UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2011

OR

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

For the transition period from              to             

Commission file number: 1-14998

ATLAS PIPELINE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

DELAWARE	23-3011077
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
Park Place Corporate Center One 1000 Commerce Drive, 4th Floor Pittsburg, Pennsylvania	15275-1011
(Address of principal executive office)	(Zip code)

Registrant’s telephone number, including area code: (877) 950-7473

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Units representing Limited Partnership Interests	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

(Title of class)

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

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  ¨    No  x

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  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files)    Yes  x    No  ¨

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.  ¨

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 definitions of “large accelerated filer,” “accelerated filer” and “small reporting company” in Rule 12b-2 of the Exchange Act (Check one):

Large accelerated filer	x	Accelerated filer	¨
Non-accelerated filer	¨	Smaller reporting company	¨

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

The aggregate market value of the equity securities held by non-affiliates of the registrant, based upon the closing price of $32.96 per common limited partner unit on June 30, 2011, was approximately $1,564.0 million.

The number of common units of the registrant outstanding on February 20, 2012 was 53,618,095

DOCUMENTS INCORPORATED BY REFERENCE: None

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

INDEX TO ANNUAL REPORT

ON FORM 10-K

		Page
Forward Looking Statements			3
Glossary of Terms			4
PART I.
Item 1.	Business		5
Item 1A.	Risk Factors		24
Item 1B.	Unresolved Staff Comments		42
Item 2.	Properties		42
Item 3.	Legal Proceedings		42
Item 4.	[Removed and reserved]		42
PART II.
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities		43
Item 6.	Selected Financial Data		44
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		50
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		69
Item 8.	Financial Statements and Supplementary Data		71
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		117
Item 9A.	Controls and Procedures		117
Item 9B.	Other Information		120
PART III.
Item 10.	Directors, Executive Officers and Corporate Governance		121
Item 11.	Executive Compensation		127
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters		156
Item 13.	Certain Relationships and Related Transactions, and Director Independence		159
Item 14.	Principal Accountant Fees and Services		160
PART IV.
Item 15.	Exhibits and Financial Statement Schedules		161
SIGNATURES			163

FORWARD-LOOKING STATEMENTS

The matters discussed within this report include forward-looking statements. These statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “should,” or “will,” or the negative thereof or other variations thereon or comparable terminology. In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this report are forward-looking statements. We have based these forward-looking statements on our current expectations, assumptions, estimates and projections. While we believe these expectations, assumptions, estimates and projections are reasonable, such forward-looking statements are only predictions and involve known and unknown risks and uncertainties, many of which are beyond our control. These and other important factors may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements. Some of the key factors that could cause actual results to differ from our expectations include:

• the demand for natural gas, natural gas liquids and condensate;

• the price volatility of natural gas, natural gas liquids and condensate;

• our ability to connect new wells to our gathering systems;

• adverse effects of governmental and environmental regulation;

• limitations on our access to capital or on the market for our common units; and

• the strength and financial resources of our competitors.

Other factors that could cause actual results to differ from those implied by the forward-looking statements in this report are more fully described under Item 1A, “Risk Factors” in this report. Given these risks and uncertainties, you are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included in this report are made only as of the date hereof. We do not undertake and specifically decline any obligation to update any such statements or to publicly announce the results of any revisions to any of these statements to reflect future events or developments.

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Glossary of Terms

Definitions of terms and acronyms generally used in the energy industry and in this report are as follows:

BPD	Barrels per day. Barrel - measurement for a standard US barrel is 42 gallons. Crude oil and condensate are generally reported in barrels.
BTU	British thermal unit, a basic measure of heat energy
Condensate	Liquid hydrocarbons present in casinghead gas that condense within the gathering system and are removed prior to delivery to the gas plant. This product is generally sold on terms more closely tied to crude oil pricing.
EBITDA	Net income (loss) before net interest expense, income taxes, and depreciation and amortization. EBITDA is considered to be a non-GAAP measurement.
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Fractionation	The process used to separate an NGL stream into its individual components.
GAAP	Generally Accepted Accounting Principles
G.P.	General Partner or General Partnership
IFRS	International Financial Reporting Standards
Keep-Whole	Contract with producer whereby plant operator pays for or returns gas having an equivalent BTU content to the gas received at the well-head.
L.P.	Limited Partner or Limited Partnership
MCF	Thousand cubic feet
MCFD	Thousand cubic feet per day
MMBTU	Million British thermal units
MMCFD	Million cubic feet per day
NGL(s)	Natural Gas Liquid(s), primarily ethane, propane, normal butane, isobutane and natural gasoline
Percentage of Proceeds, (“POP”)	Contract with natural gas producers whereby the plant operator retains a negotiated percentage of the sale proceeds.
Residue gas	The portion of natural gas remaining after natural gas is processed for removal of NGLs and impurities.
SEC	Securities and Exchange Commission

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PART I

ITEM 1. BUSINESS

Corporate Structure

We are a publicly-traded Delaware limited partnership formed in 1999 whose common units are listed on the New York Stock Exchange under the symbol “APL.” We are a leading provider of natural gas gathering and processing services in the Anadarko and Permian Basins located in the southwestern and mid-continent regions of the United States; a provider of natural gas gathering services in the Appalachian Basin in the northeastern region of the United States and a provider of NGL transportation services in the southwestern region of the United States.

Our general partner, Atlas Pipeline Partners GP, LLC (“Atlas Pipeline GP” or the “General Partner”), manages our operations and activities through its ownership of our general partner interest. Atlas Pipeline GP is a wholly-owned subsidiary of Atlas Energy, L.P. , formerly known as Atlas Pipeline Holdings, L.P., (“ATLS”), a publicly traded Delaware limited partnership (NYSE: ATLS), which owned a 10.7% limited partner interest in us at December 31, 2011, as well as the 2% general partner interest.

The following chart displays the corporate organizational structure as of December 31, 2011:

Recent Developments

Laurel Mountain Sale

On February 17, 2011, we completed the sale (the “Laurel Mountain Sale”) of our 49% non-controlling interest in Laurel Mountain Midstream, LLC joint venture (“Laurel Mountain”) to Atlas Energy Resources, LLC (“Atlas Energy Resources”) for $409.5 million in cash, net of expenses and

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adjustments based on capital contributions we made to and distributions we received from Laurel Mountain after January 1, 2011. We retained the preferred distribution rights under the limited liability company agreement of Laurel Mountain entitling APL Laurel Mountain LLC, our wholly-owned subsidiary, to receive all payments made under a note issued to Laurel Mountain by Williams Laurel Mountain, LLC in connection with the formation of Laurel Mountain. The note was paid in full as of December 31, 2011.

AHD Transaction Agreement

Concurrently with the Laurel Mountain Sale, ATLS completed a transaction agreement (the “AHD Transaction Agreement” or “AHD Transactions”), with Atlas Energy, Inc. (“AEI”), a formerly publicly-traded company, and Atlas Energy Resources, a wholly-owned subsidiary of AEI, pursuant to which among other things (1) ATLS purchased certain assets from AEI; (2) AEI contributed ATLS’ general partner, Atlas Energy, GP, LLC (formerly known as Atlas Pipeline Holdings GP, LLC) to ATLS, so that Atlas Energy GP, LLC became ATLS’ wholly-owned subsidiary; and (3) AEI distributed to its stockholders all ATLS common units it held.

Atlas Energy, Inc. Merger

Concurrently with the AHD Transactions, AEI completed an agreement and plan of merger with Chevron Corporation, a Delaware corporation (“Chevron” –NYSE: CVX), pursuant to which, among other things, AEI became a wholly-owned subsidiary of Chevron (the “Chevron Merger”). As part of the Chevron Merger, Chevron acquired 1,112,000 of our common units and our 12% cumulative Class C preferred units (“Class C Preferred Units”), which were held directly by AEI.

Atlas Pipeline Holdings, L.P. Name and Ticker Symbol Change

On February 18, 2011, subsequent to the AHD Transactions and the Chevron Merger, Atlas Pipeline Holdings, L.P. changed its name to Atlas Energy, L.P. On April 28, 2011, Atlas Energy, L.P. changed the ticker symbol of its common units on the New York Stock Exchange from “AHD” to “ATLS”, the former ticker symbol of Atlas Energy, Inc.

West Texas LPG Pipeline Acquisition

On May 11, 2011, we acquired a 20% interest in West Texas LPG Pipeline Limited Partnership (“WTLPG”) from Buckeye Partners, L.P. (NYSE: BPL) for $85.0 million. WTLPG owns an approximately 2,200 mile common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. WTLPG is operated by Chevron Pipeline Company, an affiliate of Chevron, which owns the remaining 80% interest.

Gas Plant Expansion Projects

On May 12, 2011, we announced planned major expansions to our existing gas gathering and processing systems, including (1) a $175.0 million expansion of the Waynoka plant on our WestOK system, (2) a $75.0 million expansion of our Velma system, (3) a $15.0 million re-start of the cryogenic skid at the Midkiff plant in our WestTX system, and (4) an additional $50.0 million in growth capital for compression, gathering lines and connections that are expected to be incurred in 2012.

On November 15, 2011, we announced plans to construct a new 200 MMCFD cryogenic processing plant within our WestTX system, to be known as the Driver plant. The plant is planned to be constructed in two phases, with the first phase consisting of a 100 MMCFD processing plant expected to

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be in service in the first quarter of 2013. The second phase, to increase the plant capacity to 200 MMCFD, is scheduled to be complete in the first quarter of 2015.

Class C Preferred Units Redemption

On May 27, 2011, we redeemed our 8,000 units of Class C Preferred Units for cash at the liquidation value of $1,000 per unit, or $8.0 million plus $0.2 million accrued dividends. There are no longer any Class C Preferred Units outstanding.

General

We conduct our business in the midstream segment of the natural gas industry through two reportable segments: Gathering and Processing and Pipeline Transportation.

Due to the Laurel Mountain Sale and our acquisition of a 20% interest in WTLPG (see “–Recent Developments”), we realigned the management of our business in the midstream segment of the natural gas industry from our previously reportable segments of Mid-Continent and Appalachia into the two new reportable segments.

The Gathering and Processing segment consists of (1) the WestOK, WestTX and Velma operations, which are comprised of natural gas gathering and processing assets servicing drilling activity in the Anadarko and Permian Basins, and which were formerly included within the previous Mid-Continent segment; (2) the natural gas gathering assets located in Tennessee, which were formerly included in the previous Appalachia segment; and (3) the revenues and gain on sale related to our 49% interest in Laurel Mountain, which were formerly included in the previous Appalachia segment. Gathering and Processing revenues are primarily derived from the sale of residue gas and NGLs and the gathering and processing of natural gas.

Our Gathering and Processing operations, own, have interests in and operate seven natural gas processing plants with aggregate capacity of approximately 610 MMCFD, which are connected to approximately 9,000 miles of active natural gas gathering systems located in Oklahoma, Kansas and Texas. In addition, we own and operate approximately 100 miles of active natural gas gathering systems located in Tennessee. Our gathering systems gather gas from wells and central delivery points and deliver to natural gas processing plants, as well as third-party pipelines.

Our Gathering and Processing operations are all located in or near areas of abundant and long-lived natural gas production including the Golden Trend, Woodford Shale, Hugoton field in the Anadarko Basin and the Spraberry Trend, which is an oil play with associated natural gas in the Permian Basin. Our gathering systems are connected to approximately 7,400 central delivery points or wells. Thus, we believe we have significant scale in our service areas. We provide gathering and processing services to the wells connected to our systems, primarily under long-term contracts. As a result of the location and capacity of our gathering and processing assets, we believe we are strategically positioned to capitalize on the drilling activity in our service areas.

Our Pipeline Transportation operations consist of a 20% interest in WTLPG, which was acquired on May 11, 2011 (see “–Recent Developments”). WTLPG owns an approximately 2,200 mile common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. WTLPG is operated by Chevron Pipeline Company, an affiliate of Chevron, which owns the remaining 80% interest.

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We intend to continue to expand our business through strategic acquisitions and internal growth projects in efforts to increase distributable cash flow.

Business Strategy

The primary business objective of our management team is to provide stable long-term cash distributions to our unitholders. Our business strategies focus on creating value for our unitholders by providing efficient operations, focusing on prudent growth opportunities via organic growth projects and external acquisitions, and maintaining a commodity risk management program in an attempt to manage our commodity price exposure. We intend to accomplish our primary business objectives by executing on the following:

• Increasing the profitability of our existing assets. In many cases, we can expand our gathering pipelines and processing plants and may have excess capacity, which provides us with opportunities to connect and process new supplies of natural gas with minimal additional capital requirements, also increasing plant efficiency and economics. We plan to accomplish this goal by providing excellent service to our existing customers; aggressively marketing our services to new customers; and prudently expanding our existing infrastructure to ensure our services can meet the needs of potential customers. Other opportunities include pursuing relationships with new producers; the elimination of pipeline bottlenecks; reducing operating line pressures; and focusing on reduction of pipeline losses along our gathering systems.

• Expanding operations through organic growth projects and pursuing strategic acquisitions. We continue to explore opportunities to expand our existing infrastructure. Our planned 200 MMCFD expansion of the Waynoka processing plant in WestOK; our recommissioning of the 60 MMCFD Midkiff plant in WestTX; and our planned construction of the 200 MMCFD Driver plant in WestTX are examples of executing this strategy. We also plan to pursue strategic acquisitions accretive to our unitholders by seeking opportunities that leverage our existing asset base, employees and existing customer relationships. In the past, we have pursued opportunities in certain regions outside of our current areas of operation and will continue to do so when these options make sense economically and strategically.

• Reducing the sensitivity of our cash flows through prudent economic risk management and contract arrangements. We attempt to structure our contracts in a manner that allows us to achieve our target rate of return goals while reducing our exposure to commodity price movements. We actively review our contract mix and seek to optimize a balance of cash flow stability with attractive economic returns. Our commodity risk management activities are designed to reduce the effect of commodity price volatility related to future sales of natural gas, NGLs and condensate, while allowing us to meet our debt service requirements; fund our maintenance capital program; and meet our distribution objectives.

• Maintaining our financial flexibility. We intend to maintain a capital structure in which we do not significantly exceed equal amounts of debt and equity on a long-term basis, while not jeopardizing our ability to achieve our other business strategies. We believe our revolving credit facility, our ability to issue additional long-term debt or partnership units and our relationships with our partners provide us with the ability to achieve this strategy. We will also consider alternative financing, joint venture arrangements and other means that allow us to achieve our business strategies while continuing to maintain an acceptable capital structure.

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The Midstream Natural Gas Gathering and Processing Industry

The midstream natural gas gathering and processing industry is characterized by regional competition based on the proximity of gathering systems and processing plants to producing natural gas wells.

The natural gas gathering process begins with the drilling of wells into natural gas or oil bearing rock formations. Once a well has been completed, the well is connected to a gathering system. Gathering systems generally consist of a network of pipelines that collect natural gas from points near producing wells and transport gas and other associated products to processing plants for processing and treating and to larger pipelines for further transportation to end-user markets. Gathering systems are operated at design pressures via pipe size and compression that will maximize the total throughput from all connected wells.

While natural gas produced in some areas does not require treatment or processing, natural gas produced in other areas, such as our WestTX and Velma operations, is not suitable for long-haul pipeline transportation or commercial use and must be compressed, gathered via pipeline to a central processing facility, potentially treated and then processed to remove certain hydrocarbon components such as NGLs and other contaminants that would interfere with pipeline transportation or the end use of the natural gas. Natural gas processing plants generally treat (remove carbon dioxide and hydrogen sulfide) and extract the NGLs, enabling the treated, “dry” gas (commercially marketable BTU content) to meet pipeline specification for long-haul transport to end users. After being separated from natural gas at the processing plant, the mixed NGL stream, commonly referred to as “y-grade” or “raw mix,” is typically transported in pipelines to a centralized facility for fractionation into discrete NGL purity products: ethane, propane, normal butane, isobutane, and natural gasoline. Generally NGL transportation agreements generate revenue based on a fee per unit of volume transported.

Contracts and Customer Relationships

Our principal revenue is generated from the gathering, processing and sale of natural gas, NGLs and condensate and the transportation of NGLs. Primary contracts are Fee-Based, POP and Keep-Whole (see “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations –Contractual Revenue Arrangements”).

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Our Gathering and Processing Operations

We own and operate approximately 9,100 miles of intrastate natural gas gathering systems located in Oklahoma, Kansas, Texas and Tennessee. We also own and operate seven natural gas processing plants located in Oklahoma and Texas. Our gathering and processing assets service long-lived natural gas regions, including the Permian, Anadarko and Appalachian Basins. Our systems gather natural gas from oil and natural gas wells; process the raw natural gas into residue gas by extracting NGLs and removing impurities; and transport natural gas to interstate and public utility pipelines for delivery to customers. In the aggregate, our gathering and processing systems have approximately 7,400 receipt points, consisting primarily of individual well connections and, secondarily, central delivery points, which are linked to multiple wells. Our gathering systems interconnect with interstate and intrastate pipelines operated by El Paso Natural Gas Company; Enogex LLC; Kinder Morgan Texas Pipeline; Natural Gas Pipeline Company of America; Northern Natural Gas Company; ONEOK Gas Transportation, LLC; Panhandle Eastern Pipe Line Company, LP; and Southern Star Central Gas Pipeline, Inc. Our processing facilities are connected to NGL pipelines operated by Enterprise Partners, L.P.; ONEOK Hydrocarbon, L.P. and WTLPG.

Gathering Systems

WestOK. The WestOK gathering system is located in north central Oklahoma and southern Kansas’ Anadarko Basin. The gathering system has approximately 4,700 miles of active natural gas gathering pipelines with approximately 3,700 receipt points. The primary producers on the WestOK gathering system include Chesapeake Energy Corporation; SandRidge Exploration and Production, LLC; and Bluestem Marketing, LLC.

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WestTX. The WestTX gathering system, which we operate, and in which we have an approximate 72.8% ownership, has approximately 3,100 miles of active natural gas gathering pipelines and approximately 2,900 receipt points located across seven counties within the Permian Basin in West Texas. Pioneer Natural Resources Company (NYSE: PXD) (“Pioneer”), the largest active driller in the Spraberry Trend and a major producer in the Permian Basin, owns the remaining interest in the WestTX system. The primary producers on the WestTX gathering system include Pioneer; COG Operating, LLC; and Endeavor Energy Resources, LP.

Velma. The Velma gathering system is located in the Golden Trend and near the Woodford Shale areas of southern Oklahoma. The gathering system has approximately 1,200 miles of active pipelines with approximately 600 receipt points consisting primarily of individual well connections and, secondarily, central delivery points, which are linked to multiple wells. The primary producers on the Velma gathering system include Chesapeake Energy Corporation; Range Resources Corporation; and XTO Energy, Inc.

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Tennessee. The Tennessee gathering systems are located in the Appalachian Basin. The gathering systems have approximately 100 miles of natural gas gathering pipelines, with approximately 200 receipt points. A substantial portion of the natural gas we gather in Tennessee is derived from wells operated by Atlas Energy Resources. We have a gas gathering agreement with Atlas Energy Resources, which is intended to maximize the use of the gathering systems and the amount of natural gas we gather in the region. In addition, other natural gas producers have acreage positions in relatively close proximity to our assets.

Processing and Treating Plants

WestOK. The WestOK system processes natural gas through the Waynoka and Chester plants, which are active cryogenic natural gas processing facilities. The WestOK system’s processing operations have total name-plate capacity of approximately 258 MMCFD. The Waynoka processing plant, a 200 MMCFD plant located in Woods County, Oklahoma, began operations in December 2006. The Chester plant, a 28 MMCFD plant located in Woodward County, Oklahoma, began operations in 1981. A new 30 MMCFD refrigeration plant has been constructed at the Chaney Dell plant site and was placed in operation in January 2012. A new 200 MMCFD cryogenic plant has been purchased and is being installed at the Waynoka site and is expected to be operational in mid-2012. The addition of this plant will increase the WestOK name-plate capacity to approximately 458 MMCFD. We transport and sell natural gas to parties, including various marketing companies and pipelines, at the tailgate of the Waynoka, Chester and Chaney Dell plants and sell NGL production to ONEOK Hydrocarbon, L.P.

