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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
Form 10-K
 
 
     
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the fiscal year ended December 31, 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
  26-1075808
(State or other jurisdiction of
incorporation or organization)
  (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)
 
Securities registered pursuant to Section 12(b) of the Act:
 
     
Title of Each Class
 
Name of Each Exchange on Which Registered
 
Common Units Representing Limited Partner Interests
  New York Stock Exchange
 
Securities registered pursuant to Section 12(g) of the Act:
None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes o     No þ
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ
 
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
             
Large accelerated filer o
       Accelerated filer þ   Non-accelerated filer o   Smaller reporting company o
    (Do not check if a smaller reporting company)     
 
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
 
The aggregate market value of the Partnership’s common units representing limited partner interests held by non-affiliates of the registrant was approximately $316.0 million on June 30, 2009 based on the closing price as reported on the New York Stock Exchange.
 
At March 1, 2010, there were 36,995,614 common units outstanding.
 
DOCUMENTS INCORPORATED BY REFERENCE
None
 


Table of Contents

 
TABLE OF CONTENTS
 
             
Item
      Page
 
  Business and Properties     5  
      General Overview     5  
      Our Assets and Areas of Operations     6  
      Recent Developments     6  
      Acquisitions     7  
      Strategy     8  
      Competitive Strengths     8  
      Our Relationship with Anadarko Petroleum     9  
      Industry Overview     10  
      Properties     12  
      Competition     17  
      Safety and Maintenance     18  
      Regulation of Operations     19  
      Environmental Matters     23  
      Title to Properties and Rights-of-Way     26  
      Employees     26  
1A.
  Risk Factors     27  
1B.
  Unresolved Staff Comments     53  
3.
  Legal Proceedings     53  
4.
  Reserved     54  
 
PART II
5.
  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     54  
      Market Information     54  
      Use of Proceeds From Sale of Securities     54  
      Selected Information From Our Partnership Agreement     55  
      Other Securities Matters     56  
6.
  Selected Financial and Operating Data     56  
7.
  Management’s Discussion and Analysis of Financial Condition and Results of Operations     58  
      Overview     58  
      Operating and Financial Highlights     58  
      Acquisitions     59  
      Our Operations     60  
      How We Evaluate Our Operations     61  
      Items Affecting the Comparability of Our Financial Results     65  
      General Trends and Outlook     68  
      Results of Operations — Overview     70  
        Operating Results     70  
        Liquidity and Capital Resources     80  
        Contractual Obligations     85  
      Critical Accounting Policies and Estimates     85  
      Off-Balance Sheet Arrangements     87  
      Recent Accounting Developments     87  
7A.
  Quantitative and Qualitative Disclosures About Market Risk     87  
8.
  Financial Statements and Supplementary Data     88  
9.
  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     88  
9A.
  Disclosure Controls and Procedures     88  


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Item
      Page
 
PART III
10.
  Directors, Executive Officers and Corporate Governance     89  
11.
  Executive Compensation     97  
12.
  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     120  
13.
  Certain Relationships and Related Transactions, and Director Independence     123  
14.
  Principal Accountant Fees and Services     131  
 
PART IV
15.
  Exhibits     132  
 EX-12.1
 EX-21.1
 EX-23.1
 EX-31.1
 EX-31.2
 EX-32.1


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DEFINITIONS
 
As generally used within the energy industry and in this annual report on Form 10-K, the identified terms have the following meanings:
 
Backhaul:  Pipeline transportation service in which the nominated gas flow from delivery point to receipt point is in the opposite direction as the pipeline’s physical gas flow.
 
Barrel or Bbl:  42 U.S. gallons measured at 60 degrees Fahrenheit.
 
Bcf/d:  One billion cubic feet per day.
 
Btu:  British thermal unit; the approximate amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
 
CO2:  Carbon dioxide.
 
Condensate:  A natural gas liquid with a low vapor pressure mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.
 
Delivery point:  The point where gas or natural gas liquids are delivered by a processor or transporter to a producer, shipper or purchaser, typically the inlet at the interconnection between the gathering or processing system and the facilities of a third-party processor or transporter.
 
Drip condensate:  Heavier hydrocarbon liquids that fall out of the natural gas stream and are recovered in the gathering system without processing.
 
Dry gas:  A gas primarily composed of methane and ethane where heavy hydrocarbons and water either do not exist or have been removed through processing.
 
End-use markets:  The ultimate users/consumers of transported energy products.
 
Forward-haul:  Pipeline transportation service in which the nominated gas flow from receipt point to delivery point is in the same direction as the pipeline’s physical gas flow.
 
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:  Long tons 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. All volumes presented herein are based on a standard pressure base of 14.73 pounds per square inch, absolute.
 
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.
 
Play:  A group of gas or oil fields that contain known or potential commercial amounts of petroleum and/or natural gas.
 
Pounds per square inch, absolute:  The pressure resulting from a one pound-force applied to an area of one square inch, including local atmospheric pressure.


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Receipt point:  The point where production is received by or into a gathering system, processing facility or transportation pipeline.
 
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.
 
Tailgate:  The point at which processed natural gas and/or natural gas liquids leave a processing facility for end-use markets.
 
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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WESTERN GAS PARTNERS, LP
 
PART I
 
Items 1 and 2.  Business and Properties
 
GENERAL OVERVIEW
 
Western Gas Partners, LP is a growth-oriented Delaware master limited partnership, or “MLP,” organized by Anadarko Petroleum Corporation in 2008 to own, operate, acquire and develop midstream energy assets. Our common units are publicly-traded and listed on the New York Stock Exchange under the symbol “WES.” With midstream assets in East and West Texas, the Rocky Mountains and the Mid-Continent, we are engaged in the business of gathering, compressing, treating, processing and transporting natural gas for Anadarko, as defined below, and other producers and customers.
 
Unless the context clearly indicates otherwise, references in this report to the “Partnership,” “we,” “our,” “us” or like terms, when used in the present tense or prospectively, refer to Western Gas Partners, LP and its consolidated subsidiaries. References in this report to the “Partnership,” “we,” “our,” “us” or like terms, when used in the historical context, refer to the combined financial results and operations of Anadarko Gathering Company LLC and Pinnacle Gas Treating LLC from their inception through the closing date of our initial public offering and to Western Gas Partners, LP and its subsidiaries thereafter, combined with the financial results and operations of MIGC LLC and the Powder River assets, as described in Acquisitions-Powder River Acquisition below, from August 23, 2006 thereafter, and combined with the financial results and operations of the Chipeta assets, as described in Acquisitions-Chipeta Acquisition below, from August 10, 2006 thereafter.
 
“Anadarko” refers to Anadarko Petroleum Corporation (NYSE: APC) and its consolidated subsidiaries, excluding the Partnership and Western Gas Holdings, LLC, our general partner. “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. “Anadarko Petroleum Corporation” refers to Anadarko Petroleum Corporation excluding its subsidiaries and affiliates. “AGC” refers to Anadarko Gathering Company LLC, “PGT” refers to Pinnacle Gas Treating LLC, “MIGC” refers to MIGC LLC and “Chipeta” refers to Chipeta Processing LLC. Each of AGC, PGT, MIGC, Chipeta, our general partner and the Partnership is an indirect subsidiary of Anadarko.
 
Based on throughput for the year ended December 31, 2009, approximately 98% of our services are provided under long-term contracts with fee-based rates and approximately 2% of our services are provided under percent-of-proceeds contracts. We have entered into fixed-price swap agreements with Anadarko to manage the future commodity price risk otherwise inherent in our percent-of-proceeds contracts. A substantial part of our business is conducted with Anadarko and governed by contracts which were entered into during 2008 with an initial term of 10 years.
 
We believe that one of our principal strengths is our relationship with Anadarko. Over 79% of our total natural gas gathering, processing and transportation throughput was comprised of natural gas production owned or controlled by Anadarko during the year ended December 31, 2009. In addition and solely with respect to the gathering systems connected to our initial assets, Anadarko has dedicated to us all of the natural gas production it owns or controls from (i) wells that are currently connected to such gathering systems, and (ii) additional wells that are drilled within one mile of wells connected to these gathering systems, as those systems currently exist and as they are expanded to connect additional wells in the future. As a result, this dedication will continue to expand as additional wells are connected to these gathering systems.
 
Available Information.  We file our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and other documents electronically with the U.S. Securities and Exchange Commission, or the “SEC,” under the Securities Exchange Act of 1934. From time-to-time, we may also file registration and related statements pertaining to equity or debt offerings. We provide access free of charge to all of these SEC filings, as soon as reasonably practicable after filing or furnishing, on our Internet site located at www.westerngas.com. The public may also read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, DC 20549. The public may obtain


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information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The public may also obtain such reports from the SEC’s Internet website at www.sec.gov.
 
Our Corporate Governance Guidelines, Code of Ethics for our Chief Executive Officer and Senior Financial Officers, Code of Business Conduct and Ethics and the charters of the audit committee and the special committee of our general partner’s board of directors are also available on our Internet website. We will also provide, free of charge, a copy of any of our governance documents listed above upon written request to our general partner’s corporate secretary at our principal executive office. Our principal executive offices are located at 1201 Lake Robbins Drive, The Woodlands, TX 77380-1046. Our telephone number is 832-636-6000.
 
OUR ASSETS AND AREAS OF OPERATION
 
As of December 31, 2009, our assets consist of nine gathering systems, six natural gas treating facilities, four gas processing facilities, one NGL pipeline and one interstate pipeline that is regulated by the Federal Energy Regulatory Commission or “FERC.” Our assets are located in East and West Texas, the Rocky Mountains and the Mid-Continent. The following table provides information regarding our assets by geographic region as of or for the year ended December 31, 2009:
 
                                             
                        Average Gathering,
                    Processing or
  Processing and
            Approximate
  Gas
  Treating
  Transportation
            Number of
  Compression
  Capacity
  Throughput
Area
 
Asset Type
  Miles of Pipelines   Receipt Points   (Horsepower)   (MMcf/d)   (MMcf/d)
 
East Texas
  Gathering and Treating     589       827       44,855       502       389  
West Texas
  Gathering     116       90       560             154  
Rocky Mountains
  Gathering and Treating(1)     428       179       25,839       387       175  
    Gathering and Processing(2)     1,350       699       88,838       703       395  
    Transportation     256       16       29,696             165  
Mid-Continent
  Gathering     2,034       1,536       102,257             121  
                                             
Total
        4,773       3,347       292,045       1,592       1,399  
                                             
 
 
(1) Throughput includes the Partnership’s 14.81% share of Fort Union Gas Gathering, L.L.C.’s gross volumes.
 
(2) Throughput consists of 100% of Chipeta and Hilight plant volumes and 50% of Newcastle plant volumes.
 
Our operations are organized into a single business segment which engages in gathering, compressing, processing, treating and transporting Anadarko and third-party natural gas production in the United States.
 
RECENT DEVELOPMENTS
 
Revolving Credit Facility.  In October 2009, we entered into a three-year senior unsecured revolving credit facility with aggregate initial commitments of $350.0 million, which can be expanded to a maximum of $450.0 million. This revolving credit facility matures on October 29, 2012 and bears interest at the applicable London Interbank Offered Rate, or “LIBOR,” plus applicable margins ranging from 2.375% to 3.250%. We are also required to pay a quarterly facility fee ranging from 0.375% to 0.750% of the commitment amount (whether used or unused), based upon our consolidated leverage ratio, as defined in the revolving credit facility.
 
2009 Equity Offering.  On December 9, 2009, we closed a public offering of 6,000,000 common units at a price of $18.20 per unit. On December 17, 2009, we issued an additional 900,000 common units to the public pursuant to the full exercise of the underwriters’ over-allotment option granted in connection with that offering. We refer to the December 9 and December 17, 2009 issuances collectively as the “2009 equity offering.” Net proceeds from the offering of approximately $122.5 million were used to repay $100.0 million outstanding under our revolving credit facility and to partially fund the Granger acquisition in January 2010.


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See Note 13 — Subsequent Events — Granger acquisition of the notes to the consolidated financial statements under Item 8 of this annual report.
 
ACQUISITIONS
 
We have made the following acquisitions from Anadarko:
 
Initial Assets Acquisition.  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. The May 14 and June 11, 2008 issuances are referred to collectively as the “initial public offering.” Concurrent with the May 2008 closing of our initial public offering, Anadarko contributed the assets and liabilities of AGC, PGT, and 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.
 
Chipeta Acquisition.  In July 2009, we acquired a 51% membership interest in Chipeta, together with an associated NGL pipeline, from Anadarko. Chipeta owns a natural gas processing plant complex, which includes two 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 completed in April 2009. We refer to the 51% membership interest in Chipeta and associated NGL pipeline collectively as the “Chipeta assets” and the acquisition is referred to as the “Chipeta acquisition.” In November 2009, Chipeta closed its $9.1 million acquisition from a third party of a compressor station and processing plant, or the “Natural Buttes plant,” which was known as the CIG 101 plant prior to the acquisition. The Natural Buttes plant is located in Uintah County, Utah and provides up to 180 MMcf/d of incremental refrigeration processing capacity.
 
Granger Acquisition.  In January 2010, we acquired the following assets from Anadarko: (i) the Granger gathering system, a 750-mile gathering system with related compressors and other facilities, and (ii) the Granger complex, consisting of two cryogenic trains with combined capacity of 200 MMcf/d, two refrigeration trains with combined capacity of 145 MMcf/d, an NGLs fractionation facility with capacity of 9,500 barrels per day, and ancillary equipment. We refer to these assets collectively as the “Granger assets” and to the acquisition as the “Granger acquisition.” In connection with the acquisition, we entered into five-year, fixed-price commodity swap agreements with Anadarko which cover non-fee-based volumes processed at the Granger complex. The Granger acquisition was financed with $210.0 million of borrowings under the Partnership’s revolving credit facility plus $31.7 million of cash on hand, as well as through the issuance of 620,689 common units to Anadarko and 12,667 general partner units to our general partner. See Note 13 — Subsequent Events — Granger acquisition of the notes to the consolidated financial statements under Item 8 of this annual report.
 
Presentation of Partnership Acquisitions.  For purposes of this annual report, the assets in which we owned an interest as of December 31, 2009, which consist of 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


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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.
 
Because Anadarko owns our general partner, each acquisition of Partnership Assets, except for the Natural Buttes plant, was considered a transfer of net assets between entities under common control. As a result, after each acquisition of significant assets from Anadarko, we are required to revise our financial statements to include the activities of those assets as of the date of common control. Our historical financial statements for the years ended December 31, 2008 and December 31, 2007 as presented in our annual report on Form 10-K for the year ended December 31, 2008, which included the results attributable to the Powder River assets, have been recast to reflect the results attributable to the Chipeta assets as if the Partnership owned the 51% interest in Chipeta and associated midstream assets for all periods presented.
 
STRATEGY
 
Our primary business objective is to continue to increase our cash distributions per unit over time. We intend to accomplish this objective by executing the following strategy:
 
  •  Pursuing accretive acquisitions.  We expect to continue to pursue accretive acquisition opportunities within the midstream energy industry from Anadarko and third parties.
 
  •  Capitalizing on organic growth opportunities.  We expect to grow certain of our systems organically over time by meeting Anadarko’s and our other customers’ gathering, compression, treating, processing and transportation needs that result from their drilling activity in our areas of operation.
 
  •  Attracting third-party volumes to our systems.  We expect to continue actively marketing our midstream services to, and pursuing strategic relationships with, third-party producers with the intention of attracting additional volumes and/or expansion opportunities.
 
  •  Minimizing commodity price exposure.  We intend to continue to limit our direct exposure to commodity price changes. The majority of our midstream services are provided under fee-based arrangements. In addition, we entered into fixed-price swap agreements with Anadarko to manage commodity price risk otherwise associated with our percent-of-proceeds and keep-whole contracts.
 
COMPETITIVE STRENGTHS
 
We believe that we are well positioned to successfully execute our strategy and achieve our primary business objective because of the following competitive strengths:
 
  •  Affiliation with Anadarko.  We believe Anadarko, as the indirect owner of our general partner interest, all of the IDRs and, as of December 31, 2009, a 54.8% limited partner interest in us, is motivated to promote and support the successful execution of our business plan and to pursue projects that enhance the value of our business.
 
  •  Relatively stable and predictable cash flow.  Our cash flow is largely protected from fluctuations caused by commodity price volatility due to (i) the long-term nature of our fee-based agreements and (ii) fixed-price swap agreements which limit our exposure to commodity price changes with respect to our percent-of-proceeds and keep-whole contracts.
 
  •  Well-positioned, well-maintained and efficient assets.  We believe that our established positions in our areas of operation provide us with opportunities to expand and attract additional volumes to our systems. Moreover, our systems include high-quality, well-maintained assets for which we have implemented modern processing, treating, measuring and operating technologies.
 
  •  Financial flexibility to pursue expansion and acquisition opportunities.  As of December 31, 2009, we had $350.0 million of borrowing capacity available to us under our revolving credit facility, $100.0 million of borrowing capacity available to us under Anadarko’s $1.3 billion revolving credit facility and a


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  $30.0 million working capital facility with Anadarko. In December 2009, we raised $122.5 million of net proceeds through our first follow-on equity offering. On January 29, 2010, we borrowed $210.0 million under our revolving credit facility to partially fund the acquisition of the Granger assets from Anadarko. We believe our operating cash flow, borrowing capacity, ability to finance acquisitions through Anadarko and access to debt and equity capital markets provide us with the financial flexibility necessary to execute our strategy across capital-market cycles.
 
  •  Prudent capital management.  Our asset portfolio currently has relatively low capital expenditure requirements. Total capital expenditures for the years ended December 31, 2009 and 2008 were $62.2 million and $99.5 million, respectively, including approximately $30.8 million and $55.1 million, respectively, of expansion capital expenditures for the Chipeta assets prior to our acquisition of the assets. For the years ended December 31, 2009 and 2008, our maintenance capital expenditures, including 51% of Chipeta’s expenditures, were $15.9 million and $17.5 million, respectively.
 
  •  Experienced management team.  Members of our general partner’s management team have extensive experience in building, acquiring, integrating, financing and managing midstream assets. Since our initial public offering, we have expanded our executive management team to include Donald R. Sinclair, President and Chief Executive Officer, and Benjamin M. Fink, Senior Vice President and Chief Financial Officer. Our relationship with Anadarko also provides us with the services of experienced personnel who successfully managed our assets and operations while they were owned by Anadarko.
 
We believe that we will effectively leverage our competitive strengths to successfully implement our strategy; however, our business involves numerous risks and uncertainties which may prevent us from achieving our primary business objective. For a more complete description of the risks associated with our business, please read Item 1A of this annual report
 
OUR RELATIONSHIP WITH ANADARKO PETROLEUM CORPORATION
 
One of our principal strengths is our relationship with Anadarko. Our operations and activities are managed by our general partner, which is a wholly owned subsidiary of Anadarko. Anadarko Petroleum Corporation is among the largest independent oil and gas exploration and production companies in the world. Anadarko’s upstream oil and gas business explores for and produces natural gas, crude oil, condensate and natural gas liquids, or “NGLs.” We expect to utilize the significant experience of Anadarko’s management team to execute our growth strategy, which includes acquiring and constructing additional midstream assets.
 
As of December 31, 2009, Anadarko indirectly held 1,283,903 general partner units representing a 2.0% general partner interest in the Partnership and 100% of the Partnership IDRs through its ownership of our general partner, and 8,633,746 common units and 26,536,306 subordinated units, which comprise an aggregate 54.8% limited partner interest in the Partnership. The public held 27,741,179 common units, representing a 43.2% limited partner interest in the Partnership.
 
In connection with our initial public offering, we entered into an omnibus agreement with Anadarko and our general partner that governs our relationship with them regarding certain reimbursement and indemnification matters. Although we believe our relationship with Anadarko provides us with a significant advantage in the midstream natural gas market, it is also a source of potential conflicts. For example, Anadarko is not restricted from competing with us. Given Anadarko’s significant ownership of limited and general partner interests in us, we believe it will be in Anadarko’s best interest for it to transfer additional assets to us over time; however, Anadarko continually evaluates acquisitions and divestitures and may elect to acquire, construct or dispose of midstream assets in the future without offering us the opportunity to acquire, construct or participate in the ownership of those assets. Anadarko is under no contractual obligation to offer any such opportunities to us, nor are we obligated to participate in any such opportunities. We cannot state with any certainty which, if any, opportunities to acquire additional assets from Anadarko may be made available to us or if we will elect (or be able) to pursue any such opportunities. Please see Item 1A and Item 13 of this annual report for more information.


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INDUSTRY OVERVIEW
 
The midstream natural gas industry is the link between the exploration and production of natural gas and the delivery of its components to end-use markets. Operators within this industry create value at various stages along the natural gas value chain by gathering raw natural gas from producers at the wellhead, separating the hydrocarbons into dry gas (primarily methane) and NGLs, and then routing the separated dry gas and NGL streams for delivery to end-use markets or to the next intermediate stage of the value chain. The following diagram illustrates the groups of assets found along the natural gas value chain:
 
(GRAPHIC)
 
Service Types.  The services provided by us and other midstream natural gas companies are generally classified into the categories described below. As indicated below, we do not currently provide all of these services, although we may do so in the future.
 
  •  Gathering.  At the initial stages of the midstream value chain, a network of typically small diameter pipelines known as gathering systems directly connect to wellheads in the production area. These gathering systems transport raw, or untreated, natural gas to a central location for treating and processing. A large gathering system may involve thousands of miles of gathering lines connected to thousands of wells. Gathering systems are typically designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow gathering of additional production without significant incremental capital expenditures. In connection with our gathering services, we retain and sell drip condensate, which falls out of the natural gas stream during gathering.
 
  •  Compression.  Natural gas compression is a mechanical process in which a volume of natural gas at a given pressure is compressed to a desired higher pressure, which allows the natural gas to be delivered into a higher pressure system. Field compression is typically used to allow a gathering system to operate at a lower pressure or provide sufficient discharge pressure to deliver natural gas into a higher pressure system. Since wells produce at progressively lower field pressures as they deplete, field compression is needed to maintain throughput across the gathering system.
 
  •  Treating and Dehydration.  To the extent that gathered natural gas contains contaminants, such as water vapor, CO2 and/or hydrogen sulfide, such natural gas is dehydrated to remove the saturated water and treated to separate the CO2 and hydrogen sulfide from the gas stream.
 
  •  Processing.  Most decontaminated rich natural gas does not meet the quality standards for long-haul pipeline transportation or commercial use. Processing removes the heavier hydrocarbon components, which are extracted as NGLs.
 
  •  Fractionation.  Fractionation is the separation of the mixture of extracted NGLs into individual components for end-use sale. It is accomplished by controlling the temperature and pressure of the stream of mixed NGLs in order to take advantage of the different boiling points of separate products.
 
  •  Storage, Transportation and Marketing.  Once the raw natural gas has been treated or processed and the raw NGLs mix has been fractionated into individual NGL components, the natural gas and NGL components are stored, transported and marketed to end-use markets. Each pipeline system typically has storage capacity located both throughout the pipeline network and at major market centers to help temper seasonal demand and daily supply-demand shifts. We do not currently offer storage services or conduct marketing activities.


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Typical Contractual Arrangements.  Midstream natural gas services, other than transportation, are usually provided under contractual arrangements that vary in the amount of commodity price risk they carry. Three typical contract types are described below:
 
  •  Fee-Based.  Fee-based arrangements may be used for gathering, compression, treating and processing services. Under these arrangements, the service provider typically receives a fee for each unit of natural gas gathered and compressed at the wellhead and an additional fee per unit of natural gas treated or processed at its facility. As a result, the price per unit received by the service provider does not vary with commodity price changes, minimizing that service provider’s direct commodity price risk exposure.
 
  •  Percent-of-Proceeds, Percent-of-Value or Percent-of-Liquids.  Percent-of-proceeds, percent-of-value or percent-of-liquids arrangements may be used for gathering and processing services. Under these arrangements, the service provider typically remits to the producers either a percentage of the proceeds from the sale of residue gas and/or NGLs or a percentage of the actual residue gas and/or NGLs at the tailgate. These types of arrangements expose the processor to commodity price risk, as the revenues from the contracts directly correlate with the fluctuating price of natural gas and NGLs.
 
  •  Keep-Whole.  Keep-whole arrangements may be used for processing services. Under these arrangements, the service provider keeps 100% of the NGLs produced, and the processed natural gas, or value of the gas, is returned to the producer. Since some of the gas is used and removed during processing, the processor compensates the producer for the amount of gas used and removed in processing by supplying additional gas or by paying an agreed-upon value for the gas utilized. These arrangements have the highest commodity price exposure for the processor because the costs are dependent on the price of natural gas and the revenues are based on the price of NGLs.
 
There are two forms of contracts utilized in the transportation of natural gas, as described below:
 
  •  Firm.  Firm transportation service requires the reservation of pipeline capacity by a customer between certain receipt and delivery points. Firm customers generally pay a “demand” or “capacity reservation” fee based on the amount of capacity being reserved, regardless of whether the capacity is used, plus a usage fee based on the amount of natural gas transported.
 
  •  Interruptible.  Interruptible transportation service is typically short-term in nature and is generally used by customers that either do not need firm service or have been unable to contract for firm service. These customers pay only for the volume of gas actually transported. The obligation to provide this service is limited to available capacity not otherwise used by firm customers, and as such, customers receiving services under interruptible contracts are not assured capacity on the pipeline.
 
See Note 2 — Summary of Significant Accounting Policies of the notes to the consolidated financial statements included under Item 8 of this annual report for information regarding our contracts.


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PROPERTIES
 
As of December 31, 2009, our assets consist of nine gathering systems, six natural gas treating facilities, four gas processing facilities, one NGL pipeline and one interstate pipeline. Our assets are located in East and West Texas, the Rocky Mountains and the Mid-Continent. The following sections describe in more detail the services provided by our assets in our areas of operation. All volumes stated below are based on a standard pressure base of 14.73 pounds per square inch, absolute.
 
The following map depicts our significant midstream assets as of December 31, 2009.
 
(GRAPHIC)


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East Texas
 
Dew gathering system.  The 323-mile Dew gathering system is located in Anderson, Freestone, Leon and Robertson Counties of East Texas. The Dew gathering system was placed into service in November 1998 to provide gathering services for Anadarko’s drilling program in the Bossier play. The system provides gathering, dehydration and compression services and ultimately delivers into the Pinnacle gas treating system for any required treating. The Dew gathering system has 11 compressor stations with a combined 43,515 horsepower of compression.
 
Customers.  Anadarko is the only shipper on the Dew gathering system.
 
Supply.  As of December 31, 2009, Anadarko has approximately 837 producing wells in the Bossier play and controls approximately 185,000 gross acres in the area.
 
Delivery Points.  The Dew gathering system has delivery points with Pinnacle Gas Treating LLC, which is the primary delivery point and is described in more detail below, and Kinder Morgan’s Tejas pipeline.
 
Pinnacle gathering system.  The Pinnacle gathering system includes our 266-mile Pinnacle gathering system and our Bethel treating plant. The Pinnacle system provides sour gas gathering and treating service in Anderson, Freestone, Leon, Limestone and Robertson Counties of East Texas. The Bethel treating plant, located in Anderson County, has total CO2 treating capacity of 502 MMcf/d and 20 long tons per day, or “LTD,” of sulfur treating capacity.
 
Customers.  Anadarko is the largest shipper on the Pinnacle gathering system with 198 MMcf/d for the year ended December 31, 2009, which represented approximately 88% of the total throughput on the system during such period. Approximately 10% of throughput on the system during 2009 was primarily from two third-party shippers.
 
Supply.  The Pinnacle gathering system is well positioned to provide gathering and treating services to the five-county area over which it extends, including the Cotton Valley Lime formations, which contain relatively high concentrations of sulfur and CO2. We expanded the Bethel treating facilities based on dedicated demand from a third party during 2008 by installing an additional 11 LTD of sulfur treating capacity to bring the total installed sulfur treating capacity to 20 LTD. With this expansion, we believe that we are well positioned to benefit from future sour gas production in the area.
 
Delivery Points.  The Pinnacle gathering system is connected to Enterprise Texas Pipeline, LP’s pipeline, the Energy Transfer Fuels pipeline, the ETC Texas pipeline, Kinder Morgan’s Tejas pipeline, the ATMOS Texas pipeline and the Enbridge Pipelines (East Texas) LP pipeline. These pipelines provide transportation to the Carthage, Waha and Houston Ship Channel market hubs in Texas.
 
Rocky Mountains
 
Chipeta processing plant.  We own a 51% membership interest in and are the managing member of Chipeta. Chipeta is a limited liability company owned by the Partnership (51.0%), Ute Energy Midstream Holdings LLC (25.0%) and Anadarko (24.0%). Chipeta owns a natural gas processing plant complex, which includes two 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 completed in April 2009. The Chipeta system also includes the Natural Buttes plant, which provides up to 180 MMcf/d of incremental refrigeration processing capacity, and a 100% Partnership-owned 15-mile NGL pipeline connecting the Chipeta plant to a third-party pipeline. These assets provide processing and transportation services in the Greater Natural Buttes area in Uintah County, Utah.
 
Customers.  Anadarko is the largest customer on the Chipeta system with 338 MMcf/d throughput for the year ended December 31, 2009, which represented approximately 92% of the total throughput on the system. The balance of throughput on the system during 2009 was from two third-party customers.
 
Supply.  The Chipeta system is well positioned to access Anadarko’s and third-parties’ production in the area with excess available capacity and as the only cryogenic processing facility in the Uintah Basin.


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Anadarko controls approximately 237,000 gross acres in the Uintah Basin. Chipeta is connected to both Anadarko’s Natural Buttes Gathering System and to the Three Rivers Gathering system owned by Ute Energy and a third party.
 
Delivery Points.  The Chipeta plant delivers NGLs through our 15-mile pipeline to Enterprise’s Mid-America Pipeline, which provides transportation through the Seminole pipeline in West Texas and ultimately to the NGL markets at Mont Belvieu, Texas and the Texas Gulf Coast. The Chipeta plant delivers natural gas through:
 
  •  Questar Gas Management’s pipeline to the Kern River market;
 
  •  Colorado Interstate Gas Company’s, or “CIG’s” pipeline to the Opal market;
 
  •  CIG’s pipeline at the Annabuttes interconnect point on the Uintah Basin lateral;
 
  •  Wyoming Interstate Co.’s Kanda lateral pipeline with either access to the Trailblazer system or delivery to the Northwest Pipeline or the Rockies Express Pipeline; or
 
  •  Questar Pipeline Company’s pipeline with interconnects with Kern River at the Goshen point.
 
MIGC transportation system.  The MIGC system is a 256-mile interstate pipeline operating within the Powder River Basin of Wyoming that is regulated by FERC. The MIGC system traverses the Powder River Basin from north to south, extending to Glenrock, Wyoming. As a result, the MIGC system is well positioned to provide transportation for the extensive natural gas volumes received from various coal-bed methane gathering systems and conventional gas processing plants throughout the Powder River Basin. MIGC offers both forward-haul and backhaul transportation services, and additional capacity is available from time to time on an interruptible basis. MIGC is certificated for 175 MMcf/d of firm transportation capacity, all of which is fully subscribed as of December 31, 2009.
 
Customers.  Anadarko is the largest firm shipper on the MIGC system, with approximately 93% of throughput for the year ended December 31, 2009. For the year ended December 31, 2009, the remaining throughput on the system was from four third-party shippers.
 
Revenues on the MIGC system are generated from contract demand charges and volumetric fees paid by shippers under firm and interruptible gas transportation agreements. Our current firm transportation agreements range in term from approximately one to 10 years. Of the current certificated capacity of 175 MMcf/d, 85 MMcf/d is contracted through January 2011, 45 MMcf/d is contracted through September 2012 and 40 MMcf/d is contracted through October 2018. In addition to its certificated forward haul capacity, MIGC additionally provides firm backhaul service subject to flowing capacity. MIGC currently has 15 MMcf/d of firm backhaul service contracted through May 2010. Most of our interruptible gas transportation agreements are month-to-month with the remainder generally having terms of less than one year.
 
Supply.  As of December 31, 2009, Anadarko has a working interest in over 1.8 million gross acres within the Powder River Basin. Anadarko’s gross acreage includes substantial undeveloped acreage positions in the expanding Big George coal play and the multiple seam coal fairway to the north of the Big George play.
 
Delivery Points.  MIGC volumes can be redelivered to four interstate market pipelines and one intrastate pipeline, including the Williston Basin Interstate pipeline at the northern end of the Powder River Basin, the Wyoming Interstate Company’s Medicine Bow lateral pipeline, the Colorado Interstate Gas pipeline, the Kinder Morgan interstate pipeline at the southern end of the Powder River Basin near Glenrock, Wyoming and the MGTC intrastate pipeline, a pipeline that supplies local markets in Wyoming. Anadarko owned the MGTC pipeline as of December 31, 2009.
 
Fort Union gathering system.  The Fort Union system is a 314-mile gathering system operating within the Powder River Basin of Wyoming, starting in west central Campbell County and terminating at the Medicine Bow treating plant. The Fort Union gathering system has three parallel pipelines, each approximately 106 miles in length, and includes CO2 treating facilities at the Medicine Bow plant. The system’s gas treating


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capacity will vary depending upon the CO2 content of the inlet gas. At current CO2 levels, the system is capable of treating and blending over 1 Bcf/d while satisfying the CO2 specifications of downstream pipelines.
 
Fort Union Gas Gathering, L.L.C. is a partnership among Copano Pipelines/Rocky Mountains, LLC (37.04%), Crestone Powder River L.L.C. (37.04%), Bargath, Inc. (11.11%) and the Partnership (14.81%). Anadarko is the field and construction operator of the Fort Union gathering system.
 
Customers.  The four Fort Union owners named above are the only firm shippers on the Fort Union system. To the extent capacity on the system is not used by the owners, it is available to third parties under interruptible agreements.
 
Supply.  Substantially all of Fort Union’s gas supply is comprised of coal-bed methane volumes that are either produced or gathered by the four Fort Union owners throughout the Powder River Basin and, as of December 31, 2009, produces gas from approximately 9,800 coal-bed methane wells in the expanding Big George coal play, the multiple seam coal fairway to the north of the Big George play and in the Wyodak coal play. Anadarko has a working interest in over 1.8 million gross acres within the Powder River Basin as of December 31, 2009. Another of the Fort Union owners has a comparable working interest in a large majority of Anadarko’s producing coal-bed methane wells. The two remaining Fort Union owners gather gas for delivery to Fort Union under contracts with acreage dedications from multiple producers in the heart of the Basin and from the coal-bed methane producing area near Sheridan, Wyoming.
 
Delivery Points.  The Fort Union system delivers coal-bed methane gas to the Glenrock, Wyoming Hub which accesses interstate pipelines, including Wyoming Interstate Gas Company, Kinder Morgan Interstate Gas Transportation Company and Colorado Interstate Gas Company. These interstate pipelines serve gas markets in the Rocky Mountains and Midwest regions of the United States.
 
Helper gathering system.  The 67-mile Helper gathering system, located in Carbon County, Utah, was built to provide gathering services for Anadarko’s coal-bed methane development of the Ferron Coal. The Helper gathering system provides gathering, dehydration, compression and treating services for coal-bed methane gas. The Helper gathering system includes two compressor stations with a combined 14,075 horsepower and two CO2 treating facilities.
 
Customers.  Anadarko is the only shipper on the Helper gathering system.
 
Supply.  The Helper Field and Cardinal Draw Fields are Anadarko-operated coal-bed methane developments on the southwestern edge of the Uintah Basin that produce from the Ferron Coals. The Helper Field covers approximately 19,000 acres as of December 31, 2009 and Cardinal Draw Field, which lies immediately to the east of Helper Field, also covers approximately 19,000 acres.
 
Delivery Points.  The Helper gathering system delivers into the Questar Transportation Services Company’s pipeline. Questar provides transportation to regional markets in Wyoming, Colorado and Utah and also delivers into the Kern River Pipeline, which provides transportation to markets in the western U.S., primarily California.
 
Clawson gathering system.  The 47-mile Clawson gathering system, located in Carbon and Emery Counties of Utah, was built in 2001 to provide gathering services for Anadarko’s coal-bed methane development of the Ferron Coal. The Clawson gathering system provides gathering, dehydration, compression and treating services for coal-bed methane gas. The Clawson gathering system includes one compressor station, with 6,310 horsepower, and a CO2 treating facility.
 
Customers.  Anadarko is the largest shipper on the Clawson gathering system with approximately 97% of the total throughput delivered into the system during the year ended December 31, 2009. The remaining throughput on the system was from one third-party producer.
 
Supply.  Clawson Springs Field has approximately 7,000 gross acres. Production for Clawson Springs is primarily from the Cretaceous Ferron sands and coals.
 
Delivery Points.  The Clawson gathering system delivers into Questar Transportation Services Company’s pipeline.


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Hilight gathering system and processing plant.  The 1,157-mile Hilight gathering system, located in Johnson, Campbell, Natrona and Converse Counties of Wyoming, was built to provide low- and high-pressure gathering services for the area’s conventional gas production and delivers to the Hilight plant for processing. The Hilight gathering system has 10 compressor stations with 16,366 combined horsepower. The Hilight system was built in 1969 and has a capacity of approximately 30 MMcf/d. The Hilight plant utilizes a refrigeration process and provides for fractionation of the recovered NGL products into propane, butanes and natural gasoline. The Hilight plant has an additional 10,755 horsepower for refrigeration and residue compression, including one compressor station.
 
Customers.  Gas processed at the Hilight system is purchased from numerous third-party customers, with the 11 largest producers providing approximately 80% of the system throughput during 2009.
 
Supply.  The Hilight gathering system serves the gas gathering needs of several conventional producing fields in Johnson, Campbell, Natrona and Converse Counties. Our customers have historically and may continue to maintain throughput with workover activity and by developing new prospects. Based on publicly available information, these producers are planning drilling activity over the next three to five years in the area serviced by the system.
 
Delivery Points.  The Hilight gathering system delivers natural gas into MIGC’s transmission line, which delivers to Glenrock, Wyoming. Hilight is not connected to an NGL pipeline, so all fractionated NGLs are sold locally through its truck and rail loading facilities.
 
Newcastle gathering system and processing plant.  The 176-mile Newcastle gathering system, located in Weston and Niobrara Counties of Wyoming, was built to provide gathering services for conventional gas production in the area. The gathering system delivers into the Newcastle plant, which was built in 1981 and has gross capacity of approximately 3 MMcf/d. The plant utilizes a refrigeration process and provides for fractionation of the recovered NGLs into propane and butane/gasoline mix products. The Newcastle facility is a joint venture among Black Hills Exploration and Production, Inc. (44.7%), John Paulson (5.3%) and the Partnership (50.0%). The Newcastle gathering system includes one compressor station, with 560 horsepower. The Newcastle plant has an additional 2,100 horsepower for refrigeration and residue compression.
 
Customers.  Gas processed at the Newcastle system is purchased from 11 third-party customers, with the largest three producers providing approximately 90% of the system throughput during 2009. The largest producer, Black Hills Exploration, provided approximately 68% of the throughput during 2009 and is a part owner of the Newcastle system.
 
Supply.  The Newcastle gathering system and plant primarily service gas production from the Clareton and Finn-Shurley fields in Weston County. Due to infill drilling and enhanced production techniques, producers have continued to maintain production.
 
Delivery Points.  Propane products from the Newcastle plant are typically sold locally by truck and the butane/gasoline mix products are transported to the Hilight plant for further fractionation. Residue gas from the Newcastle system is delivered into MGTC’s pipeline for transport, distribution and sales.
 
Mid-Continent
 
Hugoton gathering system.  The 2,034-mile Hugoton gathering system provides gathering service to the Hugoton field and is primarily located in Seward, Stevens, Grant and Morton Counties of Southwest Kansas and Texas County in Oklahoma. The Hugoton gathering system has 43 compressor stations with a combined 102,257 horsepower of compression.
 
Customers.  Anadarko is the largest customer on the Hugoton gathering system with 82 MMcf/d of average throughput during the year ended December 31, 2009, representing 67% of the total volume on the system. Approximately 26% of the throughput on the Hugoton system for the year ended December 31, 2009 was from one third-party shipper.
 
Supply.  The Hugoton field is one of the largest natural gas fields in North America. The Hugoton field continues to be a long-life, slow-decline asset for Anadarko, which has an extensive acreage position with


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approximately 470,000 gross acres. By virtue of a farm out agreement between a third-party producer and Anadarko, the third-party producer gained the right to explore below the primary formations in the Hugoton field. Our existing asset is well-positioned to gather volumes that may be produced from new wells the third-party producer may successfully drill. In addition, Anadarko has indicated it expects an increased activity level in the area in 2010 due to recent changes in local regulations controlling the number of wells that may be drilled in a given area.
 
Delivery Points.  The Hugoton gathering system is connected to DCP Midstream Partners, LP’s National Helium plant, which extracts NGLs and helium and redelivers residue gas into the Panhandle Eastern pipeline. The system is also connected to Pioneer Natural Resources Corporation’s Satanta plant for NGLs processing and to the adjacent Mid-Continent Market Center, which provides access to the Panhandle Eastern pipeline, the Northern Natural Gas pipeline, the Natural Gas pipeline, the Southern Star pipeline, and the ANR pipeline. These pipelines provide transportation and market access to Midwestern and Northeastern markets.
 
West Texas
 
Haley gathering system.  The 116-mile Haley gathering system provides gathering and dehydration services in Loving County, Texas and gathers Anadarko’s production from the Delaware Basin. The Haley gathering system has historically experienced rapid growth as a result of Anadarko’s successful drilling activity in the area.
 
Customers.  Anadarko’s production represented approximately 72% of the Haley gathering system’s throughput for the year ended December 31, 2009. The remaining 28% of throughput is attributable to Anadarko’s partner in the Haley area.
 
Supply.  In the greater Delaware basin, Anadarko has access to approximately 410,000 gross acres as of December 31, 2009.
 
Delivery Points.  The Haley gathering system has multiple delivery points. The primary delivery points are to the El Paso Natural Gas pipeline or the Enterprise GC, L.P. pipeline for ultimate delivery into Energy Transfer’s Oasis pipeline. We also have the ability to deliver into Southern Union Energy Services’ pipeline for further delivery into the Oasis pipeline. The pipelines at these delivery points provide transportation to both the Waha and Houston Ship Channel markets.
 
COMPETITION
 
We do not currently face significant competition on the majority of our systems due to the substantial throughput volumes being owned or controlled by Anadarko and its dedication to us of future production from its acreage surrounding our initial assets’ gathering systems. We believe our assets that are outside of the dedicated areas are geographically well positioned to retain and attract third-party volumes.
 
Competition on gathering systems and at processing plants.  The natural gas gathering, compression, processing, treating and transportation business is very competitive. Our competitors include other midstream companies, producers, and intrastate and interstate pipelines. Competition for natural gas volumes is primarily based on reputation, commercial terms, reliability, service levels, location, available capacity, capital expenditures and fuel efficiencies. We believe the primary competitive advantages of our Hilight and Newcastle systems, which gather and process third-party volumes, are their proximity to established and new production, and our ability to provide flexible services to producers, including gathering, compression and processing. We believe we can provide the services that producers and other customers require to connect, gather and process their natural gas efficiently, at competitive and flexible contract terms. Further, we believe that Chipeta’s cryogenic processing unit and Fort Union’s centralized amine treating facilities provide competitive advantages to those systems.
 
Our primary competitors for our gathering systems and processing plants include:
 
  •  Chipeta processing plant:  Questar Gas Management;


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  •  Dew and Pinnacle gathering systems:  ETC Texas Pipeline, Ltd., Enbridge Pipelines (East Texas) LP, XTO Energy and Kinder Morgan Tejas Pipeline, LP;
 
  •  Fort Union gathering system:  Thunder Creek Gas Services;
 
  •  Helper and Clawson gathering systems:  Questar Gas Management;
 
  •  Hilight gathering and processing system:  DCP Midstream and Merit Energy;
 
  •  Hugoton gathering system:  ONEOK Gas Gathering Company, DCP Midstream Partners, LP and Pioneer Natural Resources;
 
  •  Haley gathering system:  Enterprise GC, LP and Southern Union Energy Services Company; and
 
  •  Newcastle gathering and processing system:  DCP Midstream.
 
Competition on transportation system.  MIGC competes with other pipelines that service the regional market and transport gas volumes from the Powder River Basin to Glenrock, Wyoming. MIGC competitors seek to attract and connect new gas volumes throughout the Powder River Basin, including certain of the volumes currently being transported on the MIGC pipeline. An increase in competition could result from new pipeline installations or expansions by existing pipelines. Competitive factors include commercial terms, available capacity, fuel efficiencies, the interconnected pipelines and gas quality issues. MIGC’s major competitor is Thunder Creek Gas Services.
 
SAFETY AND MAINTENANCE
 
We are subject to regulation by the Pipeline and Hazardous Materials Safety Administration, or “PHMSA,” of the Department of Transportation, or the “DOT,” pursuant to the Natural Gas Pipeline Safety Act of 1968, or the “NGPSA,” and the Pipeline Safety Improvement Act of 2002, or the “PSIA,” which was recently reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. liquid and gas transportation pipelines and some gathering lines in high-population areas.
 
The PHMSA has developed regulations implementing the PSIA that require transportation pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in “high consequence areas,” such as high population areas, areas unusually sensitive to environmental damage and commercially navigable waterways. We, or the entities in which we own an interest, inspect our pipelines regularly in compliance with state and federal maintenance requirements.
 
States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant difficulty in complying with applicable state laws and regulations. Our pipelines have operations and maintenance plans designed to keep the facilities in compliance with pipeline safety requirements.
 
In addition, we are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, or “OSHA,” and comparable state statutes, the purposes of which are to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the EPA’s community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local government authorities and citizens.
 
We and the entities in which we own an interest are also subject to OSHA Process Safety Management regulations, as well as the EPA’s Risk Management Program, or “RMP,” which are designed to prevent or


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minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above specified thresholds or any process which involves flammable liquid or gas in excess of 10,000 pounds. Flammable liquids stored in atmospheric tanks below their normal boiling points without the benefit of chilling or refrigeration are exempt. We have an internal program of inspection designed to monitor and enforce compliance with worker safety requirements. We believe that we are in material compliance with all applicable laws and regulations relating to worker health and safety.
 
REGULATION OF OPERATIONS
 
Regulation of pipeline gathering and transportation services, natural gas sales and transportation of NGLs may affect certain aspects of our business and the market for our products and services.
 
Interstate transportation pipeline regulation.  MIGC, our interstate natural gas transportation system, is subject to regulation by FERC under the Natural Gas Act of 1938, or the “NGA.” Under the NGA, FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. Federal regulation extends to such matters as:
 
  •  rates, services, and terms and conditions of service;
 
  •  the types of services MIGC may offer to its customers;
 
  •  the certification and construction of new facilities;
 
  •  the acquisition, extension, disposition or abandonment of facilities;
 
  •  the maintenance of accounts and records;
 
  •  relationships between affiliated companies involved in certain aspects of the natural gas business;
 
  •  the initiation and discontinuation of services;
 
  •  market manipulation in connection with interstate sales, purchases or transportation of natural gas; and
 
  •  participation by interstate pipelines in cash management arrangements.
 
Natural gas companies are prohibited from charging rates that have been determined not to be just and reasonable by FERC. In addition, FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.
 
The rates and terms and conditions for our interstate pipeline services are set forth in FERC-approved tariffs. Pursuant to FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. Any successful complaint or protest against our rates could have an adverse impact on our revenues associated with providing transportation service.
 
Commencing in 2003, FERC issued a series of orders adopting rules for new Standards of Conduct for Transmission Providers (Order No. 2004), which apply to interstate natural gas pipelines and certain natural gas storage companies that provide storage services in interstate commerce. Order No. 2004 became effective in 2004. Among other matters, Order No. 2004 required interstate pipeline and storage companies to operate independently from their energy affiliates, prohibited interstate pipeline and storage companies from providing non-public transportation or shipper information to their energy affiliates, prohibited interstate pipeline and storage companies from favoring their energy affiliates in providing service, and obligated interstate pipeline and storage companies to post on their websites a number of items of information concerning the company, including its organizational structure, facilities shared with energy affiliates, discounts given for services and instances in which the company has agreed to waive discretionary terms of its tariff. On July 7, 2004, FERC issued an order providing MIGC with a partial waiver of the independent functioning and information access provisions of the standards of conduct.
 
Late in 2006, the D.C. Circuit vacated and remanded Order No. 2004 as it relates to natural gas transportation providers, including MIGC. The D.C. Circuit found that FERC had not adequately justified its


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expansion of the prior standards of conduct to include energy affiliates, and vacated the entire rule as it relates to natural gas transportation providers. On January 9, 2007, as clarified on March 21, 2007, FERC issued an interim rule (Order No. 690) re-promulgating on an interim basis the standards of conduct that were not challenged before the court, while FERC decided how to respond to the court’s decision on a permanent basis through FERC’s rulemaking process. On October 16, 2008, FERC issued Order No. 717, a final rule that amends the regulations adopted on an interim basis in Order No. 690. Order No. 717 implements revised standards of conduct that include three primary rules: (1) the “independent functioning rule,” which requires transmission function and marketing function employees to operate independently of each other; (2) the “no-conduit rule,” which prohibits passing transmission function information to marketing function employees; and (3) the “transparency rule,” which imposes posting requirements to help detect any instances of undue preference. FERC also clarified in Order No. 717 that existing waivers to the standards of conduct (such as those held by MIGC) shall continue in full force and effect. A number of parties have requested clarification or rehearing of Order No. 717, and FERC issued an order on rehearing on October 15, 2009. The order on rehearing generally reaffirmed the determinations in Order No. 717 and also clarified certain provisions of the Standards of Conduct.
 
