Form 10-K

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

10-K 1 d10k.htm FORM 10-K Form 10-K

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, 2009

¨	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: 1-32953

ATLAS PIPELINE HOLDINGS, L.P.

(Exact name of registrant as specified in its charter)


DELAWARE		43-2094238
(State or other jurisdiction of Incorporation or organization)		(I.R.S. Employer Identification No.)
1550 Coraopolis Heights Road Moon Township, Pennsylvania		15108
(Address of principal executive office)		(Zip code)

Registrant’s telephone number, including area code: (412) 262-2830

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 ¨ No x

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 ¨ 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):

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 $3.70 per common limited partner unit on June 30, 2009, was approximately $33.4 million.

The number of common units of the registrant outstanding on March 2, 2010 was 27,703,579.

DOCUMENTS INCORPORATED BY REFERENCE: None

ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES

INDEX TO ANNUAL REPORT

ON FORM 10-K


		Page

PART I

Item 1:	Business	5

Item 1A:	Risk Factors	23

Item 1B:	Unresolved Staff Comments	50

Item 2:	Properties	50

Item 3:	Legal Proceedings	50

Item 4:	[Omitted and reserved]	50

PART II

Item 5:	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	51

Item 6:	Selected Financial Data	53

Item 7:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	59

Item 7A:	Quantitative and Qualitative Disclosures About Market Risk	89

Item 8:	Financial Statements and Supplementary Data	93

Item 9:	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	148

Item 9A:	Controls and Procedures	148

Item 9B:	Other Information	150

PART III

Item 10:	Directors, Executive Officers and Corporate Governance	151

Item 11:	Executive Compensation	156

Item 12:	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	177

Item 13:	Certain Relationships and Related Transactions, and Director Independence	179

Item 14:	Principal Accountant Fees and Services	180

PART IV

Item 15:	Exhibits and Financial Statement Schedules	181

SIGNATURES		183

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:

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the demand for natural gas and natural gas liquids;

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the price volatility of natural gas and natural gas liquids;

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Atlas Pipeline Partners, L.P.’s ability to connect new wells to its gathering systems;

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adverse effects of governmental and environmental regulation;

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

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the strength and financial resources of Atlas Pipeline Partners, L.P.’s 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.

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. Measurement for standard US barrel is 42 gallons
BTU		British thermal unit
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.
Fractionation		The process used to separate an NGL stream into its individual components.
Keep-Whole		Contract with producer whereby plant operator pays for or returns an equivalent BTU of the gas gathered at the well-head.
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.
Y-grade		A term utilized in the industry for the NGL stream prior to fractionation, also referred to as “raw mix.”

PART I

ITEM 1.

BUSINESS

Atlas Pipeline Holdings, L.P.

Our cash generating assets currently consist solely of our interests in APL. APL is a midstream energy service provider engaged in the transmission, gathering and processing of natural gas in the Mid-Continent and Appalachia regions. Our interests in APL consist of a 100% ownership in Atlas Pipeline GP, its general partner, which together with us owned at December 31, 2009:

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a 2.0% general partner interest in APL, which entitles it to receive 2.0% of the cash distributed by APL;

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all of the incentive distribution rights in APL, which entitle it to receive increasing percentages, up to a maximum of 48.0%, of any cash distributed by APL as it reaches certain target distribution levels in excess of $0.42 per APL common unit in any quarter.

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In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see “—Atlas Pipeline Partners, L.P.”), Atlas Pipeline GP agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. Atlas Pipeline GP also agreed that the resulting allocation of incentive distribution rights back to APL would be after it receives the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 million per quarter thereafter (the “IDR Adjustment Agreement”);

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5,754,253 common units of APL, representing approximately 11.4% of the outstanding common units of APL, or a 11.2% limited partner interest in APL; and

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15,000 $1,000 par value 12.0% APL Class B cumulative preferred limited partner units.

While we, like APL, are structured as a limited partnership, our capital structure and cash distribution policy differ materially from those of APL. Most notably, our general partner, Atlas Pipeline Holdings GP, LLC (“Atlas Pipeline Holdings GP”) does not have an economic interest in us and is not entitled to receive any distributions from us, and our capital structure does not include incentive distribution rights. Therefore, all of our distributions are made first to Atlas Pipeline Holdings II, LLC (“AHD Sub”) Class B preferred units (see “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Equity Offerings”) and then to our common units.

Atlas Energy, Inc. (“Atlas Energy”), a publicly-traded company (NASDAQ: ATLS), owned 64.3% of our common units at December 31, 2009. Atlas Energy also had a direct 2.2% ownership interest in APL at December 31, 2009. On June 1, 2009, we borrowed $15.0 million from Atlas Energy under a subordinate loan. In addition, Atlas Energy guaranteed the remaining balance outstanding under our credit facility (see “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Subordinate Loan and Guaranty Note with Atlas Energy”).

Atlas Pipeline GP’s ownership of APL’s incentive distribution rights entitles it to receive an increasing percentage of cash distributed by APL as it reaches certain target distribution levels. The rights entitle Atlas Pipeline GP, subject to the IDR Adjustment Agreement, to receive the following:

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13.0% of all cash distributed in any quarter after each APL common unit has received $0.42 for that quarter;

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23.0% of all cash distributed in any quarter after each APL common unit has received $0.52 for that quarter; and

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48.0% of all cash distributed in any quarter after each APL common unit has received $0.60 for that quarter.

These amounts are partially offset by the IDR Adjustment Agreement.

Our credit facility currently prohibits us from paying distributions until we repay in full the indebtedness under this facility, which matures in April 2010. We previously paid to our unitholders, on a quarterly basis, distributions equal to the cash we received from APL, less certain reserves for expenses and other uses of cash, including:

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our general and administrative expenses, including expenses as a result of being a publicly traded partnership;

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capital contributions to maintain or increase our ownership interest in APL; and

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reserves our general partner believes prudent to maintain for the proper conduct of our business or to provide for future distributions.

Atlas Pipeline Partners, L.P.

General

APL is a publicly-traded Delaware limited partnership formed in 1999 whose common units are listed on the New York Stock Exchange under the symbol “APL.” APL is a leading provider of natural gas gathering services in the Anadarko and Permian Basins located in the southwestern and mid-continent United States and the Appalachian Basin in the eastern United States. In addition, APL is a leading provider of natural gas processing and treating services in Oklahoma and Texas. APL’s business is conducted in the midstream segment of the natural gas industry through two reportable segments: Mid-Continent and Appalachia.

In APL’s Mid-Continent operations, it owns, has interests in and operates eight natural gas processing plants with aggregate capacity of approximately 900 MMCFD and one treating facility with a capacity of approximately 200 MMCFD. These facilities are connected to approximately 9,100 miles of active natural gas gathering systems located in Oklahoma, Kansas and Texas, which gathers gas from wells and central delivery points to APL’s natural gas processing and treating plants, as well as third-party pipelines.

The Appalachia operations of APL are conducted principally through its 49% ownership interest in the Laurel Mountain Midstream, LLC joint venture (“Laurel Mountain”), which owns and operates approximately 1,800 miles of natural gas gathering systems in the Appalachian Basin located in the northeastern United States. APL also owns and operates approximately 80 miles of active natural gas gathering pipelines located in northeastern Tennessee.

On May 31, 2009, APL and subsidiaries of The Williams Companies, Inc. (NYSE: WMB) (“Williams”) completed the formation of Laurel Mountain, which currently owns and operates APL’s former Appalachia natural gas gathering system (“Legacy Appalachia”), excluding its northeastern Tennessee operations. Laurel Mountain gathers the majority of the natural gas from wells operated by Atlas Energy Resources, LLC and its subsidiaries (“Atlas Energy Resources”), a wholly owned subsidiary of Atlas Energy. Laurel Mountain has gas gathering agreements with Atlas Energy Resources under which Atlas Energy Resources is obligated to pay a gathering fee that is generally the greater of $0.35 per MCF or 16% of the realized sales price (except that a lower fee applies with respect to specific wells subject to certain existing contracts or in the event Laurel Mountain fails to perform specified obligations).

Since APL’s initial public offering in January 2000, it has completed seven acquisitions at an aggregate purchase price of approximately $2.4 billion, including, most recently, in July 2007, APL acquired control of Anadarko Petroleum Corporation’s (“Anadarko” – NYSE: APC) 100% interest in the Chaney Dell natural gas gathering systems and processing plants located in Oklahoma and its 72.8% undivided joint venture interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas (the “Anadarko Assets”). At the date of APL’s acquisition, the Chaney Dell system included 3,470 miles of gathering pipeline and three processing plants, while the Midkiff/Benedum system included 2,500 miles of gathering pipeline and two processing plants. The transaction was accomplished through the formation of two joint venture companies which own the respective systems, to which APL contributed $1.9 billion and Anadarko contributed the Anadarko Assets. APL funded the purchase price in part from its private placement of its common units to investors. We purchased $168.8 million of these APL units, which we funded through our issuance of 6.25 million common units in a private placement. APL funded the remaining purchase price from $830.0 million of proceeds from a senior secured term loan and a senior secured revolving credit facility. Atlas Pipeline GP, as general partner and holder of all of APL’s incentive distribution rights, agreed to allocate a portion of its incentive distribution rights back to APL as set forth in the IDR Adjustment Agreement. In connection with this acquisition, APL reached an agreement with Pioneer Natural Resources Company (“Pioneer” – NYSE: PXD), which holds an approximate 27.2% undivided joint venture interest in the Midkiff/Benedum system, whereby Pioneer had options to buy up to an additional 22% interest in the Midkiff/Benedum system. These options expired on November 2, 2009.

APL’s operations are all located in or near areas of abundant and long-lived natural gas production including the Granite Wash formation; Golden Trend; Woodford Shale; Hugoton field in the Anadarko basin; the Spraberry Trend, which is an oil play with associated natural gas in the Permian Basin and the Marcellus Shale in the Appalachian Basin. APL’s Mid-Continent gathering systems are connected to approximately 7,900 central delivery points or wells. In Appalachia, Laurel Mountain’s systems are connected to approximately 7,700 wells. Thus we believe APL has significant scale in its service areas. APL provides gathering and processing services to the wells connected to its systems, primarily under long-term contracts. As a result of the location and capacity of APL’s gathering and processing assets, APL management believes it is strategically positioned to capitalize on the drilling activity in its service areas. APL intends to continue to expand its business through strategic acquisitions and internal growth projects in efforts to increase distributable cash flow.

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 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, such as certain regions of the Appalachian Basin, does not require treatment or processing, natural gas produced in many other areas, such as APL’s Midkiff/Benedum and Velma operations in the Mid-Continent, are 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 (low 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.

Natural gas transportation pipelines receive natural gas from producers, other mainline transportation pipelines, shippers and gathering systems through system interconnects and redeliver the natural gas to processing facilities, local gas distribution companies, industrial end-users, utilities and other pipelines. Generally natural gas transportation agreements generate revenue for these systems based on a fee per unit of volume transported.

Business Strategy

The primary business objective of APL’s management team is to provide stable long-term cash distributions to its unitholders. APL’s business strategies focus on creating value for its 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. APL intends to accomplish its primary business objectives by executing on the following:

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Increasing the profitability of APL’s existing assets. In many cases, APL’s gathering pipelines and processing plants have excess capacity, which provides it with opportunities to connect and process new supplies of natural gas with minimal additional capital requirements. APL plans to accomplish this goal by providing excellent service to its existing customers, aggressively marketing its services to new customers and prudently expanding its existing infrastructure to ensure its services can meet the needs of potential customers. APL’s recent construction of its Consolidator Plant in West Texas is an example of executing this strategy. Other opportunities include pursuing the elimination of pipeline bottlenecks, reducing operating line pressures and focusing on a reduction of pipeline losses along its gathering systems.

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Expanding operations through organic growth projects and pursuing strategic acquisitions. APL continues to explore opportunities to expand its existing infrastructure. APL also plans to pursue strategic acquisitions that are accretive to its unitholders, by seeking acquisition opportunities that leverage its existing asset base, employees and existing customer relationships. In the past, APL has pursued opportunities in certain regions outside of its current areas of operation and will continue to do so when these options make sense economically and strategically.

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Reducing the sensitivity of APL’s cash flows through prudent economic hedging arrangements. APL attempts to structure its contracts in a manner that allows it to achieve its target rate of return goals while reducing its exposure to commodity price movements. APL’s commodity risk management activities are designed to reduce the effect of commodity price volatility related to future sales of natural gas, NGLs and crude oil, while allowing APL to meet its debt service requirements, fund its maintenance capital program and meet its distribution objectives.

Contracts and Customer Relationships

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

APL’s Mid-Continent Operations

APL owns and operates approximately 9,100 miles of intrastate natural gas gathering systems located in Oklahoma, Kansas, and Texas. APL also owns and operates eight processing plants and one stand-alone treating facility located in Oklahoma and Texas. APL’s gathering, processing and treating assets service long-lived natural gas regions, including the Permian and Anadarko Basins. APL’s systems gather natural gas from oil and natural gas wells and process the raw natural gas into merchantable, or residue, gas by extracting NGLs and removing impurities. In the aggregate, APL’s Mid-Continent systems have approximately 7,900 receipt points, consisting primarily of individual well connections and, secondarily, central delivery points which are linked to multiple wells. APL’s gathering systems interconnect with interstate and intrastate pipelines operated by ANR Pipeline Company, CenterPoint Energy, Inc., 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. APL’s processing facilities are connected to NGL pipelines operated by ONEOK Hydrocarbon, L.P.

Mid-Continent Overview

APL considers the Mid-Continent region as running from Kansas through Oklahoma, branching into northern and western Texas, as well as southeastern New Mexico. The primary producing areas in the region include the Anadarko Basin and the Permian Basin.

Mid-Continent Gathering Systems

Chaney Dell. The Chaney Dell gathering system is located in north central Oklahoma and southern Kansas’ Anadarko Basin. As of December 31, 2009, the gathering systems had approximately 4,100 miles of active natural gas gathering pipelines with approximately 3,700 receipt points.

Elk City/Sweetwater. The Elk City and Sweetwater gathering system includes approximately 800 miles of active natural gas pipelines located in the Anadarko Basin in western Oklahoma and the Texas panhandle, which encompasses the Atoka Wash and Granite Wash formations. The Elk City and Sweetwater gathering system connects to approximately 700 receipt points, with a majority of the system’s western end located in areas of active drilling.

Midkiff/Benedum. The Midkiff/Benedum gathering system, which APL operates and in which APL has an approximate 72.8% ownership as of December 31, 2009, consists of approximately 3,000 miles of active natural gas gathering pipelines and approximately 2,800 receipt points located across four counties within the Permian Basin in West Texas. Pioneer, the largest active driller in the Spraberry Trend and a major producer in the Permian Basin, owns the remaining interest in the Midkiff/Benedum system.

Velma. The Velma gathering system is located in the Golden Trend and near the Woodford Shale areas of southern Oklahoma. As of December 31, 2009, the gathering system had approximately 1,200 miles of active pipelines with approximately 700 receipt points consisting primarily of individual well connections and, secondarily, central delivery points which are linked to multiple wells.

Mid-Continent Processing and Treating Plants

Chaney Dell. The Chaney Dell system processes natural gas through the Waynoka and Chester plants, which are active cryogenic natural gas processing facilities. The Chaney Dell system’s processing operations have total capacity of approximately 228 MMCFD. The Waynoka processing plant, located in Woods County, Oklahoma began operations in December 2006 and became fully operational in July 2007. APL transports and sells natural gas to parties, including various marketing companies and pipelines, at the tailgate of the Waynoka and Chester plants and sells NGL production to ONEOK Hydrocarbon, L.P.

Elk City/Sweetwater. The Elk City, Sweetwater, Nine-Mile and Prentiss facilities are located on the Elk City/Sweetwater gathering system. The Elk City processing plant, located in Beckham County, Oklahoma, is a cryogenic natural gas processing plant with a total capacity of approximately 130 MMCFD. The Prentiss treating facility, also located in Beckham County, Oklahoma, is an amine treating facility with a total capacity of approximately 200 MMCFD. The Sweetwater processing plant, which began operations in September 2006, is a cryogenic natural gas processing plant located in Beckham County, Oklahoma. The Sweetwater plant had an initial capacity of approximately 120 MMCFD. APL built the Sweetwater plant to further access natural gas production being actively developed in western Oklahoma and the Texas panhandle. During July 2008, APL completed a 60 MMCFD expansion of the Sweetwater plant, bringing its total processing capacity to 180 MMCFD. APL subsequently sold this 60 MMCFD additional plant capacity to Penn Virginia Resources in 2009. Thus, APL now owns and operates 120 MMCFD of capacity at the Sweetwater plant, but continues to operate the entire Sweetwater plant. The Nine-Mile plant is a newly constructed cryogenic natural gas plant. It has a capacity of 120 MMCFD, began operations in mid-2009 and is located in Dewey County, Oklahoma. APL transports and sells natural gas to parties, including various marketing companies and pipelines, at the tailgate of its Elk City/Sweetwater plants, as well as sells NGL production to ONEOK Hydrocarbon, L.P.

Midkiff/Benedum. The Midkiff/Benedum system processes natural gas through the Consolidator and Benedum processing plants. The Consolidator plant is a 150 MMCFD cryogenic facility in Reagan County, Texas. The facility was started in November 2009 and replaced the Midkiff plant. The Benedum plant is a 43 MMCFD cryogenic facility in Upton County, Texas. APL’s Consolidator/Benedum processing operations have an aggregate processing capacity of approximately 193 MMCFD. APL transports and sells natural gas to parties, including various marketing companies and pipelines, at the tailgate of the Consolidator/Benedum plants and sells 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 capacity of approximately 100 MMCFD. The Velma plant is one of only two facilities in the area that is capable of treating both high-content hydrogen sulfide and carbon dioxide gases which are characteristic in this area. APL has made capital expenditures at the facility to improve its efficiency and competitiveness, including installing electric-powered compressors rather than higher-cost natural gas-powered compressors used by many of its competitors. APL transports and sells natural gas to parties, including various marketing companies and pipelines, at the tailgate of the Velma plant and sells NGL production to ONEOK Hydrocarbon, L.P.

Natural Gas Supply

In the Mid-Continent, APL has natural gas purchase, gathering and/or processing agreements with approximately 550 producers with terms ranging from one month to 15 years. 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 APL’s 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.

APL has long-term relationships with several of its Mid-Continent producers. For instance, APL has producer relationships going back over 20 years on its Velma System. Several of APL’s top producers, which accounted for a significant portion of the Velma volumes for the year ended December 31, 2009, have contracts with primary terms running well into 2013 and beyond. At the end of the primary terms, most of the contracts with producers on APL’s gathering systems have evergreen term extensions. When APL acquired control of the Midkiff/Benedum system in July 2007, APL and Pioneer agreed to extend the existing gas sales and purchase agreement to 2022. The gas sales and purchase agreement requires that 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, APL anticipates that it 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

APL typically sells natural gas to purchasers downstream of its processing plants priced at various first-of-month indices as published in Inside FERC. Additionally, swing gas, which is natural gas that is 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, an intrastate pipeline; and Southern Star Central Gas Pipeline, Inc. and Natural Gas Pipeline Company of America, interstate pipelines. The Elk City/Sweetwater/Nine-Mile plants have access to six major interstate and intrastate downstream pipelines: Natural Gas Pipeline Company of America, Panhandle Eastern Pipe Line Company, LP, CenterPoint Energy, Inc., Northern Natural Gas Company, ANR Pipeline Company and ONEOK Gas Transportation, LLC. The Chester plant has access to Panhandle Eastern Pipe Line Company, LP and the Waynoka plant has access to Enogex LLC, Panhandle Eastern Pipe Line Company, LP and Southern Star Central Gas Pipeline, Inc. The Consolidator/Benedum plants have access to Kinder Morgan Texas Pipeline, Northern Natural Gas Company and El Paso Natural Gas Company. As negotiated in specific agreements, third party producers are allowed to deliver their gas in-kind to the various delivery points.

APL sells its NGL production to ONEOK Hydrocarbon, L.P. under five separate agreements. The Velma agreement has an initial term expiring February 1, 2011, the Elk City/Sweetwater and Midkiff/Benedum agreements have initial terms expiring in 2013, and the Nine-Mile and Chaney Dell agreements have terms that expire in 2014. 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 Elk City/Sweetwater plants and around the Elk City/Sweetwater gathering system is currently sold to Petro Source Partners, L.P. Condensate collected at the Chaney Dell plants and around the Chaney Dell gathering system is currently sold to Plains Marketing. Condensate collected at the Consolidator/Benedum plants and around the Midkiff/Benedum gathering system is currently sold to ConocoPhillips Company, Occidental Energy Marketing, Inc. and Oasis Marketing and Transportation Corporation.

Natural Gas and NGL Hedging

APL’s Mid-Continent 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. APL attempts 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 a physical price environment that consists of floating prices to a risk-managed environment that is characterized by fixed prices; floor prices on products where APL is long the commodity price; ceiling prices on products where APL is short the commodity price; and/or ranges of prices, (i.e. collars). There are also risks inherent within hedging programs, including among others (i) price correlation between the physical and financial instrument deteriorating or (ii) projected physical volumes changing.

APL (a) purchases natural gas and subsequently sells processed natural gas and the resulting NGLs, or (b) purchases natural gas and subsequently sells the unprocessed natural gas, or (c) gathers and/or processes the natural gas for a fee without taking title to the commodities. Scenario (b) exposes APL to a generally neutral price risk (long sales approximate short purchases), while scenario (c) does not expose APL to any price risk; in both scenarios, risk management is not required. Scenario (a) does involve commodity price risk.

APL is exposed to commodity price risks when natural gas is purchased for processing. The amount and character of this price risk is a function of APL’s contractual relationships with natural gas producers or, alternatively, a function of cost of sales. APL is 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:

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

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

APL manages a portion of these risks by using fixed-for-floating swaps, which result in a fixed price, or by utilizing the purchase or sale of options, which result in floor prices, ceiling prices and/or a range of fixed prices. APL utilizes natural gas swaps and options along with natural gas basis swaps to manage its natural gas price risks. APL utilizes NGL and crude oil swaps and options to manage its NGL and condensate price risks.

APL generally realizes gains and losses from the settlement of its derivative instruments in revenue at the same time it sells the associated physical Residue Gas or NGLs. APL determines 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 (“NYMEX”) prices when applicable and an internally-generated algorithm for commodities that are not traded on an open market. To ensure that these derivative instruments will be used solely for managing price risks and not for speculative purposes, APL has established a committee to review its derivative instruments for compliance with its policies and procedures.

For additional information on APL’s derivative activities and a summary of its outstanding derivative instruments as of December 31, 2009, please see “Item 7A: Quantitative and Qualitative Disclosures About Market Risk.”

APL’s Appalachia Operations

APL’s Appalachia operations are principally conducted through its 49% interest in Laurel Mountain. Laurel Mountain owns and operates approximately 1,800 miles of intrastate gas gathering systems located in northeastern Appalachia, including substantial assets in the Marcellus Shale. APL also owns and operates approximately 80 miles of natural gas gathering pipelines in northeastern Tennessee. Laurel Mountain serves approximately 7,700 wells and experienced an average throughput of 97.0 MMCFD of natural gas for the year ended December 31, 2009. APL’s Tennessee systems serve approximately 190 wells and experienced an average throughput of 8.0 MMCFD of natural gas for the year ended December 31, 2009. APL’s gathering systems provide a means through which well owners and operators can transport the natural gas produced by their wells to interstate and public utility pipelines for delivery to customers. To a lesser extent, APL’s gathering systems transport natural gas directly to customers. Laurel Mountain’s systems are strategically located in the Appalachian Basin, which encompasses the Marcellus Shale. The Marcellus Shale is a vast, newly developing shale play experiencing a significant increase in natural gas exploration and production. The Appalachian Basin

is a region that has historically been characterized by long-lived, predictable natural gas reserves that are close to major eastern U.S. natural gas markets. Substantially all of the natural gas Laurel Mountain gathers in the Appalachian Basin is derived from wells operated by Atlas Energy Resources. Laurel Mountain has a gas gathering agreement with Atlas Energy Resources, which is intended to maximize the use and expansion of the gathering systems and the amount of natural gas which Laurel Mountain gathers in the region. In addition, other natural gas producers have acreage positions in relatively close proximity to Laurel Mountain’s current and planned assets, providing additional opportunities for expansion.

Appalachian Basin Overview

The Appalachian Basin includes the states of Kentucky, Maryland, New York, Ohio, Pennsylvania, Tennessee, Virginia and West Virginia. The Appalachian Basin is strategically located near the energy-consuming regions of the mid-Atlantic and northeastern United States.

Natural Gas Supply

Substantially all of the natural gas Laurel Mountain gathers in the Appalachian Basin is derived from wells operated by Atlas Energy, which owns a 64.3% ownership interest in our common units and a direct 2.2% ownership interest in APL at December 31, 2009. Laurel Mountain’s ability to increase the flow of natural gas through its gathering systems will be determined primarily by the number of wells drilled by Atlas Energy Resources and connected to the gathering systems; and Laurel Mountain’s ability to acquire additional gathering assets and secure gathering contracts with other natural gas producers with acreage positions in the area and expand existing systems. For the year ended December 31, 2009, 250 wells were connected to the Laurel Mountain gathering system.

Natural Gas Revenue

APL’s Appalachia revenue is determined primarily by the amount of natural gas flowing through Laurel Mountain’s and its Tennessee gathering systems and the price received for this natural gas. Laurel Mountain has an agreement with Atlas Energy Resources under which Atlas Energy Resources is obligated to pay a gathering fee that is generally the greater of $0.35 per MCF or 16% of the realized sales price (except that a lower fee applies with respect to specific wells subject to certain existing contracts or in the event Laurel Mountain fails to perform specified obligations). For the year ended December 31, 2009, Laurel Mountain received gathering fees averaging $1.05 per MCF. Laurel Mountain also charges other operator fees, which are negotiated at the time the joint venture connects wells to its gathering systems.

Because APL does not buy or sell gas in connection with its Appalachia operations, it does not engage in hedging activities. Atlas Energy Resources maintains a hedging program. Since Laurel Mountain receives gathering fees from Atlas Energy Resources generally based on the selling price received by Atlas Energy Resources, inclusive of the effects of financial and physical hedging, these financial and physical hedges mitigate the risk of Laurel Mountain’s arrangements.

APL’s Relationship with Atlas Energy

APL began its operations in January 2000 by acquiring the gathering systems of Atlas Energy. In May, 2009, APL contributed the majority of its Appalachia gathering system assets to Laurel Mountain, a joint venture in which APL has a 49% interest. Atlas Energy owned 64.3% of us and had a direct 2.2% ownership interest in APL at December 31, 2009.

Atlas Energy and its affiliates sponsor limited and general partnerships to raise funds from investors to explore for, develop and produce natural gas and, to a lesser extent, oil from locations in northeastern Appalachia. Laurel Mountain’s gathering systems are connected to approximately 6,800 wells developed and operated by Atlas Energy Resources in the Appalachian Basin. Laurel Mountain gathers substantially all of the natural gas from wells operated by Atlas Energy Resources.

Natural Gas Gathering Agreements

In connection with the formation of Laurel Mountain, on June 1, 2009, Laurel Mountain entered into the following natural gas gathering agreements with Atlas Energy Resources, Atlas Energy Operating Company, LLC, Atlas America, LLC, Atlas Noble, LLC, Resource Energy, LLC and Viking Resources, LLC which superseded APL’s master natural gas gathering agreement and omnibus agreement, both dated February 2, 2000: (1) a gas gathering agreement for natural gas on the Legacy Appalachia system with respect to the existing gathering systems and any expansions to it (the “Legacy Agreement”) and (2) a gas gathering agreement for natural gas on the expansion gathering system with respect to other gathering systems constructed within a specified area of mutual interest (the “Expansion Agreement” and collectively with the Legacy Agreement, the “Gathering Agreements”). Under these Gathering Agreements, Atlas Energy Resources will dedicate its natural gas production in the Appalachian Basin to Laurel Mountain for transportation to interstate pipeline systems, local distribution companies, and/or end users in the area, subject to certain exceptions. In return, Laurel Mountain is required to accept and transport Atlas Energy Resources’ dedicated natural gas in the Appalachian Basin subject to certain conditions.

Under the Gathering Agreements, Atlas Energy Resources is obligated to pay a gathering fee that is generally the same as the gathering fee required under the terminated agreements, the greater of $0.35 per MCF or 16% of the realized sales price (except that a lower fee applies with respect to specific wells subject to certain existing contracts or in the event Laurel Mountain fails to perform specified obligations). Unlike the terminated agreements, Atlas Energy will not assume or guarantee Atlas Energy Resources’ obligation to pay the required gathering fees.

The provisions in the Gathering Agreements regarding the allocation of responsibility for constructing additional gathering lines are substantially the same as the provisions in the terminated agreements. To the extent that Atlas Energy Resources own wells or propose wells that are within 2,500 feet of Laurel Mountain’s gathering system, Laurel Mountain must, at its own cost, construct up to 2,500 feet of the gathering lines as necessary to connect such wells to the gathering system. For wells more than 2,500 feet from Laurel Mountain’s gathering system, if Atlas Energy Resources construct a gathering line to within 1,000 feet of Laurel Mountain’s gathering system, then Laurel Mountain must, at its own cost, extend its gathering system to connect to such gathering lines.

The Gathering Agreements remain in effect so long as gas from Atlas Energy Resources’ wells is produced in economic quantities without lapse of more than 90 days.

Competition

Acquisitions. APL has encountered competition in acquiring midstream assets owned by third parties. In several instances APL submitted bids in auction situations and in direct negotiations for the acquisition of such assets and was either outbid by others or was unwilling to meet the sellers’ expectations. In the future, APL expects to encounter equal, if not greater, competition for midstream assets because as natural gas, crude oil and NGL prices increase the economic attractiveness of owning such assets increases.

Mid-Continent. In APL’s Mid-Continent service area, it competes for the acquisition of well connections with several other gathering/processing operations. These operations include plants and gathering systems operated by ONEOK Field Services, Carrera Gas Company, Copano Energy, LLC, Enogex, LLC, Eagle Rock Midstream Resources, L.P., Enbridge, Inc., Hiland Partners, Penn-Virginia Resources, MarkWest Energy Partners, L.P., Mustang Fuel Corporation, DCP Midstream, West Texas Gas, BP Amoco, Southern Union Company and Targa Resources.

APL believes that the principal factors upon which competition for new well connections is based are:

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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; and

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

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

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

APL believes that its relationships with operators connected to its system are good and that APL presents an attractive alternative for producers. However, if APL cannot compete successfully, it may be unable to obtain new well connections.

Appalachia. APL’s assets operated in the Appalachian Basin by Laurel Mountain do not encounter direct competition in its service areas at this time since Atlas Energy Resources controls the majority of the drillable acreage in the area. However, because these operations principally serve wells drilled by Atlas Energy Resources, APL is affected by competitive factors affecting Atlas Energy Resources’ ability to obtain properties and drill wells, which affects Laurel Mountain’s ability to expand gathering systems and to maintain or increase the volume of natural gas gathered and, thus, transportation revenues. Atlas Energy Resources also may encounter competition in obtaining drilling services from third-party providers. Any competition it encounters could delay Atlas Energy Resources in drilling wells for its sponsored partnerships, and thus delay the connection of wells to the Laurel Mountain gathering system. These delays would reduce the volume of natural gas that otherwise would have been gathered, thus reducing potential transportation revenues.

As the Gathering Agreements with Atlas Energy Resources generally requires it to connect wells it operates to the Laurel Mountain system, APL does not expect any direct competition in connecting wells drilled and operated by Atlas Energy Resources in the future. In addition, Laurel Mountain and APL’s Tennessee systems seek to occasionally connect wells operated by third parties. As of December 31, 2009, these systems are connected to approximately 1,000 third party wells.

Seasonality

APL’s 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 APL’s gathering process, which could adversely affect APL’s operating results.

Regulation

Gathering Pipeline Regulation. Section 1(b) of the Natural Gas Act exempts natural gas gathering facilities from the jurisdiction of the Federal Energy Regulatory Commission (“FERC”). APL owns a number of intrastate natural gas gathering lines in New York, Pennsylvania, Ohio, Kansas, Oklahoma and Texas that APL believes would meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. However, the distinction between the FERC-regulated transportation services and federally unregulated gathering services is the subject of regular litigation, so the classification and regulation of some of APL’s or Laurel Mountain’s gathering facilities may be subject to change based on future determinations by FERC and the courts.

Laurel Mountain’s operations in Pennsylvania currently are not subject to the Pennsylvania Public Utility Commission’s regulatory authority since Laurel Mountain does not provide service to the public generally and, accordingly, its activities do not constitute the operation of a public utility. In the event the

Pennsylvania authorities seek to regulate Laurel Mountain’s operations, APL’s operating costs could increase and its transportation fees could be adversely affected, thereby reducing APL’s net revenues and ability to fund its operations, pay required debt service on its credit facilities and make distributions to us, as general partner, and its common unitholders.

APL is currently subject to state ratable, take common purchaser and/or similar statutes in one or more jurisdictions in which it operates. 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, APL’s revenues could decrease. Collectively, any of these laws may restrict APL’s right as an owner of gathering facilities to decide with whom it contracts to purchase or gather natural gas.

APL’s 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. APL’s gathering operations also may be or 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 or adopted from time to time. We cannot predict what effect, if any, such changes might have on APL’s 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 APL’s 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 are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transportation companies that remain subject to FERC’s jurisdiction. These initiatives also may affect the intrastate transportation of natural gas and NGLs under certain circumstances. We cannot predict the ultimate impact of these regulatory changes on APL’s operations.

Energy Policy Act of 2005. The Energy Policy Act contains numerous provisions relevant to the natural gas industry and to interstate 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 APL 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 that 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 FERC as the lead agency for federal authorizations and permits relating to interstate natural gas pipelines and LNG terminals; creates 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 in current 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, none of APL’s 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 APL, primarily in its 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, natural gas liquids 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, APL must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact APL’s business activities in many ways, such as:

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restricting the way APL can handle or dispose of its wastes;

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

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requiring remedial action to mitigate pollution conditions caused by APL’s operations or attributable to former operators; and

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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 and 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. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of pollutants or wastes into the environment.

We believe that APL’s operations are in substantial compliance with applicable environmental laws and regulations and that compliance with existing federal, state and local environmental laws and regulations will not have a material adverse effect on its business, financial position or results of operations. 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 you that 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 APL to incur significant costs.

Hazardous Waste. APL’s operations generate wastes, including some hazardous wastes that are 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 hazardous 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 that APL’s 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 that APL’s 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 APL’s 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 as well as natural gas is excluded from CERCLA’s definition of “hazardous substance,” in the course of APL’s ordinary operations it 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, APL 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.

APL currently owns or leases, 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 APL 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 APL 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 APL. However, none of these spills or releases were material and APL believes that all of them have been 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 substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, APL 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. APL’s 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 APL’s processing plants and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that APL 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. APL’s failure to comply with these requirements could subject it to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. APL 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, that APL’s operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to APL than to any other similarly situated companies.

Water Discharges. APL’s 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. The discharge of pollutants is prohibited unless authorized by a permit or other agency approval. The Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Any unpermitted release of pollutants from APL’s pipelines or facilities could result in administrative, civil and criminal penalties as well as significant remedial obligations. Further, natural gas extraction activity utilizes a process called hydraulic fracturing, which results in water discharges that must be treated and disposed of in accordance with applicable regulatory requirements. Recently, this subject has received much regulatory and legislative attention at both the federal and state level and we anticipate that the permitting and compliance requirements applicable to hydraulic fracturing activity are likely to become more stringent and could have a material adverse impact on many producers, which may have an impact on our operations.

Pipeline Safety. APL’s 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 U.S. Department of Transportation’s Pipeline and Hazardous Material Safety Administration, or PHMSA, acting through the Office of Pipeline Safety, or OPS, administers the national regulatory program to assure safe transportation of natural gas, petroleum, and other hazardous materials by pipeline, by administering the Federal Pipeline Safety Regulations to (1) assure safety in design, construction, inspection, testing, operation, and maintenance of pipeline facilities and (2) set out parameters for administering the pipeline safety program.

APL’s 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 that APL’s 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.

PHMSA recently finalized a series of rules intended to require pipeline operators to develop integrity management programs for gas transportation pipelines (including gathering lines) 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 assure uniform implementation of the pipeline safety program nationwide, a Federal/State partnership of 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 that this will continue in the future.

Employee Health and Safety. APL is 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 that information be maintained about hazardous materials used or produced in APL’s 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 APL’s Velma gas plant contains high levels of hydrogen sulfide, and APL employs numerous safety precautions at the system to ensure the safety of its employees. There are various federal and state environmental and safety requirements for handling sour gas, and APL is in substantial compliance with all such requirements.

Chemicals of Interest. APL operates several facilities that are subject to registration with the U.S. Department of Homeland Security, or DHS, in order to identify quantities of various chemicals that are stored at the sites. These facilities are the Velma, Chaney Dell, Waynoka, Chester, Nine Mile, Sweetwater and Elk City gas processing plants, and the Prentiss Treating facility in Oklahoma; and the Consolidator and Benedum gas processing plants in Texas. The liquid hydrocarbons that are recovered and stored as a result of the facility processing activities, as well as 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 APL is currently in compliance with the Department’s requirements.

Green House 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. The United States Congress is also considering legislation to address the production and reduction of greenhouse gases. Additionally, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or greenhouse gas cap and trade programs. As an alternative to cap and trade programs, Congress may consider the implementation of a carbon tax program. The cap and trade programs could require major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries or gas processing plants, to acquire and surrender emission allowances. Depending on the particular program, APL could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from its operations or from combustion of fuels it processes. Depending on the design and implementation of carbon tax programs, APL’s operations could face additional taxes and higher costs of doing business. Although APL 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 APL’s cost of doing business. However, we are currently unable to assess the timing and effect of the pending legislation.

Properties

As of December 31, 2009, our assets consisted principally of our ownership interests in APL. We maintained no separate properties. As of December 31, 2009, APL’s principal facilities in Appalachia include approximately 80 miles of 2 to 12 inch diameter pipeline operated by its Tennessee gathering systems and approximately 1,800 miles of 2 to 12 inch diameter pipeline operated by Laurel Mountain. APL’s principal facilities in the Mid-Continent consist of eight natural gas processing plants, one treating facility, and approximately 9,100 miles of active 2 to 30 inch diameter pipeline. Substantially all of APL’s 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 APL’s 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 APL’s gas processing facilities and natural gas gathering systems:

Gas Processing Facilities


Facility	Location	Year of Initial Construction	Design Throughput Capacity (MMCFD)
Elk City plant	Beckham County, OK	1984	130
Prentiss treating facility	Beckham County, OK	2003	200
Sweetwater plant	Beckham County, OK	2006	120⁽¹⁾
Nine-Mile plant	Dewey County, OK	2009	120
Velma plant	Stephens County, OK	Updated 2003	100
Waynoka plant	Woods County, OK	2006	200
Chester plant	Woodward County, OK	1981	28
Consolidator plant⁽²⁾	Reagan County, TX	2009	150
Benedum plant	Upton County, TX	Updated 1981	43

⁽¹⁾	Exclusive of 60 MMCFD owned by Penn Virginia Resources

⁽²⁾	Replaced 110 MMCFD Midkiff plant, which has been shut down. Midkiff plant is available for processing if natural gas supply increases beyond the Consolidator plant capacity.

Natural Gas Gathering Systems


System	Location	Approximate Active Miles of Pipe
Chaney Dell	North Central Oklahoma and Southern Kansas	4,100
Elk City/Sweetwater	Western Oklahoma and Texas Panhandle	800
Velma	Southern Oklahoma and Northern Texas	1,200
Midkiff/Benedum	West Texas	3,000
Laurel Mountain	Northeast Appalachia	1,800
Tennessee	Northeastern Tennessee	80

APL’s property or rights-of-way are subject to encumbrances, restrictions and other imperfections. These imperfections have not materially interfered, and we do not expect that they will materially interfere, with the conduct of APL’s 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, APL’s 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 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 APL’s rights to lay and maintain pipelines are derived from recorded gas well leases, with respect to wells that are 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, nor does APL directly employ any of the persons responsible for its operations. In general, employees of Atlas Energy and its affiliates manage APL’s gathering systems and operate its business. Atlas Energy employed approximately 310 people at December 31, 2009 who provided direct support to APL’s operations.

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

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.atlaspipelineholdings.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 1550 Coraopolis Heights Road, Moon Township, Pennsylvania 15108, telephone number (412) 262-2830. 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., Room 1580, Washington, D.C. 20549. The Public Reference Room may be contacted at telephone number (800) 732-0330 for further information.

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

Our only cash generating assets are our interests in APL, and our cash flow therefore completely depends upon the ability of APL to make distributions to its partners. APL’s credit facility conditions the payment of distributions on the satisfaction of specified financial thresholds.

We depend upon cash distributions from APL to fund our operations, pay debt service on our credit facility and make distributions to our unitholders. The Second Amendment to APL’s credit facility agreement restricted it from paying distributions during the second half of 2009 and permits distributions commencing with the quarter ending March 31, 2010 only if, (i) on a pro forma basis after such payment, APL’s senior secured leverage ratio, defined generally as the ratio of total secured funded debt that is not subordinated to the credit facility to consolidated EBITDA, as defined in the credit agreement, is less than or equal to 2.75 to 1.00 and (ii) APL’s minimum liquidity, defined generally as cash and cash equivalents less restricted cash plus amounts available for borrowing under the revolver portion of the credit facility, is at least $50 million. If APL is unable to make distributions, we may be unable to make required debt service payments under our credit facility which could result in the lenders foreclosing on some portion, or all, of our interest in APL. We may then be forced to take actions such as selling our interest in APL, seeking additional equity capital, incurring additional indebtedness or other alternatives.

Even if APL’s credit facility permits APL to pay distributions, the amounts of cash that APL generates may not be sufficient for it to pay distributions to us. APL’s ability to make cash distributions depends primarily on its cash flow. Cash distributions do not depend directly on APL’s profitability, which is affected by non-cash items. Therefore, cash distributions may be made during periods when APL records losses and may not be made during periods when APL records profits. The actual amounts of cash APL generates will depend upon numerous factors relating to its business which we discuss in “Risks relating to APL’s Business,” many of which may be beyond its control, including:

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the demand for natural gas and NGLs;

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the price of natural gas and NGLs (including the volatility of such prices);

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the amount of NGL content in the natural gas APL processes;

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the volume of natural gas APL gathers;

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efficiency of APL’s gathering systems and processing plants;

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expiration of significant contracts;

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continued development of wells for connection to APL’s gathering systems;

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APL’s ability to connect new wells to its gathering systems;

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APL’s ability to integrate newly formed ventures or acquired businesses with its existing operations;

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the availability of local, intrastate and interstate transportation systems;

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the availability of fractionation capacity;

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the expenses APL incurs in providing its gathering services;

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the cost of acquisitions and capital improvements;

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APL’s issuance of equity securities;

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required principal and interest payments on APL’s debt;

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fluctuations in working capital;

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prevailing economic conditions;

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fuel conservation measures;

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alternate fuel requirements;

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the strength and financial resources of APL’s competitors;

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the effectiveness of APL’s hedging program and the creditworthiness of APL’s hedging counterparties;

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

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technical advances in fuel economy and energy generation devices.

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

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the level of capital expenditures it makes;

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the sources of cash used to fund its acquisitions;

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limitations on its access to capital or the market for APL’s common units or notes;

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its debt service requirements and requirements to pay dividends on its outstanding preferred units, and restrictions on distributions contained in its current or future debt agreements; and

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the amount of cash reserves established by us, as APL’s general partner, for the conduct of APL’s business.

APL cannot borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” under its partnership agreement. Because APL cannot borrow money to pay distributions unless it establishes a facility that meets the definition contained in its partnership agreement, APL’s ability to pay a distribution in any quarter solely depends on its ability to generate sufficient operating surplus with respect to that quarter, including meeting the minimum liquidity requirements of its credit facility.

APL’s financial and operating performance may fluctuate significantly from quarter to quarter. APL may be unable to continue to generate sufficient cash flow to fund its operations, pay required debt service on its credit facilities and make distributions to its unitholders. If APL is unable to do so, it may be required to sell assets or equity, reduce capital expenditures, refinance all or a portion of its existing indebtedness or obtain additional financing. APL may be unable to do so on acceptable terms, or at all.

Economic conditions and instability in the financial markets could negatively impact APL’s business which, in turn, could impact the cash we have to make distributions to our unitholders and make payments under our credit facility.

APL’s operations are affected by the continuing effects of the financial crisis and related turmoil 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 resulted in a reduction in drilling activity in APL’s service area and in wells currently connected to APL’s pipeline system being shut in by their operators until prices improve. Any of these events may adversely affect APL’s revenues and its ability to fund capital expenditures and, in the future, may continue to impact the cash that we have available to fund our operations, pay required debt service on our credit facility 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 the availability of funds from those markets has diminished significantly. This may affect APL’s ability to raise capital and reduce the amount of cash available to fund its operations. APL relies on its cash flow from operations and its credit facility to execute its growth strategy and to meet its financial commitments and other short-term liquidity needs. We cannot be certain that additional capital will be available to APL to the extent required and on acceptable terms. Disruptions in the capital and credit markets could negatively impact its access to liquidity needed for its business and impact its flexibility to react to changing economic and business conditions. Any disruption could require APL to take measures to conserve cash until the markets stabilize or until it can arrange alternative credit arrangements or other funding for its business needs. Such measures could include reducing or delaying business activities, reducing its operations to lower expenses, reducing other discretionary uses of cash, and eliminating future distributions to its unitholders.

The source of our earnings and cash flow currently consists exclusively of cash distributions from APL. If APL does not reinstate distributions, we may be unable to make payments under our credit facility which would result in the lenders foreclosing on some portion, or all, of our interest in APL. As discussed in “—Our credit facility prohibits us from paying distributions until all amounts have been paid in full,” we will not be able to reinstate distributions to our unitholders unless we can repay outstanding amounts under our credit facility. Moreover, APL may be unable to execute its growth strategy, take advantage of business opportunities or to respond to competitive pressures, any of which could negatively impact its and our business as we depend on APL for our growth as we describe in “We depend on APL for our growth. As a result of the fiduciary obligations of APL’s general partner, which is our wholly-owned subsidiary, to the common unitholders of APL, our ability to pursue business opportunities independently is limited,” under “Risks Relating to Our Business.”

The current economic situation could have an adverse impact on APL’s producers, key suppliers or other customers, or on our or APL’s lenders, causing them to fail to meet their obligations to us or APL. Market conditions could also impact APL’s derivative instruments. If a counterparty is unable to perform its obligations and the derivative instrument is terminated, APL’s cash flow and ability to pay distributions could be impacted which in turn affects our ability to make required debt service payments on our credit facility and the amount of distributions that we are able to make to our unitholders. The uncertainty and volatility surrounding the global financial crisis may have further impacts on APL’s, and consequently our, business and financial condition that we and APL currently cannot predict or anticipate.

Our and APL’s debt levels and restrictions in our and APL’s credit facilities could limit our ability to fund operations, pay required debt service on our credit facility and make future distributions to our unitholders.

APL will need a substantial portion of its cash flow to make principal and interest payments on its indebtedness, which will reduce the funds that would otherwise be available for operations, future business opportunities and distributions to its unitholders. If APL’s operating results are not sufficient to service its current or future indebtedness, it will be forced to take actions such as reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing its indebtedness, seeking additional equity capital or other alternatives. APL may not be able to affect any of these remedies on satisfactory terms, or at all. Therefore, APL’s ability to make distributions to us and consequently, our ability to fund our operations and pay required debt service could be impacted, which could force us to sell some or all of our interest in APL, seek additional equity capital, incur additional indebtedness or bankruptcy protection.

Our and APL’s credit facilities contain covenants limiting the ability to incur indebtedness, grant liens, engage in transactions with affiliates and make distributions to unitholders. APL’s credit facility also contains covenants requiring APL to maintain certain financial ratios and places limits on capital expenditures. In addition, under APL’s credit facility, it was not permitted to pay cash distributions for the last three quarters of fiscal 2009, and is permitted to pay cash distributions commencing with the quarter ending March 31, 2010, only if its senior secured leverage ratio meets certain thresholds and it has minimum liquidity (both as defined in the credit agreement) of at least $50.0 million as of the quarter end. Our credit facility prohibits us from paying distributions until our credit facility indebtedness is terminated. Its maturity date is in April 2010 and all such amounts are currently scheduled to be repaid in full on April 13, 2010.

Once our credit facility is terminated, our loan from Atlas Energy will be due in full, which may require us to obtain additional capital.

In connection with the amendment of our credit facility, we have borrowed funds from Atlas Energy under a subordinate loan, to facilitate the payment required on the credit facility. The maturity date of the subordinate loan is the day following the date that we repay all outstanding borrowings under our credit facility. We currently do not have sufficient cash to fund our obligations to Atlas Energy upon maturity. Interest on the outstanding balance under the loan accrues quarterly at the rate of 12.0% per annum. However, prior to the maturity date of the subordinate loan, interest on the outstanding balance under the subordinate loan will not be payable in cash, but instead the principal amount of the loan will be increased by the interest amount payable. In order to repay our obligations to Atlas Energy, we could be forced to take actions such as selling our interest in APL and/or seeking additional equity capital.

We may not have sufficient cash to pay distributions even if APL is able to reinstate distributions and we are able to repay all amounts under our credit facility.

The source of our earnings and cash flow currently consists exclusively of cash distributions from APL. Therefore, our ability to fund our operations, pay required debt service on our credit facility and, thereafter, to make distributions to our unitholders may fluctuate based on the level of distributions APL makes to its partners. The Second Amendment to APL’s credit facility agreement restricted it from paying distributions during the second half of 2009 and permits distributions commencing with the quarter ending March 31, 2010, only if, (i) on a pro forma basis after such payment, APL’s senior secured leverage ratio, defined generally as the ratio of total secured funded debt that is not subordinated to the credit facility to consolidated EBITDA, as defined in the credit agreement, is less than or equal to 2.75 to 1.00 and (ii) APL’s minimum liquidity, defined generally as cash and cash equivalents less restricted cash plus amounts available for borrowing under the revolver portion of the credit facility, is at least $50 million.

Even if the credit facility permits APL to pay distributions, we cannot assure you that APL will make quarterly distributions in the future. In addition, while we would expect to increase or decrease distributions to

our unitholders if APL increases or decreases distributions to us, the timing and amount of such increased or decreased distributions, if any, will not necessarily be comparable to the timing and amount of the increase or decrease in distributions made by APL to us.

Once current restrictions in our credit facility on making distributions are terminated, our ability to distribute cash received from APL to our unitholders will be limited by a number of factors, including:

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interest expense and principal payments on any current or future indebtedness;

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restrictions on distributions contained in any current or future debt agreements;

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our general and administrative expenses, including expenses we incur as a result of being a public company;

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expenses of our subsidiaries other than APL, including tax liabilities of our corporate subsidiaries, if any;

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reserves necessary for us to make the necessary capital contributions to maintain our 2.0% general partner interest in APL as required by its partnership agreement upon the issuance of additional partnership securities by APL; and

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reserves our general partner believes prudent for us to maintain for the proper conduct of our business or to provide for future distributions.

We cannot guarantee that in the future we will be able to pay distributions or that any distribution we make will be at or above our previous quarterly distribution levels. The actual amount of cash that is available for distribution to our unitholders will depend on numerous factors, many of which are beyond our control or the control of our general partner.

Even if APL’s credit facility permits APL to pay distributions, reduced APL distributions will disproportionately affect the amount of cash distributions to which we are entitled.

We are entitled to receive incentive distributions from APL, through our ownership of Atlas Pipeline GP, with respect to any particular quarter only if APL distributes more than $0.42 per common unit for such quarter. Furthermore, as described in the immediately following risk factor, in the IDR Adjustment Agreement, Atlas Pipeline GP agreed to allocate up to $5.0 million of incentive distributions per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter.

Atlas Pipeline GP’s incentive distribution rights entitle it to receive percentages increasing up to 48% of all cash distributed by APL, subject to the IDR Adjustment Agreement. Distribution by APL above $0.60 per common unit per quarter would result in Atlas Pipeline GP’s incremental cash distributions to be the maximum 48%. Atlas Pipeline GP’s percentage of the incremental cash distributions reduces from 48% to 23%, if APL’s distribution is between $0.52 and $0.59, and to 13%, if APL’s distribution is between $0.43 and $0.51, subject in both cases to the effect of the IDR Adjustment Agreement. As a result, lower quarterly cash distributions from APL have the effect of disproportionately reducing the amount of all incentive distributions that Atlas Pipeline GP receives as compared to cash distributions Atlas Pipeline GP receives on its 2.0% general partner interest in APL.

We, as the parent of APL’s general partner, may limit or modify the incentive distributions we are entitled to receive from APL in order to facilitate the growth strategy of APL, once APL is able to reinstate distributions. Our general partner’s board of directors can give this consent without a vote of our unitholders.

We own APL’s general partner, which owns the incentive distribution rights in APL that entitle us to receive increasing percentages, up to a maximum of 48.0%, of any cash distributed by APL as it reaches certain target distribution levels in excess of $0.42 per common unit in any quarter. APL’s board of directors may reduce the incentive distribution rights payable to us with our consent, which we may provide without the approval of our unitholders. In July 2007, in connection with APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems, Atlas Pipeline GP agreed to allocate up to $5.0 million of incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. Atlas Pipeline GP also agreed that the resulting allocation of incentive distribution rights back to APL would be after it receives the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007 and $7.0 million per quarter thereafter.

In order to facilitate acquisitions by APL, the general partner of APL may elect to limit the incentive distributions we are entitled to receive with respect to a particular acquisition or unit issuance contemplated by APL. This is because a potential acquisition might not be accretive to APL’s common unitholders as a result of the significant portion of that acquisition’s cash flows which would be paid as incentive distributions to us. By limiting the level of incentive distributions in connection with a particular acquisition or issuance of units of APL, the cash flows associated with that acquisition could be accretive to APL’s common unitholders as well as substantially beneficial to us. In doing so, the managing board of APL’s general partner would be required to consider both its fiduciary obligations to investors in APL as well as to us. Our partnership agreement specifically permits our general partner to authorize the general partner of APL to limit or modify the incentive distribution rights held by us if our general partner determines that such limitation or modification does not adversely affect our limited partners in any material respect.

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

APL has wide discretion to issue additional limited partner units, including units that rank senior to its common units and the incentive distribution rights as to quarterly cash distributions, on the terms and conditions established by its general partner. The payment of distributions on additional APL common units may increase the risk of APL being unable to make distributions at its prior per unit distribution levels. To the extent new APL limited partner units are senior to the APL common units and the incentive distribution rights, their issuance will increase the uncertainty of the payment of distributions on the common units and the incentive distribution rights. Neither the common units nor the incentive distribution rights are entitled to any arrearages from prior quarters.

We may issue an unlimited number of limited partner interests without the consent of our unitholders, which will dilute existing limited partners’ ownership interest in us and may increase the risk that we will not have sufficient available cash to make distributions once our restrictions under our credit facility are removed.

We may issue an unlimited number of limited partner interests of any type without the approval of our unitholders on terms and conditions established by our general partner at any time. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

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our unitholders’ proportionate ownership interest in us will decrease;

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

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

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the ratio of taxable income to distributions may increase; and

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the market price of the common units may decline.

Our ability to meet our future financial needs may be adversely affected by our cash distribution policy and our lack of operational assets.

