 Lake Robbins Drive The Woodlands, Texas		77380
(Address of principal executive offices)		(Zip Code)

(832) 636-6000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

There were 128,574,646 common units outstanding as of October 26, 2015.

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For purposes of this report, “we,” “us,” “our,” the “Partnership” or “Western Gas Partners” refers to Western Gas Partners, LP and its subsidiaries. “Anadarko” refers to Anadarko Petroleum Corporation and its subsidiaries, excluding us and our general partner.

Explanatory Note

We are filing this Amendment No. 1 on Form 10-Q/A (this “Form 10-Q/A”) to amend our Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, originally filed with the Securities and Exchange Commission (the “SEC”) on October 29, 2015 (the “Original Filing”), to restate our unaudited consolidated financial statements and related disclosures as of, and for the three and nine months ended, September 30, 2015. This Form 10-Q/A also amends certain other items in the Original Filing, as noted below.

Restatement Background

In connection with the preparation of our Annual Report on Form 10-K for the fiscal year ended December 31, 2015, we determined that there was an error in the impairment test calculation performed as of March 31, 2015. Specifically, the impact of our commodity price swap agreements with Anadarko was incorrectly included when performing an assessment to identify a triggering event that would necessitate a calculation to determine whether the net book value of certain midstream assets exceeded their fair value. We determined that the error caused a material understatement in our impairment expense for the quarter ended March 31, 2015.

As a result of the discovery of this error, on January 27, 2016, the Audit Committee of the Board of Directors of our general partner, after discussion with management and KPMG LLP, our independent registered public accounting firm, concluded that the unaudited consolidated financial statements included in our Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2015, June 30, 2015, and September 30, 2015, should no longer be relied upon due to changes related to impairments.

Accordingly, we are restating our unaudited consolidated financial statements as of, and for the three and nine months ended, September 30, 2015, to reflect an impairment charge in the first quarter of 2015 of $264.4 million related to the Red Desert complex, located in southwestern Wyoming. This impairment loss recorded as of March 31, 2015, also impacts depreciation and amortization for the three and nine months ended September 30, 2015. See Note 1—Description of Business and Basis of Presentation (Restated) in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q/A for more information regarding the impact of this adjustment.

In connection with the need to restate our unaudited consolidated financial statements as a result of the error noted above, we have determined that it would be appropriate within this Form 10-Q/A to make adjustments for certain previously unrecorded immaterial adjustments. See Note 1—Description of Business and Basis of Presentation (Restated) in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q/A for more information regarding the impact of such adjustments.

This report on Form 10-Q/A is presented as of the filing date of the Original Filing and does not reflect events occurring after that date, or modify or update the information contained therein in any way other than as required to correct the error and record the adjustments described above.

Internal Control Consideration

The Chief Executive Officer and Chief Financial Officer of our general partner have determined that there was a deficiency in our internal control over financial reporting that constituted a material weakness, as defined by SEC regulations, at September 30, 2015. For a discussion of management’s evaluation of our disclosure controls and procedures and the material weakness identified, see Part I, Item 4 of this Form 10-Q/A.

Table of Contents

TABLE OF CONTENTS



			PAGE
PART I		FINANCIAL INFORMATION (UNAUDITED)
	Item 1.	Financial Statements
		Consolidated Statements of Income for the three and nine months ended September 30, 2015 (Restated) and 2014	5
		Consolidated Balance Sheets as of September 30, 2015 (Restated), and December 31, 2014	6
		Consolidated Statement of Equity and Partners’ Capital for the nine months ended September 30, 2015 (Restated)	7
		Consolidated Statements of Cash Flows for the nine months ended September 30, 2015 (Restated) and 2014	8
		Notes to Consolidated Financial Statements	9
		Note 1. Description of Business and Basis of Presentation (Restated)	9
		Note 2. Acquisitions and Divestitures	14
		Note 3. Partnership Distributions	16
		Note 4. Equity and Partners’ Capital (Restated)	17
		Note 5. Transactions with Affiliates	19
		Note 6. Property, Plant and Equipment (Restated)	23
		Note 7. Equity Investments	23
		Note 8. Components of Working Capital (Restated)	24
		Note 9. Debt and Interest Expense	24
		Note 10. Commitments and Contingencies	26
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
		Cautionary Note Regarding Forward-Looking Statements	27
		Executive Summary	30
		Acquisitions and Divestitures	31
		Equity Offerings	32
		Items Affecting the Comparability of Financial Results	32
		Results of Operations	33
		Operating Results	33
		Key Performance Metrics	40
		Liquidity and Capital Resources	46
		Contractual Obligations	51
		Off-Balance Sheet Arrangements	51
		Recent Accounting Developments	51
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	52
	Item 4.	Controls and Procedures	53
PART II		OTHER INFORMATION
	Item 1.	Legal Proceedings	54
	Item 1A.	Risk Factors	54
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	55
	Item 6.	Exhibits	56

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DEFINITIONS

As generally used within the energy industry and in this quarterly report on Form 10-Q/A, the identified terms have the following meanings:

Barrel or Bbl: 42 U.S. gallons measured at 60 degrees Fahrenheit.

Btu: British thermal unit; the approximate amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Condensate: A natural gas liquid with a low vapor pressure mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.

Cryogenic: The process in which liquefied gases, such as liquid nitrogen or liquid helium, are used to bring volumes to very low temperatures (below approximately -238 degrees Fahrenheit) to separate natural gas liquids from natural gas. Through cryogenic processing, more natural gas liquids are extracted than when traditional refrigeration methods are used.