In May 2005, FERC issued a policy statement permitting the inclusion of an income tax allowance in the cost of service-based rates of a pipeline organized as a tax pass-through partnership entity, if the pipeline proves that the ultimate owner of its equity interests has an actual or potential income tax liability on public utility income. The policy statement also provides that whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by FERC on a case-by-case basis. In August 2005, FERC dismissed requests for rehearing of its new policy statement. On December 16, 2005, FERC issued its first significant case-specific review of the income tax allowance issue in a pipeline partnership’s rate case. FERC reaffirmed its new income tax allowance policy and directed the subject pipeline to provide certain evidence necessary for the pipeline to determine its income tax allowance. The new tax allowance policy and the December 16, 2005 order were appealed to the D.C. Circuit. The D.C. Circuit issued an order on May 29, 2007 in which it denied these appeals and upheld FERC’s new tax allowance policy and the application of that policy in the December 16, 2005 order on all points subject to appeal. The D.C. Circuit denied rehearing of the May 29, 2007 decision on August 20, 2007, and the D.C. Circuit’s decision is final.
 
On December 8, 2006, FERC issued another order addressing the income tax allowance in rates. In the December 8, 2006 order, FERC refined and reaffirmed prior statements regarding its income tax allowance policy, and notably raised a new issue regarding the implication of the policy statement for publicly traded partnerships. It noted that the tax deferral features of a publicly traded partnership may cause some investors to receive, for some indeterminate duration, cash distributions in excess of their taxable income, which FERC characterized as a “tax savings.” FERC stated that it is concerned that this created an opportunity for those investors to earn an additional return, funded by ratepayers. Responding to this concern, FERC chose to adjust the pipeline’s equity rate of return downward based on the percentage by which the publicly traded partnership’s cash flow exceeded taxable income. On February 7, 2007, the pipeline filed a request for rehearing on this issue. FERC issued an order on rehearing of the December 8, 2006 order on May 2, 2008, establishing a paper hearing on certain issues and determining that the remaining issues not addressed in the paper hearing would be addressed in an order following the completion of the paper hearing. Rehearing of the May 2, 2008 order has been granted and is currently pending. A partial offer of settlement of the issues subject to the paper hearing has been filed, and FERC action on the partial settlement is currently pending. The ultimate outcome of this proceeding cannot be predicted with certainty.
 
On April 17, 2008, FERC issued a proposed policy statement regarding the composition of proxy groups for determining the appropriate return on equity for natural gas and oil pipelines using FERC’s Discounted Cash Flow, or “DCF,” model. In the policy statement, which modified a proposed policy statement issued in July 2007, FERC concluded: (1) MLPs should be included in the proxy group used to determine return on equity for both oil and natural gas pipelines; (2) there should be no cap on the level of distributions included in FERC’s current DCF methodology; (3) Institutional Brokers’ Estimate System forecasts should remain the basis for the short-term growth forecast used in the DCF calculation; (4) the long-term growth component of the DCF model should be limited to fifty percent of long-term gross domestic product; and (5) there should be


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no modification to the current two-thirds and one-third weighting of the short-term and long-term growth components, respectively. FERC also concluded that the policy statement should govern all gas and oil rate proceedings involving the establishment of return on equity that are pending before FERC. FERC’s policy determinations applicable to MLPs are subject to further modification, and it is possible that these policy determinations may have a negative impact on MIGC’s rates in the future.
 
On August 8, 2005, Congress enacted the Energy Policy Act of 2005, or the “EPAct 2005.” Among other matters, EPAct 2005 amends the NGA to add an anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by FERC and, furthermore, provides FERC with additional civil penalty authority. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-manipulation provision of EPAct 2005, and subsequently denied rehearing. The rules make it unlawful for any entity, directly or indirectly in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC or the purchase or sale of transportation services subject to the jurisdiction of FERC: (1) to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-manipulation rules apply to interstate gas pipelines and storage companies and intrastate gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. The new anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but only to the extent such transactions do not have a “nexus” to jurisdictional transactions. EPAct 2005 also amends the NGA and the Natural Gas Policy Act of 1978, or “NGPA,” to give FERC authority to impose civil penalties for violations of these statutes, up to $1.0 million per day per violation for violations occurring after August 8, 2005. In connection with this enhanced civil penalty authority, FERC issued a policy statement on enforcement to provide guidance regarding the enforcement of the statutes, orders, rules and regulations it administers, including factors to be considered in determining the appropriate enforcement action to be taken. Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
 
In 2008, FERC took steps to enhance its market oversight and monitoring of the natural gas industry by issuing several rulemaking orders designed to promote gas price transparency and to prevent market manipulation. Order No. 704, as clarified on rehearing in 2008, requires buyers and sellers of natural gas above a de minimis level, including entities not otherwise subject to FERC jurisdiction, to submit an annual report to FERC describing their wholesale physical natural gas transactions. The first such report was due in July 2009 for calendar year 2008 activities. For subsequent years, the report is due annually on May 1. Order No. 720, issued on November 20, 2008, increases the Internet posting obligations of interstate pipelines, and also requires “major non-interstate” pipelines (defined as pipelines with annual deliveries of more than 50 million MMBtu) to post on the Internet the daily volumes scheduled for each receipt and delivery point on their systems with a design capacity of 15,000 MMBtu per day or greater. Numerous parties requested modification or reconsideration of this rule. A staff technical conference was held in March 2009 to gather additional information on three issues raised in the requests for rehearing: (1) the definition of major non-interstate pipelines; (2) what constitutes “scheduling” for a receipt or delivery point; and (3) how a 15,000 MMBtu per day design capacity threshold would be applied. Furthermore, FERC issued an order on July 16, 2009, requesting parties to file supplemental comments on certain issues. An order on rehearing, Order No. 720-A, was issued on January 21, 2010. In that order the FERC reaffirmed its holding that it has jurisdiction over major non-interstate pipelines for the purpose of requiring public disclosure of information to enhance market transparency. Order No. 720-A also granted clarification regarding application of the rule. Major non-interstate pipelines subject to the rule have 150 days to comply with the rule’s Internet posting requirements. In November 2008, FERC also issued a Notice of Inquiry to the industry soliciting comments regarding whether “Hinshaw” pipelines and intrastate pipelines that transport natural gas in interstate commerce pursuant to Section 311 of the NGPA should be required to post on the Internet certain details of their transactions with individual shippers in a manner comparable to the reporting requirements applicable to interstate pipelines.


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Once FERC evaluates the comments filed in response to the Notice of Inquiry, it may choose to engage in the formal rulemaking process to propose additional reporting requirements on such pipelines.
 
In 2008, FERC also took action to ease restrictions on the capacity release market, in which shippers on interstate pipelines can transfer to one another their rights to pipeline and/or storage capacity. Among other things, Order No. 712, as modified on rehearing, removes the price ceiling on short-term capacity releases of one year or less, allows a shipper releasing gas storage capacity to tie the release to the purchase of the gas inventory and the obligation to deliver the same volume at the expiration of the release, and facilitates Asset Management Agreements, or “AMAs,” by exempting releases under qualified AMAs from: the competitive bidding requirements for released capacity; FERC’s prohibition against tying releases to extraneous conditions; and the prohibition on capacity brokering.
 
Gathering pipeline regulation.  Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC. However, some of our natural gas gathering activity is subject to Internet posting requirements imposed by FERC as a result of FERC’s recent market transparency initiatives. We believe that our natural gas pipelines meet the traditional tests that FERC has used to determine that a pipeline is a gathering pipeline and is, therefore, not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. In recent years, FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies, which has resulted in a number of such companies transferring gathering facilities to unregulated affiliates. As a result of these activities, natural gas gathering may begin to receive greater regulatory scrutiny at both the state and federal levels. Our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services. Our natural gas gathering operations also may be or become subject to additional safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
 
Our natural gas gathering operations are subject to ratable take and common purchaser statutes in most of the states in which we operate. These statutes generally require our gathering pipelines to take natural gas without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. The states in which we operate have adopted a complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. To date, there has been no adverse effect to our systems due to these regulations.
 
During the 2007 legislative session, the Texas State Legislature passed H.B. 3273, or the “Competition Bill,” and H.B. 1920, or the “LUG Bill.” The Texas Competition Bill and LUG Bill contain provisions applicable to gathering facilities. The Competition Bill allows the Railroad Commission of Texas, or the “TRRC,” the ability to use either a cost-of-service method or a market-based method for setting rates for natural gas gathering in formal rate proceedings. It also gives the TRRC specific authority to enforce its statutory duty to prevent discrimination in natural gas gathering, to enforce the requirement that parties participate in an informal complaint process and to punish purchasers, transporters and gatherers for taking discriminatory actions against shippers and sellers. The LUG Bill modifies the informal complaint process at the TRRC with procedures unique to lost and unaccounted for gas issues. It extends the types of information that can be requested and gives the TRRC the authority to make determinations and issue orders in specific


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situations. Both the Competition Bill and the LUG Bill became effective September 1, 2007. We cannot predict what effect, if any, either the Competition Bill or the LUG Bill might have on our gathering operations.
 
ENVIRONMENTAL MATTERS
 
General.  Our operation of pipelines, plants and other facilities for the gathering, processing, compression, treating and transporting of natural gas and other products is subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:
 
  •  requiring the installation of pollution-control equipment or otherwise restricting the way we can handle or dispose of our wastes;
 
  •  limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;
 
  •  requiring investigatory and remedial actions to mitigate or eliminate pollution conditions caused by our operations or attributable to former operations; and
 
  •  enjoining the operations of facilities deemed to be in non-compliance with such environmental laws and regulations and permits issued pursuant thereto.
 
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of investigatory and remedial obligations and the issuance of orders enjoining future operations or imposing additional compliance requirements. Certain environmental statutes impose strict, and in some cases, joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or otherwise released, thus, we may be subject to environmental liability at our currently owned or operated facilities for conditions caused prior to our involvement.
 
The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing or future regulations.
 
We do not believe that compliance with current federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations or cash flows. In addition, we believe that the various environmental activities in which we are presently engaged are not expected to materially interrupt or diminish our operational ability to gather, process, compress, treat and transport natural gas. We can make no assurances, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations or the development or discovery of new facts or conditions will not cause us to incur significant costs. Below is a discussion of several of the material environmental laws and regulations that relate to our business. We believe that we are in material compliance with applicable environmental laws and regulations.
 
Hazardous substances and waste.  Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict, and in some cases, joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act, referred to as “CERCLA” or the “Superfund law,” and comparable state laws impose liability, without regard to fault


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or the legality of the original conduct, on certain classes of persons. These persons include current owners or operators of the site where a release of hazardous substances occurred, prior owners or operators that owned or operated the site at the time of the release, and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to strict and joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Despite the “petroleum exclusion” of CERCLA Section 101(14), which currently encompasses natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.
 
We also generate solid wastes, including hazardous wastes, which are subject to the requirements of the Resource Conservation and Recovery Act, or “RCRA,” and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA’s hazardous waste regulations. However, it is possible that these wastes, which could include wastes currently generated during our operations, will in the future be designated as “hazardous wastes” and, therefore, be subject to more rigorous and costly disposal requirements. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.
 
We own or lease properties where hydrocarbons are being or have been handled for many years. We have generally utilized operating and disposal practices that were standard in the industry at the time, although hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us, or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons and other wastes was not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our financial condition, results of operations or cash flows.
 
Air emissions.  Our operations are subject to the Federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. We believe that we are in material compliance with these requirements. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining permits and approvals for air emissions. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.
 
Climate change.  In June 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, or “ACES,” also known as the “Waxman-Markey Bill.” The U.S. Senate is


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considering a number of comparable measures. One such measure, the Clean Energy Jobs and American Power Act, or the “Boxer-Kerry Bill,” has been reported out of the Senate Committee on Energy and Natural Resources, but has not yet been considered by the full Senate. Although these bills include several differences that require reconciliation before becoming law, both contain the basic feature of establishing a “cap and trade” system for restricting greenhouse gas emissions in the U.S. Under such system, certain sources of greenhouse gas emissions would be required to obtain greenhouse gas emission “allowances” corresponding to their annual emissions of greenhouse gases. The number of emission allowances issued each year would decline as necessary to meet overall emission reduction goals. As the number of greenhouse gas emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The ultimate outcome of this legislative initiative remains uncertain. Any laws or regulations that may be adopted to restrict or reduce emissions of U.S. greenhouse gases could require us to incur increased operating costs, and could have an adverse effect on demand for the natural gas and NGLs we gather and process. In addition, at least 20 states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs.
 
Depending on the particular program, we could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from our operations or from combustion of the natural gas we gather and process. Although we believe we would not be impacted to a greater degree than other similarly situated companies, a stringent greenhouse gas control program could have an adverse affect on our cost of doing business and could reduce demand for the natural gas and NGLs we gather and process.
 
In April 2007, the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the Clean Air Act, or the “CAA.” Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. In April 2009, the EPA released a “Proposed Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” While the EPA’s proposed findings do not specifically address stationary sources, those findings, if finalized, would be expected to support the establishment of future emission requirements by the EPA for stationary sources. In September 2009, the EPA finalized a greenhouse gas reporting rule establishing a national greenhouse gas emissions collection and reporting program. The EPA rules will require covered entities to measure greenhouse gas emissions commencing in 2010 and submit reports commencing in 2011. In September 2009, EPA also proposed new thresholds for greenhouse gas emissions that define when certain permits would be required. EPA is requesting comment on a range of values in this proposal, with the intent of selecting a single value for the greenhouse gas thresholds. These proposals, along with new federal or state restrictions on emissions of CO2 that may be imposed in areas of the United States in which we conduct business, could also adversely affect our cost of doing business and demand for the natural gas and NGLs we gather and process.
 
Water discharges.  The Federal Water Pollution Control Act, or the “Clean Water Act,” and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants or dredged and fill material into state waters as well as waters of the U.S. and adjacent wetlands. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of permits issued by the EPA, the Army Corps of Engineers or an analogous state agency. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. We believe that we are in material compliance with these requirements. However, federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. We believe that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our financial condition, results of operations or cash flows.


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Endangered species.  The Endangered Species Act, or “ESA,” restricts activities that may affect endangered or threatened species or their habitats. While some of our pipelines may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in material compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected states.
 
Anti-terrorism measures.  The Department of Homeland Security Appropriation Act of 2007 requires the Department of Homeland Security, or “DHS,” to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to this act and, on November 20, 2007, further issued an Appendix A to the interim rules that establish chemicals of interest and their respective threshold quantities that will trigger compliance with these interim rules. We have determined the extent to which our facilities are subject to the rule, made the necessary notifications and determined that the requirements will not have a material impact on our financial condition, results of operations or cash flows.
 
TITLE TO PROPERTIES AND RIGHTS-OF-WAY
 
Our real property is classified into two categories: (1) parcels that we own in fee and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations. Portions of the land on which our plants and other major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our plant sites and major facilities are located are held by us pursuant to surface leases between us, as lessee, and the fee owner of the lands, as lessors. We have leased or owned these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates or fee ownership of such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses.
 
Some of the leases, easements, rights-of-way, permits and licenses transferred to us by Anadarko required the consent of the grantor of such rights, which in certain instances is a governmental entity. Our general partner has obtained sufficient third-party consents, permits and authorizations for the transfer of the assets necessary to enable us to operate our business in all material respects. With respect to any remaining consents, permits or authorizations that have not been obtained, we have determined these will not have material adverse effect on the operation of our business should we fail to obtain such consents, permits or authorization in a reasonable time frame.
 
Anadarko holds record title to portions of certain assets as we make the appropriate filings in the jurisdictions in which such assets are located and obtain any consents and approvals as needed. Such consents and approvals would include those required by federal and state agencies or other political subdivisions. In some cases, Anadarko temporarily holds record title to property as nominee for our benefit and in other cases may, on the basis of expense and difficulty associated with the conveyance of title, may cause its affiliates to retain title, as nominee for our benefit, until a future date. We anticipate that there will be no material change in the tax treatment of our common units resulting from Anadarko holding the title to any part of such assets subject to future conveyance or as our nominee.
 
EMPLOYEES
 
We do not have any employees. The officers of our general partner manage our operations and activities under the direction and supervision of our general partner’s board of directors. As of December 31, 2009, Anadarko employed approximately 174 people who provided direct, full-time support to our operations. All of the employees required to conduct and support our operations are employed by Anadarko and all of our direct,


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full-time personnel are subject to a service and secondment agreement between our general partner and Anadarko. None of these employees are covered by collective bargaining agreements, and Anadarko considers its employee relations to be good.
 
Item 1A.   Risk Factors
 
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
 
We have made in this report, and may from time to time otherwise make in other public filings, press releases and discussions, forward-looking statements concerning our operations, economic performance and financial condition. These statements can be identified by the use of forward-looking terminology such as “may,” “could,” “believe,” “expect,” “anticipate,” “estimate,” “project,” “continue,” “potential,” “plan,” “forecast” 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 the energy market;
 
  •  future gathering, treating and processing volumes and pipeline throughput, including Anadarko’s production, which is gathered or processed by or transported through our assets;
 
  •  operating results;
 
  •  competitive conditions;
 
  •  technology;
 
  •  the availability of capital resources to fund capital expenditures and other contractual obligations, and our ability to access those resources through the debt or equity capital markets;
 
  •  the supply of and demand for, and the price of oil, natural gas, NGLs and other products or services;
 
  •  the weather;
 
  •  inflation;
 
  •  the availability of goods and services;
 
  •  general economic conditions, either internationally or nationally or in the jurisdictions in which we are doing business;
 
  •  legislative or regulatory changes, including changes in environmental regulation, environmental risks, regulations by FERC and liability under federal and state environmental laws and regulations;
 
  •  changes in the financial health of our sponsor, Anadarko;
 
  •  changes in Anadarko’s capital program, strategy or desired areas of focus;
 
  •  our commitments to capital projects;
 
  •  the ability to utilize our existing credit arrangements, including up to $100.0 million under Anadarko’s $1.3 billion credit facility, our $350.0 million revolving credit facility or our $30.0 million working capital facility;
 
  •  our ability to maintain and/or obtain rights to operate our assets on land owned by third parties;
 
  •  our ability to acquire assets on acceptable terms;


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  •  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
 
  •  other factors discussed below and elsewhere in this Item 1A and the caption Critical Accounting Policies and Estimates included under Item 7 this annual report 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.
 
Limited partner units are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. We urge you to carefully consider the following risk factors together with all of the other information included in this annual report in evaluating an investment in our common units.
 
If any of the following risks were to occur, our business, financial condition or results of operation could be materially adversely affected. In that case, we might not be able to pay the currently announced distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment in us.
 
RISKS RELATED TO OUR BUSINESS
 
We are dependent on Anadarko for a majority of the natural gas that we gather, treat, process and transport. A material reduction in Anadarko’s production gathered, processed or transported by our assets would result in a material decline in our revenues and cash available for distribution.
 
We rely on Anadarko for a majority of the natural gas that we gather, treat, process and transport. For the year ended December 31, 2009, Anadarko accounted for approximately 79% of our natural gas gathering, processing and transportation volumes. Anadarko may suffer a decrease in production volumes in the areas serviced by us and is under no contractual obligation to maintain its production volumes dedicated to us. The loss of a significant portion of the natural gas volumes supplied by Anadarko would result in a material decline in our revenues and our cash available for distribution. In addition, Anadarko may reduce its drilling activity in our areas of operation or determine that drilling activity in other areas of operation is strategically more attractive. A shift in Anadarko’s focus away from our areas of operation could result in reduced throughput on our system and a material decline in our revenues and cash available for distribution.
 
Because we derive a substantial portion of our revenues from Anadarko, we are indirectly subject to risks relating to Anadarko.
 
Because we expect to derive a substantial majority of our revenues from Anadarko for the foreseeable future, any event, whether in our area of operations or otherwise, that adversely affects Anadarko’s production, financial condition, leverage, results of operations or cash flows may adversely affect our ability to sustain or increase cash distributions to our unitholders. Accordingly, we are indirectly subject to the business risks of Anadarko, some of which are the following:
 
  •  the volatility of natural gas and oil prices, which could have a negative effect on the value of its oil and natural gas properties, its drilling programs or its ability to finance its operations;
 
  •  the availability of capital on an economic basis to fund its exploration and development activities;
 
  •  its ability to replace reserves;
 
  •  its operations in foreign countries are subject to political, economic and other uncertainties;
 
  •  its drilling and operating risks, including potential environmental liabilities;


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  •  transportation capacity constraints and interruptions;
 
  •  adverse effects of governmental and environmental regulation; and
 
  •  losses from pending or future litigation.
 
Please see Item 1A, in Anadarko’s annual report on Form 10-K for the year ended December 31, 2009 for a full discussion of the risks associated with Anadarko’s business.
 
Because of the natural decline in production from existing wells, our success depends on our ability to obtain new sources of natural gas, which is dependent on certain factors beyond our control. Any decrease in the volumes of natural gas that we gather, process, compress, treat and transport could adversely affect our business and operating results.
 
The volumes that support our business are dependent on the level of production from natural gas wells connected to our gathering systems and processing and treatment facilities. This production will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our gathering systems, we must obtain new sources of natural gas. The primary factors affecting our ability to obtain sources of natural gas include (i) the level of successful drilling activity near our systems, (ii) our ability to compete for volumes from successful new wells, to the extent such wells are not dedicated to our systems, and (iii) our ability to capture volumes currently gathered or processed by third parties.
 
While Anadarko has dedicated production from certain of its properties to us, we have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our gathering systems or the rate at which production from a well declines. In addition, we have no control over Anadarko or other producers or their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, prevailing and projected commodity prices, demand for hydrocarbons, levels of reserves, geological considerations, governmental regulations, the availability of drilling rigs and other production and development costs. Fluctuations in commodity prices can also greatly affect investments by Anadarko and third parties in the development of new natural gas reserves. Declines in natural gas prices could have a negative impact on exploration, development and production activity and, if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in our areas of operation would lead to reduced utilization of our gathering and treating assets.
 
Because of these factors, even if new natural gas reserves are known to exist in areas served by our assets, producers (including Anadarko) may choose not to develop those reserves. Moreover, Anadarko may not develop the acreage it has dedicated to us. If competition or reductions in drilling activity result in our inability to maintain the current levels of throughput on our systems, it could reduce our revenue and impair our ability to make cash distributions to our unitholders.
 
We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay announced distributions to holders of our common and subordinated units.
 
In order to pay the announced distribution of $0.33 per unit per quarter, or $1.32 per unit per year, we will require available cash of approximately $21.4 million per quarter, or $85.6 million per year, based on the number of general partner units and common and subordinated units outstanding at March 1, 2010. We may not have sufficient available cash from operating surplus each quarter to enable us to pay the announced distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
 
  •  the prices of, level of production of, and demand for natural gas;
 
  •  the volume of natural gas we gather, compress, treat, process and transport;
 
  •  the volumes and prices of NGLs and condensate that we retain and sell;


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  •  demand charges and volumetric fees associated with our transportation services;
 
  •  the level of competition from other midstream energy companies;
 
  •  the level of our operating and maintenance and general and administrative costs;
 
  •  regulatory action affecting the supply of or demand for natural gas, the rates we can charge, how we contract for services, our existing contracts, our operating costs or our operating flexibility; and
 
  •  prevailing economic conditions.
 
In addition, the actual amount of cash we will have available for distribution will depend on other factors, including the following, some of which are beyond our control:
 
  •  the level of capital expenditures we make;
 
  •  our debt service requirements and other liabilities;
 
  •  fluctuations in our working capital needs;
 
  •  our ability to borrow funds and access capital markets;
 
  •  restrictions contained in debt agreements to which we are a party; and
 
  •  the amount of cash reserves established by our general partner.
 
Lower natural gas, NGL or oil prices could adversely affect our business.
 
Lower natural gas, NGL or oil prices could impact natural gas and oil exploration and production activity levels and result in a decline in the production of natural gas and condensate, resulting in reduced throughput on our systems. Any such decline may cause our current or potential customers to delay drilling or shut in production, and potentially affect our vendors’, suppliers’ and customers’ ability to continue operations. In addition, such a decline would reduce the amount of NGLs and condensate we retain and sell. As a result, lower natural gas prices could have an adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
 
In general terms, the prices of natural gas, oil, condensate, NGLs and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include:
 
  •  domestic and worldwide economic conditions;
 
  •  weather conditions and seasonal trends;
 
  •  the levels of domestic production and consumer demand, as affected by, among other things, concerns over inflation, geopolitical issues and the availability and cost of credit;
 
  •  the availability of imported liquefied natural gas, or “LNG;”
 
  •  the availability of transportation systems with adequate capacity;
 
  •  the volatility and uncertainty of regional pricing differentials such as in the Mid-Continent or Rocky Mountains;
 
  •  the price and availability of alternative fuels;
 
  •  the effect of energy conservation measures;
 
  •  the nature and extent of governmental regulation and taxation; and
 
  •  the anticipated future prices of natural gas, NGLs and other commodities.


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Our strategies to reduce our exposure to changes in commodity prices may fail to protect us and could reduce our financial condition and cash flows.
 
Based on gross margin for the year ended December 31, 2009, approximately 13% of our processing services are provided under percent-of-proceeds and keep-whole arrangements under which the associated revenues and expenses are directly correlated with the prices of natural gas and NGLs. This percentage may significantly increase as a result of future acquisitions, if any.
 
We pursue various strategies to seek to reduce our exposure to adverse changes in the prices for natural gas and NGLs. These strategies will vary in scope based upon the level and volatility of natural gas and NGL prices and other changing market conditions. We currently have in place fixed-price swap agreements with Anadarko to manage the commodity price risk otherwise inherent in our percent-of-proceeds and keep-whole contracts. To the extent that we engage in price risk management activities such as the swap agreements, we may be prevented from realizing the full benefits of price increases above the levels set by those activities. In addition, our commodity price management may expose us to the risk of financial loss in certain circumstances, including instances in which:
 
  •  the counterparties to our hedging or other price risk management contracts fail to perform under those arrangements; or
 
  •  we are unable to replace the existing hedging arrangements when they expire.
 
If we do not (or are unable to) effectively manage the commodity price risk associated with our commodity-exposed contracts, it could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
 
We may not be able to obtain funding or obtain funding on acceptable terms. This may hinder or prevent us from meeting our future capital needs.
 
Global financial markets and economic conditions have been, and continue to be volatile. While our sector has rebounded from lows seen in 2008, the repricing of credit risk and the current relatively weak economic conditions have made, and will likely continue to make, it difficult for some entities to obtain funding. In addition, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to the borrower’s current debt and reduced, or in some cases, ceased to provide funding to borrowers. Further, we may be unable to obtain adequate funding under our revolving credit facility or Anadarko’s $1.3 billion credit facility if Anadarko’s and/or our lending counterparties become unwilling or unable to meet their funding obligations. In addition, our access to Anadarko’s $1.3 billion credit facility may be limited if Anadarko has to draw down on its entire $1.3 billion credit facility in order to meet its own capital needs or the amount we may borrow under Anadarko’s $1.3 billion credit facility is reduced for other reasons. Due to these factors, we cannot be certain that funding will be available if needed and to the extent required, on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to execute our business plans, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our financial condition, results of operations or cash flows.
 
Restrictions in our revolving credit facility may limit our ability to make distributions and may limit our ability to capitalize on acquisition and other business opportunities.
 
The operating and financial restrictions and covenants in our revolving credit facility and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue business activities associated with our subsidiaries and equity investments. Our revolving credit facility contains covenants, some of which may be modified or eliminated upon our receipt of an investment grade rating, that restrict or limit our ability to:
 
  •  make distributions if any default or event of default, as defined, occurs;


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  •  make other distributions, dividends or payments on account of the purchase, redemption, retirement, acquisition, cancellation or termination of partnership interests;
 
  •  incur additional indebtedness or guarantee other indebtedness;
 
  •  grant liens to secure obligations other than our obligations under our revolving credit facility or agree to restrictions on our ability to grant additional liens to secure our obligations under our revolving credit facility;
 
  •  make certain loans or investments;
 
  •  engage in transactions with affiliates;
 
  •  make any material change to the nature of our business from the midstream energy business;
 
  •  dispose of assets; or
 
  •  enter into a merger, consolidate, liquidate, wind up or dissolve.
 
The financial covenants of our revolving credit facility include financial leverage and interest coverage ratios. The terms of the credit agreement require us to maintain a ratio of total debt to Consolidated Earnings Before Interest, Taxes, Depreciation and Amortization, or “EBITDA,” as defined in the credit agreement, of 4.5 or less. The terms of the credit agreement also require us to maintain a ratio of Consolidated EBITDA, as defined in the credit agreement, to interest expense of 3.0 or greater. As of December 31, 2009, we were in compliance with those covenants.
 
Anadarko’s credit facility and other debt instruments contain financial and operating restrictions that may limit our access to credit. In addition, our ability to obtain credit in the future may be affected by Anadarko’s credit rating.
 
We have the ability to incur up to $100.0 million of indebtedness under Anadarko’s $1.3 billion credit facility. However, this $100.0 million of borrowing capacity will be available to us only to the extent that sufficient amounts remain unborrowed by Anadarko. As a result, borrowings by Anadarko could restrict our access to this credit. In addition, if we or Anadarko were to fail to comply with the terms of this credit facility, we could be unable to make any borrowings under Anadarko’s credit facility, even if capacity were otherwise available. As a result, the restrictions in Anadarko’s credit facility could adversely affect our ability to finance our future operations or capital needs or to engage in, expand or pursue our business activities, and could also prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.
 
Anadarko’s and our ability to comply with the terms of its debt instruments may be affected by events beyond Anadarko’s or our control, including prevailing economic, financial and industry conditions. We and Anadarko are subject to covenants, and Anadarko is subject to a debt-to-capitalization ratio, under Anadarko’s credit facility. Should we or Anadarko fail to comply with any covenants under Anadarko’s credit facility, we could be unable to make any borrowings under that credit facility. Additionally, a default by Anadarko under one of its debt instruments may cause a cross-default under Anadarko’s other debt instruments, including the credit facility under which we are a co-borrower. Accordingly, a breach by Anadarko of certain of the covenants or ratios in another debt instrument could cause the acceleration of any indebtedness we might have outstanding under Anadarko’s credit facility. In the event of an acceleration, we might not have, or be able to obtain, sufficient funds to make the required repayments of debt, finance our operations and pay distributions to unitholders. For more information regarding our debt agreements, please see the caption Liquidity and Capital Resources under Item 7 of this annual report.
 
Due to our relationship with Anadarko, our ability to obtain credit will be affected by Anadarko’s credit rating. Even if we obtain our own credit rating, any future change in Anadarko’s credit rating would likely also result in a change in our credit rating. Regardless of whether we have our own credit rating, a downgrading of Anadarko’s credit rating could limit our ability to obtain financing in the future upon favorable terms or at all.


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Debt we owe or incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.
 
Future levels of indebtedness could have important consequences to us, including the following:
 
  •  our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
 
  •  our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;
 
  •  we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
 
  •  our flexibility in responding to changing business and economic conditions may be limited.
 
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to affect any of these actions on satisfactory terms or at all.
 
Increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.
 
Interest rates may increase in the future, whether because of inflation, increased yields on U.S. Treasury obligations or otherwise. In such cases, the interest rates on our floating rate debt, including amounts outstanding under our revolving credit facility and our five-year $175.0 million term loan with Anadarko (which after December 2010 will bear interest at a floating rate), would increase. If interest rates rise, our future financing costs could increase accordingly. In addition, as is true with other MLPs (the common units of which are often viewed by investors as yield-oriented securities), our unit price is impacted by our level of cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.
 
If Anadarko were to limit divestitures of midstream assets to us or if we were to be unable to make acquisitions on economically acceptable terms from Anadarko or third parties, our future growth would be limited. In addition, any acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per-unit basis.
 
Our ability to grow depends, in part, on our ability to make acquisitions that increase our cash generated from operations on a per-unit basis. The acquisition component of our strategy is based, in large part, on our expectation of ongoing divestitures of midstream energy assets by industry participants, including, most notably, Anadarko. A material decrease in such divestitures would limit our opportunities for future acquisitions and could adversely affect our ability to grow our operations and increase our distributions to our unitholders.
 
If we are unable to make accretive acquisitions from Anadarko or third parties, either because we are (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts, (ii) unable to obtain financing for these acquisitions on economically acceptable terms or (iii) outbid by competitors, then our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per-unit basis.


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Any acquisition involves potential risks, including, among other things:
 
  •  mistaken assumptions about volumes, revenues and costs, including synergies;
 
  •  an inability to successfully integrate the assets or businesses we acquire;
 
  •  the assumption of unknown liabilities;
 
  •  limitations on rights to indemnity from the seller;
 
  •  mistaken assumptions about the overall costs of equity or debt;
 
  •  the diversion of management’s and employees’ attention from other business concerns;
 
  •  unforeseen difficulties operating in new geographic areas; and
 
  •  customer or key employee losses at the acquired businesses.
 
If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.
 
The amount of cash we have available for distribution to holders of our common and subordinated units depends primarily on our cash flow rather than on our profitability; accordingly, we may be prevented from making distributions, even during periods in which we record net income.
 
The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.
 
The amount of available cash we need to pay the announced distribution on all of our units and the corresponding distribution on our general partner’s 2.0% interest for four quarters is approximately $85.6 million.
 
We typically do not obtain independent evaluations of natural gas reserves connected to our gathering, processing and transportation systems; therefore, in the future, volumes of natural gas on our systems could be less than we anticipate.
 
We typically do not obtain independent evaluations of natural gas reserves connected to our systems. Accordingly, we do not have independent estimates of total reserves connected to our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our systems are less than we anticipate and we are unable to secure additional sources of natural gas, it could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
 
Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.
 
We compete with similar enterprises in our areas of operation. Our competitors may expand or construct gathering, processing, compression, treating or transportation systems that would create additional competition for the services we provide to our customers. In addition, our customers, including Anadarko, may develop their own gathering, compression, treating, processing or transportation systems in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flow could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.


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Our results of operations could be adversely affected by asset impairments.
 
If natural gas and NGL prices continue to decrease, we may be required to write-down the value of our midstream properties if the estimated future cash flows from these properties fall below their net book value. Because we are an affiliate of Anadarko, the assets we acquire from it are recorded at Anadarko’s carrying value prior to the transaction. Accordingly, we may be at an increased risk for impairments because the initial book values of substantially all of our assets do not have a direct relationship with, and in some cases could be significantly higher than, the amounts we paid to acquire such assets.
 
Further, at December 31, 2009, we had approximately $20.8 million of goodwill on our balance sheet. Similar to the carrying value of the assets we acquired from Anadarko, our goodwill is an allocated portion of Anadarko’s goodwill, which we recorded as a component of the carrying value of the assets we acquired from Anadarko. As a result, we may be at increased risks for impairments relative to entities who acquire their assets from third parties or construct their own assets, as the carrying value of our goodwill does not reflect, and in some cases is significantly higher than, the difference between the consideration we paid for our acquisitions and the fair value of the net assets on the acquisition date.
 
Goodwill is not amortized, but instead must be tested at least annually for impairment, and more frequently when circumstances indicate likely impairment, by applying a fair-value-based test. Goodwill is deemed impaired to the extent that its carrying amount exceeds its implied fair value. Various factors could lead to goodwill impairments that could have a substantial negative effect on our profitability, such as if the Partnership is unable to replace the value of its depleting asset base or if other adverse events, such as lower sustained oil and gas prices, reduce the fair value of the associated reporting unit. Future non-cash asset impairments could negatively affect our results of operations.
 
If third-party pipelines or other facilities interconnected to our gathering or transportation systems become partially or fully unavailable, or if the volumes we gather or transport do not meet the natural gas quality requirements of such pipelines or facilities, our revenues and cash available for distribution could be adversely affected.
 
Our natural gas gathering and transportation systems connect to other pipelines or facilities, the majority of which are owned by third parties. The continuing operation of such third-party pipelines or facilities is not within our control. If any of these pipelines or facilities becomes unable to transport natural gas, or if the volumes we gather or transport do not meet the natural gas quality requirements of such pipelines or facilities, our revenues and cash available for distribution could be adversely affected.
 
Our margin from drip condensate sales is affected by changes in the relative prices of oil and gas.
 
Under our gathering agreements, we retain and sell drip condensate, which falls out of the natural gas stream during the gathering process, and compensate shippers with a thermally equivalent volume of natural gas. Condensate sales comprised a nominal amount of our total revenues for the year ended December 31, 2009. The price we receive for our drip condensate correlates to the market price of oil. The relationship between natural gas prices and oil prices therefore affects the margin on our drip condensate sales. When natural gas prices are high relative to oil prices, the profit margin we realize on our drip condensate sales is low due to the higher value of natural gas. Correspondingly, when natural gas prices are low relative to oil prices, the profit margin is relatively high.
 
Our interstate natural gas transportation operations are subject to regulation by FERC, which could have an adverse impact on our ability to establish transportation rates that would allow us to earn a reasonable return on our investment, or even recover the full cost of operating our pipeline, thereby adversely impacting our ability to make distributions.
 
MIGC, our interstate natural gas transportation system, is subject to regulation by FERC under the Natural Gas Act of 1938, or the “NGA,” and the EPAct 2005.


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Under the NGA, FERC has the authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. Federal regulation extends to such matters as:
 
  •  rates, services and terms and conditions of service;
 
  •  the types of services MIGC may offer to its customers;
 
  •  the certification and construction of new facilities;
 
  •  the acquisition, extension, disposition or abandonment of facilities;
 
  •  the maintenance of accounts and records;
 
  •  relationships between affiliated companies involved in certain aspects of the natural gas business;
 
  •  the initiation and discontinuation of services;
 
  •  market manipulation in connection with interstate sales, purchases or transportation of natural gas; and
 
  •  participation by interstate pipelines in cash management arrangements.
 
Natural gas companies are prohibited from charging rates that have been determined to be not just and reasonable by FERC. In addition, FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.
 
The rates and terms and conditions for our interstate pipeline services are set forth in a FERC-approved tariff. Pursuant to FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. Any successful complaint or protest against our rates could have an adverse impact on our revenues associated with providing transportation service.
 
Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EPAct 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation. FERC also has the power to order disgorgement of profits from transactions deemed to violate the NGA and EPAct 2005.
 
Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by our customers, which could adversely impact our revenues.
 
An increasing percentage of our customers’ oil and gas production is being developed from unconventional sources, such as deep gas shales. These reservoirs require hydraulic fracturing completion processes to release the gas from the rock so it can flow through casing to the surface. Hydraulic fracturing involves the injection of water, sand and, in some cases, chemicals under pressure into the formation to stimulate gas production. Certain environmental groups have suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process, and legislation has been proposed by some members of Congress to provide for such regulation. We cannot predict whether any such legislation will ever be enacted and if so, what its provisions would be. Additional levels of regulation and permits, if required through the adoption of new laws and regulations, could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of natural gas that move through our gathering systems. Such developments could materially adversely affect our revenues and results of operations.
 
The adoption of climate change legislation by the U.S. Congress or the issuance of new regulations by the U.S. Environmental Protection Agency with respect to climate change could increase our operating and capital costs and could have the indirect effect of decreasing demand for the products we gather, process and transport.
 
The American Clean Energy and Security Act of 2009, or “ACES,” also known as the “Waxman-Markey Bill,” was approved by the U.S. House of Representatives on June 26, 2009. ACES would establish a variant of a “cap-and-trade” plan for greenhouse gases, or “GHGs,” in order to address climate change and most sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their


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historical annual emissions of GHGs. The U.S. Senate is considering comparable “cap and trade” legislation. The number of emission allowances issued each year would decline as necessary to meet overall emission reduction goals. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. If ACES or similar legislation is ultimately passed by the U.S. Senate and enacted into law, the net effect will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas.
 
The EPA has also taken recent action related to greenhouse gases, including finalizing a GHG reporting rule in September 2009 that establishes a national GHG emissions collection and reporting program. Under this reporting rule, covered entities must begin measuring GHG emissions in 2010 and submit reports commencing 2011. Based on recent developments, the EPA now has the basis to begin regulating emissions of GHGs under existing provisions of the Federal Clean Air Act. Although it may take the EPA several years to adopt and impose regulations limiting emissions of GHGs, any limitation on emissions of GHGs from our equipment and operations could require us to incur significant costs to reduce emissions of GHGs associated with our operations, along with costs for maintaining records on and reporting GHG emissions.
 
Although it is not possible at this time to predict the impact of future EPA regulation or whether ACES or similar climate change legislation will become law, any such laws or regulations could create incentives to conserve energy or use alternative energy sources, or could cause a sustained and significant increase in the market prices of hydrocarbon-based products, in each case potentially reducing demand for natural gas and our services. Any of these developments could have an adverse effect on our business, financial condition, results of operations or cash flows.
 
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies could result in increased regulation of our assets, which could cause our revenues to decline and operating expenses to increase.
 
Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC. However, some of our gas gathering activities are subject to Internet posting requirements imposed by FERC as a result of FERC’s recent market transparency initiatives. We believe that our natural gas pipelines, other than MIGC, meet the traditional tests FERC has used to determine if a pipeline is a gathering pipeline and is, therefore, not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial ongoing litigation and, over time, FERC policy concerning where to draw the line between activities it regulates and activities excluded from its regulation has changed. The classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. In recent years, FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies, which has resulted in a number of such companies transferring gathering facilities to unregulated affiliates. As a result of these activities, natural gas gathering may begin to receive greater regulatory scrutiny at both the state and federal levels.
 
FERC regulation of MIGC, including the outcome of certain FERC proceedings on the appropriate treatment of tax allowances included in regulated rates and the appropriate return on equity, may reduce our transportation revenues, affect our ability to include certain costs in regulated rates and increase our costs of operations, and thus adversely affect our cash available for distribution.
 
FERC has certain proceedings pending, which concern the appropriate allowance for income taxes that may be included in cost-based rates for FERC-regulated pipelines owned by publicly traded partnerships that do not directly pay federal income tax. FERC issued a policy permitting such tax allowances in 2005. FERC’s policy and its initial application in a specific case were upheld on appeal by the D.C. Circuit in May of 2007 and the D.C. Circuit’s decision is final. In December 2006, FERC issued another order addressing the income tax allowance in rates, in which it reaffirmed prior statements regarding its income tax allowance policy, but raised a new issue regarding the implication of the policy statement for publicly traded partnerships. FERC noted that the tax deferral features of a publicly traded partnership may cause some investors to receive, for


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some indeterminate duration, cash distributions in excess of their taxable income, creating an opportunity for those investors to earn an additional return, funded by ratepayers. Responding to this concern, FERC adjusted the equity rate of return of the pipeline at issue downward based on the percentage by which the publicly traded partnership’s cash flow exceeded taxable income. Further procedures have been ordered in this proceeding and the proceeding is still pending before FERC.
 
FERC issued a policy statement on April 17, 2008, regarding the composition of proxy groups for purposes of determining natural gas and oil pipeline equity returns to be included in cost-of-service based rates. In the policy statement, FERC determined that MLPs should be included in the proxy group used to determine return on equity, and made various determinations on how the FERC’s Discounted Cash Flow, or “DCF,” methodology should be applied for MLPs. FERC also concluded that the policy statement should govern all gas and oil rate proceedings involving the establishment of return on equity that are pending before FERC. FERC’s application of the policy statement in individual pipeline proceedings is subject to challenge in those proceedings.
 
The ultimate outcome of these proceedings is not certain and may result in new policies being established by FERC applicable to MLPs. Any such policy developments may adversely affect the ability of MIGC to achieve a reasonable level of return or impose limits on its ability to include a full income tax allowance in cost of service, and therefore could adversely affect our cash available for distribution.
 
We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.
 
Our natural gas gathering, compression, treating, processing and transportation operations are subject to stringent and complex federal, state and local environmental laws and regulations that govern the discharge of materials into the environment or otherwise relate to environmental protection. Examples of these laws include:
 
  •  the federal Clean Air Act and analogous state laws that impose obligations related to air emissions;
 
  •  the federal Comprehensive Environmental Response, Compensation and Liability Act, also known as “CERCLA,” or the “Superfund law,” and analogous state laws that require and regulate the cleanup of hazardous substances that have been released at properties currently or previously owned or operated by us or at locations to which our wastes are or have been transported for disposal;
 
  •  the Clean Water Act and analogous state laws that regulate discharges from our facilities into state and federal waters, including wetlands;
 
  •  the federal RCRA and analogous state laws that impose requirements for the storage, treatment and disposal of solid and hazardous waste from our facilities; and
 
  •  the Toxic Substances Control Act, or “TSCA,” and analogous state laws that impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities.
 
These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to limit or prevent releases of materials from our pipelines and facilities, and the imposition of substantial liabilities for pollution resulting from our operations or existing at our owned or operated facilities. Numerous governmental authorities, such as the EPA, and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations.
 
There is an inherent risk of incurring significant environmental costs and liabilities in connection with our operations due to historical industry operations and waste disposal practices, our handling of hydrocarbon wastes and potential emissions and discharges related to our operations. Joint and several strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection


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with discharges or releases of substances or wastes on, under or from our properties and facilities, many of which have been used for midstream activities for many years, often by third parties not under our control. Private parties, including the owners of the properties through which our gathering or transportation systems pass and facilities where our wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations or financial position. Finally, future federal and/or state restrictions, caps, or taxes on greenhouse gas emissions that may be passed in response to climate-change concerns may impose additional capital investment requirements, increase our operating costs and reduce the demand for our services.
 
Our construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.
 
One of the ways we intend to grow our business is through the construction of new midstream assets. The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political and legal uncertainties that are beyond our control. Such expansion projects may also require the expenditure of significant amounts of capital, and financing may not be available on economically acceptable terms or at all. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand a pipeline, the construction may occur over an extended period of time, yet we will not receive any material increases in revenues until the project is completed. Moreover, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. Since we are not engaged in the exploration for and development of natural gas and oil reserves, we often do not have access to third-party estimates of potential reserves in an area prior to constructing facilities in that area. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate as a result of the numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. In addition, the construction of additions to our existing assets may require us to obtain new rights-of-way. We may be unable to obtain such rights-of-way and may, therefore, be unable to connect new natural gas volumes to our systems or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing existing or obtaining new rights-of-way increases, our cash flows could be adversely affected.
 
We have partial ownership interests in joint venture legal entities, which affects our ability to operate and/or control these entities. In addition, we may be unable to control the amount of cash we will receive or retain from the operation of these entities and we could be required to contribute significant cash to fund our share of their operations, which could adversely affect our ability to distribute cash to our unitholders.
 
Our inability, or limited ability, to control the operations and/or management of joint venture legal entities in which we have a partial ownership interest may result in our receiving or retaining less than the amount of cash we expect. We also may be unable, or limited in our ability, to cause any such entity to effect significant transactions such as large expenditures or contractual commitments, the construction or acquisition of assets, or the borrowing of money.
 
In addition, for Fort Union, an entity in which we have a minority ownership interest, we will be unable to control ongoing operational decisions, including the incurrence of capital expenditures or additional indebtedness that we may be required to fund. Further, Fort Union may establish reserves for working capital, capital projects, environmental matters and legal proceedings, that would similarly reduce the amount of cash


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available for distribution. Any of the above could significantly and adversely impact our ability to make cash distributions to our unitholders.
 
We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.
 
We do not own all of the land on which our pipelines and facilities have been constructed, and we are, therefore, subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
 
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not fully insured, our operations and financial results could be adversely affected.
 
Our operations are subject to all of the risks and hazards inherent in the gathering, compressing, processing, treating and transportation of natural gas, including:
 
  •  damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism;
 
  •  inadvertent damage from construction, farm and utility equipment;
 
  •  leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities;
 
  •  leaks of natural gas containing hazardous quantities of hydrogen sulfide from our Pinnacle gathering system or Bethel treating facility;
 
  •  fires and explosions; and
 
  •  other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.
 
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent in our business. For example, we do not have any property insurance on our underground pipeline systems that would cover damage to the pipelines. In addition, although we are insured for environmental pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to certain indemnification rights, for potential environmental liabilities.


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We are exposed to the credit risk of Anadarko and third-party customers, and any material non-payment or non-performance by these parties, including with respect to our gathering, processing and transportation agreements, our $260.0 million note receivable from Anadarko and our commodity price swap agreements with Anadarko, could reduce our ability to make distributions to our unitholders.
 
We are dependent on Anadarko for the majority of our revenues. Consequently, we are subject to the risk of non-payment or non-performance by Anadarko, including with respect to our gathering and transportation agreements, our $260.0 million note receivable and our commodity price swap agreements. Any such non-payment or non-performance could reduce our ability to make distributions to our unitholders. Furthermore, Anadarko is subject to its own financial, operating and regulatory risks, which could increase the risk of default on its obligations to us. We cannot predict the extent to which Anadarko’s business would be impacted if conditions in the energy industry were to deteriorate, nor can we estimate the impact such conditions would have on Anadarko’s ability to perform under our gathering and transportation agreements, note receivable or our commodity price swap agreements. Further, unless and until we receive full repayment of the $260.0 million note receivable from Anadarko, we will be subject to the risk of non-payment or late payment of the interest payments and principal of the note. Accordingly, any material non-payment or non-performance by Anadarko could reduce our ability to make distributions to our unitholders.
 
On some of our systems, we rely on a significant number of third-party customers for substantially all of our revenues related to those assets. The loss of all or even a portion of the contracted volumes of these customers, as a result of competition, creditworthiness, inability to negotiate extensions, or replacements of contracts or otherwise, could reduce our ability to make cash distributions to our unitholders.
 
The loss of, or difficulty attracting and retaining, experienced personnel could reduce our competitiveness and prospects for future success.
 
The successful execution of our growth strategy and other activities integral to our operations will depend, in part, on our ability to attract and retain experienced engineering, operating, commercial and other professionals. Competition for such professionals is intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be adversely impacted.
 
We are required to deduct estimated future maintenance capital expenditures from operating surplus, which may result in less cash available for distribution to unitholders than if actual maintenance capital expenditures were deducted.
 
