Management's Discussion and Analysis of Financial Condition

EX-99.2 5 d355678dex992.htm MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION Management's Discussion and Analysis of Financial Condition

EXHIBIT 99.2

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXECUTIVE SUMMARY

We are a growth-oriented master limited partnership (“MLP”) organized by Anadarko to own, operate, acquire and develop midstream energy assets. We currently operate in East and West Texas, the Rocky Mountains (Colorado, Utah and Wyoming) and the Mid-Continent (Kansas and Oklahoma) and are engaged primarily in the business of gathering, processing, compressing, treating and transporting natural gas, condensate, NGLs and crude oil for Anadarko and third-party producers and customers. Including the effect of the acquisition of Mountain Gas Resources, LLC (“MGR”), our assets consist of thirteen gathering systems, seven natural gas treating facilities, ten natural gas processing facilities, two NGL pipelines, one interstate gas pipeline, one intrastate gas pipeline, and interests in two gas gathering systems and a crude oil pipeline accounted for under the equity method.

Significant financial highlights during the year ended December 31, 2011, include the following:

•

We completed two acquisitions: the February acquisition of the Platte Valley gathering system and processing plant from a third party, and the July acquisition of Anadarko’s Bison gas treating facility located in the Powder River Basin in northeastern Wyoming. See Acquisitions under Items 1 and 2 of our 2011 Form 10-K for additional information.

•

Our stable operating cash flow enabled us to raise our distribution to $0.44 per unit for the fourth quarter of 2011, representing a 5% increase over the distribution for the third quarter of 2011, a 16% increase over the distribution for the fourth quarter of 2010, and our eleventh consecutive quarterly increase.

•

We entered into an amended and restated $800.0 million senior unsecured revolving credit facility (the “RCF”) to amend and restate our $450.0 million revolving credit facility and issued $500.0 million aggregate principal amount of 5.375% Senior Notes due 2021 (the “Notes”). See Liquidity and Capital Resources within this Item 7 for additional information.

•

We issued an aggregate 9,602,813 common units to the public, generating net proceeds of $335.3 million, including the general partner’s proportionate capital contribution to maintain its 2.0% general partner interest. Net proceeds from the two offerings were used to repay amounts outstanding under our revolving credit facility and for general partnership purposes.

Significant operational highlights during the year ended December 31, 2011, include the following:

•

Gross margin (total revenues less cost of product) attributable to Western Gas Partners, LP averaged $0.58 per Mcf for the year, representing a 7% increase compared to the year ended December 31, 2010.

•

Throughput attributable to Western Gas Partners, LP totaled 2,239 MMcf/d for the year, representing a 10% increase compared to the same period in 2010.

OUR OPERATIONS

The following discussion analyzes our financial condition and results of operations and should be read in conjunction with our consolidated financial statements and notes to consolidated financial statements, which are included in Item 8 of Exhibit 99.3 to this Current Report on Form 8-K. Unless the context otherwise requires, references to “we,” “us,” “our,” the “Partnership” or “Western Gas Partners” refers to Western Gas Partners, LP and its subsidiaries. The Partnership’s general partner is Western Gas Holdings, LLC (the “general partner”), a wholly owned subsidiary of Anadarko Petroleum Corporation. “Anadarko” or “Parent” refers to Anadarko Petroleum Corporation and its consolidated subsidiaries, excluding the Partnership and the general partner.

References to the “Partnership assets” refer collectively to the assets owned by the Partnership as of December 31, 2011. Because of Anadarko’s control of the Partnership through its ownership of our general partner, each acquisition of Partnership assets, except for those from third parties, was considered a transfer of net assets between entities under common control (see Note 2. Acquisitions in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K). As a result, after each acquisition of assets from Anadarko, we are required to recast our financial statements to include the activities of the Partnership assets as of the date of common control. As such, our historical financial statements have been recast in this Current Report on Form 8-K to include the results attributable to MGR and Bison as if we owned such assets for all periods presented. The consolidated financial statements for periods prior to our acquisition of the Partnership assets have been prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if we had owned the assets during the periods reported. 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. “Affiliates” refers to wholly owned and partially owned subsidiaries of Anadarko, excluding the Partnership, and also refers to Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”) and Rendezvous Gas Services, LLC (“Rendezvous”).

Our results are driven primarily by the volumes of natural gas and NGLs we gather, process, treat or transport through our systems. For the year ended December 31, 2011, approximately 77% of our total revenues and 70% of our throughput (excluding equity investment throughput) was attributable to transactions 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.

We received significant dedications from our largest customer, Anadarko, solely with respect to the gathering systems connected to the Wattenberg field and the gathering systems included in our initial assets. 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 long as additional wells are connected to these gathering systems.

For the year ended December 31, 2011, approximately 65% of our gross margin was attributed to fee-based contracts, under which a fixed fee is received based on the volume and thermal content of the natural gas we gather, process, 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. Fee-based gross margin includes equity income from our interests in Fort Union, White Cliffs and Rendezvous. Certain of our fee-based contracts contain keep-whole provisions.

For the year ended December 31, 2011, approximately 35% of our gross margin was attributed to percent-of-proceeds and keep-whole contracts, pursuant to which we have commodity price exposure, including gross margin attributable to condensate sales. 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 5. Transactions with Affiliates of the Notes to Consolidated Financial Statements included under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

We also have indirect exposure to commodity price risk in that persistent low natural gas prices have caused and may continue to cause our current or potential customers to delay drilling or shut in production in certain areas, which would reduce the volumes of natural gas available for our systems. We also bear a limited degree of commodity price risk through settlement of natural gas imbalances. Please read Item 7A of our 2011 Form 10-K.

As a result of our initial public offering and subsequent acquisitions from Anadarko and third parties, the results of operations, financial position and cash flows may vary significantly for 2011, 2010 and 2009 as compared to future periods. 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 an essential operating variable we use in assessing our ability to generate revenues. In order to maintain or increase throughput on our gathering and processing systems, we must connect additional wells to our systems. Our success in maintaining or increasing throughput is impacted by successful drilling of new wells by producers that are dedicated to our systems, recompletions of existing wells connected to our systems, our ability to secure volumes from new wells drilled on non-dedicated acreage and our ability to attract natural gas volumes currently gathered, processed or treated by our competitors. During the year ended December 31, 2011, and including the effect of the MGR acquisition, we added 112 receipt points to our systems, with initial throughput of approximately 1.0 MMcf/d per receipt point.

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 purchases and sales of natural gas, condensate and NGLs 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, equipment rentals, 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, to 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 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 incurred 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 the following:

•

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, pursuant to the terms of the omnibus agreement with Anadarko, we are required to reimburse Anadarko for allocable general and administrative expenses. See further detail under Items Affecting the Comparability of Our Financial Results – General and administrative expenses under the omnibus agreement below and Note 5. Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Adjusted EBITDA. We define “Adjusted EBITDA” as net income (loss) attributable to Western Gas Partners, LP, plus distributions from equity investees, non-cash equity-based compensation expense, expense in excess of the omnibus cap, interest expense, income tax expense, depreciation, amortization and impairments, and other expense, less income from equity investments, interest income, income tax benefit, other income and other nonrecurring adjustments that are not settled in cash. 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 the following, 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 (including amortization of deferred debt issuance costs originally paid in cash, offset by non-cash capitalized interest), maintenance capital expenditures and income taxes. We 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 Distributable cash flow 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.

Distributable cash flow should not be considered an alternative to net income, earnings per unit, operating income, cash flows 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. Our definitions of Adjusted EBITDA and Distributable cash flow may not be comparable to similarly titled measures of other companies in our industry, 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.

