þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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(1)	Capacity excludes 170 MBbls/d of fractionation capacity.

(2)

Throughput includes 100% of Chipeta volumes, 50% of Newcastle volumes, 22% of Rendezvous volumes and 14.81% of Fort Union volumes. Throughput excludes 22 MBbls/d of average NGL pipeline volumes, 7 MBbls/d of average oil pipeline volumes representing our 10% share of average White Cliffs volumes, and 8 MBbls/d of average fractionated volumes representing our 25% share of average Mont Belvieu JV volumes. See Properties below for further descriptions of these systems.

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(1)

We acquired Anadarko’s 33.75% interest (non-operated) in the Liberty and Rome gas gathering systems, serving production from the Marcellus shale in north-central Pennsylvania. The interest acquired is referred to as the “Non-Operated Marcellus Interest.” In connection with the issuance of the common units, our general partner purchased 9,166 general partner units for consideration of $0.5 million in order to maintain its 2.0% general partner interest in us.

(2)	We acquired a 33.75% interest in each of the Larry’s Creek, Seely and Warrensville gas gathering systems, which are operated by Anadarko and serve production from the Marcellus shale in north-central Pennsylvania, from a third party. The interest acquired is referred to as the “Anadarko-Operated Marcellus Interest.”

(3)	We acquired a 25% interest in Enterprise EF78 LLC, an entity formed to design, construct, and own two fractionators located in Mont Belvieu, Texas, from a third party. The interest acquired is accounted for under the equity method of accounting.

(4)	We acquired Overland Trail Transmission, LLC (“OTTCO”), a Delaware limited liability company, from a third party. OTTCO owns and operates an intrastate pipeline that connects our Red Desert and Granger complexes in southwestern Wyoming.

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(1)	Includes the issuance of 915,000 common units pursuant to the full exercise of the underwriters’ over-allotment option granted in connection with the May 2013 equity offering.

(2)	Represents general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution to maintain its 2.0% general partner interest.

(3)

Excludes the issuance of 300,000 common units on January 3, 2014, pursuant to the partial exercise of the underwriters’ over-allotment option, and the corresponding issuance of 6,122 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. Total net proceeds for the partial exercise of the underwriters’ over-allotment option (including the general partner’s proportionate capital contribution) were $18.3 million.

•	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.

•	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.

•	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 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 all 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.

•	Affiliation with Anadarko. We believe Anadarko is motivated to promote and support the successful execution of our business plan and to use its 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 three-fourths 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, 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.

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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 all three of the major rating agencies and, as of December 31, 2013, we had no outstanding borrowings under our $800.0 million senior unsecured revolving credit facility (“RCF”), and we had $12.8 million in outstanding letters of credit issued under the RCF.

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Substantial presence in basins with strong producer economics. Our portfolio includes midstream assets located in major onshore producing basins in Wyoming, Colorado, Utah, Kansas, Oklahoma, Pennsylvania, and Texas. Our interests in the Anadarko-Operated and Non-Operated Marcellus gathering systems serve dry gas production from the Marcellus shale, which provides attractive producer returns due to the overall scale and quality of the underlying resource, as well as its access to premium markets in the northeast United States. In addition, our Wattenberg, Platte Valley, and Brasada assets serve production in liquids-rich growth areas where the hydrocarbon production contains not only natural gas, but also oil, condensate, and significant amounts of NGLs. NGL prices have historically been correlated to crude oil prices as opposed to natural gas prices. 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. See Properties below for further asset descriptions.

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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.

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Consistent track record of accretive acquisitions. Since our IPO in 2008, our management team has successfully executed eight related-party acquisitions and five third-party acquisitions, for an aggregate value of $2.9 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.

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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.

•	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.

•	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 process of applying various levels of higher pressure and lower temperature to separate a stream of NGLs into ethane, propane, normal butane, isobutane and natural gasoline for end-use sale.

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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.

•	Fee-based. Under fee-based arrangements, the service provider typically receives a fee for each unit of natural gas gathered, treated and/or processed at its facilities. As a result, the price per unit received by the service provider does not vary with commodity price changes, minimizing the service provider’s direct commodity price risk exposure.

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Percent-of-proceeds, percent-of-value or percent-of-liquids. Percent-of-proceeds, percent-of-value or percent-of-liquids arrangements may be used for gathering and processing services. Under these arrangements, the service provider typically remits to the producers either a percentage of the proceeds from the sale of residue and/or NGLs or a percentage of the actual residue and/or NGLs at the tailgate. These types of arrangements expose the processor to commodity price risk, as the revenues from the contracts directly correlate with the fluctuating price of natural gas and/or NGLs.

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Keep-whole. Keep-whole arrangements may be used for processing services. Under these arrangements, the service provider keeps 100% of the NGLs produced, and the processed natural gas, or value of the gas, is returned to the producer. Since some of the gas is used and removed during processing, the processor compensates the producer for the amount of gas used and removed in processing by supplying additional gas or by paying an agreed-upon value for the gas utilized. These arrangements have the highest commodity price exposure for the processor because the costs are dependent on the price of natural gas and the revenues are based on the price of NGLs.

•	Firm. Firm transportation service requires the reservation of pipeline capacity by a customer between certain receipt and delivery points. Firm customers generally pay a demand or capacity reservation fee based on the amount of capacity being reserved, regardless of whether the capacity is used, plus a usage fee based on the amount of natural gas transported.

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Interruptible. Interruptible transportation service is typically short-term in nature and is generally used by customers that either do not need firm service or have been unable to contract for firm service. These customers pay only for the volume of gas actually transported. The obligation to provide this service is limited to available capacity not otherwise used by firm customers, and, as such, customers receiving services under interruptible contracts are not assured capacity on the pipeline.

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•	Colorado Interstate Gas Company (“CIG”);

•	Kinder Morgan Interstate Gas Transportation Company; and

•	Wyoming Interstate Gas Company.

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•	CIG;

•	Tallgrass Interstate Gas Transmission, LLC; and

•	Wyoming Interstate Gas Company.

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•	CIG;

•	The Kern River and Mountain Gas Transportation, Inc. (“MGTI”) pipelines via a connect with Rendezvous Pipeline Company;

•	Northwest Pipeline Co. (“NWPL”);

•	OTTCO; and

•	QEP Resources (“QEP”).

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•	CIG;

•	Questar Pipeline Company; and

•	WIC.

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•	Anadarko’s Wattenberg processing plant;

•	our Fort Lupton processing plant; and

•	our Platte Valley processing plant.

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•	Atmos Texas pipeline;

•	Enbridge Pipelines (East Texas) LP pipeline;

•	Energy Transfer Fuels pipeline;

•	Enterprise Texas Pipeline, LP pipeline;

•	ETC Texas Pipeline, Ltd pipeline; and

•	Kinder Morgan Tejas pipeline.