Our partnership agreement requires us to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus will be subject to review and change by our special committee at least once a year. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders will be lower than if actual maintenance capital expenditures were deducted from operating surplus. If we underestimate the appropriate level of estimated maintenance capital expenditures, we may have less cash available for distribution in future periods when actual capital expenditures begin to exceed our previous estimates. Over time, if we do not set aside sufficient cash reserves or have sufficient sources of financing available and we make sufficient expenditures to maintain our asset base, we may be unable to pay distributions at the anticipated level and could be required to reduce our distributions.
 
RISKS INHERENT IN AN INVESTMENT IN US
 
Anadarko owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Anadarko and our general partner have conflicts of interest with, and may favor Anadarko’s interests to the detriment of our unitholders.
 
Anadarko owns and controls our general partner and has the power to appoint all of the officers and directors of our general partner, some of whom are also officers of Anadarko. Although our general partner


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has a fiduciary duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to its owner, Anadarko. Conflicts of interest may arise between Anadarko and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of Anadarko over our interests and the interests of our unitholders. These conflicts include the following situations, among others:
 
  •  Neither our partnership agreement nor any other agreement requires Anadarko to pursue a business strategy that favors us.
 
  •  Anadarko is not limited in its ability to compete with us and may offer business opportunities or sell midstream assets to parties other than us.
 
  •  Our general partner is allowed to take into account the interests of parties other than us, such as Anadarko, in resolving conflicts of interest.
 
  •  The officers of our general partner will also devote significant time to the business of Anadarko and will be compensated by Anadarko accordingly.
 
  •  Our partnership agreement limits the liability of and reduces the fiduciary duties owed by our general partner, and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.
 
  •  Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.
 
  •  Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.
 
  •  Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert to common units.
 
  •  Our general partner determines which costs incurred by it are reimbursable by us.
 
  •  Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.
 
  •  Our partnership agreement permits us to classify up to $31.8 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights.
 
  •  Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.
 
  •  Our general partner intends to limit its liability regarding our contractual and other obligations.
 
  •  Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units.
 
  •  Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.


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  •  Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
 
  •  Our general partner may elect to cause us to issue Class B units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the special committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
 
Please read Item 13 of this annual report.
 
Anadarko is not limited in its ability to compete with us and is not obligated to offer us the opportunity to acquire additional assets or businesses, which could limit our ability to grow and could adversely affect our results of operations and cash available for distribution to our unitholders.
 
Anadarko is not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, in the future, Anadarko may acquire, construct or dispose of additional midstream or other assets and may be presented with new business opportunities, without any obligation to offer us the opportunity to purchase or construct such assets or to engage in such business opportunities. Moreover, while Anadarko may offer us the opportunity to buy additional assets from it, it is under no contractual obligation to do so and we are unable to predict whether or when such acquisitions might be completed.
 
Cost reimbursements due to Anadarko and our general partner for services provided to us or on our behalf will be substantial and will reduce our cash available for distribution to our unitholders. The amount and timing of such reimbursements will be determined by our general partner.
 
Prior to making distributions on our common units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf. These expenses will include all costs incurred by Anadarko and our general partner in managing and operating us. While our reimbursement of allocated general and administrative expenses is capped until December 31, 2010 under the omnibus agreement, we are required to reimburse Anadarko and our general partner for all direct operating expenses incurred on our behalf. These direct operating expense reimbursements and the reimbursement of incremental general and administrative expenses we will incur as a result of being a publicly traded partnership are not capped. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursements to Anadarko and our general partner will reduce the amount of cash otherwise available for distribution to our unitholders.
 
If you are not an Eligible Holder, you may not receive distributions or allocations of income or loss on your common units and your common units will be subject to redemption.
 
We have adopted certain requirements regarding those investors who may own our common and subordinated units. Eligible Holders are U.S. individuals or entities subject to U.S. federal income taxation on the income generated by us or entities not subject to U.S. federal income taxation on the income generated by us, so long as all of the entity’s owners are U.S. individuals or entities subject to such taxation. If you are not an Eligible Holder, our general partner may elect not to make distributions or allocate income or loss on your units and you run the risk of having your units redeemed by us at the lower of your purchase price cost and the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.
 
Our general partner’s liability regarding our obligations is limited.
 
Our general partner included provisions in its and our contractual arrangements that limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general


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partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.
 
Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
 
We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. Furthermore, we used substantially all of the net proceeds from our initial public offering to make a loan to Anadarko, and therefore, the net proceeds from our initial public offering was not used to grow our business.
 
In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per-unit distribution level. There are no limitations in our partnership agreement or in Anadarko’s credit facility, under which we are a co-borrower, on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.
 
Our partnership agreement limits our general partner’s fiduciary duties to holders of our common and subordinated units.
 
Our partnership agreement contains provisions that modify and reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:
 
  •  how to allocate corporate opportunities among us and its affiliates;
 
  •  whether to exercise its limited call right;
 
  •  how to exercise its voting rights with respect to the units it owns;
 
  •  whether to exercise its registration rights;
 
  •  whether to elect to reset target distribution levels; and
 
  •  whether or not to consent to any merger or consolidation of the Partnership or amendment to the partnership agreement.
 
By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above.


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Our partnership agreement restricts the remedies available to holders of our common and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
 
Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement:
 
  •  provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
 
  •  provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith, meaning that it believed that the decision was in the best interest of our partnership;
 
  •  provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
 
  •  provides that our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is:
 
(a) approved by the special committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;
 
(b) approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;
 
(c) on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
 
(d) fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
 
In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the special committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in subclauses (c) and (d) above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
 
Our general partner may elect to cause us to issue Class B and general partner units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the special committee of its board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.
 
Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our general partner,


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the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.
 
If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of Class B units and general partner units. The Class B units will be entitled to the same cash distributions per unit as our common units and will be convertible into an equal number of common units. The number of Class B units to be issued to our general partner will be equal to that number of common units which would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued Class B units, which are entitled to distributions on the same priority as our common units, rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new Class B units and general partner units to our general partner in connection with resetting the target distribution levels.
 
Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.
 
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner will be chosen by Anadarko. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
 
Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.
 
The unitholders initially will be unable to remove our general partner without its consent because our general partner and its affiliates currently own sufficient units to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding limited partner units voting together as a single class is required to remove our general partner. As of March 1, 2010, Anadarko owns 56.3% of our outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud, gross negligence or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of the unitholder’s


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dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.
 
Our partnership agreement restricts the voting rights of certain unitholders owning 20% or more of our common units.
 
Unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.
 
Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.
 
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of Anadarko to transfer all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers.
 
We may issue additional units without unitholder approval, which would dilute existing ownership interests.
 
Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
 
  •  our existing unitholders’ proportionate ownership interest in us will decrease;
 
  •  the amount of cash available for distribution on each unit may decrease;
 
  •  because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
 
  •  the ratio of taxable income to distributions may increase;
 
  •  the relative voting strength of each previously outstanding unit may be diminished; and
 
  •  the market price of the common units may decline.
 
Anadarko may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.
 
As of March 1, 2010, Anadarko holds an aggregate of 9,254,435 common units and 26,536,306 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier under certain circumstances. The sale of any or all of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market on which common units are traded.
 
Our general partner has a limited call right that may require existing unitholders to sell their units at an undesirable time or price.
 
If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price. As a result, existing unitholders may be required to sell their common


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units at an undesirable time or price and may not receive any return on their investment. Existing unitholders may also incur a tax liability upon a sale of their units. As of March 1, 2010, Anadarko owns approximately 25.0% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (other than upon the conversion of the subordinated units), Anadarko will own approximately 56.3% of our outstanding common units.
 
Unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.
 
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for any and all of our obligations as if that unitholder were a general partner if a court or government agency were to determine that:
 
  •  we were conducting business in a state but had not complied with that particular state’s partnership statute; or
 
  •  that unitholder’s right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
 
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
 
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.
 
We incur increased costs as a result of being a publicly traded partnership.
 
We have no history operating as a publicly traded partnership prior to our initial public offering. As a publicly traded partnership, we incur significant legal, accounting and other expenses. In addition, the Sarbanes-Oxley Act of 2002 and related rules subsequently implemented by the SEC and the New York Stock Exchange, or the “NYSE,” have required changes in the corporate governance practices of publicly traded companies. We expect these rules and regulations to increase our legal and financial compliance costs compared to our historical costs and to make activities more time-consuming and costly.
 
If we are deemed to be an “investment company” under the Investment Company Act of 1940, it would adversely affect the price of our common units and could have a material adverse effect on our business.
 
Our assets include, among other items, a $260.0 million note receivable from Anadarko. If this note receivable together with a sufficient amount of our other assets are deemed to be “investment securities,” within the meaning of the Investment Company Act of 1940, or the “Investment Company Act,” we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify our organizational structure or contract rights so as to fall outside of the definition of investment company. Registering as an investment company could, among other things, materially limit our


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ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property from or to our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates. The occurrence of some or all of these events would adversely affect the price of our common units and could have a material adverse effect on our business.
 
Moreover, treatment of us as an investment company would prevent our qualification as a partnership for federal income tax purposes, in which case we would be treated as a corporation for federal income tax purposes. As a result, we would pay federal income tax on our taxable income at the corporate tax rate, distributions to our unitholders would generally be taxed again as corporate distributions and none of our income, gains, losses or deductions would flow through to our unitholders. If we were taxed as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as an investment company would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
 
The market price of our common units could be volatile due to a number of factors, many of which are beyond our control.
 
The market price of our common units could be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:
 
  •  changes in securities analysts’ recommendations and their estimates of our financial performance;
 
  •  the public’s reaction to our press releases, announcements and our filings with the SEC;
 
  •  fluctuations in broader securities market prices and volumes, particularly among securities of midstream companies and securities of publicly-traded limited partnerships;
 
  •  changes in market valuations of similar companies;
 
  •  departures of key personnel;
 
  •  commencement of or involvement in litigation;
 
  •  variations in our quarterly results of operations or those of midstream companies;
 
  •  variations in the amount of our quarterly cash distributions;
 
  •  future issuances and sales of our common units; and
 
  •  changes in general conditions in the U.S. economy, financial markets or the midstream industry.
 
In recent years, the capital markets have experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.
 
TAX RISKS TO COMMON UNITHOLDERS
 
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders could be substantially reduced.
 
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, or the “IRS,” on this or any other tax matter affecting us.


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Despite the fact that we are classified as a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe, based upon our current operations, that we will be so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
 
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
 
Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to a material amount of entity-level taxation at the state or federal level. In addition, if we are deemed to be an investment company, as described above, we would be subject to such taxation.
 
At the state level, were we to be subject to federal income tax, we would also be subject to the income tax provisions of many states. Moreover, because of widespread state budget deficits and other reasons, several states are evaluating ways to independently subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay Texas margin tax at a maximum effective rate of 0.7% of our gross income apportioned to Texas. Imposition of such a tax on us by Texas and, if applicable, by any other state will reduce the cash available for distribution to our unitholders.
 
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
 
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
 
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the U.S. federal income tax laws or interpretations thereof could make it more difficult or impossible to meet the requirements for us to be treated as a partnership for U.S. federal income tax purposes, affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our common units. Modifications to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively. We are unable to predict any particular change. Any potential change in law or interpretation thereof could negatively impact the value of an investment in our common units.
 
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
 
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the


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IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
 
If the IRS contests the federal income tax positions we take or the pricing of our related party agreements with Anadarko, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.
 
We have not requested a ruling from the IRS with respect to the pricing of our related party agreements with Anadarko. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of or the positions we take. A court may not agree with some or all of the positions we take. For example, the IRS may reallocate items of income, deductions, credits or allowances between related parties if the IRS determines that such reallocation is necessary to clearly reflect the income of any such related parties. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. If the IRS were successful in any such challenge, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders and our general partner. Such a reallocation may require us and our unitholders to file amended tax returns. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
 
Our unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
 
Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income whether or not our unitholders receive cash distributions from us.
 
Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.
 
Tax gain or loss on the disposition of our common units could be more or less than expected.
 
If a unitholder disposes of common units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and that unitholder’s tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease that unitholder’s tax basis in its common units, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxable income to her, if she sells such units at a price greater than her tax basis in those units, even if the price received is less than the original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells her units, she may incur a tax liability in excess of the amount of cash received from the sale.
 
Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
 
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts, or “IRAs,” and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons may be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons may be required to file U.S. federal tax returns and pay tax on their share of our taxable income. Any tax-exempt entity or a non-U.S. person should consult its tax advisor before investing in our common units.


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We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
 
Because we cannot match transferors and transferees of common units, we adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. Our counsel is unable to opine on the validity of such filing positions. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from any sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to a unitholder’s tax returns.
 
We adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between our general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
 
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our general partner and certain of our unitholders.
 
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
 
A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
 
Because a unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of the loaned common units, the unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.
 
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
 
We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year, which would require us to file two tax returns (and could result in our unitholders receiving two K-1 Schedules) for one fiscal year, and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of


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our taxable year may also result in more than twelve months of our taxable income or loss being includable in the unitholder’s taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties, if we are unable to determine that a termination occurred.
 
Our unitholders are subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our common units.
 
In addition to federal income taxes, our unitholders are subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own assets and conduct business in the states of Kansas, Oklahoma, Texas, Utah and Wyoming. Each of these states, other than Texas and Wyoming, currently imposes a personal income tax, and all of these states impose income taxes on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is the responsibility of each unitholder to file all required U.S. federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units.
 
Item 1B.   Unresolved Staff Comments
 
None
 
Item 3.   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. Please see Items 1 and 2 of this annual report for more information.


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Item 4.   Reserved
 
PART II
 
Item 5.   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
MARKET INFORMATION
 
Our common units are listed on the New York Stock Exchange under the symbol “WES.” Common units began trading on May 9, 2008 at an initial offering price of $16.50 per unit. Prior to May 9, 2008, our equity securities were not listed on any exchange or traded in any public market. The following table sets forth the high and low closing prices of the common units as well as the amount of cash distributions declared and paid during each quarter since our initial public offering.
 
                                 
    Fourth
  Third
  Second
  First
    Quarter   Quarter   Quarter   Quarter
 
2009
                               
High Price
  $ 19.73     $ 17.90     $ 15.65     $ 15.62  
Low Price
  $ 17.51     $ 15.39     $ 13.96     $ 12.63  
Distribution per common and subordinated unit
  $ 0.32     $ 0.31     $ 0.30     $ 0.30  
2008
                               
High Price
  $ 15.17     $ 16.96     $ 17.25        
Low Price
  $ 10.58     $ 13.02     $ 16.15        
Distribution per common and subordinated unit
  $ 0.30     $ 0.16              
 
As of March 1, 2010, there were approximately 15 unitholders of record of the Partnership’s common units. This number does not include unitholders whose units are held in trust by other entities. The actual number of unitholders is greater than the number of holders of record. We have also issued 26,536,306 subordinated units and 1,296,570 general partner units, for which there is no established public trading market. All of the subordinated units and general partner units are held by affiliates of our general partner. Our general partner and its affiliates receive quarterly distributions on these units only after sufficient funds have been paid to the common units.
 
USE OF PROCEEDS FROM SALE OF SECURITIES
 
We completed our initial public offering of 20,810,875 common units, including 2,060,875 common units sold pursuant to the partial exercise by the underwriters of their option to purchase additional common units at a price of $16.50 per unit. In connection with the offering, we issued to our general partner 1,083,115 general partner units and 100% of our IDRs, which entitle our general partner to increasing percentages up to a maximum of 50.0% of cash distributions based on the amount of the quarterly cash distribution. We also issued 5,725,431 common units and 26,536,306 subordinated units to a subsidiary of Anadarko. Subsidiaries of Anadarko contributed our initial assets to us in connection with the offering.
 
Net proceeds of $321.1 million (net of $22.3 million of underwriting discount and structuring fees) from our initial public offering were used (i) to pay approximately $5.9 million in expenses associated with the offering and the transactions related thereto, (ii) to make a loan of $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.5%, (iii) to reimburse Anadarko $45.2 million from offering proceeds and (iv) retained $10.0 million for general partnership purposes.
 
We completed our 2009 equity offering of 6,900,000 common units, including 900,000 common units issued pursuant to the full exercise by the underwriters of their option to purchase additional common units at a price of $18.20 per unit. Net proceeds from the offering of approximately $122.5 million were used to repay $100.0 million outstanding under our revolving credit facility and to partially fund our January 2010 Granger acquisition. The net proceeds included $2.5 million from Anadarko in exchange for 140,817 general partner units.


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SELECTED INFORMATION FROM OUR PARTNERSHIP AGREEMENT
 
Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions, minimum quarterly distributions and IDRs.
 
Available cash.  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 our partnership agreement) to unitholders of record on the applicable record date. The amount of available cash generally is all cash on hand at the end of the quarter less the amount of cash reserves established by our general partner to provide for the proper conduct of our business, including reserves to fund future capital expenditures, to comply with applicable laws, or our debt instruments and other agreements, or to provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters. Working capital borrowings generally include borrowings made under a credit facility or similar financing arrangement.
 
Minimum quarterly distributions.  The partnership agreement provides that, during a period of time referred to as the “subordination period,” the common units are entitled to distributions of available cash each quarter in an amount equal to the “minimum quarterly distribution,” which is $0.30 per common unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash are permitted on the subordinated units. Furthermore, arrearages do not apply to and, therefore, will not be paid on the subordinated units. The effect of the subordinated units is to increase the likelihood that, during the subordination period, available cash is sufficient to fully fund cash distributions on the common units in an amount equal to the minimum quarterly distribution.
 
The subordination period will lapse at such time when the Partnership has paid at least $0.30 per quarter on each common unit, subordinated unit and general partner unit for any three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2011. Also, if the Partnership has paid at least $0.45 per quarter (150% of the minimum quarterly distribution) on each outstanding common unit, subordinated unit and general partner unit for each calendar quarter in a four-quarter period, the subordination period will terminate automatically. The subordination period will also terminate automatically if the general partner is removed without cause and the units held by the general partner and its affiliates are not voted in favor of such removal. When the subordination period lapses or otherwise terminates, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to preferred distributions on prior-quarter distribution arrearages. All subordinated units are held indirectly by Anadarko.
 
General partner interest and incentive distribution rights.  The general partner is currently entitled to 2.0% of all quarterly distributions that the Partnership makes prior to its liquidation. After distributing amounts equal to the minimum quarterly distribution to common and subordinated unitholders and distributing amounts to eliminate any arrearages to common unitholders, our general partner is entitled to incentive distributions pursuant to its ownership of our IDRs if the amount we distribute with respect to any quarter exceeds specified target levels shown below:
 
                     
        Marginal Percentage
    Total Quarterly Distribution
  Interest in Distributions
    Target Amount   Unitholders   General Partner
 
Minimum Quarterly Distribution
  $0.300     98 %     2 %
First Target Distribution
  up to $0.345     98 %     2 %
Second Target Distribution
  above $0.345 up to $0.375     85 %     15 %
Third Target distribution
  above $0.375 up to $0.450     75 %     25 %
Thereafter
  above $0.45     50 %     50 %
 
The table above assumes that our general partner maintains its 2% general partner interest, that there are no arrearages on common units and our general partner continues to own the IDRs. The maximum distribution sharing percentage of 50.0% includes distributions paid to the general partner on its 2.0% general partner interest and does not include any distributions that the general partner may receive on limited partner units that it may own or acquire.


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OTHER SECURITIES MATTERS
 
Sales of Unregistered Units.  In connection with our 2009 equity offering, our general partner purchased an additional 140,817 general partner units to maintain its 2% general partner interest in us. In July 2009, we acquired the Chipeta assets from Anadarko for consideration consisting of $101.5 million cash, 351,424 of our common units and 7,172 of our general partner units. Further, in December 2008, we acquired the Powder River assets from Anadarko for consideration consisting of $175.0 million cash, 2,556,891 of our common units and 52,181 of our general partner units. The common units and general partner units issued in connection with these transactions were issued to our general partner or other subsidiaries of Anadarko in private placements that were not registered with the SEC.
 
Securities Authorized for Issuance Under Equity Compensation Plans.  In connection with the closing of our initial public offering, our general partner adopted the Western Gas Partners, LP 2008 Long-Term Incentive Plan, or “LTIP,” which permits the issuance of up to 2,250,000 units. Phantom unit grants have been made to each of the independent directors of our general partner and certain employees under the LTIP. Please read the information under Item 12 of this annual report, which is incorporated by reference into this Item 5.
 
Item 6.   Selected Financial and Operating Data
 
The following table shows our selected financial and operating data for the periods and as of the dates indicated, which is derived from our consolidated financial statements. In May 2008, we closed our initial public offering. Concurrent with the closing of the offering, Anadarko contributed to us the assets and liabilities of AGC, PGT and MIGC, which we refer to as our “initial assets.” In December 2008, we closed the Powder River acquisition with Anadarko and in July 2009, we closed the Chipeta acquisition with Anadarko. Anadarko acquired MIGC and the Powder River assets in connection with its August 23, 2006 acquisition of Western and Anadarko acquired the Chipeta assets in connection with its August 10, 2006 acquisition of Kerr-McGee.
 
Our acquisition of the initial assets, the Powder River acquisition and the Chipeta acquisition are considered transfers of net assets between entities under common control. Accordingly, our consolidated financial statements include the combined financial results and operations of AGC and PGT from their inception through the closing date of our initial public offering and to Western Gas Partners, LP and its subsidiaries thereafter, combined with the financial results and operations of MIGC and the Powder River assets, from August 23, 2006 thereafter, and combined with the financial results and operations of the Chipeta assets, from August 10, 2006 thereafter.


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The information in the following table should be read together with Item 7 of this annual report.
 
                                         
    Summary Financial Information  
    2009     2008(1)     2007(1)     2006(1)     2005  
    (In thousands, except per unit data,
 
    throughput and gross margin per Mcf)  
 
Statement of Income Data (for the year ended):
                                       
Total revenues
  $ 245,119     $ 344,506     $ 261,493     $ 128,610     $ 71,650  
Costs and expenses
    124,424       212,943       166,994       80,752       35,720  
Depreciation, amortization and impairment
    40,065       45,396       30,785       20,230       15,447  
                                         
Total operating expenses
    164,489       258,339       197,779       100,982       51,167  
                                         
Operating income
    80,630       86,167       63,714       27,628       20,483  
Interest income (expense), net
    6,945       9,191       (7,805 )     (9,574 )     (8,650 )
Other income (expense), net
    42       196       (15 )     (26 )     66  
Income tax expense(2)
    12       13,988       19,424       5,327       4,789  
                                         
Net income
    87,605       81,566       36,470       12,701       7,110  
Net income (loss) attributable to noncontrolling interests
    10,260       7,908       (92 )            
                                         
Net income attributable to Western Gas Partners, LP
  $ 77,345     $ 73,658     $ 36,562     $ 12,701     $ 7,110  
                                         
Key Performance Measures (for the year ended):
                                       
Gross margin(3)
  $ 193,983     $ 204,496     $ 149,211     $ 86,804     $ 65,643  
Adjusted EBITDA(4)
    111,160       124,457       91,831       47,239       35,930  
Distributable cash flow(4)
    102,176       117,277       n/a       n/a       n/a  
General partner’s interest in net income(5)
    1,428       842       n/a       n/a       n/a  
Common unitholders’ interest in net income(5)
    37,035       20,841       n/a       n/a       n/a  
Subordinated unitholders’ interest in net income(5)
    32,945       20,420       n/a       n/a       n/a  
Net income per common unit (basic and diluted)
  $ 1.25     $ 0.78       n/a       n/a       n/a  
Net income per subordinated unit (basic and diluted)
  $ 1.24     $ 0.77       n/a       n/a       n/a  
Distributions per unit
  $ 1.23     $ 0.46       n/a       n/a       n/a  
Balance Sheet Data (at period end):
                                       
Property, plant and equipment, net
  $ 700,496     $ 686,353     $ 607,971     $ 478,873     $ 200,451  
Total assets
    1,084,229       1,033,155       646,914       518,337       206,373  
Total long-term liabilities
    187,667       186,095       139,684       140,071       37,664  
Total partners’ capital and equity
  $ 878,449     $ 804,625     $ 494,537     $ 366,532     $ 160,585  
Cash Flow Data (for the year ended):
                                       
Net cash provided by (used in):
                                       
Operating activities
  $ 113,958     $ 145,430     $ 73,223     $ 33,304     $ 30,131  
Investing activities
    (164,007 )     (542,586 )     (143,274 )     (42,963 )     (21,076 )
Financing activities
    83,959       433,230       69,593       10,113       (9,067 )
Capital expenditures
  $ 62,174     $ 99,491     $ 136,874     $ 42,963     $ 20,841  
Operating Data (volumes in MMcf/d):
                                       
Gathering and transportation throughput
    883       967       987       971       798  
Processing throughput(6)
    396       283       31       30        
Equity investment throughput(7)
    120       112       84              
                                         
Total throughput
    1,399       1,362       1,102       1,001       798  
Throughput attributable to noncontrolling interests
    180       124                    
                                         
Throughput attributable to Western Gas Partners, LP
    1,219       1,238       1,102       1,001       798  
Average gross margin per Mcf(8)
  $ 0.38     $ 0.41     $ 0.37     $ 0.23     $ 0.22  
Average gross margin per Mcf attributable to Western Gas Partners, LP
  $ 0.40     $ 0.42     $ 0.37     $ 0.23     $ 0.22  
 
 
(1) Financial information for 2008, 2007 and 2006 has been revised to include results attributable to the Chipeta acquisition. See Note 1 — Description of Business and Basis of Presentation — Chipeta Acquisition of the notes to the consolidated financial statements in under Item 8 of this annual report.
 
(2) 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


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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. See Note 6 — Transactions with Affiliates of the notes to the consolidated financial statements in under Item 8 of this annual report.
 
(3) We define gross margin as total revenues less cost of product.
 
(4) Adjusted EBITDA and distributable cash flow are not defined in GAAP. For descriptions and reconciliations of Adjusted EBITDA and distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with GAAP, please see the caption How We Evaluate Our Operations under Item 7 of this annual report. We did not utilize a distributable cash flow measure prior to becoming a publicly traded partnership in 2008 and, as such, did not differentiate between maintenance and capital expenditures prior to 2008.
 
(5) 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. Prior to our acquisition of the Partnership Assets, all income is attributed to the Parent. See Note 5 — Net Income per Limited Partner Unit of the notes to the consolidated financial statements under Item 8 of this annual report.
 
(6) Processing throughput consists of 100% of Chipeta and Hilight plant volumes and 50% of Newcastle plant volumes.
 
(7) Equity investment throughput represents the Partnership’s 14.81% share of Fort Union’s gross volumes.
 
(8) 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 14.81% interest in income and volumes attributable to Fort Union.
 
Item 7.   Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
OVERVIEW
 
We are a growth-oriented Delaware 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.
 
OPERATING AND FINANCIAL HIGHLIGHTS
 
We achieved significant milestones during 2009. Significant operational and financial highlights include:
 
  •  In July 2009, we acquired a 51% membership interest in Chipeta Processing LLC, or “Chipeta,” together with related midstream assets from Anadarko.
 
  •  In October 2009, we entered into a three-year senior unsecured revolving credit facility with aggregate initial commitments of $350.0 million. This revolving credit facility matures in October 2012 and bears interest at a variable rate.
 
  •  In December 2009, we issued 6,900,000 common units at a price of $18.20 per unit to the public. Net proceeds from the offering of approximately $122.5 million were used to repay $100.0 million outstanding under our revolving credit facility and to partially fund the January 2010 Granger acquisition.
 
  •  Our stable operating cash flow along with our Chipeta acquisition, combined with a focus on cost reduction and capital spending discipline, enabled us to raise our distribution over three consecutive


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  quarters to $0.33 per unit for the fourth quarter of 2009, representing a 10.0% increase over the distribution for the fourth quarter of 2008.
 
  •  Although the current commodity price environment, particularly for natural gas, has resulted in lower drilling activity throughout the areas in which we operate, throughput decreases were substantially offset by throughput increases at the Chipeta plant and Fort Union system due to facility expansions. The throughput attributable to Western Gas Partners, LP, for the year ended December 31, 2009, totaled approximately 1,219 MMcf/d, representing an approximate 2% decrease compared to the year ended December 31, 2008.
 
ACQUISITIONS
 
Concurrent with the closing of the initial public offering in May 2008, Anadarko contributed the assets and liabilities of AGC, PGT and MIGC to us in exchange for a 2.0% general partner interest, 100% of the IDRs, 5,725,431 common units and 26,536,306 subordinated units. In connection with the Powder River acquisition in December 2008, Anadarko contributed the Powder River assets to us for consideration consisting of $175.0 million in cash, which was funded by a note from Anadarko, 2,556,891 common units and 52,181 general partner units. In connection with the Chipeta acquisition in July 2009, Anadarko contributed the Chipeta assets to us for consideration consisting of $101.5 million in cash, which was funded by a note from Anadarko, 351,424 common units and 7,172 general partner units. In November 2009, Chipeta closed its $9.1 million acquisition from a third party of the Natural Buttes plant. In connection with the Granger acquisition in January 2010, Anadarko contributed the Granger assets to us for consideration consisting of $241.7 million in cash, which was funded with $210.0 million of borrowings under our revolving credit facility and $31.7 million of cash on hand, as well as the issuance of 620,689 common units to Anadarko and 12,677 general partner units to our general partner. See the caption Acquisitions under Items 1 and 2 of this annual report for additional transaction and asset descriptions.
 
Because Anadarko owns the Partnership’s general partner, each acquisition of Partnership Assets, except the Natural Buttes plant, was considered a transfer of net assets between entities under common control. As a result, after each acquisition of assets from Anadarko, we are required to revise our financial statements to include the activities of the those assets as of the date of common control. Our historical financial statements for the years ended December 31, 2008 and 2007 as presented in our annual report on Form 10-K for the year ended December 31, 2008, which included the results attributable to the Powder River assets, have been recast to reflect the results attributable to the Chipeta assets as if the Partnership owned a 51% interest in Chipeta and associated midstream assets for all periods presented. The following tables present the impact to the consolidated statements of income attributable to the Chipeta assets (in thousands):
 
                         
    Partnership
    Chipeta
       
    Historical     Acquisition     Combined  
    Year Ended December 31, 2008
                         
Revenues
  $ 311,648     $ 32,858     $ 344,506  
Operating expenses
    241,931       16,408       258,339  
                         
Operating income
    69,717       16,450       86,167  
Interest and other income, net
    9,336       51       9,387  
                         
Income before income taxes
    79,053       16,501       95,554  
Income tax expense
    13,777       211       13,988  
                         
Net income
    65,276       16,290       81,566  
Net income attributable to noncontrolling interests
          7,908       7,908  
                         
Net income attributable to Western Gas Partners, LP
  $ 65,276     $ 8,382     $ 73,658  
                         


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    Partnership
    Chipeta
       
    Historical     Acquisition     Combined  
    Year Ended December 31, 2007
Revenues
  $ 261,493     $     $ 261,493  
Operating expenses
    197,475       304       197,779  
                         
Operating income
    64,018       (304 )     63,714  
Interest and other (expense), net
    (7,820 )           (7,820 )
                         
Income (loss) before income taxes
    56,198       (304 )     55,894  
Income tax expense (benefit)
    19,540       (116 )     19,424  
                         
Net income
    36,658       (188 )     36,470  
Net income (loss) attributable to noncontrolling interests
          (92 )     (92 )
                         
Net income attributable to Western Gas Partners, LP
  $ 36,658     $ (96 )   $ 36,562  
                         
 
OUR OPERATIONS
 
The following discussion analyzes our financial condition and results of operations and should be read in conjunction with our historical consolidated financial statements, and the notes thereto, included in Item 8 and Item 1A of this annual report. For ease of reference, we refer to the historical financial results of the Partnership Assets prior to our acquisitions as being “our” historical financial results. Unless the context otherwise requires, references to “we,” “us,” “our,” “the Partnership” or “Western Gas Partners” are intended to refer to the business and operations of AGC and PGT from their inception through the closing date of our initial public offering and to Western Gas Partners, LP and its subsidiaries thereafter, combined with the business and operations of MIGC and the Powder River assets since August 23, 2006 and combined with the business and operations of the Chipeta assets since August 10, 2006. “Anadarko” refers to Anadarko Petroleum Corporation 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.
 
Our results are driven primarily by the volumes of natural gas we gather, compress, process, treat or transport through our systems. For the year ended December 31, 2009, approximately 87% of our total revenues and 79% of our gathering, processing and transportation throughput volumes were attributable to transactions entered into with Anadarko.
 
In our gathering operations, we contract with producers and customers to gather natural gas from individual wells located near our gathering systems. We connect wells to gathering lines through which natural gas may be compressed and delivered to a processing plant, treating facility or downstream pipeline, and ultimately to end users. We also treat a significant portion of the natural gas that we gather so that it will satisfy required specifications for pipeline transportation.
 
Effective January 1, 2008 and solely with respect to the gathering systems connected to our initial assets, we received a significant dedication from our largest customer, Anadarko. Specifically, Anadarko has dedicated to us all of the natural gas production it owns or controls from (i) wells that are currently connected to such gathering systems, and (ii) additional wells that are drilled within one mile of wells connected to such gathering systems, as those systems currently exist and as they are expanded to connect additional wells in the future. As a result, this dedication will continue to expand as additional wells are connected to these gathering systems.
 
Based on gross margin for the year ended December 31, 2009, approximately 80% of our services are provided pursuant to fee-based contracts under which we are paid a fixed fee based on the volume and thermal content of the natural gas we gather, process, compress, treat or transport. This type of contract provides us with a relatively stable revenue stream that is not subject to direct commodity-price risk, except to the extent that we retain and sell drip condensate that is recovered during the gathering of natural gas from the wellhead.

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Based on gross margin for the year ended December 31, 2009, approximately 13% of our services are provided pursuant to percent-of-proceeds and keep-whole contracts pursuant to which we have commodity price exposure. We have fixed-price swap agreements with Anadarko to manage the commodity price risk inherent in substantially all of our percent-of-proceeds and keep-whole contracts. See Note 6 — Transactions with Affiliates of the notes to the consolidated financial statements included under Item 8 of this annual report.
 
For the year ended December 31, 2009, approximately 3% of our gross margin is attributable to drip condensate and approximately 4% of our gross margin is attributable to equity income from our interest in Fort Union, changes in our imbalance positions and other revenue.
 
We also have indirect exposure to commodity price risk in that persistent low commodity prices may cause our current or potential customers to delay drilling or shut in production, which would reduce the volumes of natural gas available for gathering, compressing, treating, processing and transporting by our systems. We also bear a limited degree of commodity price risk through settlement of natural gas imbalances. Please read Item 7A of this annual report.
 
We provide a significant portion of our transportation services on our MIGC system through firm contracts that obligate our customers to pay a monthly reservation or demand charge, which is a fixed charge applied to firm contract capacity and owed by a customer regardless of the actual pipeline capacity used by that customer. When a customer uses the capacity it has reserved under these contracts, we are entitled to collect an additional commodity usage charge based on the actual volume of natural gas transported. These usage charges are typically a small percentage of the total revenues received from our firm capacity contracts. We also provide transportation services through interruptible contracts, pursuant to which a fee is charged to our customers based upon actual volumes transported through the pipeline.
 
As a result of our initial public offering, the Powder River acquisition and the Chipeta acquisition, the results of operations, financial condition and cash flows vary significantly for 2009 and 2008 as compared to periods ending prior to our initial public offering. Please see the caption Items Affecting the Comparability of Our Financial Results, set forth below in this Item 7.
 
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) gross margin, (3) operating and maintenance expenses, (4) general and administrative expenses, (5) Adjusted EBITDA and (6) distributable cash flow.
 
Throughput.  Throughput is the most important operational variable in assessing our ability to generate revenues. 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, recompletions of existing wells connected 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. During the year ended December 31, 2009, we added 52 receipt points to our systems with average initial throughput of approximately 4.0 MMcf/d per receipt point.
 
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.
 
Gross margin.  We define gross margin as total revenues less cost of product. We consider gross margin to provide information useful in assessing our results of operations and our ability to internally fund capital expenditures and to service or incur additional debt. Cost of product expenses include (i) costs associated with the purchase of natural gas and NGLs pursuant to our percent-of-proceeds and keep-whole processing


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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 and keep-whole contracts is mitigated through our commodity price swap agreements with Anadarko.
 
Operating and maintenance expenses.  We monitor operating and maintenance expenses to assess the impact of such costs on the profitability of our assets and to evaluate the overall efficiency of our operations. Operation and maintenance expenses include, among other things, field 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.
 
General and administrative expenses.  To help ensure the appropriateness of our general and administrative expenses and maximize our cash available for distribution, we monitor such expenses through comparison to prior periods, the annual budget approved by our general partner’s board of directors, as well as to general and administrative expenses incurred by similar midstream companies. 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. The amount required to be reimbursed by us to Anadarko for certain allocated general and administrative expenses was capped at $6.9 million for the year ended December 31, 2009. In connection with the January 2010 Granger acquisition, the cap under the omnibus agreement was increased to $8.3 million for the year ended December 31, 2010, subject to adjustment to reflect expansions of our operations through the acquisition or 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 further 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, 2010. 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. Public company expenses not subject to the cap contained in the omnibus agreement, excluding equity-based compensation, were $7.5 million and $4.5 million for the years ended December 31, 2009 and 2008, respectively.
 
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, expenses in excess of the omnibus cap, interest expense, income tax expense, depreciation and amortization, less income from equity investments, interest income, income tax benefit and other income (expense).


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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.
 
Distributable cash flow.  We define “distributable cash flow” as Adjusted EBITDA, plus interest income, less net cash paid for interest expense, maintenance capital expenditures, and income taxes. We use distributable cash flow to compare distributable cash flow to the cash distributions we expect to pay our unitholders. Using this measure, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. We believe this measure is useful to investors because this measurement is used by many companies, analysts and others in the industry as a performance measurement tool to evaluate our operating and financial performance and compare it with the performance of other publicly traded partnerships.
 
We did not utilize a distributable cash flow measure prior to becoming a publicly traded partnership in 2008 and, as such, did not differentiate between maintenance and capital expenditures prior to 2008 and do not report distributable cash flow for periods prior to 2008.
 
Distributable cash flow should not be considered an alternative to net income, earnings per unit, operating income, cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP. Distributable cash flow excludes some, but not all, items that affect net income and operating income and this measure may vary among other companies. Therefore, distributable cash flow as presented may not be comparable to a similarly titled measure of other companies. Furthermore, while distributable cash flow is a measure we use to assess our ability to make distributions to our unitholders, it should not be viewed as indicative of the actual amount of cash that we have available for distributions or that we plan to distribute for a given period.
 
Reconciliation to GAAP measures.  Adjusted EBITDA and distributable cash flow are not defined in GAAP. The GAAP measures most directly comparable to Adjusted EBITDA are net income attributable to Western Gas Partners, LP and net cash provided by operating activities and the GAAP measure most directly comparable to distributable cash flow is net income. Our non-GAAP financial measures of Adjusted EBITDA and distributable cash flow should not be considered as alternatives to the GAAP measures of net income or net cash provided by operating activities. Adjusted EBITDA has important limitations as an analytical tool because it excludes some, but not all, items that affect net income and net cash provided by operating activities. You should not consider Adjusted EBITDA or distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.
 
Management compensates for the limitations of Adjusted EBITDA and distributable cash flow as analytical tools by reviewing the comparable GAAP measures, understanding the differences between Adjusted EBITDA and distributable cash flow compared to (as applicable) net income and net cash provided by operating activities, and incorporating this knowledge into its decision-making processes. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results.


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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 and a reconciliation of the non-GAAP financial measure of distributable cash flow to the GAAP financial measure of net income:
 
                         
    Year Ended December 31,  
    2009     2008(1)     2007(1)  
          (In thousands)        
 
Reconciliation of Adjusted EBITDA to net income attributable to Western Gas Partners, LP
                       
Adjusted EBITDA
  $ 111,160     $ 124,457     $ 91,831  
Less:
                       
Distributions from equity investee
    5,487       5,128       1,349  
Non-cash equity-based compensation expense
    3,580       1,924        
Expenses in excess of omnibus cap
    842              
Interest expense, net
    9,955       1,512       7,805  
Income tax expense(2)
    12       13,931       19,481  
Depreciation and amortization(2)
    37,858       34,568       30,636  
Impairment
          9,354        
Other expense, net
                15  
Add:
                       
Equity income, net
    6,982       4,736       4,017  
Interest income from note — affiliate
    16,900       10,703        
Other income, net(2)
    37       179        
                         
Net income attributable to Western Gas Partners, LP
  $ 77,345     $ 73,658     $ 36,562  
                         
Reconciliation of Adjusted EBITDA to net cash provided by operating activities
                       
Adjusted EBITDA
  $ 111,160     $ 124,457     $ 91,831  
Adjusted EBITDA attributable to noncontrolling interests
    12,462       9,422        
Interest income (expense), net
    6,945       9,191       (7,805 )
Expenses in excess of omnibus cap
    (842 )            
Non-cash equity-based compensation expense
    (3,580 )     (1,924 )      
Current income tax expense
    (266 )     (12,154 )     (8,724 )
Other income (expense), net
    42       196       (15 )
Distributions from equity investee less than (in excess of) equity income, net
    1,495       (392 )     2,668  
Changes in operating working capital:
                       
Accounts receivable and natural gas imbalances
    (688 )     (3,736 )     (3,692 )
Accounts payable and accrued expenses
    (12,713 )     19,950       458  
Other, including changes in non-current assets and liabilities
    (57 )     420       (1,498 )
                         
Net cash provided by operating activities
  $ 113,958     $ 145,430     $ 73,223  
                         
 
 
(1) Financial information for 2008 and 2007 has been revised to include results attributable to the Chipeta assets.


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(2) Includes the Partnership’s 51% share of depreciation and amortization, other income, net and income tax expense attributable to the Chipeta assets.
 
                 
    Year Ended
 
    December 31,  
    2009     2008(1)  
    (In thousands)  
 
Reconciliation of distributable cash flow to net income attributable to Western Gas Partners, LP
               
Distributable cash flow
  $ 102,176     $ 117,277  
Less:
               
Distributions from equity investee
    5,487       5,128  
Non-cash share-based compensation expense
    3,580       1,924  
Expenses in excess of omnibus cap
    842        
Interest expense, net (non-cash settled)
          1,148  
Income tax expense(2)
    12       13,931  
Depreciation and amortization(2)
    37,858       34,568  
Impairments
          9,354  
Add:
               
Equity income, net
    6,982       4,736  
Cash paid for maintenance capital expenditures
    15,929       17,519  
Other income, net(2)
    37       179  
                 
Net income attributable to Western Gas Partners, LP
  $ 77,345     $ 73,658  
                 
 
 
(1) Financial information for 2008 has been revised to include results attributable to the Chipeta assets. See Note 1 — Description of Business and Basis of Presentation — Chipeta Acquisition of the notes to the consolidated financial statements under Item 8 of this annual report.
 
(2) Depreciation and amortization expense, other income, net and income tax expense for purposes of reconciling Adjusted EBITDA and distributable cash flow to net income includes 51% of the respective amounts attributable to Chipeta Processing LLC.
 
ITEMS AFFECTING THE COMPARABILITY OF OUR FINANCIAL RESULTS
 
Our historic results of operations and cash flows for the periods presented may not be comparable to future results of operations or cash flows for the reasons described below:
 
General and Administrative Expenses under the Omnibus Agreement.  Pursuant to the omnibus agreement, Anadarko performs centralized corporate functions for the Partnership, such as legal, accounting, treasury, cash management, investor relations, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, tax, marketing and midstream administration. 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. During the years ended December 31, 2009 and 2008, Anadarko billed us $6.9 million and $3.4 million, respectively, in allocated general and administrative expenses subject to the cap contained in the omnibus agreement. This amount is 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 and will increase in future periods as we acquire additional assets. In addition, our general and administrative expenses for the year ended December 31, 2009, included $0.8 million of expenses incurred by Anadarko in excess of the cap contained in the omnibus agreement. Such expenses were recorded as a capital contribution from Anadarko and did not impact the Partnership’s cash flows. We also incurred $7.5 million and $4.5 million in public company expenses, excluding equity-based


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compensation, during the years ended December 31, 2009 and 2008, respectively. We did not incur public company expenses prior to our initial public offering in May 2008.
 
Interest expense on intercompany balances.  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 (the date on which Anadarko initially contributed assets to Chipeta), 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.
 
Note receivable from Anadarko.  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.
 
Term loan agreements and revolving credit agreement.  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. In December 2009, we issued 6.9 million common units in connection with our 2009 equity offering and repaid the $100.0 million outstanding under our revolving credit facility. In January 2010, we borrowed $210.0 million under the revolving credit facility to partially fund the Granger acquisition. Interest expense on our notes and credit facilities will be incurred so long as debt remains outstanding.
 
Cash management.  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. 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 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, 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 investment. 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.
 
Commodity price swap agreements.  Our financial results for historical periods reflect commodity price changes, which, in turn, impact the financial results derived from our percent-of-proceeds and keep-whole processing contracts. Effective January 1, 2009, substantially all commodity price risk associated with our percent-of-proceeds and keep-whole processing contracts has been mitigated through our fixed-price commodity price swap agreements with Anadarko that extend through December 31, 2011, with an option to extend through 2013. See Note 6 — Transactions with Affiliates of the notes to the consolidated financial statements included under Item 8 in this annual report.


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Federal income taxes.  We are generally not subject to federal or state income tax other than Texas margin tax. Federal and state income tax expense was recorded for periods ending prior to 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 December 19, 2008, with respect to income generated by the Powder River assets. For periods including and subsequent to May 14, 2008, with respect to income generated by our initial assets, including and subsequent to June 1, 2008, with respect to income generated by the Chipeta assets, and including 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.
 
Distributions.  We made cash distributions to our unitholders and our general partner following our initial public offering in May 2008. During the years ended December 31, 2009 and 2008, the Partnership paid cash distributions to its unitholders of approximately $70.1 million and $24.8 million, respectively. On January 21, 2010, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.33 per unit for the three months ended December 31, 2009, which equates to approximately $21.4 million per full quarter, or approximately $85.6 million per full year, based on the number of common, subordinated and general partner units outstanding as of March 1, 2010.
 
Equity-based compensation plans.  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 2 — Summary of Significant Accounting Policies and Note 6 — Transactions with Affiliates of the notes to the consolidated financial statements included under Item 8 of this annual report.
 
Gas gathering agreements.  For periods ending prior to January 1, 2008, our consolidated financial statements reflect the gathering fees we historically charged Anadarko under our affiliate cost-of-service-based arrangements with respect to the initial assets. Under these arrangements, we recovered, on an annual basis, our operation and maintenance, general and administrative and depreciation expenses in addition to earning a return on our invested capital. Effective January 1, 2008, we entered into new 10-year gas gathering agreements with Anadarko with respect to the initial assets. Pursuant to the terms of the new agreements, our fees for gathering and treating services rendered to Anadarko increased. This


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increase was due, in part, to compensate us for additional operation and maintenance expense that we incur as a result of us bearing all of the cost of employee benefits specifically identified and related to operational personnel working on our assets, as compared to bearing only those employee benefit costs reasonably allocated by Anadarko to us for the periods ending prior to January 1, 2008. Because our new gas gathering agreements are designed to fully recover these incremental costs, our revenues increased by an amount approximately equal to the incremental operation and maintenance expense. Although this change in methodology for computing affiliate gathering rates does not impact our net cash flows or net income, this methodology change impacts the components thereof as compared to periods ending prior to January 1, 2008. If we applied the methodology employed under our new gas gathering agreements with Anadarko to the year ended December 31, 2007, we estimate our historic gathering revenues and operation and maintenance expense would have increased by $3.1 million and our cash flow from operations would have remained unchanged.
 
The 10-year gas gathering agreements entered into with Anadarko with respect to the initial assets included new fees for gathering and treating. The new fees are based on capital improvements and changes in our cost-of-service analysis and are higher than those fees reflected in our historical financial results for the periods ended prior to January 1, 2008.
 
Granger acquisition.  In January 2010, we acquired the following assets from Anadarko: (i) the Granger gathering system with related compressors and other facilities, and (ii) the Granger complex, consisting of two cryogenic trains, two refrigeration trains, an NGLs fractionation facility, and ancillary equipment. Beginning with our quarterly report for the first quarter of 2010, we will recast our historic financial statements to include the Granger assets from August 2006, when Anadarko acquired the assets in connection with its acquisition of Western. The acquisition will impact the comparability of our historic financial statements presented herein to our future financial statements. See Note 13 — Subsequent Events — Granger acquisition of the notes to the consolidated financial statements under Item 8 of this annual report.
 
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 recent natural gas price environment has resulted in lower drilling activity, resulting in fewer new well connections and, in some cases, temporary curtailments of production throughout areas in which we operate. A continued low gas price environment may result in further reductions in drilling activity or temporary curtailments 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 invested by Anadarko and third parties in the exploration for and development of new natural gas reserves. To the extent opportunities are available, we will 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 activities of natural gas producers and shippers.
 
Access to 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 and acquisitions. Recent market turbulence has from time to time 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


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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.
 
Acquisition opportunities.  As of December 31, 2009, Anadarko’s total domestic midstream asset portfolio, excluding assets we own, consisted of 13 gathering systems with an aggregate throughput of approximately 2.1 Bcf/d, and 12 processing and/or treating facilities. A key component of our growth strategy is to acquire midstream assets from Anadarko and third parties over time. In December 2008, we acquired the Powder River assets from Anadarko, in July 2009, we acquired the Chipeta assets from Anadarko and in January 2010, we acquired the Granger assets from Anadarko. As of December 31, 2009, Anadarko owns a 2.0% general partner interest in us, all of our IDRs and a 54.8% limited partner interest in us. Given Anadarko’s significant interests in us, we believe Anadarko will benefit from selling additional assets to us over time; however, Anadarko continually evaluates acquisitions and divestitures and may elect to acquire, construct or dispose of midstream assets in the future without offering us the opportunity to acquire or construct those assets. Should Anadarko choose to pursue additional midstream asset sales, it is under no contractual obligation to offer assets or business opportunities to us. We may also pursue certain asset acquisitions from third parties to the extent such acquisitions complement our or Anadarko’s existing asset base or allow us to capture operational efficiencies from Anadarko’s or third-party production. However, if we do not make additional acquisitions from Anadarko or third parties on economically acceptable terms, our future growth will be limited, and the acquisitions we make could reduce, rather than increase, our cash generated from operations on a per-unit basis.


