UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

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

For the fiscal year ended December 31, 2008

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

For the transition period from                 to                     

WESTERN GAS PARTNERS, LP

Delaware		26-1075808
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)
1201 Lake Robbins Drive The Woodlands, Texas (Address of principal executive offices)		77380 (Zip Code)

(832) 636-6000
(Registrant’s telephone number, including area code)

Title of Each Class		Name of Each Exchange on Which Registered
Common Units Representing Limited Partner Interests		New York Stock Exchange

     Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o      No þ

     Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o      No þ

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ      No o

     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o      No þ

     The aggregate market value of the Partnership’s common units representing limited partner interests held by non-affiliates of the registrant was approximately $350.7 million on June 30, 2008 based on the closing price as reported on the New York Stock Exchange.

     At February 27, 2009, there were 29,093,197 common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE
None

 

 

TABLE OF CONTENTS

DESCRIPTION

Item				Page
		PART I
1 and 2.		Business and Properties		3
1A.		Risk Factors		23
1B.		Unresolved Staff Comments		44
3.		Legal Proceedings		44
4.		Submission of Matters to a Vote by Securities Holders		44
		PART II
5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		45
6.		Selected Financial and Operating Data		47
7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations		51
7A.		Quantitative and Qualitative Disclosures About Market Risk		72
8.		Financial Statements and Supplementary Data		73
9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		73
9A(T).		Disclosure Controls and Procedures		73
9B		Other Information		73
		PART III
10.		Directors, Executive Officers and Corporate Governance		74
11.		Executive Compensation		78
12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		98
13.		Certain Relationships and Related Transactions, and Director Independence		100
14.		Principal Accountant Fees and Services		107
		PART IV
15.		Exhibits		107
		21.1      List of Subsidiaries of Western Gas Partners, LP
		23.1      Consent of KPMG LLP
		31.1      Certification of CEO pursuant to Rule 13a-14(a)
		31.2      Certification of CFO pursuant to Rule 13a-14(a)
		32.1      Certifications of CEO and CFO pursuant to rule 1350
EX-21.1
EX-23.1
EX-31.1
EX-31.2
EX-32.1

DEFINITIONS

As generally used within the energy industry and in this Annual Report on Form 10-K, the identified terms have the following meanings:

Backhaul: Pipeline transportation service in which the nominated gas flow from delivery point to receipt point is in the opposite direction as the pipeline’s physical gas flow.

Barrel or Bbl: 42 U.S. gallons measured at 60 degrees Fahrenheit.

Bcf/d: One billion cubic feet per day.

Btu: British Thermal Unit.

Condensate: A natural gas liquid with a low vapor pressure mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.

Delivery point: The point where gas or natural gas liquids are delivered by a processor or transporter to a producer, shipper or purchaser, typically the inlet at the interconnection between the gathering or processing system and the facilities of a third-party processor or transporter.

Drip condensate: Heavier hydrocarbon liquids that fall out of the natural gas stream and are recovered in the gathering system without processing.

Dry gas: A gas primarily composed of methane and ethane where heavy hydrocarbons and water either do not exist or have been removed through processing.

End-use markets: The ultimate users/consumers of transported energy products.

Forward-haul: Pipeline transportation service in which the nominated gas flow from receipt point to delivery point is in the same direction as the pipeline’s physical gas flow.

Long ton: A British unit of weight equivalent to 2,240 pounds.

LTD: One long ton per day.

MMBtu: One million British Thermal Units.

MMBtu/d: One million British Thermal Units per day.

MMcf/d: One million cubic feet per day.

Natural gas: Hydrocarbon gas found in the earth composed of methane, ethane, butane, propane and other gases.

Natural gas liquids or NGLs: The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

Plant condensate: Heavier hydrocarbon liquids that fall out of the natural gas stream and are recovered at the plant.

Play: A proven geological formation that contains known or potential commercial amounts of petroleum and/or natural gas.

Psia: Pounds per square inch, absolute; refers to the pressure resulting from a one pound-force applied to an area of one square inch, including local atmospheric pressure.

Receipt point: The point where production is received by or into a gathering system or transportation pipeline.

Residue gas: The natural gas remaining after being processed or treated.

Sour gas: Natural gas containing more than four parts per million of hydrogen sulfide.

Tailgate: The point at which processed natural gas and/or natural gas liquids leave a processing facility for end-use markets.

Tcf: One trillion cubic feet of natural gas.

Wellhead: The equipment at the surface of a well used to control the well’s pressure; the point at which the hydrocarbons and water exit the ground.

WESTERN GAS PARTNERS, LP

PART I

Items 1 and 2. Business and Properties

Unless the context clearly indicates otherwise, references in this report to the “Partnership,” “we,” “our,” “us” or like terms, when used in the historical context, refer to the combined financial results and operations of Anadarko Gathering Company LLC and Pinnacle Gas Treating LLC from their inception through the closing date of our initial public offering and to Western Gas Partners, LP and its subsidiaries thereafter, combined with the financial results and operations of MIGC LLC and the Powder River assets, as described in Powder River Acquisition below, from August 23, 2006 thereafter. When used in the present tense or prospectively, the “Partnership,” “we,” “our,” “us” or like terms refer to Western Gas Partners, LP and its subsidiaries.

“Anadarko” refers to Anadarko Petroleum Corporation (NYSE: APC) and its subsidiaries and affiliates, other than Western Gas Partners, LP and Western Gas Holdings, LLC, our general partner. “Anadarko Petroleum Corporation” refers to Anadarko Petroleum Corporation excluding its subsidiaries and affiliates. “AGC” refers to Anadarko Gathering Company LLC, “PGT” refers to Pinnacle Gas Treating LLC and “MIGC” refers to MIGC LLC. “Predecessor” refers to AGC, PGT and MIGC. Each of AGC, PGT, MIGC, our general partner and the Partnership is an indirect subsidiary of Anadarko.

Available Information

We file our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and other documents electronically with the U.S. Securities and Exchange Commission, or the SEC, under the Securities Exchange Act of 1934. From time-to-time, we may also file registration and related statements pertaining to equity or debt offerings. We provide access free of charge to all of these SEC filings, as soon as reasonably practicable after filing or furnishing, on our Internet site located at www.westerngas.com. You may also read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. You may also obtain such reports from the SEC’s Internet website at www.sec.gov.

Our Corporate Governance Guidelines, Code of Ethics for our Chief Executive Officer and Senior Financial Officers, Code of Business Conduct and Ethics and the charters of the audit committee and the special committee of our general partner’s board of directors are also available on our Internet website. We will also provide, free of charge, a copy of any of our governance documents listed above upon written request to our general partner’s corporate secretary at our principal executive office.

Our principal executive offices are located at 1201 Lake Robbins Drive, The Woodlands, TX 77380-1046. Our telephone number is 832-636-6000.

GENERAL

We are a growth-oriented Delaware limited partnership organized by Anadarko to own, operate, acquire and develop midstream energy assets. With midstream assets in East and West Texas, the Rocky Mountains and the Mid-Continent, we are engaged in the business of gathering, compressing, treating, processing and transporting natural gas for Anadarko and other producers and customers. Approximately 74% of our services are provided under long-term contracts with fee-based rates and approximately 22% of our services are provided under percent-of-proceeds contracts, based on operating income for the year ended December 31, 2008. Effective January 1, 2009, we have entered into fixed-price swap agreements with Anadarko to manage the future commodity price risk otherwise inherent in our percent-of-proceeds contracts. A substantial part of our business is conducted with Anadarko and governed by contracts which were entered into during 2008 with an initial term of 10 years. Certain contracts with third parties extend for primary terms of up to 20 years.

We believe that one of our principal strengths is our relationship with Anadarko. During each of the past three years, over 80% of our total natural gas gathering, processing and transportation volumes were comprised of natural gas production owned or controlled by Anadarko. In addition, Anadarko has dedicated to us all of the natural gas production it owns or controls from (i) wells that are currently connected to our gathering systems, and (ii) additional wells that are drilled within one mile of wells connected to our gathering systems, as the systems currently exist and as they are expanded to connect additional wells in the future. As a result, this dedication will continue to expand as additional wells are connected to our gathering systems.

Our operations and activities are managed by our general partner, Western Gas Holdings, LLC, a wholly owned subsidiary of Anadarko. We expect to utilize the significant experience of Anadarko’s management team to execute our growth strategy, which includes acquiring and constructing additional midstream assets. As of December 31, 2008, Anadarko’s total domestic midstream asset portfolio, excluding assets we own, consists of 19 gathering systems with an aggregate throughput of approximately 2.3 Bcf/d, 8,100 miles of pipeline, and 18 processing and/or treating facilities.

SEGMENTS

Our operations are organized into a single business segment which engages in gathering, compressing, processing, treating and transporting Anadarko and third-party natural gas production in the United States. Information on our key measure of profit is included in Note 12—Segment Information of the notes to the consolidated financial statements included in Item 8—Financial Statements and Supplementary Data in this Form 10-K.

INITIAL PUBLIC OFFERING

On May 14, 2008, we closed our initial public offering of 18,750,000 common units at a price of $16.50 per unit. On June 11, 2008, we issued an additional 2,060,875 common units to the public pursuant to the partial exercise of the underwriters’ over-allotment option. We refer to the May 14 and June 11 transactions collectively as our initial public offering. Our common units are listed on the New York Stock Exchange under the symbol “WES.”

In connection with our initial public offering, Anadarko contributed the assets and liabilities of AGC, PGT and MIGC to us in exchange for 1,083,115 general partner units, representing a 2.0% general partner interest in the Partnership, 100% of our partnership incentive distribution rights, or IDRs, and 5,725,431 common units and 26,536,306 subordinated units. The common units held by Anadarko include 751,625 common units issued to Anadarko following the expiration of the underwriters’ over-allotment option and represent the portion of the common units for which the underwriters did not exercise their over-allotment option. We refer to AGC, PGT and MIGC as our initial assets.

POWDER RIVER ACQUISITION

On December 19, 2008, we acquired certain midstream assets from Anadarko for consideration consisting of $175.0 million cash, which was financed by borrowing $175.0 million from Anadarko pursuant to the terms of a five-year term loan agreement, 2,556,891 of our common units and 52,181 of our general partner units. The acquired assets consisted of (i) a 100% ownership interest in the Hilight System, (ii) a 50% interest in the Newcastle System and (iii) a 14.81% limited liability company membership interest in Fort Union Gas Gathering, L.L.C. We refer to these assets collectively as our Powder River assets. These assets provide a combination of gathering, treating and processing services in the Powder River Basin area of Wyoming.

Our initial public offering and Powder River acquisition are considered transfers of net assets between entities under common control. Anadarko acquired MIGC and the Powder River assets in connection with its August 23, 2006 acquisition of Western Gas Resources, Inc., or Western. The financial information included in this Annual Report on Form 10-K includes the combined financial results and operations of AGC and PGT from their inception through May 14, 2008 and of the Partnership thereafter, combined with the financial results and operations of MIGC and the Powder River assets beginning on August 23, 2006.

Following the closing of the Powder River acquisition:

	•		Anadarko holds 1,135,296 general partner units, representing a 2.0% general partner interest in the Partnership, and 100% of the IDRs;
	•		Anadarko holds 8,282,322 common units and 26,536,306 subordinated units, representing an aggregate 61.3% limited partner interest in the Partnership; and
	•		the public holds 20,810,875 common units, representing a 36.7% limited partner interest in the Partnership.

OUR ASSETS AND AREAS OF OPERATION

Our assets consist of nine gathering systems, six natural gas treating facilities, two gas processing facilities and one interstate pipeline that is regulated by the Federal Energy Regulatory Commission or FERC. Our assets are located in East and West Texas, the Rocky Mountains (Utah and Wyoming) and the Mid-Continent (Kansas and Oklahoma). The following table provides information regarding our assets by geographic region as of or for the year ended December 31, 2008:

										Approximate
										number of				Gas				Treating				Average
						Length				receipt				compression				capacity				throughput
Area				Asset Type		(miles)				points				(horsepower)				(MMcf/d)				(MMcf/d)
East Texas				Gathering and Treating			587				819				44,432				502				460
West Texas				Gathering			108				77				—				—				152
Rocky Mountains				Gathering and Treating(1)			432				179				20,385				386				164
				Gathering and Processing(2)			1,130				801				29,781				—				30
				Transportation			264				19				29,696				—				171
Mid-Continent				Gathering			2,073				1,555				102,257				—				131
Total							4,594				3,450				226,551				888				1,108

STRATEGY

Our primary business objective is to increase our cash distributions per unit over time. We intend to accomplish this objective by executing the following strategy:

	•		Pursuing accretive acquisitions. We expect to continue to pursue accretive acquisition opportunities within the midstream energy industry from Anadarko and third parties.
	•		Capitalizing on organic growth opportunities. We expect to grow certain of our systems organically over time by meeting Anadarko’s and our other customers’ gathering needs that result from their drilling activity in our areas of operation.
	•		Attracting third-party volumes to our systems. We actively market our midstream services to and pursue strategic relationships with third-party producers with the intention of attracting additional volumes and/or expansion opportunities.
	•		Minimizing commodity price exposure. The majority of our midstream services are provided under fee-based arrangements. In addition, we entered into fixed-price swap agreements with Anadarko to manage commodity price risk otherwise associated with our percent-of-proceeds contracts. We intend to continue to limit our direct exposure to commodity price changes.

COMPETITIVE STRENGTHS

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

	•		Affiliation with Anadarko. We believe Anadarko, as the indirect owner of our general partner interest, all of the IDRs and a 61.3% limited partner interest in us, is motivated to promote and support the successful execution of our business plan and to pursue projects that enhance the value of our business.
	•		Relatively stable and predictable cash flow. Our cash flow is largely protected from fluctuations caused by commodity price volatility due to (i) the long-term nature of our fee-based agreements and (ii) fixed-price swap agreements which limit our exposure to commodity price changes with respect to our percent-of-proceeds contracts.
	•		Well-positioned, well-maintained and efficient assets. We believe that our established positions in our areas of operation provide us with opportunities to expand and attract additional volumes to our systems. Moreover, our

systems include high-quality, well-maintained assets for which we have implemented modern processing, treating, measuring and operating technologies.

	•		Financial flexibility to pursue expansion and acquisition opportunities. We currently have up to $100.0 million of borrowing capacity available to us under Anadarko’s revolving credit facility as well as a $30.0 million working capital facility. We believe our operating cash flow, borrowing capacity, ability to finance acquisitions through Anadarko and access to debt and equity capital markets provide us with the financial flexibility necessary to execute or strategy across capital-market cycles.
	•		Experienced management team. Members of our general partner’s management team have extensive experience in building, acquiring, integrating, financing and managing midstream assets. Our relationship with Anadarko provides us with the services of experienced personnel who successfully managed our assets and operations while they were owned by Anadarko.

We believe that we will effectively leverage our competitive strengths to successfully implement our strategy; however, our business involves numerous risks and uncertainties which may prevent us from achieving our primary business objective. For a more complete description of the risks associated with our business, please read Item 1A—Risk Factors in this Form 10-K.

OUR RELATIONSHIP WITH ANADARKO PETROLEUM CORPORATION

One of our principal attributes is our relationship with Anadarko, which indirectly owns our general partner and has a significant ownership interest in us. Anadarko is one of the largest independent oil and gas exploration and production companies in the world. Anadarko’s upstream oil and gas business finds and produces natural gas, crude oil, condensate and natural gas liquids, or NGLs. As of December 31, 2008, Anadarko’s total domestic midstream asset portfolio, excluding assets we own, consisted of 19 gathering systems with an aggregate throughput of approximately 2.3 Bcf/d, 8,100 miles of pipeline, and 18 processing and/or treating facilities.

Anadarko indirectly owns a 2.0% general partner interest in us, all of our IDRs and a 61.3% limited partner interest in us. We entered into an omnibus agreement with Anadarko and our general partner that governs our relationship with them regarding certain reimbursement and indemnification matters. Although our relationship with Anadarko provides us with a significant advantage in the midstream natural gas market, it is also a source of potential conflicts. For example, Anadarko is not restricted from competing with us. Given Anadarko’s significant ownership of limited and general partner interests in us, we believe it will be in Anadarko’s best interest for it to transfer additional assets to us over time; however, Anadarko continually evaluates acquisitions and divestitures and may elect to acquire, construct or dispose of midstream assets in the future without offering us the opportunity to acquire or construct those assets. Anadarko is under no contractual obligation to offer any such opportunities to us, nor are we obligated to participate in any such opportunities. We cannot state with any certainty which, if any, opportunities to acquire additional assets from Anadarko may be made available to us or if we will elect to pursue any such opportunities. Please see Item 1A—Risk Factors and Item 13—Certain Relationships and Related Transactions, and Director Independence of this Form 10-K for more information.

INDUSTRY OVERVIEW

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

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

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

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 delivered into a higher pressure system. Field compression is typically used to allow a gathering system to operate at a lower pressure or provide sufficient discharge pressure to deliver natural gas into a higher pressure system. Since wells produce at progressively lower field pressures as they deplete, field compression is needed to maintain throughput across the gathering system.

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

Processing. Most decontaminated rich natural gas does not meet the quality standards for long-haul pipeline transportation or commercial use and must be processed to remove the heavier hydrocarbon components, which are extracted as NGLs.

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

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

Typical Contractual Arrangements. Midstream natural gas services, other than transportation and storage, are usually provided under contractual arrangements that vary in the amount of commodity price risk they carry. Three typical contract types are described below:

	•		Fee-Based. Fee-based arrangements may be used for gathering, compression, treating and processing services. Under these arrangements, the service provider typically receives a fee for each unit of natural gas gathered and compressed at the wellhead and an additional fee per unit of natural gas treated or processed at its facility. As a result, the price per unit received by the service provider does not vary with commodity price changes, minimizing that service provider’s direct commodity price risk exposure.
	•		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 gas and/or NGLs or a percentage of the actual residue gas 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 NGLs.
	•		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.

