The following discussion analyzes our financial condition and results of operations and should be read in conjunction with the consolidated financial statements and the notes to unaudited consolidated financial statements, which are included in this report in Part I, Item 1 of this Form 10-Q, as well as our historical consolidated financial statements, and the notes thereto, included in Item 8 of our annual report on Form 10-K. Unless the context clearly indicates otherwise, references in this report to the "Partnership," "we," "our," "us" or like terms refer to Western Gas Partners, LP and its subsidiaries. "Anadarko" refers to Anadarko Petroleum Corporation (NYSE: APC) and its consolidated subsidiaries, excluding the Partnership. "Affiliates" refers to wholly owned and partially owned subsidiaries of Anadarko, excluding the Partnership. We have made in this report, and may from time to time otherwise make in other public filings, press releases and discussions by Partnership management, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 concerning our operations, economic performance and financial condition. These statements can be identified by the use of forward-looking terminology including "may," "believe," "expect," "anticipate," "estimate," "continue," or other similar words. These statements discuss future expectations, contain projections of results of operations or financial condition or include other "forward-looking" information. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct.
These forward-looking statements involve risks and uncertainties. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:
• our assumptions about energy markets;

• future gathering, treating and processing volumes and pipeline throughput, including Anadarko's production, which is gathered or transported through our assets;

• operating results;

• competitive conditions;

• technology;

• the availability of capital resources for capital expenditures and other contractual obligations;

• the supply of, demand for, and the price of oil, natural gas, NGLs and other products or services;

• the weather;

• inflation;

• the availability of goods and services;

• general economic conditions, either internationally or nationally or in the jurisdictions in which we are doing business;

• legislative or regulatory changes, including changes in environmental regulation, environmental risks, regulations by the Federal Energy Regulatory Commission or FERC and liability under federal and state environmental laws and regulations;

• our ability to access the capital markets;

• our ability to access credit, including under Anadarko's $1.3 billion credit facility;

• our ability to maintain and/or obtain rights to operate our assets on land owned by third parties;

• our ability to acquire assets on acceptable terms;

• non-payment or non-performance of Anadarko or other significant customers, including under our gathering, processing and transportation agreements and our $260.0 million note receivable from Anadarko; and

• other factors discussed below and elsewhere in Item 1A-Risk Factors and in Item 7-Management's Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies and Estimates included in our annual report on Form 10-K filed with the Securities and Exchange Commission ("SEC") on March 13, 2009, this Form 10-Q and in our other public filings and press releases.

The risk factors and other factors noted throughout or incorporated by reference in this report could cause our actual results to differ materially from those contained in any forward-looking statement. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
EXECUTIVE SUMMARY We are a growth-oriented 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.
The current commodity price environment, particularly for natural gas, has resulted in lower drilling activity throughout the areas in which we operate. Our throughput decreased approximately 6% for the three months ended June 30, 2009 compared to the three months ended June 30, 2008 and decreased approximately 4% for the six months ended June 30, 2009 compared to the six months ended June 30, 2008. These volume decreases are primarily due to the aforementioned reduced drilling activity, which limits our ability to offset lower throughput from natural production declines by connecting new wells to our systems. The predominantly fee-based and fixed-price structure of our contracts mitigated the impact of changes in commodity prices on our gross margin. We also benefited from our geographically diverse asset mix as reduced throughput on our Dew, Pinnacle and Hugoton systems was offset by higher throughput on our Haley and Fort Union systems.
INITIAL PUBLIC OFFERING On May 14, 2008, we closed our initial public offering of 18,750,000 common units at a price of $16.50 per unit. On June 11, 2008, we issued an additional 2,060,875 common units to the public pursuant to the partial exercise of the underwriters' over-allotment option granted in connection with our initial public offering. Concurrent with the initial closing of the offering, Anadarko contributed the assets and liabilities of Anadarko Gathering Company LLC, or AGC, Pinnacle Gas Treating LLC, or PGT, and MIGC LLC, or MIGC, to us in exchange for a 2.0% general partner interest in the Partnership, 5,725,431 common units, 26,536,306 subordinated units and 100% of the IDRs. We refer to AGC, PGT and MIGC as our initial assets.
POWDER RIVER ACQUISITION On December 19, 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.
PARTNERSHIP AGREEMENT AMENDMENT On April 15, 2009, after receiving the unanimous approval of the special committee of the board of directors of Western Gas Holdings, LLC, the general partner of the Partnership, the general partner's board of directors unanimously approved an amendment (the "Amendment") to the Partnership's First Amended and Restated Agreement of Limited Partnership, effective on the date of approval. The purpose of the Amendment was to ensure that the Partnership's common unitholders maintain, to the maximum extent possible, their existing share of allocable tax deductions throughout the subordination period. Absent this amendment, it would have been possible, as a result of equity issuances at a price less than the initial