The following tables present (a) 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 (b) 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,
thousands	2011			2010			2009

Reconciliation of Adjusted EBITDA to Net income attributable to Western Gas Partners, LP
Adjusted EBITDA attributable to Western Gas Partners, LP	$	324,323		$	265,024		$	223,766
Less:
Distributions from equity investees		15,999			10,973			11,206
Non-cash equity-based compensation expense		13,754			4,787			3,580
Expenses in excess of omnibus cap		—			133			842
Interest expense		30,345			18,794			9,955
Income tax expense		19,018			21,702			22,159
Depreciation, amortization and impairments ⁽¹⁾		109,151			88,188			88,486
Other expense ⁽¹⁾		3,683			2,393			—
Add:
Equity income, net		11,261			7,628			7,923
Interest income, net – affiliates		28,560			20,243			20,717
Other income ^{(1) (2)}		2,049			267			57

Net income attributable to Western Gas Partners, LP	$	174,243		$	146,192		$	116,235


Reconciliation of Adjusted EBITDA to Net cash provided by operating activities
Adjusted EBITDA attributable to Western Gas Partners, LP	$	324,323		$	265,024		$	223,766
Adjusted EBITDA attributable to noncontrolling interests		16,850			13,823			12,462
Interest income (expense), net		(1,785	)		1,449			10,762
Expenses in excess of omnibus cap		—			(133	)		(842	)
Non-cash equity-based compensation expense		(13,754	)		(4,787	)		(3,580	)
Current income tax expense		(16,414	)		(12,114	)		(22,109	)
Other income (expense), net ⁽²⁾		(1,628	)		(2,122	)		61
Distributions from equity investees less than (in excess of) equity income, net		(4,738	)		(3,345	)		(3,283	)
Changes in operating working capital:
Accounts receivable and natural gas imbalance receivable		(3,571	)		802			6,961
Accounts payable, accrued liabilities and natural gas imbalance payable		23,092			2,734			(14,267	)
Other		4,796			2,418			2,834

Net cash provided by operating activities	$	327,171		$	263,749		$	212,765

⁽¹⁾	Includes our 51% share of depreciation, amortization and impairments; other expense; and other income attributable to Chipeta.

⁽²⁾

Excludes income of $1.6 million for each of the years ended December 31, 2011, 2010 and 2009, related to a component of a gas processing agreement accounted for as a capital lease. Refer to Note 1. Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.


	Year Ended December 31,
thousands except Coverage ratio	2011			2010		2009

Reconciliation of Distributable cash flow to Net income attributable to Western Gas Partners, LP
Distributable cash flow	$	281,975		$	237,769	$	203,376
Less:
Distributions from equity investees		15,999			10,973		11,206
Non-cash equity-based compensation expense		13,754			4,787		3,580
Expenses in excess of omnibus cap		—			133		842
Income tax expense		19,018			21,702		22,159
Depreciation, amortization and impairments ⁽¹⁾		109,151			88,188		88,486
Other expense⁽¹⁾		3,683			2,393		—
Add:
Equity income, net		11,261			7,628		7,923
Cash paid for maintenance capital expenditures ⁽¹⁾		28,293			24,854		27,335
Capitalized interest		420			—		—
Cash paid for income taxes		190			507		—
Interest income, net (non-cash settled)		11,660			3,343		3,817
Other income^{(1) (2)}		2,049			267		57

Net income attributable to Western Gas Partners, LP	$	174,243		$	146,192	$	116,235


Distribution declared for the year ended December 31, 2011 ⁽³⁾
Limited partners		143,734
General partner		8,847

Total	$	152,581

Coverage ratio		1.85	x

⁽¹⁾	Includes our 51% share of depreciation, amortization and impairments; other expense; cash paid for maintenance capital expenditures; and other income attributable to Chipeta.

⁽²⁾

Excludes income of $1.6 million for each of the years ended December 31, 2011, 2010 and 2009, related to a component of a gas processing agreement accounted for as a capital lease. Refer to Note 1. Summary of Significant Accounting Policies in the Notes to the Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

⁽³⁾	Reflects distributions of $1.655 per unit declared for the year ended December 31, 2011.

ITEMS AFFECTING THE COMPARABILITY OF OUR FINANCIAL RESULTS

Our historical results of operations and cash flows for the periods presented may not be comparable to future or historic results of operations or cash flows for the reasons described below:

Affiliate contracts. Effective October 1, 2009, contracts covering substantially all of the Granger assets’ affiliate throughput were converted from primarily keep-whole contracts into a ten-year fee-based arrangement and, effective July 1, 2010, contracts covering all of Wattenberg’s affiliate throughput were converted from primarily keep-whole contracts into a ten-year fee-based agreement. These contract changes will impact the comparability of the statements of income and cash flows. See Note 5. Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Commodity price swap agreements. We have commodity price swap agreements with Anadarko to mitigate exposure to commodity price volatility that would otherwise be present as a result of the purchase and sale of natural gas, condensate or NGLs. Notional volumes for each of the swap agreements are not specifically defined; instead, the commodity price swap agreements apply to the actual volume of our natural gas, condensate and NGLs purchased and sold at the Hilight, Hugoton, Newcastle, Granger and Wattenberg assets, with various expiration dates through September 2015.

In December 2011, we extended the commodity price swap agreements for the Hilight and Newcastle assets through December 2013, and also entered into price swap agreements related to the MGR acquisition, with forward-starting effective dates beginning January 1, 2012, and extending through December 31, 2016. See Note 5. Transactions with Affiliates and Note 12. Subsequent Event in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Federal income taxes. Income earned by the Partnership, a non-taxable entity for U.S. federal income tax purposes, including and subsequent to our acquisition of the Partnership assets was subject only to Texas margin tax, while income earned prior to our acquisition of the Partnership assets was subject to federal and state income tax.

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. 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, 2011, 2010 and 2009, Anadarko billed us $11.8 million, $9.0 million and $6.9 million, respectively, in allocated general and administrative expenses, which, prior to December 31, 2010, were subject to the cap contained in the omnibus agreement. For the year ended December 31, 2011, Anadarko, in accordance with the partnership agreement and omnibus agreement, determined, in its reasonable discretion, amounts to be allocated to us in exchange for services provided under the omnibus agreement. In addition, our general and administrative expenses for the years ended December 31, 2010 and 2009, included $0.1 million and $0.8 million, respectively, of expenses incurred by Anadarko and the general partner in excess of the cap contained in the omnibus agreement. Such expenses were recorded as capital contributions from Anadarko and did not impact the Partnership’s cash flows. The amounts charged under the omnibus agreement are 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. We also incurred $7.7 million, $8.0 million and $7.5 million in public company expenses, excluding equity-based compensation, during the years ended December 31, 2011, 2010 and 2009, respectively.

Interest 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 of Chipeta, the Granger acquisition, Wattenberg acquisition, 0.4% interest in White Cliffs, Bison acquisition and MGR acquisition. Therefore, interest expense and interest income attributable to these balances are reflected in our historical consolidated financial statements for the periods ending prior to our acquisition of the Partnership assets, except for Chipeta.

Beginning December 7, 2011, Anadarko discontinued charging interest on intercompany balances. The outstanding affiliate balances on the Partnership assets prior to their acquisition were entirely settled through an adjustment to parent net equity.

Platte Valley acquisition. In February 2011, we acquired a natural gas gathering system and cryogenic gas processing facilities, collectively referred to as the “Platte Valley assets,” financed with borrowings under our revolving credit facility. These assets, acquired from a third-party, have been recorded in the Partnership’s consolidated financial statements at their estimated fair values on the acquisition date under the acquisition method of accounting. Results of operations attributable to the Platte Valley assets have been included our consolidated statements of income beginning on the acquisition date in the first quarter of 2011.

The fair values of the plant and processing facilities, related equipment, and intangible assets acquired were based on the market, cost and income approaches. The liabilities assumed include certain amounts associated with environmental contingencies estimated by management. All fair-value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs. See Note 1. Summary of Significant Accounting Policies, Note 2. Acquisitions and Note 11. Commitments and Contingencies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K for further information.

GENERAL TRENDS AND OUTLOOK

We expect our business to continue to be affected by the following key trends. Our expectations are based on our assumptions 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 relatively low natural gas price environment, which has persisted over the past three years, has led to lower levels of drilling activity served by certain of our assets. Several of our customers, including Anadarko, have reduced activity levels in certain areas, shifting capital toward liquid-rich opportunities that offer higher margins and superior economics to producers. This trend has resulted in fewer new well connections and, in some cases, temporary curtailments of production. 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 the activities of natural gas producers and shippers.

Changes in regulations. Our operations and the operations of our customers have been, and at times in the future may be, affected by political developments and are subject to an increasing number of complex federal, state, tribal, local and other laws and regulations such as production restrictions, permitting delays, limitations on hydraulic fracturing and environmental protection regulations. We and/or our customers must obtain and maintain numerous permits, approvals and certificates from various federal, state, tribal and local governmental authorities. For example, regulation of hydraulic fracturing is currently primarily conducted at the state level through permitting and other compliance requirements. If proposed federal legislation is adopted, it could establish an additional level of regulation and permitting. Any changes in statutory regulations or delays in the issuance of required permits may impact both the throughput on and profitability of our systems.

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, MLPs have accessed the 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 inflation. Although inflation in the U.S. has been relatively low in recent years, the U.S. economy could experience a significant inflationary effect from, among other things, the governmental stimulus plans enacted since 2008. To the extent permitted by regulations and escalation provisions in certain of our existing agreements, we have the ability to recover a portion of increased costs in the form of higher fees.

