Atlas Energy 10-K 2007 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, 2007

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  x    No  ¨

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

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

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

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

Large accelerated filer  ¨    Accelerated filer  x    Non-accelerated filer  ¨

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 equity securities held by non-affiliates of the registrant, based upon the closing price of $41.85 per common limited partner unit on June 30, 2007, was approximately $150.7 million.

DOCUMENTS INCORPORATED BY REFERENCE: None

ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES

INDEX TO ANNUAL REPORT

ON FORM 10-K

		Page
PART I
Item 1:	Business	3
Item 1A:	Risk Factors	23
Item 1B:	Unresolved Staff Comments	44
Item 2:	Properties	44
Item 3:	Legal Proceedings	44
Item 4:	Submission of Matters to a Vote of Security Holders	45
PART II
Item 5:	Market for Registrant’s Common Equity and Related Unitholder Matters	45
Item 6:	Selected Financial Data	47
Item 7:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	51
Item 7A:	Quantitative and Qualitative Disclosures About Market Risk	77
Item 8:	Financial Statements and Supplementary Data	83
Item 9:	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	121
Item 9A:	Controls and Procedures	121
PART III
Item 10:	Directors, Executive Officers and Corporate Governance	125
Item 11:	Executive Compensation	129
Item 12:	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	139
Item 13:	Certain Relationships and Related Transactions, and Director Independence Matters	141
Item 14:	Principal Accountant Fees and Services	142
PART IV
Item 15:	Exhibits and Financial Statement Schedules	142
SIGNATURES		144

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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 owns:

• 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 “—General” under “—Atlas Pipeline Partners, L.P.”), we, the holder of all of the incentive distribution rights in APL, had 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 (“IDR Adjustment Agreement”); and

• 5,476,253 common units of APL, representing approximately 14.1% of the outstanding common units of APL, or a 13.5% ownership interest in APL.

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.

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.

Atlas Pipeline Partners, L.P.

General

APL is a publicly-traded midstream energy services provider engaged in the transmission, gathering and processing of natural gas. APL is a leading provider of natural gas gathering services in the Anadarko, Arkoma, Golden Trend and Permian Basins in the southwestern and mid-continent United States and the

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Appalachian Basin in the eastern United States. In addition, APL is a leading provider of natural gas processing services in Oklahoma and Texas. APL also provides interstate gas transmission services in southeastern Oklahoma, Arkansas and southeastern Missouri. APL conducts its business 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 400 million cubic feet per day (“MMcfd”);

• seven natural gas processing plants with aggregate capacity of approximately 750 MMcfd and one treating facility with a capacity of approximately 200 MMcfd, located in Oklahoma and Texas; and

• 7,870 miles of active natural gas gathering systems located in Oklahoma, Arkansas and Texas, which transport gas from wells and central delivery points in the Mid-Continent region to APL’s natural gas processing plants or Ozark Gas Transmission.

Through its Appalachian operations, APL owns and operates 1,600 miles of active natural gas gathering systems located in eastern Ohio, western New York and western Pennsylvania. Through an omnibus agreement and other agreements between APL and Atlas America and its affiliates, 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 a 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:

• On July 27, 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”). The Chaney Dell system includes 3,470 miles of gathering pipeline and three processing plants, while the Midkiff/Benedum system includes 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. 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 will have an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system beginning on June 15, 2008 and ending on November 1, 2008, and up to an additional 7.4% interest beginning on 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% interest if fully exercised. APL will manage and control the Midkiff/Benedum system regardless of whether Pioneer exercised the purchase options. 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

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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. 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. APL funded the remaining purchase price from an $830.0 million 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; 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 7,300 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 that 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.

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 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 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.

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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 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 risk”) that the aggregate proceeds from the sale of the processed natural gas and NGLs could be less than the

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amount that it paid for the unprocessed natural gas. However, because the natural gas received by APL’s Elk City/Sweetwater and Chaney Dell systems, which have keep-whole contracts, is generally low in liquids content and meets 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 8,670 miles of intrastate natural gas gathering systems, including approximately 800 miles of inactive pipeline, located in Oklahoma, Arkansas, southeastern Missouri, northern and western Texas and the Texas panhandle, and seven 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 7,300 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 Ozark Gas Transmission, 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 and Natural Gas Pipeline Company of America.

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 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 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 numerous interconnects with intrastate pipelines, including Enogex, BP’s Vastar gathering system, Arkansas Oklahoma Gas Corporation, Arkansas Western Gas Company, ONEOK Gas Transmission and APL’s Ozark Gas Gathering system.

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, 2007, the combined gathering systems had approximately 3,470 miles of natural gas gathering pipelines with approximately 3,260 receipt points. The Chaney Dell system has approximately 825 active contracts with producers.

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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 450 miles of natural gas pipelines located in the Anadarko Basin in western Oklahoma and the Texas panhandle, including the Springer and Granite Wash plays. The Elk City and Sweetwater gathering system connects to over 470 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, 2007, consists of approximately 2,500 miles of gas gathering pipeline 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. The Midkiff/Benedum operations provide gathering and processing under approximately 150 contracts, including one with Pioneer.

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% beginning on June 15, 2008 and ending on November 1, 2008, and 7.4% beginning on June 15, 2009 and ending on November 1, 2009, for an aggregate ownership interest of 49.2%. The gas sales and purchase agreement requires that all Pioneer wells in the proximity of the Midkiff/Benedum system are 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 300 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, 2007, the gathering system had approximately 1,080 miles of active pipeline with approximately 690 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.

Processing and Treating Plants

Chaney Dell.The Chaney Dell system processes natural gas through the Waynoka and Chester plants, both of which are active cryogenic natural gas processing facilities. The Chaney Dell system’s processing operations have total capacity of approximately 230 MMcfd. The Waynoka processing plant, which began operations in December 2006 and became fully operational in July 2007, contains the most technologically advanced controls, systems and processes and demonstrates strong NGL recovery rates, including approximately 90% of ethane recovery and greater than 98% recovery of all other NGLs. As a result, APL is able to process volumes far more efficiently than were previously processed at Chaney Dell’s lean oil plants. Chaney Dell has a third plant, the Chaney Dell plant, which was idled in the fourth quarter of 2006 when the Waynoka plant began operations. Because of drilling activity in the Anadarko Basin, the Waynoka and Chester plants have been operating at high utilization rates. As a result, APL reactivated the Chaney Dell plant in early 2008, which added 22 MMcfd of additional processing capacity. APL’s Chaney/Dell operations gather and process natural gas for approximately 380 producers.

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Midkiff/Benedum. The Midkiff/Benedum system processes natural gas through the Midkiff and Benedum processing plants. The Midkiff plant is a 130 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 173MMcfd and gather and process natural gas for approximately 120 producers.

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’s Velma operations gather and process natural gas for approximately 135 producers. 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. APL’s Elk City/Sweetwater operations gather and process gas for more than 160 producers. 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 120 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. The Sweetwater plant is currently running near full capacity. As a result, APL is currently in the process of expanding the processing capacity at the plant by 50% to a total processing capacity of 180 MMcfd; the expansion is expected to be completed during 2008. Through this expansion, APL will extend the system’s reach into the Granite Wash play in the Roberts 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 15 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.

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, 2007, 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.

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Natural Gas and NGL Marketing

APL typically sells natural gas to purchasers at the tailgate of its processing plants and at various delivery points on Ozark Gas Transmission and Ozark Gas Gathering. The Velma plant has access to ONEOK Gas Transportation, an intrastate pipeline, and Southern Star Central Gas Pipeline, an interstate pipeline, and APL currently sells the majority of its natural gas to Conoco Phillips and Oilco Gas Co. at the average of ONEOK Gas Transportation and Southern Star Central Gas Pipeline first-of-month indices as published inInside FERC. The Elk City/Sweetwater plants have access to five major interstate and intrastate downstream pipelines: Natural Gas Pipe Line of America, Panhandle Eastern Pipeline Co., CenterPoint Energy Gas Transmission Company, Northern Natural Gas Company, ANR Pipeline Company and ONEOK Gas Transmission. At the Elk City/Sweetwater plants, APL sells substantially all of its natural gas to ONEOK Energy Marketing, based on first-of-month index pricing. Ozark Gas Gathering gas prices are generally based on CenterPoint Energy Gas Transmission index as published inInside FERC and natural gas sales have historically been to Eagle Energy Partners. The Chaney Dell plants have access to Panhandle Eastern Pipeline Co. and Southern Star Central Gas Pipeline and APL currently sells substantially all of its natural gas to Tenaska Marketing Ventures, Constellation Energy and ONEOK Energy Marketing based on first-of-month index pricing. The Midkiff/Benedum plants have access to Northern Natural Gas Company and El Paso Pipeline Company and APL currently sells substantially all of its natural gas to Tenaska Marketing Ventures, Eagle Energy Partners, Odyssey Energy Services and NGTS LP based on first-of-month index pricing.

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 October 1, 2008 and the Chaney Dell and Midkiff/Benedum agreements have initial terms expiring September 1, 2009. NGLs under the contracts 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 SemCrude L.P. and EnerWest Trading Company LLC. Condensate collected at the Elk City/Sweetwater plants and around the Elk City/Sweetwater plants is currently sold to Petro Source Partners L.P. Condensate collected at the Chaney Dell plants and around the Chaney Dell plants is currently sold to Plains Marketing. Condensate collected at the Midkiff/Benedum plants and around the Midkiff/Benedum plants 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 hedging 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 hedges 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 hedges in revenue when it sells the associated physical residue natural gas or NGLs. Any gain or loss realized as a result of hedging is substantially offset in the market when APL sells the physical residue natural gas or NGLs. The majority of APL’s hedges are characterized as cash flow hedges as defined in Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.” APL determines gains or losses on open and closed hedging transactions as the difference between the hedge price and the physical price. This mark-to-market methodology uses daily closing NYMEX prices when applicable and an internally-generated algorithm for hedged commodities that are not traded on a market. To insure that these financial instruments will be used solely for hedging price risks and not for speculative purposes, APL has established a hedging committee to review its hedges for compliance with its hedging policies and procedures. APL’s revolving credit facility prohibits speculative hedging and limits its overall hedge position to 80% of its equity volumes.

For additional information on APL’s hedging activities and a summary of its outstanding hedging instruments as of December 31, 2007, please see Item 7A, “Quantitative and Qualitative Disclosures About Market Risk.”

APL’s Appalachian Basin Operations

APL owns and operates approximately 1,600 miles of intrastate gas gathering systems located in eastern Ohio, western New York and western Pennsylvania. APL’s Appalachian operations serve approximately 6,720 wells with an average throughput of 68.7 MMcfd of natural gas for the year ended December 31, 2007. 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. 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 64.0% ownership interest in us, 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, 2007, APL connected 3,720 new wells to its Appalachian gathering system, 685 of which were added through acquisitions of other gathering systems. For the year ended December 31, 2007, APL connected 874 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, 2007, APL received gathering fees averaging $1.35 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 64.0% 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 currently owns 49.4% of Atlas Energy and, through its ownership interest in us, also owns an ownership interest in APL.

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 6,100 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, 2007, Atlas Energy and its affiliates raised $363.3 million from investors and drilled 1,014 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 systems. In December 2006, in connection with the completion of the initial public offering of, and Atlas

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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 64.0% 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

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in southeastern Ohio and in Fayette County, Pennsylvania, APL receives a fee of $0.80 per Mcf. Under the third 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 Duke Energy Field Services, ONEOK Field Services, Enogex, Inc., Enbridge, Inc., Hiland Partners, 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 interstate system is the nearest direct competitor.

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, 2007, APL connected 38 third-party wells.

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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 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 those services 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; 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 APL’s 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

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certain facilities. APL’s gas gathering operations currently are not subject to regulation by the New York Public Service Commission. APL’s 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 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 to 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 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; 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 is 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 are 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, 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

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operations, and potentially criminal enforcement actions. APL likely will be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe, however, that APL’s operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to APL than to any other similarly situated companies.

Water Discharges. APL’s operations are subject to the Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state and federal waters. The discharge of pollutants is prohibited unless authorized by a permit or other agency approval. The Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Any unpermitted release of pollutants from APL’s pipelines or facilities could result in administrative, civil and criminal penalties as well as significant remedial obligations.

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 existing rules has not had a material adverse effect on APL’s operations but there is no assurance that this trend 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, 2007, our assets consisted principally of our ownership interests in APL and we maintained no separate properties. As of December 31, 2007, APL’s principal facilities in Appalachia include approximately 1,600 miles of 2 to 12 inch diameter pipeline. APL’s principal facilities in the Mid-Continent

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area consist of seven natural gas processing plants, one treating facility, and approximately 8,670 miles of active and inactive 2 to 42 inch diameter pipeline. Substantially all of APL’s gathering systems and transmission 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 373 people at December 31, 2007 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 atwww.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 atwww.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.

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The NYSE requires the chief executive officer of each listed company to certify annually that he is not 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 2007 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 is therefore completely dependent upon the ability of APL to make distributions to its partners.

The amounts of cash that APL generates may not be sufficient for it to pay distributions 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 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;

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• fuel conservation measures;

• alternate fuel requirements;

• 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 is solely dependent on its ability to generate sufficient operating surplus with respect to that quarter.

Our and APL’s debt levels and restrictions in our and APL’s credit facilities could limit our ability to 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.

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.

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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, the amount of distributions we are able to make 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;

• 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 entitles 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.

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

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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.

We are entitled to receive incentive distribution from APL with respect to any particular quarter only in the event that 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

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• 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, 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.

• 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 our 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, the amount of distributions paid under APL’s cash distribution policy and the decision 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 is completely dependent 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.

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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, which in turn may impact the available cash that we have to distribute to our unitholders. The incurrence of additional debt to finance its growth strategy would result in increased interest expense to APL, which in turn may impact the available cash that we have to distribute to our unitholders.

We are largely dependent 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 will be 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 are applicable to us because we control the general partner through our ability to elect all of its directors. While there may be circumstances in which these fiduciary duties may be satisfied while allowing us to 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

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for its 2.0% general partner interest and the incentive distribution rights and would lose its ability to manage APL. While the common units or cash we would receive are intended under the terms of APL’s partnership agreement to fully compensate us in the event such an exchange is required, the value of these common units or investments we make with the cash over time may not be equivalent to the value of the general partner interest and the incentive distribution rights had we retained them.

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

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

Cost reimbursements due 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 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 64.0% of our units at December 31, 2007, 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 will 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 64.0% of our outstanding units at December 31, 2007, 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

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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.

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

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remove or replace our general partner, to approve some amendments to the limited partnership agreement or to take other action under our limited partnership agreement constituted participation in the “control” of our business.

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

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

Risks Related to Our Conflicts of Interest

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

Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, including APL’s general partner, on the one hand, and APL and its limited partners, on the other hand. The directors and officers of Atlas Pipeline GP have fiduciary duties to manage APL in a manner beneficial to us, its owner. At the same time, these directors and officers have a fiduciary duty to manage APL in a manner beneficial to APL and its limited partners. The managing board of APL or its conflicts committee will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.

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

• 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.

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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 will prohibit 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 distribution.

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.

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• 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. In that case, 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 its employees 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 and overhead spent.

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

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

• 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.

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In order to become a limited partner of our partnership, our unitholders are required to agree to be bound by the provisions in the partnership agreement, including the provisions discussed above.

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, 2007, Atlas America owns approximately 64.0% 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 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

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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 distribution to our unitholders.

APL’s profitability 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 would result in a change to our gross margin for the twelve-month period ended December 31, 2008, excluding the effect of minority interests in APL’s net income, of approximately $3.7 million. Additionally, changes in natural gas prices may indirectly impact APL’s profitability since prices can influence drilling activity and well operations and thus 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 is therefore completely dependent upon the ability of APL to make distributions to its partners,” under “Risks Relating to Our Business”. 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 hedging strategies may not be sufficient to offset price volatility risk and, in any event, do not cover all of the throughput volumes subject to percentage-of-proceeds contracts. Moreover, hedges are subject to inherent risks, which we describe in “— APL’s hedging 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 reducing 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. 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, geological considerations, governmental regulation and the availability and cost of capital. 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 gas.

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.

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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, 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. We expect to derive a material portion of APL’s 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 ours. Moreover, APL’s agreements with most of the drillers and operators with which its Mid-Continent operations do business do not require them to dedicate significant amounts of undeveloped acreage to APL’s systems. As a result, 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, 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 2007, Chesapeake Energy Corporation, Pioneer, Conoco Phillips, Sanguine Gas Exploration, LLC, St. Mary Land and Exploration Company, XTO Energy Inc., Henry Petroleum, L.P. and Senex Pipeline Company 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.

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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. Duke Energy Field Services, LLC, ONEOK, Inc., Carrera Gas Company, Cimmarron Transportation, LLC and Enogex, Inc. 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. and Enogex Inc. operate competing gathering systems and processing plants. CenterPoint Energy, Inc.’s interstate system is the nearest 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;

• an inability to integrate successfully or timely the businesses APL acquires;

• the assumption of unknown liabilities;

• limitations on rights to indemnity from the seller;

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• 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 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.

APL acquired the Chaney Dell and the Midkiff/Benedum systems in July 2007 and is currently in the process of integrating their operations with their own. APL also has an active, on-going program to identify other 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, as well as any operations APL may acquire in the future, 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 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 acquired the Chaney Dell and Midkiff/Benedum systems with the expectation that combining them with its existing operations will result in benefits, including, among other things, benefits from organic growth and synergies, increased scale and presence in the Mid-Continent area, expansion of relationships with top producers and increased geographic diversification. There can be no assurance that APL will realize any of these benefits or that the acquisition will not result in the deterioration or loss of its business. In addition, APL investment in the interconnection of its Elk City/Sweetwater and Chaney Dell systems and the additional overhead costs APL 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 APL’s operations could harm its business or future prospects, and result in significant decreases in APL’s 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.

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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 this acquisition, 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 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.

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.

If APL is unable to obtain new rights-of-way or the cost of renewing existing rights-of-way increases, then it may be unable to fully execute its growth strategy and 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.

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

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 interpretations of existing laws, could subject APL 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.

Nonetheless, 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 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 our 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.

Rate-making policies by FERC 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;

• construction of new facilities;

• acquisition, extension or abandonment of services or facilities;

• accounts and records; 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 can impair Ozark Gas Transmission’s ability to compete for business, the costs it incurs in its operations, 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’s fail to comply with all applicable FERC administered statutes, rules, regulations and orders, it could be subject to substantial penalties and fines. Under the recently enacted Energy Policy Act, 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;

41

• 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.

We do 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;

42

• 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;

• 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 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 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 hedging 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 hedging activities will vary in scope based upon the level and volatility of natural gas and NGL prices and other changing market conditions. APL’s hedging activity may fail to protect or could harm it because, among other things:

• hedging can be expensive, particularly during periods of volatile prices;

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

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

• the party owing money in the hedging 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not Applicable.

