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Article by DailyStocks_admin    (12-12-13 11:14 PM)

Description

WESTERN GAS PARTNERS LP. Director CRANE JAMES R bought 100,000 shares on 12-03-2013 at $ 61.51.

BUSINESS OVERVIEW

GENERAL OVERVIEW

Western Gas Partners, LP, a growth-oriented Delaware master limited partnership formed by Anadarko Petroleum Corporation in 2007 to own, operate, acquire and develop midstream energy assets, closed its initial public offering (“IPO”) to become publicly traded in 2008. For purposes of this report, the “Partnership,” “we,” “our,” “us” or like terms, refers to Western Gas Partners, LP and its subsidiaries. We are engaged in the business of gathering, processing, compressing, treating and transporting natural gas, condensate, NGLs and crude oil for Anadarko Petroleum Corporation and its consolidated subsidiaries, as well as third-party producers and customers. Our common units are publicly traded on the New York Stock Exchange (“NYSE”) under the symbol “WES.”

The Partnership’s 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 in September 2012 to own our general partner, as well as a significant limited partner interest in us. WGP’s common units are publicly traded on the NYSE under the symbol “WGP.” Western Gas Equity Holdings, LLC is WGP’s general partner and is a wholly owned subsidiary of Anadarko Petroleum Corporation. “Anadarko” refers to Anadarko Petroleum Corporation and its consolidated subsidiaries, excluding the Partnership and the general partner. “Affiliates” refers to wholly owned and partially owned subsidiaries of Anadarko, excluding the Partnership, and includes the interests in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”) and Rendezvous Gas Services, LLC (“Rendezvous”). “Equity investment throughput” refers to our 14.81% share of Fort Union and 22% share of Rendezvous gross volumes. “Anadarko Petroleum Corporation” refers to Anadarko Petroleum Corporation excluding its subsidiaries and affiliates. “PGT” refers to Pinnacle Gas Treating LLC, “MIGC” refers to MIGC LLC, “Chipeta” refers to Chipeta Processing LLC and “additional Chipeta interest” refers to the August 2012 acquisition of Anadarko’s then remaining 24% membership interest in Chipeta. The Partnership and its subsidiaries are indirect subsidiaries of Anadarko.

Available information. We file our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and other documents electronically with the U.S. Securities and Exchange Commission (“SEC”) under the Securities Exchange Act of 1934. From time to time, we may also file registration and related statements pertaining to equity or debt offerings.

We provide access free of charge to all of these SEC filings, as soon as reasonably practicable after filing or furnishing with the SEC, on our Internet site located at www.westerngas.com . The public may also read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The public may also obtain such reports from the SEC’s Internet website at www.sec.gov.

Our Corporate Governance Guidelines, Code of Ethics for our Chief Executive Officer and Senior Financial Officers, Code of Business Conduct and Ethics and the charters of the audit committee and the special committee of our general partner’s board of directors are also available on our Internet website. We will also provide, free of charge, a copy of any of our governance documents listed above upon written request to our general partner’s corporate secretary at our principal executive office. Our principal executive offices are located at 1201 Lake Robbins Drive, The Woodlands, TX 77380-1046. Our telephone number is 832-636-6000.

OUR ASSETS AND AREAS OF OPERATION

As of December 31, 2012, our assets included thirteen gathering systems, seven natural gas treating facilities, ten natural gas processing facilities, two NGL pipelines, one interstate natural gas pipeline that is regulated by Federal Energy Regulatory Commission (“FERC”), one intrastate natural gas pipeline and interests in two natural gas gathering systems and a crude oil pipeline. Our assets are located in East, West and South Texas, the Rocky Mountains (Colorado, Utah and Wyoming), and the Mid-Continent (Kansas and Oklahoma).

Our operations are organized into a single operating segment that engages in gathering, processing, compressing, treating and transporting Anadarko and third-party natural gas, condensate, NGLs and crude oil in the U.S. See Item 8 of this Form 10-K for disclosure of revenues, profits and total assets.

ACQUISITIONS

Presentation of Partnership assets. References to the “Partnership assets” refer collectively to the assets owned by us as of December 31, 2012. Because Anadarko controls us through its control of WGP, which owns our general partner, each of our acquisitions of assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets we acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by us. Further, after an acquisition of assets from Anadarko, we may be required to recast our financial statements to include the activities of such assets as of the date of common control.

EQUITY OFFERINGS

Equity offering. In June 2012, we completed a public offering of 5,000,000 common units representing limited partner interests in the Partnership, and issued 102,041 general partner units to the general partner in exchange for the general partner’s proportionate capital contribution to maintain its 2.0% general partner interest. The price per unit was $43.88, generating proceeds of $216.4 million (net of $7.4 million for the underwriting discount and other offering expenses), including the general partner’s proportionate capital contribution. The net proceeds were used for general partnership purposes, including the funding of capital expenditures.

In August 2012, we filed a registration statement with the SEC authorizing the issuance of up to $125.0 million of our common units in amounts, at prices and on terms to be determined by market conditions and other factors at the time of our offerings. As of December 31, 2012, we had not issued any common units under this registration statement. On December 12, 2012, in connection with the closing of the WGP IPO, we sold 8,722,966 common units to WGP and 178,019 general partner units to the general partner, in each case at a price of $46.00 per unit, pursuant to a unit purchase agreement among us, our general partner and WGP. The sale of common units and general partner units resulted in aggregate proceeds to us of $409.4 million. The net proceeds from this offering are being used for general partnership purposes, including the funding of capital expenditures. In addition, please refer to Note 12—Subsequent Events in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

STRATEGY

Our primary business objective is to continue to increase our cash distributions per unit over time. To accomplish this objective, we intend to execute the following strategy:

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Pursuing accretive acquisitions. We expect to continue to pursue accretive acquisitions of midstream energy assets from Anadarko and third parties.

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Capitalizing on organic growth opportunities. We expect to grow certain of our systems organically over time by meeting Anadarko’s and our other customers’ midstream service needs that result from their drilling activity in our areas of operation. We continually evaluate economically attractive organic expansion opportunities in existing or new areas of operation that allow us to leverage our existing infrastructure, operating expertise and customer relationships by constructing and expanding systems to meet new or increased demand of our services.

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Attracting third-party volumes to our systems. We expect to continue to actively market our midstream services to, and pursue strategic relationships with, third-party producers and customers with the intention of attracting additional volumes and/or expansion opportunities.

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Managing commodity price exposure. We intend to continue limiting our direct exposure to commodity price changes and promote cash flow stability by pursuing a contract structure designed to mitigate exposure to commodity price uncertainty through the use of fee-based contracts and with fixed-price hedges.

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Maintaining investment grade ratings. We intend to operate at appropriate leverage and distribution coverage levels in line with other partnerships in our sector that have received investment grade credit ratings. By maintaining an investment grade credit rating with at least two of the three credit rating agencies, in part through staying within leverage ratios appropriate for investment-grade partnerships, we believe that we will be able to pursue strategic acquisitions and large growth projects at a lower cost of fixed-income capital, which would enhance their accretion and overall return.