There are two forms of contracts utilized in the transportation and storage of natural gas, as described below:

	•		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. Firm storage contracts involve the reservation of a specific amount of storage capacity, including injection and withdrawal rights, and generally include a capacity reservation charge based on the amount of capacity being reserved plus an injection and/or withdrawal fee.
	•		Interruptible. Interruptible transportation and storage 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 or stored. 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 or at the storage facility.

See Note 2—Summary of Significant Accounting Policies of the notes to the consolidated financial statements included in Item 8—Financial Statements and Supplementary Data of this Form 10-K for information regarding our contracts.

Natural Gas Demand and Production. Natural gas is a critical component of energy supply in the U.S. According to the Energy Information Administration, or the EIA, total annual domestic consumption of natural gas is expected to decrease from approximately 23.4 trillion cubic feet, or Tcf, in 2008 to approximately 22.5 Tcf in 2011, but consumption is expected to increase to approximately 24.5 Tcf by 2028. The industrial and electricity generation sectors are the largest consumers of natural gas in the U.S. During the last three years, these sectors accounted for approximately 58% of the total natural gas consumed in the U.S. In 2007, natural gas provided approximately 24% of all end-user commercial and residential energy requirements. During the last three years, the U.S. has, on average, consumed approximately 22.7 Tcf per year, with average annual domestic production of approximately 19.4 Tcf during the same period. The EIA projects that domestic natural gas production will increase from 20.5 Tcf per year to 23.5 Tcf per year between 2008 and 2028.

PROPERTIES

Our assets consist of nine gathering systems, six natural gas treating facilities, two gas processing facilities and one interstate pipeline. Our assets are located in East and West Texas, the Rocky Mountains (Utah and Wyoming), and the Mid-Continent (Kansas and Oklahoma).

In the areas in which we operate there historically has been a significant level of drilling activity offsetting the natural decline in production from existing wells. The current commodity price environment has resulted in significantly lower drilling

activity in recent months throughout the areas in which we operate. We have no control over this activity. In addition, the recent or further decline in commodity prices could affect production rates and the level of investment by Anadarko and third parties in the exploration for and development of new natural gas reserves. Further, Anadarko and our third-party customers plan to reduce, and may temporarily suspend, drilling activities in certain areas during 2009, which would limit the number of new wells connected to our systems. For example, Anadarko has announced that it expects to reduce its onshore rig fleet by approximately 50% from peak levels reached in 2008 until further cost reductions are realized, although the specific rig activity in our areas of operations has not been announced. Anadarko’s and our third-party customers’ 2009 capital programs and drilling activity are subject to change based on their continued monitoring of industry economic conditions and the commodity price environment. The current commodity price environment may impact the comparability of our historical operating results to future operating results.

The following sections describe in more detail the services provided by our assets in our areas of operation. All volumes stated below are based on a standard pressure base of 14.73 psia.

The following map depicts the Partnership’s and Anadarko’s significant midstream assets as of December 31, 2008.

     

East Texas

Dew gathering system

General. The 320-mile Dew gathering system is located in Anderson, Freestone, Leon and Robertson Counties of East Texas. The Dew gathering system was placed into service in November 1998 to provide gathering services for Anadarko’s drilling program in the Bossier play. The system provides gathering, dehydration and compression services and ultimately delivers into the Pinnacle gas treating system for any required treating.

Average throughput on the Dew gathering system for the years ended December 31, 2008, 2007 and 2006 was 200 MMcf/d, 218 MMcf/d and 232 MMcf/d, respectively, from approximately 745, 730 and 700 receipt points, respectively. The Dew gathering system has pipeline diameters ranging from three to twelve inches and has 11 compressor stations with a combined 43,167 horsepower of compression.

Customers. Anadarko is the largest shipper on the Dew gathering system. Anadarko’s equity gas accounted for 196 MMcf/d of throughput during the year ended December 31, 2008, which represented approximately 98% of the total volume on the system.

Delivery Points. The Dew gathering system has delivery points with Pinnacle Gas Treating LLC, which is the primary delivery point and is described in more detail below, and Kinder Morgan’s Tejas pipeline.

Supply. Anadarko has approximately 879 producing wells in the Bossier play and controls approximately 238,000 gross acres in the area. Anadarko historically has maintained an active drilling program in the Bossier play, drilling approximately 20 to 30 gross wells per year.

Pinnacle Gas Treating LLC

General. Pinnacle Gas Treating LLC, or PGT, includes our Pinnacle gathering system and our Bethel treating plant. PGT provides sour gas gathering and treating service in Anderson, Freestone, Leon, Limestone and Robertson Counties of East Texas. The gathering system consists of 267 miles of pipeline with diameters ranging from three to 24 inches and one compressor station with 1,265 horsepower. The Bethel treating plant, located in Anderson County, has total CO₂ treating capacity of 500 MMcf/d and 20 LTD of sulfur treating capacity.

Average throughput on the Pinnacle gathering system for the years ended December 31, 2008, 2007 and 2006 was 260 MMcf/d, 296 MMcf/d and 306 MMcf/d, respectively, from approximately 74, 70 and 60 receipt points, respectively.

Customers. Anadarko is the largest shipper on the Pinnacle gathering system with 234 MMcf/d for the year ended December 31, 2008, which represented approximately 90% of the total throughput on the system during such period. The balance of throughput on the system during 2008 was primarily from five third-party shippers.

Delivery Points. The Pinnacle gathering system is connected to Enterprise Texas Pipeline, LP’s pipeline, the Energy Transfer Fuels pipeline, the ETC Texas pipeline, Kinder Morgan’s Tejas pipeline, the ATMOS Texas pipeline and the Enbridge Pipelines (East Texas) LP pipeline. These pipelines provide transportation to the Carthage, Waha and Houston Ship Channel market hubs in Texas.

Supply. The Pinnacle gathering system is well positioned to provide gathering and treating services to the five-county area over which it extends. With the recent drilling activity in the Cotton Valley Lime formations, which contain higher concentrations of H₂S and CO₂, we obtained a commitment from a third-party producer that allowed us to expand the Bethel treating facilities during 2008 by installing an additional 11 LTD of sulfur treating capacity to bring the total installed sulfur treating capacity to 20 LTD. With this expansion, we believe that we are well positioned to benefit from future sour gas production in the area.

Rocky Mountains

MIGC system

General. The MIGC system is a 264-mile interstate pipeline operating within the Powder River Basin of Wyoming that is regulated by FERC. The MIGC system traverses the Powder River Basin from north to south, extending approximately 150 miles to Glenrock, Wyoming. As a result, the MIGC system is well positioned to provide transportation for the extensive

natural gas volumes received from various coal-bed methane gathering systems and conventional gas processing plants throughout the Powder River Basin. MIGC offers both forward-haul and backhaul transportation services, and additional capacity is available from time to time on an interruptible basis.

During September 2007, MIGC completed the installation of, and placed into service, the Python compression station, which increased capacity on the MIGC system by approximately 50 MMcf/d. MIGC is currently certificated for 175 MMcf/d of firm transportation capacity, all of which is fully subscribed.

Average throughput on the MIGC system for the years ended December 31, 2008, 2007 and 2006 was 171 MMcf/d, 148 MMcf/d and 126 MMcf/d, respectively, from approximately 20 receipt points.

Customers. Anadarko is the largest firm shipper on the MIGC system, with approximately 72% of throughput for the year ended December 31, 2008. For the year ended December 31, 2008, two third-party shippers accounted for approximately 27% of throughput on the system.

Revenues on the MIGC system are generated from contract demand charges and volumetric fees paid by shippers under firm and interruptible gas transportation agreements. Our current firm transportation agreements range in term from approximately one to 10 years. Of the current certificated capacity of 175 MMcf/d, 85 MMcf/d is contracted through January 2011, 45 MMcf/d is contracted through September 2012 and 40 MMcf/d is contracted through October 2018. Most of our interruptible gas transportation agreements are month-to-month with the remainder generally having terms of less than one year. Approximately 92% of our revenues from the MIGC system for the year ended December 31, 2008 were associated with firm transportation demand charges.

Delivery Points. MIGC volumes can be redelivered to four interstate market pipelines and one intrastate pipeline, including the Williston Basin Interstate pipeline at the northern end of the Powder River Basin, the MGTC intrastate pipeline, a pipeline that supplies local markets in Wyoming, the Wyoming Interstate Company’s Medicine Bow lateral pipeline, the Colorado Interstate Gas pipeline and the Kinder Morgan interstate pipeline at the southern end of the Powder River Basin near Glenrock, Wyoming. The MGTC pipeline is owned by Anadarko.

Supply. Anadarko has a working interest in over 1.4 million gross acres within the prolific Powder River Basin. It currently operates approximately 4,400 gross producing coal-bed methane wells and has non-operating interests in more than 5,300 additional gross producing coal-bed methane wells. Anadarko’s gross acreage is approximately 50% developed with substantial undeveloped acreage positions in the expanding Big George coal play and the multiple seam coal fairway to the north of the Big George play.

Fort Union system

General. The Fort Union system is a gathering system operating within the Powder River Basin of Wyoming, starting in west central Campbell County and terminating at the Medicine Bow treating plant. The Fort Union gathering system has three parallel 24-inch pipes, each 106 miles in length, and includes CO₂ treating facilities at the Medicine Bow plant. The plant currently consists of two amine trains and an additional train is expected to be placed into service during the first quarter of 2009.

Fort Union Gas Gathering, L.L.C. is a partnership among Copano Pipelines/Rocky Mountains, LLC (37.04%), Crestone Powder River L.L.C. (37.04%), Bargath, Inc. (11.11%) and the Partnership (14.81%). Anadarko is the field and construction operator of the Fort Union gathering system. The Fort Union gathering system has a capacity of approximately 1.3 Bcf/d.

Average throughput on the Fort Union system for the years ended December 31, 2008, 2007 and 2006 was 754 MMcf/d, 566 MMcf/d and 521 MMcf/d, respectively, from approximately 15 receipt points.

Customers. The four Fort Union owners named above are the only firm shippers on the Fort Union system. To the extent capacity on the system is not used by the owners, it is available to third parties under interruptible agreements.

Delivery Points. The Fort Union system delivers coal-bed methane gas to the Glenrock, Wyoming Hub which accesses interstate pipelines, including Wyoming Interstate Gas Company, Kinder Morgan Interstate Gas Transportation Company and Colorado Interstate Gas Company. These interstate pipelines serve gas markets in the Rocky Mountains and Midwest regions of the United States.

Supply. Substantially all of Fort Union’s gas supply is comprised of coal-bed methane volumes that are either produced or gathered by the four Fort Union owners throughout the Powder River Basin. Anadarko has a working interest in over 1.4

million gross acres within the Powder River Basin and currently produces gas from approximately 9,800 coal-bed methane wells in the Wyodek coal, the expanding Big George coal play and the multiple seam coal fairway to the north of the Big George play. Another of the Fort Union owners has a comparable working interest in approximately 80% 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.

Helper gathering system

General. The 67-mile Helper gathering system, located in Carbon County, Utah, was built to provide gathering services for Anadarko’s coal-bed methane development of the Ferron Coal. The Helper gathering system provides gathering, dehydration, compression and treating services for coal-bed methane gas.

Average throughput on the Helper gathering system for the years ended December 31, 2008, 2007 and 2006 was 36 MMcf/d, 35 MMcf/d and 38 MMcf/d, respectively, from approximately 120 receipt points. The Helper gathering system has pipeline diameters ranging from four to 20 inches and includes two compressor stations with a combined 14,075 horsepower and two CO₂ treating facilities.

Customers. Anadarko is the largest shipper on the Helper gathering system. For the year ended December 31, 2008, Anadarko’s equity production represented approximately 99% of the Helper gathering system’s volume.

Delivery Points. The Helper gathering system delivers into the Questar Transportation Services Company’s pipeline. Questar 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 U.S., primarily California.

Supply. The Helper Field is an Anadarko-operated field on the southwestern edge of the Uintah Basin that produces from the Cretaceous Ferron sands and coals. The Helper Field consists of approximately 19,000 gross acres and has 116 gross producing wells as of December 31, 2008. Cardinal Draw, which lies immediately to the east of Helper Field, has 36 gross producing wells as of December 31, 2008 and covers approximately 19,000 gross acres.

Clawson gathering system

General. The 47-mile Clawson gathering system, located in Carbon and Emery Counties of Utah, was built in 2001 to provide gathering services for Anadarko’s coal-bed methane development of the Ferron Coal. The Clawson gathering system provides gathering, dehydration, compression and treating services for coal-bed methane gas.

Average throughput on the Clawson gathering system for the years ended December 31, 2008, 2007 and 2006 was 17 MMcf/d, 18 MMcf/d and 22 MMcf/d, respectively, from approximately 45 receipt points. The Clawson gathering system has pipeline diameters ranging from four to 18 inches and includes one compressor station, with 6,310 horsepower, and a CO₂ treating facility.

Customers. Anadarko is the largest shipper on the Clawson gathering system with approximately 97% of the total throughput delivered into the system during the year ended December 31, 2008. The remaining throughput on the system was comprised of production from third-party producers.

Delivery Points. The Clawson gathering system delivers into Questar Transportation Services Company’s pipeline.

Supply. Clawson Springs Field has 45 gross producing wells as of December 31, 2008 on approximately 7,000 gross acres. Production for Clawson Springs is primarily from the Cretaceous Ferron sands and coals.

Hilight gathering system and processing plant

General. The 980-mile Hilight gathering system, located in Johnson, Campbell, Natrona and Converse Counties of Wyoming, was built to provide low- and high-pressure gathering services for area conventional gas production and delivers to the Hilight plant for processing. The Hilight gathering system has pipeline diameters ranging from three to 16 inches and includes 10 compressor stations with 16,366 horsepower. The Hilight system was built in 1969 and has a capacity of approximately 30 MMcf/d. The Hilight plant utilizes a refrigeration process and provides for fractionation of the recovered NGL product into propane, butanes and natural gasoline.

Average throughput on the Hilight system for the years ended December 31, 2008, 2007 and 2006 was 28 MMcf/d, 28 MMcf/d and 29 MMcf/d, respectively, from approximately 400 receipt points.

Customers. Gas processed at the Hilight system is purchased from 48 third-party customers, with the ten largest producers providing approximately 80% of the system throughput.

Delivery Points. The Hilight gathering system delivers into MIGC’s 16-inch transmission line, which delivers to Glenrock, Wyoming.

Supply. The Hilight gathering system serves the gas gathering needs of several conventional producing fields in Johnson, Campbell, Natrona and Converse counties. Our customers have historically and may continue to maintain throughput with workover activity and by developing new prospects. Based on publicly available information, these producers are planning drilling activity over the next three to five years in the area serviced by the system.

Newcastle gathering system and processing plant

General. The 150-mile Newcastle gathering system, located in Weston and Niobrara Counties of Wyoming, was built to provide gathering services for conventional gas production in the area. The gathering system delivers into the Newcastle plant, which was built in 1981 and has a capacity of approximately 3 MMcf/d. The plant utilizes a refrigeration process and provides for fractionation of the recovered NGL product into propane and butane/gasoline mix products. The Newcastle facility is a joint venture among Black Hills Exploration and Production, Inc. (44.7%), John Paulson (5.3%) and the Partnership (50.0%). The Newcastle gathering system has pipeline diameters ranging from two to six inches and includes one compressor station, with 560 horsepower. The Newcastle plant has an additional 2,100 horsepower for refrigeration and residue compression.

Average throughput on the Newcastle system for the years ended December 31, 2008, 2007 and 2006 was 1 MMcf/d, 2 MMcf/d and 2 MMcf/d, respectively, from approximately 400 receipt points.

Customers. Gas processed at the Newcastle system is purchased from 15 third-party customers, with the largest three producers providing approximately 85% of the system throughput. The largest producer, Black Hills Exploration, provides approximately 70% of the throughput and is a part owner of the Newcastle system.

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 gas from the Newcastle system is delivered into MGTC’s pipeline for transport, distribution and sales.

Supply. The Newcastle gathering system and plant primarily service gas production from the Clareton and Finn-Shurley fields in Weston County. Due to infill drilling and enhanced production techniques, producers have continued to maintain and improve production. It is estimated that, after 28 years of development, approximately 9% of the original reserves in place have been produced.

Mid-Continent

Hugoton gathering system

General. The 2,073-mile Hugoton gathering system provides gathering service to the Hugoton field and is primarily located in Seward, Stevens, Grant and Morton Counties of Southwest Kansas and Texas County in Oklahoma.

Average throughput on the Hugoton gathering system for the years ended December 31, 2008, 2007 and 2006 was 131 MMcf/d, 123 MMcf/d and 114 MMcf/d, respectively, from approximately 1,550 receipt points. The Hugoton gathering system has pipeline diameters ranging from two to 26 inches and 43 compressor stations with a combined 102,257 horsepower of compression.

Customers. Anadarko is the largest customer on the Hugoton gathering system with 105 MMcf/d of average throughput during the year ended December 31, 2008, representing 83% of the total volume on the system. Of these volumes, 65% represents Anadarko’s equity production and 35% represents volumes purchased by Anadarko primarily from two third parties. Approximately 17% of the remaining throughput on the Hugoton system for the year ended December 31, 2008 was from four other third-party shippers.

Delivery Points. The Hugoton gathering system is connected to DCP Midstream, LP’s National Helium plant, which extracts NGLs and helium and redelivers residue gas into the Panhandle Eastern pipeline. The system is also connected to Pioneer Natural Resources Corporation’s Satanta plant for NGL processing and to the adjacent Mid-Continent Market Center, which provides access to the Panhandle Eastern pipeline, the Northern Natural Gas pipeline, the Natural Gas pipeline, the Southern Star pipeline, and the ANR pipeline. These pipelines provide transportation and market access to Midwestern and Northeastern markets.

Supply. The Hugoton field is one of the largest natural gas fields in North America. The Hugoton field continues to be a long-life, slow-decline asset for Anadarko, which operates over 1,200 gross wells in the area and has an extensive acreage position with approximately 470,000 gross acres. We believe that recent changes to the Hugoton and Panoma Council Grove Proration Orders will provide opportunities for significant recompletion, redrilling and density-drilling activities.