Our cash distribution policy, which is consistent with our partnership agreement, requires us to distribute all of our available cash quarterly. Our only cash generating assets are partnership interests, including incentive distribution rights, in APL, and we currently have no independent operations separate from those of APL. Even if APL is permitted to pay distributions under its credit facility, a reduction in APL’s distributions will disproportionately affect the amount of cash distributions we receive. Given that our cash distribution policy is to distribute available cash and not retain it and that our only cash generating assets are partnership interests in APL, we may not have enough cash to meet our needs if any of the following events occur:

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an increase in our operating expenses;

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an increase in general and administrative expenses;

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an increase in principal and interest payments on our outstanding debt;

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an increase in working capital requirements; or

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an increase in cash needs of APL or its subsidiaries that reduces APL’s distributions.

Even after we have repaid all outstanding amounts under our credit facility, there is no guarantee that our unitholders will receive quarterly distributions from us.

While our cash distribution policy, which is consistent with the terms of our partnership agreement, requires that we distribute all of our available cash quarterly, our cash distribution policy is subject to the following restrictions and limitations and may be changed at any time, including in the following ways:

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We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including increases in our general and administrative expenses, principal or interest payments on our outstanding debt, elimination of future distributions from APL, the effect of the IDR Adjustment Agreement, principal and interest payments on debt we may incur, working capital requirements and anticipated cash needs of us or APL and its subsidiaries.

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Our cash distribution policy is, and APL’s cash distribution policy is, subject to restrictions on distributions under our credit facility and APL’s credit facility, respectively, such as material financial tests and covenants and limitations on paying distributions during an event of default.

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Our general partner’s board of directors has the authority under our partnership agreement to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the managing board of APL’s general partner has the authority under APL’s partnership agreement to establish reserves for the prudent conduct of APL’s business and for future cash distributions to APL’s common unitholders. The establishment of those reserves could result in a reduction in future cash distributions to our unitholders pursuant to our stated cash distribution policy.

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Our partnership agreement, including the cash distribution policy contained therein, may be amended by a vote of the holders of a majority of our common units.

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Even if our cash distribution policy is not amended, modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement and the amount of distributions paid under APL’s cash distribution policy. The decision by APL to make any distribution to its unitholders is at the discretion of APL’s general partner, taking into consideration the terms of its partnership agreement.

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Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, APL may not make a distribution to its partners if the distribution would cause its liabilities to exceed the fair value of its assets, and we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.

Because of these restrictions and limitations on our cash distribution policy and our ability to change our cash distribution policy, we may not have available cash to distribute to our unitholders, and there is no guarantee that our unitholders will receive quarterly distributions from us.

Our cash distribution policy limits our ability to grow.

Because we distribute all of our available cash, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. In fact, our growth completely depends upon APL’s ability to make and increase its quarterly distribution per unit because currently our only cash-generating assets are partnership interests in APL, including incentive distribution rights. If we issue additional units or incur additional debt to fund acquisitions and capital expenditures, the payment of distributions on those additional units or interest on that debt could increase the risk that we will be unable to maintain or increase our per unit distribution level.

Consistent with the terms of its partnership agreement, APL distributes to its partners its available cash each quarter. In determining the amount of cash available for distribution, APL sets aside cash reserves, including reserves it believes prudent to maintain for the proper conduct of its business or to provide for future distributions. Additionally, it has relied upon external financing sources, including commercial borrowings and other debt and equity issuances, to fund its acquisition capital expenditures. Accordingly, to the extent APL does not have sufficient cash reserves or is unable to finance growth externally, its cash distribution policy will significantly impair its ability to grow. In addition, to the extent APL issues additional units in connection with any acquisitions or capital expenditures, the payment of distributions on those additional common units may increase the risk that APL will be unable to maintain or increase its prior per common unit distribution level. The occurrence of any of these events may impact the cash that we have available to fund our operations, pay required debt service on our credit facility and make distributions to our unitholders. Moreover, the incurrence of additional debt to finance its growth strategy would result in increased interest expense to APL, which in turn, may impact the cash it has available to distribute to its unitholders.

We depend on APL for our growth. As a result of the fiduciary obligations of APL’s general partner, which is our wholly-owned subsidiary, to the common unitholders of APL, our ability to pursue business opportunities independently is limited.

We currently intend to grow primarily through the growth of APL. While we are not precluded from pursuing business opportunities independently of APL, our subsidiary, as the general partner of APL, has a fiduciary duty to APL unitholders which would make it difficult for us to engage in any business activity that is competitive with APL. Those fiduciary duties apply to us because we control the general partner through our ability to elect all of its directors. While there may be circumstances in which we may satisfy these fiduciary duties and still pursue business opportunities independent of APL, we expect such opportunities to be limited. Accordingly, we may be unable to diversify our sources of revenue in order to increase cash distributions.

Our ability to sell our general partner interest and incentive distribution rights in APL is limited.

We face contractual limitations on our ability to sell our general partner interest and incentive distribution rights and the market for such interests is illiquid.

The control of our general partner may be transferred to a third party, and that party could replace our current management team, in each case without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our limited partnership agreement on the ability of the owners of our general partner to transfer their ownership interest in our general partner to a third party. The owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices and to control the decisions taken by the board of directors and officers.

APL’s common unitholders have the right to remove APL’s general partner with the approval of the holders of 66²/3% of all units, which would cause us to lose our general partner interest and incentive distribution rights in APL and the ability to manage APL.

We currently manage APL through Atlas Pipeline GP, APL’s general partner and our wholly-owned subsidiary. APL’s partnership agreement, however, gives common unitholders of APL the right to remove the general partner of APL upon the affirmative vote of holders of 66²/3% of APL’s outstanding common units. If Atlas Pipeline GP were removed as general partner of APL, it would receive cash or common units in exchange for its 2.0% general partner interest and the incentive distribution rights and would lose its ability to manage APL. While the common units or cash we would receive are intended under the terms of APL’s partnership agreement to fully compensate us in the event such an exchange is required, the value of these common units or investments we make with the cash over time may not be equivalent to the value of the general partner interest and the incentive distribution rights had we retained them.

If APL’s general partner is not fully reimbursed or indemnified for obligations and liabilities it incurs in managing the business and affairs of APL, its value, and therefore the value of our common units, could decline.

The general partner of APL may make expenditures on behalf of APL for which it will seek reimbursement from APL. In addition, under Delaware partnership law, APL’s general partner, in its capacity, has unlimited liability for the obligations of APL, such as its debts and environmental liabilities, except for those contractual obligations of APL that are expressly made without recourse to the general partner. To the extent Atlas Pipeline GP incurs obligations on behalf of APL, it is entitled to be reimbursed or indemnified by APL. If APL is unable or unwilling to reimburse or indemnify its general partner, Atlas Pipeline GP may be unable to satisfy these liabilities or obligations, which would reduce its value and therefore the value of our common units.

Cost reimbursements due to APL’s general partner may be substantial and will reduce the cash available for distributions to APL’s common unitholders and thereby, our unitholders.

APL reimburses Atlas Energy, APL’s general partner and their affiliates, including officers and directors of Atlas Energy, for all expenses they incur on APL’s behalf. APL’s general partner has sole discretion to determine the amount of these expenses. In addition, Atlas Energy and its affiliates provide APL with services for which APL is charged reasonable fees as determined by Atlas Energy in its sole discretion. The reimbursement of expenses or payment of fees could adversely affect APL’s ability to make distributions to its common unitholders and thereby adversely affect our ability to fund our operations, pay required debt service on our credit facility and make distributions to our unitholders.

Our unitholders do not elect our general partner or vote on our general partner’s officers or directors, and the rights of unitholders owning 20% or more of our units are further restricted under our partnership agreement. Atlas Energy owns 64.3% of our common units at December 31, 2009, a sufficient number to block any attempt to remove our general partner.

Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders did not elect our general partner or the officers or directors of our general partner and have no right to elect our general partner or the officers and directors of our general partner on an annual or other continuing basis in the future. The board of directors of our general partner, including independent directors, is chosen by the members of our general partner.

Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they have little ability to remove our general partner. Our general partner may not be removed except upon the vote of the holders of at least 66 ²/3% of the outstanding units voting together as a single class. Because Atlas Energy owns 64.3% of our outstanding common units at December 31, 2009, our general partner may not be removed without the consent of Atlas Energy.

Our unitholders’ voting rights are further restricted by the provision in our limited partnership agreement stating that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot be voted on any matter. In addition, our limited partnership agreement contains provisions limiting the ability of our unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders’ ability to influence the manner or direction of our management. As a result of these provisions, the price at which our common units will trade in the future may be lower because of the absence or reduction of a takeover premium in the trading price.

Our unitholders’ liability as a limited partner may not be limited and they may have to repay distributions or make additional contributions under certain circumstances.

Under Delaware law, our unitholders could be held liable for our obligations to the same extent as our general partner if a court determined that the right or the exercise of the right by our unitholders as a group to remove or replace our general partner, to approve some amendments to the limited partnership agreement or to take other action under our limited partnership agreement constituted participation in the “control” of our business.

Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligations that are expressly made without recourse to our general partner. Additionally, the limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in many jurisdictions.

In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

Risks Related to Our Conflicts of Interest

Although we control APL through our ownership of its general partner, APL’s general partner owes fiduciary duties to APL and APL’s unitholders, which may conflict with our interests.

Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, including APL’s general partner, on the one hand, and APL and its limited partners, on the other hand.

The directors and officers of Atlas Pipeline GP have fiduciary duties to manage APL in a manner beneficial to us, its owner. At the same time, these directors and officers have a fiduciary duty to manage APL in a manner beneficial to APL and its limited partners. The managing board of APL or its conflicts committee will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.

For example, conflicts of interest may arise in the following situations:

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the allocation of shared overhead expenses to APL and us;

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the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and APL, on the other hand;

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the determination and timing of the amount of cash to be distributed to APL’s partners and the amount of cash reserved for the future conduct of APL’s business;

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the decision as to whether APL should make acquisitions, and on what terms; and

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any decision we make in the future to engage in business activities independent of, or in competition with, APL.

The fiduciary duties of our general partner’s officers and directors may conflict with those of APL’s general partner’s officers and directors.

Our general partner’s officers and directors have fiduciary duties to manage our business in a manner beneficial to us and our partners. However, certain of our general partner’s executive officers and non-independent directors also serve as executive officers and directors of APL’s general partner, and, as a result, have fiduciary duties to manage the business of APL in a manner beneficial to APL and its partners. Consequently, these directors and officers may encounter situations in which their fiduciary obligations to APL, on one hand, and us, on the other hand, are in conflict. The resolution of these conflicts of interest may not always be in our best interest or that of our unitholders.

If we are presented with certain business opportunities, APL will have the first right to pursue such opportunities.

Pursuant to the omnibus agreement between us and APL, we have agreed to certain business opportunity arrangements to address potential conflicts that may arise between us and APL. If a business opportunity in respect of any business activity in which APL is currently engaged is presented to us, our general partner or APL or its general partner, then APL will have the first right to pursue such business opportunity.

APL and affiliates of our general partner are not limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses which in turn could adversely affect our results of operations and cash available for distribution to our unitholders.

Neither our partnership agreement nor the omnibus agreement between us, APL, Atlas Pipeline GP and Atlas Pipeline Holdings GP, LLC prohibits APL or affiliates of our general partner from owning assets or engaging in businesses that compete directly or indirectly with us or one another. In addition, APL and its affiliates or affiliates of our general partner, may acquire, construct or dispose of additional assets related to the gathering and processing of natural gas, NGLs or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. As a result, competition among these entities could adversely impact APL’s or our results of operations and cash available for paying required debt service on our credit facility or making distributions.

Potential conflicts of interest may arise among our general partner, its affiliates and us. Our general partner and its affiliates have limited fiduciary duties to us and our unitholders, which may permit them to favor their own interests to the detriment of us and our unitholders.

Conflicts of interest may arise among our general partner and its affiliates, on the one hand, and us and our unitholders, 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 the interests of our unitholders. These conflicts include, among others, the following:

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Our general partner is allowed to take into account the interests of parties other than us, including APL and its affiliates and any other businesses acquired in the future, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders.

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Our general partner has limited its liability and reduced its fiduciary duties under the terms of our partnership agreement, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duties. As a result of purchasing our units, unitholders consent to various actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law.

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Our general partner determines the amount and timing of our investment transactions, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution to our unitholders.

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Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.

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Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered, or from entering into additional contractual arrangements with any of these entities on our behalf, so long as the terms of any such payments or additional contractual arrangements are fair and reasonable to us.

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Our general partner controls the enforcement of obligations owed to us by it and its affiliates.

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

Our general partner may not be fully reimbursed for the use of its officers and employees by APL’s general partner.

Our general partner shares officers and administrative personnel with APL’s general partner to operate both our business and APL’s business. Our general partner’s officers, who are also the officers of APL’s general partner, will allocate, in their reasonable and sole discretion, the time they and the administrative personnel spend on our behalf and on behalf of APL. These allocations may not necessarily be the result of arms-length negotiations between APL’s general partner and our general partner. Although our general partner intends to be reimbursed by APL’s general partner for its employees’ activities, due to the nature of the allocations, this reimbursement may not exactly match the actual time spent and related overhead.

Our partnership agreement limits our general partner’s fiduciary duties to us and our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:

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permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its rights to vote and transfer the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of our partnership or amendment to our partnership agreement;

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provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decisions were in the best interests of our partnership;

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generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the audit and conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships among the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

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provides that in resolving conflicts of interest, it will be presumed that in making its decision the general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and

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provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that such person’s conduct was criminal.

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

If at any time our general partner and its affiliates own more than 87.5% of our outstanding units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less than their then-current market price. As a result, our unitholders may be required to sell their units at an undesirable time or price and may not receive any return on their investment. Our unitholders may also incur a tax liability upon a sale of their units. At December 31, 2009, Atlas Energy owns approximately 64.3% of our outstanding common units.

Risks Relating to APL’s Business

Because our cash flow currently consists exclusively of distributions from APL, risks to APL’s business are also risks to us. We have set forth below the material risks to APL’s business or results of operations, the occurrence of which could negatively impact APL’s financial performance and decrease the amount of cash it is able to distribute to us, thereby decreasing the amount of cash we have available for funding our operations, paying required debt service on our credit facility or making distributions to our unitholders.

APL is affected by the volatility of prices for natural gas and NGL products.

APL derives a majority of its gross margin from POP and Keep-Whole contracts. As a result, APL’s income depends to a significant extent upon the prices at which it buys and sells natural gas and at which it sells NGLs and condensate. Average estimated unhedged 2010 market prices for NGLs, natural gas and condensate, based upon NYMEX forward price curves as of February 15, 2010, are $1.10 per gallon, $5.71 per MMBTU and $76.26 per barrel, respectively. A 10% change in these prices would change our forecasted gross margin, excluding the effect of non-controlling interest in APL net income (loss), for the twelve-month period ended December 31, 2010 by approximately $27.2 million. Additionally, changes in natural gas prices may indirectly impact APL’s profitability since prices can influence drilling activity and well operations, and could cause operators of wells currently connected to APL’s pipeline system or that it expects will be connected to its system to shut in their production until prices improve, thereby affecting the volume of gas APL gathers and processes. Historically, the price of both natural gas and NGLs has been subject to significant volatility in response to relatively minor changes in the supply and demand for natural gas and NGL products, market uncertainty and a variety of additional factors beyond APL’s control, including those described in “––The amount of cash APL generates depends, in part, on factors beyond APL’s control,” above. Oil prices have traded in a range of $33.98 per barrel to $81.37 per barrel in 2009, while natural gas prices have traded in a range of $2.51 per MMBTU to $6.07 per MMBTU during the same time period. APL expects this volatility to continue. This volatility may cause APL’s gross margin and cash flows to vary widely from period to period. APL’s risk management strategies may not be sufficient to offset price volatility risk and, in any event, do not cover all of the throughput volumes. Moreover, derivative instruments are subject to inherent risks, which we describe in “—APL’s price risk management strategies may fail to protect APL and could reduce APL’s gross margin and cash flow.”

APL’s price risk management strategies may fail to protect it and could reduce its gross margin and cash flow.

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

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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 APL seeks protection;

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price correlation between the physical transaction and the derivative transaction could change;

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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 is not offset by income on the anticipated physical transaction; and

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

Due to the accounting treatment of APL’s derivative contracts, increases in prices for natural gas, crude oil and NGLs could result in non-cash balance sheet reductions.

With the objective of enhancing the predictability of future revenues, from time to time APL enters into natural gas, natural gas liquids and crude oil derivative contracts. APL accounts for these derivative contracts by

applying the mark-to-market accounting treatment required for these derivative contracts. APL could recognize incremental derivative liabilities between reporting periods resulting from increases or decreases in reference prices for natural gas, crude oil and NGLs, which could result in APL recognizing a non-cash loss in our consolidated statements of operations and a consequent non-cash decrease in our Partners’ Capital between reporting periods. Any such decrease could be substantial. In addition, APL may be required to make cash payments upon the termination of any of these derivative contracts.

APL is exposed to the credit risks of its key customers, and any material nonpayment or nonperformance by its key customers could negatively impact APL’s business.

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

Due to APL’s lack of asset diversification, negative developments in its operations would reduce its ability to fund its operations, pay required debt service on its credit facilities and make distributions to its common unitholders.

APL relies exclusively on the revenues generated from its gathering and processing operations, and as a result, its financial condition depends upon prices of, and continued demand for, natural gas and NGLs. Due to APL’s lack of asset-type diversification, a negative development in one of these businesses would have a significantly greater impact on its financial condition and results of operations than if APL maintained more diverse assets.

The amount of natural gas APL gathers will decline over time unless it is able to attract new wells to connect to its 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 APL’s gathering systems could, therefore, result in the amount of natural gas APL gathers declining substantially over time and could, upon exhaustion of the current wells, cause it to abandon one or more of its gathering systems and, possibly, cease operations. The primary factors affecting APL’s ability to connect new supplies of natural gas to its gathering systems include APL’s success in contracting for existing wells that are not committed to other systems, the level of drilling activity near its gathering systems and, in the Mid-Continent region, APL’s ability to attract natural gas producers away from its 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 APL’s gathering and processing facilities could result if there is a sustained decline in natural gas prices which, in turn, would lead to a reduced utilization of those 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. APL has no control over the level of drilling activity in its service areas, the amount of reserves underlying wells that connect to its systems and the rate at which production from a well will decline. In addition, APL has 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, such as currently exists, producers may determine to shut in wells already connected to APL’s systems until prices improve. Because APL’s operating costs are fixed to a significant degree, a reduction in the natural gas volumes it gathers or processes would result in a reduction in its gross margin and cash flows.

The amount of natural gas APL gathers or processes may be reduced if the natural gas liquids pipelines to which it delivers NGLs cannot or will not accept the NGLs.

If one or more of the pipelines to which APL delivers NGLs has service interruptions, capacity limitations or otherwise does not accept the NGLs APL sells to or transports on, and APL cannot arrange for delivery to other pipelines, the amount of NGLs APL sells or transport may be reduced. Since APL’s revenues depend upon the volumes of NGLs it sells or transports, this could result in a material reduction in its gross margin and cash flows.

The amount of natural gas APL gathers or processes may be reduced if the intrastate and interstate pipelines to which APL delivers gas cannot or will not accept the gas.

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

If APL is unable to obtain new rights-of-way or the cost of renewing existing rights-of-way increases, then its cash flows could be reduced.

The construction of additions to APL’s existing gathering assets may require it to obtain new rights-of-way before constructing new pipelines. APL may be unable to obtain rights-of-way to connect new natural gas supplies to its existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for APL to obtain new rights-of-way or to renew existing rights-of-way. If the cost of obtaining new rights-of-way or renewing existing rights-of-way increases, then its cash flows could be reduced.

The success of APL’s interest in the Laurel Mountain joint venture depends upon Atlas Energy Resources’ ability to drill and complete commercially producing wells.

Substantially all of the wells connected to the Laurel Mountain gathering systems in APL’s Appalachia service area are drilled and operated by Atlas Energy Resources for drilling investment partnerships sponsored by it. As a result, Laurel Mountain currently depends principally upon the success of Atlas Energy Resources in sponsoring drilling investment partnerships and completing wells for these partnerships. Atlas Energy Resources operates in a highly competitive environment for acquiring undeveloped leasehold acreage and attracting capital. Atlas Energy Resources may not be able to compete successfully in the future in acquiring undeveloped leasehold acreage or in raising additional capital through its drilling investment partnerships. If Atlas Energy Resources cannot or does not continue to sponsor drilling investment partnerships, if the amount of money raised by those partnerships decreases, or if the number of wells actually drilled and completed as commercially producing wells decreases, the amount of natural gas gathered via APL’s Laurel Mountain systems would substantially decrease and could, upon exhaustion of the wells currently connected to its gathering systems, cause the joint venture to abandon one or more of APL’s Appalachia gathering systems, which may reduce APL’s gross margin and cash flows.

The failure of Atlas Energy Resources to perform its obligations under the Laurel Mountain Gathering Agreements may adversely affect APL’s business.

Substantially all of Laurel Mountain’s revenues currently consist of the fees received under the Gathering Agreements and other transportation agreements it has with Atlas Energy Resources. APL expects to derive a portion of its gross margin from the services provided under contracts Laurel Mountain has with Atlas

Energy Resources for the foreseeable future. Any factor or event adversely affecting Atlas Energy Resources’ business or its ability to perform under its contracts with Laurel Mountain or any default or nonperformance by Atlas Energy Resources of its contractual obligations to Laurel Mountain, could reduce APL’s gross margin and cash flows.

The success of APL’s Mid-Continent operations depends upon its ability to continually find and contract for new sources of natural gas supply from unrelated third parties.

Unlike Laurel Mountain, none of the drillers or operators in its Mid-Continent service area is an affiliate of either APL or us. Moreover, APL’s agreements with most of the producers with which its Mid-Continent operations do business generally do not require them to dedicate significant amounts of undeveloped acreage to APL’s systems. While APL does have some undeveloped acreage dedicated on its systems, most notably with its partner Pioneer on its Midkiff/Benedum system, APL does not have assured sources to provide it with new wells to connect to its Mid-Continent gathering systems. Failure to connect new wells to APL’s Mid-Continent operations will, as described in “—The amount of natural gas APL gathers will decline over time unless it is able to attract new wells to connect to its gathering systems,” above, will reduce APL’s gross margin and cash flows.

APL’s Mid-Continent operations currently depend on certain key producers for their supply of natural gas; the loss of any of these key producers could reduce its revenues.

During 2009, Chesapeake Energy Corporation, Pioneer, Sandridge Energy, Inc., Conoco Phillips, XTO Energy Inc., Henry Petroleum, L.P., Linn Energy, LLC, Kaiser-Francis Oil Company, Sanguine Gas Exploration, LLC, Forest Oil Corporation and Apache Corporation accounted for a significant amount of APL’s Mid-Continent operations natural gas supply. If these producers reduce the volumes of natural gas that they supply to APL, APL’s gross margin and cash flows would be reduced unless it obtains comparable supplies of natural gas from other producers.

The curtailment of operations at, or closure of, any of APL’s processing plants could harm its business.

If operations at any of APL’s processing plants were to be curtailed, or closed, whether due to accident, natural catastrophe, environmental regulation or for any other reason, APL’s ability to process natural gas from the relevant gathering system and, as a result, its ability to extract and sell NGLs, would be harmed. If this curtailment or stoppage were to extend for more than a short period, APL’s gross margin and cash flows would be materially reduced.

APL may face increased competition in the future in its Mid-Continent operations.

APL’s Mid-Continent operations face competition for well connections. DCP Midstream, LLC, ONEOK, Inc., Carrera Gas Company, Copano Energy, LLC and Enogex, LLC operate competing gathering systems and processing plants in APL’s Velma service area. In APL’s Elk City, Sweetwater and Nine-Mile service area, ONEOK Field Services, Eagle Rock Midstream Resources, L.P., Enbridge Energy Partners, L.P., CenterPoint Energy, Inc., Penn-Virginia Resources, MarkWest Energy Partners, L.P. and Enogex LLC operate competing gathering systems and processing plants. Hiland Partners, DCP Midstream, Mustang Fuel Corporation and ONEOK Partners operate competing gathering systems and processing plants APL’s Chaney Dell service area. DCP Midstream, West Texas Gas, BP Amoco, Southern Union Company and Targa Resources operate competing gathering systems and processing plants in APL’s Midkiff/Benedum service area. Some of APL’s competitors have greater financial and other resources than APL does. If these companies become more active in APL’s Mid-Continent service areas, it may not be able to compete successfully with them in securing new well connections or retaining current well connections. If APL does not compete successfully, the amount of natural gas APL gathers, processes and treats will decrease, reducing its gross margin and cash flows.

The acquisitions of APL’s Chaney Dell and Midkiff/Benedum systems in July 2007 and the contribution of APL’s Appalachia assets to Laurel Mountain in May 2009 have substantially changed APL’s business, making it difficult to evaluate its business based upon its historical financial information.

The acquisitions of APL’s Chaney Dell and Midkiff/Benedum systems have significantly increased its size and substantially redefined APL’s business plan, expanded its geographic market and resulted in large changes to its revenues and expenses. In May 2009, APL contributed the majority of its Appalachia gathering system assets to Laurel Mountain, a joint venture in which APL has a 49% interest. Income for Laurel Mountain is recognized as equity income on APL’s statement of operations. As a result of these transactions, and APL’s continued plan to acquire and integrate additional companies that it believes presents attractive opportunities, APL’s financial results for any period or changes in its results across periods may continue to dramatically change. APL’s historical financial results, therefore, should not be relied upon to accurately predict its future operating results, thereby making the evaluation of its business more difficult.

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;

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mistaken assumptions about revenues and costs, including synergies;

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significant increases in APL’s indebtedness and working capital requirements;

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

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

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

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the assumption of unknown liabilities;

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limitations on rights to indemnity from the seller;

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

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increased demands on existing personnel;

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customer or key employee losses at the acquired businesses; and

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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, APL’s future acquisition costs may be higher than those it has achieved historically. Any of these factors could adversely impact APL’s future growth and its ability to make or increase distributions.

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

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

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operating a significantly larger combined entity;

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

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integrating personnel with diverse business backgrounds and organizational cultures;

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consolidating operational and administrative functions;

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integrating pipeline safety-related records and procedures;

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

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

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customer or key employee loss from the acquired businesses;

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a significant increase in APL’s indebtedness; and

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potential environmental or regulatory liabilities and title problems.

APL’s investment and the additional overhead costs it incurs to grow its NGL 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 its operations could harm its business or future prospects, and result in significant decreases in its gross margin and cash flows.

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

One of the ways APL may grow its business is through the construction of new assets, such as the recent Madill-to-Velma pipeline and the Nine-Mile and Consolidator plants. The construction of additions or modifications to its existing systems and facilities, and the construction of new assets, involve numerous regulatory, environmental, political and legal uncertainties beyond APL’s control and require the expenditure of significant amounts of capital. Any projects APL undertakes may not be completed on schedule at the budgeted cost, or at all. Moreover, APL’s revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if APL expands a gathering system, the construction may occur over an extended period of time, and it will not receive any material increases in revenues until the project is completed. Moreover, APL may construct facilities to capture anticipated future growth in production in a region in which growth does not materialize. Since APL is not engaged in the exploration for, and development of, natural gas reserves, it often does not have access to estimates of potential reserves in an area before constructing facilities in the area. To the extent APL relies on estimates of future production in its decision to construct additions to its systems, the estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not be able to attract enough throughput to achieve APL’s expected investment return, which could impair its results of operations and financial condition. In addition, APL’s 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.

APL recently completed construction of an expansion to its Nine-Mile and Consolidator natural gas processing plants. APL also recently completed a pipeline to extend its Velma system into the Madill area. From these projects, APL expects to generate additional incremental cash flow. APL also continues to expand the natural gas gathering systems surrounding its other facilities in order to maximize plant throughput. In addition to the risks discussed above, expected incremental revenue from the recent projects could be reduced or delayed due to the following reasons:

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difficulties in obtaining equity or debt financing for additional construction and operating costs;

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

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additional construction and operating costs exceeding budget estimates;

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

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difficulties in obtaining consistent supplies of natural gas; and

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terms in operating agreements that are not favorable to APL.

APL may not be able to execute its growth strategy successfully.

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

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APL may not be able to identify suitable acquisition candidates;

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APL 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;

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APL’s costs in seeking to make acquisitions may be material, even if it cannot complete any acquisition it has pursued;

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irrespective of estimates at the time it makes an acquisition, the acquisition may prove to be dilutive to earnings and operating surplus;

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

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APL may encounter difficulties in integrating operations and systems; and

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any additional debt APL incurs to finance an acquisition may impair its ability to service its existing debt.

Limitations on APL’s access to capital or the market for its common units will impair APL’s ability to execute its growth strategy.

APL’s ability to raise capital for acquisitions and other capital expenditures depends upon ready access to the capital markets. Historically, APL has financed its acquisitions, and to a much lesser extent, expansions of its gathering systems by bank credit facilities and the proceeds of public and private debt and equity offerings of its common units and preferred units of its operating partnership. If APL is unable to access the capital markets, it may be unable to execute its strategy of growth through acquisitions.

Regulation of APL’s gathering operations could increase its operating costs, decrease its revenues, or both.

Currently APL’s gathering and processing of natural gas is exempt from regulation under the Natural Gas Act of 1938. However, the implementation of new laws or policies, or changed interpretations of existing

laws, could subject APL’s gathering and processing operations to regulation by FERC under the Natural Gas Act, the Natural Gas Policy Act, or other laws. APL expects that any such regulation would increase its costs, decrease its gross margin and cash flows, or both.

Even if APL’s gathering and processing operations are not generally subject to regulation under the Natural Gas Act, FERC regulation will still affect APL’s business and the market for its products. FERC’s policies and practices affect a range of natural gas pipeline activities, including, for example, its 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 you 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 APL’s business. Matters subject to regulation include access, rates, terms of service and safety. For example, APL’s gathering lines are subject to ratable take, common purchaser and similar statutes in one or more jurisdictions in which APL operates. 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, APL’s revenues could decrease. Collectively, all of these statutes restrict APL’s right as an owner of gathering facilities to decide with whom it contracts to purchase or gathers 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:

•

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.

APL does not believe that the cost of implementing integrity management program testing along certain segments of APL’s pipeline will have a material effect on its results of operations. This does not include the costs, if any, of any repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which costs could be substantial.

APL’s 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.

The operations of APL’s gathering systems, plant and other facilities are subject to stringent and complex federal, state and local environmental laws and regulations. These laws and regulations can restrict or impact APL’s business activities in many ways, including restricting the manner in which it disposes of substances, requiring remedial action to remove or mitigate contamination, and requiring capital expenditures to comply with control requirements. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of 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 and property damage allegedly caused by the release of substances or wastes into the environment.

There is inherent risk of the incurrence of environmental costs and liabilities in APL’s business due to its handling of natural gas and other petroleum products, air emissions related to our operations, historical industry operations including releases of substances into the environment, and waste disposal practices. For example, an accidental release from one of APL’s pipelines or processing facilities could subject it to substantial liabilities arising from environmental cleanup, restoration costs and natural resource damages, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase APL’s compliance costs and the cost of any remediation that may become necessary. APL may not be able to recover some or any of these costs from insurance.

APL’s midstream natural gas operations may incur significant costs and liabilities resulting from new environmental regulations related to climate control.

Federal and state governments are considering and/or implementing measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or greenhouse gas cap and trade programs. As an alternative to cap and trade programs, Congress may consider the implementation of a carbon tax program. Depending on the particular program, APL could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from its operations or from combustion of fuels APL processes. Depending on the design and implementation of carbon tax programs, APL’s operations could face additional taxes and higher costs of doing business. Although APL 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 APL’s cost of doing business.

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

APL’s operations are subject to federal and state environmental laws under which owners of natural gas pipelines can be liable for clean-up costs and fines in connection with any pollution caused by their pipelines. APL may also be held liable for clean-up costs resulting from pollution which occurred before its acquisition of the gathering systems. In addition, APL is 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 APL.

APL is also subject to the requirements of OSHA and comparable state statutes. Any violation of OSHA could impose substantial costs on APL.

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

APL is subject to operating and litigation risks that may not be covered by insurance.

APL’s 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 and farm equipment;

•

leakage of natural gas, NGLs and other hydrocarbons;

•

fires and explosions;

•

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; and

•

acts of terrorism directed at APL’s pipeline infrastructure, production facilities and surrounding properties.

As a result, APL may be a defendant in various legal proceedings and litigation arising from its operations. APL may not be able to maintain or obtain insurance of the type and amount desired at reasonable rates. As a result of market conditions, premiums and deductibles for some of APL’s insurance policies have increased substantially, and could escalate further. In some instances, insurance could become unavailable or available only for reduced amounts of coverage. For example, insurance carriers are now requiring broad exclusions for losses due to war risk and terrorist acts. If APL were to incur a significant liability for which it was not fully insured, its gross margin and cash flows would be materially reduced.

APL’s control of the Chaney Dell and Midkiff/Benedum systems is limited by provisions of the limited liability company operating agreements with Anadarko and, with respect to the Midkiff/Benedum system, the operation and expansion agreement with Pioneer.

The managing member of each of the limited liability companies which owns the interests in the Chaney Dell and Midkiff/Benedum systems is APL’s subsidiary. However, the consent of Anadarko is required for specified extraordinary transactions, such as admission of new members, engaging in transactions with APL’s 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 Midkiff/Benedum system is also governed by an operation and expansion agreement with Pioneer which gives system owners having 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.

APL is not the operator of the gathering system owned by Laurel Mountain and does not control Laurel Mountain other than through provisions of the limited liability company agreement with Williams Laurel Mountain, LLC, or Williams.

All day-to-day operations of APL’s Appalachia assets (exclusive of Tennessee) are managed by Williams as the operating member of Laurel Mountain. Pursuant to the limited liability company agreement of Laurel Mountain, all decisions of the management committee of Laurel Mountain currently require the unanimous approval of both APL and Williams. However, upon the date that any member owns more than 66 2/3% of the outstanding ownership interests in Laurel Mountain, which is referred to as the “voting change date,” specified decisions of the management committee will require the approval of only the holders of a majority of the ownership interests, specified decisions will require the approval of more than 75% of the ownership interests, and specified decisions will require unanimous approval of the membership interests of Laurel Mountain. Dilution of a member’s ownership interests can occur when the member does not participate in capital contributions needed to fund specified capital investment projects, in which case the non-pursuing member’s ownership interest will be diluted in proportion to the amount of the capital contribution the non-pursuing member would have been required to contribute in connection with such capital investment project. APL currently owns, through a wholly-owned subsidiary, a 49% interest in Laurel Mountain and has an effective veto on all decisions of the management committee of Laurel Mountain. However, there can be no assurances that APL will maintain this ownership percentage or that a voting change date, and the related changes in voting requirements, will not occur.

Risks Related to Our Ownership Structure

Atlas Energy and its affiliates have conflicts of interest and limited fiduciary responsibilities, which may permit them to favor their own interests to the detriment of our and APL’s unitholders.

Atlas Energy and its affiliates, which own and control us, also own a 2.2% limited partner interest in APL. We and APL do not have any employees and rely solely on employees of Atlas Energy and its affiliates who serve as our agents, including all of the senior managers who operate APL’s business. A number of officers and employees of Atlas Energy also own interests in us and APL. Conflicts of interest may arise between Atlas Energy and their affiliates, on the one hand, and us and APL, on the other hand. As a result of these conflicts, we may favor our own interests and the interests of our affiliates over APL’s interests and the interests of APL’s unitholders. These conflicts include, among others, the following situations:

•

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

•

Neither our or APL’s partnership agreement nor any other agreement requires Atlas Energy to pursue a future business strategy that favors us or APL or, apart from APL’s and Laurel Mountain’s agreements with Atlas Energy Resources relating to APL’s Appalachia operations, or use APL’s assets for gathering or processing services APL provides. Atlas Energy’s directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of Atlas Energy.

•

We are allowed to take into account the interests of parties other than APL, such as Atlas Energy, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to APL.

•

We control the enforcement of obligations owed to APL, our affiliates and us, including APL’s agreements with Atlas Energy Resources.

Conflicts of interest with Atlas Energy and its affiliates and us, including the foregoing factors, could exacerbate periods of lower or declining performance, or otherwise reduce our and APL’s gross margin and cash flows.

Tax Risks of Unit Ownership

If in the future we cease to manage and control APL through our ownership of its general partner interests, we may be deemed to be an investment company.

If we cease to manage and control APL and are deemed to be an investment company under the Investment Company Act of 1940, we would either have to register as an investment company under the Investment Company Act of 1940, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates.

APL or we may no longer be qualified as a partnership or the current law may change causing APL or us to be treated as a corporation for tax purposes.

The value of our investment in APL depends largely on it being treated as a partnership for federal income tax purposes, which requires that 90% or more of APL’s 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). APL may not meet this requirement or current law may change so as to cause, in either event, APL to be treated as a corporation for federal income tax purposes or otherwise subject to federal income tax. Moreover, the anticipated after-tax benefit of an investment in our common units depends largely on us being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.

If APL were treated as a corporation for federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate, which is currently a maximum of 35%. Distributions to us would generally be taxed again as corporate dividends, and no income, gains, losses, deductions or credits would flow through to us. As a result, there would be a material reduction in our anticipated cash flow, likely causing a substantial reduction in the value of our units.

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 unit holders would generally be taxed again as corporate dividends, and no income, gains, losses, deductions or credits would flow through to our unit holders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unit holders would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in our anticipated cash flow, likely causing a substantial reduction in the value of our units.

Current law may change, causing us or APL to be treated as a corporation for federal and/or state income tax purposes or otherwise subjecting us or APL 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 or APL as an entity, the cash available for distribution to our unit holders 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 any 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.

Our ratio of taxable income to cash distributions will be much greater than the ratio applicable to holders of common units in APL.

Our ratio of taxable income to cash distributions will be much greater than the ratio applicable to holders of common units in APL. Other holders of common units in APL will receive remedial allocations of deductions from APL. Although we will receive remedial allocations of deductions from APL, remedial allocations of deductions to us will be very limited. In addition, our ownership of APL incentive distribution rights will cause more taxable income to be allocated to us from APL than will be allocated to holders who hold only common units in APL. If APL is successful in increasing its distributions over time, our income allocations from our APL incentive distribution rights will increase, and, therefore, our ratio of taxable income to cash distributions will increase. Because our ratio of taxable income to cash distributions will be greater than the ratio applicable to holders of common units in APL, our unitholders allocable taxable income will be significantly greater than that of a holder of common units in APL who receives cash distributions from APL equal to the cash distributions our unitholders would receive from us.

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 or APL’s capital and profits interest within a 12-month period will result in the termination of our or APL’s 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. Likewise, APL will be considered to have terminated its partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interest in APL’s capital and profits within a 12-month period. The termination would, among other things, result in the closing of our or APL’s 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 or APL 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 jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We and APL presently anticipate that substantially all of our income will be generated in Oklahoma, Pennsylvania and Texas. Each of those states, except Texas, currently imposes a personal income tax. We or APL 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.

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

When we or APL issue additional units or engage in certain other transactions, APL determines the fair market value of its assets and allocates any unrealized gain or loss attributable to such assets to the capital accounts of APL’s unitholders and us. Although APL may from time to time consult with professional appraisers regarding valuation matters, including the valuation of its assets, APL makes many of the fair market value estimates of its assets itself using a methodology based on the market value of its common units as a means to measure the fair market value of its assets. APL’s methodology may be viewed as understating the value of APL’s assets. In that case, there may be a shift of income, gain, loss and deduction between certain APL unitholders and us, which may be unfavorable to such APL unitholders. Moreover, under APL’s 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 APL’s tangible assets and a lesser portion allocated to APL’s intangible assets. The IRS may challenge APL’s valuation methods, or our or APL’s allocation of Section 743(b) adjustment attributable to APL’s tangible and intangible assets, and allocations of income, gain, loss and deduction between us and certain of APL’s 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 or the APL’s unitholders. It also could affect the amount of gain on the sale of common units by our unitholders or APL’s unitholders and could have a negative impact on the value of our common units or those of APL or result in audit adjustments to the tax returns of our or APL’s unitholders without the benefit of additional deductions.

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

None.

ITEM 2.

PROPERTIES

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

ITEM 3.

LEGAL PROCEEDINGS

We are not subject to any pending material legal proceedings.

ITEM 4:

[OMITTED AND RESERVED]

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 “AHD.” At the close of business on March 2, 2010, the closing price for the common units was $7.20 and there were 7 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, 2009 and 2008:


	High		Low		Distributions Declared
2009
Fourth Quarter	$	7.00	$	3.11	$	0.00
Third Quarter	$	4.78	$	2.88	$	0.00
Second Quarter	$	5.56	$	1.46	$	0.00
First Quarter	$	7.03	$	0.77	$	0.00

2008
Fourth Quarter	$	24.12	$	3.28	$	0.06
Third Quarter	$	36.36	$	22.18	$	0.51
Second Quarter	$	36.32	$	27.08	$	0.51
First Quarter	$	33.97	$	25.71	$	0.43

Our Cash Distribution Policy

The board of directors of our general partner has adopted a cash distribution policy, pursuant to our partnership agreement, which requires that we distribute all of our available cash quarterly to our limited partners within 50 days following the end of each calendar quarter in accordance with their respective percentage interests. Under our partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount of cash reserves established by our general partner to, among other things:

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provide for the proper conduct of our business;

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comply with applicable law, any of our debt instruments or other agreements; or

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provide funds for distributions to our unitholders for any one or more of 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. We make distributions of available cash to common unitholders regardless of whether the amount distributed is less than the minimum quarterly distribution. Our distributions to limited partners are not cumulative. Consequently, if distributions on our common units are not paid with respect to any fiscal quarter, our unitholders are not entitled to receive such payments in the future.

On June 1, 2009, we entered into an amendment to our credit facility agreement which, among other changes, prohibits us from paying any cash distributions on our equity while the credit facility is in effect (see “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Credit Facility”).

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

APL’s Cash Distribution Policy

Subject to the restrictions noted below, APL’s partnership agreement requires that it distribute 100% of available cash to its common unitholders and general partner, our wholly-owned subsidiary, within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Available cash consists generally of all of APL’s cash receipts, less cash disbursements and net additions to reserves, including any reserves required under debt instruments for future principal and interest payments.

APL’s general partner is granted discretion by APL’s 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 APL’s general partner determines its quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.


APL Minimum Distributions Per Unit Per Quarter		Percent of APL Available Cash in Excess of Minimum Allocated to APL’s General Partner
$ 0.42		15%
$ 0.52		25%
$ 0.60		50%

APL makes 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 APL’s general partner that are in excess of 2% of the aggregate amount of cash being distributed. During July 2007, Atlas Pipeline GP, as general partner and the holder of all of APL’s incentive distribution rights, agreed to allocate a portion of its incentive distribution rights back to APL as set forth in the IDR Adjustment Agreement. The general partner’s incentive distributions declared for the year ended December 31, 2008, after the allocation of $13.8 million of incentive distribution rights back to APL, were $23.5 million. APL declared no general partner’s incentive distributions for the year ended December 31, 2009.

On May 29, 2009, APL entered into an amendment to its senior secured credit facility (see “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations—APL Term Loan and Revolving Credit Facility”) which, among other changes, required that it pay no cash distributions from the time APL entered into the amendment through the end of 2009. Commencing with the quarter ending March 31, 2010, cash distributions can be paid, only if APL’s senior secured leverage ratio meets certain thresholds and APL has minimum liquidity (both as defined in the credit agreement) of at least $50.0 million at the end of the quarter.

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

ITEM 6.

SELECTED FINANCIAL DATA

We were formed as a wholly-owned subsidiary of Atlas Energy in December 2005 and therefore do not have any historical financial statements prior to that date. On July 26, 2006, Atlas Energy contributed its ownership interests in Atlas Pipeline GP, its then wholly-owned subsidiary and APL’s general partner, to us. Concurrent with this transaction, we issued 3,600,000 common units, representing a then-17.1% ownership interest in us, in an initial public offering at a price of $23.00 per unit, with substantially all of the net proceeds from this offering distributed to Atlas Energy. We currently have no separate operating activities apart from those conducted by APL, and our cash flows consist of distributions from APL on our partnership interests in it, including the incentive distribution rights that we own.

Prior to our initial public offering, the consolidated financial statements include only the results of Atlas Pipeline GP, which are presented on a consolidated basis including the financial statements of APL and are adjusted for the non-controlling limited partners’ interest in APL. Subsequent to our initial public offering, the consolidated financial statements contain our consolidated financial results including the accounts of Atlas Pipeline GP and APL. The non-controlling limited partner interest in APL is reflected as an expense in our consolidated results of operations and as a liability on our consolidated balance sheet. Throughout this section, when we refer to “our” consolidated financial statements, we are referring to the consolidated results for us and Atlas Pipeline GP, including APL’s financial results, adjusted for non-controlling partners’ interest in APL’s net income (loss).

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, 2009, 2008 and 2007 and at December 31, 2009 and 2008 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, 2006 and 2005 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 include our historical consolidated financial statements, which have been adjusted to reflect the following:

•

In May 2009, APL completed the sale of its NOARK gas gathering and interstate pipeline system (“NOARK”). In accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 205-20-45 “Reporting Discontinued Operations,” we have retrospectively adjusted our prior period consolidated financial statements to reflect the amounts related to the operations of NOARK as discounted operations; and

•

The adoption of FASB ASC 810-10-65, “Non-Controlling Interest in Consolidated Financial Statements,” which clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. FASB also requires consolidated net income to be reported and disclosed on the face of the consolidated statements of operations at amounts that include the amounts attributable to both the parent and the non-controlling interest. We adopted these requirements on January 1, 2009, and have reflected the retrospective application for all periods presented.

•

are participating securities and shall be included in the computation of EPU pursuant to the two-class method. We adopted these requirements on January 1, 2009 and have reflected the retroactive application for all periods presented.


	Years Ended December 31,
	2009			2008⁽¹⁾			2007⁽¹⁾⁽²⁾			2006⁽¹⁾			2005⁽¹⁾⁽³⁾
	(in thousands, except per unit and operating data)
Statement of operations data:
Revenue:
Natural gas and liquids	$	778,544		$	1,342,782		$	739,851		$	348,504		$	324,038
Transportation, compression and other fees		32,969			64,489			46,491			36,068			24,773
Equity income in joint venture		4,043			—			—			—			—
Gain on asset sales		111,440			—			—			—			—
Other income (loss), net		(23,150	)		(55,487	)		(174,110	)		12,393			2,146

Total revenue and other income (loss), net		903,846			1,351,784			612,232			396,965			350,957

Costs and expenses:
Natural gas and liquids		594,742			1,080,940			576,415			294,142			275,649
Plant operating		58,474			60,835			34,667			15,722			10,557
Transportation and compression		6,657			11,249			6,235			4,946			3,101
General and administrative⁽⁴⁾		39,377			1,728			63,175			20,032			13,606
Depreciation and amortization		92,434			82,841			43,903			16,759			12,976
Goodwill and other asset impairment loss		10,325			676,860			—			—			—
Gain on early extinguishment of debt		—			(19,867	)		—			—			—
Loss on arbitration settlement, net		—			—			—			—			138
Interest		106,373			87,853			63,695			23,852			13,448

Total costs and expenses		908,382			1,982,439			788,090			375,453			329,475

Income (loss) from continuing operations		(4,536	)		(630,655	)		(175,858	)		21,512			21,482
Income from discontinued operations		62,495			20,546			30,830			11,581			5,353

Net income (loss)		57,959			(610,109	)		(145,028	)		33,093			26,835
(Income) loss attributable to non-controlling interests⁽⁵⁾		(3,176	)		22,781			(3,940	)		(118	)		(1,083	)
(Income) loss attributable to non-controlling interest in Atlas Pipeline Partners, L.P.⁽⁶⁾		(50,748	)		513,675			133,321			(16,335	)		(13,447	)

Net income (loss) attributable to common limited partners/owners	$	4,035		$	(73,653	)	$	(15,647	)	$	16,640		$	12,305

Allocation of net income (loss) attributable to common limited partners/owners:
Portion applicable to owners’ interest (period prior to the initial public offering on July 26, 2006)	$	—		$	—		$	—		$	10,236		$	12,305
Portion applicable to common limited partners’ interest (period subsequent to the initial public offering on July 26, 2006)		4,035			(73,653	)		(15,647	)		6,404			—

Net income (loss) attributable to common limited partners/owners	$	4,035		$	(73,653	)	$	(15,647	)	$	6,404		$	—

Allocation of net income (loss) attributable to common limited partners/owners:
Continuing operations	$	(4,834	)	$	(76,124	)	$	(19,177	)	$	4,239		$	—
Discontinued operations		8,869			2,471			3,530			2,165			—

	$	4,035		$	(73,653	)	$	(15,647	)	$	6,404		$	—

Net income (loss) attributable to common limited partners per unit:
Basic
Continuing operations	$	(0.17	)	$	(2.77	)	$	(0.81	)	$	0.20		$	—
Discontinued operations		0.32			0.09			0.15			0.10			—

	$	0.15		$	(2.68	)	$	(0.66	)	$	0.30		$	—


Diluted
Continuing operations	$	(0.17	)	$	(2.77	)	$	(0.81	)	$	0.20		$	—
Discontinued operations		0.32			0.09			0.15			0.10			—

	$	0.15		$	(2.68	)	$	(0.66	)	$	0.30		$	—

Balance sheet data (at period end):
Property, plant and equipment, net	$	1,684,384		$	1,781,011		$	1,505,319		$	377,332		$	319,081
Total assets		2,138,118			2,418,984			2,875,351			787,134			742,726
Total debt, including current portion		1,286,438			1,539,427			1,254,426			324,083			259,625
Total Partners’ Capital /owners’ equity		690,679			609,852			1,246,525			379,121			329,510

Cash flow data:
Net cash provided by (used in) operating activities	$	53,507		$	(54,837	)	$	104,586		$	61,087		$	51,428
Net cash provided by (used in) investing activities		241,030			(292,970	)		(2,024,676	)		(104,499	)		(409,607	)
Net cash provided by (used in) financing activities		(300,719	)		342,602			1,930,696			27,264			357,997

Other financial data (unaudited):
Gross margin⁽⁷⁾	$	229,752		$	411,231		$	263,532		$	119,891		$	79,711
EBITDA⁽⁸⁾		267,325			257,338			(24,934	)		81,785			52,791
Adjusted EBITDA⁽⁸⁾		243,621			315,664			182,600			87,039			56,509

Maintenance capital expenditures	$	6,821		$	6,051		$	7,659		$	3,199		$	1,682
Expansion capital expenditures		148,095			294,672			113,174			75,609			49,071

Total capital expenditures	$	154,916		$	300,723		$	120,833		$	78,808		$	50,753

Operating data (unaudited):
Appalachia:
Average throughput volumes (MCFD)		104,882			87,299			68,715			61,892			55,204
Mid-Continent:
Velma system:
Gathered gas volume (MCFD)		76,378			63,196			62,497			60,682			67,075
Processed gas volume (MCFD)		73,940			60,147			60,549			58,132			62,538
Residue Gas volume (MCFD)		58,350			47,497			47,234			45,466			50,880
NGL volume (BPD)		8,232			6,689			6,451			6,423			6,643
Condensate volume (BPD)		377			280			225			193			256
Elk City/Sweetwater system⁽⁹⁾:
Gathered gas volume (MCFD)		234,675			280,860			298,200			277,063			250,717
Processed gas volume (MCFD)		213,581			232,664			225,783			154,047			119,324
Residue Gas volume (MCFD)		193,125			210,399			206,721			140,969			109,553
NGL volume (BPD)		11,175			10,487			9,409			6,400			5,303
Condensate volume (BPD)		378			332			212			140			127
Chaney Dell system⁽¹⁰⁾:
Gathered gas volume (MCFD)		270,703			276,715			259,270			—			—
Processed gas volume (MCFD)		215,374			245,592			253,523			—			—
Residue Gas volume (MCFD)		228,261			239,498			221,066			—			—
NGL volume (BPD)		13,418			13,263			12,900			—			—
Condensate volume (BPD)		824			791			572			—			—
Midkiff/Benedum system⁽¹⁰⁾:											—			—
Gathered gas volume (MCFD)		159,568			144,081			147,240			—			—
Processed gas volume (MCFD)		149,656			135,496			141,568			—			—
Residue Gas volume (MCFD)		101,788			92,019			94,281			—			—
NGL volume (BPD)		21,261			19,538			20,618			—			—
Condensate volume (BPD)		1,265			1,142			1,346			—			—

(1)	Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system

(2)

Includes APL’s acquisition of control of a 100% interest in the Chaney Dell natural gas gathering system and processing plants and a 72.8% undivided joint interest in the Midkiff/Benedum 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 Chaney Dell and Midkiff/Benedum systems represent 100% of its operating activity.

(3)	Includes APL’s acquisition of Elk City on April 14, 2005, representing approximately eight and one-half months’ operations.

(4)	Includes non-cash compensation (income) expense of $1.3 million, ($31.3) million, $39.0 million, $6.8 million, and $4.7 million for the years ended December 31, 2009, 2008, 2007, 2006, and 2005, respectively.

(5)	For the year ended December 31, 2009, 2008 and 2007, this represents Anadarko’s 5% non-controlling interest in the operating results of the Chaney Dell and Midkiff/Benedum systems, which APL acquired on July 27, 2007.

(6)	Represents the non-controlling interests in the net income (loss) of APL associated with the third-party unitholders of APL.

