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 þ No o

     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 October 31, 2008.

 

 

TABLE OF CONTENTS

						Page
PART I				FINANCIAL INFORMATION
Item 1.				Financial Statements
				Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2008 and 2007		4
				Consolidated Balance Sheets as of September 30, 2008 and December 31, 2007		5
				Consolidated Statement of Changes in Partners’ Capital and Parent Net Equity for the Nine Months Ended September 30, 2008		6
				Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2008 and 2007		7
				Notes to Consolidated Financial Statements		8
Item 2.				Management’s Discussion and Analysis of Financial Condition and Results of Operations		26
Item 3.				Quantitative and Qualitative Disclosures About Market Risk		43
Item 4T.				Controls and Procedures		43
PART II				OTHER INFORMATION
Item 1.				Legal Proceedings		45
Item 6.				Exhibits		45
EX-31.1
EX-31.2
EX-32.1

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:

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

Btu: British Thermal Unit.

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

Hydraulic fracturing: Method used to create fractures that extend from a borehole into rock formations to increase or restore the rate which oil or gas can be produced from the formation.

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.

MMcf/d: One million cubic feet per day.

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

Proppant: Sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment.

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.

Western Gas Partners, LP
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited, in thousands, except per-unit amounts)

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
Revenues — affiliates
Gathering and transportation of natural gas		$	26,405			$	22,847			$	81,199			$	69,544
Condensate			—				1,805				—				6,167
Natural gas and other			729				633				4,175				1,131
Total revenues — affiliates			27,134				25,285				85,374				76,842
Revenues — third parties
Gathering and transportation of natural gas			4,353				2,439				11,572				6,419
Condensate			3,022				—				13,882				225
Natural gas and other			3,794				1,082				5,321				2,473
Total revenues — third parties			11,169				3,521				30,775				9,117
Total Revenues			38,303				28,806				116,149				85,959
Operating Expenses (a)
Cost of product			3,913				625				14,246				4,885
Operation and maintenance			9,376				8,003				26,665				21,840
General and administrative			3,412				897				6,809				3,121
Property and other taxes			1,302				1,008				4,525				3,784
Depreciation			7,145				6,361				20,155				17,104
Total Operating Expenses			25,148				16,894				72,400				50,734
Operating Income			13,155				11,912				43,749				35,225
Interest income (expense), net — affiliates			4,216				(887	)			3,736				(6,643	)
Other income			93				—				124				—
Income Before Income Taxes			17,464				11,025				47,609				28,582
Income Tax Expense			68				4,023				8,086				10,469
Net Income		$	17,396			$	7,002			$	39,523			$	18,113
Calculation of Limited Partner Interest in Net Income:
Net income(b)		$	17,396				n/a	(c)		$	25,645				n/a
Less general partner interest in net income			348				n/a				513				n/a
Limited partner interest in net income		$	17,048				n/a			$	25,132				n/a
Net income per limited partner unit — basic		$	0.32				n/a			$	0.47				n/a
Net income per limited partner unit — diluted		$	0.32				n/a			$	0.47				n/a
Limited partner units outstanding — basic			53,072				n/a				53,072				n/a
Limited partner units outstanding — diluted			53,103				n/a				53,103				n/a

See accompanying notes to the consolidated financial statements.

Western Gas Partners, LP
CONSOLIDATED BALANCE SHEETS
(Unaudited, in thousands, except number of units)

		September 30,				December 31,
		2008				2007
ASSETS
Current Assets
Cash and cash equivalents		$	26,390			$	—
Accounts receivable, net — third parties			4,566				4,397
Accounts receivable, net — affiliates			8,229				—
Natural gas imbalance receivables — third parties			1,125				899
Natural gas imbalance receivables — affiliates			839				—
Deferred income taxes			14				2,916
Other current assets			775				—
Total current assets			41,938				8,212
Other Assets			—				27
Note Receivable — Anadarko			260,000				—
Property, Plant and Equipment
Cost			508,491				483,896
Less accumulated depreciation			140,982				120,277
Net property, plant and equipment			367,509				363,619
Goodwill			4,783				4,783
Total Assets		$	674,230			$	376,641
LIABILITIES, PARTNERS’ CAPITAL AND PARENT NET EQUITY
Current Liabilities
Accounts payable		$	1,639			$	3,357
Natural gas imbalance payable — third parties			2,251				2,104
Natural gas imbalance payable — affiliates			303				—
Accrued ad valorem taxes			4,472				1,100
Income taxes payable			13				313
Accrued liabilities — third parties			2,661				4,843
Accrued liabilities — affiliates			91				—
Total current liabilities			11,430				11,717
Long-Term Liabilities
Deferred income taxes			431				76,423
Asset retirement obligations and other			8,330				7,185
Total long-term liabilities			8,761				83,608
Total Liabilities			20,191				95,325
Partners’ Capital and Parent Net Equity
Common units (26,536,306 units issued and outstanding at September 30, 2008)			379,098				—
Subordinated units (26,536,306 units issued and outstanding at September 30, 2008)			264,153				—
General partner units (1,083,115 units issued and outstanding at September 30, 2008)			10,788				—
Parent net investment			—				281,316
Total Partners’ Capital and Parent Net Equity			654,039				281,316
Total Liabilities, Partners’ Capital and Parent Net Equity		$	674,230			$	376,641

See accompanying notes to the consolidated financial statements.

Western Gas Partners, LP
CONSOLIDATED STATEMENT OF PARENT NET EQUITY AND PARTNERS’ CAPITAL
(Unaudited, in thousands)

						Partners’ Capital
		Parent Net				Limited Partners								General
		Investment				Common			Subordinated					Partner				Total
Balance at December 31, 2007		$	281,316			$	—			$	—			$	—			$	281,316
Net income attributable to the period from January 1, 2008 through May 13, 2008			13,878				—				—				—				13,878
Reimbursement of capital expenditures by parent			(45,161	)			—				—				—				(45,161	)
Elimination of net deferred tax liabilities			76,500				—				—				—				76,500
Net advance to parent			(4,924	)			—				—				—				(4,924	)
Contribution of net assets to Western Gas Partners, LP			(321,609	)			55,222				255,941				10,446				—
Issuance of common units to public, net of offering and other costs			—				315,160				—				—				315,160
Non-cash equity-based compensation			—				192				—				—				192
Net income attributable to the period from May 14, 2008 through September 30, 2008			—				12,722				12,410				513				25,645
Distributions to unitholders			—				(4,198	)			(4,198	)			(171	)			(8,567	)
Balance at September 30, 2008		$	—			$	379,098			$	264,153			$	10,788			$	654,039

See accompanying notes to the consolidated financial statements.

Western Gas Partners, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited, in thousands)

		Nine Months Ended September 30,
		2008				2007
Cash Flows from Operating Activities
Net income		$	39,523			$	18,113
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation			20,155				17,104
Deferred income taxes			3,410				7,063
Changes in assets and liabilities:
Increase in accounts receivable			(8,398	)			(915	)
Increase in natural gas imbalance receivable			(1,065	)			(147	)
Increase in accounts payable and accrued expenses			816				580
Increase (decrease) in other items, net			(465	)			12
Net cash provided by operating activities			53,976				41,810
Cash Flows from Investing Activities
Capital expenditures			(24,094	)			(37,247	)
Loan to Anadarko			(260,000	)			—
Net cash used in investing activities			(284,094	)			(37,247	)
Cash Flows from Financing Activities
Proceeds from issuance of common units, net of $5.9 million in offering expenses			315,160				—
Reimbursement of capital expenditures to parent			(45,161	)			—
Distributions to unitholders			(8,567	)			—
Net advance to parent			(4,924	)			(5,021	)
Net cash provided by (used in) financing activities			256,508				(5,021	)
Net Increase (Decrease) in Cash and Cash Equivalents			26,390				(458	)
Cash and Cash Equivalents at Beginning of Period			—				458
Cash and Cash Equivalents at End of Period		$	26,390			$	—
Supplemental Disclosures
Significant non-cash investing and financing transactions:
Contribution of net assets to Western Gas Partners, LP from parent		$	321,609			$	—
Elimination of net deferred tax liabilities		$	76,500			$	—
Property, plant and equipment contributed by parent		$	—			$	21,884
Decrease in accrued capital expenditures		$	1,103			$	117

See accompanying notes to the consolidated financial statements.

Notes to consolidated financial statements of Western Gas Partners, LP
(Unaudited)

1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

Western Gas Partners, LP (the “Partnership”) is a Delaware limited partnership formed in August 2007. As of September 30, 2008, the Partnership’s assets consisted of six gathering systems, five natural gas treating facilities and one interstate pipeline. The Partnership’s assets are located in East and West Texas, the Rocky Mountains (Utah and Wyoming) and the Mid-Continent (Kansas and Oklahoma). The Partnership is engaged in the business of gathering, compressing, treating and transporting natural gas for Anadarko Petroleum Corporation and its consolidated subsidiaries (“Anadarko”) and third-party producers and customers. The Partnership’s general partner is Western Gas Holdings, LLC, a wholly owned subsidiary of Anadarko.

