EX-99.2

EX-99.2 5 d519871dex992.htm EX-99.2 EX-99.2

EXHIBIT 99.2

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

EXECUTIVE SUMMARY

We are a growth-oriented Delaware master limited partnership (“MLP”) organized by Anadarko to own, operate, acquire and develop midstream energy assets. We currently own assets located in East, West and South Texas, the Rocky Mountains (Colorado, Utah and Wyoming), north-central Pennsylvania, and the Mid-Continent (Kansas and Oklahoma) and are engaged in the business of gathering, processing, compressing, treating and transporting natural gas, condensate, NGLs and crude oil for Anadarko, as well as for third-party producers and customers. As of December 31, 2012, we owned and operated twelve natural gas gathering systems, seven natural gas treating facilities, seven natural gas processing facilities, two NGL pipelines, one interstate natural gas pipeline, and one intrastate natural gas pipeline. In addition, including the acquisition of the Non-Operated Marcellus Interest, we had interests in two non-operated natural gas gathering systems, one operated natural gas gathering system and two operated natural gas processing facilities, with separate interests accounted for under the equity method in two natural gas gathering systems and a crude oil pipeline. See also Note 12—Subsequent Events in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Significant financial highlights during the year ended December 31, 2012, include the following:

•

In connection with the closing of the Western Gas Equity Partners, LP (“WGP”) IPO, we sold 8,722,966 common units to WGP and 178,019 general partner units to our general partner. Net proceeds of $409.4 million are being used for general partnership purposes and the funding of capital expenditures.

•

We issued $670.0 million aggregate principal amount of 4.000% Senior Notes due 2022. Net proceeds were used to repay all amounts then outstanding under our revolving credit facility (“RCF”) and the note payable to Anadarko, with the remaining net proceeds used for general partnership purposes. See Liquidity and Capital Resources within this Item 7 for additional information.

•

We issued 5,000,000 common units to the public, generating net proceeds of $216.4 million, including the general partner’s proportionate capital contribution to maintain its 2.0% general partner interest. Net proceeds are being used for general partnership purposes, including the funding of capital expenditures. See Equity Offerings under Items 1 and 2 of our 2012 Form 10-K for additional information.

•

We completed the acquisition of Anadarko’s MGR assets located in Southwestern Wyoming in January and the acquisition of Anadarko’s then remaining 24% interest in Chipeta in August. See Acquisitions under Items 1 and 2 of our 2012 Form 10-K for additional information.

•

We announced two growth projects: (i) the expansion of our processing capacity by 300 MMcf/d at our Wattenberg system with the construction of the Lancaster plant, and (ii) the construction of a new 200 MMcf/d cryogenic processing plant in the Maverick Basin, referred to as the Brasada plant. Startup is anticipated in the first quarter of 2014 for the Lancaster plant and the second quarter of 2013 for the Brasada plant. See Liquidity and Capital Resources within this Item 7 for additional information.

•

We raised our distribution to $0.52 per unit for the fourth quarter of 2012, representing a 4% increase over the distribution for the third quarter of 2012, an 18% increase over the distribution for the fourth quarter of 2011, and our fifteenth consecutive quarterly increase.

Significant operational highlights during the year ended December 31, 2012, include the following:

•

Throughput attributable to Western Gas Partners, LP totaled 2,795 MMcf/d for the year ended December 31, 2012, representing a 13% increase compared to the year ended December 31, 2011.

•

Gross margin (total revenues less cost of product) attributable to Western Gas Partners, LP averaged $0.54 per Mcf for the year ended December 31, 2012, representing a 7% decrease compared to the year ended December 31, 2011.

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. Our general partner, Western Gas Holdings, LLC (the “general partner” or “GP”), is owned by Western Gas Equity Partners, LP (“WGP”), a Delaware master limited partnership formed by Anadarko Petroleum Corporation. Western Gas Equity Holdings, LLC is WGP’s general partner and is a wholly owned subsidiary of Anadarko Petroleum Corporation. “Anadarko” refers to Anadarko Petroleum Corporation and its consolidated subsidiaries, excluding the Partnership and our general partner, and “affiliates” refers to wholly owned and partially owned subsidiaries of Anadarko, excluding the Partnership, and includes the interests in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”), and Rendezvous Gas Services, LLC (“Rendezvous”). “Equity method investment throughput” refers to our 14.81% share of Fort Union and 22% share of Rendezvous gross volumes.

References to the “Partnership assets” refer collectively to the assets we owned as of December 31, 2012, including the Non-Operated Marcellus Interest. Because Anadarko controls us through its ownership and control of WGP, which owns our general partner, each of our acquisitions of assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets we acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by us (see Note 2—Acquisitions in the Notes to the Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K). Further, after an acquisition of assets from Anadarko, we may be required to recast our financial statements to include the activities of such assets as of the date of common control. The consolidated financial statements for periods prior to our acquisition of the Partnership assets from Anadarko 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 from Anadarko as being “our” historical financial results.

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, 2012, approximately 76% of our total revenues and 62% of our throughput (excluding equity investment revenues and throughput) were 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 our Wattenberg, Dew, Pinnacle, Haley, Helper, Clawson and Hugoton gathering systems. Specifically, pursuant to the terms of our applicable gathering agreements, 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, 2012, approximately 70% of our gross margin was attributed to fee-based contracts, under which a fixed fee is received based on the volume or 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 (i) we retain and sell drip condensate that is recovered during the gathering of natural gas from the wellhead or (ii) actual recoveries differ from contractual recoveries under a limited number of processing agreements. Fee-based gross margin includes equity income from our interests in Fort Union, White Cliffs and Rendezvous.

For the year ended December 31, 2012, approximately 30% of our gross margin, including gross margin attributable to condensate sales, was attributable to percent-of-proceeds and keep-whole contracts, pursuant to which we have commodity price exposure. A substantial majority of the commodity price risk associated with our percent-of-proceeds and keep-whole contracts is hedged under commodity price swap agreements with Anadarko. For the year ended December 31, 2012, approximately 98% of our gross margin was derived from either long-term, fee-based contracts or from percent-of-proceeds or keep-whole agreements that were hedged with commodity price swap agreements. See Note 5—Transactions with Affiliates in 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 2012 Form 10-K.

As a result of our IPO and subsequent acquisitions from Anadarko and third parties, the results of operations, financial position and cash flows may vary significantly for 2012, 2011 and 2010 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, 2012, excluding the acquisition of the Non-Operated Marcellus Interest, we added 139 receipt points to our systems with initial throughput of approximately 1.7 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 amounts attributable to costs incurred on our behalf and allocations of general and administrative costs by Anadarko and the general partner to us. For periods subsequent to our acquisition of the Partnership assets, Anadarko is no longer compensated for corporate services through a management services fee. Instead, allocations and reimbursements of general and administrative expenses are determined by Anadarko in its reasonable discretion, in accordance with our partnership agreement and omnibus agreement. Amounts required to be reimbursed to Anadarko under the omnibus agreement also 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.

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.

