EXHIBIT 99.2

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

Western Gas Partners, LP is a growth-oriented master limited partnership (“MLP”) formed by Anadarko Petroleum Corporation in 2007. For purposes of this report, “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 subsidiaries, excluding us and our general partner, and “affiliates” refers to subsidiaries of Anadarko, excluding us, and includes equity interests in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”), Rendezvous Gas Services, LLC (“Rendezvous”), Enterprise EF78 LLC (the “Mont Belvieu JV”), Texas Express Pipeline LLC (“TEP”), Texas Express Gathering LLC (“TEG”) and Front Range Pipeline LLC (“FRP”). The interests in TEP, TEG and FRP are referred to collectively as the “TEFR Interests.” “Equity investment throughput” refers to our 14.81% share of average Fort Union throughput and our 22% share of average Rendezvous throughput, but excludes throughput measured in barrels, consisting of our 10% share of average White Cliffs throughput, our 25% share of average Mont Belvieu JV throughput, our 20% share of average TEP and TEG throughput and our 33.33% share of average FRP throughput.

References to the “Partnership assets” refer collectively to the assets we owned and our interests accounted for under the equity method as of December 31, 2013, including the TEFR Interests. Because Anadarko controls us through its ownership and control of WGP, which owns our general partner, each of our acquisitions of Partnership 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 Consolidated Financial Statements under Item 8 of Exhibit 99.3 to this Current Report on Form 8-K). Further, after an acquisition of Partnership assets from Anadarko, we may be required to recast our financial statements to include the activities of the Partnership assets as of the date of common control. For those periods requiring recast, the consolidated financial statements for periods prior to our acquisition of the Partnership assets from Anadarko, including the TEFR Interests, 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 Partnership 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.

The following discussion analyzes our financial condition and results of operations and should be read in conjunction with the 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.

EXECUTIVE SUMMARY

We are a growth-oriented MLP formed by Anadarko to own, operate, acquire and develop midstream energy assets. We currently have investments in or own assets located in the Rocky Mountains (Colorado, Utah and Wyoming), the Mid-Continent (Kansas and Oklahoma), north-central Pennsylvania, and Texas, 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, 2013, our assets and investments accounted for under the equity method, including the TEFR Interests, consisted of the following:

	Owned and Operated	Operated Interests	Non-Operated Interests	Equity Interests
Natural gas gathering systems	13	1	5	2
NGL gathering systems	—	—	—	2
Natural gas treating facilities	8	—	—	1
Natural gas processing facilities	8	3	—	2
NGL pipelines	3	—	—	2
Natural gas pipelines	3	—	—	—
Oil pipeline	—	—	—	1

See alsoNote 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 and operational highlights during the year ended December 31, 2013 included the following:

• We issued $250.0 million aggregate principal amount of 2.600% Senior Notes due 2018. Net proceeds were used to repay amounts then outstanding under our revolving credit facility. See Liquidity and Capital Resources within this Item 7 for additional information.

• We completed construction and commenced operations in June 2013 of the 200 MMcf/d Brasada processing and stabilization facility in the Eagleford shale area of South Texas.

• We announced a project to expand the processing capacity at our Lancaster plant by another 300 MMcf/d with a second cryogenic processing train. The expansion project is currently under construction.

• We completed the following acquisitions: (i) Anadarko’s 33.75% interest (non-operated) in the Liberty and Rome gas gathering systems in north-central Pennsylvania, (ii) a third party’s 33.75% interest (operated by Anadarko) in each of the Larry’s Creek, Seely and Warrensville gas gathering systems, also in north-central Pennsylvania, (iii) a 25% interest in the Mont Belvieu JV, an entity formed to design, construct and own two NGL fractionation trains located in Mont Belvieu, Texas, and (iv) Overland Trail Transmission, LLC, which owns and operates a natural gas pipeline connecting our Red Desert and Granger complexes in southwestern Wyoming. See Acquisitions under Items 1 and 2 of our 2013 Form 10-K for additional information.

• We issued 12,200,735 common units to the public, generating net proceeds of $740.3 million, including the general partner’s proportionate capital contribution to maintain its 2.0% general partner interest. Net proceeds were used to repay a portion of the amount outstanding under our revolving credit facility, with the remaining net proceeds used for general partnership purposes, including the funding of capital expenditures.

• We raised our distribution to $0.60 per unit for the fourth quarter of 2013, representing a 3%increase over the distribution for the third quarter of 2013, a 15%increase over the distribution for the fourth quarter of 2012, and our nineteenth consecutive quarterly increase.

Significant operational highlights during the year ended December 31, 2013 included the following:

• Throughput attributable to Western Gas Partners, LP for natural gas assets totaled 3,200 MMcf/d for the year ended December 31, 2013, representing a 14%increase compared to the year ended December 31, 2012.

• Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets (as defined under the caption Key Performance Metrics within this Item 7) averaged $0.56 per Mcf for the year ended December 31, 2013, representing a 6%increase compared to the year ended December 31, 2012.

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OUR OPERATIONS

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, 2013, 78% of our total revenues and 57% of our throughput (excluding equity investment throughput and throughput measured in barrels) 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, 2013, 74% of our gross margin was attributable 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, Rendezvous, the Mont Belvieu JV and the TEFR Interests.

For the year ended December 31, 2013, 26% 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, 2013, 99% 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 2013 Form 10-K.

As a result of our initial public offering (“IPO”) and subsequent acquisitions from Anadarko and third parties, our results of operations, financial position and cash flows may vary significantly for 2013, 2012 and 2011 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) operating and maintenance expenses, (3) general and administrative expenses, (4) Adjusted gross margin (as defined below), (5) Adjusted EBITDA (as defined below) and (6) Distributable cash flow (as defined below).

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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, 2013, excluding the acquisition of the TEFR Interests, we added 273 receipt points to our systems.

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. Operating 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 the date of 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 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.

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Non-GAAP financial measures

Adjusted gross margin attributable to Western Gas Partners, LP.We define Adjusted gross margin attributable to Western Gas Partners, LP (“Adjusted gross margin”) as total revenues less cost of product, plus distributions from equity investees and excluding the noncontrolling interest owners’ proportionate share of revenue and cost of product. We believe Adjusted gross margin is an important performance measure of the core profitability of our operations, as well as our operating performance as compared to that of other companies in our industry. 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.

To facilitate investor and industry analyst comparisons between us and our peers, we also disclose Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets and Adjusted gross margin per Bbl for crude/NGL assets. See Key Performance Metrics within this Item 7.

Adjusted EBITDA attributable to Western Gas Partners, LP. We define Adjusted EBITDA attributable to Western Gas Partners, LP (“Adjusted EBITDA”) as net income attributable to Western Gas Partners, LP, plus distributions from equity investees, non-cash equity-based compensation expense, 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.

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.