On May 14, 2008 (the “Closing Date”), the Partnership closed its initial public offering of 18,750,000 common units at a price of $16.50 per unit. On June 11, 2008, the Partnership issued an additional 2,060,875 common units to the public pursuant to the partial exercise of the underwriters’ over-allotment option (collectively, the “Offering”). The common units are listed on the New York Stock Exchange under the symbol “WES.” The Partnership received gross proceeds of $343.4 million from the Offering, less $22.3 million for underwriting discounts and structuring fees. The Partnership used the balance of the gross offering proceeds as follows:

	Ø		approximately $5.9 million to pay offering expenses;
	Ø		approximately $45.2 million to reimburse Anadarko for capital expenditures it incurred with respect to assets contributed to the Partnership;
	Ø		$260.0 million loaned to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%; and
	Ø		$10.0 million retained for general partnership purposes.

As of September 30, 2008, the Partnership had outstanding 26,536,306 common units, 26,536,306 subordinated units, and 1,083,115 general partner units, in addition to Incentive Distribution Rights (“IDRs”). IDRs entitle the holder to specified increasing percentages of cash distributions as the Partnership’s per-unit cash distributions increase. The common units issued to the public represent an aggregate 38.4% limited partner interest in the Partnership, based on the number of limited partner units outstanding as of September 30, 2008.

Concurrent with the closing of the Offering, Anadarko contributed the assets and liabilities of Anadarko Gathering Company LLC (“AGC”), Pinnacle Gas Treating LLC (“PGT”) and MIGC LLC (“MIGC”) to the Partnership in exchange for the 1,083,115 general partner units, representing a 2.0% general partner interest in the Partnership, 100% of the IDRs, and 5,725,431 common units and 26,536,306 subordinated units, together representing an aggregate 59.6% limited partner interest in the Partnership, based on the number of limited partner units outstanding as of September 30, 2008. The common units held by Anadarko include 751,625 common units issued to Anadarko following the expiration of the underwriters’ over-allotment option and represent the portion of the common units which were not exercised by the underwriters under the option. See Note 3, “Partnership Equity and Distributions,” for information related to the distribution rights of the common and subordinated unitholders and to the IDRs held by the general partner.

The information furnished herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for a fair statement of financial position as of September 30, 2008 and December 31, 2007, the results of operations for the three months ended September 30, 2008 and 2007 and for the nine months ended September 30, 2008 and 2007, changes in partners’ capital and parent net equity for the nine months ended September 30, 2008 and statements of cash flows for the nine months ended September 30, 2008 and 2007. Certain amounts in prior periods have been reclassified to conform to the current presentation.

The accompanying unaudited consolidated financial statements of the Partnership have been prepared in accordance with accounting principles generally accepted in the United States and include the historical cost-basis accounts of AGC, PGT and MIGC for the periods prior to the Closing Date. The consolidated financial statements for periods prior to the Closing Date have been prepared from the separate records maintained by Anadarko and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had operated separately during the periods reported. The “Partnership” as used herein refers to the

Notes to consolidated financial statements of Western Gas Partners, LP
(Unaudited)

combined financial results and operations of AGC, PGT and MIGC from their inception through the date of their contribution to the Partnership and to the Partnership thereafter. Financial results for the Partnership for the three months ended September 30, 2008 and for the nine months ended September 30, 2008 are not necessarily indicative of the results for the full year ending December 31, 2008.

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

	Ø		business services, such as payroll, accounts payable and facilities management;
	Ø		corporate services, such as finance and accounting, marketing, legal, human resources, investor relations and public and regulatory policy;
	Ø		executive compensation, but not including share-based compensation for periods ending prior to the Closing Date; and
	Ø		pension and other post-retirement benefit costs.

Transactions between the Partnership and Anadarko have been identified in the consolidated financial statements as transactions between affiliates. Please see Note 5, “Transactions with Affiliates.”

The accompanying consolidated 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 accounting principles generally accepted in the United States, management makes estimates and assumptions that affect the amounts reported in the consolidated financial statements and the notes thereto. These estimates are evaluated on an ongoing basis, utilizing historical experience 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 may differ.

Effects on the Partnership’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 Partnership 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, 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 Partnership makes estimates with respect to useful lives and salvage values that the Partnership believes are reasonable. However, subsequent events could cause a change in estimates, thereby impacting future depreciation amounts.

The Partnership evaluates its ability to recover the carrying amount of its long-lived assets and determines whether its long-lived assets have been impaired. 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

Notes to consolidated financial statements of Western Gas Partners, LP
(Unaudited)

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 these consolidated 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 Partnership recognized goodwill of $4.8 million in connection with the acquisition of MIGC. None of this goodwill is deductible for income tax purposes.

The Partnership evaluates whether goodwill has been impaired. Impairment testing is performed annually, unless facts and circumstances make it necessary to test more frequently. The Partnership 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 consolidated financial statements.

Asset retirement obligations

The Partnership recognizes a liability based on the estimated costs of retiring tangible long-lived assets. The liability is recognized at the fair value of the asset retirement obligation when the obligation originates, which generally is when an asset is acquired or constructed. The carrying amount of the associated asset is increased commensurate with the liability recognized. 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. Revisions in estimated asset retirement obligations may result from changes in estimated inflation rates, discount rates, retirement costs and the estimated timing of settling asset retirement obligations.

Revenue recognition

Gathering, treating and transportation revenues are reported in gathering and transportation of natural gas revenues in the consolidated statement of income. The Partnership provides gathering and treating services pursuant to fee-based contracts. Under these arrangements, the Partnership 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 Partnership retains and sells condensate, which is recovered from the natural gas stream during the gathering process, and compensates the shippers with a thermally equivalent volume of natural gas. The Partnership recognizes revenue from the sale of this condensate upon transfer of title.

Notes to consolidated financial statements of Western Gas Partners, LP
(Unaudited)

The Partnership earns transportation revenues through firm contracts that obligate each of its customers to pay a monthly reservation or demand charge regardless of the pipeline capacity used by that customer. An additional commodity usage fee is charged to the customer based on the actual volume of natural gas transported. 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 consolidated balance sheets include natural gas imbalance receivables or payables resulting from differences in gas volumes received into the Partnership’s systems and gas volumes delivered by the Partnership to customers. Natural gas volumes owed to or by the Partnership that are subject to monthly cash settlement are valued according to the terms of the contract as of the balance sheet dates, and generally reflect market index prices. Other natural gas volumes owed to or by the Partnership are valued at the Partnership’s weighted average cost of natural gas as of the balance sheet dates and are settled in-kind. As of September 30, 2008, natural gas imbalance receivables and payables were approximately $2.0 million and $2.6 million, respectively. As of December 31, 2007, natural gas imbalance receivables and payables were approximately $899,000 and $2.1 million, respectively.

Environmental expenditures

The Partnership 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 Partnership considers all highly liquid investments with an original maturity date of three months or less to be cash equivalents. The Partnership had approximately $26.4 million of cash and cash equivalents as of September 30, 2008 and no cash or cash equivalents as of December 31, 2007.

Bad-debt reserve

The Partnership transacts its business primarily with Anadarko, for which no credit limit is maintained. The Partnership analyzes its exposure to bad debt on a customer-by-customer basis for its third-party accounts receivable and may establish credit limits for significant third-party customers. For third-party accounts receivable, the amount of bad-debt reserve at September 30, 2008 and December 31, 2007 was approximately $89,000 and $41,000, respectively.

Equity-based compensation

Concurrent with the closing of the Offering, phantom unit awards were granted to independent directors of the general partner under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (“LTIP”), which permits the issuance of up to 2,250,000 units. Upon vesting of each phantom unit, the holder will receive common units of the Partnership or, at the discretion of the general partner’s board of directors, cash in an amount equal to the market value of common units of the Partnership on the vesting date. 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 elects to make a cash payment to a participant in lieu of the issuance of common units upon the lapse of the vesting period.

Notes to consolidated financial statements of Western Gas Partners, LP
(Unaudited)

Statement of Financial Accounting Standards (“SFAS”) No. 123(R), Share-Based Payment (revised 2004) (“SFAS 123(R)”), requires companies to recognize stock-based compensation as an operating expense. The Partnership amortizes stock-based compensation expense attributable to awards granted under the LTIP over the vesting periods applicable to the awards.

Additionally, the Partnership’s general and administrative expenses include equity-based compensation costs allocated by Anadarko to the Partnership for grants made pursuant to the Western Gas Holdings, LLC Equity Incentive Plan (“Incentive Plan”) as well as the Anadarko Petroleum Corporation 1999 Stock Incentive Plan and the Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan (Anadarko’s plans are referred to collectively as the “Anadarko Incentive Plans”). The incentive units issued under the Incentive Plan are subject to time restrictions that lapse ratably over three years and become payable in cash by the general partner three days prior to the ten-year anniversary of the grant date or earlier in connection with certain other events. 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 described in Note 5, “Transactions with Affiliates,” to exceed the general and administrative expense limit set forth therein for the periods to which such expense limit applies.

Income taxes

The Partnership generally is not subject to federal or state income tax. The Partnership is subject to a Texas margin tax and recognizes this tax expense in its consolidated financial statements. Prior to closing of the Offering, tax expense was recorded for income generated by the assets contributed to the Partnership by Anadarko at the Closing Date. For periods prior to the Closing Date, deferred federal and state income taxes were provided on temporary differences between the financial statement carrying amounts of recognized assets and liabilities and their respective tax bases as if the Partnership filed tax returns as a stand-alone entity. For periods subsequent to the Closing Date, the Partnership will make payments to Anadarko pursuant to the tax sharing arrangement entered into between Anadarko and the Partnership for its share of Texas margin tax that are included in any combined or consolidated returns filed by Anadarko.