Non-GAAP financial measures

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 expense reimbursement cap provided in our omnibus agreement (which cap is no longer effective), interest expense, income tax expense, depreciation, amortization and impairments, and other expense, less income from equity investments, interest income, income tax benefit, and other income. 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, 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. Adjusted EBITDA and Distributable cash flow should not be considered 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	2012		2011		2010
Reconciliation of Adjusted EBITDA to Net income attributable to Western Gas Partners, LP
Adjusted EBITDA attributable to Western Gas Partners, LP	$	377,929	$	361,653	$	264,694
Less:
Distributions from equity investees		20,660		15,999		10,973
Non-cash equity-based compensation expense ⁽¹⁾		73,508		13,754		4,787
Expenses in excess of omnibus cap		—		—		133
Interest expense		42,060		30,345		18,794
Income tax expense		20,715		32,150		21,517
Depreciation, amortization and impairments ⁽²⁾		118,279		110,380		88,307
Other expense ⁽²⁾		1,665		3,683		2,393
Add:
Equity income, net		16,111		11,261		7,628
Interest income, net – affiliates		16,900		24,106		20,243
Other income ^{(2) (3)}		368		2,049		267

Net income attributable to Western Gas Partners, LP	$	134,421	$	192,758	$	145,928


Reconciliation of Adjusted EBITDA to Net cash provided by operating activities
Adjusted EBITDA attributable to Western Gas Partners, LP	$	377,929	$	361,653	$	264,694
Adjusted EBITDA attributable to noncontrolling interests		17,214		16,850		13,823
Interest income (expense), net		(25,160)		(6,239)		1,449
Expenses in excess of omnibus cap		—		—		(133)
Non-cash equity based compensation expense⁽¹⁾		(69,791)		(10,264)		(2,220)
Debt-related amortization and other items, net		2,319		3,110		1,705
Current income tax expense		9,398		(15,570)		(11,978)
Other income (expense), net ⁽³⁾		(1,292)		(1,628)		(2,122)
Distributions from equity investees less than (in excess of) equity income, net		(4,549)		(4,738)		(3,345)
Changes in operating working capital:
Accounts receivable and natural gas imbalance receivable		23,520		(47,415)		(14,661)
Accounts payable, accrued liabilities and natural gas imbalance payable		5,045		30,884		5,407
Other		3,393		(13,805)		279

Net cash provided by operating activities	$	338,026	$	312,838	$	252,898


Cash flow information of Western Gas Partners, LP
Net cash provided by operating activities	$	338,026	$	312,838	$	252,898
Net cash used in investing activities	$	(1,249,942)	$	(479,722)	$	(921,398)
Net cash provided by financing activities	$	1,105,338	$	366,369	$	625,590

⁽¹⁾

Includes $69.8 million of equity-based compensation associated with the Incentive Plan (as defined and described in 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), paid and contributed by Anadarko during the year ended December 31, 2012.

⁽²⁾	Includes our 51% share prior to August 1, 2012, and our 75% share after August 1, 2012, of depreciation, amortization and impairments; other expense; and other income attributable to Chipeta.

⁽³⁾

Excludes income of $1.6 million for each of the years ended December 31, 2012, 2011 and 2010, respectively, related to a component of a gas processing agreement accounted for as a capital lease. 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.


	Year Ended December 31,
thousands except Coverage ratio	2012			2011		2010
Reconciliation of Distributable cash flow to Net income attributable to Western Gas Partners, LP and calculation of the Coverage ratio
Distributable cash flow	$	309,945		$	319,294	$	237,372
Less:
Distributions from equity investees		20,660			15,999		10,973
Non-cash equity-based compensation expense⁽¹⁾		73,508			13,754		4,787
Expenses in excess of omnibus cap		—			—		133
Interest expense, net (non-cash settled)		326			—		—
Income tax expense		20,715			32,150		21,517
Depreciation, amortization and impairments ⁽²⁾		118,279			110,380		88,307
Other expense ⁽²⁾		1,665			3,683		2,393
Add:
Equity income, net		16,111			11,261		7,628
Cash paid for maintenance capital expenditures ^{(2) (3)}		36,459			28,304		24,921
Capitalized interest		6,196			420		—
Cash paid for income taxes		495			190		507
Other income ^{(2) (4)}		368			2,049		267
Interest income, net (non-cash settled)		—			7,206		3,343

Net income attributable to Western Gas Partners, LP	$	134,421		$	192,758	$	145,928


Distributions declared ⁽⁵⁾
Limited partners	$	190,123
General partner		30,358

Total	$	220,481

Coverage ratio		1.41	x

⁽¹⁾

⁽²⁾	Includes our 51% share prior to August 1, 2012, and our 75% share after August 1, 2012, of depreciation, amortization and impairments; other expense; cash paid for maintenance capital expenditures; and other income attributable to Chipeta.

⁽³⁾	Net of a prior period adjustment reclassifying approximately $0.7 million from capital expenditures to operating expenses for the year ended December 31, 2012.

⁽⁴⁾

⁽⁵⁾	Reflects distributions of $1.96 per unit declared for the year ended December 31, 2012.

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:

Gathering and processing agreements. The gathering agreements of our initial assets and the Non-Operated Marcellus Interest allow for rate resets that target a return on invested capital in those assets over the life of the agreement. Effective July 1, 2010, contracts covering all of Wattenberg’s affiliate throughput were converted from primarily keep-whole contracts into a 10-year fee-based agreement. This contract change impacts the comparability of the consolidated statements of income and cash flows. In addition, in connection with the MGR acquisition, we entered into 10-year, fee-based gathering and processing agreements with Anadarko effective December 1, 2011, for all affiliate throughput on the MGR assets. 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 commodity price 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 Granger, Hilight, Hugoton, Newcastle, MGR and Wattenberg assets, with various expiration dates through December 2016. In December 2011, we extended the commodity price swap agreements for the Hilight and Newcastle assets through December 2013. 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.

Income taxes. Income earned by the Partnership, a non-taxable entity for U.S. federal income tax purposes, including and subsequent to the date of the acquisition of the Partnership assets, is subject only to Texas margin tax.

With respect to assets acquired from Anadarko, we record Anadarko’s historic current and deferred income taxes for the periods prior to our ownership of the assets. For periods subsequent to our acquisitions from Anadarko, we are not subject to tax except for the Texas margin tax and accordingly, do not record current and deferred federal income taxes related to such assets.

General and administrative expenses. Pursuant to the omnibus agreement, Anadarko and the general partner perform centralized corporate functions for us. Prior to our acquisition of the Partnership assets from Anadarko, 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, 2012, 2011 and 2010, we reimbursed Anadarko $14.9 million, $11.8 million and $9.0 million, respectively, in general and administrative expenses. Prior to December 31, 2010, the general and administrative expenses for which we reimbursed Anadarko were subject to a cap as set forth in the omnibus agreement. In addition, our general and administrative expenses for the year ended December 31, 2010, included $0.1 million of expenses incurred by Anadarko and the general partner in excess of the cap contained in the omnibus agreement. Such expenses were recorded as capital contributions from Anadarko and did not impact the Partnership’s cash flows. The amounts reimbursed 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 acquisition of the Partnership assets from Anadarko. Our public company expenses, such as external audit and consulting fees, that were reimbursed to Anadarko were $6.8 million, $7.7 million and $8.0 million, during the years ended December 31, 2012, 2011 and 2010, respectively. We record the equity-based compensation allocated to us by Anadarko as an adjustment to partners’ capital in our consolidated financial statements in the period in which it is contributed. During the fourth quarter of 2012, we were allocated $54.9 million of general and administrative expenses from Anadarko associated with the Incentive Plan. 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 information.

Interest on intercompany balances. For periods prior to our acquisition of the Partnership assets from Anadarko, 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 IPO, the Powder River acquisition, the Chipeta acquisition, the Granger acquisition, the Wattenberg acquisition, the acquisition of a 0.4% interest in White Cliffs, the Bison acquisition, the MGR acquisition and the Non-Operated Marcellus Interest 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. Chipeta cash settles its transactions directly with third parties and Anadarko, as well as with the other subsidiaries of the Partnership.

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

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 RCF. These assets, acquired from a third-party, have been recorded in our 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 in 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.

Noncontrolling interests. Prior to August 1, 2012, the 24% membership interest in Chipeta held by Anadarko and the 25% membership interest in Chipeta held by a third-party were reflected as noncontrolling interests in our consolidated financial statements for the years ended December 31, 2011 and 2010. On August 1, 2012, we acquired Anadarko’s then remaining 24% membership interest in Chipeta, receiving distributions related to this additional interest beginning July 1, 2012. Since we acquired an additional interest in an already-consolidated entity, the acquisition of Anadarko’s then remaining 24% membership interest was accounted for on a prospective basis. As such, effective August 1, 2012, our noncontrolling interest excludes the financial results and operations of the additional Chipeta interest. The remaining 25% membership interest held by a third-party member is reflected as noncontrolling interests in our consolidated financial statements for all periods presented. See Note 1—Summary of Significant Accounting Policies and 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 further information.