By virtue of a farmout agreement between a third-party producer and Anadarko, the third-party producer gained the right to explore below the primary formations in the Hugoton field. We believe our existing asset is well-positioned to gather volumes that may be produced from new wells the third-party producer may successfully drill.

West Texas

Haley gathering system

General. The 108-mile Haley gathering system is located in Loving County, Texas and gathers Anadarko’s production from the Delaware Basin. The Haley gathering system provides gathering and dehydration services and has pipeline diameters ranging from four to 16 inches.

Average throughput on the Haley gathering system for the years ended December 31, 2008, 2007 and 2006 was 152 MMcf/d, 169 MMcf/d and 133 MMcf/d, respectively, from approximately 75, 60 and 35 receipt points, respectively. The Haley gathering system has historically experienced rapid growth as a result of Anadarko’s successful drilling activity in the area.

Customers. Anadarko’s and its partners’ production represented 99% of the Haley gathering system’s throughput for the year ended December 31, 2008.

Delivery Points. The Haley gathering system has multiple delivery points. The primary delivery points are to the El Paso Natural Gas pipeline or the Enterprise GC, L.P. pipeline for ultimate delivery into Energy Transfer’s 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.

Supply. In the greater Delaware basin, Anadarko had interests in 159 gross producing wells as of December 31, 2008 and access to approximately 545,000 gross acres.

COMPETITION

We do not currently face significant competition on the majority of our systems due to the substantial throughput volumes being owned or controlled by Anadarko and its dedication to us of future production from acreage surrounding our gathering systems. We believe our assets that are outside of the dedicated areas are geographically well positioned to retain and attract third-party volumes.

Competition on gathering systems and at processing plants

The natural gas gathering, compression, processing, treating and transportation business is very competitive. Our competitors include other midstream companies, producers, and intrastate and interstate pipelines. Competition for natural gas volumes is primarily based on reputation, commercial terms, reliability, service levels, location, available capacity, capital expenditures and fuel efficiencies. We believe the primary competitive advantages of our Hilight and Newcastle systems, which gather and process third-party volumes, are their proximity to established and new production and our ability to provide flexible services to producers, including gathering, compression and processing. We believe we can provide the services that producers and other customers require to connect, gather and process their natural gas efficiently, at competitive and flexible contract terms. Further, we believe that Fort Union’s centralized amine treating facility provides Fort Union a competitive advantage.

Our primary competitors for our gathering systems and processing plants include:

	•		Dew gathering system and Pinnacle gas treating: ETC Texas Pipeline, Ltd., Enbridge Pipelines (East Texas) LP, XTO Energy and Kinder Morgan Tejas Pipeline, LP.
	•		Fort Union: Thunder Creek Gas Services
	•		Helper and Clawson gathering systems: Questar Transportation Services Company.
	•		Hilight gathering and processing system: DCP Midstream and Merit Energy.
	•		Hugoton gathering system: ONEOK Gas Gathering Company, DCP Midstream, LP and Pioneer Resources.
	•		Haley gathering system: Enterprise GC, LP and Southern Union Energy Services Company.
	•		Newcastle gathering and processing system: DCP Midstream.

Competition on transportation system

MIGC competes with other pipelines that service the regional market and transport gas volumes from the Powder River Basin to Glenrock, Wyoming. MIGC competitors seek to attract and connect new gas volumes throughout the Powder River Basin, including certain of the volumes currently being transported on MIGC. An increase in competition could result from new pipeline installations or expansions by existing pipelines. Competitive factors include commercial terms, available capacity, fuel efficiencies, the interconnected pipelines and gas quality issues. MIGC’s major competitor is Thunder Creek Gas Services.

SAFETY AND MAINTENANCE

We are subject to regulation by the Pipeline and Hazardous Materials Safety Administration, or PHMSA, of the Department of Transportation, or the DOT, pursuant to the Natural Gas Pipeline Safety Act of 1968, or the NGPSA, and the Pipeline Safety Improvement Act of 2002, or the PSIA, which was recently reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transportation pipelines and some gathering lines in high-consequence areas. The PHMSA has developed regulations implementing the PSIA that require transportation pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in “high consequence areas,” such as high population areas, areas unusually sensitive to environmental damage and commercially navigable waterways. Our transportation pipeline system, MIGC, includes no high consequence areas and thus these particular integrity management programs are not applicable.

We, or the entity in which we own an interest, inspect our pipelines regularly using equipment rented from third-party suppliers. Third parties also assist us in interpreting the results of the inspections.

States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant difficulty in complying with applicable state laws and regulations. Our natural gas pipelines have continuous inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.

In addition, we are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes, the purposes of which are to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the Environmental Protection Agency, or EPA, community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local government authorities and citizens. We and the entities in which we own an interest are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in

excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling points without the benefit of chilling or refrigeration are exempt. We have an internal program of inspection designed to monitor and enforce compliance with worker safety requirements. We believe that we are in material compliance with all applicable laws and regulations relating to worker health and safety.

REGULATION OF OPERATIONS

Regulation of pipeline gathering and transportation services, natural gas sales and transportation of NGLs may affect certain aspects of our business and the market for our products and services.

Interstate transportation pipeline regulation

MIGC, our interstate natural gas transportation system, is subject to regulation by FERC under the Natural Gas Act of 1938, or the NGA.

Under the NGA, FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. Federal regulation extends to such matters as:

	•		rates, services, and terms and conditions of service;
	•		the types of services MIGC may offer to its customers;
	•		the certification and construction of new facilities;
	•		the acquisition, extension, disposition or abandonment of facilities;
	•		the maintenance of accounts and records;
	•		relationships between affiliated companies involved in certain aspects of the natural gas business;
	•		the initiation and discontinuation of services;
	•		market manipulation in connection with interstate sales, purchases or transportation of natural gas; and
	•		participation by interstate pipelines in cash management arrangements.

Natural gas companies are prohibited from charging rates that have been determined not to be just and reasonable by FERC. In addition, FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.

The rates and terms and conditions for our interstate pipeline services are set forth in FERC-approved tariffs. Pursuant to FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. Any successful complaint or protest against our rates could have an adverse impact on our revenues associated with providing transportation service.

Commencing in 2003, FERC issued a series of orders adopting rules for new Standards of Conduct for Transmission Providers (Order No. 2004), which apply to interstate natural gas pipelines and certain natural gas storage companies that provide storage services in interstate commerce. Order No. 2004 became effective in 2004. Among other matters, Order No. 2004 required interstate pipeline and storage companies to operate independently from their energy affiliates, prohibited interstate pipeline and storage companies from providing non-public transportation or shipper information to their energy affiliates, prohibited interstate pipeline and storage companies from favoring their energy affiliates in providing service, and obligated interstate pipeline and storage companies to post on their websites a number of items of information concerning the company, including its organizational structure, facilities shared with energy affiliates, discounts given for services and instances in which the company has agreed to waive discretionary terms of its tariff. On July 7, 2004, FERC issued an order providing MIGC with a partial waiver of the independent functioning and information access provisions of the standards of conduct.

Late in 2006, the D.C. Circuit vacated and remanded Order No. 2004 as it relates to natural gas transportation providers, including MIGC. The D.C. Circuit found that FERC had not adequately justified its expansion of the prior standards of conduct to include energy affiliates, and vacated the entire rule as it relates to natural gas transportation providers. On January 9, 2007, as clarified on March 21, 2007, FERC issued an interim rule (Order No. 690) re-promulgating on an interim basis the standards of conduct that were not challenged before the court, while FERC decided how to respond to the court’s

decision on a permanent basis through FERC’s rulemaking process. On October 16, 2008, FERC issued Order No. 717, a final rule that amends the regulations adopted on an interim basis in Order No. 690. Order No. 717 implements revised standards of conduct that include three primary rules: (1) the “independent functioning rule,” which requires transmission function and marketing function employees to operate independently of each other; (2) the “no-conduit rule,” which prohibits passing transmission function information to marketing function employees; and (3) the “transparency rule,” which imposes posting requirements to help detect any instances of undue preference. FERC also clarified in Order No. 717 that existing waivers to the standards of conduct (such as those held by MIGC) shall continue in full force and effect. A number of parties have requested clarification or rehearing of Order No. 717, and FERC action on rehearing is currently pending. We have no way to predict what revisions to the standards of conduct may be made by FERC on rehearing. However, we do not expect the impact on MIGC to materially differ from the impact on other similarly situated natural gas service providers.

In May 2005, FERC issued a policy statement permitting the inclusion of an income tax allowance in the cost of service-based rates of a pipeline organized as a tax pass-through partnership entity, if the pipeline proves that the ultimate owner of its equity interests has an actual or potential income tax liability on public utility income. The policy statement also provides that whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by FERC on a case-by-case basis. In August 2005, FERC dismissed requests for rehearing of its new policy statement. On December 16, 2005, FERC issued its first significant case-specific review of the income tax allowance issue in a pipeline partnership’s rate case. FERC reaffirmed its new income tax allowance policy and directed the subject pipeline to provide certain evidence necessary for the pipeline to determine its income tax allowance. The new tax allowance policy and the December 16, 2005 order were appealed to the D.C. Circuit. The D.C. Circuit issued an order on May 29, 2007 in which it denied these appeals and upheld FERC’s new tax allowance policy and the application of that policy in the December 16, 2005 order on all points subject to appeal. The D.C. Circuit denied rehearing of the May 29, 2007 decision on August 20, 2007, and the D.C. Circuit’s decision is final.

On December 8, 2006, FERC issued another order addressing the income tax allowance in rates. In the December 8, 2006 order, FERC refined and reaffirmed prior statements regarding its income tax allowance policy, and notably raised a new issue regarding the implication of the policy statement for publicly traded partnerships. It noted that the tax deferral features of a publicly traded partnership may cause some investors to receive, for some indeterminate duration, cash distributions in excess of their taxable income, which FERC characterized as a “tax savings.” FERC stated that it is concerned that this created an opportunity for those investors to earn an additional return, funded by ratepayers. Responding to this concern, FERC chose to adjust the pipeline’s equity rate of return downward based on the percentage by which the publicly traded partnership’s cash flow exceeded taxable income. On February 7, 2007, the pipeline filed a request for rehearing on this issue. FERC issued an order on rehearing of the December 8, 2006 order on May 2, 2008, establishing a paper hearing on certain issues and determining that the remaining issues not addressed in the paper hearing would be addressed in an order following the completion of the paper hearing. Rehearing of the May 2, 2008 order has been granted and is currently pending. A partial offer of settlement of the issues subject to the paper hearing has been filed, and FERC action on the partial settlement is currently pending. The ultimate outcome of this proceeding cannot be predicted with certainty.

On April 17, 2008, FERC issued a proposed policy statement regarding the composition of proxy groups for determining the appropriate return on equity for natural gas and oil pipelines using FERC’s Discounted Cash Flow, or DCF, model. In the policy statement, which modified a proposed policy statement issued in July 2007, FERC concluded: (1) master limited partnerships, or MLPs, should be included in the proxy group used to determine return on equity for both oil and natural gas pipelines; (2) there should be no cap on the level of distributions included in FERC’s current DCF methodology; (3) Institutional Brokers’ Estimate System, or IBES, forecasts should remain the basis for the short-term growth forecast used in the DCF calculation; (4) the long-term growth component of the DCF model should be limited to fifty percent of long-term gross domestic product; and (5) there should be no modification to the current two-thirds and one-third weighting of the short-term and long-term growth components, respectively. FERC also concluded that the policy statement should govern all gas and oil rate proceedings involving the establishment of return on equity that are pending before FERC. FERC’s policy determinations applicable to MLPs are subject to further modification, and it is possible that these policy determinations may have a negative impact on MIGC’s rates in the future.

On August 8, 2005, Congress enacted the Energy Policy Act of 2005, or the EPAct 2005. Among other matters, EPAct 2005 amends the NGA to add an anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by FERC and, furthermore, provides FERC with additional civil penalty authority. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-manipulation provision of EPAct 2005, and subsequently denied rehearing. The rules make it unlawful for any entity, directly or indirectly in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC or the purchase or sale of transportation services subject to the jurisdiction of FERC: (1) to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made

not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-manipulation rules apply to interstate gas pipelines and storage companies and intrastate gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. The new anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but only to the extent such transactions do not have a “nexus” to jurisdictional transactions. EPAct 2005 also amends the NGA and the Natural Gas Policy Act of 1978, or NGPA, to give FERC authority to impose civil penalties for violations of these statutes, up to $1,000,000 per day per violation for violations occurring after August 8, 2005. In connection with this enhanced civil penalty authority, FERC issued a policy statement on enforcement to provide guidance regarding the enforcement of the statutes, orders, rules and regulations it administers, including factors to be considered in determining the appropriate enforcement action to be taken. Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

In 2008, FERC took steps to enhance its market oversight and monitoring of the natural gas industry by issuing several rulemaking orders designed to promote gas price transparency and to prevent market manipulation. Order No. 704, as clarified on rehearing in 2008, requires buyers and sellers of natural gas above a de minimis level, including entities not otherwise subject to FERC jurisdiction, to submit an annual report to FERC describing their wholesale physical natural gas transactions. The first such report is due on May 1, 2009 for calendar year 2008 activities. Order No. 720, issued on November 20, 2008, increases the Internet posting obligations of interstate pipelines, and also requires “major non-interstate” pipelines (defined as pipelines with annual deliveries of more than 50 million MMBtu) to post on the Internet the daily volumes scheduled for each receipt and delivery point on their systems with a design capacity of 15,000 MMBtu per day or greater. Numerous parties have requested modification or reconsideration of this rule, and it remains to be seen whether the requirements will be modified on rehearing, which is currently pending. In November 2008, FERC also issued a Notice of Inquiry to the industry soliciting comments regarding whether “Hinshaw” pipelines and intrastate pipelines that transport natural gas in interstate commerce pursuant to Section 311 of the NGPA should be required to post on the Internet certain details of their transactions with individual shippers in a manner comparable to the reporting requirements applicable to interstate pipelines. Once FERC evaluates the comments filed in response to the Notice of Inquiry, it may choose to engage in the formal rulemaking process to propose additional reporting requirements on such pipelines.

In 2008, FERC also took action to ease restrictions on the capacity release market, in which shippers on interstate pipelines can transfer to one another their rights to pipeline and/or storage capacity. Among other things, Order No. 712, as modified on rehearing, removes the price ceiling on short-term capacity releases of one year or less, allows a shipper releasing gas storage capacity to tie the release to the purchase of the gas inventory and the obligation to deliver the same volume at the expiration of the release, and facilitates Asset Management Agreements, or AMAs, by exempting releases under qualified AMAs from: the competitive bidding requirements for released capacity; FERC’s prohibition against tying releases to extraneous conditions; and the prohibition on capacity brokering.

Gathering pipeline regulation

Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC. We believe that our natural gas pipelines meet the traditional tests that FERC has used to determine that a pipeline is a gathering pipeline and is, therefore, not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. In recent years, FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies, which has resulted in a number of such companies transferring gathering facilities to unregulated affiliates. As a result of these activities, natural gas gathering may begin to receive greater regulatory scrutiny at both the state and federal levels. Our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services. Our natural gas gathering operations also may be or become subject to additional safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Our natural gas gathering operations are subject to ratable take and common purchaser statutes in most of the states in which we operate. These statutes generally require our gathering pipelines to take natural gas without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another

producer or one source of supply over another source of supply. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. The states in which we operate have adopted a complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. To date, there has been no adverse effect to our systems due to these regulations.

During the 2007 legislative session, the Texas State Legislature passed H.B. 3273, or the Competition Bill, and H.B. 1920, or the LUG Bill. The Texas Competition Bill and LUG Bill contain provisions applicable to gathering facilities. The Competition Bill allows the Railroad Commission of Texas, or the TRRC, the ability to use either a cost-of-service method or a market-based method for setting rates for natural gas gathering in formal rate proceedings. It also gives the TRRC specific authority to enforce its statutory duty to prevent discrimination in natural gas gathering, to enforce the requirement that parties participate in an informal complaint process and to punish purchasers, transporters and gatherers for taking discriminatory actions against shippers and sellers. The LUG Bill modifies the informal complaint process at the TRRC with procedures unique to lost and unaccounted for gas issues. It extends the types of information that can be requested and gives the TRRC the authority to make determinations and issue orders in specific situations. Both the Competition Bill and the LUG Bill became effective September 1, 2007. We cannot predict what effect, if any, either the Competition Bill or the LUG Bill might have on our gathering operations.

ENVIRONMENTAL MATTERS

General

Our operation of pipelines, plants and other facilities for the gathering, processing, compression, treating and transporting of natural gas and other products is subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

	•		requiring the installation of pollution-control equipment or otherwise restricting the way we can handle or dispose of our wastes;
	•		limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;
	•		requiring investigatory and remedial actions to mitigate or eliminate pollution conditions caused by our operations or attributable to former operations; and
	•		enjoining the operations of facilities deemed to be in non-compliance with such environmental laws and regulations and permits issued pursuant thereto.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of investigatory and remedial obligations and the issuance of orders enjoining future operations or imposing additional compliance requirements. Certain environmental statutes impose strict and joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or otherwise released, thus, we may be subject to environmental liability at our currently owned or operated facilities for conditions caused prior to our involvement. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing or future regulations.

We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations or cash flows. In addition, we believe that the

various environmental activities in which we are presently engaged are not expected to materially interrupt or diminish our operational ability to gather, process, compress, treat and transport natural gas. We cannot assure you, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations or the development or discovery of new facts or conditions will not cause us to incur significant costs. Below is a discussion of several of the material environmental laws and regulations that relate to our business. We believe that we are in material compliance with applicable environmental laws and regulations.

