Atlas Energy 10-K 2008 FY Annual report

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, 2008

OR

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

For the transition period from              to             

Commission file number: 1-32953

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 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.  x

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

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

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

The aggregate market value of the equity securities held by non-affiliates of the registrant, based upon the closing price of $33.50 per common limited partner unit on June 30, 2008, was approximately $330.0 million.

The number of common units of the registrant outstanding on February 20, 2009 was 27,659,154.

DOCUMENTS INCORPORATED BY REFERENCE: None

ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES

INDEX TO ANNUAL REPORT

ON FORM 10-K

		Page
PART I		3
Item 1:	Business	3
Item 1A:	Risk Factors	23
Item 1B:	Unresolved Staff Comments	46
Item 2:	Properties	46
Item 3:	Legal Proceedings	46
Item 4:	Submission of Matters to a Vote of Security Holders	47
PART II		47
Item 5:	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	47
Item 6:	Selected Financial Data	48
Item 7:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	53
Item 7A:	Quantitative and Qualitative Disclosures About Market Risk	78
Item 8:	Financial Statements and Supplementary Data	84
Item 9:	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	129
Item 9A:	Controls and Procedures	129
Item 9B:	Other Information	130
PART III		131
Item 10:	Directors, Executive Officers and Corporate Governance	131
Item 11:	Executive Compensation	135
Item 12:	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	150
Item 13:	Certain Relationships and Related Transactions, and Director Independence	153
Item 14:	Principal Accountant Fees and Services	153
PART IV		154
Item 15:	Exhibits and Financial Statement Schedules	154
SIGNATURES		155

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FORWARD-LOOKING STATEMENTS

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

• the price volatility and demand for natural gas and natural gas liquids;

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

• Atlas Pipeline Partners, L.P.’s ability to integrate newly acquired businesses with its operations;

• adverse effects of governmental and environmental regulation;

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

• the strength and financial resources of 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.

PART I

ITEM 1. BUSINESS

Atlas Pipeline Holdings, L.P.

We are a publicly-traded Delaware limited partnership (NYSE: AHD) formed in December 2005. On July 26, 2006, Atlas America, Inc. and its affiliates (“Atlas America”), a publicly traded company (NASDAQ: ATLS), contributed its ownership interests in Atlas Pipeline Partners GP, LLC (“Atlas Pipeline GP”), its then wholly-owned subsidiary, a Delaware limited liability company and the general partner of Atlas Pipeline Partners, L.P. (“APL”), to us. Concurrent with this transaction, we issued 3.6 million common units, representing a then-17.1% ownership interest in us, in an initial public offering at a price of $23.00 per unit. Net proceeds from this offering were distributed to Atlas America.

Our cash generating assets currently consist solely of our interests in APL, a publicly traded Delaware limited partnership (NYSE: APL). APL is a midstream energy service provider engaged in the transmission, gathering and processing of natural gas in the Mid-Continent and Appalachian regions. Our interests in APL consist of a 100% ownership in Atlas Pipeline GP, its general partner, which owned at December 31, 2008:

• 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. In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see “—Atlas Pipeline Partners, L.P.”), we, the holder of all the incentive distribution rights in APL, agreed to allocate up to $5.0 million of our incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. We also agreed that the resulting allocation of incentive distribution rights back to APL would be after we receive 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;

• 5,754,253 common units of APL, representing approximately 12.5% of the outstanding common units of APL, or a 13.9% limited partner interest in APL, and

• 10,000 $1,000 par value 12.0% cumulative convertible preferred limited partner units, representing an approximate 3.2% ownership interest in APL based upon the market value of APL’s common units at December 31, 2008.

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.

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

• 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.

These amounts are partially offset by the IDR Adjustment Agreement.

We pay 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.

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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’s principal business objective is to generate cash for distribution to its unitholders. APL is a leading provider of natural gas gathering services in the Anadarko, Arkoma and Permian Basins and the Golden Trend 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 treatment services in Oklahoma and Texas. APL also provides interstate gas transmission services in southeastern Oklahoma, Arkansas, southern Kansas and southeastern Missouri. APL’s business is conducted in the midstream segment of the natural gas industry through two reportable segments: its Mid-Continent operations and its Appalachian operations.

Through its Mid-Continent operations, APL owns and operates:

• a Federal Energy Regulatory Commission (“FERC-”)-regulated, 565-mile interstate pipeline system (“Ozark Gas Transmission”) that extends from southeastern Oklahoma through Arkansas and into southeastern Missouri and has throughput capacity of approximately 500 million cubic feet per day (“MMcfd”);

• eight natural gas processing plants with aggregate capacity of approximately 810 MMcfd and one treating facility with a capacity of approximately 200 MMcfd, located in Oklahoma and Texas; and

• 9,100 miles of active natural gas gathering systems located in Oklahoma, Arkansas, Kansas and Texas, which transport gas from wells and central delivery points in the Mid-Continent region to APL’s natural gas processing and treating plants or Ozark Gas Transmission, as well as third-party pipelines.

Through its Appalachian operations, APL owns and operates 1,835 miles of natural gas gathering systems located in eastern Ohio, western New York, western Pennsylvania and northeastern Tennessee. Through an omnibus agreement and other agreements between APL and Atlas America, Inc. and its affiliates, a publicly traded company (NASDAQ: ATLS – “Atlas America”) and holder of a 64.4% ownership interest in us, including Atlas Energy Resources, LLC and subsidiaries (“Atlas Energy”), a leading sponsor of natural gas drilling investment partnerships in the Appalachian Basin and a publicly-traded company (NYSE: ATN), APL gathers substantially all of the natural gas for its Appalachian Basin operations from wells operated by Atlas Energy. Among other things, the omnibus agreement requires Atlas Energy to connect to APL’s gathering systems wells it operates that are located within 2,500 feet of APL’s gathering systems. APL is also party to natural gas gathering agreements with Atlas America and Atlas Energy under which it receives gathering fees generally equal to a percentage, typically 16%, of the selling price of the natural gas it transports.

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 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”). 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 effected by 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

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of $1.125 billion 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 we funded through our issuance of 6.25 million common units in a private placement at a negotiated purchase price of $27.00 per unit. APL funded the remaining purchase price from $830.0 million of proceeds from a senior secured term loan which matures in July 2014 and a new $300.0 million senior secured revolving credit facility that matures in July 2013. We, as general partner and holder of all of APL’s incentive distribution rights, have also agreed to allocate up to $5.0 million of our incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. We also agreed that the resulting allocation of incentive distribution rights back to APL would be after we receive 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 connection with this acquisition, APL reached an agreement with Pioneer Natural Resources Company (“Pioneer” – NYSE: PXD), which currently holds an approximate 27.2% undivided joint venture interest in the Midkiff/Benedum system, whereby Pioneer has an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system which began on June 15, 2008 and ended on November 1, 2008, and up to an additional 7.4% interest beginning on June 15, 2009 and ending on November 1, 2009 (the aggregate 22.0% additional interest can be entirely purchased during the period beginning June 15, 2009 and ending on November 1, 2009). If the option is fully exercised, Pioneer would increase its interest in the system to approximately 49.2%. Pioneer would pay approximately $230 million, subject to certain adjustments, for the additional 22.0% interest if fully exercised. APL will manage and control the Midkiff/Benedum system regardless of whether Pioneer exercised the purchase options; and

• In May 2006, APL acquired the remaining 25% ownership interest in NOARK Pipeline System, Limited Partnership (“NOARK”) from Southwestern Energy Company (“Southwestern”) for a net purchase price of $65.5 million, consisting of $69.0 million in cash to the seller, (including the repayment of the $39.0 million of outstanding NOARK notes at the date of acquisition), less the seller’s interest in working capital at the date of acquisition of $3.5 million. In October 2005, APL acquired from Enogex, a wholly-owned subsidiary of OGE Energy Corp., all of the outstanding equity of Atlas Arkansas, which owned the initial 75% ownership interest in NOARK, for $163.0 million, plus $16.8 million for working capital adjustments and related transaction costs. NOARK’s principal assets include the Ozark Gas Transmission system, a 565-mile interstate natural gas pipeline, and Ozark Gas Gathering, a 365-mile natural gas gathering system.

Both APL’s Mid-Continent and Appalachian operations are located in areas of abundant and long-lived natural gas production and significant new drilling activity. The Ozark Gas Transmission system, which is part of the NOARK system, and APL’s gathering systems are connected to approximately 7,800 central delivery points or wells, giving APL significant scale in its service areas. APL provides gathering and processing services to the wells connected to its systems, primarily under long-term contracts. APL provides fee-based, FERC-regulated transmission services through Ozark Gas Transmission under both long-term and short-term contractual arrangements. As a result of the location and capacity of the Ozark Gas Transmission system and its gathering and processing assets, APL management believes that it is strategically positioned to capitalize on the significant increase in drilling activity in its service areas and the positive price differential across Ozark Gas Transmission, also known as basis spread. APL intends to continue to expand its business through strategic acquisitions and internal growth projects, subject to the availability of adequate capital resources and liquidity, which increase distributable cash flow.

The Midstream Natural Gas Gathering, Processing and Transmission 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.

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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 small diameter pipelines that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission. Gathering systems are operated at design pressures 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 Velma service area in Oklahoma, is not suitable for long-haul pipeline transmission or commercial use and must be compressed, transported via pipeline to a central processing facility, and then processed to remove the heavier hydrocarbon components such as natural gas liquids (“NGLs”) and other contaminants that would interfere with pipeline transmission or the end use of the natural gas. Natural gas processing plants generally treat (remove carbon dioxide and hydrogen sulfide) and remove the NGLs, enabling the treated, “dry” gas (stripped of liquids) 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 on pipelines to a centralized facility for fractionation into discrete NGL purity products: ethane, propane, normal butane, isobutane, and natural gasoline.

Natural gas transmission pipelines receive natural gas from producers, other mainline transmission 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 transmission agreements generate revenue for these systems based on a fee per unit of volume transported.

Contracts and Customer Relationships

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

• the volumes of natural gas APL gathers, transports and processes which, in turn, depends 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; and

• the transportation and processing fees APL receives which, in turn, depends upon the price of the natural gas and NGLs it transports and processes, which itself is a function of the relevant supply and demand in the mid-continent, mid-Atlantic and northeastern areas of the United States.

In APL’s Appalachian region, substantially all of the natural gas it transports is for Atlas Energy under percentage-of-proceeds (“POP”) contracts, as described below, in which APL earns a fee equal to a percentage, generally 16%, of the gross sales price for natural gas subject, in most cases, to a minimum of $0.35 or $0.40 per thousand cubic feet, or mcf, depending on the ownership of the well. Since APL’s inception in January 2000, its Appalachian system transportation fee has generally exceeded this minimum. The balance of the Appalachian system natural gas APL transports is for third-party operators generally under fixed-fee contracts.

APL’s Mid-Continent segment revenue consists of the fees earned from its transmission, 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 NGLs, if any, off of delivery points on its systems. Under other agreements, APL transports natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with APL’s FERC-regulated transmission pipeline is comprised of firm transportation rates and, to the extent capacity is available following the reservation of firm system capacity, interruptible transportation rates and is recognized at the time transportation service is provided. 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, it enters into the following types of contractual relationships with its producers and shippers:

Fee-Based Contracts. These contracts provide for a set fee for gathering and 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.

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POP Contracts. These contracts provide for APL to retain a negotiated percentage of the sale proceeds from residue natural gas and NGLs it gathers and processes, with the remainder being remitted to the producer. In this situation, APL and the producer are directly dependent on the volume of the commodity and its value; APL owns a percentage of that commodity and is directly subject to its market value.

Keep-Whole Contracts. These contracts require APL, as the processor, to purchase raw natural gas from the producer at current market rates. Therefore, APL bears the economic risk (the “processing margin risk”) that the aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the amount that it paid for the unprocessed natural gas. However, because the natural gas purchases contracted under keep-whole agreements are generally low in liquids content and 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. Therefore, the processing margin risk associated with a portion of APL’s keep-whole contracts is minimized.

APL’s Mid-Continent Operations

APL owns and operates a 565-mile interstate natural gas pipeline, approximately 9,900 miles of intrastate natural gas gathering systems, including approximately 800 miles of inactive pipeline, located in Oklahoma, Arkansas, southeastern Missouri, Kansas, northern and western Texas and the Texas panhandle, and eight processing plants and one stand-alone treating facility in Oklahoma and Texas. Ozark Gas Transmission transports natural gas from receipt points in eastern Oklahoma, including major intrastate pipelines, and western Arkansas, where the Arkoma Basin is located, to local distribution companies in Arkansas and Missouri and to interstate pipelines in northeastern and central Arkansas. APL’s gathering and processing assets service long-lived natural gas regions that continue to experience an increase in drilling activity, including the Anadarko Basin, the Arkoma Basin, the Permian Basin and the Golden Trend area of Oklahoma. 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 7,800 receipt points, consisting primarily of individual connections and, secondarily, central delivery points which are linked to multiple wells. APL’s gathering systems interconnect with interstate and intrastate pipelines operated by ONEOK Gas Transportation, LLC, Southern Star Central Gas Pipeline, Inc., Panhandle Eastern Pipe Line Company, LP, Northern Natural Gas Company, CenterPoint Energy, Inc., ANR Pipeline Company, El Paso Natural Gas Company, Natural Gas Pipeline Company of America and Ozark Gas Transmission.

Mid-Continent Overview

The heart of the Mid-Continent region is generally defined as running from Kansas through Oklahoma, branching into northern and western Texas, southeastern New Mexico as well as western Arkansas. The primary producing areas in the region include the Hugoton field in southwestern Kansas, the Anadarko Basin in western Oklahoma, the Permian Basin in West Texas and the Arkoma Basin in western Arkansas and eastern Oklahoma.

FERC-Regulated Transmission System

Through NOARK, APL owns Ozark Gas Transmission, a 565-mile FERC-regulated natural gas interstate pipeline which transports natural gas from receipt points in eastern Oklahoma, including major intrastate pipelines, and Arkansas, where the Arkoma Basin and the Fayetteville and Woodford Shales are located, to local distribution companies and industrial markets in Arkansas and Missouri and to interstate

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pipelines in northeastern and central Arkansas. Ozark Gas Transmission delivers natural gas primarily via six interconnects with Mississippi River Transmission Corp., Natural Gas Pipeline Company of America and Texas Eastern Transmission Corp., and receives natural gas from interconnects with intrastate pipelines, including Enogex, BP’s Vastar gathering system, Arkansas Oklahoma Gas Corporation, Arkansas Western Gas Company, ONEOK Gas Transmission, APL’s Ozark Gas Gathering system and other producer owned gas gathering systems.

Mid-Continent Gathering Systems

Chaney Dell. The Chaney Dell gathering system is located in north central Oklahoma and southern Kansas’ Anadarko Basin. Chaney Dell’s natural gas gathering operations are conducted through two gathering systems, the Westana and Chaney Dell/Chester systems. As of December 31, 2008, the combined gathering systems had approximately 4,295 miles of natural gas gathering pipelines with approximately 3,520 receipt points.

Elk City/Sweetwater. The Elk City and Sweetwater gathering system, which APL considers combined due to the close geographic proximity of the processing plants they are connected to, includes approximately 600 miles of natural gas pipelines located in the Anadarko Basin in western Oklahoma and the Texas panhandle, including the Atoka and Granite Wash plays. The Elk City and Sweetwater gathering system connects to approximately 600 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 has an approximate 72.8% ownership in at December 31, 2008, consists of approximately 2,650 miles of gas gathering pipeline and approximately 2,700 receipt points located across four counties within the Permian Basin in 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.

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 and entered into an agreement under which Pioneer has the right to increase its ownership interest in the Midkiff/Benedum system by an additional 14.6% which began June 15, 2008 and ended on November 1, 2008, and an additional 7.4% beginning June 15, 2009 and ending on November 1, 2009, for an aggregate ownership interest of 49.2% (the aggregate 22.0% additional interest can be entirely purchased during the period beginning June 15, 2009 and ending on November 1, 2009). The gas sales and purchase agreement requires that all Pioneer wells in the proximity of the Midkiff/Benedum system 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.

Ozark Gas Gathering. Through NOARK, APL owns Ozark Gas Gathering, which owns 370 miles of intrastate natural gas gathering pipeline located in eastern Oklahoma and western Arkansas, providing access to both the well-established Arkoma Basin and the newly-exploited Fayetteville and Woodford Shales. This system connects to approximately 282 receipt points and compresses and transports gas to interconnections with Ozark Gas Transmission and CenterPoint.

Velma. The Velma gathering system is located in the Golden Trend area of southern Oklahoma and the Barnett Shale area of northern Texas. As of December 31, 2008, the gathering system had approximately 1,200 miles of active pipeline with approximately 650 receipt points consisting primarily of individual connections and, secondarily, central delivery points which are linked to multiple wells. The system includes approximately 800 miles of inactive pipeline, much of which can be returned to active status as local drilling activity warrants.

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Processing and Treating Plants

Chaney Dell.The Chaney Dell system processes natural gas through the Waynoka, Chester and Chaney Dell plants, all of which are active cryogenic natural gas processing facilities. The Chaney Dell system’s processing operations have total capacity of approximately 250 MMcfd. The Waynoka processing plant, which began operations in December 2006 and became fully operational in July 2007, contains technologically advanced controls, systems and processes and demonstrates strong NGL recovery rates. The Chaney Dell plant, which was idled in the fourth quarter of 2006 when the Waynoka plant began operations, was reactivated in January 2008 because of drilling activity in the Anadarko Basin, adding 22 MMcfd of additional processing capacity.

Midkiff/Benedum. The Midkiff/Benedum system processes natural gas through the Midkiff and Benedum processing plants. The Midkiff plant is a 110 MMcfd cryogenic facility in Reagan County, Texas. The facility includes three processing trains and thirteen compressors for inlet and residue recompression. The Benedum plant is a 43 MMcfd cryogenic facility in Upton County, Texas and includes eight compressors for inlet and residue recompression. APL’s Midkiff/Benedum processing operations have an aggregate processing capacity of approximately 153 MMcfd.

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 sells natural gas to purchasers at the tailgate of the Velma plant and sells NGL production to ONEOK Hydrocarbon. 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. This results in higher margins, greater efficiency and lower fuel costs.

Elk City/Sweetwater.The Elk City, Sweetwater and Prentiss facilities are on the same gathering system and are referred to as APL’s Elk City/Sweetwater operations. 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. APL transports to, and sells natural gas to purchasers at, the tailgate of its Elk City processing plant, as well as sells NGL production to ONEOK Hydrocarbon. The Prentiss treating facility, also located in Beckham County, 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, near the Elk City processing plant. The Sweetwater plant has a total capacity of approximately 180 MMcfd. APL built the Sweetwater plant to further access natural gas production being actively developed in western Oklahoma and the Texas panhandle. Built with state-of-the-art technology, APL believes that the Sweetwater plant is capable of recovering more NGLs than a lean oil processing plant. During July 2008, APL completed a 60 MMcfd expansion of the Sweetwater plant, bringing its total processing capacity to 180 MMcfd. Through this expansion, APL extended the system’s reach into the Granite Wash play in the Hemphill County, Texas area, which APL believes will continue to increase its natural gas processing and throughput volumes.

Natural Gas Supply

In the Mid-Continent, APL has natural gas purchase, gathering and processing agreements with approximately 800 producers with terms ranging from one month to 20 years. These agreements provide for the purchase or gathering of natural gas under fixed-fee, percentage-of-proceeds or keep-whole arrangements. Most of the agreements provide for compression, treating, and/or low volume fees. Producers generally provide, in-kind, their proportionate share of compressor 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,” or the gas consumed in the production of NGLs.

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APL has enjoyed long-term relationships with the majority of its Mid-Continent producers. For instance, on the Velma system, where APL has producer relationships going back over 20 years, its top four producers, which accounted for a significant portion of the Velma volumes for the year ended December 31, 2008, have contracts with primary terms running into 2009 and 2010. At the end of the primary terms, most of the contracts with producers on APL’s gathering systems have evergreen term extensions.

Natural Gas and NGL Marketing

APL typically sells natural gas to several creditworthy purchasers downstream of its processing plants priced at various first-of-month indices as published inInside FERC. Additionally, swing gas, which is natural gas that is sold at non-contracted prices during a current month, is sold daily at variousPlatt’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., an interstate pipeline. The Elk City/Sweetwater 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 Chaney Dell and Chester plants have access to Panhandle Eastern Pipe Line Company, LP and the Waynoka plant has access to Panhandle Eastern Pipe Line Company, LP and Southern Star Central Gas Pipeline, Inc. The Midkiff/Benedum plants have access to 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 above listed delivery points at all facilities.

APL sells its NGL production to ONEOK Hydrocarbon under four separate agreements. The Velma agreement has an initial term expiring February 1, 2011, the Elk City/Sweetwater agreement has an initial term expiring in 2013, the Chaney Dell agreement has an initial term expiring September 1, 2009, and the Midkiff/Benedum agreement expires in 2013. All NGL agreements are priced at the average monthly Oil Price Information Service, or OPIS, price for the selected market.

Condensate is collected at the Velma gas plant and around the Velma gathering system and currently sold for APL’s account 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 Midkiff/Benedum plants and around the Midkiff/Benedum gathering system is currently sold to ConocoPhillips, Oxy USA and Oasis Transportation.

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 mitigates a portion of these risks through a comprehensive risk management program which employs a variety of financial tools. The resulting combination of the underlying physical business and the financial risk management program is a conversion from a physical environment that consists of floating prices to a risk-managed environment that is characterized by fixed prices.

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) transports 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 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:

• Percentage-of-proceeds: 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: requires APL to deliver the same quantity of natural gas at the delivery point as it received at the receipt point; any resulting NGLs produced belong to APL. This results 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 a range of fixed prices.

APL recognizes gains and losses from the settlement of its derivative instruments in revenue when it sells the associated physical residue natural gas or NGLs. Any gain or loss realized as a result of the financial instrument settlement is substantially offset in the market when APL sells the physical residue natural gas or NGLs. APL applies the provisions of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” to its derivative instruments. 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 NYMEX prices when applicable and an internally-generated algorithm for commodities that are not traded on a market. To insure 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, 2008, please see Item 7A, “Quantitative and Qualitative Disclosures About Market Risk.”

APL’s Appalachian Basin Operations

APL owns and operates approximately 1,835 miles of intrastate gas gathering systems located in eastern Ohio, western New York, western Pennsylvania and northeastern Tennessee. APL’s Appalachian operations serve approximately 7,440 wells with an average throughput of 87.3 MMcfd of natural gas for the year ended December 31, 2008. 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. APL’s gathering systems connect with various public utility pipelines, including Peoples Natural Gas Company, National Fuel Gas Supply, Tennessee Gas Pipeline Company, National Fuel Gas Distribution Company, Dominion East Ohio Gas Company, Columbia Gas of Ohio, Consolidated Natural Gas Co., Texas Eastern Pipeline, Columbia Gas Transmission Corp., Equitrans Pipeline Company, Gatherco Incorporated, Piedmont Natural Gas Co., Inc., East Tennessee Natural Gas, Citizens Gas Utility District and Equitable Utilities. APL’s systems are strategically located in the Appalachian Basin, a region characterized by long-lived, predictable natural gas reserves that are close to major eastern U.S. markets. Substantially all of the natural gas APL transports in the Appalachian Basin is derived from wells operated by Atlas Energy. APL is party to an omnibus agreement with Atlas Energy which is intended to maximize the use and expansion of APL’s gathering systems and the amount of natural gas which it transports in the region.

Appalachian Basin Overview

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

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Natural Gas Supply

On December 18, 2006, Atlas America, which owns a 64.4% ownership interest in us and a direct 2.1% ownership in APL at December 31, 2008, contributed its ownership interests in its natural gas and oil development and production subsidiaries to Atlas Energy, a then wholly-owned subsidiary of Atlas America. Concurrent with this transaction, Atlas Energy issued 7,273,750 common units, representing a then-19.4% ownership interest, in an initial public offering. Substantially all of the natural gas APL transports in the Appalachian Basin is derived from wells operated by Atlas Energy.

From the inception of APL’s operations in January 2000 through December 31, 2008, APL connected 4,461 new wells to its Appalachian gathering system, 685 of which were added through acquisitions of other gathering systems. For the year ended December 31, 2008, APL connected 741 wells to its gathering system. APL’s ability to increase the flow of natural gas through its gathering systems and to offset the natural decline of the production already connected to its gathering systems will be determined primarily by the number of wells drilled by Atlas Energy and connected to APL’s gathering systems and by APL’s ability to acquire additional gathering assets.

Natural Gas Revenue

APL’s Appalachian Basin revenue is determined primarily by the amount of natural gas flowing through its gathering systems and the price received for this natural gas. APL has an agreement with Atlas Energy under which Atlas Energy pays APL gathering fees generally equal to a percentage, typically 16%, of the gross weighted average sales price of the natural gas APL transports subject, in most cases, to minimum prices of $0.35 or $0.40 per Mcf. For the year ended December 31, 2008, APL received gathering fees averaging $1.40 per Mcf. APL charges other operators fees negotiated at the time it connects their wells to its gathering systems or, in a pipeline acquisition, that were established by the entity from which APL acquired the pipeline.

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

Our and APL’s Relationship with Atlas Energy and Atlas America

APL began its operations in January 2000 by acquiring the gathering systems of Atlas America. On December 18, 2006, Atlas America, which owns a 64.4% ownership interest in us, contributed the ownership interests in its natural gas and oil development and production subsidiaries to Atlas Energy, a then wholly-owned subsidiary of Atlas America. Atlas America owns 48.3% of Atlas Energy and a direct 2.1% ownership interest in APL at December 31, 2008.

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 eastern Ohio, western New York and western Pennsylvania. APL’s gathering systems are connected to approximately 6,800 wells developed and operated by Atlas Energy in the Appalachian Basin. Through agreements between APL and Atlas Energy, APL gathers substantially all of the natural gas for its Appalachian Basin operations from wells operated by Atlas Energy. For the year ended December 31, 2008, Atlas Energy and its affiliates raised $438.4 million from investors and drilled 773 wells.

Omnibus Agreement

Under the omnibus agreement, Atlas America and its affiliates agreed to add wells to APL’s gathering systems and provide consulting services when APL constructs new gathering systems or extends existing

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systems. In December 2006, in connection with the completion of the initial public offering of, and Atlas America’s contribution and sale of its natural gas and oil development and production assets to, Atlas Energy, Atlas Energy joined the omnibus agreement as an obligor (except for the provisions of the omnibus agreement imposing conditions upon the disposition of us as general partner of APL), and Atlas America became secondarily liable as a guarantor of Atlas Energy’s performance. The omnibus agreement is a continuing obligation, having no specified term or provisions regarding termination except for a provision terminating the agreement if we are removed as general partner of APL without cause. The omnibus agreement may not be amended without the approval of the conflicts committee of the managing board of our general partner if, in our reasonable discretion, such amendment will adversely affect APL’s common unitholders. APL’s common unitholders do not have explicit rights to approve any termination or material modification of the omnibus agreement. We anticipate that the conflicts committee of the managing board of our general partner would submit to APL’s common unitholders for their approval any proposal to terminate or amend the omnibus agreement if we determine, in our reasonable discretion, that the termination or amendment would materially adversely affect APL’s common unitholders.

Well Connections. Under the omnibus agreement, with respect to any well Atlas Energy drills and operates for itself or an affiliate that is within 2,500 feet of APL’s gathering systems, Atlas Energy must, at its sole cost and expense, construct small diameter (two inches or less) sales or flow lines from the wellhead of any such well to a point of connection to the gathering system. Where an Atlas Energy well is located more than 2,500 feet from one of APL’s gathering systems, but Atlas Energy has extended the flow line from the well to within 1,000 feet of the gathering system, Atlas Energy has the right to require APL, at APL’s cost and expense, to extend its gathering system to connect to that well. With respect to other Atlas Energy wells that are more than 2,500 feet from APL’s gathering systems, APL has the right, at its cost and expense, to extend its gathering system to within 2,500 feet of the well and to require Atlas Energy, at its cost and expense, to construct up to 2,500 feet of flow line to connect to the gathering system extension. If APL elects not to exercise its right to extend its gathering systems, Atlas Energy may connect an Atlas Energy well to a natural gas gathering system owned by someone other than APL or one of APL’s subsidiaries or to any other delivery point; however, APL will have the right to assume the cost of construction of the necessary flow lines, which will then become APL’s property and part of its gathering systems.

Consulting Services. The omnibus agreement requires Atlas Energy to assist APL in identifying existing gathering systems for possible acquisition and to provide consulting services to APL in evaluating and making a bid for these systems. Atlas Energy must give APL notice of identification by it or any of its affiliates of any gathering system as a potential acquisition candidate, and must provide APL with information about the gathering system, its seller and the proposed sales price, as well as any other information or analyses compiled by Atlas Energy with respect to the gathering system. APL must determine, within a time period specified by Atlas Energy’s notice to APL, which must be a reasonable time under the circumstances, whether APL wants to acquire the identified system and advise Atlas Energy of its intent. If APL intends to acquire the system, it has an additional 60 days to complete the acquisition. If APL advises Atlas Energy that it does not intend to make the acquisition, does not complete the acquisition within a reasonable time period, or advises Atlas Energy that it does not intend to acquire the system, then Atlas Energy may do so.

Gathering System Construction. The omnibus agreement requires Atlas Energy to provide APL with construction management services if APL determines it needs to expand one or more of its gathering systems. APL must reimburse Atlas Energy for its costs, including an allocable portion of employee salaries, in connection with its construction management services.

Disposition of Interest in APL’s General Partner. Before the completion of our and the Atlas Energy initial public offerings, Atlas America owned both us and the entities which act as the general partners, operators or managers of the drilling investment partnerships sponsored by Atlas America. The omnibus agreement prohibited Atlas America from transferring its interest in us, as general partner of APL, unless it also transferred to the same person its interests in those subsidiaries. Atlas America was permitted, however, to transfer its interest in us to a wholly- or majority-owned direct or indirect subsidiary as long as Atlas America

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continues to control the new entity. In connection with our initial public offering, Atlas America transferred its interest in APL’s general partner to us, then Atlas America’s wholly-owned subsidiary. Atlas America currently owns a 64.4% interest in us.

Natural Gas Gathering Agreements

APL entered into a master natural gas gathering agreement with Atlas America and certain of its subsidiaries in connection with the completion of its initial public offering in February 2000. In December 2006, in connection with the completion of the initial public offering of, and Atlas America’s contribution and sale of its natural gas and oil development and production assets to, Atlas Energy, Atlas Energy joined the master natural gas gathering agreement as an obligor. Under the master natural gas gathering agreement, APL receives a fee from Atlas Energy for gathering natural gas, determined as follows:

• for natural gas from well interests allocable to Atlas America or its affiliates (excluding general or limited partnerships sponsored by them) that were connected to APL’s gathering systems at February 2, 2000, the greater of $0.40 per Mcf or 16% of the gross sales price of the natural gas transported;

• for (i) natural gas from well interests allocable to general and limited partnerships sponsored by Atlas Energy that drill wells on or after December 1, 1999 that are connected to APL’s gathering systems (ii) natural gas from well interests allocable to Atlas Energy or its affiliates (excluding general or limited partnerships sponsored by them) that are connected to APL’s gathering systems after February 2, 2000, and (iii) well interests allocable to third parties in wells connected to APL’s gathering systems at February 2, 2000, the greater of $0.35 per Mcf or 16% of the gross sales price of the natural gas transported; and

• for natural gas from well interests operated by Atlas Energy and drilled after December 1, 1999 that are connected to a gathering system that is not owned by APL and for which APL assumes the cost of constructing the connection to that gathering system, an amount equal to the greater of $0.35 per Mcf or 16% of the gross sales price of the natural gas transported, less the gathering fee charged by the other gathering system.

Atlas Energy receives gathering fees from contracts or other arrangements with third-party owners of well interests connected to APL’s gathering systems. However, Atlas Energy must pay gathering fees owed to APL from its own resources regardless of whether it receives payment under those contracts or arrangements.

The master natural gas gathering agreement is a continuing obligation and, accordingly, has no specified term or provisions regarding termination. However, if we, as general partner of APL, are removed as general partner without cause, then no gathering fees will be due under the agreement with respect to new wells drilled by Atlas Energy.

