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Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
     
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2009
Or
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission file number: 001-34046
WESTERN GAS PARTNERS, LP
(Exact name of registrant as specified in its charter)
     
Delaware
(State or other jurisdiction of
incorporation or organization)
  26-1075808
(I.R.S. Employer
Identification No.)
     
1201 Lake Robbins Drive
The Woodlands, Texas

(Address of principal executive offices)
  77380
(Zip Code)
(832) 636-6000
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o 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.
             
Large accelerated filer o   Accelerated filer o   Non-accelerated filer þ (Do not check if a smaller reporting company)   Smaller reporting company o
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 29,474,925 common units outstanding as of October 31, 2009.
 
 

 


 

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, 2009 and 2008     4  
 
               
 
      Consolidated Balance Sheets as of September 30, 2009 and December 31, 2008     5  
 
               
 
      Consolidated Statement of Equity and Partners’ Capital for the nine months ended September 30, 2009     6  
 
               
 
      Consolidated Statements of Cash Flows for the nine months ended September 30, 2009 and 2008     7  
 
               
 
      Notes to Unaudited Consolidated Financial Statements     8  
 
               
 
  Item 2.   Management’s Discussion and Analysis of Financial Condition and Results of Operations     28  
 
               
 
  Item 3.   Quantitative and Qualitative Disclosures About Market Risk     50  
 
               
 
  Item 4T.   Controls and Procedures     51  
 
               
PART II   OTHER INFORMATION        
 
               
 
  Item 1.   Legal Proceedings     51  
 
               
 
  Item 6.   Exhibits     51  
 EX-10.3
 EX-10.4
 EX-31.1
 EX-31.2
 EX-32.1

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Definitions
As generally used within the energy industry and in this Quarterly Report on Form 10-Q, the identified terms have the following meanings:
Barrel or Bbl: 42 U.S. gallons measured at 60 degrees Fahrenheit.
Bcf/d: One billion cubic feet per day.
Btu: British thermal unit.
CO2: Carbon dioxide.
Condensate: A natural gas liquid with a low vapor pressure mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.
Drip condensate: Heavier hydrocarbon liquids that fall out of the natural gas stream and are recovered in the gathering system without processing.
Imbalance: Imbalances result from (i) differences between gas volumes nominated by customers and gas volumes received from those customers and (ii) differences between gas volumes received from customers and gas volumes delivered to those customers.
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.
Natural gas liquids or NGLs: The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.
Residue gas: The natural gas remaining after being processed or treated.
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.

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PART I. FINANCIAL INFORMATION
Item 1.   Financial Statements
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,  
    2009     2008(1)     2009(1)     2008(1)  
Revenues — affiliates
                               
Gathering, processing and transportation of natural gas
  $ 33,438     $ 29,878     $ 101,314     $ 88,217  
Natural gas, natural gas liquids and condensate sales
    19,026       50,247       55,963       150,771  
Equity income and other
    2,254       2,227       6,624       7,895  
 
                       
Total revenues — affiliates
    54,718       82,352       163,901       246,883  
 
                               
Revenues — third parties
                               
Gathering, processing and transportation of natural gas
    4,514       5,254       12,985       12,811  
Natural gas, natural gas liquids and condensate sales
    1,565       3,181       4,969       14,063  
Other, net
    199       3,795       806       5,323  
 
                       
Total revenues — third parties
    6,278       12,230       18,760       32,197  
 
                       
 
                               
Total revenues
    60,996       94,582       182,661       279,080  
 
                       
 
                               
Operating expenses (2)
                               
Cost of product
    12,888       40,912       37,479       124,204  
Operation and maintenance
    11,741       14,001       34,841       39,512  
General and administrative
    5,980       4,332       15,067       9,564  
Property and other taxes
    1,876       1,630       5,984       5,510  
Depreciation and amortization
    10,216       9,380       29,642       26,890  
Impairment
          9,354             9,354  
 
                       
Total operating expenses
    42,701       79,609       123,013       215,034  
 
                       
Operating income
    18,295       14,973       59,648       64,046  
Interest income, net — affiliates
    1,098       4,661       5,977       4,932  
Other income, net
    13       126       29       159  
 
                       
Income before income taxes
    19,406       19,760       65,654       69,137  
Income tax expense (benefit)
    171       (1,463 )     (152 )     11,289  
 
                       
Net income
    19,235       21,223       65,806       57,848  
Net income attributable to noncontrolling interests
    2,187       3,274       7,741       6,177  
 
                       
Net income attributable to Western Gas Partners, LP
  $ 17,048     $ 17,949     $ 58,065     $ 51,671  
 
                       
Limited partner interest in net income:
                               
Net income attributable to Western Gas Partners, LP (3)
  $ 17,048     $ 17,949     $ 58,065     $ 51,671  
Less pre-acquisition income allocated to Parent
          553       5,935       26,026  
Less general partner interest in net income
    341       348       1,043       513  
 
                       
Limited partner interest in net income
  $ 16,707     $ 17,048     $ 51,087     $ 25,132  
Net income per common unit — basic and diluted
  $ 0.30     $ 0.32     $ 0.92     $ 0.48  
Net income per subordinated unit — basic and diluted
  $ 0.30     $ 0.32     $ 0.91     $ 0.47  
 
(1)   Financial information for 2008 and the first six months of 2009 has been revised to include results attributable to the Powder River assets and Chipeta assets. See Note 1—Description of Business and Basis of Presentation—Powder River acquisition and Chipeta acquisition.
 
(2)   Operating expenses include amounts charged by Anadarko to the Partnership (“Anadarko” and “Partnership” are as defined in Note 1—Description of Business and Basis of Presentation) for services as well as reimbursement of amounts paid by Anadarko to third parties on behalf of the Partnership. Cost of product expenses include product purchases from Anadarko of $1.3 million and $7.5 million for the three months ended September 30, 2009 and 2008, respectively, and $4.8 million and $22.2 million for the nine months ended September 30, 2009 and 2008, respectively. Operation and maintenance expenses include charges from Anadarko of $5.2 million and $5.6 million for the three months ended September 30, 2009 and 2008, respectively, and $14.6 million and $15.3 million for the nine months ended September 30, 2009 and 2008, respectively. General and administrative expenses include charges from Anadarko of $3.6 million and $3.5 million for the three months ended September 30, 2009 and 2008, respectively, and $10.5 million and $8.4 million for the nine months ended September 30, 2009 and 2008, respectively. See Note 6—Transactions with Affiliates.
 
(3)   General and limited partner interest in net income represents net income for periods including and subsequent to the Partnership’s acquisition of the Partnership Assets (as defined in Note 1—Description of Business and Basis of Presentation — Presentation of Partnership Acquisitions). See also Note 5—Net Income per Limited Partner Unit.
See accompanying notes to unaudited consolidated financial statements.

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Western Gas Partners, LP
CONSOLIDATED BALANCE SHEETS
(Unaudited, in thousands, except number of units)
                 
    September 30,     December 31,  
    2009     2008(1)  
ASSETS
               
Current assets
               
Cash and cash equivalents
  $ 56,023     $ 36,074  
Accounts receivable, net — third parties
    2,690       5,878  
Accounts receivable — affiliates
    1,145       2,012  
Natural gas imbalance receivables — third parties
    22       389  
Natural gas imbalance receivables — affiliates
    280       1,422  
Other current assets
    2,175       1,380  
 
           
Total current assets
    62,335       47,155  
Note receivable — Anadarko
    260,000       260,000  
Property, plant and equipment
               
Cost
    901,340       861,780  
Less accumulated depreciation
    204,683       175,427  
 
           
Net property, plant and equipment
    696,657       686,353  
Goodwill
    20,836       20,836  
Equity investment
    19,651       18,183  
Other assets
    410       628  
 
           
Total assets
  $ 1,059,889     $ 1,033,155  
 
           
LIABILITIES AND PARTNERS’ CAPITAL
               
Current liabilities
               
Accounts payable — third parties
  $ 5,336     $ 5,459  
Accounts payable — affiliates
          21,103  
Natural gas imbalance payable — third parties
    549       244  
Natural gas imbalance payable — affiliates
    736       1,198  
Accrued ad valorem taxes
    6,149       1,330  
Income taxes payable
    330       146  
Accrued liabilities — third parties
    8,040       12,802  
Accrued liabilities — affiliates
    398       153  
 
           
Total current liabilities
    21,538       42,435  
Long-term liabilities
               
Notes payable — Anadarko
    276,451       175,000  
Deferred income taxes
    605       1,148  
Asset retirement obligations and other
    10,568       9,947  
 
           
Total long-term liabilities
    287,624       186,095  
 
           
Total liabilities
    309,162       228,530  
Commitments and contingencies (Note 12)
               
Equity and Partners’ capital
               
Common units (29,474,925 and 29,093,197 units issued and outstanding at September 30, 2009 and December 31, 2008, respectively)
    377,032       368,049  
Subordinated units (26,536,306 units issued and outstanding at September 30, 2009 and December 31, 2008)
    276,019       275,917  
General partner units (1,143,086 and 1,135,296 units issued and outstanding at September 30, 2009 and December 31, 2008, respectively)
    11,221       10,988  
Parent net investment
          83,655  
Noncontrolling interests
    86,455       66,016  
 
           
Equity and Partners’ capital
    750,727       804,625  
 
           
Total liabilities, equity and Partners’ capital
  $ 1,059,889     $ 1,033,155  
 
           
 
(1)   Financial information for 2008 has been revised to include balances attributable to the Chipeta assets. See Note 1—Description of Business and Basis of Presentation—Chipeta acquisition.
See accompanying notes to unaudited consolidated financial statements.

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Western Gas Partners, LP
CONSOLIDATED STATEMENT OF EQUITY AND PARTNERS’ CAPITAL
(Unaudited, in thousands)
                                                 
            Partners’ Capital              
    Parent Net     Limited Partners     General     Noncontrolling        
    Investment     Common     Subordinated     Partner     Interests     Total  
 
Balance at December 31, 2008 (1)
  $ 83,655     $ 368,049     $ 275,917     $ 10,988     $ 66,016     $ 804,625  
Net pre-acquisition distributions to Anadarko
    844                               844  
Contribution of Chipeta assets
    (112,744 )     11,068             225             (101,451 )
Contributions from noncontrolling interest owners and Parent
    25,236                         15,509       40,745  
Non-cash equity-based compensation
          291                         291  
Net income
    5,935       26,838       24,249       1,043       7,741       65,806  
Distributions to unitholders
          (26,595 )     (24,147 )     (1,035 )           (51,777 )
Distributions to noncontrolling interest owners and Parent
    (2,926 )                       (2,811 )     (5,737 )
Other
          (2,619 )                       (2,619 )
 
                                   
Balance at September 30, 2009
  $     $ 377,032     $ 276,019     $ 11,221     $ 86,455     $ 750,727  
 
                                   
 
(1)   Financial information for 2008 and the first six months of 2009 has been revised to include balances attributable to the Chipeta assets. See Note 1—Description of Business and Basis of Presentation—Chipeta acquisition.
See accompanying notes to unaudited consolidated financial statements.

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Western Gas Partners, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited, in thousands)
                 
    Nine Months Ended September 30,  
    2009(1)     2008(1)  
Cash flows from operating activities
               
Net income
  $ 65,806     $ 57,848  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation and amortization
    29,642       26,890  
Impairment
          9,354  
Deferred income taxes
    (336 )     2,433  
Changes in assets and liabilities:
               
(Increase) decrease in accounts receivable
    1,434       (10,948 )
(Increase) decrease in natural gas imbalance receivable
    1,510       (1,066 )
Increase (decrease) in accounts payable, accrued liabilities and natural gas imbalance payable
    (17,007 )     21,683  
Change in other items, net
    (1,398 )     (1,479 )
 
           
Net cash provided by operating activities
    79,651       104,715  
Cash flows from investing activities
               
Chipeta acquisition
    (101,451 )      
Capital expenditures
    (41,500 )     (68,930 )
Loan to Anadarko
          (260,000 )
Investment in equity affiliate
    (264 )     (8,095 )
 
           
Net cash used in investing activities
    (143,215 )     (337,025 )
Cash flows from financing activities
               
Proceeds from issuance of common units
          315,161  
Reimbursement to Parent from offering proceeds
          (45,161 )
Issuance of Note Payable to Anadarko
    101,451        
Contributions from noncontrolling interest owners and Parent
    40,745       148,356  
Distributions to unitholders
    (51,777 )     (8,567 )
Distributions to noncontrolling interest owners and Parent
    (5,737 )     (19,734 )
Net pre-acquisition distributions from Anadarko
    (1,169 )     (106,355 )
 
           
Net cash provided by financing activities
    83,513       283,700  
 
           
Net increase in cash and cash equivalents
    19,949       51,390  
Cash and cash equivalents at beginning of period
    36,074        
 
           
Cash and cash equivalents at end of period
  $ 56,023     $ 51,390  
 
           
Supplemental disclosures
               
Contribution of net assets from Parent
  $ 112,744     $ 321,609  
Net carrying value of Chipeta assets in excess of consideration paid
  $ 11,293     $  
Elimination of deferred tax liabilities
  $     $ 1,829  
Interest paid
  $ 5,026     $  
Interest received
  $ 12,675     $ 3,662  
 
(1)   Financial information for 2008 and the first six months of 2009 has been revised to include activity attributable to the Powder River assets and Chipeta assets. See Note 1—Description of Business and Basis of Presentation—Powder River acquisition and Chipeta acquisition.
See accompanying notes to unaudited consolidated financial statements.

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Notes to unaudited consolidated financial statements of Western Gas Partners, LP
1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION
Basis of presentation
Western Gas Partners, LP (the “Partnership”) is a Delaware limited partnership formed in August 2007. The Partnership’s assets consist of nine gathering systems, six natural gas treating facilities, three gas processing 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, processing, treating and transporting natural gas for Anadarko Petroleum Corporation and its consolidated subsidiaries and third-party producers and customers. For purposes of these financial statements, the “Partnership” refers to Western Gas Partners, LP and its subsidiaries; “Anadarko” refers to Anadarko Petroleum Corporation and its consolidated subsidiaries, excluding the Partnership; “Parent” refers to Anadarko prior to our acquisition of assets from Anadarko; and “affiliates” refers to wholly owned and partially owned subsidiaries of Anadarko, excluding the Partnership. The Partnership’s general partner is Western Gas Holdings, LLC, a wholly owned subsidiary of Anadarko.
The consolidated financial statements include the accounts of the Partnership and entities in which it holds a controlling financial interest. All significant intercompany transactions have been eliminated. Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. The 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, 2009 and December 31, 2008, results of operations for the three and nine months ended September 30, 2009 and 2008, statement of equity and partners’ capital for the nine months ended September 30, 2009 and statements of cash flows for the nine months ended September 30, 2009 and 2008. The Partnership’s financial results for the nine months ended September 30, 2009 are not necessarily indicative of the results for the full year ending December 31, 2009.
The accompanying consolidated financial statements of the Partnership have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). To conform to these accounting principles, 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 under the particular circumstances. Although these estimates are based on management’s best available knowledge at the time, 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. 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.
The accompanying consolidated financial statements and notes should be read in conjunction with the Partnership’s annual report on Form 10-K, as filed with the Securities and Exchange Commission (the “SEC”) on March 13, 2009.
Initial public offering
On May 14, 2008, 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. The May 14 and June 11 issuances are referred to collectively as the “initial public offering.” The common units are listed on the New York Stock Exchange under the symbol “WES.”
Concurrent with the closing of the initial public 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 1,083,115 general partner units, representing a 2.0% general partner interest in the Partnership, 100% of the incentive distribution rights (“IDRs”), 5,725,431 common units and 26,536,306 subordinated units. AGC, PGT and MIGC are referred to collectively as the “initial assets.” The common units issued to Anadarko include 751,625 common units issued following the expiration of the underwriters’ over-allotment option and represent the portion of the common units for which the underwriters did not exercise their over-allotment option. See Note 4—Partnership Equity and Distributions in Item 8 of the Partnership’s annual report on Form 10-K for information related to the distribution rights of the common and subordinated unitholders and to the IDRs held by the general partner.

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Notes to unaudited consolidated financial statements of Western Gas Partners, LP
Powder River acquisition
In December 2008, the Partnership acquired certain midstream assets from Anadarko for consideration consisting of (i) $175.0 million in cash, which was financed by borrowing $175.0 million from Anadarko pursuant to the terms of a five-year term loan agreement, and (ii) the issuance of 2,556,891 common units and 52,181 general partner units. The acquisition consisted of (i) a 100% ownership interest in the Hilight system, (ii) a 50% interest in the Newcastle system and (iii) a 14.81% limited liability company membership interest in Fort Union Gas Gathering, L.L.C. (“Fort Union”). These assets are referred to collectively as the “Powder River assets” and the acquisition is referred to as the “Powder River acquisition.”
Chipeta acquisition
In July 2009, the Partnership acquired certain midstream assets from Anadarko for (i) approximately $101.5 million in cash, which was financed by borrowing $101.5 million from Anadarko pursuant to the terms of a 7.0% fixed-rate, three-year term loan agreement, and the (ii) issuance of 351,424 common units and 7,172 general partner units. These assets provide processing and transportation services in the Greater Natural Buttes area in Uintah County, Utah. The acquisition consisted of a 51% membership interest in Chipeta Processing LLC (“Chipeta”) and associated midstream assets. Chipeta owns a natural gas processing plant complex, which includes two recently completed processing trains: a refrigeration unit completed in November 2007 with a design capacity of 240 MMcf/d and a 250 MMcf/d capacity cryogenic unit which was commissioned in April 2009. The 51% membership interest in Chipeta and associated midstream assets are referred to collectively as the “Chipeta assets” and the acquisition is referred to as the “Chipeta acquisition.”
Presentation of Partnership acquisitions
The initial assets, Powder River assets and Chipeta assets are referred to collectively as the “Partnership Assets.” References to “periods prior to the Partnership’s acquisition of the Partnership Assets” and similar phrases refer to periods prior to May 14, 2008, with respect to the initial assets, periods prior to December 19, 2008, with respect to the Powder River assets and periods prior to July 1, 2009 with respect to the Chipeta assets. Reference to “periods including and subsequent to the Partnership’s acquisition of the Partnership Assets” and similar phrases refer to periods including and subsequent to May 14, 2008, with respect to the initial assets, periods including and subsequent to December 19, 2008, with respect to the Powder River assets, and periods including and subsequent to July 1, 2009, with respect to the Chipeta assets.
Anadarko acquired MIGC and the Powder River assets in connection with its August 23, 2006 acquisition of Western Gas Resources, Inc. (“Western”) and Anadarko acquired Chipeta in connection with its August 10, 2006 acquisition of Kerr-McGee Corporation (“Kerr-McGee”). The acquisitions of the Partnership Assets were considered transfers of net assets between entities under common control. Accordingly, the Partnership is required to revise its financial statements to include the activities of the Partnership Assets as of the date of common control. The Partnership’s historical financial statements for the three and nine months ended September 30, 2008 and the first six months of 2009 have been recast to reflect the results attributable to the Powder River assets and the Chipeta assets as if the Partnership owned the Powder River assets, a 51% interest in Chipeta and associated midstream assets for all periods presented. Net income attributable to the Partnership Assets for periods prior to the Partnership’s acquisition of such assets is not allocated to the limited partners for purposes of calculating net income per limited partner unit. In addition to recasting the Partnership’s financial statements for the Powder River assets and the Chipeta assets, certain amounts in prior periods have been reclassified to conform to the current presentation.
The consolidated financial statements for periods prior to the Partnership’s acquisition of the Partnership Assets have been prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the assets and operated as a separate entity during the periods reported.