(7)

We define gross margin as revenue less purchased product costs. Purchased product costs include the cost of natural gas and NGLs that APL purchases from third parties. Gross margin, as we define it, does not include plant operating and transportation and compression expenses as movements in gross margin generally do not result in directly correlated movements in these cost 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 that investors benefit from having access to the same financial measures that our management uses. The following table reconciles our net income (loss) to gross margin (in thousands):

RECONCILIATION OF GROSS MARGIN


	Years Ended December 31,
	2009			2008⁽¹⁾			2007⁽¹⁾⁽²⁾			2006⁽¹⁾			2005⁽¹⁾⁽³⁾
Net income (loss)	$	57,959		$	(610,109	)	$	(145,028	)	$	33,093		$	26,835
Adjustments:
Effect of prior period items⁽¹¹⁾		—			—			—			1,090			(1,090	)
Equity income in joint venture		(4,043	)		—			—			—			—
Gain on asset sale		(111,440	)		—			—			—			—
Other (income) loss, net		23,150			55,487			174,110			(12,393	)		(2,146	)
Plant operating		58,474			60,835			34,667			15,722			10,557
Transportation and compression		6,657			11,249			6,235			4,946			3,101
General and administrative		39,377			1,728			63,175			20,032			13,606
Depreciation and amortization		92,434			82,841			43,903			16,759			12,976
Goodwill and other asset impairment loss		10,325			676,860			—			—			—
Loss on arbitration settlement, net		—			—			—			—			138
Interest expense		106,373			87,853			63,695			23,852			13,448
Non-cash linefill loss (gain)⁽¹²⁾		(3,899	)		7,797			(2,270	)		820			—
Unrecognized economic impact of Chaney Dell and Midkiff/Benedum acquisition⁽¹³⁾		—			—			10,423			—			—
Gain on sale of discontinued operations		(51,078	)		—			—			—			—
NOARK other (income) loss, net⁽¹⁴⁾		25			15			(26	)		(388	)		(373	)
NOARK transportation and compression⁽¹⁴⁾		2,089			6,637			7,249			5,807			952
NOARK general and administrative⁽¹⁴⁾		547			2,255			1,386			3,442			2
NOARK depreciation and amortization⁽¹⁴⁾		2,773			7,283			7,079			6,235			978
NOARK asset impairment loss⁽¹⁴⁾		—			21,648			—			—			—
NOARK interest⁽¹⁴⁾		29			(1,148	)		(1,066	)		874			727

Gross margin	$	229,752		$	411,231		$	263,532		$	119,891		$	79,711

(8)

EBITDA represents net income (loss) before net interest expense, income taxes, and depreciation and amortization and non-controlling interests in APL. 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, and other cash items such as the non-recurring cash derivative early termination expense (see “Item 8: Financial Statements and Supplementary Data—Note 12”). 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 EBITDA calculation under our and APL’s 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,
	2009			2008⁽¹⁾			2007⁽¹⁾⁽²⁾			2006⁽¹⁾			2005⁽¹⁾⁽³⁾
Net income (loss)	$	57,959		$	(610,109	)	$	(145,028	)	$	33,093		$	26,835
Adjustments:
Effect of prior period items⁽¹¹⁾		—			—			—			1,090			(1,090	)
(Income) loss attributable to non-controlling interests from continuing operations		(3,176	)		22,781			(3,940	)		—			—
Interest expense		106,373			87,853			63,695			23,852			13,448
Interest rate swap expense in other income (loss), net		608			—			—			—			—
Depreciation and amortization		92,434			82,841			43,903			16,759			12,976
Long lived asset impairment loss		10,325			—			—			—			—
Goodwill impairment loss, net of associated non-controlling interest		—			646,189			—			—			—
Unrecognized economic impact of Chaney Dell and Midkiff/Benedum acquisition⁽¹³⁾		—			—			10,423			—			—
(Income) loss attributable to non-controlling interests from discontinued operations		—			—			—			(118	)		(1,083	)
NOARK depreciation and amortization⁽¹⁴⁾		2,773			7,283			7,079			6,235			978
NOARK asset impairment⁽¹⁴⁾		—			21,648			—			—			—
NOARK interest expense⁽¹⁴⁾		29			(1,148	)		(1,066	)		874			727

EBITDA	$	267,325		$	257,338		$	(24,934	)	$	81,785		$	52,791
Adjustments:
Equity income in joint venture		(4,043	)		—			—			—			—
Distributions from joint venture		4,310			—			—			—			—
Non-cash portion of gain on asset sale⁽¹⁵⁾		(78,053	)		—			—			—			—
Non-cash (gain) loss on derivatives		51,716			(115,767	)		169,424			(2,316	)		(954	)
Non-recurring cash derivative early termination expense⁽¹⁶⁾		5,000			197,641			—			—			—
Non-cash compensation (income) expense		1,265			(31,345	)		38,966			6,750			4,672
Non-cash linefill loss (gain)⁽¹²⁾		(3,899	)		7,797			(2,270	)		820			—
Other non-cash items⁽¹⁷⁾		—			—			1,414			—			—

Adjusted EBITDA	$	243,621		$	315,664		$	182,600		$	87,039		$	56,509

(9)	Gathered gas volume for the Elk City/Sweetwater system includes 32,106 MCFD and 11,358 MCFD transferred from the Chaney Dell system for the years ended 2009 and 2008, respectively.

(10)	Volumetric data for APL’s Chaney Dell and Midkiff/Benedum systems for the year ended December 31, 2007 represents volumes recorded for the 158-day period from July 27, 2007, the date of APL’s acquisition, through December 31, 2007.

(11)

During June 2006, APL identified measurement reporting inaccuracies on three newly installed pipeline meters. To adjust for such inaccuracies, which relate to natural gas volume gathered during the third and fourth quarters of 2005 and first quarter of 2006, APL recorded an adjustment of $1.2 million during the second quarter of 2006 to increase natural gas and liquids cost of goods sold. If the $1.2 million adjustment had been recorded when the inaccuracies arose, our reported net income would have been reduced by approximately 0.5%, 3.4% and 1.1% for the third quarter of 2005, fourth quarter of 2005, and first quarter of 2006, respectively.

(12)	Includes the non-cash impact of commodity price movements on APL’s pipeline linefill.

(13)

The acquisition of APL’s Chaney Dell and Midkiff/Benedum systems was consummated on July 27, 2007, although the acquisition’s effective date was July 1, 2007. As such, APL receives the economic benefits of ownership of the assets as of July 1, 2007. However, in accordance with generally accepted accounting principles, APL has only recorded the results of the acquired assets commencing on the closing date of the acquisition. The economic benefits of ownership APL received from the acquired assets from July 1 to July 27, 2007 were recorded as a reduction of the consideration paid for the assets.

(14)	Included within income from discontinued operations.

(15)	For the year ended December 31, 2009, includes the non-cash gain on APL’s sale of assets to the Laurel Mountain joint venture

(16)

During the years ended December 31, 2009 and 2008, APL made net payments of $5.0 million and $274.0 million, respectively, which resulted in a net cash expense recognized of $5.0 million and $197.6 million, respectively related to the early termination of derivative contracts that were principally entered into as proxy hedges for the prices received on the ethane and propane portion of its NGL equity volume. These derivative contracts were put into place simultaneously with APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007 and related to production periods ranging from the end of the second quarter of 2008 through the fourth quarter of 2009. The 2008 settlements were funded through APL’s 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 us and Atlas Energy, the parent of our general partner, in a private placement. In connection with this transaction, APL also entered into an amendment to its 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.

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

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 notes thereto appearing elsewhere in this report.

General

Overview

We are a publicly-traded Delaware limited partnership (NYSE: AHD). Our wholly-owned subsidiary, Atlas Pipeline Partners GP, LLC (“Atlas Pipeline GP”), a Delaware limited liability company, is the general partner of Atlas Pipeline Partners, L.P. (“APL” – NYSE: APL). APL is a midstream energy service provider engaged in the transmission, gathering and processing of natural gas in the Mid-Continent and Appalachia regions. Our cash generating assets currently consist solely of our interests in APL, a publicly traded Delaware limited partnership. Our interests in APL consist of a 100% ownership in Atlas Pipeline GP, their general partner, which together with us, owns at December 31, 2009:

•

a 2.0% general partner interest in APL, which entitles it to receive 2.0% of the cash distributed by APL;

•

In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see “—Atlas Pipeline Partners, L.P.”), Atlas Pipeline GP, the holder of all the incentive distribution rights in APL, agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. Atlas Pipeline GP also agreed that the resulting allocation of incentive distribution rights back to APL would be after it receives the initial $3.7 million per quarter of incentive distribution rights through the quarter ended December 31, 2007, and $7.0 million per quarter thereafter (the “IDR Adjustment Agreement”);

•

5,754,253 common units of APL, representing approximately 11.4% of the outstanding common units of APL, or a 11.2% limited partner interest in APL, and

•

15,000 $1,000 par value 12.0% APL Class B cumulative preferred limited partner units.

While we, like APL, are structured as a limited partnership, our capital structure and cash distribution policy differ materially from those of APL. Most notably, our general partner does not have an economic interest in us and is not entitled to receive any distributions from us, and our capital structure does not include incentive distribution rights. Therefore, all of our distributions are made on our common units, which is our only class of security outstanding.

•

13.0% of all cash distributed in a quarter after each APL common unit has received $0.42 for that quarter;

•

23.0% of all cash distributed after each APL common unit has received $0.52 for that quarter; and

•

48.0% of all cash distributed after each APL common unit has received $0.60 for that quarter.

We previously paid to our unitholders, on a quarterly basis, distributions equal to the cash we received from APL, less certain reserves for expenses and other uses of cash, including:

•

our general and administrative expenses, including expenses as a result of being a publicly traded partnership;

•

capital contributions to maintain or increase our ownership interest in APL; and

•

reserves our general partner believes prudent to maintain for the proper conduct of our business or to provide for future distributions.

We did not declare a cash distribution for the quarters ended December 31, 2009, September 30, 2009, June 30, 2009 or March 31, 2009. On June 1, 2009, we entered into an amendment to our credit facility agreement which, among other changes, prohibits us from paying any cash distributions on our equity while the credit facility is in effect (see “—Our Credit Facility”).

On May 29, 2009, APL entered into an amendment to its senior secured credit facility (see “—APL Term Loan and Credit Facility”) which, among other changes, required that it pay no cash distributions from the time APL entered into the amendment through the end of 2009. Commencing with the quarter ending March 31, 2010, cash distributions can be paid, only if APL’s senior secured leverage ratio meets certain thresholds and APL has minimum liquidity (both as defined in the credit agreement) of at least $50.0 million at the end of the quarter. We will not have the ability to declare a cash distribution once our credit facility is terminated, until after APL reinstates its distributions.

Atlas Pipeline Partners, L.P.

APL’s business is conducted in the midstream segment of the natural gas industry through two reportable segments: Mid-Continent and Appalachia.

The Appalachia operations of APL are conducted principally through its 49% ownership interest in the Laurel Mountain Midstream, LLC joint venture (“Laurel Mountain”), which owns and operates approximately 1,800 miles of natural gas gathering systems in the Appalachian Basin located in northeastern Appalachia. APL also owns and operates approximately 80 miles of active natural gas gathering pipelines in northeastern Tennessee.

On May 31, 2009, APL and subsidiaries of The Williams Companies, Inc. (NYSE: WMB) (“Williams”) completed the formation of Laurel Mountain, which currently owns and operates APL’s former Appalachia natural gas gathering system, excluding its northeastern Tennessee operations. Laurel Mountain gathers the majority of the natural gas from wells operated by Atlas Energy Resources, LLC and its subsidiaries (“Atlas Energy Resources”), a wholly owned subsidiary of Atlas Energy, Inc. (“Atlas Energy”), a publicly-traded company (NASDAQ: ATLS). Laurel Mountain has natural gas gathering agreements with Atlas Energy Resources, under which Atlas Energy Resources is obligated to pay a gathering fee that is generally the greater of $0.35 per MCF or 16% of the realized sales price (except that a lower fee applies with respect to specific wells subject to certain existing contracts or in the event Laurel Mountain fails to perform specified obligations).

Financial Presentation

We currently have no separate operating activities apart from those conducted by APL, and our cash flows consist of distributions from APL on our partnership interests in it, including the incentive distribution rights that we own. The non-controlling limited partner interest in APL is reflected as an expense in our consolidated results of operations and as a component of equity on our consolidated balance sheet. Throughout this section, when we refer to “our” consolidated financial statements, we are referring to the consolidated results for us and Atlas Pipeline GP, including APL’s financial results, adjusted for non-controlling partners’ interest in APL’s net income (loss).

Recent Events

On January 27, 2009, APL and Sunlight Capital Partners, LLC (“Sunlight Capital”), an affiliate of Elliott & Associates, agreed to amend certain terms of APL Class A Preferred Units Certificate of Designation. On April 1, 2009, APL redeemed 10,000 of the APL Class A Preferred Units held by Sunlight Capital for cash at the liquidation value of $1,000 per unit, or $10.0 million, pursuant to the terms of the agreement. On April 13, 2009, APL converted 5,000 of the APL Class A Preferred Units held by Sunlight Capital, at Sunlight Capital’s option, into 1,465,653 APL common limited partner units in accordance with the terms of the agreement. On May 5, 2009, APL redeemed the remaining 5,000 APL Class A Preferred Units held by Sunlight Capital for cash at the liquidation value of $1,000 per unit, or $5.0 million, pursuant to the terms of the amended preferred units certificate of designation (see “—APL Preferred Units”).

On March 30, 2009, we, pursuant to our right within the Class B Preferred Unit Purchase Agreement, purchased an additional 5,000 of APL’s 12% Class B Preferred Units of limited partner interest (the “Class B Preferred Units”) for cash consideration of $1,000 per Class B Preferred Unit (see “—APL Preferred Units”).

On May 4, 2009, APL completed the sale of its NOARK gas gathering and interstate pipeline system to Spectra Energy Partners OLP, LP (NYSE: SEP) (“Spectra”) for net proceeds of $292.0 million in cash, net of working capital adjustments. APL received an additional $2.5 million in cash in July 2009 upon the delivery of audited financial statements for the NOARK system assets to Spectra. APL used the net proceeds from the transaction to reduce borrowings under its senior secured term loan and revolving credit facility. APL has recognized the sale of the NOARK system assets as discontinued operations within its consolidated financial statements.

On May 29, 2009, APL entered into an amendment to its credit facility agreement which, among other changes, modified certain financial ratios, limited capital expenditures and required that APL pay no cash distributions during the remainder of the year ended December 31, 2009. and the amendment allows it to pay cash distributions commencing with the quarter ending March 31, 2010, only if APL’s senior secured leverage ratio meets certain thresholds and APL has minimum liquidity (as defined in the credit agreement) of at least $50.0 million (see “—APL Term Loan and Revolving Credit Facility”).

On May 31, 2009, APL and Williams completed the formation of Laurel Mountain, which currently owns and operates APL’s former Appalachia natural gas gathering system, excluding APL’s northeastern

Tennessee operations. Williams’ contribution to Laurel Mountain consisted of cash of $100.0 million, of which APL received approximately $87.8 million, net of working capital adjustments, and a note receivable of $25.5 million. APL contributed the Appalachia natural gas gathering system and retained a 49% ownership interest in Laurel Mountain, which includes entitlement to preferred distribution rights relating to all payments on the note receivable. Williams obtained the remaining 51% ownership interest in Laurel Mountain. Upon completion of the transaction, APL recognized its 49% ownership interest in Laurel Mountain as an investment in joint venture on its consolidated balance sheet at fair value and recognized a gain on sale of $108.9 million, including $54.2 million associated with the revaluation of its investment in Laurel Mountain to fair value. In addition, Atlas Energy Resources sold to Laurel Mountain two natural gas processing plants and associated pipelines located in Southwestern Pennsylvania for $10.0 million. Upon the completion of the transaction, Laurel Mountain entered into new gas gathering agreements with Atlas Energy Resources which superseded the existing natural gas gathering agreements and omnibus agreement between APL and Atlas Energy Resources. Under the new gas gathering agreement, Atlas Energy Resources is obligated to pay a gathering fee that is generally the same as the gathering fee required under the terminated agreements, the greater of $0.35 per MCF or 16% of the realized sales price (except that a lower fee applies with respect to specific wells subject to certain existing contracts or in the event Laurel Mountain fails to perform specified obligations). The new gathering agreements contain additional provisions which define certain obligations and options of each party to build and connect newly drilled wells to any Laurel Mountain gathering system. APL’s ownership interest in Laurel Mountain has been recognized in accordance with the equity method of accounting within our consolidated financial statements. APL used the net proceeds from the transaction to reduce borrowings under its senior secured credit facility.

On June 1, 2009, we entered into an amendment to our credit facility agreement which, among other changes required us to immediately repay $30.0 million of then-outstanding $46.0 million of borrowings under the credit facility and prohibits us from paying any cash distributions on our equity while the credit facility is in effect (see “—Our Credit Facility”).

In connection with our amendment of the credit facility, we borrowed $15.0 million from Atlas Energy under a subordinate loan. In addition, Atlas Energy guaranteed the remaining balance outstanding under our credit facility under a guarantee agreement with the administrative agent of our credit facility (see “—Our Subordinate Loan and Guaranty Note with Atlas Energy”).

On July 13, 2009, APL sold a natural gas processing facility and a one-third undivided interest in other associated assets located in its Mid-Continent operating segment for approximately $22.6 million in cash. The facility was sold to Penn Virginia Resource Partners, L.P. (NYSE: PVR), who will provide natural gas volumes to the facility and reimburse APL for its proportionate share of the operating expenses. APL will continue to operate the facility. APL used the proceeds from this transaction to reduce outstanding borrowings under its senior secured credit facility. APL recognized a gain on sale of $2.5 million, which is recorded within gain on asset sales on our consolidated statements of operations.

On August 17, 2009, APL 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 made a capital contribution to APL of $0.4 million for us to maintain our 2.0% general partner interest in APL. In addition, APL issued warrants granting investors in APL’s private placement the right to purchase an additional 2,689,765 APL common units at a price of $6.35 per unit for a period of two years following the issuance of the original APL common units. APL utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under APL’s senior secured term loan and revolving credit facility (see “—APL Term Loan and Revolving Credit Facility”), and APL made similar repayments with net proceeds from exercise of the warrants. In January 2010, APL amended the warrants to purchase 2,689,765 common units and all warrants were exercised (see “—Subsequent Events”).

On November 2, 2009, APL’s agreement with Pioneer Natural Resources Company (“Pioneer”), whereby Pioneer had options to purchase up to an additional 22.0% interest in APL’s Mid-Continent’s Midkiff/Benedum system expired.

Subsequent Events

On January 7, 2010, APL executed amendments to warrants to purchase 2,689,765 of APL’s common units. The warrants were originally issued along with APL’s common units in connection with a private placement to institutional investors that closed on August 20, 2009. The common units and warrants were issued and sold in a transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended. 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 of the warrants for cash, which resulted in net cash proceeds of approximately $15.3 million. APL utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under its senior secured term loan and credit facility (see “—APL Term Loan and Credit Facility”).

Significant Acquisitions

From the date of APL’s initial public offering in January 2000 through December 2009, it has completed seven acquisitions at an aggregate cost of approximately $2.4 billion, including, most recently in July 2007, APL acquired control of Anadarko Petroleum Corporation’s (“Anadarko”—NYSE: APC) 100% interest in the Chaney Dell natural gas gathering systems and processing plants located in Oklahoma and its 72.8% undivided joint venture interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas (the “Anadarko Assets”). At the date of APL’s acquisition, the Chaney Dell system included 3,470 miles of gathering pipeline and three processing plants, while the Midkiff/Benedum system included 2,500 miles of gathering pipeline and two processing plants. The transaction was accomplished through the formation of two joint venture companies which own the respective systems, to which APL contributed $1.9 billion and Anadarko contributed the Anadarko Assets. APL funded the purchase price, in part, from $1.124 billion in proceeds it received from its private placement of its common units to investors at a negotiated purchase price of $44.00 per unit.

Of the $1.125 billion, we purchased $168.8 million of these APL units, which was funded through our issuance of 6,249,995 million common units in a private placement at a negotiated purchase price of $27.00 per unit (see “—Our Common Equity Offerings”). APL funded the remaining purchase price from $830.0 million of proceeds from a senior secured term loan which matures in July 2014 and borrowings under our senior secured revolving credit facility that matures in July 2013 (see “—APL Term Loan and Credit Facility”). Atlas Pipeline GP, as general partner and holder of all of APL’s incentive distribution rights, agreed to allocate a portion of its incentive distribution rights back to APL as set forth in the IDR Adjustment Agreement (see “—APL’s Partnership Distributions”).

In connection with this acquisition, APL reached an agreement with Pioneer, which currently holds an approximate 27.2% undivided joint venture interest in the Midkiff/Benedum system, whereby Pioneer had options to buy up to an additional 22% interest in the Midkiff/Benedum system. These options expired on November 2, 2009.

Contractual Revenue Arrangements

APL’s principal revenue is generated from the gathering and sale of natural gas and NGLs. Variables that affect its revenue are:

•

the volumes of natural gas APL gathers, gathers and processes which, in turn, depend upon the number of wells connected to its gathering systems, the amount of natural gas they produce, and the demand for natural gas and NGLs;

•

the price of the natural gas APL gathers and processes and the NGLs it recovers and sells, 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 that is gathered and processed;

•

the contract terms with each producer; and

•

the efficiency of APL’s gathering systems and processing plants

APL’s revenue consists of the fees earned from its gathering and processing operations. Under certain agreements, APL purchases natural gas from producers and moves it into receipt points on its pipeline systems and then sells the natural gas and NGLs off of delivery points on its systems. Under other agreements, APL gathers natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with the physical sale of natural gas is recognized upon physical delivery of the natural gas. In connection with APL’s gathering and processing operations, APL enters into the following types of contractual relationships with its producers and shippers:

Fee-Based Contracts. These contracts provide a set fee for gathering and/or processing raw natural gas. APL’s revenue is a function of the volume of natural gas that it gathers and processes and is not directly dependent on the value of the natural gas. APL also is paid a separate compression fee on many of its systems. The fee is dependent upon the volume of gas flowing through APL’s compressors and the quantity of compression stages utilized to gather the gas.

Percentage of Proceeds (“POP”) Contracts. These contracts provide for APL to retain a negotiated percentage of the sale proceeds from residue natural gas and NGLs APL gathers and processes, with the remainder being remitted to the producer. In this contract-type, APL and the producer are directly dependent on the volume of the commodity and its value; APL effectively owns a percentage of the commodity and revenues are directly correlated to its market value. POP Contracts may include a fee component which is charged to the producer.

Keep-Whole Contracts. These contracts require APL, as the processor and gatherer, to gather or purchase raw natural gas at current market rates. The volume of gas gathered or purchased is based on the measured volume at an agreed upon location (generally at the wellhead). The volume of gas redelivered or sold at the tailgate of APL’s processing facility will be lower than the volume purchased at the wellhead primarily due to BTUs extracted when processed through a plant. Therefore, APL bears the economic risk (the “processing margin risk”) that (i) the volume of Residue Gas available for redelivery to the producer may be less than we received from the producer; or (ii) the aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the amount that APL paid for the unprocessed natural gas (plus, in either case, the cost of the natural gas APL must purchase to return an equivalent volume, measured in BTU content, to producers to keep them whole with respect to their original measured volume). In order to help mitigate the risk associated with Keep-Whole contracts APL generally imposes a fee to gather the gas that is settled under this arrangement. Also, because the natural gas volumes contracted under Keep-Whole agreements is often lower in BTU content and thus, can meet downstream pipeline specifications without being processed, the natural gas can be bypassed around the processing plants on these systems and delivered directly into downstream pipelines during periods of margin risk.

In APL’s Appalachia segment, substantially all of the natural gas it gathers via Laurel Mountain is for Atlas Energy Resources under contracts in which Laurel Mountain earns a fee equal to a percentage,

generally 16%, of the gross sales price for natural gas, inclusive of the effects of financial and physical hedging, subject, in most cases, to a minimum of $0.35 per thousand cubic feet, or MCF, depending on the ownership of the well. The balance of the natural gas gathered by Laurel Mountain and APL’s Tennessee operations is for third-party operators generally under fixed-fee contracts.

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.

APL faces competition for in obtaining natural gas supplies for its 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 APL’s competitors operate as master limited partnerships and enjoy a cost of capital comparable to and, in some cases lower than, APL. Other competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than APL. Smaller local distributors may enjoy a marketing advantage in their immediate service areas. We believe the primary difference between APL and some of its competitors is that APL provides an integrated and responsive package of midstream services, while some of its competitors provide only certain services. We believe that offering an integrated package of services, while remaining flexible in the types of contractual arrangements that APL offers producers, allows APL to compete more effectively for new natural gas supplies in its regions of operations.

As a result of APL’s POP and Keep-Whole contracts, its results of operations and financial condition substantially depend upon the price of natural gas and NGLs. APL believes that 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, APL generally expects NGL prices to follow changes in crude oil prices over the long term, which APL believes 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 drilling activity in the recent past. Lower drilling levels and shut in wells over a sustained period would have a negative effect on natural gas volumes gathered and processed.

APL is 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. APL closely monitors the risks associated with commodity price changes on APL’s future operations and, where appropriate, uses various commodity instruments such as natural gas, crude oil and NGL contracts to hedge a portion of the value of APL’s assets and operations from such price risks. APL does not realize the full impact of commodity price changes because some of its sales volumes were previously hedged at prices different than actual market prices. Average estimated unhedged 2010 market prices for NGLs, natural gas and condensate, based upon New York Mercantile Exchange (“NYMEX”) forward price curves as of February 15, 2010, are $1.10 per gallon, $5.71 per MMBTU and $76.26 per barrel, respectively. A 10% change in these prices would change our forecasted gross margin, excluding the effect of non-controlling interest in APL net income (loss), for the twelve-month period ended December 31, 2010 by approximately $27.2 million.

Currently, there is an extremely significant level of uncertainty in the financial markets. This uncertainty presents additional potential risks to us and APL. These risks include the availability and costs associated with our and APL’s borrowing capabilities and APL’s raising additional capital, and an increase in the volatility of the price of our and APL’s common units. While we and APL have no definitive plans to access the capital markets, should we and APL 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.

Results of Operations

The following table illustrates selected volumetric information related to APL’s reportable segments for the periods indicated:


	Years Ended December 31,
	2009	2008	2007
Operating data:
Appalachia:
Average throughput volumes (MCFD)	104,882	87,299	68,715
Mid-Continent:
Velma system:
Gathered gas volume (MCFD)	76,378	63,196	62,497
Processed gas volume (MCFD)	73,940	60,147	60,549
Residue Gas volume (MCFD)	58,350	47,497	47,234
NGL volume (BPD)	8,232	6,689	6,451
Condensate volume (BPD)	377	280	225
Elk City/Sweetwater system⁽¹⁾:
Gathered gas volume (MCFD)	234,675	280,860	298,200
Processed gas volume (MCFD)	213,581	232,664	225,783
Residue Gas volume (MCFD)	193,125	210,399	206,721
NGL volume (BPD)	11,175	10,487	9,409
Condensate volume (BPD)	378	332	212
Chaney Dell system⁽²⁾:
Gathered gas volume (MCFD)	270,703	276,715	259,270
Processed gas volume (MCFD)	215,374	245,592	253,523
Residue Gas volume (MCFD)	228,261	239,498	221,066
NGL volume (BPD)	13,418	13,263	12,900
Condensate volume (BPD)	824	791	572
Midkiff/Benedum system⁽²⁾:
Gathered gas volume (MCFD)	159,568	144,081	147,240
Processed gas volume (MCFD)	149,656	135,496	141,568
Residue Gas volume (MCFD)	101,788	92,019	94,281
NGL volume (BPD)	21,261	19,538	20,618
Condensate volume (BPD)	1,265	1,142	1,346

(1)	Gathered gas volume for the Elk City/Sweetwater system includes 32,106 MCFD and 11,358 MCFD transferred from the Chaney Dell system for the years ended 2009 and 2008, respectively.

(2)	Volumetric data for APL’s Chaney Dell and Midkiff/Benedum systems for the year ended December 31, 2007 represents volumes recorded for the 158-day period from July 27, 2007, the date of APL’s acquisition, through December 31, 2007.

Financial Presentation

On May 4, 2009, APL completed the sale of its NOARK gas gathering and interstate pipeline system. As such, we have adjusted the prior period consolidated financial information presented to reflect the amounts related to the operations of the NOARK gas gathering and interstate pipeline system as discontinued operations.

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Revenue. The following table details the variances between the years ended 2009 and 2008 for revenues (in thousands):


	Years Ended December 31,						Variance			Percent Variance
	2009			2008			Variance			Percent Variance
Revenues:
Natural gas and liquids	$	778,544		$	1,342,782		$	(564,238	)	(42.0	)%
Transportation, compression and other fee revenue		32,969			64,489			(31,520	)	(48.9	)%
Equity income in joint venture		4,043			—			4,043		N/A
Gain on asset sale		111,440			—			111,440		N/A
Other loss, net		(23,150	)		(55,487	)		32,337		58.3	%

Total Revenues	$	903,846		$	1,351,784		$	(447,938	)	(33.1	)%

Natural gas and liquids revenue was $778.5 million for the year ended December 31, 2009, a decrease of $564.2 million from $1,342.8 million for the prior year. The decrease was primarily attributable to decreases in production revenue from APL’s Chaney Dell system of $223.6 million, APL’s Midkiff/Benedum system of $141.8 million, APL’s Elk City/Sweetwater system of $108.5 million and APL’s Velma system of $87.2 million, which were all impacted by lower average commodity prices and changes in volumes in comparison to the prior year.

Processed natural gas volume on the Chaney Dell system was 215.4 MMCFD for the year ended December 31, 2009, a decrease of 12.3% compared to 245.6 MMCFD for the prior year, partially due to shut-in wells as a result of lower gas prices. The Chaney Dell system increased its NGL production volume for the year ended December 31, 2009 by 1.2% when compared to the prior year to 13,418 BPD, representing an increase in production efficiency. The Midkiff/Benedum system had processed natural gas volume of 149.7 MMCFD for the year ended December 31, 2009, an increase of 10.5% compared to 135.5 MMCFD for the prior year. The Midkiff/Benedum system increased its NGL production volume for the year ended December 31, 2009 by 8.8% when compared to the prior year to 21,261 BPD, representing an increase in production efficiency, partially due to the start-up of the new Consolidator plant. Processed natural gas volume averaged 73.9 MMCFD on the Velma system for the year ended December 31, 2009, an increase of 22.9% from the prior year, mainly due to the new gathering line from the Madill area. The Velma system increased its NGL production volume for the year ended December 31, 2009 by 23.1% when compared to the prior year to 8,232 BPD, primarily due to the additional gas processed. Processed natural gas volume on the Elk City/Sweetwater system averaged 213.6 MMCFD for the year ended December 31, 2009, a decrease of 8.2% from the prior year as a result of shut-in wells due to lower gas prices. NGL production volume for the Elk City/Sweetwater system was 11,175 BPD, an increase of 6.6% from the prior year, as production efficiency of the processing plants has increased. APL enters into derivative instruments solely to hedge its forecasted natural gas, NGLs and condensate sales 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.”

Transportation, compression and other fee revenue decreased to $33.0 million for the year ended December 31, 2009 compared with $64.5 million for the prior year. This $31.5 million decrease was primarily due to a $26.2 million decrease from APL’s Appalachia system and a $4.7 million decrease from APL’s Chaney Dell system. The decrease from the Appalachia system was a result of APL’s May 2009 contribution of the majority of the system to Laurel Mountain, a joint venture in which it has a 49% ownership interest, after which we recognized APL’s ownership interest in the net income of Laurel Mountain as equity income on our consolidated statements of operations. The decrease from the Chaney Dell system was due to lower fee-based volumes.

Equity income of $4.0 million for the year ended December 31, 2009 represents APL’s ownership interest in the net income of Laurel Mountain for the period from its formation on May 31, 2009 through December 31, 2009.

Gain on asset sales of $111.4 million for the year ended December 31, 2009 represents the gain recognized on APL’s sale of a 51% ownership interest in its Appalachia natural gas gathering system of $108.9 million and APL’s $2.5 million gain recognized on its sale of the natural gas processing facility (see “—Recent Events”).

Other loss, net, including the impact of certain gains and losses recognized on derivatives, was a loss of $23.2 million for the year ended December 31, 2009, which represents a favorable movement of $32.3 million from the prior year loss of $55.5 million. This favorable movement was due primarily to a $195.0 million favorable variance of net cash derivative expense related to APL’s early termination of a portion of its derivative contracts (see “Item 8: Financial Statements and Supplementary Data—Note 12”) and an $84.1 million favorable movement in non-cash derivative gains related to the early termination of a portion of APL’s derivative contracts, partially offset by an unfavorable movement of $214.5 million in APL’s non-cash mark-to-market adjustments on derivatives and a $37.0 million favorable movement related to cash settlements on APL’s non-qualified derivatives. APL enters into derivative instruments principally to hedge its forecasted natural gas, NGLs and condensate sales 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.”

Costs and Expenses. The following table details the variances between the years ended 2009 and 2008 for costs and expenses (in thousands):


	Years Ended December 31,					Variance			Percent Variance
	2009		2008			Variance			Percent Variance
Costs and Expenses:
Natural gas and liquids	$	594,742	$	1,080,940		$	(486,198	)	(45.0	)%
Plant operating		58,474		60,835			(2,361	)	(3.9	)%
Transportation and compression		6,657		11,249			(4,592	)	(40.8	)%
General and administrative		39,377		1,728			37,649		2,178.8	%
Depreciation and amortization		92,434		82,841			9,593		11.6	%
Goodwill and other asset impairment loss		10,325		676,860			(666,535	)	(98.5	)%
Interest expense		106,373		87,853			18,520		21.1	%
Gain on early extinguishment of debt		—		(19,867	)		19,867		100.0	%

Total Costs and Expenses	$	908,382	$	1,982,439		$	(1,074,057	)	(54.2	)%

Natural gas and liquids cost of goods sold of $594.7 million for the year ended December 31, 2009 represented a decrease of $486.2 million from the prior year due primarily to a decrease in average commodity prices and changes in volumes in comparison to the prior year, as discussed above in revenues. Plant operating expenses of $58.5 million for the year ended December 31, 2009 represented a decrease of $2.4 million from the prior year due primarily to a $2.7 million decrease associated with APL’s Chaney Dell system resulting from lower operating and maintenance costs. Transportation and compression expenses decreased to $6.7 million for the year ended December 31, 2009 compared with $11.2 million for the prior year due to APL’s contribution of its Appalachia system to Laurel Mountain.

General and administrative expense, including amounts reimbursed to affiliates, increased $37.6 million to $39.4 million for the year ended December 31, 2009 compared with $1.7 million for the prior year. The increase was primarily related to a $32.6 million increase in non-cash compensation expense primarily due to a $36.3 million net mark-to-market gain recognized during the year ended December 31, 2008 principally associated with the vesting of certain APL common unit awards that were based on the financial performance of certain assets during 2008. The mark-to-market gain was the result of a significant change in APL’s common unit market price at December 31, 2008 when compared with the December 31, 2007 price, which was utilized in the estimate of the non-cash compensation expense for these awards. These common unit awards were issued during the year ended December 31, 2009.

Depreciation and amortization increased to $92.4 million for the year ended December 31, 2009 compared with $82.8 million for the year ended December 31, 2008 due primarily to APL’s expansion capital expenditures incurred subsequent to December 31, 2008.

Interest expense increased to $106.4 million for the year ended December 31, 2009 as compared with $87.9 million for the prior year. This $18.5 million increase was primarily due to a $8.5 million increase in interest expense related to APL’s additional senior notes issued during June 2008 (see “—APL Senior Notes”), a $9.1 million increase in interest expense associated with outstanding borrowings on APL’s revolving credit facility, a $2.1 million increase in the amortization of deferred finance costs due principally to accelerated amortization associated with the retirement of a portion of APL’s term loan with the proceeds from the sale of APL’s NOARK system and a $1.2 million increase in interest expense associated with our subordinated loan from Atlas Energy, partially offset by a $5.9 million decrease in interest expense associated with APL’s senior secured term loan primarily due to the repayment of $273.7 million of indebtedness since December 2008 (see “—APL Term Loan and Revolving Credit Facility”) and lower unhedged interest rates.

Goodwill and other asset impairment loss decreased to $10.3 million for the year ended December 31, 2009 as compared with $676.9 million for the year ended December 31, 2008. The $10.3 million impairment was due to an impairment of certain gas plant and gathering assets as a result of APL’s annual review of long-lived assets. The $676.9 million impairment loss for the year ended December 31, 2008 was due to an impairment charge to APL’s goodwill from the reduction of APL’s estimate of the fair value of goodwill in comparison to its carrying amount at December 31, 2008. The estimate of fair value of goodwill was impacted by many factors, including the significant deterioration of commodity prices and global economic conditions during the fourth quarter of 2008. There were no goodwill impairments for the year ended December 31, 2009.

Gain on early extinguishment of debt of $19.9 million for the year ended December 31, 2008 resulted from APL’s repurchase of approximately $60.0 million of its Senior Notes for an aggregate purchase price of approximately $40.1 million plus accrued interest of approximately $2.0 million. The notes repurchased were comprised of $33.0 million of APL’s 8.125% Senior Notes and approximately $27.0 million of APL’s 8.75% Senior Notes. All of the Senior Notes repurchased have been retired and are not available for re-issue.

The following table details the variances between the years ended 2009 and 2008 for Discontinued Operations and (Gain) loss attributable to non-controlling interests (in thousands):


	Years Ended December 31,					Variance			Percent Variance
	2009			2008		Variance			Percent Variance
Income from discontinued operations	$	62,495		$	20,546	$	41,949		204.2	%
(Income) loss attributable to non-controlling interests		(3,176	)		22,781		(25,957	)	113.9	%
(Income) Loss attributable to non-controlling interests in APL		(50,748	)		513,675		(564,423	)	109.9	%

Income from discontinued operations, which consists of amounts associated with APL’s NOARK gas gathering and interstate pipeline system it sold in May 2009, was $62.5 million for the year ended December 31, 2009 compared with $20.5 million for the prior year. The increase was due to a $51.1 million gain recognized on the sale of the NOARK system, partially offset by a $9.1 million decrease in the operating results of the NOARK system due to its sale in May 2009.

Income attributable to non-controlling interests was $3.2 million for the year ended December 31, 2009 compared with loss attributable to non-controlling interests of $22.8 million for the prior year. This change was primarily due to higher net income for the Chaney Dell and Midkiff/Benedum joint ventures, which were formed to accomplish our acquisition of control of the respective systems. The increase in net income of the Chaney Dell and Midkiff/Benedum joint ventures was principally due to the goodwill impairment charge in 2008 of $613.4 million for the goodwill originally recognized upon acquisition of these systems. The non-controlling interest expense represents Anadarko’s 5% interest in the net income of the Chaney Dell and Midkiff/Benedum joint ventures.

Income attributable to non-controlling interest in APL, which represents the allocation of APL’s earnings to its non-affiliated limited partners, increased $564.4 million to income of $50.7 million for the year ended December 31, 2009 compared with loss of $513.7 million for the prior year. This change was primarily due to an increase in APL’s net earnings between periods.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Revenue. The following table details the variances between the years ended 2008 and 2007 for revenues (in thousands):


	Years Ended December 31,						Variance		Percent Variance
	2008			2007			Variance		Percent Variance
Revenues:
Natural gas and liquids	$	1,342,782		$	739,851		$	602,931	81.5	%
Transportation, compression and other fee revenue		64,489			46,491			17,998	38.7	%
Other loss, net		(55,487	)		(174,110	)		118,623	68.1	%

Total Revenues	$	1,351,784		$	612,232		$	739,552	120.8	%

Natural gas and liquids revenue was $1,342.8 million for the year ended December 31, 2008, an increase of $602.9 million from $739.9 million for the prior year. The increase was primarily attributable to an increase in revenue contribution from APL’s Chaney Dell and Midkiff/Benedum systems, which it acquired in July 2007, of $512.8 million and an increase from APL’s Velma and Elk City/Sweetwater systems of $26.6 million and $61.8 million, respectively, due primarily to higher average commodity prices over the full year and an increase in volumes. Processed natural gas volume on the Chaney Dell system was 245.6 MMCFD for the year ended December 31, 2008, a decrease of 3.1% compared to 253.5 MMCFD for the period from APL’s July 2007 acquisition to December 31, 2007. The Midkiff/Benedum system had processed natural gas volume of 135.5 MMCFD for the year ended December 31, 2008, a decrease of 4.3% compared to 141.6 MMCFD for the period from APL’s July 2007 acquisition to December 31, 2007 due to the adverse effects of a hurricane which struck the surrounding area in September 2008. Processed natural gas volume averaged 60.1 MMCFD on the Velma system for the year ended December 31, 2008, a decrease of 0.7% from the prior year. However, the Velma system increased its NGL production volume by 3.7% when compared to the prior year to 6,689 BPD for the year ended December 31, 2008, representing an increase in production efficiency. Processed natural gas volume on the Elk City/Sweetwater system averaged 232.7 MMCFD for the year ended December 31, 2008, an increase of 3.0% from the prior year. NGL production volume for the Elk City/Sweetwater system was 10,487 BPD, an increase of 11.5% from the prior year, as production efficiency of the processing plants has increased. APL enters into derivative instruments solely to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. See further discussion of derivatives in “Item 8: Financial Statements and Supplementary Data—Note 12.”

Transportation, compression and other fee revenue increased to $64.5 million for the year ended December 31, 2008 compared with $46.5 million for the prior year. This $18.0 million increase was primarily due to an $11.0 million increase from APL’s Appalachia system due to higher throughput volume and a higher average transportation rate, $5.4 million of a full year’s contributions from APL’s Chaney Dell and Midkiff/Benedum systems, and an increase of $1.7 million associated with APL’s Elk City/Sweetwater system. The Appalachia system’s average throughput volume was 87.3 MMCFD for the year ended December 31, 2008 as compared with 68.7 MMCFD for the prior year, an increase of 18.6 MMCFD or 27.0%. The increase in the Appalachia system average daily throughput volume was principally due to new wells connected to APL’s gathering system, APL’s acquisition of the McKean processing plant and gathering system in central Pennsylvania for $6.1 million in August 2007, and APL’s acquisition of the Vinland processing plant and gathering system in northeastern Tennessee for $9.1 million in February 2008.

Other loss net, including the impact of certain gains and losses recognized on APL’s derivatives, was a loss of $55.5 million for the year ended December 31, 2008, which represents a favorable movement of $118.6 million from the prior year loss of $174.1 million. This favorable movement was due primarily to a $356.8 million favorable movement in APL’s non-cash mark-to-market adjustments on derivatives, partially offset by a net cash loss of $200.0 million and a non-cash derivative loss of $39.2 million related to APL’s early termination of a portion of its derivative contracts (see “—Recent Events”), and an unfavorable movement of $1.5 million related to APL’s cash settlements on derivatives that were not designated as hedges. The $356.8 million favorable movement in non-cash mark-to-market adjustments on derivatives was due principally to a decrease in forward crude oil market prices from December 31, 2007 to December 31, 2008 and their favorable mark-to-market impact on certain non-hedge derivative contracts APL has for production volumes in future periods. For example, average forward crude oil prices, which are the basis for adjusting the fair value of APL’s crude oil derivative contracts, at December 31, 2008, were $56.94 per barrel, a decrease of $32.95 per barrel from average forward crude oil market prices at December 31, 2007 of $89.89 per barrel. APL enters into derivative instruments principally to hedge its forecasted natural gas, NGLs and condensate sales 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.”

Costs and Expenses. The following table details the variances between the years ended 2008 and 2007 for costs and expenses (in thousands):


	Years Ended December 31,					Variance			Percent Variance
	2008			2007		Variance			Percent Variance
Costs and Expenses:
Natural gas and liquids	$	1,080,940		$	576,415	$	504,525		87.5	%
Plant operating		60,835			34,667		26,168		75.5	%
Transportation and compression		11,249			6,235		5,014		80.4	%
General and administrative		1,728			63,175		(61,447	)	(97.3	)%
Depreciation and amortization		82,841			43,903		38,938		88.7	%
Goodwill and other asset impairment loss		676,860			—		676,860		N/A
Interest expense		87,853			63,695		24,158		37.9	%
Gain on early extinguishment of debt		(19,867	)		—		(19,867	)	N/A

Total Costs and Expenses	$	1,982,439		$	788,090	$	1,194,349		151.5	%

Natural gas and liquids cost of goods sold of $1,080.9 million and plant operating expenses of $60.8 million for the year ended December 31, 2008 represented increases of $504.5 million and $26.2 million, respectively, from the prior year amounts due primarily to an increase of $453.2 million in natural gas and liquids cost of goods sold and a $23.0 million increase in plant operating expenses from a full year’s contribution from APL’s Chaney Dell and Midkiff/Benedum systems and higher average commodity prices for the full year and an increase in production volume on APL’s Velma and Elk City/Sweetwater systems. Transportation and compression expenses increased $5.0 million to $11.2 million for the year ended December 31, 2008 due to an increase in APL’s Appalachia system operating and maintenance costs as a result of increased capacity, additional well connections and operating costs of APL’s McKean and Vinland processing plants and gathering systems.

General and administrative expense, including amounts reimbursed to affiliates, decreased $61.4 million to $1.7 million for the year ended December 31, 2008 compared with $63.1 million for the prior year. The decrease was primarily related to a $70.3 million decrease in non-cash compensation expense, partially offset by APL’s higher costs of managing its operations, including its Chaney Dell and Midkiff/Benedum systems acquired in July 2007 and its capital-raising and strategic activities. The decrease in non-cash compensation expense was principally attributable to a $36.3 million gain recognized during the year ended December 31, 2008 in comparison to an expense of $33.4 million for the prior year for certain APL common unit awards for which the ultimate amount issued was determined by APL after the completion of its 2008 fiscal year and was

based upon the financial performance of certain APL acquired assets (see “Item 8: Financial Statements and Supplementary Data—Note 17”). The gain was the result of a significant change in APL’s common unit market price at December 31, 2008 when compared with the December 31, 2007 price, which was utilized in APL’s estimate of the non-cash compensation expense for these awards, and lower financial performance of the certain assets acquired in comparison to estimated performance.

Depreciation and amortization increased to $82.8 million for the year ended December 31, 2008 compared with $43.9 million for the year ended December 31, 2007 due primarily to the depreciation associated with APL’s Chaney Dell and Midkiff/Benedum acquired assets and APL’s expansion capital expenditures incurred subsequent to December 31, 2007.

Interest expense increased to $87.9 million for the year ended December 31, 2008 as compared with $63.7 million for the prior year. This $24.2 million increase was primarily due to a $14.7 million increase in interest expense associated with APL’s term loan issued in connection with its acquisition of the Chaney Dell and Midkiff/Benedum systems (see“—Term Loan and Credit Facility”) and $11.1 million of interest expense related to APL’s additional senior notes issued during June 2008.

Goodwill and other asset impairment loss of $676.9 million for the year ended December 31, 2008 was due to an impairment charge to APL’s goodwill as a result of its annual goodwill impairment test. The goodwill impairment resulted from the reduction of APL’s estimate of the fair value of its goodwill in comparison to its carrying amount at December 31, 2008. The estimate of fair value of goodwill was impacted by many factors, including the significant deterioration of commodity prices and global economic conditions during the fourth quarter of 2008. There were no goodwill impairments for the year ended December 31, 2007.

Gain on early extinguishment of debt of $19.9 million for the year ended December 31, 2008 resulted from APL’s repurchase of approximately $60.0 million of its Senior Notes for an aggregate purchase price of approximately $40.1 million plus accrued interest of approximately $2.0 million. The notes repurchased were comprised of $33.0 million of APL’s 8.125% Senior Notes and approximately $27.0 million of APL’s 8.75% Senior Notes. All of the APL Senior Notes repurchased have been retired and are not available for re-issue.

The following table details the variances between the years ended 2008 and 2007 for Discontinued Operations and (Gain) loss attributable to non-controlling interests (in thousands):


	Years Ended December 31,					Variance			Percent Variance
	2008		2007			Variance			Percent Variance
Income from discontinued operations	$	20,546	$	30,830		$	(10,284	)	(33.4	)%
(Income) loss attributable to non-controlling interests		22,781		(3,940	)		26,721		678.2	%
Loss attributable to non-controlling interests in APL		513,675		133,321			380,354		285.3	%

Income from discontinued operations consists of amounts associated with the NOARK gas gathering and interstate pipeline system, which APL sold on May 4, 2009. Income from discontinued operations decreased to $20.5 million for the year ended December 31, 2008 compared with $30.8 million for the prior year. The decrease was due primarily to a $21.6 million write-off of costs related to a pipeline expansion project, partially offset by an increase of $5.9 million for natural gas and liquids revenue. The write-off of costs incurred consisted of preliminary construction and engineering costs as well as a vendor deposit for the manufacture of pipeline which expired in accordance with a contractual arrangement.

Loss attributable to non-controlling interests was $22.8 million for the year ended December 31, 2008 compared with income attributable to non-controlling interests of $3.9 million for the prior year. This change was primarily due to lower net income for APL’s Chaney Dell and Midkiff/Benedum joint ventures, which were formed to accomplish its acquisition of control of the respective systems. The decrease in net income of the

Chaney Dell and Midkiff/Benedum joint ventures was principally due to the goodwill impairment charge of $613.4 million for the goodwill originally recognized upon APL’s acquisition of these systems. The non-controlling interest expense represents Anadarko’s 5% interest in the net income of the Chaney Dell and Midkiff/Benedum joint ventures.

Loss attributable to non-controlling interest in APL, which represents the allocation of APL’s earnings to its non-affiliated limited partners, was $513.7 million for the year ended December 31, 2008 as compared with $133.3 million for the prior year. This change was primarily due to a decrease in APL’s net income between periods.

Liquidity and Capital Resources

General

Our primary sources of liquidity are distributions received with respect to our ownership interests in APL and cash on hand. Our primary cash requirements are for our general and administrative expenses, including expenses as a result of being a publicly traded partnership, capital contributions to APL to maintain or increase our ownership interest and quarterly distributions to our common unitholders. We expect to fund our general and administrative expenses through the retention of cash and our capital contributions to APL through the retention of cash from distributions received from APL. On May 29, 2009, APL entered into an amendment to its senior secured credit facility (see “—APL Term Loan and Revolving Credit Facility”) which, among other changes, restricted it from paying cash distributions from the time APL entered into the amendment through the end of 2009. Commencing with the quarter ending March 31, 2010, cash distributions can be paid, only if APL’s senior secured leverage ratio meets certain thresholds and APL has minimum liquidity (both as defined in the credit agreement) of at least $50.0 million.

At December 31, 2009, we had $8.0 million outstanding under our credit facility (see “––Our Credit Facility”) and were in compliance with our credit facility covenants. In connection with our June 1, 2009 amendment to our credit facility, we were required to immediately repay $30.0 million of then-outstanding $46.0 million of borrowings under the credit facility and are required to repay the balance of our outstanding borrowings by April 13, 2010. The amendment to our credit facility also required us to repay $4.0 million of the remaining $16.0 million outstanding under the credit facility on each of July 13, 2009, October 13, 2009 and January 13, 2010, with the balance of the indebtedness under the credit facility being due on the original maturity date of April 13, 2010. The July 13, 2009, October 13, 2009 and January 13, 2010 payments were timely made by funding from Atlas Energy under its guaranty of our obligations (see “—Our Subordinate Loan and Guaranty Note with Atlas Energy”).

At December 31, 2009, we had a working capital deficit of $63.5 million compared with a working capital deficit of $43.8 million at December 31, 2008. We believe that we will have sufficient liquid assets, including our ownership of 5.8 million limited partner units in APL, to meet our financial commitments, debt service obligations (including our requirement to repay our outstanding borrowings under our credit facility), and possible contingencies for at least the next twelve-month period. However, we are subject to business and other risks that could adversely affect our cash flow. We may need to supplement our cash generation with proceeds from financing activities, including other borrowings and the issuance of additional limited partner units and the sale of our ownership interests in APL. APL’s primary sources of liquidity are cash generated from operations and borrowings under its credit facility. APL’s primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures and quarterly distributions to its common unitholders and general partner. In general, we expect APL to fund:

•

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 borrowings; and

•

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

At December 31, 2009, APL had $326.0 million of outstanding borrowings under its $380.0 million senior secured credit facility and $10.1 million of outstanding letters of credit, which are not reflected as borrowings on our consolidated balance sheet, with $43.9 million of remaining committed capacity under its credit facility, subject to covenant limitations (see “—APL Term Loan and Revolving Credit Facility”). APL was in compliance with its credit facility covenants at December 31, 2009. At December 31, 2009, APL had a working capital deficit of $30.6 million compared with a $48.8 million working capital deficit at December 31, 2008. We believe that APL will have sufficient liquid assets, cash from operations and borrowing capacity to meet its financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve-month period. However, APL is subject to business, operational and other risks that could adversely affect its cash flow. APL may need to supplement its cash generation with proceeds from financing activities, including borrowings under its credit facility and other borrowings, the issuance of additional limited partner units and the sale of its assets.

Recent instability in the financial markets, as a result of recession or otherwise, has increased the cost of capital while the availability of funds from those markets has diminished. This may affect our and APL’s ability to raise capital and reduce the amount of cash available to fund our and APL’s operations. APL relies on its cash flow from operations and its credit facility to execute its growth strategy and to meet its financial commitments and other short-term liquidity needs. We or APL cannot be certain that additional capital will be available to the extent required and on acceptable terms.

Cash Flows – Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

The following table details the variances between the years ended 2009 and 2008 for cash flows (in thousands):


	Years Ended December 31,						Variance			Percent Variance
	2009			2008			Variance			Percent Variance
Net cash provided by (used in) operating activities	$	53,507		$	(54,837	)	$	108,344		197.6	%
Net cash provided by (used in) investing activities		241,030			(292,970	)		534,000		182.3	%
Net cash provided by (used in) financing activities		(300,719	)		342,602			(643,321	)	(187.8	)%

Net change in cash and cash equivalents	$	(6,182	)	$	(5,205	)	$	977		18.8	%

Net cash provided by operating activities of $53.5 million for the year ended December 31, 2009 represented an increase of $108.3 million from $54.8 million of net cash used in operating activities for the prior year. The increase was derived from a $157.1 million favorable movement in net earnings from continuing operations excluding non-cash charges, partially offset by a $20.1 million decrease in cash flows from working capital changes and a $28.6 million decrease in cash provided by discontinued operations. The increase in net earnings from continuing operations excluding non-cash charges was principally due to a $195.0 million favorable variance of net cash derivative expense related to the early termination of a portion of APL’s derivative contracts (see “Item 8: Financial Statements and Supplementary Data—Note 12”).

Net cash provided by investing activities was $241.0 million for the year ended December 31, 2009, an increase of $534.0 million from $293.0 million of net cash used in investing activities for the prior year. This increase was principally due to a $315.8 million increase in cash provided by discontinued operations, the net proceeds of $112.0 million received from the sale of APL’s Appalachia system assets and a natural gas processing facility and an $145.8 million decrease in capital expenditures, partially offset by a 2008 receipt of a $30.2 million cash reimbursement for state sales tax paid on APL’s 2007 transaction to acquire the Chaney Dell

and Midkiff/Benedum systems and 2008 period receipt of $1.3 million in connection with a post-closing purchase price adjustment of APL’s 2007 acquisition of the Chaney Dell and Midkiff/Benedum systems (see further discussion of capital expenditures under “—Capital Requirements”).

Net cash used in financing activities was $300.7 million for the year ended December 31, 2009, a decrease of $643.3 million from $342.6 million of net cash provided by financing activities for the prior year. This decrease was principally due to the absence in the current period of $244.9 million of net proceeds from APL’s issuance of 8.75% Senior Notes during June 2008 (see “—APL Senior Notes”), a decrease of $235.8 million of net proceeds from the issuance of APL’s common units and a $232.0 million net decrease in borrowings under our and APL’s credit facilities.

Cash Flows – Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

The following table details the variances between the years ended 2008 and 2007 for cash flows (in thousands):


	Years Ended December 31,						Variance			Percent Variance
	2008			2007			Variance			Percent Variance
Net cash provided by (used in) operating activities	$	(54,837	)	$	104,586		$	(159,423	)	(152.4	)%
Net cash used in investing activities		(292,970	)		(2,024,676	)		1,731,706		85.5	%
Net cash provided by financing activities		342,602			1,930,696			(1,588,094	)	(82.3	)%

Net change in cash and cash equivalents	$	(5,205	)	$	10,606		$	(15,811	)	(149.1	)%

Net cash used in operating activities of $54.8 million for the year ended December 31, 2008 represented a decrease of $159.4 million from $104.6 million of net cash provided by operating activities for the prior year. The decrease was derived principally from a $209.6 million unfavorable movement in net income (loss) excluding non-cash charges, partially offset by a $43.6 million increase in cash flows from working capital changes and a $6.7 million increase in cash provided by our discontinued operations. The decrease in net income (loss) excluding non-cash charges was principally due to the $197.6 million net unfavorable cash impact from APL’s early termination of certain derivative instruments during the year ended December 31, 2008.

Net cash used in investing activities was $293.0 million for the year ended December 31, 2008, a decrease of $1,731.7 million from $2,024.7 million for the prior year. This decrease was principally due to a $1,915.9 million decrease in net cash paid for APL acquisitions, partially offset by a $179.9 million increase in APL capital expenditures and a $6.3 million increase in cash used in APL’s discontinued operations. Net cash paid for acquisitions of $1,884.5 million in 2007 represents the net amount APL paid for its acquisition of the Chaney Dell and Midkiff/Benedum systems. The $31.4 million of net cash received for acquisition in the current period principally represents the reimbursement of state sales tax APL initially paid for its prior year acquisition of the Chaney Dell and Midkiff/Benedum systems. See further discussion of capital expenditures under “—Capital Requirements.”