Impact of interest rates. Interest rates were at or near historic lows at certain times during 2011. Should interest rates rise, our financing costs would increase accordingly. Additionally, as with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and an associated implied distribution yield. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity, or increase the cost of issuing equity, to make acquisitions, reduce debt or for other purposes. However, we expect our cost of capital to remain competitive, as our competitors would face similar circumstances.

Acquisition opportunities. Anadarko’s total domestic midstream asset portfolio, excluding the assets we own, consists of sixteen gathering systems and eight processing and/or treating facilities with an aggregate throughput of approximately 1.9 Bcf/d, in addition to equity investments in two midstream projects not yet in service. A key component of our growth strategy is to acquire midstream assets from Anadarko and third parties over time.

Including the effect of the MGR acquisition, Anadarko owns a 2.0% general partner interest in us, all of our IDRs and a 43.6% 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 flows generated from operations on a per-unit basis.

RESULTS OF OPERATIONS

OPERATING RESULTS

The following tables and discussion present a summary of our results of operations for the years ended December 31, 2011, 2010 and 2009:

		MMMMMM			MMMMMM			MMMMMM
	Year Ended December 31,
thousands	2011			2010			2009
Gathering, processing and transportation of natural gas and natural gas liquids	$	301,329		$	253,273		$	246,466
Natural gas, natural gas liquids and condensate sales		502,383			396,037			361,645
Equity income and other, net		19,553			13,964			11,653

Total revenues ⁽¹⁾		823,265			663,274			619,764
Total operating expenses ⁽¹⁾		614,072			485,286			483,500

Operating income		209,193			177,988			136,264
Interest income, net – affiliates		28,560			20,243			20,717
Interest expense		(30,345	)		(18,794	)		(9,955	)
Other income (expense), net		(44	)		(538	)		1,628

Income before income taxes		207,364			178,899			148,654
Income tax expense		19,018			21,702			22,159

Net income		188,346			157,197			126,495
Net income attributable to noncontrolling interests		14,103			11,005			10,260

Net income attributable to Western Gas Partners, LP	$	174,243		$	146,192		$	116,235

Key Performance Metrics ⁽²⁾
Gross margin	$	495,894		$	416,798		$	380,890
Adjusted EBITDA attributable to Western Gas Partners, LP	$	324,323		$	265,024		$	223,766
Distributable cash flow	$	281,975		$	237,769		$	203,376

⁽¹⁾

Revenues include affiliate amounts earned by the Partnership from services provided to our affiliates, as well as from the sale of residue gas, condensate and NGLs to our affiliates. Operating expenses include amounts charged by our affiliates for services as well as reimbursement of amounts paid by affiliates to third parties on our behalf. See Note 5. Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

⁽²⁾

Gross margin, Adjusted EBITDA attributable to Western Gas Partners, LP (“Adjusted EBITDA”) and Distributable cash flow are defined 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, 2011” refer to the comparison of the year ended December 31, 2011 to the year ended December 31, 2010, any increases or decreases “for the year ended December 31, 2010” refer to the comparison of the year ended December 31, 2010 to the year ended December 31, 2009.

Operating Statistics

		000000000		000000000		000000000		000000000		000000000
	Year Ended December 31,
throughput in MMcf/d	2011		2010		D		2009		D
Gathering, treating and transportation ⁽¹⁾		1,321		1,181		12 %		1,229		(4)%
Processing ⁽²⁾		962		815		18 %		808		1 %
Equity investment ⁽³⁾		198		228		(13)%		225		1 %
Total throughput ⁽⁴⁾		2,481		2,224		12 %		2,262		(2)%

Throughput attributable to noncontrolling interests		242		197		23 %		180		9 %

Total throughput attributable to Western Gas Partners, LP		2,239		2,027		10 %		2,082		(3)%

⁽¹⁾	Excludes average NGL pipeline volumes from the Chipeta assets of 24 MBbls/d, 14 MBbls/d, and 11 MBbls/d for the years ended December 31, 2011, 2010, and 2009, respectively.

⁽²⁾	Includes 100% of the Chipeta, Granger and Hilight system volumes, 100% of the Red Desert complex volumes and 50% of Newcastle system volumes for all periods presented, as well as throughput beginning March 2011 attributable to the Platte Valley system.

⁽³⁾

Represents our 14.81% share of Fort Union and 22% share of Rendezvous gross volumes and excludes 4 MBbls/d and 3 MBbls/d of oil pipeline volumes for the years ended December 31, 2011 and 2010, respectively, representing our 10% share of average White Cliffs pipeline volumes. Our 10% share of White Cliffs volumes for 2009 was not material.

⁽⁴⁾	Includes affiliate, third-party and equity-investment volumes.

Gathering, treating and transportation throughput increased by 140 MMcf/d for the year ended December 31, 2011, primarily due to the startup of the Bison assets in June 2010 and throughput increases at the Wattenberg system due to increased drilling activity in the area. These increases were partially offset by lower throughput at the MIGC system resulting from the January 2011 expiration of certain contracts that were not renewed due to the startup of the third-party owned Bison pipeline, and throughput decreases at the Haley, Pinnacle, Dew and Hugoton systems resulting from natural production declines and reduced drilling activity in those areas. Gathering, treating and transportation throughput decreased by 48 MMcf/d for the year ended December 31, 2010, primarily due to throughput decreases at Pinnacle, Haley, Dew, Hugoton and an MGR gathering system, resulting from natural production declines and reduced drilling activity in those areas as a result of low natural gas prices. These declines were partially offset by throughput increases at the Wattenberg system due to increased drilling activity and recompletions driven by favorable producer economics in the area and the startup of the Bison assets in June 2010.

Processing throughput increased by 147 MMcf/d for the year ended December 31, 2011, primarily due to the additional throughput from the Platte Valley system acquired in February 2011, as well as throughput increases at the Chipeta and Hilight systems, resulting from drilling activity in these areas driven by the relatively high liquid content of the gas volumes produced. These increases were partially offset by lower throughput at the Red Desert complex resulting from volumes being diverted away upon the resumption of a competing plant in 2011 that experienced an outage in 2010. Processing throughput increased by 7 MMcf/d for the year ended December 31, 2010, primarily due to increased throughput at the Chipeta system due to increased drilling activities in the Natural Buttes areas and at the Granger system resulting from the temporary redirection of volumes from competing systems during the last half of 2010.

Equity investment volumes decreased by 30 MMcf/d for the year ended December 31, 2011, due to lower throughput at the Fort Union system following the startup of the Bison pipeline. Equity investment volumes increased by 3 MMcf/d for the year ended December 31, 2010, due to a throughput increase of 7 MMcf/d at Rendezvous, partially offset by a 4 MMcf/d decrease in volumes at the Fort Union system as a result of reduced drilling activity in the area.

Natural Gas Gathering, Processing and Transportation Revenues

000000000

Year Ended December 31,

thousands except percentages

2011

2010

2009

Gathering, processing and transportation
of natural gas and natural gas liquids

301,329

253,273

19%

246,466

Gathering, processing and transportation of natural gas and natural gas liquids revenues increased by $48.1 million for the year ended December 31, 2011, due to the acquisition of the Platte Valley system in February 2011, the June 2010 startup of the Bison assets, and increased fee revenue at the Wattenberg system as a result of changes in affiliate contract terms (from primarily keep-whole and percentage-of-proceeds arrangements to fee-based arrangements), effective July 2010. These increases were partially offset by decreased fee revenue at MIGC due to the January 2011 expiration of certain contracts, decreased volume due to natural declines at the Haley, Hugoton and Dew systems and decreased volume processed at the Red Desert complex resulting from volumes being diverted away upon the resumption of a competing plant in 2011 that experienced an outage in 2010. Gathering, processing and transportation of natural gas and natural gas liquids revenues increased by $6.8 million for the year ended December 31, 2010, due to the June 2010 startup of Bison and increased fee revenue at the Wattenberg and Granger systems. This increase resulted from changes in affiliate contract terms effective in July 2010 at Wattenberg and in October 2009 at Granger, from primarily keep-whole and percentage-of-proceeds agreements to fee-based agreements. In addition, revenues increased due to higher rates at the Pinnacle, Hugoton and Wattenberg systems. These increases were partially offset by decreased throughput at the Pinnacle, Haley, Dew and Hugoton systems.