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Notes to unaudited consolidated financial statements of Western Gas Partners, LP
Anadarko Holdings of Partnership Equity
As of September 30, 2009, Anadarko held 1,143,086 general partner units representing a 2.0% general partner interest in the Partnership, 100% of the Partnership IDRs, 8,633,746 common units and 26,536,306 subordinated units. Anadarko’s common and subordinated unitholders owned an aggregate 61.5% limited partner interest in the Partnership. The public held 20,841,179 common units, representing a 36.5% limited partner interest in the Partnership.
2. NEW ACCOUNTING STANDARDS
The Partnership adopted new Financial Accounting Standards Board (“FASB”) staff guidance on fair-value measurement, effective January 1, 2009. This guidance applies fair value measurement in accounting for business combinations, which expands financial disclosures, defines an acquirer and modifies the accounting for some business combination items. Under the guidance an acquirer is required to record 100% of assets and liabilities, including goodwill, contingent assets and contingent liabilities, at fair value. In addition, contingent consideration must be recognized at fair value at the acquisition date, acquisition-related costs must be expensed rather than treated as an addition to the assets acquired, and restructuring costs are required to be recognized separately from the business combination. The Partnership will apply these provisions to acquisitions of businesses from third parties that close after January 1, 2009. The guidance did not change the accounting for transfers of assets between entities under common control and, therefore, does not impact the Partnership’s accounting for asset acquisitions from Anadarko.
The Partnership adopted new accounting and reporting standards for noncontrolling interests in a subsidiary and for the deconsolidation of subsidiaries, effective January 1, 2009. Specifically, these standards require the recognition of noncontrolling interests (formerly referred to as minority interests) as a component of total equity. These standards establish a single method of accounting for changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation. Dispositions of subsidiary equity are now required to be accounted for as equity transactions. Noncontrolling interests, representing the interest in Chipeta held by Anadarko and a third party, are presented within equity for all periods presented. Finally, consolidated net income is presented to include the amounts attributable to the parent, general and limited partners and the noncontrolling interests.
The Partnership also adopted new guidance which addresses the application of the two-class method in determining net 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. The guidance clarifies that the two-class method would apply, and provides the methodology for and circumstances under which undistributed earnings are allocated to the general partner, limited partners and IDR holders. In addition, the Partnership adopted guidance addressing whether instruments granted in equity-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. The guidance requires companies to treat unvested equity-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 adopted these standards effective January 1, 2009 and has applied these provisions to all periods in which earnings per unit is presented. These standards did not impact earnings per unit for the periods presented herein.
The Partnership also adopted new guidance addressing subsequent events. The guidance does not change the Partnership’s accounting policy for subsequent events, but instead incorporates existing accounting and disclosure requirements related to subsequent events from auditing standards into GAAP. This standard defines subsequent events as either recognized subsequent events (events that provide additional evidence about conditions at the balance sheet date) or nonrecognized subsequent events (events that provide evidence about conditions that arose after the balance sheet date). Recognized subsequent events are recorded in the financial statements for the current period presented, while nonrecognized subsequent events are not. Both types of subsequent events require disclosure in the consolidated financial statements if those financial statements would otherwise be misleading. The Partnership is also required to disclose the date through which subsequent events have been evaluated. The adoption of this standard had no impact on the Partnership’s financial statements. The Partnership has evaluated subsequent events through November 12, 2009.

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Notes to unaudited consolidated financial statements of Western Gas Partners, LP
The FASB also issued new accounting standards that require the Partnership to disclose the fair value of financial instruments quarterly. The Partnership has disclosed the fair value of its note receivable from Anadarko and its long-term debt in Note 6—Transactions with Affiliates and Note 10—Debt, respectively.
3. NONCONTROLLING INTERESTS
In July 2009, the Partnership acquired a 51% interest in Chipeta. Chipeta is a Delaware limited liability company formed in April 2008 to construct and operate a natural gas processing facility. As of September 30, 2009, Chipeta is owned 51% by the Partnership, 24% by Anadarko and 25% by a third-party member. The interests in Chipeta held by Anadarko and the third-party member are reflected as noncontrolling interests in the consolidated financial statements.
In connection with the Partnership’s acquisition of its 51% membership interest in Chipeta, the Partnership became party to Chipeta’s limited liability company agreement, as amended and restated as of July 23, 2009 (the “Chipeta LLC Agreement”), together with Anadarko and the third-party member. The Chipeta LLC Agreement provides that:
    Chipeta’s members will be required from time to time to make capital contributions to Chipeta to the extent approved by the members in connection with Chipeta’s annual budget;
 
    to the extent available, Chipeta will distribute cash to its members quarterly in accordance with those members’ membership interests; and
 
    Chipeta’s membership interests are subject to significant restrictions on transfer.
Upon acquisition of its interest in Chipeta, the Partnership became the managing member of Chipeta. As managing member, the Partnership manages the day-to-day operations of Chipeta and receives a management fee from the other members which is intended to compensate the managing member for the performance of its duties. The Partnership may only be removed as the managing member if it is grossly negligent or fraudulent, breaches its primary duties or fails to respond in a commercially reasonable manner to written business proposals from the other members and such behavior, breach or failure has a material adverse effect to Chipeta.
4. PARTNERSHIP 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 (as defined in the partnership agreement) to unitholders of record on the applicable record date. During the nine months ended September 30, 2009, the Partnership paid cash distributions to its unitholders of approximately $51.8 million, representing the $0.31 per unit distribution for the quarter ended June 30, 2009 and $0.30 per unit distributions for each of the quarters ended March 31, 2009 and December 31, 2008. During the nine months ended September 30, 2008, the Partnership paid cash distributions to its unitholders of approximately $8.6 million, representing the $0.1582 per unit distribution for the quarter ended June 30, 2008. See also Note 14—Subsequent Events concerning distributions approved in October 2009.

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Notes to unaudited consolidated financial statements of Western Gas Partners, LP
5. NET INCOME PER LIMITED PARTNER UNIT
The Partnership’s net income attributable to the Partnership Assets for periods including and subsequent to the Partnership’s acquisitions of the Partnership Assets is allocated to the general partner and the limited partners, including any subordinated unitholders, in accordance with their respective ownership percentages, and when applicable, giving effect to unvested units granted under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (“LTIP”) and incentive distributions allocable to the general partner. The allocation of undistributed earnings, or net income in excess of distributions, to the incentive distribution rights is limited to available cash (as defined by the partnership agreement) for the period. 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 May 14, 2008 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.
The following table illustrates the Partnership’s calculation of net income per unit for common and subordinated limited partner units (in thousands, except per-unit information):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008(1)     2009(1)     2008(1)  
 
Net income attributable to Western Gas Partners, LP
  $ 17,048     $ 17,949     $ 58,065     $ 51,671  
Less pre-acquisition income allocated to Parent
          553       5,935       26,026  
Less general partner interest in net income
    341       348       1,043       513  
 
                       
Limited partner interest in net income
  $ 16,707     $ 17,048     $ 51,087     $ 25,132  
 
                       
 
                               
Net income allocable to common units
  $ 8,818     $ 8,524     $ 26,838     $ 12,722  
Net income allocable to subordinated units
    7,889       8,524       24,249       12,410  
 
                       
Limited partner interest in net income
  $ 16,707     $ 17,048     $ 51,087     $ 25,132  
 
                       
 
                               
Net income per limited partner unit — basic and diluted
                               
Common units
  $ 0.30     $ 0.32     $ 0.92     $ 0.48  
Subordinated units
  $ 0.30     $ 0.32     $ 0.91     $ 0.47  
Total
  $ 0.30     $ 0.32     $ 0.92     $ 0.47  
 
                               
Weighted average limited partner units outstanding — basic and diluted
                               
Common units
    29,395       26,536       29,200       26,536  
Subordinated units
    26,536       26,536       26,536       26,536  
 
                       
Total
    55,931       53,072       55,736       53,072  
 
                       
 
(1)   Financial information for 2008 and the first six months of 2009 has been revised to include results attributable to the Chipeta assets. See Note 1—Description of Business and Basis of Presentation—Chipeta acquisition.

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Notes to unaudited consolidated financial statements of Western Gas Partners, LP
6. TRANSACTIONS WITH AFFILIATES
Affiliate transactions
The Partnership provides natural gas gathering, compression, processing, treating and transportation services to Anadarko and a portion of the Partnership’s expenditures are paid by or to Anadarko, which results in affiliate transactions. Except for volumes taken in-kind by certain producers, an affiliate of Anadarko sells the natural gas and extracted NGLs attributable to the Partnership’s processing activities, which also result in affiliate transactions. In addition, affiliate-based transactions also result from contributions to and distributions from Fort Union and Chipeta which are paid or received by Anadarko.
Cash management
Anadarko operates a cash management system whereby excess cash from most of its subsidiaries, held in separate bank accounts, is generally swept to centralized accounts. Prior to May 14, 2008, with respect to the initial assets, and prior to December 19, 2008, with respect to the Powder River assets, sales and purchases related to third-party transactions were received or paid in cash by Anadarko within its centralized cash management system. Anadarko charged the Partnership interest at a variable rate on outstanding affiliate balances attributable to such assets for the periods these balances remained outstanding. The outstanding affiliate balances were entirely settled through an adjustment to parent net equity in connection with the initial public offering and the Powder River acquisition. Subsequent to May 14, 2008, with respect to the initial assets, and subsequent to December 19, 2008, with respect to the Powder River assets, the Partnership cash-settles transactions directly with third parties and with Anadarko affiliates and affiliate-based interest expense on current intercompany balances is not charged.
Prior to June 1, 2008, with respect to Chipeta (the date on which Anadarko initially contributed assets to Chipeta), sales and purchases related to third-party transactions were received or paid in cash by Anadarko within its centralized cash management system and were settled with Chipeta through an adjustment to parent net equity. Subsequent to June 1, 2008, Chipeta cash settled transactions directly with third parties and with Anadarko.
Note receivable from Anadarko
Concurrent with the closing of the initial public offering, the Partnership loaned $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%. Interest on the note is payable quarterly. The fair value of the note receivable from Anadarko was approximately $275.7 million and $198.1 million at September 30, 2009 and December 31, 2008, respectively. The fair value of the note reflects any premium or discount for the differential between the stated interest rate and quarter-end market rate, based on quoted market prices of similar debt instruments.
Notes payable to Anadarko
Concurrent with the closing of the Powder River acquisition in December 2008, the Partnership entered into a five-year, $175.0 million term loan agreement with Anadarko under which the Partnership pays Anadarko interest at a fixed rate of 4.00% for the first two years and a floating rate of interest at three-month LIBOR plus 150 basis points for the final three years. In July 2009, concurrent with the closing of the Chipeta acquisition, the Partnership entered into a three-year, $101.5 million term loan agreement with Anadarko under which the Partnership paid Anadarko interest at a fixed rate of 7.00%. See Note 10—Debt. See also Note 14—Subsequent Events regarding refinancing of the three-year term loan in October 2009.
Commodity price swap agreements
The Partnership entered into commodity price swap agreements with Anadarko in December 2008 to mitigate exposure to commodity price volatility that would otherwise be present as a result of the Partnership’s acquisition of the Hilight and Newcastle systems. Beginning on January 1, 2009, the commodity price swap agreements fix the margin the Partnership will realize on its share of revenues under percent-of-proceeds contracts applicable to natural gas processing activities at the Hilight and Newcastle systems. In this regard, the Partnership’s notional volumes for each of the swap agreements are not specifically defined; instead, the commodity price swap agreements apply to volumes equal in amount to the Partnership’s share of actual volumes processed at the Hilight and Newcastle systems. Because the notional volumes are not fixed, the commodity price swap agreements do not satisfy the definition of a derivative financial instrument and are therefore not

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Notes to unaudited consolidated financial statements of Western Gas Partners, LP
required to be measured at fair value. The Partnership reports its realized gains and losses on the commodity price swap agreements in natural gas, natural gas liquids and condensate sales — affiliates in its consolidated statements of income in the period in which the associated revenues are recognized. During the three and nine months ended September 30, 2009, the Partnership recorded realized gains of $1.5 million and $5.6 million, respectively, attributable to the commodity price swap agreements.
Below is a summary of the fixed prices on the Partnership’s commodity price swap agreements outstanding as of September 30, 2009. The commodity price swap arrangements expire in December 2010 and the Partnership may annually, at its option, extend the agreements through December 2013.
                 
    Year Ended December 31,  
    2009     2010  
    (per barrel)  
Natural Gasoline
  $ 55.60     $ 63.20  
Condensate
  $ 62.27     $ 70.72  
Propane
  $ 35.56     $ 40.63  
Butane
  $ 42.24     $ 48.15  
 
  (per MMBtu)  
Natural Gas
  $ 4.85     $ 5.61  
Credit facilities
In March 2008, Anadarko entered into a five-year $1.3 billion credit facility under which the Partnership may borrow up to $100.0 million. Concurrent with the closing of the initial public offering, the Partnership entered into a two-year $30.0 million working capital facility with Anadarko as the lender. See Note 10—Debt for more information on these credit facilities and Note 14—Subsequent Events concerning the revolving Credit Facility the Partnership entered into in October 2009.
Omnibus agreement
Concurrent with the closing of the initial public offering, the Partnership entered into an omnibus agreement with the general partner and Anadarko that addresses the following:
    Anadarko’s obligation to indemnify the Partnership for certain liabilities and the Partnership’s obligation to indemnify Anadarko for certain liabilities with respect to the initial assets;
 
    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;
 
    the Partnership’s obligation to reimburse Anadarko for all insurance coverage expenses it incurs or payments it makes with respect to the Partnership Assets; and
 
    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 administration. As of September 30, 2009, the Partnership’s reimbursement to Anadarko for certain general and administrative expenses allocated to the Partnership was capped at $6.9 million annually through December 31, 2009, subject to adjustment to reflect expansions of the Partnership’s operations through the acquisition or construction of new assets or businesses and with the concurrence of the special committee of the Partnership’s general partner’s board of directors. 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. The consolidated financial statements of the Partnership include costs allocated by Anadarko pursuant to the omnibus agreement for periods including and subsequent to May 14, 2008.