WestTX. The WestTX system processes natural gas through the Consolidator, Midkiff and Benedum processing plants. The Consolidator plant is a 150 MMCFD cryogenic facility in Reagan County, Texas. The facility started operations in November 2009 and replaced the Midkiff plant. The Midkiff plant is a 60 MMCFD cryogenic facility in Reagan County, Texas, which was recommissioned in 2011. The Benedum plant is a 45 MMCFD cryogenic facility in Upton County, Texas. Our WestTX

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processing operations have an aggregate processing name-plate capacity of approximately 255 MMCFD. We plan to construct a new 200 MMCFD cryogenic processing plant, to be known as the Driver plant, which will be constructed in two phases, with the first phase consisting of 100 MMCFD of processing capacity expected to be in service in the first quarter of 2013. The second phase will increase the plant’s capacity to 200 MMCFD and is scheduled to be operational in the first quarter of 2015. The additional plant will increase the WestTX aggregate processing name-plate capacity to approximately 455 MMCFD. We transport and sell natural gas to parties, including various marketing companies and pipelines, at the tailgate of the WestTX plants and sell NGL production to ONEOK Hydrocarbon, L.P.

Velma. The Velma processing plant, located in Stephens County, Oklahoma, is a cryogenic facility with a natural gas name-plate capacity of approximately 100 MMCFD. An expansion of 60 MMCFD is planned to be completed in mid-2012, which will increase name-plate capacity to 160 MMCFD. The Velma plant is one of only two facilities in the area capable of treating both high-content hydrogen sulfide and carbon dioxide gases, which are characteristic in this area. We have made capital expenditures at the facility to improve its efficiency and competitiveness, including installing electric-powered compressors rather than natural gas-powered compressors used by many of our competitors. We transport and sell natural gas to parties, including various marketing companies and pipelines, at the tailgate of the Velma plant and sell NGL production to ONEOK Hydrocarbon, L.P.

Natural Gas Supply

We have natural gas purchase, gathering and processing agreements with approximately 600 producers. These agreements provide for the purchase or gathering of natural gas under Fee-Based, POP or Keep-Whole arrangements. Many of the agreements provide for compression, treating, processing and/or low volume fees. Producers generally provide, in-kind, their proportionate share of compressor and plant fuel required to gather the natural gas and to operate our processing plants. In addition, the producers generally bear their proportionate share of gathering system line loss and, except for Keep-Whole arrangements, bear natural gas plant “shrinkage” for the gas consumed in the production of NGLs.

We have long-term relationships with several of our producers, some going back over 20 years. Several of our top producers have contracts with primary terms running into 2018 and beyond. At the end of the primary terms, most of the contracts with producers on our gathering systems have evergreen term extensions. When we acquired control of the WestTX system in July 2007, we and Pioneer agreed to extend the existing gas sales and purchase agreement to 2022. The gas sales and purchase agreement requires all Pioneer wells within an “area of mutual interest” be dedicated to that system’s gathering and processing operations in return for specified natural gas processing rates. Through this agreement, we anticipate we will continue to provide gathering and processing for the majority of Pioneer’s wells in the Spraberry Trend of the Permian Basin.

Natural Gas and NGL Marketing

We typically sell natural gas to purchasers downstream of our processing plants priced at various first-of-month indices as published in Inside FERC. Additionally, swing gas, which is natural gas sold during the current month, is sold daily at various Platt’s Gas Daily midpoint pricing points. The Velma plant has access to ONEOK Gas Transportation, LLC, Southern Star Central Gas Pipeline, Inc. and Natural Gas Pipeline Company of America. The Chaney Dell and Chester plants have access to Panhandle Eastern Pipe Line Company, LP. The Waynoka plant has access to Enogex LLC, Panhandle Eastern Pipe Line Company, LP and Southern Star Central Gas Pipeline, Inc. The WestTX plants have access to Kinder Morgan Texas Pipeline, Northern Natural Gas Company and El Paso Natural Gas Company.

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We sell our NGL production to ONEOK Hydrocarbon, L.P. under three separate agreements. The WestTX agreement has a term expiring in 2013; the WestOK agreement has a term expiring in 2014; and the Velma agreement has a term expiring at the end of 2016. We have signed agreements with DCP NGL Services, LLC (“DCP”), a subsidiary of DCP Midstream, LLC, to sell our NGL production from each of our processing facilities upon the expiration of each of the ONEOK Hydrocarbon, L.P. agreements. The DCP agreements each have a term of fifteen years. All NGL agreements are priced at the average daily Oil Price Information Service (or OPIS) price for the month for the selected market, subject to reduction by a “Base Differential” and quality adjustment fees.

Condensate is collected at the Velma gas plant and gathering system and currently sold to EnerWest Trading Company, LLC. Condensate collected at the WestOK plants and around the WestOK system is currently sold to Plains Marketing. Condensate collected at the WestTX plants and around the WestTX gathering system is currently sold to Plains Marketing, Occidental Energy Marketing, Inc. and Oasis Marketing and Transportation Corporation.

Commodity Risk Management

Our gathering and processing operations are exposed to certain commodity price risks. These risks result from either taking title to natural gas and NGLs, including condensate, or being obligated to purchase natural gas to satisfy contractual obligations with certain producers. We attempt to mitigate a portion of these risks through a commodity risk management program, which employs a variety of financial tools. The resulting combination of the underlying physical business and the commodity risk management program attempts to convert the physical price environment that consists of floating prices to a risk-managed environment characterized by fixed prices; floor prices on products where we are long the commodity price; and ceiling prices on products where we are short the commodity price. There are also risks inherent within risk management programs, including among others (1) price relationship between the physical and financial instrument deteriorating or (2) projected physical volumes changing.

We are exposed to commodity price risks when natural gas is purchased for processing. The amount and character of this price risk is a function of our contractual relationships with natural gas producers or, alternatively, a function of cost of sales. We are therefore exposed to price risk at a gross profit level rather than at a revenue level. These cost-of-sales or contractual relationships are generally of two types:

• POP: requires us to pay a percentage of revenue to the producer. This results in our being net long physical natural gas and NGLs.

• Keep-Whole: generally requires us to deliver the same quantity of natural gas (measured in BTU’s) at the delivery point as we received at the receipt point; any resulting NGLs produced belong to us, resulting in our being long physical NGLs and short physical natural gas.

We manage a portion of these risks by using fixed-for-floating swaps, which result in a fixed price for the products we buy or sell or by utilizing the purchase or sale of options, which result in floor prices or ceiling prices for the products we buy or sell. We utilize natural gas swaps and options to manage our natural gas price risks. We utilize NGL and crude oil swaps and options to manage our NGL and condensate price risks.

We generally realize gains and losses from the settlement of our derivative instruments at the same time we sell the associated physical residue gas or NGLs. We determine gains or losses on open and closed derivative transactions as the difference between the derivative contract price and the physical price. This mark-to-market methodology uses daily closing New York Mercantile Exchange

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(“NYMEX”) prices when applicable and an internally-generated algorithm, utilizing third party sources, for commodities not traded on an open market. To ensure these derivative instruments will be used solely for managing price risks and not for speculative purposes, we have established a committee to review our derivative instruments for compliance with our policies and procedures.

For additional information on our derivative activities and a summary of our outstanding derivative instruments as of December 31, 2011, please see “Item 7A: Quantitative and Qualitative Disclosures About Market Risk.”

Our Pipeline Transportation Operations

Our Pipeline Transportation operations consist of a 20% interest in WTLPG, which owns an approximately 2,200 mile common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. WTLPG is operated by Chevron Pipeline Company, an affiliate of Chevron, which owns the remaining 80% interest. Revenues are derived from fee-based transportation services.

Competition

Acquisitions. We have encountered competition in acquiring midstream assets owned by third parties. In several instances we submitted bids in auction situations and in direct negotiations for the acquisition of such assets and were either outbid by others or were unwilling to meet the sellers’ expectations. In the future, we expect to encounter equal, if not greater, competition for midstream assets.

Gathering and Processing. In our Gathering and Processing segment, we compete for the acquisition of well connections with several other gathering/processing operations. These operations include plants and gathering systems operated by Carrera Gas Company; Copano Energy, LLC; Crosstex

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Energy Services; DCP Midstream, LLC; Enogex, LLC; Hiland Partners, L.P.; Lumen Midstream Partners, LLC; Mustang Fuel Corporation; ONEOK Field Services Company; SemGas, L.P.; Southern Union Company; Superior Pipeline Company, LLC; Targa Resources Partners; and West Texas Gas, Inc.

We believe the principal factors upon which competition for new well connections is based are:

• the price received by an operator or producer for its production after deduction of allocable charges, principally the use of the natural gas to operate compressors;

• the quality and efficiency of the gathering systems and processing plants that will be utilized in delivering the gas to market;

• the access to various residue markets that provides flexibility for producers and ensures the gas will make it to market; and

• the responsiveness to a well operator’s needs, particularly the speed at which a new well is connected by the gatherer to its system.

We believe our relationships with operators connected to our system are good and that we present an attractive alternative for producers. However, if we cannot compete successfully, we may be unable to obtain new well connections.

Pipeline Transportation. In our Pipeline Transportation segment, we compete with other intrastate and interstate pipeline companies that transport NGLs in the southwestern region of the United States. These operations include NGL pipelines operated by Enterprise Partners, L.P.; Lonestar NGL, LLC; and ONEOK Partners, L.P. The factors that typically affect our ability to compete for NGL supplies are:

• fees charged under our contracts;

• the quality and efficiency of our operations in delivering the NGLs to market;

• location of our transportation systems relative to our competitors; and

• the responsiveness to a plant operator’s needs.

Seasonality

Our business is affected by seasonal fluctuations in commodity prices. Sales volumes are also affected by various factors such as fluctuating and seasonal demands for products and variations in weather patterns from year to year. Generally, natural gas demand increases during the winter months and decreases during the summer months. Freezing conditions can disrupt our gathering process, which could adversely affect our operating results.

Regulation

Gathering Pipeline Regulation. Section 1(b) of the Natural Gas Act of 1938, 15 U.S.C. § 717(b), exempts natural gas gathering facilities from the jurisdiction of FERC. We own a number of intrastate natural gas gathering lines in Kansas, Oklahoma and Texas that we believe meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. However,

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the distinction between FERC-regulated natural gas transportation facilities and federally unregulated natural gas gathering facilities is the subject of regular litigation, so the classification and regulation of some of our gathering facilities may be subject to change based on future determinations by FERC and the courts.

We are currently subject to state ratable take, common purchaser and/or similar statutes in one or more jurisdictions in which we operate. Common purchaser statutes generally require gatherers to purchase without discrimination as to source of supply or producer, while ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. In particular, Kansas, Oklahoma and Texas have adopted 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 natural gas gathering access and discrimination with respect to rates or terms of service. Should a complaint be filed or regulation by the Kansas Corporation Commission, the Oklahoma Corporation Commission or the Texas Railroad Commission become more active, our revenues could decrease. Collectively, any of these laws may restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or gather natural gas.

Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. Our gathering operations also may be or may become subject to 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 and 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.

Sales of Natural Gas and NGLs. A portion of our revenue is tied to the price of natural gas and NGLs. The wholesale price of natural gas and NGLs is not currently subject to federal regulation and, for the most part, is not subject to state regulation. Sales of natural gas and NGLs are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation of natural gas and NGLs are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting the segments of the natural gas industry, most notably interstate natural gas transportation companies that remain subject to FERC’s jurisdiction. While FERC is less active in proposing changes in the manner in which it regulates the transportation of NGLs under the Interstate Commerce Act, it does nevertheless have authority to address the rates, terms and conditions under which NGLs are transported. FERC initiatives could, therefore, affect the intrastate transportation of natural gas and NGLs under certain circumstances. We cannot predict the ultimate impact of any regulatory changes that could result from such FERC initiatives on our operations.

Energy Policy Act of 2005. The Energy Policy Act contains numerous provisions relevant to the natural gas industry and to interstate natural gas pipelines in particular. Overall, the legislation attempts to increase supply sources by calling for various studies of the overall resource base and attempting to advantage deep water production on the Outer Continental Shelf in the Gulf of Mexico. However, the provisions of primary interest to us as an operator of natural gas gathering lines and sellers of natural gas focus on two areas: (1) infrastructure development; and (2) market transparency and enhanced enforcement. Regarding infrastructure development, the Energy Policy Act includes provisions confirming FERC has exclusive jurisdiction over the siting of liquefied natural gas (“LNG”) terminals; provides for market-based rates for certain new underground natural gas storage facilities placed into service after the date of enactment; shortens depreciable life for gathering facilities; statutorily designates

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FERC as the lead agency for federal authorizations and permits relating to interstate natural gas pipelines and LNG terminals; provides for the assembly of a consolidated record for all federal decisions relating to necessary authorizations and permits with respect to interstate natural gas pipelines and LNG terminals; and provides for expedited judicial review of any agency action involving the permitting of such facilities and review by only the D.C. Circuit Court of Appeals of any alleged failure of a federal agency to act on a permit relating to an interstate natural gas pipeline or LNG terminal by a deadline set by FERC as lead agency. Such provisions, however, do not apply to review and authorization under the Coastal Zone Management Act of 1972. Regarding market transparency and manipulation, the Natural Gas Act has been amended to prohibit market manipulation and directs FERC to prescribe rules designed to encourage the public provision of data and reports regarding the price of natural gas in wholesale markets. The Natural Gas Act and the Natural Gas Policy Act were also amended to increase monetary criminal penalties to $1,000,000 from the $5,000 amount specified under prior law and to add and increase civil penalty authority to be administered by FERC to $1,000,000 per day per violation without any limitation as to total amount.

At present, we believe none of our gathering lines qualify as interstate natural gas transmission systems subject to FERC regulation under the Natural Gas Act. Accordingly, the provisions of the Energy Policy Act have only limited applicability to us, primarily in our capacity as a seller of natural gas.

Environmental Matters

The operation of pipelines, plant and other facilities for gathering, compressing, treating, processing, or transporting natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and 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:

• restricting the way we can handle or dispose of our wastes;

• limiting or prohibiting construction and operating activities in sensitive areas such as wetlands, coastal regions, non-attainment areas, tribal lands or areas inhabited by endangered species;

• requiring remedial action to mitigate pollution conditions caused by our operations or attributable to former operators; and

• enjoining some or all of the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where pollutants or wastes have been disposed or otherwise released. Neighboring landowners and other third parties can file claims for personal injury or property damage allegedly caused by noise and/or the release of pollutants or wastes into the environment.

We believe our operations are in substantial compliance with applicable environmental laws and regulations and compliance with existing federal, state and local environmental laws and regulations will not have a material adverse effect on our business, financial position or results of operations.

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Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, 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. Moreover, we cannot assure future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause us to incur significant costs.

Hazardous Waste. Our operations generate wastes, including some hazardous wastes subject to the federal Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state laws, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and solid waste. RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes associated with the exploration, development, or production of crude oil and natural gas. However, these oil and gas exploration and production wastes may still be regulated under state law or the solid waste requirements of RCRA. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils may be regulated as solid waste. The transportation of natural gas in pipelines may also generate some hazardous wastes that are subject to RCRA or comparable state law requirements.

We believe our operations are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes to be significant, any more stringent regulation of natural gas and oil exploration and production wastes could increase our costs to manage and dispose of such wastes.

Site Remediation. The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, or CERCLA, also known as “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at offsite locations such as landfills. Although petroleum and natural gas are excluded from CERCLA’s definition of “hazardous substance,” in the course of our ordinary operations we may generate wastes that may fall within the definition of a “hazardous substance.” CERCLA authorizes the Environmental Protection Agency, or EPA, and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Under CERCLA, we could be subject to joint and several, strict liability for the costs of cleaning up and restoring sites where hazardous substances have been released, for damages to natural resources, and for the costs of certain health studies.

We currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for the measurement, gathering, field compression and processing of natural gas. Although we used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such substances have been taken for disposal. There is evidence that petroleum spills or releases have occurred at some of the properties owned or leased by us. However, none of these spills or releases appear to be material to our financial condition and we believe all of them have been or will be appropriately remediated. In addition, some of these properties have been operated by third parties or by previous owners whose treatment and disposal or release of petroleum hydrocarbons or wastes was not under our control. These properties and the

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substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed wastes (including waste disposed of by prior owners or operators), remediate contaminated property (including groundwater contamination, whether from prior owners or operators or other historic activities or spills), or perform operations to prevent future contamination.

Air Emissions. Our operations are subject to the federal Clean Air Act, as amended and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our processing plants, certain storage vessels and 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 expected to produce air emissions or result in the increase of existing air emissions, obtain and comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions. Various air quality regulations are periodically reviewed by the EPA and are amended as deemed necessary. The EPA may also issue new regulations based on changing environmental concerns. Recently, the EPA issued amended regulations that will potentially affect operation of our compressor engine fleet by requiring implementation of new monitoring requirements in calendar year 2013. The EPA has proposed new oil and gas regulations that will potentially affect our operations in calendar year 2012 by requiring more stringent volatile organic compound emission control. 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 likely will be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe, however, 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 other similarly situated companies.

Water Discharges. Our operations are subject to the Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state and federal waters and also prohibit discharges of dredged and fill material in wetlands and other waters of the United States. Failure to comply with the requirements of the Clean Water Act could result in administrative, civil or criminal penalties as well as significant remedial obligations.

Pipeline Safety. Our pipelines are subject to regulation by the U.S. Department of Transportation, or DOT, under the Natural Gas Pipeline Safety Act of 1968, as amended, or the NGPSA. The NGPSA authorizes the DOT to regulate pipeline transportation of natural (flammable, toxic, or corrosive) gas and other gases, and requires any entity that owns or operates pipeline facilities to comply with the regulations. The DOT’s Pipeline and Hazardous Material Safety Administration, or PHMSA, acting through the Office of Pipeline Safety, or OPS, administers the national regulatory program to ensure safe transportation of natural gas, petroleum, and other hazardous materials by pipeline. The OPS administers the federal pipeline safety regulations to (1) ensure safety in design, construction, inspection, testing, operation, and maintenance of pipeline facilities and (2) set out parameters for administering the pipeline safety program.

Our operations are required to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. We believe our pipeline operations are in substantial compliance with existing PHMSA requirements, however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, future compliance with the PHMSA could result in additional requirements and costs.

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The Pipeline Safety Improvement Act of 2002 finalized a series of rules intended to require pipeline operators to develop integrity management programs for gas transportation pipelines that, in the event of a failure, could affect “high consequence areas.” “High consequence areas” are currently defined as areas with specified population densities, buildings containing populations of limited mobility, and areas where people gather that are located along the route of a pipeline. To ensure uniform implementation of the pipeline safety program nationwide, federal/state partnerships, including the Texas Railroad Commission, the Oklahoma Corporation Commission and other state agencies, have adopted similar regulations applicable to intrastate gathering and transportation lines. Compliance with these rules has not had a materially adverse effect on our operations but there is no assurance this will continue in the future.

On January 3, 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the “Act”) was signed into law. The Act directs the Secretary of Transportation to undertake a number of reviews, studies and reports in preparation for potential rulemakings applicable to pipeline facilities. The primary focus of the Act, however, is the operational safety of gas transmission and hazardous liquid transmission pipeline facilities, particularly in high consequence areas. The PHMSA is considering several safety related issues addressed in the Act, and has sought public comment on changes to a number of regulations related to pipeline safety. At this time, we cannot predict what effect, if any, the future application of such regulations might have on our operations, but the midstream natural gas industry could be required as a result to incur additional capital expenditures and increased operating costs.

Employee Health and Safety. We are subject to the requirements of the Occupational Safety and Health Act, as amended, or OSHA, and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens.