The master natural gas gathering agreement may not be amended without the approval of the conflicts committee of the managing board of our general partner if, in the reasonable discretion of our general partner, such amendment will adversely affect APL’s common unitholders. APL’s Common unitholders do not have explicit rights to approve any termination or material modification of the master natural gas gathering agreement. We anticipate that the conflicts committee of the managing board of our general partner would submit to APL’s common unitholders for their approval any proposal to terminate or amend the master natural gas gathering agreement if our general partner determines, in its reasonable discretion, that the termination or amendment would materially adversely affect APL’s common unitholders.

In addition to the master natural gas gathering agreement, APL has three other gas gathering agreements with subsidiaries of Atlas Energy. Under two of these agreements, relating to certain wells located in southeastern Ohio and in Fayette County, Pennsylvania, APL receives a fee of $0.80 per Mcf. Under the third

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agreement, which covers wells owned by third parties unrelated to Atlas Energy or the investment partnerships it sponsors, APL receives fees that range between $0.20 to $0.29 per Mcf or between 10% to 16% of the weighted average sales price for the natural gas APL transports.

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/servicing operations. These operations include plants and gathering systems operated by ONEOK Field Services, Carrerra Gas Company, Copano Energy, LLC, Enogex, LLC, Eagle Rock Midstream Resources, L.P., Enbridge, Inc., Hiland Partners, MarkWest Energy Partners, L.P., Mustang Fuel Corporation, DCP Midstream, J.L. Davis and Targa Resources. APL believes that the principal factors upon which competition for new well connections is based are:

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

• 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 and, possibly, could lose wells already connected to its systems.

Being a regulated entity, Ozark Gas Transmission faces somewhat more indirect competition that is more regional or even national in character. CenterPoint Energy, Inc.’s and Texas Gas Transmission’s interstate systems are the nearest direct competitors.

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

As the omnibus agreement with Atlas Energy generally requires APL to connect wells it operates to APL’s system, APL does not expect any direct competition in connecting wells drilled and operated by Atlas Energy in the future. In addition, APL occasionally connects wells operated by third parties. For the year ended December 31, 2008, APL connected 59 third-party wells.

Regulation

Regulation by FERC of Interstate Natural Gas Pipelines. FERC regulates APL’s interstate natural gas pipeline interests. Ozark Gas Transmission transports natural gas in interstate commerce. As a result, Ozark Gas

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Transmission qualifies as a “natural gas company” under the Natural Gas Act and is subject to the regulatory jurisdiction of FERC. In general, FERC has authority over natural gas companies that provide natural gas pipeline transportation services in interstate commerce, and its authority to regulate natural gas companies includes:

• rate structures;

• rates of return on equity;

• recovery of costs;

• the services that APL’s regulated assets are permitted to perform;

• the acquisition, construction and disposition of assets;

• transactions involving the assignment of interstate pipeline capacity;

• interactions with marketing affiliates; and

• to an extent, the level of competition in that regulated industry.

Under the Natural Gas Act, FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. Its authority to regulate those services includes the rates charged for the services, terms and conditions of service, certification and construction of new facilities, the extension or abandonment of services and facilities, the maintenance of accounts and records, the acquisition and disposition of facilities, the initiation and discontinuation of services, and various other matters. Natural gas companies may only charge rates that have been determined to be just and reasonable in proceedings before FERC. In addition, FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.

The rates, terms and conditions of service provided by natural gas companies are required to be on file with FERC in FERC-approved tariffs. Pursuant to FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. We cannot assure you that FERC will continue to pursue its approach of pro-competitive policies as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity, transportation and storage facilities. Any successful complaint or protest against Ozark Gas Transmission’s FERC-approved rates could have an adverse impact on APL’s revenues associated with providing transmission services.

Gathering Pipeline Regulation. Section 1(b) of the Natural Gas Act exempts natural gas gathering facilities from the jurisdiction of the FERC. APL owns a number of intrastate natural gas pipelines in New York, Pennsylvania, Ohio, Arkansas, 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 transmission services and federally unregulated gathering services is the subject of regular litigation, so the classification and regulation of some of APL’s gathering facilities may be subject to change based on future determinations by FERC and the courts.

In Ohio, a producer or gatherer of natural gas may file an application seeking exemption from regulation as a public utility, except for the continuing jurisdiction of the Public Utilities Commission of Ohio to inspect gathering systems for public safety purposes. APL’s operating subsidiary has been granted an exemption by the Public Utilities Commission of Ohio for its Ohio facilities. The New York Public Service Commission imposes traditional public utility regulation on the transportation of natural gas by companies subject to its regulation. This regulation includes rates, services and siting authority for the construction of certain facilities. APL’s gas gathering operations currently are not subject to regulation by the New York Public Service Commission. APL’s

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operations in Pennsylvania currently are not subject to the Pennsylvania Public Utility Commission’s regulatory authority since they do not provide service to the public generally and, accordingly, do not constitute the operation of a public utility. Similarly, APL’s operations in Arkansas are not subject to rate oversight by the Arkansas Public Service Commission, but may, in certain circumstances, be subject to safety and environmental regulation by such commission or the Arkansas Oil and Gas Commission. In the event the Arkansas, Ohio, New York or Pennsylvania authorities seek to regulate APL’s operations, APL believes that its 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.

Nonetheless, 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 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. 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 transport natural gas.

Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that FERC has taken a less stringent approach to regulation of the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. For example, the Texas Railroad Commission has approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of one customer over another. 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. A portion of APL’s revenues is tied to the price of natural gas. The wholesale price of natural gas is not currently subject to federal regulation and, for the most part, is not subject to state regulation. Sales of natural gas 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 transmission companies that remain subject to FERC’s jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry, and these initiatives generally reflect more light-handed regulation. We cannot predict the ultimate impact of these regulatory changes on APL’s operations, and we note that some of FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that APL will be affected by any such FERC action materially differently than other companies with whom APL competes.

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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 engaging in 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 primary provisions of interest to APL’s interstate pipelines focus on two areas: (1) infrastructure development; and (2) market transparency and enhanced enforcement. Regarding infrastructure development, the Energy Policy Act includes provisions to clarify that FERC has exclusive jurisdiction over the siting of liquefied natural gas (“LNG”) terminals; provides for market-based rates for new 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; creates a consolidated record for all federal decisions relating to necessary authorizations and permits with respect to LNG terminals and interstate natural gas pipelines; and provides for expedited judicial review of any agency action and review by only the D.C. Circuit Court of Appeals of any alleged failure of a federal agency to act 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 rules, the Natural Gas Act has been amended to prohibit market manipulation and add provisions for 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 current law at $5,000 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.

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:

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

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

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

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

Failure to comply with these laws and regulations may result in the assessment of administrative, civil 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 substances 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 substances 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

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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 less stringent 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.

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 will generate wastes that may fall within the definition of a “hazardous substance.” CERCLA authorizes the 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. In fact, there is evidence that petroleum spills or releases have occurred at some of the properties owned or leased by APL. 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 remedial closure 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 strictly 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

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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.

Pipeline Safety. APL’s pipelines are subject to regulation by the U.S. Department of Transportation (“DOT”), under the Natural Gas Pipeline Safety Act of 1968, as amended, or the NGPSA, pursuant to which the DOT has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The NGPSA covers the pipeline transportation of natural gas and other gases, and the transportation and storage of liquefied natural gas and requires any entity that owns or operates pipeline facilities to comply with the regulations under the NGPSA, 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 NGPSA requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, future compliance with the NGPSA could result in increased costs.

The DOT, through the Office of Pipeline Safety, recently finalized a series of rules intended to require pipeline operators to develop integrity management programs for gas transmission pipelines that, in the event of a failure, could affect “high consequence areas.” “High consequence areas” are currently defined as areas with specified population densities, buildings containing populations of limited mobility, and areas where people gather that are located along the route of a pipeline. The Texas Railroad Commission, the Oklahoma Corporation Commission and other state agencies have adopted similar regulations applicable to intrastate gathering and transmission lines. Compliance with these rules has not had a material adverse effect on APL’s 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, referred to as 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.

Properties

As of December 31, 2008, our assets consisted principally of our ownership interests in APL and we maintained no separate properties. As of December 31, 2008, APL’s principal facilities in Appalachia include approximately 1,835 miles of 2 to 12 inch diameter pipeline. APL’s principal facilities in the Mid-Continent area consist of eight natural gas processing plants, one treating facility, and approximately 9,900 miles of active and inactive 2 to 42 inch diameter pipeline. Substantially all of APL’s gathering systems and transmission

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pipeline 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.

APL’s property or rights-of-way are subject to encumbrances, restrictions and other imperfections. These imperfections have not 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 right-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 right-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, for 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. In addition, 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 America and its affiliates manage APL’s gathering systems and operate its business. Atlas America employed approximately 549 people at December 31, 2008 who provided direct support to APL’s operations.

Atlas America and its affiliates, including Atlas Energy, 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 America and affiliates of Atlas America for the time and effort of the officers and employees who provide services to us and APL. Our officers who provide services to us and APL are not required to work full time on our or APL’s affairs. These officers may devote significant time to the affairs of Atlas America and its affiliates and be compensated by these affiliates for the services rendered to them. There may be significant conflicts between us and APL and Atlas America 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.

The NYSE requires the chief executive officer of each listed company to certify annually that he is not

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aware of any violation by the company of the NYSE corporate governance listing standards as of the date of the certification, qualifying the certification to the extent necessary. The Chief Executive Officer of our general partner provided such certification to the NYSE in 2008 without qualification. In addition, the certifications of the Chief Executive Officer and Chief Financial Officer of our general partner required by Sections 302 and 906 of the Sarbanes-Oxley Act have been included as exhibits to this report.

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.

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 amounts of cash that APL generates may not be sufficient for it to pay distributions to us at the current or any other level of distribution. 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:

• the demand for and price of its natural gas and NGLs;

• expiration of significant contracts;

• the volume of natural gas APL transports;

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

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

• the expenses APL incurs in providing its gathering services;

• the cost of acquisitions and capital improvements;

• APL’s issuance of equity securities;

• required principal and interest payments on APL’s debt;

• fluctuations in working capital;

• prevailing economic conditions;

• fuel conservation measures;

• alternate fuel requirements;

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• government regulation and taxation; and

• 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:

• the level of capital expenditures it makes;

• the sources of cash used to fund its acquisitions;

• 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

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

APL is unable to 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 will be unable to 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.

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

APL’s operations are affected by the continued financial crisis and related turmoil in the global financial system. The consequences of an economic recession and the current credit crisis include a lower level of economic activity and increased volatility in energy prices. This has resulted in a decline in energy consumption and lower market prices for oil and natural gas and may result in a reduction in drilling activity in APL’s service area or 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 turn, may impact the cash that we have available to fund our operations, pay debt service on our credit facility and make distributions to our unitholders.

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 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 reducing or eliminating future distributions to its unitholders. The source of our earnings and cash flow currently consists exclusively of cash distributions from APL. If APL reduces or eliminates its distributions, we would be forced to reduce or eliminate distributions to our unitholders and may be unable to make required debt service payments under our credit facility which would result in the lenders foreclosing on some portion, or all, of our interest in APL. 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

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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 of 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 distributions to our unitholders.

APL has a significant amount of debt. APL will need a substantial portion of its cash flow to make principal and interest payments on its indebtedness, reducing 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 distributions, reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing its indebtedness, or seeking additional equity capital or bankruptcy protection. APL may not be able to effect any of these remedies on satisfactory terms, or at all. If it cannot, its ability to make distributions to us and consequently, our ability to fund our operations, pay required debt service and make distributions to our unitholders could be reduced or eliminated.

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. Our and APL’s credit facilities also contain covenants requiring APL and us to maintain certain financial ratios. In addition, we and APL are prohibited from making any distribution to our respective unitholders if such distribution would cause an event of default or otherwise violate a covenant under our respective credit facilities.

If we do not pay distributions on our common units with respect to any fiscal quarter, our unitholders are not entitled to receive such payments in the future.

Our distributions to our unitholders are not cumulative. Consequently, if we do not pay distributions on our common units with respect to any fiscal quarter, our unitholders are not entitled to receive such payments in the future.

In the future, we may not have sufficient cash to pay distributions at our current quarterly distribution level or to increase distributions.

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. We cannot assure you that APL will continue to make quarterly distributions at its current level or increase its 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.

Our ability to distribute cash received from APL to our unitholders is limited by a number of factors, including:

• 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;

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

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

• 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

• 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 distributions we do make will be at or above our current quarterly distribution level. 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.

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. 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. A substantial portion of the cash flows we receive from APL is provided by these incentive distributions. 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, we 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. We also agreed that the resulting allocation of incentive distribution rights back to APL would be after we receive 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.

A reduction in APL’s distributions will disproportionately affect the amount of cash distributions to which we are currently entitled.

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We are entitled to receive incentive distributions from APL with respect to any particular quarter only if APL distributes more than $0.42 per common unit for such quarter. Furthermore, pursuant to the IDR Adjustment Agreement, we 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.

Our incentive distribution rights entitle us to receive increasing percentages, up to 48% and subject to the IDR Adjustment Agreement, of all cash distributed by APL. Because the incentive distribution rights currently participate at the maximum target cash distribution level, future growth in distributions we receive from APL will not result from an increase in the target cash distribution level associated with the incentive distribution rights.

Furthermore, a decrease in the amount of distributions by APL to less than $0.60 per common unit per quarter would reduce our percentage of the incremental cash distributions 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, any such reduction in quarterly cash distributions from APL would have the effect of disproportionately reducing the amount of all incentive distributions that we receive as compared to cash distributions we receive on our 2.0% general partner interest in APL and our APL common units.

Our ability to meet our 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. Moreover, 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:

• an increase in our operating expenses;

• an increase in general and administrative expenses;

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

• an increase in working capital requirements; or

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

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:

• 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, increases in principal or interest payments on our outstanding debt, reductions in distributions from APL, the effect of the IDR Adjustment Agreement, principal and interest payments on debt we may incur, tax expenses, 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.

• Our general partner’s board of directors will have 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 cash distributions to our unitholders from current levels pursuant to our stated cash distribution policy.

• 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.

• 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.

• 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 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 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.

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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 fiduciary duties 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 66 ²/3% 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 66 2/3% 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.

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Cost reimbursements due 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 America, APL’s general partner and their affiliates, including officers and directors of Atlas America, 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 America and its affiliates provide APL with services for which APL is charged reasonable fees as determined by Atlas America 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 America owns 64.4% of our units at December 31, 2008, 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 America owns 64.4% of our outstanding units at December 31, 2008, our general partner may not be removed without the consent of Atlas America.

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.

APL may issue additional limited partner units, which may increase the risk of it not having sufficient available cash to maintain or increase its per common unit distribution level.

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 maintain or increase its per common unit distribution level. 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.

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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 maintain or increase our per unit distribution level.

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:

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

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

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

• the ratio of taxable income to distributions may increase; and

• the market price of the common units may decline.

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 under the Investment Company Act of 1940.

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.

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.

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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:

• the allocation of shared overhead expenses to APL and us;

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

• 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;

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

• 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 transmission, 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.

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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:

• 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.

• 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.

• 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.

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

• 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.

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

• 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.

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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:

• 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;

• 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;

• 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;

• 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

• 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, 2008, Atlas America owns approximately 64.4% of our outstanding units.

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

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. 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

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benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the 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 distributions, 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 unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. 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 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 unitholders would be reduced.

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 revenues from POP and keep-whole contracts. As a result, APL’s income depends to a significant extent upon the prices at which the natural gas it transports, treats or processes and the NGLs it produces are sold. A 10% change in the average price of NGLs, natural gas and condensate APL processes and sells, based upon estimated unhedged market prices of $0.76 per gallon, $6.50 per mmbtu and $55.00 per barrel for NGLs, natural gas and condensate, respectively, would change our gross margin for the twelve-month period ended December 31, 2009, excluding the effect of minority interests in APL’s net income, by approximately $25.3 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 APL expects will be connected to its system to shut them in 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 we describe in “—Our only cash generating assets are our partnership interests in APL, and our cash flow therefore completely depends upon the ability of APL to make distributions to its partners,” under “Risks Relating to Our Business”. Oil and natural gas prices have been extremely volatile recently and have declined substantially. On December 19, 2008, the price of oil on the New York Mercantile Exchange fell to $33.87 per barrel for January 2009 delivery, declining to an approximate 5-year low from a high of $147.27 per barrel in July 2008. We expect 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 subject to

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percentage-of-proceeds contracts. Moreover, derivative instruments are subject to inherent risks, which we describe in “— APL’s price risk management strategies may fail to protect it and could reduce its gross margin and cash flow.”

The amount of natural gas APL transports 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 transports 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. 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 and pipeline transportation systems 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 transports or processes would result in a reduction in its gross margin and cash flows.

The amount of natural gas APL transports, treats 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 success of APL’s Appalachian operations depends upon Atlas Energy’s ability to drill and complete commercial producing wells.

Substantially all of the wells APL connects to its gathering systems in its Appalachian service area are drilled and operated by Atlas Energy for drilling investment partnerships sponsored by Atlas Energy. As a result, APL’s Appalachian operations depend principally upon the success of Atlas Energy in sponsoring drilling investment partnerships and completing wells for these partnerships. Atlas Energy operates in a highly competitive environment for acquiring undeveloped leasehold acreage and attracting capital. Atlas Energy 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. Furthermore, Atlas Energy is not required to connect wells for which it is not the operator to APL’s gathering systems. If Atlas Energy 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,

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the amount of natural gas transported by APL’s Appalachian gathering systems would substantially decrease and could, upon exhaustion of the wells currently connected to APL’s gathering systems, cause APL to abandon one or more of its Appalachian gathering systems, thereby materially reducing APL’s gross margin and cash flows.

The failure of Atlas Energy to perform its obligations under APL’s natural gas gathering agreements with it may adversely affect APL’s business.

Substantially all of APL’s Appalachian operating system revenues currently consist of the fees it receives under the master natural gas gathering agreement and other transportation agreements it has with Atlas Energy and its affiliates. APL expects to derive a material portion of its gross margin from the services APL provides under its contracts with Atlas Energy for the foreseeable future. Any factor or event adversely affecting Atlas Energy’s business or its ability to perform under its contracts with APL or any default or nonperformance by Atlas Energy of its contractual obligations to APL, 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 APL’s Appalachian operations, 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 transports 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 2008, Chesapeake Energy Corporation, Pioneer, Sandridge Energy, Inc., Conoco Phillips, XTO Energy Inc., Henry Petroleum, L.P., Linn Energy, LLC and Apache Corporation supplied APL’s Mid-Continent systems with a majority of their 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 service areas.

APL’s Mid-Continent operations may 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 and Sweetwater service area, ONEOK Field Services, Eagle Rock Midstream Resources, L.P., Enbridge Energy Partners, L.P., CenterPoint Energy, Inc., MarkWest Energy Partners, L.P. and Enogex LLC operate competing gathering systems and processing plants. CenterPoint Energy, Inc.’s and Texas Gas Transmission’s interstate system is the nearest

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direct competitor to APL’s Ozark Gas Transmission system. CenterPoint and Hiland Partners operate competing gathering systems in Ozark Gas Gathering’s service area. Hiland Partners, DCP Midstream, Mustang Fuel Corporation and ONEOK Partners operate competing gathering systems and processing plants in APL’s Chaney Dell service area. DCP Midstream, J.L. Davis, 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 transports, processes and treats will decrease, reducing its gross margin and cash flows.

The amount of natural gas APL transports, treats or processes may be reduced if the public utility 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 sales lines from wells connected to APL’s systems and the public utility 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 transports, and APL cannot arrange for delivery to other pipelines, local distribution companies or end users, the amount of natural gas APL transports may be reduced. Since APL’s revenues depend upon the volumes of natural gas it transports, this could result in a material reduction in APL’s gross margin and cash flows.

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:

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

• mistaken assumptions about revenues and costs, including synergies;

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

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

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

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

• the assumption of unknown liabilities;

• limitations on rights to indemnity from the seller;

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

• increased demands on existing personnel;

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

• the failure to realize expected growth or profitability.

The scope and cost of these risks may ultimately be materially greater than estimated at the time of the acquisition. Further, 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 its recent acquisitions or any future acquisitions with its operations and in realizing all of the anticipated benefits of these acquisitions.

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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:

• operating a significantly larger combined entity;

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

• integrating personnel with diverse business backgrounds and organizational cultures;

• consolidating operational and administrative functions;

• integrating pipeline safety-related records and procedures;

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

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

• customer or key employee loss from the acquired businesses;

• a significant increase in APL’s indebtedness; and

• potential environmental or regulatory liabilities and title problems.

APL’s investment in the interconnection of its Elk City/Sweetwater and Chaney Dell systems 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.

The acquisitions of APL’s Chaney Dell and Midkiff/Benedum systems 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. As a result of these acquisitions, 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.

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 transportation, 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.

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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 Sweetwater plant. 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 Sweetwater natural gas processing plant, from which it expects to generate additional incremental cash flow. APL also continues to expand the natural gas gathering system surrounding Sweetwater in order to maximize its plant throughput. In addition to the risks discussed above, expected incremental revenue from the Sweetwater natural gas processing plant could be reduced or delayed due to the following reasons:

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

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

• additional construction and operating costs exceeding budget estimates;

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

• difficulties in obtaining consistent supplies of natural gas; and

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

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.

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

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Currently APL’s gathering of natural gas from wells is exempt from regulation under the Natural Gas Act. 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. 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 APL’s natural gas pipeline activities, including, for example, its policies on interstate natural gas pipeline open access transportation, ratemaking, capacity release, and market center promotion, which indirectly affect intrastate markets. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot ensure 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 undue discrimination, natural gas production that may be tendered to the gatherer for handling. Texas and Oklahoma 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 or Oklahoma 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 transports natural gas.

Increased regulatory requirements relating to the integrity of the Ozark Transmission pipeline will require it to spend additional money to comply with these requirements. In particular, Ozark Gas Transmission is subject to extensive laws and regulations related to pipeline integrity. Federal legislation signed into law in December 2002 includes guidelines for the U.S. Department of Transportation and pipeline companies in the areas of testing, education, training and communication. Compliance with existing and recently enacted regulations requires significant expenditures. Additional laws and regulations that may be enacted in the future, such as U.S. Department of Transportation implementation of additional hydrostatic testing requirements, could significantly increase the amount of these expenditures.

Ozark Gas Transmission is subject to FERC rate-making policies that could have an adverse impact on APL’s ability to establish rates that would allow it to recover the full cost of operating the pipeline.

FERC’s rate-making policies could affect Ozark Gas Transmission’s ability to establish rates, or to charge rates that would cover future increases in its costs, or even to continue to collect rates that cover current costs. Natural gas companies may not charge rates that have been determined not to be just and reasonable by FERC. The rates, terms and conditions of service provided by natural gas companies are required to be on file with FERC in FERC-approved tariffs. Pursuant to FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. We cannot ensure that FERC will continue to pursue its approach of pro-competitive policies as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas capacity and transportation facilities. Any successful complaint or protest against Ozark Gas Transmission’s rates could reduce APL’s revenues associated with providing transmission services. We cannot ensure you that APL will be able to recover all of Ozark Gas Transmission’s costs through existing or future rates.

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Ozark Gas Transmission is subject to regulation by FERC in addition to FERC rules and regulations related to the rates it can charge for its services.

FERC’s regulatory authority also extends to:

• operating terms and conditions of service;

• the types of services Ozark Gas Transmission’s may offer to its customers;

• transactions involving the assignment of interstate pipeline capacity;

• construction of new facilities;

• acquisition, extension or abandonment of services or facilities;

• accounts and records, as well as periodic reporting requirements; and

• relationships with affiliated companies involved in all aspects of the natural gas and energy businesses.

FERC action in any of these areas or modifications of its current regulations could impair Ozark Gas Transmission’s ability to compete for business, increase the costs it incurs in its operations, limit the construction of new facilities or its ability to recover the full cost of operating its pipeline. For example, the development of uniform interstate gas quality standards by FERC could create two distinct markets for natural gas––an interstate market subject to uniform minimum quality standards and an intrastate market with no uniform minimum quality standards. Such a bifurcation of markets could make it difficult for APL’s pipelines to compete in both markets or to attract certain gas supplies away from the intrastate market. The time FERC takes to approve the construction of new facilities could raise the costs of APL’s projects to the point where they are no longer economic.

FERC has authority to review pipeline contracts. If FERC determines that a term of any such contract deviates in a material manner from a pipeline’s tariff, FERC typically will order the pipeline to remove the term from the contract and execute and refile a new contract with FERC or, alternatively, to amend its tariff to include the deviating term, thereby offering it to all shippers. If FERC audits a pipeline’s contracts and finds deviations that appear to be unduly discriminatory, FERC could conduct a formal enforcement investigation, resulting in serious penalties and/or onerous ongoing compliance obligations.

Should Ozark Gas Transmission fail to comply with all applicable FERC administered statutes, rules, regulations and orders, it could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, FERC has civil penalty authority under the Natural Gas Act to impose penalties for current violations of up to $1,000,000 per day for each violation.

Finally, we cannot give any assurance regarding the likely future regulations under which APL will operate Ozark Gas Transmission or the effect such regulation could have on its business, financial condition, and results of operations.

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;

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• 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 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:

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

• 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;

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

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

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

• 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.

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

APL pursues various hedging strategies to seek to reduce its exposure to losses from adverse changes in the prices for natural gas and NGLs. APL’s price risk management activities will vary in scope based upon the level and volatility of natural gas and NGL prices and other changing market conditions. APL’s price risk management activity may fail to protect or could harm it because, among other things:

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

• available derivative instruments may not correspond directly with the risks against which APL seeks protection;

• the duration of the derivative instrument may not match the duration of the risk against which APL seeks protection; and

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

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, methods of welding and other construction-related standards. Any violation of environmental, construction or safety laws could impose substantial liabilities and costs on APL.

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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 transporting 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, transmission and distribution 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 but, pursuant to the purchase option agreement, has the right to acquire up to an additional 22% interest.

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Risks Related to Our Ownership Structure

Atlas America and its affiliates, including Atlas Energy, 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 America and its affiliates, which own and control us, also own a 2.1% limited partner interest in APL. We and APL do not have any employees and rely solely on employees of Atlas America 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 America also own interests in us and APL. Conflicts of interest may arise between Atlas America 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 America who provide services to us and APL also devote significant time to the businesses of Atlas America in which we and APL have no economic interest. If these separate activities are significantly 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 America to pursue a future business strategy that favors us or APL or, apart from our agreements with Atlas America relating to APL’s Appalachian region operations, use APL’s assets for transportation or processing services APL provides. Atlas America’s directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of Atlas America.

• We are allowed to take into account the interests of parties other than APL, such as Atlas America, 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.

Conflicts of interest with Atlas America 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.

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.

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ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of the common unitholders during the year ended December  31, 2008.

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 February 24, 2009, the closing price for the common units was $1.58 and there were 14 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, 2008 and 2007:

	High		Low		Distributions Declared
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
2007
Fourth Quarter	$	41.34	$	26.49	$	0.34
Third Quarter	$	47.12	$	39.25	$	0.31
Second Quarter	$	42.15	$	23.61	$	0.26
First Quarter	$	26.20	$	23.31	$	0.25

Our Cash Distribution Policy

Our 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:

• provide for the proper conduct of our business;

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

• 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

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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.

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

APL’s partnership agreement requires that it distribute 100% of available cash to its general partner and common limited partners within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Available cash consists generally of all 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 its 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 APL’s quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.

Available cash is initially distributed 98% to APL’s common limited partners and 2% to APL’s 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 unitholders exceed specified targets, as follows:

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, we, as general partner and the holder of all of APL’s incentive distribution rights, 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, in connection with APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems. We also agreed that the resulting allocation of incentive distribution rights back to APL would be after we receive 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 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.

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 America in December 2005 and therefore do not have any historical financial statements prior to that date. On July 26, 2006, Atlas America contributed its ownership interests in Atlas Pipeline GP, its then wholly-owned subsidiary and APL’s general partner, to us.

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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 America. 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, 2008, 2007 and 2006 and at December 31, 2008 and 2007 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 as of December 31, 2006, 2005 and 2004 and for the years ended December 31, 2005 and 2004 from our consolidated financial statements, which were audited by Grant Thornton LLP and are not included within this report.

	Years Ended December 31,
	2008			2007(1)			2006(2)		2005(3)		2004(4)
	(in thousands, except per unit and operating data)
Statement of operations data:
Revenue:
Natural gas and liquids	$	1,370,000		$	761,118		$	391,356	$	338,672	$	72,364
Transportation, compression and other fees		99,709			81,785			60,924		30,309		18,800
Other income (loss), net		(55,502	)		(174,084	)		12,781		2,519		127
Total revenue and other income (loss), net		1,414,207			668,819			465,061		371,500		91,291
Costs and expenses:
Natural gas and liquids		1,086,142			587,524			334,299		288,180		58,707
Plant operating		60,835			34,667			15,722		10,557		2,032
Transportation and compression		17,886			13,484			10,753		4,053		2,260
General and administrative(5)		3,983			64,561			23,474		13,608		4,642
Depreciation and amortization		90,124			50,982			22,994		13,954		4,471
Goodwill and other asset impairment loss		698,508			—			—		—		—
Gain on early extinguishment of debt		(19,867	)		—			—		—		—
Loss (gain) on arbitration settlement, net		—			—			—		138		(1,457	)
Interest		86,705			62,629			24,726		14,175		2,301
Minority interests(6)		(22,781	)		3,940			118		1,083		—
Minority interests in APL(7)		(513,675	)		(133,321	)		16,335		13,447		10,941
Total costs and expenses		1,487,860			684,466			448,421		359,195		83,897
Net income (loss)		(73,653	)		(15,647	)		16,640		12,305		7,394
Premium on preferred unit redemption		—			—			—		—		(400	)
Net income (loss) attributable to common limited partners/owners	$	(73,653	)	$	(15,647	)	$	16,640	$	12,305	$	6,994
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	$	6,994

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Portion applicable to common limited partners’ interest (period subsequent to the initial public offering on July 26, 2006)		(73,653	)		(15,647	)		6,404			—			—
Net income (loss) attributable to common limited partners/owners	$	(73,653	)	$	(15,647	)	$	16,640		$	12,305		$	6,994
Net income (loss) attributable to common limited partners per unit:
Basic	$	(2.68	)	$	(0.66	)	$	0.30
Diluted(8)	$	(2.68	)	$	(0.66	)	$	0.30
Balance sheet data (at period end):
Property, plant and equipment, net	$	2,022,937		$	1,748,661		$	607,097		$	445,066		$	175,259
Total assets		2,451,321			2,877,514			787,134			742,726			234,898
Total debt, including current portion		1,539,427			1,254,426			324,083			298,625			54,452
Total partners’ capital (deficit)/owners’ equity (deficit)		(21,251	)		94,118			(7,010	)		(3,810	)		22,311
Cash flow data:
Net cash provided by (used in) operating activities	$	(202,643	)	$	37,958		$	7,532		$	47,018		$	10,419
Net cash used in investing activities		(292,970	)		(2,024,677	)		(104,499	)		(409,607	)		(150,905	)
Net cash provided by financing activities		490,844			1,996,650			64,928			378,612			143,622
Other financial data (unaudited):
Gross margin(9)	$	411,231		$	263,532		$	119,891		$	79,711		$	32,457
EBITDA(10)		257,338			(24,934	)		81,785			52,791			25,107
Adjusted EBITDA(10)		315,664			182,600			87,039			56,509			25,597
Maintenance capital expenditures	$	6,674		$	9,115		$	4,649		$	1,922		$	1,516
Expansion capital expenditures		319,260			130,532			79,067			49,179			7,635
Total capital expenditures	$	325,934		$	139,647		$	83,716		$	51,101		$	9,151
Operating data (unaudited)(11):
Appalachia:
Average throughput volumes (mcfd)		87,299			68,715			61,892			55,204			53,343
Mid-Continent:
Velma system:
Gathered gas volume (mcfd)		63,196			62,497			60,682			67,075			56,441
Processed gas volume (mcfd)		60,147			60,549			58,132			62,538			55,202
Residue gas volume (mcfd)		47,497			47,234			45,466			50,880			42,659
NGL volume (bpd)		6,689			6,451			6,423			6,643			5,799
Condensate volume (bpd)		280			225			193			256			185
Elk City/Sweetwater system:
Gathered gas volume (mcfd)		280,860			298,200			277,063			250,717			—
Processed gas volume (mcfd)		232,664			225,783			154,047			119,324			—
Residue gas volume (mcfd)		210,399			206,721			140,969			109,553			—
NGL volume (bpd)		10,487			9,409			6,400			5,303			—
Condensate volume (bpd)		332			212			140			127			—
Chaney Dell system(12):
Gathered gas volume (mcfd)		276,715			259,270			—			—			—
Processed gas volume (mcfd)		245,592			253,523			—			—			—
Residue gas volume (mcfd)		239,498			221,066			—			—			—
NGL volume (bpd)		13,263			12,900			—			—			—
Condensate volume (bpd)		791			572			—			—			—
Midkiff/Benedum system(12):
Gathered gas volume (mcfd)		144,081			147,240			—			—			—

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Processed gas volume (mcfd)	135,496	141,568	—	—	—
Residue gas volume (mcfd)	92,019	94,281	—	—	—
NGL volume (bpd)	19,538	20,618	—	—	—
Condensate volume (bpd)	1,142	1,346	—	—	—
NOARK system:
Average Ozark Gas Transmission throughput volume (mcfd)	442,464	326,651	249,581	255,777	—

(1) 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.