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, 2007.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED UNITHOLDER MATTERS

Our common units are listed on the New York Stock Exchange under the symbol “AHD”. At the close of business on February 27, 2008, the closing price for the common units was $32.04 and there were 41 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 period from July 26, 2006, the closing date of our initial public offering, to December 31, 2007:

	High		Low		Distributions Declared(1)
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
2006
Fourth Quarter	$	23.90	$	20.65	$	0.25
Third Quarter	$	23.35	$	20.55	$	0.17

⁽¹⁾ The distribution for the third quarter of 2006 represents a pro-rated distribution of $0.24 per common limited partner unit for the period from July 26, 2006 through September 30, 2006.

For a description of our recent sale of unregistered securities, see our current report on Form 8-K filed July 30, 2007.

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.

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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.

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 Stockholder 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. The general partner’s incentive distributions declared for the year ended December 31, 2007, after the allocation of $9.9 million of incentive distribution rights back to APL, were $15.9 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 Stockholder Matters”.

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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. 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, 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.

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, 2007, 2006 and 2005 and at December 31, 2007 and 2006 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, 2005, 2004 and 2003 and for the years ended December 31, 2004 and 2003 from our financial statements, which are not included within this report.

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	Years Ended December 31,
	2007(1)			2006(2)			2005(3)			2004(4)			2003
	(in thousands, except per unit and operating data)
Statement of operations data:
Revenue:
Natural gas and liquids	$	761,118		$	391,356		$	338,672		$	72,364		$	—
Transportation, compression and other fees		81,785			60,924			30,309			18,800			15,651
Other income (loss)		(174,084	)		12,781			2,519			127			98
Total revenue and other income (loss)		668,819			465,061			371,500			91,291			15,749
Costs and expenses:
Natural gas and liquids		587,524			334,299			288,180			58,707			—
Plant operating		34,667			15,722			10,557			2,032			—
Transportation and compression		13,484			10,753			4,053			2,260			2,421
General and administrative		64,561			23,474			13,608			4,642			1,662
Depreciation and amortization		50,982			22,994			13,954			4,471			1,770
Loss (gain) on arbitration settlement, net		—			—			138			(1,457	)		—
Interest		62,629			24,726			14,175			2,301			258
Minority interests(5)		3,940			118			1,083			—			—
Minority interest in APL(6)		(133,321	)		16,335			13,447			10,941			5,066
Total costs and expenses		684,466			448,421			359,195			83,897			11,177
Net income (loss)		(15,647	)		16,640			12,305			7,394			4,572
Premium on preferred unit redemption		—			—			—			(400	)		—
Net income (loss) attributable to common limited partners/owners	$	(15,647	)	$	16,640		$	12,305		$	6,994		$	4,572
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		$	4,572
Portion applicable to common limited partners’ interest (period subsequent to the initial public offering on July 26, 2006)		(15,647	)		6,404			—			—			—
Net income (loss) attributable to common limited partners/owners	$	(15,647	)	$	16,640		$	12,305		$	6,994		$	4,572
Net income (loss) attributable to common limited partners per unit:
Basic	$	(0.66	)	$	0.30
Diluted(7)	$	(0.66	)	$	0.30
Balance sheet data (at period end):
Property, plant and equipment, net	$	1,748,661		$	607,097		$	445,066		$	175,259		$	29,628
Total assets		2,877,514			787,134			742,726			234,898			63,170
Total debt, including current portion		1,254,426			324,083			298,625			54,452			—
Total partners’ capital (deficit)/owners’ equity (deficit)		94,118			(7,010	)		(3,810	)		22,311			15,729
Cash flow data:
Net cash provided by operating activities	$	37,958		$	7,532		$	47,018		$	10,419		$	4,639
Net cash used in investing activities		(2,024,677	)		(104,499	)		(409,607	)		(150,905	)		(9,154	)
Net cash provided by financing activities		1,996,650			64,928			378,612			143,622			17,734
Other financial data:
Gross margin(8)	$	265,802		$	119,071		$	79,711		$	32,457		$	15,651
EBITDA(9)		(24,934	)		81,785			52,791			25,107			11,666
Adjusted EBITDA(9)		184,881			86,219			56,509			25,597			11,666

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Maintenance capital expenditures	$	9,115	$	4,649	$	1,922	$	1,516	$	3,109
Expansion capital expenditures		143,775		79,182		50,576		8,527		4,526
Total capital expenditures	$	152,890	$	83,831	$	52,498	$	10,043	$	7,635
Operating data(10):
Appalachia:
Average throughput volumes (mcfd)		68,715		61,892		55,204		53,343		52,472
Average transportation rate per mcf	$	1.35	$	1.34	$	1.21	$	0.96	$	0.82
Mid-Continent:
Velma system:
Gathered gas volume (mcfd)		62,497		60,682		67,075		56,441		—
Processed gas volume (mcfd)		60,549		58,132		62,538		55,202		—
Residue gas volume (mcfd)		47,234		45,466		50,880		42,659		—
NGL volume (bpd)		6,451		6,423		6,643		5,799		—
Condensate volume (bpd)		225		193		256		185		—
Elk City/Sweetwater system:
Gathered gas volume (mcfd)		298,200		277,063		250,717		—		—
Processed gas volume (mcfd)		225,783		154,047		119,324		—		—
Residue gas volume (mcfd)		206,721		140,969		109,553		—		—
NGL volume (bpd)		9,409		6,400		5,303		—		—
Condensate volume (bpd)		212		140		127		—		—
Chaney Dell system(11):
Gathered gas volume (mcfd)		259,270		—		—		—		—
Processed gas volume (mcfd)		253,523		—		—		—		—
Residue gas volume (mcfd)		221,066		—		—		—		—
NGL volume (bpd)		12,900		—		—		—		—
Condensate volume (bpd)		572		—		—		—		—
Midkiff/Benedum system(11):
Gathered gas volume (mcfd)		147,240		—		—		—		—
Processed gas volume (mcfd)		103,628		—		—		—		—
Residue gas volume (mcfd)		94,281		—		—		—		—
NGL volume (bpd)		20,618		—		—		—		—
Condensate volume (bpd)		1,346		— ��		—		—		—
NOARK system:
Average Ozark Gas Transmission throughput volume (mcfd)		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 presented for the NOARK system represents 100% of its operating activity.

⁽³⁾ Includes APL’s acquisition of Elk City on April 14, 2005, representing eight and one-half months’ operations, and a 75% ownership interest in NOARK on October 31, 2005, representing 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 Spectrum on July 16, 2004, representing five and one-half months’ operations for the year ended December 31, 2004.

⁽⁵⁾ 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, 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.

⁽⁶⁾ Represents the minority interest in the net income (loss) of APL associated with the third-party unitholders of APL.

⁽⁷⁾ For the year ended December 31, 2007, approximately 357,000 phantom units 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.

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⁽⁸⁾ 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. 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,
	2007(1)			2006(2)			2005(3)			2004(4)			2003
Net income (loss)	$	(15,647	)	$	16,640		$	12,305		$	7,394		$	4,572
Adjustments:
Effect of prior period items(12)		—			1,090			(1,090	)		—			—
Other (income) loss		174,084			(12,781	)		(2,519	)		(127	)		(98	)
Plant operating		34,667			15,722			10,557			2,032			—
Transportation and compression		13,484			10,753			4,053			2,260			2,421
General and administrative		64,561			23,474			13,608			4,642			1,662
Depreciation and amortization		50,982			22,994			13,954			4,471			1,770
Loss (gain) on arbitration settlement, net		—			—			138			(1,457	)		—
Interest		62,629			24,726			14,175			2,301			258
Minority interests(5)		3,940			118			1,083			—			—
Minority interest in APL(6)		(133,321	)		16,335			13,447			10,941			5,066
Unrecognized economic impact of Chaney Dell and Midkiff/Benedum acquisition(13)		10,423			—			—			—			—
Gross margin	$	265,802		$	119,071		$	79,711		$	32,457		$	15,651
				��

⁽⁹⁾ EBITDA represents net income (loss) before net interest expense, income taxes, and depreciation and amortization and minority interest 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. 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 EBITDA calculation below is different from 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,
	2007(1)			2006(2)			2005(3)			2004(4)			2003
Net income (loss)	$	(15,647	)	$	16,640		$	12,305		$	7,394		$	4,572
Adjustments:
Effect of prior period items(12)		—			1,090			(1,090	)		—			—
Minority interest in APL(6)		(133,321	)		16,335			13,447			10,941			5,066
Interest expense		62,629			24,726			14,175			2,301			258
Depreciation and amortization		50,982			22,994			13,954			4,471			1,770
Unrecognized economic impact of Chaney Dell and Midkiff/Benedum acquisition(13)		10,423			—			—			—			—
EBITDA	$	(24,934	)	$	81,785		$	52,791		$	25,107		$	11,666
Adjustments:
Non-cash loss (gain) on derivative movements		169,424			(2,316	)		(954	)		(210	)		—
Non-cash compensation expense		38,977			6,750			4,672			700			—
Other non-cash items(14)		1,414			—			—			—			—
Adjusted EBITDA	$	184,881		$	86,219		$	56,509		$	25,597		$	11,666

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⁽¹⁰⁾ “Mcf” represents thousand cubic feet; “mcfd” represents thousand cubic feet per day; “bpd” represents barrels per day.

⁽¹¹⁾ 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.

⁽¹²⁾ 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.

⁽¹³⁾ The acquisition of APL’s Chaney Dell and Midkiff/Benedum systems was consummated on July 27, 2007, although the acquisition’s effective date was July 1, 2007. As such, APL receives the economic benefits of ownership of the assets as of July 1, 2007. However, in accordance with generally accepted accounting principles, APL has only recorded the results of the acquired assets commencing on the closing date of the acquisition. The economic benefits of ownership APL received from the acquired assets from July 1 to July 27, 2007 were recorded as a reduction of the consideration paid for the assets.

⁽¹⁴⁾ 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). 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, their general partner, 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 “—Atlas Pipeline Partners, L.P”), we, the holder of all the incentive distribution rights in APL, had 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; and

• 5,476,253 common units of APL, representing approximately 14.1% of the outstanding common units of APL, or a 13.5% limited partner interest in APL.

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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 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 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 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).

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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, Golden Trend and Permian Basins 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 services in Oklahoma and Texas. APL also provides interstate gas transmission services in southeastern Oklahoma, Arkansas 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 has throughput capacity of approximately 400 MMcfd;

• seven natural gas processing plants with aggregate capacity of approximately 750 MMcfd and one treating facility with a capacity of approximately 200 MMcfd, located in Oklahoma and Texas; and

• 7,870 miles of active natural gas gathering systems located in Oklahoma, Arkansas and Texas, which transport gas from wells and central delivery points in the Mid-Continent region to APL’s natural gas processing plants or Ozark Gas Transmission.

Through its Appalachian operations, APL owns and operates 1,600 miles of active natural gas gathering systems located in eastern Ohio, western New York and western Pennsylvania. Through an omnibus agreement and other agreements between APL and Atlas America and its affiliates, 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 a 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:

• On July 27, 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”). The Chaney Dell system includes 3,470 miles of gathering pipeline and three processing plants, while the Midkiff/Benedum system includes 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. 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 will have an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system beginning on June 15, 2008 and ending on November 1, 2008, and up to an additional 7.4% interest beginning on June 15, 2009 and ending on November 1, 2009. If the option is fully

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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% interest if fully exercised. APL will manage and control the Midkiff/Benedum system regardless of whether Pioneer exercised the purchase options. 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 6.25 million common units in a private placement at a negotiated purchase price of $27.00 per unit (see “—Our Common Equity Offerings”). 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 (see “—Our Partnership Distributions”). APL funded the remaining purchase price from an $830.0 million 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 (see “—APL Term Loan and Credit Facility”); 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.

• In April 2005, APL acquired all of the outstanding equity interests of Elk City for $196.0 million, including related transaction costs. Elk City’s principal assets currently include approximately 450 miles of natural gas pipelines located in the Anadarko Basin in western Oklahoma and the Texas panhandle, a natural gas processing facility in Elk City, Oklahoma, with a total capacity of approximately 130 MMcfd and a gas treatment facility in Prentiss, Oklahoma, with a total capacity of approximately 200 MMcfd.

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, 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 exceeded this minimum generally. The balance of the Appalachian system natural gas APL transports is for third-party operators generally under fixed-fee contracts.

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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 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 received by APL’s Elk City/Sweetwater and Chaney Dell systems, which have keep-whole contracts, is generally low in liquids content and meets 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.

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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. We believe 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, we generally expect NGL prices to follow changes in crude oil prices over the long term, which we believe will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy. 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 would result in a change to our gross margin, excluding the effect of minority interest in APL net income (loss), for the twelve-month period ending December 31, 2008 of approximately $3.7 million.

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Results of Operations

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

	Years Ended December 31,
	2007		2006		2005
Operating data(1):
Appalachia:
Average throughput volumes (mcfd)		68,715		61,892		55,204
Average transportation rate per Mcf	$	1.35	$	1.34	$	1.21
Mid-Continent:
Velma system:
Gathered gas volume (mcfd)		62,497		60,682		67,075
Processed gas volume (mcfd)		60,549		58,132		62,538
Residue gas volume (mcfd)		47,234		45,466		50,880
NGL volume (bpd)		6,451		6,423		6,643
Condensate volume (bpd)		225		193		256
Elk City/Sweetwater system:
Gathered gas volume (mcfd)		298,200		277,063		250,717
Processed gas volume (mcfd)		225,783		154,047		119,324
Residue gas volume (mcfd)		206,721		140,969		109,553
NGL volume (bpd)		9,409		6,400		5,303
Condensate volume (bpd)		212		140		127
Chaney Dell system(2):
Gathered gas volume (mcfd)		259,270		—		—
Processed gas volume (mcfd)		253,523		—		—
Residue gas volume (mcfd)		221,066		—		—
NGL volume (bpd)		12,900		—		—
Condensate volume (bpd)		572		—		—
Midkiff/Benedum system(2):
Gathered gas volume (mcfd)		147,240		—		—
Processed gas volume (mcfd)		103,628		—		—
Residue gas volume (mcfd)		94,281		—		—
NGL volume (bpd)		20,618		—		—
Condensate volume (bpd)		1,346		—		—
NOARK system:
Average Ozark Gas Transmission throughput volume (mcfd)		326,651		249,581		255,777

⁽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.

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

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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 “—Critical Accounting Policies and Estimates”.

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 APL Appalachia system’s average transportation rate was $1.35 per Mcf for the year ended December 31, 2007 compared with $1.34 per Mcf for the prior year, an increase of $0.01 per Mcf. 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), 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, 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 non-cash 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. See further discussion of derivatives under “–– Critical Accounting Policies and Estimates”.

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.

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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 a credit 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.

Year Ended December 31, 2006 Compared to Year Ended December 31, 2005

Revenue.Natural gas and liquids revenue was $391.4 million for the year ended December 31, 2006, an increase of $52.7 million from $338.7 million for the prior year. The increase was attributable to revenue contributions of $28.2 million from APL’s NOARK system, of which a 75% ownership interest was acquired in October 2005 and the remaining 25% ownership interest was acquired in May 2006, of $51.2 million from its Elk City system, which was acquired in April 2005, partially offset by a decrease from APL’s Velma system of $26.7 million due principally to a decrease in natural gas prices and lower processed volumes. Processed natural gas volume averaged 58.1 MMcfd on APL’s Velma system for the year ended December 31, 2006, a decrease of 7.0% from the prior year due to the expiration of a short-term low-margin gathering and processing agreement. The impact of Velma’s processed volume decline on total revenue was partially offset by an increase in the recovery percentage of NGLs at the Velma plant compared with the prior year. Gross natural gas gathered on the Elk City system averaged 277.1 MMcfd for the year ended December 31, 2006, a 10.5% increase from the prior year period. 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 “–– Critical Accounting Policies and Estimates”.

Transportation, compression and other fee revenue increased to $60.9 million for the year ended December 31, 2006 from $30.3 million for the prior year. This $30.6 million increase was primarily due to contributions from the transportation revenues associated with APL’s NOARK system of $19.3 million and its Elk City system of $5.4 million and increases in APL’s Appalachia system average transportation rate earned

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and volume of natural gas transported. For the NOARK system, average Ozark Gas Transmission throughput volume was 249.6 MMcfd for the year ended December 31, 2006. The Appalachia system’s average throughput volume was 61.9 MMcfd for the year ended December 31, 2006 as compared with 55.2 MMcfd for the year ended December 31, 2005, an increase of 6.7 MMcfd or 12.1%. The Appalachia system’s average transportation rate was $1.34 per Mcf for the year ended December 31, 2006 as compared with $1.21 per Mcf for the prior year, an increase of $0.13 per Mcf. The increase in APL’s Appalachia system average daily throughput volume was principally due to new wells connected to its gathering system and the completion of a capacity expansion project in 2005 on certain sections of its pipeline system.

Other income, including the impact of gains and losses recognized on derivatives, was $12.8 million for the year ended December 31, 2006, an increase of $10.3 million from the prior year. This increase was mainly due to a $4.1 million increase in the gain recognized on the change in market value of APL’s non-qualifying derivatives and the ineffective portion of APL’s qualifying derivatives, a $2.7 million gain from the sale of certain gathering pipelines within APL’s Velma system for cash proceeds of $7.5 million and a $2.9 million gain from an insurance claim settlement related to fire damage at a Velma compressor station sustained during 2006.

Costs and Expenses.Natural gas and liquids cost of goods sold of $334.3 million and plant operating expenses of $15.7 million for the year ended December 31, 2006 represented increases of $46.1 million and $5.1 million, respectively, from the prior year amounts due primarily to APL’s acquisitions of NOARK and Elk City, partially offset by a decrease from APL’s Velma system due to a decline in natural gas prices and lower volume resulting from the expiration of a short-term low-margin gathering and processing agreement. Transportation and compression expenses increased $6.8 million to $10.8 million for the year ended December 31, 2006 due mainly to NOARK system operating costs and higher Appalachia system operating costs as a result of compressors added during 2005 in connection with APL’s capacity expansion project and higher maintenance expense as a result of additional wells connected to its gathering system.

General and administrative expenses, including amounts reimbursed to affiliates, increased $9.9 million to $23.5 million for the year ended December 31, 2006 compared with $13.6 million for the prior year. This increase was mainly due to a $2.1 million increase in non-cash compensation expense related to vesting of our and APL’s phantom and common unit awards and higher costs associated with managing APL’s business, including management time related to its NOARK and Elk City acquisitions and capital raising opportunities.

Depreciation and amortization increased to $23.0 million for the year ended December 31, 2006 compared with $14.0 million for the prior year due primarily to the depreciation and amortization associated with APL’s NOARK and Elk City assets acquired.

Interest expense increased to $24.7 million for the year ended December 31, 2006 as compared with $14.2 million for the prior year. This $10.5 million increase was primarily due to interest associated with APL’s May 2006 and December 2005 issuances of 10-year senior unsecured notes, partially offset by a decrease in interest associated with APL’s borrowings under its credit facility and a $2.5 million increase in interest cost capitalized principally attributable to the construction of APL’s Sweetwater plant.