Execution of COO Agreement for the Non-Operated Marcellus Interest. In March 2013, we completed the acquisition of the Non-Operated Marcellus Interest. Anadarko and a third party entered into a 50/50 Joint Exploration Agreement, dated September 1, 2006, covering counties in north-central Pennsylvania within an Area of Mutual Interest that the parties designated as “Area A.” Initial construction of the midstream assets within Area A began in May 2008, and limited gathering services were provided to producers in 2008, 2009 and 2010, with the midstream assets becoming fully operational in 2011. In December 2011, following various sales of interests, AMM and three third-party owners (the “system owners”) entered into a Construction, Ownership and Operation agreement (the “COO Agreement”) to jointly own and develop the midstream assets in Area A (the “AMI Assets”). Deferred revenues and expenses associated with the third-party operation of the AMI Assets were recognized in 2011 upon the execution of the COO Agreement.

GENERAL TRENDS AND OUTLOOK

We expect our business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from expected results.

Impact of natural gas and NGL prices. The relatively low natural gas price environment, which has persisted over the past three years, has led to lower levels of drilling activity in areas 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 in those areas. 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 capital markets financing or, in some cases, temporarily made such financing unavailable. If we are unable either to access the 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 2012. 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. As of December 31, 2012, Anadarko’s total domestic midstream asset portfolio, excluding the assets we own, consisted of 16 gathering systems, approximately 4,559 miles of pipeline and 8 processing and/or treating facilities. A key component of our growth strategy is to acquire midstream assets from Anadarko and third parties over time.

As of December 31, 2012, WGP and affiliates held a 46.2% limited partner interest in us, and through its ownership of our general partner, indirectly held a 2.0% general partner interest in us and 100% of our incentive distribution rights (“IDRs”). Given Anadarko’s significant interests in us, we believe Anadarko will continue to be motivated to promote and support the successful execution of our business plan and to pursue projects that help to enhance the value of our business. 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:


	Year Ended December 31,
thousands	2012		2011		2010
Gathering, processing and transportation of natural gas and natural gas liquids	$	382,330	$	347,469	$	253,273
Natural gas, natural gas liquids and condensate sales		508,339		502,383		396,037
Equity income and other, net		19,918		19,553		13,964

Total revenues ⁽¹⁾		910,587		869,405		663,274
Total operating expenses ⁽¹⁾		715,693		624,111		485,735

Operating income		194,894		245,294		177,539
Interest income, net – affiliates		16,900		24,106		20,243
Interest expense		(42,060)		(30,345)		(18,794)
Other income (expense), net		292		(44)		(538)

Income before income taxes		170,026		239,011		178,450
Income tax expense		20,715		32,150		21,517

Net income		149,311		206,861		156,933
Net income attributable to noncontrolling interests		14,890		14,103		11,005

Net income attributable to Western Gas Partners, LP	$	134,421	$	192,758	$	145,928

Key Performance Metrics ⁽²⁾
Gross margin	$	574,508	$	542,034	$	416,798
Adjusted EBITDA attributable to Western Gas Partners, LP	$	377,929	$	361,653	$	264,694
Distributable cash flow	$	309,945	$	319,294	$	237,372

⁽¹⁾

Revenues include amounts earned from services provided to our affiliates, as well as from the sale of residue, 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 and Distributable cash flow are defined under the caption Key Performance Metrics within this Item 7. Such caption also includes reconciliations of Adjusted EBITDA and Distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with GAAP.

For purposes of the following discussion, any increases or decreases “for the year ended December 31, 2012” refer to the comparison of the year ended December 31, 2012 to the year ended December 31, 2011, and 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.

Operating Statistics


	Year Ended December 31,
throughput in MMcf/d	2012		2011		D		2010		D
Gathering, treating and transportation ⁽¹⁾		1,601		1,555		3%		1,181		32%
Processing ⁽²⁾		1,187		962		23%		815		18%
Equity investment ⁽³⁾		235		198		19%		228		(13)%

Total throughput ⁽⁴⁾		3,023		2,715		11%		2,224		22%
Throughput attributable to noncontrolling interests		228		242		(6)%		197		23%

Total throughput attributable to Western Gas Partners, LP		2,795		2,473		13%		2,027		22%

⁽¹⁾	Excludes average NGL pipeline volumes of 25 MBbls/d, 24 MBbls/d and 14 MBbls/d for the years ended December 31, 2012, 2011 and 2010, respectively. Includes 100% of Wattenberg system volumes for all periods presented.

⁽²⁾	Consists of 100% of Chipeta and Hilight system volumes, 100% of the Granger and Red Desert complex volumes, 50% of Newcastle volumes, and 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 our 10% share of average White Cliffs pipeline volumes consisting of 6 MBbls/d, 4 MBbls/d and 3 MBbls/d for the years ended December 31, 2012, 2011 and 2010, respectively.

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

Gathering, treating and transportation throughput increased by 46 MMcf/d for the year ended December 31, 2012, primarily due to increased drilling behind the Non-Operated Marcellus Interest. This increase was partially offset by throughput decreases at the Pinnacle and Dew systems resulting from natural production declines in those areas; throughput decreases at MIGC due to the September 2012 expiration of a firm transportation agreement; and throughput decreases at the Bison facility resulting from reduced drilling activity in the area driven by unfavorable producer economics.

Gathering, treating and transportation throughput increased by 374 MMcf/d for the year ended December 31, 2011, primarily due to the execution of the COO Agreement governing the Non-Operated Marcellus Interest in December 2011, which triggered the recognition of the related throughput, and the startup of the Bison assets in June 2010. 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, and Dew systems resulting from natural production declines in those areas.

Processing throughput increased by 225 MMcf/d for the year ended December 31, 2012, primarily due to volumes processed at a plant included in the MGR acquisition under a new contract effective January 2012, with no volumes in the comparable period, and throughput increases at the Chipeta system resulting from increased drilling activity. 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.

Equity investment volumes increased by 37 MMcf/d for the year ended December 31, 2012, resulting from higher throughput at the Fort Union system due to producers choosing to route additional gas to reach desired end markets and at the Rendezvous system due to increased third-party drilling activity. 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.

Natural Gas Gathering, Processing and Transportation Revenues


	Year Ended December 31,
thousands except percentages	2012		2011		D		2010		D
Gathering, processing and transportation of natural gas and natural gas liquids	$	382,330	$	347,469		10%	$	253,273		37%

Gathering, processing and transportation of natural gas and natural gas liquids revenues increased by $34.9 million for the year ended December 31, 2012, primarily due to increases of $15.0 million and $13.4 million at the Non-Operated Marcellus Interest and Chipeta system, respectively, due to increased volumes, and a $13.6 million increase at the Wattenberg system due to increased gathering rates and volumes. These increases were partially offset by decreased revenue of $3.0 million at the Helper system due to a downward rate revision effective April 1, 2012, decreased revenue of $3.0 million at MIGC due to the expiration of firm transportation agreements, and decreased revenue of $2.4 million at the Granger system due to diverted volumes.

Gathering, processing and transportation of natural gas and natural gas liquids revenues increased by $94.2 million for the year ended December 31, 2011, primarily due to the execution of the COO Agreement governing the Non-Operated Marcellus Interest in December 2011, which resulted in an increase of $46.1 million; the acquisition of the Platte Valley system in February 2011, which resulted in an increase of $23.5 million; the June 2010 startup of the Bison assets, which resulted in an increase of $19.3 million; and increased fee revenue of $15.3 million 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 of $8.5 million at MIGC due to the January 2011 expiration of certain contracts, an aggregate decrease of $6.4 million due to decreased volume resulting from 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.