Natural Gas, Natural Gas Liquids and Condensate Sales

		000000000		000000000		000000000		000000000		000000000
thousands except percentages and per-unit amounts	Year Ended December 31,
thousands except percentages and per-unit amounts	2011		2010		D		2009		D
Natural gas sales	$	129,939	$	91,452		42%	$	93,092		(2)%
Natural gas liquids sales		345,646		279,915		23%		250,572		12 %
Drip condensate sales		26,798		24,670		9%		17,981		37 %

Total	$	502,383	$	396,037		27%	$	361,645		10 %

Average price per unit:
Natural gas (per Mcf)	$	5.30	$	5.17		3%	$	3.86		34 %
Natural gas liquids (per Bbl)	$	47.72	$	39.94		19%	$	30.06		33 %
Drip condensate (per Bbl)	$	72.86	$	70.50		3%	$	47.87		47 %

Including the effects of commodity price swap agreements, total natural gas, natural gas liquids and condensate sales increased by $106.3 million for the year ended December 31, 2011, which consisted of a $65.7 million increase in NGLs sales, a $38.5 million increase in natural gas sales and a $2.1 million increase in drip condensate sales.

The increase in NGLs sales was primarily due to the acquisition of the Platte Valley system in February 2011, higher throughput at the Chipeta and Hilight systems and increased commodity prices impacting the Red Desert complex at which commodity price swap agreements were not effective until January 1, 2012 (see Note 12. Subsequent Event in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K), partially offset by changes in affiliate contract terms at the Wattenberg system allowing the producer to take its product in kind.

The increase in natural gas sales was due to a 38% increase in volumes sold, resulting from the acquisition of the Platte Valley system in February 2011 and higher throughput at the Hilight system due to increased third-party drilling in the area. The increase in drip condensate sales for the year ended December 31, 2011, was primarily due to a higher average sales price at the Wattenberg and Hugoton systems and Platte Valley sales.

Total natural gas, natural gas liquids and condensate sales increased by $34.4 million for the year ended December 31, 2010, consisting of a $29.3 million and $6.7 million increase in NGLs sales and drip condensate sales, respectively, partially offset by a $1.6 million decrease in natural gas sales. The increase in NGLs sales is primarily attributable to a 33% increase in the average price of NGLs for 2010. This increase was partially offset by a 16% decrease in the volume of NGLs sold primarily due to the changes in affiliate contract terms at the Granger and Wattenberg systems effective in October 2009 and July 2010, respectively, allowing the producer to take its liquids and gas in-kind.

The decrease in natural gas sales was due to a 27% decrease in the volume of natural gas sold primarily due to the changes in affiliate contract terms at the Granger and Wattenberg systems. The decrease was partially offset by a 34% increase in the average natural gas sales price. Natural gas and NGL prices pursuant to the commodity price swap agreements for the Granger system in 2010 were higher than 2009 market prices, and natural gas and NGL prices pursuant to the 2010 commodity price swap agreements for the Hilight and Newcastle systems were higher than 2009 commodity swap prices. The increase in drip condensate sales for the year ended December 31, 2010, was primarily due to a $22.63 per Bbl, or 47%, increase in the average price of condensate at the Hugoton and Wattenberg systems.

The average natural gas and NGLs prices for the year ended December 31, 2011 and 2010, include the effects of commodity price swap agreements attributable to sales for the Granger, Wattenberg, Hilight, Newcastle and Hugoton systems. See Note 5. Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Equity Income and Other Revenues

		000000000		000000000		000000000		000000000		000000000
	Year Ended December 31,
thousands except percentages	2011		2010		D		2009		D
Equity income	$	11,261	$	7,628		48%	$	7,923		(4)%
Other revenues, net		8,292		6,336		31%		3,730		70 %

Total	$	19,553	$	13,964		40%	$	11,653		20 %

Equity income increased by $3.6 million for the year ended December 31, 2011, primarily due to the acquisition of an additional 9.6% interest in White Cliffs in September 2010.

Other revenues, net increased by $2.0 million for the year ended December 31, 2011, primarily due to collection of deficiency fees, predominantly associated with MGR gathering agreements. Other revenues, net increased by $2.6 million for the year ended December 31, 2010, primarily due to changes in gas imbalance positions at the Hilight, MIGC, Hugoton and Wattenberg systems and reimbursements from a third-party customer at the Pinnacle system for both installation costs and a shared equipment arrangement that ended in the third quarter of 2009.

Cost of Product and Operation and Maintenance Expenses

		000000000		000000000		000000000		000000000		000000000
	Year Ended December 31,
thousands except percentages	2011		2010		D		2009		D
Cost of product	$	327,371	$	246,476		33%	$	238,874		3 %
Operation and maintenance		119,104		103,887		15%		106,590		(3)%

Total cost of product and operation and maintenance expenses	$	446,475	$	350,363		27%	$	345,464		1 %

Including the effects of commodity price swap agreements attributable to purchases for the Granger, Wattenberg, Hilight, Newcastle and Hugoton systems, cost of product expense increased by $7.6 million for the year ended December 31, 2010, primarily due to a $19.6 million increase in NGL purchases as a result of higher prices, partially offset by a $1.1 million decrease due to a decrease in the actual cost of fuel compared to the contractual cost of fuel, and a $1.4 million decrease due to changes in gas imbalance positions. The overall increase was also partially offset by a $9.0 million decrease in gathering fees paid by the Granger system for 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 now paid directly by the producer to the other gathering system owners.

See Note 5. Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K for further discussion of the commodity price swap agreements.

Operation and maintenance expense increased by $15.2 million for the year ended December 31, 2011, primarily due to the acquisition of the Platte Valley system and the June 2010 startup of the Bison assets, partially offset by lower compressor lease expenses resulting from the purchase of compressors used at the Wattenberg system leased during 2010.

Operation and maintenance expense decreased by $2.7 million for the year ended December 31, 2010, primarily due to lower compressor lease expenses resulting from the purchase of previously leased compressors used at the Granger and Wattenberg systems during 2010, lower electricity expense at the Chipeta system, lower chemical expenses and lower contract labor. The decrease in compressor lease expense for the year ended December 31, 2010, was offset by an increase in depreciation expense discussed below under General and Administrative, Depreciation and Other Expenses. In addition, the decrease in operating expense was partially offset by higher field personnel expenses, primarily attributable to merit increases, and a $2.0 million increase due to the startup of the Bison assets in June 2010.

General and Administrative, Depreciation and Other Expenses

		000000000		000000000		000000000		000000000		000000000
	Year Ended December 31,
thousands except percentages	2011		2010		D		2009		D
General and administrative	$	39,114	$	29,640		32%	$	33,171		(11)%
Property and other taxes		16,579		14,273		16%		14,173		1 %
Depreciation, amortization and impairments		111,904		91,010		23%		90,692		— %

Total general and administrative,
depreciation and other expenses	$	167,597	$	134,923		24%	$	138,036		(2)%

General and administrative expenses increased by $9.5 million for the year ended December 31, 2011, due to an increase of $7.2 million in noncash payroll expenses primarily due to an increase in the collective value of awards under the Western Gas Holdings, LLC Equity Incentive Plan, as amended and restated, from $215.00 per unit to $634.00 per unit and an increase of $2.7 million in corporate and management personnel costs allocated to us pursuant to the omnibus agreement. Property and other taxes increased by $2.3 million for the year ended December 31, 2011, primarily due to the ad valorem tax for the Platte Valley, Bison and Wattenberg assets. Depreciation, amortization and impairments increased by $20.9 million for the year ended December 31, 2011, primarily attributable to the addition of the Platte Valley and Bison assets, depreciation associated with capital projects completed and capitalized at the Wattenberg, Hugoton and Hilight systems, and impairment expense due to the indefinite postponement of an expansion project at the Red Desert complex. See Note 1. Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

General and administrative expenses decreased by $3.5 million for the year ended December 31, 2010, due to the management fee allocated to the Granger assets and Wattenberg assets during the year ended December 31, 2009, then discontinued effective January 2010 and July 2010, respectively, upon contribution of the assets to us. This decrease was partially offset by an increase in corporate and management personnel costs allocated to us pursuant to the omnibus agreement. Depreciation, amortization and impairments increased by approximately $0.3 million for the year ended December 31, 2010, comprised of a $5.5 million increase in depreciation, offset by a $5.2 million decrease in impairment expense. The increase in depreciation expense is primarily attributable to capital projects completed at the Chipeta, Hilight and Hugoton systems, the addition of the Bison assets, and previously leased compressors used at the Granger and Wattenberg systems purchased and contributed to the Partnership during 2010. The decrease in impairment expense is primarily due to a $6.1 million charge taken during the year ended December 31, 2009, as a result of the write-down of an idle MGR pipeline for which no future cash flows were expected. No similar impairment expense was recorded in 2010.