Minority interest expense of $0.1 million and $1.1 million for the years ended December 31, 2006 and 2005 represents Southwestern’s 25% ownership interest in the net income of NOARK from the date of acquisition of APL’s initial 75% ownership interest on October 31, 2005 through the date of APL’s acquisition of the remaining 25% ownership interest on May 2, 2006. Our financial results include the consolidated financial statements of NOARK from the date of its acquisition on October 31, 2005.

Minority interest in APL’s net income, which represents the allocation of APL’s earnings to its non-affiliated limited partners, increased to $14.4 million for the year ended December 31, 2006 as compared with $13.4 million for the prior year. This increase was primarily due to an increase in APL’s net income, partially

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offset by an increase in general partner cash distributions received, including incentive distributions, attributable to an increase in APL’s quarterly cash distributions per limited partner unit and an increase in APL’s outstanding limited partner units due to additional equity offerings in June 2005, November 2005 and May 2006.

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, 2007, we had $25.0 million outstanding and $25.0 million of remaining committed capacity under our credit facility, subject to covenant limitations (see “–– Our Credit Facility”). APL had $105.0 million of outstanding borrowings under its new $300.0 million credit facility at December 31, 2007 and $9.1 million of outstanding letters of credit, which are not reflected as borrowings on our consolidated balance sheet, and $185.9 million of remaining committed capacity under its credit facility, subject to covenant limitations (see “—APL Term Loan and Credit Facility”). In addition to the availability under its credit facility, APL has a universal shelf registration statement on file with the Securities and Exchange Commission, which allows it to issue equity or debt securities (see “—APL Shelf Registration Statement”) of which $352.1 million remains available at December 31, 2007. At December 31, 2007, we had a working capital deficit of $78.7 million compared with a working capital surplus of $0.9 million at December 31, 2006. This decrease was primarily due to an increase in the current portion of APL’s net hedge liability between periods, which is the result of changes in commodity prices after APL entered into the hedges. We believe that we and APL have sufficient liquid assets, cash from operations and borrowing capacity to meet our financial commitments, debt service obligations, unitholder distributions, 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 supplement our cash generation with proceeds from financing activities, including borrowings under our and APL’s credit facilities and other borrowings and the issuance of additional limited partner units.

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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.

Cash Flows - Year Ended December 31, 2006 Compared to Year Ended December 31, 2005

Net cash provided by operating activities of $7.5 million for the year ended December 31, 2006 represented a decrease of $39.5 million from $47.0 million for the prior year. The decrease was derived principally from a $33.0 million decrease in cash flow resulting from changes in the components of working

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capital and a $17.0 million increase in cash distributions to APL’s minority interest partners, partially offset by an $11.5 million increase in net income excluding non-cash charges. The decrease in cash resulted from changes in the components of working capital was the result of additional working capital required to support the growth of APL’s operations, including NOARK and Elk City. The increase in cash distributions to APL’s minority partners is due mainly to increases in APL’s limited partner units outstanding and their cash distribution amount per common limited partner unit. The increase in net income excluding non-cash charges was principally due to the full-year contributions from the acquisitions of NOARK, which APL acquired in October 2005, and Elk City, which APL acquired in April 2005. The non-cash charges which impacted net income include a $9.0 million increase in depreciation and amortization, a $2.9 million gain on APL’s settlement of an insurance claim for which the cash received at December 31, 2006 was recorded within cash flows from investing activities and a $2.8 million increase in gains recognized on APL’s sales of assets for which the cash received was recorded within cash flows from investing activities.

Net cash used in investing activities was $104.5 million for the year ended December 31, 2006, a decrease of $305.1 million from $409.6 million for the prior year. This decrease was principally due to a $328.8 million decrease in net cash paid for APL’s acquisitions, a $7.5 million increase in cash proceeds from APL’s sale of assets and $1.5 million in cash proceeds from APL’s settlement of an insurance claim, partially offset by a $32.6 million increase in APL’s capital expenditures. Net cash paid for APL’s acquisitions in 2006 consisted of the acquisition of the remaining 25% ownership interest in NOARK, while net cash paid for APL’s acquisitions in 2005 consisted of the acquisitions of Elk City and the initial 75% ownership interest in NOARK. See further discussion of capital expenditures under “–– Capital Requirements”.

Net cash provided by financing activities was $64.9 million for the year ended December 31, 2006, a decrease of $313.7 million from $378.6 million for the prior year. This decrease was principally due to a $206.5 million decrease in net proceeds from the issuance of APL’s senior notes, a $193.0 million decrease in net proceeds received from the issuance of APL’s common units, a net $64.0 million increase in distributions to owners, and a $38.3 million increase in repayment of APL’s debt. These amounts were partially offset by a $74.3 million increase in net proceeds from the sale of our common limited partner units in an initial public offering on July 26, 2006, a $73.3 million increase in net borrowings under APL’s credit facility and a $39.9 million increase in net proceeds from the issuance of APL’s cumulative convertible preferred units. The changes in net proceeds from the issuance of APL’s common units, preferred units, and senior notes and borrowing activity under APL’s credit facility principally relate to APL’s construction of the Sweetwater gas plant, a new natural gas processing plant in Oklahoma which initiated operations at the end of the third quarter of 2006, and financing APL’s acquisitions of Elk City in April 2005, the 75% ownership interest in NOARK in October 2005, and the remaining 25% ownership interest in NOARK in May 2006.

Capital Requirements

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

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

• expansion capital expenditures to acquire complementary assets and to expand the capacity of APL’s 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,
	2007		2006		2005
Maintenance capital expenditures	$	9,115	$	4,649	$	1,922
Expansion capital expenditures		143,775		79,182		50,576
Total	$	152,890	$	83,831	$	52,498

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Expansion capital expenditures increased to $143.8 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. As of December 31, 2007, APL is committed to expend approximately $168.4 million on pipeline extensions, compressor station upgrades and processing facility upgrades.

Expansion capital expenditures increased to $79.2 million for the year ended December 31, 2006, due principally to expansions of APL’s Appalachia, Velma and Elk City gathering systems and upgrades to processing facilities and compressors to accommodate new wells drilled in APL’s service areas. Expansion capital expenditures for APL’s Mid-Continent region also included approximately $26.1 million related to the construction of the Sweetwater gas plant. Maintenance capital expenditures for the year ended December 31, 2006 increased to $4.6 million due to the additional maintenance requirements of APL’s NOARK and Elk City acquisitions.

Our Credit Facility

On July 26, 2006, we, 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, 2007, we have $25.0 million outstanding under our revolving credit facility, which was utilized to fund our capital contribution to APL to maintain our 2.0% general partner interest and underwriters 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, 2007 was 7.1%. 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, 2007.

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, 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

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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, 2007, our combined leverage ratio was 4.5 to 1.0, our senior secured debt to EBITDA was 0.8 to 1.0, and our interest coverage ratio was 30.3 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.

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.

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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 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 “—Atlas Pipeline Partners, L.P.”). The general partner’s incentive distributions declared by APL for the year ended December 31, 2007, after the allocation of $9.9 million of our incentive distribution rights back to APL, were $15.9 million.

Contractual Obligations and Commercial Commitments

The following table summarizes our and APL’s contractual obligations and commercial commitments at December 31, 2007 (in thousands):

			Payments Due By Period
Contractual cash obligations:	Total		Less than 1 Year		1 – 3 Years		4 – 5 Years		After 5 Years
Total debt	$	1,254,426	$	34	$	25,000	$	—	$	1,229,392
Interest on total debt(1)		656		96		191		189		180
Derivative-based obligations		229,513		110,867		115,694		2,952		—
Capital leases		40		40		—		—		—
Operating leases		9,357		4,120		3,135		1,993		109
Total contractual cash obligations	$	1,493,992	$	115,157	$	144,020	$	5,134	$	1,229,681

⁽¹⁾ Based on the interest rates of our respective debt components as of December 31, 2007.

			Amount of Commitment Expiration Per Period
Other commercial commitments:	Total		Less than 1 Year		1 – 3 Years		4 – 5 Years		After 5 Years
Standby letters of credit	$	9,091	$	9,091	$	—	$	—	$	—
Other commercial commitments		168,352		168,352		—		—		—
Total commercial commitments	$	177,443	$	177,443	$	—	$	—	$	—

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

Our Common Equity Offerings

In July 2007, we sold 6.25 million 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 underwriters fees and other transaction costs). We utilized the net proceeds from the sale to purchase 3.8 million common units of APL (see “—APL Common Equity Offerings”), which utilized those net proceeds to partially fund the acquisition of control of the Chaney Dell and Midkiff/Benedum systems.

The common units we sold in the July 2007 private placement were subject to a registration rights agreement entered into in connection with the transaction. The registration rights agreement stipulated that we

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would (a) file a registration statement with the Securities and Exchange Commission for the common units by November 24, 2007 and (b) cause the registration statement to be declared effective by the Securities and Exchange Commission by March 2, 2008. On November 28, 2007, the registration statement we filed with the Securities and Exchange Commission for the common units subject to the registration rights agreement was declared effective, thereby fulfilling the requirements of the registration rights agreement.

On July 26, 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 3.6 million 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 July 2007, APL sold 25.6 million 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 25.6 million common units sold by APL, 3.8 million 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 sold in the July 2007 private placement were subject to a registration rights agreement entered into in connection with the transaction. The registration rights agreement stipulated that APL would (a) file a registration statement with the Securities and Exchange Commission for the common units by November 24, 2007 and (b) cause the registration statement to be declared effective by the Securities and Exchange Commission by March 2, 2008. On November 28, 2007, the registration statement APL filed with the Securities and Exchange Commission for the common units subject to the registration rights agreement was declared effective, thereby fulfilling the requirements of the registration rights agreement.

In May 2006, APL sold 0.5 million common units to Wachovia Securities, which then offered the common units to public investors. The units, which were issued under APL’s previously filed shelf registration statement, resulted in 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 its acquisition of the remaining 25% ownership interest in NOARK.

In November 2005, APL sold 2.7 million common units in a public offering for gross proceeds of $113.4 million. In addition, pursuant to an option granted to the underwriters of the offering, APL sold an additional 0.3 million common units in December 2005 for gross proceeds of $13.9 million, resulting in aggregate total gross proceeds of $127.3 million. The units, which were issued under APL’s previously filed shelf registration statement, resulted in total net proceeds of approximately $121.0 million, after underwriting commissions and other transaction costs. APL primarily utilized the net proceeds from the sale to repay a portion of the amounts due under its credit facility.

In June 2005, APL sold 2.3 million common units in a public offering for total gross proceeds of $96.5 million. The units, which were issued under APL’s previously filed shelf registration statement, resulted in net proceeds of approximately $91.7 million, after underwriting commissions and other transaction costs. APL primarily utilized the net proceeds from the sale to repay a portion of the amounts due under its credit facility.

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APL Shelf Registration Statement

APL has an effective shelf registration statement with the Securities and Exchange Commission that permits it to periodically issue equity and debt securities for a total value of up to $500.0 million. As of December 31, 2007, $352.1 million remains available for issuance under the shelf registration statement. However, the amount, type and timing of any offerings will depend upon, among other things, APL’s funding requirements, prevailing market conditions, and compliance with its credit facility covenants.

APL Private Placement of Convertible Preferred Units

On March 13, 2006, APL entered into an agreement to sell 30,000 6.5% cumulative convertible 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 6.5% cumulative preferred units to Sunlight Capital for $10.0 million on May 19, 2006, pursuant to its right under the agreement to require Sunlight Capital to purchase such additional units. The APL preferred units were originally entitled to receive dividends of 6.5% per annum commencing on March 13, 2007 and were to have been accrued and paid quarterly on the same date as the distribution payment date for APL’s common units. On April 18, 2007, APL and Sunlight Capital agreed to amend the terms of the preferred units effective as of that date. The terms of APL’s preferred units were amended to entitle them to receive dividends of 6.5% per annum commencing on March 13, 2008 and to be convertible, at Sunlight Capital’s option, into common units commencing on the date immediately following the first record date for APL’s common unit distributions after March 13, 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 common units in satisfaction of a conversion request. APL has the right to call the preferred units at a specified premium. The applicable redemption price under the amended agreement was increased to $53.82. In consideration of Sunlight Capital’s consent to the amendment of the preferred units, APL issued We recorded the APL Notes as long-term debt and a preferred unit dividend within minority interest in APL on our consolidated balance sheet, and have reduced minority interest in APL by $3.8 million of this amount, which is the portion deemed to be attributable to the concessions of APL’s common limited partners and its general partner to its preferred unitholder, on our consolidated statements of operations.

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

APL Term Loan and Credit Facility

APL has a credit facility comprised of an $830.0 million senior secured term loan (“term loan”) which matures in July 2014 and a $300.0 million senior secured revolving credit facility which matures in July 2013. Borrowings under APL’s credit facility bear interest, at its 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 APL’s outstanding revolving credit facility borrowings at December 31, 2007 was 7.2%, and the weighted average interest rate on the outstanding term loan borrowings at December 31, 2007 was 7.6%. Up to $50.0 million of APL’s credit facility may be utilized for letters of credit, of which $9.1 million was outstanding at December 31, 2007. These outstanding letter of credit amounts were not reflected as borrowings on our consolidated balance sheet. Borrowings under APL’s 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 APL’s consolidated subsidiaries other than the joint venture companies. APL’s credit facility contains customary covenants, including restrictions on its ability to incur

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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, 2007. Mandatory prepayments of the amounts borrowed under the term loan portion of APL’s 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 the new credit facility, APL agreed to remit an underwriting fee to the lead underwriting bank of the credit facility of 0.75% of the aggregate principal amount of the term loan outstanding on January 23, 2008. In January 2008, APL and the underwriting bank agreed to extend the agreement through June 30, 2008.

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 ratio (as defined in the credit facility) of not less than 2.5 to 1.0, increasing to 2.75 to 1.0 commencing September 30, 2008. 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, 2007, APL’s ratio of funded debt to EBITDA was 4.4 to 1.0 and its interest coverage ratio was 3.1 to 1.0.

APL Senior Notes

At December 31, 2007, APL has $293.5 million of 10-year, 8.125% senior unsecured notes due 2015 (“Senior Notes”) outstanding, net of unamortized premium received of $0.9 million. Interest on the APL Senior Notes 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. In addition, prior to December 15, 2008, APL may redeem up to 35% of the aggregate principal amount of the APL Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The APL Senior Notes 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. On April 18, 2007, APL issued Sunlight Capital $8.5 million of its Senior Notes in consideration of its consent to the amendment of APL’s preferred unit agreement.

The indenture governing the APL Senior Notes contains 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 30, 2007.

APL NOARK Notes

On May 2, 2006, APL acquired the remaining 25% equity ownership interest in NOARK from Southwestern. Prior to this acquisition, NOARK’s subsidiary, NOARK Pipeline Finance, L.L.C., had $39.0 million in principal amount outstanding of 7.15% notes due in 2018, which was presented as debt on our consolidated balance sheet, to be allocated severally 100% to Southwestern. In connection with the acquisition of the 25% equity ownership interest in NOARK, Southwestern acquired NOARK Pipeline Finance, L.L.C. and agreed to retain the obligation for the outstanding NOARK notes, with the result that neither APL nor NOARK have any further liability with respect to such notes.

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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 APL’s gathering systems. Increases in those expenses are not necessarily offset by increases in transportation fees that the gathering operations are able to charge. While we anticipate that inflation will affect APL’s future operating costs, we cannot predict the timing or amounts of any such effects. In addition, the value of APL’s gathering systems has been and will continue to be affected by changes in natural gas prices. Natural gas prices are subject to fluctuations which we are unable to control or accurately predict.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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 revenue and expense accruals, depreciation and amortization, asset impairment, fair value of derivative instruments, stock compensation, 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 we have identified are discussed below.

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Use of Estimates

The preparation of our 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 our consolidated financial statements, as well as the reported amounts of revenue and expense during the reporting periods. Our consolidated financial statements are based on a number of significant estimates, including the fair value of APL’s derivative instruments, our and APL’s stock compensation, the purchase price allocation for APL’s acquisition of Chaney Dell and Midkiff/Benedum systems, which could affect the reported amounts for APL’s property, plant and equipment, goodwill, and other intangible assets, and other items. Actual results could differ from those estimates.

Revenue Recognition

Revenue in APL’s Appalachia segment is recognized at the time the natural gas is transported through its gathering systems. Under the terms of APL’s natural gas gathering agreements with Atlas Energy and its affiliates, APL receive 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 are generally the greater of 16% of the gross sales price for natural gas produced from the wells, or $0.35 or $0.40 per Mcf, depending on the ownership of the well. Substantially all natural gas gathering revenue in our 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 consists of the fees earned from our 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 its gathering and processing operations, APL enters into the following types of contractual relationships with our 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 received by APL’s Elk City/Sweetwater and Chaney Dell systems, which have keep-whole contracts, is generally low in liquids content and meets 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.

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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 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).

Intangible Assets

At December 31, 2007 and 2006, APL has intangible assets with finite lives which were recorded in connection with certain consummated acquisitions (see Note 9 to the consolidated financial statements in Item 8, “Financial Statements and Supplementary Data”). APL recorded the initial purchase price allocation for its Chaney Dell and Midkiff/Benedum acquisition on July 27, 2007. During the fourth quarter of 2007, APL adjusted the 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. During 2006, APL adjusted the preliminary purchase price allocation for its NOARK acquisition by reducing the estimated amount allocated to customer contracts and customer relationships and allocating additional amounts to property, plant and equipment (see Note 7 to the consolidated financial statements in Item 8, “Financial Statements and Supplementary Data���).

Statement of Financial Accounting Standards (“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.

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Goodwill

At December 31, 2007 and 2006, APL has goodwill which was recorded in connection with consummated acquisitions (see Note 9 to the consolidated financial statements in Item 8, “Financial Statements and Supplementary Data”). APL recorded the initial purchase price allocation for its Chaney Dell and Midkiff/Benedum acquisition on July 27, 2007. During the fourth quarter of 2007, APL adjusted the preliminary purchase price allocation by increasing the estimated amount allocated to goodwill and reducing amounts initially allocated to property, plant and equipment. Due to the recent date of its Chaney Dell and Midkiff/Benedum acquisition, APL’s purchase price allocation for the acquisition is based upon preliminary data that remains subject to adjustment and could further change as APL continues to evaluate this allocation. Unresolved items which could affect APL’s final purchase price allocation include, among other things, the recoverability of state sales tax paid on the transaction, which has been included as an acquisition cost. The recovery of state sales tax paid on the transaction in future periods could reduce amounts allocated to goodwill. During 2006, APL adjusted the preliminary purchase price allocation for its NOARK acquisition by reducing the estimated amount allocated to goodwill and allocating additional amounts to property, plant and equipment (see Note 7 to consolidated financial statements in Item 8, “Financial Statements and Supplementary Data”). APL tests its goodwill for impairment at each year end by comparing enterprise fair values to carrying values. The evaluation of impairment under SFAS No. 142 requires the use of projections, estimates and assumptions as to the future performance of APL’s operations, including anticipated future revenues, expected future operating costs and the discount factor used. Actual results could differ from projections, resulting in revisions to APL’s assumptions and, if required, recognition of an impairment loss. APL’s test of goodwill at December 31, 2007 resulted in no impairment. APL will continue to evaluate its goodwill at least annually and if impairment indicators arise, will reflect the impairment of goodwill, if any, within our consolidated statements of operations in the period in which the impairment is indicated.

