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

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

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(1)	All system metrics are presented on a gross basis.

(2)	Capacity excludes 170 MBbls/d of fractionation capacity attributable to the Mont Belvieu JV.

(3)	Includes 100% of Chipeta throughput, 50% of Newcastle throughput, 22% of Rendezvous throughput and 14.81% of Fort Union throughput.

(4)	Represents total throughput measured in barrels, consisting of throughput from our Chipeta NGL pipeline, our 10% share of average White Cliffs throughput, our 25% share of average Mont Belvieu JV throughput, our 20% share of average TEG and TEP throughput and our 33.33% share of average FRP throughput. See Properties below for further descriptions of these systems.

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(1)

We acquired a 20% interest in each of TEG and TEP and a 33.33% interest in FRP from Anadarko. These assets gather and transport NGLs primarily from the Anadarko and Denver-Julesburg (“DJ”) Basins. TEG consists of two NGL gathering systems that link natural gas processing plants to TEP. TEP is an NGL pipeline that originates in Skellytown, Texas and extends approximately 593 miles to Mont Belvieu, Texas. FRP is a 435-mile NGL pipeline that extends from Weld County, Colorado to Skellytown, Texas. The interests in these entities are accounted for under the equity method of accounting. In connection with the issuance of the common units, our general partner purchased 6,296 general partner units in exchange for the general partner’s proportionate capital contribution of $0.4 million.

(2)

We acquired Nuevo Midstream, LLC (“Nuevo”) from a third party. Following the acquisition, we changed the name of Nuevo to Delaware Basin Midstream, LLC (“DBM”). The assets acquired include cryogenic processing plants, a gas gathering system, and related facilities and equipment, which are collectively referred to as the “DBM complex” and serve production from Reeves, Loving and Culberson Counties, Texas and Eddy and Lea Counties, New Mexico.

(3)	See Note 4—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K for a discussion of the Class C units.

(1)	Represents general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution.

(2)

Represents common and general partner units issued during the year ended December 31, 2014, pursuant to our registration statement filed with the SEC in August 2012 authorizing the issuance of up to $125.0 million of common units (the “Continuous Offering Program”). Gross proceeds generated (including the general partner’s proportionate capital contributions) during the year ended December 31, 2014, were $85.0 million. The price per unit in the table above represents an average price for all issuances under the Continuous Offering Program during the year ended December 31, 2014. As of December 31, 2014, the Partnership had used all the capacity to issue common units under this registration statement.

(3)

Includes the issuance of 1,120,153 common units pursuant to the partial exercise of the underwriters’ over-allotment option. Net proceeds from this partial exercise were $77.0 million. Beginning with this partial exercise, our general partner elected not to make a corresponding capital contribution to maintain a 2.0% interest in us. See Note 4—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

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

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

•	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 a substantial majority of the 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 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 80% 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 a substantial majority of our percent-of-proceeds and keep-whole contracts. For the year ended December 31, 2014, 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. On December 31, 2014, our commodity price swap agreements for the Hilight and Newcastle systems and the Granger complex expired without renewal. On June 30, 2015, and September 30, 2015, our commodity price swap agreements for the DJ Basin complex and Hugoton system, respectively, will expire. See Risk Factors under Item 1A and Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

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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, 2014, we had $510.0 million of outstanding borrowings and $12.8 million in outstanding letters of credit issued under our $1.2 billion senior unsecured revolving credit facility (“RCF”).

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Substantial presence in basins with historically strong producer economics. Certain of our gathering and processing systems and facilities, such as the DBM complex, the DJ Basin complex and the Brasada complex 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. Production in liquids-rich areas offers our customers higher margins and superior economics compared to basins in which the gas is predominantly dry. In addition, our interests in the Anadarko-Operated and Non-Operated Marcellus gathering systems serve dry gas production from the Marcellus shale, which historically has provided 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. See Properties below for further asset descriptions.

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Well-positioned, well-maintained and efficient assets. We believe that our asset portfolio, which is located in 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 nine related-party acquisitions and six third-party acquisitions, with an aggregate value of $4.8 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.

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Stabilization. In connection with our gathering services, we sometimes retain, stabilize and sell drip condensate, which falls out of the natural gas stream during gathering. Stabilization is a process that separates the heavier hydrocarbons (which also serve as valuable commodities) found in natural gas, typically referred to as “liquids-rich” natural gas, from the lighter components by using a distillation process or by reducing the pressure and letting the more volatile components flash. We provide stabilization for condensate at many of our processing plants (such as the DJ Basin and Brasada complexes).

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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 water vapor or contaminants, such as carbon dioxide and hydrogen sulfide, it is dehydrated to remove the saturated water and treated to separate the carbon dioxide and hydrogen sulfide from the gas stream.

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•	Processing. Processing separates the heavier and more valuable hydrocarbon components, which are extracted as NGLs, from the remaining residue. The remaining residue is then designated for long-haul pipeline transportation or commercial use.

•	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 better accommodate seasonal demand and daily supply-demand shifts. We do not currently offer storage services.

•	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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(1)	We have a 14.81% interest in Fort Union and a 50% interest in Newcastle.

(2)	The Granger complex includes the “Granger straddle plant,” a refrigeration processing plant.

(3)	The Red Desert complex includes the Patrick Draw cryogenic processing plant and the Red Desert cryogenic processing plant.

(4)	We have a 22% interest in the Rendezvous gathering system, which is operated by a third party.

•	Customers. Anadarko provided 67% of the throughput at the Bison treating facility for the year ended December 31, 2014. The remaining throughput was from one third-party producer.

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Supply and delivery points. The Bison treating facility treats and compresses gas from coal-bed methane wells in the Powder River Basin of Wyoming. The Bison pipeline, operated by TransCanada Corporation, is connected directly to the facility, which is currently the only inlet into the pipeline. The Bison treating facility also has access to Fort Union’s pipeline and Meritage Midstream Services II, LLC’s Thunder Creek pipeline.

•	Customers. Anadarko and the other members of Fort Union (Copano Pipelines/Rocky Mountains, LLC, Crestone Powder River LLC, and Bargath, LLC) are the only firm shippers on the Fort Union system. To the extent capacity on the system is not used by the members, it is available to third parties under interruptible agreements.

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Supply. Substantially all of Fort Union’s gas supply is comprised of coal-bed methane volumes that are either produced or gathered by the customers noted above throughout the Powder River Basin. As of December 31, 2014, the Fort Union system gathered gas from 1,900 Anadarko-operated coal-bed methane wells producing in the Big George coal play and a nearby multi-seam coal fairway. Anadarko had a working interest in over 1.1 million gross acres within the Powder River Basin as of December 31, 2014. Another of the Fort Union owners has a comparable working interest in a large majority of Anadarko’s producing coal-bed methane wells. The two remaining Fort Union owners gather gas for delivery to Fort Union under contracts with acreage dedications from multiple producers in the heart of the basin and from the coal-bed methane producing area near Sheridan, Wyoming.