Net income per limited partner unit

Emerging Issues Task Force (“EITF”) Issue 03-6, Participating Securities and the Two-Class Method Under FASB Statement No. 128 (“EITF 03-6”), addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and undistributed earnings of the entity when, and if, it declares dividends on its securities. EITF 03-6 requires securities that satisfy the definition of a “participating security” to be considered for inclusion in the computation of basic earnings per unit using the two-class method. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed pursuant to the terms of the relevant contractual arrangement. For the Partnership, earnings per unit is calculated based on the assumption that the Partnership distributes to its unitholders an amount of cash equal to the net income of the Partnership, notwithstanding the general partner’s ultimate discretion over the amount of cash to be distributed for the period, the existence of other legal or contractual limitations that would prevent distributions of all of the net income for the period or any other economic or practical limitation on the ability to make a full distribution of all of the net income for the period. Furthermore, earnings per unit is calculated by applying the provisions of the partnership agreement that govern actual cash distributions to the notional cash distribution amount, including giving effect to incentive distributions that would inure to the general partner.

New accounting standards

SFAS No. 157, Fair Value Measurements (“SFAS 157”). In September 2006, the Financial Accounting Standards Board (“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 Partnership’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,

Notes to consolidated financial statements of Western Gas Partners, LP
(Unaudited)

except in certain cases, to the Partnership. 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 Partnership adopted SFAS 157 effective January 1, 2008. Adoption of SFAS 157 did not have a material impact on the Partnership’s consolidated results of operations, cash flows or financial position.

Recently issued accounting standards not yet adopted

The following new accounting standards have been issued, but had not been adopted by the Partnership as of September 30, 2008:

SFAS No. 141 (revised 2007), Business Combinations (“SFAS 141(R)”). In December 2007, the FASB issued SFAS 141(R) which applies fair value measurement in accounting for business combinations, expands financial disclosures, defines an acquirer and modifies the accounting for some business combinations items. Under SFAS 141(R), 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 No. 141, Business Combinations (“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 will be recognized separately from the business combination. SFAS 141(R) will apply to the Partnership prospectively for business combinations with an acquisition date on or after January 1, 2009.

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”), and FASB Staff Position EITF Issue No. 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (“FSP EITF 03-6-1”). In March 2008, the EITF issued EITF 07-4 addressing the application of the two-class method under SFAS No. 128, Earnings per Share (“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, 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 available cash. In June 2008, the FASB issued FSP EITF 03-6-1 addressing whether instruments granted in share-based payment transactions are participating securities prior to vesting and therefore required to be accounted for in calculating earnings per unit under the two-class method described in SFAS 128. FSP EITF 03-6-1 requires companies to treat unvested share-based payment awards that have non-forfeitable rights to dividend or dividend equivalents as a separate class of securities in calculating earnings per unit. The Partnership is evaluating the impact of EITF 07-4 and FSP EITF 03-6-1 on the Partnership’s reported earnings per unit. EITF 07-4 and FSP EITF 03-6-1 are 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. PARTNERSHIP EQUITY AND DISTRIBUTIONS

The partnership agreement requires that, within 45 days subsequent to the end of each quarter, beginning with the quarter ended June 30, 2008, the Partnership distribute all of its available cash (described below) to unitholders of record on the applicable record date. On August 14, 2008, the Partnership paid a cash distribution to its unitholders of $0.1582 per unit, or $8.6 million in aggregate. This amount represented a quarterly distribution of $0.30 per unit prorated for the 48-day period beginning on the Closing Date and ending on June 30, 2008. See also Note 14, “Subsequent Events,” concerning distributions approved in October 2008.

Available cash

Available cash, for any quarter, consists of all cash and cash equivalents at the end of that quarter:

Ø

less the amount of cash reserves established by the general partner to:

	•		provide for the proper conduct of the Partnership’s business, including reserves for future capital expenditures;
	•		comply with applicable law, any of the Partnership’s debt instruments and other agreements; and

Notes to consolidated financial statements of Western Gas Partners, LP
(Unaudited)

•

provide funds for distributions to the unitholders and to the general partner for any one or more of the next four quarters;

Ø

plus, if the general partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.

Working capital borrowings generally include borrowings made under a credit facility, commercial paper facility or similar financing arrangement. It is intended that working capital borrowings be repaid within 12 months. In all cases, working capital borrowings are used solely for working capital purposes or to fund distributions to partners.

General partner interest and incentive distribution rights

The general partner is currently entitled to 2.0% of all quarterly distributions that the Partnership makes prior to its liquidation. The general partner has the right, but not the obligation, to contribute a proportionate amount of capital to the Partnership to maintain its current general partner interest. The general partner’s 2.0% interest in all cash distributions will be reduced if the Partnership issues additional units in the future and the general partner does not contribute a proportionate amount of capital to the Partnership to maintain its 2.0% general partner interest.

The general partner currently holds IDRs that entitle it to receive increasing percentages, up to a maximum of 50.0%, of Partnership cash distributions based on the amount of the Partnership’s quarterly distributions. The maximum distribution sharing percentage of 50.0% includes distributions paid to the general partner on its 2.0% general partner interest and assumes that the general partner maintains its general partner interest at 2.0%. The maximum distribution of 50.0% does not include any distributions that the general partner may receive on limited partner units that it may own or acquire.

Subordinated units

All subordinated units are held indirectly by Anadarko. The partnership agreement provides that, during a period of time referred to as the “subordination period,” the common units are entitled to distributions of available cash each quarter in an amount equal to the “minimum quarterly distribution,” which is $0.30 per common unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash are permitted on the subordinated units. Furthermore, arrearages do not apply to and therefore will not be paid on the subordinated units. The effect of the subordinated units is to increase the likelihood that, during the subordination period, available cash is sufficient to fully fund cash distributions on the common units in an amount equal to the minimum quarterly distribution.

The subordination period will lapse at such time when the Partnership has paid at least $0.30 per quarter on each common unit, subordinated unit and general partner unit for any three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2011. Also, if the Partnership has paid at least $0.45 per quarter (150% of the minimum quarterly distribution) on each outstanding common unit, subordinated unit and general partner unit for each calendar quarter in a four-quarter period, the subordination period will terminate automatically. The subordination period will also terminate automatically if the general partner is removed without cause and the units held by the general partner and its affiliates are not voted in favor of such removal. When the subordination period lapses or otherwise terminates, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to preferred distributions on prior-quarter distribution arrearages.

Distributions of available cash during the subordination period

Based on the general partner’s initial 2.0% ownership percentage, the partnership agreement requires that the Partnership make distributions of available cash for any quarter during the subordination period in the following manner:

Ø

first, 98.0% to the common unitholders, pro rata, and 2.0% to the general partner, until the Partnership distributes for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

Notes to consolidated financial statements of Western Gas Partners, LP
(Unaudited)

	Ø		second, 98.0% to the common unitholders, pro rata, and 2.0% to the general partner, until the Partnership distributes for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;
	Ø		third, 98.0% to the subordinated unitholders, pro rata, and 2.0% to the general partner, until the Partnership distributes for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and
	Ø		thereafter, in the manner described in “General partner interest and incentive distribution rights” below.

Distributions of available cash after the subordination period

Based on the general partner’s initial 2.0% ownership percentage, the partnership agreement requires that the Partnership make distributions of available cash for any quarter after the subordination period in the following manner:

	Ø		first, 98.0% to all limited partner unitholders, pro rata, and 2.0% to the general partner, until the Partnership distributes for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and
	Ø		thereafter, in the manner described in “General partner interest and incentive distribution rights” below.

General partner interest and incentive distribution rights

The following discussion assumes the general partner maintains its 2.0% general partner interest, there are no arrearages on common units, and the general partner continues to hold the IDRs. After distributing amounts equal to the minimum quarterly distribution to common and subordinated unitholders and distributing amounts to eliminate any arrearages to common unitholders, the partnership agreement requires that the Partnership distributes available cash for that quarter in the following manner:

	Ø		first, 98.0% to all limited partner unitholders, pro rata, and 2.0% to the general partner, until each unitholder receives a total of $0.345 per unit for that quarter (the “first distribution target”);
	Ø		second, 85.0% to all limited partner unitholders, pro rata, and 15.0% to the general partner, until each unitholder receives a total of $0.375 per unit for that quarter (the “second distribution target”);
	Ø		third, 75.0% to all limited partner unitholders, pro rata, and 25.0% to the general partner, until each unitholder receives a total of $0.45 per unit for that quarter (the “third distribution target”); and
	Ø		thereafter, 50.0% to all limited partner unitholders, pro rata, and 50.0% to the general partner.

4. NET INCOME PER LIMITED PARTNER UNIT

The Partnership’s net income is allocated to the general partner and the limited partners, including any subordinated unitholders, in accordance with their respective ownership percentages, and giving effect to incentive distributions allocable to the general partner. The Partnership’s net income allocable to the limited partners is allocated between the common and subordinated unitholders by applying the provisions of the partnership agreement that govern actual cash distributions as if all earnings for the period had been distributed. Accordingly, if current net income allocable to the limited partners is less than the minimum quarterly distribution, or if cumulative net income allocable to the limited partners since the Closing Date is less than the cumulative minimum quarterly distributions, more income is allocated to the common unitholders than the subordinated unitholders for that quarterly period.

Basic and diluted net income per limited partner unit is calculated by dividing limited partners’ interest in net income by the weighted average number of limited partner units outstanding during the period. However, because the Offering was completed on May 14, 2008, the number of units issued in connection with the Offering is utilized for purposes of calculating basic earnings per unit for the

Notes to consolidated financial statements of Western Gas Partners, LP
(Unaudited)

2008 periods that include the Closing Date. Diluted net income per unit reflects the potential dilution of common-equivalent units that could occur if units issued under the LTIP were settled in common units.

