Exhibit 99.2

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 and NGLs 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 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, related throughput decreases were offset by throughput increases at the Chipeta plant and Fort Union system due to facility expansions. The total throughput attributable to Western Gas Partners, LP, for the year ended December 31, 2009, was approximately 1,460 MMcf/d, representing an approximate 1% 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 12,667 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 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, included the results attributable to the Powder River assets. The financial statements as presented herein have been further recast to reflect the results attributable to the Chipeta assets and the Granger assets as if the Partnership owned the 51% interest in Chipeta, the associated NGL pipeline and the Granger assets for all periods presented. The following tables present the impact to the consolidated statements of income attributable to the Chipeta assets and the Granger assets (in thousands):

1

	Partnership			Chipeta			Granger
	Historical			Acquisition			Acquisition		Combined
	Year Ended December 31, 2009
Revenues	$	245,119			n/a	(1)	$	126,104	$	371,223
Operating expenses		164,489			n/a			106,726		271,215
Operating income		80,630			n/a			19,378		100,008
Interest and other income, net		6,987			n/a			516		7,503
Income before income taxes		87,617			n/a			19,894		107,511
Income tax expense		12			n/a			6,963		6,975
Net income		87,605			n/a			12,931		100,536
Net income attributable to noncontrolling interests		10,260			n/a			—		10,260
Net income attributable to Western Gas Partners, LP	$	77,345			n/a		$	12,931	$	90,276
	Year Ended December 31, 2008
Revenues	$	311,648		$	32,858		$	235,444	$	579,950
Operating expenses		241,931			16,408			185,303		443,642
Operating income		69,717			16,450			50,141		136,308
Interest and other income, net		9,336			51			2,049		11,436
Income before income taxes		79,053			16,501			52,190		147,744
Income tax expense		13,777			211			18,267		32,255
Net income		65,276			16,290			33,923		115,489
Net income attributable to noncontrolling interests		—			7,908			—		7,908
Net income attributable to Western Gas Partners, LP	$	65,276		$	8,382		$	33,923	$	107,581
	Year Ended December 31, 2007
Revenues	$	261,493		$	—		$	201,662	$	463,155
Operating expenses		197,475			304			145,528		343,307
Operating income (loss)		64,018			(304	)		56,134		119,848
Interest and other expense, net		(7,820	)		—			1,618		(6,202	)
Income (loss) before income taxes		56,198			(304	)		57,752		113,646
Income tax expense (benefit)		19,540			(116	)		20,213		39,637
Net income (loss)		36,658			(188	)		37,539		74,009
Net loss attributable to noncontrolling interests		—			(92	)		—		(92	)
Net income attributable to Western Gas Partners, LP	$	36,658		$	(96	)	$	37,539	$	74,101

⁽¹⁾ The Partnership Historical information for 2009 includes the results attributable to the Chipeta acquisition since the results attributable to Chipeta were included in the amounts reported in the Partnership’s annual report on Form 10-K.

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 (i) to the business and operations of AGC and PGT from their inception through the closing date of our initial public offering and (ii) to Western Gas Partners, LP and its subsidiaries thereafter, combined with (a)  the business and operations of MIGC, the Powder River assets and the Granger assets since August 23, 2006 and (b) 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 the general partner, 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.

References to the “Partnership Assets” refer collectively to the initial assets, Powder River assets, Chipeta assets and Granger assets. Unless otherwise noted, references to “periods prior to our acquisition of the Partnership Assets” and similar phrases refer to periods prior to May 2008, with respect to the initial assets, periods prior to December 2008, with respect to the Powder River assets, periods prior to July 2009, with respect to the Chipeta assets, and periods prior to January 2010, with respect to the Granger assets. Unless otherwise noted, references to “periods subsequent to our acquisition of the Partnership Assets” and similar phrases refer to

2

periods including and subsequent to May 2008, with respect to the initial assets, periods including and subsequent to December 2008, with respect to the Powder River assets, periods including and subsequent to July 2009, with respect to the Chipeta assets, and periods including and subsequent to January 2010, with respect to the Granger assets.

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 88% of our total revenues and 74% 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 71% 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. Certain of our fee-based contracts contain keep-whole provisions.