•	Delivery points. The Fort Union system delivers coal-bed methane gas to the hub in Glenrock, Wyoming, which has access to the following interstate pipelines:

◦	Colorado Interstate Gas Company LLC’s pipeline (“CIG”);

◦	Tallgrass Interstate Gas Transmission system’s pipeline (“TIGT”); and

◦	Wyoming Interstate Company’s pipeline (“WIC”).

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•	Customers. Gas gathered and processed through the Hilight system is primarily from numerous third-party customers, with the six largest producers providing 71% of the system throughput during the year ended December 31, 2014.

•	Supply. The Hilight gathering system serves the gas gathering needs of several conventional producing fields in Johnson, Campbell, Natrona and Converse Counties. Our customers, including Anadarko, have historically maintained and more recently increased throughput by developing new prospects and performing workovers.

•	Delivery points. The Hilight plant delivers residue into our MIGC transmission line (see Transportation within these Items 1 and 2). Hilight is not connected to an active NGL pipeline, resulting in all fractionated NGLs being sold locally through its truck and rail loading facilities.

•	Customers. Gas gathered and processed through the Newcastle system is from 11 third-party customers, with the largest three producers providing 80% of the system throughput during the year ended December 31, 2014. The largest producer provided 57% of the throughput during the year ended December 31, 2014.

•	Supply. The Newcastle gathering system and plant primarily service gas production from the Clareton and Finn-Shurley fields in Weston County, Wyoming. Due to infill drilling and enhanced production techniques, producers have continued to maintain production levels.

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Delivery points. Propane products from the Newcastle plant are typically sold locally by truck, and the butane/gasoline mix products are transported to the Hilight plant for further fractionation. Residue from the Newcastle system is delivered into Black Hills Corporation’s MGTC, Inc. (“MGTC”) intrastate pipeline, a Hinshaw pipeline that supplies local markets in Wyoming, for transport, distribution and sale.

•	Customers. For the year ended December 31, 2014, 7% of the Granger complex throughput was from Anadarko and the remaining throughput was from various third-party customers, with the five largest shippers providing 86% of the system throughput.

•	Supply. The Granger complex is supplied by the Moxa Arch and the Jonah and Pinedale anticline fields. The Granger gas gathering system had 667 active receipt points as of December 31, 2014.

•	Delivery points. The residue from the Granger complex can be delivered to the following major pipelines:

◦	CIG;

◦	Berkshire Hathaway Energy’s Kern River pipeline (“Kern River pipeline”) and our Mountain Gas Transportation, Inc.’s (“MGTI”) pipeline via a connect with Tesoro Logistics LP’s (“Tesoro”) Rendezvous pipeline (“Rendezvous pipeline”);

◦	The Williams Companies, Inc.’s Northwest pipeline (“NWPL”); and

◦	our Overland Trail Transmission, LLC’s pipeline (“OTTCO”).

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•	Customers. For the year ended December 31, 2014, 4% of the Red Desert complex throughput was from Anadarko and the remaining throughput was from various third-party customers, with the six largest producers providing 70% of the system throughput.

•	Supply. The Red Desert complex gathers, compresses, treats and processes natural gas and fractionates NGLs produced in the eastern portion of the Greater Green River Basin, providing service primarily to the Red Desert and Washakie Basins.

•	Delivery points. Residue from the Red Desert complex is delivered to CIG and WIC, while NGLs are delivered to MAPL, as well as to truck and rail loading facilities.

•	Customers. Tesoro and Anadarko are the only firm shippers on the Rendezvous gathering system. To the extent capacity on the system is not used by those shippers, it is available to third parties under interruptible agreements.

•	Supply and delivery points. The Rendezvous gathering system provides mainline gathering service for gas from the Jonah and Pinedale anticline fields and delivers to our Granger plant, as well as Tesoro’s Blacks Fork gas processing plant, which connects to Questar Pipeline Company’s pipeline (“Questar pipeline”), NWPL and the Kern River pipeline via the Rendezvous pipeline.

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(1)

The DJ Basin complex includes the Platte Valley cryogenic processing plant, the Wattenberg gathering system, the Fort Lupton processing plant, the Fort Lupton JT processing plant, the Hambert JT processing plant, the Platteville amine treating plant and the Lancaster plant. Train II of the Lancaster plant is currently under construction and is expected to be completed during the second quarter of 2015.

(2)	We are the managing member of and own a 75% interest in Chipeta. Chipeta owns the Chipeta processing complex and the Natural Buttes refrigeration plant.

•	Customers. For the year ended December 31, 2014, 68% of the DJ Basin complex throughput was from Anadarko and the remaining throughput was from various third-party customers, with the largest providing 21% of the throughput.

•	Supply and delivery points. There were 2,881 active receipt points connected to the DJ Basin complex as of December 31, 2014. The DJ Basin complex is primarily supplied by the Wattenberg field, in which Anadarko controls 840,000 gross acres and drilled 369 wells and completed 330 wells during the year ended December 31, 2014.

◦	Anadarko’s Wattenberg plant;

◦	DCP Midstream’s (“DCP”) Spindle, Mewbourn and Platteville plants; and

◦	AKA Energy Group, LLC’s Gilcrest plant.

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•	Customers. Anadarko is the largest customer on the Chipeta system with 82% of the system throughput for the year ended December 31, 2014. The balance of throughput on the system during the year ended December 31, 2014 was from nine third-party customers.

•	Supply. The Chipeta system is well positioned to access Anadarko and third-party production in the Uinta Basin where Anadarko controls 245,000 gross acres. Chipeta’s inlet is connected to Anadarko’s Natural Buttes gathering system, the Questar pipeline and the Three Rivers Gathering, LLC’s system, which is owned by Ute Energy and another third party.

•	Delivery points. The Chipeta plant delivers NGLs to MAPL, which provides transportation through Enterprise’s Seminole pipeline (“Seminole pipeline”) and TEP’s pipeline in West Texas and ultimately to the NGL fractionation and storage facilities in Mont Belvieu, Texas. The Chipeta plant has natural gas delivery points through the following pipelines:

◦	CIG;

◦	Questar pipeline; and

◦	WIC.

•	Customers. Anadarko is the largest shipper on the Clawson gathering system with 99% of the total throughput on the system during the year ended December 31, 2014. The remaining throughput on the system was from one third-party producer.

•	Supply. The Clawson Springs field covers 7,000 gross acres and produces primarily from the Ferron Coal play.

•	Delivery points. The Clawson gathering system delivers into the Questar pipeline. The Questar pipeline provides transportation to regional markets in Wyoming, Colorado and Utah and also delivers into the Kern River pipeline, which provides transportation to markets in the Western United States, primarily California.

•	Customers. Anadarko is the only shipper on the Helper gathering system.

•	Supply. The Helper and the Cardinal Draw fields are Anadarko-operated coal-bed methane developments on the southwestern edge of the Uinta Basin that produce from the Ferron Coal play. Anadarko owns 19,000 gross acres in each of the Helper and Cardinal Draw fields.