COMPETITIVE STRENGTHS

We believe that we are well positioned to successfully execute our strategy and achieve our primary business objective because of the following competitive strengths:

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Affiliation with Anadarko. We believe Anadarko is motivated to promote and support the successful execution of our business plan and to use our relationships throughout the energy industry, including those with producers and customers in the United States, to help pursue projects that help to enhance the value of our business. See Our Relationship with Anadarko Petroleum Corporation below.

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Relatively stable and predictable cash flows. Our cash flows are largely protected from fluctuations caused by commodity price volatility due to (i) the approximately two-thirds of our services that are provided pursuant to long-term, fee-based agreements and (ii) the commodity price swap agreements that limit our exposure to commodity price changes with respect to our percent-of-proceeds and keep-whole contracts. For the year ended December 31, 2012, approximately 97% 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.

•
Financial flexibility to pursue expansion and acquisition opportunities . We believe our operating cash flows, borrowing capacity, and access to debt and equity capital markets provide us with the financial flexibility to competitively pursue acquisition and expansion opportunities and to execute our strategy across capital market cycles. We currently have investment grade ratings from two of the three major rating agencies and, as of December 31, 2012, we did not have outstanding borrowings under the $800.0 million revolving credit facility (“RCF”), and had $6.7 million in outstanding letters of credit issued under the RCF.

•
Substantial presence in liquids-rich basins. Our asset portfolio includes gathering and processing systems, such as our Wattenberg, Platte Valley, Chipeta and Granger assets, which are in areas where the hydrocarbon production, in addition to natural gas, contains oil and condensate, as well as a significant amount of NGLs, for which pricing has historically been correlated to crude oil as opposed to natural gas. See — Properties below for further descriptions of these assets. Due to the relatively high current price of crude oil as compared to natural gas, production in these areas offers our customers higher margins and superior economics compared to basins in which the gas is predominantly dry. This pricing environment offers expansion opportunities for certain of our systems as producers attempt to increase their wet gas and crude oil production.

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Well-positioned, well-maintained and efficient assets. We believe that our asset portfolio across geographically diverse areas of operation provides us with opportunities to expand and attract additional volumes to our systems from multiple productive reservoirs. Moreover, our portfolio includes an integrated package of high-quality, well-maintained assets for which we have implemented modern processing, treating, measuring and operating technologies.

•
Consistent track record of accretive acquisitions. Since our IPO in 2008, our management team has successfully executed seven related-party acquisitions and two third-party acquisitions, for a total value of approximately $2.2 billion. Our management team has demonstrated its ability to identify, evaluate, negotiate, consummate and integrate strategic acquisitions and expansion projects, and it intends to use its experience and reputation to continue to grow the Partnership through accretive acquisitions, focusing on opportunities to improve throughput volumes and cash flows.

We believe that we will effectively leverage our competitive strengths to successfully implement our strategy; however, our business involves numerous risks and uncertainties that may prevent us from achieving our primary business objective.

OUR RELATIONSHIP WITH ANADARKO PETROLEUM CORPORATION

Our operations and activities are managed by our general partner, which is indirectly controlled by Anadarko through WGP. Anadarko Petroleum Corporation is among the largest independent oil and gas exploration and production companies in the world. Anadarko’s upstream oil and gas business explores for and produces natural gas, crude oil, condensate and NGLs.

We believe that one of our principal strengths is our relationship with Anadarko, and that Anadarko, through its significant indirect economic interest in us, 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.

Approximately 76% of our gathering, transportation and treating throughput (excluding equity investment throughput and volumes measured in barrels) during the year ended December 31, 2012, was attributable to natural gas production owned or controlled by Anadarko. Approximately 59% of our processing throughput (excluding equity investment throughput and volumes measured in barrels) during the year ended December 31, 2012, was attributable to natural gas production owned or controlled by Anadarko. In addition, with respect to the Wattenberg, Dew, Pinnacle, Haley, Helper, Clawson and Hugoton gathering systems, Anadarko has dedicated to us pursuant to the terms of its applicable gathering agreements 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. In executing our growth strategy, which includes acquiring and constructing additional midstream assets, we utilize the significant experience of Anadarko’s management team.

As of December 31, 2012, WGP and Affiliates held 49,296,205 of our common units, representing a 46.2% limited partner interest in us, and, through its ownership of our general partner, indirectly held 2,135,930 general partner units representing a 2.0% general partner interest in us and 100% of our incentive distribution rights (“IDRs”). As of December 31, 2012, the public held 55,364,348 common units, representing a 51.8% limited partner interest in us.

In connection with our IPO, we entered into an omnibus agreement with Anadarko and our general partner that governs our relationship with them regarding certain reimbursement and indemnification matters. Although we believe our relationship with Anadarko provides us with a significant advantage in the midstream natural gas sector, it is also a source of potential conflicts. For example, neither Anadarko nor WGP is restricted from competing with us. Given Anadarko’s significant indirect economic interest in us through its ownership of WGP, we believe it will be in Anadarko’s best economic interest for it to transfer additional assets to us over time. However, Anadarko continually evaluates acquisitions and divestitures and may elect to acquire, construct or dispose of midstream assets in the future without offering us the opportunity to acquire, construct or participate in the ownership of those assets. Anadarko is under no contractual obligation to offer any such opportunities to us, nor are we obligated to participate in any such opportunities. We cannot state with any certainty which, if any, opportunities to acquire additional assets from Anadarko may be made available to us or if we will elect, or will have the ability, to pursue any such opportunities. Please see Item 1A and Item 13 of this Form 10-K for more information.

INDUSTRY OVERVIEW

The midstream natural gas industry is the link between the exploration for and production of natural gas and the delivery of its hydrocarbon components to end-use markets. Operators within this industry create value at various stages along the natural gas value chain by gathering raw natural gas from producers at the wellhead, separating the hydrocarbons into dry gas (primarily methane) and NGLs, and then routing the separated dry gas and NGL streams for delivery to end-use markets or to the next intermediate stage of the value chain.

Service Types
The services provided by us and other midstream natural gas companies are generally classified into the categories described below. As indicated below, we do not currently provide all of these services, although we may do so in the future.

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Gathering. At the initial stages of the midstream value chain, a network of typically smaller diameter pipelines known as gathering systems directly connect to wellheads in the production area. These gathering systems transport raw, or untreated, natural gas to a central location for treating and processing. A large gathering system may involve thousands of miles of gathering lines connected to thousands of wells. Gathering systems are typically designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow gathering of additional production without significant incremental capital expenditures. In connection with our gathering services, we sometimes retain, stabilize and sell drip condensate, which falls out of the natural gas stream during gathering.