Based on gross margin for the year ended December 31, 2009, approximately 24% 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 2% of our gross margin is attributable to drip condensate and approximately 3% 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, the Chipeta acquisition and the Granger 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

3

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 57 receipt points to our systems with average initial throughput of approximately 3.8 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 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 and the general partner on our behalf and allocations of general and administrative costs by Anadarko and the general partner 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 and the general partner incur 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, expense in excess of the omnibus cap, interest

4

expense, income tax expense, depreciation and amortization, less income from equity investments, interest income, income tax benefit and other income (expense).

We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations and that Adjusted EBITDA is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures and make distributions. Adjusted EBITDA is a supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, 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. 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 attributable to Western Gas Partners, LP. 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 attributable to Western Gas Partners, LP or net cash provided by operating activities. Adjusted EBITDA and distributable cash flow have important limitations as analytical tools because they exclude 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 their 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.

5

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 attributable to Western Gas Partners, LP:

	Year Ended December 31,
	2009(1)			2008(1)			2007(1)
	(in thousands)
Reconciliation of Adjusted EBITDA to net income attributable to Western Gas Partners, LP
Adjusted EBITDA	$	141,563		$	185,078		$	160,772
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			364			6,187
Income tax expense(2)		6,975			32,198			39,694
Depreciation and amortization (2)		48,883			45,048			43,443
Impairment		—			9,354			—
Other expense, net		—			—			15
Add:
Equity income, net		6,982			4,736			4,017
Interest income, net		17,404			11,604			—
Other income, net (2)		49			179			—
Net income attributable to Western Gas Partners, LP	$	90,276		$	107,581		$	74,101
Reconciliation of Adjusted EBITDA to net cash provided by operating activities
Adjusted EBITDA	$	141,563		$	185,078		$	160,772
Adjusted EBITDA attributable to noncontrolling interests		12,462			9,422			—
Interest income (expense), net		7,449			11,240			(6,187	)
Expenses in excess of omnibus cap		(842	)		—			—
Non-cash equity-based compensation expense		(3,580	)		(1,924	)		—
Current income tax expense		(8,641	)		(31,204	)		(30,654	)
Other income (expense), net		54			196			(15	)
Distributions from equity investee less than (in excess of) equity income, net		1,495			(392	)		2,668
Changes in assets and liabilities:
Accounts receivable and natural gas imbalances		3,342			(6,101	)		(4,327	)
Accounts payable and accrued expenses		(17,626	)		19,000			9,280
Other, including changes in non-current assets and liabilities		(144)			607			(1,331	)
Net cash provided by operating activities	$	135,532		$	185,922		$	130,206

(1)

Financial information for 2009 has been revised to include results attributable to the Granger assets and financial information for 2008 and 2007 has been revised to include results attributable to the Chipeta assets and the Granger assets. See Note 1—Description of Business and Basis of Presentation—Offerings and acquisitions of the notes to the consolidated financial statements under Item 8 of this annual report.

(2)

Includes the Partnership’s 51% share of depreciation and amortization, other income, net and income tax expense attributable to Chipeta.

6

	Year Ended
	December 31,
	2009(1)		2008(1)
	(in thousands)
Reconciliation of distributable cash flow to net income attributable to Western Gas Partners, LP
Distributable cash flow	$	128,014	$	173,838
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		—
Income tax expense (2)		6,975		32,198
Depreciation and amortization (2)		48,883		45,048
Impairments		—		9,354
Add:
Equity income, net		6,982		4,736
Cash paid for maintenance capital expenditures(2)		20,494		21,579
Interest income, net (non-cash settled)		504		901
Other income, net (2)		49		179
Net income attributable to Western Gas Partners, LP	$	90,276	$	107,581

(1)

Financial information for 2009 has been revised to include results attributable to the Granger assets and financial information for 2008 has been revised to include results attributable to the Granger assets and the Chipeta assets. See Note 1—Description of Business and Basis of Presentation—Offerings and acquisitions of the notes to the consolidated financial statements under Item 8 of this annual report.

(2)

Includes the Partnership’s 51% share of depreciation and amortization expense, other income, net, cash paid for maintenance capital expenditures and income tax expense attributable to Chipeta.

