UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

WESTERN GAS PARTNERS, LP

1201 Lake Robbins Drive, The Woodlands, Texas 77380-1046 (832) 636-6000

Organized in the State of Delaware		Employer Identification No. 26-1075808

     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 o No þ

     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. (Check one):

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

     There were 26,536,306 Common Units outstanding as of June 11, 2008.

 

 

TABLE OF CONTENTS

						Page
PART I FINANCIAL INFORMATION
		Item 1.		Financial Statements
				Combined Statements of Income for the Quarter Ended March 31, 2008 and 2007			4
				Combined Balance Sheets as of March 31, 2008 and December 31, 2007			5
				Combined Statements of Cash Flows for the Quarter Ended March 31, 2008 and 2007			6
		Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			20
		Item 3.		Quantitative and Qualitative Disclosures About Market Risk			35
		Item 4.		Controls and Procedures			35
PART II OTHER INFORMATION
		Item 1.		Legal Proceedings			36
		Item 1A.		Risk Factors			36
		Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds			36
		Item 6.		Exhibits			36
Specimen Unit Certificate for the Common Units
2008 Long-Term Incentive Plan
Equity Incentive Plan
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO & CFO Pursuant to Section 906

Identified Terms

As generally used within the energy industry and in this Quarterly Report on Form 10-Q, the identified terms have the following meanings:

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

Long ton: A British unit of weight equivalent to 2,240 pounds.

LTD: One long ton per day.

MMBtu: One million British Thermal Units.

MMBtu/d: One million British Thermal Units per day.

Natural gas: Hydrocarbon gas found in the earth composed of methane, ethane, butane, propane and other gases.

Sour gas: Natural gas containing more than four parts per million of hydrogen sulfide.

Tcf: One trillion cubic feet of natural gas.

Wellhead: The equipment at the surface of a well used to control the well’s pressure; the point at which the hydrocarbons and water exit the ground.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Western Gas Partners Predecessor
COMBINED STATEMENTS OF INCOME
(Unaudited)

		Quarter Ended March 31,
		2008				2007
		(in thousands)
Revenues — affiliates
Gathering and transportation of natural gas		$	26,947			$	23,392
Condensate			—				2,084
Natural gas and other			516				533
Total revenues — affiliates			27,463				26,009
Revenues — third parties
Gathering and transportation of natural gas			3,842				2,000
Condensate			5,319				495
Natural gas and other			1,602				1,417
Total revenues — third parties			10,763				3,912
Total Revenues			38,226				29,921
Operating Expenses — affiliates
Cost of product			3,760				2,827
General and administrative			1,152				990
Total operating expenses — affiliates			4,912				3,817
Operating Expenses — third parties
Operation and maintenance			8,559				6,886
General and administrative			100				319
Property and other taxes			1,570				1,503
Total operating expenses — third parties			10,229				8,708
Depreciation			6,456				5,372
Total Operating Expenses			21,597				17,897
Operating Income			16,629				12,024
Interest expense — affiliates			(2,126	)			(2,139	)
Other income			4				—
Income Before Income Taxes			14,507				9,885
Income Tax Expense			5,288				3,535
Net Income		$	9,219			$	6,350

See accompanying notes to the combined financial statements.

Western Gas Partners Predecessor
COMBINED BALANCE SHEETS
(Unaudited)

		March 31, 2008				December 31, 2007
		(in thousands)
ASSETS
Current Assets
Cash		$	—			$	—
Accounts receivable, net			4,454				4,397
Natural gas imbalance receivables			823				899
Deferred income taxes			1,989				2,916
Total current assets			7,266				8,212
Other Assets			27				27
Property, Plant and Equipment
Cost			490,799				483,896
Less accumulated depreciation			127,297				120,277
Net property, plant and equipment			363,502				363,619
Goodwill			4,783				4,783
Total Assets		$	375,578			$	376,641
LIABILITIES AND PARENT NET EQUITY
Current Liabilities
Accounts payable		$	1,194			$	3,357
Natural gas imbalance payable			2,376				2,104
Accrued ad valorem taxes			2,578				1,100
Income taxes payable			2,304				313
Accrued liabilities			2,967				4,843
Total current liabilities			11,419				11,717
Long-Term Liabilities
Deferred income taxes			78,794				76,423
Asset retirement obligations			7,917				7,185
Total long-term liabilities			86,711				83,608
Total Liabilities			98,130				95,325
Parent Net Equity			277,448				281,316
Total Liabilities and Parent Net Equity		$	375,578			$	376,641

See accompanying notes to the combined financial statements.

Western Gas Partners Predecessor
COMBINED STATEMENTS OF CASH FLOWS
(Unaudited)

		Quarter Ended March 31,
		2008				2007
		(in thousands)
Cash Flow from Operating Activities
Net Income		$	9,219			$	6,350
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation			6,456				5,372
Deferred income taxes			3,298				3,450
Changes in assets and liabilities:
Increase in accounts receivable			(57	)			(185	)
Decrease in natural gas imbalance receivable			76				87
Increase/(decrease) in accounts payable and accrued expenses			758				(4,131	)
Increase/(decrease) in other items, net			(1	)			69
Cash provided by operating activities			19,749				11,012
Cash Flow from Investing Activities
Capital expenditures			(6,660	)			(4,947	)
Other investing activities			(2	)			(198	)
Cash used in investing activities			(6,662	)			(5,145	)
Cash Flow from Financing Activities
Net advance to parent			(13,087	)			(6,323	)
Cash used in financing activities			(13,087	)			(6,323	)
Net Increase (Decrease) in Cash			—				(456	)
Cash at Beginning of Period			—				458
Cash at End of Period		$	—			$	2
Supplemental Disclosures
Significant non-cash investing and financing transactions:
Property, plant and equipment contributed by parent		$	—			$	15,262
Decrease in accrued capital expenditures		$	1,056			$	1,071

See accompanying notes to the combined financial statements.

Notes to combined financial statements of Western Gas Partners Predecessor
(Unaudited)

1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

Western Gas Partners Predecessor (the “Predecessor”) is comprised of Anadarko Gathering Company LLC (“AGC”), Pinnacle Gas Treating LLC (“PGT”) and MIGC LLC (“MIGC”). Each of AGC, PGT, and MIGC is an indirect subsidiary of Anadarko. For purposes of these combined financial statements, “Anadarko” refers to Anadarko Petroleum Corporation and its consolidated subsidiaries. Western Gas Partners, LP (the “Partnership”) completed its initial public offering on May 14, 2008 (the “Offering”). Please see Note 12, “Subsequent Events.” Prior to the Offering, substantially all of the Partnership’s business and operations were conducted by AGC, PGT, and MIGC.

The Predecessor’s assets consist of six gathering systems, five natural gas treating facilities and one interstate pipeline. The Predecessor’s assets are located in East Texas, the Rocky Mountains (Utah and Wyoming), the Mid-Continent (Kansas and Oklahoma) and West Texas. The Predecessor is engaged in the business of gathering, compressing, treating and transporting natural gas for Anadarko and third-party producers and customers.

The information, as furnished herein, reflects all normal recurring adjustments that are, in the opinion of management, necessary for a fair statement of financial position as of March 31, 2008 and December 31, 2007, the results of operations for the quarters ended March 31, 2008 and 2007 and cash flows for the quarters ended March 31, 2008 and 2007.

The combined financial statements of the Predecessor have been prepared in accordance with accounting principles generally accepted in the United States on the basis of Anadarko’s historical ownership of AGC, PGT and MIGC. These combined financial statements have been prepared from the separate records maintained by Anadarko and may not necessarily be indicative of the actual results of operations that might have occurred if the Predecessor had been operated separately during the periods reported. Because a direct ownership relationship did not exist among the businesses comprising the Predecessor, the net investment in the Predecessor is shown as parent net equity, in lieu of owner’s equity, in the combined financial statements.

The Predecessor’s costs of doing business incurred by Anadarko on behalf of the Predecessor have been reflected in the accompanying financial statements. These costs include general and administrative expenses charged as a management services fee by Anadarko to the Predecessor in exchange for:

	•		business services, such as payroll, accounts payable and facilities management;
	•		corporate services, such as finance and accounting, legal, human resources, investor relations and public and regulatory policy;
	•		executive compensation, but not including share-based compensation; and
	•		pension and other post-retirement benefit costs.

Transactions between the Predecessor and Anadarko have been identified in the combined financial statements as transactions between affiliates. Please see Note 3, “Transactions with Affiliates.”

The accompanying financial statements and notes should be read in conjunction with the Partnership’s Registration Statement on Form S-1, as amended, filed with the Securities and Exchange Commission on April 25, 2008.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of estimates

To conform to generally accepted accounting principles in the United States, management makes estimates and assumptions that affect the amounts reported in the combined financial statements and the notes thereto. These estimates are evaluated on an ongoing basis, utilizing historical experience, consultation with outside advisors and other methods considered reasonable in the particular circumstances. Although these estimates are based on management’s best available knowledge at the time, actual results could differ.

Notes to combined financial statements of Western Gas Partners Predecessor
(Unaudited)

Effects on the Predecessor’s business, financial position and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revision become known. Changes in facts and circumstances or discovery of new facts or circumstances may result in revised estimates and actual results may differ from these estimates.

Property, plant and equipment

Property, plant and equipment are stated at the lower of historical cost less accumulated depreciation or fair value, if impaired. The Predecessor capitalizes all construction-related direct labor and material costs. 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 which do not extend the useful life or increase the expected output of property, plant and equipment is expensed as it is incurred. Depreciation is computed over the asset’s estimated useful life using the straight-line method or half-year convention method.

The Predecessor evaluates whether long-lived assets have been impaired and determines if the carrying amount of its assets may not be recoverable. For such long-lived assets, impairment exists 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 operating expense.

Fair value represents the estimated price between market participants to sell an asset in the principal or most advantageous market for the asset, based on assumptions a market participant would make. When warranted, management assesses the fair value of long-lived assets using commonly accepted techniques and may use more than one source in making such assessments. Sources used to determine fair value include, but are not limited to, recent third-party comparable sales, internally developed discounted cash flow analyses and analyses from outside advisors. Significant changes such as changes in commodity prices, the condition of an asset, or management’s intent to utilize the asset generally require management to reassess the cash flows related to long-lived assets.

No long-lived asset impairment has been recognized in the combined financial statements.

Goodwill

Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the identifiable assets acquired and liabilities assumed. During 2006, the Predecessor recognized goodwill of $4.8 million in connection with the acquisition of MIGC. None of the Predecessor’s goodwill is deductible for income tax purposes.