Hazardous substances and waste

Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict and joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act, referred to as CERCLA or the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons. These persons include current owners or operators of the site where a release of hazardous substances occurred, prior owners or operators that owned or operated the site at the time of the release, and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Despite the “petroleum exclusion” of CERCLA Section 101(14), which currently encompasses natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

We also generate solid wastes, including hazardous wastes, which are subject to the requirements of the Resource Conservation and Recovery Act, referred to as RCRA, and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA’s hazardous waste regulations. However, it is possible that these wastes, which could include wastes currently generated during our operations, will in the future be designated as “hazardous wastes” and, therefore, be subject to more rigorous and costly disposal requirements. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.

We currently own or lease, and our Predecessor has in the past owned or leased, properties where hydrocarbons are being or have been handled for many years. Although we have generally utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us, or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons and other wastes was not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our financial condition, results of operations or cash flows.

Air emissions

Our operations are subject to the Federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. We believe that we are in material compliance with these requirements. We may be required to incur certain capital expenditures in the future for air pollution control equipment in

connection with obtaining and maintaining permits and approvals for air emissions. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

Water discharges

The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants or fill into state waters as well as waters of the U.S. and adjacent wetlands. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of permits issued by the EPA, the Army Corps of Engineers or an analogous state agency. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. We believe that we are in material compliance with these requirements. However, federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. We believe that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our financial condition, results of operations or cash flows.

Endangered species

The Endangered Species Act, or ESA, restricts activities that may affect endangered or threatened species or their habitats. While some of our pipelines may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in material compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected states.

Climate change

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, numerous states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas initiatives. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, 549 U.S. 497 (2007), the EPA may be required or encouraged to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court’s holding in Massachusetts that greenhouse gases fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of greenhouse gas emissions from stationary sources under certain Clean Air Act programs. New legislation or regulatory programs that restrict emissions of greenhouse gases in areas where we conduct business could adversely affect our operations and demand for our services.

Anti-terrorism measures

The Department of Homeland Security Appropriation Act of 2007 requires the Department of Homeland Security, or DHS, to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to this act and, on November 20, 2007, further issued an Appendix A to the interim rules that establish chemicals of interest and their respective threshold quantities that will trigger compliance with these interim rules. We have determined the extent to which our facilities are subject to the rule, made the necessary notifications and determined that the requirements will not have a material impact on our financial condition, results of operations or cash flows.

TITLE TO PROPERTIES AND RIGHTS-OF-WAY

Our real property is classified into two categories: (1) parcels that we own in fee and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of

such land for our operations. Portions of the land on which our plants and other major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our plant sites and major facilities are located are held by us pursuant to surface leases between us, as lessee, and the fee owner of the lands, as lessors. We have or our Predecessor has leased or owned these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates or fee ownership of such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses.

Some of the leases, easements, rights-of-way, permits and licenses transferred to us at the time of our initial public offering required the consent of the grantor of such rights, which in certain instances is a governmental entity. Our general partner has obtained sufficient third-party consents, permits and authorizations for the transfer of the assets necessary to enable us to operate our business in all material respects. With respect to any remaining consents, permits or authorizations that have not been obtained, we have determined these will not have material adverse effect on the operation of our business should we fail to obtain such consents, permits or authorization in a reasonable time frame.

Anadarko holds record title to portions of certain assets as we make the appropriate filings in the jurisdictions in which such assets are located and obtain any consents and approvals as needed. Such consents and approvals would include those required by federal and state agencies or other political subdivisions. In some cases, Anadarko temporarily holds record title to property as nominee for our benefit and in other cases may, on the basis of expense and difficulty associated with the conveyance of title, may cause its affiliates to retain title, as nominee for our benefit, until a future date. We anticipate that there will be no material change in the tax treatment of our common units resulting from Anadarko holding the title to any part of such assets subject to future conveyance or as our nominee.

EMPLOYEES

We do not have any employees. The officers of our general partner manage our operations and activities. As of December 31, 2008, Anadarko employed approximately 167 people who provided direct, full-time support to our operations. All of the employees required to conduct and support our operations are employed by Anadarko and all of our direct, full-time personnel are subject to a service and secondment agreement between our general partner and Anadarko. None of these employees are covered by collective bargaining agreements, and Anadarko considers its employee relations to be good.

Item 1A. Risk Factors

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

We have made in this report, and may from time to time otherwise make in other public filings, press releases and discussions, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 concerning our operations, economic performance and financial condition. These statements can be identified by the use of forward-looking terminology such as “may,” “could,” “believe,” “expect,” “anticipate,” “estimate,” “project,” “continue,” “potential,” “plan,” “forecast” or other similar words. These statements discuss future expectations, contain projections of results of operations or financial condition or include other “forward-looking” information. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct.

These forward-looking statements involve risk and uncertainties. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:

	•		our assumptions about the energy market;
	•		future treating and processing volumes and pipeline throughput, including Anadarko’s production, which is gathered or transported through our assets;
	•		operating results;
	•		competitive conditions;
	•		technology;

	•		the availability of capital resources, capital expenditures and other contractual obligations;
	•		the supply of and demand for, and the price of oil, natural gas, NGLs and other products or services;
	•		the weather;
	•		inflation;
	•		the availability of goods and services;
	•		general economic conditions, either internationally or nationally or in the jurisdictions in which we are doing business;
	•		legislative or regulatory changes, including changes in environmental regulation, environmental risks, regulations by FERC and liability under federal and state environmental laws and regulations;
	•		the securities or capital markets, and our ability to access credit, including under Anadarko’s $1.3 billion credit facility;
	•		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; and
	•		other factors discussed below and elsewhere in Item 1A—Risk Factors and in Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates included in this Form 10-K and in our other public filings and press releases.

The risk factors and other factors noted throughout or incorporated by reference in this report could cause our actual results to differ materially from those contained in any forward-looking statement. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Limited partner units are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. We urge you to carefully consider the following risk factors together with all of the other information included in this annual report in evaluating an investment in our common units.

If any of the following risks were to occur, our business, financial condition or results of operation could be materially adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment in us.

RISKS RELATED TO OUR BUSINESS

We are dependent on Anadarko for a majority of the natural gas that we gather, treat and transport. A material reduction in Anadarko’s production gathered or transported by our assets would result in a material decline in our revenues and cash available for distribution.

We rely on Anadarko for a majority of the natural gas that we gather, treat and transport. For the year ended December 31, 2008, Anadarko accounted for approximately 83% of our natural gas gathering, processing and transportation volumes. Anadarko may suffer a decrease in production volumes in the areas serviced by us and is under no contractual obligation to maintain its production volumes dedicated to us. The loss of a significant portion of the natural gas volumes supplied by Anadarko would result in a material decline in our revenues and our cash available for distribution. In addition, Anadarko may reduce its drilling activity in our areas of operation or determine that drilling activity in other areas of operation is strategically more attractive. A shift in Anadarko’s focus away from our areas of operation could result in reduced throughput on our system and a material decline in our revenues and cash available for distribution.

Because of the natural decline in production from existing wells, our success depends on our ability to obtain new sources of natural gas, which is dependent on certain factors beyond our control. Any decrease in the volumes of natural gas that we gather, process, compress, treat and transport could adversely affect our business and operating results.

The volumes that support our business are dependent on the level of production from natural gas wells connected to our gathering systems and processing and treatment facilities. This production will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our gathering systems, we must obtain new sources of natural gas. The primary factors affecting our ability to obtain sources of natural gas include (i) the level of successful drilling activity near our systems, (ii) our ability to compete for volumes from successful new wells, to the extent such wells are not dedicated to our systems, and (iii) our ability to capture volumes currently gathered or processed by third parties.

While Anadarko has dedicated production from certain of its properties to us, we have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our gathering systems or the rate at which production from a well declines. In addition, we have no control over Anadarko or other producers or their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, prevailing and projected commodity prices, demand for hydrocarbons, levels of reserves, geological considerations, governmental regulations, the availability of drilling rigs and other production and development costs. Fluctuations in commodity prices can also greatly affect investments by Anadarko and third parties in the development of new natural gas reserves. Declines in natural gas prices could have a negative impact on exploration, development and production activity and, if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in our areas of operation would lead to reduced utilization of our gathering and treating assets.

Because of these factors, even if new natural gas reserves are known to exist in areas served by our assets, producers (including Anadarko) may choose not to develop those reserves. Moreover, Anadarko may not develop the acreage it has dedicated to us. If competition or reductions in drilling activity result in our inability to maintain the current levels of throughput on our systems, it could reduce our revenue and impair our ability to make cash distributions to our unitholders.

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution to holders of our common and subordinated units.

In order to pay the minimum quarterly distribution of $0.30 per unit per quarter, or $1.20 per unit per year, we will require available cash of approximately $17.0 million per quarter, or $68.1 million per year, based on the number of general partner units and common and subordinated units outstanding at December 31, 2008. We may not have sufficient available cash from operating surplus each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

	•		the prices of, level of production of, and demand for natural gas;
	•		the volume of natural gas we gather, compress, treat, process and transport;
	•		the volumes and prices of 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;
	•		the level of our operating and maintenance and general and administrative costs;
	•		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.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, including the following, some of which are beyond our control:

	•		the level of capital expenditures we make;
	•		our debt service requirements and other liabilities;
	•		fluctuations in our working capital needs;
	•		our ability to borrow funds and access capital markets;
	•		restrictions contained in debt agreements to which we are a party; and
	•		the amount of cash reserves established by our general partner.

Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.

Recently, concerns over inflation, energy costs, geopolitical issues, the availability and cost of credit, the U.S. mortgage market and a declining real estate market in the U.S. have contributed to increased economic uncertainty and diminished expectations for the global economy.

These factors, combined with volatile oil, natural gas and NGLs prices, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad continues to deteriorate, demand for petroleum products could continue to diminish and prices for oil, natural gas and NGLs could continue to decrease, which could reduce the throughput on our systems, affect our vendors’, suppliers’ and customers’ ability to continue operations, and adversely impact our results of operations, liquidity and financial condition.

Lower natural gas and oil prices could adversely affect our business.

Lower natural gas and oil prices could impact natural gas and oil exploration and production activity levels and result in a decline in the production of natural gas and condensate, resulting in reduced throughput on our systems. Any such decline may cause our current or potential customers to delay drilling or shut in production. In addition, such a decline would reduce the amount of NGLs and condensate we retain and sell. As a result, lower natural gas prices could have an adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

In general terms, the prices of natural gas, oil, condensate, NGLs and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include:

	•		worldwide economic conditions;
	•		weather conditions and seasonal trends;
	•		the levels of domestic production and consumer demand;
	•		the availability of imported liquefied natural gas, or LNG;
	•		the availability of transportation systems with adequate capacity;
	•		the volatility and uncertainty of regional pricing differentials such as in the Mid-Continent or Rocky Mountains;
	•		the price and availability of alternative fuels;
	•		the effect of energy conservation measures;
	•		the nature and extent of governmental regulation and taxation; and
	•		the anticipated future prices of natural gas, NGLs and other commodities.

We may not be able to obtain funding, obtain funding on acceptable terms or obtain funding under Anadarko’s $1.3 billion credit facility because of the deterioration of the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.

Global financial markets and economic conditions have been, and continue to be volatile. The debt and equity capital markets have been exceedingly distressed. These issues, along with significant write-offs in the financial services sector, the repricing of credit risk and the current weak economic conditions have made, and will likely continue to make, it difficult for some entities to obtain funding. In addition, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to the borrower’s current debt and reduced, or in some cases, ceased to provide funding to borrowers. In addition, we may be unable to obtain adequate funding under Anadarko’s $1.3 billion credit facility if (i) Anadarko’s lending counterparties become unwilling or unable to meet their funding obligations, (ii) Anadarko has to draw down on its entire $1.3 billion credit facility in order to meet its own capital needs or (iii) the amount we may borrow under Anadarko’s $1.3 billion credit facility is reduced for other reasons. Due to these factors, we cannot be certain

that funding will be available if needed and to the extent required, on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to execute our business plans, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our financial condition, results of operations or cash flows.

Limitations on our access to capital may impair our ability to execute our growth strategy.

Our ability to raise capital for acquisitions and other capital expenditures depends upon periodic ready access to the capital markets. In the future, we intend to finance our acquisitions and, to a much lesser extent, expansions of our gathering systems, through access to public and private debt and equity offerings. If we are unable to access the capital markets, we may be unable to execute our strategy of growth through acquisitions and expansions.

The amount of cash we have available for distribution to holders of our common and subordinated units depends primarily on our cash flow rather than on our profitability; accordingly, we may be prevented from making distributions, even during periods in which we record net income.

The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

The amount of available cash we need to pay the minimum quarterly distribution on all of our units and the corresponding distribution on our general partner’s 2.0% interest for four quarters is approximately $68.1 million.

We typically do not obtain independent evaluations of natural gas reserves connected to our gathering, processing and transportation systems; therefore, in the future, volumes of natural gas on our systems could be less than we anticipate.

We typically do not obtain independent evaluations of natural gas reserves connected to our systems. Accordingly, we do not have independent estimates of total reserves dedicated to our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our systems are less than we anticipate and we are unable to secure additional sources of natural gas, it could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.

We compete with similar enterprises in our areas of operation. Our competitors may expand or construct gathering, processing, compression, treating or transportation systems that would create additional competition for the services we provide to our customers. In addition, our customers, including Anadarko, may develop their own gathering, compression, treating, processing or transportation systems in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flow could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Our operating income could be affected by changes in commodity prices.

Under our gathering agreements, we retain and sell condensate, which falls out of the natural gas stream during the gathering process, and compensate shippers with a thermally equivalent volume of natural gas. Condensate sales comprised a nominal amount of our total revenues for the year ended December 31, 2008. The price we receive for our drip condensate correlates to the market price of oil. The relationship between natural gas prices and oil prices therefore affects the margin on our drip condensate sales. When natural gas prices are high relative to oil prices, the profit margin we realize on our drip condensate sales is low due to the higher value of natural gas. Correspondingly, when natural gas prices are low relative to oil prices, the profit margin is high.

Our strategies to reduce our exposure to changes in commodity prices may fail to protect us and could reduce our gross margin and cash flows.

We pursue various strategies to seek to reduce our exposure to adverse changes in the prices for natural gas and NGLs. These strategies will vary in scope based upon the level and volatility of natural gas and NGLs prices and other changing market conditions. Based on operating income for the year ended December 31, 2008, approximately 74% of our services are provided under long-term contracts with fee-based rates, which are not directly impacted by changes in commodity prices, and approximately 22% of our processing services are provided under percent-of-proceeds arrangements pursuant to which our revenues are directly correlated with the prices of natural gas and NGLs. We have entered into fixed-price swap agreements with Anadarko to manage the commodity price risk otherwise inherent in our percent-of-proceeds contracts. If we do not (or are unable to) effectively manage the commodity price risk associated with these contracts or are unable to replace the existing swap arrangements when they expire, our revenue will decline in periods marked by lower natural gas and NGLs prices. In addition, it is possible that the percentage of our services subject to percent-of-proceeds contracts may significantly increase as a result of future acquisitions, if any. Finally, future acquisitions may also result in our acquiring other commodity-price susceptible contracts, e.g., keep-whole arrangements, which could result in incremental commodity price exposure.

If third-party pipelines or other facilities interconnected to our gathering or transportation systems become partially or fully unavailable, or if the volumes we gather or transport do not meet the natural gas quality requirements of such pipelines or facilities, our revenues and cash available for distribution could be adversely affected.

Our natural gas gathering and transportation systems connect to other pipelines or facilities, the majority of which are owned by third parties. The continuing operation of such third-party pipelines or facilities is not within our control. If any of these pipelines or facilities becomes unable to transport natural gas, or if the volumes we gather or transport do not meet the natural gas quality requirements of such pipelines or facilities, our revenues and cash available for distribution could be adversely affected.

Our interstate natural gas transportation operations are subject to regulation by FERC, which could have an adverse impact on our ability to establish transportation rates that would allow us to earn a reasonable return on our investment, or even recover the full cost of operating our pipeline, thereby adversely impacting our ability to make distributions.

MIGC, our interstate natural gas transportation system, is subject to regulation by FERC under the Natural Gas Act of 1938, or the NGA, and the Energy Policy Act of 2005, or the EPAct 2005.

Under the NGA, FERC has the authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. Federal regulation extends to such matters as:

	•		rates, services and terms and conditions of service;
	•		the types of services MIGC may offer to its customers;
	•		the certification and construction of new facilities;
	•		the acquisition, extension, disposition or abandonment of facilities;
	•		the maintenance of accounts and records;
	•		relationships between affiliated companies involved in certain aspects of the natural gas business;
	•		the initiation and discontinuation of services;
	•		market manipulation in connection with interstate sales, purchases or transportation of natural gas; and
	•		participation by interstate pipelines in cash management arrangements.

Natural gas companies are prohibited from charging rates that have been determined to be not just and reasonable by FERC. In addition, FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.

The rates and terms and conditions for our interstate pipeline services are set forth in a FERC-approved tariff. Pursuant to FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. Any successful complaint or protest against our rates could have an adverse impact on our revenues associated with providing transportation service.

Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EPAct 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1,000,000 per day for each violation. FERC also has the power to order disgorgement of profits from transactions deemed to violate the NGA and EPAct 2005.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies could result in increased regulation of our assets, which could cause our revenues to decline and operating expenses to increase.

Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC. We believe that our natural gas pipelines, other than MIGC, meet the traditional tests FERC has used to determine if a pipeline is a gathering pipeline and is, therefore, not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial ongoing litigation and, over time, FERC policy concerning where to draw the line between activities it regulates and activities excluded from its regulation has changed. The classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. In recent years, FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies, which has resulted in a number of such companies transferring gathering facilities to unregulated affiliates. As a result of these activities, natural gas gathering may begin to receive greater regulatory scrutiny at both the state and federal levels.

FERC regulation of MIGC, including the outcome of certain FERC proceedings on the appropriate treatment of tax allowances included in regulated rates and the appropriate return on equity, may reduce our transportation revenues, affect our ability to include certain costs in regulated rates and increase our costs of operations, and thus adversely affect our cash available for distribution.