(2) Includes APL’s acquisition of the remaining 25% ownership interest in NOARK on May 2, 2006, representing eight months of an additional 25% ownership interest in NOARK’s operations for the year ended December 31, 2006. Operating data for the NOARK system represents 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, and a 75% ownership interest in NOARK on October 31, 2005, representing approximately two months’ operations, for the year ended December 31, 2005. Operating data presented for the NOARK system represents 100% of its operating activity.

(4) Includes APL’s acquisition of the Velma system on July 16, 2004, representing approximately five and one-half months’ operations for the year ended December 31, 2004.

(5) Includes non-cash compensation (income) expense of ($31.3) million, $39.0 million, $6.8 million, $4.7 million and $0.7 million for the years ended December 31, 2008, 2007, 2006, 2005 and 2004, respectively.

(6) For the years ended December 31, 2006 and 2005, this represents Southwestern’s 25% minority interest in the net income of NOARK. APL acquired Southwestern’s 25% ownership interest on May 2, 2006. For the year ended December 31, 2008 and 2007, this represents Anadarko’s 5% minority interest in the operating results of the Chaney Dell and Midkiff/Benedum systems, which APL acquired on July 27, 2007.

(7) Represents the minority interests in the net income (loss) of APL associated with the third-party unitholders of APL.

(8) For the year ended December 31, 2008 and 2007, approximately 438,000 and 357,000 phantom units, respectively, were excluded from the computation of diluted net income (loss) attributable to common limited partner units because the inclusion of such units would have been anti-dilutive.

(9) 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):

	Years Ended December 31,
	2008			2007(1)			2006(2)			2005(3)			2004(4)
Net income (loss)	$	(73,653	)	$	(15,647	)	$	16,640		$	12,305		$	7,394
Adjustments:
Effect of prior period items(13)		—			—			1,090			(1,090	)		—
Other (income) loss, net		55,502			174,084			(12,781	)		(2,519	)		(127	)
Plant operating		60,835			34,667			15,722			10,557			2,032
Transportation and compression		17,886			13,484			10,753			4,053			2,260
General and administrative		3,983			64,561			23,474			13,608			4,642
Depreciation and amortization		90,124			50,982			22,994			13,954			4,471
Goodwill and other asset impairment loss		698,508			—			—			—			—
Loss (gain) on arbitration settlement, net		—			—			—			138			(1,457	)
Interest		86,705			62,629			24,726			14,175			2,301
Minority interests(6)		(22,781	)		3,940			118			1,083			—
Minority interests in APL(7)		(513,675	)		(133,321	)		16,335			13,447			10,941
Non-cash linefill loss (gain)(14)		7,797			(2,270	)		820			—			—
Unrecognized economic impact of Chaney Dell and Midkiff/Benedum acquisition(15)		—			10,423			—			—			—
Gross margin	$	411,231		$	263,532		$	119,891		$	79,711		$	32,457

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(10) EBITDA represents net income (loss) before net interest expense, income taxes, and depreciation and amortization and minority 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 Note 16). 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):

	Years Ended December 31,
	2008			2007(1)			2006(2)			2005(3)			2004(4)
Net income (loss)	$	(73,653	)	$	(15,647	)	$	16,640		$	12,305		$	7,394
Adjustments:
Effect of prior period items(13)		—			—			1,090			(1,090	)		—
Minority interests in APL(7)		(513,675	)		(133,321	)		16,335			13,447			10,941
Interest expense		86,705			62,629			24,726			14,175			2,301
Depreciation and amortization		90,124			50,982			22,994			13,954			4,471
Goodwill and other asset impairment loss, net of associated minority interest		667,837			—			—			—			—
Unrecognized economic impact of Chaney Dell and Midkiff/Benedum acquisition(15)		—			10,423			—			—			—
EBITDA	$	257,338		$	(24,934	)	$	81,785		$	52,791		$	25,107
Adjustments:
Non-cash (gain) loss on derivative movements		(115,767	)		169,424			(2,316	)		(954	)		(210	)
Non-recurring cash derivative early termination expense(16)		197,641			—			—			—			—
Non-cash compensation (income) expense		(31,345	)		38,966			6,750			4,672			700
Non-cash linefill loss (gain) (14)		7,797			(2,270	)		820			—			—
Other non-cash items(17)		—			1,414			—			—			—
Adjusted EBITDA	$	315,664		$	182,600		$	87,039		$	56,509		$	25,597

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(11) “Mcf” represents thousand cubic feet; “mcfd” represents thousand cubic feet per day; “bpd” represents barrels per day.

(12) 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.

(13) 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.

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

(15) 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.

(16) During the year ended December 31, 2008, APL made net payments of $274.0 million, which resulted in a net cash expense recognized of $197.6 million, 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. These 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 America, Inc. (NASDAQ: ATLS), 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). In July 2006, Atlas America, Inc. and its affiliates (“Atlas America”), a publicly traded company (NASDAQ: ATLS), contributed its ownership interests in Atlas Pipeline Partners GP, LLC (“Atlas Pipeline GP”), its then wholly-owned subsidiary, a Delaware limited liability company and the general partner of Atlas Pipeline Partners, L.P. (“APL”), 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. Net proceeds from this offering were distributed to Atlas America. 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 Appalachian 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 owns at December 31, 2008:

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

• 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. In connection with APL’s acquisition of control

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of the Chaney Dell and Midkiff/Benedum systems (see “—Atlas Pipeline Partners, L.P.”), we, the holder of all the incentive distribution rights in APL, agreed to allocate up to $5.0 million of our incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. We also agreed that the resulting allocation of incentive distribution rights back to APL would be after we receive 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;

• 5,754,253 common units of APL, representing approximately 12.5% of the outstanding common units of APL, or a 13.9% limited partner interest in APL, and

• 10,000 $1,000 par value 12.0% cumulative convertible preferred limited partner units representing an approximate 3.2% ownership interest in APL based upon the market value of APL’s common units at December 31, 2008.

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.

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

• 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.

These amounts are partially offset by our July 2007 agreement 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. We also agreed that the resulting allocation of incentive distribution rights back to APL would be after we receive 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 (see “—APL’s Partnership Distributions”).

We pay 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.

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. Prior to our initial public offering, the consolidated financial statements include only the

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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).

Atlas Pipeline Partners, L.P.

APL is a publicly-traded Delaware limited partnership whose common units are listed on the New York Stock Exchange under the symbol “APL”. APL’s principal business objective is to generate cash for distribution to its unitholders. APL is a leading provider of natural gas gathering services in the Anadarko, Arkoma and Permian Basins and the Golden Trend 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 treatment services in Oklahoma and Texas. APL also provides interstate gas transmission services in southeastern Oklahoma, Arkansas, southern Kansas and southeastern Missouri. APL’s business is conducted in the midstream segment of the natural gas industry through two reportable segments: its Mid-Continent operations and its Appalachian operations.

Through its Mid-Continent operations, APL owns and operates:

• a FERC-regulated, 565-mile interstate pipeline system (“Ozark Gas Transmission”) that extends from southeastern Oklahoma through Arkansas and into southeastern Missouri and which has throughput capacity of approximately 500 MMcfd;

• eight natural gas processing plants with aggregate capacity of approximately 810 MMcfd and one treating facility with a capacity of approximately 200 MMcfd, located in Oklahoma and Texas; and

• 9,100 miles of active natural gas gathering systems located in Oklahoma, Arkansas, Kansas and Texas, which transport gas from wells and central delivery points in the Mid-Continent region to APL’s natural gas processing and treating plants or Ozark Gas Transmission, as well as third party pipelines.

Through its Appalachian operations, APL owns and operates 1,835 miles of natural gas gathering systems located in eastern Ohio, western New York, western Pennsylvania and northeastern Tennessee. Through an omnibus agreement and other agreements between APL and Atlas America, Inc. (“Atlas America” – NASDAQ: ATLS) and its affiliates, a publicly traded company and holder of a 64.4% ownership interest in us and a direct 2.1% ownership interest in APL, including Atlas Energy Resources, LLC and subsidiaries (“Atlas Energy”), a leading sponsor of natural gas drilling investment partnerships in the Appalachian Basin and a publicly-traded company (NYSE: ATN), APL gathers substantially all of the natural gas for its Appalachian Basin operations from wells operated by Atlas Energy. Among other things, the omnibus agreement requires Atlas Energy to connect to APL’s gathering systems wells it operates that are located within 2,500 feet of APL’s gathering systems. APL is also party to natural gas gathering agreements with Atlas America and Atlas Energy under which it receives gathering fees generally equal to a percentage, typically 16%, of the selling price of the natural gas it transports.

Recent Events

In December 2008, APL sold 10,000 newly-created 12% cumulative convertible Class B preferred units of limited partner interest (the “APL Class B Preferred Units”) to us for cash consideration of $1,000 per APL Class B Preferred Unit pursuant to a purchase agreement. We have the right, before March 30, 2009, to purchase

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an additional 10,000 APL Class B Preferred Units on the same terms. APL used the proceeds from the sale of the APL Class B Preferred Units for general partnership purposes. The APL Class B Preferred Units will receive distributions of 12% per annum, paid quarterly to us on the same date as the distribution payment date for APL common units. See “—APL Convertible Preferred Units – APL Class B Preferred Units”).

In December 2008, APL repurchased approximately $60.0 million in face amount of its senior unsecured 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 unsecured notes and approximately $27.0 million in face amount of APL’s 8.75% senior unsecured notes. All of the unsecured senior notes repurchased have been retired and are not available for re-issue.

In June 2008, we sold 308,109 common units through a private placement to Atlas America 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 (see “Our Common Equity Offerings”), which in turn utilized the proceeds to partially fund the early termination of certain derivative agreements. Following our private placement, Atlas America had a 64.4% ownership interest in us.

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 America 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 us to maintain our 2.0% general partner interest in APL.

The net proceeds from the public and private placement offerings of APL’s common units were utilized to fund the early termination of a majority of its crude oil derivative contracts that it entered into as proxy hedges for the prices it receives for the ethane and propane portion of its NGL equity volume. These derivative contracts, which related to production periods ranging from the end of second quarter of 2008 through the fourth quarter of 2009, were put in place simultaneously with APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007 (see “—Significant Acquisitions”) and had become less effective as a result of significant increases in the price of crude oil and less significant increases in the price of ethane and propane. APL estimates that it incurred a charge during the second quarter 2008 of approximately $10.6 million due to the decline in the price correlation of crude oil and ethane and propane. Our net income for the year ended December 31, 2008 includes our ownership interest in a $197.6 million cash derivative expense resulting from APL’s aggregate net payments of $274.0 million to unwind a portion of these derivative contracts.

In June 2008, APL issued $250.0 million of 10-year, 8.75% senior unsecured notes (the “APL 8.75% Senior Notes”) in a private placement transaction. The sale of the APL 8.75% Senior Notes generated net proceeds of approximately $244.9 million, which APL utilized to repay indebtedness under its senior secured term loan and revolving credit facility.

In June 2008, APL obtained $80.0 million of increased commitments to its senior secured revolving credit facility, increasing its aggregate lender commitments to $380.0 million. In connection with this and the previously mentioned transactions, APL also amended its senior secured credit facility to, among other things, exclude from the calculation of Consolidated EBITDA the costs associated with its termination of derivative instruments to the extent such costs are financed with or paid out of the net proceeds of an equity offering. In addition, consistent with several other recent energy master limited partnership agreements, APL’s general partner’s managing board and conflicts committee approved an amendment to its limited partnership agreement which will allow the cash expenditure to terminate derivative contracts to not reduce APL’s distributable cash flow.

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Subsequent Event

On January 27, 2009, APL and Sunlight Capital, the holder of its outstanding Class A Preferred Units, agreed to amend certain terms of its existing preferred unit agreement. The amendment (a) increased the dividend yield from 6.5% to 12% per annum, effective January 1, 2009, (b) changed the conversion commencement date from May 8, 2008 to April 1, 2009, (c) changed the conversion price adjustment from $43.00 to $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 the common units, and (d) changed the call redemption price from $53.22 to $27.25. Simultaneously with the execution of the amendment, APL issued Sunlight Capital $15.0 million of its 8.125% senior unsecured notes due 2015 to redeem 10,000 APL Class A Preferred Units. APL also agreed that it will redeem an additional 10,000 APL Class A Preferred Units for cash at the liquidation value on April 1, 2009. If Sunlight does not exercise its conversion right on or before June 2, 2009, APL will redeem the then-remaining 10,000 APL Class A Preferred Units for cash or one-half for cash and one-half for APL’s common limited partner units on July 1, 2009.

Significant Acquisitions

From the date of APL’s initial public offering in January 2000 through June 2008, 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 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”). 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 effected by 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 $1.125 billion 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”). We, as general partner and holder all of APL’s incentive distribution rights, have also agreed to allocate up to $5.0 million of our incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter. We also agreed that the resulting allocation of incentive distribution rights back to APL would be after we receive 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 (see “—APL’s Partnership Distributions”).

• In connection with this acquisition, APL reached an agreement with Pioneer Natural Resources Company (“Pioneer” – NYSE: PXD), which currently holds an approximate 27.2% undivided joint venture interest in the Midkiff/Benedum system, whereby Pioneer has an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system, which began on June 15, 2008 and ended on November 1, 2008, and up to an additional 7.4% interest beginning on June 15, 2009 and ending on November 1, 2009 (the aggregate 22.0% additional interest can be entirely purchased during the period beginning June 15, 2009 and ending on November 1, 2009). If the option is fully exercised, Pioneer would increase its interest in the system to approximately 49.2%. Pioneer would pay approximately $230 million, subject to certain adjustments, for the additional 22.0% interest if fully exercised. APL will manage and control the Midkiff/Benedum system regardless of whether Pioneer exercises the purchase options.

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• In May 2006, APL acquired the remaining 25% ownership interest in NOARK Pipeline System, Limited Partnership (“NOARK”) from Southwestern Energy Company (“Southwestern”) for a net purchase price of $65.5 million, consisting of $69.0 million in cash to the seller, (including the repayment of the $39.0 million of outstanding NOARK notes at the date of acquisition), less the seller’s interest in working capital at the date of acquisition of $3.5 million. In October 2005, APL acquired from Enogex, a wholly-owned subsidiary of OGE Energy Corp., all of the outstanding equity of Atlas Arkansas, which owned the initial 75% ownership interest in NOARK, for $163.0 million, plus $16.8 million for working capital adjustments and related transaction costs. NOARK’s principal assets include the Ozark Gas Transmission system, a 565-mile interstate natural gas pipeline, and Ozark Gas Gathering, a 365-mile natural gas gathering system.

Contractual Revenue Arrangements

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

• the volumes of natural gas APL gathers, transports 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; and

• the transportation and processing fees APL receives which, in turn, depends upon the price of the natural gas and NGLs it transports and processes, which itself is a function of the relevant supply and demand in the mid-continent, mid-Atlantic and northeastern areas of the United States.

In APL’s Appalachian region, substantially all of the natural gas it transports is for Atlas Energy under percentage-of-proceeds (“POP”) contracts, as described below, in which APL earns a fee equal to a percentage, generally 16%, of the gross sales price for natural gas subject, in most cases, to a minimum of $0.35 to $0.40 per thousand cubic feet, or mcf, depending on the ownership of the well. Since APL’s inception in January 2000, its Appalachian system transportation fee has exceeded this minimum generally. The balance of the Appalachian system natural gas APL transports is for third-party operators generally under fixed-fee contracts.

APL’s Mid-Continent segment revenue consists of the fees earned from its transmission, 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 NGLs, if any, off of delivery points on its systems. Under other agreements, APL transports natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with APL’s FERC-regulated transmission pipeline is comprised of firm transportation rates and, to the extent capacity is available following the reservation of firm system capacity, interruptible transportation rates and is recognized at the time transportation service is provided. 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, it enters into the following types of contractual relationships with its producers and shippers:

Fee-Based Contracts. These contracts provide for a set fee for gathering and 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.

POP Contracts. These contracts provide for APL to retain a negotiated percentage of the sale proceeds from residue natural gas and NGLs it gathers and processes, with the remainder being remitted to the producer. In this situation, APL and the producer are directly dependent on the volume of the commodity and its value; APL owns a percentage of that commodity and is directly subject to its market value.

Keep-Whole Contracts. These contracts require APL, as the processor, to purchase raw natural gas from the producer at current market rates. Therefore, APL bears the economic risk (the “processing margin

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risk”) that the aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the amount that it paid for the unprocessed natural gas. However, because the natural gas purchases contracted under keep-whole agreements are generally low in liquids content and 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. Therefore, the processing margin risk associated with a portion of APL’s keep-whole contracts is minimized.

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 natural gas transportation and 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, flexibility, 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. The number of active oil and gas rigs has increased in recent years, mainly due to recent significant increases in natural gas prices, which could result in sustained increases in drilling activity during the current and future periods. However, energy market uncertainty could negatively impact North American drilling activity in the short term. Lower drilling levels 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. We closely monitor the risks associated with commodity price changes on APL’s future operations and, where appropriate, use 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. A 10% change in the average price of NGLs, natural gas and condensate APL processes and sells, based on estimated unhedged market prices of $0.76 per gallon, $6.50 per mmbtu and $55.00 per barrel for NGLs, natural gas and condensate, respectively, would change our gross margin, excluding the effect of minority interest in APL net income (loss), for the twelve-month period ending December 31, 2009 by approximately $25.3 million.

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Currently, there is an unprecedented 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,
	2008	2007	2006
Operating data(1):
Appalachia:
Average throughput volumes (mcfd)	87,299	68,715	61,892
Mid-Continent:
Velma system:
Gathered gas volume (mcfd)	63,196	62,497	60,682
Processed gas volume (mcfd)	60,147	60,549	58,132
Residue gas volume (mcfd)	47,497	47,234	45,466
NGL volume (bpd)	6,689	6,451	6,423
Condensate volume (bpd)	280	225	193
Elk City/Sweetwater system:
Gathered gas volume (mcfd)	280,860	298,200	277,063
Processed gas volume (mcfd)	232,664	225,783	154,047
Residue gas volume (mcfd)	210,399	206,721	140,969
NGL volume (bpd)	10,487	9,409	6,400
Condensate volume (bpd)	332	212	140
Chaney Dell system(2):
Gathered gas volume (mcfd)	276,715	259,270	—
Processed gas volume (mcfd)	245,592	253,523	—
Residue gas volume (mcfd)	239,498	221,066	—
NGL volume (bpd)	13,263	12,900	—
Condensate volume (bpd)	791	572	—
Midkiff/Benedum system(2):
Gathered gas volume (mcfd)	144,081	147,240	—
Processed gas volume (mcfd)	135,496	141,568	—
Residue gas volume (mcfd)	92,019	94,281	—
NGL volume (bpd)	19,538	20,618	—
Condensate volume (bpd)	1,142	1,346	—
NOARK system:
Average Ozark Gas Transmission throughput volume (mcfd)	442,464	326,651	249,581

⁽¹⁾ “Mcf” represents thousand cubic feet; “mcfd” represents thousand cubic feet per day; “bpd” represents barrels per day.

⁽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. The Chaney Dell and Midkiff/Benedum systems were acquired on July 27, 2007.

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

Revenue.Natural gas and liquids revenue was $1,370.0 million for the year ended December 31, 2008, an increase of $608.9 million from $761.1 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 comparable 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 under Note 9 under Item 8, “Financial Statements and Supplementary Data”.

Transportation, compression and other fee revenue increased to $99.7 million for the year ended December 31, 2008 compared with $81.8 million for the prior year. This $17.9 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. For APL’s NOARK system, average Ozark Gas Transmission volume was 442.5 MMcfd for the year ended December 31, 2008, an increase of 35.5% from the prior year due to an increase in throughput capacity to 400.0 MMcfd during the third quarter 2007 and an increase to 500.0 MMcfd during the fourth quarter 2008 and higher customer demand.

Other income (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 “—7A Quantitative and Qualitative Discussion About Market Risk”.

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Costs and Expenses.Natural gas and liquids cost of goods sold of $1,086.1 million and plant operating expenses of $60.8 million for the year ended December 31, 2008 represented increases of $498.6 million and $26.1 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 $4.4 million to $17.9 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 $60.6 million to $4.0 million for the year ended December 31, 2008 compared with $64.6 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 to be 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 Note 15 to the consolidated financial statements in Item 8, “Financial Statements and Supplementary Data”). 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 calculation 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 $90.1 million for the year ended December 31, 2008 compared with $51.0 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 $86.7 million for the year ended December 31, 2008 as compared with $62.6 million for the prior year. This $24.1 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 (see “—Recent Events”).

Goodwill and other asset impairment loss of $698.5 million for the year ended December 31, 2008 consisted of a $676.9 million impairment charge to APL’s goodwill as a result of its annual goodwill impairment test and a $21.6 million write-off of costs related to an APL pipeline expansion project. 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. APL’s estimates were subjective and based upon numerous assumptions about future operations and market conditions, which are subject to change. 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 APL’s contractual arrangement. APL’s management is pursuing other strategic alternatives for this project.

Gain on early extinguishment of debt of $19.9 million for the year ended December 31, 2008 resulted

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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 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 (see “—Recent Events”).

Minority interest expense decreased $26.7 million to income of $22.8 million for the year ended December 31, 2008 from $3.9 million of expense for the prior year. This decrease was primarily due to lower net income for APL’s Chaney Dell and Midkiff/Benedum joint ventures, which were formed to effect 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 minority interest expense represents Anadarko’s 5% interest in the net income of the Chaney Dell and Midkiff/Benedum joint ventures.

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

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Revenue.Natural gas and liquids revenue was $761.1 million for the year ended December 31, 2007, an increase of $369.7 million from $391.4 million for the prior year. The increase was primarily attributable to revenue contribution from APL’s Chaney Dell and Midkiff/Benedum systems, which APL acquired in July 2007, of $344.2 million, an increase of $26.5 million from APL’s Elk City/Sweetwater system due primarily to an increase in volumes, which includes processing volumes from APL’s newly constructed Sweetwater gas plant, and an increase of $18.5 million from APL’s Velma system due primarily to an increase in volumes. These increases were partially offset by a decrease of $21.0 million from APL’s NOARK system due primarily to lower natural gas sales volumes on its gathering systems. Processed natural gas volume on the Chaney Dell system was 253.5 MMcfd for the period from July 27, 2007, the date of acquisition, to December 31, 2007, while the Midkiff/Benedum system had processed natural gas volume of 103.6 MMcfd for the same period. Processed natural gas volume on APL’s Elk City/Sweetwater system averaged 225.8 MMcfd for the year ended December 31, 2007, an increase of 46.6% from the prior year. Processed natural gas volume averaged 60.5 MMcfd on APL’s Velma system for the year ended December 31, 2007, an increase of 4.2% from the prior year. 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 Note 10 under Item 8, “Financial Statements and Supplementary Data”.

Transportation, compression and other fee revenue increased to $81.8 million for the year ended December 31, 2007 compared with $60.9 million for the prior year. This $20.9 million increase was primarily due to an increase of $10.4 million from the transportation revenues associated with APL’s NOARK system, $4.0 million of contributions from APL’s Chaney Dell and Midkiff/Benedum systems, a $3.5 million increase from APL’s Appalachia system, and an increase of $2.9 million associated with APL’s Elk City/Sweetwater system. For APL’s NOARK system, average Ozark Gas Transmission volume was 326.7 MMcfd for the year ended December 31, 2007, an increase of 30.9% from the prior year. The APL Appalachia system’s average throughput volume was 68.7 MMcfd for the year ended December 31, 2007 as compared with 61.9 MMcfd for the prior year, an increase of 6.8 MMcfd or 11.0%. The increase in the APL Appalachia system average daily throughput volume was principally due to new wells connected to APL’s gathering system and throughput associated with APL’s acquisition of a processing plant and gathering system in August 2007.

Other income (loss), net, including the impact of non-cash gains and losses recognized on derivatives, was a loss of $174.1 million for the year ended December 31, 2007, a decrease of $186.9 million from the prior year. This decrease was due primarily to a $169.4 million non-cash derivative loss for the year ended December 31,

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2007 compared with a $5.7 million non-cash derivative gain for the year ended December 31, 2006, an unfavorable movement of $175.2 million. This change in the non-cash impact of derivatives was the result of commodity price movements and their unfavorable impact on derivative contracts APL has for production volumes in future periods. We recorded $130.2 million of non-cash derivative losses during the fourth quarter 2007, when forward crude oil prices for the duration of APL’s derivative contracts, which are the basis for adjusting the fair value of its derivative contracts, increased from an average price of $74.78 per barrel at September 30, 2007 to $89.89 per barrel at December 31, 2007, an increase of $15.11. 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.

Costs and Expenses.Natural gas and liquids cost of goods sold of $587.5 million and plant operating expenses of $34.7 million for the year ended December 31, 2007 represented increases of $253.2 million and $18.9 million, respectively, from the prior year amounts due primarily to contribution from APL’s Chaney Dell and Midkiff/Benedum acquisition and an increase in gathered and processed natural gas volumes on APL’s Elk City/Sweetwater system, which includes contributions from its Sweetwater processing facility, partially offset by a decrease in APL’s NOARK gathering system natural gas purchases. Transportation and compression expenses increased $2.7 million to $13.5 million for the year ended December 31, 2007 due to higher NOARK and Appalachia system operating and maintenance costs as a result of increased capacity and additional well connections.

General and administrative expenses, including amounts reimbursed to affiliates, increased $41.1 million to $64.6 million for the year ended December 31, 2007 compared with $23.5 million for the prior year. This increase was mainly due to a $32.2 million increase in non-cash compensation expense related to vesting of our unit option awards and our and APL’s phantom and common unit awards (see Note 14 to the consolidated financial statements in Item 8, “Financial Statements and Supplementary Data”) and higher costs associated with managing our and APL’s businesses, including management time related to acquisition and capital raising opportunities.

Depreciation and amortization increased to $51.0 million for the year ended December 31, 2007 compared with $23.0 million for the year ended December 31, 2006 due primarily to the depreciation associated with APL’s Chaney Dell and Midkiff/Benedum acquired assets and APL’s expansion capital expenditures incurred between the periods, including its Sweetwater processing facility.

Interest expense increased to $62.6 million for the year ended December 31, 2007 as compared with $24.7 million for the prior year. This $37.9 million increase was primarily due to interest associated with APL’s $830.0 million term loan issued in connection with its acquisition of the Chaney Dell and Midkiff/Benedum systems and a $5.1 million increase in the amortization of deferred finance costs principally due to $5.0 million of accelerated amortization associated with the replacement of APL’s previous credit facility with a new credit facility in July 2007 (see “—APL Term Loan and Credit Facility”).

Minority interest expense of $3.9 million for the year ended December 31, 2007 represents Anadarko’s 5% ownership interest in the net income of the Chaney Dell and Midkiff/Benedum joint ventures, which were formed to effect APL’s acquisition of control of the respective systems. Minority interest expense of $0.1 million for the year ended December 31, 2006 represents Southwestern’s 25% ownership interest in the net income of NOARK through May 2, 2006, the date which APL acquired this remaining ownership interest.

Minority interest in APL’s net income (loss), which represents the allocation of APL’s earnings to its non-affiliated limited partners, was income of $133.3 million for the year ended December 31, 2007 as compared with an expense of $16.3 million for the prior year. This decrease was primarily due to a decrease in APL’s net income.

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

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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, reported net income would have been reduced by approximately 1.1%, 3.4% and 0.5% for the third quarter of 2005, fourth quarter of 2005, and first quarter of 2006, respectively. Our management believes that the impact of these adjustments is immaterial to its prior financial statements.

Liquidity and Capital Resources

General

Our primary sources of liquidity are distributions received with respect to our ownership interests in APL and borrowings under our credit facility. 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 distributions received from APL and our capital contributions to APL through the retention of cash and borrowings under our credit facility.

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 additional borrowings as they become due or by the issuance of additional limited partner units.

At December 31, 2008, we had $46.0 million outstanding and $4.0 million of remaining committed capacity under our credit facility, subject to covenant limitations (see “–– Our Credit Facility”). APL had $302.0 million of outstanding borrowings under its $380.0 million senior secured credit facility at December 31, 2008 and $5.9 million of outstanding letters of credit, which are not reflected as borrowings on our consolidated balance sheet, with $72.1 million of remaining committed capacity under its credit facility, subject to covenant limitations (see “—APL Term Loan and Credit Facility”). We and APL were in compliance with our respective credit facility’s covenants at December 31, 2008. At December 31, 2008, we had a working capital deficit of $43.8 million compared with a working capital deficit of $78.7 million at December 31, 2007. This increase in working capital was primarily due to a $94.9 million increase in the current portion of net hedge receivable, partially offset by a $14.5 million increase in accounts payable and accrued liabilities and a $37.5 million decrease in accounts receivable. We believe that we and APL have sufficient liquid assets, cash from operations and borrowing capacity to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. However, we and APL are subject to business and operational risks that could adversely affect our cash flow. We and APL may need to supplement our cash generation with proceeds from financing activities, including borrowings under our and APL’s credit facility and other borrowings, the issuance of additional limited partner units and the sale of APL 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 significantly. 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.

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

Net cash used in operating activities of $202.6 million for the year ended December 31, 2008 represented a decrease of $240.6 million from $38.0 million of net cash provided by operating activities for the prior year. The decrease was derived principally from a $280.4 million unfavorable movement in net income excluding non-cash charges, partially offset by a $39.8 million increase in cash flows from working capital changes. The decrease in net income excluding non-cash charges was principally due to the $197.6 million unfavorable cash impact from APL’s early termination of certain derivative instruments during the year ended December 31, 2008. The non-cash charges which impacted net income (loss) include a $378.2 million increase in non-cash derivative gains, a $70.3 million decrease in non-cash compensation expense, a $26.7 million unfavorable change in minority interest expense, and a $19.9 million non-cash gain on extinguishment of long-term debt, partially offset by a $698.5 million increase in goodwill and other asset impairment loss and a $39.1 million increase in depreciation and amortization expense. The movement in non-cash derivative gains and losses resulted from decreases in commodity prices at December 31, 2008 compared with the prior year end and their favorable mark-to-market impact on the fair value of derivative contracts APL has for future periods. The increase in depreciation and amortization principally resulted from APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007. The increase in goodwill and other asset impairment loss was due to APL’s goodwill impairment charge of $676.9 million and a $21.6 million write-off of costs related to APL’s pipeline expansion project during the year ended December 31, 2008. The decrease in non-cash compensation expense was principally attributable to a mark-to-market gain recognized during the year ended December 31, 2008 for certain APL common unit awards for which the ultimate amount to be issued will be determined after the completion of our 2008 fiscal year. The mark-to-market gain was the result of a decrease 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.