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Compression. Natural gas compression is a mechanical process in which a volume of natural gas at a given pressure is compressed to a desired higher pressure, which allows the natural gas to be gathered more efficiently and delivered into a higher pressure system, processing plant or pipeline. Field compression is typically used to allow a gathering system to operate at a lower pressure or provide sufficient discharge pressure to deliver natural gas into a higher pressure system. Since wells produce at progressively lower field pressures as they deplete, field compression is needed to maintain throughput across the gathering system.

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Treating and dehydration. To the extent that gathered natural gas contains contaminants, such as water vapor, carbon dioxide and/or hydrogen sulfide, such natural gas is dehydrated to remove the saturated water and treated to separate the carbon dioxide and hydrogen sulfide from the gas stream.

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Processing. Processing removes the heavier and more valuable hydrocarbon components, which are extracted as NGLs. The residue remaining after extraction of NGLs meets the quality standards for long-haul pipeline transportation or commercial use.

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Fractionation. Fractionation is the separation of the mixture of extracted NGLs into individual components for end-use sale. It is accomplished by controlling the temperature and pressure of the stream of mixed NGLs in order to take advantage of the different boiling points of separate products.

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Storage, transportation and marketing. Once the raw natural gas has been treated or processed and the raw NGL mix has been fractionated into individual NGL components, the natural gas and NGL components are stored, transported and marketed to end-use markets. Each pipeline system typically has storage capacity located both throughout the pipeline network and at major market centers to help temper seasonal demand and daily supply-demand shifts. We do not currently offer storage services or conduct marketing activities.

MANAGEMENT DISCUSSION FROM LATEST 10K

We are a growth-oriented Delaware master limited partnership (“MLP”) organized by Anadarko to own, operate, acquire and develop midstream energy assets. We currently own assets located in East, West and South Texas, the Rocky Mountains (Colorado, Utah and Wyoming), and the Mid-Continent (Kansas and Oklahoma) and are engaged in the business of gathering, processing, compressing, treating and transporting natural gas, condensate, NGLs and crude oil for Anadarko and its consolidated subsidiaries, as well as for third-party producers and customers. As of December 31, 2012, our assets consisted of thirteen gathering systems, seven natural gas treating facilities, ten natural gas processing facilities, two NGL pipelines, one interstate natural gas pipeline, one intrastate natural gas pipeline and interests accounted for under the equity method in two gas gathering systems and a crude oil pipeline. See also Note 12—Subsequent Events in the Notes to Consolidated Financial Statements under Item 8 within this Form 10-K.

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

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

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

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

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

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

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

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

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Throughput attributable to Western Gas Partners, LP totaled 2,432 MMcf/d for the year ended December 31, 2012, representing a 9% increase compared to the year ended December 31, 2011.

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Gross margin (total revenues less cost of product) attributable to Western Gas Partners, LP averaged $0.55 per Mcf for the year ended December 31, 2012, representing a 5% decrease compared to the year ended December 31, 2011.

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, 2012, approximately 79% of our total revenues and 68% of our throughput (excluding equity investment revenues and throughput) were attributable to transactions with Anadarko.

In our gathering operations, we contract with producers and customers to gather natural gas from individual wells located near our gathering systems. We connect wells to gathering lines through which natural gas may be compressed and delivered to a processing plant, treating facility or downstream pipeline, and ultimately to end users. We also treat a significant portion of the natural gas that we gather so that it will satisfy required specifications for pipeline transportation.

We received significant dedications from our largest customer, Anadarko, solely with respect to our Wattenberg, Dew, Pinnacle, Haley, Helper, Clawson and Hugoton gathering systems. Specifically, pursuant to the terms of our applicable gathering agreements, Anadarko has dedicated to us all of the natural gas production it owns or controls from (i) wells that are currently connected to such gathering systems, and (ii) additional wells that are drilled within one mile of wells connected to such gathering systems, as those systems currently exist and as they are expanded to connect additional wells in the future. As a result, this dedication will continue to expand as long as additional wells are connected to these gathering systems.

For the year ended December 31, 2012, approximately 66% of our gross margin was attributed to fee-based contracts, under which a fixed fee is received based on the volume or thermal content of the natural gas we gather, process, treat or transport. This type of contract provides us with a relatively stable revenue stream that is not subject to direct commodity price risk, except to the extent that (i) we retain and sell drip condensate that is recovered during the gathering of natural gas from the wellhead or (ii) actual recoveries differ from contractual recoveries under a limited number of processing agreements. Fee-based gross margin includes equity income from our interests in Fort Union, White Cliffs and Rendezvous.

For the year ended December 31, 2012, approximately 34% of our gross margin, including gross margin attributable to condensate sales, was attributable to percent-of-proceeds and keep-whole contracts, pursuant to which we have commodity price exposure. A substantial majority of the commodity price risk associated with our percent-of-proceeds and keep-whole contracts is hedged under commodity price swap agreements with Anadarko. For the year ended December 31, 2012, approximately 97% 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.

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.

As a result of our IPO and subsequent acquisitions from Anadarko and third parties, the results of operations, financial position and cash flows may vary significantly for 2012, 2011 and 2010 as compared to future periods.

HOW WE EVALUATE OUR OPERATIONS

Our management relies on certain financial and operational metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include (1) throughput, (2) gross margin, (3) operating and maintenance expenses, (4) general and administrative expenses, (5) Adjusted EBITDA and (6) Distributable cash flow.

Throughput . Throughput is an essential operating variable we use in assessing our ability to generate revenues. In order to maintain or increase throughput on our gathering and processing systems, we must connect additional wells to our systems. Our success in maintaining or increasing throughput is impacted by successful drilling of new wells by producers that are dedicated to our systems, recompletions of existing wells connected to our systems, our ability to secure volumes from new wells drilled on non-dedicated acreage and our ability to attract natural gas volumes currently gathered, processed or treated by our competitors. During the year ended December 31, 2012, we added 139 receipt points to our systems with initial throughput of approximately 1.7 MMcf/d per receipt point.

Gross margin. We define gross margin as total revenues less cost of product. We consider gross margin to provide information useful in assessing our results of operations and our ability to internally fund capital expenditures and to service or incur additional debt. Cost of product expenses include (i) costs associated with the purchase of natural gas and NGLs pursuant to our percent-of-proceeds and keep-whole processing contracts, (ii) costs associated with the valuation of our gas imbalances, (iii) costs associated with our obligations under certain contracts to redeliver a volume of natural gas to shippers, which is thermally equivalent to condensate retained by us and sold to third parties, and (iv) costs associated with our fuel-tracking mechanism, which tracks the difference between actual fuel usage and loss, and amounts recovered for estimated fuel usage and loss pursuant to our contracts. These expenses are subject to variability, although our exposure to commodity price risk attributable to purchases and sales of natural gas, condensate and NGLs is mitigated through our commodity price swap agreements with Anadarko.