Interest Income and Interest Expense

		000000000		000000000		000000000		000000000		000000000
	Year Ended December 31,
thousands except percentages	2011		2010		D		2009		D
Interest income on note receivable	$	16,900	$	16,900		— %	$	16,900		— %
Interest income, net on affiliate balances		11,660		3,343		nm ⁽¹⁾		3,817		(12)%

Interest income, net – affiliates⁽²⁾	$	28,560	$	20,243		41 %	$	20,717		(2)%


Third Parties
Interest expense on long-term debt	$	(20,533)	$	(8,530)		141 %	$	(304)		nm
Amortization of debt issuance costs
and commitment fees⁽³⁾		(5,297)		(3,340)		59 %		(555)		nm
Capitalized interest		420		—		nm		—		nm
Affiliates
Interest expense on notes payable to Anadarko		(4,935)		(6,828)		(28)%		(8,953)		(24)%
Credit facility commitment fees		—		(96)		(100)%		(143)		(33)%

Interest expense	$	(30,345)	$	(18,794)		61 %	$	(9,955)		89 %

⁽¹⁾	Percent change is not meaningful (“nm”).

⁽²⁾

Represents interest income recognized on the note receivable from Anadarko. Also includes interest income, net on affiliate balances related to the MGR assets, Bison assets, White Cliffs investment and Wattenberg assets for periods prior to the acquisition of such assets. Beginning December 7, 2011, Anadarko discontinued charging interest on intercompany balances. The outstanding affiliate balances on the Partnership assets prior to their acquisition were entirely settled through an adjustment to parent net equity.

⁽³⁾	For the year ended December 31, 2011, includes $0.5 million of amortization of the original issue discount and underwriters’ fees related to the Notes.

Interest expense increased by $11.6 million for the year ended December 31, 2011, due to interest expense incurred on the Notes issued in May 2011 as well as $1.3 million of accelerated amortization expense related to the early repayment of the Wattenberg term loan in March 2011 (described in Liquidity and Capital Resources). The increase was partially offset by lower interest expense on amounts outstanding on our RCF during 2011, a decrease in interest expense on the Note Payable to Anadarko which was amended in December 2010 reducing the interest rate from 4.00% to 2.82% for the remainder of the term, and the repayment of the Wattenberg term loan.

Interest expense increased by $8.8 million for the year ended December 31, 2010, primarily due to interest expense incurred on the amounts outstanding during 2010 under the Wattenberg term loan, our RCF and related commitment fees, and expense incurred on intercompany borrowings associated with assets we acquired.

See Note 10. Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Other Income (Expense), Net

0000000000

Year Ended December 31,

thousands except percentages

2011

2010

2009

Other income (expense), net

(44)

(538)

(92)%

1,628

(133)%

Other income (expense), net for the year ended December 31, 2011, primarily consists of the $1.9 million loss realized on an interest-rate swap agreement entered into in March 2011 and terminated in May 2011 in connection with the offering of the Notes. Other income (expense), net for the year ended December 31, 2010, primarily relates to financial agreements entered into in April 2010 to fix the underlying ten-year Treasury rates with respect to a potential note issuance that was under consideration at that time. Upon reaching our decision not to issue the notes in May 2010, we terminated the agreements at a cost of $2.4 million. For each of the years ended December 31, 2011 and 2010, the aforementioned loss amounts were partially offset by $1.6 million of interest income related to the capital lease component of a processing agreement assumed in connection with the MGR acquisition.

Income Tax Expense

		000000000		000000000		000000000		000000000		000000000
	Year Ended December 31,
thousands except percentages	2011		2010		D		2009		D
Income before income taxes	$	207,364	$	178,899		16 %	$	148,654		20 %
Income tax expense		19,018		21,702		(12)%		22,159		(2)%
Effective tax rate		9%		12%				15%

We are not a taxable entity for U.S. federal income tax purposes, although the portion of our income apportionable to Texas is subject to Texas margin tax. Income attributable to (a) the MGR assets prior to and including December 2011, (b) the Bison assets prior to and including June 2011, (c) the Wattenberg assets prior to and including July 2010 and (d) the Granger assets prior to and including January 2010 were subject to federal and state income tax, resulting in an overall lower income tax expense for the year ended December 31, 2011. Income earned by the Granger, Wattenberg and Bison assets for periods subsequent to January 2010, July 2010 and June 2011, respectively, was subject only to Texas margin tax on the portion of their incomes apportionable to Texas.

For 2011, 2010, and 2009, our variance from the federal statutory rate, which is zero percent as a non-taxable entity, is primarily attributable to federal and state taxes on income attributable to Partnership assets pre-acquisition and our share of Texas margin tax.

Noncontrolling Interests

000000000

Year Ended December 31,

thousands except percentages

2011

2010

2009

Net income attributable to noncontrolling interests

14,103

11,005

28%

10,260

For the year ended December 31, 2011, and 2010, net income attributable to noncontrolling interests increased by $3.1 million and $0.7 million, respectively, primarily due to the higher volumes at the Chipeta system.

Key Performance Metrics

		000000000		000000000		000000000		000000000		000000000
thousands except percentages and gross margin per Mcf	Year Ended December 31,
thousands except percentages and gross margin per Mcf	2011		2010		D		2009		D
Gross margin	$	495,894	$	416,798		19%	$	380,890		9%
Gross margin per Mcf ⁽¹⁾		0.55		0.51		8%		0.46		11%
Gross margin per Mcf attributable to
Western Gas Partners, LP ⁽²⁾		0.58		0.54		7%		0.48		13%
Adjusted EBITDA attributable to
Western Gas Partners, LP ⁽³⁾		324,323		265,024		22%		223,766		18%
Distributable cash flow ⁽³⁾	$	281,975	$	237,769		19%	$	203,376		17%

⁽¹⁾

Average for period. Calculated as gross margin (total revenues less cost of product) divided by total natural gas throughput, including 100% of gross margin and volumes attributable to Chipeta, our 14.81% interest in income and volumes attributable to Fort Union and our 22% interest in income and volumes attributable to Rendezvous.

⁽²⁾

Average for period. Calculated as gross margin, 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 attributable to our investments in Fort Union, White Cliffs and Rendezvous in addition to volumes attributable to our investments in Fort Union and Rendezvous.

⁽³⁾	For a reconciliation of Adjusted EBITDA and Distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with GAAP, please read the descriptions above under the captions How We Evaluate Our Operations within this Item 7.

Gross margin and Gross margin per Mcf. Gross margin increased by $79.1 million for the year ended December 31, 2011, primarily due to the acquisition of the Platte Valley system; the startup of the Bison assets in June 2010; higher margins at the Wattenberg and Chipeta systems, due to an increase in volumes (including the impact of commodity price swap agreements at the Wattenberg system); higher margins at our Red Desert complex due to increased NGL prices during 2011 combined with decreased cost of product as a result of lower volumes processed; and the increase in our interest in White Cliffs from 0.4% to 10% in September 2010. These increases were partially offset by lower gross margin at the MIGC system due to the expiration of certain firm transportation contracts in January 2011 and lower gross margins at the Haley and Hugoton systems due to naturally declining production volumes. For the year ended December 31, 2011, gross margin per Mcf increased by 8% and gross margin per Mcf attributable to Western Gas Partners, LP increased by 7%, primarily due to higher margins combined with lower volumes at our Red Desert complex as noted above; the acquisition of the Platte Valley system in 2011; and changes in the throughput mix of the portfolio.

Gross margin increased by $35.9 million for the year ended December 31, 2010, primarily due to higher fee revenue at the Granger and Wattenberg systems resulting from the change in affiliate contract terms, as well as higher throughput volumes at those systems; the startup of Bison in June 2010; and higher margins at our Red Desert complex due to higher NGL prices and a slight increase in volumes sold. This increase is offset by lower throughput at the Pinnacle, Haley and Dew systems. For the year ended December 31, 2010, gross margin per Mcf increased by 11% and gross margin per Mcf attributable to Western Gas Partners, LP increased by 13%, primarily due to the changes in contract terms mentioned above and changes in the throughput mix within our portfolio.

Adjusted EBITDA. Adjusted EBITDA increased by $59.3 million for the year ended December 31, 2011, primarily due to a $156.4 million increase in total revenues excluding equity income, partially offset by an $80.9 million increase in cost of product, a $15.2 million increase in operation and maintenance expenses and a $0.6 million increase in general and administrative expenses, excluding non-cash equity-based compensation and expenses in excess of the 2010 omnibus cap.