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Reconciliation to GAAP measures. Adjusted gross margin, Adjusted EBITDA and Distributable cash flow are not defined in generally accepted accounting principles in the United States (“GAAP”). The GAAP measure used by us that is most directly comparable to Adjusted gross margin is operating income, while net income attributable to Western Gas Partners, LP and net cash provided by operating activities are the GAAP measures used by us that are most directly comparable to Adjusted EBITDA. The GAAP measure used by us that is most directly comparable to Distributable cash flow is net income attributable to Western Gas Partners, LP. Our non-GAAP financial measures of Adjusted gross margin, Adjusted EBITDA and Distributable cash flow should not be considered as alternatives to the GAAP measures of operating income, net income attributable to Western Gas Partners, LP, net cash provided by operating activities or any other measure of financial performance presented in accordance with GAAP. Adjusted gross margin, Adjusted EBITDA and Distributable cash flow have important limitations as analytical tools because they exclude some, but not all, items that affect operating income, net income and net cash provided by operating activities. Adjusted gross margin, 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 gross margin, 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 gross margin, Adjusted EBITDA and Distributable cash flow as analytical tools by reviewing the comparable GAAP measures, understanding the differences between Adjusted gross margin, Adjusted EBITDA and Distributable cash flow compared to (as applicable) operating income, 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 gross margin to the GAAP financial measure of operating income, (b) 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 (c) 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	2013		2012		2011
Reconciliation of Adjusted gross margin attributable to Western Gas Partners, LP to Operating income
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets	$	654,924	$	544,853	$	516,038
Adjusted gross margin for crude/NGL assets	15,274		13,221		9,497
Adjusted gross margin attributable to Western Gas Partners, LP	$	670,198	$	558,074	$	525,535
Adjusted gross margin attributable to noncontrolling interest	17,416		20,983		21,237
Equity income, net	22,948		16,042		11,261
Less:
Distributions from equity investees	22,136		20,660		15,999
Operation and maintenance	168,657		140,106		126,464
General and administrative	29,751		99,212		40,564
Property and other taxes	23,244		19,688		16,579
Depreciation, amortization and impairments	145,916		120,608		113,133
Operating income	$	320,858	$	194,825	$	245,294

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	Year Ended December 31,
thousands	2013			2012			2011
Reconciliation of Adjusted EBITDA attributable to Western Gas Partners, LP to Net income attributable to Western Gas Partners, LP
Adjusted EBITDA attributable to Western Gas Partners, LP	$	457,773		$	377,929		$	361,653
Less:
Distributions from equity investees	22,136			20,660			15,999
Non-cash equity-based compensation expense (1)	3,575			73,508			13,754
Interest expense	51,797			42,060			30,345
Income tax expense	4,219			20,690			32,150
Depreciation, amortization and impairments (2)	143,375			118,279			110,380
Other expense (2)	175			1,665			3,683
Add:
Equity income, net	22,948			16,042			11,261
Interest income, net – affiliates	16,900			16,900			24,106
Other income (2) (3)	419			368			2,049
Income tax benefit	1,864			—			—
Net income attributable to Western Gas Partners, LP	$	274,627		$	134,377		$	192,758
Reconciliation of Adjusted EBITDA attributable to Western Gas Partners, LP to Net cash provided by operating activities
Adjusted EBITDA attributable to Western Gas Partners, LP	$	457,773		$	377,929		$	361,653
Adjusted EBITDA attributable to noncontrolling interests	13,348			17,214			16,850
Interest income (expense), net	(34,897		)	(25,160		)	(6,239		)
Non-cash equity-based compensation expense (1)	(54		)	(69,791		)	(10,264		)
Debt-related amortization and other items, net	2,449			2,319			3,110
Current income tax benefit (expense)	29,536			9,419			(15,570		)
Other income (expense), net (3)	253			(1,292		)	(1,628		)
Distributions from equity investments in excess of cumulative earnings	(4,438		)	—			—
Changes in operating working capital:
Accounts receivable, net	(34,019		)	22,916			(44,725		)
Accounts and natural gas imbalance payables and accrued liabilities, net	21,952			5,045			30,884
Other	(3,702		)	(552		)	(21,233		)
Net cash provided by operating activities	$	448,201		$	338,047		$	312,838
Cash flow information of Western Gas Partners, LP
Net cash provided by operating activities	$	448,201		$	338,047		$	312,838
Net cash used in investing activities	$	(1,652,995	)	$	(1,357,537	)	$	(485,832	)
Net cash provided by financing activities	$	885,541		$	1,212,912		$	372,479

⁽¹⁾  For the year ended December 31, 2012, includes $69.8 million of equity-based compensation associated with the Western Gas Holdings, LLC Equity Incentive Plan, as amended and restated (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.

⁽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. 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.

⁽³⁾  Excludes income of $1.6 million for each of the years ended December 31, 2013, 2012 and 2011, related to a component of a gas processing agreement accounted for as a capital lease.

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	Year Ended December 31,
thousands except Coverage ratio	2013			2012		2011
Reconciliation of Distributable cash flow to Net income attributable to Western Gas Partners, LP and calculation of the Coverage ratio
Distributable cash flow	$	380,529		$	309,945	$	319,294
Less:
Distributions from equity investees	22,136			20,660		15,999
Non-cash equity-based compensation expense (1)	3,575			73,508		13,754
Interest expense, net (non-cash settled)	—			326		—
Income tax expense	2,355			20,690		32,150
Depreciation, amortization and impairments (2)	143,375			118,279		110,380
Other expense (2)	175			1,665		3,683
Add:
Equity income, net	22,948			16,042		11,261
Cash paid for maintenance capital expenditures (2) (3)	29,850			36,459		28,304
Capitalized interest	11,945			6,196		420
Cash paid for income taxes	552			495		190
Other income (2) (4)	419			368		2,049
Interest income, net (non-cash settled)	—			—		7,206
Net income attributable to Western Gas Partners, LP	$	274,627		$	134,377	$	192,758
Distributions declared (5)
Limited partners	$	255,308
General partner	70,745
Total	$	326,053
Coverage ratio	1.17		x

⁽¹⁾  For the year ended December 31, 2012, 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.

⁽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. 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.

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

⁽⁴⁾  Excludes income of $1.6 million for each of the years ended December 31, 2013, 2012 and 2011, 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.

⁽⁵⁾  Reflects distributions of $2.28 per unit declared for the year ended December 31, 2013.

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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 2013, we extended the commodity price swap agreements for the Hilight and Newcastle assets through December 2014. 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, on 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. The amounts reimbursed under the omnibus agreement are greater than amounts allocated to us by Anadarko for the aggregate management services fees, and are reflected in our historical consolidated financial statements for periods prior to our acquisition of the Partnership assets from Anadarko. Public company expenses include expenses such as external audit and consulting fees.

The following table summarizes the amounts the Partnership reimbursed to Anadarko:

	Year Ended December 31,
thousands	2013		2012		2011
General and administrative expenses	$	16,882	$	14,904	$	11,754
Public company expenses	7,152		6,830		7,735
Total reimbursement	$	24,034	$	21,734	$	19,489

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.