Depreciation and Amortization

APL calculates depreciation based on the estimated useful lives and salvage values of its assets. However, factors such as usage, equipment failure, competition, regulation or environmental matters could cause APL to change its estimates, thus impacting the future calculation of depreciation and amortization.

Impairment of Assets

In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we, including APL, review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets may not be recoverable. APL determines if its long-lived assets are impaired by comparing the carrying amount of an asset or group of assets with the estimated undiscounted future cash flows associated with such asset or group of assets. If the carrying amount is greater than the estimated undiscounted future cash flows, an impairment loss is recognized to reduce the carrying value to fair value. APL’s operations are subject to numerous factors which could affect future cash flows which we discuss under Item 1A, “Risk Factors”. APL continuously monitor these factors and pursues alternative strategies to maintain or enhance cash flows associated with these assets; however, we cannot assure you that APL can mitigate the effects, if any, on future cash flows related to any changes in these factors.

Fair Value of Derivative Commodity Contracts

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 swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate is sold. Under these swap agreements, APL receives or pays a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. Option instruments are contractual agreements that grant the right, but not obligation, to purchase or sell natural gas,

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NGLs and condensate at a fixed price for the relevant contract period. These financial swap and option instruments are generally classified as cash flow hedges in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”).

APL formally documents all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the natural gas futures and options contracts to the forecasted transactions. APL assesses, both at the inception of the hedge and on an ongoing basis, whether the derivatives are effective in offsetting changes in the forecasted cash flow of the hedged items. 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 correlation between the hedging instrument and the underlying commodity, APL will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which APL determines through utilization of market data, will be recognized immediately within other income (loss) in our consolidated statements of operations. For APL’s derivatives qualifying as hedges, we recognize the effective portion of changes in fair value in partners’ capital (deficit) as accumulated other comprehensive income (loss), and reclassify them to natural gas and liquids revenue within our consolidated statements of operations as the underlying transactions are 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.

APL’s derivatives are recorded on our consolidated balance sheet as assets or liabilities at fair value. The net loss in accumulated other comprehensive loss within partners’ capital (deficit) on our consolidated balance sheet at December 31, 2007, if the fair values of the instruments remain at current market values, will be reclassified to natural gas and liquids revenue in our consolidated statements of operations in future periods. Actual amounts that will be reclassified will vary as a result of future price changes.

On June 3, 2007, APL signed definitive agreements to acquire control of the Chaney Dell and Midkiff/Benedum systems (see “– Atlas Pipeline Partners, L.P.”). In connection with agreements entered into with respect to our new credit facility and private placement of common units, 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 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 our consolidated statements of operations. We recognized a non-cash loss of $18.8 million related to the change in value of APL’s 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 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.

In connection with APL’s Chaney Dell and Midkiff/Benedum acquisition, APL reached an agreement with Pioneer which grants Pioneer an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system beginning on June 15, 2008 ending on November 1, 2008, and an additional 7.4% interest beginning on June 15, 2009 and ending on November 1, 2009 (see Note 9 to the consolidated financial statements in Item 8, “Financial Statements and Supplementary Data”). At December 31, 2007, APL has received no indication that Pioneer will exercise either of its options under the agreement. If Pioneer does exercise either of these options, APL will discontinue hedge accounting for the derivative instruments covering the portion of the forecasted production of the Midkiff/Benedum system sold to Pioneer and will evaluate these derivative instruments to determine if they can be documented to match other forecasted production APL may have.

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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 our consolidated balance sheet.

A portion of APL’s future natural gas, NGL and condensate sales is periodically hedged through the use of swaps and collar contracts. Realized gains and losses on the derivative instruments that are classified as effective hedges are reflected in the contract month being hedged as an adjustment to natural gas and liquids revenue within our consolidated statements of operations.

Volume Measurement

APL records amounts for natural gas gathering and transportation revenue, NGL transportation and processing revenue, natural gas sales and natural gas purchases, and the sale of production based on volume and energy measurements. Variances resulting from such calculations, while within recognized industry tolerances, are inherent in APL’s business.

Stock Compensation

We and APL adopted SFAS No. 123(R), “Share-Based Payment,” as revised (“SFAS No. 123(R)”), as of December 31, 2005. 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.

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.

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 LTIP Committee, cash equivalent to the then fair market value of a common limited partner unit. In tandem with phantom unit grants, the 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 we make on a common unit during the period such phantom unit is outstanding. The LTIP Committee will determine the vesting period for phantom units. Through December 31, 2007, phantom units granted under the LTIP generally will vest 25% three years from the date of grant, with the remaining 75% vesting 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 LTIP Committee, although no awards currently outstanding contain any such provision. Awards will automatically vest upon a change of control, as defined in the LTIP. All phantom units outstanding under the LTIP at December 31, 2007 include DERs granted to the Participants by the LTIP Committee. The amount paid with respect to the LTIP DERs are recorded as a reduction of partners’ capital (deficit) on our consolidated balance sheet.

Unit Options.A unit option entitles a Participant to receive a common unit upon payment of the

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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 common unit as determined by the LTIP Committee on the date of grant of the option. The LTIP Committee also shall determine how the exercise price may be paid by the Participant. The 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, 2007, unit options 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 LTIP Committee, although no awards currently outstanding contain any such provision. Awards will automatically vest upon a change of control, as defined in the LTIP.

APL Long-Term Incentive Plan.APL has a Long-Term Incentive Plan (“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 APL’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, 2007.

A phantom unit entitles a grantee to receive a common unit 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 APL, the APL LTIP Committee will determine the vesting period for phantom units and the exercise period for options. Through December 31, 2007, 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. All units outstanding under the APL LTIP at December 31, 2007 include DERs granted to the participants by the APL LTIP Committee. The amounts paid with respect to DERs are recorded as reductions of minority interest on the Partnership’s consolidated balance sheet.

APL Incentive Compensation Agreements.APL has incentive compensation agreements which have granted awards to certain key employees retained from previously consummated acquisitions. These individuals are 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 were issued during the year ended December 31, 2007. The remaining common units to be issued under the incentive compensation agreements will be determined based upon the financial performance of certain APL assets for the year ended 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.

The ultimate number of common units of APL estimated to be issued under the incentive compensation agreements will be determined by the financial performance of certain APL assets for the year ended December 31, 2008.

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The vesting period for such awards concluded on September 30, 2007 and all compensation expense related to the awards was recorded as of that date. APL management anticipates that adjustments will be recorded in future periods with respect to the awards under the incentive compensation agreements based upon the actual financial performance of the assets in future periods in comparison to their estimated performance.

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 the 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 manages these risks through regular operating and financing activities and periodical use of derivative financial 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, 2007. 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.

Interest Rate Risk.At December 31, 2007, we had a $50.0 million revolving credit facility with $25.0 million outstanding. The weighted average interest rate for these borrowings was 7.1% at December 31, 2007. Holding all other variables constant, a 100 basis-point, or 1%, change in interest rates would change our interest expense by $0.3 million.

At December 31, 2007, APL had a $300.0 million senior secured revolving credit facility ($105.0 million outstanding) to fund the expansion of its existing gathering systems, acquire other natural gas gathering systems and fund working capital movements as needed. APL also had an $830.0 million senior secured term loan outstanding at December 31, 2007, of which the net proceeds were utilized to partially finance its acquisition of control of the Chaney Dell and Midkiff/Benedum systems. The weighted average interest rate for APL’s revolving credit facility borrowings was 7.2% at December 31, 2007, and the weighted average interest rate for the term loan borrowings was 7.6% at December 31, 2007. During January 2008, APL entered into interest rate derivative contracts having an aggregate notional principal amount of $200.0 million. Under the terms of this agreement, APL will pay 2.88%, plus the applicable margin as defined under the terms of its credit facility, and will receive LIBOR plus the applicable margin, on the notional principal amount of $200.0 million. This hedge effectively converts $200.0 million of APL’s floating rate debt under the credit facility to fixed-rate debt. The interest rate swap agreement begins on January 31, 2008 and expires on January 31, 2010. Holding all other variables constant, a 100 basis-point, or 1%, change in APL’s interest rates would change its interest expense by $7.4 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

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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 would result in a change to our gross margin for the twelve-month period ending December 31, 2008, excluding the effect of minority interests in APL net income (loss), of approximately $3.7 million.

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 swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate is sold. Under these 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. 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. These financial swap and option instruments are generally classified as cash flow hedges in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”).

APL formally documents all relationships between hedging instruments and the item being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity futures and derivative contracts to the forecasted transactions. APL assesses, both at the inception of the hedge and on an ongoing basis, whether the derivatives are effective in offsetting changes in the forecasted cash flow of the hedged production. 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 commodity, APL will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by APL through the utilization of market data, will be recognized immediately within other income (loss) in our consolidated statements of operations. For APL’s derivatives qualifying as hedges, we recognize the effective portion of changes in fair value in partners’ capital (deficit) as accumulated other comprehensive income (loss), and reclassify them to natural gas and liquids revenue within our consolidated statements of operations as the underlying transactions are 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.

APL’s derivatives are recorded on our consolidated balance sheet as assets or liabilities at fair value. At December 31, 2007 and 2006, we reflected net derivative liabilities on our consolidated balance sheets of $229.5 million and $20.1 million, respectively. Of the $7.7 million of net loss in accumulated other comprehensive loss within partners’ capital (deficit) on our consolidated balance sheet at December 31, 2007, if the fair value of the instruments remain at current market values, we will reclassify $5.4 million of APL’s losses to natural gas and liquids revenue in our consolidated statements of operations over the next twelve month period as these contracts expire, and $2.3 million will be reclassified in later periods. Actual amounts that will be reclassified will vary as a result of future price changes.

On June 3, 2007, APL signed definitive agreements to acquire control of the Chaney Dell and Midkiff/Benedum systems (see “—Atlas Pipeline Partners, L.P.”). In connection with agreements entered into with respect to its new credit facility, term loan and private placement of common units, 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 was not considered “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 our consolidated statements of operations. We recognized a non-cash loss of $18.8 million related to the change in value of derivatives entered into specifically for the Chaney

78

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 APL’s acquisition in July 2007, the production volume of the Anadarko Assets 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.

In connection with its Chaney Dell and Midkiff/Benedum acquisition, APL reached an agreement with Pioneer which grants Pioneer an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system beginning on June 15, 2008 and ending on November 1, 2008, and an additional 7.4% interest beginning on June 15, 2009 and ending on November 1, 2009 (see Note 9 to the consolidated financial statements in Item 8, “Financial Statements and Supplementary Data”). At December 31, 2007, APL has received no indication that Pioneer will exercise either of its options under the agreement. If Pioneer does exercise either of these options, APL will discontinue hedge accounting for the derivative instruments covering the portion of the forecasted production of the Midkiff/Benedum system sold to Pioneer and will evaluate these derivative instruments to determine if they can be documented to match other forecasted production APL may have.

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 our consolidated balance sheet.

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

	Year ended December 31,
	2007			2006			2005
Loss from cash settlement of qualifying hedge instruments(1)	$	(49,393	)	$	(13,945	)	$	(11,125	)
Gain/(loss) from change in market value of non- qualifying derivatives(2)		(153,363	)		4,206			—
Gain/(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)		(3,450	)		1,520			1,625
Loss from cash settlement of non-qualifying derivatives(2)		(10,158	)		—			—

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

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

A portion of APL’s future natural gas, NGL and condensate sales is periodically hedged through the use of swaps and collar contracts. Realized gains and losses on the derivative instruments that are classified as effective hedges are reflected in the contract month being hedged as an adjustment to natural gas and liquids revenue within our consolidated statements of operations.

79

As of December 31, 2007, APL had the following NGLs, natural gas, and crude oil volumes hedged, including derivatives that do not qualify for hedge accounting:

Natural Gas Liquids Sales

Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability(1)
	(gallons)	(per gallon)		(in thousands)
2008	61,362,000	$	0.706	$	(29,435	)
2009	8,568,000		0.746		(4,189	)
				$	(33,624	)

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)(2)			Option Type
	(barrels)	(gallons)	(per barrel)		(in thousands)
2008	4,173,600	279,347,544	$	60.00	$	852		Puts purchased
2008	4,173,600	279,347,544		79.23		(55,674	)	Calls sold
2009	5,184,000	354,533,760		60.00		5,216		Puts purchased
2009	5,184,000	354,533,760		78.88		(64,031	)	Calls sold
2010	3,127,500	213,088,050		61.08		5,638		Puts purchased
2010	3,127,500	213,088,050		81.09		(35,442	)	Calls sold
2011	606,000	34,869,240		70.59		2,681		Puts purchased
2011	606,000	34,869,240		95.56		(3,924	)	Calls sold
2012	450,000	25,893,000		70.80		2,187		Puts purchased
2012	450,000	25,893,000		97.10		(2,922	)	Calls sold
					$	(145,419	)

Natural Gas Sales

Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Asset/(Liability)(2)
	(mmbtu)(3)	(per mmbtu) (3)		(in thousands)
2008	5,484,000	$	8.795	$	5,397
2009	5,724,000		8.611		538
2010	4,560,000		8.526		(351	)
2011	2,160,000		8.270		(607	)
2012	1,560,000		8.250		(331	)
				$	4,646

Natural Gas Basis Sales

Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset/(Liability)(2)
	(mmbtu)(3)	(per mmbtu)(3)			(in thousands)
2008	5,484,000	$	(0.727	)	$	187
2009	5,724,000		(0.558	)		828
2010	4,560,000		(0.622	)		221
2011	2,160,000		(0.664	)		(32	)
2012	1,560,000		(0.601	)		47
					$	1,251

80

Natural Gas Purchases

Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset/(Liability)(2)
	(mmbtu)(3)	(per mmbtu)(3)			(in thousands)
2008	16,260,000	$	8.978	(4)	$	(18,575	)
2009	15,564,000		8.680			(2,542	)
2010	8,940,000		8.580			464
2011	2,160,000		8.270			607
2012	1,560,000		8.250			331
					$	(19,715	)

Natural Gas Basis Purchases

Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Liability(2)
	(mmbtu)(3)	(per mmbtu)(3)			(in thousands)
2008	16,260,000	$	(1.114	)	$	(194	)
2009	15,564,000		(0.654	)		(6,152	)
2010	8,940,000		(0.600	)		(2,337	)
2011	2,160,000		(0.700	)		(89	)
2012	1,560,000		(0.610	)		(64	)
					$	(8,836	)

Crude Oil Sales

Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability(2)
	(barrels)	(per barrel)		(in thousands)
2008	65,400	$	59.424	$	(2,234	)
2009	33,000		62.700		(842	)
				$	(3,076	)

Crude Oil Sales Options

Production Period Ended December 31,	Volumes	Average Strike Price		Fair Value Asset/(Liability)(2)			Option Type
	(barrels)	(per barrel)		(in thousands)
2008	262,800	$	60.000	$	(42	)	Puts purchased
2008	262,800		78.174		(11,149	)	Calls sold
2009	306,000		60.000		807		Puts purchased
2009	306,000		80.017		(9,072	)	Calls sold
2010	234,000		61.795		835		Puts purchased
2010	234,000		83.027		(5,283	)	Calls sold
2011	30,000		60.000		272		Puts purchased
2011	30,000		74.500		(724	)	Calls sold
2012	30,000		60.000		195		Puts purchased
2012	30,000		73.900		(579	)	Calls sold
				$	(24,740	)
			Total net liability	$	(229,513	)

⁽¹⁾ Fair value based upon management estimates, including forecasted forward NGL prices as a function of forward NYMEX natural gas, light crude and propane prices.

81

⁽²⁾ Fair value based on forward NYMEX natural gas and light crude prices, as applicable.

⁽³⁾ Mmbtu represents million British Thermal Units.

⁽⁴⁾ Includes APL’s premium received from its sale of an option for it to sell 936,000 mmbtu of natural gas at an average price of $15.50 per mmbtu for the year ended December 31, 2008.

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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, 2007 and 2006, 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, 2007. 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, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 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), the effectiveness of Atlas Pipeline Holdings, L.P.’s internal control over financial reporting as of December 31, 2007, 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, 2008 expressed an unqualified opinion on the effectiveness of internal control over financial reporting.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

February 27, 2008

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ATLAS PIPELINE HOLDINGS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31,
	2007			2006
ASSETS
Current assets:
Cash and cash equivalents	$	12,129		$	2,198
Accounts receivable - affiliates		2,839			7,087
Accounts receivable		147,360			51,192
Current portion of derivative asset		—			5,437
Prepaid expenses and other		14,755			10,489
Total current assets		177,083			76,403
Property, plant and equipment, net		1,748,661			607,097
Long-term derivative asset		—			305
Intangible assets, net		219,203			25,530
Goodwill		709,283			63,441
Minority interest		2,163			—
Other assets, net		21,121			14,358
	$	2,877,514		$	787,134
LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)
Current liabilities:
Current portion of long-term debt	$	34		$	71
Accounts payable		20,530			18,624
Accrued liabilities		43,658			6,673
Current portion of derivative liability		110,867			17,362
Accrued producer liabilities		80,698			32,766
Total current liabilities		255,787			75,496
Long-term derivative liability		118,646			8,505
Long-term debt, less current portion		1,254,392			324,012
Minority interest in Atlas Pipeline Partners, L.P.		1,154,571			386,131
Commitments and contingencies
Partners’ capital (deficit):
Common limited partners’ interests		101,785			6,899
Accumulated other comprehensive loss		(7,667	)		(13,909	)
Total partners’ capital (deficit)		94,118			(7,010	)
	$	2,877,514		$	787,134

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,
	2007			2006		2005
Revenue:
Natural gas and liquids	$	761,118		$	391,356	$	338,672
Transportation, compression and other fees – affiliates		33,169			30,189		24,346
Transportation, compression and other fees – third parties		48,616			30,735		5,963
Other income (loss)		(174,084	)		12,781		2,519
Total revenue and other income (loss)		668,819			465,061		371,500
Costs and expenses:
Natural gas and liquids		587,524			334,299		288,180
Plant operating		34,667			15,722		10,557
Transportation and compression		13,484			10,753		4,053
General and administrative		58,622			21,155		11,825
Compensation reimbursement – affiliates		5,939			2,319		1,783
Depreciation and amortization		50,982			22,994		13,954
Interest		62,629			24,726		14,175
Minority interests		3,940			118		1,083
Minority interest in Atlas Pipeline Partners, L.P.		(133,321	)		16,335		13,447
Other		—			—		138
Total costs and expenses		684,466			448,421		359,195
Net income (loss)	$	(15,647	)	$	16,640	$	12,305
Allocation of net income (loss):
Portion applicable to owners’ interest (period prior to the initial public offering on July 26, 2006)		—		$	10,236	$	12,305
Portion applicable to common limited partners’ interest (period subsequent to the initial public offering on July 26, 2006)		(15,647	)		6,404		—
Net income (loss)	$	(15,647	)	$	16,640	$	12,305
Net income (loss) attributable to common limited partners per unit:
Basic	$	(0.66	)	$	0.30
Diluted	$	(0.66	)	$	0.30
Weighted average common limited partner units outstanding:
Basic		23,806			21,100
Diluted		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,
	2007			2006			2005
Net income (loss)	$	(15,647	)	$	16,640		$	12,305
Other comprehensive income (loss):
Change in fair value of derivative instruments accounted for as cash flow hedges		(101,968	)		(5,956	)		(39,882	)
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)		46,206			(9,014	)		16,284
Add: adjustment for realized losses reclassified to net income (loss)		49,393			13,945			11,125
Total other comprehensive income (loss)		6,242			(1,025	)		(12,473	)
Comprehensive income (loss)	$	(9,405	)	$	15,615		$	(168	)