Natural Gas, Natural Gas Liquids and Condensate Sales


thousands except percentages and per-unit amounts	Year Ended December 31,
thousands except percentages and per-unit amounts	2012		2011		D		2010		D

Natural gas sales	$	101,116	$	129,939		(22)%	$	91,452		42%
Natural gas liquids sales		377,377		345,375		9%		279,915		23%
Drip condensate sales		29,846		27,069		10%		24,670		10%

Total	$	508,339	$	502,383		1%	$	396,037		27%


Average price per unit:
Natural gas (per Mcf)	$	4.24	$	5.32		(20)%	$	5.17		3%
Natural gas liquids (per Bbl)	$	48.22	$	47.44		2%	$	39.94		19%
Drip condensate (per Bbl)	$	75.88	$	73.60		3%	$	70.50		4%

Including the effects of commodity price swap agreements, total natural gas, natural gas liquids and condensate sales increased by $6.0 million for the year ended December 31, 2012, which consisted of a $32.0 million increase in NGLs sales and a $2.8 million increase in drip condensate sales, partially offset by a $28.8 million decrease in natural gas sales.

For the year ended December 31, 2012, the increase in NGLs sales was primarily due to increases of $10.3 million, $9.2 million, and $3.1 million resulting from higher volumes sold at the Chipeta, Hilight, and Wattenberg systems, respectively; increases of $5.1 million and $2.3 million at the Granger system and Red Desert complex, respectively, due to increased pricing, offset by a decrease in volumes; and an increase of $9.6 million related to volumes processed at a plant included in the MGR acquisition under a new contract effective January 2012, with no volumes in the comparable period. These increases were partially offset by an $8.5 million price-related decrease at the Platte Valley system.

The increase in drip condensate sales for the year ended December 31, 2012, was primarily due to a $2.9 million increase at the Wattenberg system and a $0.7 million increase at the Platte Valley system, both resulting from increased volumes. These increases were partially offset by a $0.8 million decrease at the Hugoton system as a result of lower volumes.

The decrease in natural gas sales was primarily due to a 20% decrease in overall natural gas sales prices and lower sales volumes for a decrease of $17.0 million at the Hilight system, a decrease of $3.8 million at the Red Desert complex, and a decrease of $2.7 million at the Wattenberg system. Also contributing to the overall decrease in natural gas sales was a decline at the Platte Valley system of $3.2 million resulting from price decreases, partially offset by an increase in volumes sold.

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 $65.5 million increase in NGLs sales, a $38.5 million increase in natural gas sales and a $2.4 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 MGR assets for which commodity price swap agreements were not effective until January 1, 2012. These increases were partially offset by a decrease 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. 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 was primarily due to a higher average sales price at the Wattenberg and Hugoton systems and Platte Valley sales.

The average natural gas and NGL prices for the year ended December 31, 2012, include the effects of commodity price swap agreements attributable to sales for the Granger, Hilight, Hugoton, Newcastle and Wattenberg systems, and the MGR assets. The average natural gas and NGLs prices for the years ended December 31, 2011 and 2010, include the effects of commodity price swap agreements attributable to sales for the Granger, Hilight, Hugoton, Newcastle and Wattenberg 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


	Year Ended December 31,
thousands except percentages	2012		2011		D		2010		D

Equity income	$	16,111	$	11,261		43%	$	7,628		48%
Other revenues, net		3,807		8,292		(54)%		6,336		31%

Total	$	19,918	$	19,553		2%	$	13,964		40%

Equity income increased by $4.9 million for the year ended December 31, 2012, primarily due to the increase in income from White Cliffs of $3.8 million and from Rendezvous of $0.7 million as a result of increased volumes. 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 decreased by $4.5 million for the year ended December 31, 2012, primarily due to indemnity fees associated with volume commitments received in the prior year at the Red Desert complex and Hugoton system, with no comparable activity in the current period, along with changes in gas imbalance positions at the Wattenberg and Hilight systems. Other revenues, net increased by $2.0 million for the year ended December 31, 2011, primarily due to the collection of deficiency fees associated with volume commitments, predominantly associated with MGR gathering agreements.

Cost of Product and Operation and Maintenance Expenses


	Year Ended December 31,
thousands except percentages	2012		2011		D		2010		D
Cost of product	$	336,079	$	327,371		3%	$	246,476		33%
Operation and maintenance		140,106		126,464		11%		103,887		22%

Total cost of product and operation and maintenance expenses	$	476,185	$	453,835		5%	$	350,363		30%

Including the effects of commodity price swap agreements on purchases, cost of product expense increased by $8.7 million for the year ended December 31, 2012, primarily due to a $22.8 million increase attributable to higher pricing and increases in purchases of NGL volumes at the Chipeta system for an increase of $12.3 million, at the Hilight system for an increase of $6.4 million, and at the Wattenberg system for an increase of $2.1 million. In addition, cost of product expense for NGL purchases increased by $4.7 million for the MGR assets due to commodity price swap agreements beginning January 2012. Partially offsetting the increase in NGL purchases was a $3.5 million decrease at the Platte Valley system due to lower pricing subsequent to its acquisition in February 2011.

Cost of product expense also increased by $4.9 million due to the higher cost of residue purchases at the MGR assets resulting from commodity price swap agreements beginning January 2012, offset by a $15.3 million decrease at the Hilight system due to declines in residue purchase prices. The impact of other gathering purchases and changes in gas imbalance positions decreased cost of product by $2.4 million.

Cost of product expense increased by $80.9 million for the year ended December 31, 2011, primarily consisting of a $51.5 million increase due to increased throughput at the Hilight and Chipeta systems and a $44.4 million increase due to the acquisition of the Platte Valley system. These increases were partially offset by a $9.0 million decrease due to decreased throughput at the Red Desert complex and a $6.2 million decrease due to changes in gas imbalance positions.

Cost of product expense for the year ended December 31, 2012, includes the effects of commodity price swap agreements attributable to purchases for the Granger, Hilight, Hugoton, Newcastle and Wattenberg systems, and for the MGR assets. Cost of product expense for the year ended December 31, 2011, includes the effects of commodity price swap agreements attributable to purchases for the Granger, Hilight, Hugoton, Newcastle, and Wattenberg 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.

Operation and maintenance expense increased by $13.6 million for the year ended December 31, 2012, primarily due to increased contract labor expense of $5.1 million at the Platte Valley and Wattenberg systems, increased expense of $1.1 million related to general equipment for operations and increased maintenance expense at the Wattenberg system, increased expense of $1.7 million related to plant repairs and turnaround expenses at the Bison facility and Hilight system, and increased facility expense of $0.8 million at the Non-Operated Marcellus Interest.

Operation and maintenance expense increased by $22.6 million for the year ended December 31, 2011, primarily due to an increase of $12.1 million resulting from the acquisition of the Platte Valley system, an increase of $7.4 million due to the execution of the COO Agreement governing the Non-Operated Marcellus Interest in December 2011, and an increase of $3.8 million resulting from the June 2010 startup of the Bison assets. These increases were partially offset by a $1.8 million reduction in compressor lease expenses resulting from the purchase of compressors used at the Wattenberg system leased during 2010.

General and Administrative, Depreciation and Other Expenses


	Year Ended December 31,
thousands except percentages	2012		2011		D		2010		D
General and administrative	$	99,212	$	40,564		145%	$	29,970		35%
Property and other taxes		19,688		16,579		19%		14,273		16%
Depreciation, amortization and impairments		120,608		113,133		7%		91,129		24%

Total general and administrative, depreciation and other expenses	$	239,508	$	170,276		41%	$	135,372		26%

General and administrative expenses increased by $58.6 million for the year ended December 31, 2012, due to an increase of $59.8 million in non-cash compensation expenses primarily attributable to the increase in the value of the outstanding awards under the Incentive Plan from $634.00 per Unit Appreciation Right (“UAR”) to $2,745.00 per UAR and the related increase of $1.2 million in payroll taxes. In addition, corporate and management personnel costs for which we reimbursed Anadarko pursuant to our omnibus agreement increased $3.6 million. These increases were partially offset by a $3.9 million decrease in management fees allocated to the Bison and MGR assets, the agreements for which were discontinued as of the respective dates of contribution, and a $1.2 million decrease in consulting and audit fees.