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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 from Anadarko, 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 $800.0 million senior unsecured revolving credit facility (“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. On August 1, 2012, we acquired Anadarko’s then-remaining 24% membership interest in Chipeta (the “additional Chipeta interest”), 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 the additional Chipeta interest was accounted for on a prospective basis. As such, effective on the date of acquisition, 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 interest 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 Construction, Ownership and Operation 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 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.

10

GENERAL TRENDS AND OUTLOOK

We expect our business to continue to be affected by the following key trends and uncertainties. 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.

11

Impact of interest rates. Interest rates were at or near historic lows at certain times during 2013. 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, 2013, Anadarko’s total domestic midstream asset portfolio, excluding the assets we own, consisted of 16 gathering systems, 6,259 miles of pipeline and 10 processing and/or treating facilities. A key component of our growth strategy is to acquire midstream assets from Anadarko and third parties over time.

As of December 31, 2013, WGP held a 41.2% limited partner interest in us, and through its ownership of our general partner, WGP indirectly held a 2.0% general partner interest in us and 100% of our incentive distribution rights. As of December 31, 2013, Anadarko Marcellus Midstream, L.L.C. (“AMM”), a subsidiary of Anadarko, separately held a 0.4% limited partner interest in us. 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.

Other. There is uncertainty related to the ultimate outcome of the Tronox Adversary Proceeding (as defined and described in Note 17—Contingencies—Tronox Litigation in the Notes to the Consolidated Financial Statements under Item 8 of Anadarko’s Form 10-K for the year ended December 31, 2013, which is not, and shall not be deemed to be, incorporated by reference herein), and such outcome’s ultimate impact on Anadarko and us.

12

RESULTS OF OPERATIONS

OPERATING RESULTS

The following tables and discussion present a summary of our results of operations:

	Year Ended December 31,
thousands	2013			2012			2011
Gathering, processing and transportation of natural gas and natural gas liquids	$	482,542		$	382,330		$	347,469
Natural gas, natural gas liquids and condensate sales	541,244			508,339			502,383
Other, net	5,977			3,807			8,292
Total revenues(1)	1,029,763			894,476			858,144
Equity income, net	22,948			16,042			11,261
Total operating expenses(1)	731,853			715,693			624,111
Operating income	320,858			194,825			245,294
Interest income, net – affiliates	16,900			16,900			24,106
Interest expense	(51,797		)	(42,060		)	(30,345		)
Other income (expense), net	1,837			292			(44		)
Income before income taxes	287,798			169,957			239,011
Income tax expense	2,355			20,690			32,150
Net income	285,443			149,267			206,861
Net income attributable to noncontrolling interests	10,816			14,890			14,103
Net income attributable to Western Gas Partners, LP	$	274,627		$	134,377		$	192,758
Key performance metrics(2)
Adjusted gross margin attributable to Western Gas Partners, LP	$	670,198		$	558,074		$	525,535
Adjusted EBITDA attributable to Western Gas Partners, LP	$	457,773		$	377,929		$	361,653
Distributable cash flow	$	380,529		$	309,945		$	319,294

⁽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⁾  Adjusted gross margin, Adjusted EBITDA and Distributable cash flow are defined under the caption How We Evaluate Our Operations—Non-GAAP financial measures within this Item 7. For reconciliations of Adjusted gross margin, Adjusted EBITDA and Distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with GAAP, see How We Evaluate Our Operations—Reconciliation to GAAP Measures within this Item 7.

For purposes of the following discussion, any increases or decreases “for the year ended December 31, 2013” refer to the comparison of the year ended December 31, 2013, to the year ended December 31, 2012, and 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.

13

Throughput

	Year Ended December 31,
MMcf/d (except throughput measured in barrels)	2013	2012	Inc/ (Dec)		2011	Inc/ (Dec)
Throughput for natural gas assets
Gathering, treating and transportation	1,803	1,601	13	%	1,555	3	%
Processing	1,359	1,187	14	%	962	23	%
Equity investment (1)	206	235	(12	)%	198	19	%
Total throughput for natural gas assets	3,368	3,023	11	%	2,715	11	%
Throughput attributable to noncontrolling interests for natural gas assets	168	228	(26	)%	242	(6	)%
Total throughput attributable to Western Gas Partners, LP for natural gas assets(2)	3,200	2,795	14	%	2,473	13	%
Total throughput (MBbls/d) for crude/NGL assets(3)	40	31	29	%	28	11	%

⁽¹⁾  Represents our 14.81% share of average Fort Union and our 22% share of average Rendezvous throughput. Excludes equity investment throughput measured in barrels (captured in “Total throughput (MBbls/d) for crude/NGL assets” as noted below).

⁽²⁾  Includes affiliate, third-party and equity investment throughput (as equity investment throughput is defined in the above footnote), excluding the noncontrolling interest owners’ proportionate share of throughput.

⁽³⁾  Represents total throughput measured in barrels consisting of throughput from our Chipeta NGL pipeline, our 10% share of average White Cliffs throughput, our 25% share of average Mont Belvieu JV throughput, our 20% share of average TEG and TEP throughput and our 33.33% share of average FRP throughput.

Gathering, treating and transportation throughput increased by 202 MMcf/d for the year ended December 31, 2013, due to increased volumes at the Non-Operated Marcellus Interest and additional throughput from the Anadarko-Operated Marcellus Interest beginning in March 2013. These increases were partially offset by decreases at the Bison facility resulting from reduced drilling activity in the area and at MIGC due to the expiration of a firm transportation agreement effective September 2012.

Gathering, treating and transportation throughput increased by 46 MMcf/d for the year ended December 31, 2012, primarily due to increased volumes at 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.

Processing throughput increased by 172 MMcf/d for the year ended December 31, 2013, primarily due to throughput increases at Chipeta, the start-up of the Brasada facility in June 2013, and an increase in volumes at the Red Desert complex due to additional well connections during the period. In addition, increased volumes processed at a plant included in the MGR acquisition (“the Granger straddle plant”) contributed to the increase. These increases were partially offset by a decrease in throughput at the Granger complex due to natural production declines in the area.

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

Equity investment volumes decreased by 29 MMcf/d for the year ended December 31, 2013, primarily due to lower throughput at the Fort Union system due to production declines in the area. 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.

Throughput for crude/NGL assets measured in barrels increased by 9 MBbls/d for the year ended December 31, 2013, primarily due to the start-up of the Mont Belvieu JV fractionation trains, TEP and TEG in the fourth quarter of 2013. Throughput for crude/NGL assets measured in barrels increased by 3 MBbls/d for the year ended December 31, 2012, primarily due to an increase in volumes at White Cliffs.

14

Natural Gas Gathering, Processing and Transportation Revenues

	Year Ended December 31,
thousands except percentages	2013		2012		Inc/ (Dec)		2011		Inc/ (Dec)
Gathering, processing and transportation of natural gas and natural gas liquids	$	482,542	$	382,330	26	%	$	347,469	10	%

Revenues from gathering, processing and transportation of natural gas and natural gas liquids increased by $100.2 million for the year ended December 31, 2013, primarily due to increases of $30.5 million, $20.8 million, and $15.3 million at the Non-Operated Marcellus Interest, the Wattenberg system, and Chipeta, respectively, all due to higher throughput, an increase of $14.1 million due to the addition of the Anadarko-Operated Marcellus Interest beginning in March 2013, and an increase of $16.3 million due to the start-up of the Brasada facility in June 2013.