FERC has certain proceedings pending, which concern the appropriate allowance for income taxes that may be included in cost-based rates for FERC-regulated pipelines owned by publicly traded partnerships that do not directly pay federal income tax. FERC issued a policy permitting such tax allowances in 2005. FERC’s policy and its initial application in a specific case were upheld on appeal by the D.C. Circuit in May of 2007 and the D.C. Circuit’s decision is final. In December 2006, FERC issued another order addressing the income tax allowance in rates, in which it reaffirmed prior statements regarding its income tax allowance policy, but raised a new issue regarding the implication of the policy statement for publicly traded partnerships. FERC noted that the tax deferral features of a publicly traded partnership may cause some investors to receive, for some indeterminate duration, cash distributions in excess of their taxable income, creating an opportunity for those investors to earn an additional return, funded by ratepayers. Responding to this concern, FERC adjusted the equity rate of return of the pipeline at issue downward based on the percentage by which the publicly traded partnership’s cash flow exceeded taxable income. Further procedures have been ordered in this proceeding and the proceeding is still pending before FERC.

FERC issued a policy statement on April 17, 2008, regarding the composition of proxy groups for purposes of determining natural gas and oil pipeline equity returns to be included in cost-of-service based rates. In the policy statement, FERC determined that MLPs should be included in the proxy group used to determine return on equity, and made various determinations on how the Discounted Cash Flow, or DCF, methodology should be applied for MLPs. FERC also concluded that the policy statement should govern all gas and oil rate proceedings involving the establishment of return on equity that are pending before FERC. FERC’s application of the policy statement in individual pipeline proceedings is subject to challenge in those proceedings.

The ultimate outcome of these proceedings is not certain and may result in new policies being established at FERC applicable to MLPs. Any such policy developments may adversely affect the ability of MIGC to achieve a reasonable level of return or impose limits on its ability to include a full income tax allowance in cost of service, and therefore could adversely affect our cash available for distribution.

We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.

Our natural gas gathering, compression, treating, processing and transportation operations are subject to stringent and complex federal, state and local environmental laws and regulations that govern the discharge of materials into the environment or otherwise relate to environmental protection. Examples of these laws include:

	•		the federal Clean Air Act and analogous state laws that impose obligations related to air emissions;
	•		the federal Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or the Superfund law, and analogous state laws that require and regulate the cleanup of hazardous substances that have been released at properties currently or previously owned or operated by us or at locations to which our wastes are or have been transported for disposal;
	•		the federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws that regulate discharges from our facilities into state and federal waters, including wetlands;
	•		the federal Resource Conservation and Recovery Act, also known as RCRA, and analogous state laws that impose requirements for the storage, treatment and disposal of solid and hazardous waste from our facilities; and
	•		the Toxic Substances Control Act, also known as TSCA, and analogous state laws that impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities.

These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to limit or prevent releases of materials from our pipelines and facilities, and the imposition of substantial liabilities for pollution resulting from our operations or existing at our owned or operated facilities. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or the EPA, and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations.

There is an inherent risk of incurring significant environmental costs and liabilities in connection with our operations due to historical industry operations and waste disposal practices, our handling of hydrocarbon wastes and potential emissions and discharges related to our operations. Joint and several strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of substances or wastes on, under or from our properties and facilities, many of which have been used for midstream activities for many years, often by third parties not under our control. Private parties, including the owners of the properties through which our gathering or transportation systems pass and facilities where our wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations or financial position. Finally, future federal and/or state restrictions, caps, or taxes on greenhouse gas emissions that may be passed in response to climate-change concerns may impose additional capital investment requirements, increase our operating costs and reduce the demand for our services.

Our construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.

One of the ways we intend to grow our business is through the construction of new midstream assets. The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political and legal uncertainties that are beyond our control. Such expansion projects may also require the expenditure of significant amounts of capital, and financing may not be available on economically acceptable terms or at all. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand a pipeline, the construction may occur over an extended period of time, yet we will not receive any material increases in revenues until the project is completed. Moreover, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. Since we are not engaged in the exploration for and development of natural gas and oil reserves, we often do not have access to third-party estimates of potential reserves in an area prior to constructing facilities in that area. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate as a result of the numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not be able to attract enough throughput

to achieve our expected investment return, which could adversely affect our results of operations and financial condition. In addition, the construction of additions to our existing assets may require us to obtain new rights-of-way. We may be unable to obtain such rights-of-way and may, therefore, be unable to connect new natural gas volumes to our systems or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing existing or obtaining new rights-of-way increases, our cash flows could be adversely affected.

If Anadarko were to limit divestitures of midstream assets to us or if we were to be unable to make acquisitions on economically acceptable terms from Anadarko or third parties, our future growth would be limited, and the acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per-unit basis.

Our ability to grow depends, in part, on our ability to make acquisitions that increase our cash generated from operations on a per-unit basis. The acquisition component of our strategy is based, in large part, on our expectation of ongoing divestitures of midstream energy assets by industry participants, including, most notably, Anadarko. A material decrease in such divestitures would limit our opportunities for future acquisitions and could adversely affect our ability to grow our operations and increase our distributions to our unitholders.

If we are unable to make accretive acquisitions from Anadarko or third parties, either because we are (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts, (ii) unable to obtain financing for these acquisitions on economically acceptable terms or (iii) outbid by competitors, then our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per-unit basis.

Any acquisition involves potential risks, including, among other things:

	•		mistaken assumptions about volumes, revenues and costs, including synergies;
	•		an inability to successfully integrate the assets or businesses we acquire;
	•		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.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

We have a partial ownership interest in Fort Union, which limits our ability to operate and control this entity. In addition, we may be unable to control the amount of operating cash flow we will receive from this entity and we may be required to contribute a significant amount of cash to fund our share of its operations, which could adversely affect our ability to make cash distributions to our unitholders.

We own a 14.81% non-managing membership interest in Fort Union. Thus, our inability or limited ability to control the operations and management of Fort Union could cause us not to receive the amount of cash we expect to be distributed to us. Specifically, the following items may reduce cash available for distribution to us from Fort Union:

	•		we are unable to control the ongoing operational decisions of Fort Union, including the incurrence of capital expenditures;
	•		we have limited ability to control decisions with respect to the operations of Fort Union, including decisions with respect to distributions to us;
	•		Fort Union may establish reserves for working capital, capital projects, environmental matters and legal proceedings, which reserves would reduce the amount of cash available for distribution by Fort Union; and

•

Fort Union may incur additional indebtedness, whereby required principal and interest payments may reduce the amount of cash available for distribution by Fort Union.

Any of the above could significantly and adversely impact our ability to make cash distributions to our unitholders.

We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.

We do not own all of the land on which our pipelines and facilities have been constructed, and we are, therefore, subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not fully insured, our operations and financial results could be adversely affected.

Our operations are subject to all of the risks and hazards inherent in the gathering, compressing, processing, treating and transportation of natural gas, including:

	•		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 and loss of life, pollution and suspension of operations.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent in our business. For example, we do not have any property insurance on our underground pipeline systems that would cover damage to the pipelines. In addition, although we are insured for environmental pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might incur, some of which may result in toxic tort claims. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to certain indemnification rights, for potential environmental liabilities.

We are exposed to the credit risk of Anadarko and third-party customers, and any material non-payment or non-performance by these parties, including with respect to our gathering, processing and transportation agreements, our $260.0 million note receivable from Anadarko and our commodity price swap agreements with Anadarko, could reduce our ability to make distributions to our unitholders.

We are dependent on Anadarko for the majority of our revenues. Consequently, we are subject to the risk of non-payment or non-performance by Anadarko, including with respect to our gathering and transportation agreements, our $260.0 million note receivable and our commodity price swap agreements. Any such non-payment or non-performance could reduce our ability to make distributions to our unitholders. Furthermore, Anadarko is subject to its own financial, operating and regulatory risks, which could increase the risk of default on its obligations to us. We cannot predict the extent to which

Anadarko’s business would be impacted if conditions in the energy industry were to continue to deteriorate, nor can we estimate the impact such conditions would have on Anadarko’s ability to perform under our gathering and transportation agreements, note receivable or our commodity price swap agreements. Further, unless and until we receive full repayment of the $260.0 million note receivable from Anadarko, we will be subject to the risk of non-payment or late payment of the interest payments and principal of the note. Accordingly, any material non-payment or non-performance by Anadarko could reduce our ability to make distributions to our unitholders.

With respect to our Hilight and Newcastle systems, we rely on a significant number of third-party customers for substantially all of our revenues related to those assets. The loss of all or even a portion of the contracted volumes of these customers, as a result of competition, creditworthiness, inability to negotiate extensions, or replacements of contracts or otherwise, could reduce our ability to make cash distributions to our unitholders.

Anadarko’s credit facility and other debt instruments contain financial and operating restrictions that may limit our access to credit. In addition, our ability to obtain credit in the future may be affected by Anadarko’s credit rating.

We have the ability to incur up to $100.0 million of indebtedness under Anadarko’s $1.3 billion credit facility. However, this $100.0 million of borrowing capacity will be available to us only to the extent that sufficient amounts remain unborrowed by Anadarko. As a result, borrowings by Anadarko could restrict our access to credit. In addition, if we or Anadarko were to fail to comply with the terms of this credit facility, we could be unable to make any borrowings under Anadarko’s credit facility, even if capacity were otherwise available. As a result, the restrictions in Anadarko’s credit facility could adversely affect our ability to finance our future operations or capital needs or to engage in, expand or pursue our business activities, and could also prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.

Anadarko’s and our ability to comply with the terms of its and our respective debt instruments may be affected by events beyond its and our control, including prevailing economic, financial and industry conditions. We and Anadarko are subject to covenants, and Anadarko is subject to a debt-to-capitalization ratio, under Anadarko’s credit facility. Should we or Anadarko fail to comply with any covenants under Anadarko’s credit facility, we could be unable to make any borrowings under that credit facility. Additionally, a default by Anadarko under one of its debt instruments may cause a cross-default under Anadarko’s other debt instruments, including the credit facility under which we are a co-borrower. Accordingly, a breach by Anadarko of certain of the covenants or ratios in another debt instrument could cause the acceleration of any indebtedness we have outstanding under the credit facility. In the event of an acceleration, we might not have, or be able to obtain, sufficient funds to make the required repayments of debt, finance our operations and pay distributions to unitholders. For more information regarding our debt agreements, please read Item 7–Management’s discussion and analysis of financial condition and results of operations–Liquidity and capital resources.

Due to our relationship with Anadarko, our ability to obtain credit will be affected by Anadarko’s credit rating. Even if we obtain our own credit rating or separate financing arrangement, any future change in Anadarko’s credit rating would likely also result in a change in our credit rating. Regardless of whether we have our own credit rating, a downgrading of Anadarko’s credit rating could limit our ability to obtain financing in the future upon favorable terms or at all.

Debt we owe or incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.

Future levels of indebtedness, including that we owe through our $175.0 million term loan with Anadarko, could have important consequences to us, including the following:

	•		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 flow 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.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.

Increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

Interest rates may increase in the future, whether because of inflation, increased yields on U.S. Treasury obligations or otherwise. In such cases, the interest rate on our five-year $175.0 million term loan with Anadarko, which after December 2010 will be calculated at a floating rate equal to three-month LIBOR plus 150 basis points, would increase. If interest rates rise, our future financing costs could increase accordingly. In addition, as is true with other MLPs (the common units of which are often viewed by investors as yield-oriented securities), our unit price is impacted by our level of cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

RISKS INHERENT IN AN INVESTMENT IN US

Anadarko owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Anadarko and our general partner have conflicts of interest with, and may favor Anadarko’s interests to the detriment of our unitholders.

Anadarko owns and controls our general partner and has the power to appoint all of the officers and directors of our general partner, some of whom are also officers of Anadarko. Although our general partner has a fiduciary duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to its owner, Anadarko. Conflicts of interest may arise between Anadarko and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of Anadarko over our interests and the interests of our unitholders. These conflicts include the following situations, among others:

	•		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 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.
	•		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 and the ability of the subordinated units to convert to common units.
	•		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 a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.

	•		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 on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights.
	•		Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.
	•		Our general partner intends to limit its liability regarding our contractual and other obligations.
	•		Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units.
	•		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 our general partner’s incentive distribution rights 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.

Please read Item 13—Certain Relationships and Related Transactions, and Director Independence.

Anadarko is not limited in its ability to compete with us and is not obligated to offer us the opportunity to acquire additional assets or businesses, which could limit our ability to grow and could adversely affect our results of operations and cash available for distribution to our unitholders.

Anadarko is not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, in the future, Anadarko may acquire, construct or dispose of additional midstream or other assets and may be presented with new business opportunities, without any obligation to offer us the opportunity to purchase or construct such assets or to engage in such business opportunities. Moreover, while Anadarko may offer us the opportunity to buy additional assets from it, it is under no contractual obligation to do so and we are unable to predict whether or when such acquisitions might be completed.

Cost reimbursements due to Anadarko and our general partner for services provided to us or on our behalf will be substantial and will reduce our cash available for distribution to our unitholders. The amount and timing of such reimbursements will be determined by our general partner.

Prior to making distributions on our common units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf. These expenses will include all costs incurred by Anadarko and our general partner in managing and operating us. While our reimbursement of allocated general and administrative expenses is capped until December 31, 2009 under the omnibus agreement, we are required to reimburse Anadarko and our general partner for all direct operating expenses incurred on our behalf. These direct operating expense reimbursements and the reimbursement of incremental general and administrative expenses we will incur as a result of being a publicly traded partnership are not capped. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursements to Anadarko and our general partner will reduce the amount of cash otherwise available for distribution to our unitholders.

If you are not an Eligible Holder, you may not receive distributions or allocations of income or loss on your common units and your common units will be subject to redemption.

We have adopted certain requirements regarding those investors who may own our common and subordinated units. Eligible Holders are U.S. individuals or entities subject to U.S. federal income taxation on the income generated by us or entities not subject to U.S. federal income taxation on the income generated by us, so long as all of the entity’s owners are U.S. individuals or entities subject to such taxation. If you are not an Eligible Holder, our general partner may elect not to make distributions or allocate income or loss on your units and you run the risk of having your units redeemed by us at the lower of your purchase price cost and the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

Our general partner’s liability regarding our obligations is limited.

Our general partner included provisions in its and our contractual arrangements that limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. Furthermore, we used substantially all of the net proceeds from our initial public offering to make a loan to Anadarko, and therefore, the net proceeds from our initial public offering was not used to grow our business.

In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per-unit distribution level. There are no limitations in our partnership agreement or in Anadarko’s credit facility, under which we are a co-borrower, on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.

Our partnership agreement limits our general partner’s fiduciary duties to holders of our common and subordinated units.

Our partnership agreement contains provisions that modify and reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

	•		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;
	•		whether to exercise its registration rights;
	•		whether to elect to reset target distribution levels; and
	•		whether or not to consent to any merger or consolidation of the Partnership or amendment to the partnership agreement.

By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above.

Our partnership agreement restricts the remedies available to holders of our common and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement:

	•		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 our partnership;
	•		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 fiduciary duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is:

	(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.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the special committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in subclauses (c) and (d) above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Our general partner may elect to cause us to issue Class B and general partner units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the special committee of its board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.

Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of Class B units and general partner units. The Class B units will be entitled to the same cash distributions per unit as our common units and will be convertible into an equal number of common units. The number of Class B units to be issued to our general partner will be equal to that number of common units which would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Our general partner will be issued the number of general partner units necessary

to maintain our general partner’s interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued Class B units, which are entitled to distributions on the same priority as our common units, rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new Class B units and general partner units to our general partner in connection with resetting the target distribution levels.

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner will be chosen by Anadarko. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

The unitholders initially will be unable to remove our general partner without its consent because our general partner and its affiliates currently own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 ⅔% of all outstanding limited partner units voting together as a single class is required to remove our general partner. As of February 27, 2009, Anadarko owns 62.6% of our outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud, gross negligence or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of the unitholder’s dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.

Our partnership agreement restricts the voting rights of certain unitholders owning 20% or more of our common units.

Unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of Anadarko to transfer all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers.

We may issue additional units without unitholder approval, which would dilute existing ownership interests.

Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

	•		our existing unitholders’ proportionate ownership interest in us will decrease;
	•		the amount of cash available for distribution on each unit may decrease;
	•		because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
	•		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.

Anadarko may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

As of February 27, 2009, Anadarko holds an aggregate of 8,282,322 common units and 26,536,306 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier under certain circumstances. The sale of any or all of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market on which common units are traded.

Our general partner has a limited call right that may require existing unitholders to sell their units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price. As a result, existing unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Existing unitholders may also incur a tax liability upon a sale of their units. As of February 27, 2009, Anadarko owns approximately 28.5% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (other than upon the conversion of the subordinated units), Anadarko will own approximately 62.6% of our outstanding common units.

Unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for any and all of our obligations as if that unitholder were a general partner if a court or government agency were to determine that:

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

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were

unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.

We incur increased costs as a result of being a publicly traded partnership.

We have no history operating as a publicly traded partnership prior to our initial public offering. As a publicly traded partnership, we incur significant legal, accounting and other expenses. In addition, the Sarbanes-Oxley Act of 2002 and related rules subsequently implemented by the SEC and the New York Stock Exchange, or the NYSE, have required changes in the corporate governance practices of publicly traded companies. We expect these rules and regulations to increase our legal and financial compliance costs compared to our historical costs and to make activities more time-consuming and costly.

If we are deemed to be an “investment company” under the Investment Company Act of 1940, it would adversely affect the price of our common units and could have a material adverse effect on our business.

Our assets include, among other items, a $260.0 million note receivable from Anadarko. If this note receivable together with a sufficient amount of our other assets are deemed to be “investment securities,” within the meaning of the Investment Company Act of 1940, or the Investment Company Act, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify our organizational structure or contract rights so as to fall outside of the definition of investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property from or to our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates. The occurrence of some or all of these events would adversely affect the price of our common units and could have a material adverse effect on our business.