Adjusted EBITDA increased by $41.3 million for the year ended December 31, 2010, primarily due to a $43.8 million increase in total revenues excluding equity income, a $4.0 million decrease in general and administrative expenses excluding non-cash equity-based compensation and expenses in excess of the omnibus cap, and a $2.7 million decrease in operation and maintenance expenses, partially offset by a $7.6 million increase in cost of product.

Distributable cash flow. Distributable cash flow increased by $44.2 million for the year ended December 31, 2011, primarily due to the $59.3 million increase in Adjusted EBITDA and a $0.3 million decrease in cash paid for income taxes, partially offset by a $12.0 million increase in net cash paid for interest expense and a $3.4 million increase in cash paid for maintenance capital expenditures.

Distributable cash flow increased by $34.4 million for the year ended December 31, 2010, primarily due to the $41.3 million increase in Adjusted EBITDA and a $2.5 million decrease in cash paid for maintenance capital expenditures, partially offset by an $8.8 million increase in net cash paid for interest expense and a $0.5 million increase in cash paid for income taxes.

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, while 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 has important limitations as an analytical tool because it excludes some, but not all, items that affect net income and net cash provided by operating activities. You should not consider Adjusted EBITDA or Distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Our definitions of Adjusted EBITDA and Distributable cash flow may not be comparable to similarly titled measures of other companies in our industry, thereby diminishing their utility. Furthermore, while Distributable cash flow is a measure we use to assess our performance and 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.

LIQUIDITY AND CAPITAL RESOURCES

Our primary cash requirements are for acquisitions and other capital expenditures, debt service, customary operating expenses, quarterly distributions to our limited partners and general partner, and distributions to our noncontrolling interest owners. Our sources of liquidity as of December 31, 2011, include cash flows generated from operations, including interest income on our $260.0 million note receivable from Anadarko, available borrowing capacity under our RCF, and issuances of additional common and general partner units or debt securities. We believe that cash flows generated from the sources above 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 results of operations, financial conditions, capital requirements and other factors, and will be determined by the board of directors of our general partner on a quarterly basis. Due to our cash distribution policy, we expect to rely on external financing sources, including debt and common unit issuances, to fund expansion capital expenditures and future acquisitions. However, to limit interest expense, we may use operating cash flows to fund expansion capital expenditures or acquisitions, which could result in subsequent borrowings under our RCF to pay distributions or fund other short-term working capital requirements.

Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date within 45 days of the end of each quarter. We have made cash distributions to our unitholders and have increased our quarterly distribution each quarter since the second quarter of 2009. On January 18, 2012, the board of directors of our general partner declared a cash distribution to our unitholders of $0.44 per unit, or $43.0 million in aggregate, including incentive distributions. The cash distribution is payable on February 13, 2012, to unitholders of record at the close of business on February 1, 2012.

Management continuously monitors our 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 or to refinance outstanding debt balances with longer-term notes. To facilitate a potential debt or equity securities issuance, we have the ability to sell securities under our shelf registration statement. Our ability to generate cash flows is subject to a number of factors, some of which are beyond our control. Please read Item 1A—Risk Factors in our 2011 Form 10-K.

Working capital. As of December 31, 2011, we had $179.9 million of working capital, which we define as the amount by which current assets exceed current liabilities. 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 and 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.

Capital expenditures. Our business is capital intensive, requiring significant investment to maintain and improve existing facilities. We categorize capital expenditures as either of the following:

•

maintenance capital expenditures, which include those expenditures required to maintain the existing operating capacity and service capability of our assets, such as to replace system components and equipment that have been subject to significant use over time, become obsolete or reached the end of their useful lives, to remain in compliance with regulatory or legal requirements or to complete additional well connections to maintain existing system throughput 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 system throughput or capacity from current levels, including well connections that increase existing system throughput.

Capital expenditures in the consolidated statements of cash flows reflect capital expenditures on a cash basis, when payments are made. Capital incurred is presented on an accrual basis. Capital expenditures as presented in the consolidated statements of cash flows and capital incurred were as follows:

		MMMMMM		MMMMMM		MMMMMM
	Year Ended December 31,
thousands	2011		2010		2009
Acquisitions	$	330,794	$	752,827	$	101,451


Expansion capital expenditures	$	114,557	$	113,100	$	93,768
Maintenance capital expenditures		28,389		24,900		27,527

Total capital expenditures ⁽¹⁾	$	142,946	$	138,000	$	121,295


Capital incurred ⁽²⁾	$	148,348	$	143,223	$	109,168

⁽¹⁾

Capital expenditures for the years ended December 31, 2011, 2010 and 2009, includes $2.7 million, $101.2 million and $82.8 million, respectively, of pre-acquisition capital expenditures for the MGR, Bison, Wattenberg and Granger assets and includes the noncontrolling interest owners’ share of Chipeta’s capital expenditures, funded by contributions from the noncontrolling interest owners.

⁽²⁾

Capital incurred for the years ended December 31, 2011, 2010 and 2009, includes $0.9 million, $105.0 million and $76.0 million, respectively, of pre-acquisition capital incurred for the MGR, Bison, Wattenberg and Granger assets and includes the noncontrolling interest owners’ share of Chipeta’s capital incurred, funded by contributions from the noncontrolling interest owners.

Acquisitions include the MGR, Bison, Platte Valley, White Cliffs, Wattenberg, Granger and Chipeta acquisitions as outlined in Note 2. Acquisitions in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Capital expenditures, excluding acquisitions, increased by $4.9 million for the year ended December 31, 2011. Expansion capital expenditures increased by $1.5 million for the year ended December 31, 2011, primarily due to an increase of $39.5 million in expenditures primarily at our Chipeta, Bison, Highlight and Wattenberg systems, partially offset by the purchase of previously leased compressors at the Wattenberg system during the year ended December 31, 2010, for $37.5 million. Maintenance capital expenditures increased by $3.5 million, primarily as a result of maintenance projects at the Wattenberg system and higher well connects at the Hilight system, partially offset by fewer well connections at the Haley and Hugoton systems in 2011 and improvements at the Granger system completed during 2010.

Capital expenditures increased by $16.7 million for the year ended December 31, 2010. Excluding cash paid for acquisitions, expansion capital expenditures for the year ended December 31, 2010, increased by $19.3 million, primarily due to Anadarko commencing the construction of the Bison assets in 2009 and placing them in service in June 2010, in addition to the purchase of previously leased compressors at the Granger and Wattenberg systems during 2010 prior to the Granger and Wattenberg acquisitions, offset by the indefinite postponement of an expansion project at the Red Desert complex, completion of the cryogenic unit at the Chipeta plant and a compressor overhaul at the Hugoton system during 2009. In addition, maintenance capital expenditures decreased by $2.6 million, primarily as a result of fewer well connections.

We estimate our total capital expenditures for the year ending December 31, 2012, including our 51% share of Chipeta’s capital expenditures and excluding acquisitions, to be $410 million to $460 million and our maintenance capital expenditures to be approximately 6% to 10% of total capital expenditures. Expected 2012 capital projects include our 51% share of the costs associated with the completion of a second cryogenic train at the Chipeta plant and the construction of new cryogenic processing plants in Colorado and Texas. 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. 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 RCF, the issuance of additional partnership units or debt offerings.

Historical cash flow. The following table presents a summary of our net cash flows from operating activities, investing activities and financing activities.


	Year Ended December 31,
thousands	2011			2010			2009
Net cash provided by (used in):
Operating activities	$	327,171		$	263,749		$	212,765
Investing activities		(472,951	)		(885,507	)		(223,128	)
Financing activities		345,265			578,848			44,273

Net increase (decrease) in cash and cash equivalents	$	199,485		$	(42,910	)	$	33,910

Operating Activities. Net cash provided by operating activities increased by $63.4 million for the year ended December 31, 2011, primarily due to the following items:

•

a $156.4 million increase in revenues, excluding equity income; and

•

a $19.7 million increase due to changes in accounts payable balances and other items.

The impact of the above items was offset by the following:

•

an $80.9 million increase in cost of product expense;

•

a $15.2 million increase in operation and maintenance expenses;

•

an $11.6 million increase in interest expense;

•

a $4.3 million increase in current income tax expense;

•

a $2.3 million increase in property and other tax expense; and

•

a $1.3 million decrease due to changes in accounts receivable balances.

Net cash provided by operating activities increased by $51.0 million for the year ended December 31, 2010, primarily due to the following items:

•

a $43.8 million increase in revenues, excluding equity income;

•

a $12.7 million increase due to changes in accounts payable balances and other items;

•

a $10.0 million decrease in current income tax expense; and

•

a $2.7 million decrease in operation and maintenance expenses.