Hydrogen Sulfide. Exposure to gas containing high levels of hydrogen sulfide, referred to as sour gas, is harmful to humans, and prolonged exposure can result in death. The gas produced at our Velma gas plant contains high levels of hydrogen sulfide, and we employ numerous safety precautions at the system to ensure the safety of our employees. There are various federal and state environmental and safety requirements for handling sour gas, and we are in substantial compliance with all such requirements.

Chemicals of Interest. We operate several facilities registered with the U.S. Department of Homeland Security, or DHS, in order to identify the quantities of various chemicals stored at the sites. These facilities are the Velma, Chaney Dell, Waynoka, and Chester gas processing plants in Oklahoma and the Midkiff and Benedum gas processing plants in Texas. The liquid hydrocarbons recovered and stored as a result of facility processing activities, and various chemicals utilized within the processes, have been identified and registered with DHS. These registration requirements for Chemical of Interest were first promulgated by DHS in 2008 and we are currently in compliance with the Department’s requirements. None of our affected facilities are considered high security risks by DHS at this time and no specific security plans for such per DHS regulations are required.

Greenhouse Gases. In October 2009, the EPA published rules in Title 40 of the Code of Federal Regulations, part 98 (40 CFR 98) requiring mandatory reporting of greenhouse gases. The rule specifies methods by which entities that produce these gases, which include Carbon Dioxide (CO₂) and Methane (CH₄), must inventory, monitor and report such gases. Compliance with this rule has resulted, and will continue to result, in higher costs of doing business. Additionally, in 2010, the EPA issued rules to regulate greenhouse gas emissions through traditional major source construction and operating permit programs. These permitting programs require consideration of and, if deemed necessary, implementation

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of best available control technology to reduce greenhouse gas emissions. As a result, our operations could face additional costs for emissions control and higher costs of doing business. Although we would not be impacted to a greater degree than other similarly situated gatherers and processors of natural gas or NGLs, a stringent greenhouse gas control program could result in a significant effect on our cost of doing business.

Properties

Our principal facilities consist of seven natural gas processing plants; approximately 9,100 miles of active 2 to 30 inch diameter natural gas gathering lines; and approximately 2,200 miles of NGL transportation pipeline through our 20% interest in WTLPG. Substantially all of our gathering systems are constructed within rights-of-way granted by property owners named in the appropriate land records. In a few cases, property for gathering system purposes was purchased in fee. All of our compressor stations are located on property owned in fee or on property obtained via long-term leases or surface easements.

The following tables set forth certain information relating to our gas processing facilities and natural gas gathering systems:

Gas Processing Facilities

Facility	Location	Year Constructed	Design Throughput Capacity (MMCFD)		2011 Average Througput (MMCFD)		2011 Average Utilization Rate
Velma plant	Stephens County, OK	Updated 2003		100		98		98	%
Waynoka plant	Woods County, OK	2006		200
Chaney Dell plant	Major County, OK	2012		30
Chester plant	Woodward County, OK	1981		28
Total WestOK				258		254		98	%
Consolidator plant	Reagan County, TX	2009		150
Midkiff plant	Reagan County, TX	1990		60
Benedum plant	Upton County, TX	Updated 1981		45
Total WestTX				255		196		77	%

Natural Gas Gathering Systems

System	Location	Approximate Active Miles of Pipe		Approximate Number of Receipt Points
WestOK	North Central Oklahoma and Southern Kansas		4,700		3,700
Velma	Southern Oklahoma and Northern Texas		1,200		600
WestTX	West Texas		3,100		2,900
Tennessee	Tennessee		100		200

Our property or rights-of-way are subject to encumbrances, restrictions and other imperfections. These imperfections have not materially interfered, and we do not expect they will materially interfere, with the conduct of our business. In many instances, lands over which rights-of-way have been obtained are subject to prior liens, which have not been subordinated to the rights-of-way grants. In a few instances, our rights-of-way are revocable at the election of the land owners. In some cases, not all of the owners named in the appropriate land records have joined in the rights-of-way grants, but in substantially all such cases signatures of the owners of majority interests have been obtained. Substantially all permits

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have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets, and state highways, where necessary, although in some instances these permits are revocable at the election of the grantor. Substantially all permits have also been obtained from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election.

Certain of our rights to lay and maintain pipelines are derived from recorded gas well leases, with respect to wells currently in production; however, the leases are subject to termination if the wells cease to produce. In some of these cases, the right to maintain existing pipelines continues in perpetuity, even if the well associated with the lease ceases to be productive. Because many of these leases affect wells at the end of lines, these rights-of-way will not be used for any other purpose once the related wells cease to produce.

Employees

As is commonly the case with publicly-traded limited partnerships, we do not directly employ any of the persons responsible for our management or operations. In general, employees of ATLS and its affiliates manage our gathering systems and operate our business. ATLS employed approximately 280 people at December 31, 2011 who provided direct support to our operations.

Affiliates of our General Partner will conduct business and activities of their own in which we will have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition between us, our General Partner and affiliates of our General Partner for the time and effort of the officers and employees who provide services to our General Partner. Apart from our Chairman and Vice Chairman, the officers of our General Partner who provide services to us are generally assigned solely to our operations. However, they are not required to work full time on our affairs. These officers may also devote time to the affairs of our General Partner’s affiliates and be compensated by these affiliates for the services rendered to them. There may be conflicts between us and affiliates of our General Partner regarding the availability of these officers to manage us.

Available Information

We make our periodic reports under the Securities Exchange Act of 1934, including our annual report on Form 10-K, our quarterly reports on Form 10-Q and our current reports on Form 8-K, available through our website at www.atlaspipeline.com. To view these reports, click on “Investor Relations,” then “SEC Filings.” You may also receive, without charge, a paper copy of any such filings by request to us at Park Place Corporate Center One, 1000 Commerce Drive, 4^th Floor, Pittsburg, Pennsylvania 15275-1011, telephone number (877) 950-7473. A complete list of our filings is available on the Securities and Exchange Commission’s website at www.sec.gov. Any of our filings are also available at the Securities and Exchange Commission’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The Public Reference Room may be contacted at telephone number (800) 732-0330 for further information.

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ITEM 1A. RISK FACTORS

Partnership interests are inherently different from the 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 a similar business. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected.

Risks Relating to Our Business

The amount of cash we generate depends, in part, on factors beyond our control.

The amount of cash we generate may not be sufficient for us to pay distributions in the future. Our ability to make cash distributions depends primarily on our cash flows. Cash distributions do not depend directly on our profitability, which is affected by non-cash items. Therefore, cash distributions may be made during periods when we record losses and may not be made during periods when we record profits. The actual amounts of cash we generate will depend upon numerous factors relating to our business, which may be beyond our control, including:

• the demand for natural gas, NGLs, crude oil and condensate;

• the price of natural gas, NGLs, crude oil and condensate (including the volatility of such prices);

• the amount of NGL content in the natural gas we process;

• the volume of natural gas we gather and subsequently process;

• efficiency of our gathering systems and processing plants;

• expiration of significant contracts;

• continued development of wells for connection to our gathering systems;

• our ability to connect new wells to our gathering systems;

• our ability to integrate newly formed ventures or acquired businesses with our existing operations;

• the availability of local, intrastate and interstate transportation systems;

• the availability of fractionation capacity;

• the expenses we incur in providing our gathering services;

• the cost of acquisitions and capital improvements;

• required principal and interest payments on our debt;

• fluctuations in working capital;

• prevailing economic conditions;

• fuel conservation measures;

• alternate fuel requirements;

• the strength and financial resources of our competitors;

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• the effectiveness of our price risk management program and the creditworthiness of our derivatives counterparties;

• governmental (including environmental and tax) laws and regulations; and

• technical advances in fuel economy and energy generation devices.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:

• the level of capital expenditures we make;

• the sources of cash use to fund our acquisitions;

• limitations on our access to capital or the market for our common units and notes;

• our debt service requirements; and

• the amount of cash reserves established by our General Partner for the conduct of our business.

Our ability to make payments on and to refinance our indebtedness will depend on our financial and operating performance, which may fluctuate significantly from quarter to quarter, and is subject to prevailing economic and industry conditions and financial, business and other factors, many of which are beyond our control. We cannot assure that we will continue to generate sufficient cash flow or that we will be able to borrow sufficient funds to service our indebtedness, or to meet our working capital and capital expenditure requirements. If we are not able to generate sufficient cash flow from operations or to borrow sufficient funds to service our indebtedness, we may be required to sell assets or equity, reduce capital expenditures, refinance all or a portion of our existing indebtedness or obtain additional financing. We cannot assure that we will be able to refinance our indebtedness, sell assets or equity, or borrow more funds on terms acceptable to us, or at all.

Economic conditions and instability in the financial markets could negatively impact our business.

Our operations are affected by the financial markets and related effects in the global financial system. The consequences of an economic recession and the effects of the financial crisis include a lower level of economic activity and increased volatility in energy prices. This may result in a decline in energy consumption and lower market prices for oil and natural gas, and has previously resulted in a reduction in drilling activity in our service area and in wells currently connected to our pipeline system being shut in by their operators until prices improved. Any of these events may adversely affect our revenues and our ability to fund capital expenditures and, in turn, may impact the cash we have available to fund our operations, pay required debt service and make distributions to our unitholders.

Continuing instability in the financial markets, as a result of recession or otherwise, has increased the cost of capital while reducing the availability of funds. This may affect our ability to raise capital and reduce the amount of cash available to fund our operations. We rely on our cash flow from operations and borrowings under our existing credit facility to execute our growth strategy and to meet our financial commitments and other short-term liquidity needs. We cannot be certain that additional capital will be available to us to the extent required and on acceptable terms. Disruptions in the capital and credit markets could limit our access to liquidity needed for our business and impact our flexibility to react to changing economic and business conditions. Any disruption could require us to take measures to

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conserve cash until the markets stabilize or until we can arrange alternative credit arrangements or other funding for our business needs. Such measures could include reducing or delaying business activities, reducing our operations to lower expenses, and reducing other discretionary uses of cash. We may be unable to execute our growth strategy, take advantage of business opportunities or to respond to competitive pressures, any of which could negatively impact our business.

The continuing economic conditions could have an adverse impact on our lenders, producers, key suppliers or other customers, causing them to fail to meet their obligations to us. Market conditions could also impact our derivative instruments. If a counterparty is unable to perform its obligations and the derivative instrument is terminated, our cash flows and ability to make required debt service payments and pay distributions could be impacted. The uncertainty and volatility surrounding the global financial system may have further impacts on our business and financial condition that we currently cannot predict or anticipate.

We are affected by the volatility of prices for natural gas, NGL and crude oil products.

We derive a majority of our gross margin from POP and Keep-Whole contracts. As a result, our income depends to a significant extent upon the prices at which we buy and sell natural gas and at which we sell NGLs and condensate. Average estimated unhedged 2012 market prices for NGLs, natural gas and crude oil, based upon NYMEX forward price curves as of January 4, 2012, were $1.10 per gallon, $3.02 per MMBTU and $93.76 per barrel, respectively. A 10% change in these prices would change our forecasted gross margin for the twelve-month period ended December 31, 2012 by approximately $10.8 million. Additionally, changes in natural gas prices may indirectly impact our profitability since prices can influence drilling activity and well operations, and could cause operators of wells currently connected to our pipeline system or that we expect will be connected to our system to shut in their production until prices improve, thereby affecting the volume of gas we gather and process. Historically, the prices of natural gas, NGLs and crude oil have been subject to significant volatility in response to relatively minor changes in the supply and demand for these products, market uncertainty and a variety of additional factors beyond our control, including those we describe in “––The amount of cash we generate depends, in part, on factors beyond our control,” above. West Texas Intermediate crude oil prices have traded in a range of $75.67 per barrel to $113.93 per barrel in 2011, while Henry Hub natural gas prices have traded in a range of $2.99 per MMBTU to $4.85 per MMBTU, during the same time period. We expect this volatility to continue. This volatility may cause our gross margin and cash flows to vary widely from period to period. Our price risk management strategies may not be sufficient to offset price volatility risk and, in any event, do not cover all the throughput volumes. Moreover, derivative instruments are subject to inherent risks, which we describe in “—Our price risk management strategies may fail to protect us and could reduce our gross margin and cash flows.”

Our price risk management strategies may fail to protect us and could reduce our gross margin and cash flows.

Our operations expose us to fluctuations in commodity prices. We utilize derivative contracts related to the future price of crude oil, natural gas and NGLs with the intent of reducing the volatility of our cash flows due to fluctuations in commodity prices. To the extent we protect our commodity price using certain derivative contracts we may forego the benefits we would otherwise experience if commodity prices were to change in our favor. Our commodity price risk management activity may fail to protect or could harm us because, among other things:

• entering into derivative instruments can be expensive, particularly during periods of volatile prices;

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• available derivative instruments may not correspond directly with the risks against which we seek protection;

• price relationship between the physical transaction and the derivative transaction could change;

• the anticipated physical transaction could be different than projected due to changes in contracts, lower production volumes or other operational impacts, resulting in possible losses on the derivative instrument, which are not offset by income on the anticipated physical transaction; and

• the party owing money in the derivative transaction may default on its obligation to pay.

Regulations promulgated by the Commodities Futures Trading Commission could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. The Dodd-Frank Wall Street Reform and Consumer Protection Act, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The legislation requires the Commodities Futures Trading Commission, or CFTC, and the SEC to promulgate rules and regulations implementing the new legislation. The CFTC finalized its regulations and has set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our existing or future derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts; materially alter the terms of derivative contracts; reduce the availability of derivatives to protect against risks we encounter; reduce our ability to monetize or restructure our derivative contracts in existence at that time; and increase our exposure to less creditworthy counterparties. If we reduce or change the way we use derivative instruments as a result of the legislation or regulations, our results of operations may become more volatile and cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations and/or cash flows.

We are exposed to the credit risks of our key customers, and any material nonpayment or nonperformance by our key customers could negatively impact our business.

We have historically experienced minimal collection issues with our counterparties; however our revenue and receivables are highly concentrated in a few key customers and therefore we are subject to risks of loss resulting from nonpayment or nonperformance by our key customers. In an attempt to reduce this risk, we have established credit limits for each customer and we attempt to limit our credit risk by obtaining letters of credit, guarantees or other appropriate forms of security. Nonetheless, we have key customers whose credit risk cannot realistically be otherwise mitigated. Any material nonpayment or

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nonperformance by our key customers could impact our cash flows and ability to make required debt service payments and pay distributions.

Due to our lack of asset diversification, negative developments in our operations could reduce our ability to fund our operations, pay required debt service and make distributions to our common unitholders.

We rely primarily on the revenues generated from our gathering and processing operations, and as a result, our financial condition depends upon prices of, and continued demand for, natural gas, NGLs and condensate. Due to our lack of asset-type diversification, a negative development in these businesses could have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets.

The amount of natural gas we gather will decline over time unless we are able to attract new wells to connect to our gathering systems.

Production of natural gas from a well generally declines over time until the well can no longer economically produce natural gas and is plugged and abandoned. Failure to connect new wells to our gathering systems could, therefore, result in the amount of natural gas we gather declining substantially over time and could, upon exhaustion of the current wells, cause us to abandon one or more of our gathering systems and, possibly, cease operations. The primary factors affecting our ability to connect new supplies of natural gas to our gathering systems include our success in contracting for existing wells not committed to other systems, the level of drilling activity near our gathering systems and our ability to attract natural gas producers away from our competitors’ gathering systems.

Over time, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. A decrease in exploration and development activities in the fields served by our gathering and processing facilities could result if there is a sustained decline in natural gas, crude oil and/or NGL prices, which in turn, would lead to a reduced utilization of these assets. The decline in the credit markets, the lack of availability of credit, debt or equity financing and the decline in natural gas prices may result in a reduction of producers’ exploratory drilling. We have no control over the level of drilling activity in our service areas, the amount of reserves underlying wells that connect to our systems and the rate at which production from a well will decline. In addition, we have no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, drilling costs, geological considerations, governmental regulation and the availability and cost of capital. In a low price environment, producers may determine to shut in wells already connected to our systems until prices improve. Because our operating costs are fixed to a significant degree, a reduction in the natural gas volumes we gather or process would result in a reduction in our gross margin and cash flows.

The success of our operations depends upon our ability to continually find and contract for new sources of natural gas supply.

Our agreements with most producers with which we do business generally do not require them to dedicate significant amounts of undeveloped acreage to our systems. While we do have some undeveloped acreage dedicated on our systems, most notably with our partner Pioneer on our WestTX system, we do not have assured sources to provide us with new wells to connect to our gathering systems. Failure to connect new wells to our operations, as described in “—The amount of natural gas we gather will decline over time unless we are able to attract new wells to connect to our gathering systems,” above, could reduce our gross margin and cash flows.

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We may face increased competition in the future.

We face competition for well connections. Carrera Gas Company; Copano Energy, LLC; DCP Midstream, LLC; Enogex, LLC and ONEOK Field Services Company, operate competing gathering systems and processing plants in our Velma service area. DCP Midstream, LLC; Hiland Partners, L.P.; Lumen Midstream Partners, LLC; Mustang Fuel Corporation; ONEOK Field Services Company; SemGas, L. P.; and Superior Pipeline Company, LLC operate competing gathering systems and processing plants in our WestOK service area. Crosstex Energy Services; DCP Midstream, LLC; Southern Union Company; Targa Resources Partners; and West Texas Gas, Inc. operate competing gathering systems and processing plants in our WestTX service area. Some of our competitors have greater financial and other resources than we do. If these companies become more active in our service areas, we may not be able to compete successfully with them in securing new well connections or retaining current well connections. If we do not compete successfully, the amount of natural gas we gather and process will decrease, reducing our gross margin and cash flows.

We currently depend on certain key producers for their supply of natural gas; the loss of any of these key producers could reduce our revenues.

During 2011, Apache, Inc.; Bluestem Gas Marketing; BNK Petroleum, Inc.; Chesapeake Energy Corporation; COG Operating LLC; Endeavor Energy Resources LP; Pioneer; Range Resources Corporation; SandRidge Exploration and Production, LLC and XTO Energy Inc. accounted for a significant amount of our natural gas supply. If these producers reduce the volumes of natural gas they supply to us, our gross margin and cash flows could be reduced unless we obtain comparable supplies of natural gas from other producers.

If we are unable to obtain new rights-of-way or the cost of renewing existing rights-of-way increases, our cash flows could be reduced.

We do not own all the land on which our pipelines are constructed. We obtain the rights to construct and operate our pipelines on land owned by third parties for a specific period of time, therefore we are subject to the possibility of more onerous terms 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 may be unable to obtain rights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. 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 and financial condition. If the cost of obtaining new rights-of-way or renewing existing rights-of-way increases, then our cash flows could be reduced.

The amount of natural gas we gather or process may be reduced if the natural gas liquids pipelines or fractionation facilities to which we deliver NGLs cannot or will not accept the NGLs.

If one or more of the pipelines or fractionation facilities to which we deliver NGLs has service interruptions, capacity limitations or otherwise cannot or will not accept the NGLs we sell or transport, and we cannot arrange for delivery to other pipelines or facilities, the amount of NGLs we process, sell or transport may be reduced. Since our revenues depend upon the volumes of NGLs we sell or transport, this could result in a material reduction in our gross margin and cash flows.

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The amount of natural gas we gather or process may be reduced if the intrastate and interstate pipelines to which we deliver gas cannot or will not accept the gas.

Our gathering systems principally serve as intermediate transportation facilities between wells connected to our systems and the intrastate or interstate pipelines to which we deliver natural gas. If one or more of these pipelines has service interruptions, capacity limitations or otherwise cannot or will not accept the natural gas we gather, and we cannot arrange for delivery to other pipelines, local distribution companies or end users, the amount of natural gas we gather may be reduced. Since our revenues depend upon the volumes of natural gas we gather, this could result in a material reduction in our gross margin and cash flows.

Failure of the natural gas or NGLs we deliver to meet the specifications of interconnecting pipelines could result in curtailments by the pipelines.