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 and the general partner perform 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 and the general partner 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 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 our acquisition of the Partnership Assets, except for Chipeta, we incurred interest expense or earned interest income on current intercompany balances with Anadarko related to such assets. These intercompany balances were extinguished through non-cash transactions in connection with the closing of our initial public offering, the Powder River acquisition, Anadarko’s initial contribution of assets to Chipeta and the Granger 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 our acquisition of the Partnership Assets, except for Chipeta, and for periods ending prior to June 1, 2008 (the date on which Anadarko initially contributed assets to Chipeta), with respect to Chipeta.

7

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 our acquisition of the Partnership Assets, except for Chipeta, all affiliate transactions related to such assets were net settled within our consolidated financial statements and were funded by Anadarko’s working capital. Effective on the date of our acquisition of the Partnership Assets, except for Chipeta, all affiliate and third-party transactions related to such assets 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 at the Hilight and Newcastle systems 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. Beginning on January 1, 2010, commodity price swap agreements were put in place to fix the margin we realize under both keep-whole and percentage-of-proceeds contracts applicable to natural gas processing activities at the Granger system. The commodity price swap arrangements for the Granger system expire in December 2014. See Note 6—Transactions with Affiliates and Note 13—Subsequent Events—Granger Acquisition of the notes to the consolidated financial statements included under Item 8 in this annual report.

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 our acquisition of the Partnerships Assets, except for Chipeta. For periods including and subsequent to our acquisition of the Partnerships Assets, except for Chipeta, 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. Income attributable to Chipeta 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. We are required to make payments to Anadarko pursuant to a tax sharing agreement 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

8

including and subsequent to May 14, 2008, the Partnership’s general and administrative expenses include equity-based compensation costs allocated by Anadarko and the general partner 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. The new fees were based on capital improvements and changes in our cost-of-service analysis. This increase was also 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.

Granger gas processing agreements. Effective October 1, 2009, contracts covering substantially all of the Granger assets’ affiliate throughput were converted from primarily keep-whole contracts into 10-year fee-based arrangements.

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 investors, which could limit our ability to raise funds, or increase the cost of

9

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 and the Granger system, consisted of 12 gathering systems with an aggregate throughput of approximately 1.9 Bcf/d, and 10 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.

10

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(1)		2008(1)		2007(1)
	(in thousands)
Revenues
Gathering, processing and transportation of natural gas	$	173,795	$	160,454	$	127,330
Natural gas, natural gas liquids and condensate sales		187,593		402,274		327,249
Equity income and other, net		9,835		17,222		8,576
Total revenues		371,223		579,950		463,155
Operating expenses (2)
Cost of product		124,913		294,451		226,828
Operation and maintenance		60,613		64,249		52,867
General and administrative		24,306		20,089		12,680
Property and other taxes		10,293		8,977		7,340
Depreciation and amortization		51,090		46,522		43,592
Impairment		—		9,354		—
Total operating expenses		271,215		443,642		343,307
Operating income		100,008		136,308		119,848
Interest income (expense), net		7,449		11,240		(6,187	)
Other income (expense), net		54		196		(15	)
Income before income taxes		107,511		147,744		113,646
Income tax expense		6,975		32,255		39,637
Net income		100,536		115,489		74,009
Net income (loss) attributable to noncontrolling interests		10,260		7,908		(92	)
Net income attributable to Western Gas Partners, LP	$	90,276	$	107,581	$	74,101
Gross margin(3)	$	246,310	$	285,499	$	236,327
Adjusted EBITDA(3)		141,563		185,078		160,772
Distributable cash flow(3)		128,014		173,838		n/a

(1)	Financial information for 2009 has been revised to include results attributable to the Granger assets and financial information for 2008 and 2007 has been revised to include results attributable to the Granger assets and the Chipeta assets. See Note 1—Description of Business and Basis of Presentation—Offerings and acquisitions 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 Operations 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. 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.

11

Executive Summary

Total revenues decreased by $208.7 million for the year ended December 31, 2009 and increased by $116.8 million for the year ended December 31, 2008. Gathering, processing and transportation revenues increased by $13.4 million; natural gas, NGL and condensate revenues decreased by $214.7 million and equity income and other revenues decreased by $7.4 million for the year ended December 31, 2009. Gathering, processing and transportation revenues increased by $33.1 million; natural gas, NGL and condensate revenues increased by $75.0 million and equity income and other revenues increased by $8.7 million for the year ended December 31, 2008.