The impact of the above items was offset by the following:

•

an $8.8 million increase in interest expense;

•

a $7.6 million increase in cost of product expense; and

•

a $2.2 million decrease due to changes in accounts receivable balances.

Investing Activities. Net cash used in investing activities for the year ended December 31, 2011, included the following:

•

$302.0 million of cash paid for the Platte Valley acquisition;

•

$142.9 million of capital expenditures;

•

$25.0 million of cash paid for the Bison acquisition; and

•

$3.8 million for equipment purchases from Anadarko.

Net cash used in investing activities for the year ended December 31, 2010, included the following:

•

$473.1 million paid for the Wattenberg acquisition;

•

$241.7 million of cash paid for the Granger acquisition;

•

$138.0 million of capital expenditures; and

•

$38.0 million paid for the White Cliffs acquisition.

Offsetting these amounts were $5.6 million of proceeds from the sale of idle compressors to Anadarko and the sale of an idle refrigeration unit at the Granger system to a third party.

Net cash used in investing activities for the year ended December 31, 2009, included the following:

•

$121.3 million of capital expenditures; and

•

$101.5 million paid for the Chipeta acquisition in July 2009.

See the sub-caption Capital expenditures above within this Liquidity and Capital Resources discussion.

Financing Activities. Net cash provided by financing activities for the year ended December 31, 2011, included the following:

•

$493.9 million of net proceeds from our Notes offering in May 2011;

•

$303.0 million of borrowings to fund the Platte Valley acquisition;

•

$250.0 million repayment of the Wattenberg term loan (described below) using borrowings from our RCF;

•

$202.8 million of net proceeds from our September 2011 equity offering; and

•

$132.6 million of net proceeds from our March 2011 equity offering.

Proceeds from both our March 2011 equity offering and Notes offering in May 2011 were used in the $619.0 million repayment of amounts outstanding under our RCF.

Net distributions to Parent attributable to pre-acquisition intercompany balances were $53.0 million during 2011, representing the net non-cash settlement of intercompany transactions attributable to the Bison and MGR assets.

Net cash provided by financing activities for the year ended December 31, 2010, included the following:

•

$450.0 million of borrowings to partially fund the Wattenberg acquisition;

•

$210.0 million to partially fund the Granger acquisition;

•

$246.7 million of net proceeds from the November 2010 equity offering; and

•

$99.1 million of net proceeds from the May 2010 equity offering.

Proceeds from both our May 2010 and November 2010 equity offerings were used in the $361.0 million repayment of amounts outstanding under our RCF.

Net contributions from Parent attributable to pre-acquisition intercompany balances were $39.4 million during 2010, representing the net non-cash settlement of intercompany transactions attributable to the Granger, Wattenberg, Bison and MGR assets.

Net cash provided by financing activities for the year ended December 31, 2009, included the following:

•

$122.5 million of proceeds from the December 2009 equity offering;

•

$101.5 million issuance of the three-year term loan to Anadarko in connection with the Chipeta acquisition, partially offset by its repayment in October 2009; and

•

$4.3 million of costs paid in connection with the RCF we entered into in October 2009.

Proceeds from our December 2009 equity offering were used in the $101.5 million repayment of amounts outstanding under our RCF.

Net distributions to Parent attributable to pre-acquisition intercompany balances were $36.2 million during 2009, representing the net non-cash settlement of intercompany transactions attributable to the Chipeta, Granger, Wattenberg, Bison and MGR assets.

For the years ended December 31, 2011, 2010 and 2009 we paid $140.1 million, $94.2 million and $70.1 million, respectively, of cash distributions to our unitholders. Contributions from noncontrolling interest owners to Chipeta totaled $33.6 million, $2.1 million and $40.3 million during the years ended December 31, 2011, 2010 and 2009, respectively, primarily for expansion of the cryogenic units and plant construction. Distributions from Chipeta to noncontrolling interest owners totaled $17.5 million, $13.2 million and $8.0 million, for the years ended December 31, 2011, 2010 and 2009, respectively, representing the distributions for the four preceding quarterly periods ended September 30^th of the respective year.

Debt and credit facilities. As of December 31, 2011, our outstanding debt consisted of $494.2 million of the Notes and the $175.0 million note payable to Anadarko. See Note 10. Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

5.375% Senior Notes due 2021. In May 2011, we completed the offering of $500.0 million aggregate principal amount of the Notes at a price to the public of 98.778% of the face amount of the Notes. Including the effects of the issuance and underwriting discounts, the effective interest rate is 5.648%. Interest on the Notes is paid semi-annually on June 1 and December 1 of each year, with payments commencing on December 1, 2011. Proceeds from the offering of the Notes (net of the underwriting discount of $3.3 million and debt issuance costs) were used to repay the then-outstanding balance on the RCF, with the remainder used for general partnership purposes.

The Notes mature on June 1, 2021, unless redeemed at a redemption price that includes a make-whole premium. We may redeem the Notes, in whole or in part, at any time before March 1, 2021, at a redemption price equal to the greater of (i) 100% of the principal amount of the Notes to be redeemed or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on such Notes (exclusive of interest accrued to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate (as defined in the indenture governing the Notes) plus 40 basis points, plus, in either case, accrued and unpaid interest, if any, on the principal amount being redeemed to such redemption date. On or after March 1, 2021, the Notes will be redeemable and repayable, at any time in whole, or from time to time in part, at a price equal to 100% of the principal amount of the Notes to be redeemed, plus accrued interest on the Notes to be redeemed to the date of redemption.

The Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our wholly owned subsidiaries (the “Subsidiary Guarantors”). The Subsidiary Guarantors’ guarantees will be released if the Subsidiary Guarantors are released from their obligations under our RCF.

The Notes indenture contains customary events of default including, among others, (i) default in any payment of interest on any debt securities when due that continues for 30 days; (ii) default in payment, when due, of principal of or premium, if any, on the Notes at maturity; and (iii) certain events of bankruptcy or insolvency with respect to the Partnership. The indenture governing the Notes also contains covenants that limit, among other things, our ability, as well as that of the Subsidiary Guarantors to (i) create liens on our principal properties; (ii) engage in sale and leaseback transactions; and (iii) merge or consolidate with another entity or sell, lease or transfer substantially all of our properties or assets to another entity. At December 31, 2011, we were in compliance with all covenants under the Notes.

Note payable to Anadarko. In December 2008, we entered into a five-year $175.0 million term loan agreement with Anadarko. The interest rate was fixed at 4.00% until November 2010. The term loan agreement was amended in December 2010 to fix the interest rate at 2.82% through maturity in 2013. We have the option, at any time, to repay the outstanding principal amount in whole or in part.

The provisions of the five-year term loan agreement contain customary events of default, including (i) non-payment of principal when due or non-payment of interest or other amounts within three business days of when due, (ii) certain events of bankruptcy or insolvency with respect to the Partnership and (iii) a change of control. At December 31, 2011, we were in compliance with all covenants under this agreement.

Revolving credit facility. In March 2011, we entered into an amended and restated $800.0 million senior unsecured RCF and borrowed $250.0 million under the RCF to repay the Wattenberg term loan (described below). The RCF amended and restated our $450.0 million credit facility, which was originally entered into in October 2009. The RCF matures in March 2016 and bears interest at London Interbank Offered Rate (“LIBOR”) plus applicable margins currently ranging from 1.30% to 1.90%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.5%, or (c) LIBOR plus 1%, plus applicable margins currently ranging from 0.30% to 0.90%. We are also required to pay a quarterly facility fee currently ranging from 0.20% to 0.35% of the commitment amount (whether used or unused), based upon our senior unsecured debt rating.

The RCF contains covenants that limit, among other things, our, and certain of our subsidiaries’, ability to incur additional indebtedness, grant certain liens, merge, consolidate or allow any material change in the character of our business, sell all or substantially all of our assets, make certain transfers, enter into certain affiliate transactions, make distributions or other payments other than distributions of available cash under certain conditions and use proceeds other than for partnership purposes. The RCF also contains various customary covenants, customary events of default and certain financial tests as of the end of each quarter, including a maximum consolidated leverage ratio (which is defined as the ratio of consolidated indebtedness as of the last day of a fiscal quarter to Consolidated Earnings Before Interest, Taxes, Depreciation and Amortization (“Consolidated EBITDA”) for the most recent four consecutive fiscal quarters ending on such day) of 5.0 to 1.0, or a consolidated leverage ratio of 5.5 to 1.0 with respect to quarters ending in the 270-day period immediately following certain acquisitions, and a minimum consolidated interest coverage ratio (which is defined as the ratio of Consolidated EBITDA for the most recent four consecutive fiscal quarters to consolidated interest expense for such period) of 2.0 to 1.0.