General and administrative expenses increased by $10.6 million for the year ended December 31, 2011, due to an increase of $7.2 million in non-cash payroll expenses primarily due to an increase in the collective value of awards under the Incentive Plan, from $215.00 per UAR to $634.00 per UAR and an increase of $2.7 million in corporate and management personnel costs for which we reimbursed Anadarko pursuant to the omnibus agreement.

Property and other taxes increased by $3.1 million for the year ended December 31, 2012, primarily due to ad valorem tax increases at the Platte Valley and Wattenberg assets.

Property and other taxes increased by $2.3 million for the year ended December 31, 2011, primarily due to ad valorem tax increases for the Platte Valley, Bison and Wattenberg assets.

Depreciation, amortization and impairments increased by $7.5 million for the year ended December 31, 2012, primarily attributable to the addition of the Platte Valley assets, and depreciation associated with capital projects completed at the Wattenberg, Hilight, and Chipeta systems, the Non-Operated Marcellus Interest, and the Red Desert complex, partially offset by a $3.9 million decrease in impairment expense. The decrease is primarily due to a $6.6 million impairment recognized during 2012 related to a gathering system in central Wyoming and a relocated compressor, as compared to $10.3 million in impairment expense recognized during 2011, related to an indefinitely postponed expansion project at the Red Desert complex and a pipeline included in the MGR acquisition. See Note 7—Property, Plant and Equipment in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

Depreciation, amortization and impairments increased by $22.0 million for the year ended December 31, 2011, primarily attributable to the addition of the Platte Valley and Bison assets, depreciation associated with the Non-Operated Marcellus Interest, 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.

Interest Income, Net – Affiliates and Interest Expense


	Year Ended December 31,
thousands except percentages	2012		2011		D	2010		D
Interest income on note receivable	$	16,900	$	16,900	—%	$	16,900	—%
Interest income, net on affiliate balances⁽²⁾		—		7,206	(100)%		3,343	116%

Interest income, net – affiliates	$	16,900	$	24,106	(30)%	$	20,243	19%


Third parties
Interest expense on long-term debt	$	(41,171)	$	(20,533)	101%	$	(8,530)	141%
Amortization of debt issuance costs and commitment fees⁽³⁾		(4,319)		(5,297)	(18)%		(3,340)	59%
Capitalized interest⁽⁴⁾		6,196		420	nm⁽¹⁾		—	nm
Affiliates
Interest expense on note payable to Anadarko⁽⁵⁾		(2,440)		(4,935)	(51)%		(6,828)	(28)%
Interest expense, net on affiliate balances⁽⁶⁾		(326)		—	nm		—	nm
Credit facility commitment fees		—		—	nm		(96)	(100)%

Interest expense	$	(42,060)	$	(30,345)	39%	$	(18,794)	61%

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

⁽²⁾

Incurred on affiliate balances related to the Non-Operated Marcellus Interest, the MGR assets, the Bison assets, the White Cliffs investment and the 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 net investment by Anadarko.

⁽³⁾

For the year ended December 31, 2012, includes $1.1 million of amortization of (i) the original issue discount for the June 2012 offering partially offset by the original issue premium for the October 2012 offering of the 2022 Notes, as defined below, (ii) original issue discount for the 2021 Notes, as defined below, and (iii) underwriters’ fees. For the year ended December 31, 2011, includes $0.5 million of amortization of the original issue discount and underwriters’ fees for the 2021 Notes. 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.

⁽⁴⁾

For the year ended December 31, 2012, $2.2 million of interest associated with capital projects at Chipeta was capitalized and $3.5 million of interest associated with the construction of the Brasada and Lancaster gas processing facilities was capitalized. 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.

⁽⁵⁾	In June 2012, the note payable to Anadarko was repaid in full. 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.

⁽⁶⁾

Imputed interest expense on the reimbursement payable to Anadarko for certain expenditures incurred in 2011 related to the construction of the Brasada and Lancaster plants. During the year ended December 31, 2012, the reimbursement payable to Anadarko related to the construction of the Brasada and Lancaster plants was repaid. 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.

Interest expense increased by $11.7 million for the year ended December 31, 2012, primarily due to interest expense incurred on the $670.0 million aggregate principal amount of 4.000% Senior Notes due 2022 (the “2022 Notes”), partially offset by increased capitalized interest associated with the construction of a second cryogenic train at the Chipeta plant and a decrease in interest expense on the 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).

Interest expense increased by $11.6 million for the year ended December 31, 2011, due to interest expense incurred on the $500.0 million aggregate principal amount of 5.375% Senior Notes due 2021 (the “2021 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 (as defined in Liquidity and Capital Resources within this Item 7) in March 2011. 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.

Other Income (Expense), Net

Year Ended December 31,

thousands except percentages

2012

2011

2010

Other income (expense), net

292

(44)

(538)

(92)%

For the year ended December 31, 2012, other income (expense), net was primarily comprised of $1.6 million of interest income related to the capital lease component of a processing agreement assumed in connection with the MGR acquisition, primarily offset by a realized loss of $1.7 million resulting from U.S. Treasury Rate lock agreements settled simultaneously with our June 2012 issuance of the 2022 Notes (see Note 10—Debt and Interest Expense included in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K). For the year ended December 31, 2011, other income (expense), net was primarily comprised of a $1.9 million loss realized upon termination of an interest-rate swap agreement in May 2011, concurrent with the issuance of the 2021 Notes. For the year ended December 31, 2010, other income (expense), net was primarily comprised of a $2.4 million loss realized upon termination of financial agreements entered into in April 2010 to fix the underlying 10-year Treasury rates with respect to a potential note issuance that was not realized. 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 discussed above.

Income Tax Expense


	Year Ended December 31,
thousands except percentages	2012		2011		D		2010		D
Income before income taxes	$	170,026	$	239,011		(29)%	$	178,450		34%
Income tax expense		20,715		32,150		(36)%		21,517		49%
Effective tax rate		12%		13%				12%

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

Income attributable to (a) the Non-Operated Marcellus Interest prior to and including February 2013, (b) the MGR assets prior to and including January 2012, (c) the Bison assets prior to and including June 2011, (d) the Wattenberg assets prior to and including July 2010 and (e) the Granger assets prior to and including January 2010, were subject to federal and state income tax. Income earned by the Non-Operated Marcellus Interest and the MGR, Bison, Wattenberg and Granger assets for periods subsequent to February 2013, January 2012, June 2011, July 2010 and January 2010, respectively, was subject only to Texas margin tax on the portion of their incomes apportionable to Texas.

Noncontrolling Interests


	Year Ended December 31,
thousands except percentages	2012		2011		D		2010		D

Net income attributable to noncontrolling interests	$	14,890	$	14,103		6%	$	11,005		28%

For the years ended December 31, 2012 and 2011, net income attributable to noncontrolling interests increased by $0.8 million and $3.1 million, respectively, primarily due to higher volumes at the Chipeta system. For the year ended December 31, 2012, the increase was partially offset by the acquisition of Anadarko’s then remaining 24% membership interest in Chipeta in August 2012. See Note 2—Acquisitions included in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K.

KEY PERFORMANCE METRICS


thousands except percentages and gross margin per Mcf	Year Ended December 31,
thousands except percentages and gross margin per Mcf	2012		2011		D		2010		D
Gross margin	$	574,508	$	542,034		6%	$	416,798		30%
Gross margin per Mcf ⁽¹⁾		0.52		0.55		(5)%		0.51		8%
Gross margin per Mcf attributable to Western Gas Partners, LP^{(1) (2)}		0.54		0.58		(7)%		0.54		7%
Adjusted EBITDA attributable to Western Gas Partners, LP⁽³⁾		377,929		361,653		5%		264,694		37%
Distributable cash flow⁽³⁾	$	309,945	$	319,294		(3)%	$	237,372		35%

⁽¹⁾

Average for period. Calculated as gross margin (total revenues less cost of product) divided by total throughput (excluding throughput measured in barrels), 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. Gross margin also includes 100% of gross margin attributable to our NGL pipelines and our 10% interest in income attributable to White Cliffs.

⁽²⁾	Excludes the noncontrolling interest owners’ proportionate share of revenues, cost of product and throughput.