The following table illustrates the Partnership’s calculation of net income per unit for common and subordinated partner units (in thousands, except per-unit information):

		Three Months Ended				May 14, 2008 to
		September 30, 2008				September 30, 2008
Net income		$	17,396			$	25,645
Less general partner interest in net income			348				513
Limited partner interest in net income		$	17,048			$	25,132
Net income allocable to common units		$	8,524			$	12,722
Net income allocable to subordinated units			8,524				12,410
Limited partner interest in net income		$	17,048			$	25,132
Net income per limited partner unit — basic and diluted
Common units		$	0.32			$	0.48
Subordinated units		$	0.32			$	0.47
Total		$	0.32			$	0.47
Weighted average limited partner units outstanding — basic
Common units			26,536				26,536
Subordinated units			26,536				26,536
Total			53,072				53,072
Weighted average limited partner units outstanding — diluted
Common units			26,567				26,567
Subordinated units			26,536				26,536
Total			53,103				53,103

5. TRANSACTIONS WITH AFFILIATES

Affiliate transactions

The Partnership provides natural gas gathering, compression, treating and transportation services to Anadarko, which results in affiliate transactions. A portion of the Partnership’s expenditures were paid by or to Anadarko, which also resulted in affiliate transactions. Prior to the Closing Date, balances arising from affiliate transactions were net-settled on a non-cash basis by way of an adjustment to parent net equity. Anadarko charged the Partnership interest at a variable rate (5.97% for May 2008) on outstanding affiliate balances owed by the Partnership to Anadarko for the periods these balances remained outstanding. Affiliate-based interest expense was not charged subsequent to the Closing Date as the outstanding affiliate balances were entirely settled through an adjustment to parent equity in connection with the Offering.

Contribution of AGC, PGT and MIGC to the Partnership

Concurrent with the closing of the Offering, Anadarko contributed the assets and liabilities of AGC, PGT and MIGC to the Partnership in exchange for a 2.0% general partner interest in the Partnership, 100% of the Partnership IDRs and an aggregate 59.6% limited partner interest (consisting of common and subordinated units) in the Partnership. See Note 1, “Description of Business and Basis of Presentation.”

Notes to consolidated financial statements of Western Gas Partners, LP
(Unaudited)

Note receivable from Anadarko

Concurrent with the closing of the Offering, the Partnership loaned $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%. Interest on the note is payable quarterly.

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. Prior to the Closing Date, sales and purchases related to third-party transactions were received or paid in cash by Anadarko within the centralized cash management system and were settled with the Partnership through an adjustment to parent net equity. Subsequent to the Closing Date, the Partnership cash-settles transactions directly with third parties and with Anadarko affiliates.

Credit facilities

In March 2008, Anadarko entered into a five-year $1.3 billion credit facility under which the Partnership may borrow up to $100 million. Concurrent with the closing of the Offering, the Partnership entered into a two-year $30 million working capital facility with Anadarko as the lender. See Note 10, “Debt,” for more information on these credit facilities.

Omnibus agreement

Concurrent with the closing of the Offering, the Partnership entered into an omnibus agreement with the general partner and Anadarko that addresses the following:

	Ø		Anadarko’s obligation to indemnify the Partnership for certain liabilities and the Partnership’s obligation to indemnify Anadarko for certain liabilities;
	Ø		The Partnership’s obligation to reimburse Anadarko for all expenses incurred or payments made on the Partnership’s behalf in conjunction with Anadarko’s provision of general and administrative services to the Partnership, including salary and benefits of the general partner’s executive management and other Anadarko personnel and general and administrative expenses which are attributable to the Partnership’s status as a separate publicly traded entity;
	Ø		The Partnership’s obligation to reimburse Anadarko for all insurance coverage expenses it incurs or payments it makes with respect to the Partnership’s assets; and
	Ø		The Partnership’s obligation to reimburse Anadarko for the Partnership’s allocable portion of commitment fees that Anadarko incurs under its $1.3 billion credit facility.

Pursuant to the omnibus agreement, Anadarko performs centralized corporate functions for the Partnership, such as legal, accounting, treasury, cash management, investor relations, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, tax, marketing and midstream. The Partnership’s reimbursement to Anadarko for certain general and administrative expenses allocated to the Partnership is capped at $6.0 million annually through December 31, 2009, subject to adjustment to reflect changes in the Consumer Price Index and to reflect expansions of the Partnership’s operations through the acquisition or construction of new assets or businesses. The cap contained in the omnibus agreement does not apply to incremental general and administrative expenses allocated to or incurred by the Partnership as a result of being a publicly traded partnership.

Notes to consolidated financial statements of Western Gas Partners, LP
(Unaudited)

Services and secondment agreement

Concurrent with the closing of the Offering, the general partner and Anadarko entered into a services and secondment agreement pursuant to which specified employees of Anadarko are seconded to the general partner to provide operating, routine maintenance and other services with respect to the assets owned and operated by the Partnership under the direction, supervision and control of the general partner. Pursuant to the services and secondment agreement, the Partnership will reimburse Anadarko for services provided by the seconded employees. The initial term of the services and secondment agreement is 10 years and the term will automatically extend for additional twelve-month periods unless either party provides 180 days written notice otherwise before the applicable twelve-month period expires.

Tax sharing agreement

Concurrent with the closing of the Offering, the Partnership and Anadarko entered into a tax sharing agreement pursuant to which the Partnership will reimburse Anadarko for the Partnership’s share of Texas margin tax borne by Anadarko as a result of the Partnership’s results being included in a combined or consolidated tax return filed by Anadarko with respect to periods subsequent to the Closing Date. Anadarko may use its tax attributes to cause its combined or consolidated group, of which the Partnership may be a member for this purpose, to owe no tax. However, the general partner is nevertheless required to reimburse Anadarko for the tax the Partnership would have owed had the attributes not been available or used for the Partnership’s benefit, irrespective of whether Anadarko pays taxes for the period.

Allocation of costs

The consolidated financial statements of the Partnership include costs allocated by Anadarko in the form of a management services fee for periods prior to the Closing Date. General, administrative and management costs were allocated to the Partnership based on its proportionate share of Anadarko’s assets and revenues. Management believes these allocation methodologies are reasonable.

Equity-based compensation

Pursuant to SFAS 123(R), grants made under equity-based compensation plans result in equity-based compensation expense which is determined, in part, by reference to the fair value of equity compensation as of the date of the relevant equity grant. The Partnership’s general and administrative expense for the three months ended September 30, 2008 includes approximately $91,000 and $396,000 of equity-based compensation expense for grants made pursuant to the Incentive Plan and Anadarko Incentive Plans, respectively. The Partnership’s general and administrative expense for the nine months ended September 30, 2008 includes approximately $175,000 and $592,000 of equity-based compensation expense for grants made under the Incentive Plan and Anadarko Incentive Plans, respectively. These expenses are allocated to the Partnership by Anadarko as a component of compensation expense for the executive officers of the Partnership’s general partner and employees who provide services to the Partnership pursuant to the omnibus agreement and the services and secondment agreement. The amounts above exclude compensation expense associated with the LTIP, which is expensed entirely by the Partnership. See Note 13, “Equity-Based Compensation Plans.”

Pension plans, other postretirement and employee savings plans

The Partnership does not sponsor any pension, postretirement or employee savings plan. However, the Partnership participates indirectly in certain plans sponsored by Anadarko, through the management services agreement prior to the Closing Date and through the omnibus agreement and the services and secondment agreement commencing on the Closing Date. The Partnership participates in Anadarko’s non-contributory defined pension plans, including both qualified and supplemental plans. Anadarko also sponsors, and the Partnership 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 fees charged to the Partnership by Anadarko were approximately $845,000 and $279,000 for the three months ended September 30, 2008 and 2007, respectively, and were approximately $2.2 million and $406,000 for the nine months ended September 30, 2008 and 2007, respectively.

Notes to consolidated financial statements of Western Gas Partners, LP
(Unaudited)

Summary of affiliate transactions

The following table summarizes affiliate transactions (in thousands). Affiliate expenses do not bear a direct relationship to affiliate revenues and third-party expenses do not bear a direct relationship to third-party revenues. Accordingly, the Partnership’s affiliate expenses are not those expenses necessary for generating affiliate revenues. Operating expenses include all amounts accrued for or paid to affiliates for the operation of our systems, whether in providing services to affiliates or to third parties, including field labor, measurement and analysis and other disbursements. Changes in parent net equity, including affiliate transactions and other payments made to or received from Anadarko, were settled through an adjustment to parent net equity prior to the Closing Date. Thereafter, affiliate transactions are cash-settled.