•	Delivery points. The Helper gathering system delivers into the Questar pipeline.

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(1)	We own a 33.75% interest (the “Non-Operated Marcellus Interest”) in the Liberty and Rome gas gathering systems (the “Non-Operated Marcellus Interest gathering systems”), with a third party as the operator.

(2)	We own a 33.75% interest (the “Anadarko-Operated Marcellus Interest”) in the Larry’s Creek, Seely and Warrensville gas gathering systems (the “Anadarko-Operated Marcellus Interest gathering systems”), with Anadarko as the operator.

•	Customers. Anadarko is the largest customer on the Hugoton gathering system with 86% of the system throughput during the year ended December 31, 2014. Two third-party shippers account for 8% of the system throughput, with the balance from various other third-party shippers.

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•	Supply. The Hugoton field continues to be a long-life, low-decline asset for Anadarko, which has an extensive acreage position in the field with 470,000 gross acres. The Hugoton system is well positioned to gather volumes that may be produced from successful new wells drilled by third-party producers.

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Delivery points. The Hugoton gathering system is connected to the Satanta plant, which is owned by Anadarko (49%) and a third party. The Satanta plant processes NGLs and helium, and delivers residue into the Kansas Gas Service’s pipeline and Southern Star Central Gas Pipeline, Inc.’s pipeline. The system is also connected to DCP’s National Helium Plant, which extracts NGLs and delivers residue into Energy Transfer Partners, LP’s (“ETP”) Panhandle Eastern Pipe Line.

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Customers. As of December 31, 2014, there were seven and five priority shippers on the Non-Operated Marcellus Interest gathering systems and the Anadarko-Operated Marcellus Interest gathering systems, respectively, including Anadarko. For the year ended December 31, 2014, Anadarko represented 21% and 36% of throughput on the Non-Operated Marcellus Interest gathering systems and the Anadarko-Operated Marcellus Interest gathering systems, respectively. Capacity not used by priority shippers is available to third parties.

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Supply and delivery points. As of December 31, 2014, Anadarko had a working interest in over 722,000 gross acres within the Marcellus shale. The Non-Operated Marcellus Interest gathering systems have access to Transcontinental Gas Pipeline Company, LLC’s pipeline (“TRANSCO”), Tennessee Gas Pipeline Company, LLC’s pipeline and Millennium Pipeline Company, LLC’s pipeline. The Anadarko-Operated Marcellus Interest gathering systems have access to TRANSCO.

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(1)	The Pinnacle system includes the Bethel treating facility.

(2)	We own a 25% interest in the Mont Belvieu JV, which owns two NGL fractionation trains. A third party serves as the operator.

(3)	The table above excludes 15MBbls/d of condensate stabilization capacity at the Brasada complex.

(4)	The table above excludes 1,800 gpm of amine treating capacity at the DBM complex.

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•	Customers. Anadarko is the largest shipper on the Dew gathering system with 99% of the total throughput on the system during the year ended December 31, 2014. The remaining throughput on the system was from two third-party producers.

•	Supply. As of December 31, 2014, Anadarko had 794 producing wells in the Bossier play and controlled 111,000 gross acres in the area.

•	Delivery points. The Dew gathering system has delivery points on Kinder Morgan, Inc.’s Tejas pipeline (“Tejas pipeline”) and with Pinnacle, which is the primary delivery point and is described in more detail below.

•	Customers. Anadarko is the largest shipper on the Pinnacle gathering system with 92% of system throughput for the year ended December 31, 2014. The remaining throughput on the system during that period was from five third-party shippers.

•	Supply. The Pinnacle gathering system is well positioned to provide sour gas gathering and treating services to the five-county area over which it extends, including the Cotton Valley Lime and Reef formations, which contain relatively high concentrations of hydrogen sulfide and carbon dioxide.

•	Delivery points. The Pinnacle gathering system is connected to the following pipelines:

◦	Atmos Energy’s Texas pipeline;

◦	Midcoast Energy Partners, LP’s East Texas system;

◦	Energy Transfer Fuels’ pipeline;

◦	Enterprise Texas Pipeline, LP’s pipeline;

◦	ETC Texas Pipeline, Ltd’s pipeline; and

◦	the Tejas pipeline.

•	Customers. The Mont Belvieu JV does not directly contract with customers, but rather is allocated volumes from Enterprise based on the available capacity of the other trains at Enterprise’s NGL fractionation complex in Mont Belvieu, Texas.

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Supply and delivery points. Enterprise receives volumes at its fractionation complex in Mont Belvieu, Texas via a large number of pipelines that terminate there, including the Seminole pipeline, Skelly-Belvieu Pipeline Company, LLC’s pipeline and TEP. Individual NGLs are delivered to end users either through customer-owned pipelines that are connected to nearby petrochemical plants or via export terminal.

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•	Customers. Anadarko provides 100% of the throughput to the Brasada complex. Anadarko delivers gas and condensate to the plant on behalf of itself and its upstream partners.

•	Supply. Supply of gas and NGLs for the facility comes from Anadarko’s production in the Eagleford shale, in which Anadarko controls 416,000 gross acres.

•	Delivery points. The facility delivers residue gas into the Eagle Ford Midstream system operated by NET Midstream, LLC. It delivers the NGLs into the South Texas NGL Pipeline System operated by Enterprise.

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•	Customers. Anadarko’s production represented 68% of the Haley gathering system’s throughput for the year ended December 31, 2014. The remaining throughput was attributable to one third-party producer.

•	Supply. As of December 31, 2014, Anadarko had access to 445,000 gross acres in the greater Delaware Basin, a portion of which is gathered by the Haley gathering system.

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Delivery points. The Haley gathering system has multiple delivery points. The primary delivery points are to Kinder Morgan, Inc.’s El Paso Natural Gas pipeline (“El Paso pipeline”) or Enterprise GC, LLC’s pipeline for ultimate delivery into ETP’s Oasis pipeline (“Oasis pipeline”). We also have the ability to deliver into Southern Union Energy Services’ pipeline for further delivery into the Oasis pipeline. The pipelines at these delivery points provide transportation to both the Waha and Houston Ship Channel markets.

•	Customers. Gas gathered and processed through the DBM complex is primarily from nine third party producers, with the three largest producers providing 77% of the system throughput for the year ended December 31, 2014.

•	Supply. Supply of gas and NGLs for the complex comes from production from the Delaware Sands, Avalon Shale, Bone Springs and Wolfcamp formations in the Delaware Basin portion of the Permian Basin. Anadarko currently holds 445,000 gross acres within the Delaware Basin.

•	Delivery points. Residue gas produced at the facility is delivered to an interconnect with the El Paso pipeline. NGL production is delivered to an interconnect with DCP’s Sand Hills pipeline. As of December 31, 2014, there was an additional NGL interconnect under construction at our DBM complex with an expected in-service date during the first quarter of 2015.

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(1)	MIGC, GNB NGL, White Cliffs, FRP and TEP are regulated by the Federal Energy Regulatory Commission (“FERC”).