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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 years ended December 31, 2009, 2008 and 2007:
 
                         
    Year Ended December 31,  
    2009     2008(1)     2007(1)  
    (In thousands)  
 
Revenues
                       
Gathering, processing and transportation of natural gas
  $ 151,816     $ 138,864     $ 104,026  
Natural gas, natural gas liquids and condensate sales
    83,751       188,426       148,923  
Equity income and other, net
    9,552       17,216       8,544  
                         
Total revenues
    245,119       344,506       261,493  
Operating expenses(2)
                       
Cost of product
    51,136       140,010       112,282  
Operation and maintenance
    45,901       50,828       40,756  
General and administrative
    20,136       15,345       8,365  
Property and other taxes
    7,251       6,760       5,591  
Depreciation and amortization
    40,065       36,042       30,785  
Impairment
          9,354        
                         
Total operating expenses
    164,489       258,339       197,779  
                         
Operating income
    80,630       86,167       63,714  
Interest income (expense), net
    6,945       9,191       (7,805 )
Other income (expense), net
    42       196       (15 )
                         
Income before income taxes
    87,617       95,554       55,894  
Income tax expense
    12       13,988       19,424  
                         
Net income
    87,605       81,566       36,470  
Net income (loss) attributable to noncontrolling interests
    10,260       7,908       (92 )
                         
Net income attributable to Western Gas Partners, LP
  $ 77,345     $ 73,658     $ 36,562  
                         
Gross margin(3)
  $ 193,983     $ 204,496     $ 149,211  
Adjusted EBITDA(3)
    111,160       124,457       91,831  
Distributable cash flow(3)
    102,176       117,277       n/a  
 
 
(1) Financial information for 2008 and 2007 has been revised to include results attributable to the Chipeta assets. See Note 1 — Description of Business and Basis of Presentation — Chipeta Acquisition of the notes to the consolidated financial statements under Item 8 of this annual report..
 
(2) Operating expenses include amounts charged by affiliates to us for services as well as reimbursement of amounts paid by affiliates to third parties on our behalf. See Note 6 — Transactions with Affiliates of the notes to the consolidated financial statements under Item 8 of this annual report.
 
(3) Gross margin, Adjusted EBITDA and distributable cash flow are defined above under the caption How we Evaluate Our Results within this Item 7. Such caption also includes reconciliations of Adjusted EBITDA and distributable cash flow to their most directly comparable measures calculated and presented in accordance with GAAP.
 
For purposes of the following discussion, any increases or decreases “for the year ended December 31, 2009” refer to the comparison of the year ended December 31, 2009 to the year ended December 31, 2008.


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Similarly, any increases or decreases “for the year ended December 31, 2008” refer to the comparison of the year ended December 31, 2008 to the year ended December 31, 2007.
 
Executive Summary
 
Total revenues decreased by $99.4 million for the year ended December 31, 2009 and increased $83.0 million for the year ended December 31, 2008. Gathering, processing and transportation revenues increased $13.0 million; natural gas, NGL and condensate revenues decreased $104.7 million and equity income and other revenues decreased $7.7 million for the year ended December 31, 2009. Gathering, processing and transportation revenues increased $34.8 million; natural gas, NGL and condensate revenues increased $39.5 million and equity income and other revenues increased $8.7 million for the year ended December 31, 2008.
 
Net income attributable to Western Gas Partners, LP increased by $3.7 million for the year ended December 31, 2009, consisting of a $93.9 million decrease in total operating expenses primarily due to an $88.9 million decrease in cost of product from lower prices and a $14.0 million decrease in income tax expense, substantially offset by a $99.4 million decrease in revenues, a $2.2 million decrease in interest income, net due to an increase in interest expense from additional borrowings and a $2.4 million increase in net income attributable to noncontrolling interests due to increased Chipeta income.
 
Net income attributable to Western Gas Partners, LP increased by $37.1 million for the year ended December 31, 2008 consisting of an $83.0 million increase in total revenues driven by gathering rate increases, increased processing volumes, increased condensate sales, an increase in other revenues from changes in gas imbalance positions and gas prices, a $17.0 million increase in interest income, net and a $5.4 million decrease in income tax expense. These items are partially offset by a $27.7 million increase in cost of product primarily from higher prices, an $8.0 million increase in net income attributable to noncontrolling interests due to increased Chipeta income and a $32.8 million increase in other operating expenses for the year ended December 31, 2008.
 
Operating Statistics
 
                                         
    2009     2008     Δ(1)     2007     Δ(1)  
    (MMcf/d, except percentages and
 
    gross margin per Mcf)  
 
Gathering and transportation throughput
                                       
Affiliates
    761       832       (9 )%     910       (9 )%
Third parties
    122       135       (10 )%     77       75 %
                                         
Total gathering and transportation throughput
    883       967       (9 )%     987       (2 )%
Processing throughput(2)
                                       
Affiliates
    338       234       44 %           nm (4)
Third parties
    58       49       18 %     31       58 %
                                         
Total processing throughput
    396       283       40 %     31       813 %
Equity investment throughput(3)
    120       112       7 %     84       33 %
                                         
Total throughput
    1,399       1,362       3 %     1,102       24 %
Throughput attributable to noncontrolling interest owners
    180       124       45 %           nm (4)
                                         
Total throughput attributable to Western Gas Partners, LP
    1,219       1,238       (2 )%     1,102       12 %
                                         
Gross margin per Mcf
                                       
Gross margin per Mcf
  $ 0.38     $ 0.41       (7 )%   $ 0.37       11 %
Gross margin per Mcf attributable to Western Gas Partners, LP
  $ 0.40     $ 0.42       (5 )%   $ 0.37       14 %


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(1) Represents the percentage change for the year ended December 31, 2009 or for the year ended December 31, 2008.
 
(2) Consists of 100% of Chipeta and Hilight plant volumes and 50% of Newcastle system volumes.
 
(3) Represents our 14.81% share of Fort Union’s gross volumes.
 
(4) Percent change is not meaningful.
 
Total throughput, which consists of affiliate, third-party and equity investment volumes, increased by 37 MMcf/d and 260 MMcf/d for the year ended December 31, 2009 and for the year ended December 31, 2008, respectively. Total throughput attributable to Western Gas Partners, LP, which excludes the noncontrolling interest owner’s proportionate share of Chipeta’s throughput, decreased by 19 MMcf/d for the year ended December 31, 2009 and increased by 136 MMcf/d for the year ended December 31, 2008.
 
Affiliate gathering and transportation throughput decreased by 71 MMcf/d and 78 MMcf/d for the year ended December 31, 2009 and for the year ended December 31, 2008, respectively. The decrease for both the year ended December 31, 2009 and 2008 is primarily comprised of throughput decreases at the Pinnacle, Dew, Haley and Hugoton systems due to natural production declines and changes in contract terms, partially offset by affiliate throughput increases at 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, and a new affiliate contract that became effective in September 2007 in connection with expansion of the system’s capacity.
 
Third-party gathering and transportation throughput decreased by 13 MMcf/d for the year ended December 31, 2009 and increased by 58 MMcf/d for the year ended December 31, 2008. The decrease for the year ended December 31, 2009 is primarily attributable to throughput decreases at the MIGC system, partially offset by third-party throughput increases at the Haley and Pinnacle systems. The declines experienced on the MIGC pipeline were primarily due to the expiration of two third-party contracts described above. The throughput increases on the Haley system were primarily due to third-party drilling activity which partially offset natural production declines. The increase in third-party throughput at the Pinnacle system is primarily due to changes in contract terms mentioned above resulting in a shift from affiliate to third-party throughput. The increase for the year ended December 31, 2008 is primarily attributable to throughput increases at the Hugoton and Haley systems primarily from third-party drilling activity, partially offset by third-party throughput decreases at the Pinnacle system resulting primarily from natural production declines.
 
Affiliate processing throughput increased by 104 MMcf/d and 234 MMcf/d for the year ended December 31, 2009 and for the year ended December 31, 2008, respectively, and third-party processing throughput increased by 9 MMcf/d and by 18 MMcf/d for the year ended December 31, 2009 and for the year ended December 31, 2008, respectively. Affiliate throughput increased primarily due to increased throughput at the Chipeta plant from initial start-up of the plant in early 2008 and the addition of the cryogenic train in April 2009, driven by our affiliates’ drilling activities in the Natural Buttes area.
 
Equity investment volumes increased by 8 MMcf/d and by 28 MMcf/d for the year ended December 31, 2009 and for the year ended December 31, 2008, 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
 
                                         
    2009     2008     Δ     2007     Δ  
    (In thousands, except percentages)  
 
Gathering, processing and transportation of natural gas:
                                       
Affiliates
  $ 134,832     $ 121,389       11 %   $ 93,007       31 %
Third parties
    16,984       17,475       (3 )%     11,019       59 %
                                         
Total
  $ 151,816     $ 138,864       9 %   $ 104,026       33 %
                                         
 
Total gathering, processing and transportation of natural gas revenues increased by $13.0 million and by $34.8 million for the year ended December 31, 2009 and for the year ended December 31, 2008, respectively. Revenues from affiliates increased by $13.5 million for the year ended December 31, 2009 primarily due to increased affiliate throughput at the Chipeta plant following completion of the cryogenic unit in April 2009, increased throughput at the MIGC system due to the third-party contract expirations that caused volumes and associated revenues to shift from third party to affiliate and higher rates at the Haley system due to changes in contract terms, partially offset by throughput decreases at the Pinnacle, Dew, Hugoton and Haley systems. Gathering, processing and transportation of natural gas revenues from affiliates increased by $28.4 million for the year ended December 31, 2008 primarily due to increased throughput at the Chipeta plant after completion of the refrigeration unit in December 2007, increased throughput at the MIGC system and higher rates at the Dew, Haley and Pinnacle systems due to new contract terms, partially offset by throughput decreases at the Haley, Pinnacle, Dew and Hugoton systems.
 
Revenues from third parties decreased by $0.5 million for the year ended December 31, 2009, primarily due to third-party throughput decreases at the MIGC system attributable to the third-party contract expirations described above, partially offset by throughput increases at the Haley and Pinnacle systems. Revenues from third parties increased by $6.5 million for the year ended December 31, 2008 primarily due to increased third-party throughput at the Haley and Hugoton systems and higher gathering rates at the Haley system.


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Natural Gas, Natural Gas Liquids and Condensate Sales
 
                                         
    2009     2008     Δ     2007     Δ  
    (In thousands, except percentages and
 
    average price per unit)  
 
Natural gas sales:
                                       
Affiliates
  $ 29,805     $ 64,844       (54 )%   $ 42,302       53 %
Third parties
    8       23       (65 )%           nm (1)
                                         
Total
  $ 29,813     $ 64,867       (54 )%   $ 42,302       53 %
Natural gas liquids sales:
                                       
Affiliates
  $ 46,484     $ 107,304       (57 )%   $ 96,795       11 %
Third parties
          159       (100 )%           nm  
                                         
Total
  $ 46,484     $ 107,463       (57 )%   $ 96,795       11 %
Drip condensate sales:
                                       
Affiliates
  $     $       0 %   $ 7,054       (100 )%
Third parties
    7,454       16,096       (54 )%     2,772       481 %
                                         
Total
  $ 7,454     $ 16,096       (54 )%   $ 9,826       64 %
Total natural gas, natural gas liquids and condensate sales:
                                       
Affiliates
  $ 76,289     $ 172,148       (56 )%   $ 146,151       18 %
Third parties
    7,462       16,278       (54 )%     2,772       487 %
                                         
Total
  $ 83,751     $ 188,426       (56 )%   $ 148,923       27 %
                                         
Average price per unit:
                                       
Natural gas (per Mcf)
  $ 3.31     $ 7.45       (56 )%   $ 5.36       39 %
Natural gas liquids (per barrel)
  $ 40.48     $ 74.90       (46 )%   $ 57.10       31 %
Drip condensate (per barrel)
  $ 49.21     $ 89.34       (45 )%   $ 64.43       39 %
 
 
(1) Percent change is not meaningful
 
Total natural gas, NGL and condensate sales decreased by $104.7 million for the year ended December 31, 2009 and increased by $39.5 million for the year ended December 31, 2008. The decrease for the year ended December 31, 2009 consisted of a $61.0 million decrease in NGL sales, a $35.1 million decrease in natural gas sales and an $8.6 million decrease in drip condensate sales. The increase for the year ended December 31, 2008 consisted of a $22.5 million increase in natural gas sales, a $10.7 million increase in NGL sales and a $6.3 million increase in drip condensate sales.
 
The decrease in natural gas sales for the year ended December 31, 2009 was primarily due to a $4.14 per Mcf, or 56%, decrease in the average price for natural gas sold, partially offset by an approximate 1.1 MMcf, or 14%, increase in the volume of natural gas sold. The increase in natural gas sales for the year ended December 31, 2008 was primarily due to a $2.09 per Mcf, or 39%, increase in the average price of residue sold as volumes remained relatively flat.
 
The decrease in NGL sales for the year ended December 31, 2009 was primarily due to a $34.42 per barrel (or “Bbl”), or 46%, decrease in the average price for NGLs sold and an approximate 264,000 Bbls, or 18%, decrease in the volume of NGLs sold, primarily due to the suspension of operations of a plant at the Hilight system in September 2008 at which butane was purchased, processed into iso-butane and sold. The average natural gas and NGL prices for the year ended December 31, 2009 include $4.1 million of gains from commodity price swap agreements. The decrease in the NGL price per Bbl 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 for 2009 were lower than 2008 market prices but higher than 2009 market prices. The increase in NGL sales for the year ended December 31, 2008 was


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primarily due to a $17.80 per Bbl, or 31%, increase in the average price of NGLs sold, partially offset by an approximate 227,000 Bbls, or 13%, decrease in the volume of NGLs sold.
 
The decrease in drip condensate sales for the year ended December 31, 2009 was primarily due to a $40.13 per Bbl, or 45%, decrease in average prices for drip condensate sold. Conversely, the increase for the year ended December 31, 2008 was due to a $24.91 per Bbl, or 39%, increase in the average price for condensate.
 
Equity Income and Other Revenues
 
                                         
    2009     2008     Δ     2007     Δ  
    (In thousands, except percentages)  
 
Equity income — affiliate
  $ 6,982     $ 4,736       47 %   $ 4,017       18 %
Other revenues, net:
                                       
Affiliates
  $ 1,595     $ 4,552       (65 )%   $ 2,127       114 %
Third parties
    975       7,928       (88 )%     2,400       230 %
                                         
Total equity income and other revenues, net
  $ 9,552     $ 17,216       (45 )%   $ 8,544       101 %
                                         
 
Total equity income and other revenues decreased by $7.7 million for the year ended December 31, 2009 and increased by $8.7 million for the year ended December 31, 2008. During the year ended December 31, 2009, equity income from affiliates increased by approximately $2.2 million primarily from the system expansion at Fort Union and a decrease in that joint venture’s interest expense. During the year ended December 31, 2008, equity income from affiliates increased $0.7 million primarily due to increased throughput.
 
For the year ended December 31, 2009, other affiliate and third-party revenues decreased primarily due to changes in gas imbalance positions and related gas prices and $1.9 million volume deficiency and indemnity payments from two third parties during 2008. For the year ended December 31, 2008, the increase is primarily due to changes in our natural gas imbalance positions due to higher gas prices and the indemnity payment received from a third party during 2008.
 
Cost of Product and Operation and Maintenance Expenses
 
                                         
    2009     2008     Δ     2007     Δ  
    (In thousands, except percentages and price per unit)  
 
Cost of product
  $ 51,136     $ 140,010       (63 )%   $ 112,282       25 %
Operation and maintenance
    45,901       50,828       (10 )%     40,756       25 %
                                         
Total cost of product and operation and maintenance expenses
  $ 97,037     $ 190,838       (49 )%   $ 153,038       25 %
                                         
Cost of product — average price per unit:
                                       
Natural gas (per Mcf)
  $ 2.36     $ 6.22       (62 )%   $ 3.72       67 %
Natural gas liquids (per Bbl)
  $ 18.87     $ 48.07       (61 )%   $ 44.06       9 %
Drip condensate (per MMBtu)
  $ 3.26     $ 6.94       (53 )%   $ 6.09       14 %
 
Cost of product expense decreased by $88.9 million for the year ended December 31, 2009 and increased by $27.7 million for the year ended December 31, 2008. The decrease for the year ended December 31, 2009 includes an approximate $76.3 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 $5.2 million decrease due to changes in gas imbalance positions and related gas prices and a $3.7 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. For the year ended December 31, 2009, the volume of natural gas purchased from producers increased 14% and the volume of NGLs purchased from producers decreased 18%. The decrease in the volume of NGLs purchased is primarily


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due to the September 2008 suspension of operations of a plant that produced iso-butane from NGLs at the Hilight system. Excluding the impact of the plant suspension, the volume of NGLs purchased would have increased approximately 16%. The value of natural gas volumes that are purchased by us to return to producers under keep-whole arrangements are recorded as cost of product expense. The increase in the volumes of NGLs purchased, excluding the impact of the plant suspension, and the increase in the volumes of natural gas purchased are primarily due to the increase in throughput at the Chipeta plant for the year ended December 31, 2009 as well as increased NGL recoveries at the Chipeta plant due to completion of the cryogenic unit in April 2009.
 
Cost of product expense for the year ended December 31, 2008 increased by $27.7 million, $16.9 million of which was attributable to the higher cost of natural gas and NGLs we purchased from producers, primarily due to higher market prices. In addition, cost of product expense increased $6.6 million due to a change in imbalance positions and related gas prices and increased $3.1 million due to an unfavorable change in the difference between actual versus contractual fuel recoveries. The volume of natural gas purchased from producers remained relatively flat and the volume of NGLs purchased from producers decreased 13% for the year ended December 31, 2008. The decrease in the volume of NGLs purchased is primarily due to the September 2008 suspension of operations of a plant at the Hilight system. Excluding the impact of the plant suspension, the volume of NGLs purchased would have increased approximately 13%. This increase in the volumes of NGLs purchased, excluding the impact of the plant suspension, is primarily due to the increase in throughput at the Chipeta plant which was placed in service in December 2007.
 
Operation and maintenance expense decreased by $4.9 million for the year ended December 31, 2009 and increased by $10.1 million for the year ended December 31, 2008. The decrease for the year ended December 31, 2009 is primarily due to a $2.8 million decrease in operating fuel costs attributable to the plant suspension at the Hilight system in September 2008; a $1.2 million decrease in compressor parts and rental expenses primarily due to the contribution of previously leased compression equipment to us in November 2008; and lower rates on equipment rentals as a result of renegotiating with suppliers, partially offset by a $0.8 million increase in operating expenses at the Chipeta plant.
 
Operation and maintenance expense increased by $10.1 million for the year ended December 31, 2008 primarily due to a $6.5 million increase in labor and employee-related expenses primarily attributable to being charged by Anadarko for the full cost of these expenses. Specifically, contract modifications, beginning in 2008, entitled Anadarko to charge us additional labor and employee-related expenses in order for us to bear the full cost of operational personnel working our assets instead of bearing only those employee benefit costs reasonably allocated by Anadarko to us. These additional costs were taken into account when setting the gathering rates in our affiliate-based contracts for our initial assets that became effective in January 2008; thus, our revenues increased by the same amount. In addition, other increases in labor and employee-related expenses for the year ended December 31, 2008 were due to increases in benefits and incentive programs. Operating expenses also increased by $6.0 million due to operating expenses attributable to the Chipeta plant, partially offset by a $2.6 million decrease in compressor rental expenses.
 
Key Performance Metrics
 
                                         
    2009   2008   Δ   2007   Δ
    (In thousands, except percentages and
    gross margin per Mcf)
 
Gross margin
                                       
Gross margin
  $ 193,983     $ 204,496       (5 )%   $ 149,211       37 %
Gross margin per Mcf(1)
  $ 0.38     $ 0.41       (7 )%   $ 0.37       11 %
Gross margin per Mcf attributable to Western Gas Partners, LP(2)
  $ 0.40     $ 0.42       (5 )%   $ 0.37       14 %
Adjusted EBITDA(3)
  $ 111,160     $ 124,457       (11 )%   $ 91,831       36 %
Distributable cash flow(3)
  $ 102,176     $ 117,277       (13 )%                
 
 
(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 our 14.81% interest in income and volumes


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attributable to 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 our investment in Fort Union.
 
(3) For a reconciliation of Adjusted EBITDA and distributable cash flow to their most directly comparable financial measures calculated and reconciliations to measures presented in accordance with GAAP, please read the caption How We Evaluate Our Operations within this Item 7.
 
Gross margin decreased by $10.5 million for the year ended December 31, 2009 and increased $55.3 million for the year ended December 31, 2008. The decrease in gross margin for year ended December 31, 2009 is primarily due to the decrease in natural gas and NGL prices and throughput. The impact of the decrease in market prices on our gross margin for the year ended December 31, 2009 was mitigated by our fixed-price contract structure. The increase in gross margin for the year ended December 31, 2008 is primarily due to the increase in natural gas and NGL prices and throughput.
 
Gross margin per Mcf attributable to Western Gas Partners, LP decreased by 5% and increased by 14% for the year ended December 31, 2009 and for the year ended December 31, 2008, respectively, and gross margin per Mcf decreased by 7% and increased by 11% for the year ended December 31, 2009 and for the year ended December 31, 2008, respectively. The 7% decrease in gross margin per Mcf for the year ended December 31, 2009 is primarily due to lower processing margins and lower drip condensate margins. The 11% increase in gross margin per Mcf for the year ended December 31, 2008 is primarily due to higher processing margins and higher drip condensate margins.
 
Adjusted EBITDA.  Adjusted EBITDA decreased by $13.3 million for the year ended December 31, 2009 and increased by $32.6 for the year ended December 31, 2008. The decrease for the year ended December 31, 2009 is primarily due to a $101.6 million decrease in total revenues, excluding equity income; a $2.3 million increase in general and administrative expenses, excluding non-cash equity-based compensation and expenses in excess of the omnibus cap; and a $3.0 million increase in the noncontrolling interest owners’ share of Adjusted EBITDA; partially offset by a $88.9 million decrease in cost of product; a $4.9 million decrease in operation and maintenance expenses and a $0.4 million increase in distributions from Fort Union. The increase in Adjusted EBITDA for the year ended December 31, 2008 is primarily due to a $82.3 million increase in total revenues, excluding equity income, and an approximately $3.8 million increase in distributions from Fort Union, partially offset by a $27.7 million increase in cost of product, a $10.1 million increase in operation and maintenance expenses, a $9.4 million increase in the noncontrolling interest owners’ share of Adjusted EBITDA and a $5.1 million increase in general and administrative expenses, excluding non-cash equity-based compensation.
 
Distributable cash flow.  Distributable cash flow decreased by $15.1 million for the year ended December 31, 2009 primarily due to the $13.3 million decrease in Adjusted EBITDA and a $9.6 million increase in interest expense settled in cash, partially offset by a $6.2 million increase in interest income and a $1.6 million decrease in maintenance capital expenditures. We did not utilize a distributable cash flow measure prior to becoming a publicly traded partnership in 2008 and, as such, did not differentiate between maintenance and capital expenditures prior to 2008 and do not present distributable cash flow for periods prior to 2008.


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General and Administrative, Depreciation and Other Expenses
 
                                         
    2009     2008     Δ     2007     Δ  
    (In thousands, except percentages)  
 
General and administrative
  $ 20,136     $ 15,345       31 %   $ 8,365       83 %
Property and other taxes
    7,251       6,760       7 %     5,591       21 %
Depreciation and amortization
    40,065       36,042       11 %     30,785       17 %
Impairment
          9,354       nm (1)           nm (1)
                                         
Total general and administrative, depreciation and other expenses
  $ 67,452     $ 67,501       0 %   $ 44,741       51 %
                                         
 
 
(1) Percent change is not meaningful
 
General and administrative, depreciation and other expenses were flat for the year ended December 31, 2009 as a $4.8 million increase in general and administrative expenses combined with a $4.0 million increase in depreciation and amortization expense were substantially offset by a $9.4 million decrease in impairment expense. General and administrative expenses increased primarily due to incurring expenses attributable to being a publicly traded partnership for all of 2009, compared to approximately seven and a half months during the year ended December 31, 2008, and due to accounting and legal expenses attributable to the Chipeta acquisition. Depreciation and amortization expense increased for the year ended December 31, 2009 primarily due to assets placed in service during 2008 and 2009, including the Chipeta plant expansion completed in April 2009. Impairment expense for the year ended December 31, 2008 consisted of expense related to the suspension of operations of the plant at the Hilight system prior to our acquisition of the Powder River assets.
 
General and administrative, depreciation and other expenses increased by $22.7 million for the year ended December 31, 2008. General and administrative expenses increased by $7.0 million for the year ended December 31, 2008, primarily due to incurring $3.0 million of expenses attributable to being a publicly traded partnership during and subsequent to May 2008, $2.2 million attributable to equity-based compensation and $1.5 million of accounting and legal expenses attributable to the Powder River acquisition, partially offset by a decrease in expenses charged pursuant to the management services fee prior to our acquisition of the Partnership assets. Depreciation and amortization expense increased by $5.3 million for the year ended December 31, 2008 due to depreciation on assets placed in service in 2008 and 2007, primarily attributable to the Chipeta plant placed in serviced in December 2007, our Pinnacle Bethel treating facility completed in July 2008 and previously leased Hugoton compression equipment contributed to us in November 2008. Impairment expense for the year ended December 31, 2008 consisted of the $9.4 million charge recognized in connection with the plant suspension at the Hilight system.
 
Interest Income, Net
 
                                         
    2009     2008     Δ     2007     Δ  
    (In thousands, except percentages)  
 
Interest income (expense), net — affiliates
                                       
Interest income on note receivable from Anadarko
  $ 16,900     $ 10,703       58 %   $       nm (1)
Interest expense on notes payable to Anadarko
    (8,953 )     (253 )     nm             nm  
Interest expense, net
          (1,148 )     (100 )%     (7,805 )     (85 )%
Credit facility fees
    (143 )     (111 )     29 %            
                                         
Total
  $ 7,804     $ 9,191       (15 )%   $ (7,805 )     nm  
Interest expense — third parties
                                       
Credit facility interest, fees and amortization
  $ (859 )   $       nm     $       nm  
                                         
Interest income (expense), net
  $ 6,945     $ 9,191       (24 )%   $ (7,805 )     nm  
                                         
 
 
(1) Percent change is not meaningful


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Interest income, net for the year ended December 31, 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 in July 2009 and repaid in October 2009; interest expense attributable to our revolving credit facility from October to December 2009; and commitment fees on our $350.0 million credit facility, $100.0 million portion of Anadarko’s $1.3 billion credit facility and our $30.0 million working capital facility. Interest income, net for the year ended December 31, 2008 consisted of interest income on our $260.0 million note receivable from Anadarko, partially offset by interest expense on affiliate balances and commitment fees for our credit facilities. Interest expense on affiliate balances decreased for the year ended December 31, 2008 primarily due to the settlement of intercompany balances attributable to our initial assets in connection with our May 2008 initial public offering.
 
Income Tax Expense
 
                                         
    2009   2008   Δ   2007   Δ
    (In thousands, except percentages)
 
Income before income taxes
  $ 87,617     $ 95,554       (8 )%   $ 55,894       71 %
Income tax expense (benefit)
    12       13,988       (100 )%     19,424       (28 )%
Effective tax rate
    0 %     15 %             35 %        
 
The Partnership is not a taxable entity for U.S. federal income tax purposes. With respect to the initial assets, income earned prior to May 14, 2008 was subject to federal and state income tax while income earned on or after May 14, 2008 was subject only to Texas margin tax. Similarly, with respect to the Powder River assets, income earned prior to December 19, 2008, was subject to federal and state income tax while income earned on or after December 19, 2008 was subject only to Texas margin 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.
 
Income tax expense decreased by $14.0 million and by $5.4 million for the year ended December 31, 2009 and for the year ended December 31, 2008, respectively. The decrease in income tax expense for the year ended December 31, 2009 is 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, the Powder River acquisition and the June 2008 formation of the Chipeta partnership, as well as a decrease in Texas Margin tax expense attributable to the initial assets. In addition, our estimated income attributed to Texas relative to our total income decreased as compared to the prior year, which resulted in an approximately $0.6 million reduction of previously recognized deferred taxes during 2009. Income tax expense decreased for the year ended December 31, 2008 primarily due to a change in the applicability of U.S. federal income tax to our income described above, partially offset by income tax expense attributable to the Chipeta assets for the first five months of 2008.
 
For 2008 and 2009, our variance from the federal statutory rate is primarily attributable to our U.S. federal income tax status as a non-taxable entity, partially offset by state income tax expense.
 
Noncontrolling Interests
 
                                         
    2009   2008   Δ   2007   Δ
    (In thousands, except percentages)
 
Net income (loss) attributable to noncontrolling interests
  $ 10,260     $ 7,908       30 %   $ (92 )     nm(1 )
 
 
(1) Percent change is not meaningful
 
Net income attributable to noncontrolling interests increased by $2.4 million and $8.0 million for the year ended December 31, 2009 and for the year ended December 31, 2008, respectively. Noncontrolling interests represent the aggregate 49% interest in Chipeta held by Anadarko and a third party. The increase in net


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income attributable to noncontrolling interests for the year ended December 31, 2009 is primarily due to higher throughput at the Chipeta plant, partially offset by lower NGL prices. The increase for the year ended December 31, 2008 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 NGL 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 of this annual report.
 
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 investment. 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 December 31, 2009 include:
 
  •  approximately $61.8 million of working capital, which we define as the amount by which current assets exceed current liabilities;
 
  •  cash generated from operations;
 
  •  available borrowings under our $350.0 million revolving credit facility, which is expandable to $450.0 million;
 
  •  available borrowings of up to $100.0 million under Anadarko’s $1.3 billion 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
 
  •  potential issuances of additional partnership securities.
 
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.
 
On January 29, 2010, we borrowed $210.0 million under our $350.0 million revolving credit facility in connection with the Granger acquisition. See Note 13 — Subsequent Events — Granger Acquisition of the notes to the consolidated financial statements under Item 8 of this annual report.
 
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.


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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 years ended December 31, 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 investment. Subsequent to June 1, 2008, Chipeta cash-settled transactions directly with third parties and with Anadarko affiliates.
 
                                         
    2009     2008     Δ     2007     Δ  
    (In thousands, except percentages)  
 
Net cash provided by (used in):
                                       
Operating activities
  $ 113,958     $ 145,430       (22 )%   $ 73,223       99 %
Investing activities
    (164,007 )     (542,586 )     (70 )%     (143,274 )     279 %
Financing activities
    83,959       433,230       (81 )%     69,593       523 %
                                         
Net increase (decrease) in cash and cash equivalents
  $ 33,910     $ 36,074       (6 )%   $ (458 )     nm (1)
 
 
(1) Percent change is not meaningful
 
Operating Activities.  Net cash provided by operating activities decreased by $31.5 million and increased by $72.2 million for the year ended December 31, 2009 and for the year ended December 31, 2008, respectively. For the year ended December 31, 2009, the decrease is 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. In addition, these items were partially offset by lower current income taxes, and lower operations and maintenance expenses. For the year ended December 31, 2008, the increase in cash provided by operating activities is primarily attributable to gathering rate increases, increased condensate margins, revenues attributable to changes in gas imbalance positions and gas prices as well as increased net interest income, partially offset by higher cash operating expenses.
 
Investing Activities.  Net cash used in investing activities decreased by $378.6 million for the year ended December 31, 2009 and increased by $399.3 million for the year ended December 31, 2008, respectively. Net cash used in investing activities for the year ended December 31, 2009 includes the $101.5 million cash consideration paid for the Chipeta acquisition. Net cash used in investing activities for the year ended December 31, 2008 includes our $260.0 million loan made to Anadarko in connection with our initial public offering and $175.0 million cash consideration paid for the Powder River acquisition. Investing cash flows included contributions to Fort Union of $8.1 million during the year ended December 31, 2008 related to the system expansion.
 
Capital expenditures decreased by $37.3 million and $37.4 million for the year ended December 31, 2009 and for the year ended December 31, 2008, 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 44%, from $82.0 million during the year ended December 31, 2008 to $46.1 million during the year ended December 31, 2009, primarily due to capital expenditures during the full year ended December 31, 2008 for the Chipeta plant construction compared to capital expenditures for the cryogenic unit during the first six months of 2009, completion of the NGL pipeline at the tailgate of the Chipeta plant during the second quarter of 2008, expansion of the Bethel facility completed during 2008 and installation of a compressor station at the Hugoton system during 2008, offset by the acquisition of the Natural Buttes plant during the fourth quarter of 2009. In addition, maintenance capital expenditures decreased by 8%, from $17.5 million during the year ended December 31, 2008 to


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$16.1 million during the year ended December 31, 2009, primarily due to fewer well connections at the Haley, Hugoton and Pinnacle systems due to reduced drilling activity, partially offset by 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. We did not differentiate between maintenance and capital expenditures for the year ended December 31, 2007. Capital expenditures decreased by $37.4 million for the year ended December 31, 2008 primarily due to completion of the Chipeta refrigeration unit in December 2007, partially offset by expansion of the Chipeta plant cryogenic train during 2008 and expansion of the Bethel facility and installation of the compressor station at the Hugoton system during 2008.
 
Financing Activities.  Net cash provided by financing activities decreased by $349.3 million for the year ended December 31, 2009 and increased by $363.6 million for the year ended December 31, 2008. Proceeds from financing activities during the year ended December 31, 2009 included $122.5 million from the 2009 equity offering as well as the July 2009 issuance and October 2009 repayment of the three-year term loan to Anadarko originally incurred in connection with the Chipeta acquisition, partially offset by $4.3 million of costs paid in connection with the revolving credit facility we entered into in October 2009. The term loan was refinanced in October 2009 with borrowings on our revolving credit facility, then such revolving credit facility borrowings were repaid in December 2009 with a portion of the net proceeds from our 2009 equity offering. Net cash provided by financing activities for the year ended December 31, 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. Proceeds from financing activities for the year ended December 31, 2008 also included $175.0 million from the issuance of the five-year term loan to Anadarko in connection with the Powder River acquisition.
 
For the year ended December 31, 2009, $70.1 million of cash distributions were paid to our unitholders, representing distributions for the fourth quarter of 2008 through the third quarter of 2009. Distributions to unitholders totaled $24.8 million during the year ended December 31, 2008, representing the partial distribution for the second quarter of 2008 and a full distribution for the third quarter of 2008. Net contributions from Anadarko attributable to pre-acquisition intercompany balances were $3.5 million during the year ended December 31, 2009, representing the net non-cash settlement of intercompany transactions attributable to the Chipeta assets, compared to net distributions to Anadarko of $4.4 million for the year ended December 31, 2008, representing the net settlement of transactions attributable to the Powder River assets and Chipeta assets.
 
Financing proceeds for the year ended December 31, 2009 and for the year ended December 31, 2008 included $40.3 million and $55.4 million, respectively, of cash 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 July 2009 acquisition of a 51% interest in Chipeta. Distributions from Chipeta to noncontrolling interest owners and Parent totaled $8.0 million and $37.9 million during the years ended December 31, 2009 and 2008, respectively, representing the distribution of Chipeta’s available cash. Distributions to noncontrolling interest owners and Parent during the year ended December 31, 2008 included a $19.7 million one-time distribution of part of the consideration paid by the third-party owner following the initial formation of Chipeta.
 
Capital requirements.  Our business can be capital intensive, requiring significant investment to maintain and improve existing facilities. We categorize capital expenditures as either:
 
  •  maintenance capital expenditures, which include those expenditures required to maintain the existing operating capacity and service capability of our assets, including the replacement of system components and equipment that have suffered significant wear and tear, become obsolete or approached the end of their useful lives, those expenditures necessary to remain in compliance with regulatory or legal requirements or those expenditures necessary to complete additional well connections to maintain existing system volumes and related cash flows; or
 
  •  expansion capital expenditures, which include those expenditures incurred in order to extend the useful lives of our assets, reduce costs, increase revenues or increase gathering, processing, treating and


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  transmission throughput or capacity from current levels, including well connections that increase existing system volumes.
 
Total capital incurred for the year ended December 31, 2009 and 2008 was $51.8 million and $108.6 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 years ended December 31, 2009 and 2008 were $62.2 million and $99.5 million, respectively. Capital expenditures for the year ended December 31, 2009 include $30.8 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 74% and 82% of total capital expenditures for the years ended December 31, 2009 and 2008, respectively. We estimate our total capital expenditures, excluding any future acquisitions, to be $28.0 million to $32.5 million and our maintenance capital expenditures to be approximately 75% to 80% of total capital expenditures for the year ending December 31, 2010. 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 $0.33 per unit per full quarter, which equates to approximately $21.4 million per full quarter, or approximately $85.6 million per full year, based on the number of common, subordinated and general partner units outstanding as of March 1, 2010. Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date. During the year ended December 31, 2009, we paid cash distributions to its unitholders of approximately $70.1 million, representing the $0.32 per unit distribution for the quarter ended September 30, 2009, $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 January 21, 2010, the board of directors of our general partner declared a cash distribution to our unitholders of $0.33 per unit, or $21.4 million in aggregate, for the fourth quarter of 2009. The cash distribution was paid on February 12, 2010 to unitholders of record at the close of business on February 1, 2010.
 
Revolving credit facility.  On October 29, 2009, we entered into a three-year senior unsecured revolving credit facility. The aggregate initial commitments of the lenders under this revolving credit facility are $350.0 million and are expandable to a maximum of $450.0 million. The revolving credit facility matures on October 29, 2012 and bears interest at LIBOR plus applicable margins ranging from 2.375% to 3.250%. We are also required to pay a quarterly facility fee ranging from 0.375% to 0.750% of the commitment amount (whether used or unused), based upon our consolidated leverage ratio as defined in the revolving credit facility.
 
The revolving credit facility contains various covenants that limit, among other things, our, and certain of our subsidiaries’, ability to incur additional 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 revolving 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 of us or any material subsidiary; or (iii) a change of control. All amounts due by us under the revolving credit facility are unconditionally guaranteed by certain of our wholly owned subsidiaries. The subsidiary guarantees will automatically terminate on the Investment Grade Rating Date.


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On October 30, 2009, we used $100.0 million of our capacity under the revolving 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. In December 2009, we repaid the amount outstanding under the revolving credit facility using a portion of the proceeds from the 2009 equity offering. In January 2010, we borrowed $210.0 million under the revolving credit facility to partially fund the Granger acquisition.
 
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 December 31, 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 December 31, 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 certain of Anadarko’s credit and lease agreements, we and Anadarko are required to comply with certain covenants, including a financial covenant that requires Anadarko to maintain a debt-to-capitalization ratio of 65% or less. As of December 31, 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.
 
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 December 31, 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.
 
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


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commodity price risk attributable to our percent-of-proceeds and keep-whole contracts for the Hilight system and the Newcastle system and are subject to performance risk thereunder.
 
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
 
Following is a summary of our obligations as of December 31, 2009:
 
                                                 
          Asset
    Note Payable
             
    Office
    Retirement
    to Anadarko     Credit
       
    Lease     Obligations     Principal     Interest     Facility Fees     Total  
    (In thousands)  
 
2010
  $ 145     $     $     $ 7,000     $ 1,872     $ 9,017  
2011
    147                   5,119       1,860       7,126  
2012
    5                   5,119       1,558       6,682  
2013
                175,000       5,119       19       180,138  
2014
                                   
Thereafter
          11,827                         11,827  
                                                 
Total
  $ 297     $ 11,827     $ 175,000     $ 22,357       5,309     $ 214,790  
                                                 
 
Office lease:  Anadarko leases office space used exclusively by us and charges rental payments to us. The amounts above represent the future minimum rent payments due under the office lease.
 
Asset retirement obligations:  When assets are acquired or constructed, the initial estimated asset retirement obligation is recognized in an amount equal to the net present value of the settlement obligation, with an associated increase in properties and equipment. The asset retirement obligation amounts above are discounted. Revisions to estimated asset retirement obligations can result from revisions to estimated inflation rates and discount rates, escalating retirement costs and changes in the estimated timing of settlement. For additional information see Note 10 — Asset Retirement Obligations of the notes to the consolidated financial statements under Item 8 of this annual report.
 
Note payable to Anadarko:  In connection with the Powder River acquisition, we entered into a five-year, $175.0 million term loan agreement with Anadarko which calls for interest at a fixed rate of 4.0% for the first two years and a floating rate of interest at three-month LIBOR plus 150 basis points for the final three years.
 
Credit Facility Fees:  We are required to pay facility fees on our $350.0 million revolving credit facility, on our $100.0 million portion of Anadarko’s $1.3 billion credit facility and on our $30.0 million working capital facility as described under the caption Historical cash flow above within this Item 7.
 
Also see the caption Items Affecting the Comparability of Our Financial Results under Item 7 of this annual report for a discussion of contractual obligations effective with the initial public offering or Powder River acquisition, including the omnibus agreement, expenses related to operating as a publicly traded partnership, the services and secondment agreement and equity-based compensation plans.
 
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
 
The preparation of consolidated financial statements in accordance with GAAP requires our management to make informed judgments and estimates that affect the amounts of assets and liabilities as of the date of the financial statements and affect the amounts of revenues and expenses recognized during the periods reported. On an ongoing basis, management reviews its estimates, including those related to the determination of


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properties and equipment, goodwill, asset retirement obligations, litigation, environmental liabilities, income taxes and fair values. Although these estimates are based on management’s best available knowledge of current and expected future events, changes in facts and circumstances or discovery of new information may result in revised estimates and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve judgment and discusses the selection and development of these estimates with the audit committee of our general partner. For additional information concerning our accounting policies, see the Note 2 — Summary of Significant Accounting Policies of the notes to the consolidated financial statements included under Item 8 of this annual report.
 
Depreciation.  Depreciation expense is generally computed using the straight-line method over the estimated useful life of the assets. Determination of depreciation expense requires judgment regarding the estimated useful lives and salvage values of property, plant and equipment. As circumstances warrant, depreciation estimates are reviewed to determine if any changes in the underlying assumptions are necessary. The weighted average life of our long-lived assets is approximately 21 years. If the depreciable lives of our assets were reduced by 10%, we estimate that annual depreciation expense would increase by approximately $4.8 million, which would result in a corresponding reduction in our operating income.
 
Impairment of tangible assets.  Each reporting period, management assesses whether facts and circumstances indicate that the carrying amounts of property, plant and equipment may not be recoverable from expected undiscounted cash flows from the use and eventual disposition of an asset. If the carrying amount of the asset is not expected to be recoverable from future undiscounted cash flows, an impairment may be recognized. Any impairment is measured as the excess of the carrying amount of the asset over its estimated fair value.
 
In assessing long-lived assets for impairment, management evaluates changes in our business and economic conditions and their implications for recoverability of the assets’ carrying amounts. Since a significant portion of our revenues arises from gathering and transporting natural gas production from Anadarko-operated properties, significant downward revisions in reserve estimates or changes in future development plans by Anadarko, to the extent they affect our operations, may necessitate assessment of the carrying amount of our affected assets for recoverability. Such assessment requires application of judgment regarding the use and ultimate disposition of the asset, long-range revenue and expense estimates, global and regional economic conditions, including commodity prices and drilling activity by our customers, as well as other factors affecting estimated future net cash flows. The measure of impairment to be recognized, if any, depends upon management’s estimate of the asset’s fair value, which may be determined based on the estimates of future net cash flows or values at which similar assets were transferred in the market in recent transactions, if such data is available.
 
Impairment of goodwill.  We evaluate whether goodwill has been impaired annually as of October 1, unless facts and circumstances make it necessary to test more frequently. Management has determined that we have one operating segment and two reporting units: (i) gathering and processing and (2) transportation. The carrying value of goodwill as of December 31, 2009 was $16.0 million and $4.8 million for the gathering and processing reporting unit and transportation reporting unit, respectively. Accounting standards require that goodwill be assessed for impairment at the reporting unit level. Goodwill impairment assessment is a two-step process. Step one focuses on identifying a potential impairment by comparing the fair value of the reporting unit with the carrying amount of the reporting unit. If the fair value of the reporting unit exceeds its carrying amount, no further action is required. However, if the carrying amount of the reporting unit exceeds its fair value, goodwill is written down to the implied fair value of the goodwill through a charge to operating expense based on a hypothetical purchase price allocation.
 
Because quoted market prices for our reporting units are not available, management must apply judgment in determining the estimated fair value of reporting units for purposes of performing the goodwill impairment test. Management uses information available to make these fair value estimates, including market multiples of Adjusted EBITDA. Specifically, management estimates fair value by applying an estimated multiple to projected 2010 Adjusted EBITDA. Management considered the relatively few observable transactions in the market, as well as trading multiples for peers, to determine an appropriate multiple to apply against our


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projected Adjusted EBITDA. A lower fair value estimate in the future for any of our reporting units could result in a goodwill impairment. Factors that could trigger a lower fair-value estimate include sustained price declines, cost increases, regulatory or political environment changes, and other changes in market conditions such as decreased prices in market-based transactions for similar assets. Based on our most recent goodwill impairment test, we concluded that the fair value of each reporting unit substantially exceeded the carrying value of the reporting unit. Therefore, no goodwill impairment was indicated and no goodwill impairment has been recognized in these consolidated financial statements.
 
Fair Value.  Management estimates fair value in performing impairment tests for long-lived assets and goodwill as well as for the initial measurement of asset retirement obligations. When management is required to measure fair value, and there is not a market observable price for the asset or liability, or a market observable price for a similar asset or liability, management generally utilizes an income or multiples valuation approach. The income approach utilizes management’s best assumptions regarding expectations of projected cash flows, and discounts the expected cash flows using a commensurate risk adjusted discount rate. Such evaluations involve a significant amount of judgment, since the results are based on expected future events or conditions, such as sales prices; estimates of future throughput; capital and operating costs and the timing thereof; economic and regulatory climates and other factors. A multiples approach utilizes management’s best assumptions regarding expectations of projected EBITDA and multiple of that EBITDA that a buyer would pay to acquire an asset. Management’s estimates of future net cash flows and EBITDA are inherently imprecise because they reflect management’s expectation of future conditions that are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs and other factors, and are consistent with assumptions used in our business plans and investment decisions.
 
OFF-BALANCE SHEET ARRANGEMENTS
 
We do not have off-balance sheet arrangements other than operating leases. The information pertaining to operating leases required for this item is provided in Note 12 — Commitments and Contingencies included in the notes to the consolidated financial statements under Item 8 of this annual report, which information is incorporated by reference.
 
RECENT ACCOUNTING DEVELOPMENTS
 
The information required for this item is provided under the caption New Accounting Standards in Note 2 — Summary of Significant Accounting Policies included in the notes to the consolidated financial statements under Item 8 of this annual report which information is incorporated by reference.
 
Item 7A.   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. 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 discount to the price of NYMEX West Texas Intermediate crude oil.
 
In addition, certain of our processing services are provided under percent-of-proceeds and keep-whole agreements in which Anadarko is typically responsible for the marketing of the natural gas and NGLs. Under percent-of-proceeds agreements, we receive a specified percentage of the net proceeds from the sale of natural gas and NGLs. Under keep-whole agreements, we keep 100% of the NGLs produced, and the processed natural gas, or value of the gas, is returned to the producer. Since some of the gas is used and removed during processing, we compensate the producer for the amount of gas used and removed in processing by supplying additional gas or by paying an agreed-upon value for the gas utilized. To mitigate our exposure to changes in


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commodity prices on these types of processing agreements, we entered into commodity price swap agreements with Anadarko with fixed commodity prices that extend through December 31, 2011, with an option to extend through 2013. In addition, to mitigate our exposure to changes in commodity prices on these types of processing agreements on the Granger assets we acquired in January 2010, we entered into commodity price swap agreements with Anadarko with fixed commodity prices that extend through 2014. For additional information on the commodity price swap agreements, see Note 6 — Transactions with Affiliates and Note 13 — Subsequent Events — Granger acquisition included in the notes to the consolidated financial statements included under Item 8 of this annual report
 
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 year ended December 31, 2009, a 10% change in the margin between drip condensate and natural gas would have resulted in an approximate $0.5 million, or less than 3%, 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.  If interest rates rise, our future financing costs will increase. Interest rates during 2008 and 2009 were low compared to historic rates. As of December 31, 2009, we had $350.0 million of credit available under our revolving credit facility, $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. On January 29, 2010, we borrowed $210.0 million under our revolving credit facility in connection with the Granger acquisition. Our borrowings, if any, under our revolving credit facility, Anadarko’s credit facility or our working capital facility bear interest at variable rates. In addition, as of December 31, 2009, we owed $175.0 million to Anadarko under our five-year term loan we entered into in connection with the Powder River acquisition which bears interest at a fixed rate of 4.0% until December 2011 and at a floating rate thereafter. See Note 11 — Debt and Interest Expense of the notes to the consolidated financial statements included in Item 8 of this annual report.
 
We may incur additional debt in the future, either under the revolving credit facility, our $100.0 million borrowing capacity under Anadarko’s existing credit facility, our $30.0 million working capital facility with Anadarko or other financing sources, including commercial bank borrowings or debt issuances.
 
Item 8.   Financial Statements and Supplementary Data
 
Our consolidated financial statements, together with the report of our independent registered public accounting firm, begin on page F-1 of this annual report.
 
Item 9.   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
 
None
 
Item 9A.   Disclosure Controls and Procedures
 
Evaluation of Disclosure Controls and Procedures.  The Chief Executive Officer and Chief Financial Officer of the Partnership’s general partner performed an evaluation of the partnership’s disclosure controls and procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to the issuer’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions


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regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2009.
 