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 January 1, 2005	$	22,723		—	$	—		$	(412	)	$	22,311
Distribution to owners		(33,644	)	—		—			—			(33,644	)
Capital contribution from owners		7,690		—		—			—			7,690
Other comprehensive loss		—		—		—			(12,472	)		(12,472	)
Net income attributable to owners		12,305		—		—			—			12,305
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

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,
	2007			2006			2005
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(15,647	)	$	16,640		$	12,305
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.		(133,321	)		16,335			13,447
Distributions paid to minority interest limited partners in Atlas Pipeline Partners, L.P.		(59,850	)		(37,664	)		(20,615	)
Depreciation and amortization		50,982			22,994			13,954
Non-cash loss (gain) on derivative value		169,424			(2,316	)		(954	)
Non-cash compensation expense		38,966			6,750			4,672
Amortization of deferred finance costs		7,489			2,342			2,140
Minority interests		3,940			118			1,083
Net distributions paid to minority interest		(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		(96,267	)		899			(27,823	)
Accounts payable and accrued liabilities		73,292			(10,134	)		33,849
Accounts payable and accrued receivable – affiliates		4,248			(2,792	)		14,960
Net cash provided by operating activities		37,958			7,532			47,018
CASH FLOWS FROM INVESTING ACTIVITIES:
Net cash paid for acquisitions		(1,884,458	)		(30,000	)		(358,831	)
Capital expenditures		(139,647	)		(83,716	)		(51,101	)
Proceeds from sales of assets		553			7,540			—
Proceeds from insurance claim settlement		—			1,522			—
Other		(1,125	)		155			325
Net cash used in investing activities		(2,024,677	)		(104,499	)		(409,607	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from issuance of Atlas Pipeline Partners, L.P. debt		817,131			36,582			243,102
Repayment of Atlas Pipeline Partners, L.P. debt		—			(39,019	)		(677	)
Borrowings under credit facility		25,000			—			—
Borrowings under Atlas Pipeline Partners, L.P. credit facility		320,500			81,000			463,500
Repayments under Atlas Pipeline Partners, L.P. credit facility		(253,500	)		(52,500	)		(508,250	)
Net proceeds from issuance of common limited partner units		166,984			74,326			—
Net proceeds from issuance of Atlas Pipeline Partners, L.P. common limited partner units		946,399			19,704			212,700
Net proceeds from issuance of Atlas Pipeline Partners, L.P. preferred limited partner units		—			39,881			—
Capital contributions from owners		—			1,206			7,690
Distributions paid to common limited partners		(24,788	)		(3,587	)		—
Distributions to owners		—			(91,158	)		(33,644	)
Other		(1,076	)		(1,507	)		(5,809	)
Net cash provided by financing activities		1,996,650			64,928			378,612
Net change in cash and cash equivalents		9,931			(32,039	)		16,023
Cash and cash equivalents, beginning of year		2,198			34,237			18,214
Cash and cash equivalents, end of year	$	12,129		$	2,198		$	34,237

See accompanying notes to consolidated financial statements

88

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). 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” 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 3.6 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). At December 31, 2007, the Partnership had 27,350,370 common limited partnership units outstanding. The Partnership’s general partner, Atlas Pipeline Holdings GP, LLC, 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.

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 5,476,253 APL limited partner units at December 31, 2007. On November 28, 2007, the registration statement APL filed with the Securities and Exchange Commission on Form S-3 to register the Partnership’s APL limited partner units was declared effective and, as such, their resale in the public market is no longer subject to restrictions under the Securities Act. At December 31, 2007, APL had 38,758,581 common limited partnership units outstanding, including the 5,476,253 unregistered common units held by the Partnership, and 40,000 $1,000 par value cumulative convertible preferred limited partnership units outstanding (see Note 5).

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.

In addition to its 64.0% ownership interest in the Partnership at December 31, 2007, Atlas America also had a 49.4% ownership interest in Atlas Energy Resources, LLC and subsidiaries (“Atlas Energy”), a publicly-traded company (NYSE: ATN) focused on the development of natural gas and oil in the Appalachian basin. 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

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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 first quarter of 2006 and fourth and third quarters of 2005, 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 0.5%, 3.4% and 1.1% for the first quarter of 2006, fourth quarter of 2005, and third quarter of 2005, 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) 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 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 on July 26, 2006 (see Note 3), 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. APL’s limited partner equity interests owned by third-parties at December 31, 2007 and 2006 are reflected as minority interest in APL on the Partnership’s consolidated balance sheets. All material intercompany transactions have been eliminated.

On July 27, 2007, APL acquired control of Anadarko Petroleum Corporation’s (NYSE: APC) (“Anadarko”) 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 (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% ownership interest and Anadarko has a 5% interest in each. APL consolidates 100% of these joint ventures. The Partnership reflects Anadarko’s 5% ownership interest in the net income of these joint ventures as minority interest on the Partnership’s 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). In May 2006, APL acquired the remaining 25% ownership interest in NOARK from

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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 reflected on the Partnership’s consolidated statements of operations for the years ended December 31, 2006 and 2005 represents Southwestern’s interest in NOARK’s net income prior to the May 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 costs and expenses during the reporting periods. The Partnership’s consolidated financial statements are based on a number of significant estimates, including the fair value of APL’s derivative instruments, our and APL’s stock compensation, the purchase price allocation for APL’s acquisition of Chaney Dell and Midkiff/Benedum systems, which could effect the reported amounts for property, plant and equipment, goodwill, and other intangible assets, 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.

Receivables

The amounts included within Accounts Receivable on the Partnership’s consolidated balance sheet at December 31, 2007 and 2006 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, 2007 and 2006, APL recorded no allowance for uncollectible accounts receivable.

Property, Plant and Equipment

Property and Equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. Depreciation expense is recorded for each asset over its estimated useful life using the straight-line method.

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.

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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 8.0%, 8.1% and 6.6% for the years ended December 31, 2007, 2006 and 2005 respectively, and the amount of interest capitalized was $3.3 million, $2.6 million and $0.1 million for the years ended December 31, 2007, 2006 and 2005, respectively.

Fair Value of Financial Instruments

For cash and cash equivalents, receivables and payables, the carrying amounts approximate fair values because of the short maturities of these instruments. The fair values of these financial instruments are represented in the Partnership’s consolidated balance sheets (see Note 13).

Derivative Instruments

APL enters into certain financial contracts to manage its exposure to movement in commodity prices. 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 statements of income unless specific hedge accounting criteria are met.

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, 2007 and 2006 (in thousands):

	December 31,						Estimated Useful Lives
	2007			2006			In Years
Gross Carrying Amount:
Customer contracts	$	12,810		$	12,390		8
Customer relationships		222,572			17,260		7–20
	$	235,382		$	29,650
Accumulated Amortization:
Customer contracts	$	(4,215	)	$	(2,646	)
Customer relationships		(11,964	)		(1,474	)
	$	(16,179	)	$	(4,120	)
Net Carrying Amount:
Customer contracts	$	8,595		$	9,744
Customer relationships		210,608			15,786
	$	219,203		$	25,530

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. During 2006, APL adjusted the preliminary purchase price allocation for its NOARK acquisition and reduced the estimated amount allocated to customer contracts and customer relationships based upon the findings of an independent valuation firm and allocated additional amounts to property, plant and equipment (see Note 9).

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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 $12.1 million, $2.0 million and $2.1 million for the years ended December 31, 2007, 2006 and 2005, respectively. Amortization expense related to intangible assets is estimated to be $25.6 million for each of the next five calendar years commencing in 2008.

Goodwill

At December 31, 2007 and 2006, APL had $709.3 million and $63.4 million, respectively, of goodwill recorded in connection with consummated acquisitions (see Note 9). The changes in the carrying amount of goodwill for the years ended December 31, 2007, 2006 and 2005 were as follows (in thousands):

	Years Ended December 31,
	2007		2006			2005
Balance, beginning of year	$	63,441	$	111,446		$	2,305
Goodwill acquired (preliminary allocation) – Elk City acquisition		—		—			61,136
Goodwill acquired (preliminary allocation) – 75% interest in NOARK acquisition		—		—			49,088
Goodwill acquired (preliminary allocation) – remaining 25% interest in NOARK acquisition		—		30,195			—
Goodwill acquired (preliminary allocation) – Chaney Dell and Midkiff/Benedum acquisition		—		—			—
Reduction in minority interest deficit acquired		—		(118	)		(1,083	)
Purchase price allocation adjustment – NOARK		—		(78,082	)		—
Purchase price allocation adjustment – Chaney Dell and Midkiff/Benedum		645,842		—			—
Impairment losses		—		—			—
Balance, end of year	$	709,283	$	63,441		$	111,446

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 goodwill and reducing amounts initially allocated to property, plant and equipment. Due to the recent date of APL’s Chaney Dell and Midkiff/Benedum acquisition, the purchase price allocation for the acquisition is based upon preliminary data that remains subject to adjustment and could further change as APL continues to evaluate this allocation. Unresolved items which could affect the final purchase price allocation include, among other things, the recoverability of state sales tax paid on the transaction, which has been included as an acquisition cost. The recovery of state sales tax paid on the transaction in future periods could reduce amounts allocated to goodwill. During 2006, APL adjusted the preliminary purchase price allocation for the NOARK acquisition and reduced the estimated amount allocated to goodwill based upon the findings of an independent valuation firm and allocated additional amounts to property, plant and equipment (see Note 7 and Note 9). APL tests its goodwill for impairment at each year end

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by comparing reporting unit fair values to carrying values. The evaluation of impairment under SFAS No. 142 requires the use of projections, estimates and assumptions as to the future performance of APL’s operations, including anticipated future revenues, expected future operating costs and the discount factor used. Actual results could differ from projections, resulting in revisions to APL’s assumptions and, if required, recognition of an impairment loss. APL’s test of goodwill at December 31, 2007 resulted in no impairment. APL will continue to evaluate its goodwill at least annually and if impairment indicators arise, and will reflect the impairment of goodwill, if any, within the Partnership’s consolidated statement of operations for the period in which the impairment is indicated.

Income Taxes

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

In June 2006, the Financial Accounting Standards Board (“FASB”) released FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes”, an Interpretation of FASB Statement No. 109 (“FIN 48”). FIN 48 provides guidance for how uncertain tax positions should be recognized, measured, presented and disclosed in the financial statements. FIN 48 requires the evaluation of tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns to determine whether the tax positions have met a “more-likely-than-not” threshold of being sustained by the applicable tax authority. Tax benefits related to tax positions not deemed to meet the “more-likely-than-not” threshold are not permitted to be recognized in the financial statements. The provisions of FIN 48 were adopted by the Partnership effective January 1, 2007. Implementation of FIN 48 had no impact on the consolidated financial statements of the Partnership during the year ended December 31, 2007. The Partnership 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 adopted SFAS No. 123(R), “Share-Based Payment,” as revised (“SFAS No. 123(R)”), as of December 31, 2005. Generally, the approach to accounting in SFAS 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.

Prior to the adoption of SFAS No. 123(R), the Partnership and APL followed Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” and its interpretations (collectively referred to as “APB No. 25”), which SFAS No. 123(R) superseded. APB No. 25 allowed for valuation of share-based payments to employees at their intrinsic values. Under this methodology, compensation expense would have only been recognized for phantom units or unit options granted only if the current market price of the underlying units exceeded the exercise price. The Partnership did not have any share-based payments outstanding prior to the adoption of SFAS No. 123(R), and APL has only granted phantom units with no exercise price since the adoption of its Long-Term Incentive Plan (see Note 14) and, as such, recognized compensation expense based upon the market price of APL’s limited partner units at the date of grant. Since

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APL has historically recognized compensation expense for its share-based payments at their fair values, the adoption of SFAS No. 123(R) did not have a material impact on the Partnership’s consolidated financial statements.

Net Income (Loss) Per Common Unit

Basic net income (loss) 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 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 14). 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 unit with those used to compute diluted net income (loss) per unit (in thousands):

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

⁽¹⁾ For the year ended December 31, 2007, approximately 357,000 phantom units 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.

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 84.5% at December 31, 2007 and 86.5% at December 31, 2006. 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.

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A portion of the funding raised by APL was contributed by the Partnership through the purchase of 3.8 million APL common limited partner units for $168.8 million. Pursuant to Securities and Exchange Commission Staff Accounting Bulletin (“SAB”) No. 51, “Accounting for Sales of Stock by a Subsidiary”, the Partnership recorded a premium of $34.3 million as a reduction of its limited partners’ capital (deficit) with a corresponding increase in minority interest in APL, which represents the difference between the Partnership’s share of the underlying book value in APL before and after the purchase of the common units. The Partnership’s ownership percentage in APL, including its 2% interest as General Partner, increased at that time to 15.9% from 14.3% as a result of the transaction.

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, 2007 and 2006, the Partnership and APL had no environmental matters requiring specific disclosure or requiring the recognition of a liability.

Segment Information

The Partnership’s assets primarily consist of its ownership interests in APL. APL has two reportable segments: natural gas transmission and gathering located in the Appalachia Basin area (“Appalachia”) of eastern Ohio, western New York, and western Pennsylvania, and transmission, gathering and processing located in the Mid-Continent area (“Mid-Continent”) of Oklahoma, Arkansas, northern and western Texas, the Texas panhandle, and southeastern Missouri. Appalachia revenues are 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 the Appalachia segment is 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 are generally the greater of 16% of the gross sales price for natural gas produced from the wells, or $0.35 or $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 regulated transmission pipeline is recognized at the time the 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.

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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 received by the Elk City/Sweetwater and Chaney Dell systems, which have keep-whole contracts, is generally low in liquids content and meets 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.

APL accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, and condensate and the receipt of a delivery statement. These revenues are 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, 2007 and 2006 of $86.8 million and $20.2 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 include only changes in the fair value of unsettled APL derivative contracts which are accounted for as cash flow hedges (see Note 10).

New Accounting Standards

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 income, 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 is currently evaluating whether SFAS No. 160 will have an impact on its financial position and results of operations.

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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”, 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, be measured 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 is currently evaluating whether SFAS No. 141(R) will have an 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” (“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 will be effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007. The Partnership adopted SFAS No. 159 at January 1, 2008 and it had no material impact on its financial position or results of operations.

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. This statement does not require any new fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. However, in February, 2008, the FASB issued Staff Position No. 157-2, which defers the effective date of SFAS No. 157 as it pertains to fair value measurements of nonfinancial assets and nonfinancial liabilities until fiscal years beginning after November 15, 2008. The Partnership adopted SFAS No. 157 at January 1, 2008 and it had no material impact on its financial position or results of operations.

In September 2006, the Securities and Exchange Commission staff issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”). SAB 108 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,

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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 is effective for fiscal years ending on or after November 15, 2006. SAB 108 did not have an impact on the Partnership’s consolidated financial position or results of operations for the year ended December 31, 2007.

NOTE 3 – ATLAS PIPELINE HOLDINGS COMMON UNIT EQUITY OFFERINGS

In July 2007, the Partnership sold 6.25 million 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 3.8 million common units of APL (see Note 4), which utilized the net proceeds to partially fund the acquisition of control of the Chaney Dell and Midkiff/Benedum systems.

The common units sold by the Partnership in the July 2007 private placement were subject to a registration rights agreement entered into in connection with the transaction. The registration rights agreement stipulated that the Partnership would (a) file a registration statement with the Securities and Exchange Commission for the common units by November 24, 2007 and (b) cause the registration statement to be declared effective by the Securities and Exchange Commission by March 2, 2008. On November 28, 2007, the registration statement the Partnership filed with the Securities and Exchange Commission for the common units subject to the registration rights agreement was declared effective, thereby fulfilling the requirements of the registration rights agreement.

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 the Partnership. Concurrent with this transaction, the Partnership issued 3.6 million 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 July 2007, APL sold 25.6 million 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 25.6 million common units sold by APL, 3.8 million were purchased by the Partnership for $168.8 million. 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 and 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% interest in the Midkiff/Benedum natural gas gathering system and processing plants located in Texas (see Note 9).

The common units APL sold in the July 2007 private placement were subject to a registration rights agreement entered into in connection with the transaction. The registration rights agreement stipulated that APL would (a) file a registration statement with the Securities and Exchange Commission for the common units by November 24, 2007 and (b) cause the registration statement to be declared effective by the Securities and Exchange Commission by March 2, 2008. On November 28, 2007, the registration statement APL filed with the Securities and Exchange Commission for the common units subject to the registration rights agreement was declared effective, thereby fulfilling the requirements of the registration rights agreement.

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In May 2006, APL sold 0.5 million common units to Wachovia Securities, which then offered the common units to public investors. The units, which were issued under APL’s previously filed shelf registration statement, resulted in 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 its acquisition of the remaining 25% ownership interest in NOARK.

In November 2005, APL sold 2.7 million of its common units in a public offering for gross proceeds of $113.4 million. In addition, pursuant to an option granted to the underwriters of the offering, APL sold an additional 330,000 common units in December 2005 for gross proceeds of $13.9 million, resulting in aggregate total gross proceeds of $127.3 million. The units, which were issued under APL’s previously filed shelf registration statement, resulted in total net proceeds of approximately $121.0 million, after underwriting commissions and other transaction costs. APL primarily utilized the net proceeds from the sale to repay a portion of the amounts due under its credit facility.

In June 2005, APL sold 2.3 million common units in a public offering for total gross proceeds of $96.5 million. The units, which were issued under APL’s previously filed shelf registration statement, resulted in net proceeds of approximately $91.7 million, after underwriting commissions and other transaction costs. APL primarily utilized the net proceeds from the sale to repay a portion of the amounts due under its credit facility.