(2)	We own a 10% interest in the White Cliffs pipeline, which is operated by a third party.

(3)	We own a 20% interest in TEG and TEP and a 33.33% interest in FRP. All three systems are operated by third parties.

•	Customers. Anadarko is the largest firm shipper on the MIGC system, with 87% of throughput for the year ended December 31, 2014. The remaining throughput on the MIGC system was from 17 third-party shippers. MIGC offers both forward-haul and backhaul transportation services and is certificated for 175 MMcf/d of firm transportation capacity.

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Supply. As of December 31, 2014, Anadarko had a working interest in over 1.1 million gross acres within the Powder River Basin. Anadarko’s gross acreage includes substantial undeveloped acreage positions in the Big George coal play and the multiple seam coal fairway to the north of the Big George coal play. MIGC receives gas from various coal-bed methane gathering systems throughout the Powder River Basin and the Hilight system, as well as from WBI Energy Transmission, Inc. on the north end of the transportation system.

•	Delivery points. MIGC volumes can be redelivered to the hub in Glenrock, Wyoming, which has access to the following interstate pipelines:

◦	CIG;

◦	TIGT; and

◦	WIC.

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Customers. For the year ended December 31, 2014, 12% of OTTCO’s throughput was from Anadarko. The remaining throughput on the OTTCO transportation system was from two third-party shippers. Revenues on the OTTCO transportation system are generated from contract demand charges and volumetric fees paid by shippers under firm and interruptible gas transportation agreements. Most of OTTCO’s gas transportation agreements are month-to-month with the remainder generally having terms of less than one year. OTTCO has one current third-party firm transportation agreement for 21 MMBtu/d, which extends through December 2021.

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Supply and delivery points. Supply points to the OTTCO transportation system include the Granger complex and ExxonMobil Corporation’s Shute Creek plant, which are supplied by the eastern portion of the Greater Green River Basin, the Moxa Arch and the Jonah and Pinedale anticline fields. Primary delivery points include the Red Desert complex, two third-party industrial facilities and an interconnection with Kern River pipeline.

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•	Customers. Anadarko was the only shipper on the GNB NGL pipeline for the year ended December 31, 2014.

•	Supply. The GNB NGL pipeline receives NGLs from Chipeta’s gas processing facility and Tesoro’s Stagecoach/Iron Horse gas processing complex.

•	Delivery points. The GNB NGL pipeline delivers NGLs to MAPL, which provides transportation through the Seminole pipeline and TEP in West Texas, and ultimately to NGL fractionation and storage facilities in Mont Belvieu, Texas.

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Customers. The White Cliffs pipeline had multiple committed shippers, including Anadarko, during the year ended December 31, 2014. In addition, other parties may ship on the White Cliffs pipeline at FERC-based rates. The White Cliffs dual pipeline system provides 150 MBbls/d of crude takeaway capacity from Platteville, Colorado to Cushing, Oklahoma. White Cliffs is currently undergoing an expansion project that will increase the pipeline’s capacity to over 200 MBbls/d. These expansion projects are scheduled to be completed in mid-to-late 2015.

•	Supply. The White Cliffs pipeline is supplied by production from the DJ Basin and offers the only direct route from the DJ Basin to Cushing, Oklahoma.

•	Delivery points. The White Cliffs pipeline delivery point is SemCrude’s storage facility in Cushing, Oklahoma, a major crude oil marketing center, which ultimately delivers to Gulf Coast and mid-continent refineries. At the point of origin, it has a 300,000-barrel storage facility adjacent to a truck-unloading facility.

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Front Range Pipeline. FRP provides takeaway capacity from the DJ Basin in Northeast Colorado. FRP has injection points from gas plants in Weld County, Colorado (including our Lancaster plant), which is part of the DJ Basin complex (see Rocky Mountains—Colorado and Utah within these Items 1 and 2). FRP connects to TEP near Skellytown, Texas. During the year ended December 31, 2014, FRP had two committed shippers, including Anadarko and provides capacity for other shippers at the posted FERC tariff rate.

•	Texas Express Gathering. TEG consists of two NGL gathering systems that provide plants in North Texas, the Texas panhandle and West Oklahoma with access to NGL takeaway capacity on TEP. TEG had one committed shipper during the year ended December 31, 2014.

•	Texas Express Pipeline. TEP delivers to NGL fractionation and storage facilities in Mont Belvieu, Texas. At Skellytown, Texas, TEP is supplied with NGLs from other pipelines including FRP and MAPL. TEP had multiple committed shippers, including Anadarko, during the year ended December 31, 2014 and provides capacity for other shippers at the posted FERC tariff rates.

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Lancaster Train II in the DJ Basin: We are currently constructing the second train of the Lancaster plant, which is part of the DJ Basin complex. The second train is designed to have a capacity of 300 MMcf/d and is expected to begin service during 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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DBM Trains IV and V in West Texas: We are currently preparing for the construction of an additional cryogenic unit at our DBM complex with 200 MMcf/d of designed processing capacity and an in-service date expected during the first quarter of 2016. We have also made progress payments towards the construction of another cryogenic unit at our DBM complex (Train V), with an expected in-service date of mid-2016.

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

•	types of services that may be offered to customers;

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•	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 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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•	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;

•	our operating results;

•	competitive conditions;

•	technology;

•	the 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;

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

•	weather and natural disasters;

•	inflation;

•	the availability of goods and services;

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

•	federal, state and local laws, including those that limit Anadarko and other producers’ hydraulic fracturing or other oil and natural gas operations;

•	environmental liabilities;

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

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•	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;

•	our ability to use our RCF;

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

•	our ability to repay debt;

•	our ability to mitigate a substantial majority of the 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;

•	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;

•	the 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.

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•	domestic and worldwide economic and geopolitical 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;

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

•	the forecasted supply and demand for, and prices of, natural gas, NGLs and other commodities.

•	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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•	our level of capital expenditures;

•	our level of 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.

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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.

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•	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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•	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.

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•	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.

•	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 investor or analyst estimates of Anadarko’s and our financial performance or our future distribution growth;

•	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)

Net income earned on and subsequent to the date of our acquisitions of Partnership assets is allocated to the general partner and the limited partners, including any subordinated and Class C unitholders, in accordance with their respective weighted-average 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.

(2)	Includes affiliate, third-party and equity investment throughput, excluding the noncontrolling interest owners’ proportionate share of throughput.

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

(4)	Calculated as total revenues for natural gas assets less cost of product for natural gas assets plus distributions from our equity investments in Fort Union and Rendezvous, which are measured in Mcf, and excluding the noncontrolling interest owners’ proportionate share of revenue and cost of product.

(5)	Calculated as total revenues for crude/NGL assets less cost of product for crude/NGL assets plus distributions from our equity investments in White Cliffs, the Mont Belvieu JV, and the TEFR Interests, which are measured in barrels.

(6)	Average for period. Calculated as Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets (as defined under the caption How We Evaluate Our Operations under Item 7 of this Form 10-K) divided by total throughput (MMcf/d) attributable to Western Gas Partners, LP for natural gas assets.