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Lancaster plant in the DJ Basin: We are currently constructing a new cryogenic plant which will process production from the Niobrara and Codell formations in the Wattenberg field. The first train of the new plant has a capacity of 300 MMcf/d and is expected to begin service in the first quarter of 2014. Anadarko has agreed to a fee-based contract with a 10-year throughput guarantee of 270 MMcf/d, which will begin on the plant’s in-service date. A second train has been approved that will provide an additional 300 MMcf/d of capacity and is expected to be completed in the second quarter of 2015. Anadarko has agreed to a fee-based contract with a 10-year throughput guarantee of 200 MMcf/d, which will begin on the plant’s in-service date.

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•	rates, services, and terms and conditions of service;

•	types of services MIGC may offer to its customers;

•	certification and construction of new facilities;

•	acquisition, extension, disposition or abandonment of facilities;

•	maintenance of accounts and records;

•	internet posting requirements for available capacity, discounts and other matters;

•	pipeline segmentation to allow multiple simultaneous shipments under the same contract;

•	capacity release to create a secondary market for MIGC’s transportation services;

•	relationships between affiliated companies involved in certain aspects of the natural gas business;

•	initiation and discontinuation of services;

•	market manipulation in connection with interstate sales, purchases or transportation of natural gas and NGLs; and

•	participation by interstate pipelines in cash management arrangements.

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•	requiring the acquisition of various permits to conduct regulated activities;

•	requiring the installation of pollution-control equipment or otherwise restricting the way we can handle or dispose of our wastes;

•	limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;

•	requiring investigatory and remedial actions to mitigate or eliminate pollution conditions caused by our operations or attributable to former operations; and

•	imposing substantial liabilities for pollution resulting from our midstream activities.

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•	our ability to pay distributions to our unitholders;

•	our and Anadarko’s assumptions about the energy market;

•	future throughput, including Anadarko’s production, which is gathered or processed by or transported through our assets;

•	operating results;

•	competitive conditions;

•	technology;

•	availability of capital resources to fund acquisitions, capital expenditures and other contractual obligations, and our ability to access those resources from Anadarko or through the debt or equity capital markets;

•	supply of, demand for, and the price of, oil, natural gas, NGLs and related products or services;

•	weather;

•	inflation;

•	availability of goods and services;

•	general economic conditions, either internationally or domestically or in the jurisdictions in which we are doing business;

•	changes in regulations at the federal, state and local level or the inability to timely obtain or maintain permits that could affect our and our customers’ activities; environmental risks; regulations by FERC and liability under federal and state laws and regulations;

•	legislative or regulatory changes affecting our status as a partnership for federal income tax purposes;

•	changes in the financial or operational condition of Anadarko;

•	changes in Anadarko’s capital program, strategy or desired areas of focus;

•	our commitments to capital projects;

•	ability to use our RCF;

•	creditworthiness of Anadarko or our other counterparties, including financial institutions, operating partners and other parties;

•	our ability to repay debt;

•	our ability to mitigate commodity price risks inherent in our percent-of-proceeds and keep-whole contracts;

•	conflicts of interest among us, our general partner, WGP and its general partner, and affiliates, including Anadarko;

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•	our ability to maintain and/or obtain rights to operate our assets on land owned by third parties;

•	our ability to acquire assets on acceptable terms;

•	non-payment or non-performance of Anadarko or other significant customers, including under our gathering, processing and transportation agreements and our $260.0 million note receivable from Anadarko;

•	timing, amount and terms of future issuances of equity and debt securities; and

•	other factors discussed below and elsewhere in this Item 1A, under the caption Critical Accounting Policies and Estimates included under Item 7 of this Form 10-K, and in our other public filings and press releases.

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•	the volatility of natural gas and oil prices, which could have a negative effect on the value of Anadarko’s oil and natural gas properties, its drilling programs or its ability to finance its operations;

•	the availability of capital on an economic basis to fund Anadarko’s exploration and development activities;

•	a reduction in or reallocation of Anadarko’s capital budget, which could reduce the gathering, transportation and treating volumes available to us as a midstream operator, limit our midstream opportunities for organic growth or limit the inventory of midstream assets we may acquire from Anadarko;

•	Anadarko’s ability to replace reserves;

•	Anadarko’s operations in foreign countries, which are subject to political, economic and other uncertainties;

•	Anadarko’s drilling and operating risks, including potential environmental liabilities;

•	transportation capacity constraints and interruptions;

•	adverse effects of governmental and environmental regulation; and

•	adverse effects from current or future litigation, including 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).

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•	the prices of, level of production of, and demand for natural gas;

•	the volume of natural gas we gather, compress, process, treat and transport;

•	the volumes and prices of NGLs and condensate that we retain and sell;

•	demand charges and volumetric fees associated with our transportation services;

•	the level of competition from other midstream energy companies;

•	regulatory action affecting the supply of or demand for natural gas, the rates we can charge, how we contract for services, our existing contracts, our operating costs or our operating flexibility; and

•	prevailing economic conditions.

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•	the level of capital expenditures we make;

•	the level of our operating and maintenance and general and administrative costs;

•	our debt service requirements and other liabilities;

•	fluctuations in our working capital needs;

•	our ability to borrow funds and access capital markets;

•	our treatment as a flow-through entity for U.S. federal income tax purposes;

•	restrictions contained in debt agreements to which we are a party; and

•	the amount of cash reserves established by our general partner.

•	domestic and worldwide economic conditions;

•	weather conditions and seasonal trends;

•	the ability to develop recently discovered fields or deploy new technologies to existing fields;

•	the levels of domestic production and consumer demand, as affected by, among other things, concerns over inflation, geopolitical issues and the availability and cost of credit;

•	the availability of imported or a market for exported liquefied natural gas (“LNG”);

•	the availability of transportation systems with adequate capacity;

•	the volatility and uncertainty of regional pricing differentials such as in the Mid-Continent or Rocky Mountains;

•	the price and availability of alternative fuels;

•	the effect of energy conservation measures;

•	the nature and extent of governmental regulation and taxation; and

•	the anticipated future prices of natural gas, NGLs and other commodities.

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•	incur additional indebtedness or guarantee other indebtedness;

•	grant liens to secure obligations other than our obligations under the Notes or RCF or agree to restrictions on our ability to grant additional liens to secure our obligations under the Notes or RCF;

•	engage in transactions with affiliates;

•	make any material change to the nature of our business from the midstream energy business; or

•	enter into a merger, consolidate, liquidate, wind up or dissolve.

•	our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

•	our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flows required to make interest payments on our debt;

•	we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

•	our flexibility in responding to changing business and economic conditions may be limited.

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•	mistaken assumptions about volumes or the timing of those volumes, revenues or costs, including synergies;

•	an inability to successfully integrate the acquired assets or businesses;

•	the assumption of unknown liabilities;

•	limitations on rights to indemnity from the seller;

•	mistaken assumptions about the overall costs of equity or debt;

•	the diversion of management’s and employees’ attention from other business concerns;

•	unforeseen difficulties operating in new geographic areas; and

•	customer or key employee losses at the acquired businesses.