Net income attributable to Western Gas Partners, LP decreased by $17.3 million for the year ended December 31, 2009, consisting of a $208.7 million decrease in revenues, a $3.8 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, substantially offset by a $172.4 million decrease in total operating expenses primarily due to an $169.5 million decrease in cost of product from lower volumes and prices and a $25.3 million decrease in income tax expense.

Net income attributable to Western Gas Partners, LP increased by $33.5 million for the year ended December 31, 2008 consisting of a $116.8 million increase in total revenues driven by gathering rate increases, increased processing volumes, increased condensate sales, and an increase in other revenues from changes in gas imbalance positions and gas prices; a $17.4 million increase in interest income, net and a $7.4 million decrease in income tax expense. These items are partially offset by a $67.6 million increase in cost of product expense primarily from higher volumes and prices, an $8.0 million increase in net income attributable to noncontrolling interests due to increased Chipeta income and a $32.7 million increase in other operating expenses.

Operating Statistics

	2009		2008		∆(1)			2007		∆(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		451		323		40	%		82		294	%
Third parties		186		201		(7	)%		241		(17	)%
Total processing throughput		637		524		22	%		323		62	%
Equity investment throughput (3)		120		112		7	%		84		33	%
Total throughput		1,640		1,603		2	%		1,394		15	%
Throughput attributable to noncontrolling interest owners		180		124		45	%		—	nm (4)
Total throughput attributable to Western Gas Partners, LP		1,460		1,479		(1	)%		1,394		6	%
Gross margin per Mcf
Gross margin per Mcf	$	0.41	$	0.49		(16	)%	$	0.46		7	%
Gross margin per Mcf attributable to Western Gas Partners, LP	$	0.43	$	0.50		(14	)%	$	0.46		9	%

(1)	Represents the percentage change for the year ended December 31, 2009 or for the year ended December 31, 2008.
(2)	Includes 100% of Chipeta system 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 209 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 owners’ proportionate share of Chipeta’s throughput, decreased by 19 MMcf/d for the year ended December 31, 2009 and increased by 85 MMcf/d for the year ended December 31, 2008.

12

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 128 MMcf/d and by 241 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, and due to increased throughput at the Granger system. Affiliate volume increases at the Granger system are due to drilling activity in the area and the release of capacity by a third party discussed in more detail below, increasing the capacity available to affiliates.

Third-party processing throughput decreased by 15 MMcf/d and by 40 MMcf/d for the year ended December 31, 2009 and for the year ended December 31, 2008, respectively. Third-party processing throughput decreased primarily due to decreased throughput at the Granger system partially offset by increased throughput at the Chipeta system due to completion of the refrigeration unit in December 2007. The throughput declines at the Granger system were primarily due to one third-party producer redirecting volumes processed at the Granger system pursuant to month-to-month agreements to its own processing facility.

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.

Natural Gas Gathering, Processing and Transportation Revenues

	2009		2008		∆			2007		∆
	(in thousands, except percentages)
Gathering, processing and transportation of natural gas:
Affiliates	$	146,707	$	130,524		12	%	$	105,168		24	%
Third parties		27,088		29,930		(9	)%		22,162		35	%
Total	$	173,795	$	160,454		8	%	$	127,330		26	%

Total gathering, processing and transportation of natural gas revenues increased by $13.3 million and by $33.1 million for the year ended December 31, 2009 and for the year ended December 31, 2008, respectively. Revenues from affiliates increased by $16.2 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 $25.4 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

13

systems due to new contract terms, partially offset by throughput decreases at the Granger, Haley, Pinnacle, Dew and Hugoton systems.

Revenues from third parties decreased by $2.8 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 $7.8 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, partially offset by decreased third-party throughput at the Granger system.