Management’s Annual Report on Internal Control Over Financial Reporting.  See Management’s Assessment of Internal Control Over Financial Reporting under Item 8 of this annual report.
 
Attestation Report of the Independent Registered Public Accounting Firm.  See the Report of Independent Registered Public Accounting Firm under Item 8 of this annual report.
 
Changes in Internal Control over Financial Reporting.  There were no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) or in other factors during the fourth quarter of 2009, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
 
The certifications of our general partner’s Principal Executive Officer and Principal Financial Officer required under Sections 302 and 906 of the Sarbanes-Oxley Act of 2002 have been included as exhibits to this annual report.
 
PART III
 
Item 10.   Directors, Executive Officers and Corporate Governance
 
Management of Western Gas Partners, LP
 
As a limited partnership, we have no directors or officers. Instead, Western Gas Holdings, LLC, our general partner, manages our operations and activities. Our general partner is not elected by our unitholders and is not subject to re-election in the future. The directors of our general partner oversee our operations. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operations. However, our general partner owes a fiduciary duty to our unitholders as defined and described in our partnership agreement. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Our general partner, therefore, may cause us to incur indebtedness or other obligations that are nonrecourse to it.
 
Our general partner’s board of directors has nine directors, four of whom are independent as defined under the independence standards established by the NYSE, and the Securities Exchange Act of 1934, as amended, or the “Exchange Act.” Our general partner’s board of directors has affirmatively determined that Messrs. Milton Carroll, Anthony R. Chase, James R. Crane and David J. Tudor are independent as described in the rules of the NYSE and the Exchange Act. The NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating committee.
 
The executive officers of our general partner manage and conduct our day-to-day operations. The executive officers of our general partner allocate their time between managing our business and affairs and the business and affairs of Anadarko. The executive officers of our general partner may face a conflict regarding the allocation of their time between our business and the other business interests of Anadarko. The officers of our general partner generally do not devote all of their time to our business, although we expect the amount of time that they devote may increase or decrease in future periods as our business continues to develop. The officers of our general partner and other Anadarko employees operate our business and provide us with general and administrative services pursuant to the omnibus agreement and the services and secondment agreement described under Item 13 of this annual report. We reimburse Anadarko for allocated expenses of operational personnel who perform services for our benefit, and for certain direct expenses.


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Board Leadership Structure
 
Anadarko owns and controls our general partner and, within the limitations of our Partnership Agreement and applicable SEC and NYSE rules and regulations, also exercises broad discretion in establishing the governance provisions of our general partner’s limited liability company agreement. Accordingly, our general partner’s Board structure is established by Anadarko.
 
Although our general partner’s current Board structure has separated the roles of Chairman and CEO, Anadarko may in the future combine those roles at its discretion. Our general partner’s limited liability company agreement and our Corporate Governance Guidelines permit the roles of Chairman and CEO to be combined, and Mr. Gwin served as Chairman and CEO of our general partner from October 2009 to January 2010.
 
Directors and Executive Officers
 
The biographies of each of the directors below contain information regarding the person’s service as a director, business experience, director positions held currently or at any time during the last five years, information regarding involvement in certain legal or administrative proceedings, if applicable, and the experiences, qualifications, attributes or skills that caused our general partner and its board of directors to determine that the person should serve as a director for the general partner. Also, in light of our strategic relationship with our sponsor, Anadarko, our general partner considers service as an Anadarko executive to be a meaningful qualification for service as a non-independent director of our general partner.
 
The following table sets forth information with respect to the directors and executive officers of our general partner as of March 1, 2010. Directors are appointed for a term of one year.
 
             
Name
 
Age
 
Position with Western Gas Holdings, LLC
 
Robert G. Gwin
    46     Chairman of the Board
Donald R. Sinclair
    52     President, Chief Executive Officer and Director
Benjamin M. Fink
    39     Senior Vice President and Chief Financial Officer
Danny J. Rea
    51     Senior Vice President and Chief Operating Officer
Amanda M. McMillian
    37     Vice President, General Counsel and Corporate Secretary
Jeremy M. Smith
    37     Vice President and Treasurer
Michael C. Pearl
    38     Senior Vice President and Chief Financial Officer — departed May 2009
R. A. Walker
    53     Director
Milton Carroll
    59     Director
Anthony R. Chase
    54     Director
James R. Crane
    56     Director
Charles A. Meloy
    49     Director
Robert K. Reeves
    52     Director
David J. Tudor
    50     Director
 
Our directors hold office until their successors shall have been duly elected and qualified or until the earlier of their death, resignation, removal or disqualification. Officers serve at the discretion of the board of directors. There are no family relationships among any of our directors or executive officers.
 


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Robert G. Gwin
Age: 46
Houston, Texas
Director since:
August 2007
Not Independent
Officer From:
August 2007 to
January 2010
  Biography/Qualifications

Robert G. Gwin has served as a director of our general partner since August 2007 and has served as non-executive Chairman of the Board of our general partner since October 2009. He also served as Chief Executive Officer of our general partner from August 2007 to January 2010 and as President from August 2007 to September 2009. He has served as Senior Vice President, Finance and Chief Financial Officer of Anadarko since March 2009, and prior to that position had served as Senior Vice President of Anadarko since March 2008. He previously served as Vice President, Finance and Treasurer of Anadarko since January 2006. Prior to joining Anadarko, he served as Chief Executive Officer of Community Broadband Ventures, LP from November 2004 to January 2006. Prior to this position, he was with Prosoft Learning Corporation, serving as Chairman from November 2002 to February 2006, Chief Executive Officer and President from November 2002 to November 2004, and Chief Financial Officer from 2000 to November 2004. In April 2006, to facilitate its acquisition by another company, Prosoft filed a prepackaged voluntary plan of reorganization. Previously, Mr. Gwin spent 10 years at Prudential Capital Group in merchant banking roles of increasing responsibility, including serving as Managing Director with responsibility for the firm’s energy investments worldwide. Mr. Gwin holds a Bachelor of Science degree from the University of Southern California and a Master of Business Administration degree from the Fuqua School of Business at Duke University, and he is a Chartered Financial Analyst.
     
Donald R. Sinclair
Age: 52
Houston, Texas
Director since:
October 2009
Not Independent
Officer Since:
October 2009
  Biography/Qualifications

Donald R. Sinclair has served as President and a director of our general partner since October 2009 and as Chief Executive Officer since January 2010. Prior to becoming President and a director of our general partner, Mr. Sinclair was a founding partner and served as President of Ceritas Energy, LLC, a midstream energy company headquartered in Houston with operations in Texas, Wyoming and Utah from February 2003 to September 2009. Earlier in his career, Mr. Sinclair was President of Duke Energy Trading and Marketing LLC, one of the nation’s largest marketers of natural gas and wholesale electric power, and served as Chairman of the Energy Risk Committee for Duke Energy Corporation. Prior to joining Duke, Mr. Sinclair served as Senior Vice President of Tenneco Energy and as President of Tenneco Energy Resources. Previously, as one of the original principals and officers at Dynegy (formerly NGC Corporation), he served for eight years in various officer positions, including Senior Vice President and Chief Risk Officer where he was in charge of all risk management activities and commercial operations. Mr. Sinclair earned a Bachelor of Business Administration degree from Texas Tech University.

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Benjamin M. Fink
Age: 39
Houston, Texas
Officer since:
May 2009
  Biography/Qualifications

Benjamin M. Fink has served as the Senior Vice President and Chief Financial Officer of our general partner since May 2009. He was Director, Finance of Anadarko from April 2007 to May 2009, during which time he was responsible for principal oversight of the finance operations of an Anadarko subsidiary, Anadarko Algeria Company, LLC. From August 2006 to April 2007, he served as an independent financial consultant to Anadarko in its Beijing, China and Rio de Janeiro, Brazil offices. From April 2001 until June 2006, he held executive management positions at Prosoft Learning Corporation, including serving as its President and Chief Executive Officer from November 2004 until that company’s sale in June 2006. In April 2006, to facilitate its acquisition by another company, Prosoft filed a prepackaged voluntary plan of reorganization. From 2000 to 2001 he co-founded and served as Chief Operating Officer and Chief Financial Officer of Meta4 Group Limited, an online direct marketer based in Hong Kong and Tokyo. Previously, he held positions of increasing responsibility at Prudential Capital Group and Prudential Asset Management Asia, where he focused on the negotiation, structuring and execution of private debt and equity investments. He holds a Bachelor of Science degree in Economics from the Wharton School of the University of Pennsylvania, and he is a Chartered Financial Analyst.
     
Danny J. Rea
Age: 51
Houston, Texas
Officer since:
August 2007
  Biography/Qualifications

Danny J. Rea has served as Senior Vice President and Chief Operating Officer of our general partner since August 2007 and as Vice President, Midstream of Anadarko since May 2007. He also served as a director of our general partner from August 2007 to September 2009. Previously, Mr. Rea served as Manager, Midstream Services of Anadarko from May 2004 to May 2007 and Manager, Gas Field Services from August 2000 to May 2007. Mr. Rea joined Anadarko as an engineer in 1981 and has held positions of increasing responsibility over his 28 years at Anadarko. He holds a Bachelor of Science degree in Petroleum Engineering from Louisiana Tech University, and a Master of Business Administration degree from the University of Houston. He currently serves on the board of directors for the Wyoming Pipeline Authority and is a member of the Gas Processors Association and the Society of Petroleum Engineers.
     
Amanda M. McMillian
Age: 37
Houston, Texas
Officer since:
January 2008
  Biography/Qualifications

Amanda M. McMillian has served as Vice President, General Counsel and Corporate Secretary of our general partner since January 2008 and as Lead Counsel of Anadarko since March 2010. She previously served as Senior Counsel from January 2008 to March 2010 and joined Anadarko as Counsel in December 2004. Prior to joining Anadarko, she practiced corporate and securities law at the law firm of Akin Gump Strauss Hauer & Feld LLP. She holds a Bachelor of Arts degree from Southwestern University and Master of Arts and Juris Doctor degrees from Duke University.

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Jeremy M. Smith
Age: 37
Houston, Texas
Officer since:
August 2007
  Biography/Qualifications

Jeremy M. Smith has served as Vice President and Treasurer of our general partner since August 2007 and as Assistant Treasurer, Corporate Finance of Anadarko since July 2006. Prior to joining Anadarko, he served as Assistant Treasurer to Plains Exploration & Production Company from June 2003 to June 2006 and as Assistant Treasurer of 3TEC Energy Corporation from May 2000 until its sale to Plains Exploration & Production Company in June 2003. Mr. Smith holds a Bachelor of Arts degree in Economics from Rice University, a Master of Science degree in Accounting from Texas A&M University and a Master of Business Administration degree from Rice University, and he is a Chartered Financial Analyst.
     
R. A. Walker
Age: 53
Houston, Texas
Director since:
August 2007
Not Independent
  Biography/Qualifications

R. A. Walker has served as a director of our general partner since August 2007. He also served as non-executive Chairman of the Board of our general partner from August 2007 to September 2009. He has served Anadarko as President and Chief Operating Officer since February 2010 and as Chief Operating Officer since March 2009. Prior to these positions he served as Senior Vice President, Finance and Chief Financial Officer of Anadarko since 2005. Prior to joining Anadarko, he was a Managing Director for the Global Energy Group of UBS Investment Bank from 2003 to 2005. Mr. Walker has served as a director of Temple-Inland, Inc. since November 2008, and has served on the boards of directors of numerous publicly traded companies, including TEPPCO Partners, L.P. (a NYSE-listed publicly traded partnership) where he served as chairman of the audit committee. Mr. Walker holds Bachelor of Science and Master of Business Administration degrees from the University of Tulsa.
     
Milton Carroll
Age: 59
Houston, Texas
Director since:
April 2008
Independent
  Biography/Qualifications

Milton Carroll has served as a director of our general partner and as Chairman of the special committee of the board of directors since April 2008. Mr. Carroll currently serves as Chairman of Houston-based CenterPoint Energy, Inc., where he has been a director since 1992. Mr. Carroll is Chairman and founder of Instrument Products, Inc., an oil-tool manufacturing company in Houston, Texas. He also serves as Chairman of Health Care Services Corporation (a Chicago-based company operating through its Blue Cross and Blue Shield divisions in Illinois, Texas, Oklahoma and New Mexico) and is a director of Halliburton Company. Mr. Carroll also served as a director of EGL, Inc. from May 2003 until August 2007 and as a director of the general partner of DCP Midstream Partners, LP from December 2005 to December 2006. Mr. Carroll holds a Bachelor of Science degree in Industrial Technology from Texas Southern University.

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Anthony R. Chase
Age: 54
Houston, Texas
Director since:
April 2008
Independent
  Biography/Qualifications

Anthony R. Chase has served as a director of our general partner and as a member of the special and audit committees of the board of directors since April 2008. He is Chairman and Chief Executive Officer of ChaseSource LP, a Houston-based staffing firm. He is also a consultant to Crest Investment Company a Houston-based private equity firm that develops business opportunities worldwide, and served as an Executive Vice President of Crest Investment Company from January 2009 until December, 2009. Prior to these positions, he had most recently served as the Chairman and Chief Executive Officer of ChaseCom, a global customer relationship management and staffing services company until its sale in 2007 to AT&T. Mr. Chase has also been a Professor of Law at the University of Houston since 1991. Mr. Chase currently serves on the board of directors of Cornell Companies and serves on that board’s audit committee. From July 2004 to July 2008, he served as a director of the Federal Reserve Bank of Dallas, and also served as its Deputy Chairman from 2006 until his departure in July 2008. Mr. Chase holds Bachelor of Arts, Masters of Business Administration and Juris Doctor degrees from Harvard University.
     
James R. Crane
Age: 56
Houston, Texas
Director since:
April 2008
Independent
  Biography/Qualifications

James R. Crane has served as a director of our general partner and as a member of the special and audit committees of the board of directors since April 2008. Mr. Crane is currently Chairman and Chief Executive Officer of Crane Capital Group. He has also served as Chairman of the Board of Crane Worldwide Logistics, a Houston-based single-source provider of global transportation and logistics services, since August 2008. Prior to that time, he served as Founder, Chairman and Chief Executive Officer of EGL, Inc., a NASDAQ-listed global transportation, supply chain management and information services company based in Houston, Texas, from 1984 until its sale in August 2007. Mr. Crane also served on the board of HCC Insurance Holdings, Inc. from 1999 to November 2007. Mr. Crane holds a Bachelor of Science degree in Industrial Safety from the University of Central Missouri.
     
Charles A. Meloy
Age: 49
Houston, Texas
Director since:
February 2009
Not Independent
  Biography/Qualifications

Charles A. Meloy has served as a director of our general partner since February 2009, and as Senior Vice President, Worldwide Operations of Anadarko since December 2006. Before joining Anadarko, he served as Vice President of Exploration and Production at Kerr-McGee Corporation, prior to its acquisition by Anadarko. At Kerr-McGee, Mr. Meloy was Vice President of Gulf of Mexico exploration, production and development from 2004 to 2005, Vice President and Managing Director of North Sea operations from 2002 to 2004, and held several other deepwater Gulf of Mexico management positions beginning in 1999. Earlier in his career, Mr. Meloy held various planning, operations, deepwater and reservoir engineering positions with Oryx Energy Company and its predecessor, Sun Oil Company. He earned a bachelor’s degree in chemical engineering from Texas A&M University and is a member of the Society of Petroleum Engineers and Texas Professional Engineers. Mr. Meloy is a member of the Board of Directors of the Independent Producers of America Association.

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Robert K. Reeves
Age: 52
Houston, Texas
Director since:
August 2007
Not Independent
  Biography/Qualifications

Robert K. Reeves has served as a director of our general partner since August 2007 and as Senior Vice President, General Counsel and Chief Administrative Officer of Anadarko since February 2007. He previously served as Senior Vice President, Corporate Affairs & Law and Chief Governance Officer of Anadarko beginning in 2004. He has also served as a director of Key Energy Services, Inc., a publicly traded oil field services company, since October 2007. Prior to joining Anadarko, he served as Executive Vice President, Administration and General Counsel of North Sea New Ventures from 2003 to 2004 and as Executive Vice President, General Counsel and Secretary of Ocean Energy, Inc. and its predecessor companies from 1997 to 2003. Mr. Reeves holds a Bachelor of Science degree in Business Administration and a Juris Doctor degree from Louisiana State University.
     
David J. Tudor
Age: 50
Carmel, Indiana
Director since:
April 2008
Independent
  Biography/Qualifications

David J. Tudor has served as a director of our general partner and as Chairman of the audit committee and a member of the special committee of the board of directors since April 2008. Since 1999, Mr. Tudor has been the President and Chief Executive Officer of ACES Power Marketing, an Indianapolis-based commodity risk management company owned by 17 Generation and Transmission Cooperatives throughout the United States. Prior to joining ACES Power Marketing, Mr. Tudor was the Executive Vice President & Chief Operating Officer of PG&E Energy Trading, where he managed commercial operations in the United States and Canada. He also currently serves as a director of Wabash Valley Power Association’s Board Risk Oversight Committee. Mr. Tudor holds a Bachelor of Science degree in Accounting from David Lipscomb University.
 
Section 16(a) Beneficial Ownership Reporting Compliance
 
Section 16(a) of the Exchange Act requires our general partner’s board of directors and executive officers, and persons who own more than 10 percent of a registered class of our equity securities, to file with the SEC, and any exchange or other system on which such securities are traded or quoted, initial reports of ownership and reports of changes in ownership of our common units and other equity securities. Officers, directors and greater than 10 percent unitholders are required by the SEC’s regulations to furnish to us and any exchange or other system on which such securities are traded or quoted with copies of all Section 16(a) forms they file with the SEC.
 
To our knowledge, based solely on a review of the copies of such reports furnished to us and written representations that no other reports were required, we believe that all reporting obligations of our general partner’s officers, directors and greater than 10 percent unitholders under Section 16(a) were satisfied during the year ended December 31, 2009, except that (1) in January 2010 an amended Form 4 was filed for James R. Crane relating to a purchase of 5,000 common units that was inadvertently omitted from his Form 4 filed on August 27, 2008 and (2) in March 2010 a late Form 4 was filed for Anthony R. Chase relating to acquisitions pursuant to a broker-administered distribution reinvestment plan.
 
Reimbursement of Expenses of Our General Partner and its Affiliates
 
Our general partner does not receive any management fee or other compensation for its management of our partnership under the omnibus agreement, as amended, the services and secondment agreement or otherwise. Under the omnibus agreement, our reimbursement to Anadarko for certain general and administrative expenses it allocates to us is capped at $8.3 million annually through December 31, 2010, subject to adjustments to reflect changes in the Consumer Price Index and, with the concurrence of the special committee

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of our general partner’s board of directors, to reflect expansions of our operations through the acquisition or construction of new assets or businesses. Thereafter, our general partner will determine the general and administrative expenses to be reimbursed by us in accordance with our partnership agreement. The cap contained in the omnibus agreement does not apply to incremental general and administrative expenses we expect to incur or be allocated to us as a result of being a publicly traded partnership. Please read Item 13 of this annual report for additional information regarding these agreements.
 
Board Committees
 
The board of directors of our general partner has two standing committees: the audit committee and the special committee.
 
Audit Committee
 
The audit committee is comprised of three independent directors, Messrs. Tudor (chairperson), Chase and Crane, each of whom is able to understand fundamental financial statements and at least one of whom has past experience in accounting or related financial management experience. The board has determined that each member of the audit committee is independent under the NYSE listing standards and the Exchange Act. In making the independence determination, the board considered the requirements of the NYSE and our Code of Business Conduct and Ethics. The audit committee held four meetings in 2009.
 
Mr. Tudor has been designated by the board of directors of our general partner as the “audit committee financial expert” meeting the requirements promulgated by the SEC based upon his education and employment experience as more fully detailed in Mr. Tudor’s biography set forth above.
 
The audit committee assists the board of directors in its oversight of the integrity of our consolidated financial statements, our internal controls over financial reporting, and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee has the sole authority to, among other things, (1) retain and terminate our independent registered public accounting firm, (2) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and (3) establish policies and procedures for the pre-approval of all audit, audit-related, non-audit and tax services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has been given unrestricted access to the audit committee and to our management, as necessary.
 
Special Committee
 
The special committee is comprised of four independent directors, Messrs. Carroll (Chairperson), Chase, Crane and Tudor. The special committee reviews specific matters that the board believes may involve conflicts of interest (including certain transactions with Anadarko). The special committee will determine, as set forth in the partnership agreement, if the resolution of the conflict of interest is fair and reasonable to us. The members of the special committee are not officers or employees of our general partner or directors, officers, or employees of its affiliates, including Anadarko. Our partnership agreement provides that any matters approved in good faith by the special committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. The special committee held five meetings in 2009.
 
Meeting of Non-Management Directors and Communications with Directors
 
At each quarterly meeting of our general partner’s board of directors, all of our independent directors meet in an executive session without management participation or participation by non-independent directors. Mr. Carroll, the chairperson of the special committee, presides over these executive sessions.
 
The general partner’s board of directors welcomes questions or comments about the Partnership and its operations. Unitholders or interested parties may contact the board of directors, including any individual


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director, at boardofdirectors@westerngas.com or at the following address and fax number; Name of the Director(s), c/o Corporate Secretary, Western Gas Partners, LP, 1201 Lake Robbins Drive, The Woodlands, Texas 77380, (832) 636-6001.
 
Code of Ethics, Corporate Governance Guidelines and Board Committee Charters
 
Our general partner has adopted a Code of Ethics For Chief Executive Officer and Senior Financial Officers, or the “Code of Ethics,” which applies to our general partner’s Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, Controller and all other senior financial and accounting officers of our general partner. If the general partner amends the Code of Ethics or grants a waiver, including an implicit waiver, from the Code of Ethics, the Partnership will disclose the information on its Internet website. Our general partner has also adopted Corporate Governance Guidelines that outline the important policies and practices regarding our governance and a Code of Business Conduct and Ethics applicable to all employees of Anadarko or affiliates of Anadarko who perform services for us and our general partner.
 
We make available free of charge, within the “Investor Relations” section of our website at www.westerngas.com/page/ir-governance/, and in print to any unitholder who so requests, the Code of Ethics, the Corporate Governance Guidelines, the Code of Business Conduct and Ethics, our audit committee charter and our special committee charter. Requests for print copies may be directed to investors@westerngas.com or to: Investor Relations, Western Gas Partners LP, 1201 Lake Robbins Drive, The Woodlands, Texas 77380, or telephone (832) 636-6000. We will post on our Internet website all waivers to or amendments of the Code of Ethics, which are required to be disclosed by applicable law and the NYSE’s Corporate Governance Listing Standards. The information contained on, or connected to, our Internet website is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.
 
Item 11.   Executive Compensation
 
Compensation Discussion and Analysis
 
Overview
 
We do not directly employ any of the persons responsible for managing our business, and we do not have a compensation committee of the board of directors. Western Gas Holdings, LLC, our general partner, manages our operations and activities, and its board of directors and officers make compensation decisions on our behalf.
 
Some of the officers of our general partner also serve as officers of Anadarko. The compensation (other than the long-term incentive plan benefits described below) of Anadarko’s employees that perform services on our behalf, including our executive officers, is approved by Anadarko’s management. Awards under our long-term incentive plan are recommended by Anadarko’s management and approved by the board of directors of our general partner. Our reimbursement of Anadarko for the compensation of executive officers is governed by, and subject to the limitations contained in, the omnibus agreement and is based on Anadarko’s methodology used for allocating general and administrative expenses to us. Under the omnibus agreement, as amended, our reimbursement of certain general and administrative expenses was capped at $6.9 million for 2009 and is capped at $8.3 million for 2010, subject to adjustment to reflect changes in the Consumer Price Index and, with the concurrence of the special committee of our general partner’s board of directors, to reflect expansions of our operations through the acquisition or construction of new assets or businesses. Thereafter, our general partner will determine the general and administrative expenses to be reimbursed by us in accordance with our partnership agreement. The cap contained in the omnibus agreement does not apply to incremental general and administrative expenses we incur or that are allocated to us as a result of being a publicly traded partnership. Please read the caption Omnibus agreement under Item 13 of this annual report.
 
Our “named executive officers” for 2009 were Robert G. Gwin (the principal executive officer), Donald R. Sinclair, Benjamin M. Fink (the principal financial officer and principal accounting officer), Danny J. Rea (the principal operating officer), Amanda M. McMillian and Michael C. Pearl (former principal financial officer and principal accounting officer). Compensation paid or awarded by us in 2009 with respect to the


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named executive officers reflects only the portion of compensation expense that is allocated to us pursuant to Anadarko’s allocation methodology and subject to the terms of the omnibus agreement. Anadarko has the ultimate decision-making authority with respect to the total compensation of the named executive officers and, subject to the terms of the omnibus agreement, the portion of such compensation that is allocated to us pursuant to Anadarko’s allocation methodology. The following discussion relating to compensation paid by Anadarko is based on information provided to us by Anadarko and does not purport to be a complete discussion and analysis of Anadarko’s executive compensation philosophy and practices. With the exception of the independent director grants under our long-term incentive plan and awards made under the Western Gas Holdings, LLC Amended and Restated Equity Incentive Plan, the elements of compensation discussed below (and Anadarko’s decisions with respect to the levels of such compensation), are not subject to approvals by the board of directors of our general partner, including the audit or special committee thereof. Awards under our long-term incentive plan are made by the board of directors of our general partner.
 
Anadarko’s executive compensation program design, principles and process
 
Anadarko’s executive compensation program is designed to adhere to the following philosophy and design principles:
 
Anadarko’s Compensation Committee believes that:
 
  •  executive interests should be aligned with stockholder interests;
 
  •  executive compensation should be structured to provide appropriate incentive and reasonable reward for the contributions made and performance achieved; and
 
  •  a competitive compensation package must be provided to attract and retain experienced, talented executives to ensure Anadarko’s success.
 
In support of this philosophy, Anadarko’s executive compensation programs are designed to adhere to the following principles:
 
  •  a majority of total executive compensation should be in the form of equity-based compensation;
 
  •  a meaningful portion of total executive compensation should be tied directly to the achievement of goals and objectives related to Anadarko’s targeted financial and operating performance;
 
  •  a significant component of performance-based compensation should be tied to long-term relative performance measures that emphasize an increase in stockholder value over time;
 
  •  performance-based compensation opportunities should not encourage excessive risk taking that may compromise Anadarko’s value or its stockholders;
 
  •  executives should maintain significant levels of equity ownership;
 
  •  to encourage retention, a substantial portion of compensation should be forfeitable by the executive upon voluntary termination;
 
  •  total compensation opportunities should be reflective of each executive officer’s role, skills, experience level and individual contribution to the organization; and
 
  •  our executives should be motivated to contribute as team members to Anadarko’s overall success, as opposed to merely achieving specific individual objectives.
 
Anadarko establishes compensation levels for each executive officer. The level of each element of director compensation is generally benchmarked against the 50th and 75th percentiles of Anadarko’s industry peer group. In setting compensation levels of each executive officer, Anadarko considers individual experience, individual performance, internal equity, development and/or succession status, and other individual or organizational circumstances. In the case of our named executive officers, Anadarko takes into account the additional duties, as applicable, our executive officers assume in connection with their roles as officers of our general partner.


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With respect to compensation objectives and decisions regarding the named executive officers for 2009, Anadarko’s management reviewed market data for determining relevant compensation levels and compensation program elements. In addition, Anadarko’s management reviewed and, in certain cases, participated in, various relevant compensation surveys and consulted with compensation consultants with respect to determining 2009 compensation for our named executive officers. All compensation determinations are discretionary and, as noted above, subject to Anadarko’s decision-making authority.
 
Elements of compensation
 
The primary elements of Anadarko’s compensation program are a combination of annual cash and long-term equity-based compensation. For 2009, the principal elements of compensation for the named executive officers are as follows:
 
  •  base salary;
 
  •  annual cash incentives;
 
  •  equity-based compensation, which includes equity-based compensation under Anadarko’s 2008 Omnibus Incentive Compensation Plan, or the “Omnibus Plan,” the Western Gas Partners, LP 2008 Long-Term Incentive Plan, and the Western Gas Holdings, Amended and Restated LLC Equity Incentive Plan; and
 
  •  Anadarko’s other benefits, including welfare and retirement benefits, severance benefits and change of control benefits, plus other benefits on the same basis as other eligible Anadarko employees.
 
Base Salary.  Anadarko’s management establishes base salaries to provide a fixed level of income for our named executive officers for their level of responsibility (which may or may not be related to our business), their relative expertise and experience, and in some cases their potential for advancement. As discussed above, a portion of the base salaries of our named executive officers is to be allocated to us based on Anadarko’s methodology used for allocating general and administrative expenses, subject to the limitations in the omnibus agreement.
 
Annual Cash Incentives (Bonuses).  Anadarko’s management awarded annual cash awards to our named executive officers in 2010 under the 2009 Anadarko annual incentive program, or “AIP,” which is part of Anadarko’s Omnibus Plan. Annual cash incentive awards are used by Anadarko to motivate and reward executives for the achievement of Anadarko objectives aligned with value creation and/or recognize individual contributions to Anadarko’s performance. The annual incentive program puts a portion of an executive’s compensation at risk by linking potential annual compensation to Anadarko’s achievement of specific performance metrics during the year related to operational, financial and safety measures internal to Anadarko. The overall funding for Anadarko’s annual incentive program for senior executive officers is capped at 200% of target. Anadarko’s senior executives may receive up to 200% of their individual bonus target if Anadarko significantly exceeds the specified performance metrics and, conversely, no bonus is paid if Anadarko does not achieve a minimum threshold level of performance. For those named executive officers who are also executive officers of Anadarko and file reports under Section 16(a) of the Exchange Act with respect to their Anadarko holdings, actual bonus awards were determined by the compensation and benefits committee, or compensation committee, of Anadarko’s board of directors according to Anadarko’s, and each officer’s contribution toward, achievement against the established performance metrics. The bonus targets are intended to provide a designated level of compensation opportunity when Anadarko and the officers achieve the specified performance metrics as approved by Anadarko’s compensation committee.
 
The portion of any annual cash awards allocable to us is based on Anadarko’s methodology used for allocating general and administrative expenses, subject to the limitations established in the omnibus agreement. Anadarko’s general policy is to pay these awards during the first quarter of each calendar year for the prior year’s performance.
 
Long-Term Incentive Awards Under Anadarko’s 2008 Omnibus Incentive Compensation Plan.  Anadarko periodically makes equity-based awards under its Omnibus Plan to align the interests of its executive officers


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with those of Anadarko shareholders by emphasizing the long-term growth in Anadarko’s value. For 2009, the annual equity awards consisted of a combination of (1) stock options, (2) time-based restricted stock and restricted stock units, and/or (3) performance unit awards. This award structure is intended to provide a combination of equity-based vehicles that is performance-based in absolute and relative terms, while also encouraging retention.
 
Our Long-Term Incentive Plan.  Our general partner has adopted the Western Gas Partners, LP 2008 Long-Term Incentive Plan for the employees and directors of our general partner and the employees of its affiliates, including Anadarko, who perform services for us. The Long-Term Incentive Plan provides for the grant of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights and substitute awards. For a more detailed description of this plan, please read the caption Western Gas Partners, LP 2008 Long-Term Incentive Plan below within this Item 11. Any equity-based awards to our executive officers and the directors of our general partner are intended to align their long-term interests with those of our unitholders.
 
Our General Partner’s Amended and Restated Equity Incentive Plan.  Our general partner has adopted the Amended and Restated Western Gas Holdings, LLC Equity Incentive Plan for the executive officers of our general partner. The awards of unit appreciation rights, unit value rights and distribution equivalent rights made under this plan are designed to provide incentive compensation to encourage superior performance. For a description of this plan, please read the caption Western Gas Holdings, LLC Amended and Restated Equity Incentive Plan below within this Item 11.
 
Other Benefits.  In addition to the compensation discussed above, Anadarko also provides other benefits to the named executive officers who are also executive officers of Anadarko, including:
 
  •  retirement benefits to match competitive practices in Anadarko’s industry, including the Anadarko Employee Savings Plan, Anadarko’s Savings Restoration Plan, and the Anadarko Retirement Plan and Retirement Restoration Plan;
 
  •  severance benefits under the Anadarko Officer Severance Plan;
 
  •  certain change of control benefits under key employee change of control contracts;
 
  •  director and officer indemnification agreements;
 
  •  a limited number of perquisites, including financial counseling, tax preparation and estate planning, an executive physical program, management disability insurance, and personal excess liability insurance; and
 
  •  benefits including medical, dental, vision, flexible spending accounts, paid time off, life insurance and disability coverage, which are also provided to all other eligible U.S.-based Anadarko employees.
 
For a more detailed summary of Anadarko’s executive compensation program and the benefits provided thereunder, please read the caption Compensation Discussion and Analysis in Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed with the SEC no later than April 9, 2010.
 
Role of executive officers in executive compensation
 
Anadarko’s compensation committee determines the compensation (other than the long-term incentive plan benefits described above) payable to our named executive officers who are also senior executive officers of Anadarko and Anadarko’s management determines the compensation for each of our other named executive officers. The board of directors of our general partner determines compensation for the independent, non-management directors of our general partner’s board of directors, as well as any grants made under our long-term incentive plan and its equity incentive plan.
 
Compensation mix
 
We believe that the mix of base salary, cash awards, awards under Anadarko’s stock incentive plan, our long-term incentive plan and our general partner’s equity incentive plan, and other compensation fit


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Anadarko’s and our overall compensation objectives. We believe this mix of compensation provides competitive compensation opportunities to align and drive employee performance in support of Anadarko’s business strategies, as well as our own, and to attract, motivate and retain high-quality talent with the skills and competencies required by Anadarko and us.
 
WESTERN GAS PARTNERS, LP 2008 LONG-TERM INCENTIVE PLAN
 
General
 
In April 2008, our general partner adopted the Western Gas Partners, LP 2008 Long-Term Incentive Plan, which we refer to as the LTIP, for employees and directors of our general partner and its affiliates, including Anadarko, who perform services for us. The summary of the LTIP contained herein does not purport to be complete and is qualified in its entirety by reference to the LTIP, the terms of which have been previously filed with the SEC. The LTIP provides for the grant of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights and substitute awards. Subject to adjustment for certain events, an aggregate of 2,250,000 common units may be delivered pursuant to awards under the LTIP. Units that are cancelled, forfeited or are withheld to satisfy our general partner’s tax withholding obligations or payment of an award’s exercise price are available for delivery pursuant to other awards. The LTIP is administered by our general partner’s board of directors. The LTIP has been designed to promote the interests of the partnership and its unitholders by strengthening its ability to attract, retain and motivate qualified individuals to serve as directors and employees.
 
Unit awards
 
Our general partner’s board of directors may grant unit awards to eligible individuals under the LTIP. A unit award is an award of common units that are fully vested upon grant and are not subject to forfeiture.
 
Restricted units and phantom units
 
A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of our general partner’s board of directors, cash equal to the fair market value of a common unit. Our general partner’s board of directors may make grants of restricted and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the board may determine are appropriate, including the period over which restricted or phantom units will vest. The board may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria. In addition, the restricted and phantom units will vest automatically upon a change of control of our general partner (as defined in the LTIP) or as otherwise described in the award agreement. Our general partner’s board of directors approved phantom unit grants to each of Messrs. Carroll, Chase, Crane and Tudor in connection with their election to the board. The phantom units granted to each of these directors in 2009 had a grant-date value of approximately $70,000. These phantom units vest on the first anniversary of the date of grant and have tandem distribution equivalent rights.
 
If a grantee’s employment or membership on the board of directors terminates for any reason, the grantee’s restricted and phantom units will be automatically forfeited unless and to the extent that the award agreement or the board provides otherwise.
 
Distributions made by us with respect to awards of restricted units may, in the board’s discretion, be subject to the same vesting requirements as the restricted units. The board, in its discretion, may also grant tandem distribution equivalent rights with respect to phantom units.
 
Unit options and unit appreciation rights
 
The LTIP also permits the grant of options covering common units and unit appreciation rights. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit


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appreciation rights represent the right to receive the appreciation in the value of a number of common units over a specified exercise price, either in cash or in common units as determined by the board. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as the board may determine, consistent with the LTIP; however, a unit option or unit appreciation right must have an exercise price greater than or equal to the fair market value of a common unit on the date of grant. No unit options or unit appreciation rights were granted during 2009.
 
Distribution equivalent rights
 
Distribution equivalent rights are rights to receive all or a portion of the distributions otherwise payable on units during a specified time. Distribution equivalent rights may be granted alone or in combination with another award.
 
Source of common units; cost
 
Common units to be delivered with respect to awards may be newly-issued units, common units acquired by our general partner in the open market, common units already owned by our general partner or us, common units acquired by our general partner directly from us or any other person or any combination of the foregoing. Our general partner is entitled to reimbursement by us for the cost incurred in acquiring such common units. With respect to unit options, our general partner is entitled to reimbursement from us for the difference between the cost it incurs in acquiring these common units and the proceeds it receives from an optionee at the time of exercise. Thus, we bear the cost of the unit options. If we issue new common units with respect to these awards, the total number of common units outstanding will increase, and our general partner will remit the proceeds it receives from a participant, if any, upon exercise of an award to us. With respect to any awards settled in cash, our general partner is entitled to reimbursement by us for the amount of the cash settlement.
 
Amendment or termination of long-term incentive plan
 
Our general partner’s board of directors, in its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The LTIP will automatically terminate on the earlier of the 10th anniversary of the date it was initially adopted by our general partner or when common units are no longer available for delivery pursuant to awards under the LTIP. Our general partner’s board of directors will also have the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP; provided, however, that no change in any outstanding award may be made that would materially impair the rights of the participant without the consent of the affected participant, and/or result in taxation to the participant under Section 409A of the Internal Revenue Code of 1986, as amended, unless otherwise determined by the general partner’s board of directors.
 
WESTERN GAS HOLDINGS, LLC AMENDED AND RESTATED EQUITY INCENTIVE PLAN
 
General
 
Our general partner has adopted the Western Gas Holdings, LLC Amended and Restated Equity Incentive Plan, which we refer to as the Incentive Plan, for the executive officers of our general partner. The summary of the Incentive Plan and related award grants contained herein does not purport to be complete and is qualified in its entirety by reference to the Incentive Plan. The Incentive Plan provides for the grant of unit appreciation rights, unit value rights and distribution equivalent rights. Subject to adjustment for certain events, an aggregate of 100,000 unit appreciation rights, 100,000 unit value rights and 100,000 distribution equivalent rights may be delivered pursuant to awards under the Incentive Plan. Unit appreciation rights, unit value rights and distribution equivalent rights that are forfeited, cancelled, or otherwise terminated or expired without payment are available for grant pursuant to other awards made under the Incentive Plan. The Incentive Plan is administered by our general partner’s board of directors. The Incentive Plan has been designed to provide to key executives of the general partner incentive compensation to encourage superior performance of the partnership and the general partner. The costs of these awards are allocated within and subject to the reimbursement provisions of the omnibus agreement.


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Unit appreciation rights
 
Our general partner’s board of directors may grant unit appreciation rights to eligible individuals under the Incentive Plan. A unit appreciation right is the economic equivalent of a stock appreciation right so it does not include a participant’s pro rata share of the value of our general partner as of the grant date. Our general partner’s board of directors has the authority to determine the executives to whom unit appreciation rights may be granted, the number of unit appreciation rights to be granted to each participant, the period over and the conditions, if any, under which the unit appreciation rights may become vested or forfeited, and such other terms and conditions as the board may establish with respect to such awards.
 
The number of unit appreciation rights outstanding will be adjusted by our general partner’s board of directors upon certain changes in capitalization to prevent the valuation dilution or enlargement of potential benefits intended to be provided with respect to awards granted under the Incentive Plan; provided, however, that no change in any outstanding award made as a result of a change in capitalization may materially impair the rights of the participant without the consent of the affected participant.
 
Unless otherwise provided in the award agreement, termination of a participant’s employment with Anadarko shall cause all of such participant’s unvested awards under the Incentive Plan to be forfeited upon termination. However, the general partner’s board of directors may, in its discretion, waive in whole or in part such forfeiture.
 
Vesting of unit appreciation rights
 
Our general partner’s board of directors has the authority to determine the restrictions and vesting provisions for any unit appreciation rights. The initial grants of unit appreciation rights under the Incentive Plan provide for vesting (x) in one-third increments over a three-year period commencing on the first anniversary of the grant date (or in the case of our CEO, Mr. Sinclair, in two equal installments on the second and fourth anniversaries of the grant date) or (y) immediately upon the occurrence of any of the following events, if they occur earlier, including: (1) a change of control of our general partner or Anadarko; (2) the closing of an initial public offering of our general partner; (3) termination of employment with our general partner and its affiliates (including Anadarko) due to involuntary termination (with or without cause); (4) death; (5) disability as defined under Section 409A of the Internal Revenue Code of 1986, as amended; or (6) an unforeseeable emergency as defined in the Incentive Plan. Upon the occurrence of a vesting event, each participant will receive a lump-sum cash payment (less any applicable withholding taxes) for each unit appreciation right that is exercised prior to the earlier of the 90th day after a participant’s voluntary termination and the 10th anniversary of the grant date. The unit appreciation rights may not be sold or transferred except to the general partner, Anadarko or any of their affiliates.
 
Unit value rights
 
Our general partner’s board of directors may grant unit value rights to eligible individuals under the Incentive Plan. A unit value right imparts to a participant his or her pro rata share of the value of the general partner at the time of grant. Our general partner’s board of directors has the authority to determine the executives to whom unit value rights may be granted, the number of unit value rights to be granted to each participant, the period over and the conditions, if any, under which the unit value rights may become vested or forfeited, and such other terms and conditions as the board may establish with respect to such awards.
 
The number of unit value rights outstanding will be adjusted by our general partner’s board of directors upon certain changes in capitalization to prevent the valuation dilution or enlargement of potential benefits intended to be provided with respect to awards granted under the Incentive Plan; provided, however, that no change in any outstanding award made as a result of a change in capitalization may materially impair the rights of the participant without the consent of the affected participant.
 
Unless otherwise provided in the award agreement, termination of a participant’s employment with Anadarko shall cause all of such participant’s unvested awards under the Incentive Plan to be forfeited upon


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termination. However, the general partner’s board of directors may, in its discretion, waive in whole or in part such forfeiture.
 
Vesting of unit value rights
 
Our general partner’s board of directors has the authority to determine the restrictions and vesting provisions for any unit value rights. The initial grants of unit value rights provide for vesting (x) in one-third increments over a three-year period commencing on the first anniversary of the grant date (or in the case of our CEO, Mr. Sinclair, in two equal installments on the second and fourth anniversaries of the grant date) or (y) immediately upon the occurrence of any of the following events, if they occur earlier, including: (1) a change of control of our general partner or Anadarko; (2) the closing of an initial public offering of our general partner; (3) termination of employment with our general partner and its affiliates (including Anadarko) due to involuntary termination (with or without cause); (4) death; (5) disability as defined under Section 409A of the Internal Revenue Code of 1986, as amended; or (6) an unforeseeable emergency as defined in the Incentive Plan. Upon the occurrence of a vesting event, each participant will receive a lump-sum cash payment (less any applicable withholding taxes) for each unit value right. The unit value rights may not be sold or transferred except to the general partner, Anadarko or any of their affiliates.
 
Distribution equivalent rights
 
Grants of unit appreciation rights and unit value rights also include an equal number of distribution equivalent rights, which entitle the holder to receive with respect to each unit appreciation right and unit value right awarded an amount in cash or incentive units equal in value to the distributions made by our general partner to its members during the period an award is outstanding.
 
Vesting of distribution equivalent rights
 
Our general partner’s board of directors has the authority to determine the restrictions and vesting provisions for any distribution equivalent rights. The initial grants of distribution equivalent rights provide for vesting immediately upon the occurrence of any of the following events, including: (1) a change of control of our general partner or Anadarko; (2) the closing of an initial public offering of our general partner; (3) termination of employment with our general partner and its affiliates (including Anadarko) due to involuntary termination (with or without cause); (4) death; (5) disability as defined under Section 409A of the Internal Revenue Code of 1986, as amended; (6) the date three days in advance of the 10th anniversary of the grant date; or (7) an unforeseeable emergency as defined in the Incentive Plan. Upon the occurrence of a vesting event, each participant will receive a lump-sum cash payment (less any applicable withholding taxes) for each distribution equivalent right. The distribution equivalent rights may not be sold or transferred except to our general partner, Anadarko or any of their affiliates.
 
The following table summarizes information regarding UVRs, UARs and DERs issued under the Incentive Plan for the year ended December 31, 2009:
 
                         
    UVRs     UARs     DERs  
 
Outstanding at beginning of year
    50,000       50,000       50,000  
Granted
    30,000       30,000       30,000  
Vested or settled(1)
    (16,667 )            
Forfeited
    (6,666 )     (6,666 )     (6,666 )
                         
Outstanding at end of year
    56,667       73,334       73,334  
                         
Weighted average value at December 31, 2009
  $ 50.00     $ 17.00       (2)
 
 
(1) UARs and DERs remain outstanding upon vesting until they are settled in cash, are forfeited or expire. As of December 31, 2009, 16,667 of the outstanding UARs and 3,334 of the DERs were vested.
 
(2) The DERs have no attributed value as our general partner has not declared or paid distributions since its inception.


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Amendment or termination of Incentive Plan
 
Our general partner’s board of directors, in its discretion, may amend or terminate the Incentive Plan at any time with respect to the unit appreciation rights, unit value rights and distribution equivalent rights, including increasing the number of unit appreciation rights, unit value rights and distribution equivalent rights available for awards under the Incentive Plan, without the consent of the participants. The board may also waive any conditions, rights or terms under any award under this plan, provided that no change in any award under the plan will materially reduce the benefit to a participant in the plan without such participant’s consent. The Incentive Plan will terminate on the date termination is approved by our general partner’s board of directors or when all unit appreciation rights, unit value rights and distribution equivalent rights available under the Incentive Plan have been paid to participants.
 
EXECUTIVE COMPENSATION
 
We do not directly employ any of the persons responsible for managing or operating our business and we have no compensation committee. Instead, we are managed by our general partner, Western Gas Holdings, LLC, the executive officers of which are employees of Anadarko. Our reimbursement for the compensation of executive officers is governed by the omnibus agreement and the services and secondment agreement described in the caption Agreements with Anadarko — Services and secondment agreement under Item 13 of this annual report.
 
Summary Compensation Table
 
The following table summarizes the compensation amounts expensed by us for our general partner’s Chief Executive Officer, Chief Financial Officer and our three highest paid executive officers other than our CEO and CFO for the fiscal year ended December 31, 2009 and for the period from May 14, 2008 to December 31, 2008, which represents the period following our initial public offering.
 
                                                                 
                        Non-Equity
       
                Stock
  Option
  Incentive Plan
  All Other
   
Name and Principal
      Salary
  Bonus
  Awards
  Awards
  Compensation
  Compensation
  Total
Position
  Year   ($)(1)   ($)   ($)(2)   ($)(3)   ($)(4)   ($)(5)   ($)
 
Robert G. Gwin
    2009       243,228             157,633       122,275       268,020       83,779       874,935  
Chairman and Chief Executive Officer(6)
    2008       107,392             1,140,902       686,012       163,977       28,137       2,126,420  
Donald R. Sinclair
    2009       56,250             750,000             60,750       24,750       891,750  
President(7)
                                                               
Benjamin M. Fink(8)
    2009       120,762             421,120       50,132       72,363       49,069       713,446  
Senior Vice President and Chief Financial Officer
                                                               
Danny J. Rea
    2009       110,416             191,170       82,511       78,970       38,681       501,748  
Senior Vice President and Chief Operating Officer
    2008       65,699             468,489       118,861       72,459       17,213       742,721  
Amanda M. McMillian
    2009       98,960             27,531       29,961       35,673       35,105       227,230  
Vice President, General Counsel and Corporate Secretary
    2008       48,011             270,050             32,049       12,579       362,689  
Michael C. Pearl(9)
    2009       51,261             8,025       3,087       23,067       13,990       99,430  
Former Senior Vice President and Chief Financial Officer
    2008       55,286             332,523       44,508       53,787       14,485       500,589  


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(1) The amounts in this column reflect the base salary compensation allocated to us by Anadarko for the fiscal years ended December 31, 2009 and 2008.
 
(2) The amounts in this column reflect the expected allocation to us of the grant date fair value, computed in accordance with generally accepted accounting principles, for non-option stock awards granted pursuant to the Amended and Restated Western Gas Holdings, LLC Equity Incentive Plan, 2008 Omnibus Incentive Compensation Plan and Anadarko’s 1999 Stock Incentive Plan. The awards granted by Western Gas Holdings, LLC were valued by multiplying the number of units awarded by the current per unit valuation on the date of grant of $50.00, assuming no forfeitures. The value per unit was based on the estimated fair value of the general partner using a hybrid discounted cash flow and multiples valuation approach. For a discussion of valuation assumptions for the awards under the 2008 Omnibus Incentive Plan, see Note 12 — Stock-Based Compensation of the notes to consolidated financial statements included under Item 8 of Anadarko’s annual report on Form 10-K for the year ended December 31, 2009. For information regarding the non-option stock awards granted to the named executives in 2009, please see the Grants of Plan-Based Awards Table.
 
(3) The amounts in this column reflect the expected allocation to us of the grant date fair value, computed in accordance with generally accepted accounting principles, for option awards granted pursuant to the Western Gas Holdings, LLC Amended and Restated Equity Incentive Plan, 2008 Omnibus Incentive Compensation Plan and Anadarko’s 1999 Stock Incentive Plan. See note (2) above for valuation assumptions. For information regarding the option awards granted to the named executives in 2009, please see the Grants of Plan-Based Awards Table.
 