(7)	Average for period. Calculated as Adjusted gross margin for crude/NGL assets (as defined under the caption How We Evaluate Our Operations under Item 7 of this Form 10-K), divided by total throughput (MBbls/d) for crude/NGL assets.

(8)

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 definitions 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.

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•	We completed the acquisition of DBM from a third party. DBM’s assets serve production from Reeves, Loving and Culberson Counties, Texas and Eddy and Lea Counties, New Mexico. See Acquisitions under Items 1 and 2 of this Form 10-K for additional information.

•	We issued 10,913,853 Class C units to a subsidiary of Anadarko, at a price of $68.72 per unit, generating proceeds of $750.0 million, all of which was used to fund a portion of the acquisition of DBM.

•	We issued 8,620,153 common units to the public, generating net proceeds of $603.0 million, including the general partner’s proportionate capital contribution, part of which was used to fund a portion of the acquisition of DBM.

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We issued 1,133,384 common units to the public under our Continuous Offering Program (as defined and discussed in Registered Securities within this Item 7), generating net proceeds of $83.2 million, including the general partner’s proportionate capital contribution. Net proceeds were used for general partnership purposes, including funding capital expenditures. See Equity Offerings under Items 1 and 2 of this Form 10-K for additional information.

•	In April 2014, we completed construction and commenced operations of the 300 MMcf/d Train I at the Lancaster plant (located in the DJ Basin complex) in Northeast Colorado. We are currently constructing the 300 MMcf/d Train II at the same plant, with operations expected to commence in the second quarter of 2015.

•	We issued $400.0 million aggregate principal amount of 5.450% Senior Notes due 2044 and an additional $100.0 million aggregate principal amount of 2.600% Senior Notes due 2018. Net proceeds were used to repay amounts then outstanding under our RCF. See Liquidity and Capital Resources within this Item 7 for additional information.

•	We completed the acquisition of Anadarko’s 20% interests in TEG and TEP, and its 33.33% interest in FRP. See Acquisitions under Items 1 and 2 of this Form 10-K for additional information.

•	We entered into an amended and restated $1.2 billion (expandable to $1.5 billion) senior unsecured RCF replacing our $800.0 million credit facility. See Liquidity and Capital Resources within this Item 7 for additional information.

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•	We raised our distribution to $0.70 per unit for the fourth quarter of 2014, representing a 4% increase over the distribution for the third quarter of 2014 and a 17% increase over the distribution for the fourth quarter of 2013.

•	Throughput attributable to Western Gas Partners, LP for natural gas assets totaled 3,493 MMcf/d for the year ended December 31, 2014, representing a 9% increase compared to the year ended December 31, 2013.

•	Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets (as defined under the caption How We Evaluate Our Operations within this Item 7) averaged $0.65 per Mcf for the year ended December 31, 2014, representing a 16% increase compared to the year ended December 31, 2013.

•	Adjusted gross margin for crude/NGL assets (as defined under the caption How We Evaluate Our Operations within this Item 7) averaged $1.75 per Bbl for the year ended December 31, 2014, representing a 67% increase compared to the year ended December 31, 2013.

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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 Processing LLC (“Chipeta”). See Note 2—Acquisitions in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

(3)	Excludes income of $0.5 million for the year ended December 31, 2014, and $1.6 million for each of the years ended December 31, 2013 and 2012, 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)	For the year ended December 31, 2013, includes capitalized interest of $1.4 million for the construction of the Mont Belvieu JV fractionation trains, reflected as a component of the equity investment balance. For the year ended December 31, 2012, excludes $0.6 million of pre-acquisition capitalized interest attributable to the Non-Operated Marcellus Interest systems.

(5)	Excludes income of $0.5 million for the year ended December 31, 2014, and $1.6 million for each of the years ended December 31, 2013 and 2012, related to a component of a gas processing agreement accounted for as a capital lease.

(6)	Reflects cash distributions of $2.65 per unit declared for the year ended December 31, 2014. See Note 3—Partnership Distributions in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

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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)

Adjusted gross margin attributable to Western Gas Partners, LP, Adjusted EBITDA attributable to Western Gas Partners, LP and Distributable cash flow are defined under the caption How We Evaluate Our Operations—Non-GAAP financial measures within this Item 7. For reconciliations of Adjusted gross margin attributable to Western Gas Partners, LP, Adjusted EBITDA attributable to Western Gas Partners, LP 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)

The combination of our Wattenberg and Platte Valley systems in 2014 into the entity now referred to as the “DJ Basin complex” (which also includes the Lancaster plant) resulted in the following: (i) the Wattenberg system throughput previously reported as “Gathering, treating and transportation” is now reported as “Processing” for all periods presented, and (ii) beginning in 2014, throughput both gathered and processed by the two systems is no longer separately reported.

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

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

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

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•	a $36.6 million net increase in NGL purchases primarily at the DJ Basin complex, Hilight system, the DBM complex and Chipeta, partially offset by a decrease at the Red Desert complex;

•	a $23.1 million net increase in residue purchases, primarily driven by higher volumes at the Hilight system, the DJ Basin complex and Chipeta; and

•	a $13.9 million net increase in other items, primarily due to changes in imbalance positions at the DJ Basin complex.

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•	an $11.6 million net increase in residue purchases primarily at the DJ Basin and the Red Desert complexes, partially offset by decreases at the Granger complex;

•	a $10.7 million net increase in NGL purchases primarily at the Red Desert complex, the Hilight system and the DJ Basin complex, partially offset by decreases at Chipeta and the Granger complex; and

•	a $5.9 million net increase in other items, primarily due to gas compression expenses at the Granger complex and changes in imbalance positions primarily at the DJ Basin complex, and the Hilight and Hugoton systems.

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(1)	In June 2012, the note payable to Anadarko was repaid in full. See Note 12—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

(2)

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

Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets is calculated as total revenues for natural gas assets less cost of product for natural gas assets plus distributions from our equity investments in Fort Union and Rendezvous, and excluding the noncontrolling interest owners’ proportionate share of revenue and cost of product. See the reconciliation of Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets to its most comparable GAAP measure under How We Evaluate Our Operations—Reconciliation to GAAP measures within this Item 7.

(2)

Adjusted gross margin for crude/NGL assets is calculated as total revenues for crude/NGL assets less cost of product for crude/NGL assets plus distributions from our equity investments in White Cliffs, the Mont Belvieu JV, and the TEFR Interests. See the reconciliation of Adjusted gross margin for crude/NGL assets to its most comparable GAAP measure under How We Evaluate Our Operations—Reconciliation to GAAP measures within this Item 7.

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

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

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

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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 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)	Maintenance capital expenditures for the years ended December 31, 2014, 2013 and 2012, are presented net of $0.2 million, $0.6 million and zero, respectively, of contributions in aid of construction costs from affiliates.