public offering price during the subordination period, that the common unitholders' allocable share of tax deductions would be significantly diminished.
The foregoing general description of the Amendment is not complete and is qualified in its entirety by reference to the full and complete terms of the Amendment, which is attached to the Form 8-K, filed with the SEC on April 20, 2009, and the partnership agreement, which is incorporated herein.
HOW WE EVALUATE OUR OPERATIONS Our management relies on certain financial and operational metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include (1) throughput volumes,
(2) operating expenses, (3) Adjusted EBITDA and (4) gross margin. Throughput volumes In order to maintain or increase throughput volumes 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 which will be dedicated to our systems, our ability to secure volumes from new wells drilled on non-dedicated acreage and our ability to attract natural gas volumes currently gathered, processed or treated by our competitors. To maintain and increase throughput volumes on our MIGC system, we must continue to contract capacity to shippers, including producers and marketers, for transportation of their natural gas. Although firm capacity on the MIGC system is fully subscribed, we nevertheless monitor producer and marketing activities in the area served by our transportation system to identify new opportunities to attempt to maintain a full subscription of MIGC's firm capacity. Operating expenses We analyze operating expenses to evaluate our performance. Operating expenses include all amounts accrued or paid for the operation of our systems, including cost of product, utilities, field labor, measurement and analysis and other disbursements. The primary components of our operating expenses that we evaluate include operation and maintenance expenses, cost of product expenses and general and administrative expenses. Certain of our operating expenses are paid to affiliates; however, 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 those expenses necessary for generating our affiliate revenues and our third-party expenses are not those expenses necessary for generating our third-party revenues. Operation and maintenance expenses include, among other things, direct labor, insurance, repair and maintenance, contract services, utility costs and services provided to us or on our behalf. For periods commencing on and subsequent to May 14, 2008, with respect to our initial assets, and for periods commencing on and subsequent to December 1, 2008, with respect to the Powder River assets, certain of these expenses are incurred under and governed by our services and secondment agreement with Anadarko. Cost of product expenses include (i) costs associated with the purchase of natural gas and NGLs pursuant to our percent-of-proceeds processing contracts,
(ii) costs associated with the valuation of our gas imbalances, (iii) costs associated with our obligations under certain contracts to redeliver a volume of natural gas to shippers which is thermally equivalent to condensate retained by us and sold to third parties and (iv) costs associated with our fuel-tracking mechanism, which tracks the difference between actual fuel usage and loss and amounts recovered for estimated fuel usage and loss under our contracts. These expenses are subject to variability, although our exposure to commodity price risk attributable to our percent-of-proceeds contracts is mitigated through our commodity price swap agreements with Anadarko. General and administrative expenses for periods prior to May 14, 2008, with respect to our initial assets, and for periods prior to December 1, 2008, with respect to the Powder River 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. Subsequent to May 14, 2008, with respect to our initial assets, and subsequent to December 1, 2008, with respect to the Powder River assets, Anadarko is no longer compensated for corporate services through a management services fee. Instead, we reimburse Anadarko for general and administrative expenses it incurs on our behalf pursuant to the terms of our omnibus agreement with Anadarko. Amounts

required to be reimbursed to Anadarko under the omnibus agreement include those expenses attributable to our status as a publicly traded partnership, such as:
• expenses associated with annual and quarterly reporting;

• tax return and Schedule K-1 preparation and distribution expenses;

• expenses associated with listing on the New York Stock Exchange; and

• independent auditor fees, legal expenses, investor relations expenses, director fees, and registrar and transfer agent fees.