Revenues from gathering, processing and transportation of natural gas and natural gas liquids 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.

Natural Gas, Natural Gas Liquids and Condensate Sales

	Year Ended December 31,
thousands except percentages and per-unit amounts	2013		2012		Inc/ (Dec)		2011		Inc/ (Dec)
Natural gas sales	$	118,134	$	101,116	17	%	$	129,939	(22	)%
Natural gas liquids sales	391,608		377,377		4	%	345,375		9	%
Drip condensate sales	31,502		29,846		6	%	27,069		10	%
Total	$	541,244	$	508,339	6	%	$	502,383	1	%
Average price per unit:
Natural gas (per Mcf)	$	4.58	$	4.24	8	%	$	5.32	(20	)%
Natural gas liquids (per Bbl)	$	47.69	$	48.22	(1	)%	$	47.44	2	%
Drip condensate (per Bbl)	$	76.62	$	75.88	1	%	$	73.60	3	%

Including the effects of commodity price swap agreements, total natural gas, natural gas liquids and condensate sales increased by $32.9 million for the year ended December 31, 2013, which consisted of a $17.0 millionincrease in sales of natural gas, a $14.2 millionincrease in NGLs sales and a $1.7 millionincrease in drip condensate sales.

The growth in natural gas sales for the year ended December 31, 2013, was primarily due to an 8%increase in the overall sales price of natural gas, as well as higher sales volumes at the Wattenberg system and the Red Desert complex, partially offset by a decrease at the Platte Valley system due to a gas flow change that became effective in July 2013, whereby volumes previously processed under percentage-of-proceeds contracts are now processed under fee-based arrangements.

The growth in NGLs sales for the year ended December 31, 2013, was primarily due to increases of $22.1 million, $15.4 million, $9.0 million and $4.2 million resulting from higher volumes processed and sold at the Red Desert complex, the Hilight system, the Wattenberg system and the Granger straddle plant, respectively. These increases were partially offset by a decrease of $14.0 million at Chipeta (with a corresponding decrease in cost of product), a decrease of $12.8 million at the Platte Valley system due to the aforementioned gas flow changes, and a decrease of $9.1 million at the Granger complex due to a decrease in volumes sold as a result of decreased throughput.

The growth in drip condensate sales for the year ended December 31, 2013 was primarily due to a $2.4 million increase at the Wattenberg system due to an increase in condensate volumes sold as a result of increased throughput, partially offset by a $0.9 million decrease at Hugoton due to a decrease in condensate volumes sold as a result of decreased throughput.

15

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.

The growth in NGLs sales for the year ended December 31, 2012, 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, which was offset by a decrease in volumes; and an increase of $9.6 million related to volumes processed at the Granger straddle plant 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 for the year ended December 31, 2012, was primarily due to a 20% decrease in overall natural gas sales prices and lower sales volumes, resulting in decreases of $17.0 million at the Hilight system, $3.8 million at the Red Desert complex, and $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.

For the years ended December 31, 2013 and 2012, average natural gas, NGL and drip condensate prices include the effects of commodity price swap agreements attributable to sales for the Granger, Hilight, Newcastle, Hugoton and Wattenberg systems, and 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.

Equity Income, Net and Other Revenues

	Year Ended December 31,
thousands except percentages	2013		2012		Inc/ (Dec)		2011		Inc/ (Dec)
Equity income, net	$	22,948	$	16,042	43	%	$	11,261	42	%
Other revenues, net	5,977		3,807		57	%	8,292		(54	)%
Total	$	28,925	$	19,849	46	%	$	19,553	2	%

For the year ended December 31, 2013, equity income, net increased by $6.9 million, primarily due to the fourth quarter 2013 start-up of the Mont Belvieu JV fractionation trains, and volume increases at White Cliffs. These increases were offset by net losses associated with the initial start-up and line-fill stage of TEP during the fourth quarter of 2013. Equity income, net increased by $4.8 million for the year ended December 31, 2012, primarily due to a $3.8 million increase in income from White Cliffs and a $0.7 million increase in income from Rendezvous as a result of increased volumes.

Other revenues, net increased by $2.2 million for the year ended December 31, 2013, primarily due to the collection of deficiency fees associated with volume commitments at Chipeta. 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.

16

Cost of Product and Operation and Maintenance Expenses

	Year Ended December 31,
thousands except percentages	2013		2012		Inc/ (Dec)		2011		Inc/ (Dec)
NGL purchases	$	191,788	$	181,078	6	%	$	158,288	14	%
Residue purchases	156,170		143,962		8	%	156,555		(8	)%
Other	16,327		11,039		48	%	12,528		(12	)%
Cost of product	$	364,285	$	336,079	8	%	$	327,371	3	%
Operation and maintenance	168,657		140,106		20	%	126,464		11	%
Total cost of product and operation and maintenance expenses	$	532,942	$	476,185	12	%	$	453,835	5	%

Including the effects of commodity price swap agreements on purchases, cost of product expense for the year ended December 31, 2013, increased by $28.2 million primarily due to the volume fluctuations noted in Throughput and Natural Gas, Natural Gas Liquids and Condensate Sales within this Item 7, resulting in the following:

• an $11.6 million net increase in residue purchases primarily at the Wattenberg system and the Red Desert complex, partially offset by decreases at the Platte Valley system and the Granger complex; and

• a $10.7 million net increase in NGL purchases primarily at the Red Desert complex, the Hilight system, and the Wattenberg system, partially offset by decreases at Chipeta, the Platte Valley system, and the Granger complex.

Including the effects of commodity price swap agreements on purchases, cost of product expense for the year ended December 31, 2012, increased by $8.7 million primarily due to the following:

• a $22.8 million net increase in NGL purchases primarily at Chipeta, the Hilight system, and the Wattenberg system due to volume fluctuations noted in Throughput and Natural Gas, Natural Gas Liquids and Condensate Sales within this Item 7, and an increase for the MGR assets as a result of entering into commodity price swap agreements that became effective in January 2012, partially offset by a decrease at the Platte Valley system due to lower pricing subsequent to its acquisition in February 2011; and

• a $12.6 million net decrease in residue purchases at the Hilight system due to declines in residue purchase prices, partially offset by an increase in cost of product expense for residue purchases for the MGR assets as a result of entering into commodity price swap agreements that became effective in January 2012.

Cost of product expense for the years ended December 31, 2013 and 2012, includes the effects of commodity price swap agreements attributable to purchases for the Granger, Hilight, Hugoton, Newcastle and Wattenberg systems, and 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.

Operation and maintenance expense increased by $28.6 million for the year ended December 31, 2013, primarily due to an increase of $9.7 million in property, facility and overhead expense attributable to the Non-Operated Marcellus Interest, an increase of $8.3 million for plant repairs and maintenance primarily at the Wattenberg system and Chipeta, and an increase of $7.7 million for salaries, wages and payroll tax expense primarily at the Wattenberg system, the Brasada facility and the Hilight system.