Net cash provided by financing activities was $342.6 million for the year ended December 31, 2008, a decrease of $1,588.1 million from $1,930.7 million for the prior year. This decrease was principally due to a $699.5 million decrease from the net proceeds from APL’s issuance of common units, a $572.3 million decrease from the net proceeds from APL’s issuance of long-term debt, a $162.9 million increase in repayments of APL long-term debt and a $157.0 million decrease from the net proceeds from our issuance of common units. The decrease in net proceeds of issuance of APL’s common units and APL’s long-term debt were due to the prior year financing of APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems. APL’s repayments of long-term debt were associated with its issuance of $250.0 million 8.75% Senior Notes in June 2008, the net proceeds of which were utilized to repay indebtedness under APL’s senior secured term loan and revolving credit facility and APL’s repurchase of approximately $60.0 million in face amount of its Senior Notes for an aggregate purchase price of approximately $40.1 million during the year ended December 31, 2008.

Capital Requirements

APL’s operations require continual investment to upgrade or enhance existing operations and to ensure compliance with safety, operational, and environmental regulations. APL’s 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 its existing operations.

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


	Years Ended December 31,
	2009		2008		2007
Maintenance capital expenditures	$	6,821	$	6,051	$	7,659
Expansion capital expenditures		148,095		294,672		113,174

Total	$	154,916	$	300,723	$	120,833

Expansion capital expenditures decreased to $148.1 million for the year ended December 31, 2009 due principally to construction of a 60 MMCFD expansion of APL’s Sweetwater processing plant and the construction of the Madill to Velma pipeline during the prior year, decreases in capital expenditures related to the sale of APL’s NOARK system and APL’s 49% ownership interest in the Appalachia system. The increase in maintenance capital expenditures for the year ended December 31, 2009 when compared with the prior year was due to fluctuations in the timing of APL’s scheduled maintenance activity. As of December 31, 2009, APL has approved expenditures of approximately $12.8 million on well connects, pipeline extensions, compressor station upgrades and processing facility upgrades.

Expansion capital expenditures increased to $294.7 million for the year ended December 31, 2008 due principally to the expansion of APL’s gathering systems and upgrades to processing facilities and compressors to accommodate new wells drilled in APL’s service areas, including the construction of a 60 MMCFD expansion of APL’s Sweetwater processing plant and the construction of APL’s Madill to Velma pipeline. The decrease in maintenance capital expenditures for the year ended December 31, 2008 when compared with the prior year was due to fluctuations in the timing of APL’s scheduled maintenance activity.

Our Credit Facility

At December 31, 2009, we, with Atlas Pipeline GP as guarantor, had $8.0 million outstanding under a revolving credit facility with a syndicate of banks. On June 1, 2009, we entered into an amendment to our credit facility agreement which, among other changes:

•

required us to immediately repay $30.0 million of then-outstanding $46.0 million of borrowings under the credit facility;

•

required us to repay $4.0 million of the remaining $16.0 million outstanding under the credit facility on each of July 13, 2009, October 13, 2009 and January 13, 2010, with the balance of the indebtedness being due on the original maturity date of the credit facility of April 13, 2010. The July 13, 2009, October 13, 2009 and January 13, 2010 payments were timely made by funding from Atlas Energy under its guaranty of our obligations. We may not borrow additional amounts under the credit facility or issue letters of credit;

•

requires us to use any of our “excess cash flow,” which the amendment generally defines as cash in excess of $1.5 million as of the last business day of each month, to repay outstanding borrowings under the credit facility. In addition, the amendment requires us to repay borrowings under the credit facility with the net proceeds of any sales of our common units in APL;

•

eliminated all financial covenants in the credit agreement, including the leverage ratio, the combined leverage ratio with APL, and the interest coverage ratio (all as defined within the credit facility agreement);

•

prohibits us from paying any cash distributions on or redeeming any of our equity while the credit facility is in effect and permits us to pay operating expenses only to the extent incurred or paid in the ordinary course of business; and

•

reduced the applicable margin above LIBOR, the federal funds rate plus 0.5% or the Wachovia Bank, National Association prime rate to be 0.75% for LIBOR loans and 0.0% for federal funds rate or prime rate loans. The weighted average interest rate on the outstanding credit facility borrowings at December 31, 2009 was 3.25%.

Borrowings under our credit facility are secured by a first-priority lien on a security interest in all of our assets, including the pledge of Atlas Pipeline GP’s interests in APL, and are guaranteed by Atlas Pipeline GP and our other subsidiaries (excluding APL and its subsidiaries). Our credit facility contains customary covenants, including restrictions on our ability to incur additional indebtedness; make certain acquisitions, loans or investments or enter into a merger or sale of substantially all of our property or assets, including the sale or transfer of interest in our subsidiaries. We are in compliance with these covenants as of December 31, 2009. The events which constitute an event of default under our credit facility include payment defaults, breaches of representations or covenants contained in the credit agreements, adverse judgments against us in excess of a specified amount, a change of control of Atlas Energy, our general partner or any other obligor, and termination of a material agreement and occurrence of a material adverse effect.

Our $30 million repayment was funded from the proceeds of (i) a loan from Atlas Energy in the amount of $15.0 million obtained on June 1, 2009 (see “—Our Subordinate Loan and Guaranty Note with Atlas Energy”) and (ii) the purchase by APL of $15.0 million of preferred equity in our newly-formed subsidiary. The maturity date of the subordinate loan is the day following the day that we pay all indebtedness under the credit facility (“Termination Date”). The material terms of the preferred units purchased by APL in our newly-formed subsidiary are as follows: distributions are payable quarterly at the rate of 12% per annum, but before the Termination Date, distributions will be paid by increasing APL’s investment in the preferred units; upon the Termination Date, all preferred distributions will be paid in cash to APL; and we have the option, after the Termination Date, of redeeming all of the preferred units APL owns for an amount equal to the preferred unit capital. Additionally, Atlas Energy guaranteed the remaining balance outstanding under the credit facility pursuant to a guarantee agreement with the administrative agent of the credit facility. In consideration for this guarantee, we issued to Atlas Energy a promissory note (see “—Our Subordinate Loan and Guaranty Note with Atlas Energy”).

Our Subordinate Loan and Guaranty Note with Atlas Energy

On June 1, 2009, in connection with our amendment of the credit facility, we borrowed $15.0 million from Atlas Energy under a subordinate loan. The maturity date of the subordinate loan is the day following the date that we repay all outstanding borrowings under the credit facility. Interest on the outstanding balance under the loan accrues quarterly at the rate of 12.0% per annum. However, prior to the maturity date of the subordinate loan, interest on the outstanding balance under the subordinate loan will not be payable in cash, but instead the principal amount of the loan will be increased by the interest amount payable.

On June 1, 2009, in consideration of Atlas Energy’s guaranty of the indebtedness under our credit facility, we entered into a guaranty note with Atlas Energy. The principal amount of the guaranty note is increased on the first day of each fiscal quarter by an amount equal to 3.75% per annum multiplied by (i) the outstanding principal amount of indebtedness under the credit facility plus (ii) $1.0 million. The note accrues interest at 3.75% per annum which, until the credit facility is paid in full, is paid by increasing the principal amount of the note. The maturity date of the guaranty note is the day following the date that we repay all outstanding borrowings under our credit facility, which is scheduled to be April 13, 2010. During the year ended December 31, 2009, Atlas Energy funded $8.0 million in payments required under the credit facility under its guaranty of our obligations.

During the year ended December 31, 2009, we accrued interest of $1.3 million for the subordinate loan and guaranty note, resulting in a combined balance of $24.3 million as of December 31, 2009, which is reflected in the current portion of long term debt on our consolidated balance sheet.

Our Partnership Distributions

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provide for the proper conduct of our business;

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comply with applicable law, any of our debt instruments or other agreements; or

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provide funds for distributions to our unitholders for any one or more of the next four quarters.

APL’s Partnership Distributions

following the end of each calendar quarter in accordance with their respective percentage interests. Available cash consists generally of all of APL’s cash receipts, less cash disbursements and net additions to reserves, including any reserves required under debt instruments for future principal and interest payments.

Available cash is initially distributed 98% to APL’s common limited partners and 2% to its general partner. These distribution percentages are modified to provide for incentive distributions to be paid to APL’s general partner if quarterly distributions to common limited partners exceed specified targets. Incentive distributions are generally defined as all cash distributions paid to APL’s general partner that are in excess of 2% of the aggregate amount of cash being distributed. During July 2007, Atlas Pipeline GP, as sole owner of APL’s general partner, agreed to allocate a portion of its incentive distribution rights back to APL as set forth in the IDR Adjustment Agreement. No incentive distributions were declared for the year ended December 31, 2009.

On May 29, 2009, APL entered into an amendment to its senior secured credit facility (see“—APL Term Loan and Revolving Credit Facility”) which, among other changes, restricted it from paying cash distributions through the end of 2009. Commencing with the quarter ending March 31, 2010, cash distributions can be paid, only if APL’s senior secured leverage ratio meets certain thresholds and APL has minimum liquidity (both as defined in the credit agreement) of at least $50.0 million at the end of the quarter.

Off Balance Sheet Arrangements

As of December 31, 2009, our off balance sheet arrangements are limited to APL’s letters of credit, issued under the provisions of APL’s revolving credit facility, totaling $10.1 million. These are in place to support various performance obligations as required by (i) statutes within the regulatory jurisdictions where APL operates, (ii) surety and (iii) counterparty support.

Contractual Obligations and Commercial Commitments

The following table summarizes our and APL’s contractual obligations and commercial commitments at December 31, 2009 (in thousands):


Contractual cash obligations:	Total		Payments Due By Period
Contractual cash obligations:	Total		Less than 1 Year		1 – 3 Years		4 – 5 Years		After 5 Years
Total debt	$	1,290,289	$	32,255	$	—	$	759,505	$	498,529
Interest on total debt⁽¹⁾		555,701		95,688		186,562		142,606		130,845
Derivative-based obligations		43,600		32,835		10,414		351		—
Operating leases		13,549		4,547		7,490		1,512		—

Total contractual cash obligations	$	1,903,139	$	165,325	$	204,466	$	903,974	$	629,374

⁽¹⁾	Based on the interest rates of our respective debt components as of December 31, 2009.


Other commercial commitments:	Total		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	$	10,080	$	10,080	$	—	$	—	$	—

Total commercial commitments	$	10,080	$	10,080	$	—	$	—	$	—

Our Equity Offerings

On June 1, 2009, a newly created, wholly-owned subsidiary of ours, Atlas Pipeline Holdings II, LLC (“AHD Sub”), issued $15.0 million of $1,000 par value 12.0% Class B preferred equity (“AHD Sub Preferred Units”) to APL for cash pursuant to a certificate of designation. We utilized the net proceeds from the issuance to reduce borrowings under our senior secured credit facility (see “—Our Credit Facility”). Distributions on the AHD Sub Preferred Units are payable quarterly on the same date as the distribution payment date for our common units. Distributions on the AHD Sub Preferred Units shall initially be paid in cash or by increasing the amount of the AHD Sub Preferred Unit equity by the amount of the distribution. However, under the terms of the certificate of designation, prior to the repayment of all outstanding borrowings under our credit facility, AHD Sub may only pay a cash distribution on the AHD Sub Preferred Units if we have received distributions on APL’s 12.0% Class B preferred units (see “—APL Preferred Units”). After we have repaid all outstanding borrowings under our credit facility, all subsequent distributions declared by AHD Sub on the AHD Sub Preferred Units shall be paid in cash. AHD Sub has the option of redeeming some or all of the AHD Sub Preferred Units, subject to certain limitations under the terms of the certificate of designation. As APL owns all of the outstanding AHD Sub Preferred Units in an amount equal to the Class B Preferred Units of APL that we own, the amounts eliminate in consolidation of our consolidated balance sheet as of December 31, 2009.

In June 2008, we sold 308,109 common units through a private placement to Atlas Energy at a price of $32.50 per unit, for net proceeds of approximately $10.0 million. We utilized the net proceeds from the sale to purchase 278,000 common units of APL, which in turn utilized the proceeds to partially fund the early termination of certain derivative agreements. Following our private placement, Atlas Energy had a 64.4% ownership interest in our common units.

In July 2007, we sold 6,249,995 common units through a private placement to investors at a negotiated purchase price of $27.00 per unit, yielding gross proceeds of approximately $168.8 million (or net proceeds of $167.0 million, after underwriter’s fees and other transaction costs). We utilized the net proceeds from the sale to purchase 3,835,227 common units of APL (see “—APL Common Equity Offerings”), which in turn utilized those net proceeds to partially fund the acquisition of control of the Chaney Dell and Midkiff/Benedum systems. The common units issued were subsequently registered with the Securities and Exchange Commission in November 2007.

APL Common Equity Offerings

In August 2009, APL 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. APL also received a capital contribution from us of $0.4 million for us to maintain our 2.0% general partner interest in APL. In addition, APL issued warrants granting investors in its 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. APL utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under its senior secured term loan and revolving credit facility (see “—APL Term Loan and Revolving Credit Facility”), and made similar repayments with net proceeds from exercises of the warrants in January 2010 (see “—Subsequent Events”).

The common units and warrants sold by APL in the August 2009 private placement were subject to a registration rights agreement entered into in connection with the transaction. The registration rights agreement required APL to (a) file a registration statement with the Securities and Exchange Commission for the privately placed common units and those underlying the warrants by September 21, 2009 and (b) cause the registration statement to be declared effective by the Securities and Exchange Commission by November 18, 2009. APL filed a registration statement with the Securities and Exchange Commission in satisfaction of the registration requirements of the registration rights agreement on September 3, 2009, and the registration statement was declared effective on October 14, 2009.

In June 2008, APL sold 5,750,000 common units in a public offering at a price of $37.52 per unit, yielding net proceeds of approximately $206.6 million. Also in June 2008, APL sold 1,112,000 common units to Atlas Energy and 278,000 common units to us in a private placement at a net price of $36.02 per unit, resulting in net proceeds of approximately $50.1 million. APL also received a capital contribution from us of $5.4 million for it to maintain its 2.0% general partner interest in APL. APL utilized the net proceeds from both sales and the capital contribution to fund the early termination of certain derivative agreements.

In July 2007, APL sold 25,568,175 common units through a private placement to investors at a negotiated purchase price of $44.00 per unit, yielding net proceeds of approximately $1.125 billion. Of the 25,568,175 common units sold by APL, 3,835,227 common units were purchased by us for $168.8 million. APL also received a capital contribution from us of $23.1 million in order for us to maintain our 2.0% general partner interest in APL. We funded this capital contribution and underwriting fees and other transaction costs related to our private placement of common units through borrowings under our revolving credit facility of $25.0 million. APL utilized the net proceeds from the sale to partially fund the Chaney Dell and Midkiff/Benedum acquisitions (see“—Significant Acquisitions”). The common units APL issued were subsequently registered with the Securities and Exchange Commission in November 2007.

APL Preferred Units

APL Class A Preferred Units

In April 2007, APL and Sunlight Capital agreed to amend the terms of the then-outstanding 40,000 cumulative convertible preferred units (“APL Class A Preferred Units”) effective as of that date. The terms of the APL Class A Preferred Units were amended to entitle Sunlight Capital to receive dividends of 6.5% per annum commencing in March 2008 and to be convertible, at Sunlight Capital’s option, into common units commencing May 8, 2008 at a conversion price equal to the lesser of $43.00 or 95% of the market price of APL’s common units as of the date of the notice of conversion. APL could elect to pay cash rather than issue common units in satisfaction of a conversion request. APL had the right to call the APL Class A Preferred Units at a specified premium. The applicable redemption price under the amended agreement was increased to $53.22. If not converted into common units or redeemed prior to the second anniversary of the conversion commencement date, the APL Class A Preferred Units would automatically be converted into APL’s common units in accordance with the agreement. In consideration of Sunlight Capital’s consent to the amendment of the APL Class A Preferred Units, APL issued $8.5 million of its 8.125% senior unsecured notes due 2015 to Sunlight Capital. APL recorded the senior unsecured notes issued as long-term debt and a preferred unit dividend within Partners’ Capital on its consolidated balance sheet and, during the year ended December 31, 2007, reduced net income (loss) attributable to common limited partners and us, the general partner, by $3.8 million of this amount, which was the portion deemed to be attributable to the concessions of the common limited partners and us to the APL Class A preferred unitholder, on its consolidated statements of operations.

In December 2008, APL redeemed 10,000 of the APL Class A Preferred Units for $10.0 million in cash under the terms of the agreement. The redemption was classified as a reduction of non-controlling interest in APL within our consolidated balance sheet. APL’s 30,000 outstanding APL Class A preferred limited partner units were convertible into approximately 5,263,158 common limited partner units at December 31, 2008, which is based upon the market value of its common units and subject to provisions and limitations within the agreement between the parties, with an estimated fair value of approximately $31.6 million based upon the market value of its common units as of that date.

In January 2009, APL and Sunlight Capital agreed to amend certain terms to the APL Class A Preferred Units. The amendment (a) increased the dividend yield from 6.5% to 12.0% per annum, effective January 1, 2009, (b) established a new conversion commencement date on the outstanding APL Class A Preferred Units of April 1, 2009, (c) established Sunlight Capital’s new conversion option price of $22.00, enabling the APL Class A Preferred Units to be converted at the lesser of $22.00 or 95% of the market value of APL’s common units, and (d) established a new price for APL’s call redemption right of $27.25.

The amendment to the preferred units certificate of designation also required that APL issue Sunlight Capital $15.0 million of its 8.125% senior unsecured notes due 2015 (see “—APL Senior Notes”) to redeem 10,000 APL Class A Preferred Units. APL’s management estimated that the fair value of the $15.0 million 8.125% senior unsecured notes issued to redeem the APL Class A Preferred Units was approximately $10.0 million at the date of redemption based upon the market price of the publicly-traded APL senior notes. As such, APL recorded the redemption by recognizing a $10.0 million reduction of APL Class A Preferred equity within Partners’ Capital, $15.0 million of additional long-term debt for the face value of the APL senior unsecured notes issued, and a $5.0 million discount on the issuance of the APL senior unsecured notes that is presented as a reduction of long-term debt on our consolidated balance sheet. The discount recognized upon issuance of the APL senior unsecured notes will be amortized to interest expense in our consolidated statements of operations over the term of the notes based upon the effective interest rate method.

The amendment to the preferred units certificate of designation also required that (a) APL redeem 10,000 of the APL Class A Preferred Units for cash at the liquidation value on April 1, 2009 and (b) that if Sunlight Capital made a conversion request of the remaining 10,000 APL Class A Preferred Units between April 1, 2009 and June 1, 2009, APL had the option of redeeming the APL Class A Preferred Units for cash at the stipulated liquidation value or converting the APL Class A Preferred Units into APL common limited partner units at the stipulated conversion price. If Sunlight Capital made a conversion request subsequent to June 1, 2009, 5,000 of the 10,000 APL Class A Preferred Units would have been required to be redeemed in cash, while APL had the option of redeeming the remaining 5,000 APL Class A Preferred Units in cash or converting the preferred units into APL common limited partner units.

On April 1, 2009, APL redeemed 10,000 of the APL Class A Preferred Units held by Sunlight Capital for cash at the liquidation value of $1,000 per unit, or $10.0 million, in accordance with the terms of the amended preferred units’ certificate of designation. On April 13, 2009, APL converted 5,000 of the APL Class A Preferred Units into 1,465,653 APL common units in accordance with the terms of the amended preferred units’ certificate of designation. APL reclassified $5.0 million from APL Class A preferred limited partner equity to APL common limited partner equity within Partners’ Capital when these APL preferred units were converted into APL common limited partner units. On May 5, 2009, APL redeemed the remaining 5,000 APL Class A Preferred Units held by Sunlight Capital for cash at the liquidation value of $1,000 per unit, or $5.0 million, pursuant to the terms of the amended preferred units certificate of designation. Additionally, on May 5, 2009, APL paid Sunlight Capital a preferred dividend of $0.2 million, representing the quarterly dividend on the 5,000 Class A Preferred units held by Sunlight Capital prior to APL’s redemption.

APL Class B Preferred Units

In December 2008, APL sold 10,000 12.0% cumulative convertible Class B preferred units of limited partner interests (the “APL Class B Preferred Units”) to us for cash consideration of $1,000 per Class B Preferred Unit (the “Face Value”) pursuant to a certificate of designation (the “APL Class B Preferred Units Certificate of Designation”). On March 30, 2009, we, pursuant to our right within the Class B Preferred Unit Purchase Agreement, purchased an additional 5,000 APL Class B Preferred Units at Face Value. APL used the proceeds from the sale of the APL Class B Preferred Units for general partnership purposes. The APL Class B Preferred Units receive distributions of 12.0% per annum, paid quarterly on the same date as the distribution

payment date for APL’s common units. The record date of determination for holders entitled to receive distributions of the APL Class B Preferred Units will be the same as the record date of determination for APL’s common unit holders entitled to receive quarterly distributions. Additionally, on March 30, 2009, we and APL agreed to amend the terms of the APL Class B Preferred Units Certificate of Designation to remove the conversion feature, thus the APL Class B Preferred Units are not convertible into APL common units. The amended APL Class B Preferred Units Certificate of Designation also gives APL the right at any time to redeem some or all of the outstanding APL Class B Preferred Units for cash at an amount equal to the APL Class B Preferred Unit Liquidation Value being redeemed, provided that such redemption must be exercised for no less than the lesser of a) 2,500 APL Class B Preferred Units or b) the number of remaining outstanding APL Class B Preferred Units. The cumulative sale of the APL Class B Preferred Units to us is exempt from the registration requirements of the Securities Act of 1933.

APL Term Loan and Credit Facility

At December 31, 2009, APL had a senior secured credit facility with a syndicate of banks which consisted of a term loan which matures in July 2014 and a $380.0 million revolving credit facility which matures in July 2013. Borrowings under APL’s credit facility bear interest, at APL’s option, at either (i) adjusted LIBOR plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). The weighted average interest rates on the outstanding APL revolving credit facility and term loan borrowings at December 31, 2009 were 6.8%. Up to $50.0 million of APL’s credit facility may be utilized for letters of credit, of which $10.1 million was outstanding at December 31, 2009. These outstanding letter of credit amounts were not reflected as borrowings on our consolidated balance sheet.

In June 2008, APL entered into an amendment to its credit facility agreement to revise the definition of “Consolidated EBITDA” to provide for the add-back of charges relating to APL’s early termination of certain derivative contracts (see “Item 8: Financial Statements and Supplementary Data —Note 12”) in calculating APL’s Consolidated EBITDA. Pursuant to this amendment, in June 2008 APL repaid $122.8 million of its outstanding term loan and repaid $120.0 million of outstanding borrowings under its revolving credit facility with proceeds from APL’s issuance of $250.0 million of 10-year, 8.75% senior unsecured notes (see “—APL Senior Notes”). Additionally, pursuant to this amendment, in June 2008 APL’s lenders increased their commitments for its revolving credit facility by $80.0 million to $380.0 million.

On May 29, 2009, APL entered into an amendment to its credit facility agreement which, among other changes:

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increased the applicable margin above adjusted LIBOR to either (i) the federal funds rate plus 0.5% or (ii) the Wachovia Bank prime rate upon which borrowings under the credit facility bear interest;

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for borrowings under the credit facility that bear interest at LIBOR plus the applicable margin, set a floor for the adjusted LIBOR interest rate of 2.0% per annum;

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increased the maximum ratio of total funded debt (as defined in the credit agreement) to consolidated EBITDA (as defined in the credit agreement; the “leverage ratio”) and decreased the minimum ratio of interest coverage (as defined in the credit agreement) that the credit facility requires APL to maintain;

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instituted a maximum ratio of senior secured funded debt (as defined in the credit agreement) to consolidated EBITDA (the “senior secured leverage ratio”) that the credit facility requires APL to maintain;

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required that APL pay no cash distributions during the remainder of the year ended December 31, 2009 and allows it to pay cash distributions commencing with the quarter ending March 31, 2010, only if APL’s senior secured leverage ratio is less than 2.75x and APL has minimum liquidity (as defined in the credit agreement) of at least $50.0 million;

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generally limited APL’s annual capital expenditures to $95.0 million for the remainder of fiscal 2009 and $70.0 million each year thereafter, unless certain covenants are achieved;

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generally limits APL’s annual capital contributions to Laurel Mountain to $10.0 million provided that if less than $10.0 million is paid in any given year that the shortfall may be carried over to the following year;

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permitted APL to retain (i) up to $135.0 million of net cash proceeds from dispositions completed in fiscal 2009 for reinvestment in similar replacement assets within 360 days, and (ii) up to $50.0 million of net cash proceeds from dispositions completed in any subsequent fiscal year subject to certain limitations as defined within the credit agreement; and

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instituted a mandatory repayment requirement of the outstanding senior secured term loan from excess cash flow (as defined in the credit agreement) based upon APL’s leverage ratio.

Borrowings under the credit facility are secured by a lien on and security interest in all of APL’s property and that of its subsidiaries, except for the assets owned by the Chaney Dell and Midkiff/Benedum joint ventures and the Laurel Mountain joint venture. Borrowings are also secured by the guaranty of each of APL’s consolidated subsidiaries other than the joint venture companies. The credit facility contains customary covenants, including restrictions on APL’s ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to its unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. APL is also unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to its partnership agreement. APL is in compliance with these covenants as of December 31, 2009.

The events which constitute an event of default for the credit facility include payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against APL in excess of a specified amount, and a change of control of APL’s General Partner. The credit facility requires APL to maintain the following ratios:


Fiscal quarter ending:	Maximum Leverage Ratio	Maximum Senior Secured Leverage Ratio	Minimum Interest Coverage Ratio
December 31, 2009	8.50x	5.25x	1.70x
March 31, 2010	9.25x	5.75x	1.40x
June 30, 2010	8.00x	5.00x	1.65x
September 30, 2010	7.00x	4.25x	1.90x
December 31, 2010	6.00x	3.75x	2.20x
Thereafter	5.00x	3.00x	2.75x

As of December 31, 2009, APL’s leverage ratio was 5.2 to 1.0, its senior secured leverage ratio was 3.2 to 1.0, and its interest coverage ratio was 2.5 to 1.0.

APL Senior Notes

At December 31, 2009, APL had $223.1 million principal amount outstanding of 8.75% senior unsecured notes due on June 15, 2018 (“APL 8.75% Senior Notes”) and $275.5 million principal amount outstanding of 8.125% senior unsecured notes due on December 15, 2015 (“APL 8.125% Senior Notes”; collectively, the “APL Senior Notes”). The APL 8.125% Senior Notes are presented combined with a net $3.9 million of unamortized discount as of December 31, 2009. Interest on the APL Senior Notes in the aggregate is payable semi-annually in arrears on June 15 and December 15. The APL Senior Notes are redeemable at any time at certain redemption prices, together with accrued and unpaid interest to the date of redemption. Prior to June 15, 2011, APL may redeem up to 35% of the aggregate principal amount of the APL 8.75% Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The Senior Notes in the aggregate are also subject to repurchase by APL 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 APL does not reinvest the net proceeds within 360 days. The APL Senior Notes are junior in right of payment to APL’s secured debt, including APL’s obligations under its credit facility.

In December 2008, APL repurchased approximately $60.0 million in face amount of APL Senior Notes for an aggregate purchase price of approximately $40.1 million plus accrued interest of approximately $2.0 million. The notes repurchased were comprised of $33.0 million in face amount of APL’s 8.125% Senior Notes and approximately $27.0 million in face amount of APL’s 8.75% Senior Notes. All of the APL Senior Notes repurchased have been retired and are not available for re-issue.

In January 2009, APL issued Sunlight Capital $15.0 million of its 8.125% Senior Notes to redeem 10,000 APL Class A Preferred Units (see “—APL Preferred Units”). APL’s management estimated that the fair value of the $15.0 million 8.125% Senior Notes issued was approximately $10.0 million at the date of issuance based upon the market price of the publicly-traded Senior Notes. As such, APL recognized a $5.0 million discount on the issuance of the Senior Notes, which is presented as a reduction of long-term debt on our consolidated balance sheet. The discount recognized upon issuance of the Senior Notes will be amortized to interest expense in our consolidated statements of operations over the term of the 8.125% Senior Notes based upon the effective interest rate method.

Indentures governing the APL Senior Notes in the aggregate contain covenants, including limitations of APL’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare 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 of its assets. APL is in compliance with these covenants as of December 31, 2009.

In connection with the issuance of APL’s 8.75% Senior Notes, APL entered into a registration rights agreement, whereby it agreed to (a) file an exchange offer registration statement with the Securities and Exchange Commission for the APL 8.75% Senior Notes, (b) cause the exchange offer registration statement to be declared effective by the Securities and Exchange Commission, and (c) cause the exchange offer to be consummated by February 23, 2009. If APL did not meet the aforementioned deadline, the APL 8.75% Senior Notes would have been subject to additional interest, up to 1% per annum, until such time that APL had caused the exchange offer to be consummated. On November 21, 2008, APL filed an exchange offer registration statement for the APL 8.75% Senior Notes with the Securities and Exchange Commission, which was declared effective on December 16, 2008. The exchange offer was consummated on January 21, 2009, thereby fulfilling all of the requirements of the APL 8.75% Senior Notes registration rights agreement by the specified dates.

Environmental Regulation

APL’s 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 that APL’s 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 and criminal penalties, imposition of remedial requirements, issuance of injunctions affecting APL’s operations, or other mandatory or consensual measures. APL has an ongoing environmental compliance program. However, risks of accidental leaks or spills are associated with the gathering of natural gas. There can be no assurance that APL 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 its business. Moreover, it is possible that other developments, such as increasingly strict environmental laws and regulations and enforcement policies hereunder, could result in increased costs and liabilities to APL.

Environmental laws and regulations have changed substantially and rapidly over the last 25 years, including recent legislation regarding climate change, and we anticipate that there will be continuing changes. One trend in environmental regulation is to increase reporting obligations and place 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. Related to greenhouse gas emissions, cap and trade programs and/or carbon tax programs are being considered by Congress. Depending on the particular program, APL could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from its operations or from combustion of fuels it processes. Depending on the design and implementation of carbon tax programs, APL’s operations could face additional taxes and higher costs of doing business. Although APL 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 APL’s cost of doing business. However, it is difficult to assess the timing and effect of the pending legislation.

APL has developed and implemented a greenhouse gas monitoring plan (“the Plan”) in response to the EPA’s promulgation of the Mandatory Greenhouse Gas Reporting Rule in 40 CFR 98. The Plan is designed to ensure that APL achieves and maintains compliance with those facets of the rule which affect its operating facilities. APL is diligently and continuously working to ensure that the necessary resources from both within and outside the organization are engaged to provide the information and services required to execute the Plan.

APL continues to monitor regulatory and legislative activities regarding greenhouse gas production, detection, reporting and mitigation issues. APL recognizes that greenhouse gas issues continue to be very dynamic topics of discussion within the scientific, business and political communities, and APL is committed to staying abreast of developing rules and mandates that will affect its operations and business activities. APL participates within industry organizations in order that it may actively contribute to consolidated initiatives that are continuously monitoring, addressing and contributing to these greenhouse gas issues both during and following their development.

Other increasingly strict environmental restrictions and limitations have resulted in increased operating costs for APL and other similar businesses throughout the United States. It is possible that the costs of compliance with environmental laws and regulations may continue to increase. APL will attempt to anticipate future regulatory requirements that might be imposed and to plan accordingly, but there can be no assurance that APL will identify and properly anticipate each such charge, or that APL’s 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. While inflation did not have a material impact on our results of operations for the years ended December 31, 2009, 2008 and 2007, the energy sector realized increased costs during 2008, caused by the

demand in energy equipment and services due to the increase in commodity prices. Commodity prices have decreased from their highs in 2008 and the related costs have also declined. While we anticipate that inflation will affect our future operating costs, we cannot predict the timing or amounts of any such effects.

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 that 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 that are subject to such estimates and assumptions include 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 critical accounting policies and estimates we have identified are discussed below.

Depreciation and Impairment of Long-Lived Assets and Goodwill

Long-Lived Assets. The cost of properties, plants and equipment, less estimated salvage value, is generally depreciated on a straight-line basis over the estimated useful lives of the assets. Useful lives are based on historical experience and are adjusted when changes in planned use, technological advances or other factors indicate that a different life would be more appropriate. Changes in useful lives that do not result in the impairment of an asset are recognized prospectively.

Long-lived assets other than goodwill and intangibles with infinite lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. A long-lived asset other than goodwill and intangibles with infinite lives is considered to be impaired when the undiscounted net cash flows expected to be generated by the asset are less than its carrying amount. Events or changes in circumstances that would indicate the need for impairment testing include, among other factors: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing our services or for our products; changes in competition and competitive practices; uncertainties associated with the United States and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions. Additional factors impacting the economic viability of long-lived assets are discussed under “Forward Looking Statements” elsewhere in this document.

As discussed below, we recognized an impairment of goodwill at December 31, 2008. We believe this impairment of goodwill was an event that warranted assessment of APL’s long-lived assets for possible impairment. During the year ended December 31, 2009, APL completed an evaluation of certain assets based on the current operating conditions and business plans for those assets, including idle and inactive pipelines and equipment. Based on the results of this review, APL recognized an impairment charge of approximately $10.3 million for the year ended December 31, 2009, within goodwill and other asset impairments on our consolidated statements of operations.

Goodwill and Intangibles with Infinite Lives. Goodwill and intangibles with infinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. Under the prevailing accounting literature, an impairment loss should be recognized if the carrying value of an entity’s reporting units exceeds its estimated fair value. Because quoted market prices for our reporting units are not available, management must apply judgment in determining the estimated fair value of these reporting units. Management uses all available information to make these fair value

determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. A key component of these fair value determinations is a reconciliation of the sum of these net present value calculations to market capitalization. Prevailing accounting literature acknowledge that the observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity’s individual equity securities. In most industries, including ours, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above net present value calculations have been determined, we also add a control premium to the calculations. This control premium is subject to judgment and is based on observed acquisitions in our industry. The resultant fair values calculated for the reporting units are then compared to observable metrics on large mergers and acquisitions in our industry to determine whether those valuations appear reasonable in management’s judgment.

As a result of APL’s impairment evaluation at December 31, 2008, we recognized a $676.9 million non-cash impairment charge within our consolidated statements of operations for the year ended December 31, 2008. The goodwill impairment resulted from the reduction in APL’s estimated fair value of reporting units in comparison to their carrying amounts at December 31, 2008. APL’s estimated fair value of the reporting units was impacted by many factors, including the significant deterioration of commodity prices and global economic conditions during the fourth quarter of 2008. There were no goodwill impairments recognized by us during the years ended December 31, 2009 and 2007. See “Goodwill” in “Item 8: Financial Statements and Supplementary Data —Note 2” for information regarding APL’s impairment of goodwill and other assets.

Fair Value of Financial Instruments

FASB ASC established a hierarchy to measure financial instruments at fair value which requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1– Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

Level 3 – Unobservable inputs that reflect the entity’s own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

We and APL use the fair value methodology to value the assets and liabilities for its respective outstanding derivative contracts (see “Item 8: Financial Statements and Supplementary Data —Note 13”). At December 31, 2009, all of our and APL’s derivative contracts are defined as Level 2, with the exception of APL’s NGL fixed price swaps and NGL options. APL’s Level 2 commodity hedges are calculated based on observable market data related to the change in price of the underlying commodity. Our and APL’s interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model, and are therefore defined as Level 2. Valuations for APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of quoted price curves for NGL’s for similar locations, and therefore are defined as Level 3. Valuations for APL’s NGL options are based on forward price curves developed by the related financial institutions, and therefore are defined as Level 3.

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. As our assets currently consist solely of our ownership interests in APL, the following information principally encompasses APL’s exposure to market risks unless otherwise noted. 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 of our and APL’s market risk sensitive instruments were entered into for purposes other than trading.

General

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

We and APL 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 and APL manage these risks through regular operating and financing activities and periodical 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, 2009. Only the potential impact of hypothetical assumptions is analyzed. The analysis does not consider other possible effects that could impact our and APL’s business.

Current market conditions elevate our and APL’s concern over counterparty risks and may adversely affect the ability of these counterparties to fulfill their obligations to us and APL, if any. The counterparties to APL’s commodity derivative contracts and our and APL’s interest-rate derivative contracts are banking institutions currently participating in our and APL’s revolving credit facility. We and APL may choose to do business with counterparties outside of our credit facility in the future. The creditworthiness of our and APL’s counterparties is constantly monitored, and we and APL are not aware of any inability on the part of our respective counterparties to perform under our contracts.

Interest Rate Risk. At December 31, 2009, we had a credit facility with $8.0 million outstanding. The weighted average interest rate for these borrowings was 3.25% at December 31, 2009.

In May 2008, we entered into an interest rate derivative contract having an aggregate notional principal amount of $25.0 million. Under the terms of agreement, we will pay an interest rate of 3.01%, plus the applicable margin as defined under the terms of our revolving credit facility (see “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations —Our Credit Facility”), and will receive LIBOR, plus the applicable margin, on the notional principal amounts. The interest rate swap agreement is in effect at December 31, 2009 and expires on May 28, 2010.

At December 31, 2009, APL had a $380.0 million senior secured revolving credit facility ($326.0 million outstanding). APL also had $433.5 million outstanding under its senior secured term loan at December 31, 2009. Borrowings under the credit facility bear interest, at APL’s option at either (i) adjusted LIBOR plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). On May 29, 2009, APL entered into an amendment to its senior secured revolving credit facility agreement which, among other changes, set a floor for the LIBOR interest rate of 2.0% per annum. The weighted average interest rate for APL’s revolving credit facility borrowings was 6.8% at December 31, 2009, and the weighted average interest rate for the term loan borrowings was 6.8% at December 31, 2009.

At December 31, 2009, APL had interest rate derivative contracts having aggregate notional principal amounts of $450.0 million. Under the terms of these agreements, APL will pay weighted average interest rates of 3.0%, plus the applicable margin as defined under the terms of its revolving credit facility, and will receive LIBOR, plus the applicable margin, on the notional principal amounts. The APL interest rate swap agreements are in effect as of December 31, 2009 and expire during periods ranging from January 30, 2010 through April 30, 2010. Beginning May 29, 2009, APL discontinued hedge accounting for its interest rate derivatives which were qualified as hedges under prevailing accounting literature. As such, subsequent changes in fair value of these derivatives will be recognized immediately within other income (loss), net in our consolidated statements of operations.

Holding all other variables constant, a 100 basis-point, or 1%, change in our and APL’s interest rates would change its annual interest expense by $0.8 million.

Commodity Price Risk. APL is 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, APL receives fees or commodities from the producers to bring the raw natural gas from the wellhead to the processing plant. For processing services, APL either receives fees or commodities as payment for these services, based on the type of contractual agreement. Average estimated unhedged 2010 market prices for NGLs, natural gas and condensate, based upon New York Mercantile Exchange (“NYMEX”) forward price curves as of February 15, 2010, are $1.10 per gallon, $5.71 per MMBTU and $76.26 per barrel, respectively. A 10% change in these prices would change our forecasted gross margin, excluding the effect of non-controlling interest in APL net income (loss), for the twelve-month period ended December 31, 2010 by approximately $27.2 million.

We and APL use a number of different derivative instruments, principally swaps and options, in connection with our commodity price and interest rate risk management activities. APL enters into financial swap and option instruments to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. We and APL also enter into financial swap instruments to hedge certain portions of our floating interest rate debt against the variability in market interest rates. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate are sold or interest payments on the underlying debt instrument are due. Under swap agreements, APL receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not the obligation, to receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period.

On July 1, 2008, APL discontinued hedge accounting for its existing commodity derivatives which were qualified as hedges for accounting purposes. In addition, beginning May 29, 2009, we and APL discontinued hedge accounting for our existing interest rate derivatives which were qualified as hedges under prevailing accounting literature. As such, subsequent changes in fair value of these derivatives are recognized immediately within other income (loss) in our consolidated statements of operations. The fair value of these commodity derivative instruments at June 30, 2008, and interest rate derivative instruments at May 29, 2009, which were recognized in accumulated other comprehensive loss (“OCI”) within Partners’ Capital (deficit) on our consolidated balance sheet, will be reclassified to our consolidated statements of operations in the future at the time the originally hedged physical transactions affect earnings.

During the years ended December 31, 2009 and 2008 APL made net payments of $5.0 million and $274.0 million, respectively, related to the early termination of derivative contracts. The majority of these derivative contracts were put into place simultaneously with APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007 and related to production periods ranging from the end of the second quarter of 2008 through the fourth quarter of 2009. Additional terminated derivative contracts extend through the fourth quarter of 2012. During the years ended December 31, 2009, 2008 and 2007, we recognized the

following derivative activity related to APL’s early termination of these derivative instruments within our consolidated statements of operations (in thousands):

Early termination of derivative contracts


	For the Years Ended December 31,
	2009			2008			2007
Cash paid for early termination	$	(5,000	)	$	(273,987	)	$	—
Less: Deferred recognition of loss on early termination⁽¹⁾		—			(76,345	)		—

		(5,000	)		(197,642	)		—

Net cash derivative expense included within natural gas and liquids revenue		—			2,322			—
Net cash derivative expense included within other loss, net		(5,000	)		(199,964	)		—
Recognition of deferred hedge (loss) from prior periods included within natural gas and liquids revenue		(68,479	)		(32,389	)		—
Recognition of deferred hedge gain (loss) from prior periods included within other income (loss), net		44,861			(39,218	)		—

Total recognized loss from early termination	$	(28,618	)	$	(269,249	)	$	—

(1)	Deferred recognition based upon effective portion of hedges deferred to OCI, plus theoretical premium related to unwound options which had previously been purchased or sold as part of costless collars

As of December 31, 2009, we had the following interest rate derivatives, including derivatives that do not qualify for hedge accounting:

Interest Fixed-Rate Swaps


Term	Notional Amount		Type	Contract Period Ended December 31,	Fair Value Liability⁽¹⁾ (in thousands)


May 2008-May 2010	$	25,000,000	Pay 3.01% —Receive LIBOR	2010	$	(286	)

(1)	Fair value based on independent, third-party statements, supported by observable levels at which transactions are executed in the marketplace.

As of December 31, 2009, APL had the following interest rate and commodity derivatives, including derivatives that do not qualify for hedge accounting:

Interest Fixed-Rate Swaps


Term	Amount		Type	Fair Value⁽¹⁾ Asset/(Liability) (in thousands)
Term	Amount		Type	Fair Value⁽¹⁾ Asset/(Liability) (in thousands)
January 2008-January 2010	$	200,000,000	Pay 2.88% —Receive LIBOR	$	(438	)
April 2008-April 2010	$	250,000,000	Pay 3.14% —Receive LIBOR		(2,402	)

Total Interest Rate Swaps				$	(2,840	)

Fixed Price Swaps


Production Period	Purchased/ Sold	Commodity	Volumes⁽²⁾	Average Fixed Price			Fair Value⁽¹⁾ Asset/(Liability) (in thousands)
Production Period	Purchased/ Sold	Commodity	Volumes⁽²⁾	Average Fixed Price			Fair Value⁽¹⁾ Asset/(Liability) (in thousands)
2010	Purchased	Natural Gas	4,380,000	$	8.635		$	(13,306	)
2010	Sold	Natural Gas Basis	4,500,000		(0.638	)		(1,936	)
2010	Purchased	Natural Gas Basis	8,880,000		(0.597	)		3,369
2011	Sold	Natural Gas Basis	1,920,000		(0.728	)		(845	)
2011	Purchased	Natural Gas Basis	1,920,000		(0.758	)		903
2012	Sold	Natural Gas Basis	720,000		(0.685	)		(269	)
2012	Purchased	Natural Gas Basis	720,000		(0.685	)		269

Total Fixed Price Swaps							$	(11,815	)


*NGL Options*
Production Period	Purchased/ Sold	Type	Commodity	Volumes⁽²⁾	Average Strike Price		Fair Value⁽¹⁾ Asset /(Liability) (in thousands)
2010	Purchased	Put	Propane	35,910,000	$	1.022	$	1,137
2010	Purchased	Put	Normal Butane	3,654,000		1.205		29
2010	Purchased	Put	Natural Gasoline	3,906,000		1.545		102

Total NGL Options							$	1,268

*Crude Oil Options*
Production Period	Purchased/ Sold	Type	Commodity	Volumes⁽²⁾	Average Strike Price		Fair Value⁽¹⁾ Asset /(Liability) (in thousands)
2010	Purchased	Put	Crude Oil	897,000	$	73.12	$	3,518
2010	Sold	Call	Crude Oil	3,361,500		81.23		(23,183	)
2010	Purchased⁽³⁾	Call	Crude Oil	714,000		120.00		430
2011	Sold	Call	Crude Oil	678,000		94.68		(6,687	)
2011	Purchased⁽³⁾	Call	Crude Oil	252,000		120.00		1,017
2012	Sold	Call	Crude Oil	498,000		95.83		(6,197	)
2012	Purchased⁽³⁾	Call	Crude Oil	180,000		120.00		1,175

Total Crude Oil Options							$	(29,927	)

Total Fair Value							$	(43,314	)

⁽¹⁾	See “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations—Fair Value of Financial Instruments” for discussion on fair value methodology.

⁽²⁾	Volumes for Natural Gas are stated in MMBTU’s. Volumes for NGLs are stated in gallons. Volumes for Crude are stated in barrels.

⁽³⁾	Calls purchased for 2010 through 2012 represent offsetting positions for calls sold. These offsetting positions were entered into to limit the loss which could be incurred if crude oil prices continued to rise.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unitholders

Atlas Pipeline Holdings, L.P.

We have audited the accompanying consolidated balance sheets of Atlas Pipeline Holdings, L.P. (a Delaware limited partnership) and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations, comprehensive income (loss), partners’ capital, and cash flows for each of the three years in the period ended December 31, 2009. 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 Holdings, L.P. and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1, the Partnership retrospectively adopted a new accounting pronouncement on January 1, 2009 related to the accounting for noncontrolling interests in the consolidated financial statements.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Atlas Pipeline Holdings, L.P.’s internal control over financial reporting as of December 31, 2009, 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 March 5, 2010 expressed an unqualified opinion thereon.


/s/ GRANT THORNTON LLP
Tulsa, Oklahoma
March 5, 2010

ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)


	December 31,
	2009			2008
ASSETS
Current assets:
Cash and cash equivalents	$	1,103		$	7,285
Accounts receivable – affiliates		—			341
Accounts receivable		100,721			100,000
Current portion of derivative asset		998			44,961
Prepaid expenses and other		15,404			10,998
Current assets of discontinued operations		—			13,441

Total current assets		118,226			177,026

Property, plant and equipment, net		1,684,384			1,781,011
Intangible assets, net		168,091			193,647
Investment in joint venture		132,990			—
Long-term portion of derivative asset		361			—
Other assets, net		34,066			25,135
Long-term assets of discontinued operations		—			242,165

	$	2,138,118		$	2,418,984

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Current portion of long-term debt	$	32,255		$	—
Accounts payable – affiliates		2,304			—
Accounts payable		22,928			66,571
Accrued liabilities		14,549			13,439
Accrued interest payable		9,652			2,423
Current portion of derivative liability		33,833			60,947
Accrued producer liabilities		66,211			66,846
Current liabilities of discontinued operations		—			10,572

Total current liabilities		181,732			220,798

Long-term portion of derivative liability		11,126			48,333
Long-term debt, less current portion		1,254,183			1,539,427
Other long-term liability		398			574
Commitments and contingencies

Partners’ Capital:
Common limited partners’ interests		(7,756	)		(5,463	)
Accumulated other comprehensive loss		(6,551	)		(15,788	)

		(14,307	)		(21,251	)
Non-controlling interests		(30,925	)		(32,337	)
Non-controlling interest in Atlas Pipeline Partners, L.P.		735,911			663,440

Total Partners’ Capital		690,679			609,852

	$	2,138,118		$	2,418,984

See accompanying notes to consolidated financial statements

ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)


	Years Ended December 31,
	2009			2008			2007
Revenue:
Natural gas and liquids	$	778,544		$	1,342,782		$	739,851
Transportation, compression and other fees – affiliates		17,536			43,293			33,169
Transportation, compression and other fees – third parties		15,433			21,196			13,322
Equity income in joint venture		4,043			—			—
Gain on asset sales		111,440			—			—
Other loss, net		(23,150	)		(55,487	)		(174,110	)

Total revenue and other loss, net		903,846			1,351,784			612,232

Costs and expenses:
Natural gas and liquids		594,742			1,080,940			576,415
Plant operating		58,474			60,835			34,667
Transportation and compression		6,657			11,249			6,235
General and administrative		36,646			241			57,236
Compensation reimbursement – affiliates		2,731			1,487			5,939
Depreciation and amortization		92,434			82,841			43,903
Goodwill and other asset impairment loss		10,325			676,860			—
Interest		106,373			87,853			63,695
Gain on early extinguishment of debt		—			(19,867	)		—

Total costs and expenses		908,382			1,982,439			788,090

Loss from continuing operations		(4,536	)		(630,655	)		(175,858	)

Discontinued operations:
Gain on sale of discontinued operations		51,078			—			—
Earnings of discontinued operations		11,417			20,546			30,830

Income from discontinued operations		62,495			20,546			30,830

Net income (loss)	$	57,959		$	(610,109	)	$	(145,028	)

(Income) loss attributable to non-controlling interests		(3,176	)		22,781			(3,940	)
(Income) loss attributable to non-controlling interest in Atlas Pipeline Partners, L.P.		(50,748	)		513,675			133,321

Net income (loss) attributable to common limited partners	$	4,035		$	(73,653	)	$	(15,647	)


Net income (loss) attributable to common limited partners per unit:
Basic:
Continuing operations	$	(0.17	)	$	(2.77	)	$	(0.81	)
Discontinued operations		0.32			0.09			0.15

	$	0.15		$	(2.68	)	$	(0.66	)

Diluted:
Continuing operations	$	(0.17	)	$	(2.77	)	$	(0.81	)
Discontinued operations		0.32			0.09			0.15

	$	0.15		$	(2.68	)	$	(0.66	)

Weighted average common limited partner units outstanding:
Basic		27,663			27,511			23,806
Diluted		27,663			27,511			23,806

Amounts attributable to common limited partners:
Continuing operations	$	(4,834	)	$	(76,124	)	$	(19,177	)
Discontinued operations		8,869			2,471			3,530

Net income (loss) attributable to common limited partners	$	4,035		$	(73,653	)	$	(15,647	)

See accompanying notes to consolidated financial statements

ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)


	Years Ended December 31,
	2009			2008			2007
Net income (loss)	$	57,959		$	(610,109	)	$	(145,028	)
(Income) loss attributable to non-controlling interests		(3,176	)		22,781			(3,940	)
(Income) loss attributable to non-controlling interests – Atlas Pipeline Partners, L.P.		(50,748	)		513,675			133,321

Net income (loss) attributable to common limited partners		4,035			(73,653	)		(15,647	)

Other comprehensive income (loss):
Change in fair value of derivative instruments accounted for as cash flow hedges		(2,412	)		(98,223	)		(101,968	)
Reclassification adjustment to earnings for de-designation of cash flow hedges		—			—			12,611
Changes in non-controlling interest – Atlas Pipeline Partners, L.P. related to items in other comprehensive income (loss)		(47,171	)		35,499			46,206
Add: adjustment for realized losses reclassified to net income (loss)		58,820			54,603			49,393

Total other comprehensive income (loss)		9,237			(8,121	)		6,242

Comprehensive income (loss)	$	13,272		$	(81,774	)	$	(9,405	)

See accompanying notes to consolidated financial statements

ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(in thousands, except unit data)


	Common Limited Partners’ Capital				Accumulated Other Comprehensive Income (Loss)			Non-Controlling Interests			Non-Controlling Interest in Atlas Pipeline Partners L.P.			Total Partners’ Capital (Deficit)
	Units	$						Non-Controlling Interests						Total Partners’ Capital (Deficit)
Balance at January 1, 2007	21,100,000	$	6,899		$	(13,909	)	$	—		$	386,131		$	379,121
Issuance of common limited partner units	6,250,370		167,150			—			—			946,368			1,113,518
Unissued common units under incentive plans	—		2,660			—			—			36,346			39,006
Distributions paid	—		(25,026	)		—			(6,103	)		(34,748	)		(65,877	)
Net loss on purchase and sale of subsidiary equity	—		(34,251	)		—			—			—			(34,251	)
Other comprehensive gain	—		—			6,242			—			(46,206	)		(39,964	)
Net loss	—		(15,647	)		—			3,940			(133,321	)		(145,028	)

Balance at December 31, 2007	27,350,370	$	101,785		$	(7,667	)	$	(2,163	)	$	1,154,570		$	1,246,525
Issuance of common limited partner units	308,109		10,001			—			—			246,862			256,863
Unissued common units under incentive plans	—		2,665			—			—			—			2,665
Issuance of units under incentive plans	675		—			—			—			—			—
Distributions paid	—		(49,674	)		—			(7,393	)		(188,819	)		(245,886	)
Net loss on purchase and sale of subsidiary equity	—		3,413			—			—			—			3,413
Other comprehensive loss	—		—			(8,121	)		—			(35,498	)		(43,619	)
Net loss	—		(73,653	)		—			(22,781	)		(513,675	)		(610,109	)

Balance at December 31, 2008	27,659,154	$	(5,463	)	$	(15,788	)	$	(32,337	)	$	663,440		$	609,852
Issuance of common limited partner units	—		(45	)		—			—			16,074			16,029
Distributions to non-controlling interests	—		—			—			(1,764	)		(21,693	)		(23,457	)
Redemption of subsidiary preferred units	—		—			—			—			(25,000	)		(25,000	)
Unissued common units under incentive plans	—		562			—			—			—			562
Issuance of units under incentive plans	44,425		—			—			—			—			—
Distributions paid to common limited partners	—		(1,660	)		—			—			—			(1,660	)
Distributions equivalent rights paid on unissued units under incentive plans	—		(14	)		—			—			—			(14	)
Other comprehensive loss	—		—			9,237			—			47,171			56,408
Net loss on purchase and sale of subsidiary equity	—		(5,171	)		—			—			5,171			—
Net income	—		4,035			—			3,176			50,748			57,959

Balance at December 31, 2009	27,703,579	$	(7,756	)	$	(6,551	)	$	(30,925	)	$	735,911		$	690,679

See accompanying notes to consolidated financial statements

ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)


	Years Ended December 31,
	2009			2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	57,959		$	(610,109	)	$	(145,028	)
Less: Income from discontinued operations		62,495			20,546			30,830

Net income (loss) from continuing operations		(4,536	)		(630,655	)		(175,858	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		92,434			82,841			43,903
Goodwill and other asset impairment loss		10,325			676,860			—
Gain on early extinguishment of debt		—			(19,867	)		—
Equity income in joint venture		(4,043	)		—			—
Distributions received from joint venture		4,310			—			—
Loss (gain) on asset sales and dispositions		(111,440	)		—			805
Non-cash loss (gain) on derivative value, net		35,689			(208,813	)		169,424
Non-cash compensation expense (income)		1,265			(31,345	)		38,966
Amortization of deferred finance costs		8,178			6,070			7,489
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable and prepaid expenses and other		(5,201	)		42,166			(96,051	)
Accounts payable and accrued liabilities		6,947			(20,064	)		72,746
Accounts payable and accounts receivable – affiliates		2,644			2,401			4,248

Net cash provided by (used in) continuing operating activities		36,572			(100,406	)		65,672
Net cash provided by discontinued operating activities		16,935			45,569			38,914

Net cash provided by (used in) operating activities		53,507			(54,837	)		104,586

CASH FLOWS FROM INVESTING ACTIVITIES:
Net cash received (paid) for acquisitions		—			31,429			(1,884,458	)
Capital contribution to joint venture		(1,680	)		—			—
Capital expenditures		(154,916	)		(300,723	)		(120,833	)
Proceeds from insurance claim settlement		—			1,535			—
Proceeds from sales of assets		112,035			—			553
Other		(5,003	)		—			(1,059	)

Net cash used in continuing investing activities		(49,564	)		(267,759	)		(2,005,797	)
Net cash provided by (used in) discontinued investing activities		290,594			(25,211	)		(18,879	)

Net cash provided by (used in) investing activities		241,030			(292,970	)		(2,024,676	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from issuance of Atlas Pipeline Partners, L.P. debt		—			244,854			817,131
Repayment of Atlas Pipeline Partners, L.P. debt		(273,675	)		(162,938	)		—
Net proceeds from subordinate loan and guaranty note with Atlas Energy, Inc		23,000			—			—
Borrowings under credit facilities		694,000			808,400			345,500
Repayments under credit facilities		(708,000	)		(590,400	)		(253,500	)
Net proceeds from issuance of common limited partner units		—			10,001			166,984
Net proceeds from issuance of Atlas Pipeline Partners, L.P. units		16,074			246,915			946,399
Redemption of Atlas Pipeline Partners, L.P. Class A preferred limited partner units		(15,000	)		(10,053	)		—
Net distributions paid to non-controlling interests		(1,764	)		(7,393	)		(6,103	)
Distributions paid to non-controlling interest in Atlas Pipeline Partners, L.P.		(22,337	)		(140,850	)		(59,850	)
Distributions paid to common limited partners		(1,660	)		(49,272	)		(24,788	)
Other		(11,357	)		(6,662	)		(1,077	)

Net cash provided by (used in) financing activities		(300,719	)		342,602			1,930,696

Net change in cash and cash equivalents		(6,182	)		(5,205	)		10,606
Cash and cash equivalents, beginning of year		7,285			12,490			1,884

Cash and cash equivalents, end of year	$	1,103		$	7,285		$	12,490

See accompanying notes to consolidated financial statements

ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – NATURE OF OPERATIONS

Atlas Pipeline Holdings, L.P. (“Atlas Pipeline Holdings” or the “Partnership”) is a publicly-traded Delaware limited partnership (NYSE: AHD). The Partnership’s wholly-owned subsidiary, Atlas Pipeline Partners GP, LLC (“Atlas Pipeline GP” or “General Partner”), a Delaware limited liability company, is the general partner of Atlas Pipeline Partners, L.P. (“APL” – NYSE: APL). The Partnership’s general partner, Atlas Pipeline Holdings GP, LLC (“Atlas Pipeline Holdings GP”), which does not have an economic interest in the Partnership and is not entitled to receive any distributions from the Partnership, manages the operations and activities of the Partnership and owes a fiduciary duty to the Partnership’s common unitholders. At December 31, 2009, the Partnership had 27,703,579 common limited partnership units outstanding.