The Predecessor evaluates whether goodwill has been impaired. Impairment testing is performed annually, unless facts and circumstances make it necessary to test more frequently. The Predecessor has determined that it has one operating segment and two reporting units and, accordingly, goodwill is assessed for impairment at the reporting unit level. Goodwill impairment assessment is a two-step process. Step one focuses on identifying a potential impairment by comparing the fair value of the reporting unit with the carrying amount of the reporting unit. If the fair value of the reporting unit exceeds its carrying amount, no further action is required. However, if the carrying amount of the reporting unit exceeds its fair value, step two of the process is performed, and goodwill is written down to the implied fair value of the goodwill through a charge to operating expense.

No goodwill impairment has been recognized in these combined financial statements.

Asset retirement obligations

The Predecessor recognizes a liability based on estimated costs of retiring tangible long-lived assets. The liability is recognized at the fair value of the asset retirement obligation when the obligation is incurred, which generally is when an asset is acquired or

Notes to combined financial statements of Western Gas Partners Predecessor
(Unaudited)

constructed. The carrying amount of the associated asset is increased commensurate with the liability recognized. Subsequent to the initial recognition, the liability is adjusted for any changes in the expected value of the retirement obligation (with corresponding adjustments to property, plant and equipment) and for accretion of the liability due to the passage of time, until the obligation is settled. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded for both the asset retirement obligation and the associated asset carrying amount.

Revenue recognition

The Predecessor provides gathering and treating services pursuant to fee-based contracts. Under these arrangements, the Predecessor is paid a fixed fee based on the volume and thermal content of the natural gas it gathers or treats and recognizes gathering and treating revenues for its services at the time the service is performed.

Under certain gathering agreements, the Predecessor retains and sells condensate, which falls out of the natural gas stream during the gathering process, and compensates the shippers with a thermally equivalent volume of natural gas. The Predecessor recognizes revenue from the sale of this condensate upon transfer of title.

The Predecessor earns transportation revenues through firm contracts that obligate its customer 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. 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 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 and reserves are established where appropriate. During the periods presented herein, there were no pending rate cases, and no related reserves have been established.

Natural gas imbalances

The combined balance sheets include natural gas imbalance receivables or payables resulting from differences in gas volumes received into the Predecessor’s systems and gas volumes delivered by the Predecessor to customers. Natural gas volumes owed to or by the Predecessor that are subject to tariffs are valued at market index prices, as of the balance sheet dates, and are subject to cash settlement procedures. Other natural gas volumes owed to or by the Predecessor are valued at the Predecessor’s weighted average cost of natural gas as of the balance sheet dates and are settled in-kind.

Environmental expenditures

The Predecessor expenses environmental expenditures related to conditions caused by past operations that do not generate current or future revenues. Environmental expenditures related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Liabilities are recorded when the necessity for environmental remediation becomes probable and the costs can be reasonably estimated, or when other potential environmental liabilities are probable and may be reasonably estimated.

Cash equivalents

The Predecessor considers all highly liquid investments with an original maturity date of three months or less to be cash equivalents. The Predecessor had no cash or cash equivalents as of March 31, 2008 or December 31, 2007.

Bad-debt reserve

The Predecessor transacts its business primarily with Anadarko, for which no credit limit is maintained. The Predecessor analyzes its exposure to bad debt on a customer-by-customer basis for its third-party accounts receivable. For third-party accounts receivable, the amount of bad-debt reserve at March 31, 2008 and December 31, 2007 was approximately $60,000 and $41,000, respectively.

Notes to combined financial statements of Western Gas Partners Predecessor
(Unaudited)

Income taxes

Anadarko files various United States federal and state income tax returns. Deferred federal and state income taxes are provided on temporary differences between the financial statement carrying amounts of recognized assets and liabilities and their respective tax bases as if the Predecessor filed tax returns as a stand-alone entity.

New accounting standards

Financial Accounting Standard Board (“FASB”) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (“FIN 48”). In July 2006, the FASB issued FIN 48 and it became effective January 1, 2007 for the Predecessor. FIN 48 clarifies the accounting for uncertainty in income taxes by prescribing the recognition threshold that a tax position is required to meet before any part of the benefit of that position may be recognized in the financial statements. It also provides guidance on measurement of the income tax benefit associated with uncertain tax positions, derecognition, classification, interest and penalties, accounting in interim periods and disclosure. Additionally, in May 2007, the FASB published FASB Staff Position (“FSP”) No. FIN 48-1, “Definition of Settlement in FASB Interpretation No. 48” (“FSP FIN 48-1”). FSP FIN 48-1 is an amendment to FIN 48 and it clarifies how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. FSP FIN 48-1 is effective upon the initial adoption of FIN 48, and therefore is effective retroactively to January 1, 2007. The adoption of FIN 48 and FSP FIN 48-1 did not have a material impact on the Predecessor’s combined results of operations, cash flows or financial position.

Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements” (“SFAS 157”). In September 2006, the FASB issued SFAS 157, which defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS 157 does not require any new fair value measurements. However, in some cases, the application of SFAS 157 changed the Predecessor’s historical practice for measuring fair values under other accounting pronouncements that require or permit fair value measurements. As originally issued, SFAS 157 was effective as of January 1, 2008 and must be applied prospectively, except in certain cases for the Predecessor. The FASB issued FSP FAS 157-2, which delayed the effective date of SFAS 157 to January 1, 2009 for nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The Predecessor fully adopted SFAS 157 effective January 1, 2008. Adoption of SFAS 157 did not have a material impact on the Predecessor’s combined results of operations, cash flows or financial position.

Recently issued accounting standards not yet adopted

The following new accounting standards have been issued, but as of March 31, 2008 had not yet been adopted:

SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”). In December 2007, the FASB issued SFAS 141R which applies fair value measurement in accounting for business combinations, expands financial disclosures, defines an acquirer and modifies the accounting for some items for business combinations. An acquirer will be required to record 100% of assets and liabilities, including goodwill, contingent assets and contingent liabilities, at their fair value. This replaces the cost allocation process applied under SFAS 141. In addition, contingent consideration must also be recognized at fair value at the acquisition date. Acquisition-related costs will be expensed rather than treated as an addition to the assets being acquired and restructuring costs are to be recognized separately from the business combination. SFAS 141R will apply to the Predecessor prospectively for business combinations with an acquisition date on or after January 1, 2009.

Emerging Issues Task Force (“EITF”) Issue No. 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships” (“EITF 07-4”). In March 2008, the EITF issued EITF 07-4 addressing the application of the two-class method under SFAS 128 in determining income per unit for master limited partnerships having multiple classes of securities including limited partnership units, general partnership units and, when applicable, incentive distribution rights (“IDRs”) of the general partner. EITF 07-4 clarifies that the two-class method would apply. Further, EITF 07-4 states that undistributed earnings should be allocated to the general partner, limited partners and IDR holders as if undistributed earnings were

Notes to combined financial statements of Western Gas Partners Predecessor
(Unaudited)

available cash. EITF 07-4 is effective for the Partnership on January 1, 2009 and will be applied with respect to all periods in which earnings per unit is presented.

3. TRANSACTIONS WITH AFFILIATES

Affiliate transactions

The Predecessor provides natural gas gathering, compression, treating and transportation services to Anadarko resulting in affiliate transactions. The Predecessor’s expenditures are paid through Anadarko, which also results in affiliate transactions. Unlike transactions with third parties that settle in cash, settlement of these affiliate transactions occurs on a net basis through an adjustment to parent net equity. Anadarko also charges the Predecessor interest on the amounts settled through parent net equity. Interest is computed based on Anadarko’s monthly weighted average cost of capital, which was estimated to be 6.42% at March 31, 2008.

Centralized cash management

Anadarko operates a cash management system whereby excess cash from most of its subsidiaries, held in separate bank accounts, is swept to a centralized account. Sales and purchases related to third-party transactions are settled in cash but are received or paid by Anadarko within the centralized cash management system and are deemed to have occurred through an adjustment to parent net equity.

Allocation of costs

The employees supporting the Predecessor’s operations are employees of Anadarko. The combined financial statements of the Predecessor include costs allocated by Anadarko in the form of a management services fee. General, administrative and management costs were allocated to the Predecessor based on its proportionate share of Anadarko’s assets and revenues. Management believes these allocation methodologies are reasonable.

The following table summarizes the affiliate transactions and other payments made to or received from Anadarko which are settled through an adjustment to parent net equity:

		Quarter Ended March 31,
		2008				2007
		(in thousands)
Revenue — affiliates		$	(27,463	)		$	(26,009	)
Operating expense — affiliates			4,912				3,817
Interest expense — affiliates			2,126				2,139
Affiliate transactions			(20,425	)			(20,053	)
Cash used in investing activities			6,662				5,145
Other third-party payments			676				8,585
Third-party transactions			7,338				13,730
Net advance to parent		$	(13,087	)		$	(6,323	)

Notes to combined financial statements of Western Gas Partners Predecessor
(Unaudited)

4. INCOME TAXES

Components of income tax expense are as follows:

		Quarter Ended March 31,
		2008				2007
		(in thousands)
Current income taxes
Federal		$	1,929			$	—
State			61				85
Total current income taxes		$	1,990			$	85
Deferred income taxes
Federal			3,038				3,424
State			260				26
Total deferred income taxes			3,298				3,450
Total income tax expense		$	5,288			$	3,535

Total income tax expense differed from the amounts computed by applying the statutory income tax rate to income before income taxes. The sources of these differences are as follows:

		Quarter Ended March 31,
		2008				2007
		(in thousands)
Income before income taxes		$	14,507			$	9,885
Income tax expense, computed at the statutory rate of 35%			5,078				3,460
Adjustments resulting from:
State income tax, net of federal income tax effect			208				72
Other items			2				3
Total income tax expense		$	5,288			$	3,535
Effective tax rate			36.5	%			35.8	%

The tax effects of temporary differences that give rise to significant portions of deferred tax assets and liabilities as of March 31, 2008 and December 31, 2007 are as follows:

		March 31, 2008				December 31, 2007
		(in thousands)
Net operating loss and credit carryforwards		$	1,989			$	2,916
Net current deferred income tax assets			1,989				2,916
Depreciable properties			(79,191	)			(76,423	)
Net operating loss carryforward			397				—
Net long-term deferred income tax liabilities			(78,794	)			(76,423	)
Total net deferred income tax liabilities		$	(76,805	)		$	(73,507	)

Notes to combined financial statements of Western Gas Partners Predecessor
(Unaudited)

Tax loss and credit carryforwards generated by the Predecessor are as follows:

		March 31, 2008				Statutory Expiration
		(in thousands)
Net operating loss — federal		$	5,095				2024
Net operating loss — state		$	7,573				2013-2014
State credit		$	625				2027

Anadarko is subject to examination by the Internal Revenue Service and various state jurisdictions for tax years 2003 to 2008. The Predecessor may be allocated additions to or reductions from the reported tax liability to the extent that any future audit adjustments incurred by Anadarko relate to the Predecessor’s results. Please see Note 12, “Subsequent Events.”