		Nine Months Ended				May 14, 2008 to				January 1, 2008 to				Nine Months Ended
		September 30, 2008				September 30, 2008				May 13, 2008				September 30, 2007
Affiliate transactions
Revenue — affiliates		$	(85,374	)		$	(42,842	)		$	(42,532	)		$	(76,842	)
Operating expenses — affiliates			26,763				14,852				11,911				13,240
Interest income, net — affiliates			(6,479	)			(6,479	)			—				—
Interest expense, net — affiliates			2,743				76				2,667				6,643
Payments made by Anadarko prior to the Closing Date			n/a	(a)			n/a				23,030				51,938
Transactions settled through adjustments to parent net equity			n/a				n/a			$	(4,924	)		$	(5,021	)
Loan to Anadarko		$	260,000			$	260,000			$	—			$	—
Reimbursement of capital expenditures		$	45,161			$	45,161			$	—			$	—
Distribution to unitholders — affiliates		$	5,275			$	5,275			$	—			$	—
Contribution of net assets to Western Gas Partners, LP		$	321,609			$	321,609			$	—			$	—
Property, plant and equipment contributed by parent		$	—			$	—			$	—			$	21,884

		September 30,				December 31,
		2008				2007
Receivables from and payables to affiliates
Accounts receivable		$	8,229			$	—
Natural gas imbalance receivables		$	839			$	—
Note receivable from Anadarko		$	260,000			$	—
Natural gas imbalance payable		$	303			$	—
Accrued liabilities		$	91			$	—
Parent net investment		$	—			$	281,316

Notes to consolidated financial statements of Western Gas Partners, LP
(Unaudited)

6. INCOME TAXES

The following table summarizes the Partnership’s effective tax rate:

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
		(in thousands, except effective tax rate)
Income before income taxes		$	17,464			$	11,025			$	47,609			$	28,582
Income tax expense		$	68			$	4,023			$	8,086			$	10,469
Effective tax rate			0.4	%			36.5	%			17.0	%			36.6	%

The decrease in income tax expense for the three months ended September 30, 2008 is primarily due to the Partnership’s U.S. federal income tax status as a non-taxable entity. Income earned by the Partnership for the period beginning on the Closing Date and ending on September 30, 2008, is subject only to Texas margin tax. The decrease in income tax expense for the nine months ended September 30, 2008 was due to the impact of the Partnership’s non-taxable status for the period beginning on the Closing Date and ending on September 30, 2008, partially offset by an increase in income before income tax earned prior to the Closing Date, which is subject to federal and state income tax. For 2008, the variance from the 35% federal statutory rate is primarily attributable to the Partnership’s income being subject only to Texas margin tax for the period beginning on the Closing Date and ending on September 30, 2008. For 2007, the variance from the 35% federal statutory rate is primarily attributable to state income taxes (net of federal tax benefit).

7. CONCENTRATION OF CREDIT RISK

Anadarko and the National Cooperative Refinery Association (“NCRA”) were the only customers from whom revenues exceeded 10% of the Partnership’s consolidated revenues for the nine months ended September 30, 2008. Anadarko was the only customer from whom revenues exceeded 10% of the Partnership’s consolidated revenues for the three months ended September 30, 2008 and the three and nine months ended September 30, 2007. 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. The Partnership has a month-to-month contract with the NCRA for the sale of condensate collected from the Hugoton gathering system. The percentage of revenues from Anadarko, the NCRA and the Partnership’s other customers are as follows:

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
Customer		2008				2007				2008				2007
Anadarko			71	%			88	%			74	%			89	%
NCRA			8	%			—				12	%			—
Other			21	%			12	%			14	%			11	%
Total			100	%			100	%			100	%			100	%

Notes to consolidated financial statements of Western Gas Partners, LP
(Unaudited)

8. PROPERTY, PLANT AND EQUIPMENT

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

		Estimated useful life				September 30, 2008				December 31, 2007
						(in thousands, except for estimated useful life)
Land			n/a			$	175			$	175
Gathering systems			15 to 25 years				409,585				375,478
Pipeline and equipment			30 to 34.5 years				85,810				84,651
Assets under construction			n/a				11,491				22,738
Other			3 to 25 years				1,430				854
Total property, plant and equipment							508,491				483,896
Accumulated depreciation							(140,982	)			(120,277	)
Total net property, plant and equipment						$	367,509			$	363,619

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.

9. ASSET RETIREMENT OBLIGATIONS

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

		Nine Months Ended				Year Ended
		September 30, 2008				December 31, 2007
		(in thousands)
Carrying amount of asset retirement obligations at beginning of period		$	7,185			$	6,814
Additions			181				102
Accretion expense			375				409
Revisions in estimates			498				(140	)
Carrying amount of asset retirement obligations at end of period		$	8,239			$	7,185

10. 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 to the extent that sufficient amounts remain unborrowed by Anadarko and its subsidiaries. As of September 30, 2008, the full $100 million was available for borrowing by the Partnership. 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 0.50% or (ii) a periodic fixed rate equal to LIBOR plus an applicable margin. The applicable margin, which was 0.44% at September 30, 2008, and the commitment fees on the facility are based on Anadarko’s senior unsecured long-term debt rating. Pursuant to the omnibus agreement, as a co-borrower under Anadarko’s credit facility, the Partnership is required to reimburse Anadarko for its allocable portion of commitment fees (currently 0.11% of the Partnership’s committed and available borrowing capacity, including the Partnership’s outstanding balances) that Anadarko incurs under its credit facility, or up to $110,000 annually. 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 September 30, 2008, Anadarko was in compliance with all covenants. Should the Partnership or Anadarko fail to comply with any covenant in Anadarko’s credit facility, the Partnership may not be permitted to borrow under the credit

Notes to consolidated financial statements of Western Gas Partners, LP
(Unaudited)

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.

Concurrent with the closing of the Offering, the Partnership entered into a two-year $30 million working capital facility with Anadarko as the lender. At September 30, 2008, no borrowings were outstanding under the working capital facility. 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. Pursuant to the omnibus agreement, the Partnership 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 annually. 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.

In December 2007, Anadarko and an entity organized 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 Partnership, along with other Anadarko subsidiaries, became joint and several guarantors of the $2.2 billion loan. Pursuant to the loan agreement, all guarantees with respect to the Partnership’s assets were automatically released immediately prior to the closing of the Offering.

11. SEGMENT INFORMATION

The Partnership’s operations are organized into a single business segment, 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 Partnership’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 Partnership’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:

	Ø		the Partnership’s operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to financing methods, capital structure or historical cost basis;
	Ø		the ability of the Partnership’s assets to generate cash flow to make distributions; and
	Ø		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 Partnership’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 Partnership, may not be comparable to similarly titled measures used by other companies. Therefore, the Partnership’s consolidated 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 consolidated financial statements of Western Gas Partners, LP
(Unaudited)

Below is a reconciliation of Adjusted EBITDA to net income (in thousands).

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
Reconciliation of Adjusted EBITDA to Net Income
Adjusted EBITDA		$	20,300			$	18,273			$	63,904			$	52,329
Less:
Interest expense, net — affiliates			37				887				2,743				6,643
Income tax expense			68				4,023				8,086				10,469
Depreciation			7,145				6,361				20,155				17,104
Add:
Interest income from note — affiliate			4,253				—				6,479				—
Other income			93				—				124				—
Net Income		$	17,396			$	7,002			$	39,523			$	18,113

12. COMMITMENTS AND CONTINGENCIES

Environmental

The Partnership 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 Partnership’s results of operations, cash flows or financial position.

Litigation and legal proceedings

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

Lease commitments

Anadarko, on behalf of the Partnership, has entered into leases for compression equipment. During 2007 Anadarko restructured certain third-party lease commitments, resulting in a new lease and the purchase of previously leased equipment. Compression equipment purchased by Anadarko was contributed to the Partnership during 2007. Anadarko also entered into a new third-party lease in August 2007 for compression equipment used exclusively by the Partnership and entered into a third-party lease for office space. The office lease commenced in January 2008 and will expire in January 2010. There is no purchase option at the termination of the office lease.

Notes to consolidated financial statements of Western Gas Partners, LP
(Unaudited)

The amounts in the table below represent existing contractual lease obligations attributable to the compressor lease and office lease discussed above. The below amounts may be assigned or otherwise charged to the Partnership. Rent expense was approximately $309,000 and $43,000 for the three months ended September 30, 2008 and 2007, respectively, and was approximately $1.0 million and $605,000 for the nine months ended September 30, 2008 and 2007, respectively. The following table represents future minimum rent payments due as of September 30, 2008 (in thousands).

		Minimum rental
		payments
October 1 thru December 31, 2008		$	429
2009			1,717
2010			1,577
2011			1,568
2012			1,045
Total		$	6,336

See Note 14, “Subsequent Events,” for information related to a change in the compression equipment lease arrangement.

13. EQUITY-BASED COMPENSATION PLANS

Long-term incentive plan

The general partner awarded 30,304 phantom units valued at $16.50 each to the general partner’s independent directors in May 2008. These phantom units were granted under the LTIP and will vest in May 2009. Total compensation expense attributable to the phantom units granted under the LTIP during the three and nine months ended September 30, 2008 was approximately $127,000 and $192,000, respectively. The Partnership expects to recognize approximately $308,000 of additional compensation expense over the next eight months related to the phantom units granted under the LTIP.

Equity incentive plan

In April 2008, the general partner awarded to its executive officers an aggregate of 50,000 incentive units under the Incentive Plan with an initial value of $50.00 per incentive unit. The incentive units were granted subject to time restrictions that lapse ratably over three years and will be payable in cash three days prior to the ten-year anniversary of the grant date or earlier upon certain liquidation events. Equity-based compensation expense for grants made pursuant to the Incentive Plan as well as the Anadarko Incentive Plans is included in general and administrative expenses as a component of the compensation expense allocated to the Partnership by Anadarko and reflected in the Partnership’s financial statements for the three and nine months ended September 30, 2008. See Note 5, “Transactions with Affiliates.”