Operating and maintenance expenses. We monitor operating and maintenance expenses to assess the impact of such costs on the profitability of our assets and to evaluate the overall efficiency of our operations. Operation and maintenance expenses include, among other things, field labor, insurance, repair and maintenance, equipment rentals, contract services, utility costs and services provided to us or on our behalf. For periods commencing on and subsequent to our acquisition of the Partnership assets, certain of these expenses are incurred under and governed by our services and secondment agreement with Anadarko.

General and administrative expenses . To help ensure the appropriateness of our general and administrative expenses and maximize our cash available for distribution, we monitor such expenses through comparison to prior periods, to the annual budget approved by our general partner’s board of directors, as well as to general and administrative expenses incurred by similar midstream companies. General and administrative expenses for periods prior to our acquisition of the Partnership assets include amounts attributable to costs incurred on our behalf and allocations of general and administrative costs by Anadarko and the general partner to us. For periods subsequent to our acquisition of the Partnership assets, Anadarko is no longer compensated for corporate services through a management services fee. Instead, allocations and reimbursements of general and administrative expenses are determined by Anadarko in its reasonable discretion, in accordance with our partnership agreement and omnibus agreement. Amounts required to be reimbursed to Anadarko under the omnibus agreement also include those expenses attributable to our status as a publicly traded partnership, such as the following:

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expenses associated with annual and quarterly reporting;

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

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

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

Non-GAAP financial measures
Adjusted EBITDA. We define “Adjusted EBITDA” as net income (loss) attributable to Western Gas Partners, LP, plus distributions from equity investees, non-cash equity-based compensation expense, expense in excess of the expense reimbursement cap provided in our omnibus agreement (which cap is no longer effective), interest expense, income tax expense, depreciation, amortization and impairments, and other expense, less income from equity investments, interest income, income tax benefit, and other income. We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations and that Adjusted EBITDA is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures and make distributions. Adjusted EBITDA is a supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, commercial banks and rating agencies, use to assess the following, among other measures:

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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;

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

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

Distributable cash flow. We define “Distributable cash flow” as Adjusted EBITDA, plus interest income, less net cash paid for interest expense (including amortization of deferred debt issuance costs originally paid in cash offset by non-cash capitalized interest), maintenance capital expenditures, and income taxes. We compare Distributable cash flow to the cash distributions we expect to pay our unitholders. Using this measure, management can quickly compute the Coverage ratio of estimated cash flows to planned cash distributions. We believe Distributable cash flow is useful to investors because this measurement is used by many companies, analysts and others in the industry as a performance measurement tool to evaluate our operating and financial performance and compare it with the performance of other publicly traded partnerships.

Distributable cash flow should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. Furthermore, while Distributable cash flow is a measure we use to assess our ability to make distributions to our unitholders, it should not be viewed as indicative of the actual amount of cash that we have available for distributions or that we plan to distribute for a given period.

Reconciliation to GAAP measures. Adjusted EBITDA and Distributable cash flow are not defined in GAAP. The GAAP measures most directly comparable to Adjusted EBITDA are net income attributable to Western Gas Partners, LP and net cash provided by operating activities, and the GAAP measure most directly comparable to Distributable cash flow is net income attributable to Western Gas Partners, LP. Our non-GAAP financial measures of Adjusted EBITDA and Distributable cash flow should not be considered as alternatives to the GAAP measures of net income attributable to Western Gas Partners, LP or net cash provided by operating activities. Adjusted EBITDA and Distributable cash flow have important limitations as analytical tools because they exclude some, but not all, items that affect net income and net cash provided by operating activities. Adjusted EBITDA and Distributable cash flow should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Our definitions of Adjusted EBITDA and Distributable cash flow may not be comparable to similarly titled measures of other companies in our industry, thereby diminishing their utility.

Management compensates for the limitations of Adjusted EBITDA and Distributable cash flow as analytical tools by reviewing the comparable GAAP measures, understanding the differences between Adjusted EBITDA and Distributable cash flow compared to (as applicable) net income and net cash provided by operating activities, and incorporating this knowledge into its decision-making processes. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results.

ITEMS AFFECTING THE COMPARABILITY OF OUR FINANCIAL RESULTS

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

Affiliate contracts. The gathering agreements of our initial assets allow for rate resets that target an 18% 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.

Commodity price swap agreements . We have commodity price swap agreements with Anadarko to mitigate exposure to commodity price volatility that would otherwise be present as a result of the purchase and sale of natural gas, condensate or NGLs. Notional volumes for each of the commodity price swap agreements are not specifically defined; instead, the commodity price swap agreements apply to the actual volume of our natural gas, condensate and NGLs purchased and sold at the Granger, Hilight, Hugoton, Newcastle, MGR and Wattenberg assets, with various expiration dates through December 2016. In December 2011, we extended the commodity price swap agreements for the Hilight and Newcastle assets through December 2013.

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

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

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

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 and the MGR acquisition. Therefore, interest expense and interest income attributable to these balances are reflected in our historical consolidated financial statements for the periods ending prior to our acquisition of the Partnership assets, except for Chipeta. Chipeta cash settles its transactions directly with third parties and Anadarko, as well as with the other subsidiaries of the Partnership.

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

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

The fair values of the plant and processing facilities, related equipment, and intangible assets acquired were based on the market, cost and income approaches. The liabilities assumed include certain amounts associated with environmental contingencies estimated by management. All fair-value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs.

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

MANAGEMENT DISCUSSION FOR LATEST QUARTER

OVERVIEW

The Partnership is a growth-oriented Delaware limited partnership recently formed by Anadarko to own, operate, acquire and develop midstream energy assets. The Partnership currently operates in East Texas, the Rocky Mountains, the Mid-Continent and West Texas and is engaged in the business of gathering, compressing, treating and transporting natural gas for Anadarko and third-party producers and customers.

OUR OPERATIONS

Our results are driven primarily by the volumes of natural gas we gather, compress, treat or transport through our systems. For the quarter ended March 31, 2008, approximately 68% of our revenues were derived from gathering, compression and treating activities, approximately 13% of our revenues were derived from transportation activities, approximately 14% of our revenues were derived from condensate sales and 5% of our revenues were derived from natural gas sales from settlement of imbalances and other revenues. For the quarter ended March 31, 2008, approximately 72% and 14% of our total revenues were attributable to transactions entered into with Anadarko and National Cooperative Refinery Association, respectively.