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Notes to unaudited consolidated financial statements of Western Gas Partners, LP
Services and secondment agreement
Concurrent with the closing of the initial public 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 reimburses 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. The consolidated financial statements of the Partnership include costs allocated by Anadarko pursuant to the services and secondment agreement for periods including and subsequent to the Partnership’s acquisition of the Partnership Assets.
Chipeta gas processing agreement
Chipeta is party to a gas processing agreement with a subsidiary of Anadarko dated September 6, 2008, pursuant to which Chipeta processes natural gas delivered by that subsidiary and the subsidiary takes allocated residue and NGLs in-kind. That agreement, pursuant to which the Chipeta plant receives a large majority of its throughput, has a primary term that extends through 2023.
Tax sharing agreement
Concurrent with the closing of the initial public offering, the Partnership and Anadarko entered into a tax sharing agreement pursuant to which the Partnership reimburses 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 Partnership’s acquisition of the Partnership Assets. 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 Partnership 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, regardless of whether Anadarko pays taxes for the period.
Allocation of costs
Prior to the Partnership’s acquisition of the Partnership Assets, the consolidated financial statements of the Partnership include costs allocated by Anadarko in the form of a management services fee, which approximated the general and administrative costs attributable to the Partnership Assets. This management services fee was allocated to the Partnership based on its proportionate share of Anadarko’s assets and revenues or other contractual arrangements. Management believes these allocation methodologies are reasonable.
The employees supporting the Partnership’s operations are employees of Anadarko. Anadarko charges the Partnership its allocated share of personnel costs, including costs associated with Anadarko’s equity-based compensation plans, non-contributory defined pension and postretirement plans and defined contribution savings plan, through the management services fee or pursuant to the omnibus agreement and services and secondment agreement described above.
Equity-based compensation
Grants made under equity-based compensation plans result in equity-based compensation expense which is determined by reference to the fair value of equity compensation as of the date of the relevant equity grant.
Long-term incentive plan
The general partner awarded phantom units primarily to the general partner’s independent directors under the LTIP in May 2008 and May 2009. The phantom units awarded to the independent directors vest one year from the grant date. The following table summarizes information regarding phantom units under the LTIP for the nine months ended September 30, 2009:

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Notes to unaudited consolidated financial statements of Western Gas Partners, LP
                 
    Value per      
    Unit     Units  
 
Units outstanding at beginning of period
  $ 16.50       30,304  
Vested
  $ 16.50       (30,304 )
Granted
  $ 15.02       21,970  
 
             
Units outstanding at end of period
  $ 15.02       21,970  
 
             
Compensation expense attributable to the phantom units granted under the LTIP is recognized entirely by the Partnership over the vesting period and was approximately $75,000 and $0.3 million during the three and nine months ended September 30, 2009, respectively, and was approximately $0.1 million and $0.2 million during the three and nine months ended September 30, 2008, respectively.
Equity incentive plan and Anadarko incentive plans
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 Amended and Restated Equity Incentive Plan (the “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”). Under the Incentive Plan, participants are granted Unit Value Rights (“UVRs”), Unit Appreciation Rights (“UARs”) and Dividend Equivalent Rights (“DERs”). The following table summarizes information regarding UVRs, UARs and DERs issued under the Incentive Plan for the nine months ended September 30, 2009:
         
    Units  
 
Units outstanding at beginning of period
    50,000  
Granted
    10,000  
Vested
    (16,667 )
Forfeited
    (6,666 )
 
     
Units outstanding at end of period
    36,667  
 
     
Weighted average grant date fair value per UVR
  $ 50.00  
The Partnership’s general and administrative expense for the three and nine months ended September 30, 2009 included approximately $0.9 million and $2.7 million, respectively, of equity-based compensation expense for grants made pursuant to the Incentive Plan and Anadarko Incentive Plans. The Partnership’s general and administrative expense for the three and nine months ended September 30, 2008 included approximately $0.5 million and $0.8 million, respectively, of equity-based compensation expense for grants made pursuant to the Incentive Plan and Anadarko Incentive Plans. A portion of 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 other employees pursuant to the omnibus agreement and employees who provide services to the Partnership pursuant to the services and secondment agreement. These amounts exclude compensation expense associated with the LTIP.
Summary of affiliate transactions
Operating expenses include all amounts accrued or paid to affiliates for the operation of the Partnership’s systems, whether in providing services to affiliates or to third parties, including field labor, measurement and analysis, and other disbursements. Affiliate expenses do not bear a direct relationship to affiliate revenues and third-party expenses do not bear a direct

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Notes to unaudited consolidated financial statements of Western Gas Partners, LP
relationship to third-party revenues. For example, the Partnership’s affiliate expenses are not necessarily those expenses attributable to generating affiliate revenues. The following table summarizes affiliate transactions.
                                 
    Three Months Ended   Nine Months Ended
    September 30,   September 30,
    2009   2008   2009   2008
            (in thousands)        
Revenues — affiliates
  $ 54,718     $ 82,352     $ 163,901     $ 246,883  
Operating expenses — affiliates
    10,034       16,687       29,951       45,828  
Interest income — affiliates
    4,225       4,697       12,675       6,478  
Interest expense, net — affiliates
    3,127       36       6,698       1,546  
Distributions to unitholders — affiliates
    11,257       5,275       32,829       5,275  
Contributions from noncontrolling interest owners — affiliate and Parent
    13,163       14,455       32,419       14,455  
Distributions to noncontrolling interest owners — affiliate and Parent
                4,303       19,734  
7. INCOME TAXES
The following table summarizes the Partnership’s effective tax rate:
                                 
    Three Months Ended   Nine Months Ended
    September 30,   September 30,
    2009   2008   2009   2008
    (in thousands, except effective tax rate)
Income before income taxes
  $ 19,406     $ 19,760     $ 65,654     $ 69,137  
Income tax expense (benefit)
  $ 171     $ (1,463 )   $ (152 )   $ 11,289  
Effective tax rate
    1 %     (7 )%     (0 )%     16 %
Income earned by the Partnership, a non-taxable entity for U.S. federal income tax purposes, for the three and nine months ended September 30, 2009 was subject only to Texas margin tax while income earned by the Partnership and attributable to the initial assets prior to May 14, 2008 and to the Powder River assets for the three and nine months ended September 30, 2008, was subject to federal and state income tax. Income attributable to the Chipeta assets was subject to federal and state income tax for periods prior to June 1, 2008, at which time substantially all of the Chipeta assets were contributed to a non-taxable entity for U.S. federal income tax purposes. For 2008 and 2009, the Partnership’s variance from the federal statutory rate is primarily attributable to the Partnership’s status as a non-taxable entity beginning on May 14, 2008, partially offset by state income tax expense.
The increase in income tax expense for the three months ended September 30, 2009 is primarily due to a net income tax benefit resulting from the impairment loss recorded on an asset at the Hilight system during the three months ended September 30, 2008, partially offset by Texas margin tax expense attributable to the initial assets and federal income tax attributable to the Newcastle system. For the nine months ended September 30, 2009, income tax expense decreased primarily due to a change in the applicability of U.S. federal income tax to the Partnership’s income that occurred in connection with its initial public offering. In addition, for the nine months ended September 30, 2009, the Partnership’s estimated income attributed to Texas relative to the Partnership’s total income decreased as compared to the prior year, which resulted in a $0.5 million reduction of previously recognized deferred taxes.

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Notes to unaudited consolidated financial statements of Western Gas Partners, LP
8. CONCENTRATION OF CREDIT RISK
Anadarko was the only customer from whom revenues exceeded 10% of the Partnership’s consolidated revenues for the three and nine months ended September 30, 2009 and 2008. The percentage of revenues from Anadarko and the Partnership’s other customers are as follows:
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
Customer   2009     2008     2009     2008  
 
Anadarko
    87 %     85 %     87 %     87 %
Other
    13 %     15 %     13 %     13 %
 
                       
Total
    100 %     100 %     100 %     100 %
 
                       
9. 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, 2009     December 31, 2008  
            (dollars in thousands)  
Land
    n/a     $ 354     $ 354  
Gathering systems
    15 to 25 years       804,952       697,908  
Pipeline and equipment
    30 to 34.5 years       86,520       85,598  
Assets under construction
    n/a       7,827       76,275  
Other
    3 to 25 years       1,687       1,645  
 
                   
Total property, plant and equipment
            901,340       861,780  
Accumulated depreciation
            204,683       175,427  
 
                   
Total net property, plant and equipment
          $ 696,657     $ 686,353  
 
                   
The cost of property classified as “Assets under construction” is excluded from capitalized costs being depreciated. This amount represents property that is not yet suitable to be placed into productive service as of the balance sheet date.
Impairment
Prior to the Partnership’s acquisition of the Powder River assets, during the three and nine months ended September 30, 2008, a $9.4 million impairment was recognized related to the shut-in of a unit that produced iso-butane from NGLs at the Hilight system. Anadarko’s management determined the fair value of the asset based on estimates of significant unobservable inputs (level three in the GAAP fair value hierarchy), including current market values of similar equipment components.
10. DEBT
The following table presents the Partnership’s outstanding debt as of September 30, 2009 and December 31, 2008.
                                                 
    September 30, 2009   December 31, 2008
            Carrying     Interest           Carrying     Interest
    Principal     Value     Rate   Principal     Value     Rate
            (in thousands, except percentages)                
Note payable to Anadarko due 2012
  $ 101,451     $ 101,451       7.00 %   $     $        
Note payable to Anadarko due 2013
    175,000       175,000       4.00 %     175,000       175,000       4.00 %
 
                                     
Total debt
  $ 276,451     $ 276,451       5.10 %   $ 175,000     $ 175,000       4.00 %
 
                                   
In March 2008, Anadarko entered into a five-year $1.3 billion credit facility under which the Partnership may utilize up to $100.0 million to the extent that sufficient amounts remain available to Anadarko. As of September 30, 2009, the full $100.0 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

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Notes to unaudited consolidated financial statements of Western Gas Partners, LP
September 30, 2009, 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 (as of September 30, 2009, 0.11% of the Partnership’s committed and available borrowing capacity, including the Partnership’s outstanding balances, if any) that Anadarko incurs under its credit facility, or up to $0.1 million annually. Under Anadarko’s credit facilities, 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 60% or less. As of September 30, 2009, Anadarko and the Partnership were in compliance with all covenants. Should the Partnership or Anadarko fail to comply with any covenant in Anadarko’s credit facilities, the Partnership may not be permitted to borrow under the credit facility. Anadarko is a guarantor of the Partnership’s borrowings, if any, under the credit facility. The Partnership is not a guarantor of Anadarko’s borrowings under the credit facility. The $1.3 billion credit facility expires in March 2013.
In May 2008, the Partnership entered into a two-year $30.0 million working capital facility with Anadarko as the lender. At September 30, 2009, no borrowings were outstanding under the working capital facility. The facility is available exclusively to fund working capital needs. Borrowings under the facility will bear interest at the same rate that would apply to borrowings under the Anadarko credit facility described above. Pursuant to the omnibus agreement, the Partnership pays 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 2008, the Partnership entered into a five-year $175.0 million term loan agreement with Anadarko in order to finance the cash portion of the consideration paid for the Powder River acquisition. The interest rate is fixed at 4.00% for the first two years and is a floating rate equal to three-month LIBOR plus 150 basis points for the final three years. The Partnership has the option to repay the outstanding principal amount in whole or in part commencing upon the second anniversary of the five-year term loan agreement.
In July 2009, the Partnership entered into a $101.5 million, 7.00% fixed-rate, three-year term loan agreement with Anadarko in order to finance the cash portion of the consideration paid for the Chipeta acquisition. The Partnership had the option to repay the outstanding principal amount in whole or in part upon five business days’ written notice. See also Note 14—Subsequent Events regarding the Partnership’s $350.0 million revolving Credit Facility and refinancing of the three-year term loan in October 2009.
The provisions of the five-year and three-year term loan agreements discussed above are non-recourse to the Partnership’s general partner and limited partners and contain customary events of default, including (i) nonpayment of principal when due or nonpayment of interest or other amounts within three business days of when due; (ii) certain events of bankruptcy or insolvency with respect to the Partnership; or (iii) a change of control. At September 30, 2009, the Partnership was in compliance with all covenants under the five-year term loan agreement and three-year term loan agreement. The fair value of the Partnership’s debt under both the five-year and three-year term loan agreements approximate the carrying value of those instruments at September 30, 2009 and December 31, 2008. The fair value of debt reflects any premium or discount for the difference between the stated interest rate and quarter-end market rate.
11. SEGMENT INFORMATION
The Partnership’s operations are organized into a single business segment, the assets of which consist of natural gas gathering and processing systems, treating facilities, pipelines and related plants and equipment. To assess the operating results of the Partnership’s segment, management uses Adjusted EBITDA, which it defines as net income (loss) attributable to Western Gas Partners, LP, plus distributions from equity investee, non-cash equity-based compensation expense, interest expense, income tax expense, depreciation and amortization, less income from equity investee, interest income, income tax benefit and other income (expense). The Partnership changed its definition of Adjusted EBITDA from the definition used in the prior year. Adjusted EBITDA has been calculated using the revised definition for all periods presented.
Adjusted EBITDA is a supplemental financial measure that management and external users of the Partnership’s consolidated financial statements, such as industry analysts, investors, commercial banks and rating agencies, use to assess, among other measures:

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Notes to unaudited consolidated financial statements of Western Gas Partners, LP
    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;
 
    the ability of the Partnership’s assets to generate cash flow to make distributions; and
 
    the viability of acquisitions and capital expenditure projects and the returns on investment of various investment opportunities.
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.
Below is a reconciliation of Adjusted EBITDA to net income attributable to Western Gas Partners, LP.
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
            (in thousands)          
Reconciliation of adjusted EBITDA to net income attributable to Western Gas Partners, LP
                               
Adjusted EBITDA
  $ 26,404     $ 30,488     $ 81,542     $ 93,633  
Less:
                               
Distributions from equity investee
    1,555       1,422       4,125       3,673  
Non-cash equity-based compensation expense
    948       524       2,736       785  
Interest expense, net — affiliates
    3,127       36       6,698       1,546  
Income tax expense
    171                   11,289  
Depreciation and amortization (1)
    9,586       9,012       28,101       25,775  
Impairment
          9,354             9,354  
Add:
                               
Equity income, net
    1,794       1,539       5,329       3,840  
Interest income from note — affiliate
    4,225       4,697       12,675       6,478  
Other income, net (1)
    12       110       27       142  
Income tax benefit
          1,463       152        
 
                       
 
                               
Net income attributable to Western Gas Partners, LP
  $ 17,048     $ 17,949     $ 58,065     $ 51,671  
 
                       
 
(1)   Depreciation and amortization expense and other income, net for purposes of reconciling Adjusted EBITDA to net income attributable to Western Gas Partners, LP, includes 51% of the respective amounts attributable to Chipeta Processing LLC.
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 could have a material adverse effect on the Partnership’s results of operations, cash flows or financial position.

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Notes to unaudited consolidated financial statements of Western Gas Partners, LP
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.
Plant purchase commitment
In November 2008, Chipeta entered into a Purchase and Sale Agreement (the “Purchase Agreement”) with a third party to purchase a compressor station and processing plant (the “Natural Buttes plant”) located in Uintah County, Utah for $9.0 million, subject to customary closing adjustments. One of the noncontrolling interest owners contributed $2.2 million to Chipeta during the three months ended September 30, 2009 to fund its proportionate share of the Natural Buttes plant acquisition. The Natural Buttes plant is expected to provide up to 150 MMcf/d of incremental refrigeration processing capacity and 5.2 miles of 20-inch pipeline. If the transaction does not close by December 31, 2009, Chipeta, at its sole discretion, may terminate the Purchase Agreement.
Lease commitments
Anadarko, on behalf of the Partnership, formerly leased compression equipment used exclusively by the Partnership. As a result of lease modifications in October 2008, Anadarko became the owner of the compression equipment and contributed the equipment to the Partnership, effectively terminating the lease. Rent expense associated with the compression equipment was approximately $0.3 million and $0.9 million for the three and nine months ended September 30, 2008, respectively. As of September 30, 2009, the Partnership does not have significant non-cancelable lease commitments.
13. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS
The Partnership filed a shelf registration statement on Form S-3 with the SEC, which became effective in August 2009, under which the Partnership may issue and sell up to $1.25 billion of debt and equity securities. Debt securities issued under the shelf may be guaranteed by one or more existing or future subsidiaries of the Partnership (the “Guarantor Subsidiaries”), each of which is a wholly owned subsidiary of the Partnership. The guarantees, if issued, would be full, unconditional, joint and several. The following condensed consolidating financial information reflects the Partnership’s stand-alone accounts, the combined accounts of the Guarantor Subsidiaries, the accounts of the Non-Guarantor Subsidiary, consolidating adjustments and eliminations, and the Partnership’s consolidated accounts for the three and nine months ended September 30, 2009, for the three and nine months ended September 30, 2008 and as of September 30, 2009 and December 31, 2008. The condensed consolidating financial information should be read in conjunction with the Partnership’s accompanying unaudited consolidated financial statements and related notes.

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Notes to unaudited consolidated financial statements of Western Gas Partners, LP
Western Gas Partners, LP’s and the Guarantor Subsidiaries’ investment in and equity income from their consolidated subsidiaries is presented in accordance with the equity method of accounting in which the equity income from consolidated subsidiaries includes the results of operations of the Partnership Assets for periods including and subsequent to the Partnership’s acquisition of the Partnership Assets.
                                         
    Three Months Ended September 30, 2009  
    Western Gas     Guarantor     Non-Guarantor              
Statement of Income   Partners, LP     Subsidiaries     Subsidiary     Eliminations     Consolidated  
    (in thousands)  
Revenues
  $ 1,538     $ 48,830     $ 10,628     $     $ 60,996  
Operating expenses
    5,557       30,978       6,166             42,701  
 
                             
Operating income (loss)
  $ (4,019 )   $ 17,852     $ 4,462     $     $ 18,295  
Interest income, net — affiliates
    1,093       5                   1,098  
Other income, net
    10             3             13  
Equity income from consolidated subsidiaries
    19,963       2,276             (22,239 )      
 
                             
Income before income taxes
  $ 17,047     $ 20,133     $ 4,465     $ (22,239 )   $ 19,406  
Income tax expense
          171                   171  
 
                             
Net income
  $ 17,047     $ 19,962     $ 4,465     $ (22,239 )   $ 19,235  
 
                             
Net income attributable to noncontrolling interests
          2,187                   2,187  
 
                             
Net income attributable to Western Gas Partners, LP
  $ 17,047     $ 17,775     $ 4,465     $ (22,239 )   $ 17,048  
 
                             
                                         
    Three Months Ended September 30, 2008  
    Western Gas     Guarantor     Non-Guarantor              
Statement of Income   Partners, LP     Subsidiaries     Subsidiary     Eliminations     Consolidated  
    (in thousands)  
Revenues
  $     $ 82,341     $ 12,241     $     $ 94,582  
Operating expenses
    3,003       71,012       5,594             79,609  
 
                             
Operating income (loss)
  $ (3,003 )   $ 11,329     $ 6,647     $     $ 14,973  
Interest income, net — affiliates
    4,204       457                   4,661  
Other income, net
    93             33             126  
Equity income from consolidated subsidiaries
    16,457                   (16,457 )      
 
                             
Income before income taxes
  $ 17,751     $ 11,786     $ 6,680     $ (16,457 )   $ 19,760  
Income tax benefit
          (1,463 )                 (1,463 )
 
                             
Net income
  $ 17,751     $ 13,249     $ 6,680     $ (16,457 )   $ 21,223  
 
                             
Net income attributable to noncontrolling interests
          3,274                   3,274  
 
                             
Net income attributable to Western Gas Partners, LP
  $ 17,751     $ 9,975     $ 6,680     $ (16,457 )   $ 17,949  
 
                             

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Notes to unaudited consolidated financial statements of Western Gas Partners, LP
                                         
    Nine Months Ended September 30, 2009  
    Western Gas     Guarantor     Non-Guarantor              
Statement of Income   Partners, LP     Subsidiaries     Subsidiary     Eliminations     Consolidated  
    (in thousands)  
Revenues
  $ 5,605     $ 146,197     $ 30,859     $     $ 182,661  
Operating expenses
    13,422       94,521       15,070             123,013  
 