In addition to the above, we are required pursuant to the terms of the omnibus agreement with Anadarko to reimburse Anadarko for allocable general and administrative expenses. As of June 30, 2009, the amount required to be reimbursed by us to Anadarko for allocated general and administrative expenses is capped at $6.65 million for the year ended December 31, 2009, 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. After December 31, 2009, our general partner will determine the general and administrative expenses to be reimbursed by us in accordance with our partnership agreement. The cap contained in the omnibus agreement does not apply to incremental general and administrative expenses incurred by or allocated to us as a result of being a separate publicly traded entity. We currently expect public company expenses not subject to the cap contained in the omnibus agreement to be approximately $6.4 million per year, excluding equity-based compensation and transaction costs related to the Chipeta acquisition and any future acquisitions. Adjusted EBITDA
We define Adjusted EBITDA as net income (loss), plus distributions from equity investee, non-cash equity-based compensation expense, interest expense, income tax expense, depreciation and amortization, less income from equity investments, interest income, income tax benefit and other income (expense). We changed our definition of Adjusted EBITDA from the definition used in the prior year. Adjusted EBITDA has been calculated using the revised definition for all periods presented. We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations and that Adjusted EBITDA is a widely accepted financial indicator of a company's ability to incur and service debt, fund capital expenditures and make distributions. Adjusted EBITDA is a supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, use to assess, among other measures:
• our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to financing methods, capital structure or historical cost basis;

• the ability of our assets to generate cash flow to make distributions; and

• the viability of acquisitions and capital expenditure projects and the returns on investment of various investment opportunities.

The following tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measures of net income and net cash provided by operating activities (in thousands):

                                                    Three Months Ended              Six Months Ended
                                                         June 30,                       June 30,
                                                   2009           2008(1)         2009           2008(1)

Reconciliation of Adjusted EBITDA to net
income
Adjusted EBITDA                                 $   24,899        $ 25,010      $ 47,950        $  59,230
Less:
Distributions from equity investee                   1,459             844         2,570            2,251
Non-cash equity-based compensation expense             942             261         1,788              261
Interest expense, net - affiliates                   1,786             166         3,571            1,955
Income tax expense                                      55           4,168             -           12,635
Depreciation and amortization                        8,752           8,204        17,373           15,986
Add:
Equity income, net                                   1,985           1,959         3,535            2,301
Interest income from note - affiliate                4,225           2,226         8,450            2,226
Other income, net                                        9              27            14               31
Income tax benefit                                       -               -           435                -


Net income                                      $   18,124        $ 15,579      $ 35,082        $  30,700


Reconciliation of Adjusted EBITDA to Net Cash
Provided by Operating Activities
Adjusted EBITDA                                 $   24,899        $ 25,010      $ 47,950        $  59,230
Interest income, net - affiliates                    2,439           2,060         4,879              271
Non-cash equity-based compensation expense            (942 )          (261 )      (1,788 )           (261 )
Current income tax expense                             (55 )        (4,657 )        (119 )        (11,021 )
Other income (expense), net                              9              27            14               31
Distributions from equity investee less than
equity income, net                                     526           1,115           965               50
Changes in operating working capital:
Accounts receivable and natural gas
imbalances                                           7,682          (1,975 )       1,151             (603 )
Accounts payable, accrued liabilities and
natural gas imbalance payable                          490             360          (327 )            964
Other, including changes in non-current
assets and liabilities                                 (12 )        (2,373 )        (124 )         (2,031 )


Net cash provided by operating activities       $   35,036        $ 19,306      $ 52,601        $  46,630

(1) Financial information for 2008 has been revised to include results attributable to the Powder River assets. See Note 1-Description of Business and Basis of Presentation-Powder River acquisition of the notes to the unaudited consolidated financial statements in Part I, Item 1 of this Form 10-Q.

Gross margin
We define gross margin as total revenues less cost of product. We changed our definition of gross margin from the definition used in the prior year. Gross margin has been presented using the revised definition for all periods presented. We consider gross margin to provide information useful in assessing our results of operations, our ability to internally fund capital expenditures and to service or incur additional debt.
ITEMS AFFECTING THE COMPARABILITY OF OUR FINANCIAL RESULTS Our historical results of operations and cash flows for the periods presented may not be comparable to future or historic results of operations or cash flows for the reasons described below:
• We anticipate incurring approximately $6.4 million per year of public company expenses not subject to the cap contained in the omnibus agreement, excluding equity-based compensation expense and transaction costs related to the Chipeta acquisition and any future acquisitions. General and administrative expenses such as these are reflected in our historical consolidated financial statements for only those periods including and subsequent to our initial public offering in May 2008.