⁽³⁾	For reconciliations 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 caption Reconciliation to GAAP measures under Non-GAAP financial measures.

Gross margin and Gross margin per Mcf. Gross margin increased by $32.5 million for the year ended December 31, 2012, primarily due to higher margins at the Non-Operated Marcellus Interest and at the Wattenberg and Chipeta systems due to increases in volumes sold (including the impact of commodity price swap agreements at the Wattenberg system). These increases were partially offset by lower gross margins at the Red Desert complex due to higher prices in 2011, as we entered into commodity price swap agreements associated with the MGR acquisition that became effective in January 2012.

Gross margin increased by $125.2 million for the year ended December 31, 2011, primarily due to the December 2011 execution of the COO Agreement governing the Non-Operated Marcellus Interest, the acquisition of the Platte Valley system; the startup of the Bison assets in June 2010; higher margins at the Wattenberg and Chipeta systems (including the impact of commodity price swap agreements at the Wattenberg system), due to an increase in volumes; and higher margins at our Red Desert complex due to increased NGL prices during 2011. 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 system due to naturally declining production volumes.

For the year ended December 31, 2012, gross margin per Mcf decreased by $0.03, primarily due to a decrease in volumes sold at the Red Desert complex coupled with an increase in cost of product as a result of commodity price swap agreements associated with the MGR acquisition which became effective in January 2012, partially offset by increases associated with growth in certain of our lower-margin assets.

For the year ended December 31, 2011, gross margin per Mcf increased by $0.04, 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 our portfolio.

Adjusted EBITDA. Adjusted EBITDA increased by $16.3 million for the year ended December 31, 2012, primarily due to a $36.3 million increase in total revenues excluding equity income, a $4.7 million increase in distributions from equity investees, and a $1.1 million decrease in general and administrative expenses excluding non-cash equity-based compensation. These increases were partially offset by a $13.6 million increase in operation and maintenance expenses, an $8.7 million increase in cost of product, a $3.1 million increase in property and other tax expense, and a $0.8 million increase in net income attributable to noncontrolling interests.

Adjusted EBITDA increased by $97.0 million for the year ended December 31, 2011, primarily due to a $202.5 million increase in total revenues excluding equity income, partially offset by an $80.9 million increase in cost of product, a $22.6 million increase in operation and maintenance expenses and a $1.8 million increase in general and administrative expenses, excluding non-cash equity-based compensation and expenses in excess of the 2010 omnibus cap.

Distributable cash flow. Distributable cash flow decreased by $9.3 million for the year ended December 31, 2012, primarily due to a $17.2 million increase in net cash paid for interest expense, an $8.2 million increase in cash paid for maintenance capital expenditures and a $0.3 million increase in cash paid for income taxes, partially offset by the $16.3 million increase in Adjusted EBITDA.

Distributable cash flow increased by $81.9 million for the year ended December 31, 2011, primarily due to the $97.0 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.

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 owner. Our sources of liquidity as of December 31, 2012, included cash and cash equivalents, 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 equity or debt securities. We believe that cash flows generated from these sources will be sufficient to satisfy our short-term working capital requirements and long-term maintenance and expansion capital expenditure requirements. The amount of future distributions to unitholders will depend on our results of operations, financial condition, 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 equity and debt issuances, to fund expansion capital expenditures, and fund 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 each quarter since our IPO and have increased our quarterly distribution each quarter since the second quarter of 2009. On January 21, 2013, the board of directors of our general partner declared a cash distribution to our unitholders of $0.52 per unit, or $65.7 million in aggregate, including incentive distributions. The cash distribution was paid on February 12, 2013, to unitholders of record at the close of business on February 1, 2013.

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 statements. 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 of our 2012 Form 10-K.

Working capital. As of December 31, 2012, we had $291.9 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 or develop new midstream infrastructure. 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 expenditures to construct new midstream infrastructure and 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:


	Year Ended December 31,
thousands	2012		2011		2010
Acquisitions	$	611,719	$	330,794	$	752,827


Expansion capital expenditures	$	600,893	$	121,318	$	148,925
Maintenance capital expenditures		37,228		28,399		24,966

Total capital expenditures ⁽¹⁾	$	638,121	$	149,717	$	173,891


Capital incurred ⁽²⁾	$	690,041	$	182,536	$	147,069

⁽¹⁾

Capital expenditures for the year ended December 31, 2012, included $6.8 million of capitalized interest. Capital expenditures included the noncontrolling interest owners’ share of Chipeta’s capital expenditures, funded by contributions from the noncontrolling interest owners for all periods presented. Capital expenditures for the years ended December 31, 2012, 2011 and 2010, included $178.8 million, $20.1 million and $137.1 million, respectively, of pre-acquisition capital expenditures for the Non-Operated Marcellus Interest and the MGR, Bison, Wattenberg and Granger assets.

⁽²⁾

Capital incurred for the year ended December 31, 2012, included $6.8 million of capitalized interest. Capital incurred for the years ended December 31, 2012, 2011 and 2010, included $160.9 million, $45.7 million and $108.9 million, respectively, of pre-acquisition capital incurred for the Non-Operated Marcellus Interest and the MGR, Bison, Wattenberg and Granger assets and included the noncontrolling interest owners’ share of Chipeta’s capital incurred, funded by contributions from the noncontrolling interest owners.

Acquisitions included Anadarko’s remaining 24% membership interest in Chipeta, and the MGR, Bison, Platte Valley, White Cliffs, Wattenberg and Granger 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 $488.4 million for the year ended December 31, 2012. Expansion capital expenditures increased by $479.6 million for the year ended December 31, 2012, primarily due to an increase of $189.3 million related to the construction of the Brasada and Lancaster gas processing facilities, $167.3 million in expenditures for the Non-Operated Marcellus Interest, $127.3 million in expenditures at our Wattenberg, Chipeta, and Platte Valley systems and at the Red Desert complex, and $6.8 million of capitalized interest expense. These increases were partially offset by a $7.2 million decrease related to the Bison assets due to the continued startup costs incurred in early 2011, and a $1.2 million decrease at the Granger complex. Maintenance capital expenditures increased by $8.8 million, primarily as a result of increased expenditures of $10.0 million due to higher well connects at the Non-Operated Marcellus Interest, the Platte Valley and Haley systems, and the Red Desert complex, partially offset by $2.3 million in 2011 improvements at the Hugoton system.

Capital expenditures, excluding acquisitions, decreased by $24.2 million for the year ended December 31, 2011. Expansion capital expenditures decreased by $27.6 million for the year ended December 31, 2011, primarily due to a $29.1 decrease in expenditures for the Non-Operated Marcellus Interest, the purchase of previously leased compressors at the Wattenberg system during the year ended December 31, 2010, for $37.5 million, partially offset by an increase of $39.5 million in expenditures primarily at our Chipeta, Bison, Hilight and Wattenberg systems. Maintenance capital expenditures increased by $3.4 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.

We estimate our total capital expenditures for the year ending December 31, 2013, including our 75% share of Chipeta’s capital expenditures and excluding acquisitions, to be $550 million to $600 million and our maintenance capital expenditures to be approximately 5% to 10% of total capital expenditures. Expected 2013 capital projects include the continued construction of new cryogenic processing plants in Northeast Colorado and South 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 and discussion presents a summary of our net cash flows provided by (used in) operating activities, investing activities and financing activities:


	Year Ended December 31,
thousands	2012		2011		2010

Net cash provided by (used in):
Operating activities	$	338,026	$	312,838	$	252,898
Investing activities		(1,249,942)		(479,722)		(921,398)
Financing activities		1,105,338		366,369		625,590

Net increase (decrease) in cash and cash equivalents	$	193,422	$	199,485	$	(42,910)

Operating Activities. For expanded discussion, refer to Operating Results within this Item 7. Net cash provided by operating activities increased by $25.2 million for the year ended December 31, 2012, primarily due to the following items:

•

an increase of $62.3 million of working capital changes and other items, net, due to accruals of expected future operating cash receipts and cash payments;

•

a $36.3 million increase in revenues, excluding equity income, due to increased drilling activity in certain of our operating areas, increased average commodity prices pursuant to commodity price swap agreements and the addition of the Platte Valley assets in March 2011;

•

a $25.0 million decrease in current income tax expense, due to income earned by assets acquired from Anadarko being subject to federal and state income tax prior to our acquisition;

•

a $4.9 million increase in equity income, due to the increase in income from White Cliffs and Rendezvous; and

•

a $0.3 million increase in other income (expense), net.