Natural Gas, Natural Gas Liquids and Condensate Sales

	2009		2008		∆			2007		∆
	(in thousands, except percentages and average price per unit)
Natural gas sales:
Affiliates	$	48,536	$	131,626		(63	)%	$	82,468		60	%
Third parties		8		23		(65	)%		—	nm (1)
Total	$	48,544	$	131,649		(63	)%	$	82,468		60	%
Natural gas liquids sales:
Affiliates	$	131,595	$	254,370		(48	)%	$	234,955		8	%
Third parties		—		159		(100	)%		—	nm (1)
Total	$	131,595	$	254,529		(48	)%	$	234,955		8	%
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	$	180,131	$	385,996		(53	)%	$	324,477		19	%
Third parties		7,462		16,278		(54	)%		2,772		487	%
Total	$	187,593	$	402,274		(53	)%	$	327,249		23	%
Average price per unit:
Natural gas (per Mcf)	$	3.17	$	7.26		(56	)%	$	4.80		51	%
Natural gas liquids (per barrel)	$	29.32	$	60.18		(51	)%	$	48.28		25	%
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 $214.7 million for the year ended December 31, 2009 and increased by $75.0 million for the year ended December 31, 2008. The decrease for the year ended December 31, 2009 consisted of a $123.0 million decrease in NGL sales, an $83.1 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 $49.2 million increase in natural gas sales, a $19.6 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 $4.09 per Mcf, or 56%, decrease in the average price for natural gas sold and an approximate 1.6 MMcf, or 9%, decrease 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 $2.46 per Mcf, or 51%, 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 $30.86 per barrel (or “Bbl”), or 51%, decrease in the average price for NGLs sold, partially offset by a 329,000 Bbls, or 8%, increase in the volume of NGLs sold, primarily due to an increase in wellhead volumes delivered to the Granger system and improved NGL recoveries due to a change in the composition of the natural gas processed at the Granger system, partially offset by 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

14

December 31, 2008 was primarily due to an $11.90 per Bbl, or 25%, increase in the average price of NGLs sold, partially offset by an approximate 528,000 Bbls, or 11%, decrease in the volume of NGLs sold, primarily due to the Granger system.

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		∆			2007		∆
	(in thousands, except percentages)
Equity income — affiliate	$	6,982	$	4,736		47	%	$	4,017		18	%
Other revenues, net:
Affiliates	$	1,595	$	4,553		(65	)%	$	2,127		114	%
Third parties		1,258		7,933		(84	)%		2,432		226	%
Total equity income and other revenues, net	$	9,835	$	17,222		(43	)%	$	8,576		101	%

Total equity income and other revenues decreased by $7.4 million for the year ended December 31, 2009 and increased by $8.6 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 of volume deficiency and indemnity payments received 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		∆			2007		∆
	(in thousands, except percentages and price per unit)
Cost of product	$	124,913	$	294,451		(58	)%	$	226,828		30	%
Operation and maintenance		60,613		64,249		(6	)%		52,867		22	%
Total cost of product and operation and maintenance expenses	$	185,526	$	358,700		(48	)%	$	279,695		28	%
Cost of product — average price per unit:
Natural gas (per Mcf)	$	3.79	$	9.29		(59	)%	$	5.43		71	%
Natural gas liquids (per Bbl)	$	9.27	$	23.77		(61	)%	$	21.66		10	%
Drip condensate (per MMBtu)	$	3.26	$	6.94		(53	)%	$	6.09		14	%

Cost of product expense decreased by $169.5 million for the year ended December 31, 2009 and increased by $67.6 million for the year ended December 31, 2008. The decrease for the year ended December 31, 2009 includes an approximate $158.5 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 net volumes. In addition, cost of product expense decreased $3.7 million from the lower cost of natural gas to compensate shippers on a thermally equivalent basis for drip condensate retained by us and sold to third parties, primarily due to lower market prices, and decreased $3.1 million due to a contract change at the Granger system related to volumes gathered at adjacent gathering systems owned by Anadarko and a third party, then processed at Granger. Effective in October 2009, fees previously paid by Granger are paid directly by the producer to the other gathering system owners. Cost of product expense also decreased $2.7 million due to lower fees resulting from the suspension of operations of the plant at the Hilight system in September 2008 and decreased $1.1 million due to a favorable change in the difference between actual versus contractual fuel recoveries. 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. For the year ended December 31, 2009, the volume of natural gas purchased from producers decreased 9% and the volume of NGLs purchased from producers increased 8%. The increase in the volume of NGLs purchased is net of a decrease in volumes purchased resulting from the September 2008 suspension of operations of the plant at the Hilight system. Excluding the impact of the plant suspension, the volume of NGLs purchased would have increased approximately 20% primarily due to the increase in throughput at the Chipeta plant. The decrease in the volumes of natural gas purchased is primarily due to the increase in NGLs prices, the aforementioned change in contract terms for affiliate throughput at the Granger system effective in October 2009, which reduced the volumes purchased under keep-whole contracts, as well as an increase in NGL recoveries at the Chipeta system due to completion of the cryogenic unit in April 2009, partially offset by the increase in throughput at the Chipeta plant.