                             
Operating income (loss)
  $ (7,817 )   $ 51,676     $ 15,789     $     $ 59,648  
Interest income, net — affiliates
    5,966       11                   5,977  
Other income, net
    23             6             29  
Equity income from consolidated subsidiaries
    53,957       2,276             (56,233 )      
 
                             
Income before income taxes
  $ 52,129     $ 53,963     $ 15,795     $ (56,233 )   $ 65,654  
Income tax benefit
          (152 )                 (152 )
 
                             
Net income
  $ 52,129     $ 54,115     $ 15,795     $ (56,233 )   $ 65,806  
 
                             
Net income attributable to noncontrolling interests
          7,741                   7,741  
 
                             
Net income attributable to Western Gas Partners, LP
  $ 52,129     $ 46,374     $ 15,795     $ (56,233 )   $ 58,065  
 
                             
                                         
    Nine Months Ended September 30, 2008
    Western Gas     Guarantor     Non-Guarantor              
Statement of Income   Partners, LP     Subsidiaries     Subsidiary     Eliminations     Consolidated  
    (in thousands)  
Revenues
  $     $ 254,371     $ 24,709     $     $ 279,080  
Operating expenses
    4,398       198,614       12,022             215,034  
 
                             
Operating income (loss)
  $ (4,398 )   $ 55,757     $ 12,687     $     $ 64,046  
Interest income, net — affiliates
    6,391       (1,459 )                 4,932  
Other income, net
    120       5       34             159  
Equity income from consolidated subsidiaries
    23,888                   (23,888 )      
 
                             
Income before income taxes
  $ 26,001     $ 54,303     $ 12,721     $ (23,888 )   $ 69,137  
Income tax expense
          11,172       117             11,289  
 
                             
Net income
  $ 26,001     $ 43,131     $ 12,604     $ (23,888 )   $ 57,848  
 
                             
Net income attributable to noncontrolling interests
          6,177                   6,177  
 
                             
Net income attributable to Western Gas Partners, LP
  $ 26,001     $ 36,954     $ 12,604     $ (23,888 )   $ 51,671  
 
                             

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Notes to unaudited consolidated financial statements of Western Gas Partners, LP
                                         
    As of September 30, 2009
    Western Gas     Guarantor     Non-Guarantor              
Balance Sheet   Partners, LP     Subsidiaries     Subsidiary     Eliminations     Consolidated  
    (in thousands)  
Current assets
  $ 43,079     $ 29,511     $ 15,293     $ (25,548 )   $ 62,335  
Note receivable — Anadarko
    260,000                         260,000  
Investment in consolidated subsidiaries
    481,969       102,655             (584,624 )      
Net property, plant and equipment
    233       520,962       175,462             696,657  
Other long-term assets
    410       40,487                   40,897  
 
                             
Total assets
  $ 785,691     $ 693,615     $ 190,755     $ (610,172 )   $ 1,059,889  
 
                             
Current liabilities
  $ 26,150     $ 16,889     $ 4,047     $ (25,548 )   $ 21,538  
Notes payable — Anadarko
    276,451                         276,451  
Other long-term liabilities
          9,610       1,563             11,173  
 
                             
Total liabilities
  $ 302,601     $ 26,499     $ 5,610     $ (25,548 )   $ 309,162  
Partners’ capital
  $ 483,090     $ 580,661     $ 185,145     $ (584,624 )   $ 664,272  
Noncontrolling interests
          86,455                   86,455  
 
                             
Total liabilities, equity and Partners’ capital
  $ 785,691     $ 693,615     $ 190,755     $ (610,172 )   $ 1,059,889  
 
                             
                                         
    As of December 31, 2008  
    Western Gas     Guarantor     Non-Guarantor              
Balance Sheet   Partners, LP     Subsidiaries     Subsidiary     Eliminations     Consolidated  
    (in thousands)  
Current assets
  $ 33,774     $ 49,207     $ 2,999     $ (38,825 )   $ 47,155  
Note receivable — Anadarko
    260,000                         260,000  
Investment in consolidated subsidiaries
    458,256                   (458,256 )      
Net property, plant and equipment
    273       527,790       158,290             686,353  
Other long-term assets
    628       39,019                   39,647  
 
                             
Total assets
  $ 752,931     $ 616,016     $ 161,289     $ (497,081 )   $ 1,033,155  
 
                             
Current liabilities
  $ 51,656     $ 16,003     $ 26,094     $ (51,318 )   $ 42,435  
Note payable — Anadarko
    175,000                         175,000  
Other long-term liabilities
          10,240       855             11,095  
 
                             
Total liabilities
  $ 226,656     $ 26,243     $ 26,949     $ (51,318 )   $ 228,530  
Partners’ capital and parent net investment
  $ 526,275     $ 523,757     $ 134,340     $ (445,763 )   $ 738,609  
Noncontrolling interests
          66,016                   66,016  
 
                             
Total liabilities, equity and Partners’ capital
  $ 752,931     $ 616,016     $ 161,289     $ (497,081 )   $ 1,033,155  
 
                             

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Notes to unaudited consolidated financial statements of Western Gas Partners, LP
                                         
    Nine Months Ended September 30, 2009  
    Western Gas             Non-              
    Partners,     Guarantor     Guarantor              
Statement of Cash Flows   LP     Subsidiaries     Subsidiary     Eliminations     Consolidated  
    (in thousands)  
Cash flows from operating activities
                                       
Net income
  $ 52,129     $ 54,115     $ 15,795     $ (56,233 )   $ 65,806  
Adjustments to reconcile net income to net cash provided by operating activities:
                                       
Equity income from consolidated subsidiaries
    (53,957 )     (2,276 )           56,233        
Depreciation, amortization and impairment
    41       26,457       3,144             29,642  
Deferred income taxes
          (336 )                 (336 )
Change in other items, net
    (25,849 )     17,624       (19,728 )     12,492       (15,461 )
 
                             
Net cash provided by (used in) operating activities
  $ (27,636 )   $ 95,584     $ (789 )   $ 12,492     $ 79,651  
 
                             
Cash flows from investing activities
                                       
Chipeta acquisition
  $     $ (101,451 )   $     $     $ (101,451 )
Capital expenditures
          (18,779 )     (22,721 )           (41,500 )
Investment in consolidated subsidiaries and equity affiliate
          (264 )                 (264 )
 
                             
Net cash used in investing activities
  $     $ (120,494 )   $ (22,721 )   $     $ (143,215 )
 
                             
Cash flows from financing activities
                                       
Issuance of note payable to Anadarko
  $ 101,451     $     $     $     $ 101,451  
Contributions from noncontrolling interest owners and Parent
          40,745                   40,745  
Distributions to unitholders
    (51,777 )                       (51,777 )
Distributions to noncontrolling interest owners and Parent
          (5,737 )                 (5,737 )
Net (distributions to) contributions from Parent
    (13,586 )     (10,098 )     35,007       (12,492 )     (1,169 )
 
                             
Net cash provided by (used in) financing activities
  $ 36,088     $ 24,910     $ 35,007     $ (12,492 )   $ 83,513  
 
                             
Net increase in cash and cash equivalents
  $ 8,452     $     $ 11,497     $     $ 19,949  
Cash and cash equivalents at beginning of period
    33,306             2,768             36,074  
 
                             
Cash and cash equivalents at end of period
  $ 41,758     $     $ 14,265     $     $ 56,023  
 
                             

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Notes to unaudited consolidated financial statements of Western Gas Partners, LP
                                         
    Nine Months Ended September 30, 2008  
    Western Gas             Non-              
    Partners,     Guarantor     Guarantor              
Statement of Cash Flows   LP     Subsidiaries     Subsidiary     Eliminations     Consolidated  
    (in thousands)  
Cash flows from operating activities
                                       
Net income
  $ 26,001     $ 43,131     $ 12,604     $ (23,888 )   $ 57,848  
Adjustments to reconcile net income to net cash provided by operating activities:
                                       
Equity income from consolidated subsidiaries
    (23,888 )                 23,888        
Depreciation, amortization and impairment
    25       33,946       2,273             36,244  
Deferred income taxes
          2,316       117             2,433  
Change in other items, net
    27,535       (24,833 )     17,981       (12,493 )     8,190  
 
                             
Net cash provided by operating activities
  $ 29,673     $ 54,560     $ 32,975     $ (12,493 )   $ 104,715  
 
                             
Cash flows from investing activities
                                       
Loan to Anadarko
  $ (260,000 )   $     $     $     $ (260,000 )
Capital expenditures
    (312 )     (33,177 )     (35,441 )           (68,930 )
Investment in consolidated subsidiaries and equity affiliate
          (8,095 )                 (8,095 )
 
                             
Net cash used in investing activities
  $ (260,312 )   $ (41,272 )   $ (35,441 )   $     $ (337,025 )
 
                             
Cash flows from financing activities
                                       
Proceeds from issuance of common units
  $ 315,161     $     $     $     $ 315,161  
Reimbursement to Parent from offering proceeds
    (45,161 )                       (45,161 )
Contributions from noncontrolling interest owners and Parent
          148,356                   148,356  
Distributions to unitholders
    (8,567 )                       (8,567 )
Distributions to noncontrolling interest owners and Parent
          (19,734 )                 (19,734 )
Net (distribution to) contribution from Parent
    (4,404 )     (141,910 )     27,466       12,493       (106,355 )
 
                             
Net cash provided by (used in) financing activities
  $ 257,029     $ (13,288 )   $ 27,466     $ 12,493     $ 283,700  
 
                             
Net increase in cash and cash equivalents
  $ 26,390     $     $ 25,000     $     $ 51,390  
Cash and cash equivalents at beginning of period
                             
 
                             
Cash and cash equivalents at end of period
  $ 26,390     $     $ 25,000     $     $ 51,390  
 
                             
14. SUBSEQUENT EVENTS
Cash distribution
On October 20, 2009, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.32 per unit, or $18.3 million in the aggregate. The cash distribution is payable on November 13, 2009 to unitholders of record at the close of business on October 30, 2009.
Revolving credit facility
On October 29, 2009, the Partnership entered into a three-year senior unsecured revolving credit facility with a group of banks (the “Credit Facility”). The aggregate initial commitments of the lenders under the Credit Facility are $350.0 million and are expandable to a maximum of $450.0 million. The Credit Facility matures on October 29, 2012 and bears interest at LIBOR, plus applicable margins ranging from 2.375% to 3.250%, or an alternate base rate, based upon (i) the greater of the Prime Rate, the Federal Funds Rate plus 0.50%, and LIBOR plus 0.50% plus (ii) applicable margins ranging from 1.375% to 2.250%.

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Notes to unaudited consolidated financial statements of Western Gas Partners, LP
The Credit Facility contains various covenants that limit, among other things, the Partnership’s, and certain of the Partnership’s subsidiaries’, ability to incur indebtedness, grant certain liens, merge, consolidate or allow any material change in the character of its business, sell all or substantially all of the Partnership’s assets, make certain transfers, enter into certain affiliate transactions, make distributions or other payments other than distributions of available cash under certain conditions and use proceeds other than for partnership purposes. If the Partnership obtains two of the following three ratings: BBB- or better by Standard and Poor’s, Baa3 or better by Moody’s Investors Service or BBB- or better by Fitch Ratings Ltd. (the date of such rating being the “Investment Grade Rating Date”), the Partnership will no longer be required to comply with certain of the foregoing covenants. The Credit Facility also contains customary events of default, including (i) nonpayment of principal when due or nonpayment of interest or other amounts within three business days of when due; (ii) bankruptcy or insolvency with respect to the Borrower or any material subsidiary; or (iii) a change of control. All amounts due by the Partnership under the Credit Facility are unconditionally guaranteed by the Partnership’s wholly owned subsidiaries. The subsidiary guarantees will terminate on the Investment Grade Rating Date.
On October 30, 2009, the Partnership used $100.0 million of its capacity under the Credit Facility along with $2.0 million of cash on hand to refinance its $101.5 million, 7.00% fixed-rate, three-year term loan agreement entered into with Anadarko in July 2009 to finance a portion of the Chipeta acquisition, and to settle accrued interest related thereto.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion analyzes our financial condition and results of operations and should be read in conjunction with the consolidated financial statements and the notes to unaudited consolidated financial statements, which are included in this report under Part I, Item 1 of this Form 10-Q, as well as our historical consolidated financial statements, and the notes thereto, included in Item 8 of our annual report on Form 10-K. Unless the context clearly indicates otherwise, references in this report to the “Partnership,” “we,” “our,” “us” or like terms refer to Western Gas Partners, LP and its subsidiaries. “Anadarko” refers to Anadarko Petroleum Corporation (NYSE: APC) and its consolidated subsidiaries, excluding the Partnership and “Parent” refers to Anadarko prior to our acquisition of assets from Anadarko. “Affiliates” refers to wholly owned and partially owned subsidiaries of Anadarko, excluding the Partnership.
We have made in this report, and may from time to time otherwise make in other public filings, press releases and discussions by Partnership management, 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. 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 risks and uncertainties. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:
    our assumptions about energy markets;
    future gathering, treating and processing volumes and pipeline throughput, including Anadarko’s production, which is gathered by or transported through our assets;
    operating results;
    competitive conditions;
    technology;
    the availability of capital resources for capital expenditures and other contractual obligations;
    the supply of, 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, or FERC, and liability under federal and state environmental laws and regulations;
    our ability to access the capital markets;
    our ability to access credit, including under Anadarko’s $1.3 billion credit facility and the $350.0 million Credit Facility we entered into in October 2009;
    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, processing and transportation agreements and our $260.0 million note receivable from Anadarko; and

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    other factors discussed below and elsewhere in Item 1A—Risk Factors and in Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates included in our annual report on Form 10-K filed with the Securities and Exchange Commission, or SEC, on March 13, 2009, this Form 10-Q 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. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
EXECUTIVE SUMMARY
We are a growth-oriented limited partnership organized by Anadarko to own, operate, acquire and develop midstream energy assets. We currently operate in East and West Texas, the Rocky Mountains (Utah and Wyoming) and the Mid-Continent (Kansas and Oklahoma) and are engaged in the business of gathering, compressing, treating, processing and transporting natural gas for Anadarko and third-party producers and customers.
Significant operational and financial highlights during the third quarter of 2009 include:
    The completion of our acquisition of a 51% membership interest in Chipeta Processing LLC, or Chipeta, and related midstream assets from Anadarko. The Chipeta plant had gross average daily natural gas liquids (“NGLs”) recoveries of approximately 14,000 barrels per day.
    Our stable operating cash flow, combined with a focus on cost reduction and capital spending discipline, enabled us to raise our distribution to $0.32 per unit, representing a 3.2% increase over the distribution for the second quarter of 2009.
    Third-quarter throughput attributable to Western Gas Partners, LP totaled approximately 1,209 MMcf/d, representing an approximate 8% decrease compared to the third quarter of 2008. The current commodity price environment, particularly for natural gas, has resulted in lower drilling activity throughout the areas in which we operate, which limits our ability to connect wells to our systems which offset lower throughput from natural production declines. The throughput decrease for the three months ended September 30, 2009 is primarily due to decreases at the Pinnacle, Dew, Haley and Hugoton systems, mainly from natural production declines, partially offset by affiliate-throughput increases at the Chipeta plant and Fort Union system due to facility expansions.
    Third-quarter gross margin attributable to Western Gas Partners, LP averaged approximately $0.40 per Mcf, representing an approximate 2% decrease compared to the third quarter of 2008. The decrease in gross margin is primarily due to throughput at the Chipeta plant, which generates a lower margin per Mcf than our other core assets, and to lower drip condensate margins. The predominantly fee-based and fixed-price structure of our contracts mitigated the impact of changes in commodity prices on our gross margin.
INITIAL PUBLIC OFFERING
On May 14, 2008, we closed our initial public offering of 18,750,000 common units at a price of $16.50 per unit. On June 11, 2008, we issued an additional 2,060,875 common units to the public pursuant to the partial exercise of the underwriters’ over-allotment option granted in connection with our “initial public offering.” Concurrent with the closing of our initial public offering, Anadarko contributed the assets and liabilities of Anadarko Gathering Company LLC, or AGC, Pinnacle Gas Treating LLC, or PGT, and MIGC LLC, or MIGC, to us in exchange for a 2.0% general partner interest in the Partnership, 5,725,431 common units, 26,536,306 subordinated units and 100% of the incentive distribution rights, or IDRs. We refer to AGC, PGT and MIGC as our “initial assets.”
POWDER RIVER ACQUISITION
In December 2008, we acquired certain midstream assets from Anadarko, consisting of (i) a 100% ownership interest in the Hilight system, (ii) a 50% interest in the Newcastle system and (iii) a 14.81% limited liability company membership interest in Fort Union Gas Gathering, L.L.C., or Fort Union. We refer to these assets collectively as the “Powder River assets” and to the acquisition as the “Powder River acquisition.” The Powder River assets provide a combination of gathering, treating and processing services in the Powder River Basin of Wyoming.