Drip condensate: Heavier hydrocarbon liquids that fall out of the natural gas stream and are recovered in the gathering system without processing.

Imbalance: Imbalances result from (i) differences between gas volumes nominated by customers and gas volumes received from those customers and (ii) differences between gas volumes received from customers and gas volumes delivered to those customers.

MBbls/d: One thousand barrels per day.

MMBtu: One million British thermal units.

MMcf/d: One million cubic feet per day.

Natural gas liquid(s) or NGL(s): The combination of ethane, propane, normal butane, isobutane and natural gasolines that, when removed from natural gas, become liquid under various levels of higher pressure and lower temperature.

Residue: The natural gas remaining after the unprocessed natural gas stream has been processed or treated.

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PART I. FINANCIAL INFORMATION (UNAUDITED)

Item 1. Financial Statements

WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF INCOME

(UNAUDITED)



	Three Months Ended September 30,						Nine Months Ended September 30,
thousands except per-unit amounts	2015 (Restated)			2014 ⁽¹⁾			2015 (Restated)			2014 ⁽¹⁾
Revenues and other – affiliates
Gathering, processing and transportation of natural gas and natural gas liquids	$	141,556		$	124,829		$	431,182		$	340,775
Natural gas, natural gas liquids and drip condensate sales	105,032			142,025			345,385			424,207
Other	870			2,778			1,172			4,349
Total revenues and other – affiliates	247,458			269,632			777,739			769,331
Revenues and other – third parties
Gathering, processing and transportation of natural gas and natural gas liquids	94,082			70,996			267,566			201,985
Natural gas, natural gas liquids and drip condensate sales	41,968			11,647			141,489			37,533
Other	1,593			5,246			3,288			7,302
Total revenues and other – third parties	137,643			87,889			412,343			246,820
Total revenues and other	385,101			357,521			1,190,082			1,016,151
Equity income, net ⁽²⁾	21,976			19,063			59,137			41,322
Operating expenses
Cost of product ⁽³⁾	127,721			113,217			414,378			330,926
Operation and maintenance ⁽³⁾	80,633			67,489			218,640			184,023
General and administrative ⁽³⁾	9,318			8,339			28,497			25,688
Property and other taxes	8,343			6,793			25,641			21,343
Depreciation and amortization	60,160			46,379			183,715			132,236
Impairments	2,337			898			276,229			2,431
Total operating expenses	288,512			243,115			1,147,100			696,647
Gain on divestiture, net	77,244			—			77,244			—
Operating income (loss)	195,809			133,469			179,363			360,826
Interest income – affiliates	4,225			4,225			12,675			12,675
Interest expense ⁽⁴⁾	(31,773		)	(20,878		)	(82,337		)	(55,703		)
Other income (expense), net	85			97			227			788
Income (loss) before income taxes	168,346			116,913			109,928			318,586
Income tax (benefit) expense	1,869			3,891			3,575			8,199
Net income (loss)	166,477			113,022			106,353			310,387
Net income attributable to noncontrolling interest	2,188			3,863			8,230			11,005
Net income (loss) attributable to Western Gas Partners, LP	$	164,289		$	109,159		$	98,123		$	299,382
Limited partners’ interest in net income (loss):
Net income (loss) attributable to Western Gas Partners, LP	$	164,289		$	109,159		$	98,123		$	299,382
Pre-acquisition net (income) loss allocated to Anadarko	—			(6,482		)	(1,742		)	(13,282		)
General partner interest in net (income) loss ⁽⁵⁾	(50,267		)	(31,058		)	(133,415		)	(83,939		)
Limited partners’ interest in net income (loss) ⁽⁵⁾	114,022			71,619			(37,034		)	202,161
Net income (loss) per common unit – basic ⁽⁶⁾	$	0.79		$	0.60		$	(0.35	)	$	1.71
Net income (loss) per common unit – diluted ⁽⁶⁾	0.79			0.60			(0.35		)	1.71


⁽¹⁾	Financial information has been recast to include the financial position and results attributable to the DBJV system. 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 $35.7 million and $132.7 million for the three and nine months ended September 30, 2015, respectively, and $27.0 million and $85.1 million for the three and nine months ended September 30, 2014, respectively. Operation and maintenance includes charges from Anadarko of $17.7 million and $50.5 million for the three and nine months ended September 30, 2015, respectively, and $15.6 million and $45.0 million for the three and nine months ended September 30, 2014, respectively. General and administrative includes charges from Anadarko of $7.7 million and $22.6 million for the three and nine months ended September 30, 2015, respectively, and $7.0 million and $21.2 million for the three and nine months ended September 30, 2014, respectively. See Note 5.


⁽⁴⁾	Includes affiliate (as defined in Note 1) interest expense of $4.3 million and $9.9 million for the three and nine months ended September 30, 2015, respectively, and zero for each of the three and nine months ended September 30, 2014. See Note 2 and Note 9.


⁽⁵⁾	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.


⁽⁶⁾	See Note 4 for the calculation of net income (loss) per unit.

See accompanying Notes to Consolidated Financial Statements.