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 for the Non-Operated Marcellus Interest.

17

General and Administrative, Depreciation and Other Expenses

	Year Ended December 31,
thousands except percentages	2013		2012		Inc/ (Dec)		2011		Inc/ (Dec)
General and administrative	$	29,751	$	99,212	(70	)%	$	40,564	145	%
Property and other taxes	23,244		19,688		18	%	16,579		19	%
Depreciation, amortization and impairments	145,916		120,608		21	%	113,133		7	%
Total general and administrative, depreciation and other expenses	$	198,911	$	239,508	(17	)%	$	170,276	41	%

General and administrative expenses decreased by $69.5 million for the year ended December 31, 2013, primarily due to a decrease of $69.9 million in non-cash compensation expenses attributable to the awards outstanding under the Incentive Plan, which were settled in December 2012 when the Incentive Plan terminated in conjunction with WGP’s IPO. These declines were partially offset by an increase of $2.2 million in corporate and management personnel costs for which we reimbursed Anadarko pursuant to our omnibus agreement.

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.

Property and other taxes increased by $3.6 million for the year ended December 31, 2013, primarily due to ad valorem tax increases of $2.6 million associated with capital additions at the Platte Valley, Chipeta and Wattenberg systems and $0.9 million due to the completion of the Brasada facility in June 2013. 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.

Depreciation, amortization and impairments increased by $25.3 million for the year ended December 31, 2013, primarily attributable to a $12.1 million increase in depreciation expense associated with capital projects completed at the Wattenberg, Chipeta, Platte Valley and Hilight systems, a $6.2 million increase in depreciation and impairment expense associated with the Non-Operated Marcellus Interest, a $6.1 million increase in depreciation expense related to the completion of the Brasada facility in June 2013, and a $3.9 million increase in depreciation expense associated with the March 2013 acquisition of the Anadarko-Operated Marcellus Interest. Partially offsetting these increases was a decrease of $5.3 million in impairment expense, due to a $1.2 million impairment recognized in 2013 primarily related to the cancellation of various capital projects by the third-party operator of the Non-Operated Marcellus Interest, as compared to the $6.6 million impairment recognized in 2012 related to a gathering system in central Wyoming and a relocated compressor.

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.

18

Interest Income, Net – Affiliates and Interest Expense

Amortization of debt issuance costs and commitment fees in the table below includes amortization of (i) the original issue discount for the June 2012 offering of $520.0 million aggregate principal amount of 4.000% Senior Notes due 2022, (ii) the original issue premium for the October 2012 offering of an additional $150.0 million in aggregate principal amount of 4.000% Senior Notes due 2022, (iii) the original issue discount for the $500.0 million aggregate principal amount of 5.375% Senior Notes due 2021 (the “2021 Notes”), (iv) the original issue discount for the August 2013 offering of $250.0 million aggregate principal amount of 2.600% Senior Notes due 2018 (the “2018 Notes”), and (v) underwriters’ fees. The October 2012 notes and the June 2012 notes were issued under the same indenture and are considered a single class of securities, collectively referred to as the “2022 Notes.”

	Year Ended December 31,
thousands except percentages	2013			2012			Inc/ (Dec)		2011			Inc/ (Dec)
Interest income on note receivable	$	16,900		$	16,900		—	%	$	16,900		—	%
Interest income, net on affiliate balances (1)	—			—			—	%	7,206			(100	)%
Interest income, net – affiliates	$	16,900		$	16,900		—	%	$	24,106		(30	)%
Third parties
Interest expense on long-term debt	$	(59,293	)	$	(41,171	)	44	%	$	(20,533	)	101	%
Amortization of debt issuance costs and commitment fees (2)	(4,449		)	(4,319		)	3	%	(5,297		)	(18	)%
Capitalized interest	11,945			6,196			93	%	420			NM
Affiliates
Interest expense on note payable to Anadarko (3)	—			(2,440		)	(100	)%	(4,935		)	(51	)%
Interest expense on affiliate balances (4)	—			(326		)	(100	)%	—			NM
Interest expense	$	(51,797	)	$	(42,060	)	23	%	$	(30,345	)	39	%

NM-Not meaningful

⁽¹⁾  Incurred on affiliate balances related to the Non-Operated Marcellus Interest, the MGR assets, and the Bison 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.

⁽²⁾  For the year ended December 31, 2013, includes $1.2 million of amortization of debt issuance costs and underwriters’ fees for the 2022 Notes, the 2021 Notes, and the 2018 Notes. For the year ended December 31, 2012, includes $1.1 million of amortization of debt issuance costs and underwriters’ fees for the 2022 Notes and the 2021 Notes.

⁽³⁾  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.

⁽⁴⁾  Imputed interest expense on the reimbursement payable to Anadarko for certain expenditures incurred in 2011 related to the construction of the Brasada facility and Lancaster plant. In the fourth quarter of 2012, we repaid the reimbursement payable to Anadarko associated with the construction of the Brasada facility and Lancaster plant. 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 $9.7 million for the year ended December 31, 2013, primarily due to interest expense incurred on the 2022 Notes of $15.0 million as well as interest incurred on the 2018 Notes of $2.5 million. In addition, interest expense increased on the RCF by $0.6 million primarily due to greater average outstanding borrowings in the current period, partially offset by a decrease of $2.4 million attributable to the repayment of the note payable to Anadarko in June 2012. 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.

Also partially offsetting the increases in interest expense for the year ended December 31, 2013, was an increase of capitalized interest of $5.7 million primarily associated with the expansion of the Lancaster plant and construction of the two Mont Belvieu JV fractionation trains.

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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 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.

Other Income (Expense), Net

	Year Ended December 31,
thousands	2013		2012		Inc/ (Dec)	2011			Inc/ (Dec)
Other income (expense), net	$	1,837	$	292	NM	$	(44	)	NM

For the year ended December 31, 2013 and 2012, other income (expense), net included $1.6 million of interest income related to the capital lease component of a processing agreement assumed in connection with the MGR acquisition. In addition, for the year ended December 31, 2013, other income (expense), net included $0.5 million of interest earned on overnight investments, which was offset by $0.2 million of expense associated with a remediation project for MGR.

For the year ended December 31, 2012, other income (expense), net also included a realized loss of $1.7 million resulting from U.S. Treasury Rate lock agreements settled simultaneously with our June 2012 offering of the 2022 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.

Income Tax Expense

	Year Ended December 31,
thousands except percentages	2013			2012			Inc/ (Dec)		2011			Inc/ (Dec)
Income before income taxes	$	287,798		$	169,957		69	%	$	239,011		(29	)%
Income tax expense	2,355			20,690			(89	)%	32,150			(36	)%
Effective tax rate	1		%	12		%			13		%

We are not a taxable entity for U.S. federal income tax purposes; however, 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 TEFR Interests prior to and including February 2014, (b) the Non-Operated Marcellus Interest prior to and including March 2013, (c) the MGR assets prior to and including January 2012 and (d) the Bison assets prior to and including June 2011, was subject to federal and state income tax. Income earned on the TEFR Interests, the Non-Operated Marcellus Interest, MGR assets and Bison assets for periods subsequent to February 2014, March 2013, January 2012, and June 2011, respectively, was only subject to Texas margin tax on income apportionable to Texas.