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 $186.3 million increase in APL capital expenditures. Net cash paid for acquisitions of $1,884.5 million in the prior year 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 $490.8 million for the year ended December 31, 2008, a decrease of $1,505.9 million from $1,996.7 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 $157.0 million decrease from the net proceeds from our issuance of common units, a $162.9 million increase in repayments of APL long-term debt, and a $24.5 million increase in distributions paid to our common limited partners, partially offset by a $126.0 million net increase in borrowings under our and APL’s revolving credit facility. 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 (see”—Recent Events”). The increase in net borrowings under APL’s revolving credit facility was principally utilized to finance its capital expenditures during the period.

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Cash Flows – Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Net cash provided by operating activities of $38.0 million for the year ended December 31, 2007 represented an increase of $30.5 million from $7.5 million for the prior year. The increase was derived principally from a $61.6 million increase in net income excluding non-cash charges and a $6.7 million decrease in cash flow from working capital changes. This increase in net income excluding non-cash charges was principally due to the contributions from APL’s Chaney Dell and Midkiff/Benedum systems, which were acquired in July 2007. The non-cash charges which impacted net income include a $171.7 million favorable movement in APL’s derivative non-cash gains and losses, a $32.2 million increase in non-cash compensation expense, a $28.0 million increase in depreciation and amortization and a $5.1 million increase in amortization of deferred finance costs. These amounts were partially offset by a $22.2 million increase in distributions paid to minority limited partners in APL. The movement in APL’s derivative non-cash gains and losses resulted from commodity price movements and their unfavorable impact on derivative contracts APL has for future periods. The increase in non-cash compensation expense was due an increase in common unit awards estimated by APL management to be issued under incentive compensation agreements to certain key employees as a result of APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems. The increase in minority interests and depreciation and amortization resulted from APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems in July 2007.

Net cash used in investing activities was $2,024.7 million for the year ended December 31, 2007, an increase of $1,920.2 million from $104.5 million for the prior year. This increase was principally due to the $1,884.5 million of net cash paid for APL’s acquisition for the year ended December 31, 2007 compared with the $30.0 million for the prior year. Net cash paid for acquisitions for the year ended December 31, 2007 represents the net amount paid for APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems, while the net cash paid for the prior year comparable period represents the amount paid for APL’s acquisition of the remaining 25% ownership interest in the NOARK system. Also affecting the change in net cash used in investing activities was a $55.9 million increase in APL capital expenditures, a $7.0 million decrease in cash proceeds APL received from its sale of assets, and a $1.5 million decrease in net cash proceeds received from APL’s settlement of an insurance claim which occurred during the prior year. The decrease in cash proceeds received from the sale of assets resulted from APL’s sale of certain gathering pipelines within the Velma system during the year ended December 31, 2006. See further discussion of capital expenditures under “—Capital Requirements”.

Net cash provided by financing activities was $1,996.7 million for the year ended December 31, 2007, an increase of $1,931.8 million from $64.9 million of net cash provided by financing activities for the prior year. This increase was principally due to a $926.7 million increase in net proceeds from the issuance of APL’s common units, a $780.5 million increase in net proceeds from APL’s issuance of long-term debt, a $92.7 million increase in net proceeds from the issuance of our common units, an $91.2 million increase resulting from the absence in the current period of a distribution to owners during 2006, a $38.9 million favorable impact regarding repayments of long-term debt, a $38.5 million increase in borrowings under APL’s revolving credit facility and a $25.0 million increase in borrowings under our revolving credit facility. These amounts were partially offset by a $39.9 million decrease in net proceeds from APL’s issuance of cumulative convertible preferred units and a $21.2 million increase in distributions paid to our limited partners. The increase in net proceeds from the issuance of our and APL’s common units and net proceeds from the issuance of APL’s long-term debt resulted from transactions undertaken during July 2007 to finance APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems.

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

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• 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,
	2008		2007		2006
Maintenance capital expenditures	$	6,674	$	9,115	$	4,649
Expansion capital expenditures		319,260		130,532		79,067
Total	$	325,934	$	139,647	$	83,716

Expansion capital expenditures increased to $319.3 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. 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. As of December 31, 2008, APL is committed to expend approximately $93.0 million on pipeline extensions, compressor station upgrades and processing facility upgrades.

Expansion capital expenditures increased to $130.5 million for the year ended December 31, 2007 due principally to expansions of APL’s Appalachia, Velma, Elk City/Sweetwater, NOARK, Chaney Dell and Midkiff/Benedum gathering systems and upgrades to processing facilities and compressors to accommodate new wells drilled in APL’s service areas. Maintenance capital expenditures for the year ended December 31, 2007 increased to $9.1 million due to the additional maintenance requirements of APL’s Chaney Dell and Midkiff/Benedum acquisition and fluctuations in the timing of APL’s scheduled maintenance activity.

Our Credit Facility

At December 31, 2008 we, with Atlas Pipeline GP as guarantor, had a $50.0 million revolving credit facility with a syndicate of banks. At December 31, 2008, we had $46.0 million outstanding under our revolving credit facility, which was utilized to fund our capital contributions to APL to maintain our 2.0% general partner interest and underwriter fees and other transaction costs related to our July 2007 private placement of common units (see “—Atlas Pipeline Partners, L.P.”). Our credit facility matures in April 2010 and bears interest, at our option, at either (i) adjusted LIBOR (plus the applicable margin, as defined in the credit facility) or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank, National Association prime rate (each plus the applicable margin). The weighted average interest rate on our outstanding credit facility borrowings at December 31, 2008 was 3.4%. Borrowings under our credit facility are secured by a first-priority lien on a security interest in all of our assets, including a 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; make distribution payments to our unitholders if an event of default exists or would result from such distribution; or enter into a merger or sale of substantially all of our property or assets, including the sale or transfer of interests in our subsidiaries. We are in compliance with these covenants as of December 31, 2008.

The events which constitute an event of default under our 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 us in excess of a specified amount, a change of control of Atlas America,

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our general partner or any other obligor, and termination of a material agreement and occurrence of a material adverse effect. Our credit facility requires us to maintain a combined leverage ratio, defined as the ratio of the sum of (i) our funded debt (as defined in our credit facility) and (ii) APL’s funded debt (as defined in APL’s credit facility) to APL’s EBITDA (as defined in APL’s credit facility)) of not more than 5.5 to 1.0. In addition, our credit facility requires us to maintain a funded debt (as defined in our credit facility) to EBITDA ratio of not more than 3.5 to 1.0; and an interest coverage ratio (as defined in our credit facility) of not less than 3.0 to 1.0. Our credit facility defines EBITDA for any period of four fiscal quarters as the sum of (i) four times the amount of cash distributions payable by APL to us in respect of our general partner interest, limited partner interest and incentive distribution rights in APL with respect to the last fiscal quarter in such period, and (ii) our consolidated net income (as defined in our credit facility and as adjusted as provided in our credit facility). As of December 31, 2008, our combined leverage ratio was 4.9 to 1.0, our senior secured debt to EBITDA was 1.0 to 1.0, and our interest coverage ratio was 25.5 to 1.0.

We may borrow under our credit facility (i) for general business purposes, including for working capital, to purchase debt or limited partnership units of APL, to fund general partner contributions from us to APL and to make permitted acquisitions, (ii) to pay fees and expenses related to our credit facility and (iii) for letters of credit.

Our Partnership Distributions

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:

• provide for the proper conduct of our business;

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

• 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.

APL’s Partnership Distributions

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.

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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.

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, we, as sole owner of APL’s general partner, agreed to allocate up to $5.0 million of our incentive distribution rights per quarter back to APL through the quarter ended June 30, 2009, and up to $3.75 million per quarter thereafter, in connection with APL’s acquisition of the Chaney Dell and Midkiff/Benedum systems (see “—Significant Acquisitions”). We also agreed that the resulting allocation of incentive distribution rights back to APL would be after we receive 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. Of the $37.3 million of incentive distributions declared by APL for the year ended December 31, 2008, the general partner received $23.5 million after the allocation of $13.8 million of its incentive distribution rights back to APL.

Off Balance Sheet Arrangements

As of December 31, 2008, our off balance sheet arrangements are limited to APL’s letters of credit outstanding of $5.9 million and its commitments to expend approximately $93.0 million on capital projects.

Contractual Obligations and Commercial Commitments

The following table summarizes our and APL’s contractual obligations and commercial commitments at December 31, 2008 (in thousands):

Contractual cash obligations:			Payments Due By Period
	Total		Less than 1 Year		1 – 3 Years		4 – 5 Years		After 5 Years
Total debt	$	1,539,427	$	—	$	46,000	$	302,000	$	1,191,427
Interest on total debt(1)		471,332		73,006		143,542		138,404		116,380
Derivative-based obligations		64,319		26,559		35,078		2,682		—
Operating leases		11,535		4,953		5,336		1,246		—
Total contractual cash obligations	$	2,086,613	$	104,518	$	229,956	$	444,332	$	1,307,807
(1)    Based on the interest rates of our respective debt components as of December 31, 2008.
Other commercial commitments:			Amount of Commitment Expiration Per Period
	Total		Less than 1 Year		1 – 3 Years		4 – 5 Years		After 5 Years
Standby letters of credit	$	5,925	$	5,925	$	—	$	—	$	—
Other commercial commitments	$	93,007	$	93,007		—		—		—
Total commercial commitments	$	98,932	$	98,932	$	—	$	—	$	—

Other commercial commitments relate to APL’s commitments for pipeline extensions, compressor station upgrades and processing facility upgrades.

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Our Common Equity Offerings

In June 2008, we sold 308,109 common units through a private placement to Atlas America 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 (see “—Recent Events”), which in turn utilized the proceeds to partially fund the early termination of certain derivative agreements. Following our private placement, Atlas America had a 64.4% ownership interest in us.

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.

In July 2006, Atlas America contributed its ownership interests in Atlas Pipeline GP, its then wholly-owned subsidiary and Atlas Pipeline’s general partner, to us. Concurrent with this transaction, we issued 3,600,000 common units, representing a then-17.1% ownership interest, in an initial public offering at a price of $23.00 per unit for total gross proceeds of $82.8 million. Substantially all of the net proceeds of $74.5 million from this offering, after underwriting commissions and other transaction costs, were distributed to Atlas America.

APL Common Equity Offerings

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 on June 24, 2008, APL sold 1,112,000 common units to Atlas America 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 (see “—Recent Events”).

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 “—Atlas Pipeline Partners, L.P.”). The common units APL issued were subsequently registered with the Securities and Exchange Commission in November 2007.

In May 2006, APL sold 500,000 common units in a public offering at a price of $41.20 per unit, yielding net proceeds of approximately $19.7 million, after underwriting commissions and other transaction costs. APL utilized the net proceeds from the sale to partially repay borrowings under its credit facility made in connection with APL’s acquisition of the remaining 25% ownership interest in NOARK.

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APL Convertible Preferred Units

APL Class A Preferred Units

In March 2006, APL entered into an agreement to sell 30,000 6.5% cumulative convertible preferred units (“APL Class A Preferred Units”) representing limited partner interests to Sunlight Capital Partners, LLC (“Sunlight Capital”), an affiliate of Elliott & Associates, for aggregate gross proceeds of $30.0 million. APL also sold an additional 10,000 APL Class A Preferred Units to Sunlight Capital for $10.0 million in May 2006, pursuant to APL’s right under the agreement to require Sunlight Capital to purchase such additional units. The APL Class A Preferred Units were originally entitled to receive dividends of 6.5% per annum commencing in March 2007, and paid quarterly on the same date as the distribution payment date for APL’s common units. In April 2007, APL and Sunlight Capital agreed to amend the terms of the Class A Preferred Units effective as of that date. The terms of the APL Class A Preferred Units were amended to entitle them to receive dividends of 6.5% per annum commencing in March 2008 and to be convertible, at Sunlight Capital’s option, into APL 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 may elect to pay cash rather than issue its common units in satisfaction of a conversion request. APL has 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 will automatically be converted into APL 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. We recorded the senior unsecured notes issued as long-term debt and a preferred unit dividend within minority interest in APL on our consolidated balance sheet and, during the year ended December 31, 2007, reduced minority interest in APL by $3.8 million of this amount, which was the portion deemed to be attributable to the concessions of APL’s 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 minority 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.

On January 27, 2009, APL and Sunlight Capital agreed to a second amendment to the APL Class A Preferred Units. The amendment (a) increased the dividend yield from 6.5% to 12% per annum, effective January 1, 2009, (b) changed the conversion commencement date from May 8, 2008 to April 1, 2009, (c) changed the conversion price adjustment from $43.00 to $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) changed the call redemption price from $53.22 to $27.25. Simultaneously with the execution of the amendment, APL issued Sunlight Capital $15.0 million of its 8.125% senior unsecured notes due 2015 to redeem 10,000 of the APL Class A preferred units. APL also agreed that it will redeem an additional 10,000 APL Class A Preferred Units for cash at the liquidation value on April 1, 2009. If Sunlight Capital does not exercise its conversion right on or before June 2, 2009, APL will redeem the then-remaining 10,000 APL Class A Preferred Units for cash or one-half for cash and one-half for APL common limited partner units on July 1, 2009.

Dividends previously paid and those to be paid on APL’s Class A Preferred Units and the premium paid upon their redemption, if any, will be recognized within minority interest in APL in our consolidated statements of operations. If converted to APL common units, the APL Class A preferred equity amount converted will be reclassified to common limited partners’ equity within minority interest in APL on our consolidated balance sheet.

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APL Class B Preferred Units

In December 2008, APL sold 10,000 newly-created Class B Preferred Units to us for cash consideration of $1,000 per APL Class B Preferred Unit (the “Face Value”). We have the right, before March 30, 2009, to purchase an additional 10,000 APL Class B Preferred Units on the same terms. 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, we 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 for the determination of holders entitled to receive distributions of the APL Class B Preferred Units will be the same as the record date for determination of common unit holders entitled to receive quarterly distributions. The APL Class B Preferred Units are convertible, at the holder’s option, into APL common units commencing on June 30, 2009 (the “APL Class B Preferred Unit Conversion Commencement Date”), provided that the holder must request conversion of at least 2,500 APL Class B Preferred Units and cannot make a conversion request more than once every 30 days. The conversion price will be the lesser of (a) $7.50 (subject to adjustment for customary events such as stock splits, reverse stock splits, stock distributions and spin-offs) and (b) 95% of the average closing price of APL common units for the 10 consecutive trading days immediately preceding the date of the holder’s notice to APL of its conversion election (the “Market Price”). The number of APL common units issuable is equal to the Face Value of the APL Class B Preferred Units being converted plus all accrued but unpaid distributions (the “APL Class B Preferred Unit Liquidation Value”), divided by the conversion price. Within 5 trading days of its receipt of a conversion notice, APL may elect to pay the notifying holder cash rather than issue its common units in satisfaction of the conversion request. If APL elects to pay cash for the APL Class B Preferred Units, the conversion price will be the lesser of (a) $7.50 and (b) 100% of the Market Price and the cash amount will be equal to (x) if Market Price is greater than $7.50, the number of common units issuable for the APL Class B Preferred Units being redeemed multiplied by the Market Price or (y) if the Market Price is less than or equal to $7.50, the APL Class B Preferred Unit Liquidation Value. APL has the right to redeem some or all of the APL Class B Preferred Units (but not less than 2,500 APL Class B Preferred Units) for an amount equal to the APL Class B Preferred Unit Liquidation Value being redeemed divided by the conversion price multiplied by $9.50.

The sale of the APL Class B Preferred Units to us was exempt from the registration requirements of the Securities Act of 1933. APL has agreed to file, upon demand, a registration statement to cover the resale of the common units underlying the APL Class B Preferred Units. We are entitled to receive the dividends on the APL Class B Preferred units pro rata from the December 2008 commencement date.

APL’s 10,000 outstanding Class B preferred limited partner units were convertible into approximately 1,754,386 APL common limited partner units at December 31, 2008, with an estimated fair value of approximately $10.5 million based upon the market value of our common units as of that date.

APL Term Loan and Credit Facility

At December 31, 2008, 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, 2008 was 3.7%, and the weighted average interest rate on the outstanding APL term loan borrowings at December 31, 2008 was 3.0%. Up to $50.0 million of APL’s credit facility may be utilized for letters of credit, of which $5.9 million was outstanding at December 31, 2008. 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 revolving credit facility and term loan 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 “—Recent Events”) in calculating its 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 credit facility with proceeds from its issuance of $250.0

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million of 10-year, 8.75% senior unsecured notes (see “—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.

Borrowings under the APL 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 by the guaranty of each of its 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 in compliance with these covenants as of December 31, 2008. Mandatory prepayments of the amounts borrowed under the term loan portion of the credit facility are required from the net cash proceeds of debt or equity issuances, and of dispositions of assets that exceed $50.0 million in the aggregate in any fiscal year that are not reinvested in replacement assets within 360 days. In connection with entering into the credit facility, APL agreed to remit an underwriting fee to the lead underwriting bank of 0.75% of the aggregate principal amount of the term loan outstanding on January 23, 2008. Since then, APL and the underwriting bank agreed to extend the agreement through January 30, 2009 and reduce the underwriting fee to 0.50% of the aggregate principal amount of the term loan outstanding as of that date.

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 agreements, adverse judgments against APL in excess of a specified amount, and a change of control of APL’s General Partner. APL’s credit facility requires us to maintain a ratio of funded debt (as defined in the credit facility) to Consolidated EBITDA (as defined in the credit facility) ratio of not more than 5.25 to 1.0, and an interest coverage ratio (as defined in the credit facility) of not less than 2.75 to 1.0. During a Specified Acquisition Period (as defined in the credit facility), for the first 2 full fiscal quarters subsequent to the closing of an acquisition with total consideration in excess of $75.0 million, the ratio of funded debt to EBITDA will be permitted to step up to 5.75 to 1.0. As of December 31, 2008, APL’s ratio of funded debt to EBITDA was 4.7 to 1.0 and its interest coverage ratio was 4.0 to 1.0.

APL is 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 Senior Notes

At December 31, 2008, 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 $260.5 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 $0.7 million of unamortized premium received as of December 31, 2008. The APL 8.75% Senior Notes were issued in June 2008 in a private placement transaction pursuant to Rule 144A and Regulation S under the Securities Act of 1933. 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.

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;

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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, 2008.

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 APL 8.75% Senior Notes registration rights agreement by the specified dates.

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 APL’s Senior Notes repurchased have been retired and are not available for re-issue.

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, and issuance of injunctions as to future compliance or other mandatory or consensual measures. APL has an ongoing environmental compliance program. However, risks of accidental leaks or spills are associated with the transportation 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 APL’s 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, 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 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. 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 its efforts will prevent material costs, if any, from arising.

Inflation and Changes in Prices

Inflation affects the operating expenses of our operations. In addition, inflationary trends may occur if commodity prices were to increase since such an increase may cause the demand in energy equipment and services to increase, thereby increasing the costs of acquiring or obtaining such equipment and services. Increases in those expenses are not necessarily offset by increases in revenues and fees that our operations are able to charge. While we anticipate that inflation will affect our future operating costs, we cannot predict the timing or amounts of any such effects.

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Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions 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.

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. APL evaluated all of its long-lived assets, including intangible customer relationships, at December 31, 2008, and determined that the undiscounted estimated future net cash flows related to these assets continued to support the recorded values.

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 principles of SFAS No. 142, 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. The principles of SFAS No. 142 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 ours, an acquiring entity typically is willing to pay more for equity

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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 judgmental 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 its 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. These estimates were subjective and based upon numerous assumptions about future operations and market conditions, which are subject to change. There were no goodwill impairments recognized by us during the years ended December 31, 2007 and 2006. See “—Goodwill” in Note 2 under Item 8, “Financial Statements and Supplementary Data” for information regarding APL’s impairment of goodwill and other assets.

Fair Value of Financial Instruments

We adopted the provisions of SFAS No. 157 at January 1, 2008. SFAS No. 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS No. 157 (1) creates a single definition of fair value, (2) establishes a hierarchy for measuring fair value, and (3) expands disclosure requirements about items measured at fair value. SFAS No. 157 does not change existing accounting rules governing what can or what must be recognized and reported at fair value in our financial statements, or disclosed at fair value in our notes to the financial statements. As a result, we will not be required to recognize any new assets or liabilities at fair value.

SFAS No. 157’s 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 outlined in SFAS No. 157 to value the assets and liabilities for its respective outstanding derivative contracts (see Note 11 under Item 8, “Financial Statements and Supplementary Data”). All of our and APL’s derivative contracts are defined as Level 2, with the exception of APL’s NGL fixed price swaps and crude oil 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 natural gas, crude oil, and propane prices, and therefore are defined as Level 3. Valuations for APL’s crude oil options (including those associated with NGL sales) are based on forward price curves developed by the related financial institution based upon current quoted prices for crude oil futures, and therefore are defined as Level 3.

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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, 2008. 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 who also participate in our and APL’s revolving credit facility. 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, 2008, we had a $50.0 million revolving credit facility with $46.0 million outstanding. The weighted average interest rate for these borrowings was 3.4% at December 31, 2008.

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 —”Our Credit Facility”), and will receive LIBOR, plus the applicable margin, on the notional principal amounts. This derivative effectively converts $25.0 million of our floating rate debt under the revolving credit facility to fixed-rate debt. The interest rate swap agreement began on May 30, 2008 and expires on May 28, 2010. Holding all other variables constant, a 100 basis-point, or 1%, change in interest rates would change our interest expense by $5.8 million.

At December 31, 2008, APL had a $380.0 million senior secured revolving credit facility ($302.0 million outstanding). APL also had $707.2 million outstanding under its senior secured term loan at December 31, 2008. The weighted average interest rate for APL’s revolving credit facility borrowings was 3.7% at December 31, 2008, and the weighted average interest rate for the term loan borrowings was 3.0% at December 31, 2008.

At December 31, 2008, 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 3.02%, 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. These derivatives effectively convert $450.0 million of APL’s floating rate debt under its term loan and revolving credit facility to fixed-rate debt. The APL interest rate swap agreements are effective as of December 31, 2008 and expire during periods ranging from January 30, 2010 through April 30, 2010.

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Holding all other variables constant, a 100 basis-point, or 1%, change in APL’s interest rates would change its annual interest expense by $5.6 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. A 10% change in the average price of NGLs, natural gas and condensate APL processes and sells, based on estimated unhedged market prices of $0.76 per gallon, $6.50 per mmbtu and $55.00 per barrel for NGLs, natural gas and condensate, respectively, would change our gross margin for the twelve-month period ending September 30, 2009, excluding the effect of minority interests in APL net income (loss), by approximately $25.3 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 is 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 purchase or sell natural gas, NGLs and condensate at a fixed price for the relevant contract period.

We and APL apply the provisions of SFAS No. 133 to our derivative instruments. We and APL formally document all relationships between hedging instruments and the items being hedged, including our risk management objective and strategy for undertaking the hedging transactions. This includes matching the derivative contracts to the forecasted transactions. Under SFAS No. 133, we and APL can assess, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, we and APL will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by us and APL through the utilization of market data, will be recognized within other income (loss) in our consolidated statements of operations. For APL’s derivatives previously qualifying as hedges, we recognized the effective portion of changes in fair value in partners’ capital (deficit) as accumulated other comprehensive income (loss), and reclassified the portion relating to commodity derivatives to natural gas and liquids revenue and the portion relating to interest rate derivatives to interest expense within our consolidated statements of operations as the underlying transactions were settled. For APL’s non-qualifying derivatives and for the ineffective portion of qualifying derivatives, we recognize changes in fair value within other income (loss) in our consolidated statements of operations as they occur.

On July 1, 2008, APL elected to discontinue hedge accounting for its existing commodity derivatives which were qualified as hedges under SFAS No. 133. 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, which was recognized in accumulated other comprehensive loss 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.

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During the year ended December 31, 2008, APL made net payments of $274.0 million 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 our NGL equity volume. Substantially all 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. During the years ended December 31, 2008, 2007 and 2006, we recognized the following derivative activity related to APL’s termination of these derivative instruments within our consolidated statement of operations (amounts in thousands):

	Early termination of derivative contracts for the Years Ended December 31,
	2008			2007		2006
Net cash derivative expense included within other income (loss), net	$	(199,964	)	$	—	$	—
Net cash derivative income included within natural gas and liquids revenue		2,322			—		—
Net non-cash derivative expense included within other income (loss), net		(39,218	)		—		—
Net non-cash derivative expense included within natural gas and liquids		(32,389	)		—		—

The following table summarizes our and APL’s derivative activity for the periods indicated (amounts in thousands):

	Years Ended December 31,
	2008			2007			2006
Loss from cash and non-cash settlement of qualifying hedge instruments(1)	$	(105,015	)	$	(49,393	)	$	(13,945	)
Gain (loss) from change in market value of non-qualifying derivatives(2)		140,144			(153,393	)		4,206
Loss from de-designation of cash flow derivatives(2)		—			(12,611	)		—
Gain (loss) from change in market value of ineffective portion of qualifying derivatives(2)		47,229			(3,450	)		1,520
Loss from cash and non-cash settlement of non-qualifying derivatives(2)		(250,853	)		(10,158	)		—
Loss from cash settlement of interest rate derivatives(3)		(1,289	)		—			—

(1) Included within natural gas and liquids revenue on our consolidated statements of operations.

(2) Included within other income (loss), net on our consolidated statements of operations.

(3) Included within interest expense on our consolidated statements of operations.

As of December 31, 2008, we had the following interest rate derivatives:

Interest Fixed-Rate Swap

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	2009	$	(551	)
				2010		(174	)
					$	(725	)

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⁽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, 2008, APL had the following interest rate and commodity derivatives, including derivatives that do not qualify for hedge accounting:

Interest Fixed-Rate Swap

Term	Notional Amount		Type	Contract Period Ended December 31,	Fair Value Liability(1)
					(in thousands)
January 2008-January 2010	$	200,000,000	Pay2.88%—Receive LIBOR	2009	$	(4,130	)
				2010		(249	)
					$	(4,379	)
April 2008-April 2010	$	250,000,000	Pay 3.14%—Receive LIBOR	2009	$	(5,835	)
				2010		(1,513	)
					$	(7,348	)

Natural Gas Liquids Sales – Fixed Price Swaps

Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Asset(2)
	(gallons)	(per gallon)		(in thousands)
2009	8,568,000	$	0.746	$	1,509

Crude Oil Sales Options (associated with NGL volume)

Production Period Ended December 31,	Crude Volume	Associated NGL Volume	Average Crude Strike Price		Fair Value Asset/ (Liability)(3)			Option Type
	(barrels)	(gallons)	(per barrel)		(in thousands)
2009	1,056,000	56,634,732	$	80.00	$	29,006		Puts purchased
2009	304,200	27,085,968	$	126.05		(22,774	)	Puts sold(4)
2009	304,200	27,085,968	$	143.00		44		Calls purchased(4)
2009	2,121,600	114,072,336	$	81.01		(1,080	)	Calls sold
2010	3,127,500	202,370,490	$	81.09		(17,740	)	Calls sold
2010	714,000	45,415,440	$	120.00		1,279		Calls purchased(4)
2011	606,000	32,578,560	$	95.56		(3,123	)	Calls sold
2011	252,000	13,547,520	$	120.00		646		Calls purchased(4)
2012	450,000	24,192,000	$	97.10		(2,733	)	Calls sold
2012	180,000	9,676,800	$	120.00		607		Calls purchased(4)
					$	(15,868	)

Natural Gas Sales – Fixed Price Swaps

Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Asset(3)
	(mmbtu)(5)	(per mmbtu)(5)		(in thousands)
2009	5,247,000	$	8.611	$	14,326
2010	4,560,000	$	8.526		6,461
2011	2,160,000	$	8.270		2,072
2012	1,560,000	$	8.250		1,596
				$	24,455

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Natural Gas Basis Sales

Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset/ (Liability)(3)
	(mmbtu)(5)	(per mmbtu)(5)			(in thousands)
2009	5,724,000	$	(0.558	)	$	(1,220	)
2010	4,560,000	$	(0.622	)		1,106
2011	2,160,000	$	(0.664	)		367
2012	1,560,000	$	(0.601	)		316
					$	569

Natural Gas Purchases – Fixed Price Swaps

Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability(3)
	(mmbtu)(5)	(per mmbtu)(5)		(in thousands)
2009	14,267,000	$	8.680	$	(36,734	)
2010	8,940,000	$	8.580		(13,403	)
2011	2,160,000	$	8.270		(2,072	)
2012	1,560,000	$	8.250		(1,596	)
				$	(53,805	)

Natural Gas Basis Purchases

Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Liability(3)
	(mmbtu)(5)	(per mmbtu)(5)			(in thousands)
2009	15,564,000	$	(0.654	)	$	(9,201	)
2010	8,940,000	$	(0.600	)		(3,720	)
2011	2,160,000	$	(0.700	)		(423	)
2012	1,560,000	$	(0.610	)		(383	)
					$	(13,727	)

Ethane Put Options

Production Period Ended December 31,	Associated NGL Volume	Average Crude Strike Price		Fair Value Asset(2)		Option Type
	(gallons)	(per gallon)		(in thousands)
2009	14,049,000	$	0.6948	$	3,234	Puts purchased

Propane Put Options

Production Period Ended December 31,	Associated NGL Volume	Average Crude Strike Price		Fair Value Asset(2)		Option Type
	(gallons)	(per gallon)		(in thousands)
2009	14,490,000	$	1.4154	$	9,083	Puts purchased

Isobutane Put Options

Production Period Ended December 31,	Associated NGL Volume	Average Crude Strike Price		Fair Value Liability(2)			Option Type
	(gallons)	(per gallon)		(in thousands)
2009	126,000	$	0.7500	$	(3	)	Puts purchased

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Normal Butane Put Options

Production Period Ended December 31,	Associated NGL Volume	Average Crude Strike Price		Fair Value Liability(2)			Option Type
	(gallons)	(per gallon)		(in thousands)
2009	113,400	$	0.7350	$	(3	)	Puts purchased

Natural Gasoline Put Options

Production Period Ended December 31,	Associated NGL Volume	Average Crude Strike Price		Fair Value Asset(2)		Option Type
	(gallons)	(per gallon)		(in thousands)
2009	126,000	$	0.9650	$	5	Puts purchased

Crude Oil Sales

Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Asset(3)
	(barrels)	(per barrel)		(in thousands)
2009	33,000	$	62.700	$	252

Crude Oil Sales Options

Production Period Ended December 31,	Volumes	Average Strike Price		Fair Value Asset/ (Liability)(3)			Option Type
	(barrels)	(per barrel)		(in thousands)
2009	105,000	$	90.000	$	3,635		Puts purchased
2009	306,000	$	80.017		(6,122	)	Calls sold
2010	234,000	$	83.027		(4,046	)	Calls sold
2011	72,000	$	87.296		(546	)	Calls sold
2012	48,000	$	83.944		(489	)	Calls sold
				$	(7,568	)
	Total net liability			$	(64,319	)

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

⁽²⁾ Fair value based upon APL management estimates, including forecasted forward NGL prices as a function of forward NYMEX natural gas, light crude and propane prices.

⁽³⁾ Fair value based on forward NYMEX natural gas and light crude prices, as applicable.

⁽⁴⁾ Puts sold and calls purchased for 2009 represent costless collars entered into by APL as offsetting positions for the calls sold related to ethane and propane production. In addition, calls were purchased by APL for 2010 through 2012 to offset 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.