The pipelines to which we deliver natural gas and NGLs typically establish specifications for the products they are willing to accept. These specifications include requirements such as hydrocarbon dew point, compositions, temperature, and foreign content (such as water, sulfur, carbon dioxide, and hydrogen sulfide), and these specifications can vary by product or pipeline. If the total mix of a product that we deliver to a pipeline fails to meet the applicable product quality specifications, the pipeline may refuse to accept all or a part of the products scheduled for delivery to it or may invoice us for the costs to handle the out-of-specification products. In those circumstances, we may be required to find alternative markets for that product or to shut-in the producers of the non-conforming natural gas causing the products to be out of specification, potentially reducing our through-put volumes or revenues.

The curtailment of operations at, or closure of, any of our processing plants could harm our business.

Our assets and operations can be adversely affected by hurricanes, floods, earthquakes, tornadoes and other natural phenomena and weather conditions, including extreme temperatures. If operations at any of our processing plants were to be curtailed, or closed, whether due to natural catastrophe, accident, environmental regulation, periodic maintenance, or for any other reason, our ability to process natural gas from the relevant gathering system and, as a result, our ability to extract and sell NGLs, would be harmed. If this curtailment or stoppage were to extend for more than a short period, our gross margin and cash flows could be materially reduced.

The loss of key personnel could adversely affect our ability to operate.

Our ability to manage and grow our business effectively may be adversely affected if we lose key management or operational personnel. We depend on the continuing efforts of our executive officers. The departure of any of our executive officers could have a significant negative impact on our business, operating results, financial condition, and on our ability to compete effectively in the marketplace. Additionally, our ability to hire, train, and retain qualified personnel will continue to be important and will become more challenging as we grow. Our ability to grow and to continue our current level of service to our customers will be adversely impacted if we are unable to successfully hire, train and retain these important personnel.

The scope and costs of the risks involved in making acquisitions may prove greater than estimated at the time of the acquisition.

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

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• the risk that reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;

• mistaken assumptions about revenues and costs, including synergies;

• significant increases in our indebtedness and working capital requirements;

• delays in obtaining any required regulatory approvals or third party consents;

• the imposition of conditions on any acquisition by a regulatory authority;

• an inability to integrate successfully or timely the businesses we acquire;

• the assumption of unknown liabilities;

• limitations on rights to indemnity from the seller;

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

• increased demands on existing personnel;

• customer or key employee losses at the acquired businesses; and

• the failure to realize expected growth or profitability.

The scope and cost of these risks may ultimately be materially greater than estimated at the time of the acquisition. Further, our future acquisition costs may be higher than those we have achieved historically. Any of these factors could adversely impact our future growth and our ability to make or increase distributions.

We may be unsuccessful in integrating the operations from any future acquisitions with our operations and in realizing all the anticipated benefits of these acquisitions.

We have an active, on-going program to identify potential acquisitions. Our integration of previously independent operations with our own can be a complex, costly and time-consuming process. The difficulties of combining these systems with existing systems include, among other things:

• operating a significantly larger combined entity;

• the necessity of coordinating geographically disparate organizations, systems and facilities;

• integrating personnel with diverse business backgrounds and organizational cultures;

• consolidating operational and administrative functions;

• integrating pipeline safety-related records and procedures;

• integrating internal controls, compliance under Sarbanes-Oxley Act of 2002 and other corporate governance matters;

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

• customer or key employee loss from the acquired businesses;

• a significant increase in our indebtedness; and

• potential environmental or regulatory liabilities and title problems.

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Our investment and the additional overhead costs we incur to grow our business may not deliver the expected incremental volume or cash flow. Costs incurred and liabilities assumed in connection with the acquisition and increased capital expenditures and overhead costs incurred to expand our operations could harm our business or future prospects, and result in significant decreases in our gross margin and cash flows.

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

We are actively growing our business through the construction of new assets. The construction of additions or modifications to our existing systems and facilities, and the construction of new assets, involve numerous regulatory, environmental, political and legal uncertainties beyond our control and require the expenditure of significant amounts of capital. Any projects we undertake 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 gathering system, the construction may occur over an extended period of time, and we will not receive any material increase in revenues until the project is completed. Moreover, we are constructing facilities to capture anticipated future growth in production in a region in which growth may not materialize. Since we are not engaged in the exploration for, and development of, natural gas reserves, we often do not have access to estimates of potential reserves in an area before constructing facilities in the area. To the extent we rely on estimates of future production in our decision to construct additions to our systems, the estimates may prove to be inaccurate due to 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 impair our results of operations and financial condition. In addition, our actual revenues from a project could materially differ from expectations as a result of the price of natural gas, the NGL content of the natural gas processed and other economic factors described in this section.

We continue to expand the natural gas gathering systems surrounding our facilities in order to maximize plant throughput. In addition to the risks discussed above, expected incremental revenue from recent projects could be reduced or delayed due to the following reasons:

• difficulties in obtaining capital for additional construction and operating costs;

• difficulties in obtaining permits or other regulatory or third-party consents;

• additional construction and operating costs exceeding budget estimates;

• revenue being less than expected due to lower commodity prices or lower demand;

• difficulties in obtaining consistent supplies of natural gas; and

• terms in operating agreements that are not favorable to us.

We may not be able to execute our growth strategy successfully.

Our strategy contemplates substantial growth through both the acquisition of other gathering systems and processing assets and the expansion of our existing gathering systems and processing assets. Our growth strategy involves numerous risks, including:

• we may not be able to identify suitable acquisition candidates;

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• we may not be able to make acquisitions on economically acceptable terms for various reasons, including limitations on access to capital and increased competition for a limited pool of suitable assets;

• our costs in seeking to make acquisitions may be material, even if we cannot complete any acquisition we have pursued;

• irrespective of estimates at the time we make an acquisition, the acquisition may prove to be dilutive to earnings and operating surplus;

• we may encounter delays in receiving regulatory approvals or may receive approvals that are subject to material conditions;

• we may encounter difficulties in integrating operations and systems; and

• any additional debt we incur to finance an acquisition may impair our ability to service our existing debt.

Limitations on our access to capital or the market for our common units could impair our ability to execute our growth strategy.

Our ability to raise capital for acquisitions and other capital expenditures depends upon ready access to the capital markets. Historically, we have financed our acquisitions and expansions through bank credit facilities, public and private debt and proceeds from equity offerings of common and preferred units. If we are unable to access the capital markets, we may be unable to execute our growth strategy.

Our debt levels and restrictions in our revolving credit facility could limit our ability to fund operations and pay required debt service.

We will need a portion of our cash flows to make principal and interest payments on our indebtedness, which will reduce the funds that would otherwise be available for operations and future business opportunities. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying business activities, acquisitions, investments and/or capital expenditures; selling assets; restructuring or refinancing our indebtedness; or seeking additional equity capital or bankruptcy protection. We may not be able to affect any of these remedies on satisfactory terms, or at all.

Our revolving credit facility and the indenture governing our senior notes contain covenants limiting the ability to incur indebtedness, grant liens, engage in transactions with affiliates and make distributions to unitholders. Our revolving credit facility also contains covenants requiring us to maintain certain financial ratios.

We may issue additional units, which may increase the risk of not having sufficient available cash to make distributions at prior per unit distribution levels.

We have wide discretion to issue additional units, including units that rank senior to our common units as to quarterly cash distributions, on the terms and conditions established by our General Partner. The payment of distributions on these additional units may increase the risk that we will not be able to make distributions at our prior per unit distribution levels. To the extent new units are senior to our common units, their issuance will increase the uncertainty of the payment of distributions on the common units.

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Increases in interest rates could adversely affect our unit price.

Credit markets recently have experienced record lows in interest rates. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related 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. A rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity or to incur debt to make acquisitions or for other purposes and could impact our ability to make cash distributions.

Regulation of our gathering operations could increase our operating costs, decrease our revenues, or both.

Currently we believe our gathering and processing of natural gas is exempt from FERC regulation under the Natural Gas Act of 1938. However, the implementation of new laws or policies, or changed interpretations of existing laws, could subject our gathering and processing operations to regulation by FERC under the Natural Gas Act, the Natural Gas Policy Act, or other laws. We expect any such regulation could increase our costs, decrease our gross margin and cash flows, or both.

Even if our gathering and processing operations are not generally subject to regulation under the Natural Gas Act, FERC regulation will still affect our business and the market for our products. FERC’s policies and practices affect a range of natural gas pipeline activities. Among these are FERC policies on interstate natural gas pipeline open access transportation, ratemaking, capacity release, environmental protection and market center promotion, which indirectly affect intrastate markets. FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. We cannot assure that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity.

Since federal law generally leaves any economic regulation of natural gas gathering to the states, state and local regulations may also affect our business. Matters subject to such regulation include conditions of access, rates, terms of service and safety. For example, our gathering lines are subject to ratable take, common purchaser, and similar statutes in one or more jurisdictions in which we operate. Common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer, while ratable take statutes generally require gatherers to take, without discrimination, natural gas production that may be tendered to the gatherer for handling. Kansas, Oklahoma and Texas have adopted 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 natural gas gathering access and discrimination with respect to rates or terms of service. Should a complaint be filed or regulation by the Texas Railroad Commission, Oklahoma Corporation Commission or Kansas Corporation Commission become more active, our revenues could decrease. Collectively, all of these statutes may restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or gather natural gas.

Compliance with pipeline integrity regulations issued by the DOT and state agencies could result in substantial expenditures for testing, repairs and replacement.

DOT and state agency regulations require pipeline operators to develop integrity management programs for transportation pipelines located in “high consequence areas.” The regulations require operators to:

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• perform ongoing assessments of pipeline integrity;

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

• improve data collection, integration and analysis;

• repair and remediate the pipeline as necessary; and

• implement preventative and mitigating actions.

While we do not believe that the cost of implementing integrity management program testing along segments of our pipeline will have a material effect on our results of operations, the costs of any repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program could be substantial.

Our midstream natural gas operations could incur significant costs if PHMSA adopts more stringent regulations governing our business.

On January 3, 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, or the “Act,” was signed into law. The Act directs the Secretary of Transportation to undertake a number of reviews, studies and reports, some of which may result in natural gas and hazardous liquids pipeline safety rulemakings. These rulemakings will be conducted by PHMSA.

PHMSA is already considering several of the natural gas pipeline safety issues addressed in the Act. On August 25, 2011, PHMSA published an advance notice of proposed rulemaking in which the agency is seeking public comment on a number of changes to regulations governing the safety of gas transmission pipelines, gathering lines and related facilities. PHMSA has requested comment on whether PHMSA should: (1) re-define the term “gathering line;” (2) require the submission of annual, incident and safety-related conditions reports by operators of all gathering lines; (3) establish a new, risk-based regime of safety requirements for large-diameter, high pressure gas gathering lines in rural locations; (4) enhance the requirements for internal corrosion control of gathering lines; and (5) apply its gas integrity management requirements to onshore gas gathering lines. Comments in response to this advance notice were due on January 20, 2012.

The adoption of regulations that apply more comprehensive or stringent safety standards to gathering lines could require us to install new or modified safety controls, incur additional capital expenditures, or conduct maintenance programs on an accelerated basis. Such requirements could result in our incurrence of increased operational costs that could be significant and could have a material adverse effect on our financial position or results of operations and our ability to make distributions to our unitholders.

Our midstream natural gas operations may incur significant costs and liabilities resulting from a failure to comply with new or existing environmental regulations or a release of hazardous substances into the environment by us or the producers in our service areas.

The operations of our gathering systems, plants and other facilities are subject to stringent and complex federal, state and local environmental laws and regulations. These laws and regulations may restrict or impact our business activities in many ways, including restricting the manner in which we dispose of substances, requiring remedial action to remove or mitigate contamination, or requiring capital expenditures to comply with control requirements. Failure to comply with these laws and regulations

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may trigger a variety of administrative, civil or criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where substances and wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury or property damage allegedly caused by the release of regulated substances or wastes into the environment.

There is inherent risk of the incurrence of environmental costs and liabilities in our business due to our handling of natural gas and other petroleum products, air emissions related to our operations, historical industry operations including releases of regulated substances into the environment, and waste disposal practices. For example, an accidental release from one of our pipelines or processing facilities could subject us to substantial liabilities arising from (1) environmental cleanup, restoration costs and natural resource damages; (2) claims made by neighboring landowners and other third parties for personal injury and property damage; and (3) fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies, including those relating to emissions from production, processing and transmission activities, could significantly increase our compliance costs and the cost of any remediation that may become necessary. Producers in our service areas may curtail or abandon exploration and production activities if any of these regulations cause their operations to become uneconomical. We may not be able to recover some or any of these costs from insurance.

Climate change legislation or regulations restricting emissions of greenhouse gases (“GHGs”) could result in increased operating costs and reduced demand for our midstream services.

In response to findings that emissions of carbon dioxide, methane, and other GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the earth’s atmosphere and other climate changes, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that require entities that produce certain gases to inventory, monitor and report such gases. On November 30, 2010, the EPA published a final GHG emissions reporting rule relating to natural gas processing, transmission, storage, and distribution activities, which requires reporting beginning in 2012 for emissions occurring in 2011. Additionally, in 2010, EPA issued rules to regulate GHG emissions through traditional major source construction and operating permit programs. These permitting programs require consideration of and, if deemed necessary, implementation of best available control technology to reduce GHG emissions. As a result, our operations could face additional costs for emissions control and higher costs of doing business.

Litigation or governmental regulation relating to environmental protection and operational safety may result in substantial costs and liabilities.

Our operations are subject to federal and state environmental laws under which owners of natural gas pipelines can be liable for clean-up costs and penalties in connection with any pollution caused by their pipelines. We may also be held liable for clean-up costs resulting from pollution that occurred before our acquisition of a gathering system. In addition, we are subject to federal and state safety laws that dictate the type of pipeline, quality of pipe protection, depth of pipelines, methods of welding and other construction-related standards. Any violation of environmental, construction or safety laws could impose substantial liabilities and costs on us.

We are also subject to the requirements of OSHA, and comparable state statutes. Any violation of OSHA could impose substantial costs on us.

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We cannot predict whether or in what form any new legislation or regulatory requirements might be enacted or adopted, nor can we predict our future costs of compliance. In general, we expect new regulations would increase our operating costs and, possibly, require us to obtain additional capital to pay for improvements or other compliance actions necessitated by those regulations.

We are subject to operating and litigation risks that may not be covered by insurance.

Our operations are subject to all operating hazards and risks incidental to gathering and processing natural gas and NGLs. These hazards include:

• damage to pipelines, plants, related equipment and surrounding properties caused by floods and other natural disasters;

• inadvertent damage from construction;

• leakage of natural gas, NGLs and other hydrocarbons;

• fires and explosions; and

• other hazards, including those associated with high-sulfur content, or sour gas, that could also result in personal injury and loss of life, pollution and suspension of operations.

As a result, we may be a defendant in various legal proceedings and litigation arising from our operations. 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 some of our insurance policies have increased substantially, and could escalate further. In some instances, insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we were not fully insured, our gross margin and cash flows would be materially reduced.

The threat of terrorist attacks has resulted in increased costs, and future war or risk of war may adversely impact our results of operations and our ability to raise capital.

Terrorist attacks or the threat of terrorist attacks cause instability in the global financial markets and other industries, including the energy industry. Infrastructure facilities, including pipelines, production facilities, and transmission and distribution facilities, could be direct targets, or indirect casualties, of an act of terror. Our insurance policies generally exclude acts of terrorism. Such insurance is not available at what we believe to be acceptable pricing levels.

Risks Relating to Our Ownership Structure

ATLS and its affiliates have conflicts of interest and limited fiduciary responsibilities, which may permit it to favor its own interests to the detriment of our unitholders.

ATLS owns and controls our General Partner. We do not have any employees and rely solely on employees of ATLS and its affiliates, who serve as our agents, including all of the senior managers who operate our business. A number of officers and employees of ATLS also own interests in us. Conflicts of interest may arise between ATLS, our General Partner and its affiliates, on the one hand, and us, on the other hand. As a result of these conflicts, our General Partner may favor its own interests and the interests of its affiliates over our interests and the interests of our unitholders. These conflicts could include, among others, the following situations:

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• Employees of ATLS who provide services to us may also devote time to the businesses of ATLS in which we have no economic interest. If these separate activities are greater than our activities, there could be material competition for the time and effort of the employees who provide services to our General Partner, which could result in insufficient attention to the management and operation of our business.

• Neither our partnership agreement nor any other agreement requires ATLS to pursue a future business strategy that favors us or uses our assets for gathering or processing services we provide. ATLS’ directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of ATLS.

• Our General Partner is allowed to take into account the interests of parties other than us, such as ATLS, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to us.

• Our General Partner controls the enforcement of obligations owed to us by our General Partner and its affiliates.

Conflicts of interest with ATLS and its affiliates, including the foregoing factors, could exacerbate periods of lower or declining performance, or otherwise reduce our gross margin and cash flows.

Cost reimbursements due to our general partner may be substantial.

We reimburse ATLS, our General Partner and its affiliates, including officers and directors of ATLS, for all expenses they incur on our behalf. Our General Partner has sole discretion to determine the amount of these expenses. In addition, ATLS provides us with services for which we are charged reasonable fees as determined by ATLS in its sole discretion. The reimbursement of expenses or payment of fees could adversely affect our ability to fund our operations and pay required debt service.

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; and

• the market price of the common units may decline.

Our control of the WestOK and WestTX systems is limited by provisions of the limited liability company operating agreements with Anadarko and, with respect to the WestTX system, the operation and expansion agreement with Pioneer.

The managing member of each of the limited liability companies, which owns the interests in the WestOK and WestTX systems, is our subsidiary. However, the consent of Anadarko is required for specified extraordinary transactions, such as admission of new members, engaging in transactions with our affiliates not approved by the company conflicts committee, incurring debt outside the ordinary course of business and disposing of company assets above specified thresholds. The WestTX system is also governed by an operation and expansion agreement with Pioneer, which gives system owners having

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at least a 60% interest in the system the right to approve the annual operating budget and capital investment budget and to impose other limitations on the operation of the system. Thus, a holder of a greater than 40% interest in the system would effectively have a veto right over the operation of the system. Pioneer currently owns an approximate 27% interest in the system.

We own a non-controlling interest in WTLPG and may have limited ability to influence significant business decisions affecting this entity.

We have a 20% non-controlling ownership interest in WTLPG, which could adversely affect our ability to operate and control this entity. In addition, we may be unable to control the amount of cash we will receive from the operation of WTLPG and we could be required to contribute significant cash to fund our share of their operations, which could adversely affect our ability to distribute cash to our unitholders.

Tax Risks Relating to Unit Ownership

If we were treated as a corporation for federal income tax purposes, or if we were to become subject to entity-level taxation for federal or state income tax purposes, then our cash available for distribution to our unitholders could be substantially reduced.

We are currently treated as a partnership for federal income tax purposes, which requires that 90% or more of our gross income for every taxable year consist of qualifying income, as defined in Section 7704 of the Internal Revenue Code. Qualifying income is defined as income and gains derived from the exploration, development, mining or production, processing, refining, transportation (including pipelines transporting gas, oil, or products thereof), or the marketing of any mineral or natural resource (including fertilizer, geothermal energy, and timber). We may not meet this requirement or current law may change so as to cause, in either event, us to be treated as a corporation for federal income tax purposes or otherwise subject to federal income tax. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.

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. Distributions to our unitholders would generally be taxed again as corporate dividends, 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. Thus, treatment of us as a corporation would result in a material reduction in our anticipated cash flows, likely causing a substantial reduction in the value of our units.

Current tax law may change, causing us to be treated as a corporation for federal and/or state income tax purposes or otherwise subjecting us to entity level taxation. For example, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to our unitholders would be reduced.

Unitholders may be required to pay taxes on income from us even if they do not receive any cash distributions from us.

Unitholders may be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the tax liability, which results from the taxation of their share of our taxable income.

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

If a unitholder sells their common units, they will recognize a gain or loss equal to the difference between the amount realized and the adjusted tax basis in those common units. Prior distributions and the allocation of losses, including depreciation deductions, to the unitholder in excess of the total net taxable income allocated to them, which decreased the tax basis in their common units, will, in effect, become taxable income to them if the common units are sold at a price greater than their tax basis in those common units, even if the price is less than the original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to the unitholder.