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WESTERN GAS PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)



thousands except number of units	September 30, 2015 (Restated)		December 31, 2014 ⁽¹⁾
ASSETS
Current assets
Cash and cash equivalents	$	73,200	$	67,054
Accounts receivable, net ⁽²⁾	150,538		109,243
Other current assets ⁽³⁾	11,399		10,067
Total current assets	235,137		186,364
Note receivable – Anadarko	260,000		260,000
Property, plant and equipment
Cost	5,862,721		5,626,650
Less accumulated depreciation	1,330,802		1,055,207
Net property, plant and equipment	4,531,919		4,571,443
Goodwill	387,633		389,087
Other intangible assets	839,234		884,857
Equity investments	629,627		634,492
Other assets	30,779		28,289
Total assets	$	6,914,329	$	6,954,532
LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
Current liabilities
Accounts and natural gas imbalance payables ⁽⁴⁾	$	57,598	$	54,232
Accrued ad valorem taxes	26,416		14,812
Accrued liabilities	138,579		170,789
Total current liabilities	222,593		239,833
Long-term debt	2,587,189		2,422,954
Deferred income taxes	6,540		45,656
Asset retirement obligations and other	119,422		111,714
Deferred purchase price obligation – Anadarko ⁽⁵⁾	184,196		—
Total long-term liabilities	2,897,347		2,580,324
Total liabilities	3,119,940		2,820,157
Equity and partners’ capital
Common units (128,574,646 and 127,695,130 units issued and outstanding at September 30, 2015, and December 31, 2014, respectively)	2,882,831		3,119,714
Class C units (11,230,814 and 10,913,853 units issued and outstanding at September 30, 2015, and December 31, 2014, respectively)	724,922		716,957
General partner units (2,583,068 units issued and outstanding at September 30, 2015, and December 31, 2014)	119,086		105,725
Net investment by Anadarko	—		122,509
Total partners’ capital	3,726,839		4,064,905
Noncontrolling interest	67,550		69,470
Total equity and partners’ capital	3,794,389		4,134,375
Total liabilities, equity and partners’ capital	$	6,914,329	$	6,954,532


⁽¹⁾	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.


⁽²⁾	Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $46.9 million and $64.7 million as of September 30, 2015, and December 31, 2014, respectively.


⁽³⁾	Other current assets includes natural gas imbalance receivables from affiliates of zero and $0.2 million as of September 30, 2015, and December 31, 2014, respectively.


⁽⁴⁾	Accounts and natural gas imbalance payables includes amounts payable to affiliates of zero and $0.1 million as of September 30, 2015, and December 31, 2014, respectively.


⁽⁵⁾	See Note 2.

See accompanying Notes to Consolidated Financial Statements.

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WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENT OF EQUITY AND PARTNERS’ CAPITAL

(UNAUDITED)



	Partners’ Capital
thousands	Net Investment by Anadarko			Common Units			Class C Units			General Partner Units			Noncontrolling Interest			Total
Balance at December 31, 2014 ⁽¹⁾	$	122,509		$	3,119,714		$	716,957		$	105,725		$	69,470		$	4,134,375
Net income (loss)	1,742			(35,752		)	(1,282		)	133,415			8,230			106,353
Above-market component of swap extensions with Anadarko ⁽²⁾	—			7,916			—			—			—			7,916
Issuance of common units, net of offering expenses	—			57,353			—			—			—			57,353
Amortization of beneficial conversion feature of Class C units	—			(9,247		)	9,247			—			—			—
Distributions to noncontrolling interest owner	—			—			—			—			(10,150		)	(10,150		)
Distributions to unitholders	—			(278,956		)	—			(120,027		)	—			(398,983		)
Acquisitions from affiliates	(197,562		)	23,286			—			—			—			(174,276		)
Contributions of equity-based compensation from Anadarko	—			2,625			—			54			—			2,679
Net pre-acquisition contributions from (distributions to) Anadarko	31,467			—			—			—			—			31,467
Net distributions to Anadarko of other assets	—			(4,305		)	—			(81		)	—			(4,386		)
Elimination of net deferred tax liabilities	41,844			—			—			—			—			41,844
Other	—			197			—			—			—			197
Balance at September 30, 2015 (Restated)	$	—		$	2,882,831		$	724,922		$	119,086		$	67,550		$	3,794,389


⁽¹⁾	Financial information has been recast to include the financial position and results attributable to the DBJV system. See Note 1 and Note 2.


⁽²⁾	See Note 5.

See accompanying Notes to Consolidated Financial Statements.

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WESTERN GAS PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)



	Nine Months Ended September 30,
thousands	2015 (Restated)			2014 ⁽¹⁾
Cash flows from operating activities
Net income (loss)	$	106,353		$	310,387
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	183,715			132,236
Impairments	276,229			2,431
Non-cash equity-based compensation expense	3,257			3,210
Deferred income taxes	2,496			4,024
Accretion and amortization of long-term obligations, net	12,296			2,045
Equity income, net ⁽²⁾	(59,137		)	(41,322		)
Distributions from equity investment earnings ⁽²⁾	60,645			43,061
Gain on divestiture, net	(77,244		)	—
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net	(24,104		)	(52,659		)
Increase (decrease) in accounts and natural gas imbalance payables and accrued liabilities, net	15,719			35,807
Change in other items, net	(1,817		)	1,645
Net cash provided by operating activities	498,408			440,865
Cash flows from investing activities
Capital expenditures	(473,394		)	(529,197		)
Contributions in aid of construction costs from affiliates	—			183
Acquisitions from affiliates	(12,131		)	(372,393		)
Acquisitions from third parties	(3,514		)	—
Investments in equity affiliates	(9,052		)	(63,267		)
Distributions from equity investments in excess of cumulative earnings ⁽²⁾	12,409			14,387
Proceeds from the sale of assets to affiliates	700			—
Proceeds from the sale of assets to third parties	146,993			5
Net cash used in investing activities	(337,989		)	(950,282		)
Cash flows from financing activities
Borrowings, net of debt issuance costs	769,606			1,136,878
Repayments of debt	(610,000		)	(480,000		)
Increase (decrease) in outstanding checks	(1,482		)	2,908
Proceeds from the issuance of common and general partner units, net of offering expenses	57,353			101,502
Distributions to unitholders	(398,983		)	(297,013		)
Distributions to noncontrolling interest owner	(10,150		)	(11,349		)
Net contributions from Anadarko	31,467			23,600
Above-market component of swap extensions with Anadarko ⁽³⁾	7,916			—
Net cash provided by (used in) financing activities	(154,273		)	476,526
Net increase (decrease) in cash and cash equivalents	6,146			(32,891		)
Cash and cash equivalents at beginning of period	67,054			100,728
Cash and cash equivalents at end of period	$	73,200		$	67,837
Supplemental disclosures
Acquisition of DBJV from Anadarko ⁽⁴⁾	$	174,276		$	—
Net distributions to (contributions from) Anadarko of other assets	4,386			6,398
Interest paid, net of capitalized interest	60,612			43,504
Taxes paid (reimbursements received)	(138		)	(340		)
Capital lease asset transfer ⁽⁵⁾	—			4,833