⁽⁵⁾ Mmbtu represents million British Thermal Units.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unitholders

Atlas Pipeline 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, 2008 and 2007, and the related consolidated statements of operations, comprehensive income (loss), owners’ equity/partners’ capital, and cash flows for each of the three years in the period ended December 31, 2008. 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, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Atlas Pipeline Holdings, L.P.’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated February 27, 2009 expressed an unqualified opinion on the effectiveness of internal control over financial reporting.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

February 27, 2009

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ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31,
	2008			2007
ASSETS
Current assets:
Cash and cash equivalents	$	7,360		$	12,129
Accounts receivable – affiliates		341			2,839
Accounts receivable		112,365			147,360
Current portion of derivative asset		44,961			—
Prepaid expenses and other		11,999			14,755
Total current assets		177,026			177,083
Property, plant and equipment, net		2,022,937			1,748,661
Intangible assets, net		193,647			219,203
Goodwill		—			709,283
Minority interest		32,337			2,163
Other assets, net		25,374			21,121
	$	2,451,321		$	2,877,514
LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)
Current liabilities:
Current portion of long-term debt	$	—		$	34
Accounts payable		70,691			20,399
Accrued liabilities		21,754			43,658
Current portion of derivative liability		60,947			110,867
Accrued producer liabilities		67,406			80,829
Total current liabilities		220,798			255,787
Long-term derivative liability		48,333			118,646
Long-term debt, less current portion		1,539,427			1,254,392
Other long-term liability		574			—
Commitments and contingencies
Minority interest in Atlas Pipeline Partners, L.P.		663,440			1,154,571
Partners’ capital (deficit):
Common limited partners’ interests		(5,463	)		101,785
Accumulated other comprehensive loss		(15,788	)		(7,667	)
Total partners’ capital (deficit)		(21,251	)		94,118
	$	2,451,321		$	2,877,514

See accompanying notes to consolidated financial statements

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ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

	Years Ended December 31,
	2008			2007			2006
Revenue:
Natural gas and liquids	$	1,370,000		$	761,118		$	391,356
Transportation, compression and other fees – affiliates		43,293			33,169			30,189
Transportation, compression and other fees – third parties		56,416			48,616			30,735
Other income (loss), net		(55,502	)		(174,084	)		12,781
Total revenue and other income (loss), net		1,414,207			668,819			465,061
Costs and expenses:
Natural gas and liquids		1,086,142			587,524			334,299
Plant operating		60,835			34,667			15,722
Transportation and compression		17,886			13,484			10,753
General and administrative		2,496			58,622			21,155
Compensation reimbursement – affiliates		1,487			5,939			2,319
Depreciation and amortization		90,124			50,982			22,994
Interest		86,705			62,629			24,726
Goodwill and other asset impairment loss		698,508			—			—
Gain on early extinguishment of debt		(19,867	)		—			—
Minority interests		(22,781	)		3,940			118
Minority interest in Atlas Pipeline Partners, L.P.		(513,675	)		(133,321	)		16,335
Total costs and expenses		1,487,860			684,466			448,421
Net income (loss)	$	(73,653	)	$	(15,647	)	$	16,640
Allocation of net income (loss):
Portion applicable to owners’ interest (period prior to the initial public offering on July 26, 2006)	$	—		$	—		$	10,236
Portion applicable to common limited partners’ interest (period subsequent to the initial public offering on July 26, 2006)		(73,653	)		(15,647	)		6,404
Net income (loss)	$	(73,653	)	$	(15,647	)	$	16,640
Net income (loss) attributable to common limited partners per unit:
Basic	$	(2.68	)	$	(0.66	)	$	0.30
Diluted	$	(2.68	)	$	(0.66	)	$	0.30
Weighted average common limited partner units outstanding:
Basic		27,511			23,806			21,100
Diluted		27,511			23,806			21,102

See accompanying notes to consolidated financial statements

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ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

	Years Ended December 31,
	2008			2007			2006
Net income (loss)	$	(73,653	)	$	(15,647	)	$	16,640
Other comprehensive income (loss):
Change in fair value of derivative instruments accounted for as cash flow hedges		(98,223	)		(101,968	)		(5,956	)
Reclassification adjustment to earnings for de-designation of cash flow hedges		—			12,611			—
Changes in minority interest related to items in other comprehensive income (loss)		35,499			46,206			(9,014	)
Add: adjustment for realized losses reclassified to net income (loss)		54,603			49,393			13,945
Total other comprehensive income (loss)		(8,121	)		6,242			(1,025	)
Comprehensive income (loss)	$	(81,774	)	$	(9,405	)	$	15,615

See accompanying notes to consolidated financial statements

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ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OWNERS’ EQUITY (DEFICIT)/

PARTNERS’ CAPITAL (DEFICIT)

(in thousands, except unit data)

	Owners’ Equity			Common Limited Partners’ Capital				Accumulated Other Comprehensive Income (Loss)			Total Owners’ Equity (Deficit)/ Partners’ Capital (Deficit)
				Units	$
Balance at December 31, 2005	$	9,074		—	$	—		$	(12,884	)	$	(3,810	)
Capital contribution from owners		1,206		—		—			—			1,206
Distribution to owners prior to initial public offering on July 26, 2006		(15,596	)	—		—			—			(15,596	)
Net income attributable to owners prior to the initial public offering on July 26, 2006		10,236		—		—			—			10,236
Net assets contributed by owners to Atlas Pipeline Holdings, L.P		(4,920	)	17,500,000		4,920			—			—
Issuance of common limited partner units in an initial public offering		—		3,600,000		74,326			—			74,326
Distribution of initial public offering proceeds to owners		—		—		(74,147	)		—			(74,147	)
Distribution to owners subsequent to the initial public offering on July 26, 2006		—		—		(1,415	)		—			(1,415	)
Unissued common units under incentive plans		—		—		435			—			435
Distributions paid to common limited partners		—		—		(3,587	)		—			(3,587	)
Distribution equivalent rights paid on unissued units under incentive plans		—		—		(37	)		—			(37	)
Other comprehensive loss		—		—		—			(1,025	)		(1,025	)
Net income attributable to common limited partners		—		—		6,404			—			6,404
Balance at December 31, 2006	$	—		21,100,000	$	6,899		$	(13,909	)	$	(7,010	)
Issuance of common limited partner units		—		6,250,370		167,150			—			167,150
Unissued common units under incentive plans		—		—		2,660						2,660
Distributions paid to common limited partners		—		—		(24,788	)		—			(24,788	)
Distribution equivalent rights paid on unissued units under incentive plans		—		—		(238	)		—			(238	)
Net loss on purchase and sale of subsidiary equity		—		—		(34,251	)		—			(34,251	)
Other comprehensive gain		—		—		—			6,242			6,242
Net loss		—		—		(15,647	)		—			(15,647	)
Balance at December 31, 2007	$	—		27,350,370	$	101,785		$	(7,667	)	$	94,118
Issuance of common limited partner units		—		308,109		10,001			—			10,001
Unissued common units under incentive plans		—		—		2,665			—			2,665
Issuance of units under incentive plans		—		675		—			—			—
Distributions paid to common limited partners		—		—		(49,272	)		—			(49,272	)
Distribution equivalent rights paid on unissued units under incentive plans		—		—		(402	)		—			(402	)
Net loss on purchase and sale of subsidiary equity		—		—		3,413			—			3,413
Other comprehensive loss									(8,121	)		(8,121	)
Net loss		—		—		(73,653	)		—			(73,653	)
Balance at December 31, 2008	$	—		27,659,154	$	(5,463	)	$	(15,788	)	$	(21,251	)

See accompanying notes to consolidated financial statements

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ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2008			2007			2006
				(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(73,653	)	$	(15,647	)	$	16,640
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Minority interest in net income (loss) of Atlas Pipeline Partners, L.P.		(513,675	)		(133,321	)		16,335
Distributions paid to minority interest limited partners in Atlas Pipeline Partners, L.P.		(140,850	)		(59,850	)		(37,664	)
Depreciation and amortization		90,124			50,982			22,994
Goodwill and other asset impairment loss		698,508			—			—
Gain on early extinguishment of debt		(19,867	)		—			—
Non-cash loss (gain) on derivative value, net		(208,813	)		169,424			(2,316	)
Non-cash compensation expense (income)		(31,345	)		38,966			6,750
Amortization of deferred finance costs		6,070			7,489			2,342
Minority interests		(22,781	)		3,940			118
Net distributions paid to minority interest holders		(7,393	)		(6,103	)		—
Loss (gain) on asset sales and dispositions		—			805			(2,719	)
Gain on insurance claim settlement		—			—			(2,921	)
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable and prepaid expenses and other		34,515			(96,267	)		899
Accounts payable and accrued liabilities		(15,885	)		73,292			(10,134	)
Accounts payable and accounts receivable – affiliates		2,402			4,248			(2,792	)
Net cash provided by (used in) operating activities		(202,643	)		37,958			7,532
CASH FLOWS FROM INVESTING ACTIVITIES:
Net cash received (paid) for acquisitions		31,429			(1,884,458	)		(30,000	)
Capital expenditures		(325,934	)		(139,647	)		(83,716	)
Proceeds from insurance claim settlement		—			—			1,522
Proceeds from sales of assets		—			553			7,540
Other		1,535			(1,125	)		155
Net cash used in investing activities		(292,970	)		(2,024,677	)		(104,499	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from issuance of Atlas Pipeline Partners, L.P. debt		244,854			817,131			36,582
Repayment of Atlas Pipeline Partners, L.P. debt		(162,938	)		—			(39,019	)
Borrowings under credit facility		21,000			25,000			—
Borrowings under Atlas Pipeline Partners, L.P. credit facility		787,400			320,500			81,000
Repayments under Atlas Pipeline Partners, L.P. credit facility		(590,400	)		(253,500	)		(52,500	)
Net proceeds from issuance of common limited partner units		10,001			166,984			74,326
Net proceeds from issuance of Atlas Pipeline Partners, L.P. common limited partner units		246,915			946,399			19,704
Net proceeds from issuance of Atlas Pipeline Partners, L.P. Class A preferred limited partner units		—			—			39,881
Redemption of Atlas Pipeline Partners, L.P. Class A preferred limited partner units		(10,053	)		—			—
Capital contributions from owners		—			—			1,206
Distributions paid to common limited partners		(49,272	)		(24,788	)		(3,587	)
Distributions to owners		—			—			(91,158	)
Other		(6,663	)		(1,076	)		(1,507	)
Net cash provided by financing activities		490,844			1,996,650			64,928
Net change in cash and cash equivalents		(4,769	)		9,931			(32,039	)
Cash and cash equivalents, beginning of year		12,129			2,198			34,237
Cash and cash equivalents, end of year	$	7,360		$	12,129		$	2,198

See accompanying notes to consolidated financial statements

89

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). In July 2006, Atlas America, Inc. and its affiliates (“Atlas America”), a publicly-traded company (NASDAQ: ATLS), contributed its ownership interests in Atlas Pipeline Partners GP, LLC (“Atlas Pipeline GP” or the “General Partner”), its then wholly-owned subsidiary, a Delaware limited liability company and general partner of Atlas Pipeline Partners, L.P. (“APL”), to the Partnership. Concurrent with this transaction, the Partnership issued 3,600,000 million common units, representing a then-17.1% ownership interest, in an initial public offering at a price of $23.00 per unit (see Note 3). 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, 2008, the Partnership had 27,659,154 common limited partnership units outstanding.

APL is a publicly-traded (NYSE: APL) Delaware limited partnership and a midstream energy service provider engaged in the transmission, gathering and processing of natural gas in the Mid-Continent and Appalachian 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 also owns 5,754,253 common limited partner units in APL (see Note 4) and 10,000, $1,000 par value cumulative convertible preferred limited partner units in APL (see Note 5). At December 31, 2008, APL had 45,954,808 common limited partnership units outstanding, including the 5,754,253 common units held by the Partnership, and 40,000 $1,000 par value cumulative convertible preferred limited partnership units outstanding, including 10,000 cumulative convertible preferred units held by the Partnership (see Note 5).

The Partnership’s assets consist principally of 100% ownership interest in Atlas Pipeline GP, which owns:

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

• 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. In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see Note 9), 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;

• 5,754,253 common units of APL, representing approximately 12.5% of the 45,954,808 outstanding common limited partnership units of APL, and

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• 10,000 $1,000 par value 12.0% cumulative convertible preferred limited partner units at December 31, 2008 representing an approximate 3.2% ownership interest in APL based upon the market value of APL’s common units at December 31, 2008.

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 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 America, Inc. and its affiliates (“Atlas America”), a publicly-traded company (NASDAQ: ATLS), owns 100% of Atlas Pipeline Holdings GP, the general partner of the Partnership, and a 64.4% ownership interest in the Partnership at December 31, 2008. In addition to its ownership interest in the Partnership, Atlas America also owns 1,112,000 of APL’s common limited partnership units, representing a 2.1% ownership interest in it, and a 48.3% ownership interest in Atlas Energy Resources, LLC and subsidiaries (“Atlas Energy”), a publicly-traded company (NYSE: ATN). Substantially all of the natural gas APL transports in the Appalachian basin is derived from wells operated by Atlas Energy.

Certain amounts in the prior years’ consolidated financial statements have been reclassified to conform to the current year presentation. 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 the 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, the Partnership’s reported net income would have been reduced by approximately 1.1%, 3.4% and 0.5% for the third quarter of 2005, fourth quarter of 2005 and first quarter of 2006, respectively.

In August 2006, APL sustained fire damage to a compressor station within the Velma region of its Mid-Continent segment. APL maintains property damage and business interruption insurance for all of its assets and operating activities. During the fourth quarter of 2006, APL received a $1.5 million partial settlement from its insurance providers related to this incident and reached a final settlement for an additional $2.6 million of insurance proceeds to be received during the first quarter of 2007. At December 31, 2006, APL recorded the additional $2.6 million in prepaid expenses and other within the Partnership’s consolidated balance sheet and other income (loss), net within its consolidated statements of operations for the insurance proceeds settlement amount.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Minority Interest

The consolidated financial statements subsequent to the Partnership’s initial public offering on July 26, 2006 (see Note 3) include the accounts of the Partnership, the General Partner, APL, the Operating Partnership and the Operating Partnership’s subsidiaries. Prior to the Partnership’s initial public offering, at which date Atlas America contributed its ownership interests in the General Partner to the Partnership, the consolidated financial statements only include the accounts of the General Partner, APL, the Operating Partnership and the Operating Partnership’s subsidiaries. All material intercompany transactions have been eliminated. The contribution of Atlas America’s investment in the General Partner to the Partnership was recorded by the Partnership at Atlas America’s historical cost basis of $4.9 million at the date of the transaction. APL’s limited partner equity interests owned by third-parties at December 31, 2008 and 2007 are reflected as minority interest in APL on the Partnership’s consolidated balance sheets.

91

The consolidated financial statements also include the operations of APL’s Chaney Dell natural gas gathering system and processing plants located in Oklahoma (“Chaney Dell system”) and APL’s Midkiff/Benedum natural gas gathering system and processing plants located in Texas (“Midkiff/Benedum system”). In July 2007, APL acquired control of Anadarko Petroleum Corporation’s (NYSE: APC) (“Anadarko”) 100% interest in the Chaney Dell system and its 72.8% undivided joint venture interest in the Midkiff/Benedum system (see Note 9). The transaction was effected by the formation of two joint venture companies which own the respective systems, of which APL has a 95% interest and Anadarko has a 5% interest in each. APL consolidates 100% of these joint ventures. The Partnership reflects Anadarko’s 5% interest in the net income of these joint ventures as minority interest on its statements of operations. The Partnership also reflects Anadarko’s investment in the net assets of the joint ventures as minority interest on its consolidated balance sheet. In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems, the joint ventures issued cash to Anadarko of $1.9 billion in return for a note receivable. This note receivable is reflected within minority interest on the Partnership’s consolidated balance sheet.

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”). Due to the Midkiff/Benedum system’s status as an undivided joint venture, 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.

The consolidated financial statements also include the financial statements of NOARK Pipeline System, Limited Partnership (“NOARK”), an entity in which APL currently owns a 100% ownership interest (see Note 9). On May 2, 2006, APL acquired the remaining 25% ownership interest in NOARK from Southwestern Energy Pipeline Company (“Southwestern”), a wholly-owned subsidiary of Southwestern Energy Company (NYSE: SWN). Prior to this transaction, APL owned a 75% ownership interest in NOARK, which it had acquired in October 2005 from Enogex, Inc., a wholly-owned subsidiary of OGE Energy Corp. (NYSE: OGE). In connection with APL’s acquisition of the remaining 25% ownership interest, Southwestern assumed liability for $39.0 million in principal amount outstanding of NOARK’s 7.15% notes due in 2018, which had been presented as long-term debt on the Partnership’s consolidated balance sheet prior to APL’s acquisition of the remaining 25% ownership interest. Subsequent to the acquisition of the remaining 25% ownership interest in NOARK, APL consolidates 100% of NOARK’s financial statements. The minority interest expense reflected on the Partnership’s consolidated statements of operations for the year ended December 31, 2006 represents Southwestern’s interest in NOARK’s net income prior to the May 2, 2006 acquisition.

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 depreciation and amortization, asset impairment, the fair value of our 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.

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.

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Receivables

The amounts included within Accounts Receivable on the Partnership’s consolidated balance sheet at December 31, 2008 and 2007 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, 2008 and 2007, 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. 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. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized.

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. APL evaluated all of its long-lived assets, including intangible customer relationships, at December 31, 2008, and determined that the undiscounted estimated future net cash flows related to these assets continued to support the recorded values.

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 6.3%, 8.0% and 8.1% for the years ended December 31, 2008, 2007 and 2006, respectively, and the amount of interest capitalized was $8.9 million, $3.3 million and $2.6 million for the years ended December 31, 2008, 2007 and 2006, respectively.

Fair Value of Financial Instruments

For the Partnership’s cash and cash equivalents, accounts receivables and accounts payables, the carrying amounts of these financial instruments approximate fair values because of their short maturities and are represented in the Partnership’s consolidated balance sheets. For further information with regard to the Partnership’s financial instruments, see “—Recently Adopted Accounting Standards” and Note 11.

Derivative Instruments

APL enters into certain financial contracts to manage its exposure to movement in commodity prices and interest rates. APL applies the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”) to its derivative instruments. SFAS No. 133 requires each derivative instrument to be recorded 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 unless specific hedge accounting criteria are met.

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Intangible Assets

APL has recorded intangible assets with finite lives in connection with certain consummated acquisitions (see Note 9). The following table reflects the components of intangible assets being amortized at December 31, 2008 and 2007 (in thousands):

	December 31,						Estimated Useful Lives In Years
	2008			2007
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	$	(5,806	)	$	(4,215	)
Customer relationships		(35,929	)		(11,964	)
	$	(41,735	)	$	(16,179	)
Net Carrying Amount:
Customer contracts	$	7,004		$	8,595
Customer relationships		186,643			210,608
	$	193,647		$	219,203

APL recorded its initial purchase price allocation for the Chaney Dell and Midkiff/Benedum acquisition on July 27, 2007. During the fourth quarter of 2007, APL adjusted its preliminary purchase price allocation by increasing the estimated amount allocated to customer contracts and customer relationships and reducing amounts initially allocated to property, plant and equipment (see Note 7 and Note 8).

SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”) requires that intangible assets with finite useful lives be amortized 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 and residual values 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 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. Amortization expense on intangible assets was $25.6 million, $12.1 million and $2.0 million for the years ended December 31, 2008, 2007 and 2006, respectively. Amortization expense related to APL’s intangible assets is estimated to be as follows for each of the next five calendar years: 2009 - $25.6 million; 2010 - $25.6 million; 2011 - $25.6 million; 2012 - $25.6 million; 2013 - $24.5 million.

Goodwill

The changes in the carrying amount of goodwill for the years ended December 31, 2008, 2007 and 2006 were as follows (in thousands):

	Years Ended December 31,
	2008			2007		2006
Balance, beginning of year	$	709,283		$	63,441	$	111,446
Goodwill acquired (preliminary allocation) – remaining 25% interest in NOARK acquisition		—			—		30,195
Reduction in minority interest deficit acquired		—			—		(118	)
Purchase price allocation adjustment – NOARK		—			—		(78,082	)
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	$	63,441

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APL tests its goodwill for impairment at each year end under the principles of SFAS No. 142 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 SFAS No. 142 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 judgmental and is based on observed acquisitions in the Partnership’s industry. The resultant fair values calculated for the reporting units are then compared to observable metrics on large mergers and acquisitions in the Partnership’s industry to determine whether those valuations appear reasonable in management’s judgment.

As a result of its impairment evaluation at December 31, 2008, the Partnership recognized a $676.9 million non-cash impairment charge within its 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 its reporting units in comparison to their carrying amounts at December 31, 2008. APL’s estimated fair value of its reporting units was impacted by many factors, including the significant deterioration of commodity prices and global economic conditions during the fourth quarter of 2008. These estimates were subjective and based upon numerous assumptions about future operations and market conditions, which are subject to change. There were no goodwill impairments recognized by the Partnership during the years ended December 31, 2007 and 2006.

APL has 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 8).

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

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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 Financial Accounting Standards Board’s (“FASB”) FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes”, an Interpretation of FASB Statement No. 109 requires the evaluation of 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 as part of its income tax expense, when and if they become applicable.

The Partnership files income tax returns in the U.S. federal and various state jurisdictions. With limited exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2006.

Stock-Based Compensation

The Partnership and APL applies the provisions of SFAS No. 123(R), “Share-Based Payment,” as revised (“SFAS No. 123(R)”) to its share-based payments. Generally, the approach to accounting for share-based payments in SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values.

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 by the weighted average number of common limited partner units outstanding during the period. Diluted net income (loss) per common unit is calculated by dividing net income (loss) attributable to common limited partners by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of phantom unit or unit option awards, as calculated by the treasury stock method. Phantom units and unit options consist of common units issuable under the terms of the Partnership’s long-term incentive plan (see Note 15). Prior to the closing of the Partnership’s initial public offering on July 26, 2006, there were no common limited partner units outstanding. 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) per common unit with those used to compute diluted net income (loss) per common unit (in thousands):

	Years Ended December 31,
	2008	2007	2006(2)
Weighted average number of common limited partner units – basic	27,511	23,806	21,100
Add: effect of dilutive unit incentive awards(1)	—	—	2
Weighted average number of common limited partner units – diluted	27,511	23,806	21,102

⁽¹⁾ For the years ended December 31, 2008 and 2007, approximately 438,000 and 357,000 phantom units, respectively, were excluded from the computation of diluted net income (loss) per unit because the inclusion of such units would have been anti-dilutive.

⁽²⁾ Represents the period from July 26, 2006, the date of the Partnership’s initial public offering, through December 31, 2006.

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Minority Interest in Atlas Pipeline Partners, L.P.

The minority interest in APL on the Partnership’s consolidated financial statements reflect the outside ownership interests in APL, which was 84.1% and 84.5% at December 31, 2008 and 2007, respectively. The minority 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 6), 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 minority interest in APL liability on the Partnership’s consolidated balance sheets principally reflects the sum of the allocation of APL consolidated net income (loss) to the minority interest in APL and the contributed capital of minority interests through the sale of limited partner units in APL, partially offset by APL quarterly cash distributions to the minority interest owners.

APL’s preferred units are reflected on the Partnership’s consolidated balance sheet as minority interest in APL of $27.9 million and $37.1 million at December 31, 2008 and 2007, respectively.

During the year ended December 31, 2008, APL issued 56,227 common limited partner units under its Long-Term Incentive Plan (see Note 15). 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 4). 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 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 minority 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. During July 2007, the Partnership purchased 3,835,227, or 15.0%, of the 25,568,175 APL common limited partner units sold by APL (see Note 4), which increased the Partnership’s aggregate ownership percentage in APL to 15.9% from 14.3%. The increase in ownership percentage resulted in a $34.3 million reduction to the Partnership’s limited partners’ capital with a corresponding increase to minority interest in APL on its consolidated balance sheet.

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. APL accounts for environmental contingencies in accordance with SFAS No. 5, “Accounting for Contingencies.” 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. APL maintains insurance which may cover in whole or in part certain environmental expenditures. At December 31, 2008 and 2007, the Partnership and APL had no environmental matters requiring specific disclosure or requiring the recognition of a liability.

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Segment Information

The Partnership’s assets primarily consist of its ownership interests in APL. APL has two reportable segments: natural gas transmission, gathering and processing located in the Appalachia Basin area (“Appalachia”) of eastern Ohio, western New York, western Pennsylvania and northeastern Tennessee, and transmission, gathering and processing located in the Mid-Continent area (“Mid-Continent”) of primarily Oklahoma, northern and western Texas, the Texas Panhandle, Arkansas, southern Kansas and southeastern Missouri. Appalachia revenues are principally based on contractual arrangements with Atlas Energy and its affiliates. Mid-Continent revenues are derived from the gathering and transportation of natural gas and the sale of residue gas and NGLs to purchasers at the tailgate of the processing plants.

Revenue Recognition

Revenue in APL’s Appalachia segment is principally recognized at the time the natural gas is transported through the gathering systems. Under the terms of APL’s natural gas gathering agreements with Atlas Energy and its affiliates, APL receives fees for gathering natural gas from wells owned by Atlas Energy and by drilling investment partnerships sponsored by Atlas Energy. The fees received for the gathering services under the Atlas Energy agreements are generally the greater of 16% of the gross sales price for natural gas produced from the wells, or $0.35 to $0.40 per thousand cubic feet (“mcf”), depending on the ownership of the well. Substantially all natural gas gathering revenue in the Appalachia segment is derived from these agreements. Fees for transportation services provided to independent third parties whose wells are connected to APL’s Appalachia gathering systems are at separately negotiated prices.

APL’s Mid-Continent segment revenue primarily consists of the fees earned from its transmission, 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 transports natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with APL’s FERC-regulated transmission pipeline is comprised of firm transportation rates, and to the extent capacity is available following the reservation of firm system capacity, interruptible transportation rates and is recognized at the time transportation service is provided. 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:

Fee-Based Contracts. These contracts provide for a set fee for gathering and 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.

POP Contracts. These contracts provide for APL to retain a negotiated percentage of the sale proceeds from residue natural gas and NGLs it gathers and processes, with the remainder being remitted to the producer. In this situation, APL and the producer are directly dependent on the volume of the commodity and its value; APL owns a percentage of that commodity and is directly subject to its market value.

Keep-Whole Contracts. These contracts require APL, as the processor, to purchase raw natural gas from the producer at current market rates. Therefore, APL bears the economic risk (the “processing margin risk”) that the aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the amount that it paid for the unprocessed natural gas. However, because the natural gas purchases contracted under keep-whole agreements are generally low in liquids content and meet downstream pipeline specifications without being processed, the natural gas can be bypassed around the processing plants and delivered directly into downstream pipelines during periods of margin risk. Therefore, the processing margin risk associated with a portion of APL’s keep-whole contracts is minimized.

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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 transportation 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, 2008 and 2007 of $54.8 million and $86.8 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)” 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 10).

Recently Adopted Accounting Standards

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS No. 162”). SFAS No. 162 identifies sources of accounting principles and the framework for selecting such principles used in the preparation of financial statements of nongovernmental entities presented in conformity with U.S. generally accepted accounting principles. SFAS No. 162 is effective beginning November 15, 2008. The Partnership adopted the provisions of SFAS No. 162 on November 15, 2008, and it had no impact on its financial position and results of operations.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—including an amendment to FASB Statement No. 115” (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure eligible financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 is effective at the inception of an entity’s first fiscal year beginning after November 15, 2007 and offers various options in electing to apply its provisions. The Partnership adopted SFAS No. 159 on January 1, 2008, and has elected not to apply the fair value option to any of its financial instruments.

In December 2006, the FASB issued FASB Staff Position EITF 00-19-2, “Accounting for Registration Payment Arrangements” (“EITF 00-19-2”). EITF 00-19-2 provides guidance related to the accounting for registration payment arrangements and specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate arrangement or included as a provision of a financial instrument or arrangement, should be separately recognized and measured in accordance with SFAS No. 5, “Accounting for Contingencies” (“SFAS No. 5”). EITF 00-19-2 requires that if the transfer of consideration under a registration payment arrangement is probable and can be reasonably estimated at inception, the contingent liability under such arrangement shall be included in the allocation of proceeds from the related financing transaction using the measurement guidance in SFAS No. 5. The Partnership adopted EITF 00-19-2 on January 1, 2007 and it did not have an effect on the Partnership’s financial position or results of operations.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles and expands disclosures about fair value statements. In February 2008, the FASB issued FASB Staff Position SFAS No. 157-b, “Effective Date of FASB Statement No. 157”, which provides for a one-year deferral of the effective date of SFAS No. 157 with regard to an entity’s non-financial assets, non-financial liabilities or any non-recurring fair value measurement. SFAS No. 157 is effective for

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fiscal years beginning after November 15, 2007. The Partnership adopted SFAS No. 157 on January 1, 2008 with respect to APL’s derivative instruments, which are measured at fair value within its financial statements. The provisions of SFAS No. 157 have not been applied to its non-financial assets and non-financial liabilities. See Note 11 for disclosures pertaining to the provisions of SFAS No. 157 with regard to the APL’s financial instruments.

In September 2006, the Securities and Exchange Commission staff issued Staff Accounting Bulletin No. 108, Topic 1N, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108, Topic 1N”). SAB 108, Topic 1N provides guidance on quantifying and evaluating the materiality of unrecorded misstatements. The SEC staff recommends that misstatements should be quantified using both a balance sheet and income statement approach and a determination be made as to whether either approach results in quantifying a misstatement which the registrant, after evaluating all relevant factors, considers material. The SEC staff will not object if a registrant records a one-time cumulative effect adjustment to correct misstatements occurring in prior years that previously had been considered immaterial based on the appropriate use of the registrant’s methodology. SAB 108, Topic 1N is effective for fiscal years ending on or after November 15, 2006. The Partnership adopted the provisions of SAB 108, Topic 1N on January 1, 2007 and it did not have an impact on the Partnership’s consolidated financial position or results of operations for the years ended December 31, 2007 and 2006.

Recently Issued Accounting Standards

In June 2008, the FASB issued Staff Position No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”). FSP EITF 03-6-1 applies to the calculation of earnings per share (“EPS”) described in paragraphs 60 and 61 of FASB Statement No. 128, “Earnings per Share” for share-based payment awards with rights to dividends or dividend equivalents. It states that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of EPS pursuant to the two-class method. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption is prohibited. All prior-period EPS data presented shall be adjusted retrospectively to conform to the provisions of this FSP. The Partnership will apply the requirements of FSP EITF 03-6-1 upon its adoption on January 1, 2009 and it currently does not expect the adoption of FSP EITF 03-6-1 to have a material impact on its financial position and results of operations.

In April 2008, the FASB issued Staff Position No. 142-3, “Determination of Useful Life of Intangible Assets” (“FSP FAS 142-3”). FSP FAS 142-3 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 FASB Statement No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No 141(R), “Business Combinations” (“SFAS No. 141(R)”), and other U.S. Generally Accepted Accounting Principles. FSP FAS 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption is prohibited. The guidance for determining the useful life of a recognized intangible asset should be applied prospectively to intangible assets acquired after the effective date. The disclosure requirements should be applied prospectively to all intangible assets recognized as of, and subsequent to, the effective date. The Partnership will apply the requirements of FSP FAS 142-3 upon its adoption on January 1, 2009 and it currently does not expect the adoption of FSP FAS 142-3 to have a material impact on its financial position and results of operations.

In March 2008, the FASB ratified the EITF consensus on EITF Issue No. 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships” (“EITF No. 07-4”), an update of EITF No. 03-6, “Participating Securities and the Two-Class Method Under FASB Statement No. 128” (“EITF No. 03-6”). EITF 07-4 considers whether the incentive distributions of a

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master limited partnership represent a participating security when considered in the calculation of earnings per unit under the two-class method. EITF 07-4 also 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. EITF No. 07-4 is effective for fiscal years beginning after December 15, 2008, including interim periods within those fiscal years, and requires retrospective application of the guidance to all periods presented. Early adoption is prohibited. The Partnership will apply the requirements of EITF No. 07-4 upon its adoption on January 1, 2009 and does not expect it to have a material impact on its financial position or results of operations.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133” (“SFAS No. 161”). SFAS No. 161 amends the requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”), to require enhanced disclosure about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008, with early adoption encouraged. The Partnership will apply the requirements of SFAS No. 161 upon its adoption on January 1, 2009 and does not expect it to have a material impact on its financial position or results of operations or related disclosures.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 amends ARB No. 51 to establish accounting and reporting standards for the noncontrolling interest (minority interest) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 also requires consolidated net income to be reported, and disclosed on the face of the consolidated statement of operations, at amounts that include the amounts attributable to both the parent and the noncontrolling interest. Additionally, SFAS No. 160 establishes a single method for 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. SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008. The Partnership will apply the requirements of SFAS No. 160 upon its adoption on January 1, 2009 and does not expect it to have a material impact on its financial position and results of operations.