Tax-exempt entities and foreign 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, including 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 exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.

We treat each purchaser of our common units as having the same tax benefits without regard to the 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 will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. 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 on the sale of common units and could have a negative impact on the value of our common units or result in audits of and adjustments to our unitholders’ tax returns.

The sale or exchange of 50% or more of our capital and profits interest within a 12-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 interest in our capital and profits within a 12-month period. The 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 for the year in which the termination occurs. Thus, if this occurs, the unitholder will be allocated an increased amount of federal taxable income for the year in which we are considered to be terminated as a percentage of the cash distributed to the unitholder with respect to that period.

Unitholders may be subject to state and local taxes and return filing requirements as a result of investing in our common units.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if our unitholders do not reside in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these

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jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We presently anticipate substantially all of our income will be generated in Oklahoma, Texas and Kansas. Each of those states, except Texas, currently imposes a personal income tax. We may do business or own property in other states in the future. It is the responsibility of each unitholder to file all United States federal, state and local tax returns that may be required of such unitholder. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in the common units.

The IRS may challenge our tax treatment related to transfers of units, 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. 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, the market for our common units may be adversely affected, and the costs of any such contest will reduce cash available for distributions to our unitholders.

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 our positions. A court may not agree with some or all of our positions. Any contest with the IRS may materially and adversely impact the market for our common units and the prices at which they trade. In addition, we will bear the costs of any contest with the IRS thereby reducing the cash available for distribution to our unitholders.

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

When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to such assets to the capital accounts of our unitholders and our General Partner. Although we may from time to time consult with professional appraisers regarding valuation matters, including the valuation of our assets, we make many of the fair market value estimates of our assets ourselves using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. 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 current valuation methods, subsequent purchasers of our 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 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 on the sale of common units by our unitholders and could have a negative impact on the value of our common units or result in audit adjustments to the tax returns of our unitholders without the benefit of additional deductions.

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A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

ITEM 1B: UNRESOLVED STAFF COMMENTS

N/A

ITEM 2: PROPERTIES

A description of our properties is contained within Item 1, “Business –Properties.”

ITEM 3: LEGAL PROCEEDINGS

N/A

ITEM 4: [REMOVED AND RESERVED]

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PART II

ITEM 5: MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common units are listed on the New York Stock Exchange under the symbol “APL.” At the close of business on February 20, 2012, the closing price for the common units was $36.06 and there were 85 record holders, one of which is the holder for all beneficial owners who hold in street name.

The following table sets forth the range of high and low sales prices of our common units and distributions declared by quarter per unit on our common limited partner units for the years ended December 31, 2011 and 2010:

	High		Low		Distributions Declared
2011
Fourth Quarter	$	37.20	$	26.50	$	0.55
Third Quarter		35.44		24.12		0.54
Second Quarter		37.90		30.10		0.47
First Quarter		34.74		23.42		0.40
2010
Fourth Quarter		25.80		17.43		0.37
Third Quarter		18.92		8.98		0.35
Second Quarter		14.99		8.35		0.00
First Quarter		14.71		9.63		0.00

Our Cash Distribution Policy

Our partnership agreement requires we distribute 100% of available cash to our General Partner and common limited partners within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Available cash consists generally of all our cash receipts, less cash disbursements and net additions to reserves, including any reserves required under debt instruments for future principal and interest payments.

Our General Partner is granted discretion by our partnership agreement to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, rate refunds and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When our General Partner determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.

Available cash is initially distributed 98% to our common limited partners and 2% to our General Partner. These distribution percentages are modified to provide for incentive distributions to be paid to our General Partner if quarterly distributions to common unitholders exceed specified targets, as follows:

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Minimum Distributions Per Unit Per Quarter		Percent of Available Cash in Excess of Minimum Allocated to General Partner(1)
	$    0.42	15%
	0.52	25%
	0.60	50%

(1) Percent allocated to APL’s General Partner includes 2% general partner interest in addition to incentive distributions.

We make distributions of available cash to common unitholders regardless of whether the amount distributed is less than the minimum quarterly distribution. Incentive distributions are generally defined as all cash distributions paid to our General Partner that are in excess of 2% of the aggregate amount of cash being distributed. Our General Partner, the holder of all our incentive distribution rights, has agreed to allocate up to $3.75 million of its incentive distribution rights per quarter back to us after the General Partner receives the initial $7.0 million per quarter of incentive distribution rights. The General Partner’s incentive distributions paid for the year ended December 31, 2011 were $1.7 million. There were no General Partner incentive distributions paid for the year ended December 31, 2010.

For information concerning units authorized for issuance under our long-term incentive plans, see “Item 12: Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.”

ITEM 6: SELECTED FINANCIAL DATA

The following table should be read together with our consolidated financial statements and notes thereto included within “Item 8: Financial Statements and Supplementary Data” and “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this report. We have derived the selected financial data set forth in the table for each of the years ended December 31, 2011, 2010 and 2009 and at December 31, 2011 and 2010 from our consolidated financial statements appearing elsewhere in this report, which have been audited by Grant Thornton LLP, independent registered public accounting firm. We derived the financial data for the years ended December 31, 2008 and 2007 from our consolidated financial statements, which were audited by Grant Thornton LLP and are not included within this report.

The selected financial data set forth in the table includes our historical consolidated financial statements, which have been adjusted to reflect the following:

• We reclassified accelerated amortization of deferred financing costs from interest expense to loss on early extinguishment of debt.

• We adjusted prior period consolidated financial statements to separately present derivative gain (loss) within derivative loss, net instead of combining these amounts in other income, net.

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	Years Ended December 31,
	2011			2010(1)			2009(1)			2008(1)			2007(1)(2)
	(in thousands)
Statements of operations data:
Revenue:
Natural gas and liquids sales	$	1,268,195		$	890,048		$	636,231		$	1,078,714		$	527,094
Transportation, compression and other fees		43,799			41,093			59,075			87,442			50,695
Derivative gain (loss)(1)		(20,452	)		(5,945	)		(35,815	)		29,741			(104,524	)
Other income, net(1)		11,192			10,392			13,114			6,844			5,252
Total revenues		1,302,734			935,588			672,605			1,202,741			478,517
Costs and expenses:
Natural gas and liquids cost of sales		1,047,025			720,215			527,730			900,460			407,994
Plant operating		54,686			48,670			45,566			47,371			22,974
Transportation and compression		833			1,061			6,657			11,249			6,235
General and administrative(3)		36,357			34,021			37,280			(2,933	)		59,600
Other costs		1,040			—			—			—			—
Depreciation and amortization		77,435			74,897			75,684			71,764			34,453
Goodwill and other asset impairment loss		—			—			10,325			615,724			—
Interest(1)		31,603			87,273			101,309			87,422			59,017
Total costs and expenses		1,248,979			966,137			804,551			1,731,057			590,273
Equity income in joint venture		5,025			4,920			4,043			—			—
Gain (loss) on asset sales and other(4)		256,272			(10,729	)		108,947			—			—
Gain (loss) on early extinguishment of debt(1)		(19,574	)		(4,359	)		(2,478	)		17,420			(4,972	)
Income (loss) from continuing operations		295,478			(40,717	)		(21,434	)		(510,896	)		(116,728	)
Income (loss) from discontinued operations		(81	)		321,155			84,148			(93,802	)		(23,641	)
Net income (loss)		295,397			280,438			62,714			(604,698	)		(140,369	)
(Income) loss attributable to non-controlling interests(5)		(6,200	)		(4,738	)		(3,176	)		22,781			(3,940	)
Preferred unit dividend effect		—			—			—			—			(3,756	)
Preferred unit imputed dividend cost		—			—			—			(505	)		(2,494	)
Preferred unit dividends		(389	)		(780	)		(900	)		(1,769	)		—
Net income (loss) attributable to common limited partners and the General Partner	$	288,808		$	274,920		$	58,638		$	(584,191	)	$	(150,559	)

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	Years Ended December 31,
	2011			2010			2009			2008			2007(2)
	(in thousands, except per unit data)
Allocation of net income (loss) attributable to:
Common limited partner interest:
Continuing operations	$	281,449		$	(45,347	)	$	(24,997	)	$	(503,533	)	$	(139,905	)
Discontinued operations		(79	)		315,021			82,457			(91,917	)		(23,166	)
		281,370			269,674			57,460			(595,450	)		(163,071	)
General Partner interest:
Continuing operations		7,440			(888	)		(513	)		13,144			12,987
Discontinued operations		(2	)		6,134			1,691			(1,885	)		(475	)
		7,438			5,246			1,178			11,259			12,512
Net income (loss) attributable to:
Continuing operations		288,889			(46,235	)		(25,510	)		(490,389	)		(126,918	)
Discontinued operations		(81	)		321,155			84,148			(93,802	)		(23,641	)
	$	288,808		$	274,920		$	58,638		$	(584,191	)	$	(150,559	)
Net income (loss) attributable to common limited partners per unit:
Basic:
Continuing operations	$	5.22		$	(0.85	)	$	(0.52	)	$	(11.80	)	$	(5.74	)
Discontinued operations		—			5.92			1.71			(2.16	)		(0.95	)
	$	5.22		$	5.07		$	1.19		$	(13.96	)	$	(6.69	)
Diluted(6):
Continuing operations	$	5.22		$	(0.85	)	$	(0.52	)	$	(11.80	)	$	(5.74	)
Discontinued operations		—			5.92			1.71			(2.16	)		(0.95	)
	$	5.22		$	5.07		$	1.19		$	(13.96	)	$	(6.69	)
Balance sheet data (at period end):
Property, plant and equipment, net	$	1,567,828		$	1,341,002		$	1,327,704		$	1,415,517		$	1,258,602
Total assets		1,930,812			1,764,848			2,137,963			2,413,196			2,875,451
Total debt, including current portion		524,140			565,974			1,254,183			1,493,427			1,229,426
Total equity		1,236,228			1,041,647			723,527			650,842			1,271,797
Cash flow data:
Net cash provided by (used in):
Operating activities	$	102,867		$	106,427		$	55,853		$	(59,194	)	$	100,444
Investing activities		67,763			594,753			241,123			(292,944	)		(2,024,643	)
Financing activities		(170,626	)		(702,037	)		(297,400	)		341,242			1,935,059
Other financial data (unaudited):
Gross margin from continuing operations (7)	$	264,923		$	210,580		$	163,677		$	273,493		$	167,525
EBITDA (8)		398,235			450,543			256,368			(409,397	)		(36,773	)
Adjusted EBITDA (8)		181,026			209,799			174,808			322,515			183,496
Maintenance capital expenditures	$	18,247		$	10,921		$	3,750		$	4,787		$	6,383
Expansion capital expenditures		227,179			35,715			106,524			176,869			40,268
Total capital expenditures	$	245,426		$	46,636		$	110,274		$	181,656		$	46,651

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	Years Ended December 31,
	2011		2010		2009		2008		2007(2)
Operating data (unaudited):
Velma system:
Gathered gas volume (MCFD)		103,328		84,455		76,378		63,196		62,497
Processed gas volume (MCFD)		98,126		78,606		73,940		60,147		60,549
Residue Gas volume (MCFD)		80,330		64,138		58,350		47,497		47,234
NGL volume (BPD)		11,433		9,218		8,232		6,689		6,451
Condensate volume (BPD)		423		416		377		280		225
WestOK system(9):
Gathered gas volume (MCFD)		268,329		228,684		270,703		276,715		259,270
Processed gas volume (MCFD)		254,394		214,695		215,374		245,592		253,523
Residue Gas volume (MCFD)		230,907		193,200		228,261		239,498		221,066
NGL volume (BPD)		13,635		12,395		13,418		13,263		12,900
Condensate volume (BPD)		898		697		824		791		572
WestTX system(9):
Gathered gas volume (MCFD)		212,775		178,111		159,568		144,081		147,240
Processed gas volume (MCFD)		196,412		163,475		149,656		135,496		141,568
Residue Gas volume (MCFD)		133,857		105,982		101,788		92,019		94,281
NGL volume (BPD)		29,052		26,678		21,261		19,538		20,618
Condensate volume (BPD)		1,500		1,289		1,265		1,142		1,346
Tennessee system
Average throughput volume – (MCFD)		7,698		8,740		7,907		1,951		—

(1) Adjusted to reflect the reclassification of accelerated amortization of deferred financing costs from interest expense to loss on early extinguishment of debt and the separate presentation of derivative gain (loss) within derivative loss, net instead of combining these amounts in other income, net.

(2) Includes our acquisition of control of a 100% interest in the WestOK natural gas gathering system and processing plants and a 72.8% undivided joint interest in the WestTX natural gas gathering system and processing plants on July 27, 2007, representing approximately five months’ operations for the year ended December 31, 2007. Operating data for the WestOK and WestTX systems represent 100% of its operating activity.

(3) Includes non-cash compensation (income) expense of $3.3 million, $3.5 million, $0.7 million, ($34.0) million and $36.3 million for the years ended December 31, 2011, 2010, 2009, 2008 and 2007, respectively.

(4) Represents the gain on sale of assets to Laurel Mountain Midstream, LLC (“Laurel Mountain”) in 2009 and the gain on sale of our 49% non-controlling interest in Laurel Mountain in 2011 (see “Item 8: Financial Statements and Supplementary Data –
Note 3”).

(5) Represents Anadarko’s non-controlling interest in the operating results of the WestOK and WestTX systems, which we acquired on July 27, 2007.

(6) For the years ended December 31, 2010, 2009, 2008 and 2007, approximately 300,000, 82,000, 146,000 and 164,000 phantom units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such phantom units would have been anti-dilutive. For the years ended December 31, 2010 and 2009, 75,000 and 100,000 unit options were excluded, respectively, from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such unit options would have been anti-dilutive. For the year ended December 31, 2009, potential common limited partner units issuable upon exercise of our warrants were excluded from computation of diluted net loss attributable to common limited partners as the impact of the conversion would have been anti-dilutive. For the years ended December 31, 2008 and 2007, potential common limited partner units issuable upon conversion of our $1,000 par value Class A and Class B cumulative convertible preferred limited partner units were excluded from the computation of diluted net income (loss) attributable to common limited partners as the impact of the conversion would have been anti-dilutive.

(7) We define gross margin from continuing operations as natural gas and liquids sales and transportation, compression and other fees less purchased product costs. Product costs include the cost of natural gas and NGLs we purchase from third parties, subject to certain non-cash adjustments. Gross margin, as we define it, does not include plant operating expenses; transportation and compression expenses; and derivative gain (loss) related to ineffective or undesignated hedges, as movements in gross margin generally do not result in directly correlated movements in these categories. Plant operating and transportation and compression expenses generally include the costs required to operate and maintain our pipelines and processing facilities, including salaries and wages, repair and maintenance expense, real estate taxes and other overhead costs. Our management views gross margin as an important performance measure of core profitability for our operations and as a key component of our internal financial reporting. We believe investors benefit from having access to the same financial measures that our management uses. The following table reconciles our revenues and costs to gross margin from continuing operations (in thousands):

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RECONCILIATION OF GROSS MARGIN FROM CONTINUING OPERATIONS

	Years Ended December 31,
	2011			2010			2009			2008			2007(2)
	(in thousands)
Revenue:
Natural gas and liquids sales	$	1,268,195		$	890,048		$	636,231		$	1,078,714		$	527,094
Transportation, compression and other fees		43,799			41,093			59,075			87,442			50,695
Total revenues for gross margin		1,311,994			931,141			695,306			1,166,156			577,789
Natural gas and liquids cost of sales		(1,047,025	)		(720,215	)		(527,730	)		(900,460	)		(407,994	)
Adjustments:
Non-cash linefill loss (gain) (10)		(46	)		(346	)		(3,899	)		7,797			(2,270	)
Gross margin	$	264,923		$	210,580		$	163,677		$	273,493		$	167,525

(8) EBITDA represents net income (loss) before net interest expense, income taxes, and depreciation and amortization. Adjusted EBITDA is calculated by adding to EBITDA other non-cash items such as compensation expenses associated with unit issuances, principally to directors and employees, impairment charges and other cash items such as the non-recurring cash derivative early termination expense (see “Item 8: Financial Statements and Supplementary Data –Note 11”). EBITDA and Adjusted EBITDA are not intended to represent cash flow and do not represent the measure of cash available for distribution. Our method of computing EBITDA and Adjusted EBITDA may not be the same method used to compute similar measures reported by other companies. The Adjusted EBITDA calculation below is similar to the Consolidated EBITDA (see “Item 8: Financial Statements and Supplementary Data –Note 13”) calculation utilized within our financial covenants under our credit facility, with the exception that Adjusted EBITDA includes (1) EBITDA from the discontinued operations related to the sale of Elk City; (2) the unrecognized economic impact of WestOK and WestTX acquisition, and (3) other non-cash items specifically excluded under our credit facility.

Certain items excluded from EBITDA and Adjusted EBITDA are significant components in understanding and assessing an entity’s financial performance, such as their cost of capital and its tax structure, as well as historic costs of depreciable assets. We have included information concerning EBITDA and Adjusted EBITDA because they provide investors and management with additional information to better understand our operating performance and are presented solely as a supplemental financial measure. EBITDA and Adjusted EBITDA should not be considered as alternatives to, or more meaningful than, net income or cash flow as determined in accordance with generally accepted accounting principles or as indicators of our operating performance or liquidity. The following table reconciles net income (loss) to EBITDA and EBITDA to Adjusted EBITDA (in thousands):

RECONCILIATION OF EBITDA AND ADJUSTED EBITDA

	Years Ended December 31,
	2011			2010(1)			2009(1)			2008(1)			2007(1)(2)
	(in thousands)
Net income (loss)	$	295,397		$	280,438		$	62,714		$	(604,698	)	$	(140,369	)
Adjustments:
(Income) loss attributable to non-controlling interests from continuing operations(5)		(6,200	)		(4,738	)		(3,176	)		22,781			(3,940	)
Interest expense		31,603			87,273			101,309			87,422			59,017
Other interest		—			604			443			—			—
Depreciation and amortization		77,435			74,897			75,684			71,764			34,453
Discontinued operations interest expense, depreciation and amortization		—			12,069			19,394			13,334			14,066
EBITDA	$	398,235		$	450,543		$	256,368		$	(409,397	)	$	(36,773	)

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RECONCILIATION OF EBITDA AND ADJUSTED EBITDA

	Years Ended December 31,
	2011			2010(1)			2009(1)			2008(1)			2007(1)(2)
	(in thousands)
EBITDA	$	398,235		$	450,543		$	256,368		$	(409,397	)	$	(36,773	)
Adjustments:
Equity income in joint venture		(5,025	)		(4,920	)		(4,043	)		—			—
Distributions from joint venture		4,448			11,066			4,310			—			—
Unrecognized economic impact of WestOK and WestTX acquisition(11)		—			—			—			—			10,423
Long-lived asset impairment loss		—			—			10,325			—			—
Goodwill impairment loss, net of associated non-controlling interest		—			—			—			585,053			—
Gain on asset sales and other(12)		(256,191	)		(301,373	)		(162,518	)		—			—
Loss on early extinguishment of debt		19,574			4,359			2,478			2,447			4,972
Non-cash (gain) loss on derivatives		4,538			(10,166	)		74,644			(113,640	)		99,543
Non-recurring net cash derivative early termination expense(13)		—			22,401			2,260			102,146			—
Premium expense on derivative instruments		12,219			21,123			9,693			3,736			—
Non-cash compensation (income) expense		3,274			3,484			701			(34,010	)		36,306
Non-cash line fill loss (gain) (10)		(46	)		(346	)		(3,899	)		7,797			(2,270	)
Other non-cash items(14)		—			—			—			—			1,414
Discontinued operations adjustments(15)		—			13,628			(15,511	)		178,383			69,881
Adjusted EBITDA	$	181,026		$	209,799		$	174,808		$	322,515		$	183,496

(9) Volumetric data for the WestOK and WestTX systems for the year ended December 31, 2007 represents volumes recorded for the 158-day period from July 27, 2007, the date of our acquisition, through December 31, 2007.