⁽¹⁾	Financial information has been recast to include the financial position and results attributable to the DBJV system. 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⁾	See Note 5.


⁽⁴⁾	See Note 2.


⁽⁵⁾	For the nine months ended September 30, 2014, represents transfers of $4.6 million from other long-term assets associated with the capital lease component of a processing agreement.

See accompanying Notes to Consolidated Financial Statements.

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

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 September 30, 2015, the Partnership’s assets and investments accounted for under the equity method consisted of the following:



	Owned and Operated	Operated Interests	Non-Operated Interests	Equity Interests
Natural gas gathering systems	12	2	5	2
Natural gas treating facilities	9	4	—	1
Natural gas processing facilities	14	5	—	2
NGL pipelines	3	—	—	3
Natural gas pipelines	4	—	—	—
Oil pipelines	1	—	—	1

These assets and investments are located in the Rocky Mountains (Colorado, Utah and Wyoming), the Mid-Continent (Kansas and Oklahoma), North-central Pennsylvania and Texas. In June 2015, the Partnership completed the construction and commenced operations of Lancaster Train II, a processing plant located in the DJ Basin complex. In addition, the Partnership is constructing Trains IV, V and VI, all 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, and mid-2017 (Train VI).

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION (RESTATED) (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. Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. The Partnership proportionately consolidates its 33.75% share of the assets, liabilities, revenues and expenses attributable to the Non-Operated Marcellus Interest systems and Anadarko-Operated Marcellus Interest systems and its 50% share of the assets, liabilities, revenues and expenses attributable to the Newcastle system and the DBJV system (see 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.

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

Certain information and note disclosures commonly included in annual financial statements have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, the accompanying consolidated financial statements and notes should be read in conjunction with the Partnership’s 2014 Form 10-K, as filed with the SEC on February 26, 2015. Management believes that the disclosures made are adequate to make the information not misleading.

Restatement of Previously Issued Financial Statements. In connection with the preparation of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2015, the Partnership determined that there was an error in the impairment test calculation performed as of March 31, 2015. Specifically, the impact of the Partnership’s commodity price swap agreements with Anadarko was incorrectly included when performing an assessment to identify a triggering event that would necessitate a calculation to determine whether the net book value of certain midstream assets exceeded their fair value. The Partnership determined that the error caused a material understatement in its impairment expense for the quarter ended March 31, 2015. Accordingly, the Partnership’s unaudited consolidated financial statements as of, and for the three and nine months ended, September 30, 2015, and notes thereto, have been restated to reflect an impairment charge of $264.4 million related to its Red Desert complex. The impairment loss recorded as of March 31, 2015, also impacts depreciation and amortization for the three and nine months ended September 30, 2015.

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

The tables below outline the financial statement line items, including the net income (loss) per common unit (basic and diluted), as of and for the three and nine months ended September 30, 2015, that were restated as a result of the correction of this error:



	Consolidated Statement of Income for the Three Months Ended September 30, 2015									Consolidated Statement of Income for the Nine Months Ended September 30, 2015
thousands except per-unit amounts	As Reported			Adjustments			As Restated			As Reported			Adjustments			As Restated
Depreciation and amortization ⁽¹⁾	$	63,351		$	(3,191	)	$	60,160		$	190,114		$	(6,399	)	$	183,715
Impairments ⁽¹⁾	2,337			—			2,337			11,827			264,402			276,229
Operating income (loss)	192,618			3,191			195,809			437,366			(258,003		)	179,363
Income (loss) before income taxes	165,155			3,191			168,346			367,931			(258,003		)	109,928
Income tax (benefit) expense	1,661			208			1,869			4,305			(730		)	3,575
Net income (loss)	163,494			2,983			166,477			363,626			(257,273		)	106,353
Net income (loss) attributable to Western Gas Partners, LP	161,306			2,983			164,289			355,396			(257,273		)	98,123

General partner interest in net (income) loss	(50,213		)	(54		)	(50,267		)	(138,121		)	4,706			(133,415		)
Limited partners’ interest in net income (loss)	111,093			2,929			114,022			215,533			(252,567		)	(37,034		)
Net income (loss) per common unit – basic	$	0.77		$	0.02		$	0.79		$	1.46		$	(1.81	)	$	(0.35	)
Net income (loss) per common unit – diluted	0.77			0.02			0.79			1.46			(1.81		)	(0.35		)


⁽¹⁾	“As Reported” amounts previously included as a component of Depreciation, amortization and impairments in the Partnership’s Original Filing.