(2)	Includes the noncontrolling interest owners’ share of Chipeta’s capital expenditures, funded by contributions from the noncontrolling interest owners for all periods presented. For the years ended December 31, 2014, 2013 and 2012, included $9.8 million, $10.6 million and $6.8 million, respectively, of capitalized interest.

(3)	Capital expenditures for the year ended December 31, 2012, included $178.8 million of pre-acquisition capital for the Non-Operated Marcellus Interest systems.

(4)	Capital incurred for the years ended December 31, 2013 and 2012, included $8.8 million and $160.9 million, respectively, of pre-acquisition capital incurred for the Non-Operated Marcellus Interest systems.

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•	$1.5 billion of cash paid for the acquisition of DBM, net of $30.6 million of cash acquired;

•	$672.8 million of capital expenditures, net of $0.2 million of contributions in aid of construction costs from affiliates, primarily related to projects at the DJ Basin complex, which include the continued construction of Train II at the Lancaster plant and compressor expansions;

•	$356.3 million of cash paid for the acquisition of the TEFR Interests;

•	$42.0 million of cash paid related to FRP construction, which was completed in March 2014;

•	$22.9 million of cash paid for equipment purchases from Anadarko;

•	$18.1 million of distributions from equity investments in excess of cumulative earnings;

•	$10.5 million of cash paid for a White Cliffs expansion project; and

•	$6.6 million of cash paid related to TEP construction, which was completed in November 2013.

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

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

•	$236.9 million of capital contributions to TEG, TEP and FRP for construction costs;

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

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

•	$38.7 million of capital contributions to the Mont Belvieu JV to fund our share of construction costs for the fractionation trains completed in the fourth quarter of 2013;

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

•	$19.1 million of cash paid for a White Cliffs expansion project;

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

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

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•	$638.1 million of capital expenditures;

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

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

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

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

•	$750.0 million of proceeds from the issuance of Class C units to a subsidiary of Anadarko, all of which was used to fund a portion of the acquisition of DBM;

•	$603.0 million of net proceeds from our November 2014 equity offering, including net proceeds from a capital contribution by our general partner, part of which was used to fund a portion of the acquisition of DBM;

•	$475.0 million of borrowings to fund a portion of the acquisition of DBM;

•	$389.5 million of net proceeds from the 2044 Notes offering in March 2014, 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;

•	$350.0 million of borrowings to fund the acquisition of the TEFR Interests;

•	$335.0 million of borrowings to fund capital expenditures and for general partnership purposes;

•	$100.0 million of net proceeds from the additional 2018 Notes offering in March 2014, after underwriting discounts, original issue premium and offering costs, part of which was used to repay a portion of our outstanding borrowings under our RCF;

•	$83.2 million of net proceeds from sales of common units under the Continuous Offering Program (as defined and discussed in Registered Securities within this Item 7), including net proceeds from capital contributions by our general partner;

•	$18.1 million of net proceeds related to the partial exercise of the underwriters’ over-allotment option granted in connection with our December 2013 equity offering; and

•	$0.4 million of net proceeds from a capital contribution by our general partner after common units were issued in conjunction with the acquisition of the TEFR Interests.

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•	$424.7 million of net proceeds from our May 2013 equity offering, including net proceeds from a capital contribution by our general partner, $245.0 million of which was used to repay a portion of our outstanding borrowings under our RCF;

•	$299.0 million of borrowings to fund capital expenditures;

•	$273.7 million of net proceeds from our December 2013 equity offering, including net proceeds from a capital contribution by our general partner, $215.0 million of which was used to repay a portion of our outstanding borrowings under our RCF;

•	$250.0 million of borrowings to fund the Non-Operated Marcellus Interest acquisition;

•	$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;

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

•	$41.8 million of net proceeds from sales of common units under the Continuous Offering Program (as defined and discussed in Registered Securities within this Item 7), including net proceeds from capital contributions by our general partner;

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

•	$0.5 million of net proceeds from a capital contribution by our general partner after common units were issued in conjunction with the Non-Operated Marcellus Interest acquisition.

•	$511.3 million and $156.4 million of net proceeds from our 2022 Notes offerings 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 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.

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(1)	Income earned from equity investments is classified as affiliate. See Note 1.

(2)

Cost of product includes product purchases from Anadarko (as defined in Note 1) of $114.0 million, $129.0 million and $145.3 million for the years ended December 31, 2014, 2013 and 2012, respectively. Operation and maintenance includes charges from Anadarko of $58.9 million, $56.4 million and $51.2 million for the years ended December 31, 2014, 2013 and 2012, respectively. General and administrative includes charges from Anadarko of $27.0 million, $23.4 million and $92.8 million for the years ended December 31, 2014, 2013 and 2012, respectively. See Note 5.

(3)	Includes affiliate (as defined in Note 1) interest expense of zero for each of the years ended December 31, 2014 and 2013, and $2.8 million for the year ended December 31, 2012. See Note 12.

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

(5)	See Note 4 for the calculation of net income per unit.

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(1)	Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $64.7 million and $47.9 million as of December 31, 2014 and 2013, respectively.

(2)	Other current assets includes natural gas imbalance receivables from affiliates of $0.2 million and $0.1 million as of December 31, 2014 and 2013, respectively.

(3)	Accounts and natural gas imbalance payables includes amounts payable to affiliates of $0.1 million and $2.3 million as of December 31, 2014 and 2013, respectively.

(4)	Accrued liabilities includes amounts payable to affiliates of zero and $0.1 million as of December 31, 2014 and 2013, respectively.

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(1)	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.

(2)	Associated with the Anadarko Incentive Plans for the years ended December 31, 2014, 2013 and 2012 and the Incentive Plan for the year ended December 31, 2012, as defined and described in Note 1 and Note 5.

(3)	Includes deferred taxes on capitalized interest of $0.3 million and $5.5 million associated with the acquisition of the TEFR Interests (as defined and described in Note 1) for the years ended December 31, 2014 and 2013, respectively.

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(1)	Income earned on, distributions from and contributions to equity investments are classified as affiliate. See Note 1.

(2)	For the year ended December 31, 2014, represents transfers of $4.6 million from other long-term assets, associated with the capital lease components of a processing agreement. See Note 7.

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(1)

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.”

(2)

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.

(3)

The Partnership acquired Anadarko’s 33.75% interest (non-operated) (the “Non-Operated Marcellus Interest”) in the Liberty and Rome gas gathering systems (the “Non-Operated Marcellus Interest systems”), serving production from the Marcellus shale in North-central Pennsylvania. 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.

(4)

The Partnership acquired a 33.75% interest (the “Anadarko-Operated Marcellus Interest”) in each of the Larry’s Creek, Seely and Warrensville gas gathering systems (the “Anadarko-Operated Marcellus Interest systems”), which are operated by Anadarko and serve production from the Marcellus shale in North-central Pennsylvania, from a third party. During the third quarter of 2013, the Partnership recorded a $1.1 million decrease in the assets acquired and liabilities assumed in the acquisition, representing the final purchase price allocation.