In December 2007, the FASB issued SFAS No 141(R), “Business Combinations” (“SFAS No. 141(R)”). SFAS No. 141(R) replaces SFAS No. 141, “Business Combinations” (“SFAS No. 141”), however 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. SFAS No. 141(R) requires an acquirer to recognize the assets acquired, liabilities assumed, and any noncontrolling interest in the acquiree at the acquisition date, at their fair values as of that date, with specified limited exceptions. Changes subsequent to that date are to be recognized in earnings, not goodwill. Additionally, SFAS No. 141 (R) 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 noncontrolling interests in the acquiree, at the full amounts of their fair values. SFAS No. 141(R) is effective for business combinations occurring in fiscal years beginning on or after December 15, 2008. The Partnership will apply the requirements of SFAS No. 141(R) upon its adoption on January 1, 2009 and does not expect it to have a material impact on its financial position and results of operations.

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NOTE 3 – ATLAS PIPELINE HOLDINGS COMMON UNIT EQUITY OFFERINGS

In June 2008, the Partnership sold 308,109 common units through a private placement to Atlas America 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 4), which in turn utilized the proceeds to partially fund the early termination of certain derivative agreements (see Note 10). Following the Partnership’s private placement, Atlas America 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 4), which in turn utilized the net proceeds to partially fund the acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see Note 9). The common units issued were subsequently registered with the Securities and Exchange Commission in November 2007.

In July 2006, Atlas America contributed its ownership interests in Atlas Pipeline GP, its then wholly-owned subsidiary and APL’s general partner, to the Partnership. Concurrent with this transaction, the Partnership issued 3,600,000 common units, representing a then-17.1% ownership interest, in an initial public offering at a price of $23.00 per unit for total gross proceeds of $82.8 million. Substantially all of the net proceeds of $74.5 million from this offering, after underwriting commissions and other transaction costs, were distributed to Atlas America.

NOTE 4 – APL COMMON UNIT EQUITY OFFERINGS

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 America 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 10).

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.

In May 2006, APL sold 500,000 common units in a public offering at a price of $41.20 per unit, yielding net proceeds of approximately $19.7 million, after underwriting commissions and other transaction costs. APL utilized the net proceeds from the sale to partially repay borrowings under its credit facility made in connection with APL’s acquisition of the remaining 25% ownership interest in NOARK.

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NOTE 5 – APL PREFERRED UNIT EQUITY OFFERINGS

APL Class A Preferred Units

In March 2006, APL entered into an agreement to sell 30,000 6.5% cumulative convertible preferred units (“APL Class A Preferred Units”) representing limited partner interests to Sunlight Capital Partners, LLC (“Sunlight Capital”), an affiliate of Elliott & Associates, for aggregate gross proceeds of $30.0 million. APL also sold an additional 10,000 APL Class A Preferred Units to Sunlight Capital for $10.0 million in May 2006, pursuant to APL’s right under the agreement to require Sunlight Capital to purchase such additional units. The APL Class A Preferred Units were originally entitled to receive dividends of 6.5% per annum commencing in March 2007 and were to have been accrued and paid quarterly on the same date as the distribution payment date for APL’s common units. In April 2007, APL and Sunlight Capital agreed to amend the terms of the APL Class A Preferred Units effective as of that date. The terms of the APL Class A Preferred Units were amended to entitle them to receive dividends of 6.5% per annum commencing in March 2008 and to be convertible, at Sunlight Capital’s option, into APL 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 may elect to pay cash rather than issue its common units in satisfaction of a conversion request.

APL has 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 will automatically be converted into APL 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. The Partnership recorded the senior unsecured notes issued as long-term debt and a preferred unit dividend within minority interest in APL on the Partnership’s consolidated balance sheet and, during the year ended December 31, 2007, reduced minority interest in APL by $3.8 million of this amount, which was the portion deemed to be attributable to the concessions of APL’s 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 (See Note 19, “Subsequent Event”). The redemption was classified as a reduction of minority 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.

APL’s Class A Preferred Units are reflected on the Partnership’s consolidated balance sheet as minority interest in APL. Minority interest in APL on the Partnership’s consolidated balance sheet at December 31, 2008 and 2007 was $27.9 million and $37.1 million, respectively. In accordance with Securities and Exchange Commission Staff Accounting Bulletin No. 68, “Increasing Rate Preferred Stock,” APL’s Class A Preferred Units were originally recorded on the consolidated balance sheet at the amount of net proceeds received less an imputed dividend cost. The imputed dividend cost of $2.4 million was the result of APL’s Class A Preferred Units not having a dividend yield during the first year after their issuance in March 2006 and was amortized in full as of March 2007. As a result of the amended agreement, APL recognized an imputed dividend cost of $2.5 million that was amortized during the year commencing March 2007 and was based upon the present value of the net proceeds received using the 6.5% stated yield. During the year ending December 31, 2008, APL amortized the remaining $0.5 million of this imputed dividend cost, which is presented within minority interest in APL in the Partnership’s consolidated statements of operations. APL’s amortization of the imputed dividend cost was $2.5 million the year ended December 31, 2007, based on the imputed cost during the year commencing March 2007. APL’s amortization of the imputed dividend cost was $1.9 million for the year ended December 31, 2006, based on the $2.4 million imputed cost during the initial year after the unit issuance.

Sunlight Capital was entitled to receive the dividends on the APL Class A Preferred Units pro rata from the March 2008 commencement date. APL recognized $1.8 million of preferred dividend cost for the year

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ended December 31, 2008, which is presented within minority interest in APL in the Partnership’s consolidated statements of operations. The preferred dividend cost recognized by APL for the respective periods is associated with the preferred dividends earned during those periods and paid on the scheduled date of APL’s quarterly cash distribution for the respective period (see Note 6). The $0.5 million of preferred unit dividend cost recognized for the three months ended December 31, 2008 is based upon the preferred unit dividend to be paid by APL on February 13, 2009.

The net proceeds from APL’s initial issuance of the Class A Preferred Units were used to fund a portion of its capital expenditures in 2006, including the construction of its Sweetwater gas plant and related gathering system. The proceeds from APL’s issuance of the additional 10,000 preferred units were used to reduce indebtedness under its Partnership’s credit facility incurred in connection with the acquisition of the remaining 25% ownership interest in NOARK.

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 the Partnership for cash consideration of $1,000 per APL Class B Preferred Unit (the “Face Value”) pursuant to a purchase agreement (the “APL Class B Preferred Unit Purchase Agreement”). The Partnership has the right, before March 30, 2009, to purchase an additional 10,000 APL Class B Preferred Units on the same terms. APL used the proceeds from the sale of the APL 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 for the determination of holders entitled to receive distributions of the APL Class B Preferred Units will be the same as the record date for determination of APL common unit holders entitled to receive quarterly distributions. The APL Class B Preferred Units are convertible, at the holder’s option, into APL common units commencing on June 30, 2009 (the “APL Class B Preferred Unit Conversion Commencement Date”), provided that the holder must request conversion of at least 2,500 APL Class B Preferred Units and cannot make a conversion request more than once every 30 days. The conversion price will be the lesser of (a) $7.50 (subject to adjustment for customary events such as stock splits, reverse stock splits, stock distributions and spin-offs) and (b) 95% of the average closing price of APL common units for the 10 consecutive trading days immediately preceding the date of the holder’s notice to APL of its conversion election (the “Market Price”). The number of APL common units issuable is equal to the Face Value of the APL Class B Preferred Units being converted plus all accrued but unpaid distributions (the “APL Class B Preferred Unit Liquidation Value”), divided by the conversion price. Within 5 trading days of its receipt of a conversion notice, APL may elect to pay the notifying holder cash rather than issue its common units in satisfaction of the conversion request. If APL elects to pay cash for the APL Class B Preferred Units, the conversion price will be the lesser of (a) $7.50 and (b) 100% of the Market Price and the cash amount will be equal to (x) if Market Price is greater than $7.50, the number of common units issuable for the APL Class B Preferred Units being redeemed multiplied by the Market Price or (y) if the Market Price is less than or equal to $7.50, the APL Class B Preferred Unit Liquidation Value. APL has the right to redeem some or all of the APL Class B Preferred Units (but not less than 2,500 APL Class B Preferred Units) for an amount equal to the APL Class B Preferred Unit Liquidation Value being redeemed divided by the conversion price multiplied by $9.50.

The sale of the APL Class B Preferred Units to the Partnership is exempt from the registration requirements of the Securities Act of 1933. APL has agreed pursuant to a registration rights agreement entered into simultaneously with the APL Class B Preferred Unit Purchase Agreement to file, upon demand, a registration statement to cover the resale of the common units underlying the APL Class B Preferred Units. The Partnership is entitled to receive the dividends on the APL Class B Preferred Units pro rata from the December 2008 commencement date.

APL’s 10,000 outstanding Class B Preferred Units were convertible into approximately 1,754,386 APL common limited partner units at December 31, 2008, which is based upon the market value of APL common units and subject to provisions and limitations within the agreement between the parties, with an estimated fair value of approximately $10.5 million based upon the market value of APL common units as of that date.

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NOTE 6 – CASH DISTRIBUTIONS

Atlas Pipeline Holdings Cash Distributions

Upon completion of its initial public offering, the Partnership adopted 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 July 26, 2006, the date of the Partnership’s initial public offering, through December 31, 2007 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)
November 19, 2006	September 30, 2006	$	0.17	(1)	$	3,587
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

⁽¹⁾ Represents a pro-rated cash distribution of $0.24 per common unit for the period from July 26, 2006, the date of the Partnership’s initial public offering, through September 30, 2006.

On January 26, 2009, the Partnership declared a cash distribution of $0.06 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2008. The $1.7 million distribution was paid on February 19, 2009 to unitholders of record at the close of business on February 9, 2009.

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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. Distributions declared by APL for the period from January 1, 2006 through December 31, 2008 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, 2006	December 31, 2005	$	0.83	$	10,416	$	3,638
May 15, 2006	March 31, 2006	$	0.84	$	10,541	$	3,766
August 14, 2006	June 30, 2006	$	0.85	$	11,118	$	4,059
November 14, 2006	September 30, 2006	$	0.85	$	11,118	$	4,059
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

In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see Note 9), the Partnership, which holds all of 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. The Partnership also agreed that the resulting allocation of incentive distribution rights back to APL would be after the Partnership 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.

On January 26, 2009, APL declared a cash distribution of $0.38 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2008. The $17.8 million distribution, including $0.4 million to the Partnership for its general partner interest, was paid on February 13, 2009 to unitholders of record at the close of business on February 9, 2009.

NOTE 7 – PROPERTY, PLANT AND EQUIPMENT

The following is a summary of property, plant and equipment (in thousands):

	December 31, 2008			December 31, 2007			Estimated Useful Lives in Years
Pipelines, processing and compression facilities	$	1,959,379		$	1,633,454		15 – 40
Rights of way		178,114			168,359		20 – 40
Buildings		8,968			8,919		40
Furniture and equipment		9,387			7,235		3 – 7
Other		13,812			13,307		3 – 10
		2,169,660			1,831,274
Less – accumulated depreciation		(146,723	)		(82,613	)
	$	2,022,937		$	1,748,661

During the year ended December 31, 2008, the Partnership recognized impairment charges totaling $21.6 million within goodwill and other asset impairment loss on its consolidated statements of operations in connection with a write-off of costs related to an APL 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.

In July 2007, APL acquired control of the Chaney Dell and Midkiff/Benedum systems (see Note 9).

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During the fourth quarter of 2007 and the first quarter of 2008, APL adjusted its preliminary purchase price allocation by adjusting the estimated amounts allocated to goodwill and property, plant, and equipment.

NOTE 8 – OTHER ASSETS

The following is a summary of other assets (in thousands):

	December 31,
	2008		2007
Deferred finance costs, net of accumulated amortization of $17,575 and $11,505 at December 31, 2008 and 2007, respectively	$	23,818	$	18,468
Security deposits		1,419		2,498
Other		137		155
	$	25,374	$	21,121

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreement (see Note 12). In December 2008, APL recorded $1.3 million for accelerated amortization of deferred financing costs associated its repurchase of approximately $60.0 million in face amount of its Senior Notes. In June 2008, APL recorded $1.2 million for accelerated amortization of deferred financing costs associated with the retirement of a portion of its term loan with a portion of the net proceeds from its issuance of Senior Notes. In July 2007, APL recorded $5.0 million of accelerated amortization for deferred financing costs associated with the replacement of its previous credit facility with a new facility.

NOTE 9 – 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 effected by 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 12). The Partnership, which holds all of the incentive distribution rights of APL as General Partner, has also 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. The Partnership also agreed that the resulting allocation of incentive distribution rights back to APL would be after the Partnership 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 (see Note 6).

In connection with this acquisition, APL reached an agreement with Pioneer, which currently holds a

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27.2% undivided joint venture interest in the Midkiff/Benedum system, whereby Pioneer has an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system, which began on June 15, 2008 and ended on November 1, 2008, and up to an additional 7.4% interest beginning on June 15, 2009 and ending on November 1, 2009 (the aggregate 22.0% additional interest can be entirely purchased during the period beginning June 15, 2009 and ending on November 1, 2009). If the option is fully exercised, Pioneer would increase its interest in the system to approximately 49.2%. Pioneer would pay approximately $230 million, subject to certain adjustments, for the additional 22.0% interest if fully exercised. APL will manage and control the Midkiff/Benedum system regardless of whether Pioneer exercises the purchase options.

APL’s acquisition was accounted for using the purchase method of accounting under SFAS No. 141. 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.

NOARK

In May 2006, APL acquired the remaining 25% ownership interest in NOARK from Southwestern, for a net purchase price of $65.5 million, consisting of $69.0 million of cash to the seller (including the repayment of the $39.0 million of outstanding NOARK notes at the date of acquisition), less the seller’s interest in NOARK’s working capital (including cash on hand and net payables to the seller) at the date of acquisition of $3.5 million. In October 2005, APL acquired from Enogex, Inc., a wholly-owned subsidiary of OGE Energy Corp. (NYSE: OGE), all of the outstanding equity of Atlas Arkansas Pipeline, LLC, which owned the initial 75% ownership interest in NOARK, for total consideration of $179.8 million, including $16.8 million for working capital adjustments and other related transaction costs. NOARK’s assets included a Federal Energy Regulatory Commission (“FERC”)-regulated interstate pipeline and an unregulated natural gas gathering system. The acquisition was accounted for using the purchase method of accounting under SFAS No. 141. The following table presents the purchase price allocation, including professional fees and other related acquisition costs, to the assets acquired and liabilities assumed in both acquisitions, based on their fair values at the date of the respective acquisitions (in thousands):

Cash and cash equivalents	$	16,215
Accounts receivable		11,091
Prepaid expenses		497
Property, plant and equipment		232,576
Other assets		140
Total assets acquired		260,519
Accounts payable and other liabilities		(50,689	)
Net assets acquired		209,830
Less: Cash and cash equivalents acquired		(16,215	)
Net cash paid for acquisitions	$	193,615

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APL’s ownership interests in the results of NOARK’s operations associated with each acquisition are included within its consolidated financial statements from the respective dates of the acquisitions.

The following data presents pro forma revenue and net income (loss) for the Partnership for the years ended December 31, 2007 and 2006 as if APL’s acquisitions discussed above, the Partnership’s equity offering in July 2007 (see Note 3), APL’s equity offering in July 2007 and May 2006 (see Note 4), APL’s proceeds of $830.0 million from a senior unsecured term loan (see Note 12), borrowings under its senior secured revolving credit facility (see Note 12), APL’s April 2007 and May 2006 issuances of senior notes (see Note 5 and 12), and APL’s May 2006 and March 2006 issuances of the cumulative convertible preferred units (see Note 5) had occurred on January 1, 2006. The data also presents actual revenue, net income (loss) and net income (loss) per common limited partner unit for the Partnership for the year ended December 31, 2008 for comparative purposes. The Partnership has prepared these unaudited pro forma financial results for comparative purposes only. These pro forma financial results may not be indicative of the results that would have occurred if APL and the Partnership had completed these acquisitions and financing transactions at the beginning of the periods shown below or the results that will be attained in the future (in thousands, except per unit data):

	Years Ended December 31,
	2008			2007			2006
Total revenue and other income (loss)	$	1,414,207		$	990,051		$	1,090,952
Net income (loss)		(73,653	)		(15,594	)		16,264
Net income (loss) attributable to common limited partners per unit:
Basic	$	(2.68	)	$	(0.57	)	$	0.59
Diluted	$	(2.68	)	$	(0.57	)	$	0.59

NOTE 10 – DERIVATIVE INSTRUMENTS

The Partnership and APL use a number of different derivative instruments, principally swaps and options, in connection with their 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 their 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 obligation, to purchase or sell natural gas, NGLs and condensate at a fixed price for the relevant contract period.

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The Partnership and APL apply the provisions of SFAS No. 133 to their derivative instruments. APL formally documents all relationships between hedging instruments and the items being hedged, including their risk management objective and strategy for undertaking the hedging transactions. This includes matching derivative contracts to the forecasted transactions. Under SFAS No. 133, the Partnership and APL can assess, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the Partnership and APL will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by the Partnership and APL through the utilization of market data, will be recognized within other income (loss), net in the Partnership’s consolidated statements of operations. For APL’s derivatives previously qualifying as hedges, the Partnership recognized the effective portion of changes in fair value in partners’ capital (deficit) as accumulated other comprehensive income (loss) and reclassified the portion relating to commodity derivatives to natural gas and liquids revenue and the portion relating to interest rate derivatives to interest expense within its consolidated statements of operations as the underlying transactions were settled. For APL’s 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.

On July 1, 2008, APL elected to discontinue hedge accounting for its existing commodity derivatives which were qualified as hedges under SFAS No. 133. 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.

During the year ended December 31 2008, APL made net payments of $274.0 million 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. Substantially all 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. During the years ended December 31, 2008, 2007 and 2006, the Partnership recognized the following derivative activity related to APL’s termination of these derivative instruments within its consolidated statement of operations (amounts in thousands):

	Early termination of derivative contracts for the Years Ended December 31,
	2008			2007		2006
Net cash derivative expense included within other income (loss), net	$	(199,964	)	$	—	$	—
Net cash derivative income included within natural gas and liquids revenue		2,322			—		—
Net non-cash derivative expense included within other income (loss), net		(39,218	)		—		—
Net non-cash derivative expense included within natural gas and liquids		(32,389	)		—		—

At December 31, 2008, the Partnership had an interest rate derivative contract having an aggregate notional principal amount of $25.0 million, which were designated as cash flow hedges. 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 12), and will receive LIBOR, plus the applicable margin, on the notional principal amounts. This derivative effectively converts $25.0 million of the Partnership’s floating rate debt under the revolving credit facility to fixed-rate debt. The interest rate swap agreement began on May 30, 2008 and expires on May 28, 2010.

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At December 31, 2008, APL had interest rate derivative contracts having aggregate notional principal amounts of $450.0 million, which were designated as cash flow hedges. Under the terms of these agreements, APL will pay weighted average interest rates of 3.02%, plus the applicable margin as defined under the terms of its revolving credit facility (see Note 12), and will receive LIBOR, plus the applicable margin, on the notional principal amounts. These derivatives effectively convert $450.0 million of APL’s floating rate debt under its term loan and revolving credit facility to fixed-rate debt. The APL interest rate swap agreements were effective as of December 31, 2008 and expire during periods ranging from January 30, 2010 through April 30, 2010.

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, 2008 and 2007, the Partnership reflected net derivative liabilities on its consolidated balance sheets of $64.3 million and $229.5 million, respectively. Of the $15.8 million of net loss in accumulated other comprehensive loss within partners’ capital (deficit) on the Partnership’s consolidated balance sheet at December 31, 2008, if the fair values of the instruments remain at current market values, the Partnership will reclassify $8.6 million of losses to the Partnership’s consolidated statements of operations over the next twelve month period, consisting of $6.6 million of losses to natural gas and liquids revenue and $2.0 million of losses to interest expense. Aggregate losses of $7.2 million will be reclassified to the Partnership’s consolidated statements of operations in later periods, consisting of $6.7 million of losses to natural gas and liquids revenue and $0.5 million of losses to interest expense. Actual amounts that will be reclassified will vary as a result of future price change.

On June 3, 2007, APL signed definitive agreements to acquire control of the Chaney Dell and Midkiff/Benedum systems (see Note 9). In connection with certain additional agreements entered into to finance this transaction, APL agreed as a condition precedent to closing that it would hedge 80% of its projected natural gas, NGL and condensate production volume for no less than three years from the closing date of the transaction. During June 2007, APL entered into derivative instruments to hedge 80% of the projected production of the Anadarko Assets to be acquired as required under the financing agreements. The production volume of the Anadarko Assets to be acquired was not considered to be “probable forecasted production” under SFAS No. 133 at the date these derivatives were entered into because the acquisition of the Anadarko Assets had not yet been completed. Accordingly, APL recognized the instruments as non-qualifying for hedge accounting at inception with subsequent changes in the derivative value recorded within other income (loss) in the Partnership’s consolidated statements of operations. The Partnership recognized a non-cash loss of $18.8 million related to the change in value of derivatives entered into specifically for the Chaney Dell and Midkiff/Benedum systems from the time the derivative instruments were entered into to the date of closing of the acquisition during the year ended December 31, 2007. Upon closing of the acquisition in July 2007, the production volume of the Anadarko Assets acquired was considered “probable forecasted production” under SFAS No. 133. APL designated many of these instruments as cash flow hedges and evaluated these derivatives under the cash flow hedge criteria in accordance with SFAS No. 133.

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) in our consolidated statements of operations and a corresponding decrease in minority interest in APL and accumulated other comprehensive loss in partners’ capital (deficit) in the Partnership’s consolidated balance sheet.

The fair value of the Partnership’s derivative instruments was included in its consolidated balance sheets as follows (in thousands):

	December 31,
	2008			2007
Current portion of derivative asset	$	44,961		$	—
Long-term hedge asset		—			—
Current portion of derivative liability		(60,947	)		(110,867	)
Long-term derivative liability		(48,333	)		(118,646	)
	$	(64,319	)	$	(229,513	)

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The following table summarizes the Partnership’s and APL’s cumulative derivative activity for the periods indicated (amounts in thousands):

	Years Ended December 31,
	2008			2007			2006
Loss from cash and non-cash settlement of qualifying hedge instruments(1)	$	(105,015	)	$	(49,393	)	$	(13,945	)
Gain (loss) from change in market value of non-qualifying derivatives(2)		140,144			(153,363	)		4,206
Loss from de-designation of cash flow derivatives(2)		—			(12,611	)		—
Gain (loss) from change in market value of ineffective portion of qualifying derivatives(2)		47,229			(3,450	)		1,520
Loss from cash and non-cash settlement of non-qualifying derivatives(2)		(250,853	)		(10,158	)		—
Loss from cash settlement of interest rate derivatives(3)		(1,289	)		—			—

(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.

(3) Included within interest expense on the Partnership’s consolidated statements of operations.

As of December 31, 2008, the Partnership had the following interest rate derivatives:

Interest Fixed-Rate Swap

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	2009	$	(551	)
				2010		(174	)
					$	(725	)

⁽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, 2008, APL had the following interest rate and commodity derivatives, including derivatives that do not qualify for hedge accounting:

Interest Fixed-Rate Swap

Term	Notional Amount		Type	Contract Period Ended December 31,	Fair Value Liability(1)
					(in thousands)
January 2008-January 2010	$	200,000,000	Pay 2.88% —Receive LIBOR	2009	$	(4,130	)
				2010		(249	)
					$	(4,379	)
April 2008-April 2010	$	250,000,000	Pay 3.14% —Receive LIBOR	2009	$	(5,835	)
				2010		(1,513	)
					$	(7,348	)

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Natural Gas Liquids Sales – Fixed Price Swaps

Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Asset(2)
	(gallons)	(per gallon)		(in thousands)
2009	8,568,000	$	0.746	$	1,509

Crude Oil Sales Options (associated with NGL volume)

Production Period Ended December 31,	Crude Volume	Associated NGL Volume	Average Crude Strike Price		Fair Value Asset/(Liability)(3)			Option Type
	(barrels)	(gallons)	(per barrel)		(in thousands)
2009	1,056,000	56,634,732	$	80.00	$	29,006		Puts purchased
2009	304,200	27,085,968	$	126.05		(22,774	)	Puts sold(4)
2009	304,200	27,085,968	$	143.00		44		Calls purchased(4)
2009	2,121,600	114,072,336	$	81.01		(1,080	)	Calls sold
2010	3,127,500	202,370,490	$	81.09		(17,740	)	Calls sold
2010	714,000	45,415,440	$	120.00		1,279		Calls purchased(4)
2011	606,000	32,578,560	$	95.56		(3,123	)	Calls sold
2011	252,000	13,547,520	$	120.00		646		Calls purchased(4)
2012	450,000	24,192,000	$	97.10		(2,733	)	Calls sold
2012	180,000	9,676,800	$	120.00		607		Calls purchased(4)
					$	(15,868	)

Natural Gas Sales – Fixed Price Swaps

Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset (3)
	(mmbtu)(5)	(per mmbtu) (5)			(in thousands)
2009	5,247,000	$	8.611		$	14,326
2010	4,560,000	$	8.526			6,461
2011	2,160,000	$	8.270			2,072
2012	1,560,000	$	8.250			1,596
					$	24,455
Natural Gas Basis Sales
Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset/(Liability)(3)
	(mmbtu)(5)	(per mmbtu)(5)			(in thousands)
2009	5,724,000	$	(0.558	)	$	(1,220	)
2010	4,560,000	$	(0.622	)		1,106
2011	2,160,000	$	(0.664	)		367
2012	1,560,000	$	(0.601	)		316
					$	569
Natural Gas Purchases – Fixed Price Swaps
Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Liability(3)
	(mmbtu)(5)	(per mmbtu)(5)			(in thousands)
2009	14,267,000	$	8.680		$	(36,734	)
2010	8,940,000	$	8.580			(13,403	)
2011	2,160,000	$	8.270			(2,072	)
2012	1,560,000	$	8.250			(1,596	)
					$	(53,805	)

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Natural Gas Basis Purchases

Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Liability(3)
	(mmbtu)(5)	(per mmbtu)(5)			(in thousands)
2009	15,564,000	$	(0.654	)	$	(9,201	)
2010	8,940,000	$	(0.600	)		(3,720	)
2011	2,160,000	$	(0.700	)		(423	)
2012	1,560,000	$	(0.610	)		(383	)
					$	(13,727	)

Ethane Put Options

Production Period Ended December 31,	Associated NGL Volume	Average Crude Strike Price		Fair Value Asset(2)			Option Type
	(gallons)	(per gallon)		(in thousands)
2009	14,049,000	$	0.6948	$	3,234		Puts purchased
Propane Put Options
Production Period Ended December 31,	Associated NGL Volume	Average Crude Strike Price		Fair Value Asset(2)			Option Type
	(gallons)	(per gallon)		(in thousands)
2009	14,490,000	$	1.4154	$	9,083		Puts purchased
Isobutane Put Options
Production Period Ended December 31,	Associated NGL Volume	Average Crude Strike Price		Fair Value Liability(2)			Option Type
	(gallons)	(per gallon)		(in thousands)
2009	126,000	$	0.7500	$	(3	)	Puts purchased
Normal Butane Put Options
Production Period Ended December 31,	Associated NGL Volume	Average Crude Strike Price		Fair Value Liability(2)			Option Type
	(gallons)	(per gallon)		(in thousands)
2009	113,400	$	0.7350	$	(3	)	Puts purchased
Natural Gasoline Put Options
Production Period Ended December 31,	Associated NGL Volume	Average Crude Strike Price		Fair Value Asset(2)			Option Type
	(gallons)	(per gallon)		(in thousands)
2009	126,000	$	0.9650	$	5		Puts purchased

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Crude Oil Sales

Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Asset(3)
	(barrels)	(per barrel)		(in thousands)
2009	33,000	$	62.700	$	252

Crude Oil Sales Options

Production Period Ended December 31,	Volumes	Average Strike Price		Fair Value Asset/(Liability)(3)			Option Type
	(barrels)	(per barrel)		(in thousands)
2009	105,000	$	90.000	$	3,635		Puts purchased
2009	306,000	$	80.017		(6,122	)	Calls sold
2010	234,000	$	83.027		(4,046	)	Calls sold
2011	72,000	$	87.296		(546	)	Calls sold
2012	48,000	$	83.944		(489	)	Calls sold
				$	(7,568	)
Total net liability				$	(64,319	)

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

⁽²⁾ Fair value based upon APL management estimates, including forecasted forward NGL prices as a function of forward NYMEX natural gas, light crude and propane prices.

⁽³⁾ Fair value based on forward NYMEX natural gas and light crude prices, as applicable.

⁽⁴⁾ Puts sold and calls purchased for 2009 represent costless collars entered into by APL as offsetting positions for the calls sold related to ethane and propane production. In addition, calls were purchased by APL for 2010 through 2012 to offset 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.

⁽⁵⁾ Mmbtu represents million British Thermal Units.

NOTE 11 – FAIR VALUE OF FINANCIAL INSTRUMENTS

Derivative Instruments

The Partnership adopted the provisions of SFAS No. 157 at January 1, 2008. SFAS No. 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS No. 157’s 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.

The Partnership uses the fair value methodology outlined in SFAS No. 157 to value the assets and liabilities for its respective outstanding derivative contracts (see Note 10). All of the Partnership’s and APL’s

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derivative contracts are defined as Level 2, with the exception of APL’s NGL fixed price swaps and crude oil options. APL’s Level 2 commodity hedges 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 natural gas, crude oil, and propane prices, and therefore are defined as Level 3. Valuations for APL’s crude oil options (including those associated with NGL sales) are based on forward price curves developed by the related financial institution based upon current quoted prices for crude oil futures, and therefore are defined at Level 3. In accordance with SFAS No. 157, the following table represents the Partnership’s assets and liabilities recorded at fair value as of December 31, 2008 (in thousands):

	Level 1		Level 2			Level 3			Total
Commodity–based derivatives	$	—	$	(42,256	)	$	(9,611	)	$	(51,867	)
Interest rate swap–based derivatives		—		(12,452	)		—			(12,452	)
Total	$	—	$	(54,708	)	$	(9,611	)	$	(64,319	)

APL’s Level 3 fair value amount relates to its derivative contracts on NGL fixed price swaps and crude oil options. The following table provides a summary of changes in fair value of APL’s Level 3 derivative instruments as of December 31, 2008 (in thousands):

	NGL Fixed Price Swaps			Crude Oil Sales Options (associated with NGL Volume)			Crude Oil Sales Options			NGL Sales Options			Total
Balance – December 31, 2007	$	(33,624	)	$	(145,418	)	$	(24,740	)	$	—		$	(203,782	)
New options contracts		—			20,451			6,012			24,529			50,992
Cash settlements from unrealized gain (loss)(1)		(7,396	)		224,956			(3,926	)		(12,154	)		201,480
Cash settlements from other comprehensive income(1)		33,895			92,432			13,406			—			139,733
Net change in unrealized gain (loss)(2)		17,321			(57,934	)		36,159			—			(4,454	)
Deferred option premium recognition		—			150			468			(59	)		559
Net change in other comprehensive loss		(8,687	)		(150,504	)		(34,948	)		—			(194,139	)
Balance – December 31, 2008	$	1,509		$	(15,867	)	$	(7,569	)	$	12,316		$	(9,611	)

⁽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 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 could realize upon the sale or refinancing of such financial instruments.