	Consolidated Balance Sheet as of September 30, 2015
thousands	As Reported		Adjustments			As Restated
Accumulated depreciation	$	1,072,799	$	258,003		$	1,330,802
Net property, plant and equipment	4,789,922		(258,003		)	4,531,919
Total assets	7,172,332		(258,003		)	6,914,329

Accrued liabilities	138,812		(233		)	138,579
Total current liabilities	222,826		(233		)	222,593
Deferred income taxes	7,037		(497		)	6,540
Total long-term liabilities	2,897,844		(497		)	2,897,347
Total liabilities	3,120,670		(730		)	3,119,940

Common units	3,115,480		(232,649		)	2,882,831
Class C units	744,840		(19,918		)	724,922
General partner units	123,792		(4,706		)	119,086
Total partners’ capital	3,984,112		(257,273		)	3,726,839
Total equity and partners’ capital	4,051,662		(257,273		)	3,794,389
Total liabilities, equity and partners’ capital	7,172,332		(258,003		)	6,914,329

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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



	Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2015
thousands	As Reported		Adjustments			As Restated
Net income (loss)	$	363,626	$	(257,273	)	$	106,353
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization ⁽¹⁾	190,114		(6,399		)	183,715
Impairments ⁽¹⁾	11,827		264,402			276,229
Deferred income taxes	2,993		(497		)	2,496
Increase (decrease) in accounts and natural gas imbalance payables and accrued liabilities, net	15,952		(233		)	15,719


⁽¹⁾	“As Reported” amounts previously included as a component of Depreciation, amortization and impairments in the Partnership’s Original Filing.

Adjustments to Previously Issued Financial Statements. The Partnership’s unaudited consolidated statements of income also reflect adjustments for the following amounts, which previously reduced Operation and maintenance expense, to revenues related to Gathering, processing and transportation of natural gas and natural gas liquids: (i) $25.0 million for the nine months ended September 30, 2015 (all of which relates to the six months ended June 30, 2015) and (ii) $12.0 million and $28.6 million for the three and nine months ended September 30, 2014, respectively. Management determined that the third-party producer reimbursements received for electricity purchased by the Partnership are more appropriately classified as revenues, instead of as a reduction to Operation and maintenance expense. The correction of this error has no impact to Net income (loss), cash flows, or any non-GAAP metric the Partnership uses to evaluate its operations (see Key Performance Metrics under Part I, Item 2 of this Form 10-Q/A) and is not considered material to the Partnership’s results of operations for the three and nine months ended September 30, 2015 and 2014. In future filings, the Partnership will revise its previously reported consolidated financial statements for 2013, 2014 and 2015 to reflect these adjustments.

Presentation of Partnership assets. The term “Partnership assets” refers to the assets owned and interests accounted for under the equity method (see Note 7) by the Partnership as of September 30, 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

Recently issued accounting standards. The Financial Accounting Standards Board recently issued the following Accounting Standards Updates (“ASUs”):

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 will simplify the presentation of debt issuance costs by requiring such 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. These ASUs are effective for annual and interim periods beginning in 2016 and are required to be adopted using a retrospective approach, with early adoption permitted. The Partnership does not expect the adoption to have a material impact on its consolidated financial statements.

ASU 2015-02, Consolidation—Amendments to the Consolidation Analysis. This ASU will simplify existing requirements by reducing the number of acceptable consolidation models and placing more emphasis on risk of loss when determining a controlling financial interest. The provisions will affect how limited partnerships and similar entities are assessed for consolidation, including the elimination of the presumption that a general partner should consolidate a limited partnership. 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 is evaluating the impact of the adoption of this ASU on its consolidated financial statements.

ASU 2014-09, Revenue from Contracts with Customers. This ASU supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities—Oil and Gas—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 effective date for ASU 2014-09 was delayed through the issuance of ASU 2015-14, Revenue from Contracts with Customers—Deferral of the Effective Date, to annual and interim periods beginning in 2018 and is required to be adopted using one of two retrospective application methods, with early adoption permitted in 2017. The Partnership is evaluating the impact of the adoption of this ASU on its consolidated financial statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

2. ACQUISITIONS AND DIVESTITURES

The following table presents the acquisitions completed by the Partnership during 2015 and 2014, 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
TEFR Interests ⁽¹⁾	03/03/2014	Various ⁽¹⁾		$	—	$	350,000	$	6,250	308,490	—
DBM ⁽²⁾	11/25/2014	100	%	—		475,000		298,327		—	10,913,853
DBJV system ⁽³⁾	03/02/2015	50	%	174,276		—		—		—	—

⁽¹⁾

The Partnership acquired a 20% interest in each of TEG and TEP and a 33.33% interest in FRP from Anadarko. These assets gather and transport NGLs primarily from the Anadarko and Denver-Julesburg (“DJ”) Basins. The interests in these entities are accounted for under the equity method of accounting. In connection with the issuance of the common units, the Partnership issued 6,296 general partner units to the general partner in exchange for the general partner’s proportionate capital contribution of $0.4 million.

⁽²⁾

The Partnership acquired Nuevo Midstream, LLC (“Nuevo”) from a third party. Following the acquisition, the Partnership changed the name of Nuevo to Delaware Basin Midstream, LLC (“DBM”). The assets acquired include cryogenic processing plants, a gas gathering system, and related facilities and equipment, which are collectively referred to as the “DBM complex” and serve production from Reeves, Loving and Culberson Counties, Texas and Eddy and Lea Counties, New Mexico. See DBM acquisition below for further information, including the preliminary allocation of the purchase price.

⁽³⁾

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.