Moreover, treatment of us as an investment company would prevent our qualification as a partnership for federal income tax purposes, in which case we would be treated as a corporation for federal income tax purposes. As a result, we would pay federal income tax on our taxable income at the corporate tax rate, distributions to our unitholders would generally be taxed again as corporate distributions and none of our income, gains, losses or deductions would flow through to our unitholders. If we were taxed as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as an investment company would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

We expect to amend our partnership agreement to provide that any net termination losses treated as arising during the subordination period as a result of an adjustment to the carrying value of our assets in connection with an issuance by us of additional units will be allocated among the holders of subordinated units and common units in proportion to their percentage interests. As a result of this amendment, if we liquidate during the subordination period, it is possible there would be less net termination gain to be allocated to unitholders holding common units, resulting in those unitholders receiving less liquidation proceeds than under our current partnership agreement. In order to mitigate the possibility of adverse consequences to our common units of this revised allocation, we also intend to amend our partnership agreement to provide that, in the event we liquidate during the subordination period, we will allocate items of income, gain, loss and deduction that would otherwise be included in the computation of net termination gain or net termination loss and, if necessary, items included in our net income or net losses, in each case to the extent possible, so that the capital account of each common unit will equal the amount it would have been had we not amended our partnership agreement. In the unlikely event that we liquidate during the subordination period and we do not have sufficient items included in net termination gain, net termination loss, or other items of income, gain, loss and deduction, as the case may be, to cause the capital account in respect of each common unit to equal this amount, unitholders holding common units could receive less liquidation proceeds than under our current partnership agreement.

Our partnership agreement currently provides that any net termination loss, as defined in the partnership agreement, deemed recognized during the subordination period as the result of an adjustment to the carrying value of our assets in connection with an issuance of additional units will first be allocated to the general partner and unitholders holding subordinated units until the capital account with respect to each subordinated unit has been reduced to zero. Under our current partnership agreement, an issuance of additional units at a time when our common units are trading at a price lower than the capital account balance of our then outstanding common units may require us to adjust the carrying value of our property to an amount that causes the capital account with respect to each of our (i) subordinated units to equal zero and (ii) existing common units to equal the then-current trading price of common units.

While the existing allocation provisions are intended to preserve the senior economic position of our common units during the subordination period, they may also have the effect of causing the holders of our common units to suffer adverse tax consequences. A “book down” of our assets that results in the capital account in respect of each subordinated unit equaling zero would require a substantial reduction in the carrying value of our property. As a result of such a book down and because we have adopted the “remedial allocation method” with respect to the depreciation and amortization of our assets, the amount of tax depreciation and amortization allocated to holders of our common units could be substantially reduced. There would be a corresponding reduction in the amount of taxable income allocated to the holders of subordinated units.

In order to mitigate the possibility of this adverse tax effect to the common units and corresponding benefit to the subordinated units, we expect to amend our partnership agreement to provide that any net termination loss, as defined in the partnership agreement, deemed to be recognized by us during the subordination period as a result of a book down in the carrying value of our assets will be allocated pro rata to the holders of common units and subordinated units. This amendment will not affect the amount of the reduction in the capital account with respect to a common unit resulting from a book down. Under both the current partnership agreement and the amended partnership agreement, the capital account with respect to each existing common unit will be decreased to the trading price of common units existing at the time of the contribution to us that requires us to book down the carrying value of our assets. The amendment will reduce (perhaps substantially) the amount of the book down in the carrying value of our assets, as well as the amount of the resulting reduction in tax depreciation allocable to holders of common units that would otherwise occur pursuant to the book down provisions contained in the current partnership agreement.

While the amount of the decrease in the capital account of an existing holder of common units will not be affected by the amendment to our partnership agreement, the potential amount of net termination gain recognized by us if we liquidate during the subordination period may be substantially reduced as a result of the amendment. Therefore, our amended partnership agreement will provide that upon a liquidation during the subordination period, we will specially allocate items included in net termination gain or net termination loss and, if necessary, items of income, gain, loss and deduction that would otherwise be included in our net income or net losses, in each case to the maximum extent possible, to cause the capital account of each common unit to equal the amount the capital account would have been had we not amended our partnership agreement. In the unlikely event that we liquidate during the subordination period and we do not have sufficient items included in net termination gain, net termination loss, or other items of income, gain, loss and deduction, as the case may be, to cause the capital account in respect of each common unit to equal this amount, unitholders holding common units could receive less liquidation proceeds than under our current partnership agreement.

TAX RISKS TO COMMON UNITHOLDERS

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders could be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, or the IRS, on this or any other tax matter affecting us.

Despite the fact that we are classified as a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe, based upon our current operations, that we will be so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to a material amount of entity-level taxation at the state or federal level. In addition, if we are deemed to be an investment company, as described above, we would be subject to such taxation.

At the state level, were we to be subject to federal income tax, we would also be subject to the income tax provisions of many states. Moreover, because of widespread state budget deficits and other reasons, several states are evaluating ways to independently subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay Texas margin tax at a maximum effective rate of 0.7% of our gross income apportioned to Texas. Imposition of such a tax on us by Texas and, if applicable, by any other state will reduce the cash available for distribution to our unitholders.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the U.S. federal income tax laws or interpretations thereof could make it more difficult or impossible to meet the requirements for us to be treated as a partnership for U.S. federal income tax purposes, affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our common units. Modifications to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively. We are unable to predict any particular change. Any potential change in law or interpretation thereof could negatively impact the value of an investment in our common units.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

If the IRS contests the federal income tax positions we take or the pricing of our related party agreements with Anadarko, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us, including the pricing of our related party agreements with Anadarko. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of or the positions we take. A court may not agree with some or all of the positions we take. For example, the IRS may reallocate items of income, deductions, credits or allowances between related parties if the IRS determines that such reallocation is necessary to prevent evasion of taxes or clearly to reflect the income of any such related parties. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. If the IRS were successful in any such challenge, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders and our general partner. Such a reallocation may require us and our unitholders to file amended tax returns. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

Our unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income whether or not our unitholders receive cash distributions from us.

Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If a unitholder disposes of common units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and that unitholder’s tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease that unitholder’s tax basis in its common units, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxable income to her, if she sells such units at a price greater than her tax basis in those units, even if the price received is less than the original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells her units, she may incur a tax liability in excess of the amount of cash received from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. Any tax-exempt entity or a non-U.S. person should consult its tax advisor before investing in our common units.

We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units, we adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. Our counsel is unable to opine on the validity of such filing positions. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from any sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to a unitholder’s tax returns.

We adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between our general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation

deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in the unitholder’s taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties, if we are unable to determine that a termination occurred.

Our unitholders are subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our common units.

In addition to federal income taxes, our unitholders are subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own assets and conduct business in the states of Kansas, Oklahoma, Texas, Utah and Wyoming. Each of these states, other than Texas and Wyoming, currently imposes a personal income tax, and all of these states impose income taxes on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is the responsibility of each unitholder to file all required U.S. federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units.

Item 1B. Unresolved Staff Comments

None

Item 3. Legal Proceedings

We are not a party to any legal proceeding other than legal proceedings arising in the ordinary course of our business. We are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business. Please see Items 1 and 2—Business and Properties, in this Form 10-K for more information.

Item 4. Submission of Matters to a Vote of Security Holders

None

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

MARKET INFORMATION

Our common units are listed on the New York Stock Exchange under the symbol “WES.” Common units began trading on May 9, 2008, at an initial offering price of $16.50 per unit. Prior to May 9, 2008, our equity securities were not listed on any exchange or traded in any public market. The following table sets forth the high and low closing prices of the common units as well as the amount of cash distributions declared and paid for each quarter since our initial public offering.

		Quarter Ended				Quarter Ended				Quarter Ended
		December 31,				September 30,				June 30,
		2008				2008				2008
High Price		$	15.17			$	16.96			$	17.25
Low Price		$	10.58			$	13.02			$	16.15
Distribution per common unit		$	0.30			$	0.1582				—
Distribution per subordinated unit		$	0.30			$	0.1582				—

As of February 27, 2009, there were approximately 12 unitholders of record of the Partnership’s common units. This number does not include unitholders whose units are held in trust by other entities. The actual number of unitholders is greater than the number of holders of record.

We have also issued 26,536,306 subordinated units and 1,135,296 general partner units, for which there is no established public trading market. All of the subordinated units and general partner units are held by affiliates of our general partner. Our general partner and its affiliates receive quarterly distributions on these units only after sufficient funds have been paid to the common units.

USE OF PROCEEDS FROM SALE OF SECURITIES

We completed our initial public offering of 20,810,875 common units, including 2,060,875 common units sold pursuant to the partial exercise by the underwriters of their option to purchase additional common units, representing limited partnership interests in us at a price of $16.50 per unit. In connection with the offering, we issued to our general partner 1,083,115 general partner units and 100% of our IDRs, which entitle our general partner to increasing percentages up to a maximum of 50.0% of cash distributions based on the amount of the quarterly cash distribution. We also issued 5,725,431 common units and 26,536,306 subordinated units to a subsidiary of Anadarko. Subsidiaries of Anadarko contributed our initial assets to us in connection with the offering.

Net proceeds of $321.1 million (net of $22.3 million of underwriting discount and structuring fees) from our initial public offering were used (i) to pay approximately $5.9 million in expenses associated with the offering and the transactions related thereto, (ii) to make a loan of $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.5%, (iii) to reimburse Anadarko $45.2 million from offering proceeds and (iv) retained $10.0 million for general partnership purposes.

SELECTED INFORMATION FROM OUR PARTNERSHIP AGREEMENT

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions, minimum quarterly distributions and IDRs.

Available cash

The partnership agreement requires that, within 45 days subsequent to the end of each quarter, beginning with the quarter ended June 30, 2008, the Partnership distribute all of its available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. The amount of available cash generally is all cash on hand at the end of the quarter less the amount of cash reserves established by our general partner to provide for the proper conduct of our business, including reserves to fund future capital expenditures, to comply with applicable laws, or our debt instruments and other agreements, or to provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters. Working capital borrowings generally include borrowings made under a credit facility or similar financing arrangement.

Minimum quarterly distributions

The partnership agreement provides that, during a period of time referred to as the “subordination period,” the common units are entitled to distributions of available cash each quarter in an amount equal to the “minimum quarterly distribution,” which is $0.30 per common unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash are permitted on the subordinated units. Furthermore, arrearages do not apply to and therefore will not be paid on the subordinated units. The effect of the subordinated units is to increase the likelihood that, during the subordination period, available cash is sufficient to fully fund cash distributions on the common units in an amount equal to the minimum quarterly distribution.

The subordination period will lapse at such time when the Partnership has paid at least $0.30 per quarter on each common unit, subordinated unit and general partner unit for any three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2011. Also, if the Partnership has paid at least $0.45 per quarter (150% of the minimum quarterly distribution) on each outstanding common unit, subordinated unit and general partner unit for each calendar quarter in a four-quarter period, the subordination period will terminate automatically. The subordination period will also terminate automatically if the general partner is removed without cause and the units held by the general partner and its affiliates are not voted in favor of such removal. When the subordination period lapses or otherwise terminates, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to preferred distributions on prior-quarter distribution arrearages. All subordinated units are held indirectly by Anadarko.

General partner interest and incentive distribution rights

The general partner is currently entitled to 2.0% of all quarterly distributions that the Partnership makes prior to its liquidation. After distributing amounts equal to the minimum quarterly distribution to common and subordinated unitholders and distributing amounts to eliminate any arrearages to common unitholders, our general partner is entitled to incentive distributions pursuant to its ownership of our IDRs if the amount we distribute with respect to any quarter exceeds specified target levels shown below:

				Marginal Percentage
		Total Quarterly Distribution		Interest in Distributions
		Target Amount		Unitholders				General Partner
Minimum Quarterly Distribution		$0.300			98	%			2	%
First Target Distribution		up to $0.345			98	%			2	%
Second Target Distribution		above $0.345 up to $0.375			85	%			15	%
Third Target distribution		above $0.375 up to $0.450			75	%			25	%
Thereafter		above $0.45			50	%			50	%

The table above assumes that our general partner maintains its 2% general partner interest, that there are no arrearages on common units and our general partner continues to own the IDRs. The maximum distribution sharing percentage of 50.0% includes distributions paid to the general partner on its 2.0% general partner interest and does not include any distributions that the general partner may receive on limited partner units that it may own or acquire.

OTHER SECURITY MATTERS

Sales of Unregistered Units

On December 19, 2008, we acquired certain midstream assets from Anadarko for consideration consisting of $175.0 million cash, 2,556,891 of our common units and 52,181 of our general partner units. The common units and general partner units issued in connection with the acquisition were issued to subsidiaries of Anadarko Petroleum Corporation in a private placement and the issuance was not registered with the SEC.

Securities Authorized for Issuance Under Equity Compensation Plans

In connection with the closing of our initial public offering, our general partner adopted the Western Gas Partners, LP 2008 Long-Term Incentive Plan, or LTIP, which permits the issuance of up to 2,250,000 units. Phantom unit grants have been made to each of the independent directors of our general partner under the LTIP. Please read the information under Item 12—Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters of this report, which is incorporated by reference into this Item 5.

Repurchase of Equity

None

Item 6. Selected Financial and Operating Data

The following table shows our selected financial and operating data for the periods and as of the dates indicated, which is derived from our consolidated financial statements. On May 14, 2008, we closed our initial public offering of 18,750,000 common units. Concurrent with the closing of the offering, Anadarko contributed to us the assets and liabilities of the Predecessor, which were comprised of AGC, PGT and MIGC, which we refer to as our initial assets. On June 11, 2008, we issued an additional 2,060,875 common units to the public and 751,625 common units to Anadarko in connection with the partial exercise of the underwriters’ over-allotment option. On December 19, 2008, we closed the Powder River acquisition with Anadarko. Anadarko acquired MIGC and the Powder River assets in connection with its August 23, 2006 acquisition of Western.

Our acquisition of the initial assets and the Powder River acquisition are considered transfers of net assets between entities under common control. Accordingly, our consolidated financial statements include the combined financial results and operations of AGC and PGT from their inception through the closing date of our initial public offering and to the Partnership’s consolidated financial statements thereafter, combined with the financial results and operations of MIGC and the Powder River acquisition from August 23, 2006 thereafter.

The information in the following table should be read together with Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Form 10-K.

		Summary Financial Information
		2008				2007(1)				2006(1)				2005				2004
		(in thousands, except per unit data)
Statement of Income Data:
Total revenues		$	311,648			$	261,493			$	128,610			$	71,650			$	68,049
Costs and expenses			199,566				166,994				80,752				35,720				31,301
Depreciation and impairment			42,365				30,481				20,230				15,447				14,841
Total operating expenses			241,931				197,475				100,982				51,167				46,142
Operating income			69,717				64,018				27,628				20,483				21,907
Interest income (expense), net			9,191				(7,805	)			(9,574	)			(8,650	)			(7,146	)
Other income (expense), net			145				(15	)			(26	)			66				—
Income tax expense (2)			13,777				19,540				5,327				4,789				5,504
Net income		$	65,276			$	36,658			$	12,701			$	7,110			$	9,257
Gross margin (3)		$	159,716			$	140,666			$	83,235			$	64,841			$	63,065
General partner interest in net income (4)		$	842				n/a				n/a				n/a				n/a
Common unitholders’ interest in net income (4)		$	20,841				n/a				n/a				n/a				n/a
Subordinated unitholders’ interest in net income (4)		$	20,420				n/a				n/a				n/a				n/a
Net income per common unit (basic and diluted)		$	0.78				n/a				n/a				n/a				n/a
Net income per subordinated unit (basic and diluted)		$	0.77				n/a				n/a				n/a				n/a
Distributions per unit		$	0.46				n/a				n/a				n/a				n/a
Balance Sheet Data (at period end):
Property, plant and equipment, net		$	517,815			$	511,775			$	464,919			$	200,451			$	196,065
Total assets			856,441				544,318				504,383				206,373				199,110
Total long-term liabilities			185,146				139,801				140,071				37,664				30,573
Total partners’ capital and parent net equity		$	654,954			$	392,140			$	352,578			$	160,585			$	162,542
Cash Flow Data:
Net cash provided by (used in):
Operating activities		$	109,796			$	72,908			$	33,304			$	30,131			$	31,160
Investing activities			(479,959	)			(54,328	)			(42,963	)			(21,076	)			(16,548	)
Financing activities			403,469				(19,038	)			10,113				(9,067	)			(14,596	)
Adjusted EBITDA(5)			112,474				91,830				47,239				35,930				36,748
Capital expenditures, net		$	36,864			$	54,328			$	42,963			$	20,841			$	16,548
Operating Data:
Affiliate
Gathering throughput (MMcf/d)			831				917				891				757				715
Third Party
Gathering throughput (MMcf/d)			135				90				80				41				31
Processing throughput (MMcf/d)			30				30				30				—				—
Total
Gathering throughput (MMcf/d)			966				1,007				971				798				746
Processing throughput (MMcf/d)			30				30				30				—				—
Average gross margin per Mcf		$	0.44			$	0.37			$	0.23			$	0.22			$	0.23

NON-GAAP FINANCIAL MEASURES

Adjusted EBITDA

We define Adjusted EBITDA as net income (loss), plus distributions from equity investee, interest expense, income tax expense and depreciation, less income from equity investments, interest income, income tax benefit and other income (expense). We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations and that Adjusted EBITDA is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures and make distributions. Adjusted EBITDA is a supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:

	•		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.