14. SUBSEQUENT EVENTS

Cash Distribution

On October 24, 2008, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.30 per unit, or $16.2 million in aggregate. The cash distribution is payable on November 14, 2008 to unitholders of record at the close of business on October 31, 2008.

In October 2008, Anadarko modified certain lease arrangements including leased compression equipment used exclusively by the Partnership. As a result of the lease modifications, Anadarko became the owner of the compression equipment, effectively terminating the lease. Remaining minimum lease payments attributable to the compression equipment were $6.1 million as of September 30, 2008. Pursuant to the Contribution, Conveyance and Assumption Agreement signed in connection with the Offering, the Partnership expects Anadarko to contribute the compression equipment to the Partnership at no cost. The carrying value of the compression equipment was approximately $14.3 million as of September 30, 2008.

In November 2008, the Partnership entered into an agreement to acquire certain midstream assets from Anadarko for $175 million in cash and the issuance of 2,556,891 common units. These assets provide a combination of gathering, treating and processing services in the Powder River Basin and are connected or adjacent to the Partnership’s MIGC pipeline. Specifically, the Partnership has agreed to acquire Anadarko’s 100% ownership interest in the natural gas gathering systems and processing plants known as the “Hilight system,” its 50% interest in the natural gas gathering systems and processing plants known as the “Newcastle system” and its 15% interest in Fort Union Gas Gathering, L.L.C. (collectively, the “Powder River Basin Assets”). The Powder River Basin Assets are operated by Anadarko. The acquisition will be financed primarily with debt, through the issuance of a 5-year, $175 million note to Anadarko, as well as through the issuance of 2,556,891 common units to Anadarko at an implied price of approximately $13.69 per unit.

The acquisition and related transactions are expected to close in December 2008 and are subject to standard closing conditions and adjustments, including a right of first refusal related to the Newcastle system. The Partnership will account for the acquisition as a transfer of net assets between entities under common control pursuant to the provisions of SFAS 141. The Powder River Basin Assets will be recorded at the amounts reflected in Anadarko’s consolidated financial statements. The difference between the purchase price and Anadarko’s carrying value of the Powder River Basin combined net assets and liabilities will be recorded as an adjustment to partners’ capital. SFAS 141 also prescribes that all income statements be revised to include the results of the acquired assets as of the date of common control. After the transaction is completed, the Partnership will recast its current and prior year financial statements for periods including and subsequent to August 23, 2006, the date Anadarko acquired the Powder River Basin Assets in conjunction with its acquisition of Western Gas Resources, Inc.

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

The historical consolidated financial statements reflect the assets, liabilities and operations of Western Gas Partners, LP (the “Partnership”), a Delaware limited partnership formed in August 2007, and include the historical cost-basis accounts of Anadarko Gathering Company LLC (“AGC”), Pinnacle Gas Treating LLC (“PGT”) and MIGC LLC (“MIGC”). All of the assets, liabilities and operations of AGC, PGT and MIGC were contributed by Anadarko to 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 (the “Closing Date”).

The following discussion analyzes the financial condition and results of operations of the Partnership and should be read in conjunction with the Partnership’s historical consolidated financial statements, and the notes thereto. For ease of reference, we refer to the historical financial results of AGC, PGT and MIGC prior to the Offering 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 and the business and operations of AGC, PGT and MIGC since their inception. 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 financial condition or include 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 treating volumes and pipeline throughput, including Anadarko’s production gathered or transported through our assets, operating results, competitive conditions, technology, the availability of capital resources, the ability to consumate the pending acquisition and related transactions, 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 formed by Anadarko to own, operate, acquire and develop midstream energy assets. The Partnership currently operates in East and West Texas, the Rocky Mountains (Utah and Wyoming) and the Mid-Continent (Kansas and Oklahoma) and is engaged in the business of gathering, compressing, treating and transporting natural gas for Anadarko and third-party producers and customers.

Our results are driven primarily by the volumes of natural gas we gather, compress, treat or transport through our systems. For the nine months ended September 30, 2008, our revenues were derived approximately as follows:

	Ø		67% from gathering and compression activities,
	Ø		13% from transportation activities,
	Ø		12% from condensate sales, and
	Ø		8% from natural gas sales related to the changes in our imbalance positions and other revenues.

For the nine months ended September 30, 2008, approximately 74% and 12% of our total revenues were attributable to transactions entered into with Anadarko and the National Cooperative Refinery Association, respectively.

In our gathering operations, we contract with producers and customers 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 646,000 MMBtu/d for the nine months ended September 30, 2008 and 734,000 MMBtu/d for the nine months ended September 30, 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.

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. We also bear a limited degree of commodity price risk through our condensate recovery and sale and settlement of natural gas imbalances. Please read “Quantitative and Qualitative Disclosures about Market Risk” below.

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 Offering, the results of operations, financial condition and cash flows are expected to vary significantly for 2008 as compared to comparable periods ending prior to the Closing Date. 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 capacity to shippers, including producers and marketers, for transportation of their natural gas. Although firm capacity on the MIGC system is fully subscribed, we nevertheless monitor producer and marketing activities in the area served by our transportation system to maintain a full subscription of MIGC’s firm capacity and to identify new opportunities.

Operating expenses

We analyze operating expenses to evaluate our performance. Operating expenses include all amounts accrued for or paid to affiliates or third parties for the operation of our systems, including utilities, field labor, measurement and analysis and other disbursements. The primary components of our operating expenses that we evaluate include operation and maintenance expenses, cost of product expenses and general and administrative expenses. Certain of our operating expenses are paid to our affiliates. Affiliate expenses do not bear a direct relationship to affiliate revenues and third-party expenses do not bear a direct relationship to third-party revenues. Accordingly, our affiliate expenses are not those expenses necessary for generating our affiliate revenues and our third-party expenses are not those expenses necessary for generating our third-party revenues.

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 periods commencing on and subsequent to the Closing Date, these expenses are incurred under and 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) costs associated with 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. For the nine months ended September 30, 2008 and 2007, cost of product expenses comprised 20% and 10% of total operating expenses, respectively.

Prior to the Closing Date, general and administrative expenses included reimbursements of costs incurred by Anadarko on our behalf and allocations from Anadarko in the form of a management services fee in lieu of direct reimbursements for various corporate services. Subsequent to the Closing Date, Anadarko no longer receives a management services fee. Our general and administrative expenses are 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:

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

Pursuant to the omnibus agreement with Anadarko, which became effective on the Closing Date, we reimburse Anadarko for allocated general and administrative expenses. The amount required to be reimbursed by us to Anadarko for allocated general and administrative expenses pursuant to the omnibus agreement is 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 incurred by or allocated to us as a result of being a publicly traded partnership. We currently expect those expenses to be approximately $3.4 million per year, excluding equity-based compensation.

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 consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:

	Ø		our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to financing methods, capital structure or historical cost basis;
	Ø		the ability of our assets to generate cash flow to make distributions; and
	Ø		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 tables present 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 (in thousands):

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
Reconciliation of Adjusted EBITDA to Net Income
Adjusted EBITDA		$	20,300			$	18,273			$	63,904			$	52,329
Less:
Interest expense, net — affiliates			37				887				2,743				6,643
Income tax expense			68				4,023				8,086				10,469
Depreciation			7,145				6,361				20,155				17,104
Add:
Interest income from note — affiliate			4,253				—				6,479				—
Other income			93				—				124				—
Net income		$	17,396			$	7,002			$	39,523			$	18,113
Reconciliation of Adjusted EBITDA to Net Cash Provided by Operating Activities
Adjusted EBITDA		$	20,300			$	18,273			$	63,904			$	52,329
Interest income (expense), net — affiliates			4,216				(887	)			3,736				(6,643	)
Current income tax expense			(9	)			(3,222	)			(4,676	)			(3,406	)
Other income			93				—				124				—
Changes in operating working capital:
Accounts receivable and natural gas imbalances			(8,876	)			(983	)			(9,463	)			(1,062	)
Accounts payable and accrued expenses			(487	)			4,434				816				580
Other, including changes in non-current assets and liabilities			511				61				(465	)			12
Net cash provided by operating activities		$	15,748			$	17,676			$	53,976			$	41,810

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:

	Ø		We anticipate incurring approximately $3.4 million of general and administrative expenses annually attributable to operating as a publicly traded partnership, including expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution 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. General and administrative expenses such as these are reflected in our historical consolidated financial statements for the three and nine months ended September 30, 2008.
	Ø		We anticipate incurring up to $6.0 million in general and administrative expenses annually to be charged by Anadarko to us pursuant to the omnibus agreement. This amount is expected to be greater than amounts allocated to us by Anadarko for the management services fee reflected in our historical consolidated financial statements. The omnibus agreement became effective on the Closing Date.
	Ø		Prior to the Closing Date, all affiliate transactions were net settled within our consolidated 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. Effective on the Closing Date, all affiliate and third-party transactions are funded by our working capital. This impacts the comparability of our cash flow statements, working capital analysis and liquidity discussion.