(4) The amounts in this column reflect the compensation under the Anadarko annual incentive program allocated to us for the fiscal years ended December 31, 2009 and 2008. The 2009 amounts represent payments which were earned in 2009 and paid in early 2010 and the 2008 amounts represent the payments which were earned in 2008 and paid in early 2009.
 
(5) The amounts in this column reflect the compensation expenses related to Anadarko’s retirement and savings plans that were allocated to us for the fiscal years ended December 31, 2009 and 2008. The 2009 allocated expenses are detailed in the table below:
 
                 
    Retirement Plan
  Savings Plan
Name
  Expense   Expense
 
Robert G. Gwin
  $ 62,996     $ 20,783  
Donald R. Sinclair
  $ 20,250     $ 4,500  
Benjamin M. Fink
  $ 38,868     $ 10,201  
Danny J. Rea
  $ 29,344     $ 9,337  
Amanda M. McMillian
  $ 26,724     $ 8,381  
Michael C. Pearl
  $ 9,640     $ 4,350  
 
(6) On October 1, 2009, Mr. Gwin was elected Chairman of our general partner’s board of directors and Mr. Sinclair succeeded him as President. On January 11, 2010, Mr. Sinclair succeeded Mr. Gwin as Chief Executive Officer of our general partner.
 
(7) Mr. Sinclair was appointed President on October 1, 2009 and Chief Executive Officer of our general partner on January 11, 2010.
 
(8) Mr. Fink was appointed Senior Vice President, Chief Financial Officer of our general partner on May 21, 2009.
 
(9) Mr. Pearl departed as Senior Vice President, Chief Financial Officer of our general partner on May 21, 2009 to assume the responsibilities associated with his promotion in March 2009 to Corporate Controller at Anadarko.


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Grants of Plan-Based Awards in 2009
 
The following table sets forth information concerning annual incentive awards, stock options, unit appreciation rights, unit value rights, restricted stock shares, restricted stock units and performance units granted during 2009 to each of the named executive officers:
 
                                                                             
                            All Other
  All Other
      Grant
                            Stock
  Option
      Date
    Estimated Future Payouts
              Awards:
  Awards:
  Exercise
  Fair Value
    Under Non-
              Number of
  Number of
  or
  of Stock
    Equity Incentive Plan
  Estimated Future Payouts Under
  Shares of
  Securities
  Base Price
  and
Name
  Awards(1)   Equity Incentive Plan Awards(2)   Stock or
  Underlying
  of Option
  Option
and
  Threshold
  Target
  Maximum
  Threshold
  Target
  Maximum
  Units
  Options
  Awards
  Awards
Grant Date
  ($)   ($)   ($)   (#)   (#)   (#)   (#)(3)   (#)(4)   ($/Sh)   ($)(5)
 
Robert G. Gwin
 —
      239,270       268,020                                                          
3/1/2009
                                                        66,200       34.95       107,277  
3/1/2009
                                                29,900                       123,951  
11/10/2009
                                                        47,200       65.44       14,998  
11/10/2009
                                                21,400                       16,611  
11/10/2009
                        5,724       21,200       42,400                               17,071  
Donald R. Sinclair
 —
      33,750       60,750                                                          
10/1/09(6)
                                                        20,000       50.00        
10/1/09(6)
                                                20,000                       750,000  
Benjamin M. Fink
 —
      54,341       72,363                                                          
3/6/2009
                                                        5,555       33.07       50,132  
3/6/2009
                                                2,000                       46,120  
5/21/09(7)
                                                        10,000       50.00        
5/21/09(7)
                                                10,000                       375,000  
Danny J. Rea
 —
      66,250       78,970                                                          
11/10/2009
                                                        7,700       65.44       82,511  
11/10/2009
                                                3,500                       91,616  
11/10/2009
                        945       3,500       7,000                               99,554  
Amanda M. McMillian
 —
      29,688       35,673                                                          
3/6/2009
                                                        4,630       33.07       29,961  
3/6/2009
                                                1,665                       27,531  
Michael C. Pearl
 —
      23,067       23,067                                                          
3/6/2009
                                                        6,790       33.07       3,087  
3/6/2009
                                                2,445                       2,840  
4/1/2009
                                                5,500                       5,185  
6/1/2009(8)
                                                        8,057       49.78        
6/1/2009(8)
                                                3,348                        
 
 
(1) Reflects the estimated future cash payouts allocable to us under Anadarko’s annual incentive program. If threshold levels of performance are not met, then the payout can be zero. The maximum value reflects the maximum amount allocable to us under the program. The expense allocated to us for the actual bonus payouts under the annual incentive program for 2009 are reflected in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table. For additional discussion of Anadarko’s annual incentive program please see section Compensation Discussion and Analysis — Elements of Total Compensation — Annual Cash Incentives (Bonuses) of Anadarko’s proxy statement for its annual meeting of stockholders which is expected to be filed no later than April 9, 2010.


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(2) Reflects the estimated future payout under Anadarko’s performance unit awards. Executives may earn from 0% to 200% of the targeted award based on Anadarko’s relative TSR performance over a specified performance period. Fifty percent of this award is tied to a two-year performance period and the remaining fifty percent is tied to a three-year performance period. If earned, the awards are to be paid in cash. The threshold value represents the minimum payment (other than zero) that may be earned. For additional discussion of Anadarko’s performance unit awards please see section Compensation Discussion and Analysis — Elements of Total Compensation — Equity Compensation of Anadarko’s proxy statement for its annual meeting of stockholders which is expected to be filed no later than April 9, 2010.
 
(3) Reflects the number of unit value rights, restricted stock shares and restricted stock units awarded in 2009. Unless otherwise specified, these awards vest equally over three years, beginning with the first anniversary of the grant date. Executive officers receive distribution equivalent rights on the unit value rights, dividends on the restricted stock shares and dividend equivalents on the restricted stock units.
 
(4) Reflects the number of stock options and unit appreciation rights each named executive officer was awarded in 2009. Unless otherwise specified, these awards vest equally over three years, beginning with the first anniversary of the date of grant. The stock options have a term of seven years and the unit appreciation rights have a term of ten years.
 
(5) The amounts included in the Grant Date Fair Value of Stock and Option Awards column represent the expected allocation to us of the grant date fair value of the awards made to named executives in 2009 computed in accordance with generally accepted accounting principles. The value ultimately realized by the executive upon the actual vesting of the award(s) or the exercise of the unit appreciation right(s) and stock option(s) may or may not be equal to the determined value. The awards granted by Western Gas Holdings, LLC were valued by multiplying the number of units awarded by the current per unit valuation on the date of grant of $50.00, assuming no forfeitures. The value per unit was based on the estimated fair value of the general partner using a hybrid discounted cash flow and multiples valuation approach. For a discussion of valuation assumptions for the awards under the 2008 Omnibus Incentive Plan, see Note 12 — Stock-Based Compensation of the notes to consolidated financial statements included under Item 8 of Anadarko’s annual report on Form 10-K for the year ended December 31, 2009.
 
(6) The October 1, 2009 awards were granted under the Western Gas Holdings, LLC Amended and Restated Equity Incentive Plan. These awards vest 50% on the second anniversary of the grant date and 50% on the fourth anniversary of the grant date.
 
(7) The May 21, 2009 awards were granted under the Western Gas Holdings, LLC Amended and Restated Equity Incentive Plan.
 
(8) Mr. Pearl received this award in connection with his departure from the Partnership to assume the responsibilities associated with his promotion at Anadarko. In order to better align his incentive compensation with his new position, he agreed to terminate the unvested portion of his existing equity award granted under the Western Gas Holdings, LLC Amended and Restated Equity Incentive Plan, and receive equity-based compensation of an equivalent value under Anadarko’s compensation plans. This award was treated as a modification to his original award and the incremental fair value computed in accordance with generally accepted accounting principles was zero. These awards maintained the remaining vesting schedule of the original awards so that 50% vest on April 2, 2010 and 50% vest on April 2, 2011.


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Outstanding Equity Awards at Fiscal Year-End 2009
 
The following table reflects all outstanding equity awards as of December 31, 2009 for each of the named executives, including both Anadarko and Western Gas Holdings, LLC awards and does not take into account that under our omnibus agreement with Anadarko we are only allocated a portion of the expense related to these awards. The market values shown are based on Anadarko’s closing stock price on December 31, 2009 of $62.42, unless otherwise noted.
 
                                                                 
          Stock Awards  
                                        Equity Incentive Plan
 
                                        Awards
 
                                        Performance Units(3)  
                                              Market
 
                            Restricted Stock
          Payout
 
                            Shares/Units and Unit Value Rights(2)     Number of
    Value of
 
                                  Market
    Unearned
    Unearned
 
                            Number of
    Value of
    Shares,
    Shares,
 
                            Shares or
    Shares or
    Units or
    Units or
 
    Option Awards(1)     Units of
    Units of
    Other
    Other
 
    Number of Securities
    Option
          Stock That
    Stock That
    Rights
    Rights
 
    Underlying Unexercised Options     Exercise
    Option
    Have Not
    Have Not
    That Have
    That Have
 
    Exercisable
    Unexercisable
    Price
    Expiration
    Vested
    Vested
    Not Vested
    Not Vested
 
Name
  (#)     (#)     ($)     Date     (#)     ($)     (#)     ($)  
 
Robert G. Gwin
    13,500       13,500       50.6900       1/16/2013       4,250       265,285       10,045 (7)     627,009  
      19,100             48.6900       12/4/2013       2,400       149,808       3,800       237,196  
      27,334       13,666       40.5100       1/10/2014       8,533       532,630       19,300       1,204,706  
      14,467       7,233       59.8700       11/6/2014       29,900       1,866,358       21,200       1,323,304  
      7,434       14,866       64.6900       3/12/2015       21,400       1,335,788                  
      26,200       52,400       35.1800       11/4/2015       13,333 (5)     666,650 (6)                
            66,200       34.9500       3/1/2016                                  
            47,200       65.4400       11/10/2016                                  
      6,667 (4)     13,333       50.0000       4/2/2018                                  
Donald R. Sinclair
    (4)     20,000       50.0000       10/1/2019       20,000 (5)     1,000,000 (6)                
Benjamin M. Fink
    3,467       1,733       46.2700       5/1/2014       1,000       62,420                  
      2,800       1,400       51.8900       7/2/2014       933       58,238                  
      1,775       3,550       65.9900       3/13/2015       2,133       133,142                  
            5,555       33.0700       3/6/2016       2,000       124,840                  
      (4)     10,000       50.0000       5/21/2019       10,000 (5)     500,000 (6)                
Danny J. Rea
    5,000             33.4000       12/2/2011       1,166       72,782       6,068 (7)     378,765  
      5,000             43.5550       11/15/2012       5,200       324,584       3,700       230,954  
      5,750             48.9000       12/1/2013       3,500       218,470       4,000       249,680  
      7,067       3,533       59.8700       11/6/2014       6,666 (5)     333,300 (6)     3,500       218,470  
      6,367       12,733       35.1800       11/4/2015                                  
            7,700       65.4400       11/10/2016                                  
      3,334 (4)     6,666       50.0000       4/2/2018                                  
Amanda M. McMillian
          4,630       33.0700       3/6/2016       600       37,452                  
      1,667 (4)     3,333       50.0000       4/2/2018       3,284       204,987                  
                                      1,665       103,929                  
                                      3,333 (5)     166,650 (6)                
Michael C. Pearl
    1,916             48.9000       12/1/2013       1,666       103,992                  
      5,000       2,500       51.8900       7/2/2014       2,000       124,840                  
      1,667       3,333       65.9900       3/13/2015       2,445       152,617                  
            6,790       33.0700       3/6/2016       5,500       343,310                  
            8,057       49.7800       6/1/2016       3,348       208,982                  
      3,334 (4)           50.0000       4/2/2018                                  
 
 
(1) The table below shows the vesting dates for the respective unexercisable stock options and unit appreciation rights listed in the above Outstanding Equity Awards Table:
 


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Vesting Date
  Robert G. Gwin   Donald R. Sinclair   Benjamin M. Fink   Danny J. Rea   Amanda M. McMillian   Michael C. Pearl
 
1/10/2010
    13,666                                
1/16/2010
    13,500                                
3/1/2010
    22,067                                
3/6/2010
                1,852             1,544       2,264  
3/12/2010
    7,433                                
3/13/2010
                1,775                   1,667  
4/2/2010
    6,667                   3,333       1,667       4,029  
5/1/2010
                1,733                    
5/21/2010
                3,334                    
7/2/2010
                1,400                   2,500  
11/4/2010
    26,200                   6,367              
11/6/2010
    7,233                   3,533              
11/10/2010
    15,734                   2,567              
3/1/2011
    22,066                                
3/6/2011
                1,851             1,543       2,263  
3/12/2011
    7,433                                
3/13/2011
                1,775                   1,666  
4/2/2011
    6,666                   3,333       1,666       4,028  
5/21/2011
                3,333                    
10/1/2011
          10,000                          
11/4/2011
    26,200                   6,366              
11/10/2011
    15,733                   2,566              
3/1/2012
    22,067                                
3/6/2012
                1,852             1,543       2,263  
5/21/2012
                3,333                    
11/10/2012
    15,733                   2,567              
10/1/2013
          10,000                          
 
(2) The table below shows the vesting dates for the respective restricted stock shares, restricted stock units and unit value rights listed in the above Outstanding Equity Awards Table:
 

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Vesting Date
  Robert G. Gwin   Donald R. Sinclair   Benjamin M. Fink   Danny J. Rea   Amanda M. McMillian   Michael C. Pearl
 
1/16/2010
    4,250                                
3/1/2010
    9,967                                
3/6/2010
                667             555       815  
3/13/2010
                1,067             1,642       1,000  
4/1/2010
                                  1,834  
4/2/2010
    6,667                   3,333       1,667       1,674  
5/1/2010
                1,000                    
5/21/2010
                3,334                    
7/2/2010
                933             600       1,666  
11/10/2010
    7,134                   1,167              
12/1/2010
    4,267                   2,600              
12/3/2010
    2,400                   1,166              
3/1/2011
    9,966                                
3/6/2011
                666             555       815  
3/13/2011
                1,066             1,642       1,000  
4/1/2011
                                  1,833  
4/2/2011
    6,666                   3,333       1,666       1,674  
5/21/2011
                3,333                    
10/1/2011
          10,000                          
11/10/2011
    7,133                   1,166              
12/1/2011
    4,266                   2,600              
3/1/2012
    9,967                                
3/6/2012
                667             555       815  
4/1/2012
                                  1,833  
5/21/2012
                3,333                    
11/10/2012
    7,133                   1,167              
10/1/2013
          10,000                          
 
(3) The table below shows the performance periods for the respective performance units listed in the above Outstanding Equity Awards Table:
 
                 
Performance Period
  Robert G. Gwin   Danny J. Rea
 
1/1/2008 to 12/31/2009
    10,045       6,068  
1/1/2008 to 12/31/2010
    3,800       3,700  
1/1/2009 to 12/31/2010
    9,650       2,000  
1/1/2009 to 12/31/2011
    9,650       2,000  
1/1/2010 to 12/31/2011
    10,600       1,750  
1/1/2010 to 12/31/2012
    10,600       1,750  
 
(4) This award represents a grant of unit appreciation rights under the Western Gas Holdings, LLC Amended and Restated Equity Incentive Plan.
 
(5) This award represents a grant of unit value rights under the Western Gas Holdings, LLC Amended and Restated Equity Incentive Plan.
 
(6) The market value for this award is calculated based on the maximum per-unit value specified under the award agreement of $50.00.
 
(7) These values represent the number of performance units earned for the performance period ending December 31, 2009. Anadarko’s TSR performance ranked third relative to the defined peer group, which resulted in a 164% payout as a percent of target. Payments of these awards were made in February 2010 after the Compensation Committee’s certification of the performance results. For additional discussion of these awards see section Compensation Discussion and Analysis — Elements of Total Compensation — Equity Compensation of Anadarko’s proxy statement for its annual meeting of stockholders which is expected to be filed no later than April 9, 2010.

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Option Exercises and Stock Vested in 2009
 
The following table reflects all Anadarko option awards exercised in 2009 and Anadarko stock awards that vested in 2009 and does not take into account that under our omnibus agreement with Anadarko we were only allocated a portion of the expense related to these awards.
 
                                 
    Option Awards   Stock Awards
    Number of Shares
      Number of Shares
   
    Acquired on
  Value Realized on
  Acquired on
  Value Realized on
Name
  Exercise (#)   Exercise ($)(1)   Vesting (#)(2)   Vesting ($)(1)
 
Robert G. Gwin
                12,883       684,178  
Donald R. Sinclair
                       
Benjamin M. Fink
                3,000       124,352  
Danny J. Rea
    5,000       230,891       4,850       296,629  
Amanda M. McMillian
                2,713       114,368  
Michael C. Pearl
                3,208       140,982  
 
 
(1) The Value Realized reflects the taxable value to the named executive officer as of the date of the option exercise or vesting of restricted stock. The actual value ultimately realized by the named executive officer may be more or less than the Value Realized calculated in the above table depending on the timing in which the named executive officer held or sold the stock associated with the exercise or vesting occurrence.
 
(2) Shares acquired on vesting include restricted stock shares or units whose restrictions lapsed during 2009.
 
Pension Benefits for 2009
 
Anadarko maintains both funded tax-qualified defined benefit pension plans and unfunded nonqualified pension benefit plans. The nonqualified pension benefit plans are designed to provide for supplementary pension benefits due to limitations imposed by the Internal Revenue Code that restrict the amount of benefits payable under tax-qualified plans. Our named executive officers are eligible to participate in these plans. As part of the omnibus agreement a portion of the expense related to these plans is allocated to us by Anadarko. The allocated expense for each named executive officer is included in the All Other Compensation column of the Summary Compensation Table. For additional discussion on Anadarko’s pension benefits, please see section Compensation Discussion and Analysis — Elements of Total Compensation — Retirement Benefits of Anadarko’s proxy statement for its annual meeting of stockholders which is expected to be filed no later than April 9, 2010.
 
Nonqualified Deferred Compensation for 2009
 
Anadarko maintains a Deferred Compensation Plan and a Savings Restoration Plan for certain employees, including our named executive officers. The Deferred Compensation Plan allows certain employees to voluntarily defer receipt of up to 75% of their salary and/or up to 100% of their annual incentive bonus payments. The Savings Restoration Plan accrues a benefit substantially equal to the amount that, in the absence of certain Internal Revenue Code limitations, would have been allocated to their account as matching contributions under Anadarko’s 401(k) Plan. Pursuant to the terms of the omnibus agreement, a portion of the expense related to these plans is allocated to us by Anadarko. The allocated expense for each named executive officer is included in the All Other Compensation column of the Summary Compensation Table. For additional discussion on Anadarko’s pension benefits please see section Compensation Discussion and Analysis — Elements of Total Compensation — Retirement Benefits of Anadarko’s proxy statement for its annual meeting of stockholders which is expected to be filed no later than April 9, 2010.
 
Potential Payments Upon Termination or Change of Control
 
In the event of termination of employment with Western Gas Holdings, LLC by reason of: (A) a Change of Control of either Western Gas Holdings, LLC or Anadarko; (B) the closing of an initial public offering of Western Gas Holdings, LLC; (C) the involuntary termination of employment with Western Gas Holdings, LLC or its affiliates (with or without cause); (D) death; (E) disability, as defined under Section 409A of the Internal Revenue Code of 1986, as amended; or (F) an unforeseeable emergency, and assuming that the employee


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remains employed by Anadarko, the only payment triggered is the accelerated vesting of unvested awards under the Western Gas Holdings, LLC Amended and Restated Equity Incentive Plan. The award values under this Plan as of December 31, 2009 are as follows:
 
         
    Accelerated
    Incentive Plan
Name
  Awards(1)
 
Robert G. Gwin
  $ 893,311  
Donald R. Sinclair
  $ 1,340,000  
Benjamin M. Fink
  $ 670,000  
Danny J. Rea
  $ 446,622  
Amanda M. McMillian
  $ 223,311  
 
 
(1) Unit value rights are valued based on the maximum value specified under the award agreement of $50.00. Unit appreciation rights are valued based on the December 31, 2009 per-unit value of $67.00.
 
In connection with Mr. Pearl’s departure from the Partnership to assume the responsibilities associated with his promotion in March 2009 to Corporate Controller at Anadarko, he agreed to terminate the unvested portion of his existing awards under the Western Gas Holdings, LLC Amended and Restated Equity Incentive Plan, and received equity-based compensation of an equivalent value under Anadarko’s compensation plans. The vested portion of his unit appreciation rights, together with the associated distribution equivalent rights, continue in full force and effect. There were no severance payments incurred in connection with Mr. Pearl’s departure from service with the Partnership, and no amounts will be allocated to the Partnership with respect to any future severance event for Mr. Pearl. Accordingly, the tables in this section do not reflect any severance amounts for Mr. Pearl.
 
We have not entered into any employment agreements with our named executive officers, nor do we manage any severance plans. However, our named executive officers are eligible for certain benefits provided by Anadarko. Currently, we are not allocated any expense for these agreements or plans, but for disclosure purposes we are presenting the full value of the potential payments provided by Anadarko in the event of termination or change of control of Anadarko. Values exclude those benefits generally provided to all salaried employees. For additional discussion related to these termination scenarios, please see section Compensation Discussion and Analysis — Elements of Total Executive Compensation — Severance Benefits of Anadarko’s proxy statement for its annual meeting of stockholders which is expected to be filed no later than April 9, 2010.
 
The following tables reflect potential payments to our named executive officers under existing contracts, agreements, plans or arrangements, whether written or unwritten, with Anadarko, for various scenarios involving a change of control of Anadarko or termination of employment from Anadarko for each named executive officer, assuming a December 31, 2009 termination date, and, where applicable, using the closing price of Anadarko’s common stock of $62.42 (as reported on the NYSE as of December 31, 2009). As of December 31, 2009, none of our executive officers were eligible for retirement; accordingly, no table is included for this event.
 
Involuntary For Cause or Voluntary Termination
 
                                         
                    Ms.
    Mr. Gwin   Mr. Sinclair   Mr. Fink   Mr. Rea   McMillian
 
Supplemental Pension Benefits(1)
  $ 229,886     $     $     $ 750,568     $ 11,845  
Nonqualified Deferred Compensation(2)
  $ 119,469     $     $ 50,525     $ 160,540     $ 7,517  
Total
  $ 349,355     $     $ 50,525     $ 911,108     $ 19,362  
 
 
(1) Reflects the lump-sum present value of vested benefits related to Anadarko’s supplemental pension benefits.
 
(2) Reflects the combined vested balances in Anadarko’s nonqualified Savings Restoration Plan and Deferred Compensation Plan.


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Involuntary Not For Cause Termination
 
                                         
                    Ms.
    Mr. Gwin   Mr. Sinclair   Mr. Fink   Mr. Rea   McMillian
 
Cash Severance(1)
  $ 1,917,500     $ 780,000     $     $ 707,200     $  
Pro-rata Bonus for 2009(2)
  $ 995,015     $ 54,000     $     $ 280,000     $  
Accelerated Anadarko Equity Compensation(3)
  $ 10,637,186     $     $ 584,409     $ 1,670,796     $ 482,259  
Accelerated Western Equity Compensation(4)
  $ 893,311     $ 1,340,000     $ 670,000     $ 446,622     $ 223,311  
Supplemental Pension Benefits(5)
  $ 424,757     $     $ 13,718     $ 1,664,725     $ 11,845  
Nonqualified Deferred Compensation(6)
  $ 119,469     $     $ 50,525     $ 160,540     $ 7,517  
Health and Welfare Benefits(7)
  $ 46,841     $ 53,796     $     $ 179,692     $  
Financial Counseling(8)
  $ 25,888     $ 25,888     $     $ 25,888     $  
Total
  $ 15,059,967     $ 2,253,684     $ 1,318,652     $ 5,135,463     $ 724,932  
 
 
(1) Messrs. Gwin’s, Sinclair’s and Rea’s values assume two times base salary plus one times target bonus. No values have been disclosed for the other named executive officers as they receive the same benefits as generally provided to all salaried employees.
 
(2) Payment, if provided, will be paid at the end of the performance period based on actual performance. The values for Messrs. Gwin, Sinclair, and Rea are based on the actual bonuses awarded under Anadarko’s annual incentive program for 2009. For additional discussion of this program please see section Compensation Discussion and Analysis — Elements of Total Compensation — Annual Cash Incentives (Bonuses) of Anadarko’s proxy statement for its annual meeting of stockholders which is expected to be filed no later than April 9, 2010. No values have been disclosed for the other named executive officers as they receive the same benefits as generally provided to all salaried employees.
 
(3) Reflects the in-the-money value of unvested stock options, the target value of unvested performance units, and the value of unvested restricted stock shares and restricted stock units, granted under Anadarko equity plans, all as of December 31, 2009.
 
(4) Reflects the in-the-money value of unvested unit appreciation rights and the value of unvested unit value rights, granted under the Western Gas Holdings, LLC Amended and Restated Equity Incentive Plan. Unit appreciation rights are valued based on the December 31, 2009 per-unit value of $67.00. Unit value rights are valued based on the maximum value specified under the award agreement of $50.00.
 
(5) Messrs. Gwin’s, Sinclair’s and Rea’s values include a special retirement benefit enhancement that is equivalent to the additional supplemental pension benefits that would have accrued assuming they were eligible for subsidized early retirement benefits. All other named executive officers’ values reflect their vested balance in Anadarko’s Retirement Restoration Plan. Values exclude vested amounts payable under the qualified plans available to all employees.
 
(6) Reflects the combined vested balances in Anadarko’s nonqualified Savings Restoration Plan and Deferred Compensation Plan.
 
(7) Messrs. Gwin’s, Sinclair’s and Rea’s values represent 24 months of health and welfare benefit coverage. These amounts are present values determined in accordance with generally accepted accounting principles. Mr. Rea’s value also includes the present value of a retiree death benefit in Anadarko’s Management Life Insurance Plan, or MLIP. The “MLIP” provides for a retiree death benefit equal to one times final base salary. This retiree death benefit is only applicable to participants who were employed by Anadarko on June 30, 2003. Therefore, this benefit is only applicable to Mr. Rea. No values have been disclosed for the other named executive officers as they receive the same benefits as generally provided to all salaried employees.


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(8) Messrs. Gwin’s, Sinclair’s and Rea’s values assume financial counseling services continue for two years after termination. No values have been disclosed for the other named executive officers as they are not eligible for this benefit.
 
Change of Control: Involuntary Termination or Voluntary For Good Reason
 
                                         
                    Ms.
    Mr. Gwin   Mr. Sinclair   Mr. Fink   Mr. Rea   McMillian
 
Cash Severance(1)
  $ 3,591,325     $ 1,392,000     $     $ 1,542,800     $  
Pro-rata Bonus for 2009(2)
  $ 588,388     $ 180,000     $     $ 260,000     $  
Accelerated Anadarko Equity Compensation(3)
  $ 10,637,186     $     $ 584,409     $ 1,670,796     $ 482,259  
Accelerated Western Equity Compensation(4)
  $ 893,311     $ 1,340,000     $ 670,000     $ 446,622     $ 223,311  
Supplemental Pension Benefits(5)
  $ 1,282,390     $ 100,961     $ 13,718     $ 2,047,500     $ 16,845  
Nonqualified Deferred Compensation(6)
  $ 342,379     $ 86,400     $ 50,525     $ 256,300     $ 7,517  
Health and Welfare Benefits(7)
  $ 70,690     $ 82,195     $     $ 207,026     $  
Outplacement Assistance(8)
  $ 30,000     $ 30,000     $     $ 30,000     $  
Financial Counseling(9)
  $ 39,613     $ 39,613     $     $ 39,613     $  
Excise Tax and Gross-up(10)
  $ 4,061,380     $ 981,892     $     $ 1,898,417     $  
Total
  $ 21,536,662     $ 4,233,061     $ 1,318,652     $ 8,399,074     $ 729,932  
 
 
(1) Messrs. Gwin’s, Sinclair’s and Rea’s values assume 2.9 times the sum of base salary plus the highest bonus paid in the past three years. Because Mr. Sinclair was hired in 2009 and does not have any full-year bonus history, his value is based on his current target bonus. No values have been disclosed for the other named executive officers as they receive the same benefits as generally provided to all salaried employees.
 
(2) Messrs. Gwin’s, Sinclair’s and Rea’s values assume the full-year equivalent of the highest annual bonus the officer received over the past three years. Because Mr. Sinclair was hired in 2009 and does not have any full year bonus history, his value is based on his current target bonus. No values have been disclosed for the other named executive officers as they receive the same benefits as generally provided to all salaried employees.
 
(3) Reflects the in-the-money value of unvested stock options, the target value of unvested performance units, and the value of unvested restricted stock shares and restricted stock units, granted under Anadarko equity plans, all as of December 31, 2009.
 
(4) Reflects the in-the-money value of unvested unit appreciation rights and the value of unvested unit value rights, granted under the Western Gas Holdings, LLC Amended and Restated Equity Incentive Plan. Unit appreciation rights are valued based on the December 31, 2009 per-unit value of $67.00. Unit value rights are valued based on the maximum value specified under the award agreement of $50.00.
 
(5) Messrs. Gwin’s, Sinclair’s and Rea’s values include a special retirement benefit enhancement that is equivalent to the additional supplemental pension benefits that would have accrued assuming the named executive officers were eligible for subsidized early retirement benefits and include special pension credits provided through change of control agreements. All other named executive officers’ values reflect their vested balance in Anadarko’s Retirement Restoration Plan. Values exclude vested amounts payable under the qualified plans available to all employees.
 
(6) Messrs. Gwin’s, Sinclair’s and Rea’s values include their combined balances in Anadarko’s nonqualified Savings Restoration Plan and Deferred Compensation Plan plus an additional three years of employer contributions into the Savings Restoration Plan based on their current contribution rate to the Plan. All other named executive officers’ values reflect their combined balances in Anadarko’s nonqualified Savings Restoration Plan and Deferred Compensation Plan.


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(7) Messrs. Gwin’s, Sinclair’s and Rea’s values represent 36 months of health and welfare benefit coverage. All amounts are present values determined in accordance with generally accepted accounting principles. Mr. Rea’s value also includes the present value of a retiree death benefit in the MLIP. The MLIP provides for a retiree death benefit equal to one times final base salary. This retiree death benefit is only applicable to participants who were employed by Anadarko on June 30, 2003. Therefore, this benefit is only applicable to Mr. Rea. No values have been disclosed for the other named executive officers as they receive the same benefits as generally provided to all salaried employees.
 
(8) Messrs. Gwin’s, Sinclair’s and Rea’s values represent the outplacement assistance benefits provided under their change of control agreements. No values have been disclosed for the other named executive officers as they receive the same benefits as generally provided to all salaried employees.
 
(9) Messrs. Gwin’s, Sinclair’s and Rea’s values assume financial counseling services continue for three years after termination. No values have been disclosed for the other named executive officers as they are not eligible for this benefit.
 
(10) Values estimate the total payment required to make each executive whole for the 20% excise tax imposed by Section 280G of the Internal Revenue Code. No values have been disclosed for the other named executive officers as they receive the same benefits as generally provided to all salaried employees.
 
Disability
 
                                         
                    Ms.
    Mr. Gwin   Mr. Sinclair   Mr. Fink   Mr. Rea   McMillian
 
Cash Severance
  $     $     $     $     $  
Pro-rata Bonus for 2009(1)
  $     $     $     $     $  
Accelerated Anadarko Equity Compensation(2)
  $ 10,637,186     $     $ 584,409     $ 1,670,796     $ 482,259  
Accelerated Western Equity Compensation(3)
  $ 893,311     $ 1,340,000     $ 670,000     $ 446,622     $ 223,311  
Supplemental Pension Benefits(4)
  $ 229,886     $     $     $ 750,568     $ 11,845  
Nonqualified Deferred Compensation(5)
  $ 119,469     $     $ 50,525     $ 160,540     $ 7,517  
Health and Welfare Benefits(6)
  $ 403,060     $ 175,690     $ 163,075     $ 161,856     $  
Total
  $ 12,282,912     $ 1,515,690     $ 1,468,009     $ 3,190,382     $ 724,932  
 
 
(1) There are no special arrangements related to the payment of a pro-rata bonus in the event of disability. Payments are paid pursuant to the standards established under Anadarko’s annual incentive program for all salaried employees.
 
(2) Reflects the in-the-money value of unvested stock options, the target value of unvested performance units, and the value of unvested restricted stock shares and restricted stock units, granted under Anadarko equity plans, all as of December 31, 2009.
 
(3) Reflects the in-the-money value of unvested unit appreciation rights and the value of unvested unit value rights, granted under the Western Gas Holdings, LLC Amended and Restated Equity Incentive Plan. Unit appreciation rights are valued based on the December 31, 2009 per-unit value of $67.00. Unit value rights are valued based on the maximum value specified under the award agreement of $50.00.
 
(4) Reflects the lump sum present value of vested benefits related to Anadarko’s supplemental pension benefits.
 
(5) Reflects the combined vested balances in Anadarko’s nonqualified Savings Restoration Plan and Deferred Compensation Plan.
 
(6) Values reflect the continuation of additional death benefit coverage provided to certain employees of Anadarko until age 65. All amounts are present values determined in accordance with generally accepted accounting principles. No values have been disclosed for Ms. McMillian as she is not eligible for this benefit.


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Death
 
                                         
                    Ms.
    Mr. Gwin   Mr. Sinclair   Mr. Fink   Mr. Rea   McMillian
 
Cash Severance
  $     $     $     $     $  
Pro-rata Bonus for 2009(1)
  $     $     $     $     $  
Accelerated Anadarko Equity Compensation(2)
  $ 10,637,186     $     $ 584,409     $ 1,670,795     $ 482,259  
Accelerated Western Equity Compensation(3)
  $ 893,311     $ 1,340,000     $ 670,000     $ 446,622     $ 223,311  
Supplemental Pension Benefits(4)
  $ 229,886     $     $ 13,718     $ 750,568     $ 11,845  
Nonqualified Deferred Compensation(5)
  $ 119,469     $     $ 50,525     $ 160,540     $ 7,517  
Life Insurance Proceeds(6)
  $ 2,045,633     $ 944,138     $ 840,283     $ 856,019     $  
Total
  $ 13,925,485     $ 2,284,138     $ 2,158,935     $ 3,884,544     $ 724,932  
 
 
(1) There are no special arrangements related to the payment of a pro-rata bonus in the event of death. Payments are paid pursuant to the standards established under Anadarko’s annual incentive program for all salaried employees.
 
(2) Reflects the in-the-money value of unvested stock options, the target value of unvested performance units, and the value of unvested restricted stock shares and restricted stock units, granted under Anadarko equity plans, all as of December 31, 2009.
 
(3) Reflects the in-the-money value of unvested unit appreciation rights and the value of unvested unit value rights, granted under the Western Gas Holdings, LLC Amended and Restated Equity Incentive Plan. Unit appreciation rights are valued based on the December 31, 2009 per-unit value of $67.00. Unit value rights are valued based on the maximum value specified under the award agreement of $50.00.
 
(4) Includes the lump sum present value of vested benefits related to Anadarko’s supplemental pension benefits.
 
(5) Includes the combined vested balances in Anadarko’s nonqualified Savings Restoration Plan and Deferred Compensation Plan.
 
(6) Values include amounts payable under additional death benefits provided to certain employees of Anadarko. These liabilities are not insured, but are self-funded by Anadarko. Proceeds are not exempt from federal taxes; values shown include an additional tax gross-up amount to equate benefits with nontaxable life insurance proceeds. Values exclude death benefit proceeds from programs available to all employees. No values have been disclosed for Ms. McMillian as she is not eligible for this benefit.
 
Director Compensation
 
Officers or employees of Anadarko who also serve as directors of our general partner do not receive additional compensation for their service as a director of our general partner. Non-employee directors of Anadarko receive compensation for their board service and for attending meetings of the board of directors of our general partner and committees of the board pursuant to the director compensation plan approved by the board of directors in April 2009. Such compensation consists of:
 
  •  an annual retainer of $40,000 for each board member;
 
  •  an annual retainer of $2,000 for each member of the audit committee ($15,000 for the committee chair);
 
  •  an annual retainer of $2,000 for each member of the special committee ($15,000 for the committee chair);
 
  •  a fee of $2,000 for each board meeting attended;
 
  •  a fee of $2,000 for each committee meeting attended; and


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  •  annual grants of phantom units with a value of approximately $70,000 on the date of grant, all of which vest 100% on the first anniversary of the date of grant (with vesting to be accelerated upon a change of control of our general partner or Anadarko).
 
In addition, each non-employee director is reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director is fully indemnified by us, pursuant to individual indemnification agreements and our partnership agreement, for actions associated with being a director to the fullest extent permitted under Delaware law. On May 21, 2009, the non-employee directors received a grant of phantom units with a value of approximately $70,000.
 
The following table sets forth information concerning total director compensation earned during the 2009 fiscal year by each non-employee director:
 
                                                         
                    Change in
       
                    Pension Value
       
                    and
       
                Non-Equity
  Nonqualified
       
                Incentive
  Deferred
       
    Fees Earned or
  Stock
  Option
  Plan
  Compensation
  All Other
   
    Paid in Cash
  Awards
  Awards
  Compensation
  Earnings
  Compensation
  Total
Name
  ($)   ($)(1)   ($)   ($)   ($)   ($)   ($)
 
Milton Carroll
    85,000       69,993                               154,993  
Anthony R. Chase
    76,000       69,993                               145,993  
James R. Crane
    78,000       69,993                               147,993  
David J. Tudor
    95,000       69,993                               164,993  
 
 
(1) The amounts included in the Stock Awards column represent the compensation cost recognized by the Partnership in 2009 related to non-option awards to directors, computed in accordance with generally accepted accounting principles. For a discussion of valuation assumptions, see Note 6 — Transactions with Affiliates — Equity-based compensation — Long-term incentive plan of the notes to the consolidated financial statements included under Item 8 of this annual report. As of December 31, 2009, each of the non-employee directors had 4,660 outstanding phantom units.
 
The following table contains the grant date fair value of phantom unit awards made to each non-employee director during 2009.
 
                         
            Grant Date
            Fair
            Value of
            Stock
            and Option
    Grant
  Phantom
  Awards
Directors
  Date   Units (#)   ($)(1)
 
Milton Carroll
    May 21       4,660       69,993  
Anthony R. Chase
    May 21       4,660       69,993  
James R. Crane
    May 21       4,660       69,993  
David J. Tudor
    May 21       4,660       69,993  
 
 
(1) The amounts included in the Grant Date Fair Value of Stock and Option Awards column represent the grant date fair value of the awards made to non-employee directors in 2009 computed in accordance with generally accepted accounting principles. The value ultimately realized by a director upon the actual vesting of the award(s) may or may not be equal to the determined value.
 
Compensation Committee Interlocks and Insider Participation
 
As previously discussed, our general partner’s board of directors is not required to maintain, and does not maintain, a compensation committee. Messrs. Gwin, Meloy, Sinclair, Reeves and Walker, who are directors of


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our general partner, are also executive officers of Anadarko. However, all compensation decisions with respect to each of these persons are made by Anadarko and none of these individuals receive any compensation directly from us or our general partner for their service as directors. Please read Item 13 below in this annual report for information about relationships among us, our general partner and Anadarko.
 
Compensation Committee Report
 
Neither we nor our general partner has a compensation committee. The board of directors of our general partner has reviewed and discussed the Compensation Discussion and Analysis set forth above and based on this review and discussion has approved it for inclusion in this Form 10-K.
 
The board of directors of Western Gas Holdings, LLC:
 
Robert G. Gwin
Milton Carroll
Anthony R. Chase
James R. Crane
Charles A. Meloy
Robert K. Reeves
Donald R. Sinclair
David J. Tudor
R. A. Walker


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Item 12.   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
 
The following tables set forth the beneficial ownership of our units as of March 1, 2010 held by:
 
  •  each member of the board of directors of our general partner;
 
  •  each named executive officer of our general partner;
 
  •  all directors and officers of our general partner as a group; and
 
  •  each person or group of persons known by us to be a beneficial owner of 5% or more of the then outstanding units.
 
                                         
                    Percentage of
                Percentage of
  Total Common
        Percentage of
  Subordinated
  Subordinated
  and Subordinated
        Common Units
  Units
  Units
  Units
Name and address of
  Common Units
  Beneficially
  Beneficially
  Beneficially
  Beneficially
Beneficial Owner(1)
  Beneficially Owned(2)   Owned   Owned   Owned   Owned
 
Anadarko Petroleum Corporation(2)
    9,254,435       25.0 %     26,536,306       100.0 %     56.3 %
Western Gas Resources, Inc.(2)
    9,254,435       25.0 %     26,536,306       100.0 %     56.3 %
WGR Holdings, LLC(2)
    9,254,435       25.0 %     26,536,306       100.0 %     56.3 %
Robert G. Gwin
    10,000       *                   *  
Donald R. Sinclair
    54,945       *                   *  
Benjamin M. Fink
    550       *                   *  
Danny J. Rea
    7,500       *                   *  
Amanda M. McMillian
                             
Michael C Pearl
                             
Jeremy M. Smith
    3,800       *                   *  
Milton Carroll(3)
    576       *                   *  
Anthony R. Chase(3)
    24,375       *                   *  
James R. Crane(3)
    438,103       1.18 %                 *  
Charles A. Meloy
    3,000       *                   *  
Robert K. Reeves
    9,000       *                   *  
David J. Tudor(3)
    7,576       *                   *  
R. A. Walker
    6,000       *                   *  
All directors and executive officers as a group (13 persons)(3)
    565,425       1.53 %                 *  
 
 
Less than 1%
 
(1) Unless otherwise indicated, the address for all beneficial owners in this table is 1201 Lake Robbins Drive, The Woodlands, Texas 77380.
 
(2) Anadarko Petroleum Corporation is the ultimate parent company of WGR Holdings, LLC and Western Gas Resources, Inc. and may, therefore, be deemed to beneficially own the units held by WGR Holdings, LLC and Western Gas Resources, Inc.
 
(3) Does not include 4,660 phantom units that were granted to each of Messrs. Carroll, Chase, Crane and Tudor under the Western Gas Partners, LP 2008 Long-Term Incentive Plan. These phantom units vest 100% on the first anniversary of the date of the grant. Each vested phantom unit entitles the holder to


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receive a common unit or, in the discretion of our general partner’s board of directors, cash equal to the fair market value of a common unit. Holders of phantom units are entitled to distribution equivalents on a current basis. Holders of phantom units have no voting rights until such time as the phantom units become vested and common units are issued to such holders.
 
The following table sets forth, as of March 1, 2010, the number of shares of common stock of Anadarko owned by each of the named executive officers and directors of our general partner and all directors and executive officers of our general partner as a group.
 
                                 
        Shares
      Percentage of
    Shares of
  Underlying
  Total Shares of
  Total Shares of
    Common Stock
  Options
  Common Stock
  Common Stock
Name and Address of
  Owned Directly
  Exercisable
  Beneficially
  Beneficially
Beneficial Owner(1)
  or Indirectly(2)   within 60 days(2)   Owned(2)   Owned(2)
 
Robert G. Gwin(3)(4)
    31,006       164,702       195,708       *
Donald R. Sinclair(4)
    145             145       *
Benjamin M. Fink(4)
    6,186       13,402       19,588       *
Danny J. Rea(3)(4)
    9,792       29,184       38,976       *
Amanda M. McMillian(4)
    5,549       1,544       7,093       *
Michael C Pearl
    14,959       19,043       34,002       *
Jeremy M. Smith(4)
    11,206       720       11,926       *
Milton Carroll
                      *
Anthony R. Chase
                      *
James R. Crane
                      *
Charles A. Meloy(3)(4)
    43,819       87,767       131,586       *
Robert K. Reeves(3)(4)
    68,988       350,268       419,256       *
David J. Tudor
                      *
R. A. Walker(3)(4)
    89,399       262,634       352,033       *
All directors and executive officers as a group (13 persons)(3)(4)
    266,090       910,221       1,176,311       *
 
 
Less than 1%
 
(1) Unless otherwise indicated, the address for all beneficial owners in this table is 1201 Lake Robbins Drive, The Woodlands, Texas 77380.
 
(2) As of January 29, 2010, there were 492.6 million shares of Anadarko Petroleum Corporation common stock issued and outstanding.
 
(3) Does not include unvested restricted stock units of Anadarko Petroleum Corporation held by the following directors and executive officers in the amounts indicated: Robert G. Gwin — 62,233; Danny J. Rea — 9,866; Charles A. Meloy — 55,799; Robert K. Reeves — 39,033; R. A. Walker — 59,632; and a total of 226,563 unvested restricted stock units are held by the directors and executive officers as a group. Restricted stock units typically vest equally over three years beginning on the first anniversary of the date of grant, and upon vesting are payable in Anadarko common stock, subject to applicable tax withholding. Holders of restricted stock units receive dividend equivalents on the units, but do not have voting rights. Generally, a holder will forfeit any unvested restricted units if he or she terminates voluntarily or is terminated for cause prior to the vesting date. Holders of restricted stock units have the ability to defer such awards.
 
(4) Includes unvested shares of restricted common stock of Anadarko Petroleum Corporation held by the following directors and executive officers in the amounts indicated: Robert G. Gwin — 4,250; Benjamin M. Fink — 6,066; Amanda M. McMillian — 5,549; Jeremy M. Smith — 4,764; Michael C. Pearl — 14,959; and a total of 20,629 unvested shares of restricted common stock are held by the directors and executive officers as a group. Restricted stock awards typically vest equally over three


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years beginning on the first anniversary of the date of grant. Holders of restricted stock receive dividends on the shares and also have voting rights. Generally, a holder of restricted stock will forfeit any unvested restricted shares if he or she terminates voluntarily or is terminated for cause prior to the vesting date.
 
The following table sets forth owners of 5% or greater of our units, other than Anadarko, the holdings of which are listed in the first table of this Item 12.
 
                     
        Amount and
   
        Nature
   
        of Beneficial
   
Title of Class
 
Name and Address of Beneficial Owner
  Ownership   Percent of Class
 
Common Units
  Neuberger Berman Inc.
605 Third Avenue
New York, NY 10158
    3,788,598(2 )     10.2 %
Common Units
  Kayne Anderson Capital Advisors, L.P.
1800 Avenue of the Stars
Second Floor
Los Angeles, CA 90067
    3,256,197(1 )     8.8 %
 
 
(1) Based upon its Schedule 13G/A filed February 11, 2010 with the SEC with respect to Partnership securities held as of December 31, 2009, Kayne Anderson Capital Advisors, L.P. has shared voting power as to 3,256,197 shares of common units and shared dispositive power as to 3,256,197 shares of common units, and Richard A. Kayne has shared voting power as to 3,256,197 shares of common units and shared dispositive power as to 3,256,197 shares of common units.
 
(2) Based upon its Schedule 13G/A filed February 16, 2010 with the SEC with respect to Partnership securities held as of December 31, 2009, Neuberger Berman Group LLC has shared voting power as to 3,404,203 common units, and shared dispositive power as to 3,788,598 common units, and Neuberger Berman, LLC has sole voting power as to 3,404,203 common units and shared dispositive power as to 3,788,598 common units.
 
Securities Authorized for Issuance Under Equity Compensation Plan
 
The following table sets forth information with respect to the securities that may be issued under the LTIP, as of December 31, 2009. For more information regarding the LTIP, which did not require approval by our unitholders, please read Note 6 — Transactions with Affiliates included in the notes to the consolidated financial statements under Item 8 of this annual report and the caption Western Gas Partners, LP 2008 Long-Term Incentive Plan included under Item 11 of this annual report.
 
                         
            (c)
            Number of Securities
    (a)
  (b)
  Remaining Available
    Number of Securities
  Weighted-Average
  for Future Issuance
    to be Issued upon
  Exercise Price of
  Under Equity
    Exercise of
  Outstanding
  Compensation Plans
    Outstanding Options,
  Options, Warrants
  (Excluding Securities
Plan category
  Warrants and Rights   and Rights   Reflected in Column (a))
 
Equity compensation plans approved by security holders
                 
Equity compensation plans not approved by security holders(1)
    21,970       (2)     2,197,726  
                         
Total
    21,970             2,197,726  
 
 
(1) The board of directors of our general partner adopted the LTIP in connection with the initial public offering of our common units.
 
(2) Phantom units constitute the only rights outstanding under the LTIP. Each phantom unit that may be settled in common units entitles the holder to receive, upon vesting, one common unit with respect to each phantom unit, without payment of any cash. Accordingly, there is no reportable weighted-average exercise price.


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Item 13.   Certain Relationships and Related Transactions, and Director Independence
 
As of March 1, 2010, our general partner and its affiliates owned 9,254,435 common units and 26,536,306 subordinated units representing an aggregate 55.2% limited partner interest in us. In addition, as of March 1, 2010, our general partner owned 1,296,570 general partner units, representing a 2% general partner interest in us, as well as incentive distribution rights.
 
Distributions and Payments to Our General Partner and its Affiliates
 
The following table summarizes the distributions and payments made by us to our general partner and its affiliates in connection with our formation and to be made to us by our general partner and its affiliates in connection with our ongoing operation and liquidation. These distributions and payments were determined, before our initial public offering, by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.
 
Formation stage
 
The consideration received by Anadarko and its subsidiaries for the contribution of the assets and liabilities to us 5,725,431 common units; 26,536,306 subordinated units; 1,083,115 general partner units, and our incentive distribution rights.
 
Operational stage
 
Distributions of available cash to our general partner and its affiliates We will generally make cash distributions of 98.0% to our unitholders pro rata, including Anadarko as the indirect holder of an aggregate 9,254,435 common units and 26,536,306 subordinated units, and 2.0% to our general partner, assuming it makes any capital contributions necessary to maintain its 2.0% interest in us. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 50.0% of the distributions above the highest target distribution level.
 