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CHIPETA ACQUISITION
In July 2009, we acquired certain midstream assets from Anadarko for (i) approximately $101.5 million cash, which was financed by borrowing $101.5 million from Anadarko pursuant to the terms of a 7.00% fixed-rate, three-year term loan agreement, and (ii) the issuance of 351,424 common units and 7,172 general partner units. These assets provide processing and transportation services in the Greater Natural Buttes area in Uintah County, Utah. The acquisition is comprised of a 51% membership interest in Chipeta and associated midstream assets. Chipeta owns a natural gas processing plant complex, which includes two recently completed processing trains: a refrigeration unit completed in November 2007 with a design capacity of 240 MMcf/d and a 250 MMcf/d capacity cryogenic unit which was commissioned in April 2009. The 51% membership interest in Chipeta and associated midstream assets are referred to collectively as the “Chipeta assets” and the acquisition is referred to as the “Chipeta acquisition.”
PRESENTATION OF PARTNERSHIP ACQUISITIONS
The initial assets, Powder River assets and Chipeta assets are referred to collectively as the “Partnership Assets.” References to “periods prior to our acquisition of the Partnership Assets” and similar phrases refer to periods prior to May 14, 2008, with respect to the initial assets, periods prior to December 19, 2008, with respect to the Powder River assets, and periods prior to July 1, 2009 with respect to the Chipeta assets. Reference to “periods including and subsequent to our acquisition of the Partnership Assets” and similar phrases refer to periods including and subsequent to May 14, 2008, with respect to the initial assets, periods including and subsequent to December 19, 2008, with respect to the Powder River assets, and periods including and subsequent to July 1, 2009, with respect to the Chipeta assets.
The acquisitions of the Partnership Assets were considered transfers of net assets between entities under common control. Accordingly, we are required to revise our financial statements to include the activities of the Partnership Assets as of the date of common control. Our historical financial statements for the three and nine months ended September 30, 2008 and the first six months of 2009 have been recast to reflect the results attributable to the Powder River assets and the Chipeta assets as if the Partnership owned the Powder River assets, a 51% interest in Chipeta and associated midstream assets for all periods presented.
PARTNERSHIP AGREEMENT AMENDMENT
On April 15, 2009, after receiving the unanimous approval of the special committee of the board of directors of Western Gas Holdings, LLC, the Partnership’s general partner, the general partner’s board of directors unanimously approved an amendment (the “Amendment”) to the Partnership’s First Amended and Restated Agreement of Limited Partnership, effective on the date of approval. The purpose of the Amendment was to ensure that the Partnership’s common unitholders maintain, to the maximum extent possible, their existing share of allocable tax deductions throughout the subordination period. Absent the Amendment, it would have been possible, as a result of equity issuances at a price less than the initial public offering price during the subordination period, that the common unitholders’ allocable share of tax deductions would be significantly diminished.
The foregoing general description of the Amendment is not complete and is qualified in its entirety by reference to the full and complete terms of the Amendment, which is attached to the Form 8-K, filed with the SEC on April 20, 2009, and the partnership agreement, which is incorporated herein.

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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, (2) operating expenses, (3) Adjusted EBITDA and (4) gross margin.
Throughput
In order to maintain or increase throughput on our gathering and processing systems, we must connect additional wells to our systems. Our success in maintaining or increasing throughput is impacted by successful drilling of new wells by producers that are 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, processed or treated by our competitors.
To maintain and increase throughput 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 identify new opportunities and to attempt to maintain a full subscription of MIGC’s firm capacity.
Operating expenses
We analyze operating expenses to evaluate our performance. Operating expenses include all amounts accrued or paid for the operation of our systems, including cost of product, 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.
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 our acquisition of the Partnership Assets, certain of 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 and NGLs pursuant to our percent-of-proceeds processing contracts, (ii) costs associated with the valuation of our gas imbalances, (iii) 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 (iv) 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 pursuant to our contracts. These expenses are subject to variability, although our exposure to commodity price risk attributable to our percent-of-proceeds contracts is mitigated through our commodity price swap agreements with Anadarko.
General and administrative expenses for periods prior to our acquisition of the Partnership Assets include reimbursements attributable to costs incurred by Anadarko on our behalf and allocations of general and administrative costs by Anadarko to us. For these periods, Anadarko received compensation or reimbursement through a management services fee. For periods subsequent to our acquisition of the Partnership Assets, Anadarko is no longer compensated for corporate services through a management services fee. Instead, we reimburse Anadarko for general and administrative expenses it incurs on our behalf pursuant to the terms of our omnibus agreement with Anadarko. Amounts required to be reimbursed to Anadarko under the omnibus agreement include those expenses attributable to our status as a publicly traded partnership, such as:
    expenses associated with annual and quarterly reporting;
    tax return and Schedule K-1 preparation and distribution expenses;
    expenses associated with listing on the New York Stock Exchange; and
    independent auditor fees, legal expenses, investor relations expenses, director fees, and registrar and transfer agent fees.
In addition to the above, we are required pursuant to the terms of the omnibus agreement with Anadarko to reimburse Anadarko for allocable general and administrative expenses. As of September 30, 2009, the amount required to be reimbursed by us to Anadarko for certain allocated general and administrative expenses is capped at $6.9 million for the year ended December 31, 2009, subject to adjustment to reflect expansions of our operations through the acquisition or

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construction of new assets or businesses and with the concurrence of the special committee of our general partner’s board of directors. If the Omnibus Agreement is not amended by the parties, our general partner will determine the general and administrative expenses to be reimbursed by us in accordance with our partnership agreement for periods subsequent to December 31, 2009. 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 separate publicly traded entity. We currently expect public company expenses not subject to the cap contained in the omnibus agreement to be approximately $6.4 million per year, excluding equity-based compensation and transaction costs related to the Chipeta acquisition and future acquisitions.
Adjusted EBITDA
We define Adjusted EBITDA as net income (loss) attributable to Western Gas Partners, LP, plus distributions from equity investee, non-cash equity-based compensation expense, interest expense, income tax expense, depreciation and amortization, less income from equity investments, interest income, income tax benefit and other income (expense). We changed our definition of Adjusted EBITDA from the definition used in the prior year. Adjusted EBITDA has been calculated using the revised definition for all periods presented. 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, commercial banks and rating agencies, use to assess, among other measures:
    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;
    the ability of our assets to generate cash flow to make distributions; and
    the viability of acquisitions and capital expenditure projects and the returns on investment of various investment opportunities.
The following tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measures of net income attributable to Western Gas Partners, LP and net cash provided by operating activities (in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008(1)     2009(1)     2008(1)  
   
Reconciliation of adjusted EBITDA to net income attributable to Western Gas Partners, LP
                               
Adjusted EBITDA attributable to Western Gas Partners, LP
  $ 26,404     $ 30,488     $ 81,542     $ 93,633  
Less:
                               
Distributions from equity investee
    1,555       1,422       4,125       3,673  
Non-cash equity-based compensation expense
    948       524       2,736       785  
Interest expense, net — affiliates
    3,127       36       6,698       1,546  
Income tax expense
    171                   11,289  
Depreciation and amortization (2)
    9,586       9,012       28,101       25,775  
Impairment
          9,354             9,354  
Add:
                               
Equity income, net
    1,794       1,539       5,329       3,840  
Interest income from note — affiliate
    4,225       4,697       12,675       6,478  
Other income, net (2)
    12       110       27       142  
Income tax benefit
          1,463       152        
 
                       
Net income attributable to Western Gas Partners, LP
  $ 17,048     $ 17,949     $ 58,065     $ 51,671  
 
                       

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    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008(1)     2009(1)     2008(1)  
Reconciliation of adjusted EBITDA to net cash provided by operating activities
                               
Adjusted EBITDA attributable to Western Gas Partners, LP
  $ 26,404     $ 30,488     $ 81,542     $ 93,633  
Adjusted EBITDA attributable to noncontrolling interests
    2,816       3,627       9,280       7,275  
Interest income, net — affiliates
    1,098       4,661       5,977       4,932  
Non-cash equity-based compensation expense
    (948 )     (524 )     (2,736 )     (785 )
Current income tax expense (benefit)
    (65 )     2,165       (184 )     (8,856 )
Other income, net
    13       126       29       159  
Distributions from equity investee less than equity income, net
    239       117       1,204       167  
Changes in operating working capital:
                               
Accounts receivable and natural gas imbalance receivable
    (269 )     (9,481 )     2,944       (12,014 )
Accounts payable, accrued liabilities and natural gas imbalance payable
    (6,638 )     14,145       (17,007 )     21,683  
Other, including changes in non-current assets and liabilities
    (1,206 )     469       (1,398 )     (1,479 )
 
                       
Net cash provided by operating activities
  $ 21,444     $ 45,793     $ 79,651     $ 104,715  
 
                       
 
(1)   Financial information for 2008 and the first six months of 2009 has been revised to include results attributable to the Powder River assets and Chipeta assets. See Note 1—Description of Business and Basis of Presentation—Powder River acquisition and Chipeta acquisition of the notes to unaudited consolidated financial statements included under Part I, Item 1 of this Form 10-Q.
 
(2)   Depreciation and amortization expense and other income, net for purposes of reconciling Adjusted EBITDA to net income includes 51% of the respective amounts attributable to Chipeta Processing LLC.
Gross margin
We define gross margin as total revenues less cost of product. We changed our definition of gross margin from the definition used in the prior year. Gross margin has been presented using the revised definition for all periods presented. We consider gross margin to provide information useful in assessing our results of operations, our ability to internally fund capital expenditures and to service or incur additional debt.
ITEMS AFFECTING THE COMPARABILITY OF OUR FINANCIAL RESULTS
Our historical results of operations and cash flows for the periods presented may not be comparable to future or historic results of operations or cash flows for the reasons described below:
    Pursuant to the omnibus agreement, Anadarko performs centralized corporate functions for the Partnership, such as legal, accounting, treasury, cash management, investor relations, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, tax, marketing and midstream administration. We anticipate incurring up to $6.9 million in general and administrative expenses annually to be charged by Anadarko for these centralized corporate functions. Prior to our ownership of the Partnership Assets, our historical consolidated financial statements reflect a management services fee representing the general and administrative expenses attributable to the Partnership Assets. The $6.9 million in general and administrative expenses to be charged pursuant to the omnibus agreement is expected to be greater than amounts allocated to us by Anadarko for the aggregate management services fees reflected in our historical consolidated financial statements for periods prior to our ownership of the Partnership Assets. In addition, we currently expect to incur approximately $6.4 million per year in public company expenses, excluding equity-based compensation and transaction costs related to the Chipeta acquisition and future acquisitions. We did not incur public company expenses prior to our initial public offering in May 2008.
    Prior to May 14, 2008, with respect to our initial assets, and prior to December 19, 2008, with respect to the Powder River assets, all affiliate transactions were net settled within our consolidated financial statements and were funded by Anadarko’s working capital. Effective on May 14, 2008, with respect to our initial assets, and effective on

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      December 19, 2008, with respect to the Powder River assets, all affiliate and third-party transactions are funded by our working capital. Prior to June 1, 2008 with respect to Chipeta (the date on which Anadarko initially contributed assets to Chipeta), 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 Chipeta through an adjustment to parent net equity. Subsequent to June 1, 2008, Chipeta cash-settled transactions directly with third parties and with Anadarko affiliates. This impacts the comparability of our cash flow statements, working capital analysis and liquidity discussion.
 
    For periods prior to May 14, 2008, with respect to our initial assets, prior to December 19, 2008, with respect to the Powder River assets, and prior to June 1, 2008, with respect to Chipeta, we incurred interest expense or earned interest income on current intercompany balances with Anadarko. These intercompany balances were extinguished through non-cash transactions in connection with the closing of our initial public offering, the Powder River acquisition and Anadarko’s initial contribution of assets to Chipeta; therefore, interest expense and interest income attributable to these balances is reflected in our historical consolidated financial statements for the periods ending prior to and including May 14, 2008, with respect to our initial assets, prior to and including June 1, 2008, with respect to Chipeta, and prior to and including December 19, 2008, with respect to the Powder River assets.
 
    Concurrent with the closing of our initial public 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%. For periods including and subsequent to May 14, 2008, interest income attributable to the note is reflected in our consolidated financial statements so long as the note remains outstanding.
 
    In connection with the Powder River acquisition in December 2008, we entered into a five-year, $175.0 million term loan agreement with Anadarko, under which we pay interest at a fixed rate of 4.00% for the first two years and a floating rate of interest at three-month LIBOR plus 150 basis points for the final three years. In connection with the Chipeta acquisition in July 2009, we entered into a three-year, 7.00% fixed rate, $101.5 million term loan agreement with Anadarko. In October 2009, we borrowed $100.0 million under our new revolving Credit Facility and used $2.0 million of cash on hand to refinance the $101.5 million three-year term loan with Anadarko and related accrued interest. See Note 14—Subsequent Events of the notes to unaudited consolidated financial statements included under Part I, Item 1 of this Form 10-Q. Interest expense on our notes and credit facilities will be incurred so long as the debt remains outstanding.
 
    Our financial results for historical periods reflect commodity price changes, which, in turn, impact the financial results derived from our percent-of-proceeds processing contracts. Effective January 1, 2009, commodity price risk associated with our percent-of-proceeds processing contracts has been mitigated through our fixed-price commodity price swap agreements with Anadarko that extend through December 31, 2010, with an option to extend through 2013. See Note 6—Transactions with Affiliates of the notes to unaudited consolidated financial statements included under Part I, Item 1 of this Form 10-Q.
 
    We are generally not subject to federal or state income tax. Federal and state income tax expense was recorded for periods ending prior to and including May 14, 2008, with respect to income generated by our initial assets, prior to June 1, 2008, with respect to income generated by the Chipeta assets, and prior to and including December 19, 2008, with respect to income generated by the Powder River assets. For periods subsequent to May 14, 2008, with respect to income generated by our initial assets, subsequent to June 1, 2008, with respect to the Chipeta assets, and subsequent to December 19, 2008, with respect to income generated by the Powder River assets, we are no longer subject to federal income tax and are only subject to Texas margin tax; therefore, income tax expense attributable to Texas margin tax will continue to be recognized in our consolidated financial statements. We are required to make payments to Anadarko pursuant to a tax sharing arrangement for our share of Texas margin tax included in any combined or consolidated returns of Anadarko.
 
    We made cash distributions to our unitholders and our general partner following our initial public offering in May 2008. During the nine months ended September 30, 2008, the Partnership paid cash distributions to its unitholders of approximately $8.6 million, representing the $0.1582 per unit distribution for the quarter ended June 30, 2008. During the nine months ended September 30, 2009, the Partnership paid cash distributions to its unitholders of approximately $51.8 million, representing the $0.31 per unit distribution for the quarter ended June 30, 2009 and $0.30 per unit distributions for each of the quarters ended March 31, 2009 and December 31, 2008. On

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      October 20, 2009, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.32 per unit for the three months ended September 30, 2009, which equates to approximately $18.3 million per full quarter, or approximately $73.2 million per full year, based on the number of common, subordinated and general partner units outstanding as of October 31, 2009.
 
    We expect to rely upon external financing sources, including commercial bank borrowings and long-term debt and equity issuances, to fund our acquisitions and expansion capital expenditures. Historically, we largely relied on internally generated cash flows and capital contributions from Anadarko to satisfy our capital expenditure requirements.
 
    In connection with the closing of our initial public offering, our general partner adopted two new compensation plans: the Western Gas Partners, LP 2008 Long-Term Incentive Plan, or LTIP, and the Amended and Restated Western Gas Holdings, LLC Equity Incentive Plan, or the Incentive Plan. Phantom unit grants have been made under the LTIP and incentive unit grants have been made under the Incentive Plan. These grants 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. For periods ending prior to May 14, 2008, equity-based compensation expense attributable to the LTIP and Incentive Plan is not reflected in our historical consolidated financial statements as there were no outstanding equity grants under either plan. For periods including and subsequent to May 14, 2008, the Partnership’s general and administrative expenses include equity-based compensation costs allocated by Anadarko to the Partnership for grants made under the LTIP and Incentive Plan as well as under 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”). Equity-based compensation expense attributable to grants made under the LTIP will impact our cash flows from operating activities only to the extent cash payments are made to a participant in lieu of the actual issuance of common units to 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 who provided services to us pursuant to the omnibus agreement 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 in that agreement for the periods to which such expense limit applies. Equity-based compensation granted under the Anadarko Incentive Plans does not impact our cash flow from operating activities. See equity-based compensation discussion included in Note 6—Transactions with Affiliates of the notes to unaudited consolidated financial statements included under Part I, Item 1 of this Form 10-Q and in Note 2 — Summary of Significant Accounting Policies of the notes to consolidated financial statements in Item 8 of our annual report on Form 10-K.
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.
Impact of natural gas prices
The current natural gas price environment has recently resulted in lower drilling activity, resulting in fewer new well connections throughout areas in which we operate, and may result in further reductions in drilling activity or temporary suspension of production. We have no control over this activity. In addition, the recent or further decline in commodity prices could affect production rates and the level of capital investment by Anadarko and third parties in the exploration for and development of new natural gas reserves. To the extent opportunities are available, we continue to connect new wells to our systems to mitigate the impact of natural production declines in order to maintain throughput on our systems. However, our success in connecting new wells to our systems is dependent on natural gas producers and shippers.
Benefits from system expansions
We completed significant capital expansion projects during 2008 and 2009 that position us to capitalize on future drilling activity by Anadarko and third-party producers and shippers. In April 2009, we completed a 250 MMcf/d capacity cryogenic unit at the Chipeta plant in the Uintah Basin in northeastern Utah. Chipeta provides processing services to Anadarko and third-party production in the Greater Natural Buttes field. In addition, during 2008, Anadarko completed Phase III of the Fort

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Union expansion project by installing a third parallel 106 mile 24” line, increasing the total Fort Union throughput capacity to 1,300 MMcf/d. During the fourth quarter of 2008, Anadarko completed train two of the Medicine Bow Plant at the terminus of the Fort Union gathering system, which is designed for 600 gallons per minute of amine circulation. During the first quarter of 2009, Anadarko completed train three of the Medicine Bow Plant, which is identical to train two. The system’s gas treating capacity will vary depending upon the CO2 content of the inlet gas. At the current level of 3.7% CO2, the system is capable of treating and blending over 1 Bcf/d while satisfying the CO2 specifications of downstream pipelines.
Capital markets
We require periodic 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 could 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.
Rising operating costs and inflation
The high level of natural gas exploration, development and production activities across the U.S. in recent years, and the associated construction of required midstream infrastructure, resulted in an increase in the competition for and cost of personnel and equipment. As a result of the recent decline in commodity prices, we have and will continue to actively work with our suppliers to negotiate cost savings on services and equipment to more accurately reflect the current industry environment. To the extent we are unable to negotiate lower costs, or recover higher costs through escalation provisions provided for in our contracts, our operating results will be adversely impacted.