In our gathering operations, we contract with producers to gather natural gas from individual wells located near our gathering systems. We connect wells to gathering lines through which natural gas may be compressed and delivered to a processing plant, treating facility or downstream pipeline, and ultimately to end-users. We also treat a significant portion of the natural gas that we gather so that it will satisfy required specifications for pipeline transportation.
Effective January 1, 2008, we received a significant dedication from our largest customer, Anadarko, in order to maintain or increase our existing throughput levels and to offset the natural production declines of the wells currently connected to our gathering systems. Specifically, Anadarko has dedicated to us all of the natural gas production it owns or controls from (i) wells that are currently connected to our gathering systems, and (ii) additional wells that are drilled within one mile of connected wells or our gathering systems, as the systems currently exist and as they are expanded to connect additional wells in the future. As a result, this dedication will continue to expand as additional wells are connected to our gathering systems. Volumes associated with this dedication averaged approximately 671,000 MMBtu/d for the quarter ended March 31, 2008 and 771,000 MMBtu/d for the quarter ended March 31, 2007, based on throughput from the wells ultimately subject to the dedication.

We generally do not take title to the natural gas that we gather, compress, treat or transport. We currently provide all of our gathering and treating services pursuant to fee-based contracts. Under these arrangements, we are paid a fixed fee based on the volume and thermal content of the natural gas we gather, compress, treat or transport. This type of contract provides us with a relatively stable revenue stream that is not subject to direct commodity price risk, except to the extent that we retain and sell condensate that is recovered during the gathering of natural gas from the wellhead. Pursuant to the terms of the new gathering contracts we entered into with Anadarko and described in more detail under “Items Affecting the Comparability of our Financial Results” below, we will receive higher gathering fees than we have historically received.

We have indirect exposure to commodity price risk in that persistent low commodity prices may cause our current or potential customers to delay drilling or shut in production, which would reduce the volumes of natural gas available for gathering, compressing, treating and transporting by our systems. Please read “Quantitative and Qualitative Disclosures about Market Risk” below for a discussion of our exposure to commodity price risk through our condensate recovery and sales.

We provide a significant portion of our transportation services on our MIGC system through firm contracts that obligate our customers to pay a monthly reservation or demand charge, which is a fixed charge applied to firm contract capacity and owed by a customer regardless of the actual pipeline capacity used by that customer. When a customer uses the capacity it has reserved under these contracts, we are entitled to collect an additional commodity usage charge based on the actual volume of natural gas transported. These usage charges are typically a small percentage of the total revenues received from our firm capacity contracts. We also provide transportation services through interruptible contracts, pursuant to which a fee is charged to our customers based upon actual volumes transported through the pipeline.

As a result of the completion of the Offering on May 14, 2008, the results of operations, financial condition and cash flows are expected to vary significantly in 2008 and future periods when compared to the quarter ended March 31, 2008 and prior periods. Please see “Items Affecting the Comparability of our Financial Results,” set forth below in this Item.

HOW WE EVALUATE OUR OPERATIONS

Our management relies on certain financial and operational metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include (1) throughput volumes, (2) operating expenses and (3) Adjusted EBITDA.

Throughput volumes

In order to maintain or increase throughput volumes on our gathering systems, we must connect additional wells to our systems. Our success in connecting additional wells is impacted by successful drilling of new wells which will be dedicated to our systems, our ability to secure volumes from new wells drilled on non-dedicated acreage and our ability to attract natural gas volumes currently gathered or treated by our competitors.
To maintain and increase throughput volumes on our MIGC system, we must continue to contract our capacity to shippers, including producers and marketers, for transportation of their natural gas. We monitor producer and marketing activities in the area served by our transportation system to identify new opportunities.

Operating expenses

We analyze operating expenses to evaluate our performance. The primary components of our operating expenses that we evaluate include operation and maintenance expenses, cost of product expenses, general and administrative expenses and direct operating expenses. Certain of our operating expenses are classified based on whether the expenses are accrued for or paid to our affiliates or third-party vendors. Neither affiliate expenses nor third-party expenses bear a direct relationship to affiliate revenues or third-party revenues. For example, our third-party expenses are not those expenses necessary for generating our third-party revenues. Third-party expenses include all amounts accrued for or paid to third parties for the operation of our systems, whether in providing services to Anadarko or third parties, including utilities, field labor, measurement and analysis and other third-party disbursements.
Operation and maintenance expenses include, among other things, direct labor, insurance, repair and maintenance, contract services, utility costs and services provided to us or on our behalf. For future periods, including a portion of the period in which the Offering was completed, these expenses are governed by our services and secondment agreement with Anadarko.

Cost of product expenses include (i) costs associated with the purchase of natural gas pursuant to the gas imbalance provisions contained in our contracts, (ii) 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 (iii) our fuel tracking mechanism, which tracks the difference between actual fuel usage and loss and amounts recovered for estimated fuel usage and loss under our contracts. These expenses are subject to variability. However, for the quarters ended March 31, 2008 and 2007, cost of product expenses comprised 17.4% and 15.8% of total operating expenses, respectively. We do not expect the variability in our cost of product expenses to have a material impact on our overall results.

General and administrative expenses include reimbursements of costs incurred by Anadarko on our behalf and allocations from Anadarko in the form of a management service fee in lieu of direct reimbursements for various corporate services. Subsequent to the Offering, Anadarko will not receive a management services fee and we expect general and administrative expenses to be comprised primarily of amounts reimbursed by us to Anadarko pursuant to our omnibus agreement with Anadarko and expenses attributable to our status as a publicly traded partnership, such as:

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expenses associated with annual and quarterly reporting;
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tax return and Schedule K-1 preparation and distribution expenses;
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Sarbanes-Oxley compliance expenses;
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expenses associated with listing on the New York Stock Exchange;
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independent auditor fees; legal fees; investor relations expenses; and registrar and transfer agent fees.

Pursuant to the omnibus agreement with Anadarko, we will reimburse Anadarko for allocated general and administrative expenses. The amount required to be reimbursed by us to Anadarko for certain allocated general and administrative expenses pursuant to the omnibus agreement will be capped at $6.0 million annually through December 31, 2009, subject to adjustment to reflect changes in the Consumer Price Index and, with the concurrence of the special committee of our general partner’s board of directors, to reflect expansions of our operations through the acquisition or construction of new assets or businesses. Thereafter, our general partner will determine the general and administrative expenses to be reimbursed by us in accordance with our partnership agreement. The cap contained in the omnibus agreement does not apply to incremental general and administrative expenses we expect to incur or to be allocated to us as a result of becoming a publicly traded partnership. We currently expect those expenses to be approximately $2.5 million per year.

Adjusted EBITDA

We define Adjusted EBITDA as net income (loss), plus interest expense, income tax expense and depreciation, less interest income, income tax benefit and other income (expense).

We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations and that Adjusted EBITDA is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures and make distributions. Adjusted EBITDA is a supplemental financial measure that management and external users of our combined financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:

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our operating performance as compared to publicly traded partnerships in the midstream energy industry, without regard to financing methods, capital structure or historical cost basis;
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the ability of our assets to generate cash flow to make distributions; and
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the viability of acquisitions and capital expenditure projects and the returns on investment of various investment opportunities.

The GAAP measures most directly comparable to Adjusted EBITDA are net income and net cash provided by operating activities. Our non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to the GAAP measures of net income or net cash provided by operating activities. Adjusted EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income and net cash provided by operating activities. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA may be defined differently by other companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between Adjusted EBITDA and 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.