(10) Includes the non-cash impact of commodity price movements on pipeline linefill.

(11) The acquisition of the WestOK and WestTX systems was consummated on July 27, 2007, although the acquisition’s effective date was July 1, 2007. As such, we receive the economic benefits of ownership of the assets as of July 1, 2007. However, in accordance with generally accepted accounting principles, we have only recorded the results of the acquired assets commencing on the closing date of the acquisition. The economic benefits of ownership we received from the acquired assets from July 1 to July 27, 2007 were recorded as a reduction of the consideration paid for the assets.

(12) For the year-ended December 31, 2011, includes the gain on the sale of our non-controlling interest in Laurel Mountain. For the year ended December 31, 2010, includes the gain on the sale of Elk City and expenses related to the sale of our non-controlling interest in Laurel Mountain. For the year ended December 31, 2009, includes the gain on the sale of assets to Laurel Mountain and the gain on sale of the NOARK gas gathering and interstate pipeline system.

(13) During the years ended December 31, 2010, 2009 and 2008, we made net payments of $33.7 million, $5.0 million and $274.0 million, respectively, which resulted in a net cash expense recognized of $33.7 million, $5.0 million and $197.6 million, respectively, related to the early termination of derivative contracts principally entered into as proxy hedges for the prices received on the ethane and propane portion of our NGL equity volume. These derivative contracts were put into place simultaneously with our acquisition of the WestOK and WestTX systems in July 2007. The 2008 settlements were funded through our June 2008 issuance of 5.75 million common limited partner units in a public offering and issuance of 1.39 million common limited partner units to Atlas Energy, L.P. and Atlas Energy, Inc. in a private placement. In connection with this transaction, we also entered into an amendment to our credit facility to revise the definition of Consolidated EBITDA to allow for the add-back of charges relating to the early termination of certain derivative contracts for debt covenant calculation purposes when the early termination of derivative contracts is funded through the issuance of common equity.

(14) Includes the cash proceeds received from the sale of Enville plant and the non-cash loss recognized within our statements of operations.

(15) Includes non-cash (gain) loss on derivatives, non-recurring cash derivative early termination and premium expense on derivative instruments recorded in discontinued operations.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with our consolidated financial statements and related notes thereto appearing elsewhere in this report.

General

We are a publicly-traded Delaware limited partnership formed in 1999 whose common units are listed on the New York Stock Exchange under the symbol “APL.” We are a leading provider of natural gas gathering and processing services in the Anadarko and Permian Basins located in the southwestern and mid-continent regions of the United States; a provider of natural gas gathering services in the Appalachian Basin in the northeastern region of the United States; and a provider of NGL transportation services in the southwestern region of the United States.

Due to the sale of our 49% non-controlling interest in Laurel Mountain Midstream, LLC (“Laurel Mountain”), a Delaware limited liability company, and our acquisition of a 20% interest in West Texas LPG Pipeline Limited Partnership (“WTLPG”) (see “–Recent Events”), we realigned the management of our business in the midstream segment of the natural gas industry into two new reportable segments: Gathering and Processing; and Pipeline Transportation.

The Gathering and Processing segment consists of (1) the WestOK, WestTX and Velma operations, which are comprised of natural gas gathering and processing assets servicing drilling activity in the Anadarko and Permian Basins, and which were formerly included within the previous Mid-Continent segment; (2) the natural gas gathering assets located in Tennessee, which were formerly included in the previous Appalachia segment; and (3) the revenues and gain on sale related to our 49% interest in Laurel Mountain, which were formerly included in the previous Appalachia segment. Gathering and Processing revenues are primarily derived from the sale of residue gas and NGLs and gathering and processing of natural gas.

Our Gathering and Processing operations, own, have interests in and operate seven natural gas processing plants with aggregate capacity of approximately 610 MMCFD, which are connected to approximately 9,000 miles of active natural gas gathering systems located in Oklahoma, Kansas and Texas. In addition, we own and operate approximately 100 miles of active natural gas gathering systems located in Tennessee. Our gathering systems gather gas from wells and central delivery points and deliver to natural gas processing plants, as well as third-party pipelines.

Our Pipeline Transportation operations consist of a 20% interest in WTLPG, which was acquired on May 11, 2011 (see “–Recent Events”). WTLPG owns a common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. WTLPG is operated by Chevron Pipeline Company, an affiliate of Chevron Corporation, a Delaware corporation (“Chevron” –NYSE: CVX), which owns the remaining 80% interest.

Recent Events

On February 17, 2011, we completed the sale to Atlas Energy Resources, LLC of our 49% non-controlling interest in Laurel Mountain (the “Laurel Mountain Sale”) for $409.5 million in cash, net of expenses and adjustments based on certain capital contributions we made to and distributions we received from Laurel Mountain after January 1, 2011. We utilized the proceeds from the sale to repay our indebtedness, to fund capital expenditures, and for general corporate purposes. We retained the preferred

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distribution rights under the limited liability company agreement of Laurel Mountain entitling APL Laurel Mountain, LLC, our wholly-owned subsidiary, to receive all payments made under a $25.5 million note issued to Laurel Mountain by Williams Laurel Mountain, LLC in connection with the formation of Laurel Mountain. The $8.5 million remaining balance of the note was paid by Williams in December 2011.

On April 7, 2011, we purchased $7.2 million, or 3.24%, of the outstanding 8.75% senior unsecured notes due on June 15, 2018 (“8.75% Senior Notes”), which represented all the 8.75% Senior Notes validly tendered pursuant to our offer to purchase the 8.75% Senior Notes, at par, and paid $0.2 million in accrued and unpaid interest for a total payment of $7.4 million (see “–Senior Notes”). We funded the purchase from a portion of the net proceeds from the sale of our 49% non-controlling interest in Laurel Mountain.

On April 8, 2011, we redeemed all our 8.125% senior unsecured notes due on December 15, 2015 (“8.125% Senior Notes”) for a total redemption of $293.7 million, including accrued interest of $7.0 million and premium of $11.2 million (see “–Senior Notes”). We funded the redemption with a portion of the net proceeds from the sale of our 49% non-controlling interest in Laurel Mountain.

On May 11, 2011, we acquired a 20% interest in WTLPG from Buckeye Partners, L.P. for $85.0 million. WTLPG owns an approximately 2,200 mile common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation and is operated by Chevron Pipeline Company, an affiliate of Chevron, which owns the remaining 80% interest.

On May 12, 2011, we announced planned major expansions to our existing gas gathering and processing systems including, (1) a $175.0 million expansion of our WestOK system; (2) a $75.0 million expansion of our Velma system; (3) a $15.0 million re-start of the cryogenic skid at the Midkiff plant in our WestTX system; and (4) an additional $50.0 million in growth capital for compression, gathering lines and connections that are expected to be incurred in 2012.

On May 27, 2011, we redeemed our 8,000 units of Class C Preferred Units for cash at the liquidation value of $1,000 per unit, or $8.0 million plus $0.2 million accrued dividends. There are no longer any Class C Preferred Units outstanding (see “–Preferred Units”).

On July 8, 2011, we exercised the $100.0 million accordion feature on our revolving credit facility to increase the capacity from $350.0 million to $450.0 million. The other terms of the credit agreement remain unchanged.

On July 15, 2011, we amended an operating lease for eight compressors to include a mandatory purchase of the equipment at the end of the term of the lease, thereby converting the agreement into a capital lease upon the effective date of the amendment, and capitalized $11.4 million within property plant and equipment with an offsetting liability within debt on our consolidated balance sheets based on the minimum payments required under the lease and our incremental borrowing rate.

On August 29, 2011, we signed long-term product sales agreements with DCP NGL Services, LLC (“DCP”), a subsidiary of DCP Midstream, LLC, to sell our NGL production from each of our processing facilities in Oklahoma and Texas. The agreements are based on Mt. Belvieu NGL pricing and each has a term of fifteen years, which will become effective at various times upon expiration of our existing NGL sales agreements.

On November 15, 2011, we announced plans to construct a new 200 MMCFD cryogenic processing plant within our WestTX system, to be known as the Driver plant. The plant is planned to be

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constructed in two phases, with the first phase consisting of a 100 MMCFD processing plant expected to be in service in the first quarter of 2013. The second phase, to increase the plant capacity to 200 MMCFD, is scheduled to be complete in the first quarter of 2015.

On November 21, 2011, we issued $150.0 million of our 8.75% Senior Notes in a private placement transaction. The 8.75% Senior Notes were issued at a premium of 103.5% of the principal amount for a yield of 7.82% (see “–Senior Notes”). We received net proceeds of $152.4 million after underwriting commissions and other transaction costs, and utilized the proceeds to reduce the outstanding balance on our revolving credit facility.

Acquisitions

In May 2011, we acquired a 20% interest in WTLPG from Buckeye Partners, L.P. WTLPG owns a common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu for fractionation and is operated by Chevron Pipeline Company, an affiliate of Chevron, which owns the remaining 80% interest (see “–Recent Events”).

Dispositions

On May 4, 2009, we completed the sale of our NOARK gas gathering and interstate pipeline system to Spectra Energy Partners OLP, LP (NYSE:SEP) (“Spectra”) for net proceeds of $294.5 million in cash, net of working capital adjustments, and recorded a gain of $51.1 million within discontinued operations.

On May 31, 2009, we completed the formation of Laurel Mountain, a joint venture, with subsidiaries of The Williams Companies, Inc. (NYSE: WMB) (“Williams”). Williams contributed cash of $100.0 million to the joint venture (of which we received approximately $87.8 million, net of working capital adjustments) and a note receivable of $25.5 million. We contributed our Appalachia natural gas gathering system and retained a 49% non-controlling ownership interest in Laurel Mountain. Williams obtained the remaining 51% ownership interest in Laurel Mountain. We recognized a gain on sale of $108.9 million, including $54.2 million associated with the revaluation of our investment in Laurel Mountain to fair value.

On September 16, 2010, we completed the sale of our Elk City and Sweetwater, Oklahoma natural gas gathering systems, and the related processing and treating facilities (including the Prentiss treating facility and the Nine Mile processing plant, collectively “Elk City”) to a subsidiary of Enbridge Energy Partners, L.P. (NYSE: EEP) for $682.0 million in cash, excluding working capital adjustments and transaction costs, and recognized a gain of $312.1 million within discontinued operations.

On February 17, 2011, we completed the Laurel Mountain Sale to Atlas Energy Resources for $409.5 million in cash, net of expenses and adjustments and recognized a gain of $254.1 million (see “–Recent Events”).

Contractual Revenue Arrangements

Our principal revenue is generated from the gathering and sale of natural gas, NGLs and condensate. Variables that affect our revenue are:

• the volumes of natural gas we gather and process, which in turn, depend upon the number of wells connected to our gathering systems, the amount of natural gas the wells produce, and the demand for natural gas, NGLs and condensate;

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• the price of the natural gas we gather and process and the NGLs and condensate we recover and sell, which is a function of the relevant supply and demand in the mid-continent, mid-Atlantic and northeastern areas of the United States;

• the NGL and BTU content of the gas gathered and processed;

• the contract terms with each producer; and

• the efficiency of our gathering systems and processing plants.

Revenue consists of the sale of natural gas and NGLs and the fees earned from our gathering and processing operations. Under certain agreements, we purchase natural gas from producers and move it into receipt points on our pipeline systems and then sell the natural gas and NGLs off delivery points on our systems. Under other agreements, we gather natural gas across our systems, from receipt to delivery point, without taking title to the natural gas. (See “Item 8: Financial Statements and Supplementary Data –Note 2–Revenue Recognition” for further discussion of contractual revenue arrangements).

Recent Trends and Uncertainties

The midstream natural gas industry links the exploration and production of natural gas and the delivery of its components to end-use markets and provides natural gas gathering, compression, dehydration, treating, conditioning, processing, fractionation and transportation services. This industry group is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.

We face competition in obtaining natural gas supplies for our processing and related services operations. Competition for natural gas supplies is based primarily on the location of gas gathering facilities and gas processing plants, operating efficiency and reliability, and the ability to obtain a satisfactory price for products recovered. Competition for customers is based primarily on price, delivery capabilities, quality of assets, flexibility, service history and maintenance of high-quality customer relationships. Many of our competitors operate as master limited partnerships and enjoy a cost of capital comparable to, and in some cases lower than, ours. Other competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than ours. Smaller local distributors may enjoy a marketing advantage in their immediate service areas. We believe the primary difference between us and some of our competitors is that we provide an integrated and responsive package of midstream services, while some of our competitors provide only certain services. We believe offering an integrated package of services, while remaining flexible in the types of contractual arrangements that we offer producers, allows us to compete more effectively for new natural gas supplies in our regions of operations.

As a result of our POP and Keep-Whole contracts, our results of operations and financial condition substantially depend upon the price of natural gas, NGLs and crude oil (see “Item 8. Financial Statements and Supplementary Data –Note 2 –Revenue Recognition”). We believe future natural gas prices will be influenced by supply deliverability, the severity of winter and summer weather and the level of United States economic growth. Based on historical trends, we generally expect NGL prices to follow changes in crude oil prices over the long term, which we believe will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy. However, energy market uncertainty has negatively impacted North American

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drilling activity in the past. Lower drilling levels and shut-in wells over a sustained period would have a negative effect on natural gas volumes gathered and processed.

We are exposed to commodity prices as a result of being paid for certain services in the form of natural gas, NGLs and condensate rather than cash. We closely monitor the risks associated with commodity price changes on our future operations and, where appropriate, use various commodity-based derivative instruments such as natural gas, crude oil and NGL financial contracts to hedge a portion of the value of our assets and operations from such price risks. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk -Commodity Price Risk” for further discussion of commodity price risk.

Currently, there is a significant level of uncertainty in the financial markets. This uncertainty presents additional potential risks to us. These risks include the availability and costs associated with our borrowing capabilities and ability to raise additional capital, and an increase in the volatility of the price of our common units. While we have no definitive plans to access the capital markets, should we decide to do so in the near future, the terms, size, and cost of new debt or equity could be less favorable than in previous transactions.

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Results of Operations

The following table illustrates selected pricing before the effect of derivatives and volumetric information related to our Gathering and Processing segment for the periods indicated:

	Years Ended December 31,
	2011		2010		Percent Change			2009		Percent Change
Pricing:
Weighted Average Prices:
NGL price per gallon – Conway hub	$	1.08	$	0.92		17.4	%	$	0.68		35.3	%
NGL price per gallon – Mt. Belvieu hub		1.31		1.03		27.2	%		0.77		33.8	%
Natural gas sales ($/Mcf):
Velma		3.86		4.14		(6.8	)%		3.24		27.8	%
WestOK		3.87		4.13		(6.3	)%		3.25		27.1	%
WestTX		3.84		4.10		(6.3	)%		3.35		22.4	%
Weighted Average		3.86		4.12		(6.3	)%		3.28		25.6	%
NGL sales ($/gallon):
Velma		1.11		0.90		23.3	%		0.69		30.4	%
WestOK		1.10		0.94		17.0	%		0.69		36.2	%
WestTX		1.33		1.02		30.4	%		0.83		22.9	%
Weighted Average		1.20		0.97		23.7	%		0.73		32.9	%
Condensate sales ($/barrel):
Velma		94.35		78.28		20.5	%		59.80		30.9	%
WestOK		86.63		72.67		19.2	%		55.07		32.0	%
WestTX		92.84		75.57		22.9	%		60.35		25.2	%
Weighted Average		90.65		75.08		20.7	%		58.21		29.0	%
Operating data:
Velma system:
Gathered gas volume (MCFD)		103,328		84,455		22.3	%		76,378		10.6	%
Processed gas volume (MCFD)		98,126		78,606		24.8	%		73,940		6.3	%
Residue Gas volume (MCFD)		80,330		64,138		25.2	%		58,350		9.9	%
NGL volume (BPD)		11,433		9,218		24.0	%		8,232		12.0	%
Condensate volume (BPD)		423		416		1.7	%		377		10.3	%
WestOK system:
Gathered gas volume (MCFD)		268,329		228,684		17.3	%		270,703		(15.5	)%
Processed gas volume (MCFD)		254,394		214,695		18.5	%		215,374		(0.3	)%
Residue Gas volume (MCFD)		230,907		193,200		19.5	%		228,261		(15.4	)%
NGL volume (BPD)		13,635		12,395		10.0	%		13,418		(7.6	)%
Condensate volume (BPD)		898		697		28.8	%		824		(15.4	)%
WestTX system(1):
Gathered gas volume (MCFD)		212,775		178,111		19.5	%		159,568		11.6	%
Processed gas volume (MCFD)		196,412		163,475		20.1	%		149,656		9.2	%
Residue Gas volume (MCFD)		133,857		105,982		26.3	%		101,788		4.1	%
NGL volume (BPD)		29,052		26,678		8.9	%		21,261		25.5	%
Condensate volume (BPD)		1,500		1,289		16.4	%		1,265		1.9	%
Tennessee system:
Average throughput volumes (MCFD)		7,698		8,740		(11.9	)%		7,907		10.5	%

(1) Operating data for the WestTX system represents 100% of its operating activity.

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Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Revenues The following table details the variances between the years ended 2011 and 2010 for revenues (in thousands):

	Years Ended December 31,									Percent
	2011			2010(1)			Variance			Change
Revenues:
Natural gas and liquids sales	$	1,268,195		$	890,048		$	378,147			42.5	%
Transportation, processing and other fees		43,799			41,093			2,706			6.6	%
Derivative loss, net		(20,452	)		(5,945	)		(14,507	)		(244.0	)%
Other income, net		11,192			10,392			800			7.7	%
Total Revenues	$	1,302,734		$	935,588		$	367,146			39.2	%

(1) Adjusted to reflect the separate presentation of derivative gain (loss) within derivative loss, net instead of combining these amounts in other income, net.

Natural gas and liquids sales for the year ended December 31, 2011 increased as a result of higher realized commodity prices combined with higher production volumes across all systems. Volumes on the Velma system increased for the year ended December 31, 2011 when compared to the prior year period primarily due to new production gathered on the Madill-to-Velma gas gathering pipeline. Volume on the WestOK system increased for the year ended December 31, 2011 compared to the prior year due to the completion of an expansion into Kansas in June 2010. WestTX system volumes for the year ended December 31, 2011 increased when compared to the prior year period due to increased volumes from Pioneer Natural Resources Company (NYSE: PXD) as a result of their continued drilling program.

Derivative loss, net had an unfavorable variance for the year ended December 31, 2011 due to a $7.3 million loss recorded on the fair value revaluation of derivatives in 2011 as a result of higher prices plus $7.2 million unfavorable variance resulting from losses on cash settlements recorded to derivative loss, net instead of natural gas liquids sales as a result of the discontinuance of hedge accounting in prior years. We enter into derivative instruments solely to hedge our forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices (see “Item 8: Financial Statements and Supplementary Data –Note 11”).

Costs and Expenses. The following table details the variances between the years ended 2011 and 2010 for costs and expenses (in thousands):

	Years Ended December 31,							Percent
	2011		2010(1)		Variance			Change
Costs and Expenses:
Natural gas and liquids cost of sales	$	1,047,025	$	720,215	$	326,810			45.4	%
Plant operating		54,686		48,670		6,016			12.4	%
Transportation and compression		833		1,061		(228	)		(21.5	)%
General and administrative		36,357		34,021		2,336			6.9	%
Other costs		1,040		—		1,040			100.0	%
Depreciation and amortization		77,435		74,897		2,538			3.4	%
Interest expense		31,603		87,273		(55,670	)		(63.8	)%
Total Costs and Expenses	$	1,248,979	$	966,137	$	282,842			29.3	%

(1) Adjusted to reflect the reclassification of accelerated amortization of deferred financing costs from interest expense to loss on early extinguishment of debt.

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Natural gas and liquids cost of sales for the year ended December 31, 2011 increased due to an increase in average commodity prices and processed volumes in comparison to the prior year period, as discussed above in “Revenues.”