5. CONCENTRATION OF CREDIT RISK

Anadarko was the only customer accounting for 10% or more of the Predecessor’s combined revenues for the quarter ended March 31, 2007. Anadarko and the National Cooperative Refinery Association (“NCRA”) were the only customers from whom revenues exceeded 10% of the Predecessor’s combined revenues for the quarter ended March 31, 2008. The NCRA is an inter-regional cooperative located in McPherson, Kansas that is engaged in crude oil acquisition, transportation, refining and product distribution throughout the north central United States. AGC has a month-to-month contract with the NCRA for the sale of condensate collected from our Hugoton gathering system. The percentage of revenues from Anadarko, NCRA and the Predecessor’s other customers are as follows:

		Quarter Ended March 31,
Customer		2008				2007
Anadarko			72	%			87	%
NCRA			14	%			—
Other			14	%			13	%
Total			100	%			100	%

No credit limit is maintained with respect to Anadarko. The Predecessor examines the creditworthiness of third-party customers and may establish credit limits for significant third-party customers.

Notes to combined financial statements of Western Gas Partners Predecessor
(Unaudited)

6. PROPERTY, PLANT AND EQUIPMENT

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

		Estimated
		useful life				March 31, 2008				December 31, 2007
						(in thousands, except for
						estimated useful life)
Land			n/a			$	175			$	175
Gathering systems			15 to 25 years				386,282				375,478
Pipeline and equipment			30 to 34.5 years				86,222				84,651
Assets under construction			n/a				17,065				22,738
Other			5 to 25 years				1,055				854
Total property, plant and equipment							490,799				483,896
Accumulated depreciation							(127,297	)			(120,277	)
Total net property, plant and equipment						$	363,502			$	363,619

Depreciation is calculated using the straight-line method or half-year convention method, based on estimated useful lives and salvage values of assets. Uncertainties that may impact these estimates include, among others, changes in laws and regulations relating to restoration and abandonment requirements, economic conditions and supply and demand in the area. When assets are placed into service, the Predecessor makes estimates with respect to useful lives and salvage values that the Predecessor believes are reasonable. However, subsequent events could cause a change in estimates, thereby impacting future depreciation amounts. The cost of property classified as “Assets under construction” is excluded from capitalized costs being depreciated. This amount represents property elements that are works-in-progress and not yet suitable to be placed into productive service as of the balance sheet date.

7. ASSET RETIREMENT OBLIGATIONS

The following table provides a roll forward of asset retirement obligations. Revisions in other estimates for both periods relate primarily to revisions of current cost estimates.

		Quarter Ended				Year Ended
		March 31, 2008				December 31, 2007
		(in thousands)
Carrying amount of asset retirement obligations at beginning of period		$	7,185			$	6,814
Additions			104				102
Accretion expense			124				409
Revisions in other estimates			504				(140	)
Carrying amount of asset retirement obligations at end of period		$	7,917			$	7,185

8. DEBT

In March 2008, Anadarko entered into a five-year $1.3 billion credit facility under which the Partnership may borrow up to $100 million. Interest on borrowings under the credit facility is calculated based on the election by the borrower of either: (i) a floating rate equal to the federal funds effective rate plus 0.5% or (ii) a periodic fixed rate equal to LIBOR plus an applicable margin. The applicable margin, which is currently 0.44%, and the commitment fees are based on Anadarko’s senior unsecured long-term debt rating. Under the credit facility, the Partnership and Anadarko are required to comply with certain covenants, including a financial covenant that requires Anadarko to maintain a debt-to-capitalization ratio of 65% or less. As of March 31, 2008, Anadarko was in

Notes to combined financial statements of Western Gas Partners Predecessor
(Unaudited)

compliance with this covenant. Should the Partnership or Anadarko fail to comply with any covenant in Anadarko’s credit facility, the Partnership may not be allowed to borrow thereunder. Pursuant to the credit facility, Anadarko is a guarantor of all borrowings under the credit facility, including the Partnership’s borrowings. The Partnership is not a guarantor of Anadarko’s borrowings under the credit facility.

In December 2007, Anadarko and an entity formed by a group of unrelated investors formed Trinity Associates, LLC (“Trinity”). Trinity extended a $2.2 billion loan to WGR Asset Holding Company, LLC (“WGR Asset Holdings”), a subsidiary of Anadarko. On February 16, 2008, the Predecessor, along with other Anadarko subsidiaries, became joint and several guarantors of the $2.2 billion loan. Please see Note 12, “Subsequent Events.”

9. SEGMENT INFORMATION

The Predecessor’s operations are organized into a single business segment, all of the assets of which consist of natural gas gathering systems, treating facilities, a pipeline and related plant and equipment.

To assess the operating results of the Predecessor’s segment, management uses Adjusted EBITDA, which it defines as net income (loss) plus interest expense, income tax expense and depreciation, less interest income, income tax benefit and other income (expense).

Adjusted EBITDA is a supplemental financial measure that management and external users of the Predecessor’s combined financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:

	•		the Predecessor’s operating performance as compared to publicly traded partnerships in the midstream energy industry, without regard to financing methods, capital structure or historical cost basis;
	•		the ability of the Predecessor’s assets to generate cash flow to make distributions to its parent; and
	•		the viability of acquisitions and capital expenditure projects and the returns on investment of various investment opportunities.

Management believes that the presentation of Adjusted EBITDA provides information useful in assessing the Predecessor’s financial condition and results of operations and that Adjusted EBITDA is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures and make distributions. Adjusted EBITDA, as defined by the Predecessor, may not be comparable to similarly titled measures used by other companies. Therefore, the Predecessor’s combined Adjusted EBITDA should be considered in conjunction with net income and other performance measures, such as operating income or cash flow from operating activities.

Notes to combined financial statements of Western Gas Partners Predecessor
(Unaudited)

Below is a reconciliation of Adjusted EBITDA to net income.

		Quarter Ended March 31,
		2008				2007
		(in thousands)
Reconciliation of Adjusted EBITDA to Net Income
Net Income		$	9,219			$	6,350
Add:
Interest expense — affiliates			2,126				2,139
Income tax expense			5,288				3,535
Depreciation			6,456				5,372
Less:
Other income			4				—
Adjusted EBITDA		$	23,085			$	17,396

10. COMMITMENTS AND CONTINGENCIES

Environmental

The Predecessor is subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. Management believes there are no such matters that will have a material adverse effect on the Predecessor’s results of operations, cash flows or financial position.

Litigation and legal proceedings

From time to time, the Predecessor is involved in legal, tax, regulatory and other proceedings in various forums regarding performance, contracts and other matters that arise in the ordinary course of business. Management is not aware of any such proceeding for which a final disposition could have a material adverse effect on the Predecessor’s results of operations, cash flows or financial position.

Lease commitments

The Predecessor, or Anadarko on behalf of the Predecessor, entered into leases for compression equipment. During 2007, Anadarko, on behalf of the Predecessor, restructured certain lease commitments, resulting in a new lease and the purchase of previously leased equipment. Compression equipment purchased by Anadarko was contributed to the Predecessor during 2007.

The new lease was entered into between Anadarko and a third party during August 2007. The leased compression equipment is used exclusively by the Predecessor and the underlying lease agreement is accounted for as an operating lease. Upon closing the Offering, Anadarko has the option but not the obligation, to terminate this lease, purchase and take title to the subject compression equipment, and contribute the subject compression equipment to the Partnership.

The compression equipment may be purchased by Anadarko at any time. If upon the expiration date of the lease, August 20, 2012, Anadarko has not purchased the leased compression equipment, it may be sold by the lessor to a third party. If purchased by Anadarko, the purchase price would be approximately $11.0 million. Alternatively, if the compression equipment is sold by the lessor to a third party at lease expiration, Anadarko is obligated to make a cash payment to the lessor equal to the lesser of $8.0 million or the excess, if any, of $11.0 million over the actual sales price of the compression equipment realized by the lessor in connection with a third-party sale.

Notes to combined financial statements of Western Gas Partners Predecessor
(Unaudited)

The amounts in the table below represent existing contractual lease obligations attributable to the compressor lease discussed above. If Anadarko does not purchase and contribute the leased compression equipment to the Partnership, the below amounts may be assigned or otherwise charged to the Partnership subsequent to the Offering, as will any amounts due to the lessor in connection with the purchase option at lease expiration.

Rent expense under the compressor operating lease was approximately $372,000 and $349,000 for the quarters ended March 31, 2008 and 2007, respectively. The following table represents the future minimum rent payments due under the compressor lease as of March 31, 2008.

		Minimum rental
		payments
		(in thousands)
April 1 thru December 31, 2008		$	1,176
2009			1,568
2010			1,568
2011			1,568
2012			1,045
Total		$	6,925

The Predecessor also utilizes facilities leased by Anadarko. Although rent expense is charged by Anadarko to the Predecessor, these amounts do not represent obligations of the Predecessor. Accordingly, these amounts were not included in the amounts set forth in the table above.

11. PENSION PLANS, OTHER POSTRETIREMENT AND EMPLOYEE SAVINGS PLANS

The Predecessor does not sponsor any pension, postretirement or employee savings plan. However, the Predecessor participates in certain plans sponsored by Anadarko indirectly through the management services agreement. The Predecessor participates in Anadarko’s non-contributory defined pension plans, including both qualified and supplemental plans. Anadarko also provides certain health care and life insurance benefits for retired employees. Anadarko also sponsors, and the Predecessor participates in, an employee defined contribution savings plan that matches a portion of each employee’s contributions.

Pension, postretirement and employee savings plan costs included in the management services fee charged to the Predecessor by Anadarko were approximately $70,000 and $63,000 for the quarters ended March 31, 2008 and 2007, respectively.

12. SUBSEQUENT EVENTS

Initial public offering

On May 14, 2008, the Partnership closed its Offering of common units representing limited partner interests in the Partnership. As of May 14, 2008, the Partnership had outstanding 23,723,806 common units, 26,536,306 subordinated units, 1,083,115 general partner units and IDRs. IDRs entitle the holder to specified increasing percentages of cash distributions as the Partnership’s per-unit cash distributions increase. The Partnership initially retained 2,812,500 common units pending exercise or expiration of the underwriters’ 30-day over-allotment option. The underwriters partially exercised their over-allotment option on June 11, 2008 and, accordingly, the 2,060,875 common units were issued to the public and 751,625 common units were issued to Anadarko. The common units are listed on the New York Stock Exchange under the symbol “WES”.

Notes to combined financial statements of Western Gas Partners Predecessor
(Unaudited)

A summary of the Offering transactions is as follows:

•		The Partnership received gross offering proceeds of $309.4 million from the issuance and sale of 18,750,000 common units at an initial offering price of $16.50 per unit less $20.1 million for underwriting discounts and a structuring fee. The Partnership received an additional $31.8 million in net proceeds on June 11, 2008, after deducting underwriting discounts and structuring fees totaling $2.2 million, upon partial exercise of the underwriters’ over-allotment option. These common units issued to the public represent an aggregate 38.4% limited partner interest in the Partnership, based on common units outstanding as of June 11, 2008.
•		The Partnership used the balance of the gross offering proceeds as follows:

	•		approximately $5.0 million to pay offering expenses;
	•		approximately $46.1 million to reimburse Anadarko for capital expenditures it incurred with respect to assets contributed to the Partnership;
	•		$260.0 million to make a loan to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%;
	•		$10.0 million retained for general partnership purposes.