The Partnership’s current assets and liabilities on the consolidated balance sheets are financial instruments. 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 long-term debt at December 31, 2008 and 2007, which consists principally of borrowings under the Partnership’s and APL’s credit facility, APL’s Term Loan and APL’s Senior Notes, was $1,199.2 million and $1,250.6 million, respectively, compared with the

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carrying amount of $1,539.4 million and $1,254.4 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 12 – DEBT

Total debt consists of the following (in thousands):

	December 31,
	2008		2007
Revolving credit facility	$	46,000	$	25,000
APL Revolving credit facility		302,000		105,000
APL Term loan		707,180		830,000
APL 8.125% Senior notes – due 2015		261,197		294,392
APL 8.75% Senior notes – due 2018		223,050		—
Other APL debt		—		34
Total debt		1,539,427		1,254,426
Less current maturities		—		(34	)
Total long-term debt	$	1,539,427	$	1,254,392

Atlas Pipeline Holdings Credit Facility

On July 26, 2006, the Partnership, as borrower, and Atlas Pipeline GP, as guarantor, entered into a $50.0 million revolving credit facility with a syndicate of banks. At December 31, 2008, the Partnership, with Atlas Pipeline GP as guarantor, had a $50.0 million revolving credit facility with a syndicate of banks. At December 31, 2008, the Partnership had $46.0 million outstanding under its revolving credit facility, which was utilized to fund its capital contribution to APL to maintain its 2.0% general partner interest, underwriter fees and other transaction costs related to its July 2007 private placement of common units (see Note 3). The Partnership’s credit facility matures in April 2010 and bears interest, at its option, at either (i) adjusted LIBOR (plus the applicable margin, as defined in the credit facility) or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank, National Association prime rate (each plus the applicable margin). The weighted average interest rate on the outstanding credit facility borrowings at December 31, 2008 was 3.4%. 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 a 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; make distribution payments to the Partnership’s unitholders if an event of default exists or would result from such distribution; or enter into a merger or sale of substantially all of the Partnership’s property or assets, including the sale or transfer of interests in its subsidiaries. The Partnership is in compliance with these covenants as of December 31, 2008.

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 America, the Partnership’s general partner or any other obligor, and termination of a material agreement and occurrence of a material adverse effect. The Partnership’s credit facility requires it to maintain a combined leverage ratio, defined as the ratio of the sum of (i) the Partnership’s funded debt (as defined in its credit facility) and (ii) APL’s funded debt (as defined in APL’s credit facility) to APL’s EBITDA (as defined in APL’s credit facility) of not more than 5.5 to 1.0. In addition, the Partnership’s credit facility requires it to maintain a funded debt (as defined in its credit facility) to EBITDA ratio of not more than 3.5 to 1.0; and an interest coverage ratio (as defined in its credit facility) of not less than 3.0 to 1.0. The Partnership’s credit

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facility defines EBITDA for any period of four fiscal quarters as the sum of (i) four times the amount of cash distributions payable with respect to the last fiscal quarter in such period by APL to the Partnership in respect of the Partnership’s general partner interest, limited partner interest and incentive distribution rights in APL and (ii) the Partnership’s consolidated net income (as defined in its credit facility and as adjusted as provided in its credit facility). As of December 31, 2008, the Partnership’s combined leverage ratio was 4.9 to 1.0, its funded debt to EBITDA was 1.0 to 1.0, and its interest coverage ratio was 25.5 to 1.0.

The Partnership may borrow under its credit facility (i) for general business purposes, including for working capital, to purchase debt or limited partnership units of APL, to fund general partner contributions from the Partnership to APL and to make permitted acquisitions, (ii) to pay fees and expenses related to its credit facility and (iii) for letters of credit.

APL Term Loan and Credit Facility

At December 31, 2008, 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, 2008 was 3.7%, and the weighted average interest rate on the outstanding APL term loan borrowings at December 31, 2008 was 3.0%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $5.9 million was outstanding at December 31, 2008. These outstanding letter of credit amounts were not reflected as borrowings on the Partnership’s consolidated balance sheet.

In June 2008, APL entered into an amendment to its revolving credit facility and term loan 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 Note 10) in calculating its 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 credit facility with proceeds from its issuance of $250.0 million of 10-year, 8.75% senior unsecured notes (see “—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.

Borrowings under the APL 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 by the guaranty of each of its 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 in compliance with these covenants as of December 31, 2008. Mandatory prepayments of the amounts borrowed under the term loan portion of the credit facility are required from the net cash proceeds of debt and equity issuances, and of dispositions of assets that exceed $50.0 million in the aggregate in any fiscal year that are not reinvested in replacement assets within 360 days. In connection with entering into the credit facility, APL agreed to remit an underwriting fee to the lead underwriting bank of 0.75% of the aggregate principal amount of the term loan outstanding on January 23, 2008. Since then, APL and the underwriting bank agreed to extend the agreement through January 30, 2009 and reduce the underwriting fee to 0.50% of the aggregate principal amount of the term loan outstanding as of that date.

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 agreements, adverse judgments against APL in excess of a specified amount, and a change of control of APL’s General Partner. APL’s credit facility requires it to maintain a ratio of funded debt (as defined in the credit facility) to EBITDA (as defined in the credit facility) ratio of not more than 5.25 to 1.0, and an interest coverage

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ratio (as defined in the credit facility) of not less than 2.75 to 1.0. During a Specified Acquisition Period (as defined in the credit facility), for the first 2 full fiscal quarters subsequent to the closing of an acquisition with total consideration in excess of $75.0 million, the ratio of funded debt to EBITDA will be permitted to step up to 5.75 to 1.0. As of December 31, 2008, APL’s ratio of funded debt to EBITDA was 4.7 to 1.0 and its interest coverage ratio was 4.0 to 1.0.

APL is 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 Senior Notes

At December 31, 2008, 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 $261.2 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 $0.7 million of unamortized premium received as of December 31, 2008. The APL 8.75% Senior Notes were issued in June 2008 in a private placement transaction pursuant to Rule 144A and Regulation S under the Securities Act of 1933 for net proceeds of $244.9 million, after underwriting commissions and other transaction costs. 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.

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, 2008.

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.

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 APL Senior Notes repurchased have been retired and are not available for re-issue.

The aggregate amount of the Partnership’s debt maturities, including APL, is as follows (in thousands):

Years Ended December 31:
2009	$	—
2010		46,000
2011		—
2012		—
2013		302,000
Thereafter		1,191,427
	$	1,539,427

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Cash payments for interest related to the Partnership’s and APL’s debt were $87.6 million, $58.2 million and $25.6 million for the years ended December 31, 2008, 2007 and 2006, respectively.

NOTE 13 – COMMITMENTS AND CONTINGENCIES

APL has noncancelable operating leases for equipment and office space. Total rental expense for the years ended December 31, 2008, 2007 and 2006 was $9.1 million, $5.6 million and $4.0 million, respectively. The aggregate amount of remaining future minimum annual lease payments as of December 31, 2008 is as follows (in thousands):

Years Ended December 31:
2009	$	4,953
2010		3,115
2011		2,221
2012		1,116
2013		130
Thereafter		—
	$	11,535

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.

As of December 31, 2008, APL is committed to expend approximately $93.0 million on pipeline extensions, compressor station upgrades and processing facility upgrades.

NOTE 14 – 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, 2008, the Mid-Continent segment had two customers that individually accounted for approximately 50% and 13% of the Partnership’s consolidated total revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2007, the Mid-Continent segment had one customer that individually accounted for approximately 50% of the Partnership’s consolidated total revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2006, the Mid-Continent segment had three customers that individually accounted for approximately 36%, 18% and 10% of the Partnership’s consolidated total revenues, excluding the impact of all financial derivative activity. Additionally, the Mid-Continent segment had one customer that individually accounted for approximately 37% of the Partnership’s consolidated accounts receivable at December 31, 2008, and two customers that individually accounted for approximately 26% and 11% of the Partnership’s consolidated accounts receivable at December 31, 2007. Substantially all of the Appalachian segment’s revenues are derived from a master gas gathering agreement with Atlas Energy.

APL has certain producers which supply a majority of the natural gas to its Mid-Continent gathering

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and transportation 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, 2008, the Partnership and its subsidiaries, including APL, had $11.6 million in deposits at banks, of which $10.4 million was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments.

NOTE 15 – STOCK COMPENSATION

The Partnership and APL follow the provisions of SFAS No. 123(R), “Share-Based Payment”, as revised (“SFAS No. 123(R)”), for their stock compensation. Generally, the approach to accounting in SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values.

Partnership’s Long-Term Incentive Plan. In November 2006, the Board of Directors approved and adopted our 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 us. The LTIP is administered by a committee (the “LTIP Committee”), appointed by our 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, 2008, the Partnership had 1,441,300 phantom units and unit options outstanding under the Partnership’s LTIP, with 657,650 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 or, at the discretion of the Partnership’s LTIP Committee, cash equivalent to the then fair market value of a common limited partner unit of the Partnership. 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, 2008, 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. The vesting of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by the Partnership’s LTIP Committee, although no awards currently outstanding contain any such provision. 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, 2008, 55,675 units will vest within the following twelve months. All phantom units outstanding under the Partnership’s LTIP at December 31, 2008 include DERs granted to the Participants by the Partnership’s LTIP Committee. The amounts paid with respect to the Partnership’s LTIP DERs were $0.4 million and $0.3 million for the years ended December 31, 2008 and 2007, respectively. These amounts were recorded as reductions of partners’ capital (deficit) on the Partnership’s consolidated balance sheet.

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The following table sets forth the Partnership’s LTIP phantom unit activity for the periods indicated:

	Years Ended December 31,
	2008			2007			2006
Outstanding, beginning of year		220,825			220,492			—
Granted(1)		6,150			708			220,492
Matured		(675	)		(375	)		—
Forfeited		—			—			—
Outstanding, end of year		226,300			220,825			220,492
Non-cash compensation expense recognized (in thousands)	$	1,427		$	1,420		$	229

⁽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 $26.51, $37.46 and $22.56 for awards granted for the year ended December 31, 2008, 2007 and 2006, respectively.

⁽²⁾ The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2008 is $0.9 million.

⁽³⁾ The intrinsic values for phantom unit awards exercised during the years ended at December 31, 2008 and 2007 were $6,000 and $14,000, respectively. There were no exercises of phantom units during the year ended December 31, 2006.

At December 31, 2008, the Partnership had approximately $2.2 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, 2008, 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. The vesting of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by the Partnership’s LTIP Committee, although no awards currently outstanding contain any such provision. Awards will automatically vest upon a change of control of the Partnership, as defined in the Partnership’s LTIP. There are 303,750 unit options outstanding under the Partnership’s LTIP at December 31, 2008 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,
	2008				2007				2006
	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		—		—
Granted		—		—		—		—		1,215,000	$	22.56
Matured		—		—		—		—		—		—
Forfeited		—		—		—		—		—		—
Outstanding, end of period(1)(2)		1,215,000	$	22.56		1,215,000	$	22.56		1,215,000	$	22.56
Options exercisable, end of period(3)		—		—		—		—		—		—
Weighted average fair value of unit options per unit granted during the year		—		—		—		—		—	$	3.76
Non-cash compensation expense recognized (in thousands)	$	1,237			$	1,237			$	206

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(1) The weighted average remaining contractual lives for outstanding options at December 31, 2008, 2007 and 2006 were 7.9 years, 8.9 years and 9.9 years, respectively.

(2) There was no intrinsic value of options outstanding at December 31, 2008. The aggregate intrinsic values of options outstanding at December 31, 2007 and 2006 were approximately $5.6 million and $1.6 million, respectively.

(3) There were no options exercised during the years ended December 31, 2008, 2007 and 2006, respectively.

At December 31, 2008, the Partnership had approximately $1.9 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 each unit option granted with weighted average assumptions for (a) expected dividend yield of 4.0%, (b) risk-free interest rate of 4.5%, (c) expected volatility of 20.0%, and (d) an expected life of 6.9 years.

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. Only phantom units have been granted under the APL LTIP through December 31, 2008.

A phantom unit entitles a grantee to receive a common unit, without payment of an exercise price, upon vesting of the phantom unit or, at the discretion of the APL LTIP Committee, cash equivalent to the fair market value of an APL common 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 the Partnership, the APL LTIP Committee will determine the vesting period for phantom units and the exercise period for options. Through December 31, 2008, phantom units granted under the APL LTIP generally had vesting periods of four years. The vesting of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by the APL LTIP Committee, although no awards currently outstanding contain any such provision. 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, 2008, 55,228 units will vest within the following twelve months. All units outstanding under the APL LTIP at December 31, 2008 include DERs granted to the participants by the APL LTIP Committee. The amounts paid with respect to APL LTIP DERs were $0.5 million, $0.6 million and $0.4 million for the years ended December 31, 2008, 2007 and 2006, respectively. These amounts were recorded as reductions of minority interest in APL on the Partnership’s consolidated balance sheet.

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The following table sets forth the APL LTIP phantom unit activity for the periods indicated:

	Years Ended December 31,
	2008			2007			2006
Outstanding, beginning of year		129,746			159,067			110,128
Granted(1)		54,796			25,095			82,091
Matured(2)		(56,227	)		(51,166	)		(31,152	)
Forfeited		(1,750	)		(3,250	)		(2,000	)
Outstanding, end of year(3)		126,565			129,746			159,067
Non-cash compensation expense recognized (in thousands)	$	2,313		$	2,936		$	2,030

⁽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 $44.28, $50.09 and $45.45 for awards granted for the years ended December 31, 2008, 2007 and 2006, respectively.

⁽²⁾ The intrinsic values for phantom unit awards exercised during the years ended at December 31, 2008, 2007, and 2006 were $2.0 million, $2.6 million, and $1.3 million, respectively.

⁽³⁾ The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2008 is $0.8 million.

At December 31, 2008, APL had approximately $2.1 million of unrecognized compensation expense related to unvested phantom units outstanding under the APL LTIP based upon the fair value of the awards.

APL Incentive Compensation Agreements

APL has incentive compensation agreements which have 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 to be 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 estimated to be issued under the incentive compensation agreements were determined principally by the financial performance of certain APL assets for 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 dictate that no individual covered under the agreements shall 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 shall be paid in cash.

APL recognized a reduction of compensation expense of $36.3 million, expense of $33.4 million and expense of $4.3 million for the years ended December 31, 2008, 2007 and 2006, 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 was 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 follows SFAS No. 123(R) and recognized compensation expense related to these awards based upon the fair value method. During the first quarter of 2009, APL expects to issue 348,620 common units to the certain key employees covered under the incentive compensation agreements to fulfill its obligations under the terms of the agreements. No additional common units will be issued with regard to these agreements.

NOTE 16 – 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 America and its affiliates. 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

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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 America 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 $1.5million, $5.9 million and $2.3 million for the years ended December 31, 2008, 2007 and 2006, respectively, for compensation and benefits related to their employees. There were no direct reimbursements by APL to the Partnership and its affiliates for the years ended December 31, 2008 and 2007. During the year ended December 31, 2006, direct reimbursements by APL to the Partnership and its affiliates were $15.1 million, including certain costs that have been capitalized by APL. The Partnership believes that the method utilized in allocating costs to APL is reasonable.

Under an agreement between APL and Atlas Energy, Atlas Energy must construct up to 2,500 feet of sales lines from its existing wells in the Appalachian region to a point of connection to APL’s gathering systems. APL must, at its own cost, extend its system to connect to any such lines within 1,000 feet of its gathering systems. With respect to wells to be drilled by Atlas Energy that will be more than 3,500 feet from APL’s gathering systems, APL has various options to connect those wells to its gathering systems at its own cost.

NOTE 17 – SEGMENT INFORMATION

The Partnership’s assets primarily consist of its ownership interests in APL. APL has two reportable segments: natural gas transmission, gathering and processing located in the Appalachian Basin area (“Appalachia”) of eastern Ohio, western New York, western Pennsylvania and northeastern Tennessee, and transmission, gathering and processing located in the Mid-Continent area (“Mid-Continent”) of primarily Oklahoma, northern and western Texas, the Texas Panhandle, Arkansas, southern Kansas and southeastern Missouri. Appalachia revenues are principally based on contractual arrangements with Atlas Energy and its affiliates. Mid-Continent revenues are primarily derived from the sale of residue gas and NGLs and transport of natural gas. These reportable segments reflect the way APL manages its operations.

The following summarizes the Partnership’s reportable segment data for the periods indicated (in thousands):

	Years Ended December 31,
	2008			2007			2006
Mid-Continent
Revenue:
Natural gas and liquids	$	1,366,270		$	759,553		$	391,356
Transportation, compression and other fees		55,007			48,041			30,653
Other income (loss), net		(55,836	)		(174,438	)		11,804
Total revenue and other income (loss), net		1,365,441			633,156			433,813
Costs and expenses:
Natural gas and liquids		1,084,318			586,677			334,299
Plant operating		60,835			34,667			15,722
Transportation and compression		6,637			7,249			5,807
General and administrative		(7,636	)		48,332			15,036
Depreciation and amortization		83,694			46,327			19,322
Goodwill and other asset impairment loss		696,204			—			—
Minority interests		(22,781	)		3,940			118
Total costs and expenses		1,901,271			727,192			390,304
Segment profit (loss)	$	(535,830	)	$	(94,036	)	$	43,509

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Appalachia
Revenue:
Natural gas and liquids	$	3,730		$	1,565		$	—
Transportation, compression and other fees – affiliates		43,293			33,169			30,189
Transportation, compression and other fees – third parties		1,409			575			82
Other income		317			335			608
Total revenue and other income		48,749			35,644			30,879
Costs and expenses:
Natural gas and liquids		1,824			847			—
Transportation and compression		11,249			6,235			4,946
General and administrative		4,027			6,327			3,767
Depreciation and amortization		6,430			4,655			3,672
Goodwill and other asset impairment loss		2,304			—			—
Total costs and expenses		25,834			18,064			12,385
Segment profit	$	22,915		$	17,580		$	18,494
Reconciliation of segment profit (loss) to net income (loss):
Segment profit (loss):
Mid-Continent	$	(535,830	)	$	(94,036	)	$	43,509
Appalachia		22,915			17,580			18,494
Total segment profit (loss)		(512,915	)		(76,456	)		62,003
Corporate general and administrative expenses		(7,575	)		(9,883	)		(4,302	)
Interest expense(1)		(86,705	)		(62,629	)		(24,726	)
Gain on extinguishment of debt.		19,867			—			—
Minority interest in Atlas Pipeline Partners, L.P.		513,675			133,321			(16,335	)
Net income (loss)	$	(73,653	)	$	(15,647	)	$	16,640
Capital Expenditures:
Mid-Continent	$	284,432		$	120,027		$	65,301
Appalachia		41,502			19,620			18,415
	$	325,934			139,647			83,716

⁽¹⁾ The Partnership notes that interest expense has not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented.

	December 31,
	2008		2007
Balance Sheet
Total assets:
Mid-Continent	$	2,306,627	$	2,813,049
Appalachia		114,166		43,860
Corporate other		30,528		20,605
	$	2,451,321	$	2,877,514
Goodwill:
Mid-Continent	$	—	$	706,978
Appalachia		—		2,305
	$	—	$	709,283

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The following tables summarize the Partnership’s total revenues by product or service for the periods indicated (in thousands):

	Years Ended December 31,
	2008		2007		2006
Natural gas and liquids:
Natural gas	$	568,698	$	264,438	$	196,182
NGLs		688,623		434,773		169,840
Condensate		57,366		27,269		6,678
Other(1)		55,313		34,638		18,656
Total	$	1,370,000	$	761,118	$	391,356
Transportation, compression and other fees:
Affiliates	$	43,293	$	33,169	$	30,189
Third parties		56,416		48,616		30,735
Total	$	99,709	$	81,785	$	60,924

(1) Includes treatment, processing, and other revenue associated with the products noted.

NOTE 18 – 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, 2008:
Revenue and other income (loss), net	$	379,528		$	582,131	$	149,158		$	303,390
Costs and expenses		446,164			548,126		187,360			306,210
Net income (loss)		(66,636	)		34,005		(38,202	)		(2,820	)
Basic net income (loss) attributable to common limited partners per unit	$	(2.41	)	$	1.23	$	(1.40	)	$	(0.10	)
Diluted net income (loss) attributable to common limited partners per unit(5)	$	(2.41	)	$	1.21	$	(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.

⁽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⁾ 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.

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	Fourth Quarter(1)			Third Quarter(2)			Second Quarter(3)			First Quarter(4)
	(in thousands, except per unit data)
Year ended December 31, 2007:
Revenue and other income (loss)	$	213,554		$	242,302		$	95,419		$	117,544
Costs and expenses		227,436			245,441			96,708			114,881
Net income (loss)		(13,882	)		(3,139	)		(1,289	)		2,663
Basic net income (loss) attributable to common limited partners per unit	$	(0.51	)	$	(0.12	)	$	(0.06	)	$	0.13
Diluted net income (loss) attributable to common limited partners per unit(5)	$	(0.51	)	$	(0.12	)	$	(0.06	)	$	0.13

⁽¹⁾ Net loss includes APL’s $130.2 million non-cash derivative loss.

⁽²⁾ Net loss includes APL’s $8.4 million non-cash derivative loss.

⁽³⁾ Net loss includes APL’s $28.5 million non-cash derivative loss.

⁽⁴⁾ Net income includes APL’s $2.3 million non-cash derivative loss.

⁽⁵⁾ For the fourth, third and second quarters of the year ended December 31, 2007, approximately 842,000, 521,000 and 42,000 phantom units, respectively, were excluded from the computation of diluted earnings attributable to common limited partner units because the inclusion of such units would have been anti-dilutive.

NOTE 19 – SUBSEQUENT EVENT

On January 27, 2009, APL and Sunlight Capital, the holder of its outstanding Class A Preferred Units, agreed to amend certain terms of its existing preferred unit agreement. The amendment (a) increased the dividend yield from 6.5% to 12% per annum, effective January 1, 2009, (b) changed the conversion commencement date from May 8, 2008 to April 1, 2009, (c) changed the conversion price adjustment from $43.00 to $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 the common units, and (d) changed the call redemption price from $53.22 to $27.25. Simultaneously with the execution of the amendment, APL issued Sunlight Capital $15.0 million of its 8.125% senior unsecured notes due 2015 to redeem 10,000 APL Class A Preferred Units. APL also agreed that it will redeem an additional 10,000 APL Class A Preferred Units for cash at the liquidation value on April 1, 2009. If Sunlight does not exercise its conversion right on or before June 2, 2009, APL will redeem the then-remaining 10,000 APL Class A Preferred Units for cash or one-half for cash and one-half for APL’s common limited partner units on July 1, 2009.

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.

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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, 2008, 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, 2008. Grant Thornton LLP, an independent registered public accounting firm and auditors of our consolidated financial statements, has issued an attestation report on the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2008, which is included herein.

There have been no changes in our internal control over financial reporting during the fourth quarter of 2008 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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 (Partnership) (a Delaware limited partnership) internal control over financial reporting as of December 31, 2008, based on criteria established inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership’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 “Managements Report on Internal Control over Financial Reporting”. Our responsibility is to express an opinion on the Partnership’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

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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 partnership’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 partnership’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 partnership; (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 partnership are being made only in accordance with authorizations of management and directors of the partnership; (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or dispositions of the partnership’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, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established inInternal 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 the Partnership and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of operations, comprehensive income (loss), owners’ equity/partners’ capital, and cash flows for each of the three years in the period ended December 31, 2008 and our report dated February 27, 2009 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

February 27, 2009

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 America 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 America and its affiliates and may face a conflict regarding the allocation of their time between our business and affairs and their other business interests.

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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	54	Chief Executive Officer, President and Director	2008
Matthew A. Jones	47	Chief Financial Officer and Director	2006
Edward E. Cohen	70	Chairman of the Board	2006
Jonathan Z. Cohen	38	Vice Chairman of the Board	2006
Sean P. McGrath	37	Chief Accounting Officer	2006
Lisa Washington	41	Chief Legal Officer and Secretary	2006
William G. Karis	60	Director	2006
Jeffrey C. Key	43	Director	2006
Harvey G. Magarick	69	Director	2006

Eugene N. Dubay, 60, has been our Chief Executive Officer, President and director 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 and Chief Executive Officer 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) since 2003. 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.

Matthew A. Jones has been our Chief Financial Officer since January 2006 and a director since February 2006. Mr. Jones has been the Chief Financial Officer of Atlas Pipeline GP and Atlas America since March 2005. He has been the Chief Financial Officer and a director of Atlas Energy and Atlas Energy Management since their formation. 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.

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 America since its formation in 2000. Mr. Cohen has been the Chairman of the Board and Chief Executive Officer of Atlas Energy and its manager, Atlas Energy Management, 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; 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.

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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 America since its formation in 2000. Mr. Cohen has been Vice Chairman of the Board of Atlas Energy 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 was its Vice Chairman from 2003 until December 2006. Mr. Cohen is a son of Edward E. Cohen.

Sean P. McGrath has been the Chief Accounting Officer of our general partner since January 2006. Mr. McGrath has been the Chief Accounting Officer of Atlas Pipeline GP since May 2005. In December, 2008, Mr. McGrath became the Chief Accounting Officer of Atlas America and Atlas Energy Resources, LLC. Mr. McGrath was the Controller of Sunoco Logistics Partners L.P., a publicly-traded partnership that transports, terminals and stores refined products and crude oil, from 2002 to 2005. From 1998 to 2002, Mr. McGrath was Assistant Controller of Asplundh Tree Expert Co., a utility services and vegetation management company. Mr. McGrath is a Certified Public Accountant.

Lisa Washington has been the Chief Legal Officer and Secretary of our general partner since January 2006 and a Senior Vice President since October 2008. Ms. Washington has been the Chief Legal Officer, Secretary of Atlas Pipeline GP since November 2005 and Senior Vice President since October 2008. Ms. Washington was a Vice President from November 2005 until October 2008. Ms. Washington also has been the Chief Legal Officer and Secretary of Atlas America since November 2005, and a Senior Vice President since October 2008. Ms. Washington was a Vice President of Atlas America from November 2005 until October 2008. She is also the Chief Legal Officer and Secretary of Atlas Energy and Atlas Energy Management, positions she has held since their formation in 2006. Ms. Washington was Vice President of Atlas Energy from 2006 until July 2008, when she became a Senior Vice President. From 1999 to 2005, Ms. Washington was an attorney in the business department of the law firm of Blank Rome LLP.

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.

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.

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.

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Other Significant Employees

Daniel C. Herz, 32, has been our Senior Vice President of Corporate Development since August 2007. He has also been the Senior Vice President of Corporate Development of Atlas America, Atlas Pipeline Partners GP and Atlas Energy Resources, LLC since August 2007. Before that, he was Vice President of Corporate Development of Atlas America and Atlas Pipeline Partners GP from December 2004 and of Atlas Pipeline Holdings GP from its formation in January 2006. Mr. Herz joined Atlas America and Atlas Pipeline Partners GP in January 2004. He was an Associate Investment Banker with Banc of America Securities from 2002 to 2003 and an Analyst from 1999 to 2002.

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 all of the officers and 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 during fiscal year 2008.

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 America and its affiliates who provide us with services is set by Atlas America and such affiliates. There was no allocation of the salaries of such personnel to us; however, Atlas America 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.

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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.

ITEM 11. EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

We are required to provide information regarding the compensation program in place as of December 31, 2008, 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.

We do not directly compensate our NEOs. Rather, Atlas America 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 America and its affiliates. APL reimburses Atlas America for the compensation allocated to it for its and our executive officers. Atlas America does not make a separate allocation to us. Because Atlas America 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 America 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 America compensation committee makes recommendations to the Atlas America board on compensation amounts after the close of its (and our) fiscal year. In the case of base salaries, it recommends the amounts to be paid for that 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 America typically pays cash awards and issues equity awards in February of the following fiscal year. The Atlas America compensation committee has the discretion to recommend the issuance of equity awards at other times during the fiscal year. In addition, some of our NEOs who also perform services for Atlas America and its other publicly-traded subsidiary, Atlas Energy Resources, may receive stock-based awards from Atlas America and/or Atlas Energy.

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Each year, Atlas America’s Chief Executive Officer provides the Atlas America compensation committee with key elements of Atlas America’s performance and the NEOs’ performance as well as recommendations to assist it in determining compensation levels. The Atlas America compensation committee focuses on Atlas America’s equity performance, market capitalization, corporate developments, business performance (including production of energy and replacement of reserves) and financial position in recommending the compensation for those NEOs who provided services to both Atlas America and to us.

The Atlas America compensation committee has retained Mercer (US) Inc. to provide information, analyses, and advice regarding executive compensation.

At the Atlas America compensation committee’s direction, Mercer provided the following services for the committee during fiscal 2008:

• provided on-going advice as needed on the design of Atlas America’s annual and long-term incentive plans;

• advised the committee as requested on the performance measures and performance targets for the annual programs by providing an analysis of total shareholder return for a peer group of companies identified by Atlas America and of the metrics of its internal performance review; and

• provided advice in connection with Jonathan Cohen’s employment agreement.

Mercer did not provide a peer group or other analysis with respect to compensation levels. In the course of conducting its activities for fiscal 2008, Mercer attended four meetings of the Atlas America compensation committee and presented its findings and recommendations for discussion.

The Atlas America compensation committee has established procedures that it considers adequate to ensure that Mercer’s advice remains objective and is not influenced by Atlas America’s management. These procedures include: a direct reporting relationship of the Mercer consultant to the chairman of the Atlas America 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 committee on Mercer’s financial relationship with Atlas America, including a summary of the work performed for it during the preceding 12 months; and written assurances from Mercer that, within the Mercer organization, the Mercer consultant who performs services for the committee has a reporting relationship and compensation determined separately from Mercer’s other lines of business and from its other work for Atlas America. With the consent of the Atlas America compensation committee chair, Mercer may contact Atlas America’s executive officers for information necessary to fulfill its assignment and may make reports and presentations to and on behalf of the Atlas America compensation committee that the executive officers also receive.

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Atlas America’s Chief Executive Officer provides the Atlas America compensation committee with key elements of both Atlas America’s and our company’s and the NEOs’ performance during the year. Atlas America’s CEO makes recommendations to the Atlas America compensation committee regarding the salary, bonus and incentive compensation component of each NEO’s total compensation, including his own. Atlas America’s CEO, at the committee’s request, may attend committee meetings; however, his role during the meetings is to provide insight into Atlas America’s and our company’s and the NEOs’ performance as well as the performance of other comparable companies in the same industry. In making its compensation decisions, the Atlas America compensation committee meets in executive session, without management, both with and without Mercer.

Ultimately, the decisions regarding executive compensation are made by the Atlas America compensation committee after extensive discussion regarding appropriate compensation and may reflect factors and considerations other than the information and advice provided by Mercer and Atlas America’s CEO. The Atlas America compensation committee decisions are approved by Atlas America’s board of directors.

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 America. 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 America and us as measured by the elements of corporate performance mentioned above. 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 America’s annual performance and /or that of one of Atlas America’s subsidiaries or divisions for which the officer is responsible. Generally, the higher the level of responsibility of the executive within Atlas America, the greater is the incentive component of that executive’s target total cash compensation. The Atlas America compensation committee may recommend awards of performance-based bonuses and discretionary bonuses.

Performance-Based Bonuses— The Atlas America 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 America’s fiscal year. Awards under the Senior Executive Plan are paid in cash. The Senior Executive Plan is designed to permit Atlas America 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 America compensation committee believes that the interests of Atlas America’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 2008, the Atlas America compensation committee approved 2008 target bonus awards to be paid from a bonus pool. The bonus pool is equal to 18.3% of Atlas America’s adjusted distributable cash flow unless the adjusted distributable cash flow includes any capital transaction gains in excess of $50 million, in which case 10% of that excess will be included in the bonus pool. If the adjusted distributable cash flow does not equal at least 95% of the adjusted distributable cash flow for the previous year, no bonuses will be paid. Adjusted distributable cash flow means the sum of (i) cash available for distribution to Atlas America by any of its

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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 America’s stand-alone general and administrative expenses for the year (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 America’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 our basis in the subsidiary. The maximum award payable, expressed as a percentage of Atlas America’s estimated 2008 adjusted distributable cash flow, for our NEO participants is 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 Atlas America compensation committee has the discretion to recommend reductions, but not increases, in awards under the plan.

We anticipate that in March 2009, the Atlas America compensation committee will adopt a formula governing 2009 targets for bonus awards.

Discretionary Bonuses—Discretionary bonuses may be awarded to recognize individual and group performance.

Long-Term Incentives

We believe that our long-term success depends upon aligning our executives’ and unitholders’ interests. To support this objective, Atlas America provides our executives with various means to become significant equity holders, including our Long-Term Incentive Plan, which we refer to as our Plan. Our NEOs are also eligible to receive awards under the Atlas America Stock Incentive Plan, which we refer to as the Atlas Plan, the Atlas Energy Resources Long-Term Incentive Plan, which we refer to as the ATN Plan, 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 America compensation committee may recommend grants of equity awards in the form of options and/or phantom units, which generally vest 25% on the third anniversary of the grant date, and 75% on the fourth anniversary.