NOTE 5 – APL PREFERRED UNIT EQUITY OFFERING

On March 13, 2006, APL entered into an agreement to sell 30,000 6.5% cumulative convertible 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 6.5% cumulative preferred units to Sunlight Capital for $10.0 million on May 19, 2006, pursuant to its right under the agreement to require Sunlight Capital to purchase such additional units. The APL preferred units were originally entitled to receive dividends of 6.5% per annum commencing on March 13, 2007 and were to have been accrued and paid quarterly on the same date as the distribution payment date for APL’s common units. On April 18, 2007, APL and Sunlight Capital agreed to amend the terms of the preferred units effective as of that date. The terms of APL’s preferred units were amended to entitle them to receive dividends of 6.5% per annum commencing on March 13, 2008 and to be convertible, at Sunlight Capital’s option, into common units commencing on the date immediately following the first record date for APL’s common unit distributions after March 13, 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 common units in satisfaction of a conversion request. APL has the right to call the preferred units at a specified premium. The applicable redemption price under the amended agreement was increased to $53.82. In consideration of Sunlight Capital’s consent to the amendment of the preferred units, APL issued $8.5 million of its 8.125% senior unsecured notes due 2015 (the “Notes”) (see Note 11) to Sunlight Capital. The Partnership recorded the APL Notes as long-term debt and a preferred unit dividend within minority interest in APL on its consolidated balance sheet, and has reduced minority interest in APL by $3.8 million of this amount, which is the portion deemed to be attributable to the concessions of APL’s common limited partners and its general partner to its preferred unitholder, on its consolidated statements of operations.

APL’s preferred units are reflected on the Partnership’s consolidated balance sheet as minority interest in APL. In accordance with SAB No. 68, “Increasing Rate Preferred Stock,” APL’s 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 preferred units not having a dividend yield during the first year after their issuance on March 13, 2006 and was amortized in full as of March 12, 2007. As a result of the amended agreement, APL recognized an imputed dividend cost of $2.5 million that will be amortized during the year commencing March 13, 2007 and is based upon the present value of the net proceeds received using the 6.5% stated yield.

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Amortization of the imputed dividend cost, which is presented within minority interest in APL in the Partnership’s consolidated statements of operations, was $2.5 million for the year ended December 31, 2007, based on the imputed dividend cost for the period commencing March 13, 2007, the date of amendment. 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. If converted to APL common units, the preferred equity amount converted will be reclassified to common limited partners’ equity within minority interest in APL on the Partnership’s consolidated balance sheet. Dividends accrued and paid on APL’s preferred units and the premium paid upon their redemption, if any, will be recognized within minority interest in APL in the Partnership’s consolidated statements of operations.

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

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

⁽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 28, 2008, the Partnership declared a cash distribution of $0.34 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2007. The $9.3 million distribution was paid on February 19, 2008 to unitholders of record at the close of business on February 7, 2008.

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

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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, 2005 through December 31, 2007 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 11, 2005	December 31, 2004	$	0.72	$	5,187	$	1,280
May 13, 2005	March 31, 2005	$	0.75	$	5,404	$	1,501
August 5, 2005	June 30, 2005	$	0.77	$	7,319	$	2,174
November 14, 2005	September 30, 2005	$	0.81	$	7,711	$	2,565
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

In connection with APL’s acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see Note 9), the Partnership, which holds of all of 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 (“IDR Adjustment Agreement”).

On January 28, 2008, APL declared a cash distribution of $0.93 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2007. The $41.1 million distribution, including $10.2 million to the Partnership for its general partner interest after the allocation of $5.0 million of its incentive distribution rights back to the APL, was paid on February 14, 2008 to common unitholders of record at the close of business on February 7, 2008.

NOTE 7 – PROPERTY, PLANT AND EQUIPMENT

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

	December 31,						Estimated Useful Lives
	2007			2006			In Years
Pipelines, processing and compression facilities	$	1,633,454		$	611,575		15 – 40
Rights of way		168,359			30,401		20 – 40
Buildings		8,919			3,800		40
Furniture and equipment		7,235			3,288		3 – 7
Other		13,307			2,081		3 – 10
		1,831,274			651,145
Less – accumulated depreciation		(82,613	)		(44,048	)
	$	1,748,661		$	607,097

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In July 2007, APL acquired control of the Chaney Dell and Midkiff/Benedum systems (see Note 9). Due to the recent date of acquisition, the purchase price allocation is based upon estimated values determined by APL, which are subject to adjustment and could change as APL continues to evaluate this allocation. At December 31, 2007, the portion of the purchase price allocated to property, plant and equipment for this acquisition is primarily located within pipeline, processing, and compression facilities.

In May 2006, APL acquired the remaining 25% ownership interest in NOARK for $69.0 million in cash, including the repayment of the $39.0 million of NOARK notes at the date of acquisition (see Note 9). APL acquired the initial 75% ownership interest in NOARK for approximately $179.8 million in October 2005 (see Note 9). During 2006, APL adjusted the preliminary purchase price allocation for the NOARK acquisition and reduced the estimated amount allocated to customer contracts and customer relationships intangible assets and goodwill based upon the findings of an independent valuation firm (see Note 9) and allocated additional amounts to property, plant and equipment.

NOTE 8 – OTHER ASSETS

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

	December 31,
	2007		2006
Deferred finance costs, net of accumulated amortization of $11,505 and $4,016 at December 31, 2007 and 2006, respectively	$	18,468	$	12,846
Security deposits		2,498		1,415
Other		155		97
	$	21,121	$	14,358

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreement (see Note 11). In July 2007, APL recorded $5.0 million of accelerated amortization of deferred financing costs associated with the replacement of its previous credit facility with a new facility (see Note 11).

NOTE 9 – ACQUISITIONS

Chaney Dell and Midkiff/Benedum

On July 27, 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 Chaney Dell System includes 3,470 miles of gathering pipeline and three processing plants, while the Midkiff/Benedum System includes 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.

In connection with this acquisition, APL has reached an agreement with Pioneer, which currently holds a 27.2% undivided joint venture interest in the Midkiff/Benedum system, whereby Pioneer will have an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system beginning on June 15, 2008 and ending on November 1, 2008, and up to an additional 7.4% interest beginning on 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% 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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APL funded the purchase price in part from the private placement of 25.6 million common limited partner units at a negotiated purchase price of $44.00 per unit, generating gross proceeds of $1.125 billion. The Partnership purchased 3.8 million of the 25.6 million common limited partner units issued by APL for $168.8 million and funded this through the private placement of 6.25 million 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 and the 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 11). 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 (see Note 6). APL funded the remaining purchase price from an $830.0 million 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 (see Note 11).

APL’s acquisition was accounted for using the purchase method of accounting under SFAS No. 141, “Business Combinations” (“SFAS No. 141”). The following table presents the preliminary purchase price allocation as of December 31, 2007, 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):

Prepaid expenses and other	$	4,587
Property, plant and equipment		1,030,232
Intangible assets – customer relationships		205,312
Goodwill		645,842
Total assets acquired		1,885,973
Accounts payable and accrued liabilities		(1,515	)
Net cash paid for acquisition	$	1,884,458

APL 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. Due to the recent date of the acquisition, the purchase price allocation for the acquisition is based upon preliminary data that remains subject to adjustment and could further change as APL continues to evaluate this allocation. Unresolved items which could affect the final purchase price allocation include, among other things, the recoverability of state sales tax paid on the transaction, which has been included as an acquisition cost. The recovery of state sales tax paid on the transaction in future periods could reduce amounts allocated to goodwill. 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

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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 accrued liabilities		(50,689	)
Net assets acquired		209,830
Less: Cash and cash equivalents acquired		(16,215	)
Net cash paid for acquisitions	$	193,615

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.

Elk City

In April 2005, APL acquired all of the outstanding equity interests in ETC Oklahoma Pipeline, Ltd. (“Elk City”), a Texas limited partnership, for $196.0 million, including related transaction costs. Elk City’s principal assets included approximately 450 miles of natural gas pipelines located in the Anadarko Basin in western Oklahoma, a natural gas processing facility in Elk City, Oklahoma and a gas treatment facility in Prentiss, Oklahoma. 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, based on their fair values at the date of acquisition (in thousands):

Accounts receivable	$	5,587
Other assets		497
Property, plant and equipment		104,106
Intangible assets – customer contracts		12,390
Intangible assets – customer relationships		17,260
Goodwill		61,136
Total assets acquired		200,976
Accounts payable and accrued liabilities		(4,970	)
Net assets acquired	$	196,006

APL recorded goodwill in connection with this acquisition as a result of Elk City’s significant cash flow and its strategic industry position. Elk City’s results of operations are included within the Partnership’s consolidated financial statements from its date of acquisition.

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 offerings in July 2007 and May 2006 (see Note 4), APL’s issuance of

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an $830.0 million term loan and a new $300.0 million senior secured credit facility and respective borrowings under these facilities (see Note 11), APL’s April 2007 and May 2006 issuance of senior notes (see Note 11), 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 following data also presents pro forma revenue and net income (loss) for the Partnership for the year ended December 31, 2005 as if APL’s NOARK and Elk City acquisitions discussed above, APL’s equity offerings in November 2005 and June 2005 (see Note 4), and APL’s December 2005 issuance of senior notes (see Note 11) had occurred on January 1, 2005. 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; unaudited):

	Years Ended December 31,
	2007			2006		2005
Total revenue and other income (loss)	$	990,051		$	1,090,952	$	469,867
Net income (loss)		(14,655	)		16,264		12,395
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)		—			—		10,522
Portion applicable to common limited partners’ interest (period subsequent to the initial public offering on July 26, 2006)		(14,655	)		16,264		—
	$	(14,655	)	$	16,264	$	10,522
Net income (loss) attributable to common limited partners per unit - basic and diluted	$	(0.54	)	$	0.59

NOTE 10 – DERIVATIVE INSTRUMENTS

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 swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate is sold. Under these 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. 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. These financial swap and option instruments are generally classified as cash flow hedges in accordance with SFAS No. 133.

APL formally documents all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity futures and derivative contracts to the forecasted transactions. APL assesses, both at the inception of the hedge and on an ongoing basis, whether the derivatives are effective in offsetting changes in the forecasted cash flow of the hedged production. 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 commodity, APL will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by APL through the utilization of market data, will be recognized immediately within other income (loss) in the Partnership’s consolidated statements of operations. For APL’s derivatives qualifying as hedges, the Partnership recognizes the effective portion of changes in fair value in partners’ capital (deficit) as accumulated other comprehensive income (loss), and reclassifies them to natural gas and liquids revenue within its consolidated statements of operations as the underlying transactions are 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) in its consolidated statements of operations as they occur.

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APL’s derivatives are recorded on the Partnership’s consolidated balance sheet as assets or liabilities at fair value. At December 31, 2007 and 2006, the Partnership reflected net derivative liabilities on its consolidated balance sheets of $229.5 million and $20.1 million, respectively. Of the $7.7 million of net loss in accumulated other comprehensive loss within partners’ capital (deficit) on the Partnership’s consolidated balance sheet at December 31, 2007, if the fair value of the instruments remain at current market values, the Partnership will reclassify $5.4 million of APL’s losses to natural gas and liquids revenue in its consolidated statements of operations over the next twelve month period as these contracts expire, and $2.3 million will be reclassified in later periods. Actual amounts that will be reclassified will vary as a result of future price changes.

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 “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.

In connection with its Chaney Dell and Midkiff/Benedum acquisition, APL reached an agreement with Pioneer which grants Pioneer an option to buy up to an additional 14.6% interest in the Midkiff/Benedum system beginning on June 15, 2008 and ending on November 1, 2008, and an additional 7.4% interest beginning on June 15, 2009 and ending on November 1, 2009 (see Note 9). At December 31, 2007, APL has received no indication that Pioneer will exercise either of its options under the agreement. If Pioneer does exercise either of these options, APL will discontinue hedge accounting for the derivative instruments covering the portion of the forecasted production of the Midkiff/Benedum system sold to Pioneer and will evaluate these derivative instruments to determine if they can be documented to match other forecasted production APL may have.

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.

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

	Year ended December 31,
	2007			2006			2005
Loss from cash settlement of qualifying hedge instruments(1)	$	(49,393	)	$	(13,945	)	$	(11,125	)
Gain/(loss) from change in market value of non- qualifying derivatives(2)		(153,363	)		4,206			—
Gain/(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)		(3,450	)		1,520			1,625
Loss from cash settlement of non-qualifying derivatives(2)		(10,158	)		—			—

⁽¹⁾ Included within natural gas and liquids revenue on the Partnership’s consolidated statements of operations.

⁽²⁾ Included within other income (loss) on the Partnership’s consolidated statements of operations.

A portion of APL’s future natural gas, NGL and condensate sales is periodically hedged through the use of swaps and collar contracts. Realized gains and losses on the derivative instruments that are classified as effective hedges are reflected in the contract month being hedged as an adjustment to natural gas and liquids revenue within the Partnership’s consolidated statements of operations.

As of December 31, 2007, APL had the following NGLs, natural gas, and crude oil volumes hedged, including derivatives that do not qualify for hedge accounting:

Natural Gas Liquids Sales

Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Liability(1)
	(gallons)	(per gallon)		(in thousands)
2008	61,362,000	$	0.706	$	(29,435	)
2009	8,568,000		0.746		(4,189	)
				$	(33,624	)

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)(2)			Option Type
	(barrels)	(gallons)	(per barrel)		(in thousands)
2008	4,173,600	279,347,544	$	60.00	$	852		Puts purchased
2008	4,173,600	279,347,544		79.23		(55,674	)	Calls sold
2009	5,184,000	354,533,760		60.00		5,216		Puts purchased
2009	5,184,000	354,533,760		78.88		(64,031	)	Calls sold
2010	3,127,500	213,088,050		61.08		5,638		Puts purchased
2010	3,127,500	213,088,050		81.09		(35,442	)	Calls sold
2011	606,000	34,869,240		70.59		2,681		Puts purchased
2011	606,000	34,869,240		95.56		(3,924	)	Calls sold
2012	450,000	25,893,000		70.80		2,187		Puts purchased
2012	450,000	25,893,000		97.10		(2,922	)	Calls sold
					$	(145,419	)

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Natural Gas Sales

Production Period Ended December 31,	Volumes	Average Fixed Price		Fair Value Asset/(Liability)(2)
	(mmbtu)(3)	(per mmbtu) (3)		(in thousands)
2008	5,484,000	$	8.795	$	5,397
2009	5,724,000		8.611		538
2010	4,560,000		8.526		(351	)
2011	2,160,000		8.270		(607	)
2012	1,560,000		8.250		(331	)
				$	4,646

Natural Gas Basis Sales

Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset/(Liability)(2)
	(mmbtu)(3)	(per mmbtu)(3)			(in thousands)
2008	5,484,000	$	(0.727	)	$	187
2009	5,724,000		(0.558	)		828
2010	4,560,000		(0.622	)		221
2011	2,160,000		(0.664	)		(32	)
2012	1,560,000		(0.601	)		47
					$	1,251

Natural Gas Purchases

Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Asset/(Liability)(2)
	(mmbtu)(3)	(per mmbtu)(3)			(in thousands)
2008	16,260,000	$	8.978	(4)	$	(18,575	)
2009	15,564,000		8.680			(2,542	)
2010	8,940,000		8.580			464
2011	2,160,000		8.270			607
2012	1,560,000		8.250			331
					$	(19,715	)

Natural Gas Basis Purchases

Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Liability(2)
	(mmbtu)(3)	(per mmbtu)(3)			(in thousands)
2008	16,260,000	$	(1.114	)	$	(194	)
2009	15,564,000		(0.654	)		(6,152	)
2010	8,940,000		(0.600	)		(2,337	)
2011	2,160,000		(0.700	)		(89	)
2012	1,560,000		(0.610	)		(64	)
					$	(8,836	)

Crude Oil Sales

Production Period Ended December 31,	Volumes	Average Fixed Price			Fair Value Liability(2)
	(barrels)	(per barrel)			(in thousands)
2008	65,400	$	59.424	��	$	(2,234	)
2009	33,000		62.700			(842	)
					$	(3,076	)

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Crude Oil Sales Options

Production Period Ended December 31,	Volumes	Average Strike Price		Fair Value Asset/(Liability)(2)			Option Type
	(barrels)	(per barrel)		(in thousands)
2008	262,800	$	60.000	$	(42	)	Puts purchased
2008	262,800		78.174		(11,149	)	Calls sold
2009	306,000		60.000		807		Puts purchased
2009	306,000		80.017		(9,072	)	Calls sold
2010	234,000		61.795		835		Puts purchased
2010	234,000		83.027		(5,283	)	Calls sold
2011	30,000		60.000		272		Puts purchased
2011	30,000		74.500		(724	)	Calls sold
2012	30,000		60.000		195		Puts purchased
2012	30,000		73.900		(579	)	Calls sold
				$	(24,740	)
			Total net liability	$	(229,513	)

⁽¹⁾ Fair value based upon management estimates, including forecasted forward NGL prices as a function of forward NYMEX natural gas, light crude and propane prices.

⁽²⁾ Fair value based on forward NYMEX natural gas and light crude prices, as applicable.

⁽³⁾ Mmbtu represents million British Thermal Units.

⁽⁴⁾ Includes APL’s premium received from its sale of an option for it to sell 936,000 mmbtu of natural gas at an average price of $15.50 per mmbtu for the year ended December 31, 2008.

NOTE 11 – DEBT

Total debt consists of the following (in thousands):

	December 31,
	2007			2006
Revolving credit facility	$	25,000			—
APL Revolving credit facility		105,000		$	38,000
APL Term loan		830,000			—
APL Senior notes		294,392			285,977
Other APL debt		34			106
Total debt		1,254,426			324,083
Less current maturities		(34	)		(71	)
Total long-term debt	$	1,254,392		$	324,012

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, 2007, the Partnership has $25.0 million outstanding under its revolving credit facility, which was utilized to fund its capital contribution

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to APL to maintain its 2.0% general partner interest and underwriters 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, 2007 was 7.1%. 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, 2007.

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 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, 2007, the Partnership’s combined leverage ratio was 4.5 to 1.0, its funded debt to EBITDA was 0.8 to 1.0, and its interest coverage ratio was 30.3 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 us 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

In connection with APL’s July 27, 2007 acquisition of control of the Chaney Dell and Midkiff/Benedum systems (see Note 9), APL entered into a new credit facility, comprised of an $830.0 senior secured term loan (“term loan”) which matures in July 2014 and a $300.0 million senior secured revolving credit facility which matures in July 2013. APL borrowed $830.0 million under the term loan and $15.0 million under the revolving credit facility to finance a portion of the acquisition purchase price and to repay indebtedness under its prior revolving credit facility. Borrowings under the APL 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 APL’s outstanding revolving credit facility borrowings at December 31, 2007 was 7.2%, and the weighted average interest rate on the outstanding term loan borrowings at December 31, 2007 was 7.6%. Up to $50.0 million of the APL credit facility may be utilized for letters of credit, of which $9.1 million was outstanding at December 31, 2007. These outstanding letter of credit amounts were not reflected as borrowings on the Partnership’s consolidated balance sheet. Borrowings under the APL credit facility are

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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 APL 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, 2007. Mandatory prepayments of the amounts borrowed under the term loan portion of the APL 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 the new credit facility, APL agreed to remit an underwriting fee to the lead underwriting bank of the credit facility of 0.75% of the aggregate principal amount of the term loan outstanding on January 23, 2008. In January 2008, APL and the underwriting bank agreed to extend the agreement through June 30, 2008.