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RESULTS OF OPERATIONS — OVERVIEW
OPERATING RESULTS
The following table and discussion presents a summary of our results of operations for the three and nine months ended September 30, 2009 and 2008:
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008(1)     2009(1)     2008(1)  
    (in thousands)  
Revenues
                               
Gathering, processing and transportation of natural gas
  $ 37,952     $ 35,132     $ 114,299     $ 101,028  
Natural gas, natural gas liquids and condensate sales
    20,591       53,428       60,932       164,834  
Equity income and other, net
    2,453       6,022       7,430       13,218  
 
                       
Total revenues
    60,996       94,582       182,661       279,080  
 
                       
 
                               
Operating expenses (2)
                               
Cost of product
    12,888       40,912       37,479       124,204  
Operation and maintenance
    11,741       14,001       34,841       39,512  
General and administrative
    5,980       4,332       15,067       9,564  
Property and other taxes
    1,876       1,630       5,984       5,510  
Depreciation and amortization
    10,216       9,380       29,642       26,890  
Impairment
          9,354             9,354  
 
                       
Total operating expenses
    42,701       79,609       123,013       215,034  
 
                       
 
                               
Operating income
    18,295       14,973       59,648       64,046  
 
                               
Interest income, net — affiliates
    1,098       4,661       5,977       4,932  
Other income, net
    13       126       29       159  
 
                       
 
                               
Income before income taxes
    19,406       19,760       65,654       69,137  
 
                               
Income tax expense (benefit)
    171       (1,463 )     (152 )     11,289  
 
                       
 
                               
Net income
    19,235       21,223       65,806       57,848  
 
                               
Net income attributable to noncontrolling interests
    2,187       3,274       7,741       6,177  
 
                       
 
                               
Net income attributable to Western Gas Partners, LP
  $ 17,048     $ 17,949     $ 58,065     $ 51,671  
 
                       
 
                               
Adjusted EBITDA (3)
  $ 26,404     $ 30,488     $ 81,542     $ 93,633  
Gross margin (3)
    48,108       53,670       145,182       154,876  
 
(1)   Financial information for 2008 and the first six months of 2009 has been revised to include results attributable to the Powder River assets and Chipeta assets. See Note 1—Description of Business and Basis of Presentation—Powder River acquisition and Chipeta acquisition of the notes to unaudited consolidated financial statements included under Part I, Item 1 of this Form 10-Q.
 
(2)   Operating expenses include amounts charged by affiliates to the Partnership for services as well as reimbursement of amounts paid by affiliates to third parties on behalf of the Partnership. See Note 6—Transactions with Affiliates of the notes to unaudited consolidated financial statements included under Part I, Item 1 of this Form 10-Q.
 
(3)   Adjusted EBITDA and gross margin are defined above within this Item 2 under the caption How We Evaluate Our Operations, which includes a reconciliation of Adjusted EBITDA to its most directly comparable measures calculated and presented in accordance with GAAP.
For purposes of the following discussion, any increases or decreases “for the three months ended September 30, 2009” refer to the comparison of the three months ended September 30, 2009 to the three months ended September 30, 2008 and any

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increases or decreases “for the nine months ended September 30, 2009” refer to the comparison of the nine months ended September 30, 2009 to the nine months ended September 30, 2008.
Summary Financial Results
Total revenues decreased by $33.6 million and $96.4 million for the three months ended September 30, 2009 and for the nine months ended September 30, 2009, respectively. For the three months ended September 30, 2009, gathering, processing and transportation revenues increased by $2.8 million; natural gas, NGLs and condensate revenues decreased by $32.8 million and equity income and other revenues decreased by $3.6 million. For the nine months ended September 30, 2009, gathering, processing and transportation revenues increased by $13.3 million; natural gas, NGLs and condensate revenues decreased by $103.9 million and equity income and other revenues decreased by $5.8 million.
Net income attributable to Western Gas Partners, LP decreased by approximately $0.9 million for the three months ended September 30, 2009 and increased by $6.4 million for the nine months ended September 30, 2009. The decrease for the three months ended September 30, 2009 is due to a $33.6 million decrease in revenues, a $1.6 million increase in income tax expense and a $3.6 million decrease in net interest income, partially offset by a $36.9 million decrease in operating expenses and a $1.1 million decrease in net income attributable to noncontrolling interests. The increase for the nine months ended September 30, 2009 is due to a $92.0 million decrease in operating expenses, a $11.4 million decrease in income tax expense and a $1.0 million increase in net interest income, partially offset by a $96.4 million decrease in revenues and a $1.6 million increase in net income attributable to noncontrolling interests. The changes in revenues, operating expenses, interest expense, income taxes and net income attributable to noncontrolling interests are discussed in more detail below.
Operating Statistics
                                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     D (1)     2009     2008     D (1)  
    (MMcf/d, except percentages and gross margin per Mcf)  
Gathering and transportation throughput (2)
                                               
Affiliates
    752       840       (10 )%     773       845       (9 )%
Third parties
    124       170       (27 )%     126       137       (8 )%
 
                                       
Total gathering and transportation throughput
    876       1,010       (13 )%     899       982       (8 )%
 
                                               
Processing throughput (3)
                                               
Affiliates
    327       282       16 %     332       206       61 %
Third parties
    65       64       2 %     57       44       30 %
 
                                       
Total processing throughput
    392       346       13 %     389       250       56 %
 
                                               
Equity investment throughput (4)
    119       111       7 %     120       110       9 %
 
                                       
 
                                               
Total throughput
    1,387       1,467       (5 )%     1,408       1,342       5 %
 
                                               
Throughput attributable to noncontrolling interest owners
    178       155       15 %     176       109       61 %
 
                                       
 
                                               
Total throughput attributable to Western Gas Partners, LP
    1,209       1,312       (8 )%     1,232       1,233        
 
                                       
 
(1)   Represents the percentage change for the three months ended September 30, 2009 or for the nine months ended September 30, 2009.
 
(2)   Includes 50% of Newcastle system volumes.
 
(3)   Includes 100% of Chipeta plant volumes.
 
(4)   Represents the Partnership’s 14.81% share of Fort Union’s gross volumes.

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Total throughput, which consists of affiliate, third-party and equity investment volumes, decreased by 80 MMcf/d for the three months ended September 30, 2009 and increased by 66 MMcf/d for the nine months ended September 30, 2009. Total throughput attributable to Western Gas Partners, LP, which excludes the noncontrolling interest owner’s proportionate share of Chipeta’s throughput, decreased by 103 MMcf/d for the three months ended September 30, 2009 and remained relatively flat for the nine months ended September 30, 2009.
Affiliate gathering and transportation throughput decreased by 88 MMcf/d and 72 MMcf/d for the three months ended September 30, 2009 and for the nine months ended September 30, 2009, respectively. The decrease for both the three months and nine months ended September 30, 2009 is primarily due to throughput decreases at the Pinnacle, Dew, Haley and Hugoton systems primarily due to natural production declines and changes in contract terms, partially offset by affiliate throughput increases at the Chipeta plant and the MIGC system. Contract terms for one Pinnacle customer changed in August 2008 when a producer chose to take its product in-kind and contract directly with us for gathering services, rather than to sell its production to our affiliate at the wellhead, resulting in a shift in volumes from affiliate to third-party. Affiliate volume increases for the MIGC system are primarily due to throughput from contracts entered into by our affiliate upon expiration of two third-party contracts in December 2008 and January 2009, which enabled an affiliate of Anadarko to increase its volumes.
Third-party gathering and transportation throughput decreased by 46 MMcf/d and 11 MMcf/d for the three months ended September 30, 2009 and for the nine months ended September 30, 2009, respectively. The decrease for the three months and nine months ended September 30, 2009 is primarily attributable to throughput decreases at the Haley and MIGC systems, partially offset by third-party throughput increases at the Pinnacle system. The declines experienced on the MIGC pipeline were primarily due to the expiration of two third-party contracts described above. The throughput declines on the Haley system were primarily due to natural production declines. The increase in third-party throughput at the Pinnacle systems is primarily due to changes in contract terms mentioned above resulting in a shift from affiliate to third-party throughput.
Affiliate processing throughput increased by 45 MMcf/d and 126 MMcf/d for the three months ended September 30, 2009 and for the nine months ended September 30, 2009, respectively, and third-party processing throughput remained relatively flat for the three months ended September 30, 2009 and increased by 13 MMcf/d for the nine months ended September 30, 2009. Affiliate throughput increased primarily due to increased throughput at the Chipeta plant from drilling activities by our affiliate in the Natural Buttes Field.
Equity investment volumes increased by 8 MMcf/d and 10 MMcf/d for the three months ended September 30, 2009 and for the nine months ended September 30, 2009, respectively, primarily due to additional throughput from the Powder River area following expansion of the Fort Union system during the second half of 2008.

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Natural Gas Gathering, Processing and Transportation Revenues
                                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     D     2009     2008     D  
    (in thousands, except percentages)  
Gathering, processing and transportation of natural gas:
                                               
Affiliates
  $ 33,438     $ 29,878       12 %   $ 101,314     $ 88,217       15 %
Third parties
    4,514       5,254       (14 )%     12,985       12,811       1 %
 
                                       
Total
  $ 37,952     $ 35,132       8 %   $ 114,299     $ 101,028       13 %
 
                                       
Total gathering, processing and transportation of natural gas revenues increased by $2.8 million and by $13.3 million for the three months ended September 30, 2009 and for the nine months ended September 30, 2009, respectively. Revenues from affiliates increased by $3.6 million and $13.1 million for the three months ended September 30, 2009 and for the nine months ended September 30, 2009, respectively, primarily due to increased affiliate throughput at the Chipeta plant and at the MIGC system due to the third-party contract expirations that caused volumes and associated revenues to shift from third party to affiliate, partially offset by throughput decreases at the Pinnacle, Dew, Haley and Hugoton systems. Revenues from third parties decreased by $0.7 million for the three months ended September 30, 2009, primarily due to third-party throughput decreases at the Haley system and a decrease in third-party volumes on the MIGC system attributable to the third-party contract expirations described above, partially offset by throughput increases at the Pinnacle system. Revenues from third parties remained relatively flat for the nine months ended September 30, 2009.
Natural Gas, Natural Gas Liquids and Condensate Sales
                                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     D     2009     2008     D  
    (in thousands, except percentages and per-unit amounts)  
Natural gas sales:
                                               
Affiliates
  $ 6,659     $ 18,802       (65 )%   $ 21,973     $ 56,157       (61 )%
Third parties
    2             nm (1)     6       23       (74 )%
 
                                       
Total
  $ 6,661     $ 18,802       (65 )%   $ 21,979     $ 56,180       (61 )%
 
                                               
Natural gas liquids sales:
                                               
Affiliates
  $ 12,367     $ 31,445       (61 )%   $ 33,990     $ 94,614       (64 )%
Third parties
          159       (100 )%           160       (100 )%
 
                                       
Total
  $ 12,367     $ 31,604       (61 )%   $ 33,990       94,774       (64 )%
 
                                               
Drip condensate sales — third parties
  $ 1,563     $ 3,022       (48 )%   $ 4,963     $ 13,880       (64 )%
 
                                               
Total natural gas, natural gas liquids and condensate sales:
                                               
Affiliates
  $ 19,026     $ 50,247       (62 )%   $ 55,963     $ 150,771       (63 )%
Third parties
    1,565       3,181       (51 )%     4,969       14,063       (65 )%
 
                                       
Total
  $ 20,591     $ 53,428       (61 )%   $ 60,932     $ 164,834       (63 )%
 
                                       
 
                                               
Average price per unit:
                                               
Natural gas (per Mcf)
  $ 3.10     $ 8.95       (65 )%   $ 3.18     $ 8.76       (64 )%
Natural gas liquids (per Bbl)
  $ 37.99     $ 82.57       (54 )%   $ 38.14     $ 81.64       (53 )%
Drip condensate (per Bbl)
  $ 59.31     $ 109.02       (46 )%   $ 43.33     $ 104.07       (58 )%
 
(1)   Percent change is not meaningful
Total natural gas, natural gas liquids and condensate sales decreased by $32.8 million and $103.9 million for the three months ended September 30, 2009 and for the nine months ended September 30, 2009, respectively. The decrease for the three months ended September 30, 2009 consisted of a $19.2 million decrease in NGLs sales, a $12.1 million decrease in natural gas sales and a $1.5 million decrease in drip condensate sales. The decrease for the nine months ended September 30, 2009 consisted of a $60.8 million decrease in NGLs sales, a $34.2 million decrease in natural gas sales and an $8.9 million decrease in drip condensate sales.

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The decrease in NGLs sales was primarily due to a decrease in the average price for NGLs sold. The average natural gas and NGLs prices for the three and nine months ended September 30, 2009 include gains from commodity price swap agreements. The decrease in the NGLs price per barrel is due to the decrease in market prices, partially offset by the fixed prices at the Hilight and Newcastle systems under the commodity price swap agreements. The fixed prices under the swap agreements were lower than 2008 market prices but higher than 2009 market prices. The volume of NGLs sold decreased by approximately 63,000 Bbls, or 15%, for the three months ended September 30, 2009 and decreased by approximately 222,000 Bbls, or 19%, for the nine months ended September 30, 2009, primarily due to the shut-in of a plant at the Hilight system in September 2008 at which butane was purchased, processed into iso-butane and sold.
The decrease in natural gas sales was primarily due to a decrease in the average price for residue gas sold. For the nine months ended September, 30, 2009, the decrease in average natural gas prices was partially offset by an 19% increase in the volume of natural gas sold.
The decrease in drip condensate sales was primarily due to decreased average prices for drip condensate sold.
Equity Income and Other Revenues
                                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     D     2009     2008     D  
    (in thousands, except percentages)  
Equity income — affiliate
  $ 1,794     $ 1,539       17 %   $ 5,329     $ 3,840       39 %
 
                                               
Other revenues, net:
                                               
Affiliates
  $ 460     $ 688       (33 )%   $ 1,295     $ 4,055       (68 )%
Third parties
    199       3,795       (95 )%     806       5,323       (85 )%
 
                                       
 
                                               
Total equity income and other revenues, net
  $ 2,453     $ 6,022       (59 )%   $ 7,430     $ 13,218       (44 )%
 
                                       
Total equity income and other revenues decreased by $3.6 million and $5.8 million for the three months ended September 30, 2009 and for the nine months ended September 30, 2009, respectively. During the three and nine months ended September 30, 2009, equity income increased by approximately $0.3 million and $1.5 million, respectively, primarily from the system expansion at Fort Union and a decrease in that joint venture’s interest expense. For the nine months ended September 30, 2009, other affiliate revenues decreased primarily due to changes in gas imbalance positions and related gas prices. The decrease in other third-party revenues for the three months ended September 30, 2009 and for the nine months ended September 30, 2009 was primarily due to a decrease in other third-party revenues due to changes in gas imbalance positions and related gas prices and, in addition for the nine months ended September 30, 2009, due to a $0.9 million indemnity payment received from a third party during 2008.

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Cost of Product and Operation and Maintenance Expenses
                                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     D     2009     2008     D  
    (in thousands, except percentages and per-unit amounts)  
Cost of product
  $ 12,888     $ 40,912       (68 )%   $ 37,479     $ 124,204       (70 )%
Operation and maintenance
    11,741       14,001       (16 )%     34,841       39,512       (12 )%
 
                                       
Total cost of product and operation and maintenance expenses
  $ 24,629     $ 54,913       (55 )%   $ 72,320     $ 163,716       (56 )%
 
                                       
 
                                               
Cost of product — average price per unit:
                                               
Natural gas (per Mcf)
  $ 2.32     $ 6.63       (65 )%   $ 2.10     $ 6.88       (69 )%
Natural gas liquids (per Bbl)
  $ 19.48     $ 66.47       (71 )%   $ 18.16     $ 60.31       (70 )%
Drip condensate (per MMBtu)
  $ 2.91     $ 8.28       (65 )%   $ 2.98     $ 7.99       (63 )%
Cost of product expense decreased by $28.0 million and $86.7 million for the three months ended September 30, 2009 and for the nine months ended September 30, 2009, respectively. The decrease for the three months ended September 30, 2009 includes an approximate $24.8 million decrease in cost of product expense attributable to the lower cost of natural gas and NGLs we purchase from producers due to lower market prices and lower volumes, a $2.5 million decrease due to changes in gas imbalance positions and related gas prices and a $0.7 million decrease from the lower cost of natural gas to compensate shippers on a thermally equivalent basis for drip condensate retained by us and sold to third parties, primarily due to lower market prices. The volume of natural gas purchased from producers decreased 4% for the three months ended September 30, 2009 and the volume of NGLs purchased from producers decreased 15% for the nine months ended September 30, 2009. The decrease in the volume of NGLs purchased is primarily due to the September 2008 shut-in of a unit that produced iso-butane from NGLs at the Hilight system. Excluding the impact of the shut-in, the volume of NGLs purchased would have increased approximately 30%. This increase in the volumes of NGLs purchased and the increase in the volumes of natural gas purchased are primarily due to the increase in throughput at the Chipeta plant for the three months ended September 30, 2009 as well as increased NGLs recoveries at the Chipeta plant due to completion of the cryogenic unit in April 2009. Cost of product expense for the nine months ended September 30, 2009 decreased by $76.2 million attributable to the lower cost of natural gas and NGLs we purchase from producers, primarily due to lower market prices and an increase in the volume of natural gas purchased; decreased by $6.1 million due to changes in gas imbalance positions and related gas prices; $3.6 million from the lower cost of natural gas to compensate shippers on a thermally equivalent basis for drip condensate retained by us and sold to third parties and by approximately $0.8 million due to a decrease in the excess of actual fuel costs over contractual fuel recoveries. The volume of natural gas purchased from producers increased 19% for the nine months ended September 30, 2009 and the volume of NGLs purchased from producers decreased 19% for the nine months ended September 30, 2009. The decrease in the volume of NGLs purchased is primarily due to the September 2008 shut-in of a unit at the Hilight system. Excluding the impact of the shut-in, the volume of NGLs purchased would have increased approximately 35%. This increase in the volumes of NGLs purchased and the increase in the volumes of natural gas purchased are primarily due to the increases in throughput and NGL recoveries at the Chipeta plant described above.
Operation and maintenance expense decreased by $2.3 million and $4.7 million for the three months ended September 30, 2009 and for the nine months ended September 30, 2009, respectively. The decrease for the three months ended September 30, 2009 is primarily due to a $0.9 million decrease in operating fuel costs attributable to the shut-in of a plant in the Hilight system in September 2008; a $0.3 million decrease in compressor parts and rental expenses primarily due to the contribution of previously leased compression equipment to the Partnership in November 2008 and lower rates on equipment rentals as a result of renegotiating with suppliers; and a decrease in labor and labor-related expenses. The decrease for the nine months ended September 30, 2009 is primarily due to a $2.6 million decrease in operating fuel costs attributable to the shut-in of a plant in the Hilight system effective September 2008; a $0.9 million decrease in compressor parts and rental expenses primarily due to the contribution of previously leased compression equipment to the Partnership in November 2008; and lower rates on equipment rentals as a result of renegotiating with suppliers and a decrease in labor and labor-related expenses.