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•	rates, services and terms and conditions of service;

•	the certification and construction of new facilities;

•	the acquisition, extension, disposition or abandonment of facilities;

•	the maintenance of accounts and records;

•	relationships between affiliated companies involved in certain aspects of the natural gas business; and

•	market manipulation in connection with interstate sales, purchases or transportation of natural gas.

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•	perform ongoing assessments of pipeline integrity;

•	identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

•	improve data collection, integration and analysis;

•	repair and remediate the pipeline as necessary; and

•	implement preventive and mitigating actions.

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•	the federal Clean Air Act and analogous state laws that impose obligations related to emissions of air pollutants;

•	the federal Comprehensive Environmental Response, Compensation and Liability Act and analogous state laws that require and regulate the cleanup of hazardous substances that have been released at properties currently or previously owned or operated by us or at locations to which our wastes are or have been transported for disposal;

•	the federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws that regulate discharges from our facilities into state and federal waters, including wetlands;

•	the federal Resources Conservation and Recovery Act and analogous state laws that impose requirements for the storage, treatment and disposal of solid and hazardous waste from our facilities; and

•	the federal Toxic Substances Control Act and analogous state laws that impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities.

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•	damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism;

•	inadvertent damage from construction, farm and utility equipment;

•	leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities;

•	leaks of natural gas containing hazardous quantities of hydrogen sulfide from our Pinnacle gathering system or Bethel treating facility;

•	fires and explosions; and

•	other hazards that could also result in personal injury, loss of life, pollution, natural resource damages and/or suspension of operations.

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•	Neither our partnership agreement nor any other agreement requires Anadarko to pursue a business strategy that favors us.

•	Anadarko is not limited in its ability to compete with us and may offer business opportunities or sell midstream assets to parties other than us.

•	Our general partner is allowed to take into account the interests of parties other than us, such as Anadarko, in resolving conflicts of interest.

•	The officers of our general partner will also devote significant time to the business of Anadarko and will be compensated by Anadarko accordingly.

•	Our partnership agreement limits the liability of and reduces the default state law fiduciary duties owed by our general partner, and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under state law.

•	Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

•	Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.

•	Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner.

•	Our general partner determines which costs incurred by it are reimbursable by us.

•	Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make IDR payments.

•	Our partnership agreement permits us to classify up to $31.8 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions to our general partner in respect of the general partner interest or the IDRs.

•	Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.

•	Our general partner intends to limit its liability regarding our contractual and other obligations.

•	Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units.

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•	Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.

•	Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

•	Our general partner may elect to cause us to issue Class B units to it in connection with a resetting of the target distribution levels related to the IDRs without the approval of the special committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

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•	how to allocate corporate opportunities among us and its affiliates;

•	whether to exercise its limited call right;

•	how to exercise its voting rights with respect to the units it owns;

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•	whether to exercise its registration rights;

•	whether to elect to reset target distribution levels; and

•	whether to consent to any merger or consolidation of the Partnership or amendment to the partnership agreement.

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provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

•	provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith, meaning that it believed that the decision was in the best interest of the Partnership;

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provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

•	provides that our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is any of the following:

(a)	approved by the special committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;

(b)	approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;

(c)	on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

(d)	fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

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•	our existing unitholders’ proportionate ownership interest in us will decrease;

•	the amount of cash available for distribution on each unit may decrease;

•	the ratio of taxable income to distributions may increase;

•	the relative voting strength of each previously outstanding unit may be diminished; and

•	the market price of the common units may decline.

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•	we were conducting business in a state but had not complied with that particular state’s partnership statute; or

•	such unitholder’s right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

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•	changes in securities analysts’ recommendations regarding Anadarko or us and their estimates of Anadarko’s and our financial performance;

•	the public’s reaction to Anadarko’s or our press releases, announcements and filings with the SEC;

•	legislative or regulatory changes affecting our status as a partnership for federal income tax purposes;

•	fluctuations in broader securities market prices and volumes, particularly among securities of midstream companies and securities of publicly traded limited partnerships;

•	changes in market valuations of similar companies;

•	departures of key personnel;

•	commencement of or involvement in litigation;

•	variations in our quarterly results of operations or those of midstream companies;

•	variations in the amount of our quarterly cash distributions;

•	future issuances and sales of our common units; and

•	changes in general conditions in the U.S. economy, financial markets or the midstream industry.

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(1)

Income earned by the Partnership, a non-taxable entity for U.S. federal income tax purposes, on the date of and subsequent to our acquisition of the Partnership assets from Anadarko, except for the Chipeta assets, was subject only to Texas margin tax, while income earned prior to our acquisition of the Partnership assets, except for the Chipeta assets, was subject to federal and state income tax. Income attributable to Chipeta was subject to federal and state income tax prior to June 1, 2008, at which time substantially all of the Chipeta assets were contributed to a non-taxable entity for U.S. federal income tax purposes. See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

(2)

Adjusted EBITDA attributable to Western Gas Partners, LP (“Adjusted EBITDA”) and Distributable cash flow are not defined in the generally accepted accounting principles in the United States (“GAAP”). For descriptions and reconciliations of Adjusted EBITDA and Distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with GAAP, please see the caption How We Evaluate Our Operations under Item 7 of this Form 10-K.

(3)

Net income earned on and subsequent to the date of our acquisitions of the Partnership assets is allocated to the general partner and the limited partners, including any subordinated unitholders, in accordance with their respective ownership percentages, and when applicable, giving effect to incentive distributions allocable to the general partner. Prior to our acquisition of the Partnership assets, all income is attributed to Anadarko. All subordinated units were converted into common units on August 15, 2011, on a one-for-one basis. For purposes of calculating net income per common and subordinated unit, the conversion of the subordinated units is deemed to have occurred on July 1, 2011. See Note 4—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

(4)

Excludes average NGL pipeline volumes of 22 MBbls/d, 25 MBbls/d, 24 MBbls/d, 14 MBbls/d and 11 MBbls/d for the years ended December 31, 2013, 2012, 2011, 2010 and 2009, respectively. Includes 100% of Wattenberg system volumes for all periods presented, throughput beginning March 2013 attributable to the Anadarko-Operated Marcellus Interest, and throughput beginning September 2013 attributable to OTTCO.

(5)	Consists of 100% of Chipeta and Hilight system volumes, 100% of the Granger and Red Desert complex volumes, 50% of Newcastle volumes, and throughput beginning March 2011 attributable to the Platte Valley system.