Reconciliation to GAAP measures

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

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

The following tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measures of net income and net cash provided by operating activities:

		Summary Financial Information
		2008				2007(1)				2006(1)				2005				2004
		(in thousands)
Reconciliation of Adjusted EBITDA to net income
Adjusted EBITDA		$	112,474			$	91,830			$	47,239			$	35,930			$	36,748
Less:
Distributions from equity investee			5,128				1,348				741				—				—
Interest expense, net — affiliates			1,259				7,805				9,574				8,650				7,146
Interest expense from note — affiliate			253				—				—				—				—
Income tax expense			13,777				19,540				5,327				4,789				5,504
Depreciation and impairment			42,365				30,481				20,230				15,447				14,841
Other expense, net			—				15				26				—				—
Add:
Equity income, net			4,736				4,017				1,360				—				—
Interest income from note — affiliate			10,703				—				—				—				—
Other income			145				—				—				66				—
Net income		$	65,276			$	36,658			$	12,701			$	7,110			$	9,257
Reconciliation of Adjusted EBITDA to Net Cash Provided by Operating Activities
Adjusted EBITDA		$	112,474			$	91,830			$	47,239			$	35,930			$	36,748
Interest income (expense), net — affiliates			9,191				(7,805	)			(9,574	)			(8,650	)			(7,146	)
Current income tax expense			(12,153	)			(8,724	)			(2,101	)			—				—
Other income (expense), net			145				(15	)			(26	)			66				—
Distributions from equity investee in excess of equity income, net			(392	)			2,669				619				—				—
Changes in operating working capital:
Accounts receivable and natural gas imbalances			(4,959	)			(3,692	)			2,037				(662	)			933
Accounts payable and accrued expenses			4,840				142				(4,312	)			3,373				(551	)
Other, including changes in non-current assets and liabilities			650				(1,497	)			(578	)			74				1,176
Net cash provided by operating activities		$	109,796			$	72,908			$	33,304			$	30,131			$	31,160

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

OVERVIEW

We are a growth-oriented Delaware limited partnership organized by Anadarko to own, operate, acquire and develop midstream energy assets. We currently operate in East and West Texas, the Rocky Mountains (Utah and Wyoming) and the Mid-Continent (Kansas and Oklahoma) and are engaged in the business of gathering, compressing, treating, processing and transporting natural gas for Anadarko and third-party producers and customers.

OPERATING AND FINANCIAL HIGHLIGHTS

We achieved significant milestones during 2008. Significant operational and financial highlights include:

	•		closed our initial public offering in May 2008;
	•		completed our first acquisition of midstream assets from Anadarko in December 2008 in a challenging market environment;
	•		completed several system expansions, including modifying horsepower on our Dew gathering system; expanding our Bethel treating facility; connecting new wells, including 26 wells on our Hugoton gathering system and 13 wells on our Haley gathering system, and completed train two of the Fort Union gathering system; and
	•		leveraged our fee-based structure and managed capital and operating costs to generate cash flows, funding distributions to unitholders.

INITIAL PUBLIC OFFERING

On May 14, 2008, we closed our initial public offering of 18,750,000 common units at a price of $16.50 per unit. On June 11, 2008, we issued an additional 2,060,875 common units to the public pursuant to the partial exercise of the underwriters’ over-allotment option granted in connection with our initial public offering. Concurrent with the initial closing of the offering, Anadarko contributed the assets and liabilities of AGC, PGT and MIGC to us in exchange for 1,083,115 general partner units, representing a 2.0% general partner interest in the Partnership, 100% of the IDRs, and 5,725,431 common units and 26,536,306 subordinated units. The common units held by Anadarko include 751,625 common units issued to Anadarko following the expiration of the underwriters’ over-allotment option and represent the portion of the common units for which the underwriters did not exercise their over-allotment option. We refer to AGC, PGT and MIGC as our initial assets.

POWDER RIVER ACQUISITION

On December 19, 2008, we acquired certain midstream assets from Anadarko for consideration consisting of $175.0 million cash, which was financed by borrowing $175.0 million from Anadarko pursuant to the terms of a five-year term loan agreement, 2,556,891 of our common units and 52,181 of our general partner units. The acquired assets consisted of (i) a 100% ownership interest in the Hilight System, (ii) a 50% interest in the Newcastle System and (iii) a 14.81% limited liability company membership interest in Fort Union Gas Gathering, L.L.C. We refer to these assets collectively as the Powder River assets. The Powder River assets provide a combination of gathering, treating and processing services in the Powder River Basin of Wyoming.

The following tables present the impact to the consolidated statements of income attributable to the Powder River assets (in thousands):

		Partnership				Powder River
		Historical				Acquisition				Eliminations				Combined
		Year Ended December 31, 2008
Revenues		$	151,841			$	159,967			$	(160	)		$	311,648
Operating expenses			93,986				148,105				(160	)			241,931
Operating income			57,855				11,862				—				69,717
Interest and other income (expense), net — affiliates			7,817				1,519				—				9,336
Income before income taxes			65,672				13,381				—				79,053
Income tax expense			8,772				5,005				—				13,777
Net income		$	56,900			$	8,376				—			$	65,276
		Year Ended December 31, 2007
Revenues		$	117,993			$	143,660			$	(160	)		$	261,493
Operating expenses			72,748				124,887				(160	)			197,475
Operating income			45,245				18,773				—				64,018
Interest and other income (expense), net — affiliates			(8,521	)			701				—				(7,820	)
Income before income taxes			36,724				19,474				—				56,198
Income tax expense			12,724				6,816				—				19,540
Net income		$	24,000			$	12,658				—			$	36,658
		Year Ended December 31, 2006
Revenues		$	81,562			$	47,105			$	(57	)		$	128,610
Operating expenses			58,379				42,660				(57	)			100,982
Operating income			23,183				4,445				—				27,628
Interest and other income (expense), net — affiliates			(9,657	)			57				—				(9,600	)
Income before income taxes			13,526				4,502				—				18,028
Income tax expense			3,814				1,513				—				5,327
Net income		$	9,712			$	2,989				—			$	12,701

The following discussion analyzes our financial condition and results of operations and should be read in conjunction with our historical consolidated financial statements, and the notes thereto, included in Item 8—Financial Statements and Supplementary Data and Item 1A—Risk Factors of this report on Form 10-K. For ease of reference, we refer to the historical financial results of AGC and PGT prior to our initial public offering, combined with the historical financial results of MIGC and the Powder River assets from August 23, 2006 thereafter, as being “our” historical financial results. Unless the context otherwise requires, references to “we,” “us,” “our,” “the Partnership” or “Western Gas Partners” are intended to refer to the business and operations of Western Gas Partners, LP and its consolidated subsidiaries since May 14, 2008, the business and operations of AGC and PGT since their inception and the business and operations of MIGC and the Powder River assets since August 23, 2006. For purposes of the following discussion, “Anadarko” refers to Anadarko Petroleum Corporation and its consolidated subsidiaries, excluding the Partnership.

OUR OPERATIONS

Our results are driven primarily by the volumes of natural gas we gather, compress, process, treat or transport through our systems. For the year ended December 31, 2008, our revenues were derived approximately as follows:

	•		50% from natural gas and natural gas liquids sales;
	•		40% from gathering, processing, compression and transportation activities;
	•		5% from condensate sales; and
	•		5% from equity income from our interest in Fort Union, changes in our imbalance positions and other revenues.

For the year ended December 31, 2008, approximately 86% of our total revenues and 83% of our gathering, processing and transportation throughput volumes were attributable to transactions entered into with Anadarko.

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

Effective January 1, 2008, we received a significant dedication from our largest customer, Anadarko, in order to maintain or increase our existing throughput levels and to offset the natural production declines of the wells currently connected to our gathering systems. Specifically, Anadarko has dedicated to us all of the natural gas production it owns or controls from (i) wells that are currently connected to our gathering systems, and (ii) additional wells that are drilled within one mile of wells connected to our gathering systems, as the systems currently exist and as they are expanded to connect additional wells in the future. As a result, this dedication will continue to expand as additional wells are connected to our gathering systems. Volumes associated with this dedication averaged approximately 646,000 MMBtu/d for the year ended December 31, 2008 and 734,000 MMBtu/d for the year ended December 31, 2007, based on throughput from the wells ultimately subject to the dedication.

Based on operating income for the year ended December 31, 2008, approximately 74% of our services are provided pursuant to fee-based contracts under which we are paid a fixed fee based on the volume and thermal content of the natural gas we gather, compress, treat or transport. This type of contract provides us with a relatively stable revenue stream that is not subject to direct commodity-price risk, except to the extent that we retain and sell drip condensate that is recovered during the gathering of natural gas from the wellhead.

Based on operating income for the year ended December 31, 2008, approximately 22% of our services are provided pursuant to percent-of-proceeds contracts pursuant to which Anadarko is typically responsible for the marketing of the natural gas and NGLs and we are entitled to a specified percentage of the net proceeds from the sale of natural gas and NGLs. Revenue is recognized when the natural gas or NGLs are sold and the related product purchases are recorded as a percent of the product sale. We have entered into fixed-price swap agreements with Anadarko to manage the commodity price risk inherent in our percent-of-proceeds contracts. See Note 6—Transactions with Affiliates of the notes to the consolidated financial statements included in Item 8—Financial Statements and Supplementary Data in this Form 10-K.

We also have indirect exposure to commodity price risk in that persistent low commodity prices may cause our current or potential customers to delay drilling or shut in production, which would reduce the volumes of natural gas available for gathering, compressing, treating, processing and transporting by our systems. We also bear a limited degree of commodity price risk through our condensate recovery and sale operations and through settlement of natural gas imbalances. Please read Item 7A—Quantitative and Qualitative Disclosures about Market Risk below.

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

As a result of our initial public offering and the Powder River acquisition, the results of operations, financial condition and cash flows vary significantly for 2008 as compared to periods ending prior to our initial public offering. Please see Items Affecting the Comparability of Our Financial Results, set forth below in this Item.

HOW WE EVALUATE OUR OPERATIONS

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

Throughput volumes

In order to maintain or increase throughput volumes on our gathering and processing systems, we must connect additional wells to our systems. Our success in maintaining or increasing throughput is impacted by successful drilling of new wells by producers which will be dedicated to our systems, our ability to secure volumes from new wells drilled on non-dedicated acreage and our ability to attract natural gas volumes currently gathered, processed or treated by our competitors.

To maintain and increase throughput volumes on our MIGC system, we must continue to contract capacity to shippers, including producers and marketers, for transportation of their natural gas. Although firm capacity on the MIGC system is fully subscribed, we nevertheless monitor producer and marketing activities in the area served by our transportation system to maintain a full subscription of MIGC’s firm capacity and to identify new opportunities.

Operating expenses

We analyze operating expenses to evaluate our performance. Operating expenses include all amounts accrued for or paid to affiliates or third parties for the operation of our systems, including product purchases, utilities, field labor, measurement and analysis and other disbursements. The primary components of our operating expenses that we evaluate include operation and maintenance expenses, cost of product expenses and general and administrative expenses. Certain of our operating expenses are paid to affiliates; however, affiliate expenses do not bear a direct relationship to affiliate revenues and third-party expenses do not bear a direct relationship to third-party revenues. Accordingly, our affiliate expenses are not those expenses necessary for generating our affiliate revenues and our third-party expenses are not those expenses necessary for generating our third-party revenues.

Operation and maintenance expenses include, among other things, direct labor, insurance, repair and maintenance, contract services, utility costs and services provided to us or on our behalf. For periods commencing on and subsequent to May 14, 2008 with respect to our initial assets and for periods commencing on and subsequent to December 1, 2008 with respect to the Powder River assets, these expenses are incurred under and governed by our services and secondment agreement with Anadarko.

Cost of product expenses include (i) costs associated with the purchase of natural gas and NGLs pursuant to our percent-of-proceeds processing contracts, (ii) costs associated with the purchase of natural gas pursuant to the gas imbalance provisions contained in our contracts, (iii) costs associated with our obligations under certain contracts to redeliver a volume of natural gas to shippers which is thermally equivalent to condensate retained by us and sold to third parties and (iv) costs associated with our fuel tracking mechanism, which tracks the difference between actual fuel usage and loss and amounts recovered for estimated fuel usage and loss under our contracts. These expenses are subject to variability, although our exposure to commodity price risk attributable to our percent-of-proceeds contracts is mitigated through our commodity price swap agreements with Anadarko. For the years ended December 31, 2008, 2007 and 2006, cost of product expenses comprised 56%, 57% and 41% of total operating expenses, respectively.

General and administrative expenses for periods prior to May 14, 2008 with respect to our initial assets and for periods prior to December 1, 2008 with respect to the Powder River assets, include reimbursements attributable to costs incurred by Anadarko on our behalf and allocations of Anadarko’s general and administrative costs by Anadarko to us. For these periods, Anadarko received compensation or reimbursement through a management services fee. Subsequent to May 14, 2008 with respect to our initial assets and subsequent to December 1, 2008 with respect to the Powder River assets, Anadarko is no longer compensated for corporate services through a management services fee. Instead, we reimburse Anadarko for general and administrative expenses it incurs on our behalf pursuant to the terms of our omnibus agreement with Anadarko. Amounts required to be reimbursed to Anadarko under the omnibus agreement include those expenses attributable to our status as a publicly traded partnership, such as:

	•		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 fees, investor relations expenses, and registrar and transfer agent fees.

In addition to the above, we are required pursuant to the terms of the omnibus agreement with Anadarko, to reimburse Anadarko for allocable general and administrative expenses. The amount required to be reimbursed by us to Anadarko for allocated general and administrative expenses was originally capped at $6.0 million annually; however, this amount was increased to $6.65 million annually in connection with the Powder River acquisition. The annual expense cap stipulated in the omnibus agreement is effective through December 31, 2009, subject to adjustment to reflect changes in the Consumer Price Index and, with the concurrence of the special committee of our general partner’s board of directors, to reflect expansions of our operations through the acquisition or construction of new assets or businesses. After December 31, 2009, our general partner will determine the general and administrative expenses to be reimbursed by us in accordance with our partnership agreement. The cap contained in the omnibus agreement does not apply to incremental general and administrative expenses incurred by or allocated to us as a result of being a separate publicly traded entity. We currently expect those expenses to be approximately $5.6 million per year, excluding equity-based compensation.

Adjusted EBITDA

We define Adjusted EBITDA as net income (loss), plus distributions from equity investee, interest expense, income tax expense and depreciation, less income from equity investments, interest income, income tax benefit and other income (expense). We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations and that Adjusted EBITDA is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures and make distributions. Adjusted EBITDA is a supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:

	•		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.

Adjusted EBITDA is not defined in GAAP. For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please see Non-GAAP Financial Measures in Item 6—Selected Financial and Operating Data of this Form 10-K.

Gross margin

We define gross margin as gathering, processing and transportation revenues, plus natural gas, natural gas liquids and condensate sales, less cost of product. We consider gross margin to provide information useful in assessing our results of operations, our ability to internally fund capital expenditures and to service or incur additional debt.

ITEMS AFFECTING THE COMPARABILITY OF OUR FINANCIAL RESULTS

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

	•		We anticipate incurring approximately $5.6 million of general and administrative expenses annually, excluding equity-based compensation expense, attributable to operating as a publicly traded entity, including 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; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; insurance premiums; and expenses associated with maintaining a limited accounting staff and facilities. General and administrative expenses such as these are reflected in our historical consolidated financial statements for periods including and subsequent to our initial public offering in May 2008.
	•		Additionally, we anticipate incurring up to $6.65 million in general and administrative expenses annually to be charged by Anadarko to us pursuant to the omnibus agreement, which became effective in connection with our initial public offering. This amount is expected to be greater than amounts allocated to us by Anadarko for the management services fee reflected in our historical consolidated financial statements for periods prior to May 14, 2008.
	•		Prior to May 14, 2008 with respect to our initial assets and prior to December 19, 2008 with respect to the Powder River assets, all affiliate transactions were net settled within our consolidated financial statements because these transactions related to Anadarko and were funded by Anadarko’s working capital. Effective on May 14, 2008 with respect to our initial assets and December 19, 2008 with respect to the Powder River assets, all affiliate and third-party transactions are funded by our working capital. This impacts the comparability of our cash flow statements, working capital analysis and liquidity discussion.
	•		Prior to May 14, 2008 with respect to our initial assets and prior to December 19, 2008 with respect to the Powder River assets, we incurred interest expense or earned interest income on intercompany balances with Anadarko. These intercompany balances were extinguished through non-cash transactions in connection with the closing of our initial public offering and the Powder River acquisition; therefore, interest expense and interest income attributable to these balances is reflected in our historical consolidated financial statements for the periods ending prior to and including May 14, 2008 with respect to our initial assets and prior to and including December 19, 2008 with respect to the Powder River assets.
	•		In connection with the Powder River acquisition, we entered into a five-year, $175.0 million term loan agreement with Anadarko, under which we will pay interest at a fixed rate of 4.0% for the first two years and a floating rate of interest at three-month LIBOR plus 150 basis points for the final three years. For periods including and subsequent to the Powder River acquisition, interest expense on the $175.0 million note payable to Anadarko will be incurred so long as the loan agreement remains in place.
	•		Concurrent with the closing of our initial public offering, we loaned $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%. Interest income attributable to the note is reflected in our consolidated financial statements for the period beginning on May 14, 2008 and ending December 31, 2008 and will be included in future periods so long as the note remains outstanding.
	•		Pursuant to the omnibus agreement, as a co-borrower under Anadarko’s credit facility, we are required to reimburse Anadarko for our allocable portion of commitment fees (0.11% of our committed and available borrowing capacity, including our outstanding balances) that Anadarko incurs under its credit facility, or up to $110,000 per year. See Note 6—Transactions with Affiliates in the notes to the consolidated financial statements included in Item 8—Financial Statements and Schedules of this Form 10-K. In addition, Anadarko entered into a working capital facility with us, under which we incur an annual commitment fee of 0.11% of the unused portion of our committed borrowing capacity of $30.0 million, or up to $33,000 per year. These commitment fees are included in interest income (expense), net in our consolidated financial statements for the period beginning on May 14, 2008 and ending December 31, 2008 and will be included in future periods so long as the credit facilities are in place.
	•		For periods ending prior to January 1, 2008, our consolidated financial statements reflect the gathering fees we historically charged Anadarko under our affiliate cost-of-service-based arrangements. Under these arrangements, we recovered, on an annual basis, our operation and maintenance, general and administrative and depreciation expenses in addition to earning a return on our invested capital. Effective January 1, 2008, we entered into new 10-year gas gathering agreements with Anadarko. Pursuant to the terms of the new agreements, our fees for gathering and treating services rendered to Anadarko increased. This increase was due, in part, to compensate us for additional operation and maintenance expense that we incur as a result of us bearing all of the cost of employee benefits

specifically identified and related to operational personnel working on our assets, as compared to bearing only those employee benefit costs reasonably allocated by Anadarko to us for the periods ending prior to January 1, 2008. Because our new gas gathering agreements are designed to fully recover these incremental costs, our revenues increased by an amount approximately equal to the incremental operation and maintenance expense. Although this change in methodology for computing affiliate gathering rates does not impact our net cash flows or net income, this methodology change impacts the components thereof as compared to periods ending prior to January 1, 2008. If we applied the methodology employed under our new gas gathering agreements with Anadarko to the year ended December 31, 2007, we estimate our historic gathering revenues and operation and maintenance expense would have increased by $3.1 million and our cash flow from operations would have remained unchanged.