•		Anadarko contributed the assets and liabilities of AGC, PGT and MIGC to the Partnership in exchange for 1,083,115 general partner units representing a 2.0% general partner interest in the Partnership, 100% of the Partnership IDRs, 5,725,428 common units and 26,536,306 subordinated units, together representing an aggregate 59.6% limited partner interest in the Partnership, based on common units outstanding as of June 11, 2008. Anadarko’s common units include 751,625 common units that were issued following the exercise of the underwriters’ over-allotment option.
•		Western Gas Holdings, LLC (“General Partner”), the general partner of the Partnership, adopted two new compensation plans, the Western Gas Partners, LP 2008 Long-Term Incentive Plan (“LTIP”) and the Western Gas Holdings, LLC Equity Incentive Plan (“Incentive Plan”). Phantom unit grants were made to each of the General Partner’s independent directors under the LTIP, and incentive unit grants were made to each of the General Partner’s executive officers pursuant to the Incentive Plan. Pursuant to SFAS No. 123 (revised 2004), “Shared-Based Payment,” grants made under equity-based compensation plans result in share-based compensation expense which is determined, in part, by reference to the fair value of equity compensation as of the date of grant. Share-based compensation expense is not reflected in the Predecessor’s historical combined financial statements as there were no outstanding equity grants under either plan for the periods presented. Share-based compensation expense for grants made pursuant to the LTIP and Incentive Plan will be reflected in the Partnership’s future statements of operations. Share-based compensation expense attributable to grants made pursuant to the LTIP will impact the Partnership’s cash flow from operating activities only to the extent the General Partner’s board of directors, at its discretion, elects to make a cash payment to a participant in lieu of actual receipt of common units by the participant upon the lapse of the relevant vesting period. Equity-based compensation expense attributable to grants made pursuant to the Incentive Plan will impact the Partnership’s cash flow from operating activities only to the extent cash payments are made to Incentive Plan participants and such cash payments do not cause total annual reimbursements made by the Partnership to Anadarko pursuant to the omnibus agreement to exceed the general and administrative expense limit set forth therein for the periods to which such expense limit applies.

Omnibus agreement

Upon the closing of the Offering, the Partnership entered into an omnibus agreement with Anadarko which requires Anadarko to provide an indemnity to the Partnership for all federal, state and local income tax liabilities, environmental losses and other liabilities, other than liabilities incurred in the ordinary course of business, attributable to the ownership or operation of the Partnership’s assets prior to May 14, 2008. Please read “Certain relationships and related party transactions — Agreements governing the transactions — Omnibus agreement” in the Partnership’s Registration Statement on Form S-1, as amended, filed with the SEC on April 25, 2008.

Notes to combined financial statements of Western Gas Partners Predecessor
(Unaudited)

Working capital credit facility

Concurrent with the closing of the Offering, the Partnership entered into a two-year $30 million working capital facility with Anadarko as the lender. The facility is available exclusively to fund working capital borrowings. Borrowings under the facility will bear interest at the same rate as would apply to borrowings under the Anadarko credit facility described in Note 8, “Debt.” The Partnership will pay a commitment fee of 0.11% annually to Anadarko on the unused portion of the working capital facility, up to $33,000. The Partnership is required to reduce all borrowings under the working capital facility to zero for a period of at least 15 consecutive days at least once during each of the twelve-month periods prior to the maturity date of the facility.

Guarantee of WGR Asset Holdings loan

As described in Note 8, “Debt,” as of March 31, 2008, the Predecessor was a joint and several guarantor of WGR Asset Holdings’ $2.2 billion loan. Pursuant to the loan agreement, the Predecessor’s obligations for this guarantee were automatically released immediately prior to the Offering.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The historical combined financial statements reflect the assets, liabilities and operations of Western Gas Partners Predecessor (the “Predecessor”), which is comprised of Anadarko Gathering Company LLC (“AGC”), Pinnacle Gas Treating LLC (“PGT”) and MIGC LLC (“MIGC”). All of the assets, liabilities and operations of the Predecessor were contributed by Anadarko to Western Gas Partners, LP (the “Partnership”) in connection with the closing of the Partnership’s initial public offering of common units representing limited partner interests (the “Offering”) on May 14, 2008. Please see Note 12,” “Subsequent Events” in Part I, Item 1 of this Form 10-Q.

The following discussion analyzes the financial condition and results of operations of the Predecessor. The following discussion and analysis of financial condition and results of operations should be read in conjunction with the Predecessor’s historical combined financial statements, and the notes thereto. For ease of reference, we refer to the historical financial results of our Predecessor as being “our” historical financial results. Unless the context otherwise requires, references to “we,” “us,” “our,” “the Partnership” or “Western Gas Partners” are intended to mean the business and operations of Western Gas Partners, LP and its consolidated subsidiaries since May 14, 2008. When used in an historical context (i.e., prior to May 14, 2008), these terms are intended to mean the combined business and operations of the Predecessor. For purposes of the following discussion, “Anadarko” refers to Anadarko Petroleum Corporation and its consolidated subsidiaries.

We have made in this report, and may from time to time otherwise make in other public filings, press releases and discussions, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 concerning our operations, economic performance and financial condition. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. For such statements, the Partnership claims the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct.

These forward-looking statements involve risk and uncertainties. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about energy markets, future processing volumes and pipeline throughput, including Anadarko’s production gathered or transported through our assets, operating results, competitive conditions, technology, the availability of capital resources, capital expenditures and other contractual obligations, the supply and demand for and the price of oil, natural gas, NGLs and other products or services, the weather, inflation, the availability of goods and services, general economic conditions, either internationally or nationally or in the jurisdictions in which we are doing business, legislative or regulatory changes, including changes in environmental regulation, environmental risks, regulations by the Federal Energy Regulatory Commission and liability under federal and state environmental laws and regulations, the securities or capital markets, our ability to access credit, including under Anadarko’s $1.3 billion credit facility, our ability to maintain and/or obtain rights to operate our assets on land owned by third parties, our ability to acquire assets on acceptable terms, non-payment or non-performance of Anadarko or other significant customers, including under our gathering and transportation agreements and our $260.0 million note receivable from Anadarko, and other factors discussed below and elsewhere in “Risk Factors” and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates” included in our Registration Statement on Form S-1, as amended, filed with the Securities and Exchange Commission (“SEC”) on April 25, 2008 and in our other public filings and press releases. The risk factors and other factors noted throughout or incorporated by reference in this report could cause our actual results to differ materially from those contained in any forward-looking statement.

OVERVIEW

The Partnership is a growth-oriented Delaware limited partnership recently formed by Anadarko to own, operate, acquire and develop midstream energy assets. The Partnership currently operates in East Texas, the Rocky Mountains, the Mid-Continent and West Texas and is engaged in the business of gathering, compressing, treating and transporting natural gas for Anadarko and third-party producers and customers.

OUR OPERATIONS

Our results are driven primarily by the volumes of natural gas we gather, compress, treat or transport through our systems. For the quarter ended March 31, 2008, approximately 68% of our revenues were derived from gathering, compression and treating activities, approximately 13% of our revenues were derived from transportation activities, approximately 14% of our revenues were derived from condensate sales and 5% of our revenues were derived from natural gas sales from settlement of imbalances and other revenues. For the quarter ended March 31, 2008, approximately 72% and 14% of our total revenues were attributable to transactions entered into with Anadarko and National Cooperative Refinery Association, respectively.

In our gathering operations, we contract with producers to gather natural gas from individual wells located near our gathering systems. We connect wells to gathering lines through which natural gas may be compressed and delivered to a processing plant, treating facility or downstream pipeline, and ultimately to end-users. We also treat a significant portion of the natural gas that we gather so that it will satisfy required specifications for pipeline transportation.

Effective January 1, 2008, we received a significant dedication from our largest customer, Anadarko, in order to maintain or increase our existing throughput levels and to offset the natural production declines of the wells currently connected to our gathering systems. Specifically, Anadarko has dedicated to us all of the natural gas production it owns or controls from (i) wells that are currently connected to our gathering systems, and (ii) additional wells that are drilled within one mile of connected wells or our gathering systems, as the systems currently exist and as they are expanded to connect additional wells in the future. As a result, this dedication will continue to expand as additional wells are connected to our gathering systems. Volumes associated with this dedication averaged approximately 671,000 MMBtu/d for the quarter ended March 31, 2008 and 771,000 MMBtu/d for the quarter ended March 31, 2007, based on throughput from the wells ultimately subject to the dedication.

We generally do not take title to the natural gas that we gather, compress, treat or transport. We currently provide all of our gathering and treating services pursuant to fee-based contracts. Under these arrangements, we are paid a fixed fee based on the volume and thermal content of the natural gas we gather, compress, treat or transport. This type of contract provides us with a relatively stable revenue stream that is not subject to direct commodity price risk, except to the extent that we retain and sell condensate that is recovered during the gathering of natural gas from the wellhead. Pursuant to the terms of the new gathering contracts we entered into with Anadarko and described in more detail under “Items Affecting the Comparability of our Financial Results” below, we will receive higher gathering fees than we have historically received.

We have indirect exposure to commodity price risk in that persistent low commodity prices may cause our current or potential customers to delay drilling or shut in production, which would reduce the volumes of natural gas available for gathering, compressing, treating and transporting by our systems. Please read “Quantitative and Qualitative Disclosures about Market Risk” below for a discussion of our exposure to commodity price risk through our condensate recovery and sales.

We provide a significant portion of our transportation services on our MIGC system through firm contracts that obligate our customers to pay a monthly reservation or demand charge, which is a fixed charge applied to firm contract capacity and owed by a customer regardless of the actual pipeline capacity used by that customer. When a customer uses the capacity it has reserved under these contracts, we are entitled to collect an additional commodity usage charge based on the actual volume of natural gas transported. These usage charges are typically a small percentage of the total revenues received from our firm capacity contracts. We also provide transportation services through interruptible contracts, pursuant to which a fee is charged to our customers based upon actual volumes transported through the pipeline.

As a result of the completion of the Offering on May 14, 2008, the results of operations, financial condition and cash flows are expected to vary significantly in 2008 and future periods when compared to the quarter ended March 31, 2008 and prior periods. Please see “Items Affecting the Comparability of our Financial Results,” set forth below in this Item.

HOW WE EVALUATE OUR OPERATIONS

Our management relies on certain financial and operational metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include (1) throughput volumes, (2) operating expenses and (3) Adjusted EBITDA.