(6)

Represents our 14.81% share of Fort Union and 22% share of Rendezvous gross volumes. Excludes 7 MBbls/d, 6 MBbls/d, 4 MBbls/d and 3 MBbls/d of average oil pipeline volumes for the years ended December 31, 2013, 2012, 2011 and 2010, respectively, representing our 10% share of average White Cliffs pipeline volumes (our 0.4% share of White Cliffs volumes for 2009 was not material) and excludes 8 MBbls/d of average fractionated volumes for the year ended December 31, 2013, representing our 25% share of average Mont Belvieu JV volumes.

(7)

Average for period. Calculated as gross margin (total revenues less cost of product) divided by total throughput (excluding throughput measured in barrels), including 100% of gross margin and volumes attributable to Chipeta, our 14.81% interest in income and volumes attributable to Fort Union and our 22% interest in income and volumes attributable to Rendezvous. Gross margin also includes 100% of gross margin attributable to our NGL pipelines, our 10% interest in income attributable to White Cliffs, and our 25% interest in income attributable to the Mont Belvieu JV.

(8)	Calculated as described in footnote seven above, except also excludes the noncontrolling interest owners’ proportionate share of revenues, cost of product and throughput.

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•	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 this 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.

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

•	Gross margin (total revenues less cost of product) attributable to Western Gas Partners, LP averaged $0.58 per Mcf for the year ended December 31, 2013, representing a 7% increase compared to the year ended December 31, 2012.

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•	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.

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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;

•	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.

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(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 this Form 10-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 this Form 10-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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(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 this Form 10-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 this Form 10-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 this Form 10-K.

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

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(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 this Form 10-K.

(2)

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 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.

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(1)

Excludes average NGL pipeline volumes of 22 MBbls/d, 25 MBbls/d and 24 MBbls/d for the years ended December 31, 2013, 2012 and 2011, respectively. Includes 100% of Wattenberg system volumes for all periods presented, throughput beginning March 2013 attributable to the Anadarko-Operated Marcellus Interest, and throughput beginning September 2013 attributable to the Overland Trail Transmission, LLC (“OTTCO”).

(2)	Consists of 100% of Chipeta, Hilight and Platte Valley system volumes, 100% of the Granger and Red Desert complex volumes, and 50% of Newcastle volumes.

(3)

Represents our 14.81% share of Fort Union and 22% share of Rendezvous gross volumes. Excludes our 10% share of average White Cliffs pipeline volumes consisting of 7 MBbls/d, 6 MBbls/d and 4 MBbls/d for the years ended December 31, 2013, 2012 and 2011, respectively, and for the year ended December 31, 2013, excludes 8 MBbls/d of average fractionated volumes, representing our 25% share of average fractionated Mont Belvieu JV volumes.

(4)	Includes affiliate, third-party and equity-investment volumes (as equity-investment volumes are defined in the above footnote).

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•	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.

•

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.

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(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 this Form 10-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 this Form 10-K.

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(1)

Average for period. Calculated as gross margin (total revenues less cost of product) divided by total throughput (excluding throughput measured in barrels), including 100% of gross margin and volumes attributable to Chipeta, our 14.81% interest in income and volumes attributable to Fort Union and our 22% interest in income and volumes attributable to Rendezvous. Gross margin also includes 100% of gross margin attributable to our NGL pipelines, our 10% interest in income attributable to White Cliffs, and our 25% interest in income attributable to the Mont Belvieu JV.

(2)	Calculated as described in footnote one above, except also excludes the noncontrolling interest owners’ proportionate share of revenues, cost of product and throughput.

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

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•

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.

(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.

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•	$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;

•	$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; and

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

•	$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; and

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

•	$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; and

•	$3.8 million for equipment purchases from Anadarko.

•	$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.

•	$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.

•	$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.

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(1)

Cost of product includes product purchases from Anadarko (as defined in Note 1) of $129.0 million, $145.3 million and $83.7 million for the years ended December 31, 2013, 2012 and 2011, respectively. Operation and maintenance includes charges from Anadarko of $56.4 million, $51.2 million and $51.3 million for the years ended December 31, 2013, 2012 and 2011, respectively. General and administrative includes charges from Anadarko of $23.4 million, $92.8 million and $33.3 million for the years ended December 31, 2013, 2012 and 2011, respectively. See Note 5.

(2)	Includes affiliate (as defined in Note 1) interest expense of zero, $2.8 million and $4.9 million for the years ended December 31, 2013, 2012 and 2011, respectively. See Note 10.

(3)	Represents net income earned on and subsequent to the date of the acquisition of the Partnership assets (as defined in Note 1). See Note 4.

(4)	All subordinated units were converted to common units on a one-for-one basis on August 15, 2011. See Note 4.

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(1)	Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $47.9 million and $19.1 million as of December 31, 2013 and 2012, respectively.

(2)	Other current assets includes natural gas imbalance receivables from affiliates of $0.1 million and $0.4 million as of December 31, 2013 and 2012, respectively.

(3)	Accounts and natural gas imbalance payables includes amounts payable to affiliates of $2.3 million and $2.5 million as of December 31, 2013 and 2012, respectively.

(4)	Accrued liabilities include amounts payable to affiliates of $0.1 million as of December 31, 2013 and 2012.

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(1)	All subordinated units were converted to common units on a one-for-one basis on August 15, 2011. See Note 4.

(2)	Associated with the Anadarko Incentive Plans for the years ended December 31, 2011 and 2013, associated with the Anadarko Incentive Plans and the Incentive Plan for the year ended December 31, 2012, as defined and described in Note 1 and Note 5.

(3)	See Note 2 for a description of the acquisition of Anadarko’s then-remaining 24% membership interest in Chipeta in August 2012. The $43.9 million decrease to partners’ capital resulting from the August 2012 Chipeta acquisition together with net income attributable to Western Gas Partners, LP totaled $90.5 million for the year ended December 31, 2012.

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(1)

The Partnership has a 14.81% interest in Fort Union, a joint venture which owns a gathering pipeline and treating facilities in the Powder River Basin. Anadarko is the construction manager and physical operator of the Fort Union facilities. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the owners’ firm gathering agreements, require 65% or unanimous approval of the owners.

(2)

The Partnership has a 10% interest in White Cliffs, a limited liability company which owns a crude oil pipeline that originates in Platteville, Colorado and terminates in Cushing, Oklahoma. The third-party majority owner is the manager of the White Cliffs operations. Certain business decisions, including, but not limited to, approval of annual budgets and decisions with respect to significant expenditures, contractual commitments, acquisitions, material financings, dispositions of assets or admitting new members, require more than 75% approval of the members.

(3)

The Partnership has a 22% interest in Rendezvous, a limited liability company that operates gas gathering facilities in Southwestern Wyoming. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the members’ gas servicing agreements, require unanimous approval of the members.

(4)

The Partnership has a 25% interest in the Mont Belvieu JV, an entity formed to design, construct, and own two fractionation trains located in Mont Belvieu, Texas. A third party is the operator of the Mont Belvieu JV fractionation trains. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require 50% or unanimous approval of the owners.