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Gross Margin
                                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     D     2009     2008     D  
    (in thousands, except percentages and gross margin per Mcf)  
Gross margin
  $ 48,108     $ 53,670       (10 )%   $ 145,182     $ 154,876       (6 )%
Gross margin per Mcf (1)
  $ 0.38     $ 0.40       (5 )%   $ 0.38     $ 0.42       (10 )%
Gross margin per Mcf attributable to Western Gas Partners, LP (2)
  $ 0.40     $ 0.41       (2 )%   $ 0.39     $ 0.43       (9 )%
 
(1)   Calculated as gross margin (total revenues less cost of product) divided by total throughput, including 100% of gross margin and volumes attributable to Chipeta and the Partnership’s 14.81% interest in income and volumes attributable to the Fort Union. Calculating gross margin per Mcf separately for affiliates and third parties is not meaningful since a significant portion of throughput is delivered from third parties while the related residue gas and NGLs are sold to an affiliate.
 
(2)   Calculated as gross margin (total revenues less cost of product), excluding the noncontrolling interest owners’ proportionate share of revenues and cost of product, divided by total throughput attributable to Western Gas Partners, LP. Calculation includes income and volumes attributable to the Partnership’s investment in Fort Union.
Gross margin decreased by $5.6 million and $9.7 million for the three months ended September 30, 2009 and for the nine months ended September 30, 2009, respectively. The decrease in gross margin for the three months ended September 30, 2009 and for the nine months ended September 30, 2009 is primarily due to the decrease in natural gas and NGLs prices and throughput. The impact of the decrease in market prices on our gross margin was mitigated by our fixed-price contract structure. Gross margin per Mcf attributable to Western Gas Partners, LP decreased by 2% and 9% for the three months ended September 30, 2009 and for the nine months ended September 30, 2009, respectively. The decrease in gross margin per Mcf is primarily due to lower processing margins and lower drip condensate margins.
General and Administrative, Depreciation and Other Expenses
                                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     D     2009     2008     D  
    (in thousands, except percentages)  
General and administrative
  $ 5,980     $ 4,332       38 %   $ 15,067     $ 9,564       58 %
Property and other taxes
    1,876       1,630       15 %     5,984       5,510       9 %
Depreciation and amortization
    10,216       9,380       9 %     29,642       26,890       10 %
Impairment
          9,354       (100 )%           9,354       (100 )%
 
                                       
Total general and administrative, depreciation and other expenses
  $ 18,072     $ 24,696       (27 )%   $ 50,693     $ 51,318       (1 )%
 
                                       
General and administrative, depreciation and other expenses decreased by $6.6 million and $0.6 million for the three months ended September 30, 2009 and for the nine months ended September 30, 2009, respectively. General and administrative expenses increased by $1.6 million for the three months ended September 30, 2009, primarily due to accounting and legal expenses attributable to the Chipeta acquisition. General and administrative expenses increased $5.5 million for the nine months ended September 30, 2009, primarily due to incurring expenses attributable to being a publicly traded partnership for all of the nine months ended September 30, 2009, compared to approximately three and a half months during the nine months ended September 30, 2008, and to accounting and legal expenses attributable to the Chipeta acquisition and equity-based compensation expense.
Depreciation and amortization expense increased by approximately $0.8 million and $2.8 million for the three months ended September 30, 2009 and for the nine months ended September 30, 2009, respectively, due to depreciation on assets placed in service in late 2008 and in 2009, primarily attributable to the expansion to our Chipeta plant completed in April 2009, our Pinnacle Bethel treating facility completed in July 2008 and previously leased Hugoton compression equipment contributed to the Partnership in November 2008. Prior to our acquisition of the Powder River assets, during the three and nine months ended September 30, 2008, a $9.4 million impairment charge was recognized related to the shut-in of a plant at the Hilight system.

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Interest Income, Net Affiliates
                                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     D     2009     2008     D  
    (in thousands, except percentages)  
Interest income on note receivable from Anadarko
  $ 4,225     $ 4,225           $ 12,675     $ 6,478       96 %
Interest (expense) on notes payable to Anadarko
    (3,091 )           nm (1)      (6,591 )           nm (1)   
Interest income (expense), net — affiliates
          472       (100 )%           (1,470 )     (100 )%
Credit facility commitment fees — affiliates
    (36 )     (36 )           (107 )     (76 )     41 %
 
                                       
Total
  $ 1,098     $ 4,661       (76 )%   $ 5,977     $ 4,932       21 %
 
                                       
 
(1)   Percent change is not meaningful
Interest income, net for the three and nine months ended September 30, 2009, consisted of interest income on our $260.0 million note receivable from Anadarko entered into in connection with our initial public offering in May 2008, partially offset by interest expense attributable to our $175.0 million term loan agreement entered into with Anadarko in connection with the Powder River acquisition, interest expense attributable to our $101.5 million term loan agreement entered into with Anadarko in connection with the Chipeta acquisition, and commitment fees on our $100.0 million portion of Anadarko’s $1.3 billion credit facility and our $30.0 million working capital facility. In October 2009, we borrowed $100.0 million under our new $350.0 million three-year revolving Credit Facility and refinanced the $101.5 million term loan. See Note 14—Subsequent Events — Revolving credit facility of the notes to unaudited consolidated financial statements included under Part I, Item 1 of this Form 10 Q. Interest income, net for the three months ended September 30, 2008 consisted of interest income on our $260.0 million note receivable from Anadarko and interest earned on affiliate balances, partially offset by commitment fees for our credit facilities. Interest income, net for the three and nine months ended September 30, 2008 consisted of interest income on our $260.0 million note receivable from Anadarko, partially offset by interest charged on affiliate balances and commitment fees on our credit facilities.
Income Tax Expense
                                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     D     2009     2008     D  
    (in thousands, except percentages)  
Income before income taxes
  $ 19,406     $ 19,760       (2 )%   $ 65,654     $ 69,137       (5 )%
Income tax expense (benefit)
    171       (1,463 )     112 %     (152 )     11,289       (101 )%
Effective tax rate
    1 %     (7 )%                   16 %        
Income tax expense increased by $1.6 million for the three months ended September 30, 2009 and decreased by $11.4 million for the nine months ended September 30, 2009. Income earned by the Partnership, a non-taxable entity for U.S. federal income tax purposes, including and subsequent to May 14, 2008, with respect to the initial assets, and including and subsequent to December 19, 2008, with respect to the Powder River assets, was subject only to Texas margin tax while income earned prior to May 14, 2008, with respect to the initial assets, and prior to December 19, 2008, with respect to the Powder River assets, was subject to federal and state income tax. Income attributable to the Chipeta assets was subject to federal and state income tax for periods prior to June 1, 2008, at which time substantially all of the Chipeta assets were contributed to a non-taxable entity for U.S. federal income tax purposes. For 2008 and 2009, the Partnership’s variance from the federal statutory rate is primarily attributable to our U.S. federal income tax status as a non-taxable entity beginning on May 14, 2008, partially offset by state income tax expense.
The increase in income tax expense for the three months ended September 30, 2009 is primarily due to a net income tax benefit resulting from the impairment loss recorded on an asset at the Hilight system during the three months ended September 30, 2008, partially offset by Texas margin tax expense attributable to the initial assets and federal income tax attributable to the Newcastle system. For the nine months ended September 30, 2009, income tax expense decreased primarily due to a change in the applicability of U.S. federal income tax to our income that occurred in connection with the initial public offering. In addition, for the nine months ended September 30,

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2009, our estimated income attributed to Texas relative to our total income decreased as compared to the prior year, which resulted in an approximately $0.5 million reduction of previously recognized deferred taxes.
Noncontrolling Interests
                                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     D     2009     2008     D  
    (in thousands, except percentages)  
Net income attributable to noncontrolling interests
  $ 2,187     $ 3,274       (33 )%   $ 7,741     $ 6,177       25 %
Net income attributable to noncontrolling interests decreased $1.1 million for the three months ended September 30, 2009 and increased $1.6 million for the nine months ended September 30, 2009. Noncontrolling interests represent the aggregate 49% interest in Chipeta held by Anadarko and a third party. The decrease in net income attributable to noncontrolling interests for the three months ended September 30, 2009 is primarily due to lower prices on NGLs sales at the Chipeta plant, offset by higher volumes. The increase for the nine months ended September 30, 2009 is primarily due to an increase in volumes processed at the Chipeta plant as the refrigeration unit was placed in service in late 2007 and throughput increased to the plant’s initial capacity during the first quarter of 2008. The cryogenic unit was placed in service in April 2009, leading to further increased volumes and NGLs recoveries during the balance of 2009.
LIQUIDITY AND CAPITAL RESOURCES
Our ability to finance operations, fund maintenance capital expenditures and pay distributions will largely depend on our ability to generate sufficient cash flow to cover these requirements. Our ability to generate cash flow is subject to a number of factors, some of which are beyond our control. Please read Item 1A—Risk Factors of our annual report on Form 10-K.
Prior to our initial public offering, our sources of liquidity included cash generated from operations and funding from Anadarko. Furthermore, we participated in Anadarko’s cash management program, whereby Anadarko, on a periodic basis, swept cash balances residing in our bank accounts. Thus, our historical consolidated financial statements for periods ending prior to our initial public offering reflect no significant cash balances. Unlike our transactions with third parties, which ultimately are settled in cash, our affiliate transactions prior to our acquisition of the Partnership Assets were settled on a net basis through an adjustment to parent net equity. Subsequent to our initial public offering, we maintain our own bank accounts and sources of liquidity. Although we continue to utilize Anadarko’s cash management system, our cash accounts are not subject to cash sweeps by Anadarko.
Our sources of liquidity as of September 30, 2009 include:
    approximately $40.8 million of working capital as of September 30, 2009, which we define as the amount by which current assets exceed current liabilities;
 
    cash generated from operations;
 
    available borrowings of up to $100.0 million under Anadarko’s credit facility;
 
    available borrowings under our $30.0 million working capital facility with Anadarko;
 
    interest income from our $260.0 million note receivable from Anadarko; and
 
    issuances of additional partnership units.
In addition, we entered into a $350.0 million three-year revolving Credit Facility in October 2009. See Note 14—Subsequent Events — Revolving credit facility of the notes to unaudited consolidated financial statements included under Part I, Item 1 of this Form 10-Q. We believe that cash generated from these sources will be sufficient to satisfy our short-term working capital requirements and long-term maintenance capital expenditure requirements. The amount of future distributions to unitholders will depend on earnings, financial conditions, capital requirements and other factors, and will be determined by the board of directors of our general partner on a quarterly basis.

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Working capital
Working capital, defined as the amount by which current assets exceed current liabilities, is an indication of our liquidity and potential need for short-term funding. Our working capital requirements are driven by changes in accounts receivable and accounts payable. These changes are primarily impacted by factors such as credit extended to, and the timing of collections from, our customers and the level and timing of our spending for maintenance and expansion activity.
Historical cash flow
The following table and discussion presents a summary of our net cash flows from operating activities, investing activities and financing activities as well as Adjusted EBITDA for the three and nine months ended September 30, 2009 and 2008.
For periods prior to May 14, 2008, with respect to the initial assets, and prior to December 19, 2008, with respect to the Powder River assets, our net cash from operating activities and capital contributions from our Parent were used to service our cash requirements, which included the funding of operating expenses and capital expenditures. Subsequent to May 14, 2008, with respect to our initial assets, and subsequent to December 19, 2008, with respect to the Powder River assets, transactions with Anadarko and third parties are cash-settled. Prior to June 1, 2008 with respect to Chipeta, sales and purchases related to third-party transactions were received or paid in cash by Anadarko within its centralized cash management system and were settled with Chipeta through an adjustment to parent net equity. Subsequent to June 1, 2008, Chipeta cash-settled transactions directly with third parties and with Anadarko affiliates.
                                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     D     2009     2008     D  
    (in thousands, except percentages)  
Net cash provided by (used in):
                                               
Operating activities
  $ 21,444     $ 45,793       (53 )%   $ 79,651     $ 104,715       (24 )%
Investing activities
    (107,615 )     (31,505 )     242 %     (143,215 )     (337,025 )     (58 )%
Financing activities
    100,029       10,413       861 %     83,513       283,700       (71 )%
 
                                       
Net increase in cash and cash equivalents
  $ 13,858     $ 24,701       (44 )%   $ 19,949     $ 51,390       (61 )%
Adjusted EBITDA (1)
  $ 26,404     $ 30,488       (13 )%   $ 81,542     $ 93,633       (13 )%
 
(1)   For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please see above within this Item 2 under the caption How We Evaluate Our Operations.
Operating Activities. Net cash provided by operating activities decreased by $24.3 million and $25.1 million for the three months ended September 30, 2009 and for the nine months ended September 30, 2009, respectively, primarily attributable to changes in working capital, lower throughput and gross margins, and higher general and administrative expenses as described in Results of Operations—Overview above. For the nine months ended September 30, 2009, these items were partially offset by lower current income taxes, higher net interest income and lower operations and maintenance expenses as described in Results of Operations—Overview above.
Investing Activities. Net cash used in investing activities increased by $76.1 million for the three months ended September 30, 2009 and decreased by $193.8 million for the nine months ended September 30, 2009, respectively. Net cash used in investing activities for the three and nine months ended September 30, 2009 includes the $101.5 million cash consideration paid for the Chipeta acquisition. Net cash used in investing activities for the nine months ended September 30, 2008 includes our $260.0 million loan made to Anadarko in connection with our initial public offering. In addition, capital expenditures decreased by $22.9 million and $27.4 million for the three months ended September 30, 2009 and for the nine months ended September 30, 2009, respectively. Capital expenditures include costs attributable to the Chipeta assets prior to the Chipeta acquisition and include the noncontrolling interest owners’ share of Chipeta’s capital expenditures. Expansion capital expenditures decreased by 89%, from $24.1 million during the three months ended September 30, 2008 to $2.8 during the three months ended September 30, 2009, primarily due to payment of capital expenditures for the Chipeta cryogenic unit, expansion of the Bethel facility completed during 2008 and installation of a compressor station at the Hugoton system during 2008. In addition, maintenance capital expenditures decreased by 32%, from $5.0 million during the three months ended September 30, 2008 to $3.4 million during the three months ended September 30, 2009, primarily as a result of fewer well connections at the Haley and Pinnacle systems due to reduced drilling activity. Expansion capital expenditures decreased by

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50%, from $58.5 million during the nine months ended September 30, 2008 to $29.5 million during the nine months ended September 30, 2009, primarily due to paying capital expenditures during the full nine months ended September 30, 2008 for the Chipeta plant construction compared to paying the majority of capital expenditures for the cryogenic unit during the first six months of 2009, completion of expansions of the Bethel facility and at the Dew system during 2008 and completion of the NGL pipeline at the tailgate of the Chipeta plant during the second quarter of 2008. This decrease was partially offset by a 15% increase in maintenance capital expenditures, from $10.4 million during the nine months ended September 30, 2008 to $12.0 million during the nine months ended September 30, 2009, primarily due to a compression overhaul at our Hugoton System, an upgrade to the control system at the Hilight facility and equipment replacements at the Bethel facility during 2009, partially offset by fewer well connections at the Haley, Hugoton and Pinnacle systems due to reduced drilling activity. Investing cash flows included contributions to Fort Union of $8.1 million during the nine months ended September 30, 2009 related to the system expansion.
Financing Activities. Net cash provided by financing activities increased by $89.6 million for the three months ended September 30, 2009 and decreased by $200.2 million for the nine months ended September 30, 2009. Net cash provided by financing activities for the three and nine months ended September 30, 2009 included $101.5 million in loan proceeds from our term loan agreement with Anadarko which was entered into in connection with the Chipeta acquisition. Net cash provided by financing activities for the nine months ended September 30, 2008 included the receipt of $315.2 million of net proceeds from our initial public offering, partially offset by a $45.2 million reimbursement to Anadarko of offering proceeds. Financing proceeds for the three and nine months ended September 30, 2009 and for the three and nine months ended September 30, 2008 included $13.3 million, $36.0 million, $21.5 million and $42.1 million, respectively, of contributions from noncontrolling interest owners and Parent attributable to the Chipeta plant construction, for which the associated capital expenditures are included in investing activities above. Most of these contributions were received by Chipeta prior to our acquisition of a 51% interest in Chipeta. For the three and nine months ended September 30, 2009, $17.7 million and $51.8 million, respectively, of cash distributions were paid to our unitholders. Distributions to unitholders totaled $8.6 million during the three and nine months ended September 30, 2008, representing the partial distribution for the second quarter of 2008 following our May 2008 initial public offering. Distributions from Chipeta to noncontrolling interest owners and Parent totaled $5.7 million during the nine months ended September 30, 2009, representing the distribution of all of Chipeta’s available cash prior to our acquisition of a 51% interest in Chipeta. Distributions to noncontrolling interest owners and Parent totaled $19.7 million during the nine months ended September 30, 2008, representing the one-time distribution to Anadarko of part of the consideration paid by the third-party owner following the initial formation of Chipeta. Net distributions to Anadarko were $106.4 million for the nine months ended September 30, 2008, representing the net settlement of intercompany transactions attributable to the Powder River assets and Chipeta assets, compared to $1.2 million of net distributions to Anadarko during the nine months ended September 30, 2009, representing the net non-cash settlement of intercompany transactions attributable to the Chipeta assets.
Adjusted EBITDA. Adjusted EBITDA decreased by $4.1 million and $12.1 for the three months ended September 30, 2009 and for the nine months ended September 30, 2009, respectively. The decrease for the three months ended September 30, 2009 is primarily due to a $33.8 million decrease in total revenues, excluding equity income and a $1.2 million increase in general and administrative expenses, excluding non-cash equity-based compensation, partially offset by a $28.0 million decrease in cost of product, a $2.3 million decrease in operation and maintenance expenses and an approximately $0.8 million decrease in the noncontrolling interest owners’ share of Adjusted EBITDA. The decrease for the nine months ended September 30, 2009 is primarily due to a $97.9 million decrease in total revenues, excluding equity income, a $3.6 million increase in general and administrative expenses, excluding non-cash equity-based compensation, and a $2.0 million increase in the noncontrolling interest owners’ share of Adjusted EBITDA, partially offset by a $86.7 million decrease in cost of product, a $4.7 million decrease in operation and maintenance expenses and an approximately $0.5 million increase in distributions from Fort Union.
Capital requirements
Our business can be capital intensive, requiring significant investment to maintain and improve existing facilities. We categorize capital expenditures as either:
    maintenance capital expenditures, which include those expenditures required to maintain the existing operating capacity and service capability of our assets, including the replacement of system components and equipment that have suffered significant wear and tear, become obsolete or approached the end of their useful lives, those