Noncontrolling Interests

	Year Ended December 31,
thousands except percentages	2013		2012		Inc/ (Dec)		2011		Inc/ (Dec)
Net income attributable to noncontrolling interests	$	10,816	$	14,890	(27	)%	$	14,103	6	%

For the year ended December 31, 2013, net income attributable to noncontrolling interests decreased by $4.1 million primarily due to our acquisition of the additional Chipeta interest in August 2012. For the year ended December 31, 2012, net income attributable to noncontrolling interests increased by $0.8 million primarily due to higher volumes at the Chipeta system, partially offset by the acquisition of the additional Chipeta interest in August 2012. 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.

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KEY PERFORMANCE METRICS

	Year Ended December 31,
thousands except percentages and per-unit amounts	2013		2012		Inc/ (Dec)		2011		Inc/ (Dec)
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets (1)	$	654,924	$	544,853	20	%	$	516,038	6	%
Adjusted gross margin for crude/NGL assets (2)	15,274		13,221		16	%	9,497		39	%
Adjusted gross margin attributable to Western Gas Partners, LP (3)	$	670,198	$	558,074	20	%	$	525,535	6	%
Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets (4)	0.56		0.53		6	%	0.57		(7	)%
Adjusted gross margin per Bbl for crude/NGL assets (5)	1.05		1.17		(10	)%	0.94		24	%
Adjusted EBITDA attributable to Western Gas Partners, LP (6)	457,773		377,929		21	%	361,653		5	%
Distributable cash flow (6)	$	380,529	$	309,945	23	%	$	319,294	(3	)%

⁽¹⁾  Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets is calculated as total revenues for natural gas assets less cost of product for natural gas assets plus distributions from our equity investments in Fort Union and Rendezvous, which are measured in Mcf, and excluding the noncontrolling interest owners’ proportionate share of revenue and cost of product.

⁽²⁾  Adjusted gross margin for crude/NGL assets is calculated as total revenues for crude/NGL assets less cost of product for crude/NGL assets plus distributions from our equity investments in White Cliffs, the Mont Belvieu JV, TEG, TEP and FRP, which are measured in barrels.

⁽³⁾  For a reconciliation of Adjusted gross margin attributable to Western Gas Partners, LP to the most directly comparable financial measure calculated and presented in accordance with GAAP, see How We Evaluate Our Operations—Reconciliation to GAAP measures within this Item 7.

⁽⁴⁾  Average for period. Calculated as Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets, divided by total throughput attributable to Western Gas Partners, LP for natural gas assets.

⁽⁵⁾  Average for period. Calculated as Adjusted gross margin for crude/NGL assets, divided by total throughput (MBbls/d) for crude/NGL assets.

⁽⁶⁾  For reconciliations of Adjusted EBITDA and Distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with GAAP, see How We Evaluate Our Operations—Reconciliation to GAAP measures within this Item 7.

Adjusted gross margin attributable to Western Gas Partners, LP. Adjusted gross margin increased by $112.1 million for the year ended December 31, 2013, primarily due to higher margins on the Non-Operated Marcellus Interest, the Wattenberg system, the Anadarko-Operated Marcellus Interest, Chipeta, and the start-up of the Brasada facility in June 2013.

Adjusted gross margin increased by $32.5 million for the year ended December 31, 2012, primarily due to higher margins on the Non-Operated Marcellus Interest and on 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.

Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets increased by $0.03 for the year ended December 31, 2013, primarily due to higher margins and increases in throughput at Chipeta, the Wattenberg system, and the Non-Operated Marcellus Interest, as well as overall changes in the throughput mix of our portfolio.

Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets decreased by $0.04 for the year ended December 31, 2012, 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.

Adjusted gross margin per Bbl for crude/NGL assets decreased by $0.12 for the year ended December 31, 2013, primarily due to net losses associated with the initial start-up and line-fill stage of TEP during the fourth quarter of 2013. Adjusted gross margin per Bbl for crude/NGL assets increased by $0.23 for the year ended December 31, 2012, primarily due to an increase in volumes at White Cliffs.

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Adjusted EBITDA. Adjusted EBITDA increased by $79.8 million for the year ended December 31, 2013, primarily due to a $135.3 million increase in total revenues and a $4.1 milliondecrease in net income attributable to noncontrolling interest as a result of the acquisition of the additional Chipeta interest. These amounts were offset by a $28.6 millionincrease in operation and maintenance expenses, a $28.2 millionincrease in cost of product, and a $3.6 millionincrease in property and other tax expense.

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, 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.

Distributable cash flow. Distributable cash flow increased by $70.6 million for the year ended December 31, 2013, primarily due to a $79.8 millionincrease in Adjusted EBITDA and a $6.6 milliondecrease in maintenance capital expenditures, offset by a $15.8 millionincrease in net cash paid for interest expense.

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.

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, 2013, included cash and cash equivalents, cash flows generated from operations, 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 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 20, 2014, the board of directors of our general partner declared a cash distribution to our unitholders of $0.60 per unit, or $92.6 million in aggregate, including incentive distributions. The cash distribution was paid on February 12, 2014, to unitholders of record at the close of business on January 31, 2014.

Management continuously monitors our leverage position and coordinates our capital expenditure program, quarterly distributions and acquisition strategy with our 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 2013 Form 10-K.

Working capital. As of December 31, 2013, we had $4.4 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. As of December 31, 2013, we had $787.2 million available for borrowing under our $800.0 million RCF.

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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	2013		2012		2011
Acquisitions	$	716,985	$	611,719	$	330,794
Expansion capital expenditures	$	615,924	$	600,893	$	121,318
Maintenance capital expenditures	29,930		37,228		28,399
Total capital expenditures (1)	$	645,854	$	638,121	$	149,717
Capital incurred (2)	$	628,285	$	690,041	$	182,536

⁽¹⁾  Capital expenditures for the years ended December 31, 2013 and 2012, included $10.6 million and $6.8 million, respectively, 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 and 2011, included $178.8 million and $20.1 million, respectively, of pre-acquisition capital expenditures for the Non-Operated Marcellus Interest, the MGR assets, and the Bison assets.

⁽²⁾  Includes the noncontrolling interest owners’ share of Chipeta’s capital incurred, funded by contributions from the noncontrolling interest owners for all periods presented. Capital incurred for the years ended December 31, 2013 and 2012, included $10.6 million and $6.8 million, respectively, of capitalized interest. Capital incurred for the years ended December 31, 2013, 2012 and 2011, included $8.8 million, $160.9 million and $45.7 million, respectively, of pre-acquisition capital incurred for the Non-Operated Marcellus Interest, the MGR assets, and the Bison assets.