(5)	The Partnership acquired a 25% interest in the Mont Belvieu JV, 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.

(6)	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.

(7)

The Partnership acquired a 20% interest in each of TEG and TEP and a 33.33% interest in FRP from Anadarko. These assets gather and transport NGLs primarily from the Anadarko and Denver-Julesburg (“DJ”) Basins. The interests in these entities are accounted for under the equity method of accounting. In connection with the issuance of the common units, the Partnership’s general partner purchased 6,296 general partner units in exchange for the general partner’s proportionate capital contribution of $0.4 million.

(8)

The Partnership acquired Nuevo Midstream, LLC (“Nuevo”) from a third party. Following the acquisition, the Partnership changed the name of Nuevo to Delaware Basin Midstream, LLC (“DBM”). The assets acquired include cryogenic processing plants, a gas gathering system, and related facilities and equipment, which serve production from Reeves, Loving and Culberson Counties, Texas and Eddy and Lea Counties, New Mexico. These assets are referred to collectively as the “DBM complex.” See Note 4 for a discussion of the Class C units.

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(1)

On January 22, 2015, the Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.700 per unit, or $126.0 million in aggregate, including incentive distributions, but excluding distributions on Class C units (see Class C unit distributions below). The cash distribution was paid on February 12, 2015, to unitholders of record at the close of business on February 2, 2015.

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(1)	Represents general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution.

(2)	Includes the issuance of 915,000 common units pursuant to the full exercise of the underwriters’ over-allotment option.

(3)	Includes the issuance of 300,000 common units on January 3, 2014, pursuant to the partial exercise of the underwriters’ over-allotment option. Net proceeds from this partial exercise (including the general partner’s proportionate capital contribution) were $18.1 million.

(4)

Represents common and general partner units issued during the year ended December 31, 2013, pursuant to the Partnership’s registration statement filed with the U.S. Securities and Exchange Commission (“SEC”) in August 2012 authorizing the issuance of up to an aggregate of $125.0 million of common units (the “Continuous Offering Program”). Gross proceeds generated (including the general partner’s proportionate capital contributions) during the year ended December 31, 2013, were $42.6 million. The price per unit in the table above represents an average price for all issuances under the Continuous Offering Program during 2013.

(5)

Represents common and general partner units issued during the year ended December 31, 2014, under the Continuous Offering Program. Gross proceeds generated (including the general partner’s proportionate capital contributions) during the year ended December 31, 2014, were $85.0 million. The price per unit in the table above represents an average price for all issuances under the Continuous Offering Program during the year ended December 31, 2014. As of December 31, 2014, the Partnership had used all the capacity to issue common units under this registration statement.

(6)	Includes the issuance of 1,120,153 common units pursuant to the partial exercise of the underwriters’ over-allotment option. Net proceeds from this partial exercise were $77.0 million. Beginning with this partial exercise, the Partnership’s general partner elected not to make a corresponding capital contribution to maintain the general partner’s 2.0% interest in the Partnership. See Note 3.

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(1)	Reported in affiliate natural gas, natural gas liquids 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 earned or incurred on and subsequent to the date of acquisition of the Partnership assets, as well as amounts earned or incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets, 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.

(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 WES LTIP, WGP LTIP and Anadarko Incentive Plans, and The Incentive Plan within this Note 5).

(4)	Represents interest income recognized on the note receivable from Anadarko.

(5)

For the year ended December 31, 2012, includes interest expense recognized on the note payable to Anadarko (see Note 12) and interest imputed on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada complex and Lancaster plant. The Partnership repaid the note payable to Anadarko in June 2012, and repaid the reimbursement payable to Anadarko associated with the construction of the Brasada complex and Lancaster plant in the fourth quarter of 2012.

(6)	Represents distributions paid under the partnership agreement (see Note 3 and Note 4).

(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)

The Partnership has a 14.81% interest in Fort Union, a joint venture that 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 that 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.

(5)

The Partnership has a 20% interest in TEG, an entity that consists of two NGL gathering systems that link natural gas processing plants to TEP. Enbridge Midcoast Energy, LP (“Enbridge”) is the operator of the two gathering systems. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the delegation, creation, appointment, or removal of officer positions require more than 50% approval of the members.

(6)

The Partnership has a 20% interest in TEP, which consists of an NGL pipeline that originates in Skellytown, Texas and extends to Mont Belvieu, Texas. Enterprise Products Operating LLC (“Enterprise”) is the operator of TEP. 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 more than 50% approval of the members.

(7)

The Partnership has a 33.33% interest in the FRP, an NGL pipeline that extends from Weld County, Colorado to Skellytown, Texas. Enterprise is the operator of FRP. 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 more than 50% approval of the members.

(8)	Distributions in excess of cumulative earnings, classified as investing cash flows in the consolidated statements of cash flows, is calculated on an individual investment basis.

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

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(1)	In June 2012, the note payable to Anadarko was repaid in full. See Note payable to Anadarko within this Note 12.

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

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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

•	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, voluntary participation in the Deferred Compensation Plan, and personal excess liability insurance; and

•	benefits, including medical, dental, vision, flexible spending and health savings 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 years ended December 31, 2014, 2013 and 2012.

(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 and include unvested amounts. 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, 2014 (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 2014, 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 2014, 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 year ended December 31, 2014, and allocated to us for the years ended December 31, 2013 and 2012. The 2014 amounts represent payments which were earned in 2014 and are expected to be paid in early 2015, the 2013 amounts represent payments which were earned in 2013 and paid in early 2014 and the 2012 amounts represent the payments which were earned in 2012 and paid in early 2013. For an explanation of the 2014 annual incentive plan awards, please read Compensation Discussion and Analysis – Analysis of 2014 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 2, 2015.

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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 years ended December 31, 2014, 2013 and 2012. The 2014 allocated expenses are detailed in the table below:

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(1)

Reflects the estimated 2014 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 2014 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 2014 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 2, 2015.

(2)

Reflects the estimated future payout allocable to us under Anadarko’s performance units awarded in 2014. 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. With respect to the performance units granted to Ms. Dimpel on January 8, 2014, 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. The performance units granted to Messrs. Sinclair and Fink and Ms. Dimpel on November 6, 2014 are subject solely 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 2014 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 2, 2015.

(3)

Reflects the allocable number of restricted stock shares and restricted stock units awarded in 2014 under the Omnibus Plan. These awards vest equally over three years, beginning with the first anniversary of the grant date. Executive officers receive 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 2014. 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 2014 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 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, 2014 (which is not, and shall not be deemed to be, incorporated by reference herein).

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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. Generally, the number of outstanding units for each award is calculated based on Anadarko’s relative performance ranking as of December 31, 2014, and is not necessarily indicative of what the payout percent earned will be at the end of the performance period. As of December 31, 2014, the performance to date calculation for the awards with performance periods beginning January 1, 2014 was 146%. For awards with performance periods beginning January 1, 2015, target payout has been assumed.

(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, 2014, of $73.05.

(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, 2014 of $60.23.