ITEMS AFFECTING THE COMPARABILITY OF OUR FINANCIAL RESULTS

Our historical results of operations for the periods presented may not be comparable to future or historic results of operations for the reasons described below:
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We anticipate incurring approximately $2.5 million of general and administrative expenses annually attributable to operating as a publicly traded partnership, such as expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the New York Stock Exchange; independent auditor fees; legal fees; investor relations expenses; and registrar and transfer agent fees. These incremental general and administrative expenses are not reflected in our historical combined financial statements.

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We anticipate incurring up to $6.0 million in general and administrative expenses annually to be charged to us by Anadarko pursuant to the omnibus agreement. This amount is expected to be greater than the amount allocated to us by Anadarko for the management services fee reflected in our historical combined financial statements.

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Historically, the impact of all affiliated transactions has been net settled within our combined financial statements because these transactions related to Anadarko and were funded by Anadarko’s working capital. Third-party transactions were funded by our working capital. In the future, all affiliate and third-party transactions will be funded by our working capital. This will impact the comparability of our cash flow statements, working capital analysis and liquidity discussion.

• Prior to the Offering, we incurred interest expense on intercompany notes payable to Anadarko. These intercompany balances were extinguished through non-cash transactions in connection with the Offering; therefore, interest expense attributable to these balances and reflected in our historical combined financial statements will not be incurred in future periods.

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For periods ending prior to January 1, 2008, our combined financial statements reflect the gathering fees we historically charged Anadarko under our affiliate cost-of-service-based arrangements. Under these arrangements, we recovered, on an annual basis, our operation and maintenance, general and administrative and depreciation expenses in addition to earning a return on our invested capital. Effective January 1, 2008, we entered into new 10-year gas gathering agreements with Anadarko. As discussed above, our fees for gathering and treating services rendered to Anadarko pursuant to the terms of the new gas gathering agreements increased. In part, this increase is attributable to our operation and maintenance expense increasing as a result of us bearing all of the cost of employee benefits specifically identified and related to operational personnel working on our assets, as compared to bearing only those employee benefit costs reasonably allocated by Anadarko to us for the periods ending prior to January 1, 2008. Since our new gas gathering agreements are designed to fully recover these costs, our revenues increased by an amount equal to the employee-benefit related increase in operation and maintenance expense. Although this change in methodology for computing affiliate gathering rates does not impact our net cash flows or net income, this methodology change impacts the components thereof as compared to periods ending prior to January 1, 2008. If we applied the methodology employed under our new gas gathering agreements with Anadarko for the quarter ended March 31, 2007, we estimate our gathering revenues and operation and maintenance expense would have increased by $1.1 million and our cash flow from operations would have remained unchanged.

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The gas gathering agreements with Anadarko effective January 1, 2008 include new fees for gathering and treating. The new fees are based on recent capital improvements and changes in our cost-of-service analysis and are higher than those fees reflected in our historical financial results prior to January 1, 2008.

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Concurrent with the closing of the Offering, we loaned $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%. Interest income attributable to the note is not reflected in our historical combined financial statements, but will be included in our combined financial statements in the future.

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Pursuant to the omnibus agreement, as a co-borrower under Anadarko’s credit facility, we are required to reimburse Anadarko for our allocable portion of commitment fees (0.11% of our committed and available borrowing capacity) that Anadarko incurs under its credit facility, or up to $110,000. Please read “Certain relationships and related party transactions — Agreements governing the transactions — Omnibus agreement” in the Partnership’s Registration Statement on Form S-1, as amended, filed with the SEC on April 25, 2008. In addition, Anadarko entered into a working capital facility with us, under which we expect to incur an annual commitment fee of 0.11% of the unused portion of our committed borrowing capacity of $30 million, or up to $33,000.

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Our historical combined financial statements include U.S. federal and state income tax expense incurred by us. Due to our status as a partnership, we will not be subject to U.S. federal income tax and certain state income taxes in the future. However, we will make payments to Anadarko pursuant to a tax sharing agreement for our share of state and local income and other taxes that are included in combined or consolidated tax returns filed by Anadarko.

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After the Offering date, we intend to make cash distributions to our unitholders and our general partner at an initial distribution rate of $0.30 per unit per full quarter ($1.20 per unit on an annualized basis). Based on the terms of our cash distribution policy, we expect that we will distribute to our unitholders and our general partner most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, including commercial bank borrowings and debt and equity issuances, to fund our acquisition and expansion capital expenditures. Historically, we largely relied on internally generated cash flows and capital contributions from Anadarko to satisfy our capital expenditure requirements.

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In connection with the closing of the Offering, our general partner adopted two new compensation plans, the Western Gas Partners, LP 2008 Long-Term Incentive Plan (“LTIP”) and the Western Gas Holdings, LLC Equity Incentive Plan (“Incentive Plan”). Phantom unit grants have been made to each of our independent directors under the LTIP, and incentive unit grants have been made to each of our executive officers pursuant to the Incentive Plan. Pursuant to Financial Accounting Standards Board (“FASB”) Statement No. 123 (revised 2004), “Shared-Based Payment” (“SFAS 123R”), grants made under equity-based compensation plans result in share-based compensation expense which is determined, in part, by reference to the fair value of equity compensation as of the date of grant. Share-based compensation expense is not reflected in our historical combined financial statements as there were no outstanding equity grants under either plan for the periods presented. Share-based compensation expense for grants made pursuant to the LTIP and Incentive Plan will be reflected in our future statements of operations. Share-based compensation expense attributable to grants made pursuant to the LTIP will impact our cash flow from operating activities only to the extent our board of directors, at its discretion, elects to make a cash payment to a participant in lieu of actual receipt of common units by the participant upon the lapse of the relevant vesting period. Equity-based compensation expense attributable to grants made pursuant to the Incentive Plan will impact our cash flow from operating activities only to the extent cash payments are made to Incentive Plan participants and such cash payments do not cause total annual reimbursements made by us to Anadarko pursuant to the omnibus agreement to exceed the general and administrative expense limit set forth therein for the periods to which such expense limit applies.

GENERAL TRENDS AND OUTLOOK

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

Natural gas supply and demand

Natural gas continues to be a critical component of energy supply in the U.S. According to the Energy Information Administration, or EIA, total annual domestic consumption of natural gas is expected to increase from approximately 23.0 trillion cubic feet, or Tcf, in 2007 to approximately 24.7 Tcf in 2010. During the last three years, the U.S. has, on average, consumed approximately 22.0 Tcf per year, while total domestic production averaged approximately 18.4 Tcf per year during the same period. We believe that high natural gas prices and increasing demand will continue to drive an increase in natural gas drilling and production in the U.S. Overall, natural gas reserves in the U.S. have increased in recent years, based on data obtained from the EIA.