Grants under Other Plans: As described above, our NEOs who perform services for us and one or more of Atlas America’s publicly-traded subsidiaries may receive stock-based awards under the Atlas Plan, the ATN Plan or the APL Plan.

Supplemental Benefits, Deferred Compensation and Perquisites

We do not provide supplemental benefits for executives and perquisites are discouraged. Atlas America 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 America does not favor employment agreements unless they are required to attract or to retain executives to the organization. It entered into an employment agreement with Mr. E. Cohen in 2004 and, in January 2009, it entered into an employment agreement with Mr. J. Cohen. See “Employment Agreements and Potential Payments Upon Termination or Change of Control.” The Atlas America 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 America’s and our performance during the year.

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Determination of 2008 Compensation Amounts

As described above, after the end of our 2008 fiscal year, the Atlas America compensation committee set the base salaries of our NEOs for the 2009 fiscal year and recommended incentive awards based on the prior year’s performance. In carrying out its function, the Atlas America compensation committee acted in consultation with Mercer.

In determining the actual amounts to be paid to the NEOs, the Atlas America 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 America’s publicly-held subsidiaries for which each NEO provides service; however, the Atlas America compensation committee has the discretion to approve, reject or modify the recommendations. The Atlas America compensation committee noted that our management team had accomplished the following strategic objectives, among others, during fiscal 2008: raised approximately $526 million for APL through issuances of equity and senior unsecured notes, increased natural gas processing capacity and achieved record throughput on both APL’s Appalachia and Mid-Continent pipeline systems. In addition, the Atlas America compensation committee reviewed calculations of Atlas America’s adjusted distributable cash flow and determined that 2008 adjusted distributable cash flow exceeded the pre-determined minimum threshold of 95% of 2007 adjusted distributable cash flow by more than 50%.

Base Salary. Consistent with its preference for having a significant portion of the NEOs’ overall compensation package be incentive compensation, Atlas America’s CEO did not recommend any increases in salaries for 2009.

Annual Incentives.

Performance-Based Bonuses. The maximum amounts payable to each of our NEOs pursuant to the predetermined percentages was as follows: Edward E. Cohen, $8,644,000; Jonathan Z. Cohen, $6,152,000 and Matthew A. Jones, $4,880,000. As described above, our NEOs substantially outperformed the incentive goals set for them and, under normal circumstances, Atlas America would anticipate awarding substantially increased bonuses for 2008. However, the prevailing economic conditions do not constitute normal circumstances and, accordingly, each NEO will receive awards that are substantially less than the maximum award amounts and less than awards made in fiscal 2007. No part of the bonus awards was allocated to us.

Long-Term Incentives. The Atlas America compensation committee determined that it would not recommend any equity-based awards to our NEOs because it felt that previous awards were adequate.

The following table sets forth the compensation allocation for fiscal years 2008, 2007, and 2006 for Atlas Pipeline GP’s Chief Executive Officer and Chief Financial Officer and each of its other most highly compensated executive officers whose allocated aggregate salary and bonus (including amounts of salary and bonus foregone to receive non-cash compensation) exceeded $100,000. As required by SEC guidance, the table also discloses awards under the APL Plan and the Atlas Plan.

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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 ($)
Edward E. Cohen, Chairman of the Board and Chief Executive Officer of Atlas Pipeline GP(8)	2008	$	135,000		—	$	884,449	$	1,385,669		—	$	257,938	(3)	$	2,663,056
	2007	$	405,000		—	$	1,254,901	$	509,167	$	2,250,000	$	253,212		$	4,672,280
	2006	$	180,000	$	360,000	$	674,625	$	84,861		—	$	32,300		$	1,331,786
Matthew A. Jones, Chief Financial Officer of Atlas Pipeline GP	2008	$	135,000		—	$	236,944	$	760,078		—	$	67,713	(4)	$	1,199,734
	2007	$	135,000		—	$	356,912	$	409,128	$	900,000	$	75,062		$	1,875,977
	2006	$	105,000	$	210,000	$	276,546	$	16,972		—	$	7,650		$	616,168
Jonathan Z. Cohen, Vice Chairman of Atlas Pipeline GP	2008	$	90,000		—	$	503,504	$	904,868		—	$	113,488	(5)	$	1,611,860
	2007	$	215,217		—	$	807,707	$	203,667	$	1,434,783	$	153,906		$	2,815,280
	2006	$	190,000		—	$	439,563	$	48,527		—	$	20,400		$	698,490
Robert R. Firth, Chief Operating Officer & President of Atlas Pipeline Mid-Continent(8)	2008	$	250,000		—	$	598,743	$	443,511		—	$	149,468	(6)	$	1,441,721
	2007	$	250,000		—	$	12,370,293	$	443,393	$	50,000	$	118,512		$	13,232,198
	2006	$	250,000	$	150,000	$	1,806,506	$	61,100		—		—		$	2,267,606
Michael Staines, President of Atlas Pipeline GP(8)	2008	$	191,250		—	$	22,631	$	19,228		—	$	8,460	(7)	$	241,569
	2007	$	191,250	$	42,500	$	61,148	$	19,198		—	$	21,770		$	336,136

⁽¹⁾ Represents the dollar amount of (i) expense recognized by us for financial statement reporting purposes with respect to phantom units granted under our Plan; and/or (ii) expense recognized by Atlas Pipeline Partners for financial statement reporting purposes with respect to phantom units granted under the APL Plan and our incentive compensation arrangements, all in accordance with FAS 123R. See note 15 to our consolidated financial statements for an explanation of the assumptions we make for this valuation.

⁽²⁾ Represents the dollar amount of (i) expense recognized by Atlas America for financial statement reporting purposes with respect to options granted under the Atlas Plan; and/or (ii) expense we recognized for financial statement reporting purposes for options granted under our Plan, all in accordance with FAS 123R.

⁽³⁾ Represents payments on DERs of $ 96,838 with respect to the phantom units awarded under the APL Plan and $161,100 with respect to phantom units awarded under our Plan.

⁽⁴⁾ Includes payments on DERs of $ 31,913 with respect to the phantom units awarded under the APL Plan and $ 35,800 with respect to phantom units awarded under our Plan.

⁽⁵⁾ Represents payments on DERs of $48,238 with respect to the phantom units awarded under the APL Plan and $65,250 with respect to phantom units awarded under our Plan.

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⁽⁶⁾ Represents payments on DERs of $68,918 with respect to the phantom units awarded under the APL Plan and its incentive compensation arrangements, and $80,550 with respect to phantom units awarded under our Plan.

⁽⁷⁾ Represents payments on DERs with respect to the phantom units awarded under the APL Plan.

⁽⁸⁾ On January 15, 2009, Eugene N. Dubay was appointed Chief Executive Officer and President of Atlas Pipeline GP and as President of Atlas Pipeline Mid-Continent. On February 20, 2009, Mr. Dubay was appointed Chief Executive Officer and President of Atlas Pipeline Holdings GP.

No awards were granted to our named executive officers under our Plan or the APL Plan in 2008.

Employment Agreements and Potential Payments Upon Termination or Change of Control

Edward E. Cohen

In May 2004, Atlas America entered into an employment agreement with Edward E. Cohen, who currently serves as our Chairman, 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 America 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 America adds 14% 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.

Mr. Cohen’s employment agreement requires him to devote such time to Atlas America 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 $350,000 per year, which may be increased by the Atlas America compensation committee 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. Mr. Cohen’s employment agreement was entered into in 2004, around the time that Atlas America 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 President of Atlas America. 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.

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 America 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 America’s employees, during the three years following his termination, (c) a lump sum amount equal to the cost Atlas America 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 America’s long-term disability plan.

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• Atlas America 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 America’s Board of Directors or Atlas America’s material breach of the agreement. Mr. Cohen must provide Atlas America with 30 days’ notice of a termination by him for good reason within 60 days of the event constituting good reason. Atlas America 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 America 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 America’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 America’s employees, during the three years following his termination, (iii) a lump sum amount equal to the cost Atlas America would incur for life, disability and accident insurance coverage during the three-year period, less the premium charge that is paid by Atlas America’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 America, 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 America’s voting securities or all or substantially all of Atlas America’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;

• Atlas America consummates a merger, consolidation, combination, share exchange, division or other reorganization or transaction with an unaffiliated entity in which either (a) Atlas America’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 Atlas America’s directors immediately before the transaction and Atlas America’s chief executive officer immediately before the transaction continues as the chief executive officer of the surviving entity; or (b) Atlas America’s voting securities immediately prior to the transaction represent less than 60% of the combined voting power immediately after the transaction of Atlas America, 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 America Board members at the beginning of the period cease for any reason to constitute a majority of the Atlas America Board, unless the election or nomination for election by Atlas America’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 America’s stockholders approve a plan of complete liquidation of winding up of Atlas America, or agreement of sale of all or substantially all of Atlas America’s assets or all or substantially all of the assets of Atlas America’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 America 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.

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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, 2008.

Reason for termination	Lump sum severance payment			Benefits(1)		Accelerated vesting of stock awards and option awards(2)		Tax gross- up(3)
Death	$	405,000	(4)	$	—	$	430,200	$	—
Disability		405,000	(4)		5,763		430,200		—
Termination by us without cause		1,612,500	(5)		5,763		430,200		—
Termination by Mr. Cohen for good reason		1,612,500	(5)		5,763		430,200		—
Change of control		1,612,500	(5)		5,763		430,200		688,696
Termination by Mr. Cohen without cause		67,500	(4)		—		430,200		—

(1) Represents rates currently in effect for COBRA insurance benefits for 36 months.

(2) Represents the value of unexercisable option and unvested stock 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, 2008. The payments relating to stock awards are calculated by multiplying the number of accelerated shares or units by the closing price of the applicable stock 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 42.65% combined effective tax rate.

(4) Calculated based on Mr. Cohen’s 2008 base salary.

(5) Calculated based on Mr. Cohen’s average 2008, 2007 and 2006 base salary and bonus.

Jonathan Z. Cohen

In January 2009, Atlas America 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 America 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 America adds 14% 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.

Mr. Cohen’s employment agreement requires him to devote such time to Atlas America 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 America 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.

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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) accrued but unpaid bonus and vacation pay and (b) automatic vesting of all equity-based awards.

• Atlas America 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 America’s board determines, in good faith based upon medical evidence, that he is unable to perform his duties. Upon termination by Atlas America 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 America 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 America 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 America 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 America’s voting securities or all or substantially all of Atlas America’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;

• Atlas America consummates a merger, consolidation, combination, share exchange, division or other reorganization or transaction with an unaffiliated entity in which either (a) Atlas America’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 America’s Chief Executive Officer immediately before the transaction continues as the Chief Executive Officer of the surviving entity; or (b) Atlas America’s voting securities immediately prior to the transaction represent less than 60% of the combined voting power immediately after the transaction of Atlas America, 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 America board members at the beginning of the period cease for any reason to constitute a majority of Atlas America’s board, unless the election or nomination for election by Atlas America’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

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• Atlas America’s stockholders approve a plan of complete liquidation of winding up, or agreement of sale of all or substantially all of Atlas America’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, 2008.

Reason for termination	Lump sum severance payment			Benefits(1)	Accelerated vesting of stock 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)	$	1,224,000	(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 America.

⁽²⁾ Represents the value of unexercisable option and unvested stock 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, 2008. The payments relating to stock awards are calculated by multiplying the number of accelerated shares or units by the closing price of the applicable stock on December 31, 2008.

⁽³⁾ Calculated based on Mr. J. Cohen’s average 2008, 2007 and 2006 base salary and bonus.

Robert R. Firth

Atlas America entered into an employment agreement in July 2004 with Robert R. Firth in connection with APL’s acquisition of Spectrum, pursuant to which he serves as president of APL’s Mid-Continent operations. The agreement expired on July 16, 2007, unless extended or earlier terminated. The agreement provides for initial base compensation of $200,000 per year, subject to increase, but not decrease, at the discretion of the board of directors of Atlas America. Mr. Firth is eligible to receive discretionary bonuses in the discretion of the Atlas America board. Mr. Firth is also entitled to receive awards under APL’s executive group incentive program, described below. Mr. Firth’s current allocation under this program is 40%, but the allocation is subject to change at Mr. Firth’s election.

The agreement restricts Mr. Firth, for 18 months following the expiration of his employment agreement, from engaging in any business in direct competition with Atlas America and located in the counties in which Atlas Pipeline Mid-Continent, LLC maintains operations or in which Mr. Firth worked; soliciting any of Atlas America’s clients; recruiting, soliciting or hiring any of Atlas America’s employees or consultants; or inducing any employee or consultant to terminate its relationship with Atlas America. Pursuant to the terms of the grant agreements related to Mr. Firth’s stock and option awards, upon Mr. Firth’s death or disability, the stock and options awards will automatically vest.

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Our Long-Term Incentive Plan

Our Plan provides performance 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 America’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 or, at the discretion of the compensation committee, cash equivalent to the then fair market value of a common unit. In tandem with phantom unit grants, the compensation committee may grant a DER. The compensation committee determines the vesting period for phantom units. Through December 31, 2008, 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. Through December 31, 2008, 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.

The vesting of both types of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by the compensation committee, although no awards currently outstanding contain any such provision. 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 America 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 participant to receive a common unit upon the vesting of the phantom unit or, at the discretion of the compensation committee, cash equivalent to the value of a common unit. In tandem with phantom unit grants, the compensation committee may grant a DER. The compensation committee determines the vesting period for phantom units. Through December 31, 2008, phantom units granted under the APL Plan generally vested over a 4-year period at the rate of 25% per year.

APL Unit Options. A unit option entitles the participant to purchase our 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. Through December 31, 2008, no unit options had been granted under the APL Plan.

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Each non-employee manager of Atlas Pipeline GP is awarded the lesser of 500 phantom units, with DERs, or that number of phantom units, with DERs, equal to $15,000 divided by the then fair market value of a common unit for each year of service on the managing board. Up to 10,000 phantom units may be awarded to non-employee managers. 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.

The vesting of both types of awards may also be contingent upon the attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by the compensation committee, although no awards currently outstanding contain any such provision. Awards will automatically vest upon a change of control, as defined in the APL Plan.

Executive Group Incentive Program.

In connection with APL’s acquisition of Spectrum, and its retention of certain Spectrum’s executive officers, Atlas America created an executive group incentive program for APL’s Mid-Continent operations. Eligible participants in the executive group incentive program are Robert R. Firth, David D. Hall and such other of APL’s officers as agreed upon by Messrs. Firth and Hall and Atlas America board of directors. The executive group incentive program has three award components: base incentive, additional incentive and acquisition look-back incentive, as follows:

• Base incentive. An award of 29,411 of APL common units on the day following the earlier to occur of the filing of its quarterly report on Form 10-Q for the quarter ending September 30, 2007 or a change in control if the following conditions are met:

• distributable cash flow (defined as earnings before interest, depreciation, amortization and any allocation of overhead from APL, less maintenance capital expenditures on the Spectrum assets) generated by the Spectrum assets, as expanded since APL’s acquisition of them, has averaged at least 10.7%, on an annualized basis, of average gross long term assets (defined as total assets less current assets, closing costs associated with any acquisition and plus accumulated depreciation, depletion and amortization) over the 13 quarters ending September 30, 2007 and

• there having been no more than 2 quarters with distributable cash flow of less than 7%, on an annualized basis, of gross long term assets for that quarter.

Atlas Pipeline issued 29,411 common units under this component.

• Additional incentive. An award of APL’s common units, promptly upon the filing of its September 30, 2007 Form 10-Q, in an amount equal to 7.42% of the base incentive for each 0.1% by which average annual distributable cash flow exceeds 10.7% of average gross long term assets, as described above, up to a maximum of an additional 29,411 common units. 29,411 APL common units were issued under this component.

• Acquisition look-back incentive. If the requirements for the base incentive have been met, an award of APL common units determined by dividing (x) 1.5% of the imputed value of the Elk City system plus 1.0% of the imputed value of all Mid-Continent acquisitions completed before December 31, 2007 that were identified by members of the Mid-Continent executive group by (y) the average closing price of APL common units for the 5 trading days before December 31, 2008. Imputed value of an acquisition is equal to the distributable cash flow generated by the acquired entity during the 12 months ending December 31, 2008 divided by the yield. Yield is determined

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by dividing (i) the sum of APL’s quarterly distributions for the quarter ending December 31, 2008 multiplied by 4 by (ii) the closing price of its common units on December 31, 2008. Atlas Pipeline expects to award 348,620 common units under this component in March 2009.

Atlas Plan

The Atlas Plan authorizes the granting of up to 4.5 million shares of Atlas America common stock to its employees, affiliates, consultants and directors in the form of incentive stock options, non-qualified stock options, stock appreciation rights (“SARs”), restricted stock 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 America common stock on the exercise date and the exercise price, and may be free-standing or tied to grants of options. A deferred unit represents the right to receive one share of Atlas America common stock upon vesting. Awards under the Atlas Plan generally become exercisable as to 25% each anniversary after the date of grant, except that deferred units awarded to our non-executive board members vest 33 ¹/3% on the second, third and fourth anniversaries of the grant, and expire not later than ten years after the date of grant. Units will vest sooner upon a change in control of Atlas America or death or disability of a grantee, provided the grantee has completed at least six months service.

As required by SEC guidelines, the following table discloses awards under our Plan as well as the APL Plan and the Atlas Plan.

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
Edward E. Cohen	1,012,500	(1)	—		$	11.32	7/1/2015	—		$	—
	75,000	(2)	225,000	(3)	$	32.53	1/29/2018	15,000	(4)	$	90,000	(5)
	—		500,000	(6)	$	22.56	11/10/2016	90,000	(7)	$	340,200	(8)
Matthew A. Jones	202,500	(9)	67,500	(10)	$	11.32	7/1/2015	—		$	—
	30,000	(11)	90,000	(12)	$	32.53	1/29/2018	6,250	(13)	$	37,500	(5)
	—		100,000	(14)	$	22.56	11/10/2016	20,000	(15)	$	75,600	(8)
Jonathan Z. Cohen	675,000	(16)	—		$	11.32	7/1/2015	—		$	—
	60,000	(17)	180,000	(18)	$	32.53	1/29/2018	10,625	(19)	$	63,750	(5)
	—		200,000	(20)	$	22.56	11/10/2016	45,000	(21)	$	170,100	(8)
Robert R. Firth	16,875	(22)	16,875	(23)	$	11.32	7/1/2015	12,250	(24)	$	73,500	(5)
	—		360,000	(25)	$	22.56	11/10/2016	45,000	(26)	$	170,100	(8)
Michael L. Staines	12,656	(27)	4,220	(28)	$	11.32	7/1/2015	1,000	(29)	$	6,000	(5)

⁽¹⁾ Represents 1,012,500 options to purchase Atlas America stock, granted on 7/1/05 in connection with its spin-off from Resource America, which vested immediately. Reflects a 3-for-2 stock split which was effected on June 2, 2008.

⁽²⁾ Represents 75,000 options to purchase Atlas America stock, granted on 1/29/08. Reflects a 3-for-2 stock split which was effected on June 2, 2008.

⁽³⁾ Represents options to purchase Atlas America stock, which vest as follows: 1/29/09 – 75,000, 1/29/09 – 75,000 and 1/29/10 – 75,000.

⁽⁴⁾ Represents Atlas Pipeline Partners phantom units, which vest as follows: 3/16/09 - 5,000; 11/1/09 – 5,000 and 11/1/10 – 5,000.

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⁽⁵⁾ Based on closing market price of Atlas Pipeline Partners common units on December 31, 2008 of $ 6.00.

⁽⁶⁾ Represents our options, which vest as follows: 11/10/09 – 125,000 and 11/10/10 – 375,000.

⁽⁷⁾ Represents our phantom units, which vest as follows: 11/10/09 – 22,500 and 11/10/10 – 67,500.

⁽⁸⁾ Based on closing market price of our common units on December 31, 2008 of $ 3.78.

⁽⁹⁾ Represents 202,500 options to purchase Atlas America stock, granted on 7/1/05 in connection with its spin-off from Resource America. Reflects a 3-for-2 stock split which was effected on June 2, 2008.

⁽¹⁰⁾ Represents options to purchase Atlas America stock, which vest as follows: 7/1/09 – 67,500.

⁽¹¹⁾ Represents 30,000 options to purchase Atlas America stock, granted on 1/29/08. Reflects a 3-for-2 stock split which was effected on June 2, 2008.

⁽¹²⁾ Represents options to purchase Atlas America stock, which vest as follows: 1/29/09 – 30,000, 1/29/09 – 30,000 and 1/29/10 – 30,000.

⁽¹³⁾ Represents Atlas Pipeline Partners phantom units, which vest as follows: 3/16/09 – 3,750; 11/1/09 – 1,250 and 11/1/10 – 1,250.

⁽¹⁴⁾ Represents our options, which vest as follows: 11/10/09 – 25,000 and 11/10/10 – 75,000.

⁽¹⁵⁾ Represents our phantom units, which vest as follows: 11/10/09 – 5,000 and 11/10/10 – 15,000.

⁽¹⁶⁾ Represents 675,000 options to purchase Atlas America stock, granted on 7/1/05 in connection with its spin-off from Resource America, which vested immediately. Reflects a 3-for-2 stock split which was effected on June 2, 2008.

⁽¹⁷⁾ Represents 60,000 options to purchase Atlas America stock, granted on 1/29/08. Reflects a 3-for-2 stock split which was effected on June 2, 2008.

⁽¹⁸⁾ Represents options to purchase Atlas America stock, which vest as follows: 1/29/09 – 60,000, 1/29/09 – 60,000 and 1/29/10 – 60,000.

⁽¹⁹⁾ Represents Atlas Pipeline Partners phantom units, which vest as follows: 3/16/09 – 3,125; 11/1/09 – 3,750 and 11/1/10 – 3,750.

⁽²⁰⁾ Represents our options, which vest as follows: 11/10/09 – 50,000 and 11/10/10 – 150,000.

⁽²¹⁾ Represents our phantom units, which vest as follows: 11/10/09 – 11,250 and 11/10/10 – 33,750.

⁽²²⁾ Represents 16,875 options to purchase Atlas America stock, granted on 7/1/05 in connection with its spin-off from Resource America. Reflects a 3-for-2 stock split which was effected on June 2, 2008.

⁽²³⁾ Represents options to purchase Atlas America stock, which vest as follows: 7/1/09 – 16,875.

⁽²⁴⁾ Represents Atlas Pipeline Partners phantom units, which vest as follows: 1/24/09 – 5,750, 3/16/09 – 750 and 1/24/10 – 5,750.

⁽²⁵⁾ Represents our options, which vest as follows: 11/10/09 – 90,000 and 11/10/10 – 270,000.

⁽²⁶⁾ Represents our phantom units, which vest as follows: 11/10/09 – 11,250 and 11/10/10 – 33,750.

⁽²⁷⁾ Represents 12,656 options to purchase Atlas America stock, granted on 7/1/05 in connection with its spin-off from Resource America. Reflects a 3-for-2 stock split which was effected on June 2, 2008.

⁽²⁸⁾ Represents options to purchase Atlas America stock, which vest as follows: 7/1/09 – 4,220.

⁽²⁹⁾ Represents Atlas Pipeline Partners phantom units, which vest as follows: 3/16/09 – 1,000.

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2008 OPTION EXERCISES AND STOCK VESTED TABLE

	Stock Awards
Name	Number of Shares Acquired on Vesting		Value Realized on Vesting ($)
Edward E. Cohen	16,250	(1)	$	557,500
Matthew A. Jones	5,000	(1)	$	176,562
Jonathan Z. Cohen	10,625	(1)	$	353,100
Robert R. Firth	6,500	(2)	$	280,892
Michael L. Staines	3,000	(1)	$	124,160

⁽¹⁾ Represents awards under the APL Plan.

⁽²⁾ Represents options to purchase Atlas America common stock.

DIRECTOR COMPENSATION TABLE

Name	Fees Earned or Paid in Cash ($)		Stock Awards ($)(1)			All Other Compensation ($)(2)		Total ($)
William G. Karis	$	35,000	$	(2,052	)(3)	$	1,642	$	34,590
Jeffrey C. Key	$	35,000	$	(2,052	)(3)	$	1,642	$	34,590
Harvey G. Magarick	$	35,000	$	(2,052	)(3)	$	1,642	$	34,590

⁽¹⁾ Represents the dollar amount of expense we recognized for financial statement reporting purposes with respect to phantom units granted under our Plan in accordance with FAS 123R.

⁽²⁾ Represents payments on DERs with respect to the phantom units awarded under our Plan.

⁽³⁾ Represents 1,050 phantom units granted to each of Messrs. Karis, Key and Magarick. The shares vest one-quarter on each of the first through fourth anniversaries of the date of grant. The vesting schedule for the shares is as follows: 11/10/09 – 350; 11/10/10 – 350; 11/10/11 – 225; and 11/10/12 – 125. Also includes an award of 500 phantom units to each director on 11/10/08 with a fair market value of $8.61.

Our general partner does not pay additional remuneration to officers or employees of Atlas America who also serve as managing board members. In fiscal year 2008, 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 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 February 23, 2009, 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.

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Name of Beneficial Owner	Common Units		Percent of Class
Members of the Board of Directors
Edward E. Cohen	590,000	(1)	2.09	%
Jonathan Z. Cohen	246,000	(2)	*
Eugene N. Dubay	100,500	(3)	*
Matthew A. Jones	120,000	(4)	*
Robert R. Firth	410,170	(5)	1.46	%
William G. Karis	1,400	(6)	*
Jeffrey C. Key	1,400	(6)	*
Harvey G. Magarick	1,400	(6)	*
Executive Officers
Sean P. McGrath	22,500	(7)	*
Lisa Washington	11,000	(8)	*
Executive officers and board of directors as a group (10 persons)	1,504,370		5.16	%
Other Owners of More than 5% of Outstanding Units
Atlas America, Inc.	17,808,109		64.4	%
Swank Capital, LLC	3,022,218	(9)	11.05	%
Leon G. Cooperman	1,522,256	(10)	5.50	%

* Less than 1%.

⁽¹⁾ Includes 90,000 phantom units and 500,000 unit options granted pursuant to our Long-Term Incentive Plan (the “Plan”) on November 10, 2006. 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. The phantom units and unit options vest 25% on the third anniversary of the grant, with the remaining 75% vesting on the fourth anniversary of the grant.

⁽²⁾ Includes 45,000 phantom units and 200,000 unit options granted pursuant to our Plan on November 10, 2006. 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. The phantom units and unit options vest 25% on the third anniversary of the grant, with the remaining 75% vesting on the fourth anniversary of the grant.

⁽³⁾ Includes 100,000 unit options granted under our Plan pursuant to the terms of Mr. Dubay’s employment agreement on January 15, 2009. 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. The unit options vest 25% on each anniversary of the grant.

⁽⁴⁾ Includes 20,000 phantom units and 100,000 unit options granted pursuant to our Plan on November 10, 2006. 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. The phantom units and unit options vest 25% on the third anniversary of the grant, with the remaining 75% vesting on the fourth anniversary of the grant.

⁽⁵⁾ Includes 45,000 phantom units and 360,000 unit options granted pursuant to our Plan on November 10, 2006. 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. The phantom units and unit options vest 25% on the third anniversary of the grant, with the remaining 75% vesting on the fourth anniversary of the grant. As of February 20, 2009, Mr. Firth no longer serves as a member of our board of directors or as our President and Chief Operating Officer.

⁽⁶⁾ Includes 1,400 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: 11/10/09 – 350; 11/10/10 – 350; 11/10/11 – 225; and 11/10/12 – 125.

⁽⁷⁾ Includes 7,500 phantom units and 15,000 unit options granted pursuant to our Plan on November 10, 2006. 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. The phantom units and unit options vest 25% on the third anniversary of the grant, with the remaining 75% vesting on the fourth anniversary of the grant.

⁽⁸⁾ Includes 1,000 phantom units and 10,000 unit options granted pursuant to our Plan on November 10, 2006. 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. The phantom units and unit options vest 25% on the third anniversary of the grant, with the remaining 75% vesting on the fourth anniversary of the grant.

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⁽⁹⁾ This information is based on a Schedule 13G/A which was filed with the SEC on February 13, 2009. The address for Swank Capital, LLC is 330 Oak Lawn Avenue, Suite 650, Dallas, TX 75219.

⁽¹⁰⁾ This information is based on a Schedule 13G/A which was filed with the SEC on February 4, 2009. The address for Mr. Cooperman is 88 Pine Street, Wall Street Plaza—31st Floor, New York, NY 10005.

Equity Compensation Plan Information

The following table contains information about our Plan as of December 31, 2008:

	(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	226,300		n/a
Equity compensation plans approved by security holders – unit options	1,215,000	$	22.56
Equity compensation plans approved by security holders – Total	1,441,300			657,650

The following table contains information about the APL Plan as of December 31, 2008:

	(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	126,565	n/a	155,009

The following table contains information about the Atlas Plan as of December 31, 2008:

	(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	12,232		n/a
Equity compensation plans approved by security holders – options	3,495,351	$	16.97
Equity compensation plans approved by security holders – Total	3,507,583			838,160

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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 America. 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 America 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 America 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 $1.5 million for the year ended December 31, 2008 for compensation and benefits related to their employees. Atlas Pipeline GP believes that the method utilized in allocating costs to APL is reasonable.

APL’s omnibus agreement and natural gas gathering agreements with Atlas Energy and its affiliates were not the result of arms-length negotiations and, accordingly, we cannot ensure that APL could have obtained more favorable terms from independent third parties similarly situated. However, since these agreements principally involve the imposition of obligations on Atlas Energy and its affiliates, we do not believe that APL could obtain similar agreements from independent third parties.

The board of directors of our general partner has determined that Messrs. 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, 2008 and 2007 by our principal accounting firm, Grant Thornton LLP, are set forth below:

	2008		2007
Audit fees(1)	$	2,140,738	$	1,795,631
Audit related fees		—		—
Tax fees(2)		191,975		209,568
Total aggregate fees billed	$	2,332,713	$	2,005,199

⁽¹⁾ Represents the aggregate fees recognized in 2008 and 2007 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 2008 and 2007.

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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

No schedules are required to be presented.

(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.
10.2(e)	Amendment No. 4 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.
10.2(f)	Amendment No. 5 to Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.
10.3	Second Amended and Restated Certificate of Designation for 12% Cumulative Convertible Preferred Units of Atlas Pipeline Partners, L.P.
10.4	Certificate of Designation for 12% Cumulative Convertible Class B Preferred Units of Atlas Pipeline Partners, L.P.
10.5	Common Unit Purchase Agreement dated June 17, 2008, by and between Atlas America, Inc. and Atlas Pipeline Holdings, L.P.(5)
10.6	Long-Term Incentive Plan
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.

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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.

	ATLAS PIPELINE HOLDINGS, L.P.
	By:	Atlas Pipeline Holdings GP, LLC, its General Partner
March 2, 2009	By:	/s/ EUGENE N. DUBAY
		Chief Executive Officer & President

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 2, 2009.

/s/ EDWARD E. COHEN	Chairman of the Board of the General Partner
Edward E. Cohen
/s/ JONATHAN Z. COHEN	Vice Chairman of the Board of the General Partner
Jonathan Z. Cohen
/s/ EUGENE N. DUBAY	Chief Executive Officer, President, and Director of the General Partner
Eugene N. Dubay
/s/ MATTHEW A. JONES	Chief Financial Officer and Director of the General Partner
Matthew A. Jones
/s/ SEAN P. MCGRATH	Chief Accounting Officer of the General Partner
Sean P. McGrath
/s/ LISA WASHINGTON	Chief Legal Officer and Secretary of the General Partner
Lisa Washington
/s/ WILLIAM G. KARIS	Director of the General Partner
William G. Karis
/s/ JEFFREY C. KEY	Director of the General Partner
Jeffrey C. Key
/s/ HARVEY G. MAGARICK	Director of the General Partner
Harvey G. Magarick

155