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(1)	The Partnership acquired (i) a natural gas gathering system and related compression and other ancillary equipment and (ii) cryogenic gas processing facilities from a third party. These assets are located in the Denver-Julesburg Basin. The acquisition is referred to as the “Platte Valley acquisition.”

(2)

The Bison gas treating facility acquired from Anadarko is located in the Powder River Basin in northeastern Wyoming and includes (i) three amine treating units, (ii) compressor units, and (iii) generators. These assets are referred to collectively as the “Bison assets.” The Bison assets are the only treating and delivery point into the third-party-owned Bison pipeline. The Bison assets were placed in service in June 2010.

(3)

The assets acquired from Anadarko consisted of (i) the Red Desert complex, which is located in the greater Green River Basin in southwestern Wyoming, and includes the Patrick Draw processing plant, the Red Desert processing plant, gathering lines, and related facilities, (ii) a 22% interest in Rendezvous, which owns a gathering system serving the Jonah and Pinedale Anticline fields in southwestern Wyoming, and (iii) certain additional midstream assets and equipment. These assets are collectively referred to as the “MGR assets” and the acquisition as the “MGR acquisition.”

(4)

The Partnership acquired Anadarko’s additional Chipeta interest (as described in Note 1). The Partnership received distributions related to the additional interest beginning July 1, 2012. This transaction brought the Partnership’s total membership interest in Chipeta to 75%. The remaining 25% membership interest in Chipeta held by a third-party member is reflected as noncontrolling interests in the consolidated financial statements for all periods presented.

(5)

The Partnership acquired Anadarko’s 33.75% interest (non-operated) in the Liberty and Rome gas gathering systems, serving production from the Marcellus shale in north-central Pennsylvania. The interest acquired is referred to as the “Non-Operated Marcellus Interest” and the acquisition as the “Non-Operated Marcellus Interest acquisition.” In connection with the issuance of the common units, the Partnership’s general partner purchased 9,166 general partner units for consideration of $0.5 million in order to maintain its 2.0% general partner interest in the Partnership.

(6)

The Partnership acquired a 33.75% interest in each of the Larry’s Creek, Seely and Warrensville gas gathering systems, which are operated by Anadarko and serve production from the Marcellus shale in north-central Pennsylvania, from a third party. The interest acquired is referred to as the “Anadarko-Operated Marcellus Interest” and the acquisition as the “Anadarko-Operated Marcellus Interest acquisition.” See Anadarko-Operated Marcellus Interest acquisition below for further information, including the final allocation of the purchase price.

(7)

The Partnership acquired a 25% interest in Enterprise EF78 LLC, an entity formed to design, construct, and own two fractionation trains located in Mont Belvieu, Texas, from a third party. The interest acquired is accounted for under the equity method of accounting and is referred to as the “Mont Belvieu JV” and the acquisition as the “Mont Belvieu JV acquisition.” See Mont Belvieu JV acquisition below for further information.

(8)	The Partnership acquired Overland Trail Transmission, LLC (“OTTCO”), a Delaware limited liability company, from a third party. OTTCO owns and operates an intrastate pipeline that connects the Partnership’s Red Desert and Granger complexes in southwestern Wyoming.

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(1)	On January 20, 2014, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.60 per unit, or $92.6 million in aggregate, including incentive distributions. The cash distribution is payable on February 12, 2014, to unitholders of record at the close of business on January 31, 2014.

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(1)	Includes the issuance of 302,813 common units, 750,000 common units and 915,000 common units pursuant to the full exercise of the underwriters’ over-allotment option granted in connection with the March 2011, September 2011 and May 2013 equity offerings, respectively.

(2)	Represents general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution to maintain its 2.0% general partner interest.

(3)

Excludes the issuance of 300,000 common units on January 3, 2014, pursuant to the partial exercise of the underwriters’ over-allotment option, and the corresponding issuance of 6,122 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. Total net proceeds for the partial exercise of the underwriters’ over-allotment option (including the general partner’s proportionate capital contribution) were $18.3 million.

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(1)	Reported in affiliate natural gas, NGLs and condensate sales in the consolidated statements of income in the period in which the related sale is recorded.

(2)	Reported in cost of product in the consolidated statements of income in the period in which the related purchase is recorded.

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(1)	Represents amounts recognized under gathering, treating or processing agreements, and purchase and sale agreements.

(2)	Represents expenses incurred on and subsequent to the date of the acquisition of the Partnership assets, as well as expenses incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets by the Partnership.

(3)

Represents general and administrative expense incurred on and subsequent to the date of the Partnership’s acquisition of the Partnership assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of the Partnership assets by the Partnership. These amounts include equity-based compensation expense allocated to the Partnership by Anadarko (see The Incentive Plan and WGP LTIP and Anadarko Incentive Plans within this Note 5).

(4)

Represents interest income recognized on the note receivable from Anadarko. For the year ended December 31, 2011, this line item also includes interest income, net 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 aforementioned assets prior to their acquisition were entirely settled through an adjustment to net investment by Anadarko.

(5)

For the year ended December 31, 2012, includes interest expense recognized on the note payable to Anadarko (see Note 10) and interest imputed on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada facility and Lancaster plant. The Partnership repaid the note payable to Anadarko in June 2012, and repaid the reimbursement payable to Anadarko related to the construction of the Brasada facility and Lancaster plant in the fourth quarter of 2012.

(6)	Represents distributions paid under the partnership agreement.

(7)	As described in Note 2, the Partnership acquired the additional Chipeta interest on August 1, 2012, and accounted for the acquisition on a prospective basis. As such, contributions from noncontrolling interest owners and distributions to noncontrolling interest owners subsequent to the acquisition date no longer reflect contributions from or distributions to Anadarko.

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(1)	Fair value is measured using Level 2 inputs.

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(1)

For the years ended December 31, 2013 and 2012, includes $1.0 million and $1.1 million, respectively, of amortization of (i) the original issue discount for the June 2012 offering of the 2022 Notes, partially offset by the original issue premium for the October 2012 offering of the 2022 Notes, (ii) original issue discount for the 2021 Notes and (iii) underwriters’ fees. In addition, for the year ended December 31, 2013, includes the amortization of the original issue discount and underwriters’ fees for the 2018 Notes of $0.2 million. For the year ended December 31, 2011, includes $0.5 million of amortization of the original issue discount and underwriters’ fees for the 2021 Notes.

(2)	In June 2012, the note payable to Anadarko was repaid in full. See Note payable to Anadarko within this Note 10.

(3)	Imputed interest expense on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada facility and Lancaster plant. In the fourth quarter of 2012, the Partnership repaid the reimbursement payable to Anadarko associated with the construction of the Brasada facility and Lancaster plant.

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(1)	Represents net income earned on and subsequent to the acquisition of the Partnership assets (as defined in Note 1—Summary of Significant Accounting Policies).