Throughput volumes

In order to maintain or increase throughput volumes on our gathering systems, we must connect additional wells to our systems. Our success in connecting additional wells is impacted by successful drilling of new wells which will be dedicated to our systems, our ability to secure volumes from new wells drilled on non-dedicated acreage and our ability to attract natural gas volumes currently gathered or treated by our competitors.

To maintain and increase throughput volumes on our MIGC system, we must continue to contract our capacity to shippers, including producers and marketers, for transportation of their natural gas. We monitor producer and marketing activities in the area served by our transportation system to identify new opportunities.

Operating expenses

We analyze operating expenses to evaluate our performance. The primary components of our operating expenses that we evaluate include operation and maintenance expenses, cost of product expenses, general and administrative expenses and direct operating expenses. Certain of our operating expenses are classified based on whether the expenses are accrued for or paid to our affiliates or third-party vendors. Neither affiliate expenses nor third-party expenses bear a direct relationship to affiliate revenues or third-party revenues. For example, our third-party expenses are not those expenses necessary for generating our third-party revenues. Third-party expenses include all amounts accrued for or paid to third parties for the operation of our systems, whether in providing services to Anadarko or third parties, including utilities, field labor, measurement and analysis and other third-party disbursements.

Operation and maintenance expenses include, among other things, direct labor, insurance, repair and maintenance, contract services, utility costs and services provided to us or on our behalf. For future periods, including a portion of the period in which the Offering was completed, these expenses are governed by our services and secondment agreement with Anadarko.

Cost of product expenses include (i) costs associated with the purchase of natural gas pursuant to the gas imbalance provisions contained in our contracts, (ii) costs associated with our obligations under certain contracts to redeliver a volume of natural gas to shippers which is thermally equivalent to condensate retained by us and sold to third parties and (iii) our fuel tracking mechanism, which tracks the difference between actual fuel usage and loss and amounts recovered for estimated fuel usage and loss under our contracts. These expenses are subject to variability. However, for the quarters ended March 31, 2008 and 2007, cost of product expenses comprised 17.4% and 15.8% of total operating expenses, respectively. We do not expect the variability in our cost of product expenses to have a material impact on our overall results.

General and administrative expenses include reimbursements of costs incurred by Anadarko on our behalf and allocations from Anadarko in the form of a management service fee in lieu of direct reimbursements for various corporate services. Subsequent to the Offering, Anadarko will not receive a management services fee and we expect general and administrative expenses to be comprised primarily of amounts reimbursed by us to Anadarko pursuant to our omnibus agreement with Anadarko and expenses attributable to our status as a publicly traded partnership, such as:

	•		expenses associated with annual and quarterly reporting;
	•		tax return and Schedule K-1 preparation and distribution expenses;
	•		Sarbanes-Oxley compliance expenses;
	•		expenses associated with listing on the New York Stock Exchange;
	•		independent auditor fees; legal fees; investor relations expenses; and registrar and transfer agent fees.

Pursuant to the omnibus agreement with Anadarko, we will reimburse Anadarko for allocated general and administrative expenses. The amount required to be reimbursed by us to Anadarko for certain allocated general and administrative expenses pursuant to the omnibus agreement will be capped at $6.0 million annually through December 31, 2009, subject to adjustment to reflect changes in the Consumer Price Index and, with the concurrence of the special committee of our general partner’s board of directors, to reflect expansions of our operations through the acquisition or construction of new assets or businesses. Thereafter, our general partner will

determine the general and administrative expenses to be reimbursed by us in accordance with our partnership agreement. The cap contained in the omnibus agreement does not apply to incremental general and administrative expenses we expect to incur or to be allocated to us as a result of becoming a publicly traded partnership. We currently expect those expenses to be approximately $2.5 million per year.

Adjusted EBITDA

We define Adjusted EBITDA as net income (loss), plus interest expense, income tax expense and depreciation, less interest income, income tax benefit and other income (expense).

We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations and that Adjusted EBITDA is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures and make distributions. Adjusted EBITDA is a supplemental financial measure that management and external users of our combined financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:

	•		our operating performance as compared to publicly traded partnerships in the midstream energy industry, without regard to financing methods, capital structure or historical cost basis;
	•		the ability of our assets to generate cash flow to make distributions; and
	•		the viability of acquisitions and capital expenditure projects and the returns on investment of various investment opportunities.

The GAAP measures most directly comparable to Adjusted EBITDA are net income and net cash provided by operating activities. Our non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to the GAAP measures of net income or net cash provided by operating activities. Adjusted EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income and net cash provided by operating activities. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA may be defined differently by other companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between Adjusted EBITDA and net income and net cash provided by operating activities, and incorporating this knowledge into its decision-making processes. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results.

The following table presents a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measures of net income and net cash provided by operating activities on an historical as adjusted basis:

		Quarter Ended March 31,
		2008				2007
		(in thousands)
Reconciliation of Adjusted EBITDA to Net Income
Net Income		$	9,219			$	6,350
Add:
Interest expense — affiliates			2,126				2,139
Income tax expense			5,288				3,535
Depreciation			6,456				5,372
Less:
Other income			4				—
Adjusted EBITDA		$	23,085			$	17,396
Reconciliation of Adjusted EBITDA to Net Cash Provided by Operating Activities
Net cash provided by operating activities		$	19,749			$	11,012
Interest expense			2,126				2,139
Current income tax expense			1,990				85
Less other income			4				—
Changes in operating working capital:
Accounts receivable and natural gas imbalances			(19	)			98
Accounts payable and accrued expenses			(758	)			4,131
Other, including changes in non-current assets and liabilities			1				(69	)
Adjusted EBITDA		$	23,085			$	17,396

ITEMS AFFECTING THE COMPARABILITY OF OUR FINANCIAL RESULTS

Our historical results of operations for the periods presented may not be comparable to future or historic results of operations for the reasons described below:

	•		We anticipate incurring approximately $2.5 million of general and administrative expenses annually attributable to operating as a publicly traded partnership, such as expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the New York Stock Exchange; independent auditor fees; legal fees; investor relations expenses; and registrar and transfer agent fees. These incremental general and administrative expenses are not reflected in our historical combined financial statements.
	•		We anticipate incurring up to $6.0 million in general and administrative expenses annually to be charged to us by Anadarko pursuant to the omnibus agreement. This amount is expected to be greater than the amount allocated to us by Anadarko for the management services fee reflected in our historical combined financial statements.
	•		Historically, the impact of all affiliated transactions has been net settled within our combined financial statements because these transactions related to Anadarko and were funded by Anadarko’s working capital. Third-party transactions were funded by our working capital. In the future, all affiliate and third-party transactions will be funded by our working capital. This will impact the comparability of our cash flow statements, working capital analysis and liquidity discussion.

	•		Prior to the Offering, we incurred interest expense on intercompany notes payable to Anadarko. These intercompany balances were extinguished through non-cash transactions in connection with the Offering; therefore, interest expense attributable to these balances and reflected in our historical combined financial statements will not be incurred in future periods.
	•		For periods ending prior to January 1, 2008, our combined financial statements reflect the gathering fees we historically charged Anadarko under our affiliate cost-of-service-based arrangements. Under these arrangements, we recovered, on an annual basis, our operation and maintenance, general and administrative and depreciation expenses in addition to earning a return on our invested capital. Effective January 1, 2008, we entered into new 10-year gas gathering agreements with Anadarko. As discussed above, our fees for gathering and treating services rendered to Anadarko pursuant to the terms of the new gas gathering agreements increased. In part, this increase is attributable to our operation and maintenance expense increasing as a result of us bearing all of the cost of employee benefits specifically identified and related to operational personnel working on our assets, as compared to bearing only those employee benefit costs reasonably allocated by Anadarko to us for the periods ending prior to January 1, 2008. Since our new gas gathering agreements are designed to fully recover these costs, our revenues increased by an amount equal to the employee-benefit related increase in operation and maintenance expense. Although this change in methodology for computing affiliate gathering rates does not impact our net cash flows or net income, this methodology change impacts the components thereof as compared to periods ending prior to January 1, 2008. If we applied the methodology employed under our new gas gathering agreements with Anadarko for the quarter ended March 31, 2007, we estimate our gathering revenues and operation and maintenance expense would have increased by $1.1 million and our cash flow from operations would have remained unchanged.
	•		The gas gathering agreements with Anadarko effective January 1, 2008 include new fees for gathering and treating. The new fees are based on recent capital improvements and changes in our cost-of-service analysis and are higher than those fees reflected in our historical financial results prior to January 1, 2008.
	•		Concurrent with the closing of the Offering, we loaned $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%. Interest income attributable to the note is not reflected in our historical combined financial statements, but will be included in our combined financial statements in the future.
	•		Pursuant to the omnibus agreement, as a co-borrower under Anadarko’s credit facility, we are required to reimburse Anadarko for our allocable portion of commitment fees (0.11% of our committed and available borrowing capacity) that Anadarko incurs under its credit facility, or up to $110,000. Please read “Certain relationships and related party transactions — Agreements governing the transactions — Omnibus agreement” in the Partnership’s Registration Statement on Form S-1, as amended, filed with the SEC on April 25, 2008. In addition, Anadarko entered into a working capital facility with us, under which we expect to incur an annual commitment fee of 0.11% of the unused portion of our committed borrowing capacity of $30 million, or up to $33,000.
	•		Our historical combined financial statements include U.S. federal and state income tax expense incurred by us. Due to our status as a partnership, we will not be subject to U.S. federal income tax and certain state income taxes in the future. However, we will make payments to Anadarko pursuant to a tax sharing agreement for our share of state and local income and other taxes that are included in combined or consolidated tax returns filed by Anadarko.
	•		After the Offering date, we intend to make cash distributions to our unitholders and our general partner at an initial distribution rate of $0.30 per unit per full quarter ($1.20 per unit on an annualized basis). Based on the terms of our cash distribution policy, we expect that we will distribute to our unitholders and our general partner most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, including commercial bank borrowings and debt and equity issuances, to fund our acquisition and expansion capital expenditures. Historically, we largely relied on internally generated cash flows and capital contributions from Anadarko to satisfy our capital expenditure requirements.
	•		In connection with the closing of the Offering, our general partner adopted two new compensation plans, the Western Gas Partners, LP 2008 Long-Term Incentive Plan (“LTIP”) and the Western Gas Holdings, LLC Equity Incentive Plan (“Incentive Plan”). Phantom unit grants have been made to each of our independent directors under the LTIP, and incentive unit grants have been made to each of our executive officers pursuant to the Incentive Plan. Pursuant to Financial Accounting Standards Board (“FASB”) Statement No. 123 (revised 2004), “Shared-Based Payment” (“SFAS 123R”), grants made under

equity-based compensation plans result in share-based compensation expense which is determined, in part, by reference to the fair value of equity compensation as of the date of grant. Share-based compensation expense is not reflected in our historical combined financial statements as there were no outstanding equity grants under either plan for the periods presented. Share-based compensation expense for grants made pursuant to the LTIP and Incentive Plan will be reflected in our future statements of operations. Share-based compensation expense attributable to grants made pursuant to the LTIP will impact our cash flow from operating activities only to the extent our board of directors, at its discretion, elects to make a cash payment to a participant in lieu of actual receipt of common units by the participant upon the lapse of the relevant vesting period. Equity-based compensation expense attributable to grants made pursuant to the Incentive Plan will impact our cash flow from operating activities only to the extent cash payments are made to Incentive Plan participants and such cash payments do not cause total annual reimbursements made by us to Anadarko pursuant to the omnibus agreement to exceed the general and administrative expense limit set forth therein for the periods to which such expense limit applies.