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 the Partnership’s General Partner. APL’s credit facility requires the Partnership 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 ratio (as defined in the credit facility) of not less than 2.5 to 1.0, increasing to 2.75 to 1.0 commencing September 30, 2008. 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, 2007, APL’s ratio of funded debt to EBITDA was 4.4 to 1.0 and its interest coverage ratio was 3.1 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, 2007, APL has $293.5 million of 10-year, 8.125% senior unsecured notes due 2015 (“Senior Notes”) outstanding, net of unamortized premium received of $0.9 million. Interest on the APL Senior Notes 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. In addition, prior to December 15, 2008, APL may redeem up to 35% of the aggregate principal amount of the APL Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The APL Senior Notes 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. On April 18, 2007, APL issued Sunlight Capital $8.5 million of its Senior Notes in consideration of its consent to the amendment of APL’s preferred units agreement (see Note 5).

The indenture governing the APL Senior Notes contains 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, 2007.

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

Years Ended December 31:
2008	$	34
2009		—
2010		25,000
2011		—
2012		—
Thereafter		1,229,392
	$	1,254,426

Cash payments for interest related to the Partnership’s and APL’s debt were $58.2 million, $25.6 million, and $9.2 million for the years ended December 31, 2007, 2006 and 2005, respectively.

NOTE 12 – COMMITMENTS AND CONTINGENCIES

APL has noncancelable operating leases for equipment and office space. Total rental expense for the years ended December 31, 2007, 2006 and 2005 was $5.6 million, $4.0 million, and $2.0 million, respectively. The aggregate amount of remaining future minimum annual lease payments as of December 31, 2007 is as follows (in thousands):

Years Ended December 31:
2008	$	4,120
2009		1,732
2010		1,403
2011		1,181
2012		812
Thereafter		109
	$	9,357

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, 2007, APL is committed to expend approximately $168.4 million on pipeline extensions, compressor station upgrades and processing facility upgrades.

NOTE 13 – FINANCIAL INSTRUMENTS AND CONCENTRATIONS OF CREDIT RISK

The estimated fair value of financial instruments has been determined based upon the Partnership’s 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, 2007 and 2006, which consists principally of borrowings under the Partnership’s and APL’s credit facility, the APL Term Loan and APL Senior Notes, was $1,250.6 million and $330.9 million, respectively, compared with the carrying amount of $1,254.4 million and $324.0 million, respectively. The 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.

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APL sells natural gas and NGLs under contract to various purchasers in the normal course of business. For the year ended December 31, 2007, the Mid-Continent segment had one customer that individually accounted for approximately 53% of the Partnership’s consolidated total revenues, excluding the impact of non-cash derivative items; three customers that individually accounted for approximately 37%, 19% and 10% of the Partnership’s consolidated total revenues, excluding the impact of non-cash derivative items, for the year ended December 31, 2006 and three customers that individually accounted for approximately 33%, 15% and 11% of the Partnership’s consolidated total revenues, excluding the impact of non-cash derivative items, for the year ended December 31, 2005. Additionally, the Mid-Continent segment had two customers that accounted for approximately 26% and 11% and one customer that accounted for approximately 16% of the Partnership’s consolidated accounts receivable at December 31, 2007 and 2006, respectively. 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 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, 2007, the Partnership and its subsidiaries, including APL, had $57.7 million in deposits at banks, of which $56.9 million was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments.

NOTE 14 – 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.

The Partnership’s Long-term Incentive Plan

In November 2006, the Board of Directors approved and adopted the Partnership’s Long-Term Incentive Plan (“LTIP”), which provides performance incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners (collectively, the “Participants”) who perform services for the Partnership. The Partnership’s LTIP is administered by a committee (the “LTIP Committee”), appointed by the Partnership’s board. Under the Partnership’s LTIP, phantom units and/or unit options may be granted, at the discretion of the Partnership’s LTIP Committee, to all or designated Participants, at the discretion of the Partnership’s LTIP Committee. The Partnership’s 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, 2007, the Partnership had 1,435,825 phantom units and unit options outstanding under the Partnership’s LTIP, with 663,800 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 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.

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The Partnership’s LTIP Committee will determine the vesting period for phantom units. Through December 31, 2007, phantom units granted under the LTIP generally will vest 25% three years from the date of grant, with the remaining 75% vesting 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, 2007, 675 units will vest within the following twelve months. All phantom units outstanding under the Partnership’s LTIP at December 31, 2007 include DERs granted to the Participants by the Partnership’s LTIP Committee. The amount paid with respect to the Partnership’s LTIP DERs was $0.2 million and $37,000 for the years ended December 31, 2007 and 2006, respectively. This amount was recorded as a reduction of partners’ capital (deficit) on the Partnership’s consolidated balance sheet.

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

	Years Ended December 31,
	2007			2006
Outstanding, beginning of year		220,492			—
Granted(1)		708			220,492
Matured		(375	)		—
Forfeited		—			—
Outstanding, end of year		220,825			220,492
Non-cash compensation expense recognized (in thousands)	$	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 $37.46 and $22.56 for awards granted for the year ended December 31, 2007 and 2006, respectively.

At December 31, 2007, the Partnership had approximately $3.6 million of unrecognized compensation expense related to unvested phantom units outstanding under the Partnership’s 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, 2007, 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 no unit options outstanding under the Partnership’s LTIP at December 31, 2007 that will vest within the following twelve months. The following table sets forth the LTIP unit option activity for the periods indicated:

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	Year Ended December 31, 2007				Year Ended December 31, 2006
	Number Of Unit Options		Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price
Outstanding, beginning of year		1,215,000	$	22.56		—	$	—
Granted		—		—		1,215,000		22.56
Matured		—		—		—		—
Forfeited		—		—		—		—
Outstanding, end of year(1)(2)		1,215,000	$	22.56		1,215,000	$	22.56
Options exercisable, end of year		—		—		—		—
Weighted average fair value of unit options per unit granted during the year	$	—			$	3.76
Non-cash compensation expense recognized (in thousands)	$	1,237			$	206

⁽¹⁾ The weighted average remaining contractual life for outstanding options at December 31, 2007 was 8.9 years.

⁽²⁾ The aggregate intrinsic value of options outstanding at December 31, 2007 was approximately $5.6 million.

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.

At December 31, 2007, the Partnership had approximately $3.1 million of unrecognized compensation expense related to unvested unit options outstanding under the Partnership’s LTIP based upon the fair value of the awards.

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 APL’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, 2007.

A phantom unit entitles a grantee to receive a common unit 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

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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, 2007, 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, 2007, 56,481 units will vest within the following twelve months. All units outstanding under the APL LTIP at December 31, 2007 include DERs granted to the participants by the APL LTIP Committee. The amounts paid with respect to APL LTIP DERs were $0.6 million, $0.4 million and $0.3 million for the years ended December 31, 2007, 2006 and 2005, respectively. These amounts were recorded as reductions of minority interest in APL on the Partnership’s consolidated balance sheet.

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

	Years Ended December 31,
	2007			2006			2005
Outstanding, beginning of year		159,067			110,128			58,329
Granted(1)		25,095			82,091			67,399
Matured		(51,166	)		(31,152	)		(14,581	)
Forfeited		(3,250	)		(2,000	)		(1,019	)
Outstanding, end of year		129,746			159,067			110,128
Non-cash compensation expense recognized (in thousands)	$	2,936		$	2,030		$	2,201

⁽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 $50.09, $45.45 and $48.59 for awards granted for the years ended December 31, 2007, 2006 and 2005, respectively.

At December 31, 2007, APL had approximately $2.3 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 were issued during the year ended December 31, 2007. The remaining common units to be issued under the incentive compensation agreements will be determined based upon the financial performance of certain APL assets for the year ended December 31, 2008. APL’s incentive compensation agreements also dictates 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 compensation expense of $33.4 million, $4.3 million and $2.5 million for the years ended December 31, 2007, 2006 and 2005, respectively, related to the vesting of awards under these incentive compensation agreements. The increase in non-cash compensation expense was due to an increase in common

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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 ultimate number of common units estimated to be issued under the incentive compensation agreements will be determined by the financial performance of certain APL assets for the year ended December 31, 2008. The vesting period for such awards concluded on September 30, 2007 and all compensation expense related to the awards was recorded as of that date. APL management anticipates that adjustments will be recorded in future periods with respect to the awards under the incentive compensation agreements based upon the actual financial performance of the assets in future periods in comparison to their estimated performance. Based upon APL management’s estimate of the probable outcome of the performance targets at December 31, 2007, 948,847 common unit awards are ultimately expected to be issued under these agreements during the year ended December 31, 2009. APL follows SFAS No. 123(R) and recognized compensation expense related to these awards based upon the fair value method.

NOTE 15 – 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 (“Atlas Holdings GP”), does not receive a management fee in connection with its management of the Partnership’s operations, nor does Atlas Pipeline GP, the general partner of APL, receive a management fee in connection with its management of APL apart from its interest as general partner and its right to receive incentive distributions. APL reimburses the Partnership and its affiliates for compensation and benefits related to their employees who perform services for it based upon an estimate of the time spent by such persons on activities for APL. Other indirect costs, such as rent for offices, are allocated to APL by Atlas 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 $5.9 million, $2.3 million and $1.8 million for the years ended December 31, 2007, 2006 and 2005, respectively, for compensation and benefits related to their employees. For the years ended December 31, 2007, 2006 and 2005, direct reimbursements by APL to the Partnership were $26.4 million, $28.6 million and $24.8 million, respectively, 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 16 – 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 and western Pennsylvania, and transmission, gathering and processing located in the Mid-Continent area (“Mid-Continent”) of primarily Oklahoma, northern and western Texas, the Texas panhandle, Arkansas 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.

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

	Years Ended December 31,
	2007			2006			2005
Mid-Continent
Revenue:
Natural gas and liquids	$	759,553		$	391,356		$	338,672
Transportation, compression and other fees		48,041			30,653			5,880
Other income (loss)		(174,438	)		11,804			2,138
Total revenues and other income (loss)		633,156			433,813			346,690
Costs and expenses:
Natural gas and liquids		586,677			334,299			288,180
Plant operating		34,667			15,722			10,557
Transportation and compression		7,249			5,807			952
General and administrative		48,332			15,036			7,375
Depreciation and amortization		46,327			19,322			11,307
Minority interests		3,940			118			1,083
Total costs and expenses		727,192			390,304			319,454
Segment profit (loss)	$	(94,036	)	$	43,509		$	27,236
Appalachia
Revenue:
Natural gas and liquids	$	1,565		$	—		$	—
Transportation, compression and other fees – affiliates		33,169			30,189			24,346
Transportation, compression and other fees – third parties		575			82			83
Other income		335			608			381
Total revenues and other income		35,644			30,879			24,810
Costs and expenses:
Natural gas and liquids		847			—			—
Transportation and compression		6,235			4,946			3,101
General and administrative		6,327			3,767			3,117
Depreciation and amortization		4,655			3,672			2,647
Total costs and expenses		18,064			12,385			8,865
Segment profit	$	17,580		$	18,494		$	15,945
Reconciliation of segment profit to net income (loss):
Segment profit (loss):
Mid-Continent	$	(94,036	)	$	43,509		$	27,236
Appalachia		17,580			18,494			15,945
Total segment profit (loss)		(76,456	)		62,003			43,181
Corporate general and administrative expenses		(9,883	)		(4,302	)		(3,116	)
Interest expense		(62,629	)		(24,726	)		(14,175	)
Minority interest in Atlas Pipeline Partners, L.P.		133,321			(16,335	)		(13,447	)
Other		—			—			(138	)
Net income (loss)	$	(15,647	)	$	16,640		$	12,305
Capital Expenditures:
Mid-Continent	$	133,270		$	65,416		$	35,263
Appalachia		19,620			18,415			17,235
	$	152,890		$	83,831		$	52,498

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	December 31,
	2007		2006
Balance sheet
Total assets:
Mid-Continent	$	2,813,049	$	730,791
Appalachia		43,860		42,448
Corporate other		20,605		13,895
	$	2,877,514	$	787,134
Goodwill:
Mid-Continent	$	706,978	$	61,136
Appalachia		2,305		2,305
	$	709,283	$	63,441

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

	Years Ended December 31,
	2007		2006		2005
Natural gas and liquids:
Natural gas	$	264,438	$	196,182	$	198,972
NGLs		434,773		169,840		126,498
Condensate		27,269		6,678		5,417
Other(1)		34,638		18,656		7,785
Total	$	761,118	$	391,356	$	338,672
Transportation and Compression:
Affiliates	$	33,169	$	30,189	$	24,346
Third parties		48,616		30,735		5,963
Total	$	81,785	$	60,924	$	30,309

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

NOTE 17 – QUARTERLY FINANCIAL DATA (Unaudited)

	Fourth Quarter(1)			Third Quarter(1)			Second Quarter(1)			First Quarter(1)
	(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	$	(0.51	)	$	(0.12	)	$	(0.06	)	$	0.13

⁽¹⁾ 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.

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	Fourth Quarter(1)		Third Quarter(2)		Second Quarter		First Quarter
	(in thousands, except per unit data)
Year ended December 31, 2006:
Revenue and other income	$	116,840	$	120,910	$	109,501	$	117,810
Costs and expenses		113,333		116,666		104,968		113,454
Net income		3,507		4,244		4,533		4,356
Basic net income attributable to common limited partners per unit	$	0.17	$	0.14
Diluted net income attributable to common limited partners per unit	$	0.17	$	0.14

⁽¹⁾ Includes APL’s $2.9 million gain from the settlement of an insurance claim pertaining to fire damage to a compressor station within the Velma region of its Mid-Continent segment.

⁽²⁾ Includes APL’s $2.7 million gain from the sale of certain gathering pipelines within the Velma system.

NOTE 18 – SUBSEQUENT EVENT

During January 2008, APL entered into interest rate derivative contracts having an aggregate notional principal amount of $200.0 million. Under the terms of this agreement, APL will pay 2.88%, plus the applicable margin as defined under the terms of its credit facility, and will receive LIBOR plus the applicable margin, on the notional principal amount of $200.0 million. This hedge effectively converts $200.0 million of APL’s floating rate debt under the credit facility to fixed-rate debt. The interest rate swap agreement begins on January 31, 2008 and expires on January 31, 2010.

ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our General Partner’s Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision of our General Partner’s Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an

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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, 2007, our disclosure controls and procedures were effective.

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.

In conducting management’s evaluation of the effectiveness of its internal control over financial reporting, management has excluded, due to their size and complexity, the operations of APL’s newly acquired Chaney Dell and Midkiff/Benedum systems, which were acquired in July 2007, from the December 31, 2007 Sarbanes-Oxley 404 review. In connection with this acquisition, APL entered into a transition services agreement with the former owner and, as a result, did not begin to perform substantially all accounting control functions for these systems until November 2007. The Chaney Dell and Midkiff/Benedum systems constituted 68% of our total assets as of December 31, 2007, and 41% of our total revenues and 32% of our net loss, excluding minority interest in APL, for the year ended December 31, 2007 (see Note 9 to the consolidated financial statements which contain further discussion of these acquisitions). We believe that management had sufficient cause to exclude this acquisition in its evaluation of the effectiveness of our internal control over financial reporting based on the size, complexity, and timing of the acquisition.

Based on our evaluation under the COSO framework, management concluded that internal control over financial reporting was effective as of December 31, 2007. 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, 2007, which is included herein.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unitholders

Atlas Pipeline Holdings, L.P.

We have audited Atlas Pipeline Holdings, L.P.’s (Partnership) (a Delaware limited partnership) internal control over financial reporting as of December 31, 2007, 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 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.

In conducting management’s evaluation of the effectiveness of its internal control over financial reporting, management has excluded, due to its size and complexity, the Partnership’s subsidiaries Atlas Pipeline Mid-Continent WestOk, LLC. (Chaney Dell) and Atlas Pipeline Mid-Continent WestTex, LLC. (Midkiff/Benedum), which were recently acquired in July 2007. The Chaney Dell and Midkiff/Benedum systems constituted 68% of the Partnership’s total assets as of December 31, 2007, 41% of its total revenues and 32% of its net loss, excluding minority interest in Atlas Pipeline Partners, L.P., for the year ended December 31, 2007. Our audit of internal control over financial reporting of the Partnership also did not include an evaluation of the internal control over financial reporting of Chaney Dell and Midkiff/Benedum.

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, 2007, based on the criteria established inInternal Control – Integrated Framework issued by COSO.

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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, 2007 and 2006, 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, 2007 and our report dated February 27, 2008 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

February 27, 2008

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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
Edward E. Cohen	69	Chairman of the Board and Chief Executive Officer	2006
Jonathan Z. Cohen	37	Vice Chairman of the Board	2006
Robert R. Firth	53	President, Chief Operating Officer and Director	2006
Matthew A. Jones	46	Chief Financial Officer and Director	2006
Sean P. McGrath	36	Chief Accounting Officer	2006
Lisa Washington	40	Chief Legal Officer and Secretary	2006
William G. Karis	59	Director	2006
Jeffrey C. Key	42	Director	2006
Harvey G. Magarick	68	Director	2006

Edward E. Cohen has been the Chairman of the Board and Chief Executive Officer of our general partner since its formation in January 2006. Mr. Cohen has been the Chairman of the managing board and Chief Executive Officer of Atlas Pipeline GP, since its formation in 1999. 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.

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.

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.

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Robert R. Firthhas been the President and Chief Executive Officer of Atlas Pipeline Mid-Continent since July 2004. Mr. Firth has been a director of our general partner since February 2006 and has been the President and Chief Operating Officer of our general partner since January 2006. Before joining Atlas Pipeline Mid-Continent, Mr. Firth had been President and Chief Executive Officer of Spectrum, its predecessor, since 2002. From September 2001 to June 2002, Mr. Firth was Vice President of Business Development for CMS Field Services. From July 2000 to September 2001, Mr. Firth helped to form ScissorTail Energy through the acquisition of Octagon Resources, where he served as Vice President of Operations and Commercial Services. In addition to the positions listed above, Mr. Firth has held positions with Northern Natural Gas, Panda Resources and Transok in his approximately 30 years in the midstream energy sector.

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. 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. Ms. Washington has been the Chief Legal Officer, Vice President and Secretary of Atlas Pipeline GP since November 2005. Ms. Washington also has been the Vice President, Chief Legal Officer and Secretary of Atlas America since November 2005. 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. 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 has been Vice President, Strategy and Global Business Development for Tekelec, a supplier of telecommunications equipment 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, Steams & 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.

Other Significant Employees

Daniel C. Herz, 31, 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.

Michael L. Staines, 58, has been the President and Chief Operating Officer of Atlas Pipeline GP since

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2000. Mr. Staines has been an Executive Vice President of Atlas America since its formation in 2000. Mr. Staines was Senior Vice President of Resource America from 1989 to 2004 and served as a director from 1989 through 2000 and Secretary from 1989 through 1998. Mr. Staines is a member of the Ohio Oil and Gas Association, the Independent Oil and Gas Association of New York and the Independent Petroleum Association of America.

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 2007, except Mr. Firth inadvertently filed a late Form 4.

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.

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 atwww.atlaspipelineholdings.com.