DBJV acquisition. Because the acquisition of DBJV was a transfer 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 10-Q/A to include the results attributable to the DBJV system as if the Partnership owned DBJV for all periods presented. The consolidated financial statements for periods prior to the Partnership’s acquisition of DBJV 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 during the periods reported.

The following table presents the impact of the DBJV system on revenues and other, equity income, net and net income (loss) as presented in the Partnership’s historical consolidated statements of income:



	Three Months Ended September 30, 2014
thousands	Partnership Historical ⁽¹⁾		DBJV System		Combined
Revenues and other	$	341,282	$	16,239	$	357,521
Equity income, net	19,063		—		19,063
Net income (loss)	106,540		6,482		113,022

	Nine Months Ended September 30, 2014
thousands	Partnership Historical ⁽¹⁾		DBJV System		Combined
Revenues and other	$	970,027	$	46,124	$	1,016,151
Equity income, net	41,322		—		41,322
Net income (loss)	296,149		14,238		310,387


⁽¹⁾	See Adjustments to Previously Issued Financial Statements in Note 1.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 was $282.8 million, which had a net present value of $174.3 million, using a discount rate of 10%. As of September 30, 2015, the net present value of this obligation was $184.2 million and has been recorded on the consolidated balance sheet under Deferred purchase price obligation - Anadarko. Accretion expense for the three and nine months ended September 30, 2015, was $4.3 million and $9.9 million, respectively, and has been recorded as a charge to interest expense. The fair value measurement was calculated using Level 3 inputs, which consisted of management’s estimate of the Partnership’s share of forecasted Net Earnings and capital expenditures for the DBJV system.

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 preliminary allocation of the purchase price as of September 30, 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, pending final review of certain support related to the acquired entity’s assets and liabilities:



thousands
Current assets	$	62,940
Property, plant and equipment	467,171
Goodwill	282,697
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.

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 $146.7 million, after closing adjustments, resulting in a net gain on sale of $77.2 million recorded as Gain on divestiture, net in the Partnership’s consolidated statements of income.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

3. PARTNERSHIP DISTRIBUTIONS

The partnership agreement of Western Gas Partners, LP 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
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 ⁽¹⁾	0.775		146,160		November 2015

⁽¹⁾

On October 14, 2015, the Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.775 per unit, or $146.2 million in aggregate, including incentive distributions, but excluding distributions on Class C units (see Class C unit distributions below). The cash distribution is payable on November 12, 2015, to unitholders of record at the close of business on November 2, 2015.

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


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

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(UNAUDITED)

4. EQUITY AND PARTNERS’ CAPITAL (RESTATED)

Equity offerings. The Partnership completed the following public offerings of its common units during 2015 and 2014, including through its Continuous Offering Programs (“COP”):



thousands except unit and per-unit amounts	Common Units Issued	GP Units Issued ⁽¹⁾	Price Per Unit		Underwriting Discount and Other Offering Expenses		Net Proceeds
2014
$125.0 million COP ⁽²⁾	1,133,384	23,132	$	73.48	$	1,738	$	83,245
November 2014 equity offering ⁽³⁾	8,620,153	153,061	70.85		18,615		602,967
2015
$500.0 million COP ⁽⁴⁾	873,525	—	$	66.61	$	805	$	57,385


⁽¹⁾	Represents general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution.

⁽²⁾

Represents common and general partner units issued during the year ended December 31, 2014, 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, 2014, were $85.0 million. The price per unit in the table above represents an average price for all issuances under the $125.0 million COP during the year ended December 31, 2014. As of December 31, 2014, the Partnership had used all the capacity to issue common units under this registration statement.


⁽³⁾	Includes the issuance of 1,120,153 common units pursuant to the partial exercise of the underwriters’ over-allotment option, the net proceeds from which were $77.0 million. Beginning with this partial exercise, the Partnership’s general partner elected not to make a corresponding capital contribution to maintain its 2.0% interest in the Partnership.

⁽⁴⁾

Represents common units issued during the nine months ended September 30, 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 and nine months ended September 30, 2015, were zero and $58.2 million, respectively. Commissions paid during the three and nine months ended September 30, 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 nine months ended September 30, 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 September 30, 2015, no such proceeds had been received and no Class C units had been redeemed.

The Class C units were issued at a discount to the then-current market price of the common units into which they are convertible. This discount, totaling $34.8 million, represents a beneficial conversion feature and at December 31, 2014, 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. The Partnership is amortizing the beneficial conversion feature assuming a conversion date of December 31, 2017, using the effective yield method. The impact of the beneficial conversion feature is also included in the calculation of earnings per unit.

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(UNAUDITED)

4. EQUITY AND PARTNERS’ CAPITAL (RESTATED) (CONTINUED)

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 nine months ended September 30, 2015:



	Common Units	Class C Units	General Partner Units	Total
Balance at December 31, 2014	127,695,130	10,913,853	2,583,068	141,192,051
PIK Class C units	—	316,961	—	316,961
Long-Term Incentive Plan award vestings	5,991	—	—	5,991
$500.0 million COP	873,525	—	—	873,525
Balance at September 30, 2015	128,574,646	11,230,814	2,583,068	142,388,528

Holdings of Partnership equity. As of September 30, 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 September 30, 2015, other subsidiaries of Anadarko held 757,619 common units and 11,230,814 Class C units, representing an aggregate 8.4% limited partner interest in the Partnership. As of September 30, 2015, the public held 78,520,822 common units, representing a 55.2% limited partner interest in the Partnership.