GENERAL TRENDS AND OUTLOOK

We expect our business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.

Natural gas supply and demand

Natural gas continues to be a critical component of energy supply in the U.S. According to the Energy Information Administration, or EIA, total annual domestic consumption of natural gas is expected to increase from approximately 23.0 trillion cubic feet, or Tcf, in 2007 to approximately 24.7 Tcf in 2010. During the last three years, the U.S. has, on average, consumed approximately 22.0 Tcf per year, while total domestic production averaged approximately 18.4 Tcf per year during the same period. We believe that high natural gas prices and increasing demand will continue to drive an increase in natural gas drilling and production in the U.S. Overall, natural gas reserves in the U.S. have increased in recent years, based on data obtained from the EIA.

There is a natural decline in production from existing wells, but in the areas in which we operate there is a significant level of drilling activity that can offset this decline. Although we anticipate continued high levels of exploration and production activities in all of the areas in which we operate, we have no control over this activity. Fluctuations in energy prices could affect production rates over time and levels of investment by Anadarko and third parties in exploration for and development of new natural gas reserves.

Rising operating costs and inflation

The current high level of natural gas exploration, development and production activities across the U.S. and the associated construction of required midstream infrastructure have resulted in increased competition for personnel and equipment. This is causing increases in the prices we pay for labor, supplies and property, plant and equipment. An increase in the general level of prices in the economy could have a similar effect. We have the ability to recover increased costs from our customers through escalation provisions provided for in our contracts. However, there may be a delay in recovering these costs or we may be unable to recover all these costs. To the extent we are unable to recover higher costs, our operating results will be negatively impacted.

Impact of interest rates

Interest rates have been volatile in recent periods. If interest rates rise, our future financing costs would increase accordingly. In addition, because our common units are yield-based securities, rising market interest rates could impact the relative attractiveness of our common units to investors, which could limit our ability to raise funds, or increase the price of raising funds, in the capital markets. Though our competitors may face similar circumstances, such an environment could render us less competitive in our efforts to expand our operations or make future acquisitions.

Benefits from system expansions

We expect that expansion projects, including the following, will allow us to capitalize on increased drilling activity by Anadarko and other third-party producers:

	•		We installed additional compression on our Dew system, which added an incremental 16,537 horsepower in 2007 and we anticipate adding an additional 2,680 horsepower in 2008;
	•		We are expanding our Bethel treating facility by installing an additional 11 LTD of sulfur treating capacity in order to provide additional sour gas treating capacity for drilling in the area, which we expect to complete in 2008; and
	•		We are expanding our Hugoton gathering system to connect wells drilled by third parties.

Acquisition opportunities

We may acquire additional midstream energy assets from Anadarko. On December 27, 2007, Anadarko announced a $2.2 billion financing of its midstream assets which may require partial repayment based on a debt-to-EBITDA leverage ratio that declines incrementally over time. The repayments that may be necessary to satisfy the terms of this financing may be made with internally generated cash flow, cash on hand, or cash received from midstream asset sales. Should Anadarko choose to pursue midstream asset sales, it is under no contractual obligation to offer assets or business opportunities to us. In addition, we may also pursue selected asset acquisitions from third parties to the extent such acquisitions complement our or Anadarko’s existing asset base or allow us to capture operational efficiencies from Anadarko’s production. However, if we do not make acquisitions on economically acceptable terms, our future growth will be limited, and the acquisitions we make may reduce, rather than increase, our cash generated from operations on a per-unit basis.

RESULTS OF OPERATIONS — COMBINED OVERVIEW

OPERATING RESULTS

Our discussion below compares the results for specific periods to the previous comparable period. The discussion compares the quarter ended March 31, 2008 to the quarter ended March 31, 2007. For purposes of the following discussion, any increases or decreases “for the quarter ended March 31, 2008” refer to the comparison of the three-month period ended March 31, 2008 to the three-month period ended March 31, 2007.

Summary

Total revenues increased $8.3 million for the quarter ended March 31, 2008. Gathering and transportation revenue increased $5.4 million, condensate revenue increased $2.7 million and other revenue increased $0.2 million. These revenue increases are discussed below.

Net income increased by $2.9 million for the quarter ended March 31, 2008. The increase in net income was primarily driven by higher revenue due to gathering rate increases and increased condensate margins. These increases were partially offset by higher operating expenses and income taxes of $3.7 million and $1.8 million, respectively.

Throughput volumes decreased by 90,000 MMbtu/d for the quarter ended March 31, 2008. Affiliate volumes declined by 99,000 MMbtu/d and third-party volumes increased by 9,000 MMbtu/d. The decline in affiliate throughput volumes is primarily due to a production decline and reduced drilling activity in the area currently dedicated to the Haley system, located within the Delaware Basin. Specifically, Haley field production and related throughput into the Haley system peaked in the first quarter of 2007 in connection with first production from several wells. Since the first quarter of 2007, production and associated throughput volumes from the Haley field have gradually declined and the number of new wells connected to the system have decreased due to a shift in rig activity from the dedicated area to other exploration areas within the Delaware Basin. However, the number of wells currently being drilled in the Haley field is consistent with our expectations. Three wells were connected to the Haley gathering system during the quarter ended March 31, 2008 and we expect at least four additional wells to be connected by September 30, 2008. Additionally, the

Anadarko/Chesapeake Energy Corporation joint venture continues an active drilling program in the Delaware Basin with 10 rigs running in the first quarter of 2008.

Third-party throughput volumes increased due to a third party’s successful drilling program, which resulted in additional wells being connected to the Hugoton gathering system. We expect the third party to maintain its active drilling program in the area and to drill approximately 50 gross wells in 2008. This increase in third-party throughput volumes for the quarter ended March 31, 2008 was partially offset by a decline in third-party volumes transported on the Pinnacle system resulting from the termination of an interim contract that concluded subsequent to the period ended March 31, 2007.

Revenues and Operating Statistics

		Quarter Ended March 31,
		2008				2007
		(in thousands except per-unit data)
Revenues
Affiliate		$	27,463			$	26,009
Third-party			10,763				3,912
Total Revenues		$	38,226			$	29,921
Throughput (MMBtu/d)
Affiliate			848				947
Third-party			121				112
Total Throughput			969				1,059
Weighted average price per MMbtu
Affiliate		$	0.35			$	0.27
Third-party		$	0.35			$	0.20
Total		$	0.35			$	0.27

Gathering and Transportation of Natural Gas Revenues

		Quarter Ended March 31,
		2008				2007
		(in thousands)
Gathering and transportation of natural gas — affiliates		$	26,947			$	23,392
Gathering and transportation of natural gas — third parties			3,842				2,000
Total gathering and transportation of natural gas		$	30,789			$	25,392

Total gathering and transportation of natural gas revenues increased $5.4 million for the quarter ended March 31, 2008. Revenues from affiliates increased $3.6 million primarily due to an increase in AGC gathering rates on all systems for the quarter ended March 31, 2008. Revenues from third parties increased $1.8 million primarily due to an increase in AGC volumes gathered for a third party on the Hugoton system and recognition of approximately $589,000 of demand charges related to the period from April 2006 through December 2007.

Condensate Revenues

		Quarter Ended March 31,
		2008				2007
		(in thousands)
Condensate — affiliates		$	—			$	2,084
Condensate — third parties			5,319				495
Total condensate		$	5,319			$	2,579

Total condensate revenues increased $2.7 million for the quarter ended March 31, 2008. This increase was primarily due to increased condensate prices, which averaged $91.56 for the quarter ended March 31, 2008 as compared to $51.70 for the quarter ended March 31, 2007. As a result of modifications to contractual arrangements which took effect November 2007, all of our condensate sales for the quarter ended March 31, 2008 are third-party sales.

Natural Gas and Other Revenues

		Quarter Ended March 31,
		2008				2007
		(in thousands)
Natural gas and other — affiliates		$	516			$	533
Natural gas and other — third parties			1,602				1,417
Total natural gas and other		$	2,118			$	1,950

Total natural gas and other revenues increased $0.2 million for the quarter ended March 31, 2008. The increase was due to an increase in other operating revenues of $0.9 million related to an indemnity payment received from a third party for guaranteed volumes offset by changes in our gas imbalance position.

Cost of Product and Operation and Maintenance Expenses

		Quarter Ended March 31,
		2008				2007
		(in thousands)
Cost of product — affiliates		$	3,760			$	2,827
Operation and maintenance — third parties			8,559				6,886
Total cost of product and operation and maintenance expenses		$	12,319			$	9,713

Cost of product and operation and maintenance expenses increased $2.6 million for the quarter ended March 31, 2008 primarily due to $1.7 million of increased labor and related employee expenses. AGC and PGT labor expenses increased $1.1 million and $0.6 million, respectively, for the quarter ended March 31, 2008. For the quarter ended March 31, 2008, approximately $1.1 million of the $1.7 million increase in labor and related employee expenses was attributable to a change in the structure of affiliate contracts and the treatment of such expenses. Specifically, approximately $1.1 million in additional labor and related employee expenses were charged by Anadarko to us in order for us to bear the full cost of operational personnel working on our assets as opposed to bearing only those employee benefit costs reasonably allocated by Anadarko to us. These additional costs were taken into account when setting the affiliate-based gathering rates in the new contracts; thus, our revenues increased by the same amount. Cost of product expense increased $0.9 million primarily due to the increased cost of natural gas that we are contractually required to redeliver to shippers to compensate them on a thermally-equivalent basis for condensate retained by us and sold to third parties. Additionally, cost of product expense increased due to an increase in gas imbalances associated with MIGC.

General and Administrative, Depreciation and Other Expenses

		Quarter Ended March 31,
		2008				2007
		(in thousands)
General and administrative — affiliates		$	1,152			$	990
General and administrative — third parties			100				319
Property and other taxes			1,570				1,503
Depreciation			6,456				5,372
Total general and administrative, depreciation and other expenses		$	9,278			$	8,184

General and administrative, depreciation and other expenses increased $1.1 million for the quarter ended March 31, 2008 primarily due to an increase in depreciation expense of $1.1 million resulting from $61.6 million of assets placed into service during 2007.