	Ø		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 closing of the Offering; therefore, interest expense attributable to these balances is reflected in our historical consolidated financial statements for the periods ending prior to the Closing Date. Interest expense on intercompany balances is not expected to be incurred in future periods.
	Ø		For periods ending prior to January 1, 2008, our consolidated 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. Pursuant to the terms of the new agreements, our fees for gathering and treating services rendered to Anadarko increased. This increase was due, in part, to compensate us for additional operation and maintenance expense that we incur 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. Because our new gas gathering agreements are designed to fully recover these incremental costs, our revenues increased by an amount approximately equal to the incremental 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 to the nine months ended September 30, 2007, we estimate our historic gathering revenues and operation and maintenance expense would have increased by $4.0 million and our cash flow from operations would have remained unchanged.
	Ø		The new 10-year gas gathering agreements entered into with Anadarko 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 for the periods ended prior to January 1, 2008.
	Ø		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 reflected in our consolidated financial statements for the period beginning on May 14, 2008 and ending September 30, 2008 and will be included in future periods so long as the note remains outstanding.
	Ø		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, including our outstanding balances) that Anadarko incurs under its credit facility, or up to $110,000. See Note 5, “Transactions with Affiliates,” in the notes to the consolidated financial statements. In addition, Anadarko entered into a working capital facility with us, under which we 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. These commitment fees are included in interest income (expense), net in our consolidated financial statements for the three and nine months ended September 30, 2008.
	Ø		The Partnership generally is not subject to federal or state income tax. Federal and state income tax expense was recorded for periods ending prior to the Closing Date and the period that includes the Closing Date for income generated by the assets that were contributed by Anadarko to the Partnership. In periods subsequent to the Closing Date, the Partnership is only subject to Texas margin tax; therefore, tax expense attributable to Texas margin tax will continue to be recognized in the Partnership’s consolidated financial statements. The Partnership is required to make payments to Anadarko pursuant to a tax sharing arrangement for its share of Texas margin tax included in any combined or consolidated returns of Anadarko. The consolidated financial statements for periods ending prior to the Closing Date include deferred federal and state income taxes which were provided on temporary differences between the financial statement carrying amounts of recognized assets and liabilities and their respective tax bases as if the Partnership filed tax returns as a stand-alone entity. Immediately prior to closing of the Offering, the Partnership recorded an adjustment to equity of $76.5 million for the elimination of net deferred tax liabilities.

	Ø		Subsequent to closing of the Offering, 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). Our initial $8.6 million distribution represented a quarterly distribution of $0.30 per unit, prorated for the 48-day period beginning on the Closing Date and ending on June 30, 2008, and was distributed to unitholders during the three months ended September 30, 2008.
	Ø		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.
	Ø		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 the independent directors of our general partner under the LTIP, and incentive unit grants have been made to each of our general partner’s executive officers under the Incentive Plan. Pursuant to Financial Accounting Standards Board Statement No. 123 (revised 2004), Shared-Based Payment (“SFAS 123(R)”), grants made under equity-based compensation plans result in equity-based compensation expense which is determined, in part, by reference to the fair value of equity compensation as of the date of grant. Prior to the Closing Date, equity-based compensation expense for the LTIP and Incentive Plan was not reflected in our historical consolidated financial statements as there were no outstanding equity grants under either plan. Effective on the Closing Date, equity-based compensation expense for grants made under the LTIP and Incentive Plan is reflected in our statements of operations. Share-based compensation expense attributable to grants made under the LTIP will impact our cash flows from operating activities only to the extent our 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 under 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 expectations.

Capital markets

We require access to capital in order to fund acquisitions and expansion projects. Under the terms of our partnership agreement, we are required to distribute all of our available cash to our unitholders, which makes us dependent upon raising capital to fund growth projects. Historically, master limited partnerships have accessed the public debt and equity capital markets to raise money for new growth projects. Recent market turbulence has either raised the cost of those public funds or, in some cases, eliminated the availability of these funds to prospective issuers. If we are unable either to access the public capital markets or find alternative sources of capital, our growth strategy may be more challenging to execute.

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 cost of raising funds, in the capital markets. Though our competitors may face similar circumstances, such an environment could adversely impact our efforts to expand our operations or make future acquisitions.

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 22.9 Tcf in 2007 to approximately

23.3 Tcf in 2010. During the last three years, the U.S. has, on average, consumed approximately 22.2 Tcf per year, while total domestic production averaged approximately 18.6 Tcf per year during the same period. We believe that relatively 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 drilling 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 and the level of investment by Anadarko and third parties in the 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.

Benefits from system expansions

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

	Ø		We modified and relocated horsepower on our Dew system during the third quarter of 2008, which resulted in lower gathering line pressures and an increase in throughput of approximately 2 MMcf/d;
	Ø		We expanded 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 completed in July 2008; and
	Ø		We are expanding our Hugoton gathering system to connect wells drilled by third parties, including 8 third-party wells we connected during the first nine months of 2008 with an average initial production rate of 3.3 MMcf/d. We expect to connect 3 additional wells during the fourth quarter of 2008.

Acquisition opportunities

A key component of our growth strategy is to acquire midstream energy assets from Anadarko over time. In November 2008, the Partnership agreed to acquire certain midstream assets from Anadarko for $175 million in cash and the issuance of 2,556,891 common units. These assets provide a combination of gathering, treating and processing services in the Powder River Basin in locations that are connected or adjacent to the Partnership’s MIGC pipeline. Specifically, the Partnership has agreed to acquire Anadarko’s 100% ownership interest in the Hilight System, its 50% interest in the Newcastle gas gathering and processing facilities and its 15% interest in the Fort Union Gas Gathering, L.L.C. (collectively, the “Powder River Basin Assets”). The Powder River Basin Assets are operated by Anadarko. The acquisition will be financed primarily with debt, through the issuance of a 5-year, $175 million note to Anadarko, as well as through the issuance of 2,556,891 common units to Anadarko at an implied price of approximately $13.69 per unit. The acquisition and related transactions are expected to close in December 2008 and are subject to standard closing conditions and adjustments, including a right of first refusal related to the Newcastle system.

On December 27, 2007, Anadarko completed 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. Repayments that may be required by Anadarko in order for it 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 additional 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 additional acquisitions from Anadarko or third parties 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 — OVERVIEW

OPERATING RESULTS

Our discussion below compares the results for specific periods to the previous comparable period. For purposes of the following discussion, any increases or decreases “for the three months ended September 30, 2008” refer to the comparison of the three months ended September 30, 2008 to the three months ended September 30, 2007. Similarly, any increases or decreases “for the nine months ended September 30, 2008” refer to the comparison of the nine months ended September 30, 2008 to the nine months ended September 30, 2007.

Summary

Total revenues increased by $9.5 million and $30.2 million for the three months ended September 30, 2008 and for the nine months ended September 30, 2008, respectively. Gathering and transportation revenues increased $5.5 million, condensate revenues increased $1.2 million and other revenues increased $2.8 million for the three months ended September 30, 2008. Gathering and transportation revenues increased $16.8 million, condensate revenues increased $7.5 million and other revenues increased $5.9 million for the nine months ended September 30, 2008. These revenue increases are discussed below.

Net income increased by $10.4 million and $21.4 million for the three months ended September 30, 2008 and for the nine months ended September 30, 2008, respectively. The increase in net income for the three months ended September 30, 2008 is primarily due to a $9.5 million increase in total revenues driven by gathering rate increases, increased condensate margins, an increase in other revenues from changes in gas imbalance positions and gas prices, a $5.1 million increase in net affiliate interest income and a $4.0 million decrease in income tax expense. These items are partially offset by higher operating expenses of $8.3 million for the three months ended September 30, 2008. The increase in net income for the nine months ended September 30, 2008 is primarily due to a $30.2 million increase in total revenues driven by gathering rate increases, increased condensate margins and an increase in other revenues from changes in gas imbalance positions and gas prices, a $10.4 million increase in net affiliate interest income and a $2.4 million decrease in income tax expense. These items are partially offset by higher operating expenses of $21.7 million for the nine months ended September 30, 2008. The changes in revenues, operating expenses, interest expense and income taxes are discussed in more detail below.

Revenues and Operating Statistics

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
		(in thousands, except per-unit data)
Revenues
Affiliates		$	27,134			$	25,285			$	85,374			$	76,842
Third parties			11,169				3,521				30,775				9,117
Total revenues		$	38,303			$	28,806			$	116,149			$	85,959
Throughput volumes (MMBtu/d)
Affiliates			812				846				831				910
Third parties			178				93				140				90
Total throughput			990				939				971				1,000
Weighted average price per MMBtu (a)
Affiliates		$	0.35			$	0.29			$	0.36			$	0.28
Third parties		$	0.27			$	0.29			$	0.30			$	0.26
Total		$	0.34			$	0.29			$	0.35			$	0.28

Throughput volumes, which consist of affiliate and third-party volumes, increased by 51,000 MMBtu/d for the three months ended September 30, 2008 and decreased by 29,000 MMBtu/d for the nine months ended September 30, 2008.

Compared to the third quarter of 2007, affiliate volumes decreased by 34,000 MMBtu/d for the three months ended September 30, 2008, primarily attributable to throughput decreases at the Dew, Hugoton, Pinnacle and Haley systems, partially offset by increases at the MIGC system. The decline in affiliate volumes is primarily due to natural production declines, reduced activity and delayed completions. Specifically, delays in securing proppant used to hydraulically fracture wells in the Bossier area connected to the Dew and Pinnacle systems resulted in well-completion delays, which, in turn, adversely affected throughput volumes. Year-over-year volume declines at the Haley system from natural production declines and reduced drilling activity substantially offset out-of-period affiliate volumes recorded during the third quarter of 2008 that are related to the periods from the first quarter of 2007 to the second quarter of 2008. The increases in MIGC’s volumes are primarily attributable to a new affiliate contract effective with the expansion of the system in September 2007.