APL is a publicly-traded Delaware limited partnership and a midstream energy service provider engaged in the gathering and processing of natural gas in the Mid-Continent and Appalachia regions. APL’s operations are conducted through subsidiary entities whose equity interests are owned by Atlas Pipeline Operating Partnership, L.P. (the “Operating Partnership”), a wholly-owned subsidiary of APL. The Partnership, through its general partner interests in APL and the Operating Partnership, owns a 2% general partner interest in the consolidated pipeline operations of APL, through which it manages and effectively controls both APL and the Operating Partnership. The remaining 98% ownership interest in the consolidated pipeline operations consists of limited partner interests in APL.

The Partnership’s assets consist principally of 100% ownership interest in Atlas Pipeline GP, which as of December 31, 2009, together with the Partnership, owns:

•

a 2.0% general partner interest in APL, which entitles it to receive 2.0% of the cash distributed by APL;

•

In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see Note 11), Atlas Pipeline GP agreed to allocate up to $5.0 million of its incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter; Atlas Pipeline GP also agreed that the resulting allocation of incentive distribution rights back to APL would be after Atlas Pipeline GP receives the initial $7.0 million per quarter of incentive distribution rights (the “IDR Adjustment Agreement”);

•

5,754,253 common units of APL, representing approximately 11.4% of the 50,517,103 outstanding common limited partnership units of APL (see note 6), and

•

15,000 $1,000 par value 12.0% Class B cumulative preferred limited partner units of APL (see Note 7).

The Partnership, as general partner, manages the operations and activities of APL and owes a fiduciary duty to APL’s common unitholders. The Partnership is liable, as general partner, for all of APL’s debts (to the extent not paid from APL’s assets), except for indebtedness or other obligations that are made specifically non-recourse to the Partnership. The Partnership does not receive any management fee or other compensation for its management of APL. The Partnership and its affiliates are reimbursed for expenses

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incurred on APL’s behalf. These expenses include the costs of employee, officer, and managing board member compensation and benefits properly allocable to APL and all other expenses necessary or appropriate to conduct the business of, and allocable to, APL. The APL partnership agreement provides that the Partnership, as general partner, will determine the expenses that are allocable to APL in any reasonable manner in its sole discretion.

Atlas Energy, Inc and its affiliates (“Atlas Energy”), a publicly-traded company (NASDAQ: ATLS), owns 100% of Atlas Pipeline Holdings GP, the general partner of the Partnership, and a 64.3% ownership interest in the common units of the Partnership at December 31, 2009. In addition to its ownership interest in the Partnership, Atlas Energy also owned, at December 31, 2009, 1,112,000 of APL’s common limited partnership units, representing a 2.2% ownership interest in APL. On September 29, 2009, Atlas America, Inc., the former name of Atlas Energy, and Atlas Energy Resources, LLC (“Atlas Energy Resources”), a former publicly-traded Delaware limited liability company, consummated a merger pursuant to a definitive merger agreement, whereby Atlas Energy’s wholly owned subsidiary merged with Atlas Energy Resources (the “Merger”), with Atlas Energy Resources surviving as Atlas America’s wholly-owned subsidiary. Additionally, Atlas America changed its name to Atlas Energy, Inc. upon completion of the Merger.

The majority of the natural gas that APL and its affiliates, including Laurel Mountain Midstream LLC (“Laurel Mountain”), gather in Appalachia is derived from wells operated by Atlas Energy Resources. Laurel Mountain, which was formed in May 2009, is a joint venture between the Partnership and The Williams Companies, Inc. (NYSE: WMB) (“Williams”) in which APL retains 49% ownership interest and Williams retains the remaining 51% ownership interest (see Note 3).

The Partnership has adjusted its consolidated financial statements and related footnote disclosures presented within this Form 10-K from the amounts previously presented to reflect the following items:

•

In May 2009, APL completed the sale of its NOARK gas gathering and interstate pipeline system (“NOARK”) (see Note 4). In accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 205-20-45 “Reporting Discontinued Operations,” the Partnership has retrospectively adjusted its prior period consolidated financial statements to reflect the amounts related to the operations of NOARK as discounted operations;

•

The adoption of FASB ASC 810-10-65, “Non-Controlling Interest in Consolidated Financial Statements,” which clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. FASB also requires consolidated net income to be reported and disclosed on the face of the consolidated statements of operations at amounts that include the amounts attributable to both the parent and the non-controlling interest. The Partnership adopted these requirements on January 1, 2009, and has reflected the retrospective application for all periods presented; and

•

The adoption of FASB ASC 260-10-45, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities,” which applies to the calculation of earnings per unit (“EPU”) described in previous guidance for share-based payment awards with rights to dividends or dividend equivalents. It states that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of EPU pursuant to the two-class method. The Partnership adopted these requirements on January 1, 2009 and has reflected the retroactive application for all periods presented.

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NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Non-Controlling Interest

The consolidated financial statements include the accounts of the Partnership, the General Partner, APL, the Operating Partnership and the Operating Partnership’s wholly-owned and majority-owned subsidiaries. All material intercompany transactions have been eliminated.

The Partnership’s consolidated financial statements also include APL’s 95% ownership interest in joint ventures which individually own a 100% ownership interest in the Chaney Dell natural gas gathering system and processing plants and a 72.8% undivided interest in the Midkiff/Benedum natural gas gathering system and processing plants. APL consolidates 100% of these joint ventures. The Partnership reflects the non-controlling 5% ownership interest in the joint ventures as non-controlling interests on its statements of operations. The Partnership also reflects the 5% ownership interest in the net assets of the joint ventures as non-controlling interests and as a component of Partners’ Capital on its consolidated balance sheets. The joint ventures have a $1.9 billion note receivable from the holder of the 5% ownership interest in the joint ventures, which is reflected within non-controlling interests on the Partnership’s consolidated balance sheets.

The Midkiff/Benedum joint venture has a 72.8% undivided joint venture interest in the Midkiff/Benedum system, of which the remaining 27.2% interest is owned by Pioneer Natural Resources Company (NYSE: PXD) (“Pioneer”). Accordingly, the Midkiff/Benedum joint venture proportionally consolidates its 72.8% ownership interest in the assets and liabilities and operating results of the Midkiff/Benedum system.

Equity Method Investments

The Partnership’s consolidated financial statements include APL’s 49% ownership interest in Laurel Mountain, a joint venture which owns and operates APL’s former Appalachia Basin natural gas gathering systems, excluding APL’s northeastern Tennessee operations. The Partnership accounts for APL’s investment in the joint venture under the equity method of accounting. Under this method, the Partnership records APL’s proportionate share of the joint venture’s net income (loss) as equity income on its consolidated statements of operations (see Note 3).

Use of Estimates

The preparation of the Partnership’s consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s consolidated financial statements, as well as the reported amounts of revenue and expense during the reporting periods. The Partnership’s consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depreciation and amortization, asset impairment, the fair value of the Partnership’s and APL’s derivative instruments, the probability of forecasted transactions, APL’s allocation of purchase price to the fair value of assets it acquired and other items. Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results were recorded using estimated volumes and commodity market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented represent actual results in all material respects (see “Revenue Recognition” accounting policy for further description).

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Cash Equivalents

The Partnership considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. These cash equivalents consist principally of temporary investments of cash in short-term money market instruments.

Receivables

The amounts included within Accounts Receivable on the Partnership’s consolidated balance sheet at December 31, 2009 and 2008 are associated entirely with APL’s operating activities. In evaluating the realizability of its accounts receivable, APL performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by APL’s review of its customers’ credit information. APL extends credit on an unsecured basis to many of its customers. At December 31, 2009 and 2008, APL recorded no allowance for uncollectible accounts receivable on its consolidated balance sheets.

Property, Plant and Equipment

Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized. Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. The Partnership follows the composite method of depreciation and has determined the composite groups to be the major asset classes of its gathering and processing systems. Under the composite depreciation method, any gain or loss upon disposition or retirement of pipeline, gas gathering and processing components, is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in the Partnership’s results of operations.

Impairment of Long-Lived Assets

The Partnership, including APL, reviews its long-lived assets for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

As discussed below, the Partnership recognized an impairment of goodwill at December 31, 2008. The Partnership believes this impairment of goodwill was an event that warranted assessment of APL’s long-lived assets for possible impairment. During the year ended December 31, 2009, APL completed an evaluation of certain assets based on the current operating conditions and business plans for those assets, including idle and inactive pipelines and equipment. Based on the results of this review, APL recognized an impairment charge of approximately $10.3 million for the year ended December 31, 2009, within goodwill and other asset impairments on the Partnership’s consolidated statements of operations.

Capitalized Interest

APL capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average rate used to capitalize interest on borrowed funds by APL was 6.4%, 6.3% and 8.0% for the years ended December 31, 2009, 2008 and 2007, respectively. The amount of interest capitalized was $2.8 million, $7.7 million and $2.2 million for the years ended December 31, 2009, 2008 and 2007, respectively.

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Derivative Instruments

The Partnership and APL enters into certain financial contracts to manage its exposure to movement in commodity prices and interest rates. The Partnership and APL record each derivative instrument in the balance sheet as either an asset or liability measured at fair value. Changes in a derivative instrument’s fair value are recognized currently in the consolidated statements of operations. On July 1, 2008, APL discontinued hedge accounting for all of its existing commodity derivatives which were qualified as hedges. As such, subsequent changes in fair value of these derivatives are recognized immediately within other income (loss), net in the Partnership’s consolidated statements of operations. Prior to discontinuance of hedge accounting, the fair value of these commodity derivative instruments was recognized in accumulated other comprehensive loss within Partners’ Capital on the Partnership’s consolidated balance sheet and reclassified to the Partnership’s consolidated statements of operations at the time the originally hedged physical transactions affect earnings.

Intangible Assets

APL has recorded intangible assets with finite lives in connection with certain consummated acquisitions. The following table reflects the components of intangible assets being amortized at December 31, 2009 and 2008 (in thousands):


	December 31,						Estimated Useful Lives In Years
	2009			2008			Estimated Useful Lives In Years
Gross Carrying Amount:
Customer contracts	$	12,810		$	12,810		8
Customer relationships		222,572			222,572		7–20

	$	235,382		$	235,382

Accumulated Amortization:
Customer contracts	$	(7,397	)	$	(5,806	)
Customer relationships		(59,894	)		(35,929	)

	$	(67,291	)	$	(41,735	)

Net Carrying Amount:
Customer contracts	$	5,413		$	7,004
Customer relationships		162,678			186,643

	$	168,091		$	193,647

APL amortizes intangible assets with finite useful lives over their estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset must be amortized over the best estimate of its useful life. At a minimum, APL will assess the useful lives of all intangible assets on an annual basis to determine if adjustments are required. The estimated useful life for APL’s customer contract intangible assets is based upon the approximate average length of customer contracts in existence and expected renewals at the date of acquisition. The estimated useful life for APL’s customer relationship intangible assets is based upon the estimated average length of non-contracted customer relationships in existence at the date of acquisition, adjusted for APL management’s estimate of whether these individual relationships will continue in excess or less than the average length. Amortization expense on intangible assets was $25.6 million, $25.6 million and $12.1 million for the years ended December 31, 2009, 2008 and 2007, respectively. Amortization expense related to APL’s intangible assets is estimated to be as follows for each of the next five calendar years: 2010 to 2012 - $25.6 million; 2013 - $24.5 million; 2014 - $20.4 million.

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Goodwill

The changes in the carrying amount of goodwill for the years ended December 31, 2009, 2008 and 2007 were as follows (in thousands):


	Years Ended December 31,
	2009		2008⁽¹⁾			2007⁽¹⁾
Balance, beginning of year	$	—	$	709,283		$	63,441
Purchase price allocation adjustment – Chaney Dell and Midkiff/Benedum acquisition		—		—			645,842
Post-closing purchase price adjustment with seller and purchase price allocation adjustment - Chaney Dell and Midkiff/Benedum acquisition		—		(2,217	)		—
Recovery of state sales tax initially paid on transaction – Chaney Dell and Midkiff/Benedum acquisition		—		(30,206	)		—
Impairment loss		—		(676,860	)		—

Balance, end of year	$	—	$	—		$	709,283

⁽¹⁾	Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system (see Note 4).

APL tests its goodwill for impairment at each year end by comparing its reporting unit estimated fair values to carrying values. Because quoted market prices for its reporting units are not available, APL management must apply judgment in determining the estimated fair value of these reporting units. APL management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. A key component of these fair value determinations is a reconciliation of the sum of these net present value calculations to APL’s market capitalization. The principles of prevailing accounting literature and its interpretations acknowledge that the observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity’s individual equity securities. In most industries, including APL’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above net present value calculations have been determined, APL also adds a control premium to the calculations. This control premium is subject to judgment and is based on observed acquisitions in APL’s industry. The resultant fair values calculated for the reporting units are then compared to observable metrics on large mergers and acquisitions in APL’s industry to determine whether those valuations appear reasonable in management’s judgment.

As a result of its impairment evaluation at December 31, 2008, APL recognized a $676.9 million non-cash impairment charge within the Partnership’s consolidated statements of operations for the year ended December 31, 2008. The goodwill impairment resulted from the reduction in APL’s estimated fair value of reporting units in comparison to their carrying amounts at December 31, 2008. APL’s estimated fair value of reporting units was impacted by many factors, including the significant deterioration of commodity prices and global economic conditions during the fourth quarter of 2008. There were no goodwill impairments recognized by the Partnership during the years ended December 31, 2009 and 2007.

105

APL had adjusted its preliminary purchase price allocation for the acquisition of its Chaney Dell and Midkiff/Benedum systems since its July 2007 acquisition date by adjusting the estimated amounts allocated to goodwill, intangible assets and property, plant and equipment. Also, in April 2008, APL received a $30.2 million cash reimbursement for sales tax initially paid on its transaction to acquire the Chaney Dell and Midkiff/Benedum systems in July 2007. The $30.2 million was initially capitalized as an acquisition cost and allocated to the assets acquired, including goodwill, based upon their estimated fair values at the date of acquisition. Based upon the reimbursement of the sales tax paid in April 2008, the Partnership reduced goodwill recognized in connection with the acquisition (see Note 9).

Income Taxes

The Partnership is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income (loss) reported in the accompanying consolidated financial statements. Certain corporate subsidiaries of the Partnership are subject to federal and state income tax. The federal and state income taxes related to the Partnership and these corporate subsidiaries were immaterial to the consolidated financial statements and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for in the accompanying consolidated financial statements.

The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its consolidated financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. The Partnership has not recognized any potential interest or penalties in its consolidated financial statements as of December 31, 2009.

The Partnership files income tax returns in the U.S. federal and various state jurisdictions. The Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2006. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2009.

Stock-Based Compensation

All share-based payments to employees, including grants of employee stock options, are to be recognized in the financial statements based on their fair values. Compensation expense associated with share-based payments is recognized within general and administrative expenses on the Partnership’s statement of operations from the date of the grant through the date of vesting amortized on a straight-line method. Generally, no expense is recorded for awards that do not vest due to forfeiture.

Net Income (Loss) Per Common Unit

Basic net income (loss) attributable to common limited partners per unit is computed by dividing net income (loss) attributable to common limited partners, which is determined after the deduction of net income attributable to participating securities, if applicable, by the weighted average number of common limited partner units outstanding during the period.

Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of EPU pursuant to the two-class method. The Partnership’s phantom unit awards, which consist of common units issuable under the terms of its long-term incentive plan and incentive compensation agreements (see Note 17), contain non-forfeitable rights to distribution equivalents of the Partnership. The participation rights result in a

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non-contingent transfer of value each time the Partnership declares a distribution or distribution equivalent right during the award’s vesting period. However, unless the contractual terms of the participating securities require the holders to share in the losses of the entity, net loss is not allocated to the participating securities. As such, the net income (loss) utilized in the calculation of net income (loss) per unit must be after the allocation of only net income to the phantom units on a pro-rata basis. All prior period EPU computations have been retroactively adjusted to reflect the adoption of accounting standards summarized above related to EPU that were effective January 1, 2009.

The following is a reconciliation of net income (loss) from continuing operations and net income from discontinued operations allocated to the common limited partners for purposes of calculating net income (loss) attributable to common limited partners per unit (in thousands, except per unit data):


	Years Ended December 31,
	2009			2008⁽¹⁾			2007⁽¹⁾
Continuing operations:
Net income (loss)	$	(4,536	)	$	(630,655	)	$	(175,858	)
(Income) loss attributable to non-controlling interests		(3,176	)		22,781			(3,940	)
(Income) loss attributable to non-controlling interests – Atlas Pipeline Partners, L.P.		2,878			531,749			160,621

Net income (loss) attributable to common limited partners		(4,834	)		(76,125	)		(19,177	)
Less: Net income attributable to participating securities – phantom units⁽²⁾		—			—			—

Net income (loss) utilized in the calculation of net income (loss) from continuing operations attributable to common limited partners per unit	$	(4,834	)	$	(76,125	)	$	(19,177	)

Discontinued operations:
Net income	$	62,495		$	20,546		$	30,830
Income attributable to non-controlling interests – Atlas Pipeline Partners, L.P.		(53,627	)		(18,075	)		(27,300	)

Net income utilized in the calculation of net income from discontinued operations attributable to common limited partners per unit	$	8,868		$	2,471		$	3,530

⁽¹⁾	Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system (see Note 4).

⁽²⁾

For the years ended December 31, 2009, 2008 and 2007, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 185,000, 438,000 and 357,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity.

Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners, less income allocable to participating securities, by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of unit option awards, as calculated by the treasury stock method. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of the Partnership’s long-term incentive plan (see Note 17). The following table sets forth the reconciliation of the Partnership’s weighted average number of common limited partner units used to compute basic net income (loss) attributable to common limited partners per unit with those used to compute diluted net income (loss) attributable to common limited partners per unit (in thousands):


	Years Ended December 31,
	2009	2008	2007
Weighted average number of common limited partner units – basic	27,663	27,511	23,805
Add: effect of dilutive unit incentive awards⁽¹⁾	—	—	—

Weighted average number of common limited partner units – diluted	27,663	27,511	23,805

⁽¹⁾

For the years ended December 31, 2009, 2008 and 2007 approximately 1.0 million unit options, 1.2 million unit options and 1.2 million option units, respectively, were excluded 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.

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Non-Controlling Interest in Atlas Pipeline Partners, L.P.

The non-controlling interest in APL on the Partnership’s consolidated financial statements reflects the outside ownership interests in APL, which was 86.8% and 84.1% at December 31, 2009 and 2008, respectively. The non-controlling interests in APL in the Partnership’s consolidated statements of operations is calculated quarterly by multiplying (i) the weighted average APL common limited partner units outstanding held by non-affiliated third parties by (ii) the consolidated net income (loss) per APL common limited partner unit for the respective quarter. The net income (loss) per APL common limited partner unit is calculated by dividing the net income (loss) allocated to common limited partners, after the allocation of net income (loss) to the Partnership as general partner in accordance with the terms of the APL partnership agreement, by the total weighted average APL common limited partner units outstanding. The Partnership’s general partner interest in the net income (loss) of APL is based upon its 2% general partner ownership interest and incentive distributions, with a priority allocation of APL’s net income (loss) in an amount equal to the incentive distributions (see Note 8), in accordance with the APL partnership agreement, and the remaining APL net income (loss) allocated with respect to the general partner’s and APL’s limited partners’ ownership interests. The non-controlling interest in APL on the Partnership’s consolidated balance sheets principally reflects the sum of the allocation of APL’s consolidated net income (loss) to the non-controlling interest in APL and the contributed capital of non-controlling interests through the sale of limited partner units in APL, partially offset by APL quarterly cash distributions to the non-controlling interest owners.

During the year ended December 31, 2009, APL issued 348,620 common units to certain key employees covered under incentive compensation agreements (see Note 17). Additionally, APL issued 1,465,653 of its common units upon conversion of 5,000 preferred units previously held by Sunlight Capital Partners, LLC (see Note 7). In addition, APL executed a private placement of 2,689,765 of its common units (see Note 6). As a result of these transactions, the Partnership’s ownership percentage in APL, including its 2% interest as general partner, was reduced. Pursuant to Securities and Exchange Commission Staff Accounting Bulletin No. 51, “Accounting for Sales of Stock by a Subsidiary” (“SAB No. 51”), during the year ended December 31, 2009, the Partnership recorded a $5.2 million increase to non-controlling interest in APL with a corresponding decrease to its limited Partners’ Capital, which represents the difference between the Partnership’s share of the underlying book value in APL before and after the respective common unit transactions, on its consolidated balance sheet.

During the year ended December 31, 2008, APL issued 56,227 common limited partner units under its Long-Term Incentive Plan (see Note 17). Additionally, during June 2008, the Partnership purchased 278,000, or 3.9%, of the aggregate 7,140,000 APL common limited partner units sold through a public offering and private placement (see Note 6). As a result of these transactions, the Partnership’s ownership percentage in APL, including its 2% interest as general partner, was reduced to 14.3% from 15.8%. Pursuant

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to Securities and Exchange Commission Staff Accounting Bulletin No. 51, “Accounting for Sales of Stock by a Subsidiary” (“SAB No. 51”), during the year ended December 31, 2008, the Partnership recorded a $3.4 million increase to its limited Partners’ Capital with a corresponding decrease to non-controlling interest in APL, which represents the difference between the Partnership’s share of the underlying book value in APL before and after the respective common unit transactions, on its consolidated balance sheet.

APL’s preferred units are reflected on the Partnership’s consolidated balance sheet as non-controlling interest in APL of $15.0 million and $27.9 million at December 31, 2009 and 2008, respectively.

Environmental Matters

APL’s operations are subject to various federal, state and local laws and regulations relating to the protection of the environment. APL has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures, including legislation related to greenhouse gas emissions. APL accounts for environmental contingencies in accordance with prevailing accounting literature. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. At this time, APL is unable to assess the timing and/or effect of potential cap and trade programs or carbon taxes related to greenhouse gas emissions. APL maintains insurance which may cover in whole or in part certain environmental expenditures. At December 31, 2009 and 2008, the Partnership and APL had no environmental matters requiring specific disclosure or requiring the recognition of a liability.

Segment Information

The Partnership’s assets primarily consist of its ownership interests in APL. APL has two reportable segments. The Mid-Continent segment consists of APL’s Chaney Dell, Elk City/Sweetwater, Velma and Midkiff/Benedum operations, which are comprised of natural gas gathering and processing assets located in Oklahoma, Texas, and southern Kansas. The Appalachia segment is comprised of natural gas transportation, gathering and processing assets located in the Appalachian Basin area (“Appalachia”) of eastern Ohio, western New York, western Pennsylvania and northeastern Tennessee. Effective May 31, 2009, the Appalachia operations were principally conducted through APL’s gathering system in Tennessee and its 49% ownership interest in Laurel Mountain, a joint venture to which APL contributed its natural gas transportation, gathering and processing assets located in northeastern Appalachia. APL recognizes its ownership interest in Laurel Mountain under the equity method of accounting. Mid-Continent revenues are primarily derived from the sale of Residue Gas and NGLs and gathering of natural gas. Appalachia revenues are principally based on contractual arrangements with Atlas Energy and its affiliates. These reportable segments reflect the way APL manages its operations.

Revenue Recognition

APL’s revenue primarily consists of the fees earned from its gathering and processing operations. Under certain agreements, APL purchases natural gas from producers and moves it into receipt points on its pipeline systems, and then sells the natural gas, or produced natural gas liquids (“NGLs”), if any, off of delivery points on its systems. Under other agreements, APL gathers natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with the physical sale of natural gas is recognized upon physical delivery of the natural gas. In connection with its gathering and processing operations, APL enters into the following types of contractual relationships with its producers and shippers:

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dependent on the value of the natural gas. APL also is paid a separate compression fee on many of its systems. The fee is dependent upon the volume of gas flowing through APL’s compressors and the quantity of compression stages utilized to gather the gas.

Keep-Whole Contracts. These contracts require APL, as the processor and gatherer, to gather or purchase raw natural gas at current market rates. The volume of gas gathered or purchased is based on the measured volume at an agreed upon location (generally at the wellhead). The volume of gas redelivered or sold at the tailgate of APL’s processing facility will be lower than the volume purchased at the wellhead primarily due to BTUs extracted when processed through a plant. Therefore, APL bears the economic risk (the “processing margin risk”) that (i) the volume of Residue Gas available for redelivery to the producer may be less than APL received from the producer; or (ii) the aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the amount that APL paid for the unprocessed natural gas (plus, in either case, the cost of the natural gas APL must purchase to return an equivalent volume, measured in BTU content, to producers to keep them whole with respect to their original measured volume). In order to help mitigate the risk associated with Keep-Whole contracts APL generally imposes a fee to gather the gas that is settled under this arrangement. Also, because the natural gas volumes contracted under Keep-Whole agreements is often lower in BTU content and thus, can meet downstream pipeline specifications without being processed, the natural gas can be bypassed around the processing plants on these systems and delivered directly into downstream pipelines during periods of margin risk.

APL accrues unbilled revenue 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 volumetric data from APL’s records and management estimates of the related gathering and compression fees which are, in turn, based upon applicable product prices (see “–Use of Estimates” accounting policy for further description). APL had unbilled revenues at December 31, 2009 and 2008 of $65.4 million and $50.1 million, respectively, which are included in accounts receivable and accounts receivable-affiliates within the Partnership’s consolidated balance sheets.

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources. These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” or “OCI” and for the Partnership only include changes in the fair value of unsettled APL derivative contracts which are accounted for as cash flow hedges (see Note 12).

Recently Adopted Accounting Standards

In June 2009, the FASB issued Accounting Standards Update 2009-01, “Topic 105 – Generally Acceptable Accounting Principles Amendments Based on Statement of Financial Accounting Standards No. 168 – The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (“Update 2009-01”). Update 2009-01 establishes the FASB Accounting Standards Codification (“ASC”) as the single source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities. The ASC supersedes all existing non-Securities and Exchange Commission accounting and reporting standards. Following the ASC, the FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. Instead,

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the FASB will issue Accounting Standards Updates, which will serve only to update the ASC. The ASC is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Partnership adopted the requirements of Update 2009-01 to its financial statements on September 30, 2009 and it did not have a material impact on its financial statement disclosures.

In May 2009, the FASB issued ASC 855-10, “Subsequent Events” (“ASC 855-10”). ASC 855-10 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The provisions require management of a reporting entity to evaluate events or transactions that may occur after the balance sheet date for potential recognition or disclosure in the financial statements and provides guidance for disclosures that an entity should make about those events. ASC 855-10 is effective for interim or annual financial periods ending after June 15, 2009 and shall be applied prospectively. The Partnership adopted the requirements of this standard on June 30, 2009 and it did not have a material impact to its financial position or results of operations or related disclosures. The adoption of these provisions does not change the Partnership’s current practices with respect to evaluating, recording and disclosing subsequent events.

In June 2008, the FASB issued ASC 260-10-45-61A, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“ASC 260-10-45-61A”). ASC 260-10-45-61A applies to the calculation of EPU described in previous guidance, for share-based payment awards with rights to dividends or dividend equivalents. It states that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of EPU pursuant to the two-class method. ASC 260-10-45-61A is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption was prohibited. The Partnership adopted the requirements on January 1, 2009 and its adoption did not have a material impact on its financial position and results of operations.

In April 2008, the FASB issued ASC 350-30-65-1, “Determination of Useful Life of Intangible Assets” (“ASC 350-30-65-1”). ASC 350-30-65-1 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under previous guidance. The intent of ASC 350-30-65-1 is to improve the consistency between the useful life of a recognized intangible asset and the period of expected cash flows used to measure the fair value of the asset. The Partnership adopted the requirements of ASC 350-30-65-1 on January 1, 2009 and its adoption did not have a material impact on its financial position and results of operations.

In March 2008, the FASB issued ASC 260-10-55-103 through 55-110, “Application of the Two-Class Method” (“ASC 260-10-55-103”), which considers whether the incentive distributions of a master limited partnership represent a participating security when considered in the calculation of earnings per unit under the two-class method. ASC 260-10-55-103 considers whether the partnership agreement contains any contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive distribution rights’ share of currently designated available cash for distributions as defined under the partnership agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. The Partnership’s adoption of ASC 260-10-55-103 on January 1, 2009 impacted its presentation of net income (loss) per common limited partner unit as the Partnership previously presented net income (loss) per common limited partner unit as though all earnings were distributed each quarterly period (see “—Net Income (Loss) Per Common Unit”). The Partnership adopted the requirements of ASC 260-10-55-103 on January 1, 2009 and its adoption did not have a material impact on its financial position and results of operations.

In March 2008, the FASB issued ASC 815-10-50-1, “Disclosures about Derivative Instruments and Hedging Activities” (“ASC 815-10-50-1”), to require enhanced disclosure about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how

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derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The Partnership adopted the requirements of this section of ASC 815-10-50-1 on January 1, 2009 and it did not have a material impact on its financial position or results of operations (see Note 12).

In December 2007, the FASB issued ASC 810-10-65-1, “Non-controlling Interests in Consolidated Financial Statements” (“ASC 810-10-65-1”). ASC 810-10-65-1 establishes accounting and reporting standards for the non-controlling interest (minority interest) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. It also requires consolidated net income to be reported and disclosed on the face of the consolidated statements of operations at amounts that include the amounts attributable to both the parent and the non-controlling interest. Additionally, ASC 810-10-65-1 establishes a single method of accounting for changes in a parent’s ownership interest in a subsidiary that does not result in deconsolidation and that the parent recognize a gain or loss in net income when a subsidiary is deconsolidated and adjust its remaining investment, if any, at fair value. The Partnership adopted the requirements of ASC 810-10-65-1on January 1, 2009 and adjusted its presentation of its financial position and results of operations. Prior period financial position and results of operations have been adjusted retrospectively to conform to these provisions.

In December 2007, the FASB issued ASC 805, “Business Combinations” (“ASC 805”). ASC 805 retains the fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. ASC 805 requires an acquirer to recognize the assets acquired, liabilities assumed, and any non-controlling interest in the acquiree at the acquisition date, at their fair values as of that date, with specified limited exceptions. Additionally, it requires costs incurred in connection with an acquisition be expensed as incurred. Restructuring costs, if any, are to be recognized separately from the acquisition. The acquirer in a business combination achieved in stages must also recognize the identifiable assets and liabilities, as well as the non-controlling interests in the acquiree, at the full amounts of their fair values. The Partnership adopted these requirements on January 1, 2009 and it did not have a material impact on its financial position and results of operations.

Recently Issued Accounting Standards

In January 2010, the FASB issued Accounting Standards Update 2010-06, “Fair Value Measurements and Disclosures (Topic 820) – Improving Disclosures about Fair Value Measurements” (“Update 2010-06”). Update 2010-06 amends Subtopic 820-10, “Fair Value Measurements and Disclosures – Overall” and provides enhanced disclosure requirements for activity in Levels 1, 2 and 3 fair value measurements. The amendment requires significant transfers in and out of Levels 1 and 2 fair value measurements to be reported separately and the reasons for such transfers to be disclosed. Update 2010-06 also requires information regarding purchases, sales, issuances, and settlements to be disclosed separately on a gross basis in the reconciliation of fair value measurements using unobservable inputs for all activity in Level 3 fair value measurements. Additionally, the amendment clarifies that fair value measurement for each class of assets and liabilities must be disclosed as well as disclosures pertaining to the inputs and valuation techniques for both recurring and nonrecurring fair value measurements in Levels 2 and 3. These requirements are effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those requirements will be effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. The Partnership will apply these requirements upon its adoption on January 1, 2010 and does not expect it to have a material impact on its financial position, results of operations or related disclosures.

NOTE 3 – APL INVESTMENT IN JOINT VENTURE

On May 31, 2009, APL and subsidiaries of Williams completed the formation of Laurel Mountain, a joint venture which owns and operates APL’s Appalachia natural gas gathering system, excluding APL’s

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northeastern Tennessee operations. Williams contributed cash of $100.0 million to the joint venture (of which APL received approximately $87.8 million, net of working capital adjustments) and a note receivable of $25.5 million. APL contributed its Appalachia natural gas gathering system and retained a 49% ownership interest in Laurel Mountain. APL is also entitled to preferred distribution rights relating to all payments on the note receivable. Williams obtained the remaining 51% ownership interest in Laurel Mountain.

Upon completion of the transaction, APL recognized its 49% ownership interest in Laurel Mountain as an investment in joint venture on the Partnership’s consolidated balance sheet at fair value. During the year ended December 31, 2009, the Partnership recognized a gain on sale of $108.9 million, including $54.2 million associated with the revaluation of APL’s investment in Laurel Mountain to fair value. APL used the net proceeds from the transaction to reduce borrowings under its senior secured credit facility (see Note 14). In addition, Atlas Energy Resources sold two natural gas processing plants and associated pipelines located in southwestern Pennsylvania to Laurel Mountain for $10.0 million. In connection with the formation of Laurel Mountain, Laurel Mountain entered into natural gas gathering agreements with Atlas Energy Resources, which superseded the existing natural gas gathering agreements and omnibus agreement between APL and Atlas Energy Resources. Under the new gas gathering agreement, Atlas Energy Resources is obligated to pay a gathering fee that is generally the same as the gathering fee required under the terminated agreements, the greater of $0.35 per MCF or 16% of the realized sales price (except that a lower fee applies with respect to specific wells subject to certain existing contracts or in the event Laurel Mountain fails to perform specified obligations). APL has accounted for its ownership interest in Laurel Mountain under the equity method of accounting, with recognition of its ownership interest in the income of Laurel Mountain as equity income on the Partnership’s consolidated statements of operations. As of the year ended December 31, 2009, APL has utilized $1.7 million of the $25.5 million note receivable to make a capital contribution to Laurel Mountain.

NOTE 4 – DISCONTINUED OPERATIONS

On May 4, 2009, APL completed the sale of its 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. APL used the net proceeds from the transaction to reduce borrowings under its senior secured term loan and revolving credit facility (see Note 14). The Partnership accounted for the sale of the NOARK system assets as discontinued operations within its consolidated financial statements and recorded a gain of $51.1 million on the sale of APL’s NOARK assets within income from discontinued operations on its consolidated statements of operations during the year ended December 31, 2009. The following table summarizes the components included within income from discontinued operations on the Partnership’s consolidated statements of operations (in thousands):


	Year Ended December 31,
	2009			2008			2007
Total revenue and other income (loss), net	$	21,274		$	62,423		$	56,587
Total costs and expenses		(9,857	)		(41,877	)		(25,757	)

Earnings of discontinued operations	$	11,417		$	20,546		$	30,830

During the year ended December 31, 2008, the Partnership recognized impairment charges totaling $21.6 million within discontinued operations on its consolidated statements of operations in connection with a write-off of costs related to APL’s NOARK pipeline expansion project. The costs incurred consisted of preliminary construction and engineering costs incurred as well as a vendor deposit for the manufacture of pipeline which expired in accordance with APL’s contractual arrangement.

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The following table summarizes the components included within total assets and liabilities of discontinued operations within the Partnership’s consolidated balance sheet for the year ended December 31, 2008 (in thousands):


	December 31, 2008
Cash and cash equivalents	$	75
Accounts receivable		12,365
Prepaid expenses and other		1,001

Total current assets of discontinued operations		13,441
Property, plant and equipment, net		241,926
Other assets, net		239

Total assets of discontinued operations	$	255,606

Accounts payable	$	4,120
Accrued liabilities		5,892
Accrued producer liabilities		560

Total current liabilities of discontinued operations	$	10,572

NOTE 5 – ATLAS PIPELINE HOLDINGS EQUITY OFFERINGS

On June 1, 2009, a newly created, wholly-owned subsidiary of the Partnership, Atlas Pipeline Holdings II, LLC (“AHD Sub”), issued $15.0 million of $1,000 par value 12.0% Class B preferred equity (“AHD Sub Preferred Units”) to APL for cash pursuant to a certificate of designation. The Partnership utilized the net proceeds from the issuance to reduce borrowings under its senior secured credit facility (see Note 14). Distributions on the AHD Sub Preferred Units are payable quarterly on the same date as the distribution payment date for the Partnership’s common units. Distributions on the AHD Sub Preferred Units will initially be paid in cash or by increasing the amount of the AHD Sub Preferred Unit equity by the amount of the distribution. However, under the terms of the certificate of designation, prior to the repayment of all outstanding borrowings under the Partnership’s credit facility (see Note 14), AHD Sub may only pay a cash distribution on the AHD Sub Preferred Units if the Partnership has received distributions on APL’s 12.0% Class B preferred units (see Note 7). After the Partnership has repaid all outstanding borrowings under its credit facility, all subsequent distributions declared by AHD Sub on the AHD Sub Preferred Units shall be paid in cash. AHD Sub has the option of redeeming some or all of the AHD Sub Preferred Units, subject to certain limitations under the terms of the certificate of designation. As APL owns all of the outstanding AHD Sub Preferred Units in an amount equal to the Class B Preferred Units of APL that the Partnership owns (see Note 7), the amounts eliminate in consolidation of the Partnership’s consolidated balance sheet as of December 31, 2009.

In June 2008, the Partnership sold 308,109 common units through a private placement to Atlas Energy at a price of $32.50 per unit, for net proceeds of approximately $10.0 million. The Partnership utilized the net proceeds from the sale to purchase 278,000 common units of APL (see Note 6), which in turn utilized the proceeds to partially fund the early termination of certain derivative agreements (see Note 12). Following the Partnership’s private placement, Atlas Energy had a 64.4% ownership interest in the Partnership.

In July 2007, the Partnership sold 6,249,995 common units through a private placement to investors at a negotiated purchase price of $27.00 per unit, yielding gross proceeds of approximately $168.8 million (or net proceeds of $167.0 million, after underwriting fees and other transaction costs). The Partnership utilized the net proceeds from the sale to purchase 3,835,227 common units of APL (see Note 6), which in turn utilized the net proceeds to partially fund the acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see Note 11). The common units issued were subsequently registered with the Securities and Exchange Commission in November 2007.

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NOTE 6 – APL COMMON UNIT EQUITY OFFERINGS

In August 2009, APL 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. APL also received a capital contribution from the Partnership of $0.4 million for the Partnership to maintain its 2.0% general partner interest in APL. In addition, APL issued warrants granting investors in its 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. APL utilized the net proceeds from the common unit offering to repay a portion of its indebtedness under its senior secured term loan (see Note 14), and made similar repayments with net proceeds from exercises of the warrants. In January 2010, APL amended the warrants to purchase 2,689,765 common units and all warrants were exercised (see Note 22).

In June 2008, APL sold 5,750,000 common units in a public offering at a price of $37.52 per unit, yielding net proceeds of approximately $206.6 million. Also in June 2008, APL sold 1,112,000 common units to Atlas Energy and 278,000 common units to the Partnership in a private placement at a net price of $36.02 per unit, resulting in net proceeds of approximately $50.1 million. APL also received a capital contribution from the Partnership of $5.4 million for it to maintain its 2.0% general partner interest in APL. APL utilized the net proceeds from both sales and the capital contribution to fund the early termination of certain derivative agreements (see Note 12).

In July 2007, APL sold 25,568,175 common units through a private placement to investors at a negotiated purchase price of $44.00 per unit, yielding net proceeds of approximately $1.125 billion. Of the 25,568,175 common units sold by APL, 3,835,227 common units were purchased by the Partnership for $168.8 million. APL also received a capital contribution from the Partnership of $23.1 million for the Partnership to maintain its 2.0% general partner interest in APL. The Partnership funded this capital contribution, underwriting fees and other transaction costs related to its private placement of common units through borrowings under its revolving credit facility of $25.0 million. APL utilized the net proceeds from the sale to partially fund the acquisition of control of the Chaney Dell natural gas gathering system and processing plants located in Oklahoma and a 72.8% ownership interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas (see Note 9). The common units APL issued were subsequently registered with the Securities and Exchange Commission in November 2007.

NOTE 7 – APL PREFERRED UNIT EQUITY OFFERINGS

APL Class A Preferred Units

In April 2007, APL and Sunlight Capital Partners, LLC (“Sunlight Capital”), an affiliate of Elliott & Associates, agreed to amend the terms of the then-outstanding 40,000 cumulative convertible preferred units (“APL Class A Preferred Units”) effective as of that date. The terms of the APL Class A Preferred Units were amended to entitle Sunlight Capital to receive dividends of 6.5% per annum commencing in March 2008 and to be convertible, at Sunlight Capital’s option, into common units commencing May 8, 2008 at a conversion price equal to the lesser of $43.00 or 95% of the market price of APL’s common units as of the date of the notice of conversion. APL could elect to pay cash rather than issue common units in satisfaction

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of a conversion request. APL had the right to call the APL Class A Preferred Units at a specified premium. The applicable redemption price under the amended agreement was increased to $53.22. If not converted into APL common units or redeemed prior to the second anniversary of the conversion commencement date, the APL Class A Preferred Units would automatically be converted into APL’s common units in accordance with the agreement. In consideration of Sunlight Capital’s consent to the amendment of the APL Class A Preferred Units, APL issued $8.5 million of its 8.125% senior unsecured notes due 2015 to Sunlight Capital. APL recorded the senior unsecured notes issued as long-term debt and a preferred unit dividend within Partners’ Capital on its consolidated balance sheet and, during the year ended December 31, 2007, reduced net income (loss) attributable to common limited partners and the general partner by $3.8 million of this amount, which was the portion deemed to be attributable to the concessions of the common limited partners and the general partner to the APL Class A preferred unitholder, on its consolidated statements of operations.

In December 2008, APL redeemed 10,000 of the APL Class A Preferred Units for $10.0 million in cash under the terms of the agreement. The redemption was classified as a reduction of non-controlling interest in APL within the Partnership’s consolidated balance sheet. APL’s 30,000 outstanding APL Class A preferred limited partner units were convertible into approximately 5,263,158 common limited partner units at December 31, 2008, which is based upon the market value of its common units and subject to provisions and limitations within the agreement between the parties, with an estimated fair value of approximately $31.6 million based upon the market value of its common units as of that date.

In January, 2009, APL and Sunlight Capital agreed to amend certain terms of the APL Class A Preferred Units. The amendment (a) increased the dividend yield from 6.5% to 12.0% per annum, effective January 1, 2009, (b) established a new conversion commencement date on the outstanding APL Class A Preferred Units of April 1, 2009, (c) established Sunlight Capital’s new conversion option price of $22.00, enabling the APL Class A Preferred Units to be converted at the lesser of $22.00 or 95% of the market value of APL’s common units, and (d) established a new price for APL’s call redemption right of $27.25.

The amendment to the preferred units certificate of designation also required that APL issue Sunlight Capital $15.0 million of its 8.125% senior unsecured notes due 2015 (see Note 14) to redeem 10,000 APL Class A Preferred Units. Management of APL estimated that the fair value of the $15.0 million 8.125% APL senior unsecured notes issued to redeem the APL Class A Preferred Units was approximately $10.0 million at the date of redemption based upon the market price of the publicly-traded APL senior notes. As such, APL recorded the redemption by recognizing a $10.0 million reduction of APL Class A Preferred equity within Partners’ Capital, $15.0 million of additional long-term debt for the face value of the senior unsecured notes issued, and a $5.0 million discount on the issuance of the APL senior unsecured notes which is presented as a reduction of long-term debt on the Partnership’s consolidated balance sheet. The discount recognized upon issuance of the APL senior unsecured notes will be amortized to interest expense within the Partnership’s consolidated statements of operations over the term of the notes based upon the effective interest rate method.

The amendment to the preferred units certificate of designation also required that (a) APL redeem 10,000 of the APL Class A Preferred Units for cash at the liquidation value on April 1, 2009 and (b) that if Sunlight Capital made a conversion request of the remaining 10,000 APL Class A Preferred Units between April 1, 2009 and June 1, 2009, APL had the option of redeeming the APL Class A Preferred Units for cash at the stipulated liquidation value or converting the APL Class A Preferred Units into its common limited partner units at the stipulated conversion price. If Sunlight Capital made a conversion request subsequent to June 1, 2009, 5,000 of the 10,000 APL Class A Preferred Units would have been required to be redeemed in cash, while APL had the option of redeeming the remaining 5,000 APL Class A Preferred Units in cash or converting the preferred units into its common limited partner units.

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Sunlight prior to APL’s redemption. On April 13, 2009, APL converted 5,000 of the APL Class A Preferred Units into 1,465,653 Partnership common units in accordance with the terms of the amended preferred units’ certificate of designation. APL reclassified $5.0 million from Class A preferred limited partner equity to common limited partner equity within Partners’ Capital when these preferred units were converted into common limited partner units. On May 5, 2009, APL redeemed the remaining 5,000 Class A Preferred Units held by Sunlight Capital for cash at the liquidation value of $1,000 per unit, or $5.0 million, pursuant to the terms of the amended preferred units certificate of designation. Additionally, on May 5, 2009, APL paid Sunlight a preferred dividend of $0.2 million, representing the quarterly dividend on the 5,000 APL Class A Preferred Units held by Sunlight prior to APL’s redemption.

Dividends previously paid on the APL Class A Preferred Units and the premium paid upon their redemption, were recognized as a reduction to APL’s net income (loss) in determining net income (loss) attributable to common unitholders and us.

In accordance with Securities and Exchange Commission Staff Accounting Bulletin No. 68, “Increasing Rate Preferred Stock,” the initial issuances of the 40,000 APL Class A Preferred Units were recorded on the consolidated balance sheet at the amount of net proceeds received less an imputed dividend cost. As a result of an amendment to the preferred units certificate of designation in March 2007, APL, in lieu of dividend payments to Sunlight Capital, recognized an imputed dividend cost of $2.5 million that was amortized over a twelve-month period commencing March 2007 and was based upon the present value of the net proceeds received using the then 6.5% stated dividend yield. During the twelve months ended December 31, 2008, APL amortized the remaining $0.5 million of this imputed dividend cost, which is presented as an additional adjustment of net income (loss) to determine net income (loss) attributable to common limited partners and the general partner on APL’s consolidated statements of operations for the year ended December 31, 2008.

APL recognized $0.4 million and $1.8 million of preferred dividend cost for the years ended December 31, 2009 and 2008, respectively, for dividends paid to the APL Class A preferred units, which is presented as a reduction of net income (loss) to determine net income (loss) attributable to common limited partners and the general partner on APL’s consolidated statements of operations.

APL Class B Preferred Units

In December 2008, APL sold 10,000 newly-created Class B Preferred Units to the Partnership for cash consideration of $1,000 per APL Class B Preferred Unit (the “Face Value”) pursuant to a certificate of designation (the “Class B Preferred Units Certificate of Designation”). On March 30, 2009, the Partnership, pursuant to rights within the Class B Preferred Unit Purchase Agreement, purchased an additional 5,000 Class B Preferred Units at Face Value for net cost of $5.0 million. APL used the proceeds from the sale of the Class B Preferred Units for general partnership purposes. As holders of the APL Class B Preferred Units, the Partnership will receive distributions of 12.0% per annum, paid quarterly on the same date as the distribution payment date for APL common units. The record date of determination for holders entitled to receive distributions of the APL Class B Preferred Units will be the same as the record date of determination for common unit holders entitled to receive quarterly distributions. Additionally, on March 30, 2009, APL and the Partnership agreed to amend the terms of the APL Class B Preferred Units Certificate of Designation to remove the conversion feature, thus the APL Class B Preferred Units are not convertible into APL common units. The amended APL Class B Preferred Units Certificate of Designation also gives APL the right at any time to redeem some or all of the outstanding APL Class B Preferred Units for cash at an amount equal to the APL Class B Preferred Unit Liquidation Value being redeemed, provided that such redemption must be exercised for no less than the lesser of a) 2,500 APL Class B Preferred Units or b) the number of remaining outstanding APL Class B Preferred Units.

The sale of the APL Class B Preferred Units to us was exempt from the registration requirements of the Securities Act of 1933. The Partnership received $0.5 million in preferred dividends for the year ended December 31, 2009.

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NOTE 8 – CASH DISTRIBUTIONS

Atlas Pipeline Holdings Cash Distributions

The Partnership has a cash distribution policy under which it distributes, within 50 days after the end of each quarter, all of its available cash (as defined in the partnership agreement) for that quarter to its common unitholders. Distributions declared by the Partnership for the period from January 1, 2007 through December 31, 2009 were as follows:


Date Cash Distribution Paid	For Quarter Ended	Cash Distribution per Common Limited Partner Unit		Total Cash Distribution to Common Limited Partners
				(in thousands)
February 19, 2007	December 31, 2006	$	0.25	$	5,275
May 18, 2007	March 31, 2007	$	0.25	$	5,275
August 17, 2007	June 30, 2007	$	0.26	$	5,486
November 19, 2007	September 30, 2007	$	0.32	$	8,752

February 19, 2008	December 31, 2007	$	0.34	$	9,299
May 20, 2008	March 31, 2008	$	0.43	$	11,761
August 19, 2008	June 30, 2008	$	0.51	$	14,106
November 19, 2008	September 30, 2008	$	0.51	$	14,106

February 19, 2009	December 31, 2008	$	0.06	$	1,660

There were no cash distributions declared by the Partnership for the quarters ended December 31, 2009, September 30, 2009, June 30, 2009, or March 31, 2009. On June 1, 2009, the Partnership entered into an amendment to its credit facility agreement which, among other changes, prohibit it from paying any cash distributions on its equity while the credit facility is in effect (see Note 14).

APL Cash Distributions

APL is required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its partnership agreement) for that quarter to its common unitholders and the Partnership, as general partner. If APL’s common unit distributions in any quarter exceed specified target levels, the Partnership will receive between 15% and 50% of such distributions in excess of the specified target levels. Common unit and General Partner distributions declared by APL for the period from January 1, 2008 through December 31, 2009 were as follows:


Date Cash Distribution Paid	For Quarter Ended	APL Cash Distribution per Common Limited Partner Unit		Total APL Cash Distribution To Common Limited Partners		Total APL Cash Distribution To the General Partner
				(in thousands)		(in thousands)
February 14, 2007	December 31, 2006	$	0.86	$	11,249	$	4,193
May 15, 2007	March 31, 2007	$	0.86	$	11,249	$	4,193
August 14, 2007	June 30, 2007	$	0.87	$	11,380	$	4,326
November 14, 2007	September 30, 2007	$	0.91	$	35,205	$	4,498

February 14, 2008	December 31, 2007	$	0.93	$	36,051	$	5,092
May 15, 2008	March 31, 2008	$	0.94	$	36,450	$	7,891
August 14, 2008	June 30, 2008	$	0.96	$	44,096	$	9,308
November 14, 2008	September 30, 2008	$	0.96	$	44,105	$	9,312

February 13, 2009	December 31, 2008	$	0.38	$	17,463	$	358
May 15, 2009	March 31, 2009	$	0.15	$	7,149	$	147

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APL did not declare a cash distribution for the quarters ended December 31, September 30 and June 30, 2009. On May 29, 2009, APL entered into an amendment to its senior secured credit facility (see Note 14) which, among other changes, restricted it from paying cash distributions from the time APL entered into the amendment through the end of 2009. Commencing with the quarter ending March 31, 2010, cash distributions can be paid, only if APL’s senior secured leverage ratio meets certain thresholds and APL has minimum liquidity (both as defined in the credit agreement) of at least $50.0 million.

APL is also prohibited by its Limited Partnership Agreement from lending money to Atlas Pipeline GP, the Partnership’s wholly-owned subsidiary, or any of its affiliates. As of December 31, 2009, APL had consolidated restricted net assets of $723.5 million (see Schedule I for Financial Statements of Registrant).

In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems, Atlas Pipeline GP, which holds all of the incentive distribution rights in APL, agreed to allocate a portion of its incentive distribution rights back to APL as set forth in the IDR Adjustment Agreement (see Note 1).

NOTE 9 – PROPERTY, PLANT AND EQUIPMENT

The following is a summary of property, plant and equipment (in thousands):


	December 31,						Estimated Useful Lives in Years
	2009			2008⁽¹⁾			Estimated Useful Lives in Years
Pipelines, processing and compression facilities	$	1,658,282		$	1,707,046		2 – 40
Rights of way		167,048			168,057		20 – 40
Buildings		8,920			8,920		40
Furniture and equipment		9,538			9,279		3 – 7
Other		12,849			13,002		3 – 10

		1,856,637			1,906,304
Less – accumulated depreciation		(172,253	)		(125,293	)

	$	1,684,384		$	1,781,011

⁽¹⁾	Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system (see Note 4).