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ITEM 11. EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

We are required to provide information regarding the compensation program in place as of December 31, 2007, for our CEO, CFO and the three other most highly-compensated executive officers. In this report, we refer to our 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.

Through the end of 2007, the compensation committee of Atlas America, our parent, has been responsible for formulating and presenting recommendations to its Board of Directors and our board with respect to the compensation of our named executive officers. We do not directly compensate our named executive officers. Rather, Atlas America and its affiliates do allocate compensation costs to APL for employees who perform services for it, including persons who are our executive officers, based upon an estimate of the time spent by such persons on activities for APL and for Atlas America and its affiliates. We reimburse Atlas America for the compensation allocated to us. The compensation allocation was $5.9 million for the year ended December 31, 2007. Since these allocated costs are included in our consolidated financial statements, we present in this Item 11 information with respect to (a) compensation costs allocated to APL with respect to APL’s named executive officers in their capacities as officers of Atlas Pipeline GP and (b) awards granted to such persons under our long-term incentive plan (our “Plan”), the APL long-term incentive plan, which we refer to as the APL Plan, the APL executive group incentive plan, and the Atlas America Stock Incentive Plan, which we refer to as the Atlas Plan. The compensation committee is comprised solely of independent directors of Atlas America.

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.

The compensation awarded to our NEOs for fiscal 2007 specifically was intended:

• To encourage and reward strong performance; and

• To motivate our NEOs by providing them with a meaningful equity stake in our company and our publicly-traded subsidiaries, as appropriate.

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 compensation committee makes recommendations to the Atlas America board on compensation amounts during the month 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. We typically pay cash awards and issue equity awards in February of the following fiscal year. The 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 subsidiaries, Atlas

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Energy Resources and Atlas Pipeline Partners, may receive stock-based awards from these subsidiaries, each of which have delegated compensation decisions to the compensation committee since neither we, nor the other subsidiaries, have employees.

Each year, Atlas America’s (and our) Chief Executive Officer provides the 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 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.

In June 2006, the compensation committee retained Mercer Human Resource Consulting to analyze and review the competitiveness and appropriateness of all elements of the compensation paid by Atlas America to its executive officers, including our NEOs, individually and as a group, for fiscal 2006. The purpose of retaining Mercer was to determine whether Atlas America’s compensation practices were within the norm for companies of similar size and focus. Because of the importance to Atlas America or Atlas Energy’s direct-placement energy investment programs and Atlas America’s creation of new initiatives entities, Mercer looked not only to the energy industry in evaluating our compensation levels but also to the financial services and alternative asset industries. Mercer’s analysis established that Atlas America’s fiscal 2006 compensation amounts fell between the median and the 75^th percentile of the peer group it used, which the compensation committee found acceptable in the context of its evaluation of the performance of the NEOs.

Ultimately, the decisions regarding executive compensation are made by the compensation committee after extensive discussion regarding appropriate compensation and are approved by the Atlas America 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 base salary plus cash bonus. 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 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. Notwithstanding the existence of the Senior Executive Plan, the compensation committee believes that stockholder interests are best served by not

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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 February 2007, the compensation committee set the performance goals for the Atlas America’s executive offers, some of whom are also our NEOs. Specifically, the committee decided that if Atlas America’s 2007 net income, which was defined as net income before income taxes and compensatory bonuses paid, exceeded $18,000,000, a bonus pool equal to 15% of the 2007 net income would be established, from which bonus awards would be made. Pursuant to the terms of the Senior Executive Plan, in determining whether and to what extent the performance target was achieved, the compensation committee relies on information contained in the Atlas America’s audited financial statements and other objectively determinable information. If the performance target was not achieved, no annual incentives would be awarded. Pursuant to the terms of the Senior Executive Plan, the compensation committee has the discretion to recommend the reduction, but not the increase, of the annual incentive 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 stockholders’ interests. To support this objective, we provide our executives with various means to become significant stockholders, including our long-term incentive programs. These awards are usually a combination of stock options, restricted units and phantom units which vest over four years to support long-term retention of executives and reinforce our longer-term goals. Our NEOs are eligible to receive awards under our Long-Term Incentive Plan, which we refer to as our Plan, 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 compensation committee may recommend grants of equity awards in the form of options and/or phantom units. In May 2007, our Plan was amended to meet the deductibility requirements of Section 162(m) when the awards are granted pursuant to pre-established performance goals.

Options—Options have a ten-year term and, in general, vest 25% on the third anniversary of the grant date, with the remaining 75% vesting on the fourth anniversary of the grant date.

Phantom Units—A phantom unit is a notional unit which, upon vesting, converts into a common unit in our company. Phantom units may be granted with or without tandem distribution equivalent rights, which we refer to as DERs. In general, grants of our phantom units vest 25% on the third anniversary of the grant date, with the remaining 75% vesting on the fourth anniversary of the grant date.

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.

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Supplemental Benefits, Deferred Compensation and Perquisites

We do not emphasize supplemental benefits for executives other than Mr. E. Cohen, and perquisites are discouraged. None of our NEOs have deferred any portion of their compensation.

Determination of 2007 Compensation Amounts

As described above, after the end of our 2007 fiscal year, the compensation committee set the base salaries of the Atlas America executives for the 2008 fiscal year and recommended incentive awards based on the prior year’s performance. In carrying out its function, the compensation committee acted in consultation with Mercer.

In determining the actual amounts to be paid to the Atlas America executives, the compensation committee looked to both the individual’s performance as well as to the overall performance of our company and our publicly-held subsidiaries during fiscal 2007. As described above, Atlas America allocates the cash compensation for our NEOs to us based upon an estimate of the time spent by such persons on activities for us and for Atlas America and its affiliates.

Base Salary. Consistent with its preference for having a significant portion of our NEOs’ overall compensation package be incentive compensation, the compensation committee decided to recommend that base salaries for 2008 be maintained at the same levels as 2007.

Annual Incentives.

Performance-Based Bonuses. The compensation committee reviewed Atlas America’s financial statements and determined that the 2007 net income exceeded the pre-determined minimum threshold. It accordingly recommended for approval awards under the Senior Executive Plan. The amount of these awards that were allocated to APL were as follows: Edward E. Cohen, $2,250,000; Jonathan Z. Cohen, $1,434,783; Matthew A. Jones, $900,000; and Robert R. Firth, $50,000.

Discretionary Bonuses. No discretionary bonuses were recommended by the compensation committee.

Long-Term Incentives. Additionally, the compensation committee recognized the importance of a long-term incentive component as a part of the 2007 compensation. The compensation committee recommended the award of Atlas America stock options as follows: Mr. E. Cohen—200,000 options; Mr. J. Cohen—160,000 options; and Mr. M. Jones—80,000 options. (These awards are not reflected in the Summary Compensation Table because we did not recognize expense for them in fiscal 2007). The compensation committee determined that it would not recommend that awards be made to our NEOs under our Plan, the ATN Plan or the APL Plan because it felt that previous awards were adequate.

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The following table sets forth the compensation allocation for fiscal year 2007 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.

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	2007	$	405,000		—	$	1,254,901	$	509,167	$	2,250,000	$	253,212	(3)	$	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	2007	$	135,000		—	$	356,912	$	409,128	$	900,000	$	75,062	(4)	$	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	2007	$	215,217		—	$	807,707	$	203,667	$	1,434,783	$	153,906	(5)	$	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	2007	$	250,000		—	$	12,370,293	$	443,393	$	50,000	$	118,512	(6)	$	13,232,198
	2006	$	250,000	$	150,000	$	1,806,506	$	61,100		—		—		$	2,267,606
Michael Staines, President	2007	$	191,250	$	42,500	$	61,148	$	19,198		—	$	21,770	(7)	$	336,136

⁽¹⁾ Represents the dollar amount of (i) expense we recognized 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 its incentive compensation arrangements, all in accordance with FAS 123R. See Note 14 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 $ 156,012 with respect to the phantom units awarded under the APL Plan and $97,200 with respect to phantom units awarded under our Plan.

⁽⁴⁾ Includes payments on DERs of $ 53,462 with respect to the phantom units awarded under the APL Plan and $ 21,600 with respect to phantom units awarded under our Plan.

⁽⁵⁾ Represents payments on DERs of $105,306 with respect to the phantom units awarded under the APL Plan and $48,600 with respect to phantom units awarded under our Plan.

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⁽⁶⁾ Represents payments on DERs of $67,912 with respect to the phantom units awarded under the APL Plan and its incentive compensation arrangements, and $48,600 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.

No awards were granted to our named executive officers under our Plan or the Atlas Plan in 2007.

2007 GRANTS OF PLAN-BASED AWARDS TABLE

Name	Grant Date	Approval Date	All Other Stock Awards: Number of Shares Of Stock or Units (#)		All Other Option Awards: Number of Securities Underlying Options (#)	Exercise or Base Price of Option Awards ($ / Sh)		Grant Date Fair Value of Stock and Option Awards
Robert R. Firth	1/24/07	1/22/07	23,000	(1)	—	$	42.85	$	2,306,000	(3)

⁽¹⁾ Represents grants of phantom units under the APL Plan, which vest 25% per year on the anniversary of the grant date, valued in accordance with FAS 123R at the closing price of our common units on the grant date of $42.85.

Employment Agreement

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.

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, 2007, 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.

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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, 2007, 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. In May 2007, Atlas America’s stockholders approved an amendment to our Plan which provides for performance-based awards criteria for purposes of complying with Section 162(m) of the Internal Revenue Code (“Section 162(m)”).

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, 2007, 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. No unit options have been granted under the APL Plan.

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. In May 2007, Atlas’s stockholders approved an amendment to the APL Plan which provides for performance-based awards criteria for purposes of complying with Section 162(m).

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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 29,412 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.

• 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 29,412 common units.

• 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 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.

The executive group incentive program awards will be allocated among members of the executive group at the discretion of Mr. Firth, provided that no member may receive more than 60% of the total compensation provided under the program.

Atlas Plan

The Atlas Plan authorizes the granting of up to 2.0 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

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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	675,000	(1)	—		$	16.98	7/1/2015	31,250	(2)	$	1,339,062	(3)
	—		500,000	(4)	$	22.56	11/10/2016	90,000	(5)	$	2,441,700	(6)
Matthew A. Jones	90,000	(7)	90,000	(8)	$	16.98	7/1/2015	11,250	(9)	$	482,062	(3)
	—		100,000	(10)	$	22.56	11/10/2016	20,000	(11)	$	542,600	(6)
Jonathan Z. Cohen	450,000	(12)	—		$	16.98	7/1/2015	21,250	(13)	$	910,562	(3)
	—		200,000	(14)	$	22.56	11/10/2016	45,000	(15)	$	1,220,850	(6)
Robert R. Firth	—		22,500	(16)	$	16.98	7/1/2015	18,750	(17)	$	803,438	(3)
	—		360,000	(18)	$	22.56	11/10/2016	45,000	(19)	$	1,220,850	(6)
Michael L. Staines	5,624	(20)	5,626	(21)	$	16.98	7/1/2015	4,000	(22)	$	171,400	(3)

⁽¹⁾ 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 May 29, 2007.

⁽²⁾ Represents APL phantom units, which vest as follows: 3/16/08 – 5,000; 6/8/08 – 6,250; 11/1/08 – 5,000; 3/16/09 – 5,000; 11/1/09 – 5,000 and 11/1/10 – 5,000.

⁽³⁾ Based on closing market price of APL common units on December 31, 2007 of $42.85.

⁽⁴⁾ Represents our options, which vest as follows: 11/10/09 – 125,000 and 11/10/10 – 375,000.

⁽⁵⁾ Represents our phantom units, which vest as follows: 11/10/09 – 22,500 and 11/10/10 – 67,500.

⁽⁶⁾ Based on closing market price of our common units on December 31, 2007 of $27.13.

⁽⁷⁾ Represents 90,000 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 May 29, 2007.

⁽⁸⁾ Represents options to purchase Atlas America stock, which vest as follows: 7/1/08 – 45,000 and 7/1/09 – 45,000.

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⁽⁹⁾ Represents APL phantom units, which vest as follows: 3/16/08 – 3,750; 11/1/08 – 1,250; 3/16/09 – 3,750; 11/1/09 – 1,250 and 11/1/10 – 1,250.

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

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

⁽¹²⁾ Represents 450,000 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 May 29, 2007.

⁽¹³⁾ Represents APL phantom units, which vest as follows: 3/16/08 – 3,125; 6/8/08 – 3,750; 11/1/08 – 3,750; 3/16/09 – 3,125; 11/1/09 – 3,750 and 11/1/10 – 3,750.

⁽¹⁴⁾ Represents our options, which vest as follows: 11/10/09 – 50,000 and 11/10/10 – 150,000.

⁽¹⁵⁾ Represents our phantom units, which vest as follows: 11/10/09 – 11,250 and 11/10/10 – 33,750.

⁽¹⁶⁾ Represents options to purchase Atlas America stock, which vest as follows: 7/1/08 – 11,250 and 7/1/09 – 11,250.

⁽¹⁷⁾ Represents APL phantom units, which vest as follows: 3/16/08 – 750; 1/24/09 –5,750; 3/16/09 – 750; 1/24/10 –5,750 and 1/24/11 – 5,750.

⁽¹⁸⁾ Represents our options, which vest as follows: 11/10/09 – 90,000 and 11/10/10 – 270,000.

⁽¹⁹⁾ Represents our phantom units, which vest as follows: 11/10/09 – 11,250 and 11/10/10 – 33,750.

⁽²⁰⁾ Represents 5,624 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 May 29, 2007.

⁽²¹⁾ Represents options to purchase Atlas America stock, which vest as follows: 7/1/08 – 2,813 and 7/1/09 – 2,813.

⁽²²⁾ Represents APL phantom units, which vest as follows: 3/16/08–1,000; 6/8/08—2,000; and 3/16/09 – 1,000.

2007 OPTION EXERCISES AND STOCK VESTED TABLE

	Option Awards			Stock Awards
Name	Number of Shares Acquired on Exercise (#)	Value Realized on Exercise ($)		Number of Shares Acquired on Vesting		Value Realized on Vesting ($)
Edward E. Cohen				16,250	(1)	$	818,500
Matthew A. Jones				5,000	(1)	$	239,375
Jonathan Z. Cohen				10,625	(1)	$	533,787
Robert R. Firth	22,500	$	701,550	750	(2)	$	36,750
Michael L. Staines				750	(1)	$	36,750

⁽¹⁾ Represents awards under APL Plan.

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

DIRECTOR COMPENSATION TABLE

Name	Fees Earned or Paid in Cash ($)		Stock Awards ($)			Total ($)
William G. Karis	$	35,000	$	7,519	(1)	$	42,579
Jeffrey C. Key	$	35,000	$	7,519	(1)	$	42,579
Harvey G. Magarick	$	35,000	$	7,519	(1)	$	42,579

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⁽¹⁾ Represents 500 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: 11/10/08 – 100; 11/10/09 – 100; 11/10/10 – 100; and 11/10/11-100.

Our general partner does not pay additional remuneration to officers or employees of Atlas America who also serve as members of our general partner’s board of directors. The annual retainer for non-employee directors is $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 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 STOCKHOLDER MATTERS

The following table sets forth the number and percentage of shares of common stock owned, as of February 25, 2008, 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 Corapolis Heights Road—2^nd Floor, Moon Township, Pennsylvania 15108.

Name of Beneficial Owner	Common Units		Percent of Class
Members of the Board of Directors
Edward E. Cohen	590,000	(1)	2.15	%
Jonathan Z. Cohen	246,000	(2)		*
Robert R. Firth	410,170	(3)	1.48	%
Matthew A. Jones	120,000	(4)		*
William G. Karis	900	(5)		*
Jeffrey C. Key	900	(5)		*
Harvey G. Magarick	900	(5)		*
Executive Officers
Sean P. McGrath	22,500	(6)		*
Lisa Washington	11,000	(7)		*
Executive officers and board of directors as a group (9 persons)	1,402,370		4.88	%
Other Owners of More than 5% of Outstanding Units
Atlas America, Inc.	17,500,000	(8)	63.98	%
Swank Capital, LLC	3,022,218	(9)	11.05	%

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* 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 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.

⁽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 775 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: 11/10/08—225; 11/10/09—225; 11/10/10—225; and 11/10/11—100.

⁽⁶⁾ 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.

⁽⁷⁾ 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.

⁽⁸⁾ This information is based on a Schedule 13 D/A which was filed with the SEC on February 29, 2008.

⁽⁹⁾ This information is based on a Schedule 13G which was filed with the SEC on February 14, 2008. The address for Swank Capital, LLC is 330 Oak Lawn Avenue, Suite 650, Dallas, TX 75219.

Equity Compensation Plan Information

The following table contains information about our Plan as of December 31, 2007:

	(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	220,825		n/a
Equity compensation plans approved by security holders – unit options	1,215,000	$	22.56
Equity compensation plans approved by security holders – Total	1,435,825			663,800

The following table contains information about the APL Plan as of December 31, 2007:

	(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	129,746	n/a	208,055

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The following table contains information about the Atlas Plan as of December 31, 2007:

	(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	4,263		n/a
Equity compensation plans approved by security holders – options	1,810,254	$	18.15
Equity compensation plans approved by security holders – Total	1,814,517			1,112,565

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE MATTERS

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 $5.9 million for the year ended December 31, 2007 for compensation and benefits related to their employees, and reimbursed $26.4 million for other indirect costs, including certain costs that APL capitalized. 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.

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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Aggregate fees recognized by us during the years ending December 31, 2007 and 2006 by our principal accounting firm, Grant Thornton LLP, are set forth below:

	2007		2006
Audit fees(1)	$	1,795,631	$	1,418,838
Audit related fees		—		—
Tax fees(2)		209,568		94,973
Total aggregate fees billed	$	2,005,199	$	1,513,811

⁽¹⁾ Represents the aggregate fees recognized in 2007 and 2006 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 2006.

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	Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Holdings, L.P.(2)
4.1	Specimen Certificate Representing Common Units(1)
10.1	Certificate of Formation of Atlas Pipeline Holdings GP, LLC(1)
10.2	Amended and Restated Limited Liability Company Agreement of Atlas Pipeline Partners GP, LLC(1)
10.3	Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.(1)
10.3(a)	Amendment No. 2 to Second Amendment and Restated Agreement of Limited Partnership(3)
10.4	Common Unit Purchase Agreement among Atlas Pipeline Partners, L.P. and the purchasers named therein dated June 1, 2007(4)

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10.5	Common Unit Purchase Agreement among Atlas Pipeline Holdings, L.P. and the purchasers named therein dated June 1, 2007(4)
10.6	Registration Rights Agreement dated July 27, 2007(3)
14.1	Pre-Clearance Procedures Memorandum, as amended October 23, 2007(5)
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 July 30, 2007.

⁽⁴⁾ Previously filed as an exhibit to current report on Form 8-K filed June 5, 2007.

⁽⁵⁾ Previously filed as an exhibit to current report on Form 8-K filed October 26, 2007.

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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 3, 2008	By:	/s/ EDWARD E. COHEN
		Chairman of the Board

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 3, 2008.

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

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