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

•

a $58.4 million increase in general and administrative expenses, excluding an increase of $0.2 million of non-cash equity-based compensation expense under the Anadarko Incentive Plans and the LTIP, primarily due to the vesting and settlement of the Incentive Plan awards during the fourth quarter of 2012;

•

a $13.6 million increase in operation and maintenance expense, primarily due to increased expenses at the Platte Valley and Wattenberg systems;

•

a $12.5 million increase in interest expense, primarily due to the 2022 Notes offering in June 2012 and October 2012, excluding a decrease of $0.8 million of debt-related amortization expense and other items, net;

•

an $8.7 million increase in cost of product expense, due to increased processing throughput as a result of increased drilling activity in certain of our operating areas, partially offset by pricing received at Platte Valley;

•

a $7.2 million decrease in interest income related to Bison and MGR affiliate balances for periods prior to our acquisition of such assets from Anadarko in July 2011 and January 2012, respectively, partially offset by interest income related to affiliate balances of the Non-Operated Marcellus Interest; and

•

a $3.1 million increase in property and other taxes expense.

Net cash provided by operating activities increased by $59.9 million for the year ended December 31, 2011, primarily due to the following items:

•

a $202.5 million increase in revenues, excluding equity income, due to the execution of the COO Agreement governing the Non-Operated Marcellus Interest, increased processing throughput as a result of increased drilling activity in certain of our operating areas, and the addition of the Platte Valley assets in March 2011.

The impact of these items was partially offset by the following:

•

an $80.9 million increase in cost of product expense, due to increased processing throughput as a result of increased drilling activity in certain of our operating areas and additional throughput from the Platte Valley assets beginning in March 2011;

•

a $22.6 million increase in operation and maintenance expenses, due to the execution of the COO Agreement governing the Non-Operated Marcellus Interest in December 2011, the addition of the Platte Valley system in March 2011, as well as the June 2010 startup of the Bison assets;

•

a decrease of $21.4 million of working capital changes and other items, net, due to accruals of expected future operating cash receipts and cash payments;

•

a $10.1 million increase in interest expense, excluding an increase of $1.4 million of debt-related amortization expense and other items, net, primarily due to the 2021 Notes offering in May 2011;

•

a $3.6 million increase in current income tax expense, due to income earned by assets acquired from Anadarko in 2011 being subject to higher federal and state income tax for the 2011 pre-acquisition period as compared to 2010; and

•

a $2.3 million increase in property and other tax expense, primarily due to ad valorem taxes for the Platte Valley, Bison and Wattenberg assets beginning in March 2011, July 2011, and August 2010, respectively.

Investing Activities. Net cash used in investing activities for the year ended December 31, 2012, included the following:

•

$638.1 million of capital expenditures;

•

$458.6 million of cash paid for the MGR acquisition;

•

$128.3 million of cash paid for the additional 24% membership interest in Chipeta; and

•

$24.7 million of cash paid for equipment purchases from Anadarko.

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;

•

$149.7 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;

•

$173.9 million of capital expenditures;

•

$38.0 million paid for the White Cliffs acquisition; and

•

a $5.6 million offset related to 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.

Financing Activities. Net cash provided by financing activities for the year ended December 31, 2012, included the following:

•

$511.3 million and $156.4 million of net proceeds from our 2022 Notes offerings in June 2012 and October 2012, respectively, after original issue premiums and discounts, underwriting discounts and offering costs;

•

$409.4 million of net proceeds from the issuance of WES common and general partner units sold in connection with the closing of the WGP IPO;

•

$299.0 million of borrowings to fund the MGR acquisition; and

•

$216.4 million of net proceeds from our June 2012 equity offering.

Proceeds from our 2022 Notes offering were used to repay amounts outstanding under our RCF and our note payable to Anadarko.

Net contributions from Anadarko attributable to intercompany balances were $171.1 million during 2012, attributable to the Non-Operated Marcellus Interest acquisition, the compensation expense allocated to us since the inception of the Incentive Plan and the settlement of intercompany transactions attributable to the Bison assets.

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

•

$493.9 million of net proceeds from our 2021 Notes offering in May 2011, after underwriting and original issue discounts and offering costs;

•

$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 our 2021 Notes offering and our March 2011 equity offering were used to repay $619.0 million of borrowings outstanding under our RCF.

Net distributions to Anadarko attributable to pre-acquisition intercompany balances were $36.0 million during 2011, attributable to the Non-Operated Marcellus Interest acquisition and the net non-cash settlement of intercompany transactions attributable to the MGR and Bison 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;

•

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

•

$210.0 million to partially fund the Granger acquisition; and

•

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

Proceeds from our May 2010 and November 2010 equity offerings were used to repay $361.0 million of borrowings outstanding under our RCF.

Net contributions from Anadarko attributable to pre-acquisition intercompany balances were $91.0 million during 2010, attributable to the Non-Operated Marcellus Interest acquisition and the net non-cash settlement of intercompany transactions attributable to the Granger, Wattenberg, Bison and MGR assets.

For the years ended December 31, 2012, 2011 and 2010, we paid $197.9 million, $140.1 million and $94.2 million, respectively, of cash distributions to our unitholders. Contributions from noncontrolling interest owners to Chipeta totaled $29.1 million, $33.6 million and $2.1 million during the years ended December 31, 2012, 2011 and 2010, respectively, primarily for expansion of the cryogenic units and plant construction. Distributions from Chipeta to noncontrolling interest owners totaled $17.3 million, $17.5 million and $13.2 million for the years ended December 31, 2012, 2011 and 2010, respectively, representing the distributions for the four preceding quarterly periods ended September 30^th of the respective year.

Debt and credit facility. As of December 31, 2012, the carrying value of our outstanding debt consisted of $673.6 million of the 2022 Notes and $494.7 million of the 2021 Notes. 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.

Senior Notes. In June 2012, we completed the offering of $520.0 million aggregate principal amount of 4.000% Senior Notes due 2022 at a price to the public of 99.194% of the face amount. In October 2012, we issued an additional $150.0 million in aggregate principal amount of 4.000% Senior Notes due 2022 at a price to the public of 105.178% of the face amount. The additional notes were issued under the same indenture as, and as a single class of securities with, the June 2012 issuance. The notes issued in June 2012 and in October 2012 are referred to as the “2022 Notes.” Including the effects of the issuance discount for the June 2012 offering, the issuance premium for the October 2012 offering, and underwriting discounts, the effective interest rate of the 2022 Notes was 4.040%. Interest is paid semi-annually on January 1 and July 1 of each year. Proceeds (net of underwriting discounts of $4.4 million and debt issuance costs) were used to repay all amounts then outstanding under our RCF and the $175.0 million note payable to Anadarko (see below), with the remaining net proceeds used for general partnership purposes.

The 2022 Notes mature on July 1, 2022, unless redeemed at a redemption price that includes a make-whole premium. We may redeem the 2022 Notes in whole or in part, at any time before April 1, 2022, at a redemption price equal to the greater of (i) 100% of the principal amount of the 2022 Notes to be redeemed or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on such 2022 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 2022 Notes) plus 37.5 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 April 1, 2022, the 2022 Notes may be redeemed, at any time in whole, or from time to time in part, at a price equal to 100% of the principal amount of the 2022 Notes to be redeemed, plus accrued interest on the 2022 Notes to be redeemed to the date of redemption.