On July 13, 2009, APL sold a natural gas processing facility and a one-third undivided interest in other associated assets located in its Mid-Continent operating segment for approximately $22.6 million in cash. The facility was sold to Penn Virginia Resource Partners, L.P. (NYSE: PVR), who will provide natural gas volumes to the facility and reimburse APL for its proportionate share of the operating expenses. APL will continue to operate the facility. APL used the proceeds from this transaction to reduce outstanding borrowings under its senior secured credit facility (see Note 14). APL recognized a gain on sale of $2.5 million, which is recorded within gain on asset sales on the Partnership’s consolidated statements of operations.

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NOTE 10 – OTHER ASSETS

The following is a summary of other assets (in thousands):


	December 31,
	2009		2008⁽¹⁾
Deferred finance costs, net of accumulated amortization of $25,752 and $17,575 at December 31, 2009 and 2008, respectively	$	27,404	$	23,818
Long-term pipeline lease prepayment		3,168		—
Security deposits		3,494		1,317

	$	34,066	$	25,135

(1)	Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system (see Note 4).

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreement (see Note 14). During the years ended December 31, 2009 and 2008, APL recorded $2.5 million in each year related to accelerated amortization of deferred financing costs associated with the retirement of a portion of its term loan. Total amortization expense of deferred finance costs for the Partnership and APL was $8.0 million, $5.9 million and $7.4 million for the years ended December 31, 2009, 2008 and 2007, respectively, which is recorded within interest expense on the Partnership’s consolidated statements of operations. Amortization expense related to deferred finance costs is estimated to be as follows for each of the next five calendar years: 2010—$6.3 million; 2011 and 2012—$6.2 million; 2013—$4.4 million; 2014—$1.7 million.

NOTE 11 – ACQUISITIONS

APL’s Chaney Dell and Midkiff/Benedum

In July 2007, APL acquired control of Anadarko’s 100% interest in the Chaney Dell natural gas gathering system and processing plants located in Oklahoma and its 72.8% undivided joint venture interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas (the “Anadarko Assets”). The transaction was accomplished through the formation of two joint venture companies which own the respective systems, to which APL contributed $1.9 billion and Anadarko contributed the Anadarko Assets.

APL funded the purchase price in part from the private placement of 25,568,175 common limited partner units at a negotiated purchase price of $44.00 per unit, generating gross proceeds of $1.125 billion. The Partnership purchased 3,835,227 of the 25,568,175 common limited partner units issued by APL for $168.8 million and funded this through the private placement of 6,249,995 of its common units to investors at a negotiated price of $27.00 per unit, yielding gross proceeds of $168.8 million (or net proceeds of $167.0 million, after underwriting fees and other transaction costs). APL also received a capital contribution from the Partnership of $23.1 million in order for the Partnership to maintain its 2.0% general partner interest in APL. The Partnership funded this capital contribution, underwriting fees and other transaction costs related to its private placement of common units through borrowings under its revolving credit facility of $25.0 million (see Note 12). APL funded the remaining purchase price from $830.0 million of proceeds from a senior secured term loan which matures in July 2014 and borrowings from its senior secured revolving credit facility that matures in July 2013 (see Note 14). Atlas Pipeline GP, which holds all of the incentive distribution rights of APL as General Partner, has also agreed to allocate a portion of its incentive distribution rights per quarter back to APL as set forth in the IDR Adjustment Agreement (see Note 1).

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In connection with this acquisition, APL reached an agreement with Pioneer, which currently holds a 27.2% undivided joint venture interest in the Midkiff/Benedum system, whereby Pioneer had options to buy up to an additional 22% interest in the Midkiff/Benedum system. These options expired on November 2, 2009.

The following table presents the purchase price allocation, including professional fees and other related acquisition costs, to the assets acquired and liabilities assumed in the acquisition, based on their fair values at the date of the acquisition (in thousands):


Accounts receivable	$	745
Prepaid expenses and other		4,587
Property, plant and equipment		1,030,464
Intangible assets – customer relationships		205,312
Goodwill		613,420

Total assets acquired		1,854,528
Accounts payable and accrued liabilities		(1,499	)

Net cash paid for acquisition	$	1,853,029

APL initially recorded goodwill in connection with this acquisition as a result of Chaney Dell’s and Midkiff/Benedum’s significant cash flow and strategic industry position. APL tested its goodwill for impairment at December 31, 2008 and recognized an impairment charge of $676.9 million during the year ended December 31, 2008, which included the amounts recognized in connection with its Chaney Dell and Midkiff/Benedum acquisitions (see “—Goodwill” in Note 2).

In April 2008, APL received a $30.2 million cash reimbursement for state sales tax initially paid on its transaction to acquire the Chaney Dell and Midkiff/Benedum systems. The $30.2 million was initially capitalized as an acquisition cost and allocated to the assets acquired, including goodwill, based upon their estimated fair values at the date of acquisition. Based upon the reimbursement of the sales tax paid in April 2008, APL reduced goodwill recognized in connection with the acquisition. The results of Chaney Dell’s and Midkiff/Benedum’s operations are included within the Partnership’s consolidated financial statements from the date of acquisition.

NOTE 12 – DERIVATIVE INSTRUMENTS

The Partnership and APL use a number of different derivative instruments, principally swaps and options, in connection with its commodity price and interest rate risk management activities. APL enters into financial swap and option instruments to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. The Partnership and APL also enter into financial swap instruments to hedge certain portions of its floating interest rate debt against the variability in market interest rates. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate are sold or interest payments on the underlying debt instrument are due. Under its swap agreements, APL receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not the obligation, to receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period.

During December 2007, APL discontinued hedge accounting for crude oil derivative instruments covering certain forecasted condensate production for 2008 and other future periods, and then documented these derivative instruments to match certain forecasted NGL production for the respective periods. The discontinuation of hedge accounting for these instruments with regard to APL’s condensate production resulted in a $12.6 million non-cash derivative loss recognized within other income (loss), net in the

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Partnership’s consolidated statements of operations and a corresponding decrease in non-controlling interest in APL and accumulated other comprehensive loss in Partners’ Capital (deficit) in the Partnership’s consolidated balance sheet for the year ended December 31, 2007.

On July 1, 2008, APL discontinued hedge accounting for all of its existing commodity derivatives which were qualified as hedges. As such, subsequent changes in fair value of these derivatives are recognized immediately within other income (loss), net in the Partnership’s consolidated statements of operations. The fair value of these commodity derivative instruments at June 30, 2008, which was recognized in accumulated other comprehensive loss within Partners’ Capital (deficit) on the Partnership’s consolidated balance sheet, will be reclassified to the Partnership’s consolidated statements of operations in the future at the time the originally hedged physical transactions affect earnings. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Partnership recognizes changes in fair value within other income (loss), net in its consolidated statements of operations as they occur.

At December 31, 2009, the Partnership had an interest rate derivative contract having an aggregate notional principal amount of $25.0 million. Under the terms of agreement, the Partnership will pay an interest rate of 3.01%, plus the applicable margin as defined under the terms of its revolving credit facility (see Note 14), and will receive LIBOR, plus the applicable margin, on the notional principal amounts. The interest rate swap agreement is effective at December 31, 2009 and expires on May 28, 2010. In June 2009, the Partnership repaid a portion of its borrowings under the credit facility with additional payments made in July and October with a resulting balance of $8.0 million outstanding under the credit facility at December 31, 2009. In addition, in accordance with the June 2009 amendment to its credit facility (see Note 14), the Partnership is prohibited from borrowing additional amounts under its credit facility once the amounts have been repaid. In accordance with prevailing accounting literature, the portion of any gain or loss in other comprehensive income related to forecasted hedge transactions that are no longer expected to occur are to be removed from other comprehensive income and recognized within the statements of operations. As a result of this reduction in borrowings under the credit facility below the notional amount of the interest rate derivative contract, the Partnership recognized an expense of $0.3 million within other income (loss), net in its consolidated statements of operations for the year ended December 31, 2009.

Beginning May 29, 2009, the Partnership and APL discontinued hedge accounting for its interest rate derivatives which were qualified as hedges. As such, subsequent changes in the fair value of these derivatives will be recognized immediately within other income (loss), net in the Partnership’s consolidated statements of operations. The fair value of these derivative instruments at May 29, 2009, which was recognized in accumulated other comprehensive loss within Partners’ Capital on the Partnership’s consolidated balance sheet, will be reclassified to the Partnership’s consolidated statements of operations in the future at the time the originally hedged interest rates affect earnings. For non-qualifying derivatives, the Partnership recognizes changes in fair value within other income (loss), net in its consolidated statements of operations as they occur.

The Partnership’s and APL’s derivatives are recorded on the Partnership’s consolidated balance sheet as assets or liabilities at fair value. At December 31, 2009 and 2008, the Partnership reflected net derivative liabilities on its consolidated balance sheets of $43.6 million and $64.3 million, respectively. Of the $6.6 million of net loss in accumulated other comprehensive loss within Partners’ Capital (deficit) on the Partnership’s consolidated balance sheet at December 31, 2009, the Partnership will reclassify $3.8 million of losses to the Partnership’s consolidated statements of operations over the next twelve month period, consisting of $3.4 million of losses to natural gas and liquids revenue and $0.4 million of losses to interest

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expense. Aggregate losses of $2.8 million will be reclassified to the Partnership’s consolidated statements of operations in later periods, consisting of losses to natural gas and liquids revenue. At December 31, 2009, no derivative instruments are designated as hedges for hedge accounting purposes.

The fair value of the Partnership’s and APL’s derivative instruments was included in the Partnership’s consolidated balance sheets as follows (in thousands):


	December 31,
	2009			2008
Current portion of derivative asset	$	998		$	44,961
Long-term derivative asset		361			—
Current portion of derivative liability		(33,833	)		(60,947	)
Long-term derivative liability		(11,126	)		(48,333	)

	$	(43,600	)	$	(64,319	)

The following table summarizes the Partnership’s and APL’s gross fair values of derivative instruments for the period indicated (in thousands):


	Asset Derivatives					Liability Derivatives
		December 31,					December 31,
	Balance Sheet Location	2009		2008		Balance Sheet Location	2009			2008
Interest rate contracts	N/A	$	—	$	—	Current portion of derivative liability	$	(2,533	)	$	(10,516	)
Interest rate contracts	N/A		—		—	Current portion of derivative asset		(593	)		—
Interest rate contracts	N/A		—		—	Long-term derivative liability		—			(1,936	)
Commodity contracts	Current portion of derivative asset		1,591		44,961	Current portion of derivative asset		—			—
Commodity contracts	Long-term derivative asset		361		—	Long-term derivative asset		—			—
Commodity contracts	Current portion of derivative liability		6,562		7,723	Current portion of derivative liability		(37,862	)		(58,154	)
Commodity contracts	Long-term derivative liability		3,435		3,505	Long-term derivative liability		(14,561	)		(49,902	)

		$	11,949	$	56,189		$	(55,549	)	$	(120,508	)

As of December 31, 2009, the Partnership had the following interest rate derivatives, including derivatives that do not qualify for hedge accounting:

Interest Fixed-Rate Swaps


Term	Notional Amount		Type	Contract Period Ended December 31,	Fair Value Liability⁽¹⁾ (in thousands)
May 2008-May 2010	$	25,000,000	Pay 3.01% —Receive LIBOR	2010	$	(286	)

(1)	Fair value based on independent, third-party statements, supported by observable levels at which transactions are executed in the marketplace.

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As of December 31, 2009, APL had the following interest rate and commodity derivatives, including derivatives that do not qualify for hedge accounting:

Interest Fixed-Rate Swaps


Term	Amount		Type	Fair Value⁽¹⁾ Asset/(Liability) (in thousands)
January 2008-January 2010	$	200,000,000	Pay 2.88% —Receive LIBOR	$	(438	)
April 2008-April 2010	$	250,000,000	Pay 3.14% —Receive LIBOR		(2,402	)

Total Interest Rate Swaps				$	(2,840	)

Fixed Price Swaps


Production Period	Purchased/ Sold	Commodity	Volumes⁽²⁾	Average Fixed Price			Fair Value⁽¹⁾ Asset/(Liability) (in thousands)
2010	Purchased	Natural Gas	4,380,000	$	8.635		$	(13,306	)
2010	Sold	Natural Gas Basis	4,500,000		(0.638	)		(1,936	)
2010	Purchased	Natural Gas Basis	8,880,000		(0.597	)		3,369
2011	Sold	Natural Gas Basis	1,920,000		(0.728	)		(845	)
2011	Purchased	Natural Gas Basis	1,920,000		(0.758	)		903
2012	Sold	Natural Gas Basis	720,000		(0.685	)		(269	)
2012	Purchased	Natural Gas Basis	720,000		(0.685	)		269

Total Fixed Price Swaps							$	(11,815	)

NGL Options


Production Period	Purchased/ Sold	Type	Commodity	Volumes⁽²⁾	Average Strike Price		Fair Value⁽¹⁾ Asset/(Liability) (in thousands)
2010	Purchased	Put	Propane	35,910,000	$	1.022	$	1,137
2010	Purchased	Put	Normal Butane	3,654,000		1.205		29
2010	Purchased	Put	Natural Gasoline	3,906,000		1.545		102

Total NGL Options							$	1,268


*Crude Oil Options*

Production Period	Purchased/ Sold	Type	Commodity	Volumes⁽²⁾	Average Strike Price		Fair Value⁽¹⁾ Asset/ (Liability) (in thousands)
2010	Purchased	Put	Crude Oil	897,000	$	73.12	$	3,518
2010	Sold	Call	Crude Oil	3,361,500		81.23		(23,183	)
2010	Purchased⁽³⁾	Call	Crude Oil	714,000		120.00		430
2011	Sold	Call	Crude Oil	678,000		94.68		(6,687	)
2011	Purchased⁽³⁾	Call	Crude Oil	252,000		120.00		1,017
2012	Sold	Call	Crude Oil	498,000		95.83		(6,197	)
2012	Purchased⁽³⁾	Call	Crude Oil	180,000		120.00		1,175

Total Crude Oil Options							$	(29,927	)

Total Fair Value							$	(43,314	)

⁽¹⁾	See Note 13 for discussion on fair value methodology.

⁽²⁾	Volumes for Natural Gas are stated in MMBTU’s. Volumes for NGLs are stated in gallons. Volumes for Crude Oil are stated in barrels.

⁽³⁾	Calls purchased for 2010 through 2012 represent offsetting positions for calls sold. These offsetting positions were entered into to limit the loss which could be incurred if crude oil prices continued to rise.

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During the years ended December 31, 2009 and 2008, APL made net payments of $5.0 million and $274.0 million, respectively, related to the early termination of derivative contracts. The majority of these derivative contracts were put into place simultaneously with APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007 and related to production periods ranging from the end of the second quarter of 2008 through the fourth quarter of 2009. Additional terminated derivative contracts extend through the fourth quarter of 2012. During the years ended December 31, 2009, 2008 and 2007, the Partnership recognized the following derivative activity related to APL’s early termination of these derivative instruments within its consolidated statements of operations (in thousands):

Early termination of derivative contracts


	For the Years Ended December 31,
	2009			2008			2007
Cash paid for early termination	$	(5,000	)	$	(273,987	)	$	—
Less: Deferred recognition of loss on early termination⁽¹⁾		—			(76,345	)		—

		(5,000	)		(197,642	)		—

Net cash derivative expense included within natural gas and liquids revenue		—			2,322			—
Net cash derivative expense included within other loss, net		(5,000	)		(199,964	)		—
Recognition of deferred hedge loss from prior periods included within natural gas and liquids revenue		(68,479	)		(32,389	)		—
Recognition of deferred hedge gain (loss) from prior periods included within other income (loss), net		44,861			(39,218	)		—

Total recognized loss from early termination	$	(28,618	)	$	(269,249	)	$	—

⁽¹⁾	Deferred recognition based upon effective portion of hedges deferred to OCI, plus theoretical premium related to unwound options which had previously been purchased or sold as part of costless collars

In addition, the Partnership will recognize $14.6 million, $2.3 million and $2.0 million of income in years 2010, 2011 and 2012, respectively, the remaining period for which the hedged physical transactions are scheduled to be settled, in the Partnership’s consolidated statements of operations. This $18.9 million includes $23.5 million of income related to the theoretical premiums for unwound options which had previously been purchased or sold as part of costless collars, with an offsetting expense of $4.6 million which will be reclassified from accumulated other comprehensive loss within Partners’ Capital on the Partnership’s consolidated balance sheet.

The following table summarizes the Partnership’s and APL’s cumulative derivative activity for the periods indicated including the amounts shown above (in thousands):


	Years Ended December 31,
	2009			2008			2007
Cash settlements:
Gain (loss) from cash settlement of effective portion of qualifying commodity derivatives⁽¹⁾	$	22,211		$	(49,268	)	$	(48,601	)
Loss from cash settlement of ineffective portion of qualifying commodity derivatives⁽¹⁾		(123	)		(23,359	)		(792	)
Loss from cash settlement of qualifying interest rate derivatives⁽²⁾		(12,260	)		(1,289	)		—
Loss from cash settlement of non-qualifying /ineffective commodity derivatives⁽³⁾		(53,699	)		(211,636	)		(10,158	)
Loss from cash settlement of non-qualifying interest rate derivatives⁽³⁾		(608	)		—			—

Total loss from cash settlements	$	(44,479	)	$	(285,552	)	$	(59,551	)

Non-cash gain (loss)
Loss from recognition of effective portion of qualifying commodity derivatives settled in a prior period ⁽¹⁾		(68,479	)		(32,389	)		—
Gain from non-cash recognition of non-qualifying derivatives settled in a prior period⁽³⁾⁽⁴⁾		44,861			(39,218	)		—
Gain (loss) from change in market value of non-qualifying and ineffective commodity derivatives⁽²⁾		(27,126	)		187,374			(169,424	)
Loss from change in market value of non-qualifying interest rate derivatives⁽²⁾		(972	)		—			—

Total non-cash gain (loss)	$	(51,716	)	$	115,767		$	(169,424	)

Total derivative loss	$	(96,195	)	$	(169,785	)	$	(228,975	)

⁽¹⁾	Included within natural gas and liquids revenue on the Partnership’s consolidated statements of operations.

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⁽²⁾	Included within interest expense on the Partnership’s consolidated statements of operations.

⁽³⁾	Included within other income (loss), net on the Partnership’s consolidated statements of operations.

⁽⁴⁾	Non-Cash recognition of non-qualifying derivatives includes the theoretical premium related to calls sold in conjunction with puts purchased in costless collars in which the puts were sold as part of the equity unwinds in 2008.

The following tables summarize the gross effect of the Partnership’s and APL’s derivative instruments on the Partnership’s consolidated statements of operations for the period indicated (in thousands):


	Gain (Loss) Recognized in Accumulated OCI									Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
	Years ended December 31,										Years ended December 31,
	2009			2008			2007			Location	2009			2008			2007
Interest rate contracts⁽¹⁾	$	(2,412	)	$	(13,741	)	$	—		Interest expense	$	(12,260	)	$	(1,289	)	$	—
Interest rate contracts⁽³⁾		—			—			—		Other income (loss), net		(292	)		—			—
Commodity contracts⁽¹⁾		—			(112,824	)		(101,176	)	Natural gas and liquids revenue		(46,268	)		(81,657	)		(48,601	)
Commodity contracts⁽³⁾		—			—			—		Other income (loss), net		—			—			(12,611	)

	$	(2,412	)	$	(126,565	)	$	(101,176	)		$	(58,820	)	$	(82,946	)	$	(61,212	)


	Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
		Years ended December 31,
	Location	2009			2008			2007
Interest rate contracts⁽¹⁾	Other income (loss), net	$	(1,288	)	$	—		$	—
Commodity contracts⁽¹⁾	Natural gas and liquids revenue		(123	)		(23,359	)		(792	)
Commodity contracts⁽¹⁾	Other income (loss), net		—			(263,977	)		(4,093	)
Commodity contracts⁽²⁾	Other income (loss), net		(35,964	)		200,497			(162,877	)

		$	(37,375	)	$	(86,839	)	$	(167,762	)

⁽¹⁾	Hedges previously designated as cash flow hedges

⁽²⁾	Dedesignated cash flow hedges and non-designated hedges

⁽³⁾	Reclass out of OCI resulting from dedesignation of hedge due to probability of future physical transaction not occurring

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NOTE 13 – FAIR VALUE OF FINANCIAL INSTRUMENTS

Derivative Instruments

FASB ASC has established a hierarchy to measure its financial instruments at fair value which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1– Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 3 – Unobservable inputs that reflect the entity’s own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

The Partnership uses a fair value methodology to value the assets and liabilities for its respective outstanding derivative contracts (see Note 12). At December 31, 2009, all of the Partnership’s and APL’s derivative contracts are defined as Level 2, with the exception of APL’s NGL fixed price swaps and NGL options. APL’s Level 2 commodity derivatives are calculated based on observable market data related to the change in price of the underlying commodity. The Partnership’s and APL’s interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model, and are therefore defined as Level 2. Valuations for APL’s NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of quoted price curves for NGL’s for similar locations, and therefore are defined as Level 3. Valuations for APL’s NGL options are based on forward price curves developed by the related financial institutions, and therefore are defined as Level 3.

On June 30, 2009, APL changed the basis for its valuation of crude oil options. Previously, APL utilized forward price curves developed by its derivative counterparties. Effective June 30, 2009, APL utilized crude oil option prices quoted from a public commodity exchange. With this change in valuation basis, APL reclassified the inputs for the valuation of its crude oil options from a Level 3 input to a Level 2 input. The change in valuation basis did not materially impact the fair value of APL’s derivative instruments on its consolidated statements of operations.

The following table represents the Partnership’s and APL’s assets and liabilities recorded at fair value as of December 31, 2009 (in thousands):


	Level 1		Level 2			Level 3		Total
Commodity-based derivatives	$	—	$	(41,742	)	$	1,268	$	(40,474	)
Interest rate swap-based derivatives		—		(3,126	)		—		(3,126	)

Total	$	—	$	(44,868	)	$	1,268	$	(43,600	)

127

APL’s Level 3 fair value amount relates to its derivative contracts on NGL fixed price swaps and NGL options. The following table provides a summary of changes in fair value of APL’s Level 3 derivative instruments for the years ended December 31, 2009 and 2008 (in thousands):


	NGL Fixed Price Swaps			NGL Sales Options			Crude Oil Options			Total
Balance – December 31, 2008	$	1,509		$	12,316		$	(23,436	)	$	(9,611	)
New contracts		(1,593	)		(9,462	)		—			(11,055	)
Cash settlements from unrealized gain (loss)⁽¹⁾		(5,527	)		(7,065	)		(37,671	)		(50,263	)
Cash settlements from other comprehensive income⁽²⁾		7,153			—			11,618			18,771
Net change in unrealized gain (loss)⁽¹⁾		(1,542	)		(1,090	)		14,886			12,254
Deferred option premium recognition		—			6,569			2,239			8,808
Transfer to Level 2		—			—			32,364			32,364

Balance – December 31, 2009	$	—		$	1,268		$	—		$	1,268

⁽¹⁾	Included within natural gas and liquids revenue on the Partnership’s consolidated statements of operations.

⁽²⁾	Included within other income (loss), net on the Partnership’s consolidated statements of operations.

Other Financial Instruments

The estimated fair value of the Partnership’s and APL’s other financial instruments has been determined based upon its assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that the Partnership or APL could realize upon the sale or refinancing of such financial instruments.

The Partnership’s current assets and liabilities on its consolidated balance sheets, other than the derivatives discussed above, are considered to be financial instruments for which the estimated fair values of these instruments approximate their carrying amounts due to their short-term nature. The estimated fair values of the Partnership’s total debt at December 31, 2009 and 2008, which consists principally of borrowings under the Partnership’s and APL’s credit facilities, APL’s Term Loan and APL’s Senior Notes, was $1,226.5 million and $1,199.2 million, respectively, compared with the carrying amounts of $1,286.4 million and $1,539.4 million, respectively. The APL term loan and APL Senior Notes were valued based upon available market data for similar issues. The carrying value of outstanding borrowings under the Partnership’s and APL’s credit facility, which bear interest at a variable interest rate, approximates their estimated fair value.

NOTE 14 – DEBT

Total debt consists of the following (in thousands):


	December 31,
	2009			2008
Credit facility	$	8,000		$	46,000
Subordinate loan and guaranty note with Atlas Energy, Inc		24,255			—
APL Revolving credit facility		326,000			302,000
APL Term loan		433,505			707,180
APL 8.125% Senior notes – due 2015		271,628			261,197
APL 8.75% Senior notes – due 2018		223,050			223,050

Total debt		1,286,438			1,539,427
Less current maturities		(32,255	)		—

Total long-term debt	$	1,254,183		$	1,539,427

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Atlas Pipeline Holdings Credit Facility

At December 31, 2009, the Partnership, with Atlas Pipeline GP as guarantor, had $8.0 million outstanding under a credit facility with a syndicate of banks. On June 1, 2009, the Partnership entered into an amendment to its credit facility agreement which, among other changes:

•

required the Partnership to immediately repay $30.0 million of then-outstanding $46.0 million of borrowings under the credit facility;

•

required the Partnership to repay $4.0 million of the remaining $16.0 million outstanding under the credit facility on each of July 13, 2009, October 13, 2009 and January 13, 2010, with the balance of the indebtedness being due on the original maturity date of the credit facility of April 13, 2010. The July 13, 2009, October 13, 2009 and January 13, 2010 payments were timely made by funding from Atlas Energy under its guaranty of the Partnership’s obligations. The Partnership may not borrow additional amounts under the credit facility or issue letters of credit;

•

requires the Partnership to use any of its “excess cash flow,” which the amendment generally defines as cash in excess of $1.5 million as of the last business day of each month, to repay outstanding borrowings under the credit facility. In addition, the amendment requires the Partnership to repay borrowings under the credit facility with the net proceeds of any sales of its common units in APL;

•

prohibits the Partnership from paying any cash distributions on or redeeming any of its equity while the credit facility is in effect and permits the Partnership to pay operating expenses only to the extent incurred or paid in the ordinary course of business; and

•

Borrowings under the Partnership’s credit facility are secured by a first-priority lien on a security interest in all of the Partnership’s assets, including the pledge of Atlas Pipeline GP’s interests in APL, and are guaranteed by Atlas Pipeline GP and the Partnership’s other subsidiaries (excluding APL and its subsidiaries). The Partnership’s credit facility contains customary covenants, including restrictions on its ability to incur additional indebtedness; make certain acquisitions, loans or investments; or enter into a merger or sale of substantially all of the Partnership’s property or assets, including the sale or transfer of interest in its subsidiaries. The Partnership is in compliance with these covenants as of December 31, 2009. The events which constitute an event of default under the Partnership’s credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreements, adverse judgments against the Partnership in excess of a specified amount, a change of control of Atlas Energy, the Partnership’s general partner or any other obligor, and termination of a material agreement and occurrence of a material adverse effect.

129

The Partnership’s $30 million repayment was funded from the proceeds of (i) a subordinate loan from Atlas Energy in the amount of $15.0 million obtained on June 1, 2009 and (ii) the purchase by APL of $15.0 million of preferred equity in a newly-formed subsidiary of the Partnership. The maturity date of the subordinate loan is the day following the day that the Partnership pays all indebtedness under the credit facility (“Termination Date”). The material terms of the preferred units purchased by APL in a newly-formed subsidiary of the Partnership are as follows: distributions are payable quarterly at the rate of 12.0% per annum, but before the Termination Date, distributions will be paid by increasing APL’s investment in the preferred units; upon the Termination Date, all preferred distributions will be paid in cash to APL; and the Partnership has the option, after the Termination Date, of redeeming all of the preferred units APL owns for an amount equal to the preferred unit capital. Additionally, Atlas Energy guaranteed the remaining balance outstanding under the credit facility under a guarantee agreement with the administrative agent of the credit facility. In consideration for this guarantee, the Partnership issued to Atlas Energy a guaranty note.

Atlas Pipeline Holdings Subordinate Loan and Guaranty Note with Atlas Energy

On June 1, 2009, in connection with its amendment of the credit facility, the Partnership borrowed $15.0 million from Atlas Energy under a subordinate loan. The maturity date of the subordinate loan is the day following the date that the Partnership repays all outstanding borrowings under its credit facility. Interest on the outstanding balance under the loan accrues quarterly at the rate of 12.0% per annum. However, prior to the maturity date of the subordinate loan, interest on the outstanding balance under the subordinate loan will not be payable in cash, but instead the principal amount of the loan will be increased by the interest amount payable. The Partnership incurred interest expense of $1.1 million on the subordinate loan during the year ended December 31, 2009.

On June 1, 2009, in consideration of Atlas Energy’s guaranty of the indebtedness under the Partnership’s credit facility, the Partnership entered into a guaranty note with Atlas Energy. The principal amount of the guaranty note is increased on the first day of each fiscal quarter by an amount equal to 3.75% per annum multiplied by (i) the outstanding principal amount of indebtedness under the credit facility plus (ii) $1.0 million. The note also accrues interest at 3.75% per annum which, until the credit facility is paid in full, is paid by increasing the principal amount of the note. The maturity date of the guaranty note is the day following the date that the Partnership repays all outstanding borrowings under its credit facility, which is scheduled to be April 13, 2010. During the year ended December 31, 2009, Atlas Energy funded $8.0 million in payments required under the credit facility under its guaranty of the Partnership’s obligations. During the year ended December 31, 2009, the Partnership incurred interest expense of $0.2 million for funds advanced under Atlas Energy’s guaranty.

As of December 31, 2009, the Partnership reflected $24.3 million in the current portion of long term debt on the Partnership’s consolidated balance sheet related to the subordinate loan and guaranty.

APL Term Loan and Credit Facility

At December 31, 2009, APL had a senior secured credit facility with a syndicate of banks which consisted of a term loan which matures in July 2014 and a $380.0 million revolving credit facility which matures in July 2013. Borrowings under APL’s credit facility bear interest, at APL’s option, at either (i) adjusted LIBOR plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). The weighted average interest rate on the outstanding APL revolving credit facility borrowings at December 31, 2009 was 6.8%, and the weighted average interest rate on the outstanding APL term loan borrowings at December 31, 2009 was 6.8%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $10.1 million was outstanding at December 31, 2009. These outstanding letter of credit amounts were not reflected as borrowings on the Partnership’s consolidated balance sheet. At December 31, 2009, APL had $43.9 million of remaining committed capacity under its credit facility, subject to covenant limitations.

130

On May 29, 2009, APL entered into an amendment to its credit facility agreement which, among other changes:

•

increased the applicable margin above adjusted LIBOR to either (i) the federal funds rate plus 0.5% or (ii) the Wachovia Bank prime rate upon which borrowings under the credit facility bear interest;

•

for borrowings under the credit facility that bear interest at LIBOR plus the applicable margin, set a floor for the adjusted LIBOR interest rate of 2.0% per annum;

•

generally limits APL’s annual capital expenditures to $95.0 million for the remainder of fiscal 2009 and $70.0 million each year thereafter, unless certain covenants are achieved;

•

instituted a mandatory repayment requirement of the outstanding senior secured term loan from excess cash flow (as defined in the credit agreement) based upon APL’s leverage ratio.

In June 2008, APL entered into an amendment to the credit facility agreement to revise the definition of “Consolidated EBITDA” to provide for the add-back of charges relating to its early termination of certain derivative contracts (see Note 12) in calculating Consolidated EBITDA. Pursuant to this amendment, in June 2008, APL repaid $122.8 million of its outstanding term loan and repaid $120.0 million of outstanding borrowings under the revolving credit facility with proceeds from its issuance of $250.0 million of 10-year, 8.75% senior unsecured notes (see “Note 14—APL Senior Notes”). Additionally, pursuant to this amendment, in June 2008, APL’s lenders increased their commitments for its revolving credit facility by $80.0 million to $380.0 million.

131

Borrowings under the credit facility are secured by a lien on and security interest in all of APL’s property and that of its subsidiaries, except for the assets owned by Chaney Dell and Midkiff/Benedum joint ventures and Laurel Mountain; and by the guaranty of each of APL’s consolidated subsidiaries other than the joint venture companies. The credit facility contains customary covenants, including restrictions on APL’s ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to its unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries. APL is also unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to its partnership agreement. APL is in compliance with these covenants as of December 31, 2009.

The events which constitute an event of default for APL’s credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against APL in excess of a specified amount, and a change of control of APL’s General Partner. The credit facility requires APL to maintain the following ratios:


Fiscal quarter ending:	Maximum Leverage Ratio	Maximum Senior Secured Leverage Ratio	Minimum Interest Coverage Ratio
December 31, 2009	8.50x	5.25x	1.70x
March 31, 2010	9.25x	5.75x	1.40x
June 30, 2010	8.00x	5.00x	1.65x
September 30, 2010	7.00x	4.25x	1.90x
December 31, 2010	6.00x	3.75x	2.20x
Thereafter	5.00x	3.00x	2.75x

As of December 31, 2009, APL’s leverage ratio was 5.2 to 1.0, its senior secured leverage ratio was 3.2 to 1.0, and its interest coverage ratio was 2.5 to 1.0.

APL Senior Notes

In December 2008, APL repurchased approximately $60.0 million in face amount of its Senior Notes for an aggregate purchase price of approximately $40.1 million plus accrued interest of approximately $2.0 million. The notes repurchased were comprised of $33.0 million in face amount of APL’s 8.125% Senior Notes and approximately $27.0 million in face amount of APL’s 8.75% Senior Notes. All of the Senior Notes repurchased have been retired and are not available for re-issue.

132

In January 2009, APL issued Sunlight Capital $15.0 million of its 8.125% Senior Notes to redeem 10,000 APL Class A Preferred Units (see Note 7). Management of APL estimated that the fair value of the $15.0 million 8.125% Senior Notes issued was approximately $10.0 million at the date of issuance based upon the market price of the publicly-traded Senior Notes. As such, APL recognized a $5.0 million discount on the issuance of the Senior Notes, which is presented as a reduction of long-term debt on the Partnership’s consolidated balance sheets. The discount recognized upon issuance of the Senior Notes will be amortized to interest expense within the Partnership’s consolidated statements of operations over the term of the 8.125% Senior Notes based upon the effective interest rate method.

In connection with the issuance of the APL 8.75% Senior Notes, APL entered into a registration rights agreement, whereby it agreed to (a) file an exchange offer registration statement with the Securities and Exchange Commission for the APL 8.75% Senior Notes, (b) cause the exchange offer registration statement to be declared effective by the Securities and Exchange Commission, and (c) cause the exchange offer to be consummated by February 23, 2009. If APL did not meet the aforementioned deadline, the APL 8.75% Senior Notes would have been subject to additional interest, up to 1% per annum, until such time that APL had caused the exchange offer to be consummated. On November 21, 2008, APL filed an exchange offer registration statement for the APL 8.75% Senior Notes with the Securities and Exchange Commission, which was declared effective on December 16, 2008. The exchange offer was consummated on January 21, 2009, thereby fulfilling all of the requirements of the 8.75% Senior Notes registration rights agreement by the specified dates.

The aggregate amount of the Partnership’s debt maturities, including APL, is as follows (in thousands):


Years Ended December 31:
2010	$	32,255
2011		—
2012		—
2013		326,000
2014		433,505
Thereafter		494,678

	$	1,286,438

Cash payments for interest related to the Partnership’s and APL’s debt were $92.2 million, $87.8 million and $57.1 million for the years ended December 31, 2009, 2008 and 2007, respectively.

NOTE 15 – COMMITMENTS AND CONTINGENCIES

APL has noncancelable operating leases for equipment and office space that expire at various dates. Certain operating leases provide APL with the option to renew for additional periods. Where operating leases contain escalation clauses, rent abatements, and/or concessions, APL applies them in the determination of straight-line rent expense over the lease term. Leasehold improvements are amortized over the shorter of the lease term or asset life, which may include renewal periods where the renewal is reasonably assured, and is included in the determination of straight-line rent expense. Total rental expense for the years ended December 31, 2009, 2008 and 2007 was $8.5 million, $9.1 million and $5.1 million, respectively. The aggregate amount of remaining future minimum annual lease payments as of December 31, 2009 is as follows (in thousands):


Years Ended December 31:
2010	$	4,547
2011		3,916
2012		3,574
2013		1,512
2014		—
Thereafter		—

	$	13,549

133

APL is a party to various routine legal proceedings arising out of the ordinary course of its business. Management of the Partnership believes that the ultimate resolution of these actions, individually or in the aggregate, will not have a material adverse effect on its financial condition or results of operations.

APL’s predecessor with respect to APL’s Chaney Dell assets was named as a defendant in a set of lawsuits filed in 1999 named Will Price, et al. v. Gas Pipelines and Pipelines and Their Predecessors, et al., in the District Court of Stevens County, Kansas. The lawsuits allege various claims related to industry-wide under reporting of volumes and heating value of natural gas. The plaintiffs currently seek certification of a class of royalty owners on non-federal and non-Native American lands in Kansas, Wyoming and Colorado. APL conducts limited operations in Kansas. Motions for class certification were argued in March 2005. In September 2009, the motions were denied. Plaintiffs have filed a motion for reconsideration that was argued in February 2010. The plaintiffs seek unspecified monetary damages (along with interest, expenses and punitive damages) and injunctive relief with regard to future gas measurement practices. At this stage, discovery has not been conducted with respect to the merits of these lawsuits and APL’s liability, if any, will arise under the indemnity provisions of agreements with APL’s predecessor. As such, it is not currently possible to evaluate the likelihood or extent of an unfavorable outcome.

On February 26, 2010, APL received notice from Williams, its partner in Laurel Mountain (see Note 3), alleging that certain title defects exist with respect to the real property contributed by APL to Laurel Mountain. Under the Formation and Exchange Agreement with Williams: (i) Williams had nine (9) months after closing (the “Claim Date”) to assert any alleged title defects, and (ii) APL has 30 days following the Claim Date to contest the title defects asserted by Williams and 180 days following the Claim Date to cure those title defects. At the end of the cure period with respect to any remaining title defects, APL may elect, at its option, to pay Williams for the cost of such defects, up to a total of $3.5 million, or indemnify Williams with respect to such title defects. APL is conducting a review with respect to the title defects that have been alleged. Although an adverse outcome is reasonably possible, it is not currently possible to evaluate the amount that APL may be required to pay with respect to such alleged title defects.

NOTE 16 – CONCENTRATIONS OF CREDIT RISK

APL sells natural gas and NGLs under contract to various purchasers in the normal course of business. For the year ended December 31, 2009, APL had two customers that individually accounted for approximately 53% and 12% of the Partnership’s consolidated total third party revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2008, APL had two customers that individually accounted for approximately 52% and 13% of the Partnership’s consolidated total third party revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2007, APL had one customer that individually accounted for approximately 56% of the Partnership’s consolidated total third party revenues, excluding the impact of all financial derivative activity. Additionally, APL had two customers that individually accounted for approximately 56% and 19% of the Partnership’s consolidated accounts receivable at December 31, 2009, and one customer that individually accounted for approximately 42% of the Partnership’s consolidated accounts receivable at December 31, 2008.

134

APL has certain producers which supply a majority of the natural gas to its Mid-Continent gathering systems and processing facilities. A reduction in the volume of natural gas that any one of these producers supply to APL could adversely affect its operating results unless comparable volume could be obtained from other producers in the surrounding region.

The Partnership places its temporary cash investments in high quality short-term money market instruments and deposits with high quality financial institutions. At December 31, 2009, the Partnership and its subsidiaries, including APL, had $5.8 million in deposits at banks, of which $4.4 million was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments.

NOTE 17 – BENEFIT PLANS

Generally, all share-based payments to employees, which are not cash settled, including grants of employee stock options are recognized in the financial statements based on their fair values on the date of the grant.

Partnership’s Long-Term Incentive Plan. In November 2006, the Board of Directors approved and adopted the Partnership’s Long-Term Incentive Plan (“LTIP”), which provides performance incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners (collectively, the “Participants”) who perform services for the Partnership. The LTIP is administered by a committee (the “LTIP Committee”), appointed by the Partnership’s board. Under the LTIP, phantom units and/or unit options may be granted, at the discretion of the LTIP Committee, to all or designated Participants, at the discretion of the LTIP Committee. The LTIP Committee may grant such awards of either phantom units or unit options for an aggregate of 2,100,000 common limited partner units. At December 31, 2009, the Partnership had 1,093,875 phantom units and unit options outstanding under the Partnership’s LTIP, with 960,650 phantom units and unit options available for grant.

Partnership Phantom Units. A phantom unit entitles a Participant to receive a common unit of the Partnership, without payment of an exercise price, upon vesting of the phantom unit. In tandem with phantom unit grants, the Partnership’s LTIP Committee may grant a Participant a distribution equivalent right (“DER”), which is the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions the Partnership makes on a common unit during the period such phantom unit is outstanding. The Partnership’s LTIP Committee will determine the vesting period for phantom units. Through December 31, 2009, phantom units granted under the LTIP generally will vest 25% three years from the date of grant and 100% four years from the date of grant. Awards will automatically vest upon a change of control of the Partnership, as defined in the Partnership’s LTIP. Of the phantom units outstanding under the Partnership’s LTIP at December 31, 2009, 131,675 units will vest within the following twelve months. All phantom units outstanding under the Partnership’s LTIP at December 31, 2009 include DERs granted to the Participants by the Partnership’s LTIP Committee. The amounts paid with respect to the Partnership’s LTIP DERs were $14,000 and $0.4 million for the years ended December 31, 2009 and 2008, respectively. These amounts were recorded as reductions of Partners’ Capital (deficit) on the Partnership’s consolidated balance sheet.

135

The following table sets forth the Partnership’s LTIP phantom unit activity for the periods indicated:


	Years Ended December 31,
	2009			2008			2007
Outstanding, beginning of year		226,300			220,825			220,492
Granted⁽¹⁾		2,000			6,150			708
Matured⁽³⁾		(44,425	)		(675	)		(375	)
Forfeited		(45,000	)		—			—

Outstanding, end of year⁽²⁾		138,875			226,300			220,825

Non-cash compensation expense recognized (in thousands)	$	515		$	1,427		$	1,420

⁽¹⁾

The weighted average price for phantom unit awards on the date of grant, which is utilized in the calculation of compensation expense and does not represent an exercise price to be paid by the recipient, was $3.60, $26.51, and $37.46 for awards granted for the year ended December 31, 2009, 2008 and 2007, respectively.

⁽²⁾	The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2009 is $0.9 million.

⁽³⁾	The intrinsic values for phantom unit awards exercised during the years ended at December 31, 2009, 2008 and 2007 were $0.2 million, $6,000 and $14,000, respectively.

At December 31, 2009, the Partnership had approximately $0.7 million of unrecognized compensation expense related to unvested phantom units outstanding under its LTIP based upon the fair value of the awards.

Partnership Unit Options. A unit option entitles a Participant to receive a common unit of the Partnership upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of the Partnership’s common unit as determined by the Partnership’s LTIP Committee on the date of grant of the option. The Partnership’s LTIP Committee also shall determine how the exercise price may be paid by the Participant. The Partnership’s LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through December 31, 2009, unit options granted under the Partnership’s LTIP generally will vest 25% three years from the date of grant and 100% four years from the date of grant. Awards will automatically vest upon a change of control of the Partnership, as defined in the Partnership’s LTIP. There are 641,250 unit options outstanding under the Partnership’s LTIP at December 31, 2009 that will vest within the following twelve months. The following table sets forth the LTIP unit option activity for the periods indicated:


	Years Ended December 31,
	2009					2008				2007
	Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price
Outstanding, beginning of period		1,215,000		$	22.56		1,215,000	$	22.56		1,215,000	$	22.56
Granted		100,000			3.24		—		—		—		—
Matured		—			—		—		—		—		—
Forfeited		(360,000	)		22.56		—		—		—		—

Outstanding, end of period⁽¹⁾⁽²⁾		955,000		$	20.54		1,215,000	$	22.56		1,215,000	$	22.56

Options exercisable, end of period⁽³⁾		213,750			—		—		—		—		—

Weighted average fair value of unit options per unit granted during the year	$	0.61				$	—			$	—
Non-cash compensation expense recognized (in thousands)	$	48				$	1,237			$	1,237

⁽¹⁾	The weighted average remaining contractual lives for outstanding options at December 31, 2009, 2008 and 2007 were 7.1 years, 7.9 years and 8.9 years, respectively.

136

⁽²⁾	The aggregate intrinsic values of options outstanding at December 31, 2009 and 2007 were approximately $0.4 million and $5.6 million, respectively. There was no intrinsic value of options outstanding at December 31, 2008.

⁽³⁾	There were no options exercised during the years ended December 31, 2009, 2008 and 2007, respectively.

At December 31, 2009, the Partnership had approximately $0.5 million of unrecognized compensation expense related to unvested unit options outstanding under the Partnership’s LTIP based upon the fair value of the awards.

The Partnership used the Black-Scholes option pricing model to estimate the weighted average fair value of options granted. The following weighted average assumptions were used for the period indicated:


	Year Ended December 31, 2009
Expected dividend yield	7.0	%
Expected stock price volatility	40	%
Risk-free interest rate	2.3	%
Expected term (in years)	6.9

APL Long-Term Incentive Plan

APL has a Long-Term Incentive Plan (“APL LTIP”), in which officers, employees and non-employee managing board members of the General Partner and employees of the General Partner’s affiliates and consultants are eligible to participate. The APL LTIP is administered by a committee (the “APL LTIP Committee”) appointed by the Partnership’s managing board. The APL LTIP Committee may make awards of either phantom units or unit options for an aggregate of 435,000 common units.

APL Phantom Units. A phantom unit entitles a grantee to receive a common unit, without payment of an exercise price, upon vesting of the phantom unit. In addition, the APL LTIP Committee may grant a participant a DER, which is the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions APL makes on a common unit during the period the phantom unit is outstanding. A unit option entitles the grantee to purchase APL’s common limited partner units at an exercise price determined by the APL LTIP Committee at its discretion. The APL LTIP Committee also has discretion to determine how the exercise price may be paid by the participant. Except for phantom units awarded to non-employee managing board members of APL, the APL LTIP Committee will determine the vesting period for phantom units and the exercise period for options. Through December 31, 2009, phantom units granted under the APL LTIP generally had vesting periods of four years. Phantom units awarded to non-employee managing board members will vest over a four year period. Awards will automatically vest upon a change of control, as defined in the APL LTIP. Of the units outstanding under the APL LTIP at December 31, 2009, 28,961 units will vest within the following twelve months. All phantom units outstanding under the APL LTIP at December 31, 2009 include DERs granted to the participants by the APL LTIP Committee. The amounts paid with respect to APL LTIP DERs were $0.1 million, $0.5 million and $0.6 million for the years ended December 31, 2009, 2008 and 2007, respectively. These amounts were recorded as reductions of non-controlling interest in APL on the Partnership’s consolidated balance sheet.

137

The following table sets forth the APL LTIP phantom unit activity for the periods indicated:


	Years Ended December 31,
	2009			2008			2007
Outstanding, beginning of year		126,565			129,746			159,067
Granted⁽¹⁾		2,000			54,796			25,095
Matured⁽²⁾		(58,257	)		(56,227	)		(51,166	)
Forfeited		(18,075	)		(1,750	)		(3,250	)

Outstanding, end of year⁽³⁾		52,233			126,565			129,746

Non-cash compensation expense recognized (in thousands)	$	694		$	2,313		$	2,936

⁽¹⁾

The weighted average prices for phantom unit awards on the date of grant, which is utilized in the calculation of compensation expense and does not represent an exercise price to be paid by the recipient, were $4.75, $44.28 and $50.09 for awards granted for the years ended December 31, 2009, 2008 and 2007, respectively.

⁽²⁾	The intrinsic values for phantom unit awards exercised during the years ended at December 31, 2009, 2008 and 2007 are $0.3 million, $2.0 million and $2.6 million, respectively.

⁽³⁾	The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2009 is $0.5 million.

At December 31, 2009, APL had approximately $0.7 million of unrecognized compensation expense related to unvested phantom units outstanding under the APL LTIP based upon the fair value of the awards.

APL Unit Options. A unit option entitles a Participant to receive a common unit of APL upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of APL’s common unit as determined by the APL LTIP Committee on the date of grant of the option. The APL LTIP Committee also shall determine how the exercise price may be paid by the Participant. The APL LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Through December 31, 2009, unit options granted under APL’s LTIP generally will vest 25% on each of the next four anniversaries of the date of grant. Awards will automatically vest upon a change of control of APL, as defined in the APL’s LTIP. There are 25,000 unit options outstanding under the APL’s LTIP at December 31, 2009 that will vest within the following twelve months.

The following table sets forth the LTIP unit option activity for the periods indicated:


	Year Ended December 31,
	2009
	Number of Unit Options		Weighted Average Exercise Price
Outstanding, beginning of period		—	$	—
Granted		100,000		6.24
Matured		—		—
Forfeited		—		—

Outstanding, end of period⁽¹⁾⁽²⁾		100,000	$	6.24

Options exercisable, end of period		—		—

Weighted average fair value of unit options per unit granted during the period		100,000	$	0.14

Non-cash compensation expense recognized (in thousands)	$	7

⁽¹⁾	The weighted average remaining contractual life for outstanding options at December 31, 2009 was 9.0 years.

⁽²⁾	The aggregate intrinsic value of options outstanding at December 31, 2009 was $0.4 million.

138

APL used the Black-Scholes option pricing model to estimate the weighted average fair value of options granted. The following weighted average assumptions were used for the period indicated:


	Year Ended December 31, 2009
Expected dividend yield	11.0	%
Expected stock price volatility	20.0	%
Risk-free interest rate	2.2	%
Expected term (in years)	6.3

APL Incentive Compensation Agreements

APL had incentive compensation agreements which granted awards to certain key employees retained from previously consummated acquisitions. These individuals were entitled to receive common units of APL upon the vesting of the awards, which was dependent upon the achievement of certain predetermined performance targets through September 30, 2007. At September 30, 2007, the predetermined performance targets were achieved and all of the awards under the incentive compensation agreements vested. Of the total common units issued under the incentive compensation agreements, 58,822 common units were issued during the year ended December 31, 2007. The ultimate number of common units issued under the incentive compensation agreements was determined principally by the financial performance of certain APL assets during the year ended December 31, 2008 and the market value of APL’s common units at December 31, 2008. APL’s incentive compensation agreements also dictated that no individual covered under the agreements would receive an amount of common units in excess of one percent of the outstanding common units of APL at the date of issuance. Common unit amounts due to any individual covered under the agreements in excess of one percent of the outstanding common units of APL would have been paid in cash.

Compensation expense is recognized on a straight-line basis over the vesting period. As of December 31, 2008, APL recognized in full within the Partnership’s consolidated statements of operations the compensation expense associated with the vesting of awards issued under APL’s incentive compensation agreements, therefore no compensation expense was recognized during the year ended December 31, 2009. APL recognized reductions of compensation expense of $36.3 million and $33.4 million for the years ended December 31, 2008 and 2007, respectively, related to the vesting of awards under these incentive compensation agreements. The non-cash compensation expense adjustments for the year ended December 31, 2008 were principally attributable to changes in APL’s common unit market price, which was utilized in the calculation of the non-cash compensation expense for these awards, at December 31, 2008 when compared with the common unit market price at earlier periods and adjustments based upon the achievement of actual financial performance targets through December 31, 2008. APL recognized compensation expense related to these awards based upon the fair value method. During the year ended December 31, 2009, APL issued 348,620 common units to the certain key employees covered under APL’s incentive compensation agreements. No additional common units will be issued with regard to these agreements.

Employee Incentive Compensation Plan and Agreement

In June 2009, a wholly-owned subsidiary of APL adopted an incentive plan (the “APL Plan”) which allows for equity-indexed cash incentive awards to employees of APL (the “Participants”), but expressly excludes as an eligible Participant any person that, at the time of the grant, is a “Named Executive Officer” of APL (as such term is defined under the rules of the Securities and Exchange Commission). The APL Plan is administered by a committee appointed by the chief executive officer of APL. Under the APL Plan, cash bonus units may be awarded to Participants at the discretion of the committee and bonus units totaling 325,000 were awarded under the APL Plan in June 2009. In September 2009, the APL subsidiary entered into an agreement with an APL executive officer that granted an award of 50,000 bonus units on substantially the same terms as the bonus units available under the APL Plan (the bonus units issued under the APL Plan and under the separate agreement are, for purposes hereof, referred to as “APL Bonus Units”). An APL

139

Bonus Unit entitles the employee to receive the cash equivalent of the then-fair market value of an APL common limited partner unit, without payment of an exercise price, upon vesting of the APL Bonus Unit. APL Bonus Units vest ratably over a three year period from the date of grant and will automatically vest upon a change of control, death, or termination without cause, each as defined in the governing document. Vesting will terminate upon termination of employment with cause. During the year ended December 31, 2009, APL granted 375,000 APL Bonus Units. Of the APL Bonus Units outstanding at December 31, 2009, 123,750 APL Bonus Units will vest within the following twelve months. APL recognized compensation expense related to these awards based upon the fair value, which is remeasured each reporting period based upon the current fair value of the underlying common units. APL recognized $1.2 million of compensation expense within general and administrative expense on the Partnership’s consolidated statements of operations with respect to the vesting of these awards for the year ended December 31, 2009. At December 31, 2009, the Partnership has recognized $1.2 million within accounts payable – affiliates on its consolidated balance sheet with regard to the awards, which represents their fair value at December 31, 2009.

NOTE 18 – RELATED PARTY TRANSACTIONS

Neither the Partnership nor APL directly employs any persons to manage or operate their businesses. These functions are provided by employees of Atlas Energy. Atlas Pipeline Holdings GP, LLC, the Partnership’s general partner, does not receive a management fee in connection with its management of APL, nor does Atlas Pipeline GP, the general partner of APL, receive a management fee in connection with its management of APL apart from its interest as general partner and its right to receive incentive distributions. APL reimburses the Partnership and its affiliates for compensation and benefits related to their employees who perform services for it based upon an estimate of the time spent by such persons on activities for APL. Other indirect costs, such as rent for offices, are allocated to APL by Atlas Energy based on the number of its employees who devote their time to activities on APL’s behalf.

APL’s partnership agreement provides that the Partnership will determine the costs and expenses that are allocable to APL in any reasonable manner determined by the Partnership at its sole discretion. APL reimbursed the Partnership and its affiliates $2.7 million, $1.5 million and $5.9 million for the years ended December 31, 2009, 2008 and 2007, respectively, for compensation and benefits related to their employees. There were no reimbursements by APL for direct expenses incurred by the Partnership and its affiliates for the years ended December 31, 2009, 2008 and 2007.

NOTE 19 – SEGMENT INFORMATION

The Partnership’s assets primarily consist of its ownership interests in APL. APL has two reportable segments. These reportable segments reflect the way APL manages its operations.

APL’s Mid-Continent segment consists of APL’s Chaney Dell, Elk City/Sweetwater, Velma and Midkiff/Benedum operations, which are comprised of natural gas gathering and processing assets servicing drilling activity in the Anadarko and Permian Basins. APL’s Mid-Continent revenues are primarily derived from the sale of Residue Gas and NGLs and gathering of natural gas.

APL’s Appalachia segment is comprised of natural gas transportation, gathering and processing assets located in the Appalachian Basin area of eastern Ohio, western New York, western Pennsylvania and northeastern Tennessee and services drilling activity in the Marcellus Shale area in southwestern Pennsylvania. Effective May 31, 2009, APL’s Appalachia operations were principally conducted through its Tennessee operations and APL’s 49% ownership interest in Laurel Mountain, a joint venture to which APL contributed its natural gas transportation, gathering and processing assets located in northeastern Appalachia. APL recognizes its ownership interest in Laurel Mountain under the equity method of accounting. APL’s Appalachia revenues are principally based on contractual arrangements with Atlas Energy and its affiliates.