There is a natural decline in production from existing wells, but in the areas in which we operate there is a significant level of drilling activity that can offset this decline. Although we anticipate continued high levels of exploration and production activities in all of the areas in which we operate, we have no control over this activity. Fluctuations in energy prices could affect production rates over time and levels of investment by Anadarko and third parties in exploration for and development of new natural gas reserves.

Rising operating costs and inflation

The current high level of natural gas exploration, development and production activities across the U.S. and the associated construction of required midstream infrastructure have resulted in increased competition for personnel and equipment. This is causing increases in the prices we pay for labor, supplies and property, plant and equipment. An increase in the general level of prices in the economy could have a similar effect. We have the ability to recover increased costs from our customers through escalation provisions provided for in our contracts. However, there may be a delay in recovering these costs or we may be unable to recover all these costs. To the extent we are unable to recover higher costs, our operating results will be negatively impacted.

Impact of interest rates

Interest rates have been volatile in recent periods. If interest rates rise, our future financing costs would increase accordingly. In addition, because our common units are yield-based securities, rising market interest rates could impact the relative attractiveness of our common units to investors, which could limit our ability to raise funds, or increase the price of raising funds, in the capital markets. Though our competitors may face similar circumstances, such an environment could render us less competitive in our efforts to expand our operations or make future acquisitions.

Benefits from system expansions

We expect that expansion projects, including the following, will allow us to capitalize on increased drilling activity by Anadarko and other third-party producers:

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We installed additional compression on our Dew system, which added an incremental 16,537 horsepower in 2007 and we anticipate adding an additional 2,680 horsepower in 2008;
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We are expanding our Bethel treating facility by installing an additional 11 LTD of sulfur treating capacity in order to provide additional sour gas treating capacity for drilling in the area, which we expect to complete in 2008; and
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We are expanding our Hugoton gathering system to connect wells drilled by third parties.

Acquisition opportunities

We may acquire additional midstream energy assets from Anadarko. On December 27, 2007, Anadarko announced a $2.2 billion financing of its midstream assets which may require partial repayment based on a debt-to-EBITDA leverage ratio that declines incrementally over time. The repayments that may be necessary to satisfy the terms of this financing may be made with internally generated cash flow, cash on hand, or cash received from midstream asset sales. Should Anadarko choose to pursue midstream asset sales, it is under no contractual obligation to offer assets or business opportunities to us. In addition, we may also pursue selected 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 production. However, if we do not make acquisitions on economically acceptable terms, our future growth will be limited, and the acquisitions we make may reduce, rather than increase, our cash generated from operations on a per-unit basis.

RESULTS OF OPERATIONS — COMBINED OVERVIEW

OPERATING RESULTS

Our discussion below compares the results for specific periods to the previous comparable period. The discussion compares the quarter ended March 31, 2008 to the quarter ended March 31, 2007. For purposes of the following discussion, any increases or decreases “for the quarter ended March 31, 2008” refer to the comparison of the three-month period ended March 31, 2008 to the three-month period ended March 31, 2007.

Summary

Total revenues increased $8.3 million for the quarter ended March 31, 2008. Gathering and transportation revenue increased $5.4 million, condensate revenue increased $2.7 million and other revenue increased $0.2 million. These revenue increases are discussed below.

Net income increased by $2.9 million for the quarter ended March 31, 2008. The increase in net income was primarily driven by higher revenue due to gathering rate increases and increased condensate margins. These increases were partially offset by higher operating expenses and income taxes of $3.7 million and $1.8 million, respectively.

Throughput volumes decreased by 90,000 MMbtu/d for the quarter ended March 31, 2008. Affiliate volumes declined by 99,000 MMbtu/d and third-party volumes increased by 9,000 MMbtu/d. The decline in affiliate throughput volumes is primarily due to a production decline and reduced drilling activity in the area currently dedicated to the Haley system, located within the Delaware Basin. Specifically, Haley field production and related throughput into the Haley system peaked in the first quarter of 2007 in connection with first production from several wells. Since the first quarter of 2007, production and associated throughput volumes from the Haley field have gradually declined and the number of new wells connected to the system have decreased due to a shift in rig activity from the dedicated area to other exploration areas within the Delaware Basin. However, the number of wells currently being drilled in the Haley field is consistent with our expectations. Three wells were connected to the Haley gathering system during the quarter ended March 31, 2008 and we expect at least four additional wells to be connected by September 30, 2008. Additionally, the Anadarko/Chesapeake Energy Corporation joint venture continues an active drilling program in the Delaware Basin with 10 rigs running in the first quarter of 2008.

Third-party throughput volumes increased due to a third party’s successful drilling program, which resulted in additional wells being connected to the Hugoton gathering system. We expect the third party to maintain its active drilling program in the area and to drill approximately 50 gross wells in 2008. This increase in third-party throughput volumes for the quarter ended March 31, 2008 was partially offset by a decline in third-party volumes transported on the Pinnacle system resulting from the termination of an interim contract that concluded subsequent to the period ended March 31, 2007.

Revenues and Operating Statistics

Gathering and Transportation of Natural Gas Revenues

Total gathering and transportation of natural gas revenues increased $5.4 million for the quarter ended March 31, 2008. Revenues from affiliates increased $3.6 million primarily due to an increase in AGC gathering rates on all systems for the quarter ended March 31, 2008. Revenues from third parties increased $1.8 million primarily due to an increase in AGC volumes gathered for a third party on the Hugoton system and recognition of approximately $589,000 of demand charges related to the period from April 2006 through December 2007.

Condensate Revenues

Total condensate revenues increased $2.7 million for the quarter ended March 31, 2008. This increase was primarily due to increased condensate prices, which averaged $91.56 for the quarter ended March 31, 2008 as compared to $51.70 for the quarter ended March 31, 2007. As a result of modifications to contractual arrangements which took effect November 2007, all of our condensate sales for the quarter ended March 31, 2008 are third-party sales.

Natural Gas and Other Revenues

Total natural gas and other revenues increased $0.2 million for the quarter ended March 31, 2008. The increase was due to an increase in other operating revenues of $0.9 million related to an indemnity payment received from a third party for guaranteed volumes offset by changes in our gas imbalance position.

Cost of Product and Operation and Maintenance Expenses

Cost of product and operation and maintenance expenses increased $2.6 million for the quarter ended March 31, 2008 primarily due to $1.7 million of increased labor and related employee expenses. AGC and PGT labor expenses increased $1.1 million and $0.6 million, respectively, for the quarter ended March 31, 2008. For the quarter ended March 31, 2008, approximately $1.1 million of the $1.7 million increase in labor and related employee expenses was attributable to a change in the structure of affiliate contracts and the treatment of such expenses. Specifically, approximately $1.1 million in additional labor and related employee expenses were charged by Anadarko to us in order for us to bear the full cost of operational personnel working on our assets as opposed to bearing only those employee benefit costs reasonably allocated by Anadarko to us. These additional costs were taken into account when setting the affiliate-based gathering rates in the new contracts; thus, our revenues increased by the same amount. Cost of product expense increased $0.9 million primarily due to the increased cost of natural gas that we are contractually required to redeliver to shippers to compensate them on a thermally-equivalent basis for condensate retained by us and sold to third parties. Additionally, cost of product expense increased due to an increase in gas imbalances associated with MIGC.