Acquisitions during 2013 included OTTCO, the Mont Belvieu JV, the Anadarko-Operated Marcellus Interest and the Non-Operated Marcellus Interest. Acquisitions during 2012 included the additional Chipeta interest and the MGR assets. Acquisitions during 2011 included the Bison facility and the Platte Valley system. 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.

Capital expenditures, excluding acquisitions, increased by $7.7 million for the year ended December 31, 2013. Expansion capital expenditures increased by $15.0 million (including a $3.8 million increase in capitalized interest) for the year ended December 31, 2013, primarily due to an increase of $114.2 million related to the construction of the Lancaster plants and a $91.7 million increase in expenditures at the Wattenberg and Hilight systems and the Anadarko-Operated Marcellus Interest. These increases were partially offset by a $191.2 million decrease at Chipeta, the Non-Operated Marcellus Interest, the Brasada facility and the Platte Valley system. Maintenance capital expenditures decreased by $7.3 million, primarily as a result of decreased expenditures of $7.5 million at the Wattenberg, Hilight, Haley, and Platte Valley systems, the Red Desert complex and the Non-Operated Marcellus Interest, partially offset by a $1.7 million increase at the Anadarko-Operated Marcellus Interest.

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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 gas processing facility and Lancaster plant, $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.

We estimate our total capital expenditures for the year ended December 31, 2014, including our 75% share of Chipeta’s capital expenditures and excluding acquisitions, to be $614 million to $664 million and our maintenance capital expenditures to be 9% to 11% of total capital expenditures. Expected 2014 projects include the construction of a second train at our Lancaster plant and continued well connections in the Denver-Julesburg basin and the Marcellus shale. 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 present a summary of our net cash flows provided by (used in) operating activities, investing activities and financing activities:

	Year Ended December 31,
thousands	2013			2012			2011
Net cash provided by (used in):
Operating activities	$	448,201		$	338,047		$	312,838
Investing activities	(1,652,995		)	(1,357,537		)	(485,832		)
Financing activities	885,541			1,212,912			372,479
Net increase (decrease) in cash and cash equivalents	$	(319,253	)	$	193,422		$	199,485

Operating Activities. Net cash provided by operating activities during the year ended December 31, 2013, was $448.2 million, compared to $338.0 million for the year ended December 31, 2012. Operating cash flows increased primarily due to the impact of changes in working capital items, in addition to higher sales volumes and higher average natural gas prices.

Net cash provided by operating activities during the year ended December 31, 2012, was $338.0 million, compared to $312.8 million for the year ended December 31, 2011. Operating cash flows increased primarily due to the impact of changes in working capital items, in addition to higher sales volumes and increased average commodity prices pursuant to commodity price swap agreements and the addition of the Platte Valley assets in March 2011. The impact of changes in working capital items was primarily due to accruals of expected future operating cash receipts and payments.

Refer to Operating Results within this Item 7 for a discussion of our results of operations as compared to the prior periods.

Investing Activities. Net cash used in investing activities for the year ended December 31, 2013, included the following:

• $465.5 million of cash paid for the acquisition of the Non-Operated Marcellus Interest;

• $646.5 million of capital expenditures, net of $0.6 million of contributions in aid of construction costs from affiliates;

• $221.2 million of capital contributions to TEG, TEP and FRP for construction costs;

• $134.6 million of cash paid for the acquisition of the Anadarko-Operated Marcellus Interest;

• $78.1 million of cash paid for the acquisition of the Mont Belvieu JV;

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• $37.3 million of capital contributions to the Mont Belvieu JV to fund our share of construction costs for the fractionation facilities completed in the fourth quarter of 2013;

• $27.5 million of cash paid for the acquisition of OTTCO;

• $19.1 million of cash paid related to a White Cliffs expansion project anticipated to be completed in the first half of 2014;

• $17.0 million of capitalized interest on equity investments related to the Mont Belvieu JV, TEP, TEG and FRP;

• $11.2 million of cash paid for equipment purchases from Anadarko; and

• $4.4 million of distributions from equity investments in excess of cumulative earnings.

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

• $458.6 million of cash paid for the acquisition of the MGR assets;

• $638.1 million of capital expenditures;

• $128.3 million of cash paid for the additional Chipeta interest;

• $107.6 million of cash paid for the capital contributions to TEP for construction costs and the initial investments in TEG and FRP; 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 acquisition of the Platte Valley system;

• $149.7 million of capital expenditures;

• $25.0 million of cash paid for the acquisition of the Bison facility;

• $6.1 million of cash paid for the initial investment in TEP; and

• $3.8 million for equipment purchases from Anadarko.

Financing Activities. Net cash provided by financing activities for the year ended December 31, 2013, included the following:

• $273.7 million of net proceeds from our December 2013 equity offering, including net proceeds from the issuance of general partner units to our general partner to maintain its 2.0% general partner interest, $215.0 million of which was used to repay a portion of our outstanding borrowings under our RCF;

• $424.7 million of net proceeds from our May 2013 equity offering, including net proceeds from the issuance of general partner units to our general partner to maintain its 2.0% general partner interest, $245.0 million of which was used to repay a portion of our outstanding borrowings under our RCF;

• $247.6 million of net proceeds from our 2018 Notes offering in August 2013, after underwriting and original issue discounts and offering costs, all of which was used to repay a portion of our outstanding borrowings under our RCF, including $250.0 million of borrowings to fund the acquisition of the Non-Operated Marcellus Interest;

• $133.5 million of borrowings to fund the acquisition of the Anadarko-Operated Marcellus Interest;

• $299.0 million of borrowings to fund capital expenditures;

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• $27.5 million of borrowings to fund the acquisition of OTTCO;

• $41.8 million of net proceeds from activity under our Continuous Offering Program (as defined and discussed in Registered Securities within this Item 7), including net proceeds from the issuance of general partner units to our general partner to maintain its 2.0% general partner interest; and

• $0.5 million of net proceeds from the issuance of general partner units to our general partner to maintain its 2.0% general partner interest after common units were issued in conjunction with the acquisition of the Non-Operated Marcellus Interest.

Net contributions from Anadarko attributable to intercompany balances were $209.0 million during the year ended December 31, 2013, representing intercompany transactions attributable to the acquisitions of the TEFR Interests and the Non-Operated Marcellus Interest.

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 offering in June 2012 and October 2012, respectively, after underwriting and original issue discounts, original issue premiums 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 acquisition of the MGR assets; and

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

Proceeds from our 2022 Notes offerings were used to repay amounts outstanding under our RCF and our note payable to Anadarko. Net contributions from Anadarko attributable to intercompany balances were $278.6 million during the year ended December 31, 2012, representing intercompany transactions attributable to the acquisitions of the TEFR Interests and the Non-Operated Marcellus Interest, the compensation expense allocated to us since the inception of the Incentive Plan and the settlement of intercompany transactions attributable to the MGR 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 acquisition of the Platte Valley system;

• $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 $29.9 million during 2011, attributable to the acquisitions of the TEFR Interests and the Non-Operated Marcellus Interest, and the net non-cash settlement of intercompany transactions attributable to the MGR assets and the Bison facility.