140

The following summarizes the Partnership’s reportable segment data for the periods indicated (in thousands):


	Appalachia		Mid- Continent			Corporate and Other			Consolidated
Year Ended December 31, 2009:
Revenue:
Revenues – third party	$	1,779	$	852,803		$	(83,755	)	$	770,827
Revenues – affiliates		17,536		—			—			17,536
Gain on asset sale		108,947		2,493			—			111,440
Equity income		4,043		—			—			4,043

Total revenue and other income (loss), net		132,305		855,296			(83,755	)		903,846

Costs and Expenses:
Operating costs and expenses		6,917		652,956			—			659,873
General and administrative⁽²⁾		—		—			39,377			39,377
Depreciation and amortization		3,591		88,843			—			92,434
Goodwill and other asset impairment loss		—		10,325			—			10,325
Interest expense⁽²⁾		—		—			106,373			106,373

Total costs and expenses		10,508		752,124			145,750			908,382

Net income (loss) from continuing operations		121,797		103,172			(229,505	)		(4,536	)
Income from discontinued operations		—		—			62,495			62,495

Net income (loss)	$	121,797	$	103,172		$	(167,010	)	$	57,959

Year Ended December 31, 2008⁽¹⁾:
Revenue:
Revenues – third party	$	5,456	$	1,471,516		$	(168,481	)	$	1,308,491
Revenues – affiliates		43,293		—			—			43,293

Total revenue and other income (loss), net		48,749		1,471,516			(168,481	)		1,351,784

Costs and expenses:
Operating costs and expenses		13,073		1,139,951			—			1,153,024
General and administrative⁽²⁾		—		—			1,728			1,728
Depreciation and amortization		6,430		76,411			—			82,841
Goodwill and other asset impairment loss		2,304		674,556			—			676,860
Interest expense⁽²⁾		—		—			87,853			87,853
Gain on extinguishment of debt		—		—			(19,867	)		(19,867	)

Total costs and expenses		21,807		1,890,918			69,714			1,982,439

Net income (loss) from continuing operation		26,942		(419,402	)		(238,195	)		(630,655	)
Income from discontinued operations		—		—			20,546			20,546

Net income (loss)	$	26,942	$	(419,402	)	$	(217,649	)	$	(610,109	)

Year Ended December 31, 2007⁽¹⁾:
Revenue:
Revenues – third party	$	2,475	$	805,544		$	(228,956	)	$	579,063
Revenues – affiliates		33,169		—			—			33,169

Total revenue and other income (loss), net		35,644		805,544			(228,956	)		612,232

Costs and expenses:
Operating costs and expenses		7,082		610,235			—			617,317
General and administrative⁽²⁾		—		—			63,175			63,175
Depreciation and amortization		4,655		39,248			—			43,903
Interest expense⁽²⁾		—		—			63,695			63,695

Total costs and expenses		11,737		649,483			126,870			788,090

Net income (loss) from continuing operations		23,907		156,061			(355,826	)		(175,858	)
Income from discontinued operations		—		—			30,830			30,830

Net income (loss)	$	23,907	$	156,061		$	(324,996	)	$	(145,028	)

141


	Years Ended December 31,
	2009		2008⁽¹⁾		2007⁽¹⁾
Capital Expenditures:
Mid-Continent	$	145,354	$	259,221	$	101,213
Appalachia		9,562		41,502		19,620

	$	154,916	$	300,723	$	120,833


	December 31,
Balance Sheet	2009		2008⁽¹⁾
Total assets:
Mid-Continent	$	1,965,219	$	1,973,723
Appalachia		170,905		114,166
Discontinued operations		—		255,606
Corporate other		1,994		75,489

	$	2,138,118	$	2,418,984

The following tables summarize the Partnership’s total revenues by product or service for the periods indicated (in thousands):


	Years Ended December 31,
	2009		2008⁽¹⁾		2007⁽¹⁾
Natural gas and liquids:
Natural gas	$	274,643	$	559,110	$	255,043
NGLs		428,851		688,623		434,773
Condensate		28,681		57,366		27,269
Other ⁽²⁾		46,369		37,683		22,766

Total	$	778,544	$	1,342,782	$	739,851

⁽¹⁾	Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system (see Note 4).

⁽²⁾	The Partnership notes that derivative contracts, interest and general and administrative expenses have not been allocated to its reportable segments as it would be unfeasible to reasonably do so for the periods presented.

NOTE 20 – QUARTERLY FINANCIAL DATA (Unaudited)


	Fourth Quarter⁽¹⁾			Third Quarter⁽²⁾			Second Quarter⁽³⁾		First Quarter⁽⁴⁾
	(in thousands, except per unit data)
Year ended December 31, 2009:
Revenue and other income (loss), net	$	241,031		$	206,465		$	282,108	$	174,242
Costs and expenses		277,650			220,599			203,759		206,374

Income (loss) from continuing operations		(36,619	)		(14,134	)		78,349		(32,132	)
Income (loss) from discontinued operations		—			—			53,619		8,876

Net income (loss)	$	(36,619	)	$	(14,134	)	$	131,968	$	(23,256	)

Net income (loss) attributable to common limited partners per unit – basic:
Income (loss) from continuing operations attributable to common limited partners	$	(0.23	)	$	(0.13	)	$	0.34	$	(0.16	)
Income (loss) from discontinued operations attributable to common limited partners		—			—			0.27		0.05

Net income (loss) attributable to common limited partners	$	(0.23	)	$	(0.13	)	$	0.61	$	(0.11	)

Net income (loss) attributable to common limited partners per unit – diluted: ⁽⁵⁾
Income (loss) from continuing operations attributable to common limited partners	$	(0.23	)	$	(0.13	)	$	0.34	$	(0.16	)
Income (loss) from discontinued operations attributable to common limited partners		—			—			0.27		0.05

Net income (loss) attributable to common limited partners	$	(0.23	)	$	(0.13	)	$	0.61	$	(0.11	)

⁽¹⁾	Net loss includes APL’s $11.7 million non-cash derivative loss and $10.3 million non-cash impairment charge for goodwill and other assets,

142

⁽²⁾	Net loss includes APL’s $7.5 million non-cash derivative gain.

⁽³⁾	Net income includes APL’s $2.5 million non-cash derivative loss and a $79.8 million non-cash gain of the total $111.4 million gain on sale of APL’s assets.

⁽⁴⁾	Net loss includes APL’s $44.0 million non-cash derivative loss and a $5.0 million cash derivative expense from the APL’s termination of certain derivative instruments.

⁽⁵⁾	For all quarters of the year ended December 31, 2009, approximately 1.0 million unit options were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive.


	Fourth Quarter⁽¹⁾			Third Quarter⁽²⁾		Second Quarter⁽³⁾			First Quarter⁽⁴⁾
	(in thousands, except per unit data)
Year ended December 31, 2008⁽⁵⁾:
Revenue and other income (loss)	$	362,932		$	568,663	$	133,170		$	287,019
Costs and expenses		850,492			375,366		418,242			338,339

Income (loss) from continuing operations		(487,560	)		193,297		(285,072	)		(51,320	)
Income (loss) from discontinued operations		(483	)		6,538		8,245			6,246

Net income (loss)	$	(488,043	)	$	199,835		(276,827	)		(45,074	)

Net income (loss) attributable to common limited partners per unit – basic:
Income (loss) from continuing operations attributable to common limited partners	$	(2.41	)	$	1.18	$	(1.44	)	$	(0.11	)
Income (loss) from discontinued operations attributable to common limited partners		—			0.04		0.04			0.01

Net income (loss) attributable to common limited partners	$	(2.41	)	$	1.22	$	(1.40	)	$	(0.10	)

Net income (loss) attributable to common limited partners per unit – diluted:
Income (loss) from continuing operations attributable to common limited partners	$	(2.41	)	$	1.16	$	(1.44	)	$	(0.11	)
Income (loss) from discontinued operations attributable to common limited partners		—		$	0.04	$	0.04		$	0.01

Net income (loss) attributable to common limited partners	$	(2.41	)	$	1.20	$	(1.40	)	$	(0.10	)

⁽¹⁾

Net loss includes APL’s $690.5 million non-cash impairment charge for goodwill and other assets, APL’s $151.8 million non-cash derivative gain, and a $19.9 million gain from APL’s repurchase of approximately $60.0 million in face amount of its Senior Notes for an aggregate purchase price of approximately $40.1 million.

143

⁽²⁾	Net income includes a $222.0 million non-cash derivative gain and a $71.5 million cash derivative expense from APL’s early termination of certain derivative instruments.

⁽³⁾	Net loss includes a $181.1 million non-cash derivative loss and a $116.1 million cash derivative expense from the APL’s termination of certain derivative instruments.

⁽⁴⁾	Net loss includes APL’s $76.9 million non-cash derivative loss.

⁽⁵⁾	Restated to reflect amounts reclassified to discontinued operations due to APL’s sale of its NOARK gas gathering and interstate pipeline system (see Note 4).

⁽⁶⁾

For the fourth, second and first quarters of the year ended December 31, 2008, approximately 193,000, 511,000 and 585,000 phantom units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive

NOTE 21 – SUBSEQUENT EVENTS

144

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT

ATLAS PIPELINE HOLDINGS, L.P.

BALANCE SHEETS


	December 31,
	2009			2008
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	82		$	5,840
Prepaid expenses and other		—			2

Total current assets		82			5,842
Investment in subsidiaries⁽¹⁾		18,541			19,738
Other assets, net		73			142

	$	18,696		$	25,722

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable - affiliates	$	261		$	196
Current portion of long-term debt - affiliates		24,255			—
Current portion of long-term debt		8,000			—
Current portion of derivative liability		286			551
Accrued liabilities		201			52

Total current liabilities		33,003			799
Long term portion of derivative liability		—			174
Long term debt, less current portion		—			46,000
Commitments and contingencies

Partners’ Capital (deficit)		(14,307	)		(21,251	)

	$	18,696		$	25,722

⁽¹⁾	Investments in subsidiaries are recorded in accordance with the equity method of accounting

145

ATLAS PIPELINE HOLDINGS, L.P.

STATEMENTS OF OPERATIONS


	Years Ended December 31,
	2009			2008			2007
	(in thousands)
Revenues:
Equity earnings in subsidiaries	$	8,790		$	(68,242	)	$	(10,988	)
Other income (loss), net		(359	)		17			19

Total revenues		8,431			(68,225	)		(10,969	)

Costs and expenses:
General and administrative		1,652			3,566			3,575
Interest expense		2,744			1,862			1,103

Total costs and expenses		4,396			5,428			4,678

Net income (loss)	$	4,035		$	(73,653	)	$	(15,647	)

146

ATLAS PIPELINE HOLDINGS, L.P.

STATEMENTS OF CASH FLOWS


	Years Ended December 31,
	2009			2008			2007
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	4,035		$	(73,653	)	$	(15,647	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Non-cash compensation expense (income)		563			2,665			2,660
Distributions received from unconsolidated companies		4,012			52,891			26,443
Non-cash gain on derivatives		215			—			—
Amortization of deferred financing costs		162			124			109
Changes in operating assets and liabilities		7,679			67,828			10,916

Net cash provided by operating activities		16,666			49,855			24,481

CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in unconsolidated companies		(4,955	)		(20,013	)		(168,750	)
Capital contribution to unconsolidated subsidiaries		(658	)		(5,452	)		(23,076	)
Other		(94	)		(26	)		(33	)

Net cash used in investing activities		(5,707	)		(25,491	)		(191,859	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from subordinate loan with Atlas Energy, Inc.		23,000			—			—
Net proceeds from issuance of common limited partner units		—			10,001			167,150
Distributions paid to common limited partners		(1,660	)		(49,272	)		(24,788	)
Net proceeds from borrowings under credit facility		—			21,000			25,000
Repayments under credit facility		(38,000	)		—			—
Other		(57	)		(402	)		(238	)

Net cash (used in) provided by financing activities		(16,717	)		(18,673	)		167,124

Net change in cash and cash equivalents		(5,758	)		5,691			(254	)
Cash and cash equivalents, beginning of year		5,840			149			403

Cash and cash equivalents, end of year	$	82		$	5,840		$	149

147

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.

CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our General Partner’s Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision of our General Partner’s Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our General Partner’s Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2009, our disclosure controls and procedures were effective at the reasonable assurance level.

Management’s Report on Internal Control over Financial Reporting

The management of our General Partner is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of management, including our General Partner’s Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of internal control over financial reporting based upon criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework (COSO framework).

An effective internal control system, no matter how well designed, has inherent limitations, including the possibility of human error and circumvention or overriding of controls and therefore can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, effectiveness of an internal control system in future periods cannot be guaranteed because the design of any system of internal controls is based in part upon assumptions about the likelihood of future events. There can be no assurance that any control design will succeed in achieving its stated goals under all potential future conditions. Over time certain controls may become inadequate because of changes in business conditions, or the degree of compliance with policies and procedures may deteriorate. As such, misstatements due to error or fraud may occur and not be detected.

Based on our evaluation under the COSO framework, management concluded that internal control over financial reporting was effective at the reasonable assurance level as of December 31, 2009. Grant Thornton LLP, an independent registered public accounting firm and auditors of our consolidated financial statements, has issued its report on the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2009, which is included herein.

There have been no changes in our internal control over financial reporting during the fourth quarter of 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unitholders

Atlas Pipeline Holdings, L.P.

We have audited Atlas Pipeline Holdings, L.P.’s (a Delaware limited partnership) internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Atlas Pipeline Holdings, L.P.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on Atlas Pipeline Holdings, L.P.’s internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Atlas Pipeline Holdings, L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Atlas Pipeline Holdings, L.P. and subsidiaries as of December 31, 2009 and 2008 and the related consolidated statements of operations, comprehensive income (loss), partners’ capital and cash flows for each of the three years in the period ended December 31, 2009, and our report dated March 5, 2010 expressed an unqualified opinion thereon.


/s/ GRANT THORNTON LLP

Tulsa, Oklahoma
March 5, 2010

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ITEM 9B.

OTHER INFORMATION

None.

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PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Our general partner manages our activities. Unitholders do not directly or indirectly participate in our management or operation or have actual or apparent authority to enter into contracts on our behalf or to otherwise bind us. Our general partner will be liable, as general partner, for all of our debts to the extent not paid, except to the extent that indebtedness or other obligations incurred by us are specifically with recourse only to our assets. Whenever possible, our general partner intends to make any of our indebtedness or other obligations with recourse only to our assets.

As set forth in our Partnership Governance Guidelines and in accordance with NYSE listing standards, the non-management members of the managing board will meet in executive session regularly without management. The managing board member who presides at these meetings will rotate each meeting. The purpose of these executive sessions is to promote open and candid discussion among the non-management board members. Interested parties wishing to communicate directly with the non-management members may contact the chairman of the audit committee, Harvey Magarick. Correspondence to Mr. Magarick should be marked “Confidential” and sent to Mr. Magarick’s attention, c/o Atlas Pipeline Holdings, L.P., 1845 Walnut Street, 10^th Floor, Philadelphia, PA 19103.

The independent board members comprise all of the members of both of the managing board’s committees: the conflicts committee and the audit committee. The conflicts committee has the authority to review specific matters as to which the managing board believes there may be a conflict of interest to determine if the resolution of the conflict proposed by our general partner is fair and reasonable to us. Any matters approved by the conflicts committee are conclusively judged to be fair and reasonable to us, approved by all our partners and not a breach by our general partner or its managing board of any duties they may owe us or the unitholders. The audit committee reviews the external financial reporting by our management, the audit by our independent public accountants, the procedures for internal auditing and the adequacy of our internal accounting controls.

As is commonly the case with publicly traded limited partnerships, we do not directly employ any of the persons responsible for our management or operation. Rather, Atlas Energy personnel manage and operate our business. Officers of our general partner may spend a substantial amount of time managing the business and affairs of Atlas Energy and its affiliates and may face a conflict regarding the allocation of their time between our business and affairs and their other business interests.

Board of Directors and Executive Officers of Our General Partner

The following table sets forth information with respect to the executive officers and directors of our general partner:


Name	Age	Position with the general partner	Year in which service began
Eugene N. Dubay	61	Chief Executive Officer, President and Director	2008
Eric T. Kalamaras	36	Chief Financial Officer	2009
Edward E. Cohen	71	Chairman of the Board	2006
Jonathan Z. Cohen	39	Vice Chairman of the Board	2006
Gerald R. Shrader	50	Chief Legal Officer and Secretary	2009
Robert W. Karlovich, III	32	Chief Accounting Officer	2009
Matthew A. Jones	48	Director	2006
William G. Karis	61	Director	2006
Jeffrey C. Key	44	Director	2006
Harvey G. Magarick	70	Director	2006
William R. Bagnell	47	Director	2009

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Eugene N. Dubay has been Chief Executive Officer, President and a director of our general partner since February 2009. Mr. Dubay has been President and Chief Executive Officer of Atlas Pipeline GP since January 2009. Mr. Dubay has served as a member of the managing board of Atlas Pipeline GP since October 2008, where he served as an independent member until his appointment as President and Chief Executive Officer. Mr. Dubay has been the President of Atlas Pipeline Mid-Continent, LLC since January 2009. Mr. Dubay was the Chief Operating Officer of Continental Energy Systems LLC (a successor to SEMCO Energy) from 2002 to January 2009. Mr. Dubay has also held positions with ONEOK, Inc. and Southern Union Company and has over 20 years experience in midstream assets and utilities operations, strategic acquisitions, regulatory affairs and finance. Mr. Dubay is a certified public accountant and a graduate of the U.S. Naval Academy. Throughout his career, Mr. Dubay has held positions of increasing responsibility in the energy industry. In these positions, Mr. Dubay has been responsible for developing and implementing strategic plans including, as applicable, regulatory strategies. This long-range approach is important to the Board’s development of Atlas Pipeline Partners’ strategic plans. This combined experience and approach served as the basis for Mr. Dubay’s appointment as a director.

Eric T. Kalamaras has been Chief Financial Officer of our general partner since September 2009. Mr. Kalamaras has been the Chief Financial Officer of Atlas Pipeline GP since September 2009. From 2003 to 2009, Mr. Kalamaras was Director of Energy Leveraged Finance & High Yield for Wells Fargo Securities, LLC (formerly Wachovia Securities, LLC), where he focused on equity and debt capital funding in public and private natural gas master limited partnerships. From 1999 to 2003, Mr. Kalamaras was an analyst with Banc of America Securities.

Edward E. Cohen has been the Chairman of the Board of our general partner since its formation in January 2006. Mr. Cohen served as the Chief Executive Officer of our general partner from its formation in January 2006 until February 2009. Mr. Cohen has been the Chairman of the managing board of Atlas Pipeline GP, since its formation in 1999. From 1999 to January 2009, Mr. Cohen was the Chief Executive Officer of Atlas Pipeline GP. Mr. Cohen also has been the Chairman of the Board and Chief Executive Officer of Atlas Energy (formerly known as Atlas America, Inc.) since its organization in 2000 and also served as its President from 2000 to October 2009 when Atlas Energy Resources became its wholly-owned subsidiary following its merger transaction. Mr. Cohen has been the Chairman of the Board and Chief Executive Officer of Atlas Energy Resources and its manager, Atlas Energy Management, Inc.; since their formation in June 2006. In addition, Mr. Cohen has been Chairman of the Board of Directors of Resource America, Inc. (a publicly-traded specialized asset management company) since 1990 and was its Chief Executive Officer from 1988 until 2004, and President from 2000 until 2003; Chairman of the Board of Resource Capital Corp. (a publicly-traded real estate investment trust) since its formation in September 2005 until November 2009 and still serves on its board; a director of TRM Corporation (a publicly-traded consumer services company) from 1998 to July 2007; and Chairman of the Board of Brandywine Construction & Management, Inc. (a property management company) since 1994. Mr. Cohen is the father of Jonathan Z. Cohen. Mr. Cohen has been active in the energy business since the late 1970s. Among the reasons for his appointment as a director, Mr. Cohen brings to the board the vast experience that he has accumulated through his activities as a financier, investor and operator in various parts of the country.

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Jonathan Z. Cohen has been Vice Chairman of the Board of our general partner since its formation in January 2006. Mr. Cohen has been the Vice Chairman of the managing board of Atlas Pipeline GP since its formation in 1999. Mr. Cohen also has been the Vice Chairman of the Board of Atlas Energy (formerly known as Atlas America, Inc.) since its organization in 2000. Mr. Cohen has been Vice Chairman of the Board of Atlas Energy Resources and Atlas Energy Management since their formation in June 2006. Mr. Cohen has been a senior officer of Resource America since 1998, serving as the Chief Executive Officer since 2004, President since 2003 and a director since 2002. Mr. Cohen has been Chief Executive Officer, President and a director of Resource Capital Corp. since its formation in 2005 and was a trustee and secretary of RAIT Financial Trust (a publicly-traded real estate investment trust) from 1997, and its Vice Chairman from 2003, until December 2006. Mr. Cohen is a son of Edward E. Cohen. Among the reasons for his appointment as a director, Mr. Cohen’s financial, business and energy experience add strategic vision to our General Partner’s board to assist with our growth and development.

Gerald R. Shrader has been our Chief Legal Officer and Secretary of our general partner since October 2009. Mr. Shrader has been the Chief Legal Officer and Secretary of Atlas Pipeline GP since October 2009 and has also been the General Counsel and a Senior Vice President of Atlas Pipeline Mid-Continent, LLC since August 2007. From January 2006 through July 2007, Mr. Shrader was the Assistant General Counsel of CMS Enterprises Company, a subsidiary of CMS Energy Corporation, a publicly-traded energy company. From November 2005 through January 2006, he was the General Counsel of Atlas Pipeline Mid-Continent, LLC. From July 2003 through November 2005, Mr. Shrader was self-employed, primarily providing consulting services to CMS Enterprises Company.

Robert W. Karlovich, III has been the Chief Accounting Officer of our general partner since November 2009. Mr. Karlovich has been the Chief Accounting Officer of Atlas Pipeline GP since November 2009. Before that, he was the Controller of Atlas Pipeline Mid-Continent, LLC, our wholly owned subsidiary, since September 2006. Mr. Karlovich was the Controller for Syntroleum Corporation, a publicly-traded energy company, from April 2005 until September 2006, and Accounting Manager from February 2004. Mr. Karlovich also worked as a public accountant with Arthur Andersen LLP and Grant Thornton LLP where he served numerous public clients and energy companies. Mr. Karlovich is a certified public accountant.

Matthew A. Jones has been the Chief Financial Officer of Atlas Energy since March 2005. Mr. Jones has been the Chief Financial Officer of Atlas Energy Resources and Atlas Energy Management since their formation. Mr. Jones served as the Chief Financial Officer of our general partner from January 2006 to September 2009 and as the Chief Financial Officer of Atlas Pipeline GP from March 2005 to September 2009. From 1996 to 2005, Mr. Jones worked in the Investment Banking Group at Friedman Billings Ramsey, concluding as Managing Director. Mr. Jones worked in Friedman Billings Ramsey’s Energy Investment Banking Group from 1999 to 2005, and in Friedman Billings Ramsey’s Specialty Finance and Real Estate Group from 1996 to 1999. Mr. Jones is a Chartered Financial Analyst. Based on his experience with Friedman Billings Ramsey, Mr. Jones has extensive experience in the capital markets relating to the energy industry. This experience is critical to a strategic evaluation of our financing options and capital needs and served as a basis, among other reasons, for his appointment as a director. Since joining the Partnership, Mr. Jones’ experience has been fundamental to negotiating ours and APL’s credit facilities, as well as their equity and debt offerings.

William G. Karis has been the principal of Karis and Associates, LLC, a consulting company that provides financial and consulting services to the coal industry, since 1997. Prior to that, Mr. Karis was President and CEO of CONSOL Inc. (now CONSOL Energy Company). Mr. Karis is a member of the Boards of Directors and is Chairman of the Audit and Finance Committees of Blue Danube Inc., and Greenbriar Minerals, LLC. Mr. Karis has extensive experience in the energy industry, primarily relating to coal. Mr. Karis’ experience in the coal industry has helped the Board shape its thinking regarding the relative competition between APL’s products in relation to other energy sources (most notably coal). Mr. Karis also brings valuable management insight in various areas based on his experience as a chief executive officer. These combined experiences and insight serve as the basis, among other reasons, for Mr. Karis’ appointment as a director.

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Jeffrey C. Key is Vice President, Corporate Development for Tekelec, a supplier of telecommunications equipment and has been with Tekelec since 2004. From 2002 to 2004, Mr. Key was the Managing Partner of his own consulting firm, Key Technology Partners, LLC, which provided strategy development and planning services to communications and networking technology companies. From 2000 to 2002, Mr. Key was a Managing Director of Investment Banking at Bear, Sterns & Co. Inc. Mr. Key has extensive experience in strategic planning and growth projects, complemented by investment banking experience. Among the reasons for his appointment as a director, Mr. Key’s finance and planning experience are critical in understanding our capital needs and understanding our credit facilities and other capital alternatives.

Harvey G. Magarick has maintained his own consulting practice since June 2004. From 1997 to 2004, Mr. Magarick was a partner at BDO Seidman. Mr. Magarick is a member of the Board of Trustees of the Hirtle Callaghan Trust, an investment fund, and has been the Chairman of its audit committee since 2004. Mr. Magarick brings a strong accounting background to our General Partner’s board and, as a “financial expert”, serves as the chair of our audit committee. Mr. Magarick’s accounting experience is critical to an understanding of the varied issues that face us. This experience, among other reasons, serves as the basis for Mr. Magarick’s appointment as a director.

William R. Bagnell has been Vice President of Energy for Planalytics, Inc., an energy industry risk management and software company, since March 2000. Before that, he served as Director of Business Development for Buckeye Pipeline Partners, L.P. (a refined petroleum products transportation company) from October 1992 until February 2000. Mr. Bagnell served as a director of Atlas Energy from February 2004 until July 2009. Mr. Bagnell’s experience includes matters related to weather-modeling and risk assessment. Among the reasons for his appointment as a director, Mr. Bagnell has valuable management and business development experience, in particular with respect to limited partnerships like APL, based on his experience with Buckeye Pipeline Partners.

We have assembled a board of directors of our General Partner comprised of individuals who bring diverse but complementary skills and experience to oversee our business and based upon the experience and attributes of the directors discussed herein, our board of our General Partner determined that each of the directors should, as of the date hereof, serve on the board of our General Partner.

We administer our risk oversight function through our audit committee as well as through our board of directors of our General Partner as a whole. Our audit committee was appointed to assist our board of directors in fulfilling its oversight duties. Our audit committee is empowered to appoint and oversee our independent auditors, monitor the integrity of our financial reporting processes and systems of internal controls and provide an avenue of communication among our independent auditors, management, our internal auditing department and our board of directors. Additionally, individuals who oversee risk management in liquidity and credit areas, and environmental, litigation and other operational areas provide reports to our board of directors during regular board meetings.

Edward E. Cohen serves as the chairman of the board of directors of our General Partner and Eugene N. Dubay serves as our chief executive officer of our General Partner. The board of directors of our General Partner believes that oversight of management is an important component of an effective board of directors. The board of directors of our General Partner believes that the most effective leadership structure at the present time is for separation of the chairman of the board of directors from the chief executive officer position. The board of directors believes that because the chief executive officer is ultimately responsible for our day-to-day operations and for executing our strategy, we are best served to have a separate role of chairman of the board of directors of our General Partner as it allows for proper oversight, guidance and accountability. The chief executive officer contacts the chairman of the board of directors on a regular basis and provides status updates of operations during these discussions.

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Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires executive officers and managing board members of our general partner and persons who beneficially own more than 10% of a registered class of our equity securities to file reports of ownership and changes in ownership with the Securities and Exchange Commission and to furnish us with copies of all such reports.

Based solely upon our review of reports received by us, or representations from certain reporting persons that no filings were required for those persons, we believe that during fiscal year 2009 our executive officers, managing board members of our general partner and persons who beneficially owned more than 10% of our common units complied with all applicable filing requirements of Section 16(a) of the Securities Exchange Act, except Mr. Dubay inadvertently filed one Form 3 late and Mr. Jones inadvertently filed one Form 4 late.

Information Concerning the Audit Committee

Our board of directors has a standing audit committee. All of the members of the audit committee are independent directors as defined by NYSE rules. The members of the audit committee are Mr. Karis, Mr. Key and Mr. Magarick, with Mr. Magarick acting as the chairman. Our managing board has determined that Mr. Magarick is an “audit committee financial expert,” as defined by SEC rules. The audit committee reviews the scope and effectiveness of audits by the independent accountants, is responsible for the engagement of independent accountants and reviews the adequacy of our internal controls.

Compensation Committee Interlocks and Insider Participation

Neither we nor the board of directors of our general partner has a compensation committee. Compensation of the personnel of Atlas Energy and its affiliates who provide us with services is set by Atlas Energy and such affiliates. There was no allocation of the salaries of such personnel to us; however, Atlas Energy allocates the salaries of such personnel for reimbursement by APL.

None of the independent directors is an employee or former employee of ours or of our general partner. No executive officer of our general partner is a director or executive officer of any entity in which an independent director is a director or executive officer.

Code of Business Conduct and Ethics, Partnership Governance Guidelines and Audit Committee Charter

We have adopted a code of business conduct and ethics that applies to the principal executive officer, principal financial officer and principal accounting officer of our general partner, as well as to persons performing services for us generally. We have also adopted Partnership Governance Guidelines and a charter for the audit committee. We will make a printed copy of our code of ethics, our Partnership Governance Guidelines and our audit committee charter available to any unitholder who so requests. Requests for print copies may be directed to us as follows: Atlas Pipeline Holdings, L.P., Westpointe Corporate Center, 1550 Coraopolis Heights Road, Moon Township, Pennsylvania 15108, Attention: Secretary. Each of the code of business conduct and ethics, the Partnership Governance Guidelines and the audit committee charter are posted, and any waivers we grant to our code of business conduct and ethics will be posted, on our website at www. atlaspipelineholdings.com.

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ITEM 11.

EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

We are required to provide information regarding the compensation program in place as of December 31, 2009, for Atlas Pipeline GP’s CEO, CFO and the three other most highly-compensated executive officers. In this report, we refer to Atlas Pipeline GP’s CEO, CFO and the other three most highly-compensated executive officers as our “named executive officers” or “NEOs.” This section should be read in conjunction with the detailed tables and narrative descriptions below.

Except for the Atlas Pipeline Mid-Continent, LLC 2009 Equity-Indexed Bonus Plan (the “APLMC Plan”), we do not directly compensate our NEOs. Rather, Atlas Energy allocates the compensation of our executive officers between activities on behalf of us and Atlas Pipeline and activities on behalf of itself and its other affiliates based upon an estimate of the time spent by such persons on activities for us and APL and for Atlas Energy and its affiliates. Because Messrs. Dubay, Kalamaras, Shrader and Karlovich devote all of their time to us and APL, all of their compensation costs are allocated to APL. APL reimburses Atlas Energy for the compensation allocated to it for its and our executive officers. Atlas Energy does not make a separate allocation to us. Because Atlas Energy employs our NEOs, its compensation committee, comprised solely of independent directors, has been responsible for formulating and presenting recommendations to its Board of Directors with respect to the compensation of our NEOs. The Atlas Energy compensation committee has also been responsible for administering our employee benefit plans, including our and APL’s incentive plans.

Compensation Objectives

We believe that our compensation program must support our business strategy, be competitive, and provide both significant rewards for outstanding performance and clear financial consequences for underperformance. We also believe that a significant portion of the NEOs’ compensation should be “at risk” in the form of annual and long-term incentive awards that are paid, if at all, based on individual and company accomplishment. Accounting and cost implications of compensation programs are considered in program design; however, the essential consideration is that a program is consistent with our business needs.

Compensation Methodology

The Atlas Energy compensation committee generally makes recommendations to the Atlas Energy board on compensation amounts shortly after the close of its (and our) fiscal year. In the case of base salaries, it recommends the amounts to be paid for the new fiscal year. In the case of annual bonus and long-term incentive compensation, the committee recommends the amount of awards based on the then concluded fiscal year. Atlas Energy and we typically pay cash awards and issue equity awards in February, although the Atlas Energy compensation committee has the discretion to recommend salary adjustments and the issuance of equity awards at other times during the fiscal year. In addition, some of our NEOs who also perform services for Atlas Energy and its other subsidiaries may receive stock-based awards from Atlas Energy and these subsidiaries, each of which have delegated compensation decisions to the Atlas Energy compensation committee because they, like us, do not have their own employees.

Each year, our Chairman, who also serves as Atlas Energy’s Chief Executive Officer and Chairman, provides the Atlas Energy compensation committee with key elements of Atlas Energy’s, our and our NEOs’ performance during the year. Our Chairman makes recommendations to the compensation committee regarding the salary, bonus, and incentive compensation component of each NEO’s total compensation. Our Chairman, at the compensation committee’s request, may attend committee meetings; however, his role during the meetings is to provide insight into Atlas Energy’s and our company’s performance, as well as the performance of other comparable companies in the same industry.

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Compensation Consultant

The Atlas Energy compensation committee has retained Mercer (US) Inc. on an annual basis to provide information, analyses, and advice regarding executive compensation. In June 2009, the compensation committee engaged Mercer to conduct a competitive review of its then current NEO compensation program. This review included three of our NEOs: Messrs. E. Cohen, J. Cohen and M. Jones. Mercer provided a proxy analysis based on a peer group of 14 energy companies, which we refer to as the full peer group, against which Atlas Energy competes for executive talent, land and mineral rights, oil and gas services, pipeline and takeaway capacity, and/ or water disposal capacity. The peer group consists of: Anadarko Petroleum Corporation, Chesapeake Energy Corporation, Cabot Oil & Gas Corporation, CONSOL Energy Inc., EQT Corporation, Exco Resources, Inc., Linn Energy, LLC, MarkWest Energy Partners, L.P., Quicksilver Resources Inc., Pioneer Natural Resources Company, Range Resources Corporation, Southwestern Energy Company, The Williams Companies, Inc., and XTO Energy Inc. In our business, we compete against some of the members of the peer group for takeaway capacity, processing services and/or water disposal capacity.

Mercer also analyzed a 10-company subset of the full peer group, which we refer to as the size-adjusted peer group, that included companies’ 2008 revenues of between $750 million to $3 billion, that is, approximately one-half to twice Atlas Energy’s revenues. The size-adjusted peer group excluded Anadarko Petroleum, Chesapeake Energy, Williams, and XTO Energy. In addition, Mercer provided a survey analysis of competitive data gathered from published surveys.

The compensation committee does not set a specific percentile range for NEO compensation amounts. Rather, it uses the comparative information as part of the total mix of information it considers.

In addition to the competitive analysis of the NEO compensation program, at the compensation committee’s direction, Mercer provided the following services for the committee during fiscal 2009:

•

provided advice with respect to Atlas Energy’s new long-term incentive plan;

•

advised the committee with respect to awards for 2009 under Atlas Energy’s Senior Executive Plan, discussed below, and established performance measures and performance targets for 2010; and

•

provided advice on the employment agreement for Mr. Jones.

In the course of conducting its activities for fiscal 2009, Mercer attended five meetings of the compensation committee and presented its findings and recommendations for discussion.

The compensation committee has established procedures that it considers adequate to ensure that Mercer’s advice remains objective and is not unduly influenced by Atlas Energy’s management. These procedures include: a direct reporting relationship of the Mercer consultant to the chairman of the compensation committee; provisions in the engagement letter with Mercer specifying the information, data, and recommendations that can and cannot be shared with management; an annual update to the compensation committee on Mercer’s financial relationship with Atlas Energy, including a summary of the work performed for Atlas Energy during the preceding 12 months; and written assurances from Mercer that, within the Mercer organization, the Mercer consultant who performs services for the compensation committee has a reporting relationship and compensation determined separately from Mercer’s other lines of business and from its other work for Atlas Energy. In fact, Mercer did not perform non-executive compensation consulting services for Atlas Energy during the last fiscal year or during any other year. With the consent of the compensation committee chair, Mercer may contact Atlas Energy’s executive officers for information necessary to fulfill its assignment and may make reports and presentations to and on behalf of the compensation committee that the executive officers also receive.

In making its compensation decisions, the compensation committee meets in executive session, without management, both with and without Mercer. Ultimately, the decisions regarding executive

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compensation are made by the compensation committee after extensive discussion regarding appropriate compensation and may reflect factors and considerations other than the information and advice provided by Mercer and our Chairman. The compensation committee’s decisions are then submitted to the Board.

Elements of our Compensation Program

Our executive officer compensation package includes a combination of annual cash and long-term incentive compensation. Annual cash compensation is comprised of an allocation of base salary plus cash bonus awarded by Atlas Energy. Long-term incentives consist of a variety of equity awards. Both the annual cash incentives and long-term incentives may be performance-based.

Base Salary

Base salary is intended to provide fixed compensation to the NEOs for their performance of core duties that contributed to the success of Atlas Energy and us. Base salaries are not intended to compensate individuals for extraordinary performance or for above average company performance.

Annual Incentives

Annual incentives are intended to tie a significant portion of each of the NEO’s compensation to Atlas Energy’s annual performance and /or that of one of Atlas Energy’s subsidiaries or divisions for which the officer is responsible. Generally, the higher the level of responsibility of the executive within Atlas Energy, the greater is the incentive component of that executive’s target total cash compensation. The Atlas Energy compensation committee may recommend awards of performance-based bonuses and discretionary bonuses.

Performance-Based Bonuses— The Atlas Energy Annual Incentive Plan for Senior Executives, which we refer to as the Senior Executive Plan, provides awards for the achievement of predetermined, objective performance measures over a specified 12-month performance period, generally Atlas Energy’s fiscal year. Awards under the Senior Executive Plan may be paid in cash or in shares of Atlas Energy’s common stock under its stock incentive plan. The Senior Executive Plan is designed to permit Atlas Energy to qualify for an exemption from the $1,000,000 deduction limit under Section 162(m) of the Internal Revenue Code for compensation paid to the NEOs. Notwithstanding the existence of the Senior Executive Plan, the Atlas Energy compensation committee believes that the interests of Atlas Energy’s stockholders and our unitholders are best served by not restricting its discretion and flexibility in crafting compensation, even if the compensation amounts result in non-deductible compensation expense. Therefore, the committee reserves the right to approve compensation that is not fully deductible.

In March 2009, the compensation committee approved 2009 target bonus awards to be paid from a bonus pool. The bonus pool is equal to 18.3% of Atlas Energy’s adjusted distributable cash flow unless the adjusted distributable cash flow includes any capital transaction gains in excess of $50 million, in which case only 10% of that excess will be included in the bonus pool. If the adjusted distributable cash flow does not equal at least 75% of the average adjusted distributable cash flow for the previous 3 years, no bonuses will be paid. Adjusted distributable cash flow means the sum of (i) cash available for distribution to Atlas Energy by any of its subsidiaries (regardless of whether such cash is actually distributed), plus (ii) interest income during the year, plus (iii) to the extent not otherwise included in adjusted distributable cash flow, any realized gain on the sale of securities, including securities of a subsidiary, less (iv) Atlas Energy’s stand-alone general and administrative expenses for the year excluding any bonus expense (other than non-cash bonus compensation included in general and administrative expenses), and less (v) to the extent not otherwise included in adjusted distributable cash flow, any loss on the sale of securities, including securities of a subsidiary. A return of Atlas Energy’s capital investment in a subsidiary is not intended to be included and, accordingly, if adjusted distributable cash flow includes proceeds from the sale of all or substantially all of the assets of a subsidiary, the amount of such proceeds to be included in adjusted distributable cash flow will be reduced by its basis in the subsidiary. The maximum award payable, expressed as a percentage of Atlas Energy’s estimated 2009

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adjusted distributable cash flow, for our NEO participants was as follows: Edward E. Cohen, 6.14%; Jonathan Z. Cohen, 4.37% and Matthew A. Jones, 3.46%. Pursuant to the terms of the Senior Executive Plan, the compensation committee has the discretion to recommend reductions, but not increases, in awards under the plan. As set forth below, actual awards for 2009 were substantially less than the maximum award permitted under the plan. In February 2010, the compensation committee approved target bonus awards identical to the 2009 target bonus awards.

Discretionary Bonuses—Discretionary bonuses may be awarded to recognize individual and group performance. Mr. Shrader received a cash bonus of $50,000 in recognition of his performance in connection with the disposition of our NOARK assets.

Long-Term Incentives

We believe that our long-term success depends upon aligning our executives’ and unitholders’ interests. To support this objective, Atlas Energy provides our executives with various means to become significant equity holders, including awards under our Long-Term Incentive Plan, which we refer to as our Plan. Our NEOs are also eligible to receive awards under the Atlas Energy Stock Incentive Plans, which we refer to as the Atlas Plans, and the Atlas Pipeline Partners Long-Term Incentive Plan, which we refer to as the APL Plan, as appropriate.

Grants under our Plan: The Atlas Energy compensation committee may recommend grants of equity awards in the form of options and/or phantom units. Generally, the unit options and phantom units vest 25% on the third anniversary and 75% on the fourth anniversary of the date of grant.

Grants under Other Plans: As described above, our NEOs who perform services for us and one or more of Atlas Energy’s subsidiaries may receive stock-based awards under the Atlas Plan or the APL Plan.

Supplemental Benefits, Deferred Compensation and Perquisites

We do not provide supplemental benefits for executives and perquisites are discouraged. Atlas Energy does provide a Supplemental Executive Retirement Plan for Messrs. E. Cohen and J. Cohen pursuant to their employment agreements, but none of those benefits or related costs are allocated to us. None of our NEOs have deferred any portion of their compensation.

Employment Agreements

Generally, Atlas Energy does not favor employment agreements unless they are required to attract or to retain executives to the organization. It entered into employment agreements Messrs. E. Cohen, J. Cohen, E. Dubay, M. Jones and E. Kalamaras. See “Employment Agreements and Potential Payments Upon Termination or Change of Control.” The Atlas Energy compensation committee takes termination compensation payable under these agreements into account in determining annual compensation awards, but ultimately its focus is on recognizing each individual’s contribution to Atlas Energy’s and our performance during the year.

Determination of 2009 Compensation Amounts

As described above, after the end of Atlas Energy’s 2009 fiscal year, the Atlas Energy compensation committee set the base salaries of our NEOs for the 2010 fiscal year and recommended incentive awards based on the prior year’s performance. In carrying out its function, the Atlas Energy compensation committee acted in consultation with Mercer.

In determining the actual amounts to be paid to the NEOs, the Atlas Energy compensation committee considered both individual and company performance. Our CEO makes recommendations of award amounts based upon the NEOs’ individual performances as well as the performance of Atlas Energy’s subsidiaries for

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which each NEO provides service; however, the Atlas Energy compensation committee has the discretion to approve, reject, or modify the recommendations. The Atlas Energy compensation committee noted that our management team had repositioned us through renegotiation of bank arrangements, strengthened hedging, increased volumes, effectuated a joint venture with Williams, and restructured the Mid-Continent division. In addition, the compensation committee reviewed the calculations of Atlas Energy’s adjusted distributable cash flow and determined that 2009 adjusted distributable cash flow exceeded the pre-determined minimum threshold of 75% of the average adjusted distributable cash flow for the previous three years by more than 50%.

Base Salary. Following a review of the analysis conducted by Mercer in June 2009 of the Atlas Energy NEOs’ compensation, the compensation committee determined to increase base salaries by $100,000 effective July 1, 2009 for each of its NEOs, including those of Messrs. E. Cohen, J. Cohen and M. Jones, and for Mr. Dubay. In light of these interim increases, the compensation committee determined at the end of the 2009 fiscal year that the adjusted base salaries for those individuals were appropriate for the 2010 fiscal year. In addition, the compensation committee set 2010 salaries for our other NEOs as follows: Mr. Kalamaras-$275,000 Mr. Karlovich-$180,000; and Mr. Shrader-$275,000. These amounts represent a 10% increase from the 2009 base salaries for each of Messrs. Kalamaras and Shrader. Mr. Karlovich’s base salary was increased by 22% as a result of an internal company survey which indicated that his previous salary was not commensurate with his position and responsibilities.

Annual Incentives

Performance-Based Bonuses. As described above, Atlas Energy substantially outperformed the incentive goals that had been set under the Senior Executive Plan. Based upon this performance, the compensation committee recommended that Atlas Energy award cash incentive bonuses to its NEOs as follows: Edward E. Cohen, $2,500,000; Jonathan Z. Cohen, $2,000,000; and Matthew A. Jones, $800,000. The compensation committee also recommended that each of the NEOs receive an amount of Atlas Energy restricted stock units equivalent to their cash bonuses. The restricted stock units will vest 25% per annum. The aggregate annual incentive awards were less than the maximum amount payable to each of the NEOs pursuant to the predetermined percentages established under the Senior Executive Plan, which were as follows: Edward E. Cohen, $8,639,000; Jonathan Z. Cohen, $6,148,000; and Matthew A. Jones.

Discretionary Bonuses. Messrs. Dubay, Kalamaras, Karlovich and Shrader are not participants in the Senior Executive Plan. Therefore, the compensation committee awarded them discretionary bonuses as follows: Mr. Dubay-$500,000 in cash and $500,000 in Atlas Energy restricted stock units that vest over four years, Mr. Kalamaras-$72,917, Mr. Karlovich-$73,308; and Mr. Shrader-$250,000. Because the Atlas Energy restricted stock unit award was made after our fiscal year end, it is not included, under new SEC rules, in our Summary Compensation Table for 2009, but will be included in our table for 2010.

Long-Term Incentives. In order to retain management and in recognition of company and individual accomplishments in 2009 as set forth above, the compensation committee determined to award Atlas Energy stock options to Messrs. Dubay and Kalamaras which vest 25% per year on the anniversary of the grant date as follows: Mr. Dubay-70,000 and Mr. Kalamaras-19,000. Because the Atlas Energy stock option awards were made after our fiscal year end, it is not included, under new SEC rules, in our Summary Compensation Table for 2009, but will be included in our table for 2010.

Dubay Employment Agreement. Pursuant to the terms of his employment agreement in January 2009, Mr. Dubay was granted the following awards:

•

Options to purchase 100,000 shares of Atlas Energy’s common stock, which vest 25% per year on each anniversary of the effective date of the agreement;

•

Options to purchase 100,000 of APL common units, which vest 25% per year on each anniversary of the effective date of the agreement; and

•

Options to purchase 100,000 our common units, which vest 25% on the third anniversary, and 75% on the fourth anniversary, of the effective date of the agreement.

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APLMC Plan Awards. The APLMC Plan specifically prohibits awards to anyone who is a named executive officer at the time of the grant. Messrs. Shrader and Karlovich received awards under the APLMC Plan, but were granted those awards prior to becoming named executive officers. No additional grants to our named executive officers can be made under the APLMC Plan. In addition, upon execution of his employment agreement in September 2009, Mr. Kalamaras was awarded 50,000 bonus units.

Summary Compensation Table


Name and Principal Position	Year	Salary ($)		Bonus ($)			Stock Awards ($)⁽¹⁾			Option Awards ($)⁽²⁾		Non-Equity Incentive Plan Compensation ($)		All Other Compensation ($)			Total ($)
Eugene N. Dubay, Chief Executive Officer and President⁽⁴⁾	2009	$	438,847	$	500,000		$	—		$	564,000	$	—	$	555,805	⁽³⁾	$	2,058,652

Eric T. Kalamaras,⁽⁵⁾Chief Financial Officer	2009		157,000		152,917	⁽⁶⁾		66,620	⁽⁷⁾		—		—		—			376,537

Edward E. Cohen, Chairman of the Board and Former Chief Executive Officer and President⁽⁸⁾	2009		147,577		—			—			—		375,000		12,600	⁽⁹⁾		535,177
	2008		135,000		—			—			3,507,000		—		257,938			3,899,938
	2007		405,000		—			4,612,160			1,205,000		2,250,000		253,212			8,725,372

Matthew A. Jones, Former Chief Financial Officer of Atlas Pipeline GP	2009		126,270		—			—			—		280,000		3,950	⁽¹⁰⁾		410,220
	2008		135,000		—						1,402,800		—		67,713			1,605,513
	2007		135,000		—			461,216			120,500		900,000		75,062			1,691,778

Jonathan Z. Cohen, Vice Chairman of Atlas Pipeline GP	2009		101,539		—			—			—		300,000		7,863	⁽¹¹⁾		409,402
	2008		90,000		—			—			2,805,600		—		113,488			3,009,088
	2007		215,217		—			2,306,080			482,000		1,434,783		153,906			4,591,986

Gerald R. Shrader, Chief Legal Officer	2009		224,616		300,000	⁽¹²⁾		96,000	⁽⁷⁾		—		—		—			620,616

Robert W. Karlovich, III Chief Accounting Officer	2009		152,255		73,308			48,000	⁽⁷⁾		—		—		—			273,563

⁽¹⁾	Represents the fair value on the date of grant of the (i) phantom units granted under our Plan and (ii) phantom units granted under the APL Plan as well as under the APLMC Plan, all in accordance with prevailing accounting literature.

⁽²⁾	Represents the fair value on the date of grant of the (i) options granted under our Plan; (ii) options granted under the AHD Plan; and, with respect to Mr. Dubay, (iii) options granted under the Atlas Energy Plan, all in accordance with prevailing accounting literature.

⁽³⁾

Includes our net cost of $526,768 related to the purchase and subsequent sale of Mr. Dubay’s home, calculated by subtracting the sale price and related legal and maintenance expenses from the purchase price and moving expenses of $28,772. Also includes payments on DERs of $ 265 with respect to the phantom units awarded under the APL Plan.

⁽⁴⁾	On January 15, 2009, Eugene N. Dubay was appointed serve in the capacity of Chief Executive Officer and President of Atlas Holdings GP.

⁽⁵⁾	On September 7, 2009, Eric T. Kalamaras was appointed Chief Financial Officer of our general partner and of Atlas Pipeline Partners GP.

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⁽⁶⁾	Includes a signing bonus of $80,000.

⁽⁷⁾

Includes for Messrs. Shrader and Karlovich bonus unit awards made in 2009 under the APLMC Plan and for Mr. Kalamaras under an award agreement which, in each case, vest ratably over a three-year period from the date of grant. Consistent with FASB ASC Topic 718 and the assumptions disclosed in “Item 8: Financial Statements and Supplementary Data—Note 17”, amounts shown include only the amount allocated for the first year of the vesting period; the total amount of the awards is reflected in the “Stock awards” columns of the Outstanding Equity Awards a Fiscal-Year End Table. These awards are valued based on the closing price of our common units on the grant date. For financial statement purposes, the value of these awards is re-measured as of the end of each reporting period until they vest or are otherwise settled. The value of these awards reflected in “Item 8: Financial Statements and Supplementary Data—Note 17 APL’s Employee Incentive Compensation Plan and Agreement” based on the closing price of our common units on December 31, 2009 is as follows: Mr. Kalamaras-$490,500; Mr. Shrader-$490,500; and Mr. Karlovich-$245,250.

⁽⁸⁾	On January 15, 2009, Edward E. Cohen resigned as Chief Executive Officer when Eugene N. Dubay was appointed to serve in the capacity of Chief Executive Officer and President of Atlas Holdings GP.

⁽⁹⁾	Includes payments on DERs of $7,200 with respect to the phantom units awarded under the APL Plan and $5,400 with respect to phantom units awarded under our Plan.

⁽¹⁰⁾	Includes payments on DERs of $2,750 with respect to the phantom units awarded under the APL Plan and $1,200 with respect to phantom units awarded under our Plan.

⁽¹¹⁾	Represents payments on DERs of $5,163 with respect to the phantom units awarded under the APL Plan and $2,700 with respect to phantom units awarded under our Plan.

⁽¹²⁾	Includes a $50,000 bonus granted to Mr. Shrader in recognition of his performance in connection with the disposition of our NOARK assets.

Employment Agreements and Potential Payments Upon Termination or Change of Control

Edward E. Cohen

In May 2004, Atlas Energy entered into an employment agreement with Edward E. Cohen, who currently serves as our Chairman and, from January 2006 until February 2009, served as our Chief Executive Officer and President. The agreement was amended as of December 31, 2008 to comply with requirements under Section 409A of the Code relating to deferred compensation. As discussed above under “Compensation Discussion and Analysis,” Atlas Energy allocates a portion of Mr. Cohen’s compensation cost based on an estimate of the time spent by Mr. Cohen on our and APL’s activities. Atlas Energy adds 50% to the compensation amount allocated to APL to cover the costs of health insurance and similar benefits. The following discussion of Mr. Cohen’s employment agreement summarizes those elements of Mr. Cohen’s compensation that are allocated in part to APL.

The agreement has a term of three years and, until notice to the contrary, the term is automatically extended so that on any day on which the agreement is in effect it has a then-current three-year term. Mr. Cohen’s employment agreement was entered into in 2004, around the time that Atlas Energy was preparing to launch its initial public offering in connection with its spin-off from Resource America, Inc. At that time, it was important to establish a long-term commitment to and from Mr. Cohen as the Chief Executive Officer and then-current President of Atlas Energy. The rolling three-year term was determined to be an appropriate amount of time to reflect that commitment and was deemed a term that was commensurate with Mr. Cohen’s position. The multiples of the compensation components upon termination or a change of control, discussed below, were generally aligned with competitive market practice for similar executives at the time that the agreement was negotiated.

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The agreement provides the following regarding termination and termination benefits:

•

Upon termination of employment due to death, Mr. Cohen’s estate will receive (a) a lump sum payment in an amount equal to three times his final base salary and (b) automatic vesting of all stock and option awards.

•

Atlas Energy may terminate Mr. Cohen’s employment if he is disabled for 180 consecutive days during any 12-month period. If his employment is terminated due to disability, Mr. Cohen will receive (a) a lump sum payment in an amount equal to three times his final base salary, (b) a lump sum amount equal to the COBRA premium cost for continued health coverage, less the premium charge that is paid by Atlas Energy’s employees, during the three years following his termination, (c) a lump sum amount equal to the cost Atlas Energy would incur for life, disability and accident insurance coverage during the three-year period, less the premium charge that is paid by our employees, (d) automatic vesting of all stock and option awards and (e) any amounts payable under Atlas Energy’s long-term disability plan.

•

Atlas Energy may terminate Mr. Cohen’s employment without cause, including upon or after a change of control, upon 30 days’ prior written notice. He may terminate his employment for good reason. Good reason is defined as a reduction in his base pay, a demotion, a material reduction in his duties, relocation, his failure to be elected to Atlas Energy’s Board of Directors or Atlas Energy’s material breach of the agreement. Mr. Cohen must provide Atlas Energy with 30 days’ notice of a termination by him for good reason within 60 days of the event constituting good reason. Atlas Energy then would have 30 days in which to cure and, if it does not do so, Mr. Cohen’s employment will terminate 30 days after the end of the cure period. If employment is terminated by Atlas Energy without cause, by Mr. Cohen for good reason or by either party in connection with a change of control, he will be entitled to either (a) if Mr. Cohen does not sign a release, severance benefits under Atlas Energy’s then-current severance policy, if any, or (b) if Mr. Cohen signs a release, (i) a lump sum payment in an amount equal to three times his average compensation (defined as the average of the three highest years of total compensation), (ii) a lump sum amount equal to the COBRA premium cost for continued health coverage, less the premium charge that is paid by Atlas Energy’s employees, during the three years following his termination, (iii) a lump sum amount equal to the cost Atlas Energy would incur for life, disability and accident insurance coverage during the three-year period, less the premium charge that is paid by Atlas Energy’s employees, and (iv) automatic vesting of all stock and option awards.