(2)	During the fourth quarter of 2012, the Partnership was allocated $54.9 million of general and administrative expenses from Anadarko associated with the Incentive Plan (as defined and described in Note 1—Summary of Significant Accounting Policies and Note 5—Transactions with Affiliates).

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•	base salary;

•	annual cash incentives;

•	equity-based compensation, which includes equity-based compensation under Anadarko’s 2012 Omnibus Incentive Compensation Plan (the “Omnibus Plan”) and the WGP LTIP; and

•	Anadarko’s other benefits, including welfare and retirement benefits, severance benefits and change of control benefits, plus other benefits on the same basis as other eligible Anadarko employees.

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•	retirement benefits to match competitive practices in Anadarko’s industry, including participation in Anadarko’s employee savings plan, savings restoration plan, retirement plan and retirement restoration plan;

•	severance benefits under the Anadarko Officer Severance Plan;

•	certain change of control benefits under key employee change of control contracts;

•	director and officer indemnification agreements;

•	a limited number of perquisites, including financial counseling, tax preparation and estate planning, an executive physical program, management life insurance, and personal excess liability insurance; and

•	benefits, including medical, dental, vision, flexible spending accounts, paid time off, life insurance and disability coverage, which are also provided to all other eligible U.S.-based Anadarko employees.

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(1)	The amounts in this column reflect the base salary compensation allocated to us by Anadarko for the fiscal years ended December 31, 2013, 2012 and 2011.

(2)

The amounts in this column reflect the expected allocation to us of the grant date fair value, computed in accordance with FASB ASC Topic 718 (without respect to the risk of forfeitures), for non-option stock awards granted pursuant to the WES LTIP, the WGP LTIP and the 2008 and 2012 Anadarko Omnibus Incentive Compensation Plans. For awards of phantom units granted under the WES LTIP and WGP LTIP, the grant date value is determined by multiplying the number of phantom units awarded by the per-unit closing price of the underlying common units on the date of grant. For a discussion of valuation assumptions for the awards under the 2008 and 2012 Anadarko Omnibus Incentive Compensation Plans, see Note 15—Share-Based Compensation in the Notes to Consolidated Financial Statements included 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). For information regarding the non-option stock awards granted to the named executives in 2013, please see the Grants of Plan-Based Awards Table.

(3)

The amounts in this column reflect the expected allocation to us of the grant date fair value, computed in accordance with FASB ASC Topic 718 (without respect to the risk of forfeitures), for option awards granted pursuant to the 2008 and 2012 Anadarko Omnibus Incentive Compensation Plans. See note (2) above for valuation assumptions. For information regarding the option awards granted to the named executives in 2013, please see the Grants of Plan-Based Awards Table.

(4)

The amounts in this column reflect the compensation under the Anadarko annual incentive program expected to be allocated to us for the fiscal years ended December 31, 2013, and allocated to us for the fiscal years ended December 31, 2012 and 2011. The 2013 amounts represent payments which were earned in 2013 and are expected to be paid in early 2014, the 2012 amounts represent payments which were earned in 2012 and paid in early 2013 and the 2011 amounts represent the payments which were earned in 2011 and paid in early 2012. For an explanation of the 2013 annual incentive plan awards, please read Compensation Discussion and Analysis – Analysis of 2013 Compensation Actions – Performance-Based Annual Cash Incentives (Bonuses).

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(5)	The amounts in this column reflect the compensation expenses related to Anadarko’s retirement and savings plans that were allocated to us for the fiscal years ended December 31, 2013, 2012 and 2011. The 2013 allocated expenses are detailed in the table below:

(6)	Mr. Rea retired from Anadarko and his position as Senior Vice President and Chief Operating Officer of our general partner on December 31, 2013. As a result of his retirement prior to annual incentive program payments, he did not receive a 2013 annual incentive plan award.

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(1)

Reflects the estimated 2013 cash payouts allocable to us under Anadarko’s annual incentive plan. If threshold levels of performance are not met, then the payout can be zero. The maximum value reflects the maximum amount allocable to us consistent with the methodologies set forth in the services and secondment agreement. The expense expected to be allocated to us for the actual bonus payouts under the annual incentive program for 2013 is reflected in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table. For additional discussion of Anadarko’s annual incentive plan please read Compensation Discussion and Analysis — Analysis of 2013 Compensation Actions — Performance-Based Annual Cash Incentives (Bonuses) contained within Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed no later than April 3, 2014.

(2)

Reflects the estimated future payout allocable to us under Anadarko’s performance units awarded in 2013. Under the performance unit program, participants may earn from 0% to 200% of the targeted award based on Anadarko’s relative total shareholder return performance over a specified performance period. Fifty percent of this award is tied to a two-year performance period and the remaining fifty percent is tied to a three-year performance period. If earned, the awards are to be paid in cash rather than equity. The threshold value represents the minimum payment (other than zero) that may be earned. For additional discussion of Anadarko’s performance unit awards please read Compensation Discussion and Analysis — Analysis of 2013 Compensation Actions — Equity Compensation contained within Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed no later than April 3, 2014.

(3)

Reflects the allocable number of phantom units under the WGP LTIP and restricted stock shares and restricted stock units awarded in 2013 under the Omnibus Plan. These awards vest equally over three years, beginning with the first anniversary of the grant date. Executive officers receive distribution equivalent rights on the phantom units and dividends on the restricted stock shares. For restricted stock units, dividend equivalents are reinvested in shares of Anadarko common stock and paid upon the applicable vesting of the underlying award.

(4)	Reflects the allocable number of Anadarko stock options each named executive officer was awarded in 2013. These awards vest equally over three years, beginning with the first anniversary of the date of grant and have a term of seven years.

(5)

The amounts included in the Grant Date Fair Value of Stock and Option Awards column represent the expected allocation to us of the grant date fair value of the awards made to named executives in 2013 computed in accordance with FASB ASC Topic 718. The value ultimately realized by the executive upon the actual vesting of the award(s) or the exercise of the stock option(s) may or may not be equal to the determined value. For awards of phantom units granted under the WGP LTIP, the grant date value is determined by multiplying the number of phantom units awarded by the per-unit closing price of the underlying common units on the date of grant. For a discussion of valuation assumptions for the awards under the Omnibus Plan, see Note 15—Share-Based Compensation in the Notes to 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).

(6)	Reflects an award of phantom units granted under the WGP LTIP.

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(1)	The table below shows the vesting dates for the respective unexercisable stock options listed in the above Outstanding Equity Awards Table:

(2)	The table below shows the vesting dates for the respective phantom units, restricted stock shares and restricted stock units listed in the above Outstanding Equity Awards Table:

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(3)

The table below shows the performance periods for the respective performance units listed in the above Outstanding Equity Awards Table. As a result of Mr. Rea’s retirement, his outstanding performance units were pro-rated based on the number of months he worked during the applicable performance periods. Except for the awards with performance periods beginning January 1, 2013, the number of outstanding units disclosed is calculated based on Anadarko’s performance to date for each award. As of December 31, 2013, the performance to date calculation for the awards with performance periods beginning January 1, 2013 was 0%, however, in accordance with the rules, we have disclosed the threshold performance payout of 54%. The estimated payout percentages reflect our relative performance ranking as of December 31, 2013, and are not necessarily indicative of what the payout percentage earned will be at the end of the performance period.