All amounts due under the RCF are unconditionally guaranteed by our wholly owned subsidiaries. We will no longer be required to comply with the minimum consolidated interest coverage ratio, as well as the subsidiary guarantees and certain of the aforementioned covenants, if we obtain two of the following three ratings: BBB- or better by Standard & Poor’s, Baa3 or better by Moody’s Investors Service, or BBB- or better by Fitch Ratings. As of December 31, 2011, no amounts were outstanding under the RCF, and $800.0 million was available for borrowing. See Note 2. Acquisitions in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K for borrowing activity under our RCF in January 2012, related to the MGR acquisition. At December 31, 2011, we were in compliance with all covenants under the RCF.

Wattenberg term loan. In connection with the Wattenberg acquisition, in August 2010 we borrowed $250.0 million under a three-year term loan from a group of banks (“Wattenberg term loan”). The Wattenberg term loan incurred interest at LIBOR plus a margin ranging from 2.50% to 3.50% depending on our consolidated leverage ratio as defined in the Wattenberg term loan agreement. We repaid the Wattenberg term loan in March 2011 using borrowings from our RCF and recognized $1.3 million of accelerated amortization expense related to its early repayment.

Registered securities. We may issue an indeterminate amount of common units and various debt securities under our effective shelf registration statement on file with the U.S. Securities and Exchange Commission.

Credit risk. We bear credit risk represented by our exposure to non-payment or non-performance by our counterparties, including Anadarko, financial institutions, customers and other parties. Generally, non-payment or non-performance results from a customer’s inability to satisfy payables to us 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 third-party customers.

We are dependent upon a single producer, Anadarko, for the substantial 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, processing and transportation fees and for proceeds from the sale of residue 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, which was issued concurrently with the closing of our initial public offering. We are also party to agreements 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 assets acquired from Anadarko. Finally, we have entered into various commodity price swap agreements with Anadarko in order to reduce our exposure to commodity price risk and are subject to performance risk thereunder.

Our ability to make distributions to our unitholders may be adversely impacted 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, contribution agreements or the commodity price swap agreements.

CONTRACTUAL OBLIGATIONS

The following is a summary of our contractual cash obligations as of December 31, 2011, including the contractual obligations of MGR. See Note 2. Acquisitions in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K. The table below excludes amounts classified as current liabilities on the consolidated balance sheets, other than the current portions of the categories listed within the table. It is expected that the majority of the excluded current liabilities will be paid in cash in 2012.


	Obligations by Period
thousands	2012		2013		2014		2015		2016		Thereafter		Total

Long-term debt
Principal	$	—	$	175,000	$	—	$	—	$	—	$	500,000	$	675,000
Interest		31,810		32,043		26,875		26,875		26,875		119,967		264,445
Asset retirement obligations		875		—		—		1,694		470		61,106		64,145
Capital expenditures		30,203		—		—		—		—		—		30,203
Credit facility fees		2,005		2,000		2,000		2,000		460		—		8,465
Environmental obligations		1,679		481		481		160		160		349		3,310
Operating leases		261		228		168		168		168		103		1,096

Total	$	66,833	$	209,752	$	29,524	$	30,897	$	28,133	$	681,525	$	1,046,664

Debt and credit facility fees. For additional information on notes payable and credit facility fees required under our RCF, see Note 10. Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

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, changes in retirement costs and the estimated timing of settlement. For additional information see Note 9. Asset Retirement Obligations in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Capital expenditures. Included in this amount are capital obligations related to our expansion projects. We have other planned capital and investment projects that are discretionary in nature, with no substantial contractual obligations made in advance of the actual expenditures. See Note 11. Commitments and Contingencies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Environmental obligations. We are subject to various environmental-remediation obligations arising from federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. We regularly monitor the remediation and reclamation process and the liabilities recorded and believe our environmental obligations are adequate to fund remedial actions to comply with present laws and regulations. For additional information on environmental obligations, see Note 11. Commitments and Contingencies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Operating leases. Anadarko, on our behalf, has entered into lease agreements for corporate offices, shared field offices and a warehouse supporting our operations, for which it charges us rent. The amounts above represent existing contractual operating lease obligations that may be assigned or otherwise charged to us pursuant to the reimbursement provisions of the omnibus agreement. See Note 11. Commitments and Contingencies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

For additional information on contracts, obligations and arrangements we enter into from time to time, see Note 5. Transactions with Affiliates and Note 11. Commitments and Contingencies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

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 Note 1. Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

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 25 years. If the depreciable lives of our assets were reduced by 10%, we estimate that annual depreciation expense would increase by approximately $11.2 million, which would result in a corresponding reduction in our operating income.

Impairments of tangible assets. Property, plant and equipment are generally stated at the lower of historical cost less accumulated depreciation or fair value, if impaired. Because acquisitions of assets from Anadarko are transfers of net assets between entities under common control, the Partnership assets acquired by us from Anadarko are initially recorded at Anadarko’s historic carrying value. Assets acquired in a business combination or non-monetary exchange with a third party are initially recorded at fair value. Property, plant and equipment balances are evaluated for potential impairment when events or changes in circumstances indicate that their carrying amounts 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 impairments, 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, processing and transporting the 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 impairments 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.

Impairments of goodwill. Goodwill represents the allocated portion of Anadarko’s midstream goodwill attributed to the assets the Partnership has acquired from Anadarko. The carrying value of Anadarko’s midstream goodwill represents the excess of the purchase price of an entity over the estimated fair value of the identifiable assets acquired and liabilities assumed by Anadarko. Accordingly, our goodwill balance does not reflect, and in some cases is significantly higher than, the difference between the consideration paid by us for acquisitions from Anadarko compared to the fair value of the net assets on the acquisition date. We evaluate whether goodwill has been impaired annually, as of October 1, or more often as facts and circumstances warrant. 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, 2011, was $77.3 million for the gathering and processing reporting unit and $4.8 million for the transportation reporting unit. 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 earnings before interest, taxes, depreciation, and amortization (“EBITDA”). Specifically, management estimates fair value by applying an estimated multiple to projected 2012 EBITDA. Management considered observable transactions in the market, as well as trading multiples for peers, to determine an appropriate multiple to apply against our projected 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, throughput declines, cost increases, regulatory or political environment changes, and other changes in market conditions such as decreased prices in market-based transactions for similar assets. Based on our most recent goodwill impairment test, we concluded that the fair value of each reporting unit substantially exceeded the carrying value of the reporting unit. Therefore, no goodwill impairment was indicated and no goodwill impairment has been recognized in these consolidated financial statements.

Impairments of intangible assets. Our intangible asset balance at December 31, 2011, represents the fair value, net of amortization, of the contracts assumed by the Partnership in connection with the Platte Valley acquisition in February 2011. These long-term contracts, which dedicate certain customers’ field production to the acquired gathering and processing system, provide an extended commercial relationship with the existing customers whereby we will have the opportunity to gather and process future production from the customers’ acreage. Customer relationships are amortized on a straight-line basis over 50 years, which is the estimated productive life of the reserves covered by the underlying acreage ultimately expected to be produced and gathered or processed through the Partnership’s assets subject to current contractual arrangements.

Management assesses intangible assets for impairment, together with the related underlying long-lived assets, whenever events or changes in circumstances indicate that the carrying amount of the respective asset may not be recoverable. Impairments exist when an asset’s carrying amount exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the tested asset. When alternative courses of action to recover the carrying amount are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the tested asset is not recoverable based on the estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying amount over its estimated fair value such that the asset’s carrying amount is adjusted to its estimated fair value with an offsetting charge to operating expense. No intangible asset impairment has been recognized in connection with these assets.

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 and the initial recognition of environmental obligations assumed in third-party acquisitions. 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 utilizes the cost, income, or market valuation approach depending on the quality of information available to support management’s assumptions. 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 multiple 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 any off-balance sheet arrangements other than operating leases. The information pertaining to operating leases required for this item is provided under Note 11. Commitments and Contingencies included in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

RECENT ACCOUNTING DEVELOPMENTS

Recently issued accounting standard not yet adopted. In September 2011, the Financial Accounting Standards Board issued an Accounting Standards Update (“ASU”) that permits an initial assessment of qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount for goodwill impairment testing purposes. Thus, determining a reporting unit’s fair value is not required unless, as a result of the qualitative assessment, it is more likely than not that the fair value of the reporting unit is less than its carrying amount. This ASU is effective prospectively beginning January 1, 2012. Adoption of this ASU will have no impact on our consolidated financial statements.