•

Mr. Cohen may terminate the agreement without cause with 60 days notice to Atlas Energy, and if he signs a release, he will receive (a) a lump sum payment equal to one-half of one year’s base salary then in effect and (b) automatic vesting of all stock and option awards.

Change of control is defined as:

•

the acquisition of beneficial ownership, as defined in the Securities Exchange Act of 1933, of 25% or more of Atlas Energy’s voting securities or all or substantially all of Atlas Energy’s assets by a single person or entity or group of affiliated persons or entities, other than an entity affiliated with Mr. Cohen or any member of his immediate family;

•

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entity; or (b) Atlas Energy’s voting securities immediately prior to the transaction represent less than 60% of the combined voting power immediately after the transaction of Atlas Energy, the surviving entity or, in the case of a division, each entity resulting from the division;

•

during any period of 24 consecutive months, individuals who were Atlas Energy Board members at the beginning of the period cease for any reason to constitute a majority of the Atlas Energy Board, unless the election or nomination for election by Atlas Energy’s stockholders of each new director was approved by a vote of at least 2/3 of the directors then still in office who were directors at the beginning of the period; or

•

Atlas Energy’s stockholders approve a plan of complete liquidation or winding up of Atlas Energy, or agreement of sale of all or substantially all of Atlas Energy’s assets or all or substantially all of the assets of Atlas Energy’s primary subsidiaries to an unaffiliated entity.

Termination amounts will not be paid until 6 months after the termination date, if such delay is required by Section 409A. In the event that any amounts payable to Mr. Cohen upon termination become subject to any excise tax imposed under Section 4999 of the Code, Atlas Energy must pay Mr. Cohen an additional sum such that the net amounts retained by Mr. Cohen, after payment of excise, income and withholding taxes, equals the termination amounts payable, unless Mr. Cohen’s employment terminates because of his death or disability.

We anticipate that lump sum termination amounts paid to Mr. Cohen would be allocated to APL consistent with past practice and, with respect to payments based on three years’ of compensation, would be allocated to APL based on the average amount of time Mr. Cohen devoted to our and APL’s activities during the prior three-year period. The following table provides an estimate of the value of the benefits to Mr. Cohen if a termination event had occurred as of December 31, 2009.


Reason for termination	Lump sum severance payment			Benefits⁽¹⁾		Accelerated vesting of unit awards and option awards⁽²⁾		Tax gross- up⁽³⁾
Death	$	442,731	⁽⁴⁾	$	—	$	506,700	$	—
Disability		442,731	⁽⁴⁾		5,702		506,700		—
Termination by us without cause		2,210,077	⁽⁵⁾		5,702		506,700		—
Termination by Mr. Cohen for good reason		2,210,077	⁽⁵⁾		5,702		506,700		—
Change of control		2,210,077	⁽⁵⁾		5,702		506,700		926,455
Termination by Mr. Cohen without cause		73,789	⁽⁴⁾		—		506,700		—

(1)	Represents rates currently in effect for COBRA insurance benefits for 36 months.

(2)

Represents the value of unexercisable option and unvested unit awards disclosed in the “Outstanding Equity Awards at Fiscal Year-End Table.” The payments relating to option awards are calculated by multiplying the number of accelerated options by the difference between the exercise price and the closing price of the applicable units on December 31, 2009. The payments relating to awards are calculated by multiplying the number of accelerated shares or units by the closing price of the applicable unit on December 31, 2008.

(3)	Calculated after deduction of any excise tax imposed under section 4999 of the Code, and any federal, state and local income tax, FICA and Medicare withholding taxes, taking into account the 20% excess parachute payment rate and a 36.45% combined effective tax rate.

(4)	Calculated based on Mr. Cohen’s 2009 base salary.

(5)	Calculated based on Mr. Cohen’s average 2009, 2008 and 2007 base salary and bonus.

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Jonathan Z. Cohen

In January 2009, Atlas Energy entered into an employment agreement with Jonathan Z. Cohen, who currently serves as our Vice-Chairman. As discussed above under “Compensation Discussion and Analysis,” Atlas Energy allocates a portion of Mr. Cohen’s compensation cost based on an estimate of the time spent by Mr. Cohen on our and APL’s activities. The following discussion of Mr. Cohen’s employment agreement summarizes those elements of Mr. Cohen’s compensation that are allocated in part to APL.

Mr. Cohen’s employment agreement requires him to devote such time to Atlas Energy as is reasonably necessary to the fulfillment of his duties, although it permits him to invest and participate in outside business endeavors. The agreement provided for initial base compensation of $600,000 per year, which may be increased by the Atlas Energy board based upon its evaluation of Mr. Cohen’s performance. Mr. Cohen is eligible to receive incentive bonuses and stock option grants and to participate in all employee benefit plans in effect during his period of employment. The agreement has a term of three years and, until notice to the contrary, the term is automatically extended so that on any day on which the agreement is in effect it has a then-current three-year term. The rolling three-year term and the multiples of the compensation components upon termination or a change of control, discussed below, were generally aligned with competitive market practice for similar executives at the time that the employment agreement was negotiated.

The agreement provides the following regarding termination and termination benefits:

•

Upon termination of employment due to death, Mr. Cohen’s estate will receive (a) accrued but unpaid bonus and vacation pay and (b) automatic vesting of all equity-based awards.

•

Atlas Energy may terminate Mr. Cohen’s employment without cause upon 90 days’ prior notice or if he is physically or mentally disabled for 180 days in the aggregate or 90 consecutive days during any 365-day period and Atlas Energy’s board determines, in good faith based upon medical evidence, that he is unable to perform his duties. Upon termination by Atlas Energy other than for cause, including disability, or by Mr. Cohen for good reason (defined as any action or inaction that constitutes a material breach by Atlas Energy of the employment agreement or a change of control), Mr. Cohen will receive either (a) if Mr. Cohen does not sign a release, severance benefits under our then-current severance policy, if any, or (b) if Mr. Cohen signs a release, (i) a lump sum payment in an amount equal to three years of his average compensation (which is defined as his base salary in effect immediately before termination plus the average of the cash bonuses earned for the three calendar years preceding the year in which the termination occurred), less, in the case of termination by reason of disability, any amounts paid under disability insurance provided by us, (ii) monthly reimbursement of any COBRA premium paid by Mr. Cohen, less the amount Mr. Cohen would be required to contribute for health and dental coverage if he were an active employee and (iv) automatic vesting of all equity-based awards.

•

Atlas Energy may terminate Mr. Cohen’s employment for cause (defined as a felony conviction or conviction of a crime involving fraud, deceit or misrepresentation, failure by Mr. Cohen to materially perform his duties after notice other than as a result of physical or mental illness, or violation of confidentiality obligations or representations contained in the employment agreement). Upon termination by Atlas Energy for cause or by Mr. Cohen for other than good reason, Mr. Cohen’s vested equity-based awards will not be subject to forfeiture.

Change of control is defined as:

•

the acquisition of beneficial ownership, as defined in the Securities Exchange Act, of 25% or more of Atlas Energy’s voting securities or all or substantially all of Atlas Energy’s assets by a single person or entity or group of affiliated persons or entities, other than an entity affiliated with Mr. Cohen or any member of his immediate family;

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•

Atlas Energy consummates a merger, consolidation, combination, share exchange, division or other reorganization or transaction with an unaffiliated entity in which either (a) Atlas Energy’s directors immediately before the transaction constitute less than a majority of the board of the surviving entity, unless 1/2 of the surviving entity’s board were our directors immediately before the transaction and Atlas Energy’s Chief Executive Officer immediately before the transaction continues as the Chief Executive Officer of the surviving entity; or (b) Atlas Energy’s voting securities immediately prior to the transaction represent less than 60% of the combined voting power immediately after the transaction of Atlas Energy, the surviving entity or, in the case of a division, each entity resulting from the division;

•

during any period of 24 consecutive months, individuals who were Atlas Energy board members at the beginning of the period cease for any reason to constitute a majority of Atlas Energy’s board, unless the election or nomination for election by Atlas Energy’s stockholders of each new director was approved by a vote of at least 2/3 of the directors then still in office who were directors at the beginning of the period; or

•

Atlas Energy’s stockholders approve a plan of complete liquidation or winding up, or agreement of sale of all or substantially all of Atlas Energy’s assets or all or substantially all of the assets of its primary subsidiaries to an unaffiliated entity.

Termination amounts will not be paid until 6 months after the termination date, if such delay is required by Section 409A. We anticipate that lump sum termination amounts paid to Mr. Cohen would be allocated to APL consistent with past practice and, with respect to payments based on three years’ of compensation, would be allocated to APL based on the average amount of time Mr. Cohen devoted to our and APL’s activities during the prior three-year period. The following table provides an estimate of the value of the benefits to Mr. Cohen if a termination event had occurred as of December 31, 2009.


Reason for termination	Lump sum severance payment			Benefits⁽¹⁾		Accelerated vesting of unit awards and option awards⁽²⁾
Death	$	—		$	—	$	233,850
Termination by us other than for cause (including disability) or by Mr. Cohen for good reason (including a change of control)		1,738,616	⁽³⁾		—		233,850
Termination by us for cause or by Mr. Cohen for other than good reason		—			—		—

⁽¹⁾	Mr. J. Cohen does not currently receive benefits from Atlas Energy.

⁽²⁾

Represents the value of unexercisable option and unvested unit awards disclosed in the “Outstanding Equity Awards at Fiscal Year-End Table.” The payments relating to option awards are calculated by multiplying the number of accelerated options by the difference between the exercise price and the closing price of the applicable unit on December 31, 2009. The payments relating to unit awards are calculated by multiplying the number of accelerated units by the closing price of the applicable unit on December 31, 2009.

⁽³⁾	Calculated based on Mr. J. Cohen’s average 2009, 2008 and 2007 base salary and bonus.

Eugene N. Dubay

In January 2009, Atlas Energy entered into an employment agreement with Eugene N. Dubay, who currently serves as our President and Chief Executive Officer. As discussed above under “Compensation Discussion and Analysis,” Atlas Energy allocates all of Mr. Dubay’s compensation cost to us and Atlas Pipeline Partners.

The agreement provide s for an initial base salary of $400,000 per year and a bonus of not less than $300,000 for the period ending December 31, 2009. After that, bonuses will be awarded solely at the discretion of Atlas Energy’s compensation committee. In addition to reimbursement of reasonable and necessary expenses incurred in carrying out his duties, Mr. Dubay was entitled to reimbursement of up to

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$40,000 for relocation costs and Atlas Energy agreed to purchase his residence in Michigan for $1,000,000. If Mr. Dubay’s employment is terminated before June 30, 2011 by him without good reason or by Atlas Energy for cause, Mr. Dubay must repay an amount equal to the difference between the amount Atlas Energy paid for his residence and its fair market value on the date acquired by Atlas Energy. Upon execution of the agreement, Mr. Dubay was granted the following equity compensation:

•

Options to purchase 100,000 shares of Atlas Energy’s common stock, which vest 25% per year on each anniversary of the effective date of the agreement;

•

Options to purchase 100,000 of our common units, which vest 25% per year on each anniversary of the effective date of the agreement; and

•

Options to purchase 100,000 AHD common units, which vest 25% on the third anniversary, and 75% on the fourth anniversary, of the effective date of the agreement.

The agreement has a term of two years period and, until notice to the contrary, his term is automatically renewed for one year renewal terms. Atlas Energy may terminate the agreement:

•

at any time for cause;

•

without cause upon 45 days’ prior written notice;

•

if he is physically or mentally disabled for 180 days in the aggregate or 90 consecutive days during any 365-day period and our and Atlas Pipeline Holding’s board of directors determine, in good faith based upon medical evidence, that he is unable to perform his duties;

•

in the event of Mr. Dubay’s death.

Mr. Dubay has the right to terminate the agreement for good reason, including a change of control. Mr. Dubay must provide notice of a termination by him for good reason within 30 days of the event constituting good reason. Termination by Mr. Dubay for good reason is only effective if such failure has not been cured within 90 days after notice is given to Atlas Energy. Mr. Dubay may also terminate the agreement without good reason upon 60 days’ notice. Termination amounts will not be paid until six months after the termination date, if such delay is required by Section 409A of the Internal Revenue Code.

Cause is defined as (a) the commitment of a material act of fraud, (b) illegal or gross misconduct that is willful and results in damage to our business or reputation, (c) being charged with a felony, (d) continued failure by Mr. Dubay to perform his duties after notice other than as a result of physical or mental illness, or (e) Mr. Dubay’s failure to follow Atlas Energy’s reasonable written directions consistent with his duties. Good reason is defined as any action or inaction that constitutes a material breach by Atlas Energy of the agreement or a change of control. Change of control is defined as:

•

the acquisition of beneficial ownership, as defined in the Securities Exchange Act, of 50% or more of Atlas Energy’s voting securities or all or substantially all of Atlas Energy’s assets by a single person or entity or group of affiliated persons or entities, other than an entity affiliated with Atlas Energy or Mr. Dubay or any member of his immediate family;

•

Atlas Energy consummates a merger, consolidation, combination, share exchange, division or other reorganization or transaction of Atlas Energy other than with a related entity, in which either (a) Atlas Energy’s directors immediately before the transaction constitute less than a majority of the board of directors of the surviving entity, unless ¹/2 of the surviving entity’s board were Atlas Energy directors

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immediately before the transaction and Atlas Energy’s Chief Executive Officer immediately before the transaction continues as the Chief Executive Officer of the surviving entity; or (b) Atlas Energy’s voting securities immediately before the transaction represent less than 60% of the combined voting power immediately after the transaction of Atlas Energy, the surviving entity or, in the case of a division, each entity resulting from the division;

•

during any period of 24 consecutive calendar months, individuals who were Atlas Energy board members at the beginning of the period cease for any reason to constitute a majority of Atlas Energy’s board, unless the election or nomination for the election by Atlas Energy’s stockholders of each new director was approved by a vote of at least 2/3 of the directors then still in office who were directors at the beginning of the period; or

•

Atlas Energy’s shareholders approve a plan of complete liquidation or winding-up, or agreement of sale of all or substantially all of Atlas Energy’s assets or all or substantially all of the assets of its primary subsidiaries other than to a related entity.

The agreement provides the following regarding termination and termination benefits:

•

Upon termination of employment due to death, Mr. Dubay’s designated beneficiaries will receive a lump sum cash payment within 60 days of the date of death of (a) any unpaid portion of his annual salary earned and not yet paid, (b) an amount representing the incentive compensation earned for the period up to the date of termination computed by assuming that all such incentive compensation would be equal to the amount of incentive compensation Mr. Dubay earned during the prior fiscal year, pro-rated through the date of termination; and (c) any accrued but unpaid incentive compensation and vacation pay.

•

Upon termination of employment by Atlas Energy other than for cause, including disability, or by Mr. Dubay for good reason, if Mr. Dubay executes and does not revoke a release, Mr. Dubay will receive (a) pro-rated cash incentive compensation for the year of termination, based on actual performance for the year; and (b) monthly severance pay for the remainder of the employment term in an amount equal to 1/12 of (x) his annual base salary and (y) the annual amount of cash incentive compensation paid to Mr. Dubay for the fiscal year prior to his year of termination; (c) monthly reimbursements of any COBRA premium paid by Mr. Dubay, less the monthly premium charge paid by employees for such coverage; and (d) automatic vesting of all equity awards.

•

Upon Mr. Dubay’s termination from employment by Atlas Energy for cause or by Mr. Dubay for any reason other than good reason, Mr. Dubay will receive his accrued but unpaid base salary.

Mr. Dubay is also subject to a non-solicitation covenant for two years after any termination of employment and, in the event his employment is terminated by Atlas Energy for cause, or terminated by him for any reason other than good reason, a non-competition covenant not to engage in any natural gas pipeline and/or processing business in the continental United States for 18 months.

Termination amounts will not be paid until 6 months after the termination date, if such delay is required by Section 409A. We anticipate that lump sum termination amounts paid to Mr. Dubay would be allocated to us consistent with past practice. The following table provides an estimate of the value of the benefits to Mr. Dubay if a termination event had occurred as of December 31, 2009.

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Reason for termination	Lump sum severance payment			Benefits		Accelerated vesting of unit awards and option awards⁽¹⁾
Death	$	—		$	38,906	$	1,408,291
Termination by Atlas Energy other than for cause (including disability) or by Mr. Dubay for good reason (including a change of control)		938,847	⁽²⁾		38,906		1,408,291

⁽¹⁾

Represents the value of unexercisable option and unvested unit awards disclosed in the “Outstanding Equity Awards at Fiscal Year-End Table.” The payments relating to option awards are calculated by multiplying the number of accelerated options by the difference between the exercise price and the closing price of the applicable stock on December 31, 2009. The payments relating to stock awards are calculated by multiplying the number of accelerated shares by the closing price of the applicable unit on December 31, 2009.

⁽²⁾	Calculated based on Mr. Dubay’s 2009 base salary and cash bonus.

Eric T. Kalamaras

In September 2009, Atlas Energy entered into a letter agreement with Eric Kalamaras, who currently serves as our Chief Financial Officer. As discussed above under “Compensation Discussion and Analysis,” Atlas Energy allocates all of Mr. Kalamaras’ compensation cost to us and Atlas Pipeline Holdings.

The agreement provides for an annual base salary of $250,000, a one-time cash signing bonus of $80,000 and a one-time award of 50,000 equity-indexed bonus units which entitle Mr. Kalamaras, upon vesting, to receive a cash payment equal to the fair market value of our common units. These bonus units vest 1/3 per year over three years, but will vest immediately upon a change of control, Mr. Kalamaras’ death or if Mr. Kalamaras employment is terminated without cause. If such an event had occurred as of December 31, 2009, the value of the accelerated bonus award would be $490,500 based on the closing price of our common units on that date.

Mr. Kalamaras is also eligible for discretionary annual bonus compensation in an amount not to exceed 100% of his annual base salary and participation in all employee benefit plans in effect during his employment. The agreement provides that Mr. Kalamaras will serve as an at-will employee.

The agreement provides the following regarding termination and termination benefits:

•

Atlas Energy may terminate Mr. Kalamaras’ employment for any reason upon 30 days prior written notice, or immediately for cause.

•

Mr. Kalamaras may terminate his employment for any reason upon 60 days prior written notice.

•

Upon termination of employment for any reason, Mr. Kalamaras will receive his accrued but unpaid annual base salary through his date of termination and any accrued and unpaid vacation pay.

Cause is defined as having (a) committed an act of malfeasance or wrongdoing affecting the company or its affiliates, (ii) breached any confidentiality, non-solicitation or non-competition covenant or employment agreement or (iii) otherwise engaged in conduct that would warrant discharge from employment or service because of his negative effect on the company or its affiliates. Change of control means the acquisition by a person or group of (i) more than 50% of the total value of ownership interests or voting interests in Atlas Pipeline Mid-Continent, LLC or APL or (ii) during any 12 month period, assets of either company having a total gross fair market value equal to more than 50% of the total gross fair market value of the assets of the affected company.

Mr. Kalamaras is also subject to a confidentiality and non-solicitation agreement for 12 months after any termination of employment. Termination amounts will not be paid until six months after the termination date, if such delay is required by Section 409A of the Internal Revenue Code.

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Matthew A. Jones

In July 2009, Atlas Energy entered into an employment agreement with Matthew A. Jones, who currently serves as its Chief Financial Officer and, from January 2006 until September 2009, served as our Chief Financial Officer. As discussed above under “Compensation Discussion and Analysis,” Atlas Energy allocated a portion of Mr. Jones’s compensation cost to us based on an estimate of the time spent by Mr. Jones on our activities. Atlas Energy adds 50% to the compensation amount allocated to us to cover the costs of health insurance and similar benefits. The following discussion of Mr. Jones’s employment agreement summarizes those elements of Mr. Jones’s compensation that were allocated in part to us.

The agreement provides for initial base compensation of $300,000 per year, which may be increased at the discretion of Atlas Energy’s board of directors. Mr. Jones is eligible to receive incentive bonuses and stock option grants and to participate in all employee benefit plans in effect during his period of employment. The agreement has a term of two years with the option of renewal at the end of the term.

Atlas Energy may terminate the agreement:

•

at any time for cause;

•

without cause upon 90 days’ prior written notice;

•

if Mr. Jones is physically or mentally disabled for 180 days in the aggregate or 90 consecutive days during any 365-day period and our Board of Directors determines, in good faith based upon medical evidence, that he is unable to perform his duties;

•

in the event of Mr. Jones’s death.

Mr. Jones has the right to terminate the agreement for good reason, defined as material breach by Atlas Energy of the agreement or a change of control. Mr. Jones must provide notice of a termination by him for good reason within 30 days of the event constituting good reason. Atlas Energy then would have 30 days in which to cure and, if it does not do so, Mr. Jones’s employment will terminate 30 days after the end of the cure period. Mr. Jones may also terminate the agreement without good reason upon 30 days’ notice. Termination amounts will not be paid until six months after the termination date, if such delay is required by Section 409A of the Internal Revenue Code.

Cause is defined as (a) Mr. Jones’ having committed a demonstrable and material act of fraud, (b) illegal or gross misconduct that is willful and results in damage to the business or reputation of the Atlas Energy or any of its affiliates, (c) being charged with a felony, (d) continued failure by Mr. Jones to perform his duties after notice other than as a result of physical or mental illness, or (e) Mr. Jones’s failure to follow Atlas Energy’s reasonable written directions consistent with his duties. Good reason is defined as any action or inaction that constitutes a material breach by us of the agreement or a change of control. Change of control is defined as:

•

the acquisition of beneficial ownership, as defined in the Securities Exchange Act, of 50% or more of our voting securities or all or substantially all of our assets by a single person or entity or group of affiliated persons or entities, other than by a related entity, defined as Atlas Energy or any of its affiliates or affiliate of Mr. Jones or any member of his immediate family;

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•

Atlas Energy’s consummation of a merger, consolidation, combination, share exchange, division or other reorganization or transaction with an unaffiliated entity, other than a related entity, in which either (a) its directors immediately before the transaction constitute less than a majority of the board of directors of the surviving entity, unless ¹/2 of the surviving entity’s board were Atlas Energy’s directors immediately before the transaction and its Chief Executive Officer immediately before the transaction continues as the Chief Executive Officer of the surviving entity; or (b) its voting securities immediately before the transaction represent less than 60% of the combined voting power immediately after the transaction of Atlas Energy, the surviving entity or, in the case of a division, each entity resulting from the division;

•

during any period of 24 consecutive calendar months, individuals who were Board members at the beginning of the period cease for any reason to constitute a majority of the Board, unless the election or nomination for the election by our stockholders of each new director was approved by a vote of at least 2/3 of the directors then still in office who were directors at the beginning of the period; or

•

Atlas Energy’s stockholders approve a plan of complete liquidation or winding-up, or agreement of sale of all or substantially all of Atlas Energy’s assets or all or substantially all of the assets of its primary subsidiaries other than to a related entity.

The agreement provides the following regarding termination and termination benefits:

•

Upon termination of employment due to death, Mr. Jones’s designated beneficiaries will receive, a lump sum cash payment within 60 days of the date of death of (a) any unpaid portion of his annual salary earned and not yet paid, (b) an amount representing the incentive compensation earned for the period up to the date of termination, computed by assuming that the amount of all such incentive compensation would be equal to amount that Mr. Jones earned the prior fiscal year, pro-rated through the date of termination; (c) any accrued but unpaid incentive compensation and vacation pay ; and (d) all equity compensation awards will immediately vest.

•

Upon termination by Atlas Energy for cause or by Mr. Jones for other than good reason, Mr. Jones will receive only base salary and vacation pay to the extent earned and not paid. Mr. Jones’s equity awards that have vested as of the date of termination will not be subject to forfeiture.

•

Upon termination by Atlas Energy other than for cause, including disability, or by Mr. Jones for good reason, he will be entitled to either (a) if Mr. Jones does not sign a release, severance benefits under our then current severance policy, if any, or (b) if Mr. Jones signs a release, (i) a lump sum payment in an amount equal to two years of his average compensation (which is defined as his base salary in effect immediately before termination plus the average of the cash bonuses earned for the three calendar years preceding the year in which the date of terminated occurred), less, in the case of termination by reason of disability, any amounts paid under disability insurance provided by Atlas Energy; (ii) monthly reimbursement of any COBRA premium paid Mr. Jones, less the amount Mr. Jones would be required to contribute for health and dental coverage if he were an active employee, for the 24 months following the date of termination , and (iii) automatic vesting of Mr. Jones’s equity awards.

Termination amounts will not be paid until 6 months after the termination date, if such delay is required by Section 409A. We anticipate that lump sum termination amounts paid to Mr. Jones would be allocated to us consistent with past practice and, with respect to payments based on two years’ of compensation, would be allocated to us based on the average amount of time Mr. Jones devoted to our activities during the prior three-year period. The following table provides an estimate of the value of the benefits to Mr. Jones if a termination event had occurred as of December 31, 2009.

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Reason for termination	Lump sum severance payment			Benefits		Accelerated vesting of unit awards and option awards⁽¹⁾
Death	$	—		$	—	$	113,963
Termination by Atlas Energy other than for cause (including disability) or by Mr. Jones for good reason (including a change of control)		1,255,873	⁽²⁾		13,617		113,963

⁽¹⁾

Represents the value of unexercisable option and unvested unit awards disclosed in the “Outstanding Equity Awards at Fiscal Year-End Table.” The payments relating to option awards are calculated by multiplying the number of accelerated options by the difference between the exercise price and the closing price of the applicable units on December 31, 2009. The payments relating to unit awards are calculated by multiplying the number of accelerated units by the closing price of the applicable units on December 31, 2009.

⁽²⁾	Calculated based on Mr. Jones’s 2009 base salary and the average of his 2009, 2008 and 2007 cash bonuses.

Our Long-Term Incentive Plan

Our Plan provides equity incentive awards to officers, employees and board members and employees of our general partner and its affiliates, consultants and joint-venture partners who perform services for us. Our Plan is administered by Atlas Energy’s compensation committee under delegation from our general partner’s board. The compensation committee may grant awards of either phantom units or unit options for an aggregate of 2,100,000 common limited partner units.

Partnership Phantom Units. A phantom unit entitles a participant to receive a common unit upon vesting of the phantom unit. Non-employee directors receive an annual grant of a maximum of 500 phantom units which, upon vesting, entitle the grantee to receive the equivalent number of common units or the cash equivalent to the fair market value of the units. The phantom units vest over four years. In tandem with phantom unit grants, the compensation committee may grant a DER. The compensation committee determines the vesting period for phantom units. Phantom units granted under our Plan generally vest 25% on the third anniversary of the date of grant, with the remaining 75% vesting on the fourth anniversary of the date of grant.

Partnership Unit Options. A unit option entitles a participant to receive a common unit upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option may be equal to or more than the fair market value of a common unit as determined by the compensation committee on the date of grant of the option. The compensation committee determines the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Unit options granted generally will vest 25% on the third anniversary of the date of grant, with the remaining 75% vesting on the fourth anniversary of the date of grant. Awards will automatically vest upon a change of control, as defined in our Plan.

APL Plan

The APL Plan provides incentive awards to officers, employees and non-employee managers of Atlas Pipeline GP and officers and employees of its affiliates, consultants and joint venture partners who perform services for APL or in furtherance of its business. The APL Plan is administered by the Atlas Energy compensation committee, under delegation from Atlas Pipeline GP’s managing board. Under the APL Plan, the compensation committee may make awards of either phantom units or options covering an aggregate of 435,000 common units.

•

APL Phantom Units. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit. In addition, the compensation committee may grant a participant the right, which is referred to as a DER, to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions are made on an APL common unit during the period the phantom unit is outstanding.

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•

APL Unit Options. An option entitles the grantee to purchase APL common units at an exercise price determined by the compensation committee, which may be less than, equal to or more than the fair market value of APL common units on the date of grant. The compensation committee will also have discretion to determine how the exercise price may be paid.

Each non-employee manager of Atlas Pipeline GP receives an annual grant of a maximum of 500 phantom units which, upon vesting, entitles the grantee to receive the equivalent number of common units or the cash equivalent to the fair market value of the units. APL’s Plan was amended by its managing board in February 2010 to increase the pool of phantom units that may be awarded to non-employee managers from 10,000 to 15,000. The total amount of common units that can be awarded under the Plan was not amended. Except for phantom units awarded to non-employee managers of Atlas Pipeline GP, the compensation committee will determine the vesting period for phantom units and the exercise period for options. Phantom units awarded to non-employee managers will generally vest over a 4-year period at the rate of 25% per year. Both types of awards will automatically vest upon a change of control, as defined in the APL Plan.

APL Executive Group Incentive Program.

APL had incentive compensation agreements which granted awards to certain key employees retained from previously consummated acquisitions. These individuals were entitled to receive APL common units upon the vesting of the awards, which was dependent upon the achievement of certain predetermined performance targets through September 30, 2007. At September 30, 2007, the predetermined performance targets were achieved and all of the awards under the incentive compensation agreements vested. Of the total APL common units issued under the incentive compensation agreements, 58,822 common units were issued during the year ended December 31, 2007. The ultimate number of APL common units issued under the incentive compensation agreements was determined principally by the financial performance of certain of APL’s assets during the year ended December 31, 2008 and the market value of APL’s common units at December 31, 2008. The incentive compensation agreements also dictated that no individual covered under the agreements would receive an amount of APL common units in excess of one percent of APL’s outstanding common units at the date of issuance. APL common unit amounts due to any individual covered under the agreements in excess of one percent of the outstanding common units would have been paid in cash.

As of December 31, 2008, we recognized in full within our consolidated statements of operations the compensation expense associated with the vesting of awards issued under these incentive compensation agreements, therefore no compensation expense was recognized during the year ended December 31, 2009. During the year ended December 31, 2009, APL issued 348,620 common units to the certain key employees covered under the incentive compensation agreements. No additional common units will be issued with regard to these agreements.

APL Employee Incentive Compensation Plan and Agreement

The APLMC Plan, adopted in June 2009, allows for equity-indexed cash incentive awards to personnel who perform services for APL (the “Participants”), but expressly excludes as an eligible Participant any of our “Named Executive Officers” (as such term is defined under the rules of the Securities and Exchange Commission) at the time of the award. The APLMC Plan is administered by a committee appointed by our chief executive officer. Under the APLMC Plan, cash bonus units may be awarded Participants at the discretion of the committee and bonus units totaling 325,000 were awarded under the Incentive Plan during the year ended December 31, 2009. In September 2009, Mr. Kalamaras was separately awarded 50,000 bonus units on substantially the same terms as the bonus units available under the APLMC Plan (the bonus units issued under the Incentive Plan and under the separate agreement are, for purposes hereof, referred to as

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“bonus units”). A bonus unit entitles the employee to receive the cash equivalent of the then-fair market value of a common limited partner unit, without payment of an exercise price, upon vesting of the bonus unit. Bonus units vest ratably over a three year period from the date of grant and will automatically vest upon a change of control, death, or termination without cause, each as defined in the governing document. Vesting will terminate upon termination of employment with cause. During the year ended December 31, 2009, we granted 375,000 bonus units.

Pursuant to their bonus unit awards under the APLMC Plan, Messrs. Shrader and Karlovich are entitled to accelerated vesting of the awards upon a change in control. Change in control means a change in the ownership of APLMC or us, or a change in the ownership of a substantial portion of the assets of either company, provided that:

•

no event will be a change in control event unless it is a “change in control event” as defined in Section 1.409A-3(i)(5) of the Treasury regulations under Section 409A;

•

a change in ownership will occur only if ownership interests in either company are acquired by any one person or more than one person acting as a group and, after the acquisition, the acquiring person or persons own more than 50% of the total value or total voting power of such ownership interests; and

•

a change in the ownership of a substantial portion of the assets of either company will occur only if one person or more than one person acting as a group acquire during the 12-month period ending on the date of the last such acquisition assets that have a total gross fair market value equal to more than 50% of the total gross fair market value of all the assets of such company.

If such an event had occurred as of December 31, 2009, the value of Mr. Shrader’s accelerated bonus units would be $490,500 and the value of Mr. Karlovich’s would be $245,250 based on the closing price of our common units on that date.

Atlas Energy Plans

Atlas Energy’s Stock Incentive Plan (the “2004 Plan”) authorizes the granting of up to 4.5 million shares of its common stock to its employees, affiliates, consultants and directors in the form of incentive stock options (“ISOs”), non-qualified stock options, stock appreciation rights (“SARs”), restricted stock and deferred units. Atlas Energy also has a 2009 Stock Incentive Plan (the “2009 Plan”) which authorizes the granting of up to 4.8 million shares of its common stock to its employees, affiliates, consultants and directors in the form of ISOs, non-qualified stock options, SARs, restricted stock, restricted stock units and deferred units. SARs represent a right to receive cash in the amount of the difference between the fair market value of a share of Atlas Energy’s common stock on the exercise date and the exercise price, and may be free-standing or tied to grants of options. A deferred unit or a restricted stock unit represents the right to receive one share of Atlas Energy’s common stock upon vesting. Generally, awards under the 2004 Plan and 2009 Plan become exercisable 25% on each anniversary after the date of grant except that deferred units awarded to Atlas Energy’s non-executive board members vest 33¹/3%on each of the second, third and fourth anniversaries of the grant, and expire not later than ten years after the date of grant.

As required by SEC guidelines, the following table disclosed awards under our Plan as well as under the APL Plan and Atlas Energy’s Plans.

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OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END TABLE


	Option Awards					Stock Awards
	Number of Securities Underlying Unexercised Options (#)	Number of Securities Underlying Unexercised Options (#)		Option Exercise Price ($)		Option Expiration Date	Number of Shares or Units of Stock That Have Not Vested (#)		Market Value of Shares or Units of Stock That Have Not Vested ($)
Name	Exercisable	Unexercisable		Option Exercise Price ($)		Option Expiration Date
Eugene N. Dubay	—	100,000	⁽¹⁾	$	13.35	01/15/2019	—			—
	—	100,000	⁽²⁾		6.24	01/15/2019	375	⁽³⁾	$	3,679	⁽⁴⁾
	—	100,000	⁽⁵⁾		3.24	01/15/2019	—			—
Eric T. Kalamaras	—	—			—	—	50,000	⁽⁶⁾		490,500	⁽⁴⁾
Edward E. Cohen	—	—			—	—	5,000	⁽⁷⁾		49,050	⁽⁴⁾
	125,000	375,000	⁽⁸⁾		22.56	11/10/2016	67,500	⁽⁹⁾		457,650	⁽¹⁰⁾
Matthew A. Jones	—	—			—	—	1,250	⁽⁷⁾		12,263	⁽⁴⁾
	25,000	75,000	⁽⁸⁾		22.56	11/10/2016	15,000	⁽⁹⁾		101,700	⁽¹⁰⁾
Jonathan Z. Cohen	—	—			—	—	3,750	⁽⁷⁾		36,788	⁽⁴⁾
	50,000	150,000	⁽⁸⁾		22.56	11/10/2016	11,250	⁽⁹⁾		76,275	⁽¹⁰⁾
Gerald R. Shrader	—	—			—	—	750	⁽¹¹⁾		7,358	⁽⁴⁾
	—	—			—	—	50,000	⁽¹²⁾		490,500	⁽⁴⁾
Robert W. Karlovich III	—	—			—	—	750	⁽¹¹⁾		7,358	⁽⁴⁾
	—	—			—	—	25,000	⁽¹³⁾		245,250	⁽⁴⁾

⁽¹⁾	Represents options to purchase Atlas Energy common stock, which vests as follows: 01/15/2010—25,000; 01/15/2011 – 25,000; 01/15/2012 – 25,000 and 01/15/2013 – 25,000.

⁽²⁾	Represents options to purchase APL common units, which vest as follows: 01/15/2010—25,000; 01/15/2011 – 25,000; 01/15/2012 – 25,000 and 01/15/2013 – 25,000.

⁽³⁾	Represents APL phantom units, which vest as follows: 10/14/2010 – 125; 10/14/2011 - 125 and 10/14/2012 – 125.

⁽⁴⁾	Based on closing market price of APL common units on December 31, 2009 of $9.81.

⁽⁵⁾	Represents options to purchase our common units, which vest as follows: 01/15/2012 – 25,000 and 01/15/2013 – 75,000.

⁽⁶⁾	Includes APL bonus units which vest as follows: 9/14/2010-16,667; 9/14/2011-16,667 and 9/14/2012-16,666. See “Item 8: Financial Statements and Supplementary Data—Note 17 - APL Employee Incentive Compensation Plan and Agreement.”

⁽⁷⁾	Represents APL phantom units, which vest on 11/01/2010.

⁽⁸⁾	Represents our options, which vest on 11/10/2010.

⁽⁹⁾	Represents our phantom units, which vest on 11/10/2010

⁽¹⁰⁾	Based on closing market price of our common units on December 31, 2009 of $ 6.78.

⁽¹¹⁾	Represents APL phantom units, which vest as follows: 03/03/2010 – 250; 03/03/2011—250 and 03/03/12—250.

⁽¹²⁾	Includes APL bonus units which vest as follows: 6/1/2010-16,667; 6/1/2011-16,667 and 6/1/2012-16,666. See “Item 8: Financial Statements and Supplementary Data—Note 17 - APL Employee Incentive Compensation Plan and Agreement.”

⁽¹³⁾	Includes APL bonus units which vest as follows: 6/1/2010-8,333; 6/1/2011-8,333 and 6/1/2012-8,333. See “Item 8: Financial Statements and Supplementary Data—Note 17 - APL Employee Incentive Compensation Plan and Agreement.”

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2009 OPTION EXERCISES AND STOCK VESTED TABLE


	Unit Awards
Name	Number of Units Acquired on Vesting		Value Realized on Vesting ($)
Eugene E. Dubay	125	⁽¹⁾	$	2,708
Edward E. Cohen	32,500	⁽²⁾		802,850
Matthew A. Jones	10,000	⁽³⁾		289,363
Jonathan Z. Cohen	18,125	⁽⁴⁾		449,550
Gerald R. Shrader	250	⁽¹⁾		11,128
Robert W. Karlovich, III	250	⁽¹⁾		11,128

⁽¹⁾	Represents Atlas Pipeline Partners common units.

⁽²⁾	Represents 10,000 common units of Atlas Pipeline Partners and 22,500 of our common units.

⁽³⁾	Represents 5,000 common units of Atlas Pipeline Partners and 5,000 of our common units.

⁽⁴⁾	Represents 6,875 common units of Atlas Pipeline Partners and 11,250 of our common units

DIRECTOR COMPENSATION TABLE


Name	Fees Earned or Paid in Cash ($)			Stock Awards ($)			All Other Compensation ($)⁽¹⁾		Total ($)
William Bagnell	$	14,742	⁽²⁾	$	1,700	⁽³⁾	$	—	$	16,442
William G. Karis		35,000			1,835	⁽⁴⁾		63		36,898
Harvey G. Magarick		35,000			1,835	⁽⁴⁾		63		36,898
Jeffrey C. Key		35,000			1,835	⁽⁴⁾		63		36,898

⁽¹⁾	Payments for DERs under phantom units

⁽²⁾	Mr. Bagnell was elected to the board of directors in July 2009 and, therefore, received a pro-rated director’s fee for 2009.

⁽³⁾	Represents 500 phantom units granted under our Plan, having a grant date fair value of $3.40. The phantom units vest 25% on each anniversary of the date of grant as follows: 7/30/10—125, 7/30/11—125, 7/30/12—125 and 7/30/13—125.

⁽⁴⁾	Represents 500 phantom units granted under our Plan to Messrs. Karis, Key and Magarick, having a grant date fair value of $3.67. The phantom units vest 25% on each anniversary of the date of grant as follows: 11/10/10—125, 11/10/11—125, 11/10/12—125 and 11/10/13—125.

Our general partner does not pay additional remuneration to officers or employees of Atlas Energy who also serve as managing board members. In fiscal year 2009, each non-employee director received an annual retainer of $35,000 in cash and an annual grant of phantom units with DERs in an amount equal to the

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lesser of 500 units or $15,000 worth of units (based upon the market price of our common units) pursuant to our Long-Term Incentive Plan. In addition, our general partner reimburses each non-employee director for out-of-pocket expenses in connection with attending meetings of the board or committees. We reimburse our general partner for these expenses and indemnify our general partner’s directors for actions associated with serving as directors to the extent permitted under Delaware law.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

The following table sets forth the number and percentage of shares of common stock owned, as of March 2, 2010, by (a) each person who, to our knowledge, is the beneficial owner of more than 5% of the outstanding shares of common stock, (b) each of the members of the board of directors of our general partner, (c) each of the executive officers named in the Summary Compensation Table in Item 11, and (d) all of the named executive officers and directors as a group. This information is reported in accordance with the beneficial ownership rules of the Securities and Exchange Commission under which a person is deemed to be the beneficial owner of a security if that person has or shares voting power or investment power with respect to such security or has the right to acquire such ownership within 60 days. Unless otherwise indicated in footnotes to the table, each person listed has sole voting and dispositive power with respect to the securities owned by such person. The address of our general partner, its executive officers and directors is Westpointe Corporate Center One, 1550 Coraopolis Heights Road—2^nd Floor, Moon Township, Pennsylvania 15108.


Name of Beneficial Owner	Common Units		Percent of Class
Members of the Board of Directors
William R. Bagnell	500	⁽¹⁾	*
Edward E. Cohen	590,000	⁽²⁾	1.65	%
Jonathan Z. Cohen	246,000	⁽³⁾	*
Eugene N. Dubay	100,800	⁽⁴⁾	*
Matthew A. Jones	120,000	⁽⁵⁾	*
William G. Karis	1,900	⁽⁶⁾	*
Jeffrey C. Key	1,900	⁽⁶⁾	*
Harvey G. Magarick	1,900	⁽⁶⁾	*

Executive Officers
Eric Kalamaras	0		*
Robert W. Karlovich	0		*
Gerald R. Shrader	0		*

Executive officers and board of directors as a group (11 persons)	1,603,000		3.70	%

Other Owners of More than 5% of Outstanding Units
Atlas Energy, Inc.	17,808,109		64.3	%
Leon G. Cooperman	1,554,856	⁽⁷⁾	5.60	%

*	Less than 1%.

⁽¹⁾	Includes 500 phantom units granted pursuant to our Plan. Each phantom unit represents the right to receive, upon vesting, either one Common Unit or its then fair market value in cash. The phantom units vest as follows: 7/30/10—125; 7/30/11—125; 7/30/12—125; and 7/30/13—125.

⁽²⁾

Represents 22,500 common units and 125,000 vested unit options. Includes 67,500 phantom units and 375,000 unit options granted pursuant to our Long-Term Incentive Plan (the “Plan”) which will vest on November 10, 2010. Each phantom unit represents the right to receive, upon vesting, one common unit. Each unit option represents the right to purchase, upon vesting, one common unit.

177

⁽³⁾

Represents 12,250 common units and 50,000 vested unit options. Includes 33,750 phantom units and 150,000 unit options granted pursuant to our Plan which will vest on November 10, 2010. Each phantom unit represents the right to receive, upon vesting, one common unit. Each unit option represents the right to purchase, upon vesting, one common unit.

⁽⁴⁾

Represents 800 common units. Includes 100,000 unit options granted under our Plan pursuant to the terms of Mr. Dubay’s employment agreement on January 15, 2009. Each unit option represents the right to purchase, upon vesting, one common unit. The unit options vest which vest 25% on the third anniversary and 75% on the fourth anniversary of the date of grant.

⁽⁵⁾

Represents 5,000 common units and 25,000 vested unit options. Includes 15,000 phantom units and 75,000 unit options granted pursuant to our Plan which will vest on November 10, 2010. Each phantom unit represents the right to receive, upon vesting, one common unit. Each unit option represents the right to purchase, upon vesting, one common unit.

⁽⁶⁾	Includes 1,200 phantom units granted pursuant to our Plan. Each phantom unit represents the right to receive, upon vesting, either one Common Unit or its then fair market value in cash. The phantom units vest as follows: 11/10/10—475; 11/10/11—350; 11/10/12—250; and 11/10/13—125.

⁽⁷⁾	This information is based on a Schedule 13G/A which was filed with the SEC on February 4, 2010. The address for Mr. Cooperman is 88 Pine Street, Wall Street Plaza—31^st Floor, New York, NY 10005.

Equity Compensation Plan Information

The following table contains information about our Plan as of December 31, 2009:


	(a)	(b)		(c)
Plan category	Number of securities to be issued upon exercise of equity instruments	Weighted- average exercise price of outstanding equity instruments		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders – phantom units	138,875		n/a
Equity compensation plans approved by security holders – unit options	955,000	$	20.54
Equity compensation plans approved by security holders – total	1,093,875			960,650

The following table contains information about the APL Plan as of December 31, 2009:


	(a)	(b)		(c)
Plan category	Number of securities to be issued upon exercise of equity instruments	Weighted- average exercise price of outstanding equity instruments		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders – phantom units	52,233		n/a
Equity compensation plans approved by security holders – unit options	100,000	$	6.24
Equity compensation plans approved by security holders – total	152,233			66,584

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The following table contains information about Atlas Energy Plans as of December 31, 2009:


	(a)	(b)		(c)
Plan category	Number of securities to be issued upon exercise of equity instruments	Weighted- average exercise price of outstanding equity instruments		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders – restricted units	46,999		n/a
Equity compensation plans approved by security holders – options	3,509,554	$	16.82
Equity compensation plans approved by security holders – Total	3,556,553			5,544,137

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Neither we nor APL directly employ any persons to manage or operate our businesses. These functions are provided by our general partner and employees of Atlas Energy. Our general partner does not receive a management fee in connection with its management of our operations, nor does Atlas Pipeline GP receive a management fee in connection with its management of APL’s operations, but APL reimburses Atlas Pipeline GP and its affiliates for compensation and benefits related to Atlas Energy employees who perform services to it, based upon an estimate of the time spent by such persons on APL’s activities. Other indirect costs, such as rent for offices, are allocated to APL by Atlas Energy based on the number of its employees who devote substantially all of their time to APL’s activities. APL’s partnership agreement provides that Atlas Pipeline GP will determine the costs and expenses that are allocable to APL in any reasonable manner determined at its sole discretion. APL reimbursed Atlas Pipeline GP and its affiliates $2.7 million for the year ended December 31, 2009 for compensation and benefits related to their employees. Atlas Pipeline GP believes that the method utilized in allocating costs to APL is reasonable.

Effective as of April 30, 2009, Atlas Holdings GP adopted a written policy governing related party transactions. For purposes of this policy, a related party includes: (i) any executive officer, director or director nominee; (ii) any person known to be a beneficial owner of 5% or more of our common units; (iii) an immediate family member of any person included in clauses (i) and (ii) (which, by definition, includes, a person’s spouse, parents and parents in law, step parents, children, children in law and stepchildren, siblings and brothers and sisters in law and anyone residing in the that person’s home); and (iv) any firm, corporation or other entity in which any person included in clauses (i) through (iii) above is employed as an executive officer, is a director, partner, principal or occupies a similar position or in which that person owns a 5% or more beneficial interest. With certain exceptions outlined below, any transaction between us and a related party that is anticipated to exceed $120,000 in any calendar year must be approved, in advance, by the Conflicts Committee of Atlas Holdings GP. If approval in advance is not feasible, the related party transaction must be ratified by the Conflicts Committee. In approving a related party transaction the Conflicts Committee will take into account, in addition to such other factors as the Conflicts Committee deems appropriate, the extent of the related party’s interest in the transaction and whether the transaction is no less favorable to us than terms generally available to an unaffiliated third party under similar circumstances.

The following related party transactions are pre-approved under the policy: (i) employment of an executive officer to perform services on our behalf (or on behalf of one of our subsidiaries); (ii) compensation paid to directors for serving on the board of Atlas Holdings GP or any committee thereof; (iii) transactions where the related party’s interest arises solely as a holder of our common units and such interest is proportional to all other owners of common units or a transaction (e.g. participation in health plans) that are available to all employees generally; (iv) a transaction at another company where the related party is only an

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employee (and not an executive officer), director or beneficial owner of less than 10% of such company’s shares and the aggregate amount involved does not exceed the greater of $1,000,000 or 2% of that firm’s total annual revenues; and (v) any charitable contribution, grant or endowment by us or Atlas Holdings GP to a charitable organization, foundation or university at which the related party’s only relationship is as an employee (other than an executive officer) or director or similar capacity, if the aggregate amount involved does not exceed the greater of $5,000 or 2% of that organization’s total receipts. We are not aware of any related party transactions requiring approval under the policy that were undertaken in 2009.

The board of directors of our general partner has determined that Messrs. Bagnell, Karis, Key and Magarick each satisfy the requirement for independence set out in Section 303A.02 of the rules of the New York Stock Exchange (the “NYSE”) including those set forth in Rule 10A-3(b)(1) of the Securities Exchange Act, and meet the definition of an independent member set forth in our Partnership Governance Guidelines. In making theses determinations, the board of directors reviewed information from each of these non-management directors concerning all their respective relationships with us and analyzed the materiality of those relationships.

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

Aggregate fees recognized by us during the years ended December 31, 2009 and 2008 by our principal accounting firm, Grant Thornton LLP, are set forth below:


	2009		2008
Audit fees⁽¹⁾	$	1,816,725	$	2,140,738
Audit related fees		100,500		—
Tax fees⁽²⁾		159,557		191,975
All other fees		—		—

Total aggregate fees billed	$	2,076,782	$	2,332,713

⁽¹⁾

Represents the aggregate fees recognized in 2009 and 2008 for professional services rendered by Grant Thornton LLP for the audit of our annual financial statements and the review of financial statements included in Form 10-Q. The fees are for services that are normally provided by Grant Thornton LLP in connection with statutory or regulatory filings or engagements.

⁽²⁾	Represents the fees recognized for professional services rendered by Grant Thornton LLP for tax compliance, tax advice, and tax planning.

Audit Committee Pre-Approval Policies and Procedures

Pursuant to its charter, the audit committee of the board of our general partner is responsible for reviewing and approving, in advance, any audit and any permissible non-audit engagement or relationship between us and our independent auditors. All of such services and fees were pre-approved during 2009 and 2008.

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PART IV

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)

The following documents are filed as part of this report:

(1)

Financial Statements

The financial statements required by this Item 15(a)(1) are set forth in Item 8.

(2)

Financial Statement Schedules

Schedule I – Condensed Financial Information of Registrant

(3)

Exhibits:


Exhibit No.		Description

3.1		Certificate of Limited Partnership of Atlas Pipeline Holdings, L.P.⁽¹⁾

3.2(a)		Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Holdings, L.P.⁽²⁾

3.2(b)		Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Holdings, L.P.⁽³⁾

4.1		Specimen Certificate Representing Common Units⁽¹⁾

10.1		Certificate of Formation of Atlas Pipeline Holdings GP, LLC⁽¹⁾

10.2(a)		Amended and Restated Limited Liability Company Agreement of Atlas Pipeline Partners GP, LLC⁽¹⁾

10.2(b)		Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽¹⁾

10.2(c)		Amendment No. 2 to Second Amendment and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽⁴⁾

10.2(d)		Amendment No. 3 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽⁶⁾

10.2(e)		Amendment No. 4 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽⁶⁾

10.2(f)		Amendment No. 5 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽⁶⁾

10.2(g)		Amendment No. 6 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.⁽⁷⁾

10.3		Amended and Restated Certificate of Designation for 12% Cumulative Convertible Class B Preferred Units of Atlas Pipeline Partners, L.P.⁽⁷⁾

10.4		Long-Term Incentive Plan⁽⁶⁾

10.5(a)		Revolving Credit Agreement dated as of July 26, 2006 by and among Atlas Pipeline Holdings, L.P., Atlas Pipeline Partners GP, LLC, Wachovia Bank, National Association and the lenders thereto⁽²⁾

10.5(b)		First Amendment to Revolving Credit Agreement dated as of June 1, 2009⁽⁸⁾

10.6		Atlas Pipeline Holdings II, LLC Limited Liability Company Agreement⁽⁸⁾

10.7		Promissory Note to Atlas America, Inc. dated June 1, 2009⁽⁸⁾

10.8		Guaranty Note to Atlas America, Inc. dated June 1, 2009⁽⁸⁾

10.9		ATN Option Agreement dated as of June 1, 2009, by and among APL Laurel Mountain, LLC, Atlas Pipeline Operating Partnership, L.P. and Atlas Energy Resources, LLC⁽⁹⁾

10.10		Amended and Restated Limited Liability Company Agreement of Laurel Mountain Midstream, LLC dated as of June 1, 2009⁽⁹⁾

10.11(a)		Revolving Credit and Term Loan Agreement dated July 27, 2007 among Atlas Pipeline Partners, L.P., the guarantors therein, Wachovia Bank, National Association, and other banks party thereto⁽¹¹⁾

10.11(b)		Amendment No. 1 and Agreement to the Revolving Credit and Term Loan Agreement, dated June 12, 2008⁽¹¹⁾

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10.11(c)		Amendment No. 2 to Revolving Credit and Term Loan Agreement, dated May 29, 2009⁽¹⁰⁾

10.12		Securities Purchase Agreement dated April 7, 2009, by and between Atlas Pipeline Mid-Continent, LLC and Spectra Energy Partners OLP, LP⁽¹¹⁾

10.13		Letter Agreement, dated as of August 31, 2009, between Atlas America, Inc. and Eric Kalamaras⁽¹²⁾

10.14		Phantom Unit Grant Agreement between Atlas Pipeline Mid-Continent, LLC and Eric Kalamaras, dated September 14, 2009⁽¹²⁾

21.1		Subsidiaries of Registrant

23.1		Consent of Grant Thornton LLP

31.1		Rule 13(a)-14(a)/15(d)-14(a) Certification

31.2		Rule 13(a)-14(a)/14(d)-14(a) Certification

32.1		Section 1350 Certification

32.2		Section 1350 Certification

¹	Previously filed as an exhibit to the registration statement on Form S-1 (File No. 333-130999).

²	Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended June 30, 2006.

³	Previously filed as an exhibit to current report on Form 8-K filed January 8, 2008.

⁴	Previously filed as an exhibit to current report on Form 8-K filed July 30, 2007.

⁵	Previously filed as an exhibit to current report on Form 8-K filed June 23, 2008.

⁶	Previously filed as an exhibit to annual report on Form 10-K for the year ended December 31, 2008.

⁷	Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended March 31, 2009.

⁸	Previously filed as an exhibit to current report on Form 8-K filed June 2, 2009.

⁹	Previously filed as an exhibit to current report on Form 8-K filed June 5, 2009.

¹⁰	Previously filed as an exhibit to current report on Form 8-K filed June 1, 2009.

¹¹	Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended June 30, 2009.

¹²	Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended September 30, 2009.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated as of March 5, 2010.



/S/ EDWARD E. COHEN Edward E. Cohen		Chairman of the Board of the General Partner

/S/ JONATHAN Z. COHEN Jonathan Z. Cohen		Vice Chairman of the Board of the General Partner

/S/ EUGENE N. DUBAY Eugene N. Dubay		Chief Executive Officer, President, and Director of the General Partner

/S/ ERIC T. KALAMARAS Eric T. Kalamaras		Chief Financial Officer of the General Partner

/S/ ROBERT W. KARLOVICH III Robert W. Karlovich III		Chief Accounting Officer of the General Partner

/S/ WILLIAM R. BAGNELL William R. Bagnell		Director of the General Partner

/S/ MATTHEW A. JONES Matthew A. Jones		Director of the General Partner

/S/ WILLIAM G. KARIS William G. Karis		Director of the General Partner

/S/ JEFFREY C. KEY Jeffrey C. Key		Director of the General Partner

/S/ HARVEY G. MAGARICK Harvey G. Magarick		Director of the General Partner

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