(4)	These awards represent grants of phantom units under the WES LTIP. The market values for these awards are based on the closing common unit price for the Partnership on December 31, 2013, of $61.69.

(5)	These awards represent grants of phantom units under the WGP LTIP. The market values for these awards are based on the closing common unit price for WGP on December 31, 2013 of $39.51.

(1)	Shares acquired and values realized on exercise include options exercised in 2013. The actual value ultimately realized by the named executive officer may be more or less than the realized value calculated in the above table depending on the timing in which the named executive officer held or sold the stock associated with the exercise.

(2)

Shares acquired and values realized on vesting reflect the taxable value to the named executive officer as of the date of the vesting in 2013 of restricted stock shares or units, performance units, or phantom units. For restricted stock shares or units and phantom units, the actual value ultimately realized by the named executive officer may be more or less than the value realized calculated in the above table depending on the timing in which the named executive officer held or sold the stock associated with the exercise or vesting occurrence.

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(1)	WES LTIP phantom units are valued based on the closing WES common unit price of $61.69 on December 31, 2013; WGP LTIP phantom units are valued based on the closing WGP common unit price of $39.51 on December 31, 2013.

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(1)	Messrs. Sinclair’s and Fink’s values assume two times base salary plus one times target bonus multiplied by their allocation percentages in effect as of December 31, 2013. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.

(2)

Payment, if provided, will be paid at the end of the performance period based on actual performance. The values for Messrs. Sinclair and Fink reflect the allocated portion of their actual bonuses awarded under the AIP. For additional discussion of this program please see section Compensation Discussion and Analysis — Analysis of 2013 Compensation Actions — Performance-Based Annual Cash Incentives (Bonuses) of Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed no later than April 3, 2014. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.

(3)	Reflects the in-the-money value of unvested stock options and the value of unvested restricted stock shares and restricted stock units, under Anadarko equity plans, all as of December 31, 2013.

(4)	Messrs. Sinclair’s and Fink’s values represent 24 months of health and welfare benefit coverage. These amounts are present values determined in accordance with GAAP. These values reflect their allocation percentage in effect as of December 31, 2013. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.

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(1)

Messrs. Sinclair’s and Fink’s values assume 2.9 times and two times, respectively, the sum of base salary plus the highest bonus paid in the past three years and reflect their allocation percentages in effect as of December 31, 2013, per the terms of their key employee change of control agreements with Anadarko. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.

(2)	Messrs. Sinclair’s and Fink’s values assume the full-year equivalent of their highest annual bonus allocated to us over the past three years. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.

(3)	Reflects the in-the-money value of unvested stock options, the value of unvested restricted stock shares and restricted stock units granted under Anadarko equity plans, all as of December 31, 2013. All values reflect each named executive officer’s allocation percentage in effect as of December 31, 2013.

(4)	Reflects the value of unvested WES and WGP LTIP phantom units based on the applicable closing common unit price of $61.69 and $39.51, respectively, on December 31, 2013. All values reflect each named executive officer’s allocation percentage in effect as of December 31, 2013.

(5)

Under the terms of their change of control agreements, Messrs. Sinclair and Fink would receive a special retirement benefit enhancement that is equivalent to the additional supplemental pension benefits that would have accrued under Anadarko’s retirement plan assuming they were eligible for subsidized early retirement benefits and include additional special pension credits. The value of this benefit has not been included in this table as Anadarko does not allocate expense to the partnership for distribution of these benefits. If Anadarko were to allocate this expense to the Partnership, assuming their allocation percentages in effect as of December 31, 2013, the expense would be as follows: Mr. Sinclair—$139,739 and Mr. Fink—$69,627.

(6)

Messrs. Sinclair’s and Fink’s values reflect an additional three years and two years, respectively, of employer contributions into the savings restoration plan at their current contribution rate to the Plan and are based on their allocation percentages in effect as of December 31, 2013, per the terms of their key employee change of control agreements with Anadarko. No value has been disclosed for Mr. Peacock as he is not eligible for this additional benefit.

(7)	Messrs. Sinclair’s and Fink’s values represent 36 months and 24 months, respectively, of health and welfare benefit coverage. All amounts are present values determined in accordance with GAAP and reflect their allocation percentages in effect as of December 31, 2013. No value has been disclosed for the Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.

(1)	Reflects the in-the-money value of unvested stock options and the value of unvested restricted stock shares and restricted stock units granted under Anadarko equity plans, all as of December 31, 2013. All values reflect each named executive officer’s allocation percentage in effect as of December 31, 2013.

(2)	Values reflect the continuation of additional death benefit coverage provided to certain employees of Anadarko until age 65. All amounts are present values determined in accordance with GAAP and reflect each named executive officer’s allocation percentage in effect as of December 31, 2013.

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(1)	Reflects the in-the-money value of unvested stock options and the value of unvested restricted stock shares and restricted stock units granted under Anadarko equity plans, all as of December 31, 2013. All values reflect each named executive officer’s allocation percentage in effect as of December 31, 2013.

(2)

Values include amounts payable under additional death benefits provided to certain employees of Anadarko. These liabilities are not insured, but are self-funded by Anadarko. Proceeds are not exempt from federal taxes. Values shown include an additional tax gross-up amount to equate benefits with non-taxable life insurance proceeds. Values are based on each named executive officer’s allocation percentage in effect as of December 31, 2013, and exclude death benefit proceeds from programs available to all employees.

•	an annual retainer of $70,000 for each board member;

•	an annual retainer of $2,000 for each member of the audit committee, or $22,000 for the committee chair;

•	an annual retainer of $2,000 for each member of the special committee, or $22,000 for the committee chair;

•	a fee of $2,000 for each board meeting attended;

•	a fee of $2,000 for each committee meeting attended; and

•	annual grants of phantom units with a value of approximately $80,000 on the date of grant, all of which vest 100% on the first anniversary of the date of grant (with vesting to be accelerated upon a change of control of our general partner or Anadarko). The non-employee directors received such a grant of phantom units on May 9, 2013.

(1)

The amounts included in the Stock Awards column represent the grant date fair value of non-option awards made to directors in 2013, computed in accordance with FASB ASC Topic 718. For a discussion of valuation assumptions, see Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. As of December 31, 2013, each of the non-employee directors had 1,280 outstanding phantom units. Mr. Chase’s outstanding phantom unit grant was vested as of the date of his resignation from the board of directors on February 12, 2014.