Net income (loss) per unit for common units. 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 any Class C unitholders, in accordance with their respective weighted-average ownership percentages and, when applicable, giving effect to incentive distributions allocable to the general partner. The Partnership’s net income (loss) allocable to the limited partners is net of amortization of the beneficial conversion feature related to the Class C units (see Class C units above) and is allocated between the common and Class C unitholders by applying the provisions of the partnership agreement that govern actual cash distributions and capital account allocations, as if all earnings for the period had been distributed. Net income (loss) attributable to the Partnership assets acquired from Anadarko for periods prior to the Partnership’s acquisition of the Partnership assets is not allocated to the limited partners for purposes of calculating net income (loss) per common unit.

Basic net income (loss) per common unit is calculated by dividing the limited partners’ interest in net income (loss) attributable to common unitholders by the weighted-average number of common units outstanding during the period. The common units issued in connection with acquisitions and equity offerings are included on a weighted-average basis for periods they were outstanding. 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.

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

4. EQUITY AND PARTNERS’ CAPITAL (RESTATED) (CONTINUED)

The following table illustrates the Partnership’s calculation of net income (loss) per unit for common units:



	Three Months Ended September 30,						Nine Months Ended September 30,
thousands except per-unit amounts	2015 (Restated)			2014			2015 (Restated)			2014
Net income (loss) attributable to Western Gas Partners, LP	$	164,289		$	109,159		$	98,123		$	299,382
Pre-acquisition net (income) loss allocated to Anadarko	—			(6,482		)	(1,742		)	(13,282		)
General partner interest in net (income) loss	(50,267		)	(31,058		)	(133,415		)	(83,939		)
Limited partners’ interest in net income (loss)	114,022			71,619			(37,034		)	202,161
Net income (loss) allocable to common units ⁽¹⁾	101,140			71,619			(44,999		)	202,161
Net income (loss) allocable to Class C units ⁽¹⁾	12,882			—			7,965			—
Limited partners’ interest in net income (loss)	$	114,022		$	71,619		$	(37,034	)	$	202,161
Net income (loss) per unit
Common units - basic	$	0.79		$	0.60		$	(0.35	)	$	1.71
Common units – diluted ⁽²⁾	0.79			0.60			(0.35		)	1.71
Weighted-average units outstanding
Common units – basic	128,575			119,068			128,267			118,326
Class C units ⁽²⁾	11,161			—			11,042			—
Common units – diluted	139,736			119,068			139,309			118,326


⁽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 would have had an anti-dilutive effect.

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.

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

5. TRANSACTIONS WITH AFFILIATES (CONTINUED)

Note receivable from and Deferred purchase price obligation - Anadarko. Concurrently with the closing of the Partnership’s May 2008 initial public offering, the Partnership loaned $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%, payable quarterly. The fair value of the note receivable from Anadarko was $288.9 million and $317.8 million at September 30, 2015, and December 31, 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 for the March 2015 acquisition of DBJV consists of a cash payment to Anadarko due on March 31, 2020. See Note 2 and Note 9.

Commodity price swap agreements. The Partnership has commodity price swap agreements with Anadarko to mitigate exposure to a substantial 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 at the Hugoton system, the MGR assets and the DJ Basin complex, with various expiration dates through December 2016. 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 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 September 30, 2015:



per barrel except natural gas	2015				2016
Ethane	$	18.41	−	23.41	$	23.11
Propane	47.08		−	52.99	52.90
Isobutane	62.09		−	74.02	73.89
Normal butane	54.62		−	65.04	64.93
Natural gasoline	72.88		−	81.82	81.68
Condensate	76.47		−	81.82	81.68
Natural gas (per MMBtu)	4.66		−	5.96	4.87

The following table summarizes gains and losses upon settlement of commodity price swap agreements recognized in the consolidated statements of income:



	Three Months Ended September 30,						Nine Months Ended September 30,
thousands	2015			2014			2015			2014
Gains (losses) on commodity price swap agreements related to sales:⁽¹⁾
Natural gas sales	$	5,774		$	3,179		$	39,100		$	1,525
Natural gas liquids sales	33,746			22,737			116,475			66,746
Total	39,520			25,916			155,575			68,271
Losses on commodity price swap agreements related to purchases ⁽²⁾	(23,998		)	(19,533		)	(99,897		)	(38,081		)
Net gains (losses) on commodity price swap agreements	$	15,522		$	6,383		$	55,678		$	30,190


⁽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.

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

5. TRANSACTIONS WITH AFFILIATES (CONTINUED)

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 compared to the forward market prices on the date the commodity price swap extensions were executed.



	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 forward strip price as of June 25, 2015, adjusted for location, basis and, in the case of NGLs, transportation and fractionation costs.

Revenues or costs attributable to volumes settled during the respective extension period, at the applicable market price in the above table, 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 table. For each of the three and nine months ended September 30, 2015, the capital contribution from Anadarko was $7.9 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 and throughput measured in barrels) attributable to natural gas production owned or controlled by Anadarko was 42% and 46% for the three and nine months ended September 30, 2015, respectively, and 48% and 49% for the three and nine months ended September 30, 2014, respectively. The Partnership’s processing throughput (excluding equity investment throughput and throughput measured in barrels) attributable to natural gas production owned or controlled by Anadarko was 47% and 51% for the three and nine months ended September 30, 2015, respectively, and 58% for each of the three and nine months ended September 30, 2014.

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

WES LTIP. The general partner awards phantom units under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (“WES LTIP”) primarily to its independent directors, but also from time to time to its executive officers and Anadarko employees performing services for the Partnership. The phantom units awarded to the independent directors vest one year from the grant date, while all other awards are subject to graded vesting over a three-year service period. Compensation expense is recognized over the vesting period and was $0.1 million and $0.4 million for the three and nine months ended September 30, 2015, respectively, and $0.2 million and $0.5 million for the three and nine months ended September 30, 2014, respectively.