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      expenditures necessary to remain in compliance with regulatory or legal requirements or those expenditures necessary to complete additional well connections to maintain existing system volumes and related cash flows; or
    expansion capital expenditures, which include those expenditures incurred in order to extend the useful lives of our assets, reduce costs, increase revenues or increase gathering, processing, treating and transmission throughput or capacity from current levels, including well connections that increase existing system volumes.
Total capital incurred for the nine months ended September 30, 2009 and 2008 was $38.0 million and $80.3 million, respectively. Capital incurred is presented on an accrual basis. Capital expenditures in the consolidated statement of cash flows reflect capital expenditures on a cash basis, when payments are made. Capital expenditures for the nine months ended September 30, 2009 and 2008 were $41.5 million and $68.9 million, respectively. Capital expenditures for the nine months ended September 30, 2009 include $23.6 million attributable to the Chipeta assets prior to the Chipeta acquisition and include the noncontrolling interest owners’ share of Chipeta’s capital expenditures which were funded by contributions from the noncontrolling interest owners. Expansion capital expenditures represented approximately 71% and 85% of total capital expenditures for the nine months ended September 30, 2009 and 2008, respectively. We estimate our total capital expenditures, excluding any future acquisitions, to be $55.0 million to $59.0 million and our maintenance capital expenditures to be approximately 30% of total capital expenditures for the twelve months ending December 31, 2009. Our future expansion capital expenditures may vary significantly from period to period based on the investment opportunities available to us, which are dependent, in part, on the drilling activities of Anadarko and third-party producers. From time to time, for projects with significant risk or capital exposure, we may secure indemnity provisions or throughput agreements. We expect to fund future capital expenditures from cash flows generated from our operations, interest income from our note receivable from Anadarko, borrowings under our revolving Credit Facility or Anadarko’s credit facility, the issuance of additional partnership units or debt offerings.
Distributions to unitholders
We expect to pay a quarterly distribution of $0.32 per unit per full quarter, which equates to approximately $18.3 million per full quarter, or approximately $73.2 million per full year, based on the number of common, subordinated and general partner units outstanding as of October 31, 2009. Our partnership agreement requires that the Partnership distribute all of its available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date. During the nine months ended September 30, 2009, the Partnership paid cash distributions to its unitholders of approximately $51.8 million, representing the $0.31 per unit distribution for the quarter ended June 20, 2009 and $0.30 per unit distributions for each of the quarters ended March 31, 2009 and December 31, 2008. On October 20, 2009, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.32 per unit, or $18.3 million in aggregate. The cash distribution is payable on November 13, 2009 to unitholders of record at the close of business on October 30, 2009.
Our borrowing capacity under Anadarko’s credit facility
On March 4, 2008, Anadarko entered into a $1.3 billion credit facility under which we are a co-borrower. This credit facility is available for borrowings and letters of credit and permits us to utilize up to $100.0 million under the facility for general partnership purposes, including acquisitions, but only to the extent that sufficient amounts remain unborrowed by Anadarko. At September 30, 2009, the full $100.0 million was available for borrowing by us. The $1.3 billion credit facility expires in March 2013.
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, 2009, 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, 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, if any) that Anadarko incurs under its credit facility, or up to $0.1 million annually. Under Anadarko’s credit facilities, we and Anadarko are required to comply with certain covenants, including a financial covenant that requires Anadarko to maintain a debt-to-capitalization ratio of 60% or less. As of September 30, 2009, we and Anadarko were in compliance with all covenants. Should we or Anadarko fail to comply with any covenant in Anadarko’s credit facilities, we may not be permitted to borrow thereunder. Anadarko is a guarantor of our borrowings, if any, under the credit facility. We are not a guarantor of Anadarko’s borrowings under the credit facility.

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Our working capital facility
Concurrent with the closing of our initial public offering, we entered into a two-year, $30.0 million working capital facility with Anadarko as the lender. At September 30, 2009, no borrowings were outstanding under the working capital facility. The facility is available exclusively to fund working capital needs. Borrowings under the facility will bear interest at the same rate as would apply to borrowings under the Anadarko credit facility described above. We 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.
We are required to reduce all borrowings under our working capital facility to zero for a period of at least 15 consecutive days at least once during each of the twelve-month periods prior to the maturity date of the facility.
Revolving credit facility
On October 29, 2009, we entered into a three-year senior unsecured revolving credit facility with a group of banks (the “Credit Facility”). The aggregate initial commitments of the lenders under the Credit Facility are $350.0 million and are expandable to a maximum of $450.0 million. The Credit Facility matures on October 29, 2012 and bears interest at LIBOR plus applicable margins ranging from 2.375% to 3.250%, or an alternate base rate, based upon (i) the greater of the Prime Rate, the Federal Funds Rate plus 0.5%, and LIBOR plus 0.5% plus (ii) applicable margins ranging from 1.375% to 2.250%.
The Credit Facility contains various covenants that limit, among other things, our, and certain of our subsidiaries’, ability to incur indebtedness, grant certain liens, merge, consolidate or allow any material change in the character of its business, sell all or substantially all of our assets, make certain transfers, enter into certain affiliate transactions, make distributions or other payments other than distributions of available cash under certain conditions and use proceeds other than for partnership purposes. If we obtain two of the following three ratings: BBB- or better by Standard and Poor’s, Baa3 or better by Moody’s Investors Service or BBB- or better by Fitch Ratings Ltd. (the date of such ratings being the “Investment Grade Rating Date”), we will no longer be required to comply with certain of the foregoing covenants. The Credit Facility also contains customary events of default, including (i) nonpayment of principal when due or nonpayment of interest or other amounts within three business days of when due; (ii) bankruptcy or insolvency with respect to the Borrower or any material subsidiary; or (iii) a change of control. All amounts due by us under the Credit Facility are unconditionally guaranteed by certain of our wholly owned subsidiaries. The subsidiary guarantees will automatically terminate on the Investment Grade Rating Date.
On October 30, 2009, we used $100.0 million of our capacity under the Credit Facility along with $2.0 million of cash on hand to refinance our $101.5 million, 7.00% fixed-rate, three-year term loan and settle related accrued interest. We entered into the three-year term loan agreement with Anadarko in July 2009 to finance a portion of the Chipeta acquisition.
Credit risk
We bear credit risk represented by our exposure to non-payment or non-performance by our customers, including Anadarko. Generally, non-payment or non-performance results from a customer’s inability to satisfy receivables for services rendered or volumes owed pursuant to gas imbalance agreements. We examine and monitor the creditworthiness of third-party customers and may establish credit limits for significant third-party customers.
We are dependent upon a single producer, Anadarko, for the majority of our natural gas volumes and we do not maintain a credit limit with respect to Anadarko. Consequently, we are subject to the risk of non-payment or late payment by Anadarko for gathering, treating and transmission fees and for proceeds from the sale of natural gas, NGLs and condensate to Anadarko.
We expect our exposure to concentrated risk of non-payment or non-performance to continue for as long as we remain substantially dependent on Anadarko for our revenues. Additionally, we are exposed to credit risk on the note receivable from Anadarko that was issued concurrent with the closing of our initial public offering. We are also party to an omnibus agreement with Anadarko under which Anadarko is required to indemnify us for certain environmental claims, losses arising from rights-of-way claims, failures to obtain required consents or governmental permits and income taxes with respect to the initial assets. Finally, we entered into commodity price swap agreements with Anadarko in order to substantially reduce our exposure to commodity price risk attributable to our percent-of-proceeds contracts for the Hilight system and the Newcastle system and are subject to performance risk thereunder.

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If Anadarko becomes unable to perform under the terms of our gathering, processing and transportation agreements, natural gas and NGL purchase agreements, its note payable to us, the omnibus agreement, the services and secondment agreement or the commodity price swap agreements, our ability to make distributions to our unitholders may be adversely impacted.
CONTRACTUAL OBLIGATIONS
Our contractual obligations include notes payable to Anadarko and credit facilities, for which information is provided in Note 10Debt and Note 14—Subsequent Events, included in the notes to unaudited consolidated financial statements included under Part I, Item 1 of this Form 10-Q, and a plant purchase commitment, for which information is provided in Note 12Commitments and Contingencies, included in the notes to unaudited consolidated financial statements included under Part I, Item 1 of this Form 10-Q. Our contractual obligations also include an office lease and asset retirement obligations which have not changed significantly since December 31, 2008 and for which information is provided under Management’s Discussion and Analysis of Financial Condition and Results of OperationsContractual Obligations in Part II, Item 7 of our annual report on Form 10-K, as filed with the SEC on March 13, 2009.
OFF-BALANCE SHEET ARRANGEMENTS
We do not have any off-balance sheet arrangements other than operating leases. The information pertaining to operating leases required for this item is provided under Management’s Discussion and Analysis of Financial Condition and Results of OperationsContractual Obligations in Part II, Item 7 of our annual report on Form 10-K.
Item 3.   Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
We bear a limited degree of commodity price risk with respect to certain of our gathering and processing contracts. Specifically, pursuant to certain of our contracts, we retain and sell drip condensate that is recovered during the gathering of natural gas. As part of this arrangement, we are required to provide a thermally equivalent volume of natural gas or the cash equivalent thereof to the shipper. Thus, our revenues for this portion of our contractual arrangement are based on the price received for the drip condensate and our costs for this portion of our contractual arrangement depend on the price of natural gas. Historically, drip condensate sells at a price representing a slight discount to the price of NYMEX West Texas Intermediate crude oil.
In addition, certain of our processing services are provided under percent-of-proceeds agreements in which Anadarko is typically responsible for the marketing of the natural gas and NGLs. Under these agreements, we receive a specified percentage of the net proceeds from the sale of natural gas and NGLs. To mitigate our exposure to changes in commodity prices on these processing agreements, we entered into commodity price swap agreements with Anadarko with fixed commodity prices that extend through December 31, 2010, with an option to extend through 2013. For additional information on the commodity price swap agreements, see Note 6—Transactions with Affiliates included in the notes to unaudited consolidated financial statements included under Part I, Item 1 of this Form 10-Q.
We consider our exposure to commodity price risk associated with the above-described arrangements to be minimal given the relatively small amount of our operating income generated by drip condensate sales and the existence of the commodity price swap agreements with Anadarko. For the three months ended September 30, 2009, a 10% change in the margin between drip condensate and natural gas would have resulted in an approximate $293,000, or less than 1%, change in operating income for the period.
We also bear a limited degree of commodity price risk with respect to settlement of our natural gas imbalances that arise from differences in gas volumes received into our systems and gas volumes delivered by us to customers. Natural gas volumes owed to or by us 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 us are valued at our weighted average cost of natural gas as of the balance sheet dates and are settled in-kind. Our exposure to the impact of changes in commodity prices on outstanding imbalances depends on the timing of settlement of the imbalances.
Interest Rate Risk
Interest rates during the periods discussed above were low compared to rates over the last 50 years. If interest rates rise, our future financing costs will increase. As of September 30, 2009, we owed an aggregate of $276.5 million to Anadarko under

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our five-year term loan we entered into in connection with the Powder River acquisition and the three-year term loan we entered into in connection with the Chipeta acquisition. In addition, we had $100.0 million of credit available for borrowing under Anadarko’s five-year credit facility in addition to $30.0 million available under our two-year working capital facility with Anadarko. Our $175.0 million term loan agreement with Anadarko requires us to pay interest at a fixed rate of 4.0% for the first two years and a floating rate, three-month LIBOR plus 150 basis points, for the final three years. Our $101.5 million term loan agreement with Anadarko required us to pay interest at a fixed rate of 7.00%; however, on October 30, 2009, we used $100.0 million of our capacity under the Credit Facility along with $2.0 million of cash on hand to refinance the $101.5 million term loan with Anadarko and settle related accrued interest. The Credit Facility bears interest at LIBOR plus an initial margin of 3.00%. Interest on borrowings under Anadarko’s 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, 2009, is based on Anadarko’s senior unsecured long-term debt rating. Borrowings under our working capital facility bear interest at the same rate that would apply to borrowings under the Anadarko credit facility. We may incur additional debt in the future, either under the Credit Facility, our $30.0 million working capital facility with Anadarko, our $100.0 million borrowing capacity under Anadarko’s existing credit facility or other financing sources, including commercial bank borrowings or debt issuances.
Item 4T.   Controls and Procedures
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
We carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Securities Exchange Act Rule 13a-15. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of the end of the third quarter of 2009, our disclosure controls and procedures were effective to provide reasonable assurance that material information required to be disclosed by us in reports that we file or submit under the Securities Exchange Act of 1934 is appropriately recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
Changes in Internal Control Over Financial Reporting
There has been no change in our internal control over financial reporting during the quarter ended September 30, 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1.   Legal Proceedings
We are not a party to any legal proceeding other than legal proceedings arising in the ordinary course of our business. We are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business. Management believes that there are no such proceedings for which final disposition could have a material adverse effect on our results of operations, cash flows or financial position.
Item 6.   Exhibits
Exhibits are listed below in the Exhibit Index of this report on Form 10-Q.

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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
         
     
Date: November 12, 2009  By:   /s/ Robert G. Gwin    
    Robert G. Gwin   
    Chairman and Chief Executive Officer
Western Gas Holdings, LLC
(as general partner of Western Gas Partners, LP) 
 
 
     
Date: November 12, 2009  By:   /s/ Benjamin M. Fink    
    Benjamin M. Fink   
    Senior Vice President and Chief Financial Officer
Western Gas Holdings, LLC
(as general partner of Western Gas Partners, LP) 
 

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EXHIBIT INDEX
Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.
     
2.1
  Contribution, Conveyance and Assumption Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, Anadarko Petroleum Corporation, WGR Holdings, LLC, Western Gas Resources, Inc., WGR Asset Holding Company LLC, Western Gas Operating, LLC and WGR Operating, LP, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
 
   
2.2
  Contribution Agreement, dated as of November 11, 2008, by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on November 12, 2008, File No. 001-34046).
 
   
2.3
  Contribution Agreement, dated as of July 10, 2009, by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, Anadarko Uintah Midstream, LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, WES GP, Inc., Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 23, 2009, File No. 001-34046).
 
   
3.1
  Certificate of Limited Partnership of Western Gas Partners, LP (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on October 15, 2007, File No. 333-146700).
 
   
3.2
  First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated May 14, 2008 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
 
   
3.3
  Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated as of December 19, 2008 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 24, 2008, File No. 001-34046).
 
   
3.4
  Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated as of April 15, 2009 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on April 20, 2009, File No. 001-34046).
 
   
3.5
  Amendment No. 3 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP dated July 22, 2009 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 23, 2009, File No. 001-34046).
 
   
3.6
  Certificate of Formation of Western Gas Holdings, LLC (incorporated by reference to Exhibit 3.3 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on October 15, 2007, File No. 333-146700).
 
   
3.7
  Amended and Restated Limited Liability Company Agreement of Western Gas Holdings, LLC, dated as of May 14, 2008 (incorporated by reference to Exhibit 3.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
 
   
4.1
  Specimen Unit Certificate for the Common Units (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on June 13, 2008, File No. 001-34046).
 
   
10.1
  Term Loan Agreement due 2012 dated as of July 22, 2009 by and between Anadarko Petroleum Corporation and Western Gas Partners, LP (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 23, 2009, File No. 001-34046).
 
   
10.2
  Amendment No. 2 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of July 22, 2009 (incorporated by reference to Exhibit 10.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 23, 2009, File No. 001-34046).

 


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10.3*+
  Gas Processing Agreement between Chipeta Processing LLC and Kerr-McGee Oil & Gas Onshore LP dated September 6, 2008.
 
   
10.4*+
  Amended and Restated Limited Liability Company Agreement of Chipeta Processing LLC effective July 23, 2009.
 
   
10.5
  Revolving Credit Agreement, dated as of October 29, 2009, among Western Gas Partners, LP, Wells Fargo Bank National Association, as the administrative agent and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on October 30, 2009, File No. 001-34046)
 
   
31.1*
  Certification of Chief Executive Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
31.2*
  Certification of Chief Financial Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
32.1*
  Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
   
+
  Confidential treatment has been requested for certain confidential portions of this exhibit pursuant to Rule 24b-2 under the Securities Exchange Act of 1934. In accordance with Rule 24b-2, these confidential portions have been omitted from this exhibit and filed separately with the Securities and Exchange Commission.