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(1)	The amounts included in the Grant Date Fair Value of Stock and Option Awards column represent the grant date fair value of the awards made to non-employee directors in 2013 computed in accordance with FASB ASC Topic 718. The value ultimately realized by a director upon the actual vesting of the award(s) may or may not be equal to the determined value.

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•	each member of the board of directors of our general partner;

•	each named executive officer of our general partner;

•	all directors and officers of our general partner as a group; and

•	Anadarko and its affiliates.

*	Less than 1%

(1)	The address for all beneficial owners in this table is 1201 Lake Robbins Drive, The Woodlands, Texas 77380.

(2)	Anadarko Petroleum Corporation is the ultimate parent company of Western Gas Resources, Inc. and Anadarko Marcellus Midstream, L.L.C. and the general partner of WGP and may, therefore, be deemed to beneficially own the units held by Western Gas Resources, Inc., Anadarko Marcellus Midstream, L.L.C. and WGP.

(3)

Does not include (a) 1,280 phantom units that were granted to each of Messrs. Carroll, Crane and Tudor and 10,782 phantom units granted to Mr. Sinclair under the WES LTIP, and (b) an aggregate of 26,758 phantom units that were granted to Messrs. Sinclair and Fink under the WGP LTIP. WES phantom units granted to the independent directors of WES vest 100% on the first anniversary of the date of the grant, and Mr. Sinclair’s WES phantom unit awards vest pro-rata over three years. Each vested phantom unit entitles the holder to receive a common unit or, in the discretion of our general partner’s board of directors, cash equal to the fair market value of a common unit. Holders of phantom units are entitled to distribution equivalents on a current basis. Holders of phantom units have no voting rights until such time as the phantom units become vested and common units are issued to such holders.

(4)	Includes (a) 2,000 and 670,600 WES units held by Messrs. Carroll and Crane, respectively, and (b) 4,000 WGP units held by Mr. Carroll, in margin accounts.

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*	Less than 1%

(1)	The address for all beneficial owners in this table is 1201 Lake Robbins Drive, The Woodlands, Texas 77380.

(2)	As of January 31, 2014, there were 503.8 million shares of Anadarko Petroleum Corporation common stock issued and outstanding.

(3)

Does not include unvested restricted stock units of Anadarko Petroleum Corporation held by the following individuals in the amounts indicated: Robert G. Gwin—30,432; Donald R. Sinclair—7,226; Benjamin M. Fink—2,477; Charles A. Meloy—31,195; Robert K. Reeves—27,792; and a total of 99,122 unvested restricted stock units are held by the directors and executive officers as a group. Restricted stock units typically vest equally over three years beginning on the first anniversary of the date of grant, and upon vesting are payable in Anadarko common stock, subject to applicable tax withholding. Holders of restricted stock units receive dividend equivalents on the units, but do not have voting rights. Generally, a holder will forfeit any unvested restricted units if he or she terminates voluntarily or is terminated for cause prior to the vesting date. Holders of restricted stock units have the ability to defer such awards.

(4)

Includes unvested shares of restricted common stock of Anadarko Petroleum Corporation held by the following individuals in the amounts indicated: Benjamin M. Fink—6,336; Philip H. Peacock—3,137; and a total of 9,473 unvested shares of restricted common stock are held by the directors and executive officers as a group. Restricted stock awards typically vest equally over three years beginning on the first anniversary of the date of grant. Holders of restricted stock receive dividends on the shares and also have voting rights. Generally, a holder of restricted stock will forfeit any unvested restricted shares if he or she terminates voluntarily or is terminated for cause prior to the vesting date.

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(1)	Based upon its Schedule 13G filed February 11, 2014, with the SEC with respect to Partnership securities held as of December 31, 2013, Tortoise Capital Advisors, L.L.C. has shared voting power as to 6,657,722 common units and shared dispositive power as to 7,226,800 common units.

(2)	Based upon its Schedule 13G filed February 4, 2014, with the SEC with respect to Partnership securities held as of December 31, 2013, Kayne Anderson Capital Advisors, L.P. has shared voting and dispositive power as to 6,002,546 common units.

(1)	The board of directors of our general partner adopted the WES LTIP in connection with the initial public offering of our common units.

(2)	Phantom units constitute the only rights outstanding under the WES LTIP. Each phantom unit that may be settled in common units entitles the holder to receive, upon vesting, one common unit with respect to each phantom unit, without payment of any cash. Accordingly, there is no reportable weighted-average exercise price.

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•	Anadarko’s obligation to indemnify us for certain liabilities and our obligation to indemnify Anadarko for certain liabilities;

•

our obligation to reimburse Anadarko for expenses incurred or payments made on our behalf in conjunction with Anadarko’s provision of general and administrative services to us, including salary and benefits of Anadarko personnel, our public company expenses, general and administrative expenses and salaries and benefits of our executive management who are employees of Anadarko (see Administrative services and reimbursement below for details regarding certain agreements for amounts reimbursed in 2013); and

•	our obligation to reimburse Anadarko for all insurance coverage expenses it incurs or payments it makes with respect to our assets.

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•	Chipeta’s members will be required from time to time to make capital contributions to Chipeta to the extent approved by the members in connection with Chipeta’s annual budget;

•	Chipeta will distribute available cash, as defined in the Chipeta LLC agreement, if any, to its members quarterly in accordance with those members’ membership interests; and

•	Chipeta’s membership interests are subject to significant restrictions on transfer.

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(1)	Represents amounts recognized under gathering, treating or processing agreements, and purchase and sale agreements.

(2)	Represents expenses incurred on and subsequent to the date of the acquisition of our assets, as well as expenses incurred by Anadarko on a historical basis related to our assets prior to the acquisition of such assets by us.

(3)

Represents general and administrative expense incurred on and subsequent to the date of the acquisition of our assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of our assets by us. These amounts include equity-based compensation expense allocated to us by Anadarko. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

(4)

Represents interest income recognized on the note receivable from Anadarko. For the year ended December 31, 2011, this line item also includes interest income, net 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 our assets prior to acquisition were entirely settled through an adjustment to net investment by Anadarko. See Note 10—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

(5)

For the year ended December 31, 2012, includes interest expense recognized on the note payable to Anadarko and interest imputed on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada facility and Lancaster plant. We repaid the note payable to Anadarko in June 2012, and repaid the reimbursement payable to Anadarko related to the construction of the Brasada facility and Lancaster plant in the fourth quarter of 2012. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

(6)	Represents distributions paid under the partnership agreement.

(7)

As described in the caption Chipeta LLC Agreement within this Item 13, we acquired Anadarko’s then-remaining 24% membership interest in Chipeta on August 1, 2012, and accounted for the acquisition on a prospective basis. As such, contributions from noncontrolling interest owners and distributions to noncontrolling interest owners subsequent to the acquisition date no longer reflect contributions from or distributions to Anadarko.

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•	approved by the special committee of our general partner, although our general partner is not obligated to seek such approval;

•	approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

•	on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

•	fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

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