Income Tax Expense

		Quarter Ended March 31,
		2008				2007
		(in thousands except percentages)
Income before income taxes		$	14,507			$	9,885
Income tax expense			5,288				3,535
Effective tax rate			36.5	%			35.8	%

For the quarter ended March 31, 2008, income tax expense increased 49.6% primarily due to an increase in income before income taxes. The variances from the 35% statutory rate for the quarters ended March 31, 2008 and March 31, 2007 are primarily attributable to state income taxes (net of federal income tax benefit).

LIQUIDITY AND CAPITAL RESOURCES

Our ability to finance operations and fund maintenance capital expenditures will largely depend on our ability to generate sufficient cash flow to cover these requirements. Our ability to generate cash flow is subject to a number of factors, some of which are beyond our control. Please read “Risk factors” in the Partnership’s Registration Statement on Form S-1, as amended, filed with the SEC on April 25, 2008.

Historically, our sources of liquidity included cash generated from operations and funding from Anadarko. We historically participated in Anadarko’s cash management program, whereby Anadarko, on a periodic basis, swept cash balances residing in our bank accounts. Thus, our historical combined financial statements reflect no cash balances. Unlike our transactions with third parties which ultimately settle in cash, our affiliate transactions are settled on a net basis through an adjustment to parent net equity. Subsequent to the Offering, we maintain our own bank accounts and sources of liquidity and will utilize Anadarko’s cash management system.

Subsequent to the Offering, we expect our sources of liquidity to include:

	•		$10 million of net offering proceeds retained for general partnership purposes;
	•		cash generated from operations;
	•		borrowings of up to $100 million under Anadarko’s credit facility;
	•		borrowings under our $30 million working capital facility with Anadarko;

	•		interest income from our $260.0 million note receivable from Anadarko;
	•		issuances of additional partnership units; and
	•		debt offerings.

We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements, long-term capital expenditure requirements, and the Partnership’s quarterly cash distributions to unitholders.

Working capital

Working capital, defined as the amount by which current assets exceed current liabilities, is an indication of our liquidity and potential need for short-term funding. Our working capital requirements are driven by changes in accounts receivable and accounts payable. These changes are primarily impacted by factors such as credit extended to, and the timing of collections from, our customers and our level of spending for maintenance and expansion activity. Historically, all affiliated transactions were not cash settled within our combined financial statements and did not require independent working capital borrowings. Prospectively, to the extent transactions with Anadarko and third parties require working capital, such amounts will be obtained by us through our working capital facility with Anadarko or other sources.

Historical combined cash flow

The following table and discussion presents a summary of our combined net cash provided by operating activities, combined net cash used in investing activities and combined net cash used in financing activities for the quarters ended March 31, 2008 and 2007.

For all periods presented below, our net cash from operating activities and capital contributions from our parent were used to service our cash requirements, which included the funding of operating expenses and capital expenditures.

		Quarter Ended March 31,
		2008				2007
		(in thousands)
Net cash provided by (used in):
Operating activities		$	19,749			$	11,012
Investing activities			(6,662	)			(5,145	)
Financing activities			(13,087	)			(6,323	)
Net increase (decrease) in cash		$	—			$	(456	)
Adjusted EBITDA		$	23,085			$	17,396

Operating Activities. Net cash provided by operating activities increased by $8.7 million, or 79%, for the quarter ended March 31, 2008. The increase in net cash provided by operating activities was primarily due to $4.9 million change in accounts payable and accrued expenses for the quarter ended March 31, 2008. Additionally, the increase was attributable to a $2.9 million increase in net income resulting from gathering rate increases and increased condensate margins, partially offset by higher operating expenses and income taxes.

Investing Activities. Net cash used in investing activities increased by $1.5 million for the quarter ended March 31, 2008. Capital expenditures for the quarter ended March 31, 2008 include $3.4 million for the expansion of the Bethel treating facility.

Financing Activities. Net cash used in financing activities for the quarter ended March 31, 2008 increased $6.8 million. Increases were attributable to period-to-period variances in net cash payments to Anadarko.

Adjusted EBITDA. Adjusted EBITDA for the quarter ended March 31, 2008 increased 32.7% primarily due to the $5.4 million increase in gathering and transportation revenues and $2.7 million increase in condensate revenues, partially offset by the $2.6 million

increase in cost of product and operation and maintenance expenses discussed above. For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read “How we evaluate our operations — adjusted EBITDA.”

Off-balance sheet arrangements

We do not have any off-balance sheet arrangements.

Capital requirements

Our business can be capital-intensive, requiring significant investment to maintain and improve existing facilities. We categorize capital expenditures as either:

	•		Maintenance capital expenditures, which include those expenditures required to maintain the existing operating capacity and service capability of our assets, including the replacement of system components and equipment that have suffered significant wear and tear, become obsolete or approached the end of their useful lives, those expenditures necessary to remain in compliance with regulatory or legal requirements or those expenditures necessary to complete additional well connections to maintain existing system volumes and related cash flows; or
	•		Expansion capital expenditures, which include those expenditures incurred in order to extend the useful lives of our assets, increase gathering, treating and transmission throughput from current levels, reduce costs or increase revenues.

Total capital expenditures for the quarter ended March 31, 2008 were $6.7 million. Our historical accounting records did not differentiate between maintenance and expansion capital expenditures. However, we estimate that expansion capital specifically represented approximately 80% of total capital expenditures for each of the quarters ended March 31, 2008 and 2007. Our total historical capital expenditures were as follows:

		Quarter Ended March 31,
		2008				2007
		(in thousands)
Total capital expenditures		$	6,660			$	4,947

We expect our maintenance capital expenditures to be $23.4 million and expansion capital expenditures to be $20.6 million for the twelve months ending March 31, 2009. Our future expansion capital expenditures may vary significantly from period to period based on the investment opportunities available to us. From time to time, for projects with significant risk or capital exposure, we may secure indemnity provisions or throughput agreements. We expect to fund future capital expenditures from cash flow generated from our operations, interest income from our note receivable from Anadarko, borrowings under Anadarko’s credit facility, the issuance of additional partnership units or debt offerings.

Distributions

We expect to pay a minimum quarterly distribution of $0.30 per unit per complete quarter, which equates to approximately $16.25 million per full quarter or approximately $65.0 million per full year, based on the number of common, subordinated and general partner units outstanding immediately after the Offering. We do not have a legal obligation to pay this distribution. Please read “Our cash distribution policy and restrictions on distribution” in the Partnership’s Registration Statement on Form S-1, as amended, filed with the SEC on April 25, 2008.

Our borrowing capacity under Anadarko’s credit facility

On March 4, 2008, Anadarko entered into a new $1.3 billion credit facility under which we are a co-borrower. This credit facility is available for borrowings and letters of credit and permits us to borrow up to $100 million under the facility. Our $100 million borrowing limit under Anadarko’s credit facility is available for general partnership purposes, including acquisitions, but only to the

extent that sufficient amounts remain unborrowed by Anadarko and its other subsidiaries. The $1.3 billion credit facility expires March 2013. At March 31, 2008, the full $100 million was available for borrowing by us.

Interest on borrowings under the credit facility is calculated based on the election by the borrower of either: (i) a floating rate equal to the federal funds effective rate plus 0.5% or (ii) a periodic fixed rate equal to LIBOR plus an applicable margin. The applicable margin, which is currently 0.44% and the commitment fees are based on Anadarko’s senior unsecured long-term debt rating. Under the credit facility, we and Anadarko are required to comply with certain covenants, including a financial covenant that requires Anadarko to maintain a debt-to-capitalization ratio of 65% or less. As of March 31, 2008, Anadarko was in compliance with this covenant. Should we or Anadarko fail to comply with any covenant in Anadarko’s credit facility, we may not be allowed to borrow thereunder. Pursuant to the credit facility, Anadarko is a guarantor of all borrowings under the credit facility, including our borrowings. We are not a guarantor of Anadarko’s borrowings under the credit facility.

Our working capital facility

Concurrent with the closing of the Offering, we entered into a two-year, $30 million working capital facility with Anadarko as the lender. The facility is available exclusively to fund working capital borrowings. Borrowings under the facility will bear interest at the same rate as would apply to borrowings under the Anadarko credit facility described above. We will pay a commitment fee of 0.11% annually to Anadarko on the unused portion of the working capital facility, or up to $33,000.

We are required to reduce all borrowings under our working capital facility to zero for a period of at least 15 consecutive days at least once during each of the twelve-month periods prior to the maturity date of the facility.

Credit risk

We bear credit risk represented by our exposure to non-payment or non-performance by our customers, including Anadarko. Generally, non-payment or non-performance results from a customer’s inability to satisfy receivables for services rendered or volumes owed pursuant to gas imbalance agreements. We examine the creditworthiness of third-party customers and may establish credit limits for significant third-party customers.

We are dependent upon a single producer, Anadarko, for the majority of our natural gas volumes and we do not have a credit limit with respect to Anadarko. Consequently, we are subject to the risk of non-payment or late payment by Anadarko of gathering, treating and transmission fees.

We expect our exposure to concentrated risk of non-payment or non-performance to continue for as long as we remain substantially dependent on Anadarko for our revenues. Additionally, we will be exposed to credit risk on the note receivable from Anadarko that was issued by Anadarko to us concurrent with the closing of the Offering. We also entered into an omnibus agreement with Anadarko at the closing of the Offering under which Anadarko is required to indemnify us for certain environmental claims, losses arising from rights-of-way claims, failures to obtain required consents or governmental permits, and income taxes.

If Anadarko becomes unable to perform under the terms of our gathering and transportation agreements, its note payable to us, the omnibus agreement or the services and secondment agreement, it may significantly reduce our ability to make distributions to our unitholders.

Total contractual cash obligations

Anadarko leases compression equipment used exclusively by the Predecessor and charges rental payments to the Predecessor. The following table represents the future minimum rent payments due under the compressor lease as of March 31, 2008.

		Minimum rental
		payments
		(in thousands)
April 1 thru December 31, 2008		$	1,176
2009			1,568
2010			1,568
2011			1,568
2012			1,045
Total		$	6,925

Anadarko may at any time terminate this compression equipment lease, purchase and take title to the compression equipment and contribute the compression equipment to us. However, Anadarko is under no legal obligation to do so.

In connection with the Offering, we entered into an omnibus agreement with Anadarko whereby we will reimburse Anadarko for certain operating and general and administrative expenses it incurs for our benefit with respect to our assets and operations. Under the omnibus agreement, our reimbursement to Anadarko for certain allocable general and administrative expenses will be capped at $6.0 million annually through December 31, 2009, subject to adjustment to reflect changes in the Consumer Price Index and, with the concurrence of the special committee of our general partner’s board of directors, to reflect our expansion of operations through the acquisition or construction of new assets or businesses. Thereafter, our general partner will determine the general and administrative expenses to be reimbursed by us in accordance with the partnership agreement. The cap contained in the omnibus agreement does not apply to incremental general and administrative expenses expected to be incurred or to be allocated to us as a result of becoming publicly traded. Those expenses are expected to be approximately $2.5 million per year, excluding equity-based compensation.