In May 2011, we completed the offering of the 2021 Notes at a price to the public of 98.778% of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rate is 5.648%. Interest on the 2021 Notes is paid semi-annually on June 1 and December 1 of each year. Proceeds from the offering of the 2021 Notes (net of the underwriting discount of $3.3 million and debt issuance costs) were used to repay the then-outstanding balance on the Partnership’s RCF, with the remainder used for general partnership purposes. Upon issuance, the 2021 Notes were fully and unconditionally guaranteed on a senior unsecured basis by each of our wholly owned subsidiaries (the “Subsidiary Guarantors”). The Subsidiary Guarantors’ guarantees were immediately released on June 13, 2012, upon the Subsidiary Guarantors becoming released from their obligations under our RCF, as discussed below.

The 2021 Notes mature on June 1, 2021, unless redeemed at a redemption price that includes a make-whole premium. We may redeem the 2021 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 2021 Notes to be redeemed or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on such 2021 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 2021 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 2021 Notes may be redeemed, at any time in whole, or from time to time in part, at a price equal to 100% of the principal amount of the 2021 Notes to be redeemed, plus accrued interest on the 2021 Notes to be redeemed to the date of redemption.

The indentures governing the 2022 Notes and the 2021 Notes contain customary events of default including, among others, (i) default for 30 days in the payment of interest when due; (ii) default in payment, when due, of principal of or premium, if any, at maturity, upon redemption or otherwise; and (iii) certain events of bankruptcy or insolvency. The indentures also contain covenants that limit, among other things, our ability, as well as that of certain of our subsidiaries, 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, 2012, we were in compliance with all covenants under the indentures.

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. In June 2012, the note payable to Anadarko was repaid in full with proceeds from the issuance of the 2022 Notes.

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 a $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%, in each case plus applicable margins currently ranging from 0.30% to 0.90%. The interest rate was 1.71% and 1.80% at December 31, 2012 and 2011, respectively. 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 facility fee rate was 0.25% at December 31, 2012 and 2011.

On June 13, 2012, following the receipt of a second investment grade rating as defined in the RCF, the guarantees provided by our wholly owned subsidiaries were released, and we are no longer subject to certain of the restrictive covenants associated with the RCF, including the maintenance of an interest coverage ratio and adherence to covenants that limit, among other things, our ability, and that of certain of our subsidiaries, to dispose of assets and make certain investments or payments. The RCF continues to contain certain covenants that limit, among other things, our ability, and that of certain of our subsidiaries, to incur additional indebtedness, grant certain liens, merge, consolidate or allow any material change in the character of our business, enter into certain affiliate transactions and use proceeds other than for partnership purposes. The RCF also contains various customary covenants, customary events of default and a maximum consolidated leverage ratio as of the end of each fiscal quarter (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. As of December 31, 2012, we had no outstanding borrowings and $6.7 million in outstanding letters of credit issued under our $800.0 million RCF. At December 31, 2012, we were in compliance with all remaining covenants under the RCF. Refer to Note 2—Acquisitions and Note 12—Subsequent Events in the Notes to Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K for a discussion of borrowing activity under the RCF in March 2013, related to acquisitions which closed after December 31, 2012.

The 2022 Notes, the 2021 Notes and obligations under the RCF are recourse to our general partner. In turn, our general partner has been indemnified by a wholly owned subsidiary of Anadarko against any claims made against the general partner under the 2022 Notes, the 2021 Notes and/or 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 statements on file with the U.S. Securities and Exchange Commission.

In August 2012, we filed a registration statement with the SEC authorizing the issuance of up to $125.0 million of our common units in amounts, at prices and on terms to be determined by market conditions and other factors at the time of our offerings. As of December 31, 2012, we had not issued any common units under this registration statement.

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. A substantial portion of our throughput, however, comes from producers that have investment-grade ratings.

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, 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, Anadarko’s note payable to us, our 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, 2012, including the contractual obligations of the Non-Operated Marcellus Interest. 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 2013.


	Obligations by Period
thousands	2013		2014		2015		2016		2017		Thereafter		Total

Long-term debt
Principal	$	—	$	—	$	—	$	—	$	—	$	1,170,000	$	1,170,000
Interest		53,161		53,143		53,124		53,105		53,084		210,648		476,265
Asset retirement obligations		1,711		184		1,490		119		—		63,219		66,723
Capital expenditures		55,878		—		—		—		—		—		55,878
Credit facility fees		2,000		2,000		2,000		460		—		—		6,460
Environmental obligations		799		485		485		171		171		541		2,652
Operating leases		235		169		169		169		169		42		953

Total	$	113,784	$	55,981	$	57,268	$	54,024	$	53,424	$	1,444,450	$	1,778,931

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 that the amounts reflected in our recorded 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 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, 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 23 years. If the depreciable lives of our assets were reduced by 10%, we estimate that annual depreciation expense would increase by approximately $14.6 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, our 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.

During the fourth quarter of 2012, we recognized a $6.0 million impairment related to a gathering system in central Wyoming that was impaired to its estimated fair value using Level 3 fair-value inputs. Also in the fourth quarter of 2012, an impairment of $0.6 million was recognized for the original installation costs on a compressor relocated within our operating assets.

During the year ended December 31, 2011, we recognized a $7.3 million impairment related to certain equipment and materials. The costs of the equipment and materials, previously capitalized as assets under construction and related to a Red Desert complex expansion project, were deemed no longer recoverable as the expansion project was indefinitely postponed by Anadarko management. Subsequent to the project evaluation and impairment, the remaining fair value of the equipment and materials was reclassified from within property, plant and equipment to other assets on the consolidated balance sheet and was approximately $10.6 million as of December 31, 2011. Also during 2011, following an evaluation of future cash flows, an impairment of $3.0 million was recognized for a transportation pipeline that was impaired to its estimated fair value using Level 3 fair-value inputs.

During the year ended December 31, 2010, we recognized a $0.6 million impairment related to a compressor sold during the year to a third party, and a $0.3 million impairment due to cancelled capital projects and additional costs recorded on a project previously impaired to salvage value.

Impairments of goodwill. Goodwill represents the allocated portion of Anadarko’s midstream goodwill attributed to the assets we have 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 acquired.

We evaluate whether goodwill has been impaired annually as of October 1, unless facts and circumstances make it necessary to test more frequently. Accounting standards require that goodwill be assessed for impairment at the reporting unit level. 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, 2012, was $100.5 million for the gathering and processing reporting unit and $4.8 million for the transportation reporting unit.

The first step in assessing whether an impairment of goodwill is necessary is an optional qualitative assessment to determine the likelihood of whether the fair value of the reporting unit is greater than its carrying amount. If we conclude that the fair value of the reporting unit more than likely exceeds the related carrying amount, then goodwill is not impaired and further testing is not necessary. If the qualitative assessment is not performed or indicates the fair value of the reporting unit may be less than its carrying amount, we would compare the estimated fair value of the reporting unit to which goodwill is assigned to the carrying amount of the associated net assets, including goodwill, and determine whether an impairment is necessary. In this manner, estimating the fair value of our reporting units was not necessary based on the evaluation as of October 1, 2012. However, fair-value estimates of our reporting units may be required for goodwill impairment testing in the future, and if the carrying amount of a reporting unit exceeds its fair value, goodwill is written down to the implied fair value 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, when necessary. Management uses information available to make these fair value estimates, including market multiples of earnings before interest, taxes, depreciation, and amortization (“EBITDA”). Specifically, our management estimates fair value by applying an estimated multiple to projected 2013 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, based on a qualitative assessment, that it is more likely than not that the fair value of each reporting unit 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 as of December 31, 2012 and 2011, represents the fair value, net of amortization, of the contracts we assumed 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.

In November 2012, Chipeta entered into interconnect agreements with a third party, whereby the third party will construct, own and operate an inlet interconnect to the Chipeta plant and a redelivery interconnect from the Chipeta plant. Chipeta will pay the third party $3.7 million and will be granted access rights to the third-party infrastructure, thereby providing us the ability to enter into processing agreements with additional third-party producers. Our intangible asset balance as of December 31, 2012, includes this payment, which will be amortized on a straight-line basis over the 10-year life of the agreements.

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 our 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 multiples 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

None.