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For the years ended December 31, 2013, 2012 and 2011, we paid $299.1 million, $197.9 million and $140.1 million, respectively, of cash distributions to our unitholders. Contributions from noncontrolling interest owners of Chipeta totaled $2.2 million, $29.1 million and $33.6 million during the years ended December 31, 2013, 2012 and 2011, respectively, primarily for expansion of the cryogenic units and plant construction. Distributions to noncontrolling interest owners of Chipeta totaled $13.1 million, $17.3 million and $17.5 million for the years ended December 31, 2013, 2012 and 2011, respectively, representing the distributions paid as of December 31 of the respective year. Decreases in contributions by and distributions to noncontrolling interest owners of Chipeta were also impacted by the August 2012 acquisition of the additional Chipeta interest.

Debt and credit facility. As of December 31, 2013, the carrying value of our outstanding debt consisted of $249.7 million of the 2018 Notes, $673.3 million of the 2022 Notes and $495.2 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 August 2013, we completed the offering of $250.0 million aggregate principal amount of 2.600% Senior Notes due 2018 at a price to the public of 99.879% of the face amount. Including the effects of the issuance and underwriting discounts, the effective interest rate of the 2018 Notes is 2.806%. Interest is paid semi-annually on February 15 and August 15 of each year. Proceeds (net of underwriting discount of $1.5 million, original issue discount and debt issuance costs) were used to repay amounts then outstanding under our RCF.

The 2018 Notes mature on August 15, 2018, unless earlier redeemed. The Partnership may redeem the 2018 Notes in whole or in part, at any time before July 15, 2018, at a redemption price equal to the greater of (i) 100% of the principal amount of the 2018 Notes to be redeemed or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on such 2018 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 2018 Notes) plus 20 basis points, plus, in either case, accrued and unpaid interest to such redemption date, if any, on the principal amount being redeemed. On or after July 15, 2018, the 2018 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 2018 Notes to be redeemed, plus accrued interest on the 2018 Notes to be redeemed to the date of redemption.

In June 2012, we completed the offering of $520.0 million aggregate principal amount of the 2022 Notes 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 the 2022 Notes 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. 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 is 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 earlier redeemed. 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.

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In May 2011, we completed the offering of $500.0 million aggregate principal amount 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 earlier redeemed. 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 2021 Notes, 2022 Notes, and 2018 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, 2013, we were in compliance with all covenants under the indentures governing the 2021 Notes, 2022 Notes, and the 2018 Notes.

Note payable to Anadarko. In 2008, we entered into a five-year $175.0 million term loan agreement with Anadarko. The interest rate was fixed at 2.82% prior to June 2012 when the note payable to Anadarko was repaid in full with proceeds from the June 2012 offering of the 2022 Notes.

Revolving credit facility. As of December 31, 2013, we had no outstanding borrowings and $12.8 million in outstanding letters of credit issued under our $800.0 million RCF. 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 1.67% and 1.71% at December 31, 2013 and 2012, respectively. We are 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, 2013 and 2012. At December 31, 2013, we were in compliance with all covenants under the RCF. See 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.

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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 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. At December 31, 2013, we were in compliance with all remaining covenants under the RCF.

The 2021 Notes, the 2022 Notes, the 2018 Notes and obligations under the RCF are recourse to our general partner. Our general partner is indemnified by a wholly owned subsidiary of Anadarko, Western Gas Resources, Inc. (“WGRI”), against any claims made against our general partner under the 2022 Notes, the 2021 Notes, and/or the RCF. See 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 amendments to the RCF and borrowing activity under the new RCF in March 2014, related to acquisitions that closed after December 31, 2013.

In connection with the acquisition of the Non-Operated Marcellus Interest in March 2013, our general partner and another wholly owned subsidiary of Anadarko entered into an indemnification agreement (the “2013 Indemnification Agreement”) whereby such subsidiary agreed to indemnify our general partner for any recourse liability it may have for RCF borrowings, or other debt financing, attributable to the acquisitions of the Non-Operated Marcellus Interest or the Anadarko-Operated Marcellus Interest. The 2013 Indemnification Agreement applies to the 2018 Notes. Our general partner and WGRI also amended and restated the existing indemnity agreement between them to reduce the amount for which WGRI would indemnify our general partner by an amount equal to any amounts payable to our general partner under the 2013 Indemnification Agreement. See 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.

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 SEC.

In August 2012, we filed a registration statement with the SEC authorizing the issuance of up to an aggregate of $125.0 million of common units, in amounts, at prices and on terms to be determined by market conditions and other factors at the time of our offerings (the “Continuous Offering Program”). See Note 4—Equity and Partners’ Capital 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 trades completed under our Continuous Offering Program.

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.

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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, 2013, including the contractual obligations of the TEFR Interests. 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 2014.

	Obligations by Period
thousands	2014		2015		2016		2017		2018		Thereafter		Total
Long-term debt
Principal	—		—		—		—		250,000		1,170,000		1,420,000
Interest	59,652		59,634		59,614		59,595		56,324		160,275		455,094
Asset retirement obligations	1,966		1,755		127		—		—		74,187		78,035
Capital expenditures	47,112		—		—		—		—		—		47,112
Credit facility fees	2,000		2,000		460		—		—		—		4,460
Environmental obligations	932		532		532		135		135		579		2,845
Operating leases	309		245		233		157		34		—		978
Total	$	111,971	$	64,166	$	60,966	$	59,887	$	306,493	$	1,405,041	$	2,008,524

Debt and credit facility fees. For additional information on 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.

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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 to this Current Report on Form 8-K.

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of consolidated financial statements in accordance with GAAP requires our management to make informed judgments and estimates that affect the amounts of assets and liabilities as of the date of the financial statements and affect the amounts of revenues and expenses recognized during the periods reported. On an ongoing basis, management reviews its estimates, including those related to the determination of properties and equipment, 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 23 years. If the depreciable lives of our assets were reduced by 10%, we estimate that annual depreciation expense would increase by $18.7 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.

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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 2013, we recognized a $1.2 million impairment primarily related to the cancellation of various capital projects by the third-party operator of the Non-Operated Marcellus Interest.

During 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 during 2012, an impairment of $0.6 million was recognized for the original installation costs on a compressor relocated within our operating assets.

During 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 $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.

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 ofDecember 31, 2013, 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 qualitative evaluation as of October 1, 2013. 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.

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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 2014 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 our consolidated financial statements.

Impairments of intangible assets. Our intangible asset balance as of December 31, 2013 and 2012, primarily represents the fair value, net of amortization, of (i) contracts we assumed in connection with the Platte Valley acquisition in February 2011, which are amortized on a straight-line basis over 50 years, and (ii) interconnect agreements at Chipeta entered into in November 2012, amortized on a straight-line basis over 10 years.

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 an asset may not be recoverable. Impairments exist when the carrying amount of an asset exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the long-lived asset is not recoverable based on the estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying amount over its estimated fair value, such that the asset’s carrying amount is adjusted to its estimated fair value with an offsetting charge to impairment 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 uses 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 uses 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.

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