General and Administrative, Depreciation and Other Expenses

General and administrative, depreciation and other expenses increased $1.1 million for the quarter ended March 31, 2008 primarily due to an increase in depreciation expense of $1.1 million resulting from $61.6 million of assets placed into service during 2007.

Income Tax Expense

For the quarter ended March 31, 2008, income tax expense increased 49.6% primarily due to an increase in income before income taxes. The variances from the 35% statutory rate for the quarters ended March 31, 2008 and March 31, 2007 are primarily attributable to state income taxes (net of federal income tax benefit).

LIQUIDITY AND CAPITAL RESOURCES

Our ability to finance operations and fund maintenance capital expenditures will largely depend on our ability to generate sufficient cash flow to cover these requirements. Our ability to generate cash flow is subject to a number of factors, some of which are beyond our control. Please read “Risk factors” in the Partnership’s Registration Statement on Form S-1, as amended, filed with the SEC on April 25, 2008.

Historically, our sources of liquidity included cash generated from operations and funding from Anadarko. We historically participated in Anadarko’s cash management program, whereby Anadarko, on a periodic basis, swept cash balances residing in our bank accounts. Thus, our historical combined financial statements reflect no cash balances. Unlike our transactions with third parties which ultimately settle in cash, our affiliate transactions are settled on a net basis through an adjustment to parent net equity. Subsequent to the Offering, we maintain our own bank accounts and sources of liquidity and will utilize Anadarko’s cash management system.

Subsequent to the Offering, we expect our sources of liquidity to include:

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$10 million of net offering proceeds retained for general partnership purposes;

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cash generated from operations;

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borrowings of up to $100 million under Anadarko’s credit facility;

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borrowings under our $30 million working capital facility with Anadarko;

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interest income from our $260.0 million note receivable from Anadarko;

•
issuances of additional partnership units; and

•
debt offerings.

We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements, long-term capital expenditure requirements, and the Partnership’s quarterly cash distributions to unitholders.

Working capital

Working capital, defined as the amount by which current assets exceed current liabilities, is an indication of our liquidity and potential need for short-term funding. Our working capital requirements are driven by changes in accounts receivable and accounts payable. These changes are primarily impacted by factors such as credit extended to, and the timing of collections from, our customers and our level of spending for maintenance and expansion activity. Historically, all affiliated transactions were not cash settled within our combined financial statements and did not require independent working capital borrowings. Prospectively, to the extent transactions with Anadarko and third parties require working capital, such amounts will be obtained by us through our working capital facility with Anadarko or other sources.

CONF CALL

Benjamin M. Fink - Chief Financial Officer of Western Gas Holdings LLC, Principal Accounting Officer of Western Gas Holdings LLC, Senior Vice President of Western Gas Holdings LLC and Treasurer of Western Gas Holdings LLC
Good morning, everyone. Thanks for joining us today to discuss Western Gas's Third Quarter 2013 Results. Please note that on this call, we will be referring to Western Gas Partners as WES and Western Gas Equity Partners as WGP.

Joining me on the call today are Don Sinclair, our President and CEO; Danny Rea, our COO; and other members of the management team, who'll be able to answer your questions later in the call.

This presentation contains estimates that are based on the best information available to us at this time, and we believe that these estimates are reasonable. However, a number of factors could cause actual results to differ materially from what we discuss. Please refer to our latest filings with the SEC for the risk factors associated with our business.

In addition, we'll be referencing certain non-GAAP measures on the call, so be sure to see the reconciliations in our earnings release. As a reminder, you can view and download all of these materials, including this call's presentation slides at www.westerngas.com.

With that, let me turn the call over to Don.

Donald R. Sinclair - Chief Executive Officer of Western Gas Holdings LLC, President of Western Gas Holdings LLC and Director of Western Gas Holdings LLC
Thanks, Ben. Good morning, everyone, and thank you for joining us today. Our third quarter operating results were very impressive. You'll recall that in early 2012, we began several substantial organic growth projects and we are now realizing the benefits of these significant investments.

Our strong performance enabled us to raise WES's third quarter distribution to $0.58 per unit, which is a 16% increase over last year and is WES's 18th consecutive quarterly increase. We also raised WGP's distribution to $0.21375 per unit, which is an 8% increase over the second quarter.

Also in the third quarter, we executed our first senior notes offering that carried investment-grade rating from all 3 major credit-rating agencies. These 5-year notes were very well received by the market as evidenced by the final coupons of 2.6%.

Yesterday we announced our third quarter results for 2013. We reported adjusted EBITDA of $125.2 million, distributable cash flow of $105.9 million, and a healthy Coverage ratio of 1.26x. We expect that coverage will be above 1.1x for the full-year, although it may fall below 1.1x in the fourth quarter as additional maintenance CapEx is spent.

Our third quarter's throughput numbers were driven by the ramp up of our Brasada facility, sequential growth in the DJ and Marcellus basins, and increased volumes at our Hilight and Chipeta plants. The Brasada facility was also a key driver of the increase in our gross margin per Mcf, which was $0.04 higher than what we reported in the second quarter.

With Brasada online and ramping up, our remaining major growth projects under construction are Lancaster Trains I and II. As we noted on our last conference call, the start up of the Lancaster I is contingent on Front Range pipeline being in service. Based on Front Range's updated completion schedule and construction delays suffered as a result of the flooding in Colorado, we now believe that Lancaster I will be operational in March 2014. Train II remains on schedule for first quarter 2015 start up.

As you read in yesterday's release, we have revised our full-year outlook for 2013. We believe adjusted EBITDA will be between $440 million and $450 million and our maintenance capital will be between 7% and 10% of adjusted EBITDA. Our total capital expenditure guidance of $670 million to $740 million is unchanged and does not include acquisitions or the equity investments in White Cliffs and Mont Belvieu fractionators. However, please note that the capital expenditure guidance we provide is on a cash basis. This means that the actual amount [ph] spent can be materially affected by the items over which we have no control, such as the timing of invoices.

In the future, we will provide CapEx guidance on an incurred basis, which will have less sensitivity to invoice timing issues.

We now believe WES and WGP will generate 2013 full-year distribution growth of 16% and 37%, respectively, which exceeds our initial guidance. While we cannot give formal guidance for 2014 until after our annual budgeting process has been completed, what we can say today is that we liked the organic growth we're seeing from our portfolio and we believe 2014 has the potential to be another outstanding year.

With that, operator, I'd like to open up the line for questions.

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