Payments to our general partner and its affiliates Our general partner and its affiliates are entitled to reimbursement for all expenses incurred on our behalf, including salaries and employee benefit costs for employees who provide services to us, and all other necessary or appropriate expenses allocable to us or reasonably incurred by our general partner and its affiliates in connection with operating our business. The partnership agreement provides that our general partner determines in good faith the amount of such expenses that are allocable to us.
 
Withdrawal or removal of our general partner If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
 
Liquidation stage
 
Liquidation Upon our liquidation, our partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.


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Agreements with Anadarko
 
We and other parties entered into various agreements with Anadarko in connection with our initial public offering in May 2008 and our asset acquisitions in December 2008 and July 2009. These agreements address the acquisition of assets and the assumption of liabilities by us and our subsidiaries. These agreements were not the result of arm’s-length negotiations and, as such, they or underlying transactions may not be based on terms as favorable as those that could have been obtained from unaffiliated third parties.
 
Omnibus Agreement
 
In connection with our initial public offering, we entered into an omnibus agreement with Anadarko and our general partner that addresses the following matters:
 
  •  Anadarko’s obligation to indemnify us for certain liabilities and our obligation to indemnify Anadarko for certain liabilities;
 
  •  our obligation to reimburse Anadarko for expenses incurred or payments made on our behalf in conjunction with Anadarko’s provision of general and administrative services to us, including salary and benefits of Anadarko personnel, our public company expenses, general and administrative expenses and salaries and benefits of our executive management who are employees of Anadarko (see Administrative services and reimbursement below for details regarding certain agreements for amounts to be reimbursed in 2010); and
 
  •  our obligation to reimburse Anadarko for all insurance coverage expenses it incurs or payments it makes with respect to our assets; and our obligation to reimburse Anadarko for our allocable portion of commitment fees (0.11% of our committed and available borrowing capacity) that Anadarko incurs under its $1.3 billion credit facility.
 
The table below reflects the categories of expenses for which the Partnership was obligated to reimburse Anadarko pursuant to the omnibus agreement for the year ended December 31, 2009:
 
         
    Year Ended
    December 31,
    2009
    (In thousands)
 
Reimbursement of general and administrative expenses
  $ 6,900  
Reimbursement of public company expenses
  $ 4,162  
Reimbursement of direct expenses related to acquisitions
  $ 1,609  
Reimbursement of commitment fees
  $ 143  
 
Any or all of the provisions of the omnibus agreement are terminable by Anadarko at its option if our general partner is removed without cause and units held by our general partner and its affiliates are not voted in favor of that removal. The omnibus agreement will also generally terminate in the event of a change of control of us or our general partner.
 
Administrative services and reimbursement
 
Under the omnibus agreement, we reimburse Anadarko for the payment of certain operating expenses and for the provision of various general and administrative services for our benefit with respect to our initial assets and for subsequent acquisitions. The omnibus agreement further provides that we reimburse Anadarko for all expenses it incurs or payments it makes with respect to our assets.
 
Pursuant to these arrangements, Anadarko performs centralized corporate functions for us, such as legal, accounting, treasury, cash management, 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 reimburse Anadarko for all of the expenses it incurs or payments it makes on our behalf, including salaries and benefits of Anadarko personnel, our public company expenses,


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our general and administrative expenses and salaries and benefits of our executive management who are also employees of Anadarko.
 
Under the omnibus agreement, our reimbursement to Anadarko for certain general and administrative expenses it allocates to us was initially capped at $6.0 million annually. This cap was subsequently modified due to the acquisition of additional assets and was $6.9 million for 2009 and is $8.3 million for the year ending December 31, 2010. The cap is subject to further adjustment to reflect changes in the Consumer Price Index and, with the concurrence of the special committee of our general partner’s board of directors, to reflect expansions of our operations through the acquisition or construction of new assets or businesses. Thereafter, our general partner will determine the general and administrative expenses to be allocated to us in accordance with our partnership agreement. The cap contained in the omnibus agreement does not apply to incremental general and administrative expenses that we incur or are allocated to us as a result of being a publicly traded entity.
 
Indemnification
 
Under the omnibus agreement, Anadarko has indemnified us until May 14, 2011 against certain potential environmental claims, losses and expenses associated with the operation of our initial assets, which occurred prior to May 14, 2008 or relate to any investigation, claim or proceeding under environmental laws relating to such assets and pending as of May 14, 2008. Anadarko will have no indemnification obligation with respect to environmental claims on our initial assets made as a result of additions to or modifications of environmental laws that are promulgated after May 14, 2008.
 
Additionally, Anadarko will indemnify us for losses attributable to the following with respect to our initial assets:
 
(1) our failure, as of May 14, 2008, to have valid easements, fee title or leasehold interests in and to the lands on which our assets are located, to the extent such failure renders us unable to use or operate our assets in substantially the same manner in which they were used and operated immediately prior to the closing of our initial public offering;
 
(2) our failure, as of May 14, 2008, to have any consent or governmental permit necessary to allow (i) the transfer of assets from Anadarko to us at May 14, 2008 or (ii) us to use or operate our assets in substantially the same manner in which they were used and operated immediately prior to May 14, 2008;
 
(3) all income tax liabilities
 
(i) attributable to the pre-closing operations of our assets,
 
(ii) arising from or relating to the formation transactions, or
 
(iii) arising under Treasury Regulation Section 1.1502-6 and any similar provision from state, local or foreign applicable law, by contract, as successor or transferee or otherwise, provided that such income tax is attributable to having been a member of any consolidated, combined or unitary group prior to the closing of our initial public offering;
 
(4) all liabilities, other than covered environmental laws and other than liabilities incurred in the ordinary course of business conducted in compliance with the applicable laws, that arise prior to May 14, 2008; and
 
(5) all liabilities attributable to any assets or entities retained by Anadarko.
 
Anadarko’s liability for indemnification is unlimited in amount. Anadarko will not have any obligation to indemnify us, unless a claim for indemnification specifying in reasonable detail the basis for such claim is furnished to us in good faith (a) with respect to a claim under clause (1) or (2) above, prior to the third anniversary date of the closing of our initial public offering or (b) with respect to a claim under clause (3) or (5) above, prior to the first day after expiration of the statute of limitations period applicable to such claim. In no event shall Anadarko be obligated to indemnify us for any losses or income taxes to the extent we have made reservations for any such losses or income taxes in our consolidated financial statements as of


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December 31, 2007 or to the extent we recover any such losses or income taxes under available insurance coverage or from contractual rights against any third party.
 
Under the omnibus agreement, we have agreed to indemnify Anadarko for all claims, losses and expenses attributable to operations of our initial assets on or after May 14, 2008, to the extent that such losses are not subject to Anadarko’s indemnification obligations.
 
Indemnification Agreements with Directors and Officers
 
In connection with our initial public offering, our general partner entered into indemnification agreements with each of its officers and directors (each, an Indemnitee). Each indemnification agreement provides that our general partner will indemnify and hold harmless each Indemnitee against all expense, liability and loss (including attorney’s fees, judgments, fines or penalties and amounts to be paid in settlement) actually and reasonably incurred or suffered by the Indemnitee in connection with serving in their capacity as officers and directors of our general partner (or of any subsidiary of our general partner) or in any capacity at the request of our general partner or its board of directors to the fullest extent permitted by applicable law, including Section 18-108 of the Delaware Limited Liability Company Act in effect on the date of the agreement or as such laws may be amended to provide more advantageous rights to the Indemnitee. The indemnification agreements also provide that our general partner must advance payment of certain expenses to the Indemnitee, including fees of counsel, in advance of final disposition of any proceeding subject to receipt of an undertaking from the Indemnitee to return such advance if it is ultimately determined that the Indemnitee is not entitled to indemnification.
 
Through December 31, 2009, there have been no payments or claims to Anadarko related to indemnifications and no payments or claims have been received from Anadarko related to indemnifications.
 
Services and Secondment Agreement
 
In connection with our initial public offering, Anadarko and our general partner entered into a services and secondment agreement pursuant to which specified employees of Anadarko are seconded to our general partner to provide operating, routine maintenance and other services with respect to our business under the direction, supervision and control of our general partner. Pursuant to the services and secondment agreement, our general partner reimburses Anadarko for the services provided by the seconded employees. The initial term of the services and secondment agreement is 10 years. The term will extend for additional 12-month periods unless either party provides 180 days written notice otherwise prior to the expiration of the applicable 12-month period. Either party may terminate the agreement at any time upon 180 days written notice.
 
Tax Sharing Agreement
 
In connection with our initial public offering, we entered into a tax sharing agreement pursuant to which we reimburse Anadarko for our share of Texas margin tax borne by Anadarko as a result of our results being included in a combined or consolidated tax return filed by Anadarko with respect to periods subsequent to our acquisition of the Partnership Assets. Anadarko may use its tax attributes to cause its combined or consolidated group, of which we may be a member for this purpose, to owe no tax. However, we would nevertheless be required to reimburse Anadarko for the tax we would have owed had the attributes not been available or used for our benefit, regardless of whether Anadarko pays taxes for the period.
 
Note Receivable from Anadarko
 
In connection with our initial public offering, we loaned $260.0 million to Anadarko. The note is a 30-year note bearing interest at a fixed annual rate of 6.5%, payable quarterly, with principal and all accrued and unpaid interest due in full at maturity.


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Our Working Capital Facility
 
In connection with our initial public offering, we entered into a $30.0 million two-year revolving credit facility with Anadarko as the lender. The facility is available exclusively to fund our working capital borrowings. Borrowings under the facility bear interest at the same rate as applies to borrowings under Anadarko’s revolving credit facility. We pay a commitment fee of 0.11% annually to Anadarko on the unused portion of the working capital facility.
 
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.
 
Contribution Agreements
 
Powder River Assets.  On November 11, 2008, we and our subsidiaries entered into a contribution agreement (Powder River contribution agreement) with Anadarko and several of its affiliates. Pursuant to the Powder River contribution agreement, we acquired the Powder River assets from Anadarko. These assets provide a combination of gathering, treating and processing services in the Powder River Basin of Wyoming and are connected or adjacent to our MIGC pipeline. The consideration consisted of $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, 2,556,891 of our common units and 52,181 of our general partner units. The acquisition closed on December 19, 2008.
 
Chipeta Assets.  In July 2009, we and our subsidiaries entered into a contribution agreement (Chipeta contribution agreement) with Anadarko and several of its affiliates. Pursuant to the Chipeta contribution agreement, we acquired the Chipeta 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 of our common units and 7,172 of our 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), together with 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 completed in April 2009. The acquisition closed on July 22, 2009.
 
Granger Assets.  In January 2010, we and our subsidiaries entered into a contribution agreement (Granger contribution agreement) with Anadarko and several of its affiliates. Pursuant to the Granger contribution agreement, we acquired the Granger assets from Anadarko for (i) approximately $241.7 million in cash, which was financed with $210.0 million of borrowings under the Partnership’s revolving credit facility plus $31.7 million of cash on hand, and the (ii) issuance of 620,689 of our common units and 12,667 of our general partner units. In connection with the acquisition, we entered into five-year, fixed-price commodity swap agreements with Anadarko which cover non-fee-based volumes processed at the Granger complex.
 
Pursuant to the Powder River contribution agreement, Chipeta contribution agreement and Granger contribution agreement, Anadarko has agreed to indemnify us and our respective affiliates (other than any of the entities controlled by Anadarko), shareholders, unitholders, members, directors, officers, employees, agents and representatives against certain losses resulting from any breach of Anadarko’s representations, warranties, covenants or agreements, and for certain other matters. We have agreed to indemnify Anadarko and its respective affiliates (other than us and our respective security holders, officers, directors and employees) and their respective security holders, officers, directors and employees against certain losses resulting from any breach of our representations, warranties, covenants or agreements.
 
The board of directors of our general partner unanimously approved the acquisition of the Powder River assets, the Chipeta assets and the Granger assets, based in part on the unanimous recommendations in favor of the acquisitions from, and the granting of special approval under our partnership agreement by, the board’s special committee. The special committee, a committee of independent members of our general partner’s board


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of directors, retained independent legal and financial advisors to assist it in evaluating and negotiating the acquisitions. In recommending the approval of the acquisitions, the special committee based its decision, in part, on the independent financial advisor’s written opinions representing that the consideration to be paid by us to Anadarko was fair.
 
Chipeta LLC Agreement
 
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, together with Anadarko and the third-party member. Among other things, 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 available cash, as defined in the Chipeta LLC Agreement, to its members quarterly in accordance with those members’ membership interests; and
 
  •  Chipeta’s membership interests are subject to significant restrictions on transfer.
 
Term Loan Agreements
 
In connection with the acquisition of the Powder River assets, we entered into a term loan agreement under which Anadarko loaned $175.0 million to us to fund a portion of the acquisition cost. The term loan agreement has a term of five years and bears interest at a rate of 4% for the first two years. During the year ended December 31, 2009, we incurred approximately $7.0 million in interest on the five-year term loan. After the first two years, the term loan agreement calls for interest at a floating rate equal to LIBOR (defined in the agreement) plus 150 basis points. We have the option to repay the amount due in whole or in part commencing upon the second anniversary of the term loan agreement. The provisions of the term loan agreement are non-recourse to our general partner and our 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. The term loan agreement also contains a full guaranty of the amounts due by a wholly-owned subsidiary of Anadarko.
 
In connection with the acquisition of the Chipeta assets, we entered into a 7.00% fixed rate, three-year term loan agreement under which Anadarko loaned $101.5 million to us to fund a portion of the acquisition cost. During the year ended December 31, 2009, we incurred approximately $2.0 million in interest on the three-year term loan. On October 30, 2009, we used $100.0 million of our capacity under the revolving credit facility along with $2.0 million of cash on hand to repay the 7.00% fixed-rate, three-year term loan agreement with Anadarko, and to settle accrued interest related thereto. For more information regarding our revolving credit facility, please read the caption Liquidity and Capital Resources under Item 7 of this annual report.
 
Commodity Price Swap Agreements
 
We 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 our acquisition of the Hilight and Newcastle Systems. Specifically, the commodity price swap agreements fix the margin we will realize under substantially all percent-of-proceeds and keep-whole contracts applicable to natural gas processing activities at the Hilight and Newcastle Systems. In this regard, our 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 our share of actual volumes processed at the Hilight and Newcastle Systems. The commodity prices we will realize under the specified contracts are fixed through December 31, 2011 and we can extend the agreements, at our option, annually through December 31, 2013. See Note 6 — Transactions with Affiliates — Commodity price swap agreements in the notes to the consolidated financial statements under


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Item 8 of this annual report for information on commodity price swap agreements entered into in December 2008.
 
We also entered into five-year commodity price swap agreements with Anadarko in January 2010 to mitigate exposure to commodity price volatility that would otherwise be present as a result of the percent-of-proceeds and keep-whole processing arrangements we acquired in our Granger acquisition. Similar to the above swaps for Hilight and Newcastle, the notional volumes for each of the Granger swap agreements are not specifically defined; instead, the commodity price swap agreements apply to volumes equal in amount to our share of actual volumes processed at the Granger plant. See Note 13 — Subsequent Events — Granger acquisition in the notes to the consolidated financial statements under Item 8 of this annual report for information on commodity price swap agreements entered into in January 2010.
 
Gas gathering agreements
 
Our gathering agreements with Anadarko accounted for approximately 92% of our gathering and transportation throughput for the year ended December 31, 2009. Approximately 8% of the affiliate throughput we gathered or transported for the year ended December 31, 2009 was comprised of third-party volumes purchased by AESC, and gathered under gathering agreements we have in place with AESC.
 
Anadarko Petroleum Corporation.  We entered into new gas gathering agreements with Anadarko effective January 1, 2008 for the gathering systems included in our initial assets. These agreements provide us with dedication of all of the natural gas owned or controlled by Anadarko and produced from (i) wells that are currently connected to our gathering systems, and (ii) additional wells that are drilled within one mile of wells connected to our gathering systems, as the systems currently exist and as they are expanded to connect additional wells in the future. As a result, this dedication will continue to expand as additional wells are connected to our gathering systems. Each gas gathering agreement is fee-based, and we provide gathering, compression, treating, dehydration and well connections within the dedicated area for a specified gathering fee. The gathering fee varies for each system and is subject to automatic annual escalators as well as other adjustments in the event Anadarko requests improvements to the level of service we currently provide under the agreement. Each of the gas gathering agreements has a 10-year primary term. After the expiration of the primary term, either party may request a re-determination of the gathering fee on an annual basis. If a fee re-determination occurs, the methodology which was utilized to determine the original gathering fee will also be utilized to determine the renegotiated fee, taking into account current production forecasts, capital expenditures and operating expenses. Our gathering agreements permit us to retain and sell condensate that is recovered from the gas stream during the gathering process. The gas gathering agreements are assignable by Anadarko to an affiliate without our consent and Anadarko will be permitted to sell the production which is dedicated to our systems to an affiliate or third-party purchaser, provided that the purchaser of the dedicated gas will be subject to the terms and conditions of our agreements and Anadarko will remain liable under the agreements in the event the purchaser defaults. The gathering fees we charge under our January 1, 2008 gas gathering agreements with Anadarko are higher than the fees reflected in our historical financial results for periods prior to January 1, 2008.
 
Anadarko Energy Services Company (AESC).  AESC is Anadarko’s marketing affiliate that purchases gas and is a shipper on our gathering systems. We provide our services to AESC under fixed-fee arrangements whereby gathering fees and contract terms are based on a variety of factors, including gas quality and level of service provided. The terms of our agreements with AESC vary from month-to-month terms to 20-year terms.
 
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.


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Gas purchase and sale agreements
 
All of the throughput volumes for the Hilight System and Newcastle System are sourced from third-party producers. However, substantially all natural gas, NGLs and condensate are sold to AESC pursuant to sales agreements. In addition, we purchase natural gas and NGLs from AESC pursuant to gas purchase agreements. Our gas purchase and sale agreements with AESC are generally one-year contracts, subject to annual renewal.
 
Transportation agreements
 
Western Gas Resources, Inc. and MGTC, Inc., affiliates of Anadarko, have contracted for 170,000 MMBtu/d of firm capacity on our MIGC system in agreements ranging in term from two years to 11 years. For the year ended December 31, 2009, our transportation agreements with Anadarko accounted for approximately 93% of the throughput on the MIGC system.
 
Summary of affiliate transactions
 
Revenues from affiliates include amounts earned by us from the gathering, treating, processing and transportation of natural gas for Anadarko, as well as from the sale of natural gas and NGLs to Anadarko. Operating expenses include all amounts accrued or paid to affiliates for the operation of our systems, whether in providing services to affiliates or to third parties, including field labor, measurement and analysis, and other disbursements. Affiliate expenses do not bear a direct relationship to affiliate revenues and third-party expenses do not bear a direct relationship to third-party revenues. For example, our affiliate expenses are not necessarily those expenses attributable to generating affiliate revenues. The following table summarizes affiliate transactions.
 
                         
    Year Ended December 31,
    2009   2008   2007
    (In thousands)
 
Revenues — affiliates
  $ 219,698     $ 302,825     $ 245,302  
Operating expenses — affiliates
    40,975       56,849       38,868  
Interest income — affiliates
    16,900       10,703        
Interest expense, net — affiliates
    9,096       1,512       7,805  
Distributions to unitholders — affiliates
    44,450       15,279        
Contributions from noncontrolling interest owners — affiliate and Parent
    34,011       130,094        
Distributions to noncontrolling interest owners — affiliate and Parent
    5,410       33,335        
 
Conflicts of Interest
 
Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates, including Anadarko, on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders.
 
Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us and our limited partners, on the other hand, our general partner will resolve the conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions taken by our general partner that, without those limitations, might constitute breaches of its fiduciary duty. See the caption Special Committee under Item 10 of this annual report.


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Our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our unitholders if the resolution of the conflict is:
 
  •  approved by the special committee of our general partner, although our general partner is not obligated to seek such approval;
 
  •  approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;
 
  •  on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
 
  •  fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
 
Our general partner may, but is not required to, seek the approval of such resolution from the special committee of its board of directors. In connection with a situation involving a conflict of interest, any determination by our general partner involving the resolution of the conflict of interest must be made in good faith, provided that, if our general partner does not seek approval from the special committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the special committee may consider any factors that it determines in good faith to be appropriate when resolving a conflict. Our partnership agreement provides that for someone to act in good faith, that person must reasonably believe he is acting in the best interests of the partnership.
 
Item 14.   Principal Accounting Fees and Services
 
We have engaged KPMG LLP as our independent registered public accounting firm. The following table summarizes the fees we have paid KPMG LLP to audit the Partnership’s annual consolidated financial statements and for other services for each of the last two fiscal years:
 
                 
    2009     2008  
    (In thousands)  
 
Audit fees
  $ 915     $ 640  
Audit-related fees
    289       270  
Tax
           
All other fees
           
                 
Total
  $ 1,204     $ 910  
                 
 
Audit fees are primarily for the audit of the Partnership’s consolidated financial statements, including the audit of the effectiveness of the Company’s internal controls over financial reporting beginning in 2009, and reviews of the Partnership’s financial statements included in the Form 10-Qs.
 
Audit-related fees are primarily for other audits, consents, comfort letters and certain financial accounting consultation. The above amounts represent fees paid by the Partnership. Certain fees approved by Anadarko and reimbursed by the Partnership from initial public offering proceeds are not included in the above amounts. The excluded amount is $0.7 million for 2008 and is solely attributable to audit fees and audit-related fees for the Partnership’s initial assets for periods prior to its initial public offering.
 
Audit Committee Approval of Audit and Non-Audit Services
 
The Audit Committee of the Partnership’s general partner has adopted a Pre-Approval Policy with respect to services which may be performed by KPMG LLP. This policy lists specific audit-related services as well as


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any other services that KPMG LLP is authorized to perform and sets out specific dollar limits for each specific service, which may not be exceeded without additional Audit Committee authorization. The Audit Committee receives quarterly reports on the status of expenditures pursuant to that Pre-Approval Policy. The Audit Committee reviews the policy at least annually in order to approve services and limits for the current year. Any service that is not clearly enumerated in the policy must receive specific pre-approval by the Audit Committee or by its Chairman, to whom such authority has been conditionally delegated, prior to engagement. During 2009, no fees for services outside the scope of audit, review, or attestation that exceed the waiver provisions of 17 CFR 210.2-01(c)(7)(i)(C) were approved by the Audit Committee.
 
The Audit Committee has approved the appointment of KPMG LLP as independent registered public accounting firm to conduct the audit of the Partnership’s consolidated financial statements for the year ended December 31, 2010.
 
PART IV
 
Item 15.   Exhibits
 
(a)(1) Financial Statements
 
Our consolidated financial statements are included under Part II, Item 8 of this annual report. For a listing of these statements and accompanying footnotes, please see the Index to Consolidated Financial Statements on page F-1 under Item 8 of this annual report.
 
(a)(2) Financial Statement Schedules
 
All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto.
 
(a)(3) Exhibits
 
Exhibit index
 
         
Exhibit
   
Number
 
Description
 
  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 13, 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).
  2 .4#   Contribution Agreement, dated as of January 29, 2010 by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, Mountain Gas Resources 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 February 3, 2010 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).


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Exhibit
   
Number
 
Description
 
  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 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   Amendment No. 4 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP dated January 29, 2010 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on February 3, 2010, File No. 001-34046).
  3 .7   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 .8   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   Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC and Anadarko Petroleum Corporation, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.3 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
  10 .2   Amendment No. 1 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of December 19, 2008 (incorporated by reference to Exhibit 10.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 24, 2008, File No. 001-34046).
  10 .3   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).
  10 .4   Amendment No. 3 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of December 31, 2009 (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on January 7, 2010, File No. 001-34046).
  10 .5   Amendment No. 4 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of January 29, 2010 (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on February 3, 2010, File No. 001-34046).
  10 .6   Services And Secondment Agreement between Western Gas Holdings, LLC and Anadarko Petroleum Corporation dated May 14, 2008 (incorporated by reference to Exhibit 10.4 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
  10 .7   Tax Sharing Agreement by and among Anadarko Petroleum Corporation and Western Gas Partners, LP, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.5 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
  10 .8   Anadarko Petroleum Corporation Fixed Rate Note due 2038 (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).

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Exhibit
   
Number
 
Description
 
  10 .9   Working Capital Loan Agreement between Anadarko Petroleum Corporation and Western Gas Partners, LP, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.6 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
  10 .10   Revolving Credit Agreement, dated as of March 4, 2008, by and among Anadarko Petroleum Corporation, Western Gas Partners, LP, JPMorgan Chase Bank, N.A., The Royal Bank of Scotland, PLC, BNP Paribas, Bank of America, N.A., BMO Capital Markets Financing, Inc., The Bank of Tokyo-Mitsubishi UFJ, LTD., and each of the Lenders named therein (incorporated by reference to Exhibit 10.14 to Amendment No. 4 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on April 15, 2008, File No. 333-146700).
  10 .11   Term Loan Agreement due 2013 dated as of December 19, 2008 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 December 24, 2008, File No. 001-34046).
  10 .12†   Dew Gas Gathering Agreement between Anadarko Gathering Company LLC and Anadarko Petroleum Corporation (incorporated by reference to Exhibit 10.4 to Amendment No. 2 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on January 23, 2008, File No. 333-146700).
  10 .13†   Haley Gas Gathering Agreement between Anadarko Gathering Company LLC and Anadarko Petroleum Corporation (incorporated by reference to Exhibit 10.5 to Amendment No. 2 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on January 23, 2008, File No. 333-146700).
  10 .14†   Hugoton Gas Gathering Agreement between Anadarko Gathering Company LLC and Anadarko Petroleum Corporation (incorporated by reference to Exhibit 10.6 to Amendment No. 2 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on January 23, 2008, File No. 333-146700).
  10 .15†   Pinnacle Gas Gathering Agreement between Pinnacle Gas Treating LLC and Anadarko Petroleum Corporation (incorporated by reference to Exhibit 10.7 to Amendment No. 2 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on January 23, 2008, File No. 333-146700).
  10 .16‡   Form of Indemnification Agreement by and between Western Gas Holdings, LLC, its Officers and Directors (incorporated by reference to Exhibit 10.10 to Amendment No. 2 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on January 23, 2008, File No. 333-146700).
  10 .17‡   Western Gas Partners, LP 2008 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.13 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on June 13, 2008, File No. 001-34046).
  10 .18‡   Form of Award Agreement under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.9 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
  10 .19‡   Amended and Restated Western Gas Holdings, LLC Equity Incentive Plan (incorporated by reference to Exhibit 10.3 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 24, 2008, File No. 001-34046).
  10 .20‡   Form of Amended and Restated Award Agreement under Western Gas Holdings, LLC Equity Incentive Plan (incorporated by reference to Exhibit 10.4 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 24, 2008, File No. 001-34046).
  10 .21†   Gas Processing Agreement between Chipeta Processing LLC and Kerr-McGee Oil & Gas Onshore LP dated September 6, 2008 (incorporated by reference to Exhibit 10.3 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on November 12, 2009, File No. 001-34046).
  10 .22†   Amended and Restated Limited Liability Company Agreement of Chipeta Processing LLC effective July 23, 2009 (incorporated by reference to Exhibit 10.4 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on November 12, 2009, File No. 001-34046).
  10 .23   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).

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Exhibit
   
Number
 
Description
 
  12 .1*   Ratio of Earnings to Fixed Charges.
  21 .1*   List of Subsidiaries of Western Gas Partners, LP.
  23 .1*   Consent of KPMG LLP.
  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.
 
 
Filed herewith.
 
# Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted schedule to the Securities and Exchange Commission upon request.
 
†  Portions of this exhibit, which was previously filed with the Securities and Exchange Commission, were omitted pursuant to a request for confidential treatment. The omitted portions were filed separately with the Securities and Exchange Commission.
 
‡  Management contracts or compensatory plans or arrangements required to be filed pursuant to Item 15.

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SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) 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.
 
Western Gas Partners, LP
(Registrant)
 
  By:  Western Gas Holdings, LLC, its general partner
 
  By: 
/s/  Benjamin M. Fink
Benjamin M. Fink
Senior Vice President and
Chief Financial Officer
(Principal Financial and Accounting Officer)
 
Date: March 11, 2010
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 11, 2010.
 
         
Signature
 
Title (Position with Western Gas Holdings, LLC)
 
     
/s/  Robert G. Gwin

Robert G. Gwin
  Chairman and Director
     
/s/  Donald R. Sinclair

Donald R. Sinclair
  President, Chief Executive Officer and Director
(Principal Executive Officer)
     
/s/  Benjamin M. Fink

Benjamin M. Fink
  Senior Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer)
     
/s/  R. A. Walker

R. A. Walker
  Director
     
/s/  Charles A. Meloy

Charles A. Meloy
  Director
     
/s/  Robert K. Reeves

Robert K. Reeves
  Director
     
/s/  Milton Carroll

Milton Carroll
  Director
     
/s/  Anthony R. Chase

Anthony R. Chase
  Director
     
/s/  James R. Crane

James R. Crane
  Director
     
/s/  David J. Tudor

David J. Tudor
  Director


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WESTERN GAS PARTNERS, LP
 
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
 
         
    F-2  
    F-2  
    F-3  
    F-5  
    F-6  
    F-7  
    F-8  
    F-9  
    F-35  


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WESTERN GAS PARTNERS, LP
 
REPORT OF MANAGEMENT
 
Management of the Partnership’s general partner prepared, and is responsible for, the consolidated financial statements and the other information appearing in this annual report. The consolidated financial statements present fairly the Partnership’s financial position, results of operations and cash flows in conformity with accounting principles generally accepted in the United States. In preparing its consolidated financial statements, the Partnership includes amounts that are based on estimates and judgments that Management believes are reasonable under the circumstances. The Partnership’s financial statements have been audited by KPMG LLP, an independent registered public accounting firm appointed by the Audit Committee of the Board of Directors. Management has made available to KPMG LLP all of the Partnership’s financial records and related data, as well as the minutes of the Directors’ meetings.
 
MANAGEMENT’S ASSESSMENT OF INTERNAL CONTROL OVER FINANCIAL REPORTING
 
Management is responsible for establishing and maintaining adequate internal control over financial reporting. The Partnership’s internal control system was designed to provide reasonable assurance to the Partnership’s Management and Directors regarding the preparation and fair presentation of published financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
Management assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2009. This assessment was based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, we believe that as of December 31, 2009 the Partnership’s internal control over financial reporting is effective based on those criteria.
 
KPMG LLP has issued an attestation report on the Partnership’s internal control over financial reporting as of December 31, 2009.
 
/s/  Donald R. Sinclair
Donald R. Sinclair
President and Chief Executive Officer
Western Gas Holdings, LLC
(as general partner of Western Gas Partners, LP)
 
/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)
 
March 11, 2010


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WESTERN GAS PARTNERS, LP
 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
The Board of Directors and Unitholders
Western Gas Holdings, LLC (as general partner of Western Gas Partners, LP):
 
We have audited Western Gas Partners, LP’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Western Gas Partners, LP’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Assessment of Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
 
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, Western Gas Partners, LP maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Western Gas Partners, LP and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of income, equity and partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2009, and our report dated March 11, 2010 expressed an unqualified opinion on those consolidated financial statements.
 
/s/ KPMG LLP
 
Houston, Texas
March 11, 2010


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WESTERN GAS PARTNERS, LP
 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
The Board of Directors and Unitholders
Western Gas Holdings, LLC (as general partner of Western Gas Partners, LP):
 
We have audited the accompanying consolidated balance sheets of Western Gas Partners, LP and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of income, equity and partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2009. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Western Gas Partners, LP and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Western Gas Partners, LP’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 11, 2010 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.
 
/s/ KPMG LLP
 
Houston, Texas
March 11, 2010


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WESTERN GAS PARTNERS, LP
 
CONSOLIDATED STATEMENTS OF INCOME
 
                         
    Year Ended December 31,  
    2009     2008(1)     2007(1)  
    (In thousands, except per-unit data)  
 
Revenues — affiliates
                       
Gathering, processing and transportation of natural gas
  $ 134,832     $ 121,389     $ 93,007  
Natural gas, natural gas liquids and condensate sales
    76,289       172,148       146,151  
Equity income and other
    8,577       9,288       6,144  
                         
Total revenues — affiliates
    219,698       302,825       245,302  
Revenues — third parties
                       
Gathering, processing and transportation of natural gas
    16,984       17,475       11,019  
Natural gas, natural gas liquids and condensate sales
    7,462       16,278       2,772  
Other
    975       7,928       2,400  
                         
Total revenues — third parties
    25,421       41,681       16,191  
                         
Total revenues
    245,119       344,506       261,493  
                         
Operating expenses(2)
                       
Cost of product
    51,136       140,010       112,282  
Operation and maintenance
    45,901       50,828       40,756  
General and administrative
    20,136       15,345       8,365  
Property and other taxes
    7,251       6,760       5,591  
Depreciation and amortization
    40,065       36,042       30,785  
Impairment
          9,354        
                         
Total operating expenses
    164,489       258,339       197,779  
                         
Operating income
    80,630       86,167       63,714  
Interest income (expense), net(3)
    6,945       9,191       (7,805 )
Other income (expense), net
    42       196       (15 )
                         
Income before income taxes
    87,617       95,554       55,894  
Income tax expense
    12       13,988       19,424  
                         
Net income
    87,605       81,566       36,470  
Net income attributable to noncontrolling interests
    10,260       7,908       (92 )
                         
Net income attributable to Western Gas Partners, LP
  $ 77,345     $ 73,658     $ 36,562  
                         
Limited partner interest in net income:
                       
Net income attributable to Western Gas Partners, LP(4)
  $ 77,345     $ 73,658       n/a (5)
Less pre-acquisition income allocated to Parent
    5,937       31,555       n/a  
Less general partner interest in net income
    1,428       842       n/a  
                         
Limited partner interest in net income
  $ 69,980     $ 41,261       n/a  
Net income per common unit — basic and diluted
  $ 1.25     $ 0.78       n/a  
Net income per subordinated unit — basic and diluted
  $ 1.24     $ 0.77       n/a  
 
 
(1) Financial information for 2008 and 2007 has been revised to include results attributable to the Chipeta assets. See Note 1 — Description of Business and Basis of Presentation — Offerings and acquisitions.
 
(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. Cost of product expenses include product purchases from affiliates of $6.6 million, $24.2 million and $18.8 million for the years ended December 31, 2009, 2008 and 2007, respectively. Operation and maintenance expenses include charges from affiliates of $20.0 million, $20.6 million and $11.7 million for the years ended December 31, 2009, 2008 and 2007, respectively. General and administrative expenses include charges from affiliates of $14.4 million, $12.0 million and $8.4 million for the years ended December 31, 2009, 2008 and 2007, respectively. See Note 6 — Transactions with Affiliates.
 
(3) Interest income (expense), net includes income (charges), net from affiliates of $7.8 million, $9.2 million and ($7.8 million) for the years ended December 31, 2009, 2008 and 2007, respectively. See Note 6 — Transactions with Affiliates.
 
(4) 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 — Offerings and acquisitions). See also Note 5 — Net Income per Limited Partner Unit.
 
(5) Not applicable.
 
See accompanying notes to the consolidated financial statements.


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Table of Contents

 
WESTERN GAS PARTNERS, LP
 
CONSOLIDATED BALANCE SHEET
 
                 
    December 31,
    December 31,
 
    2009     2008(1)  
    (In thousands, except
 
    number of units)  
 
ASSETS
Current assets
               
Cash and cash equivalents
  $ 69,984     $ 36,074  
Accounts receivable, net — third parties
    3,896       5,878  
Accounts receivable — affiliates
    2,203       2,012  
Natural gas imbalance receivables — third parties
    45       389  
Natural gas imbalance receivables — affiliates
    448       1,422  
Other current assets
    3,287       1,380  
                 
Total current assets
    79,863       47,155  
Other assets
    2,974       628  
Note receivable — Anadarko
    260,000       260,000  
Property, plant and equipment
               
Cost
    915,438       861,780  
Less accumulated depreciation
    214,942       175,427  
                 
Net property, plant and equipment
    700,496       686,353  
Goodwill
    20,836       20,836  
Equity investment
    20,060       18,183  
                 
Total assets
  $ 1,084,229     $ 1,033,155  
                 
 
LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
Current liabilities
               
Accounts payable — third parties
  $ 8,602     $ 5,459  
Accounts payable — affiliates
          21,104  
Natural gas imbalance payable — third parties
    289       244  
Natural gas imbalance payable — affiliates
    1,319       1,198  
Accrued ad valorem taxes
    1,525       1,330  
Income taxes payable
    412       146  
Accrued liabilities — third parties
    5,496       12,801  
Accrued liabilities — affiliates
    470       153  
                 
Total current liabilities
    18,113       42,435  
Long-term liabilities
               
Note payable — Anadarko
    175,000       175,000  
Deferred income taxes
    687       1,148  
Asset retirement obligations and other
    11,980       9,947  
                 
Total long-term liabilities
    187,667       186,095  
                 
Total liabilities
    205,780       228,530  
Commitments and contingencies (Note 12)
           
Equity and partners’ capital
               
Common units (36,374,925 and 29,093,197 units issued and outstanding at December 31, 2009 and 2008, respectively)
    497,230       368,050  
Subordinated units (26,536,306 units issued and outstanding at December 31, 2009 and 2008)
    276,571       275,917  
General partner units (1,283,903 and 1,135,296 units issued and outstanding at December 31, 2009 and 2008, respectively)
    13,726       10,988  
Parent net investment
          83,654  
                 
Total partners’ capital
    787,527       738,609  
Noncontrolling interest
    90,922       66,016  
                 
Total equity and partners’ capital
    878,449       804,625  
                 
Total liabilities, equity and partners’ capital
  $ 1,084,229     $ 1,033,155  
                 
 
 
(1) Financial information for 2008 has been revised to include results attributable to the Chipeta assets. See Note 1 — Description of Business and Basis of Presentation — Offerings and acquisitions.
 
See accompanying notes to the consolidated financial statements.


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Table of Contents

 
WESTERN GAS PARTNERS, LP
 
CONSOLIDATED STATEMENTS OF EQUITY AND PARTNERS’ CAPITAL
 
                                                 
          Partners’ Capital              
    Parent Net
    Limited Partners     General
    Noncontrolling
       
    Investment     Common     Subordinated     Partner     Interests     Total  
    (In thousands)  
 
Balance at December 31, 2006(1)
  $ 366,532     $     $     $     $     $ 366,532  
Contributions of property from Parent
    21,942                               21,942  
Net pre-acquisition contributions from Parent
    69,593                               69,593  
Net income
    36,562                         (92 )     36,470  
                                                 
Balance at December 31, 2007(1)
  $ 494,629     $     $     $     $ (92 )   $ 494,537  
Net pre-acquisition distributions to Parent
    (109,435 )                             (109,435 )
Elimination of net deferred tax liabilities
    126,936                               126,936  
Contribution of initial assets
    (321,609 )     55,221       255,941       10,447              
Acquisition of Powder River assets
    (160,851 )     (13,866 )           (283 )           (175,000 )
Contribution of other assets from Parent
    2,089       2,528       11,715       478             16,810  
Reimbursement to Parent from offering proceeds
    (45,161 )                             (45,161 )
Issuance of common units to public, net of offering and other costs
          315,161                         315,161  
Contributions from noncontrolling interest holders and Parent
    88,465                         73,105       161,570  
Distributions to noncontrolling interest holders and Parent
    (22,668 )                       (15,201 )     (37,869 )
Non-cash equity-based compensation
          324                         324  
Net income
    31,555       20,841       20,420       842       7,908       81,566  
Distributions to unitholders
          (12,159 )     (12,159 )     (496 )           (24,814 )
Other
    (296 )                       296        
                                                 
Balance at December 31, 2008(1)
  $ 83,654     $ 368,050     $ 275,917     $ 10,988     $ 66,016     $ 804,625  
Net pre-acquisition distributions to Parent
    3,181                               3,181  
Acquisition of Chipeta assets
    (112,744 )     11,068             225             (101,451 )
Issuance of common and general partner units, net of offering costs
          120,080             2,459             122,539  
Contributions from noncontrolling interest owners and Parent
    20,544                         19,718       40,262  
Distributions to noncontrolling interest owners and Parent
    (2,926 )                       (5,072 )     (7,998 )
Non-cash equity-based compensation
          366                         366  
Net income
    5,937       37,035       32,945       1,428       10,260       87,605  
Distributions to unitholders
          (36,025 )     (32,640 )     (1,401 )           (70,066 )
Other
    2,354       (3,344 )     349       27             (614 )
                                                 
Balance at December 31, 2009
  $     $ 497,230     $ 276,571     $ 13,726     $ 90,922     $ 878,449  
                                                 
 
 
(1) Financial information for 2008, 2007 and 2006 has been revised to include activity attributable to the Chipeta assets. See Note 1 — Description of Business and Basis of Presentation — Offerings and acquisitions.
 
See accompanying notes to the consolidated financial statements.


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WESTERN GAS PARTNERS, LP
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
                         
    Year Ended December 31,  
    2009     2008(1)     2007(1)  
    (In thousands)  
 
Cash flows from operating activities
                       
Net income
  $ 87,605     $ 81,566     $ 36,470  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Depreciation and amortization
    40,065       36,042       30,785  
Impairment
          9,354        
Deferred income taxes
    (254 )     1,834       10,700  
Changes in assets and liabilities:
                       
(Increase) decrease in accounts receivable
    (2,006 )     (2,824 )     (3,466 )
(Increase) in natural gas imbalance receivable
    1,318       (912 )     (226 )
Increase (decrease) in accounts payable, accrued expenses and natural gas imbalance payable
    (12,713 )     19,950       458  
Change in other items, net
    (57 )     420       (1,498 )
                         
Net cash provided by operating activities
    113,958       145,430       73,223  
Cash flows from investing activities
                       
Capital expenditures
    (62,174 )     (99,491 )     (136,874 )
Acquisitions
    (101,451 )     (175,000 )      
Investment in equity affiliate
    (382 )     (8,095 )     (6,400 )
Loan to Anadarko
          (260,000 )      
                         
Net cash used in investing activities
    (164,007 )     (542,586 )     (143,274 )
Cash flows from financing activities
                       
Proceeds from issuance of common and general partner units, net of $5.5 million and $28.2 million in offering and other expenses for the years ended December 31, 2009 and 2008, respectively
    122,539       315,161        
Issuance of Note Payables to Anadarko
    101,451       175,000        
Repayment of Note Payables to Anadarko
    (101,451 )            
Revolving credit facility issuance costs
    (4,263 )            
Reimbursement to Parent from offering proceeds
          (45,161 )      
Distributions to unitholders
    (70,066 )     (24,814 )      
Net pre-acquisition contributions from (distributions to) Anadarko
    3,485       (4,449 )     69,593  
Contributions from noncontrolling interest owners and Parent
    40,262       55,362        
Distributions to noncontrolling interest owners and Parent
    (7,998 )     (37,869 )      
                         
Net cash provided by financing activities
    83,959       433,230       69,593  
                         
Net increase (decrease) in cash and cash equivalents
    33,910       36,074       (458 )
Cash and cash equivalents at beginning of period
    36,074             458  
                         
Cash and cash equivalents at end of period
  $ 69,984     $ 36,074     $  
                         
Supplemental disclosures
                       
Significant non-cash investing and financing transactions:
                       
Contribution of initial assets from Parent
  $     $ 321,609     $  
Elimination of net deferred tax liabilities
  $     $ 126,936     $  
Property, plant and equipment and other assets contributed by Parent
  $     $ 123,018     $ 21,942  
(Increase) decrease in accrued capital expenditures
  $ 11,610     $ (9,792 )   $ (501 )
Interest paid
  $ 9,372     $ 82     $  
Interest received
  $ 16,900     $     $  
 
 
(1) Financial information for 2008 and 2007 has been revised to include results attributable to the Chipeta assets. See Note 1 — Description of Business and Basis of Presentation — Offerings and acquisitions of the notes to the consolidated financial statements.
 
See accompanying notes to the consolidated financial statements.


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Table of Contents

 
 
Notes to the 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. As of December 31, 2009, the Partnership’s assets consisted of nine gathering systems, six natural gas treating facilities, four gas processing facilities, one NGL pipeline 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 the Partnership’s 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. Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. All significant intercompany transactions have been eliminated. The Partnership’s 50% undivided interest in the Newcastle system is consolidated on a proportionate basis.
 
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.
 
Offerings and acquisitions.
 
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, 2008 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 Distributions for information related to the distribution rights of the common and subordinated unitholders and to the IDRs held by the general partner.
 
Equity offering.  On December 9, 2009, the Partnership closed its equity offering of 6,000,000 common units to the public at a price of $18.20 per unit. On December 17, 2009, the Partnership issued an additional 900,000 units to the public pursuant to the full exercise of the underwriters’ over-allotment option granted in


F-9


Table of Contents

 
Notes to the consolidated financial statements of Western Gas Partners, LP — (Continued)
 
connection with the equity offering. The December 9 and December 17, 2009 issuances are referred to collectively as the “2009 equity offering.” Net proceeds from the offering of approximately $122.5 million were used to repay $100.0 million outstanding under the Partnership’s revolving credit facility and to partially fund the January 2010 Granger acquisition referenced below. In connection with the 2009 equity offering, the Partnership issued 140,817 general partner units to Anadarko.
 
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 (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 consisted of a 51% membership interest in Chipeta Processing LLC (“Chipeta”), together with an associated NGL pipeline. Chipeta owns a natural gas processing plant complex, which includes two recently completed processing trains: a refrigeration unit completed in November 2007 and a cryogenic unit which was completed in April 2009. The 51% membership interest in Chipeta and associated NGL pipeline are referred to collectively as the “Chipeta assets” and the acquisition is referred to as the “Chipeta acquisition.”
 
In November 2009, Chipeta closed its acquisition of a compressor station and processing plant (the “Natural Buttes plant,” which was formerly known as the CIG 101 plant prior to the Partnership’s acquisition) from a third party for $9.1 million. The noncontrolling interest owners contributed $4.5 million to Chipeta during the year ended December 31, 2009 to fund their proportionate share of the Natural Buttes plant acquisition. The Natural Buttes plant is located in Uintah County, Utah.
 
Granger acquisition.  On January 29, 2010, the Partnership acquired certain midstream assets located in Southwestern Wyoming from Anadarko. See Note 13 — Subsequent Events — Granger Acquisition.
 
Presentation of Partnership acquisitions.  For purposes of this annual report, the assets in which the Partnership owned an interest as of December 31, 2009, which consist of 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 the Chipeta assets in connection with its August 10, 2006 acquisition of Kerr-McGee Corporation (“Kerr-McGee”). Because of Anadarko’s control of the Partnership, each acquisition of Partnership Assets, except for the Natural Buttes plant, was considered a transfer of net assets between entities under common control. As a result, after each acquisition of assets from Anadarko, 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 years ended December 31, 2008 and 2007 as presented in the Partnership’s annual report on Form 10-K for


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Table of Contents

 
Notes to the consolidated financial statements of Western Gas Partners, LP — (Continued)
 
the year ended December 31, 2008, which included the results attributable to the Powder River assets, have been recast to reflect the results attributable to the Chipeta assets as if the Partnership owned 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. Beginning with the Partnership’s quarterly report for the three months ending March 31, 2010, its historic financial statements will be recast to reflect the results attributable to the Granger assets for periods including and subsequent to August 23, 2006, the date Anadarko acquired the Granger assets in conjunction with its acquisition of Western.
 
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. In addition, certain amounts in prior periods have been reclassified to conform to the current presentation.
 
Limited partner and general partner units.  The following table summarizes common, subordinated and general partner units issued during the years ended December 31, 2009 and 2008:
 
                                 
    Limited Partner Units     General
       
    Common     Subordinated     Partner Units     Total  
 
Balance at December 31, 2007
                       
Initial public offering and contribution of initial assets
    26,536,306       26,536,306       1,083,115       54,155,727  
Powder River acquisition
    2,556,891             52,181       2,609,072  
                                 
Balance at December 31, 2008
    29,093,197       26,536,306       1,135,296       56,764,799  
Chipeta acquisition
    351,424             7,172       358,596  
Equity offering
    6,900,000             140,817       7,040,817  
Long-Term Incentive Plan awards
    30,304             618       30,922  
                                 
Balance at December 31, 2009
    36,374,925       26,536,306       1,283,903       64,195,134  
                                 
 
Anadarko holdings of partnership equity.  As of December 31, 2009, Anadarko held 1,283,903 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 54.8% limited partner interest in the Partnership. The public held 27,741,179 common units, representing a 43.2% limited partner interest in the Partnership.
 
2.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
Use of estimates.  To conform to accounting principles generally accepted in the United States, management makes estimates and assumptions that affect the amounts reported in the consolidated financial statements and the notes thereto. These estimates are evaluated on an ongoing basis, utilizing historical experience and other methods considered reasonable in the particular circumstances. Although these estimates are based on management’s best available knowledge at the time, actual results may differ.
 
Effects on the Partnership’s business, financial position and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revision become known. Changes in facts and circumstances or discovery of new facts or circumstances may result in revised estimates and actual results may differ from these estimates.
 
Property, plant and equipment.  Property, plant and equipment are stated at the lower of historical cost less accumulated depreciation or fair value, if impaired. The Partnership capitalizes all construction-related direct labor and material costs. The cost of renewals and betterments that extend the useful life of property,


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Notes to the consolidated financial statements of Western Gas Partners, LP — (Continued)
 
plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects which do not extend the useful life or increase the expected output of property, plant and equipment is expensed as incurred.
 
Depreciation is computed over the asset’s estimated useful life using the straight-line method or half-year convention method, based on estimated useful lives and salvage values of assets. Uncertainties that may impact these estimates include, among others, changes in laws and regulations relating to restoration and abandonment requirements, economic conditions and supply and demand in the area. When assets are placed into service, the Partnership makes estimates with respect to useful lives and salvage values that the Partnership believes are reasonable. However, subsequent events could cause a change in estimates, thereby impacting future depreciation amounts.
 