15

Cost of product expense for the year ended December 31, 2008 increased by $67.6 million, $55.3 million of which was attributable to the higher cost of natural gas and NGLs we purchased from producers, primarily due to higher market prices partially offset by lower volumes. In addition, cost of product expense increased $5.5 million due to a change in imbalance positions and related gas prices, increased $3.1 million due to an unfavorable change in the difference between actual versus contractual fuel recoveries, increased $2.5 million due to an increase in fees from higher volumes gathered at adjacent gathering systems and processed at the Granger system and increased $1.9 million from the higher cost of natural gas to compensate shippers for drip condensate retained by us and sold to third parties. These increases were slightly offset by a $1.6 million decrease in expenses attributable to a decline in NGLs volumes processed at the Highlight facility that produced iso-butane from NGLs. The volume of natural gas purchased from producers remained relatively flat and the volume of NGLs purchased from producers decreased 11% 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 decreased approximately 4%. This decrease in the volumes of NGLs purchased, excluding the impact of the plant suspension, is primarily due to the decrease in throughput for the Granger system, partially offset by the increase in throughput at the Chipeta plant which was placed in service in December 2007.

Operation and maintenance expense decreased by $3.6 million for the year ended December 31, 2009 and increased by $11.4 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 and a $1.4 million decrease in plant repair costs at the Granger system, partially offset by a $0.8 million increase in operating expenses at the Chipeta plant and increases in costs related to employee incentive programs.

Operation and maintenance expense increased by $11.4 million for the year ended December 31, 2008 primarily due to a $7.4 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 and included in our general and administrative expenses. 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 $6.5 million due to operating expenses attributable to the Chipeta plant and the Granger system, partially offset by a $2.6 million decrease in compressor rental expenses.

Key Performance Metrics

	2009		2008		∆			2007			∆
	(in thousands, except percentages and gross margin per Mcf)
Gross margin
Gross margin	$	246,310	$	285,499		(14	)%		$	236,327		21	%
Gross margin per Mcf (1)	$	0.41	$	0.49		(16	)%		$	0.46		7	%
Gross margin per Mcf attributable to Western Gas Partners, LP (2)	$	0.43	$	0.50		(14	)%		$	0.46		9	%
Adjusted EBITDA (3)	$	141,563	$	185,078		(24	)%		$	160,772		15	%
Distributable cash flow (3)	$	128,014	$	173,838		(26	)%

(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 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 presented in accordance with GAAP, please read the caption How We Evaluate Our Operations within this Item 7.

Gross margin decreased by $39.2 million for the year ended December 31, 2009 and increased by $49.2 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 partially offset by a net increase in 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 14% and total gross margin per Mcf decreased by 16% for the year ended December 31, 2009, primarily due to lower processing margins and lower drip condensate margins.

16

Gross margin per Mcf attributable to Western Gas Partners, LP increased by 9% and total gross margin per Mcf increased by 7% for the year ended December 31, 2008, primarily due to higher processing margins and higher drip condensate margins.

Adjusted EBITDA. Adjusted EBITDA decreased by $43.5 million for the year ended December 31, 2009 and increased by $24.3 million for the year ended December 31, 2008. The decrease for the year ended December 31, 2009 is primarily due to a $211.0 million decrease in total revenues, excluding equity income; a $1.7 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 $169.5 million decrease in cost of product; a $3.6 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 $116.1 million increase in total revenues, excluding equity income, and an approximately $3.8 million increase in distributions from Fort Union, partially offset by a $67.6 million increase in cost of product, an $11.4 million increase in operation and maintenance expenses, a $9.4 million increase in the noncontrolling interest owners’ share of Adjusted EBITDA and a $5.5 million increase in general and administrative expenses, excluding non-cash equity-based compensation.