Plant operating expense for the year ended December 31, 2011 increased primarily due to increased gathered and processed volumes in comparison to the prior year period, as operating expenses are generally dependent on activity in our systems.

Transportation and compression expenses for the year ended December 31, 2011 decreased due to lower throughput volumes on the Tennessee gathering system.

Interest expense for the year ended December 31, 2011 decreased primarily due to a $21.1 million decrease in interest expense associated with our term loan retired during the prior year; a $16.4 million decrease in interest expense associated with the 8.125% Senior Notes; and an $11.6 million decrease in interest expense associated with our revolving credit facility. The lower interest expense on our term loan and revolving credit facility is due to the retirement of the term loan and a reduction of the credit facility borrowings with proceeds from the sale of Elk City. The lower interest expense on our 8.125% Senior Notes is due to the redemption of the 8.125% Senior Notes in April 2011, with proceeds from the sale of our 49% non-controlling interest in Laurel Mountain (see “–Recent Events”).

Other income items. The following table details the variances between the years ended 2011 and 2010 for other income items (in thousands):

	Years Ended December 31									Percent Change
	2011			2010(1)			Variance
Equity income in joint ventures	$	5,025		$	4,920		$	105			2.1	%
Gain (loss) on asset sales and other		256,272			(10,729	)		267,001			2,488.6	%
Loss on early extinguishment of debt		(19,574	)		(4,359	)		(15,215	)		(349.0	)%
Income (loss) from discontinued operations		(81	)		321,155			(321,236	)		(100.0	)%
Income attributable to non-controlling interests		(6,200	)		(4,738	)		(1,462	)		(30.9	)%

(1) Adjusted to reflect the reclassification of accelerated amortization of deferred financing costs from interest expense to loss on early extinguishment of debt.

Equity income in joint ventures increased for the year ended December 31, 2011, primarily due to $4.6 million in equity earnings generated in the current period from our 20% ownership interest in WTPLG, which was purchased in May 2011 (see “–Recent Events”), which was offset by $4.5 million in lower equity earnings from Laurel Mountain, due to the sale of our ownership interest on February 17, 2011 (see “–Recent Events”).

Gain (loss) on asset sales and other for the years ended December 31, 2011 and 2010 includes amounts associated with the sale of our 49% interest in Laurel Mountain on February 17, 2011 (see “–Recent Events”).

Loss on early extinguishment of debt for the year ended December 31, 2011 represents the premium paid for the redemption of the 8.125% Senior Notes and the recognition of deferred finance costs related to the redemption (see “–Recent Events”). Loss on early extinguishment of debt for the year ended December 31, 2010 represents the accelerated amortization of debt expense related to the early retirement of our term loan with proceeds from the sale of Elk City.

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Income from discontinued operations for the year ended December 31, 2010 represents a $312.1 million gain on sale associated with the Elk City system, which was sold on September 16, 2010, and $9.1 million net income related to the operations of Elk City.

Income attributable to non-controlling interests increased primarily due to higher net income for the WestOK and WestTX joint ventures, which were formed to accomplish our acquisition of control of the systems. The increase in net income of the joint ventures was principally due to higher gross margins on the sale of commodities, resulting from higher prices and volumes. The non-controlling interest expense represents Anadarko Petroleum Corporation’s (“Anadarko” – NYSE: APC) interest in the net income of the WestOK and WestTX joint ventures.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Revenue. The following table details the variances between the years ended 2010 and 2009 for revenues (in thousands):

	Years Ended December 31,									Percent
	2010(1)			2009(1)			Variance			Change
Revenues:
Natural gas and liquids sales	$	890,048		$	636,231		$	253,817			39.9	%
Transportation, processing and other fees		41,093			59,075			(17,982	)		(30.4	)%
Derivative loss, net		(5,945	)		(35,815	)		29,870			83.4	%
Other income, net		10,392			13,114			(2,722	)		(20.8	)%
Total Revenues	$	935,588		$	672,605		$	262,983			39.1	%

(1) Adjusted to reflect the separate presentation of derivative gain (loss) within derivative loss, net instead of combining these amounts in other income, net.

Natural gas and liquids sales for the year ended December 31, 2010 increased primarily due to a favorable price change as a result of higher realized commodity prices, combined with lower qualified hedge losses. Gains and losses within other comprehensive income (loss), related to previously designated hedges, are recorded within natural gas and liquids sales, while all other gains and losses related to derivative instruments are recorded within derivative loss, net. We enter into derivative instruments solely to hedge our forecasted natural gas, NGLs and condensate sales and natural gas purchases against the variability in expected future cash flows attributable to changes in market prices. See further discussion of derivatives under “Item 7A: Quantitative and Qualitative Disclosures About Market Risk.”

The WestTX system’s NGL production volume for the year ended December 31, 2010 increased when compared to the prior year period representing an increase in production efficiency primarily due to the start-up of the new Consolidator plant, which provides greater recoveries, increasing the liquid volumes extracted from the natural gas stream. NGL production volume on the WestOK system decreased for the year ended December 31, 2010 compared to the prior year due to a decreased number of well connects in 2010, resulting from lower capital spending. NGL production on the Velma system increased for the year ended December 31, 2010 when compared to the prior year period primarily due to increased gathered gas volume resulting from the completion of the Madill-to-Velma gas gathering pipeline.

Transportation, processing and other fee revenue decreased primarily due to a $16.9 million decrease from the Appalachia system as a result of our May 2009 contribution of the majority of the

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system to Laurel Mountain, a joint venture in which we had a 49% non-controlling ownership interest. After the contribution, we recognized our ownership interest in the net income of Laurel Mountain as equity income on our consolidated statements of operations.

Derivative loss, net had a favorable movement for the year ended December 31, 2010 due primarily to a $63.6 million favorable variance in non-cash mark-to-market adjustments on derivatives, offset by $32.3 million unfavorable variance of net cash derivative expense related to the early termination of a portion of our derivative contracts (see “Item 8: Financial Statements and Supplementary Data –Note 11”).

Other income, net, decreased for the year ended December 31, 2010 due primarily to a $1.8 million decrease in interest income recognized on the note receivable from Anadarko, related to their non-controlling interest in WestTX and WestOK.

Costs and Expenses. The following table details the variances between the years ended 2010 and 2009 for costs and expenses (in thousands):

	Years Ended December 31,							Percent
	2010(1)		2009(1)		Variance			Change
Costs and Expenses:
Natural gas and liquids cost of sales	$	720,215	$	527,730	$	192,485			36.5	%
Plant operating		48,670		45,566		3,104			6.8	%
Transportation and compression		1,061		6,657		(5,596	)		(84.1	)%
General and administrative		34,021		37,280		(3,259	)		(8.7	)%
Depreciation and amortization		74,897		75,684		(787	)		(1.0	)%
Goodwill and other asset impairment loss		—		10,325		(10,325	)		(100.0	)%
Interest expense		87,273		101,309		(14,036	)		(13.9	)%
Total Costs and Expenses	$	966,137	$	804,551	$	161,586			20.1	%

(1) Adjusted to reflect the reclassification of accelerated amortization of deferred financing costs from interest expense to loss on early extinguishment of debt.

Natural gas and liquids cost sales for the year ended December 31, 2010 increased primarily due to an increase in average commodity prices in comparison to the prior year period, as discussed above in revenues.

Transportation and compression expenses for the year ended December 31, 2010 decreased due to our contribution of the Appalachia system to Laurel Mountain.

Goodwill and other asset impairment loss for the year ended December 31, 2009 was due to an impairment of certain gas plant and gathering assets as a result of our annual review of long-lived assets.

Interest expense for the year ended December 31, 2010 decreased primarily due to a $9.5 million decrease in interest rate swap expense due to the interest rate swaps expiring in April 2010 and due to a $5.8 million decrease in interest expense associated with our term loan. The lower interest expense on our term loan is due to the retirement of the term loan in September 2010 with proceeds from the sale of Elk City.

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Other income items. The following table details the variances between the years ended 2010 and 2009 for other income items (in thousands):

	Years Ended December 31									Percent
	2010(1)			2009(1)			Variance			Change
Equity income in joint venture	$	4,920		$	4,043		$	877			21.7	%
Gain (loss) on asset sales and other		(10,729	)		108,947			(119,676	)		(109.8	)%
Loss on early extinguishment of debt		(4,359	)		(2,478	)		(1,881	)		(75.9	)%
Income from discontinued operations		321,155			84,148			237,007			281.7	%
Income attributable to non-controlling interests		(4,738	)		(3,176	)		(1,562	)		(49.2	)%

(1) Adjusted to reflect the reclassification of accelerated amortization of deferred financing costs from interest expense to loss on early extinguishment of debt.

Equity income represents our ownership interest in the net income of Laurel Mountain, and it increased for the year ended December 31, 2010 as a result of the prior year including only seven months of operations.

Gain (loss) on asset sales and other for the years ended December 31, 2010 and 2009 includes amounts associated with the contribution of a 51% ownership interest in our Appalachia natural gas gathering system in 2009 and the sale of our 49% interest in Laurel Mountain in 2010.

Loss on early extinguishment of debt for the year ended December 31, 2010 represents the accelerated amortization of debt expense related to the early retirement of our term loan with proceeds from the sale of Elk City. Loss on early extinguishment of debt for the year ended December 31, 2009 represents the accelerated amortization of debt expense related to the early retirement of a portion of our term loan with proceeds from the sale of NOARK gas gathering and interstate pipeline, which was sold in May 2009.

Income from discontinued operations increased for the year ended December 31, 2010 primarily due to the $312.1 million gain on sale of Elk City in the current year period compared to the $51.1 million gain on sale of the NOARK gas gathering and interstate pipeline, which was sold in May 2009.

Income attributable to non-controlling interests increased for the year ended December 31, 2010 primarily due to higher net income for the WestOK and WestTX joint ventures, which were formed to accomplish our acquisition of control of the respective systems. The increase in net income of the WestOK and WestTX joint ventures was principally due to higher gross margins on the sale of commodities resulting from higher prices. The non-controlling interest expense represents Anadarko’s interest in the net income of the WestOK and WestTX joint ventures.

Liquidity and Capital Resources

General

Our primary sources of liquidity are cash generated from operations and borrowings under our revolving credit facility. Our primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures and quarterly distributions to our common unitholders and General Partner. In general, we expect to fund:

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• cash distributions and maintenance capital expenditures through existing cash and cash flows from operating activities;

• expansion capital expenditures and working capital deficits through the retention of cash and additional capital raising; and

• debt principal payments through operating cash flows and refinancings as they become due, or by the issuance of additional limited partner units or asset sales.

At December 31, 2011, we had $142.0 million outstanding borrowings under our $450.0 million senior secured revolving credit facility and $0.1 million of outstanding letters of credit, which are not reflected as borrowings on our consolidated balance sheets, with $307.9 million of remaining committed capacity under the revolving credit facility, (see “–Revolving Credit Facility”). We were in compliance with the credit facility’s covenants at December 31, 2011. We had a working capital deficit of $39.5 million at December 31, 2011 compared with a $36.6 million working capital deficit at December 31, 2010. We believe we will have sufficient liquid assets, cash from operations and borrowing capacity to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve-month period. However, we are subject to business, operational and other risks that could adversely affect our cash flows. We may need to supplement our cash generation with proceeds from financing activities, including borrowings under our credit facility and other borrowings, the issuance of additional limited partner units and sales of our assets.

Instability in the financial markets, as a result of recession or otherwise, may cause volatility in the markets and may impact the availability of funds from those markets. This may affect our ability to raise capital and reduce the amount of cash available to fund our operations. We rely on our cash flows from operations and our revolving credit facility to execute our growth strategy and to meet our financial commitments and other short-term liquidity needs. We cannot be certain additional capital will be available to the extent required and on acceptable terms.

Cash Flows – Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

The following table details the variances between the years ended 2011 and 2010 for cash flows (in thousands):

	Years Ended December 31,									Percent
	2011			2010			Variance			Change
Net cash provided by (used in):
Operating activities	$	102,867		$	106,427		$	(3,560	)		(3.4	)%
Investing activities		67,763			594,753			(526,990	)		(88.6	)%
Financing activities		(170,626	)		(702,037	)		531,411			75.7	%
Net change in cash and cash equivalents	$	4		$	(857	)	$	861			100.5	%

Net cash provided by operating activities for the year ended December 31, 2011 decreased primarily due to a $42.4 million decrease in the change in working capital and a $23.4 million decrease in cash provided by discontinued operations; offset by a $62.2 million increase in net earnings from continuing operations excluding non-cash charges. The increase in net earnings from continuing operations excluding non-cash charges is primarily due to increased revenues from the sale of natural gas and NGLs (see “–Results of Operations”).

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Net cash provided by investing activities for the year ended December 31, 2011 decreased mainly as a result of net proceeds of $676.8 million received from the sale of the Elk City system in the prior period; a $199.7 million increase in capital expenditures in the current year period compared to the prior year period (see further discussion of capital expenditures under “–Capital Requirements”); and $85.0 million paid for the acquisition of WTLPG (see “–Recent Events”); partially offset by $403.6 million net cash proceeds from the sale of Laurel Mountain (see “–Recent Events”).

Net cash used in financing activities for the year ended December 31, 2011 decreased mainly due to a $433.5 million repayment of our term loan in the prior period; a $256.0 million reduction in the outstanding borrowings on our revolving credit facility in the prior period; $152.4 million proceeds received in the current period related to our issuance of 8.75% Senior Notes (see “–Recent Events”) and a $72.0 million increase in the outstanding borrowings on our revolving credit facility in the prior period; partially offset by $293.9 million paid for the redemption of the 8.125% Senior Notes and a portion of the 8.75% Senior Notes in the current period and an $80.5 million increase in distributions paid to common limited partners, the General Partner and preferred limited partners. The proceeds from the sale of Elk City were utilized in the retirement of the term loan and the reduction in borrowings on the revolving credit facility in the prior year period. The proceeds from the sale of Laurel Mountain were utilized in the redemption of the Senior Notes in the current year period (see “–Recent Events”).

Cash Flows – Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

The following table details the variances between the years ended 2010 and 2009 for cash flows (in thousands):

	Years Ended December 31,									Percent
	2010			2009			Variance			Change
Net cash provided by (used in):
Operating activities	$	106,427		$	55,853		$	50,574			90.5	%
Investing activities		594,753			241,123			353,630			146.7	%
Financing activities		(702,037	)		(297,400	)		(404,637	)		(136.1	)%
Net change in cash and cash equivalents	$	(857	)	$	(424	)	$	(433	)		(102.1	)%

Net cash provided by operating activities for the year ended December 31, 2010 increased primarily due to a $48.8 million increase in net earnings from continuing operations, excluding non-cash charges, and a $20.6 million increase in cash flows from working capital changes, partially offset by an $18.8 million decrease in cash provided by discontinued operations. Net earnings from continuing operation, excluding non-cash charges, increased primarily due to a favorable gross margin in continuing operations of $46.9 million, mainly as a result of higher commodity prices.

Net cash provided by investing activities for the year ended December 31, 2010 increased as a result of the net proceeds of $676.8 million received from the sale of Elk City in 2010 compared to $292.0 million received from the sale of the NOARK gas gathering and interstate pipeline system in the prior year period combined with the $89.5 million received from the sale of our 51% interest in the Appalachia assets in the prior year period. Additionally, there was a $64.5 million decrease in capital expenditures compared to the prior year period (see further discussion of capital expenditures under “–Capital Requirements”).

Net cash used in financing activities for the year ended December 31, 2010 increased mainly due to a $280.0 million net increase in repayments of the outstanding principal balance on our revolving credit facility and a $159.8 million increase in repayments of our term loan. The increase in repayments on our

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term loan and revolving credit facility is principally due to the retirement of the term loan and a portion of our revolving credit facility with proceeds from the sale of Elk City.

Capital Requirements

Our operations require continual investment to upgrade or enhance existing operations and to ensure compliance with safety, operational, and environmental regulations. Our capital requirements consist primarily of:

• maintenance capital expenditures to maintain equipment reliability and safety and to address environmental regulations; and

• expansion capital expenditures to acquire complementary assets and to expand the capacity of our existing operations.

The following table summarizes maintenance and expansion capital expenditures, excluding amounts paid for acquisitions, for the periods presented (in thousands):

	Years Ended December 31,
	2011		2010		2009
Maintenance capital expenditures	$	18,247	$	10,921	$	3,750
Expansion capital expenditures		227,179		35,715		106,524
Total	$	245,426	$	46,636	$	110,274

Expansion capital expenditures increased for year ended December 31, 2011 primarily due to major processing facility expansions, compressor upgrades and pipeline projects. The increase in maintenance capital expenditures for the year ended December 31, 2011 when compared with the prior year period was due to expanded processing and gathering facilities and increased volumes on these facilities. As of December 31, 2011, we had approved additional expenditures of approximately $159.4 million on processing facility expansions, pipeline extensions and compressor station upgrades, of which approximately $73.2 million purchase commitments had been made. We expect to fund these projects through operating cash flows and borrowings under our existing revolving credit facility.

Expansion capital expenditures decreased for the year ended December 31, 2010 primarily due to the completion of the Madill to Velma pipeline and the construction of the Consolidator gas plant in 2009, compounded by a reduction of well connects in 2010. The increase in maintenance capital expenditures for the year ended December 31, 2010 was partially due to planned maintenance expense at the Waynoka plant plus fluctuations in the timing of other scheduled maintenance activity

Partnership Distributions

Our partnership agreement requires that we distribute 100% of available cash to our common unitholders and our General Partner within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Available cash consists generally of all our cash receipts, less cash disbursements and net additions to reserves, including any reserves required under debt instruments for future principal and interest payments.

Our General Partner is granted discretion by our partnership agreement to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type

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of future cash requirements with which they can be associated. When our General Partner determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.

Available cash is initially distributed 98% to our common limited partners and 2% to our General Partner. These distribution percentages are modified to provide for incentive distributions to be paid to our General Partner if quarterly distributions to common limited partners exceed specified targets. Incentive distributions are generally defined as all cash distributions paid to our General Partner that are in excess of 2% of the aggregate amount of cash being distributed. Our General Partner, holder of all our incentive distribution rights, has agreed to allocate up to $3.75 million of its incentive distribution rights per quarter back to us after the General Partner receives the initial $7.0 million of incentive distribution rights per quarter. Incentive distributions of $1.7 million were paid during year ended December 31, 2011. No incentive distributions were paid during the year ended December 31, 2010.

Off Balance Sheet Arrangements

As of December 31, 2011, our off balance sheet arrangements include our letters of credit, issued under the provisions of our revolving credit facility, totaling $0.1 million. These are in place to support various performance obligations as required by (1) statutes within the regulatory jurisdictions where we operate, (2) surety and (3) counterparty support.

We have certain long-term unconditional purchase obligations and commitments, primarily throughput contracts. These agreements provide transportation services to be used in the ordinary course of our operations.

Contractual Obligations and Commercial Commitments

The following table summarizes our contractual obligations and commercial commitments at December 31, 2011 (in thousands):

			Payments Due By Period
Contractual cash obligations:	Total		Less than 1 Year		1 – 3 Years		4 – 5 Years		After 5 Years
Total debt	$	507,822	$	—	$	—	$	142,000	$	365,822
Interest on total debt(1)		224,543		36,469		72,938		68,367		46,769
Capital leases		12,126		2,685		9,441		—		—
Operating leases		2,682		1,580		780		322		—
Total contractual cash obligations	$	747,173	$	40,734	$	83,159	$	210,689	$	412,591

(1) Based on the interest rates of our respective debt components as of December 31, 2011.