• We anticipate incurring up to $6.9 million in general and administrative expenses annually to be charged by Anadarko to us pursuant to the omnibus agreement, which became effective in connection with our initial public offering. This amount is expected to be greater than amounts allocated to us by Anadarko for the management services fee reflected in our historical consolidated financial statements for periods prior to May 14, 2008, with respect to our initial assets, and prior to December 1, 2008, with respect to the Powder River assets.

• 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 because these transactions related to Anadarko and were funded by Anadarko's working capital. Effective on May 14, 2008, with respect to our initial assets, and December 19, 2008, with respect to the Powder River assets, all affiliate and third-party transactions are funded by our working capital. This impacts the comparability of our cash flow statements, working capital analysis and liquidity discussion.

• Prior to May 14, 2008, with respect to our initial assets, and prior to December 19, 2008, with respect to the Powder River assets, 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 and the Powder River acquisition; 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, and prior to and including December 19, 2008, with respect to the Powder River assets.

• Concurrent with the closing of our initial public offering, we loaned $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%. For periods including and subsequent to May 14, 2008, interest income attributable to the note is reflected in our consolidated financial statements so long as the note remains outstanding.

• In connection with the Powder River acquisition, we entered into a five-year, $175.0 million term loan agreement with Anadarko, under which we pay interest at a fixed rate of 4.0% for the first two years and a floating rate of interest at three-month LIBOR plus 150 basis points for the final three years. For periods including and subsequent to December 19, 2008, interest expense on the $175.0 million note payable to Anadarko will be incurred so long as the loan remains outstanding.

• Our financial results for historical periods reflect commodity price changes, which, in turn, impact the financial results derived from our percent-of-proceeds processing contracts. Effective January 1, 2009, commodity price risk associated with our percent-of-proceeds processing contracts has been mitigated through our fixed-price commodity price swap agreements with Anadarko that extend through December 31, 2010, with an option to extend through 2013. See Note 5-Transactions with Affiliates of the notes to the unaudited consolidated financial statements included in

• We are generally not subject to federal or state income tax. Federal and state income tax expense was recorded for periods ending prior to and including May 14, 2008, with respect to income generated by our initial assets, and prior to and including December 19, 2008, with respect to income generated by the Powder River assets. For periods subsequent to May 14, 2008, with respect to income generated by our initial assets, and subsequent to December 19, 2008, with respect to income generated by the Powder River assets, we are only subject to Texas margin tax; therefore, income tax expense attributable to Texas margin tax will continue to be recognized in our consolidated financial statements. We are required to make payments to Anadarko pursuant to a tax sharing arrangement for our share of Texas margin tax included in any combined or consolidated returns of Anadarko.

• We have made cash distributions to our unitholders and our general partner at an initial distribution rate of $0.30 per unit per full quarter ($1.20 per unit on an annualized basis) commencing with the quarter ended September 30, 2008. We paid cash distributions to our unitholders of $0.60 per unit, or $34.1 million in aggregate, during the six months ended June 30, 2009. We did not make any such distributions during the six months ended June 30, 2008.

• We expect that we will rely upon external financing sources, including commercial bank borrowings, long-term debt and equity issuances, to fund our acquisitions and expansion capital expenditures. Historically, we largely relied on internally generated cash flows and capital contributions from Anadarko to satisfy our capital expenditure requirements.

• In connection with the closing of our initial public offering, our general partner adopted two new compensation plans; the Western Gas Partners, LP 2008 Long-Term Incentive Plan, or LTIP, and the Amended and Restated Western Gas Holdings, LLC Equity Incentive Plan, or the Incentive Plan. Phantom unit grants have been made under the LTIP and incentive unit grants have been made under the Incentive Plan. These grants result in equity-based compensation expense which is determined, in part, by reference to the fair value of equity compensation as of the date of grant. For periods ending prior to May 14, 2008, equity-based compensation expense attributable to the LTIP and Incentive Plan is not reflected in our historical consolidated financial statements as there were no outstanding equity grants under either plan. For periods including and subsequent to May 14, 2008, the Partnership's general and administrative expenses include equity-based compensation costs allocated by Anadarko to the Partnership for grants made under the LTIP and Incentive Plan as well as 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 therein for the periods to which such expense limit applies. Equity-based compensation granted under the Anadarko Incentive Plans does not impact our . . .