Distributable cash flow. Distributable cash flow decreased by $45.8 million for the year ended December 31, 2009 primarily due to the $43.5 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 $1.1 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.

General and Administrative, Depreciation and Other Expenses

	2009		2008		∆			2007		∆
	(in thousands, except percentages)
General and administrative	$	24,306	$	20,089		21	%	$	12,680		58	%
Property and other taxes		10,293		8,977		15	%		7,340		22	%
Depreciation and amortization		51,090		46,522		10	%		43,592		7	%
Impairment		—		9,354	nm		(1)		—	nm		(1)
Total general and administrative, depreciation and other expenses	$	85,689	$	84,942		1	%	$	63,612		34	%

⁽¹⁾ Percent change is not meaningful

General and administrative, depreciation and other expenses increased by $0.7 million for the year ended December 31, 2009 as a $4.2 million increase in general and administrative expenses, a $1.3 million increase in property and other taxes primarily attributable to the Granger assets and a $4.6 million increase in depreciation and amortization expense were partially 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 the $9.4 million charge recognized in connection with the plant suspension at the Hilight system prior to our acquisition of the Powder River assets.

General and administrative, depreciation and other expenses increased by $21.3 million for the year ended December 31, 2008. General and administrative expenses increased by $7.4 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 $2.9 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.

17

Interest Income, Net

	2009			2008			∆			2007			∆
				(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 income (expense), net		504			901			(44	)%		(6,187	)	nm
Credit facility fees		(143	)		(111	)		29	%		—			—
Total	$	8,308		$	11,240			(26	)%	$	(6,187	)	nm
Interest expense — third parties
Credit facility interest, fees and amortization	$	(859	)	$	—		nm			$	—		nm
Interest income (expense), net	$	7,449		$	11,240			(34	)%	$	(6,187	)	nm

⁽¹⁾ Percent change is not meaningful

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 and interest earned on affiliate balances, 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 and interest earned on affiliate balances, partially offset by commitment fees for our credit facilities. Interest on affiliate balances changed from net interest expense on net payable balances for the year ended December 31, 2007 to net interest income on net receivable balances 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			∆			2007			∆
				(in thousands, except percentages)
Income before income taxes	$	107,511		$	147,744			(27	)%	$	113,646			30	%
Income tax expense (benefit)		6,975			32,255			(78	)%		39,637			(19	)%
Effective tax rate		6	%		22	%					35	%

The Partnership is not a taxable entity for U.S. federal income tax purposes. Income earned by the Partnership prior to our acquisition of the Partnership Assets, except for Chipeta, was subject to federal and state income tax while income earned by the Partnership after our acquisition of the Partnership Assets, except for Chipeta, was subject only to Texas margin tax. Income attributable to Chipeta 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 $25.3 million and by $7.4 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. Income tax also decreased for the year ended December 31, 2009 due to a decrease in income attributable to the Granger system and a decrease in Texas margin tax expense attributable to the initial assets. In addition, our estimated income earned by our initial assets and the Powder River assets 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. For 2009, our variance from the federal statutory rate is primarily attributable to our U.S. federal income tax status as a non-taxable entity as well as state income tax benefit.

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 and a decrease in income attributable to the Granger system, partially offset by income tax expense attributable to the Chipeta assets for the first five months of 2008 following completion of the refrigeration unit in December 2007. For 2008, 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.

18

Noncontrolling Interests

	2009		2008		∆			2007			∆
			(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 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 $54.0 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. Management continuously monitors the Partnership’s leverage position and coordinates its capital expenditure program, quarterly distributions and acquisition strategy with its expected cash flows and projected debt-repayment schedule. We will continue to evaluate funding alternatives, including additional borrowings and the issuance of debt or equity securities, to secure funds as needed. To facilitate a potential debt or equity securities issuance, we have the ability to sell securities under our shelf registration statement which became effective with the SEC in August 2009.

In January 2010, we borrowed $210.0 million under our $350.0 million revolving credit facility in connection with the Granger acquisition. See Note 1—Description of Business and Basis of Presentation—Offerings and Acquisitions of the notes to the consolidated financial statements under Item 8 of this annual report.

19

Working capital. Working capital is an indication of our liquidity and potential need for short-term funding. Our working capital requirements are driven by changes in accounts receivable and accounts payable. These changes are primarily impacted by factors such as credit extended to, and the timing of collections from, our customers and the level and timing of our spending for maintenance and expansion activity.