In connection with the closing of the Offering, our general partner adopted two new compensation plans, the LTIP and the Incentive Plan. Phantom unit grants have been made to each of our independent directors under the LTIP, and incentive unit grants have been made to each of our executive officers pursuant to the Incentive Plan. Pursuant to SFAS 123R, grants made under equity-based compensation plans result in share-based compensation expense which is determined, in part, by reference to the fair value of equity compensation as of the date of grant. Share-based compensation expense is not reflected in our historical combined financial statements as there were no outstanding equity grants under either plan for the periods presented. Share-based compensation expense for grants made pursuant to the LTIP and Incentive Plan will be reflected in our future statements of operations. Share-based compensation expense attributable to grants made pursuant to the LTIP will impact our cash flow from operating activities only the extent our board of directors, at its discretion, elects to make a cash payment to a participant in lieu of actual receipt of common units by the participant upon the lapse of the relevant vesting period. Equity-based compensation expense attributable to grants made pursuant to the Incentive Plan will impact our cash flow from operating activities only to the extent cash payments are made to Incentive Plan participants and such cash payments do not cause total annual reimbursements made by us to Anadarko pursuant to the omnibus agreement to exceed the general and administrative expense limit set forth therein for the periods to which such expense limit applies.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

We bear a limited degree of commodity price risk with respect to our gathering contracts. Specifically, pursuant to our contracts, we retain and sell condensate that is recovered during the gathering of natural gas. As part of this arrangement, we are required to provide a thermally equivalent volume of natural gas or the cash equivalent thereof to the shipper. Thus, our revenues for this portion of our contractual arrangement are based on the price received for the condensate and our costs for this portion of our contractual arrangement are dependent upon the price of natural gas. Condensate historically sells at a price representing a slight discount to the price of NYMEX West Texas Intermediate crude oil. We consider our exposure to commodity price risk associated with these arrangements to be minimal based on the amount of operating income generated under these arrangements compared to our overall operating income and the fact that the balance of our operating income is fee-based. For the quarter ended March 31, 2008, a 10% change in the trading margin between condensate and natural gas would have resulted in a $156,000, or a 1.0%, change in operating income for the period.

Interest Rate Risk

Interest rates during the periods discussed above were low compared to rates over the last 50 years. If interest rates rise, our future financing costs will increase accordingly. Although increased borrowing costs could limit our ability to raise funds in the capital markets, we expect our competitors would be similarly affected. We expect to incur debt in the future, either through accessing our working capital facility with Anadarko, our $100 million borrowing capacity under Anadarko’s existing credit facility or the capital markets.

Item 4. Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Securities Exchange Act Rule 13a-15. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of the end of the first quarter of 2008, our disclosure controls and procedures were effective to provide reasonable assurance that material information required to be disclosed by us in reports that we file or submit under the Securities Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the quarter ended March 31, 2008 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We are not a party to any legal proceeding other than legal proceedings arising in the ordinary course of our business. We are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business. Management believes that there are no such proceedings for which final disposition could have a material adverse effect on our results of operations, cash flows or financial position. Further, there have been no material developments in legal, administrative or regulatory proceedings during the quarter ended March 31, 2008.

Item 1A. Risk Factors

There have been no material changes in our risk factors from those described in the Partnership’s Registration Statement on Form S-1, as amended, filed with the SEC on April 25, 2008.

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

The effective date of our registration statement filed on Form S-1 under the Securities Act of 1933 (File No. 333-146700) relating to our initial public offering of common units representing limited partner interests was May 8, 2008. A total of 18,750,000 common units were registered and sold to the public. The sale of 18,750,000 common units was completed on May 14, 2008. UBS Securities LLC, Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC and Morgan Stanley & Co. Incorporated acted as representatives of the underwriters and as joint book-running managers of the initial public offering. The sale of an additional 2,060,875 common units was completed on June 11, 2008 upon partial exercise of the underwriters’ over-allotment option.

The additional information required for this item is provided in Note 12, “Subsequent Events,” included in the Notes to the Unaudited Combined Financial Statements included under Part I, Item 1, which information is incorporated by reference into this item.

Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.

3.1		Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated May 14, 2008 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
3.2		Amended and Restated Limited Liability Company Agreement of Western Gas Holdings, LLC, dated as of May 14, 2008 (incorporated by reference to Exhibit 3.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
4.1*		Specimen Unit Certificate for the Common Units.
10.1		Contribution, Conveyance and Assumption Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, Anadarko Petroleum Corporation, WGR Holdings, LLC, Western Gas Resources, Inc., WGR Asset Holding Company LLC, Western Gas Operating, LLC and WGR Operating, LP, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
10.2		Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC and Anadarko Petroleum Corporation, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.3 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
10.3		Services and Secondment Agreement by and between Western Gas Holdings, LLC and Anadarko Petroleum Corporation, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.4 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).

10.4		Tax Sharing Agreement by and among Anadarko Petroleum Corporation and Western Gas Partners, LP, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.5 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
10.5		Anadarko Petroleum Corporation Fixed Rate Note due 2038 (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
10.6		Working Capital Loan Agreement between Anadarko Petroleum Corporation and Western Gas Partners, LP, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.6 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
10.7		Revolving Credit Agreement, dated as of March 4, 2008, by and among Anadarko Petroleum Corporation, Western Gas Partners, LP, JPMorgan Chase Bank, N.A., The Royal Bank of Scotland, PLC, BNP Paribas, Bank of America, N.A., BMO Capital Markets Financing, Inc., The Bank of Tokyo-Mitsubishi UFJ, LTD., and each of the Lenders named therein (incorporated by reference to Exhibit 10.14 to Amendment No. 4 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on April 15, 2008, File No. 333-146700).
10.8		Dew Gas Gathering Agreement between Anadarko Gathering Company LLC and Anadarko Petroleum Corporation (incorporated by reference to Exhibit 10.4 to Amendment No. 2 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on January 23, 2008, File No. 333-146700).
10.9		Haley Gas Gathering Agreement between Anadarko Gathering Company LLC and Anadarko Petroleum Corporation (incorporated by reference to Exhibit 10.5 to Amendment No. 2 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on January 23, 2008, File No. 333-146700).
10.10		Hugoton Gas Gathering Agreement between Anadarko Gathering Company LLC and Anadarko Petroleum Corporation (incorporated by reference to Exhibit 10.6 to Amendment No. 2 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on January 23, 2008, File No. 333-146700).
10.11		Pinnacle Gas Gathering Agreement between Pinnacle Gas Treating LLC and Anadarko Petroleum Corporation (incorporated by reference to Exhibit 10.7 to Amendment No. 2 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on January 23, 2008, File No. 333-146700).
10.12		Form of Indemnification Agreement by and between Western Gas Holdings, LLC, its Officers and Directors (incorporated by reference to Exhibit 10.10 to Amendment No. 2 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on January 23, 2008, File No. 333-146700).
10.13*		Western Gas Partners, LP 2008 Long-Term Incentive Plan.
10.14		Form of Award Agreement under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.19 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
10.15*		Western Gas Holdings, LLC Equity Incentive Plan.
10.16		Form of Award Agreement under Western Gas Holdings, LLC Equity Incentive Plan (incorporated by reference to Exhibit 10.15 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on April 15, 2008, File No. 333-146700).
31.1*		Certification of Chief Executive Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Chief Financial Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*		Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Exhibit Index

Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.

3.1		Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated May 14, 2008 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
3.2		Amended and Restated Limited Liability Company Agreement of Western Gas Holdings, LLC, dated as of May 14, 2008 (incorporated by reference to Exhibit 3.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
4.1*		Specimen Unit Certificate for the Common Units.
10.1		Contribution, Conveyance and Assumption Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, Anadarko Petroleum Corporation, WGR Holdings, LLC, Western Gas Resources, Inc., WGR Asset Holding Company LLC, Western Gas Operating, LLC and WGR Operating, LP, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
10.2		Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC and Anadarko Petroleum Corporation, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.3 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
10.3		Services and Secondment Agreement by and between Western Gas Holdings, LLC and Anadarko Petroleum Corporation, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.4 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).

10.4		Tax Sharing Agreement by and among Anadarko Petroleum Corporation and Western Gas Partners, LP, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.5 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
10.5		Anadarko Petroleum Corporation Fixed Rate Note due 2038 (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
10.6		Working Capital Loan Agreement between Anadarko Petroleum Corporation and Western Gas Partners, LP, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.6 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
10.7		Revolving Credit Agreement, dated as of March 4, 2008, by and among Anadarko Petroleum Corporation, Western Gas Partners, LP, JPMorgan Chase Bank, N.A., The Royal Bank of Scotland, PLC, BNP Paribas, Bank of America, N.A., BMO Capital Markets Financing, Inc., The Bank of Tokyo-Mitsubishi UFJ, LTD., and each of the Lenders named therein (incorporated by reference to Exhibit 10.14 to Amendment No. 4 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on April 15, 2008, File No. 333-146700).
10.8		Dew Gas Gathering Agreement between Anadarko Gathering Company LLC and Anadarko Petroleum Corporation (incorporated by reference to Exhibit 10.4 to Amendment No. 2 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on January 23, 2008, File No. 333-146700).
10.9		Haley Gas Gathering Agreement between Anadarko Gathering Company LLC and Anadarko Petroleum Corporation (incorporated by reference to Exhibit 10.5 to Amendment No. 2 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on January 23, 2008, File No. 333-146700).
10.10		Hugoton Gas Gathering Agreement between Anadarko Gathering Company LLC and Anadarko Petroleum Corporation (incorporated by reference to Exhibit 10.6 to Amendment No. 2 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on January 23, 2008, File No. 333-146700).
10.11		Pinnacle Gas Gathering Agreement between Pinnacle Gas Treating LLC and Anadarko Petroleum Corporation (incorporated by reference to Exhibit 10.7 to Amendment No. 2 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on January 23, 2008, File No. 333-146700).
10.12		Form of Indemnification Agreement by and between Western Gas Holdings, LLC, its Officers and Directors (incorporated by reference to Exhibit 10.10 to Amendment No. 2 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on January 23, 2008, File No. 333-146700).
10.13*		Western Gas Partners, LP 2008 Long-Term Incentive Plan.
10.14		Form of Award Agreement under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.19 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
10.15*		Western Gas Holdings, LLC Equity Incentive Plan.
10.16		Form of Award Agreement under Western Gas Holdings, LLC Equity Incentive Plan (incorporated by reference to Exhibit 10.15 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on April 15, 2008, File No. 333-146700).
31.1*		Certification of Chief Executive Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Chief Financial Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*		Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.