			Amount of Commitment Expiration Per Period
Other commercial commitments:	Total		Less than 1 Year		1 – 3 Years		4 – 5 Years		After 5 Years
Standby letters of credit	$	75	$	75	$	—	$	—	$	—
Purchase commitments		73,193		73,193		—		—		—
Throughput contracts		22,590		8,235		14,355		—		—
Total commercial commitments	$	95,858	$	81,503	$	14,355	$	—	$	—

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Common Equity Offerings

In August 2009, we sold 2,689,765 common units in a private placement at an offering price of $6.35 per unit, yielding net proceeds of approximately $16.1 million. We also received a capital contribution from the General Partner of $0.4 million for the General Partner to maintain its 2.0% general partner interest in us. In addition, we issued warrants granting investors in our private placement the right to purchase an additional 2,689,765 common units at a price of $6.35 per unit for a period of two years following the issuance of the original common units. We utilized the net proceeds from the common unit offering to repay a portion of our indebtedness under our senior secured term loan and revolving credit facility (see “–Revolving Credit Facility”).

On January 7, 2010, we executed amendments to the warrants, which were originally issued in August 2009. The amendments to the warrants provided that, for the period January 8 through January 12, 2010, the warrant exercise price was lowered to $6.00 per unit from $6.35 per unit. In connection with the amendments, the holders of the warrants exercised all the warrants for cash, which resulted in net cash proceeds of approximately $15.3 million. On November 30, 2010, we received a capital contribution from the General Partner of $0.3 million for the General Partner to maintain its 2.0% general partner interest in us. We utilized the net proceeds from the common unit offering to repay a portion of our indebtedness under our senior secured term loan and credit facility (see “–Revolving Credit Facility”) and to fund the early termination of certain derivative agreements. See “Item 8. Financial Statements and Supplementary Data –Note 11”.

Preferred Units

On June 30, 2010, we sold 8,000 newly-created 12% Cumulative Class C Preferred Units of limited partner interest (the “Class C Preferred Units”) to Atlas Energy, Inc., for cash consideration of $1,000 per Class C Preferred Unit, for total proceeds of $8.0 million.

The Class C Preferred Units received distributions of 12% per annum, paid quarterly on the same date as the distribution payment date for our common units. The record date for the determination of holders entitled to receive distributions was the same as the record date for determination of common unit holders entitled to receive quarterly distributions. We had the right to redeem some or all of the Class C Preferred Units for an amount equal to the face value of the Class C Preferred Units being redeemed plus all accrued but unpaid dividends.

On May 27, 2011, we redeemed the 8,000 Class C Preferred units for cash, at the liquidation value of $1,000 per unit, or $8.0 million, plus $0.2 million, representing the accrued dividends on the 8,000 Class C Preferred Units prior to our redemption. There are no Class C Preferred Units outstanding at December 31, 2011.

Revolving Credit Facility

At December 31, 2011, we had a $450.0 million senior secured revolving credit facility with a syndicate of banks, which matures in December 2015. On July 8, 2011, the revolving credit facility was increased from $350.0 million to $450.0 million. Borrowings under the revolving credit facility bear interest, at our option, at either (1) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% or (c) three-month LIBOR plus 1.0%, or (2) the LIBOR rate for the applicable period (each plus the applicable margin). The weighted average interest rate for borrowings on the revolving credit facility, at December 31, 2011, was 3.1%. Up to $50.0 million of the revolving credit facility may be utilized for letters of credit, of which $0.1 million was outstanding at December 31, 2011. These outstanding letter of credit amounts were not reflected as borrowings on our consolidated balance sheets.

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Borrowings under the revolving credit facility are secured by a lien on and security interest in all our property and that of our subsidiaries, except for the assets owned by the WestOK and WestTX joint ventures. Borrowings are also secured by the guaranty of each of our consolidated subsidiaries other than the joint venture companies. The revolving credit facility contains customary covenants, including covenants to maintain specified financial ratios, restrictions on our ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to our unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in our subsidiaries. We are also unable to borrow under our revolving credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to our partnership agreement.

The events that constitute an event of default for our revolving credit facility include payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against us in excess of a specified amount, and a change of control of our General Partner. As of December 31, 2011, we were in compliance with all covenants under the revolving credit facility.

Senior Notes

8.75% Senior Notes

At December 31, 2011, we had $371.0 million principal amount outstanding of 8.75% Senior Notes, including a net $5.2 million unamortized premium. Interest on the 8.75% Senior Notes is payable semi-annually in arrears on June 15 and December 15. The 8.75% Senior Notes are redeemable at any time after June 15, 2013, at certain redemption prices, together with accrued and unpaid interest to the date of redemption. The 8.75% Senior Notes are subject to repurchase by us at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if we do not reinvest the net proceeds within 360 days. The 8.75% Senior Notes are junior in right of payment to our secured debt, including our obligations under our revolving credit facility.

On April 7, 2011, we redeemed $7.2 million of the 8.75% Senior Notes, which were tendered upon our offer to purchase the 8.75% Senior Notes, at par. The sale of our 49% non-controlling interest in Laurel Mountain on February 17, 2011 constituted an “Asset Sale” pursuant to the terms of the indenture of the 8.75% Senior Notes. As a result of the Asset Sale, we offered to purchase any and all of the 8.75% Senior Notes.

On November 21, 2011, we issued $150.0 million of the 8.75% Senior Notes in a private placement transaction. The 8.75% Senior Notes were issued at a premium of 103.5% of the principal amount for a yield of 7.82%. We received net proceeds of $152.4 million after underwriting commissions and other transaction costs and utilized the proceeds to reduce the outstanding balance on our revolving credit facility.

The 8.75% Senior Notes sold in private placement were subject to a registration rights agreement entered into in connection with the transaction. The registration rights agreement required us to file a registration statement with the SEC to exchange the privately placed notes for registered notes. We filed a registration statement with the SEC in satisfaction of the requirements of the registration rights agreement on December 12, 2011, and the registration statement was declared effective on January 13, 2012. We currently anticipate completing the exchange offer on March 5, 2012.

The indenture governing the 8.75% Senior Notes contains covenants, including limitations of our ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare

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or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all our assets. We were in compliance with these covenants as of December 31, 2011.

8.125% Senior Notes

In November 2010, we paid $1.3 million to the holders of the 8.125% Senior Notes in connection with a solicited consent received from the majority of holders of those notes to amend certain provisions of the indenture governing the 8.125% Senior Notes. The amendment allowed us to make certain capital contributions to Laurel Mountain Midstream, LLC.

On April 8, 2011, we redeemed all the 8.125% Senior Notes. The redemption price was determined in accordance with the indenture for the 8.125% Senior Notes, plus accrued and unpaid interest thereon to the redemption date. We paid $293.7 million to redeem the $275.5 million principal plus $11.2 million premium and $7.0 million accrued interest. There are no 8.125% Senior Notes outstanding at December 31, 2011.

Environmental Regulation

Our operations are subject to federal, state and local laws and regulations governing the release of regulated materials into the environment or otherwise relating to environmental protection or human health or safety. We believe our operations and facilities are in substantial compliance with applicable environmental laws and regulations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, imposition of remedial requirements, issuance of injunctions affecting our operations, or other measures. Risks of accidental leaks or spills are associated with the gathering of natural gas. There can be no assurance we will not incur significant costs and liabilities relating to claims for damages to property, the environment, natural resources, or persons resulting from the operation of our business. Moreover, it is possible other developments, such as increasingly stringent environmental laws and regulations and enforcement policies, could result in increased costs and liabilities to us.

Environmental laws and regulations have changed substantially and rapidly over the last 25 years, and we anticipate there will be continuing changes. Trends in environmental regulation include increased reporting obligations and placing more restrictions and limitations on activities, such as emissions of greenhouse gases and other pollutants, generation and disposal of wastes and use, storage and handling of chemical substances, that may impact human health, the environment and/or endangered species.

Other increasingly stringent environmental restrictions and limitations have resulted in increased operating costs for us and other similar businesses throughout the United States. It is possible the costs of compliance with environmental laws and regulations may continue to increase. We will attempt to anticipate future regulatory requirements that might be imposed and to plan accordingly, but there can be no assurance we will identify and properly anticipate each such charge, or that our efforts will prevent material costs, if any, from rising.

Inflation and Changes in Prices

Inflation affects the operating expenses of our operations due to the increase in costs of labor and supplies. Inflation did not have a material impact on our results of operations for the years ended December 31, 2011, 2010 and 2009. While we anticipate inflation may affect our future operating costs, we cannot predict the timing or amounts of any such effects.

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Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point of time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items subject to such estimates and assumptions include revenue and expense accruals, depreciation and amortization, asset impairment, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired. We summarize our significant accounting policies within our consolidated financial statements included in Item 8, “Financial Statements and Supplementary Data.” The following table evaluates the potential impact of estimates utilized during the year ended December 31, 2011.

Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Revenue Recognition
Revenue primarily consists of the sale of natural gas and NGLs along with the fees earned from gathering, processing and transportation.	Revenues are estimated and accrued due to timing differences between the delivery of natural gas, NGLs, and condensate and the receipt of a delivery statement. This revenue is recorded based upon estimated volumetric data and management estimates of the related gathering and compression fees and product prices. Costs of goods sold are estimated based upon the estimated revenues.	As of December 31, 2011, there were $68.6 million accrued unbilled revenues. A 10% change in the estimated revenues would change gross margin by approximately $1.4 million.
Impairment of Long-Lived Assets
Management evaluates our long-lived assets, including intangibles, for impairment when events or changes in circumstances warrant such a review. A long-lived asset is considered impaired when the estimated undiscounted cash flow from such asset is less than the asset’s carrying value. In that event, a loss is recognized to the extent that the carrying value exceeds the fair value of the long-lived asset.	In evaluating impairment, management considers the use or disposition of an asset, the estimated remaining life of an asset, and future expenditures to maintain an asset’s existing service potential. In order to determine the cash flow, management must make certain estimates and assumptions, which include, but are not limited to, changes in general economic conditions in regions in which we operate, our ability to negotiate favorable contracts, the risks that natural gas exploration and production activities will not occur or be successful, competition from other midstream companies, our dependence on certain significant customers and producers of natural gas, and the volume of reserves behind an asset and future NGL product and natural gas prices.	As of December 31, 2011, there were no indicators of impairment for any of our assets. A significant variance in any of these assumptions or factors could materially affect future cash flows, which could result in the impairment of an asset.

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Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Depreciation
Depreciation expense is generally computed using the straight-line method over the estimated useful life of the assets.	Determination of depreciation expense requires judgment regarding the estimated useful lives and salvage values of property, plant and equipment. As circumstances warrant, depreciation estimates are reviewed to determine if any changes in the underlying assumptions are necessary.	The life of our long-lived assets ranges from 2 – 40 years. If the depreciable lives of our assets were decreased by 10%, we estimate that annual depreciation expense would increase by approximately $5.6 million, which would result in a corresponding change in our operating income.
Derivative Instruments
Our derivative financial instruments are recorded at fair value in the consolidated balance sheets. Changes in fair value and settlements are reflected in our earnings in the consolidated statements of operations as gains and losses related to natural gas liquids sales, interest expense and/or derivative loss, net. (See “Item 8: “Financial Statements and Supplementary Data –Note 12” for further discussion)	When available, quoted market prices or prices obtained through external sources are used to determine a financial instrument’s fair value. The valuation of Level 2 financial instruments is based on quoted market prices for similar assets and liabilities in active markets and other inputs that are observable. However, for other financial instruments for which quoted market prices are not available, the fair value is based upon inputs that are largely unobservable. These instruments are classified as Level 3 under the fair value hierarchy. The fair value of these instruments are determined based on pricing models developed primarily from historical and expected correlations with quoted market prices. At December 31, 2011, approximately 70% of our derivatives are classified as Level 3 with the remainder classified as Level 2.	If the assumptions used in the pricing models for our financial instruments are inaccurate or if we had used an alternative valuation methodology, the estimated fair value may have been different, and we may be exposed to unrealized losses or gains that could be material. A 10% increase in our prices utilized in calculating the fair value of derivatives at December 31, 2011 would have decreased net income by approximately $17.3 million for the year ended December 31, 2011.

Recently Issued Accounting Standards

See “Item 8. Financial Statements and Supplementary Data –Note 2 –Recently Issued Accounting Standards” for information regarding recent accounting pronouncements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and oil and natural gas prices. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All our market risk sensitive instruments were entered into for purposes other than trading.

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General

All our assets and liabilities are denominated in U.S. dollars, and as a result, we do not have exposure to currency exchange risks.

We are exposed to various market risks, principally fluctuating interest rates and changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We manage these risks through regular operating and financing activities and periodic use of derivative instruments. The following analysis presents the effect on our results of operations, cash flows and financial position as if the hypothetical changes in market risk factors occurred on December 31, 2011. Only the potential impact of hypothetical assumptions is analyzed. The analysis does not consider other possible effects that could impact our business.

Current market conditions elevate our concern over counterparty risks and may adversely affect the ability of these counterparties to fulfill their obligations to us, if any. The counterparties to our commodity-based derivatives are banking institutions, or their affiliates, currently participating in our revolving credit facility. The creditworthiness of our counterparties is constantly monitored, and we are not aware of any inability on the part of our counterparties to perform under our contracts.

Interest Rate Risk. At December 31, 2011, we had a $450.0 million senior secured revolving credit facility with $142.0 million in outstanding borrowings. Borrowings under the revolving credit facility bear interest, at our option, at either (1) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% or (c) three-month LIBOR plus 1.0%, or (2) the LIBOR rate for the applicable period (each plus the applicable margin). The weighted average interest rate for the revolving credit facility borrowings was 3.1% at December 31, 2011. Based upon the outstanding borrowings on the senior secured revolving credit facility and holding all other variables constant, a 100 basis-point, or 1%, change in interest rates would change our annual interest expense by approximately $1.4 million.

Commodity Price Risk. We are exposed to commodity prices as a result of being paid for certain services in the form of natural gas, NGLs and condensate rather than cash. For gathering services, we receive fees or commodities from the producers to bring the raw natural gas from the wellhead to the processing plant. For processing services, we either receive fees or commodities as payment for these services, based on the type of contractual agreement. We use a number of different derivative instruments in connection with our commodity price risk management activities. We enter into financial swap and option instruments to hedge our forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate are sold. Under swap agreements, we receive a fixed price and remit a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right to receive the difference between a fixed price and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. See “Item 8. Financial Statements and Supplementary Data –Note 11” for further discussion of our derivative instruments. Average estimated market prices for NGLs, natural gas and condensate, based upon twelve-month forward price curves as of January 4, 2012, were $1.10 per gallon, $3.02 per million BTU and $93.76 per barrel, respectively. A 10% change in these prices would change our forecasted gross margin for the twelve-month period ended December 31, 2012 by approximately $10.8 million.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unitholders

Atlas Pipeline Partners, L.P.

We have audited the accompanying consolidated balance sheets of Atlas Pipeline Partners, L.P. (a Delaware limited partnership) as of December 31, 2011 and 2010, and the related consolidated statements of operations, comprehensive income (loss), equity and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Atlas Pipeline Partners, L.P. and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Atlas Pipeline Partners, L.P.’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated February 24, 2012 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

February 24, 2012

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31, 2011			December 31, 2010
ASSETS
Current assets:
Cash and cash equivalents	$	168		$	164
Accounts receivable		115,412			99,759
Current portion of derivative assets		1,645			—
Prepaid expenses and other		15,641			15,118
Total current assets		132,866			115,041
Property, plant and equipment, net		1,567,828			1,341,002
Intangible assets, net		103,276			126,379
Investment in joint ventures		86,879			153,358
Long-term portion of derivative assets		14,814			—
Other assets, net		25,149			29,068
Total assets	$	1,930,812		$	1,764,848
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	2,085		$	210
Accounts payable – affiliates		2,675			12,280
Accounts payable		54,644			29,382
Accrued liabilities		23,282			30,013
Accrued interest payable		1,624			1,921
Current portion of derivative liabilities		—			4,564
Accrued producer liabilities		88,096			72,996
Distribution payable		—			240
Total current liabilities		172,406			151,606
Long-term portion of derivative liabilities		—			5,608
Long-term debt, less current portion		522,055			565,764
Other long-term liability		123			223
Commitments and contingencies
Equity:
General Partner’s interest		23,856			20,066
Preferred limited partner’s interest		—			8,000
Common limited partners’ interests		1,245,163			1,057,342
Accumulated other comprehensive loss		(4,390	)		(11,224	)
Total partners’ capital		1,264,629			1,074,184
Non-controlling interest		(28,401	)		(32,537	)
Total equity		1,236,228			1,041,647
Total liabilities and equity	$	1,930,812		$	1,764,848

See accompanying notes to consolidated financial statements

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

	Years Ended December 31
	2011			2010			2009
Revenue:
Natural gas and liquids sales	$	1,268,195		$	890,048		$	636,231
Transportation, processing and other fees– third parties		43,464			40,474			41,539
Transportation, processing and other fees– affiliates		335			619			17,536
Derivative loss, net		(20,452	)		(5,945	)		(35,815	)
Other income, net		11,192			10,392			13,114
Total revenues		1,302,734			935,588			672,605
Costs and expenses:
Natural gas and liquids cost of sales		1,047,025			720,215			527,730
Plant operating		54,686			48,670			45,566
Transportation and compression		833			1,061			6,657
General and administrative		34,551			32,521			34,549
Compensation reimbursement – affiliates		1,806			1,500			2,731
Other costs		1,040			—			—
Depreciation and amortization		77,435			74,897			75,684
Other asset impairment loss		—			—			10,325
Interest		31,603			87,273			101,309
Total costs and expenses		1,248,979			966,137			804,551
Equity income in joint ventures		5,025			4,920			4,043
Gain (loss) on asset sale and other		256,272			(10,729	)		108,947
Loss on early extinguishment of debt		(19,574	)		(4,359	)		(2,478	)
Income (loss) from continuing operations		295,478			(40,717	)		(21,434	)
Discontinued operations:
Gain (loss) on sale of discontinued operations		(81	)		312,102			53,571
Earnings from discontinued operations		—			9,053			30,577
Income (loss) from discontinued operations		(81	)		321,155			84,148
Net income		295,397			280,438			62,714
Income attributable to non-controlling interests		(6,200	)		(4,738	)		(3,176	)
Preferred unit dividends		(389	)		(780	)		(900	)
Net income attributable to common limited partners and the General Partner	$	288,808		$	274,920		$	58,638

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

	Years Ended December 31,
	2011			2010			2009
Allocation of net income (loss) attributable to:
Common limited partner interest:
Continuing operations	$	281,449		$	(45,347	)	$	(24,997	)
Discontinued operations		(79	)		315,021			82,457
		281,370			269,674			57,460
General Partner interest:
Continuing operations		7,440			(888	)		(513	)
Discontinued operations		(2	)		6,134			1,691
		7,438			5,246			1,178
Net income (loss) attributable to:
Continuing operations		288,889			(46,235	)		(25,510	)
Discontinued operations		(81	)		321,155			84,148
	$	288,808		$	274,920		$	58,638
Net income (loss) attributable to common limited partners per unit:
Basic:
Continuing operations	$	5.22		$	(0.85	)	$	(0.52	)
Discontinued operations		—			5.92			1.71
	$	5.22		$	5.07		$	1.19
Weighted average common limited partner units (basic)		53,525			53,166			48,299
Diluted:
Continuing operations	$	5.22		$	(0.85	)	$	(0.52	)
Discontinued operations		—			5.92			1.71
	$	5.22		$	5.07		$	1.19
Weighted average common limited partner units (diluted)		53,944			53,166			48,299

See accompanying notes to consolidated financial statements

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

	Years Ended December 31,
	2011			2010			2009
Net income	$	295,397		$	280,438		$	62,714
Income attributable to non-controlling interests		(6,200	)		(4,738	)		(3,176	)
Preferred unit dividends		(389	)		(780	)		(900	)
Net income attributable to common limited partners and the General Partner		288,808			274,920			58,638
Other comprehensive income:
Changes in fair value of derivative instruments accounted for as cash flow hedges		—			—			(2,268	)
Adjustment for realized losses reclassified to net income		6,834			37,966			58,022
Total other comprehensive income		6,834			37,966			55,754
Comprehensive income	$	295,642		$	312,886		$	114,392

See accompanying notes to consolidated financial statements

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(in thousands, except unit data)