Affiliate volumes decreased by 79,000 MMBtu/d for the nine months ended September 30, 2008, primarily attributable to throughput decreases at the Haley, Pinnacle, Hugoton and Dew systems, partially offset by increases at the MIGC system. Haley field production and related Haley system throughput peaked in the first quarter of 2007. Since the first quarter of 2007, production and associated volumes from the Haley field have gradually declined due to the natural production decline and a shift in rig activity from the dedicated gathering area to other exploration areas within the Delaware Basin, resulting in fewer well connections. Recent activity has partially offset volume declines at the Haley system, with 10 wells connected during the nine months ended September 30, 2008 and 2 additional wells expected to be connected by December 31, 2008, in addition to the third-party volumes described below. Volume declines at the Haley system were also partially offset by out-of-period affiliate volumes recorded during the third quarter of 2008 that are related to the periods from the first quarter of 2007 to the second quarter of 2008. The decline in affiliate volumes at the Hugoton, Dew and Pinnacle systems for the nine months ended September 30, 2008 is primarily due to natural production declines and reduced or delayed activity in the Dew and Pinnacle areas. These volume decreases are partially offset by increases in the MIGC system due to the new affiliate contract that became effective in September 2007.

Third-party volumes increased by 85,000 MMBtu/d for the three months ended September 30, 2008, primarily attributable to throughput increases at the Haley and Hugoton systems. The increase in third-party volumes at the Haley gathering system is primarily due to out-of-period third-party volumes recorded during the third quarter of 2008 that are related to the periods from the first quarter of 2007 to the second quarter of 2008, as well as a third party’s activity in the area. Increased volumes at the Hugoton system are due to a third-party customer’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, with 7 wells connected during the nine months ended September 30, 2008 and 3 additional wells expected to be connected by December 31, 2008.

Third-party volumes increased by 50,000 MMBtu/d for the nine months ended September 30, 2008, primarily due to increases at the Haley and Hugoton systems described previously, partially offset by throughput declines at the Pinnacle system resulting primarily from a decrease in volumes at two central receipt points from a large third-party shipper.

Gathering and Transportation of Natural Gas Revenues

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
		(in thousands)
Gathering and transportation of natural gas:
Affiliates		$	26,405			$	22,847			$	81,199			$	69,544
Third parties			4,353				2,439				11,572				6,419
Total		$	30,758			$	25,286			$	92,771			$	75,963

Total gathering and transportation of natural gas revenues increased by $5.5 million and $16.8 million for the three months ended September 30, 2008 and for the nine months ended September 30, 2008, respectively. Revenues from affiliates increased primarily due to an increase in affiliate gathering rates under new contracts that became effective January 1, 2008, partially offset by lower volumes. Revenues from third parties increased primarily due to an increase in volumes on the Haley and Hugoton systems.

Condensate Revenues

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
		(in thousands, except barrels and price per barrel)
Condensate:
Affiliates		$	—			$	1,805			$	—			$	6,167
Third parties			3,022				—				13,882				225
Total		$	3,022			$	1,805			$	13,882			$	6,392
Volume (barrels per day)			301				301				487				412
Price per barrel		$	109.02			$	65.28			$	104.07			$	56.79

Total condensate revenues increased by $1.2 million and $7.5 million for the three months ended September 30, 2008 and for the nine months ended September 30, 2008, respectively. This increase was primarily due to increased condensate prices, which increased by $43.74 per barrel and $47.28 per barrel for the three months ended September 30, 2008 and for the nine months ended September 30, 2008, respectively. Condensate volumes were relatively flat for the three months ended September 30, 2008 and increased by 75 barrels per day for the nine months ended September 30, 2008. The volume increase for the nine months ended September 30, 2008 is primarily attributable to an increase in condensate recoveries due to the higher Btu composition of the gas stream from third-party drilling activity that has offset production declines. The change from affiliate revenues to third-party revenues is attributable to a November 2007 contract modification which effectively converted all of our condensate sales for 2008 to third-party sales.

Natural Gas and Other Revenues

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
		(in thousands)
Natural gas and other:
Affiliates		$	729			$	633			$	4,175			$	1,131
Third parties			3,794				1,082				5,321				2,473
Total natural gas and other		$	4,523			$	1,715			$	9,496			$	3,604

Total natural gas and other revenues increased by $2.8 million and $5.9 million for the three months ended September 30, 2008 and for the nine months ended September 30, 2008, respectively. The increase for the three months ended September 30, 2008 and for the nine months ended September 30, 2008 is primarily due to changes in our gas imbalance positions and higher gas prices. In addition, for the nine months ended September 30, 2008, other operating revenues increased $0.9 million related to an indemnity payment received from a third party.

Cost of Product and Operation and Maintenance Expenses

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
						(in thousands)
Cost of product		$	3,913			$	625			$	14,246			$	4,885
Operation and maintenance			9,376				8,003				26,665				21,840
Total cost of product and operation and maintenance expenses		$	13,289			$	8,628			$	40,911			$	26,725

Total cost of product and operation and maintenance expenses increased by $4.7 million and $14.2 million for the three months ended September 30, 2008 and for the nine months ended September 30, 2008, respectively. Cost of product expense for the three months ended September 30, 2008 and for the nine months ended September 30, 2008 increased by $3.3 million and $9.4 million, respectively, 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. Gas purchases were $8.28 per MMBtu for the three months ended September 30, 2008 compared to $5.55 per MMBtu for the three months ended September 30, 2007 and were $7.99 per MMBtu for the nine months ended September 30, 2008 compared to $6.14 per MMBtu for the nine months ended September 30, 2007. Cost of product expense increases are also attributable to increases in gas imbalances associated with MIGC. Cost of product expenses include natural gas purchases from affiliates of $3.2 million and $0.6 million for the three months ended September 30, 2008 and 2007, respectively, and $10.3 million and $4.9 million for the nine months ended September 30, 2008 and 2007, respectively.

Operation and maintenance expense for the three months ended September 30, 2008 and for the nine months ended September 30, 2008 increased by $1.4 million and $4.8 million, respectively. These increases are primarily attributable to labor and employee-related expenses, which increased $1.7 million and $5.7 million for the three months ended September 30, 2008 and for the nine months ended September 30, 2008, respectively. For the three months ended September 30, 2008 and for the nine months ended September 30, 2008, approximately $1.1 million and $4.0 million, respectively, of the increase in labor and employee-related expenses is attributable to contract modifications which entitle Anadarko, beginning in 2008, to charge us additional labor and employee-related expenses in order for us to bear the full cost of operational personnel working on our assets instead of bearing only those employee benefit costs reasonably allocated by Anadarko to us. These additional costs were taken into account when setting the gathering rates in our new affiliate-based contracts; thus, our revenues increased by approximately the same amount. Other increases in labor and employee-related expenses are primarily due to increases in benefits and incentive programs. These increases are partially offset by decreases in contract labor, compressor expenses and chemical expenses. Operation and maintenance expenses include charges from affiliates of $3.9 million and $2.2 million for the three months ended September 30, 2008 and 2007, respectively, and $10.9 million and $5.2 million for the nine months ended September 30, 2008 and 2007, respectively, for services provided to the Partnership pursuant to the services and secondment agreement for periods subsequent to the Offering and for personnel costs allocated by Anadarko to us for periods prior to the Closing Date. The foregoing amounts reflect a reclassification of personnel costs from third party to affiliate for prior periods to conform to the current presentation.

General and Administrative, Depreciation and Other Expenses

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
						(in thousands)
General and administrative		$	3,412			$	897			$	6,809			$	3,121
Property and other taxes			1,302				1,008				4,525				3,784
Depreciation			7,145				6,361				20,155				17,104
Total general and administrative, depreciation and other expenses		$	11,859			$	8,266			$	31,489			$	24,009

General and administrative, depreciation and other expenses increased by $3.6 million and $7.5 million for the three months ended September 30, 2008 and for the nine months ended September 30, 2008, respectively. The increases are partially attributable to an

increase in general and administrative expenses of $2.5 million and $3.7 million for the three months ended September 30, 2008 and for the nine months ended September 30, 2008, respectively. These general and administrative expense increases are primarily due to increases in general and administrative expenses charged by Anadarko to us pursuant to the omnibus agreement, which became effective on the Closing Date. For periods prior to the Closing Date, general and administrative expenses included costs allocated by Anadarko to the Partnership in the form of a management services fee. Specifically, general and administrative expenses increased by approximately $0.8 million and $1.1 million for the three months ended September 30, 2008 and for the nine months ended September 30, 2008, respectively, due to increased audit, legal and rent expenses primarily due to doing business as an independent public company. General and administrative expenses include charges from affiliates of $2.6 million and $0.9 million for the three months ended September 30, 2008 and 2007, respectively, and $5.6 million and $3.1 million for the nine months ended September 30, 2008 and 2007, respectively. Property and other taxes increased by $0.3 million and $0.7 million for the three months ended September 30, 2008 and for the nine months ended September 30, 2008, respectively, primarily due to higher ad valorem taxes. Depreciation expense increased by $0.8 million and $3.1 million for the three months ended September 30, 2008 and for the nine months ended September 30, 2008, respectively. The increased depreciation expense is attributable to additional assets placed into service during 2007 and 2008.

Interest Income (Expense), Net — Affiliates

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
						(in thousands)
Interest income on note receivable from Anadarko		$	4,253			$	—			$	6,479			$	—
Interest expense, net — affiliates			(37	)			(887	)			(2,743	)			(6,643	)
Total interest income (expense), net — affiliates		$	4,216			$	(887	)		$	3,736			$	(6,643	)