	•		The 10-year gas gathering agreements entered into with Anadarko included new fees for gathering and treating. The new fees are based on capital improvements and changes in our cost-of-service analysis and are higher than those fees reflected in our historical financial results for the periods ended prior to January 1, 2008.
	•		Our financial results for historical periods reflect commodity prices changes, which, in turn, impacts the financial results derived from our percent-of-proceeds processing contracts. Effective January 1, 2009, we have mitigated the commodity price risk associated with our percent-of-proceeds processing contracts by entering into fixed-price commodity price swap agreements with Anadarko that extend through at least December 31, 2010. See Note 6—Transactions with Affiliates of the notes to the consolidated financial statements included in Item 8—Financial Statements and Supplementary Data in this Form 10-K.
	•		We are generally not subject to federal or state income tax. Federal and state income tax expense was recorded for periods ending prior to and including May 14, 2008 with respect to income generated by our initial assets and prior to and including December 19, 2008 with respect to income generated by the Powder River assets. In periods subsequent to May 14, 2008 with respect to income generated by our initial assets and subsequent to December 19, 2008 with respect to income generated by the Powder River assets, we are only subject to Texas margin tax; therefore, income tax expense attributable to Texas margin tax will continue to be recognized in our consolidated financial statements. We are required to make payments to Anadarko pursuant to a tax sharing arrangement for our share of Texas margin tax included in any combined or consolidated returns of Anadarko. The consolidated financial statements for periods ending prior to May 14, 2008 with respect to income generated by our initial assets and prior to December 19, 2008 with respect to income generated by the Powder River assets include deferred federal and state income taxes which were provided on temporary differences between the financial statement carrying amounts of recognized assets and liabilities and their respective tax bases as if we filed tax returns as a stand-alone entity. Immediately prior to closing of the dates of our initial public offering and the Powder River acquisition, we recorded an adjustment to equity of $76.5 million and $50.4 million, respectively, for the elimination of net deferred tax liabilities.
	•		We currently make cash distributions to our unitholders and our general partner at an initial distribution rate of $0.30 per unit per full quarter ($1.20 per unit on an annualized basis). We paid cash distributions to our unitholders of $0.4582 per unit during the year ended December 31, 2008. This amount represents a $0.30 per unit quarterly distribution prorated for the 48-day period beginning on the date of our initial public offering and ending on June 30, 2008, or $0.1582 per unit, and a $0.30 per unit distribution for the quarter ended on September 30, 2008.
	•		We expect that we will rely upon external financing sources, including commercial bank borrowings and debt and equity issuances, to fund our acquisition and expansion capital expenditures. Historically, we largely relied on internally generated cash flows and capital contributions from Anadarko to satisfy our capital expenditure requirements.
	•		In connection with the closing of our initial public offering, our general partner adopted two new compensation plans; the Western Gas Partners, LP 2008 Long-Term Incentive Plan, or LTIP, and the Amended and Restated Western Gas Holdings, LLC Equity Incentive Plan, or the Incentive Plan. Phantom unit grants have been made to each of the independent directors of our general partner under the LTIP, and incentive unit grants have been made to each of our general partner’s executive officers under the Incentive Plan. Pursuant to Financial Accounting Standards Board Statement No. 123 (revised 2004), Shared-Based Payment, or SFAS 123(R), grants made under equity-based compensation plans result in equity-based compensation expense which is determined, in part, by reference to the fair value of equity compensation as of the date of grant. For periods ending prior to May 14, 2008, equity-based compensation expense attributable to the LTIP and Incentive Plan is not reflected in our historical consolidated financial statements as there were no outstanding equity grants under either plan. Effective as of May 14, 2008, equity-based compensation expense for grants made under the LTIP and Incentive Plan is reflected in our statements of operations. Share-based compensation expense attributable to grants made under the LTIP will impact our cash flows from operating activities only to the extent our general partner’s board of directors, at its discretion, elects to make a cash payment to a participant in lieu of actual

receipt of common units by the participant upon the lapse of the relevant vesting period. Equity-based compensation expense attributable to grants made under the Incentive Plan will impact our cash flow from operating activities only to the extent cash payments are made to Incentive Plan participants and such cash payments do not cause total annual reimbursements made by us to Anadarko pursuant to the omnibus agreement to exceed the general and administrative expense limit set forth therein for the periods to which such expense limit applies. See equity-based compensation discussion included in Note 2 — Summary of Significant Accounting Policies and Note 6—Transactions with Affiliates of the notes to the consolidated financial statements included in Item 8—Financial Statements and Supplementary Data in this Form 10-K.

GENERAL TRENDS AND OUTLOOK

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

Capital markets

We require periodic access to capital in order to fund acquisitions and expansion projects. Under the terms of our partnership agreement, we are required to distribute all of our available cash to our unitholders, which makes us dependent upon raising capital to fund growth projects. Historically, master limited partnerships have accessed the public debt and equity capital markets to raise money for new growth projects. Recent market turbulence has either raised the cost of those public funds or, in some cases, eliminated the availability of these funds to prospective issuers. If we are unable either to access the public capital markets or find alternative sources of capital, our growth strategy may be more challenging to execute.

Impact of interest rates

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

Natural gas supply and demand

Natural gas continues to be a critical component of energy supply in the U.S. According to the Energy Information Administration, or EIA, total annual domestic consumption of natural gas is expected to decrease from approximately 23.4 Tcf in 2008 to approximately 22.5 Tcf in 2011, but consumption is expected to increase to approximately 24.5 Tcf by 2028. During the last three years, the U.S. has, on average, consumed approximately 22.7 Tcf per year, while total domestic production averaged approximately 19.4 Tcf per year during the same period. Overall, natural gas reserves in the U.S. have increased in recent years, based on data obtained from the EIA.

There is a natural decline in production from existing wells. Although in the areas in which we operate there has been a significant level of drilling activity offsetting this decline in recent years, the current natural gas price environment has resulted in significantly lower drilling activity throughout areas in which we operate and drilling activity in certain areas could be temporarily suspended. We have no control over this activity. In addition, the recent or further decline in commodity prices could affect production rates and the level of investment by Anadarko and third parties in the exploration for and development of new natural gas reserves.

Rising operating costs and inflation

The high level of natural gas exploration, development and production activities across the U.S. in recent years, and the associated construction of required midstream infrastructure, resulted in increased competition for personnel and equipment. Although the activities have slowed in recent months, we have not yet realized a material decline in the prices we pay for labor, supplies and property, plant and equipment. An increase in the general level of prices in the economy could have a similar effect. We have the ability to recover increased costs from our customers through escalation provisions provided for in our contracts. However, there may be a delay in recovering these costs or we may be unable to recover all these costs. To the extent we are unable to recover higher costs our operating results will be negatively impacted.

Benefits from system expansions

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

	•		We modified and relocated horsepower on our Dew system during the third quarter of 2008, which resulted in lower gathering line pressures and an increase in throughput of approximately 2 MMcf/d.
	•		Further modifications of compression on our Dew system are planned for 2009 which are expected to result in lower gathering line pressures servicing the Holly Branch producing area and may further increase throughput by up to approximately 2 MMcf/d.
	•		We expanded our Bethel treating facility by installing an additional 11 LTD of sulfur treating capacity in order to provide additional sour gas treating capacity for drilling in the area, which we completed in July 2008.
	•		We are expanding our Hugoton gathering system to connect wells drilled by third parties and Anadarko. During 2008, we connected 12 third-party wells with an average initial production rate of 2.8 MMcf/d. We also connected 8 new Anadarko wells and reconnected 6 others that were previously connected to third-party gathering systems. These 14 wells collectively produced at a rate of 1.9 MMcf/d during the month of December 2008.
	•		In November 2007, Anadarko completed Phase II of the Fort Union expansion project by installing 42 miles of 24” pipe, bringing the total header system to two parallel 24” lines stretching 106 miles in length. During 2008, Anadarko completed Phase III of the Fort Union expansion project by installing a third parallel 106-mile 24” line, increasing the total Fort Union handling capacity to 1,300 MMcf/d.
	•		Anadarko expanded train one of the Medicine Bow Plant at the terminus of the Fort Union gathering system in March 2007, increasing the total amine circulation capacity to 300 gal/min and increasing the system’s gas treating capability to 70 MMcf/d of gas containing 3.2% CO2. During the fourth quarter of 2008, we completed train two, which has 600 gal/min of amine circulation and a gas treating capacity of 112 MMcf/d of gas containing 4.5% CO2. Train three, which is identical to train two, is currently under construction and is expected to begin operations in the first quarter of 2009. Upon the completion of train three, we expect to have sufficient treating capacity to meet the CO2 specifications of downstream pipelines in the future.

Acquisition opportunities

A key component of our growth strategy is to acquire midstream assets from Anadarko over time. In December 2008, we acquired the Powder River assets from Anadarko. As of December 31, 2008, Anadarko’s total domestic midstream asset portfolio, excluding assets we own, consisted of 19 gathering systems with an aggregate throughput of approximately 2.3 Bcf/d, 8,100 miles of pipeline and 18 processing and/or treating facilities. Anadarko owns a 2.0% general partner interest in us, all of our IDRs and a 61.3% limited partner interest in us. Given Anadarko’s significant interests in us, we believe Anadarko will benefit from selling additional assets to us over time; however, Anadarko continually evaluates acquisitions and divestitures and may elect to acquire, construct or dispose of midstream assets in the future without offering us the opportunity to acquire or construct those assets. Should Anadarko choose to pursue additional midstream asset sales, it is under no contractual obligation to offer assets or business opportunities to us. We may also pursue selected asset acquisitions from third parties to the extent such acquisitions complement our or Anadarko’s existing asset base or allow us to capture operational efficiencies from Anadarko’s or third-party production. However, if we do not make additional acquisitions from Anadarko or third parties on economically acceptable terms, our future growth will be limited, and the acquisitions we make could reduce, rather than increase, our cash generated from operations on a per-unit basis.

RESULTS OF OPERATIONS — OVERVIEW

OPERATING RESULTS

The following table and discussion presents a summary of our results of operations for the years ended December 31, 2008, 2007 and 2006:

		Year Ended December 31,
		2008				2007(1)				2006(1)
		(in thousands)
Revenues — affiliates
Gathering, processing and transportation of natural gas		$	107,582			$	93,007			$	66,296
Natural gas, natural gas liquids and condensate sales			154,772				146,151				52,959
Equity income and other			9,289				6,144				2,380
Total revenues — affiliates			271,643				245,302				121,635
Revenues — third parties
Gathering, processing and transportation of natural gas			15,958				11,019				5,783
Natural gas, natural gas liquids and condensate sales			16,119				2,772				3
Other			7,928				2,400				1,189
Total revenues — third parties			40,005				16,191				6,975
Total Revenues			311,648				261,493				128,610
Operating Expenses (2)
Cost of product			134,715				112,283				41,806
Operation and maintenance			44,765				40,756				29,907
General and administrative			14,385				8,364				4,320
Property and other taxes			5,701				5,591				4,719
Depreciation and impairment			42,365				30,481				20,230
Total Operating Expenses			241,931				197,475				100,982
Operating Income			69,717				64,018				27,628
Interest income (expense), net — affiliates			9,191				(7,805	)			(9,574	)
Other income (expense), net			145				(15	)			(26	)
Income Before Income Taxes			79,053				56,198				18,028
Income Tax Expense			13,777				19,540				5,327
Net Income		$	65,276			$	36,658			$	12,701
Adjusted EBITDA(3)		$	112,474			$	91,830			$	47,239
Gross margin(3)			159,716				140,666				83,235

For purposes of the following discussion, any increases or decreases “for the year ended December 31, 2008” refer to the comparison of the year ended December 31, 2008 to the year ended December 31, 2007. Similarly, any increases or decreases “for the year ended December 31, 2007” refer to the comparison of the year ended December 31, 2007 to the year ended December 31, 2006.

Executive Summary

Total revenues increased by $50.2 million and $132.9 million for the year ended December 31, 2008 and for the year ended December 31, 2007, respectively. Gathering, processing and transportation revenues increased $19.5 million; natural gas, NGLs and condensate revenues increased $22.0 million and equity income and other revenues increased $8.7 million for the year ended December 31, 2008. Gathering, processing and transportation revenues increased $31.9 million; natural gas,

NGLs and condensate revenues increased $96.0 million and equity income and other revenues increased $5.0 million for the year ended December 31, 2007. Revenues attributable to MIGC and the Powder River assets contributed to $110.0 million of the increase in total revenues for the year ended December 31, 2007. This distinction bears significance for all comparisons for the year ended December 31, 2007 in that results attributable to these assets for 2006 include only the results from August 23, 2006, the date Anadarko acquired Western.

Net income increased by $28.6 million and $24.0 million for the year ended December 31, 2008 and for the year ended December 31, 2007, respectively. The increase in net income for the year ended December 31, 2008 is primarily due to a $50.2 million increase in total revenues driven by gathering rate increases, increased condensate margins, an increase in other revenues from changes in gas imbalance positions and gas prices, a $17.0 million increase in net affiliate interest income and a $5.8 million decrease in income tax expense. These items are partially offset by higher operating expenses of $44.5 million for the year ended December 31, 2008.

For the year ended December 31, 2007, the increase in net income of $24.0 million is primarily due to a $132.9 million increase in total revenues attributable to acquisitions, gathering rate increases, increased condensate margins and an increase in equity income and other revenues from changes in gas imbalance positions and gas prices, and a $1.8 million decrease in net affiliate interest expense. These items are partially offset by higher operating expenses of $96.5 million and increased income tax expense of $14.2 million. MIGC and the Powder River assets contributed to $16.5 million of the increase in net income for the year ended December 31, 2007. The changes in revenues, operating expenses, interest expense and income taxes are discussed in more detail below.

Revenues and Operating Statistics

		2008				2007				2008 vs. 2007				2006				2007 vs. 2006
		(in thousands, except per-unit data and percents)
Revenues
Affiliates		$	271,643			$	245,302				11	%		$	121,635				102	%
Third parties			40,005				16,191				147	%			6,975				132	%
Total revenues		$	311,648			$	261,493				19	%		$	128,610				103	%
Gathering and transportation throughput (MMcf/d)(a)
Affiliates			831				917				(9	%)			891				3	%
Third parties			135				90				50	%			80				13	%
Total throughput			966				1,007				(4	%)			971				4	%
Processing throughput (MMcf/d)
Affiliates			—				—				—				—				—
Third parties			30				30				0	%			30				(0	%)
Total throughput			30				30				0	%			30				(0	%)
Gross margin per MMcf (b)		$	0.44			$	0.37				19	%		$	0.23				61	%

Throughput volumes, which consist of affiliate and third-party volumes, decreased by 41,000 Mcf/d for the year ended December 31, 2008 and increased by 36,000 Mcf/d for the year ended December 31, 2007.

Affiliate gathering and transportation volumes decreased by 86,000 Mcf/d for the year ended December 31, 2008, primarily attributable to throughput decreases at the Haley, Pinnacle, Hugoton and Dew systems, partially offset by increases at the MIGC system. Haley field production and related Haley system throughput peaked in the first quarter of 2007. Since the first quarter of 2007, production and associated volumes from the Haley field have gradually declined due to the natural production decline and a shift in rig activity from the dedicated gathering area to other exploration areas within the Delaware Basin, resulting in fewer well connections. Recent activity has partially offset volume declines at the Haley system, with 13 wells connected during the year ended December 31, 2008, in addition to the third-party volumes described below. The decline in affiliate volumes at the Hugoton, Dew and Pinnacle systems for the year ended December 31, 2008 is primarily

due to natural production declines and reduced or delayed activity in the Dew and Pinnacle areas. These volume decreases are partially offset by increases in the MIGC system due to a new affiliate contract that became effective in September 2007 in connection with expansion of the system’s capacity.

Affiliate gathering and transportation volumes increased by 26,000 Mcf/d for the year ended December 31, 2007, primarily attributable to increases in volumes at the Haley and MIGC systems, partially offset by decreases at the Dew system.

Third-party gathering and transportation volumes increased by 45,000 Mcf/d for the year ended December 31, 2008, primarily attributable to the throughput increases at the Haley and Hugoton systems, partially offset by throughput declines at the Pinnacle system resulting primarily from a decrease in volumes at two central receipt points from a large third-party shipper. The increase in third-party volumes at the Haley gathering system is primarily due to a third party’s activity in the area. Increased volumes at the Hugoton system are due to a third-party customer’s successful drilling program, which resulted in 12 additional wells being connected to the Hugoton gathering system during the year ended December 31, 2008.

Third-party gathering and transportation volumes increased by 10,000 Mcf/d for the year ended December 31, 2007, primarily attributable to throughput increases at the Hugoton system.

Processing volumes remained flat for the year ended December 31, 2008 and for the year ended December 31, 2007.

Gathering, Processing and Transportation of Natural Gas Revenues

		2008				2007				2008 vs. 2007				2006				2007 vs. 2006
						(in thousands, except percents)
Gathering, processing and transportation of natural gas:
Affiliates		$	107,582			$	93,007				16	%		$	66,296				40	%
Third parties			15,958				11,019				45	%			5,783				91	%
Total		$	123,540			$	104,026				19	%		$	72,079				44	%