The Partnership evaluates its ability to recover the carrying amount of its long-lived assets and determines whether its long-lived assets have been impaired. Impairment exists when the carrying amount of an asset exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the long-lived asset is not recoverable, based on the estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying amount over its estimated fair value, such that the asset’s carrying amount is adjusted to its estimated fair value with an offsetting charge to operating expense.
 
Fair value represents the estimated price between market participants to sell an asset in the principal or most advantageous market for the asset, based on assumptions a market participant would make. When warranted, management assesses the fair value of long-lived assets using commonly accepted techniques and may use more than one source in making such assessments. Sources used to determine fair value include, but are not limited to, recent third-party comparable sales, internally developed discounted cash flow analyses and analyses from outside advisors. Significant changes, such as changes in contract rates or terms, the condition of an asset, or management’s intent to utilize the asset generally require management to reassess the cash flows related to long-lived assets.
 
During the year ended December 31, 2008, an impairment charge was recorded in connection with the suspension of operations of a plant at the Hilight System prior to its contribution to the Partnership.
 
Equity-method investment.  Fort Union is a partnership among Copano Pipelines/Rocky Mountains, LLC (37.04%), Crestone Powder River L.L.C. (37.04%), Bargath, Inc. (11.11%) and the Partnership (14.81%). Fort Union owns a gathering pipeline and treating facilities in the Powder River Basin. The Parent is the construction manager and physical operator of the Fort Union facilities.
 
The Partnership’s investment in Fort Union is accounted for under the equity method of accounting. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the owners’ firm gathering agreements, require 65% or unanimous approval of the owners.
 
Management evaluates its equity-method investment for impairment whenever events or changes in circumstances indicate that the carrying value of such investment may have experienced a decline in value that is other than temporary. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether the investment has been impaired. Management assesses the fair value of equity-method investments using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. If the estimated fair value is less than the carrying value, the excess of the carrying value over the estimated fair value is recognized as an impairment loss.
 
The investment balance at December 31, 2009 includes $3.2 million for the purchase price allocated to the investment in Fort Union in excess of Western’s historic cost basis. This balance was attributed to the


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Notes to the consolidated financial statements of Western Gas Partners, LP — (Continued)
 
difference between the fair value and book value of Fort Union’s gathering and treating facilities and is being amortized over the remaining life of those facilities. Investment earnings from Fort Union, net of investment amortization, are reported in equity income and other revenues — affiliates in the consolidated statements of income.
 
At December 31, 2009, Fort Union had expansion projects under construction and had project financing debt of $99.7 million outstanding, which is not guaranteed by the members. Fort Union’s lender has a lien on the Partnership’s interest in Fort Union.
 
Goodwill.  Goodwill represents the allocated portion of Anadarko’s midstream goodwill attributed to the assets the Partnership has acquired from Anadarko. The carrying value of Anadarko’s midstream goodwill represents the excess of the purchase price of an entity over the estimated fair value of the identifiable assets acquired and liabilities assumed by Anadarko. During 2009, the carrying amount of goodwill did not change. During 2008, the carrying amount of goodwill increased due to revisions in estimates of deferred tax liabilities recorded upon Anadarko’s acquisitions of Western. None of the Partnership’s goodwill is deductible for tax purposes.
 
Changes in the carrying amount of goodwill for 2009 and 2008 are as follows:
 
                 
    Year Ended December 31,  
    2009     2008  
    (In thousands)  
 
Balance at beginning of year
  $ 20,836     $ 18,747  
Change in goodwill associated with Anadarko’s 2006 acquisitions
          2,089  
                 
Balance at end of year
  $ 20,836     $ 20,836  
                 
 
The Partnership evaluates whether goodwill has been impaired. Impairment testing is performed annually as of October 1, unless facts and circumstances make it necessary to test more frequently. The Partnership has determined that it has one operating segment and two reporting units: (i) gathering and processing and (ii) transportation. Accounting standards require that goodwill be assessed for impairment at the reporting unit level. Goodwill impairment assessment is a two-step process. Step one focuses on identifying a potential impairment by comparing the fair value of the reporting unit with the carrying amount of the reporting unit. If the fair value of the reporting unit exceeds its carrying amount, no further action is required. However, if the carrying amount of the reporting unit exceeds its fair value, goodwill is written down to the implied fair value of the goodwill through a charge to operating expense based on a hypothetical purchase price allocation. No goodwill impairment has been recognized in these consolidated financial statements.
 
Asset retirement obligations.  Management recognizes a liability based on the estimated costs of retiring tangible long-lived assets. The liability is recognized at its fair value measured using expected discounted future cash outflows of the asset retirement obligation when the obligation originates, which generally is when an asset is acquired or constructed. The carrying amount of the associated asset is increased commensurate with the liability recognized. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. Subsequent to the initial recognition, the liability is adjusted for any changes in the expected value of the retirement obligation (with a corresponding adjustment to property, plant and equipment) and for accretion of the liability due to the passage of time, until the obligation is settled. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded for both the asset retirement obligation and the associated asset carrying amount. Revisions in estimated asset retirement obligations may result from changes in estimated inflation rates, discount rates, retirement costs and the estimated timing of settling asset retirement obligations.
 
Fair value.  The fair-value-measurement standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard characterizes inputs used in determining fair value according to a hierarchy


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Notes to the consolidated financial statements of Western Gas Partners, LP — (Continued)
 
that prioritizes those inputs based upon the degree to which they are observable. The three levels of the fair value hierarchy are as follows:
 
Level 1 — inputs represent quoted prices in active markets for identical assets or liabilities.
 
Level 2 — inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).
 
Level 3 — inputs that are not observable from objective sources, such as management’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in management’s internally developed present value of future cash flows model that underlies the fair value measurement).
 
Nonfinancial assets and liabilities initially measured at fair value include third-party business combinations, impaired long-lived assets (asset groups), goodwill impairment and initial recognition of asset retirement obligations.
 
The fair value of the note receivable from Anadarko 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. See Note 6 - Transactions with Affiliates for disclosures regarding the fair value of the note receivable from Anadarko.
 
The fair value of debt is the estimated amount the Partnership would have to pay to repurchase its debt, including any premium or discount attributable to the difference between the stated interest rate and market rate of interest at the balance sheet date. Fair values are based on quoted market prices or average valuations of similar debt instruments at the balance sheet date for those debt instruments for which quoted market prices are not available. See Note 11 — Debt and Interest Expense for disclosures regarding the fair value of debt.
 
The carrying amount of cash and cash equivalents, accounts receivable and accounts payable reported on the balance sheet approximates fair value.
 
Segments.  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.
 
Revenue recognition.  Under its fee-based arrangements, the Partnership is paid a fixed fee based on the volume and thermal content of the natural gas it gathers or treats and recognizes gathering and treating revenues for its services at the time the service is performed.
 
Producers’ wells are connected to the Partnership’s gathering systems for delivery of natural gas to the Partnership’s processing or treating plants, where the natural gas is processed to extract NGLs or treated in order to satisfy pipeline specifications. In some areas, where no processing is required, the producers’ gas is gathered, compressed and delivered to pipelines for market delivery. Except for volumes taken in-kind by certain producers, an affiliate of Anadarko sells the natural gas and extracted NGLs attributable to processing activities. Under percent-of-proceeds contracts, revenue is recognized when the natural gas or NGLs are sold and the related product purchases are recorded as a percentage of the product sale.
 
Under keep-whole contracts, NGLs recovered by the processing facility are retained and sold. Producers are kept whole through the receipt of a thermally equivalent volume of residue gas at the tailgate of the plant. The keep-whole contract conveys an economic benefit to the Partnership when the individual values of the NGLs are greater as liquids than as a component of the natural gas stream; however, the Partnership is adversely impacted when the value of the NGLs are lower as liquids than as a component of the natural gas stream. Revenue is recognized from the sale of NGLs upon transfer of title.


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Notes to the consolidated financial statements of Western Gas Partners, LP — (Continued)
 
Condensate recovered in the field and during processing is retained and sold. Depending upon contract terms, proceeds from condensate sales are either retained by the gatherer or processor or are credited to the producer. Revenue is recognized from the sale of condensate upon transfer of title.
 
The Partnership earns transportation revenues through firm contracts that obligate each of its customers to pay a monthly reservation or demand charge regardless of the pipeline capacity used by that customer. An additional commodity usage fee is charged to the customer based on the actual volume of natural gas transported. Revenues are also generated from interruptible contracts pursuant to which a fee is charged to the customer based on volumes transported through the pipeline. Revenues for transportation of natural gas are recognized over the period of firm transportation contracts or, in the case of usage fees and interruptible contracts, when the volumes are received into the pipeline. From time to time, certain revenues may be subject to refund pending the outcome of rate matters before the Federal Energy Regulatory Commission and reserves are established where appropriate. During the periods presented herein, there were no pending rate cases and no related reserves have been established.
 
Proceeds from the sale of residue gas, NGLs and condensate are recorded in natural gas, natural gas liquids and condensate revenues in the consolidated statements of income. Revenues attributable to the fixed-fee component of gathering and processing contracts as well as demand charges and commodity usage fees on transportation contracts are reported in gathering, processing and transportation of natural gas revenues in the consolidated statements of income.
 
Natural gas imbalances.  The consolidated balance sheets include natural gas imbalance receivables and payables resulting from differences in gas volumes received into the Partnership’s systems and gas volumes delivered by the Partnership to customers. Natural gas volumes owed to or by the Partnership that are subject to monthly cash settlement are valued according to the terms of the contract as of the balance sheet dates, and generally reflect market index prices. Other natural gas volumes owed to or by the Partnership are valued at the Partnership’s weighted average cost of natural gas as of the balance sheet dates and are settled in-kind. As of December 31, 2009, natural gas imbalance receivables and payables were approximately $0.5 million and $1.6 million, respectively. As of December 31, 2008, natural gas imbalance receivables and payables were approximately $1.8 million and $1.4 million, respectively. Changes in natural gas imbalances are reported in other revenues or cost of product expense in the consolidated statements of income.
 
Inventory.  The cost of natural gas and NGLs inventories are determined by the weighted average cost method on a location-by-location basis. Inventory is accounted for at the lower of weighted average cost or market value.
 
Environmental expenditures.  The Partnership expenses environmental expenditures related to conditions caused by past operations that do not generate current or future revenues. Environmental expenditures related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Liabilities are recorded when the necessity for environmental remediation becomes probable and the costs can be reasonably estimated, or when other potential environmental liabilities are probable and can be reasonably estimated.
 
Cash equivalents.  The Partnership considers all highly liquid investments with an original maturity date of three months or less to be cash equivalents. The Partnership had approximately $70.0 million and $36.1 million of cash and cash equivalents as of December 31, 2009 and December 31, 2008, respectively.
 
Bad-debt reserve.  The Partnership revenues are primarily from Anadarko, for which no credit limit is maintained. The Partnership analyzes its exposure to bad debt on a customer-by-customer basis for its third-party accounts receivable and may establish credit limits for significant third-party customers. For third-party accounts receivable, the amount of bad-debt reserve at December 31, 2009 and December 31, 2008 was approximately $114,000 and $60,000, respectively.
 
Equity-based compensation.  Concurrent with the closing of the initial public offering, phantom unit awards were granted to independent directors of the general partner under the Western Gas Partners, LP 2008


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Notes to the consolidated financial statements of Western Gas Partners, LP — (Continued)
 
Long-Term Incentive Plan (“LTIP”), which permits the issuance of up to 2,250,000 units. The general partner awarded additional phantom units primarily to the general partner’s independent directors under the LTIP in May 2009. Upon vesting of each phantom unit, the holder will receive common units of the Partnership or, at the discretion of the general partner’s board of directors, cash in an amount equal to the market value of common units of the Partnership on the vesting date. Share-based compensation expense attributable to grants made under the LTIP will impact the Partnership’s 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.
 
GAAP requires companies to recognize stock-based compensation as an operating expense. The Partnership amortizes stock-based compensation expense attributable to awards granted under the LTIP over the vesting periods applicable to the awards.
 
Additionally, the Partnership’s general and administrative expenses include equity-based compensation costs allocated by Anadarko to the Partnership for grants made pursuant to the Western Gas Holdings, LLC Equity Incentive Plan as amended and restated (“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”). UVRs and UARs granted under the Incentive Plan (i) are collectively valued at approximately $67.00 per unit as of December 31, 2009, (ii) either vest ratably over three years or vest in two equal installments on the second and fourth anniversaries of the grant date, or earlier in connection with certain other events, and (iii) become payable in cash by the general partner no later than 30 days subsequent to vesting. UARs granted under the Incentive Plan expire upon the earlier of the 90th day subsequent to the participant’s voluntary termination or 10 years from the date of grant. DERs granted under the Incentive Plan vest upon the occurrence of certain events, become payable no later than 30 days subsequent to vesting and expire 10 years from the date of grant. Equity-based compensation expense attributable to grants made under the Incentive Plan will impact the Partnership’s cash flow from operating activities only to the extent cash payments are made to Incentive Plan participants 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 the Partnership’s cash flow from operating activities. See Note 6 — Transactions with Affiliates.
 
Income taxes.  The Partnership generally is not subject to federal income tax, or state income tax other than Texas margin tax. Federal and state income tax expense was recorded for periods ending prior to May 14, 2008, with respect to income generated by the initial assets, prior to June 1, 2008 (the date on which substantially all of the Chipeta assets were contributed to a non-taxable entity for U.S. federal income tax purposes) with respect to income generated by the Chipeta assets, and prior to December 19, 2008, with respect to income generated by the Powder River assets. For periods including or subsequent to May 14, 2008, with respect to income generated by the initial assets, including or subsequent to June 1, 2008, with respect to income generated by the Chipeta assets, and including or subsequent to December 19, 2008, with respect to income generated by the Powder River assets, the Partnership is no longer subject to federal income tax and is only subject to Texas margin tax. Accordingly, income tax expense attributable to Texas margin tax will continue to be recognized in the consolidated financial statements. For periods subsequent to the Partnership’s ownership of the Partnership assets, the Partnership makes payments to Anadarko pursuant to the tax sharing agreement entered into between Anadarko and the Partnership for its share of Texas margin tax that are included in any combined or consolidated returns filed by Anadarko. The aggregate difference in the basis of the Partnership’s assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each partner’s tax attributes in the Partnership.


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Notes to the consolidated financial statements of Western Gas Partners, LP — (Continued)
 
The Partnership adopted the accounting standard for uncertain tax positions on January 1, 2007. The standard defines the criteria an individual tax position must meet for any part of the benefit of that position to be recognized in the financial statements. The Partnership has no material uncertain tax positions at December 31, 2009 or 2008.
 
Net income per limited partner unit.  Certain accounting standards address the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and undistributed earnings of the entity when, and if, it declares dividends on its securities. The accounting standards require securities that satisfy the definition of a “participating security” to be considered for inclusion in the computation of basic earnings per unit using the two-class method. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed pursuant to the terms of the relevant contractual arrangement. For the Partnership, earnings per unit is calculated based on the assumption that the Partnership distributes to its unitholders an amount of cash equal to the net income of the Partnership, notwithstanding the general partner’s ultimate discretion over the amount of cash to be distributed for the period, the existence of other legal or contractual limitations that would prevent distributions of all of the net income for the period or any other economic or practical limitation on the ability to make a full distribution of all of the net income for the period. Earnings per unit is calculated by applying the provisions of the partnership agreement that govern actual cash distributions to the notional cash distribution amount, including giving effect to incentive distributions, when applicable, with such incentive distributions limited to the amount of available cash as defined in the partnership agreement. See Note 5 — Net Income per Limited Partner Unit.
 
New accounting standards.  The Partnership adopted new Financial Accounting Standards Board (“FASB”) staff guidance on fair-value measurement, effective January 1, 2009 which address the accounting for business combinations. This guidance 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 unless the Partnership loses control requiring deconsolidation, which would require gain or loss recognition in the statement of income. 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 adopted new accounting guidance effective January 1, 2009 that clarify that an equity method investor is required to continue to recognize an other-than-temporary impairment of its investment. In addition, an equity method investor should not separately test an investee’s underlying assets for impairment. However, an equity method investor should recognize its share of an impairment charge recorded by an investee. The initial adoption of this standard had no impact on the Partnership’s financial statements.
 
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


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Notes to the consolidated financial statements of Western Gas Partners, LP — (Continued)
 
limited partnership units, general partnership units and, when applicable, IDRs of the general partner. The guidance clarifies that the two-class method would apply to master limited partnerships, 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 adoption of this standard had no impact on the Partnership’s financial statements.
 
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 11 — Debt and Interest Expense, 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 December 31, 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 for all periods presented.
 
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


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Table of Contents

 
Notes to the consolidated financial statements of Western Gas Partners, LP — (Continued)
 
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 year ended December 31, 2009, the Partnership paid cash distributions to its unitholders of approximately $70.1 million, representing the $0.32 per-unit distribution for the quarter ended September 30, 2009, 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 year ended December 31, 2008, the Partnership paid cash distributions to its unitholders of approximately $24.8 million, representing the $0.1582 per-unit distribution for the quarter ended June 30, 2008 and the $0.30 per-unit distribution for the quarter ended September 30, 2008. See also Note 13 — Subsequent Events concerning distributions approved in January 2010 for the quarter ended December 31, 2009.
 
Available cash.  The amount of available cash (as defined in the partnership agreement) generally is all cash on hand at the end of the quarter, less the amount of cash reserves established by the Partnership’s general partner to provide for the proper conduct of the Partnership’s business, including reserves to fund future capital expenditures, to comply with applicable laws, debt instruments or other agreements, or to provide funds for distributions to its unitholders and to its general partner for any one or more of the next four quarters. Working capital borrowings generally include borrowings made under a credit facility or similar financing arrangement. It is intended that working capital borrowings be repaid within 12 months. In all cases, working capital borrowings are used solely for working capital purposes or to fund distributions to partners.
 
Minimum quarterly distributions.  The partnership agreement provides that, during a period of time referred to as the “subordination period,” the common units are entitled to distributions of available cash each quarter in an amount equal to the “minimum quarterly distribution,” which is $0.30 per common unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash are permitted on the subordinated units. Furthermore, arrearages do not apply to subordinated units and, therefore, will not be paid on the subordinated units. The effect of the subordinated units is to increase the likelihood that, during the subordination period, available cash is sufficient to fully fund cash distributions on the common units in an amount equal to the minimum quarterly distribution. From its inception through December 31, 2009, the Partnership has paid equal distributions on common, subordinated and general partner units and there are no distributions in arrears on common units.
 
The subordination period will lapse at such time when the Partnership has paid at least $0.30 per quarter on each common unit, subordinated unit and general partner unit for any three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2011. Also, if the Partnership has paid at least $0.45 per quarter (150% of the minimum quarterly distribution) on each outstanding common unit, subordinated unit and general partner unit for each calendar quarter in a four-quarter period, the subordination period will terminate automatically. The subordination period will also terminate automatically if the general partner is removed without cause and the units held by the general partner and its affiliates are not voted in favor of such removal. When the subordination period lapses or otherwise terminates, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to preferred distributions on prior-quarter distribution arrearages. All subordinated units are held indirectly by Anadarko.
 
General partner interest and incentive distribution rights.  The general partner is currently entitled to 2.0% of all quarterly distributions that the Partnership makes prior to its liquidation. After distributing amounts equal to the minimum quarterly distribution to common and subordinated unitholders and distributing amounts to eliminate any arrearages to common unitholders, the Partnership’s general partner is entitled to incentive


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Table of Contents

 
Notes to the consolidated financial statements of Western Gas Partners, LP — (Continued)
 
distributions if the amount the Partnership distributes with respect to any quarter exceeds specified target levels shown below:
 
                     
        Marginal Percentage
    Total Quarterly Distribution
  Interest in Distributions
    Target Amount   Unitholders   General Partner
 
Minimum quarterly distribution
  $0.300     98 %     2 %
First target distribution
  up to $0.345     98 %     2 %
Second target distribution
  above $0.345 up to $0.375     85 %     15 %
Third target distribution
  above $0.375 up to $0.450     75 %     25 %
Thereafter
  above $0.45     50 %     50 %
 
The table above assumes that the Partnership’s general partner maintains its 2% general partner interest, that there are no arrearages on common units and the general partner continues to own the IDRs. The maximum distribution sharing percentage of 50.0% includes distributions paid to the general partner on its 2.0% general partner interest and does not include any distributions that the general partner may receive on limited partner units that it owns or may acquire.
 
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 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. However, because the initial public offering was completed on May 14, 2008, the number of units issued in connection with the initial public offering, including shares issued in connection with the partial exercise of the underwriters’ over-allotment option, is utilized for purposes of calculating basic earnings per unit for the 2008 periods that include May 14, 2008 as if the shares were outstanding from May 14, 2008. The common units and general partner units issued in connection with the Powder River acquisition, Chipeta acquisition and 2009 equity offering are included on a weighted-average basis for periods they were outstanding.


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Table of Contents

 
Notes to the consolidated financial statements of Western Gas Partners, LP — (Continued)
 
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):
 
                 
    Year Ended
 
    December 31,  
    2009     2008(1)  
 
Net income attributable to Western Gas Partners, LP
  $ 77,345     $ 73,658  
Less pre-acquisition income allocated to Parent
    5,937       31,555  
Less general partner interest in net income
    1,428       842  
                 
Limited partner interest in net income
  $ 69,980     $ 41,261  
                 
Net income allocable to common units
  $ 37,035     $ 20,841  
Net income allocable to subordinated units
    32,945       20,420  
                 
Limited partner interest in net income
  $ 69,980     $ 41,261  
                 
Net income per limited partner unit — basic and diluted
               
Common units
  $ 1.25     $ 0.78  
Subordinated units
  $ 1.24     $ 0.77  
Total
  $ 1.24     $ 0.78  
Weighted average limited partner units outstanding — basic and diluted
               
Common units
    29,684       26,680  
Subordinated units
    26,536       26,536  
                 
Total
    56,220       53,216  
                 
 
 
(1) Financial information for 2008 has been revised to include results attributable to the Chipeta assets. See Note 1 — Description of Business and Basis of Presentation — Offerings and acquisitions.
 
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.
 
Contribution of Partnership Assets to the Partnership.  Concurrent with the closing of the initial public offering in May 2008, Anadarko contributed the assets and liabilities of AGC, PGT and MIGC to the Partnership in exchange for a 2.0% general partner interest, 100% of the IDRs, 5,725,431 common units and 26,536,306 subordinated units. In connection with the Powder River acquisition in December 2008, Anadarko contributed the Powder River assets to the Partnership for consideration consisting of $175.0 million in cash, which was funded by a note from Anadarko, 2,556,891 common units and 52,181 general partner units. In connection with the Chipeta acquisition in July 2009, Anadarko contributed the Chipeta assets to the Partnership for consideration consisting of $101.5 million in cash, 351,424 common units and 7,172 general partner units. See Note 1 — Description of Business and Basis of Presentation. See also Note 13 — Subsequent Events concerning the January 2010 Granger acquisition.
 
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


F-21


Table of Contents

 
Notes to the consolidated financial statements of Western Gas Partners, LP — (Continued)
 
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 investment 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 investment. 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 $271.3 million and $198.1 million at December 31, 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. See Note 11 — Debt and Interest Expense.
 
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 11 — Debt and Interest Expense for more information on these credit facilities. See also Note 13 — Subsequent Events — Granger acquisition regarding financing of the Granger acquisition.
 
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. In December 2009, the Partnership extended the swap agreements through December 2011. 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 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 year ended December 31, 2009, the Partnership recorded realized gains of $4.1 million attributable to the commodity price swap agreements.


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Table of Contents

 
Notes to the consolidated financial statements of Western Gas Partners, LP — (Continued)
 
Below is a summary of the fixed prices on the Partnership’s commodity price swap agreements outstanding as of December 31, 2009. The commodity price swap arrangements are for two years and the Partnership can extend the agreements, at its option, annually through December 2013. Also see Note 13 — Subsequent Events — Granger acquisition for information on commodity price swap agreements entered into in January 2010.
 
                 
    Year Ended December 31,
    2010   2011
    (Per barrel)
 
Natural gasoline
  $ 63.20     $ 68.50  
Condensate
  $ 70.72     $ 68.87  
Propane
  $ 40.63     $ 44.97  
Butane
  $ 48.15     $ 55.57  
Iso butane
  $ 48.15     $ 59.41  
                 
                 
    (Per MMBtu)
 
Natural gas
  $ 5.61     $ 5.61  
 
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 December 31, 2009, the Partnership’s reimbursement to Anadarko for certain general and administrative expenses allocated to the Partnership was capped at $6.9 million for the year ended December 31, 2009 and is capped at $8.3 million for the year ending December 31, 2010, 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. During the year ended December 31, 2009, Anadarko incurred $0.8 million of expenses in excess of the $6.9 million cap. Such expenses were recorded as a capital contribution from Anadarko and did not impact the Partnership’s cash flows. Expenses Anadarko incurred on behalf of the Partnership subject to the cap in the omnibus agreement during the year ended December 31, 2008 did not exceed the cap. Also see Note 13 — Subsequent Events — Granger acquisition for information on adjustments to the cap made as a result of the Granger acquisition.


F-23


Table of Contents

 
Notes to the consolidated financial statements of Western Gas Partners, LP — (Continued)
 
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 of termination 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. In general, the Partnership’s reimbursement to Anadarko under the omnibus agreement or services and secondment agreements is either (i) on an actual basis for direct expenses Anadarko incurs on behalf of the Partnership or (ii) based on an allocation of salaries and related employee benefits between the Partnership and Anadarko based on estimates of time spent on each entity’s business and affairs. The vast majority of direct general and administrative expenses charged to the Partnership by Anadarko are attributed to the Partnership on an actual basis, excluding any mark-up or subsidy charged or received by Anadarko. With respect to allocated costs, management believes that the allocation method employed by Anadarko is reasonable. While it is not practicable to determine what these direct and allocated costs would be on a stand-alone basis if the Partnership were to directly obtain these services, management believes these costs would be substantially the same.
 
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.


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Table of Contents

 
Notes to the consolidated financial statements of Western Gas Partners, LP — (Continued)
 
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 year ended December 31, 2009:
 
                 
    Value per
   
    Unit   Units
 
Units outstanding at beginning of year
  $ 16.50       30,304  
Vested
  $ 16.50       (30,304 )
Granted
  $ 15.02       21,970  
                 
Units outstanding at end of year
  $ 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 $0.4 million and $0.3 million during the years ended December 31, 2009 and 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 Incentive Plan, as well as the Anadarko Incentive Plans.
 
The Partnership’s general and administrative expense for the years ended December 31, 2009 and 2008 included approximately $3.6 million and $1.9 million, respectively, of allocated 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 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.
 
                         
    Year Ended December 31,
    2009   2008   2007
    (In thousands)
 
Revenues — affiliates
  $ 219,698     $ 302,825     $ 245,302  
Operating expenses — affiliates
    40,975       56,849       38,868  
Interest income — affiliates
    16,900       10,703        
Interest expense, net — affiliates
    9,096       1,512       7,805  
Distributions to unitholders — affiliates
    44,450       15,279        
Contributions from noncontrolling interest owners — affiliate and Parent
    34,011       130,094 (1)      
Distributions to noncontrolling interest owners — affiliate and Parent
    5,410       33,335        
 
 
(1) Includes the $106.2 million initial contribution of net assets to Chipeta in connection with Anadarko’s formation of Chipeta.


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Table of Contents

 
Notes to the consolidated financial statements of Western Gas Partners, LP — (Continued)
 
 
7.   INCOME TAXES
 
The components of the Partnership’s income tax expense are as follows:
 
                         
    Year Ended December 31,  
    2009     2008     2007  
    (In thousands)  
 
Current income tax expense
                       
Federal income tax expense
  $     $ 11,759     $ 8,411  
State income tax expense
    266       395       313  
                         
Total current income tax expense
    266       12,154       8,724  
                         
Deferred income tax expense
                       
Federal income tax expense
    97       791       11,244  
State income tax expense (benefit)
    (351 )     1,043       (544 )
                         
Total deferred income tax expense (benefit)
    (254 )     1,834       10,700  
                         
Total income tax expense
  $ 12     $ 13,988     $ 19,424  
                         
 
Total income taxes differed from the amounts computed by applying the statutory income tax rate to income before income taxes. The sources of these differences are as follows:
 
                         
    Year Ended December 31,  
    2009     2008     2007  
    (In thousands, except percentages)  
 
Income before income taxes
  $ 87,617     $ 95,554     $ 55,894  
Statutory tax rate
    35 %     35 %     35 %
                         
Tax computed at statutory rate
    30,666       33,444       19,563  
Adjustments resulting from:
                       
Partnership income not subject to federal taxes
    (30,563 )     (18,919 )      
State income taxes, net of federal tax benefit
    (91 )     1,133       258  
Tax status change
          (1,674 )      
Other
          4       (397 )
                         
Income tax expense
  $ 12     $ 13,988     $ 19,424  
                         
Effective tax rate
    0 %     15 %     35 %
                         
 
The tax effects of temporary differences that give rise to significant portions of deferred tax assets and liabilities are as follows:
 
                 
    As of December 31,  
    2009     2008  
    (In thousands)  
 
Net operating loss and credit carryforwards
  $ 14     $ 14  
                 
Net current deferred income tax assets
    14       14  
                 
Depreciable property
    (1,424 )     (2,138 )
Equity investment
    152        
Net operating loss and credit carryforwards
    585       990  
                 
Net long-term deferred income tax liabilities
    (687 )     (1,148 )
                 
Total net deferred income tax liabilities
  $ (673 )   $ (1,134 )
                 


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Table of Contents

 
Notes to the consolidated financial statements of Western Gas Partners, LP — (Continued)
 
Credit carryforwards, which are available for utilization on future income tax returns, are as follows:
 
                 
    December 31,
  Statutory
    2009   Expiration
    (In thousands)    
 
State credit
  $ 599       2026  
 
8.   CONCENTRATION OF CREDIT RISK
 
Anadarko was the only customer from whom revenues exceeded 10% of the Partnership’s consolidated revenues for the years ended December 31, 2009, 2008 and 2007. The percentage of revenues from Anadarko and the Partnership’s other customers are as follows:
 
                         
    Year Ended December 31,
    2009   2008   2007
 
Anadarko
    87 %     87 %     92 %
Other
    13 %     13 %     8 %
                         
Total
    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
    December 31,
    December 31,
 
    Useful Life     2009     2008  
    (Dollars in thousands)  
 
Land
    n/a     $ 354     $ 354  
Gathering systems
    15 to 25 years       820,425       697,908  
Pipeline and equipment
    30 to 34.5 years       86,617       85,598  
Assets under construction
    n/a       6,323       76,275  
Other
    3 to 25 years       1,719       1,645  
                         
Total property, plant and equipment
            915,438       861,780  
Accumulated depreciation
            214,942       175,427  
                         
Total net property, plant and equipment
          $ 700,496     $ 686,353  
                         
 
The cost of property classified as “Assets under construction” is excluded from capitalized costs being depreciated. This amount represents property elements that are works-in-progress and not yet suitable to be placed into productive service as of the balance sheet date.
 
Impairment.  Prior to the Partnership’s acquisition of the Powder River assets, during the year ended December 31, 2008, a $9.4 million impairment was recognized related to the suspension of operations of a plant 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.


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Table of Contents

 
Notes to the consolidated financial statements of Western Gas Partners, LP — (Continued)
 
10.   ASSET RETIREMENT OBLIGATIONS
 
The following table provides a summary of changes in asset retirement obligations. Revisions in estimates for the periods presented relate primarily to revisions of current cost estimates, inflation rates and/or discount rates.
 
                         
    Year Ended December 31,  
    2009     2008     2007  
    (In thousands)  
 
Carrying amount of asset retirement obligations at beginning of period
  $ 9,947     $ 10,534     $ 9,968  
Additions
    1,272       1,248       102  
Accretion expense
    615       814       604  
Revisions in estimates
    (7 )     (2,649 )     (140 )
                         
Carrying amount of asset retirement obligations at end of period
  $ 11,827     $ 9,947     $ 10,534  
                         
 
11.   DEBT AND INTEREST EXPENSE
 
The Partnership’s outstanding debt as of December 31, 2009 and 2008 consists of its $175.0 million note payable to Anadarko due in 2013 issued in connection with the Powder River acquisition.
 
Term loan agreements
 
Five-year term loan.  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.
 
The provisions of the five-year agreement 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. The fair value of the Partnership’s debt under the five-year term loan agreement approximate the carrying value at December 31, 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.
 
Three-year term loan.  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 and the Partnership repaid the three-year term loan and accrued interest on October 30, 2009.
 
Credit facilities
 
Revolving credit facility.  In October 2009, the Partnership entered into a three-year senior unsecured revolving credit facility with a group of banks (the “revolving credit facility”). The aggregate initial commitments of the lenders under the revolving credit facility are $350.0 million and are expandable to a maximum of $450.0 million. As of December 31, 2009, the full $350.0 million was available for borrowing by the Partnership. The revolving credit facility matures on October 29, 2012 and bears interest at LIBOR, plus applicable margins ranging from 2.375% to 3.250%. The Partnership is required to pay a quarterly facility fee ranging from 0.375% to 0.750% of the commitment amount (whether used or unused), based upon the Partnership’s consolidated leverage ratio, as defined in the revolving credit facility. The facility fee rate was 0.50% at December 31, 2009. On January 29, 2010, the Partnership borrowed $210.0 million under the revolving credit facility in connection with the Granger acquisition. See Note 13 — Subsequent Events — Granger Acquisition.


F-28


Table of Contents

 
Notes to the consolidated financial statements of Western Gas Partners, LP — (Continued)
 
The revolving credit facility contains various covenants that limit, among other things, the Partnership’s, and certain of the Partnership’s subsidiaries’, ability to incur additional 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 revolving 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 revolving credit facility are unconditionally guaranteed by the Partnership’s wholly owned subsidiaries. The subsidiary guarantees will terminate on the Investment Grade Rating Date.
 
Working capital facility.  In May 2008, the Partnership entered into a two-year $30.0 million working capital facility with Anadarko as the lender. 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 below. 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. At December 31, 2009, no borrowings were outstanding under the working capital facility.
 
Anadarko credit facility.  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. 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 December 31, 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 December 31, 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 certain of Anadarko’s credit and lease agreements, the Partnership and Anadarko are required to comply with certain covenants, including a financial covenant that requires Anadarko to maintain a debt-to-capitalization ratio of 65% or less. 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. As of December 31, 2009, the full $100.0 million was available for borrowing by the Partnership.
 
At December 31, 2009, the Partnership was in compliance with all covenants under the five-year term loan agreement, the revolving credit facility, the working capital facility and Anadarko’s credit facility and Anadarko was in compliance with all covenants under its $1.3 billion credit facility.


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Notes to the consolidated financial statements of Western Gas Partners, LP — (Continued)
 
Interest income (expense), net
 
The following table summarizes the amounts included in interest income (expense), net.
 
                         
    Year Ended December 31,  
    2009     2008     2007  
    (In thousands)  
 
Affiliate interest income (expense)
                       
Interest income on note receivable from Anadarko
  $ 16,900     $ 10,703     $  
Interest (expense) on notes payable to Anadarko
    (8,953 )     (253 )      
Interest income (expense), net on intercompany balances
          (1,148 )     (7,805 )
Credit facility commitment fees — affiliates
    (143 )     (111 )      
                         
Interest income (expenses), net — affiliates
    7,804       9,191       (7,805 )
Third-party interest expense and fees on credit facility
    (859 )            
                         
Interest income (expense), net
  $ 6,945     $ 9,191     $ (7,805 )
                         
 
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.
 
Litigation and legal proceedings.  From time to time, the Partnership is involved in legal, tax, regulatory and other proceedings in various forums regarding performance, contracts and other matters that arise in the ordinary course of business. Management is not aware of any such proceeding for which a final disposition could have a material adverse effect on the Partnership’s results of operations, cash flows or financial position.
 
Lease commitments.  Anadarko, on behalf of the Partnership, formerly leased certain compression equipment used exclusively by the Partnership. As a result of lease modifications in October 2008, Anadarko became the owner of this compression equipment and contributed the equipment to the Partnership, effectively terminating the lease. Rent expense associated with the compression equipment was approximately $1.0 million for the year ended December 31, 2008. As of December 31, 2009, the Partnership does not have significant non-cancelable lease commitments.
 
Anadarko leases office space used by the Partnership from a third party. The office lease will expire on January 23, 2012 and there is no purchase option at the termination of the lease. Rent expense associated with the office lease was approximately $211,000 and $80,000 for the year ended December 31, 2009 and 2008, respectively. The amounts in the table below represent existing contractual lease obligations for the office lease as of December 31, 2009 that may be assigned or otherwise charged to the Partnership (in thousands).
 
         
    Minimum Rental
 
    Payments  
 
2010
  $ 145  
2011
    147  
2012
    5  
2013
     
2014
     
         
Total
  $ 297  
         
 
13.   SUBSEQUENT EVENTS
 
Distributions.  On January 21, 2010, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.33 per unit, or $21.4 million in aggregate. The cash distribution was paid on February 12, 2010 to unitholders of record at the close of business on February 1, 2010.


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Notes to the consolidated financial statements of Western Gas Partners, LP — (Continued)
 
Granger acquisition.  On January 29, 2010, the Partnership acquired Anadarko’s entire 100% ownership interest in the following assets located in Southwestern Wyoming: (i) the Granger gathering system with related compressors and other facilities, and (ii) the Granger complex, consisting of two cryogenic trains, two refrigeration trains, an NGLs fractionation facility and ancillary equipment. These assets are referred to collectively as the “Granger assets” and the acquisition is referred to as the “Granger acquisition.” The Granger acquisition was financed primarily with a $210.0 million draw on the Partnership’s revolving credit facility plus cash on hand, as well as through the issuance of 620,689 common units to Anadarko and 12,667 general partner units to the Partnership’s general partner. In connection with the Granger acquisition, the Partnership increased the cap under the omnibus agreement to $8.3 million for the year ended December 31, 2010.
 
In connection with the Granger acquisition, the Partnership also entered into five-year commodity price swap agreements with Anadarko effective January 1, 2010 to mitigate exposure to commodity price volatility that would otherwise be present as a result of the Partnership’s acquisition of the Granger system. Specifically, the commodity price swap agreements fix the margin the Partnership will realize under both keep-whole and percentage-of-proceeds contracts applicable to natural gas processing activities at the Granger system. 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 actual throughput subject to keep-whole or percentage-of-proceeds contracts at the Granger system. Because the notional volumes are not fixed, the commodity price swap agreements do not satisfy the definition of a derivative financial instrument. The Partnership will recognize gains and losses on the commodity price swap agreements in the period in which the associated revenues are recognized. Below is a summary of the fixed prices on the Partnership’s commodity price swap agreements for the Granger system.
 
                                         
    Year Ended December 31,
    2010   2011   2012   2013   2014
    (Per barrel)
 
Ethane
  $ 28.85     $ 29.31     $ 29.78     $ 30.10     $ 30.53  
Propane
  $ 48.76     $ 50.07     $ 50.93     $ 51.56     $ 52.37  
Iso butane
  $ 64.07     $ 66.03     $ 67.22     $ 68.11     $ 69.23  
Normal butane
  $ 60.03     $ 61.82     $ 62.92     $ 63.74     $ 64.78  
Natural gasoline
  $ 73.62     $ 75.99     $ 77.37     $ 78.42     $ 79.74  
Condensate
  $ 72.25     $ 75.33     $ 76.85     $ 78.07     $ 79.56  
                                         
                                         
    (Per MMBtu)
 
Natural gas
  $ 5.53     $ 5.94     $ 5.97     $ 6.09     $ 6.20  
 
14.   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 each of the years in the two-year period ended December 31, 2009 and as of December 31, 2009 and December 31, 2008. Western Gas Partners, LP did not hold an interest in WGR Operating and its subsidiaries prior to the Partnership’s initial public offering in May 2008; thus financial information for the year ended December 31, 2007 is not presented. The condensed consolidating financial information should be read in conjunction with the Partnership’s accompanying consolidated financial statements and related notes.


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Notes to the consolidated financial statements of Western Gas Partners, LP — (Continued)
 
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.
 
Statement of Income
 
                                         
    Year Ended December 31, 2009  
    Western Gas
          Non-
             
    Partners,
    Guarantor
    Guarantor
             
    LP     Subsidiaries     Subsidiary     Eliminations     Consolidated  
    (In thousands)  
 
Revenues
  $ 4,103     $ 199,009     $ 42,007     $     $ 245,119  
Operating expenses
    18,063       125,348       21,078             164,489  
                                         
Operating income (loss)
    (13,960 )     73,661       20,929             80,630  
Interest income, net
    6,928       17                   6,945  
Other income, net
    32             10             42  
Equity income from consolidated subsidiaries
    78,408       4,898             (83,306 )      
                                         
Income before income taxes
    71,408       78,576       20,939       (83,306 )     87,617  
Income tax expense
          12                   12  
                                         
Net income
    71,408       78,564       20,939       (83,306 )     87,605  
Net income attributable to noncontrolling interests
          10,260                   10,260  
                                         
Net income attributable to Western Gas Partners, LP
  $ 71,408     $ 68,304     $ 20,939     $ (83,306 )   $ 77,345  
                                         
 
Statement of Income
 
                                         
    Year Ended December 31, 2008  
    Western Gas
          Non-
             
    Partners,
    Guarantor
    Guarantor
             
    LP     Subsidiaries     Subsidiary     Eliminations     Consolidated  
    (In thousands)  
 
Revenues
  $     $ 311,942     $ 32,564     $     $ 344,506  
Operating expenses
    9,124       232,854       16,361             258,339  
                                         
Operating income (loss)
    (9,124 )     79,088       16,203             86,167  
Interest income (expense), net
    10,323       (1,132 )                 9,191  
Other income, net
    139       6       51             196  
Equity income from consolidated subsidiaries
    41,871                   (41,871 )      
                                         
Income before income taxes
    43,209       77,962       16,254       (41,871 )     95,554  
Income tax expense
          13,872       116             13,988  
                                         
Net income
    43,209       64,090       16,138       (41,871 )     81,566  
Net income attributable to noncontrolling interests
          7,908                   7,908  
                                         
Net income attributable to Western Gas Partners, LP
  $ 43,209     $ 56,182     $ 16,138     $ (41,871 )   $ 73,658  
                                         


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Notes to the consolidated financial statements of Western Gas Partners, LP — (Continued)
 
Balance Sheet
 
                                         
    December 31, 2009  
    Western Gas
          Non-
             
    Partners,
    Guarantor
    Guarantor
             
    LP     Subsidiaries     Subsidiary     Eliminations     Consolidated  
    (In thousands)  
 
Current assets
  $ 64,001     $ 58,371     $ 9,425     $ (51,934 )   $ 79,863  
Note receivable — Anadarko
    260,000                         260,000  
Investment in consolidated subsidiaries
    497,997       98,959             (596,956 )      
Net property, plant and equipment
    219       516,071       184,206             700,496  
Other long-term assets
    2,974       40,896                   43,870  
                                         
Total assets
  $ 825,191     $ 714,297     $ 193,631     $ (648,890 )   $ 1,084,229  
                                         
Current liabilities
  $ 52,545     $ 15,973     $ 1,529     $ (51,934 )   $ 18,113  
Note payable — Anadarko
    175,000                         175,000  
Other long-term liabilities
          10,446       2,221             12,667  
                                         
Total liabilities
    227,545       26,419       3,750       (51,934 )     205,780  
Partners’ capital
    597,646       596,956       189,881       (596,956 )     787,527  
Noncontrolling interests
          90,922                   90,922  
                                         
Total liabilities, equity and Partners’ capital
  $ 825,191     $ 714,297     $ 193,631     $ (648,890 )   $ 1,084,229  
                                         
 
Balance Sheet
 
                                         
    December 31, 2008  
    Western Gas
          Non-
             
    Partners,
    Guarantor
    Guarantor
             
    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
    523,756                   (523,756 )      
Net property, plant and equipment
    273       527,790       158,290             686,353  
Other long-term assets
    628       39,019                   39,647  
                                         
Total assets
  $ 818,431     $ 616,016     $ 161,289     $ (562,581 )   $ 1,033,155  
                                         
Current liabilities
  $ 51,655     $ 16,004     $ 26,093     $ (51,317 )   $ 42,435  
Note payable — Anadarko
    175,000                         175,000  
Other long-term liabilities
          10,240       855             11,095  
                                         
Total liabilities
    226,655       26,244       26,948       (51,317 )     228,530  
Partners’ capital and parent net investment
    591,776       523,756       134,341       (511,264 )     738,609  
Noncontrolling interests
          66,016                   66,016  
                                         
Total liabilities, equity and Partners’ capital
  $ 818,431     $ 616,016     $ 161,289     $ (562,581 )   $ 1,033,155  
                                         


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Notes to the consolidated financial statements of Western Gas Partners, LP — (Continued)
 
Statement of Cash Flows
 
                                         
    Year Ended December 31, 2009  
    Western Gas
    Guarantor
    Non-Guarantor
             
    Partners, LP     Subsidiaries     Subsidiary     Eliminations     Consolidated  
    (In thousands)  
 
Cash flows from operating activities
                                       
Net income
  $ 71,408     $ 78,564     $ 20,939     $ (83,306 )   $ 87,605  
Adjustments to reconcile net income to net cash provided by operating activities:
                                       
Equity income from consolidated subsidiaries
    (78,408 )     (4,898 )           83,306        
Depreciation, amortization and impairment
    54       35,507       4,504             40,065  
Change in other items, net
    2,112       (13,236 )     (15,081 )     12,493       (13,712 )
                                         
Net cash provided by (used in) operating activities
    (4,834 )     95,937       10,362       12,493       113,958  
Net cash used in investing activities
          (124,629 )     (39,378 )           (164,007 )
Net cash provided by financing activities
    33,157       28,692       34,603       (12,493 )     83,959  
                                         
Net increase in cash and cash equivalents
  $ 28,323     $     $ 5,587     $     $ 33,910  
Cash and cash equivalents at beginning of period
    33,307             2,767             36,074  
                                         
Cash and cash equivalents at end of period
  $ 61,630     $     $ 8,354     $     $ 69,984  
                                         
 
Statement of Cash Flows
 
                                         
    Year Ended December 31, 2008  
    Western Gas
    Guarantor
    Non-Guarantor
             
    Partners, LP     Subsidiaries     Subsidiary     Eliminations     Consolidated  
    (In thousands)  
 
Cash flows from operating activities
                                       
Net income
  $ 43,209     $ 64,090     $ 16,138     $ (41,871 )   $ 81,566  
Adjustments to reconcile net income to
net cash provided by operating activities:
                                       
Equity income from consolidated subsidiaries
    (41,871 )                 41,871        
Depreciation, amortization and impairment
    39       42,349       3,008             45,396  
Change in other items, net
    51,512       (35,555 )     15,004       (12,493 )     18,468  
                                         
Net cash provided by operating activities
    52,889       70,884       34,150       (12,493 )     145,430  
Net cash used in investing activities
    (435,312 )     (53,346 )     (53,928 )           (542,586 )
Net cash provided by (used in) financing activities
    415,730       (17,538 )     22,545       12,493       433,230  
                                         
Net increase in cash and cash equivalents
  $ 33,307     $     $ 2,767     $     $ 36,074  
Cash and cash equivalents at beginning of period
                             
                                         
Cash and cash equivalents at end of period
  $ 33,307     $     $ 2,767     $     $ 36,074  
                                         


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WESTERN GAS PARTNERS, LP
 
SUPPLEMENTAL QUARTERLY INFORMATION
(Unaudited)
 
The following table presents a summary of the Partnership’s operating results by quarter for the years ended December 31, 2009 and 2008. Financial information for 2008 has been revised to include results attributable to the Chipeta assets and for a prior period adjustment. See Note 1 — Description of Business and Basis of Presentation — Offerings and acquisitions.
 
                                 
    First
  Second
  Third
  Fourth
    Quarter   Quarter   Quarter   Quarter
    (In thousands, except per unit amounts)
    (Unaudited)
 
2009
                               
Revenues
  $ 59,613     $ 62,052     $ 60,997     $ 62,457  
Operating income
  $ 18,429     $ 22,925     $ 18,294     $ 20,982  
Net income attributable to Western Gas Partners, LP
  $ 19,211     $ 21,807     $ 17,049     $ 19,278  
Net income per limited partner unit(1)
  $ 0.30     $ 0.32     $ 0.30     $ 0.33  
2008
                               
Revenues
  $ 85,816     $ 98,682     $ 94,582     $ 65,426  
Operating income
  $ 27,382     $ 21,691     $ 14,973     $ 22,121  
Net income attributable to Western Gas Partners, LP
  $ 16,122     $ 17,600     $ 17,949     $ 21,987  
Net income per limited partner unit(1)
        $ 0.15     $ 0.32     $ 0.30  
 
 
(1) Includes net income attributable to the Partnership assets subsequent to the Partnership’s acquisition of the Partnership assets.
 
Cost of product expense for the fourth quarter of 2009 includes a $2.5 million out-of-period adjustment attributable to the Hilight system in which a reduction in cost of product expense related to the period from January 2008 to September 2009 was recorded in the fourth quarter of 2009. Of the adjustment, approximately $317,000, $149,000 and $152,000 is attributable to the first, second and third quarters of 2009, respectively, and approximately $364,000, ($12,000), $796,000 and $692,000 is attributable to the first, second, third and fourth quarters of 2008, respectively. Approximately $1.5 million of the adjustment attributable to 2008 is for periods prior to the Partnership’s acquisition of the asset and has no impact on the Partnership’s cash flows. The adjustment and out-of-period correction resulted in overstating earnings per limited partner unit for the year ended December 31, 2009 by $0.03 and understating earnings per limited partner unit by $0.01 for the year ended December 31, 2008. Management determined the adjustments were not material to the Partnership’s financial statements for the years ended December 31, 2009 or 2008 or to the Partnership’s interim financial statements and, accordingly, restatement of its previously reported interim or annual financials statements was not necessary.


F-35