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

5. TRANSACTIONS WITH AFFILIATES (CONTINUED)

WGP LTIP and Anadarko Incentive Plans. General and administrative expenses included $1.0 million and $3.1 million for the three and nine months ended September 30, 2015, respectively, and $0.9 million and $2.7 million for the three and nine months ended September 30, 2014, respectively, of equity-based compensation expense, allocated to the Partnership by Anadarko, for awards granted to the executive officers of the general partner and other employees under the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan (“WGP LTIP”) and the Anadarko Petroleum Corporation 2008 and 2012 Omnibus Incentive Compensation Plans (collectively referred to as the “Anadarko Incentive Plans”). Of this amount, $2.7 million is reflected as a contribution to partners’ capital in the Partnership’s consolidated statement of equity and partners’ capital for the nine months ended September 30, 2015.

Equipment purchases and sales. The following table summarizes the Partnership’s purchases from and sales to Anadarko of pipe and equipment:



	Nine Months Ended September 30,
	2015		2014		2015		2014
thousands	Purchases				Sales
Cash consideration	$	12,131	$	16,143	$	700	$	—
Net carrying value	7,411		9,745		366		—
Partners’ capital adjustment	$	4,720	$	6,398	$	334	$	—

Summary of affiliate transactions. The following table summarizes affiliate transactions, which include revenue from affiliates, reimbursement of operating expenses and purchases of natural gas:



	Three Months Ended September 30,				Nine Months Ended September 30,
thousands	2015		2014		2015		2014
Revenues and other ⁽¹⁾	$	247,458	$	269,632	$	777,739	$	769,331
Equity income, net ⁽¹⁾	21,976		19,063		59,137		41,322
Cost of product ⁽¹⁾	35,673		27,034		132,663		85,071
Operation and maintenance ⁽²⁾	17,662		15,583		50,534		44,961
General and administrative ⁽³⁾	7,671		7,016		22,556		21,243
Operating expenses	61,006		49,633		205,753		151,275
Interest income ⁽⁴⁾	4,225		4,225		12,675		12,675
Interest expense ⁽⁵⁾	4,310		—		9,920		—
Distributions to unitholders ⁽⁶⁾	80,845		60,794		228,893		169,001

⁽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. See Adjustments to Previously Issued Financial Statements in Note 1.


⁽²⁾	Represents expenses incurred on and subsequent to the date of the acquisition of the Partnership assets, as well as expenses incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets.

⁽³⁾

Represents general and administrative expense incurred on and subsequent to the date of the Partnership’s acquisition of the Partnership assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of the Partnership assets by the Partnership. These amounts include equity-based compensation expense allocated to the Partnership by Anadarko (see WES LTIP and WGP LTIP and Anadarko Incentive Plans within this Note 5).


⁽⁴⁾	Represents interest income recognized on the note receivable from Anadarko.


⁽⁵⁾	For the three and nine months ended September 30, 2015, includes accretion expense recognized on the Deferred purchase price obligation - Anadarko for the acquisition of DBJV (see Note 2 and Note 9).


⁽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.

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WESTERN GAS PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

6. PROPERTY, PLANT AND EQUIPMENT (RESTATED)

A summary of the historical cost of the Partnership’s property, plant and equipment is as follows:



thousands	Estimated Useful Life	September 30, 2015 (Restated)		December 31, 2014
Land	n/a	$	3,191	$	2,884
Gathering systems	3 to 47 years	5,431,716		4,972,892
Pipelines and equipment	15 to 45 years	136,303		151,107
Assets under construction	n/a	272,445		483,347
Other	3 to 40 years	19,066		16,420
Total property, plant and equipment		5,862,721		5,626,650
Accumulated depreciation		1,330,802		1,055,207
Net property, plant and equipment		$	4,531,919	$	4,571,443

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.

During the nine months ended September 30, 2015, the Partnership recognized impairments of $276.2 million, primarily due to an impairment of $264.4 million at its Red Desert complex. This asset was impaired to its estimated fair value of $23.2 million, using the income approach and Level 3 fair value inputs, due to a reduction in estimated future cash flows caused by the low commodity price environment and resulting reduced producer drilling activity and related throughput. Also during this period, the Partnership recognized impairments of $11.8 million, primarily due to the abandonment of compressors at the MIGC system and the DJ Basin complex, and the cancellation of projects at the Non-Operated Marcellus Interest systems, the DBJV system and the Brasada and Red Desert complexes.

7. EQUITY INVESTMENTS

The following table presents the activity in the Partnership’s equity investments for the nine months ended September 30, 2015:



	Equity Investments
thousands	Fort Union			White Cliffs			Rendezvous			Mont Belvieu JV			TEG			TEP			FRP			Total
Balance at December 31, 2014	$	25,933		$	44,315		$	56,336		$	121,337		$	16,790		$	198,793		$	170,988		$	634,492
Investment earnings (loss), net of amortization	4,831			10,663			1,591			17,256			475			11,691			12,630			59,137
Contributions	—			6,081			—			(432		)	—			1,520			1,883			9,052
Distributions	(4,606		)	(10,227		)	(3,047		)	(17,924		)	(685		)	(11,880		)	(12,276		)	(60,645		)
Distributions in excess of cumulative earnings ⁽¹⁾	—			(2,584		)	(2,708		)	(1,987		)	(82		)	(4,302		)	(746		)	(12,409		)
Balance at September 30, 2015	$	26,158		$	48,248		$