Historical cash flow. The following table and discussion presents a summary of our net cash flows from operating activities, investing activities and financing activities as well as Adjusted EBITDA for the years ended December 31, 2009 and 2008.

For periods prior to our acquisition of the Partnership Assets, except for Chipeta, our net cash from operating activities and capital contributions from our Parent related to such assets were used to service our cash requirements, which included the funding of operating expenses and capital expenditures. Subsequent to our acquisition of the Partnership Assets, except for Chipeta, transactions with Anadarko and third parties related to such assets 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			∆			2007			∆
				(in thousands, except percentages)
Net cash provided by (used in):
Operating activities	$	135,532		$	185,922			(27	)%	$	130,206			43	%
Investing activities		(171,321	)		(552,585	)		(69	)%		(149,013	)		271	%
Financing activities		69,699			402,737			(83	)%		18,349		nm		(1)
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 $50.4 million and increased by $55.7 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 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 $381.3 million for the year ended December 31, 2009 and increased by $403.6 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 $40.0 million and $33.1 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 $87.9 million during the year ended December 31, 2008 to $49.0 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 5%, from $21.6 million during the year ended December 31, 2008 to $20.5 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 $33.1 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, the expansion of the Bethel facility and the installation of the compressor station at the Hugoton system during 2008.

20

Financing Activities. Net cash provided by financing activities decreased by $333.0 million for the year ended December 31, 2009 and increased by $384.4 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 distributions to Anadarko attributable to pre-acquisition intercompany balances were $10.8 million during the year ended December 31, 2009, representing the net non-cash settlement of intercompany transactions attributable to the Chipeta assets and the Granger assets, compared to net distributions to Anadarko of $34.9 million for the year ended December 31, 2008, representing the net settlement of transactions attributable to the Powder River assets, the Chipeta assets and the Granger 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 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 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 $59.2 million and $117.7 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 $69.5 million and $109.5 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 71% and 80% 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 million to $32 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

21

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 our 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 in October 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 customary covenants, customary events of default and certain financial tests, including a maximum consolidated leverage ratio, as defined in the revolving credit facility, of 4.5 to 1.0 as of the end of each quarter and a minimum consolidated interest coverage ratio, as defined in the revolving credit facility, of 3.0 to 1.0 as of the end of each quarter. 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. 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.

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.

22

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

We expect our exposure to concentrated risk of non-payment or non-performance to continue for as long as we remain substantially dependent on Anadarko for our revenues. Additionally, we are exposed to credit risk on the note receivable from Anadarko that was issued concurrent with the closing of our initial public offering. We are also party to an omnibus agreement with Anadarko under which Anadarko is required to indemnify us for certain environmental claims, losses arising from rights-of-way claims, failures to obtain required consents or governmental permits and income taxes with respect to the initial assets. Finally, we entered into commodity price swap agreements with Anadarko in order to substantially reduce our exposure to commodity price risk attributable to our percent-of-proceeds and keep-whole contracts for the Hilight system, the Newcastle system and the Granger 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				Credit
	Operating		Retirement		To Anadarko				Facility
	Leases		Obligations		Principal		Interest		Fees		Total
					(in thousands)
2010	$	970	$	—	$	—	$	7,000	$	1,872	$	9,842
2011		969		—		—		3,064		1,860		5,893
2012		799		—		—		3,064		1,558		5,421
2013		794		—		175,000		3,064		19		178,877
2014		311		—		—		—		—		311
Thereafter		—		14,924		—		—		—		14,924
Total	$	3,843	$	14,924	$	175,000	$	16,192	$	5,309	$	215,268

Operating leases: Anadarko leases compression equipment, office space and a warehouse used by us and charges rental payments to us. The amounts above represent the future minimum rent payments due under these operating leases.

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. 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, including the omnibus agreement, expenses related to operating as a publicly traded partnership, the services and secondment agreement and equity-based compensation plans; the Powder River acquisition; the Chipeta acquisition and the Granger acquisition.

23

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 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 23 years. If the depreciable lives of our assets were reduced by 10%, we estimate that annual depreciation expense would increase by approximately $6.1 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 $26.4 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 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

24

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.

25