(1)	Shares acquired and values realized on exercise include options exercised in 2014. 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 2014 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 $73.05 on December 31, 2014; WGP LTIP phantom units are valued based on the closing WGP common unit price of $60.23 on December 31, 2014.

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(1)	Messrs. Sinclair’s and Fink’s and Ms. Dimpel’s values assume two times base salary plus one times target bonus multiplied by their allocation percentages in effect as of December 31, 2014. 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 and Ms. Dimpel reflect the allocated portion of their actual bonuses awarded under the AIP. For additional discussion of this program please read Compensation Discussion and Analysis — Analysis of 2014 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 2, 2015. 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 estimated current value of unvested performance units (based on performance to date) and the value of unvested restricted stock shares and restricted stock units granted under Anadarko equity plans, all as of December 31, 2014. In the event of an involuntary termination, unvested performance units would be paid after the end of the applicable performance period, based on actual performance. All values reflect each named executive officer’s allocation percentage in effect as of December 31, 2014.

(4)

Messrs. Sinclair’s and Fink’s and Ms. Dimpel’s values represent 24 months of health and welfare benefit coverage. These amounts are present values determined in accordance with the generally accepted accounting principles in the United States (“GAAP”). These values reflect their allocation percentage in effect as of December 31, 2014. 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)

Mr. Sinclair’s values and Mr. Fink’s and Ms. Dimpel’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, 2014, 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 and Ms. Dimpel’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 and the estimated current value of unvested performance units (based on performance to date) granted under Anadarko equity plans, all as of December 31, 2014. Upon a Change of Control, the value of unvested performance units would be calculated based on Anadarko’s total shareholder return performance and stock price at the time of the Change of Control and converted into restricted stock units of the surviving company. In the event of an involuntary not for cause termination or voluntary for good reason termination within two years following a Change of Control, the units will generally be paid on the first business day that is at least six months and one day following the separation from service. In the event of an involuntary not for cause or voluntary for good reason termination that is more than two years following a Change of Control, the units will be paid at the end of the original performance period. All values reflect each named executive officer’s allocation percentage in effect as of December 31, 2014.

(4)	Reflects the value of unvested WES and WGP LTIP phantom units based on the applicable closing common unit price of $73.05 and $60.23, respectively, on December 31, 2014. All values reflect each named executive officer’s allocation percentage in effect as of December 31, 2014.

(5)

Under the terms of their change of control agreements, Messrs. Sinclair and Fink and Ms. Dimpel 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, 2014, the expense would be as follows: Mr. Sinclair—$185,512, Mr. Fink—$86,295 and Ms. Dimpel—$137,894.

(6)

Mr. Sinclair’s values and Mr. Fink’s and Ms. Dimpel’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, 2014, 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)

Mr. Sinclair’s values and Mr. Fink’s and Ms. Dimpel’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, 2014. No value has been disclosed for 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, the value of unvested restricted stock shares and restricted stock units and the estimated current value of unvested performance units (based on performance to date) granted under Anadarko equity plans, all as of December 31, 2014. In the event of a termination as a result of disability, performance units would be paid after the end of the applicable performance period, based on actual performance. All values reflect each named executive officer’s allocation percentage in effect as of December 31, 2014.

(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, 2014.

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(1)	Reflects the in-the-money value of unvested stock options, the target value of unvested performance units, and the value of unvested restricted stock shares and restricted stock units granted under Anadarko equity plans, all as of December 31, 2014. All values reflect each named executive officer’s allocation percentage in effect as of December 31, 2014.

(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, 2014, and exclude death benefit proceeds from programs available to all employees.

•	an annual retainer of $90,000 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 $90,000 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 22, 2014.

(1)

The amounts included in the Stock Awards column represent the grant date fair value of non-option awards made to directors in 2014, 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, 2014, each of the non-employee directors had 1,262 outstanding phantom units, except for Mr. Arnold who was granted 2,014 phantom units upon his appointment as director in February 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 2014 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)

WGP held 49,296,205 common units and other subsidiaries of Anadarko, Anadarko Marcellus Midstream, L.L.C. (“AMM”) and APC Midstream Holdings, LLC (“AMH”), collectively held 757,619 common units. Anadarko is the ultimate parent company of Western Gas Resources, Inc. (“WGRI”), AMM, AMH and WGP GP and may, therefore, be deemed to beneficially own the units held by such parties. Anadarko, through AMH, also held 10,959,564 Class C units of the Partnership.

(3)

Does not include (a) 1,262 unvested phantom units that were granted to each of Messrs. Carroll, Crane and Tudor, 2,014 unvested phantom units granted to Mr. Arnold and 3,192 unvested phantom units previously granted to Mr. Sinclair under the WES LTIP, and (b) an aggregate 17,838 unvested phantom units that were previously granted to Messrs. Sinclair and Fink under the WGP LTIP. 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 and Mr. Fink’s 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 495,601 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, 2015, there were 506.7 million shares of Anadarko common stock issued and outstanding.

(3)

Does not include unvested restricted stock units of Anadarko held by the following individuals in the amounts indicated: Robert G. Gwin—26,393; Donald R. Sinclair—8,232; Benjamin M. Fink—4,605; Jacqueline A. Dimpel—4,663; Charles A. Meloy—27,018; Robert K. Reeves—20,660; and a total of 91,571 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 held by the following individuals in the amounts indicated: Benjamin M. Fink—3,345; Jacqueline A. Dimpel—1,874; Philip H. Peacock—3,873; and a total of 9,092 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 12, 2015, with the SEC with respect to Partnership securities held as of December 31, 2014, Neuberger Berman Group LLC has shared voting power as to 6,437,942 common units and shared dispositive power as to 6,683,147 common units.

(2)	Based upon its Schedule 13G/A filed February 10, 2015, with the SEC with respect to Partnership securities held as of December 31, 2014, Tortoise Capital Advisors, L.L.C. has shared voting power as to 7,685,801 common units and shared dispositive power as to 8,257,574 common units.

(3)	Based upon its Schedule 13G/A filed January 14, 2015, with the SEC with respect to Partnership securities held as of December 31, 2014, Kayne Anderson Capital Advisors, L.P. has shared voting and dispositive power as to 8,019,103 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 2014); 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 earned or incurred on and subsequent to the date of acquisition of our assets, as well as amounts earned or incurred by Anadarko on a historical basis related to our assets prior to the acquisition of such assets, 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.

(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.

(5)

For the year ended December 31, 2012, includes interest expense recognized on the note payable to Anadarko (see Note 12—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K) and interest imputed on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada complex and Lancaster plant. We repaid the note payable to Anadarko in June 2012, and repaid the reimbursement payable to Anadarko associated with the construction of the Brasada complex and Lancaster plant in the fourth quarter of 2012.

(6)	Represents distributions paid under the partnership agreement. See Note 3—Partnership Distributions and Note 4—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

(7)

We acquired Anadarko’s then-remaining interest in Chipeta on August 1, 2012 (see Note 2—Acquisitions in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K), 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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