UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2005

OR

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

For the transition period from                      to                     

Commission file number: 1-14998

ATLAS PIPELINE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

DELAWARE		23-3011077
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)
311 Rouser Road
Moon Township, Pennsylvania		15108
(Address of principal executive office)		(Zip code)

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

None

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

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

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

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

     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 o		Accelerated filer þ		Non-accelerated filer o

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

     The aggregate market value of the equity securities held by non-affiliates of the registrant, based upon the closing price of $43.61 per limited partner unit on June 30, 2005, was approximately $342.9 million.

 

 

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
INDEX TO ANNUAL REPORT
ON FORM 10-K

						Page
PART I
		Item 1:		Business			3
		Item 1A:		Risk Factors			21
		Item 2:		Properties			32
		Item 3:		Legal Proceedings			32
		Item 4:		Submission of Matters to a Vote of Security Holders			33
PART II
		Item 5:		Market for Registrant’s Common Equity and Related Unitholder Matters			33
		Item 6:		Selected Financial Data			34
		Item 7:		Management’s Discussion and Analysis of Financial Condition and Results of Operations			37
		Item 7A:		Quantitative and Qualitative Disclosures About Market Risk			52
		Item 8:		Financial Statements and Supplementary Data			56
		Item 9:		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			86
		Item 9A:		Controls and Procedures			86
PART III
		Item 10:		Directors and Executive Officers of the Registrant			90
		Item 11:		Executive Compensation			94
		Item 12:		Security Ownership of Certain Beneficial Owners and Management			97
		Item 13:		Certain Relationships and Related Transactions			98
		Item 14:		Principal Accountant Fees and Services			99
PART IV
		Item 15:		Exhibits and Financial Statement Schedules			100
SIGNATURES							101
Subsidiaries of Registrant
Consent of Grant Thornton LLP
Rule 13a-14(a)/15d-14(a) Certification
Rule 13a-14(a)/15d-14(a) Certification
Section 1350 Certification
Section 1350 Certification
Audited Balance Sheet of Atlas Pipeline Partners GP, LLC

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 volatility of natural gas prices and demand for natural gas and natural gas liquids;
	•		our ability to connect new wells to our gathering systems;
	•		our ability to integrate newly acquired businesses with our 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 our competitors.

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

PART I

ITEM 1. BUSINESS

General

     We are a Delaware limited partnership formed in May 1999 to acquire, own and operate natural gas gathering systems previously owned by Atlas America, Inc. and its affiliates (“Atlas America”), a publicly traded company (NASDAQ: ATLS). We provide midstream energy services through the transmission, gathering and processing of natural gas in the Appalachian and Mid-Continent areas of the United States, specifically Pennsylvania, Ohio, New York, Oklahoma, Texas, Arkansas and Missouri. We conduct our business through two operating segments: our Mid-Continent operations and our Appalachian operations.

     We own and operate through our Mid-Continent operations:

	•		a 75% interest in a Federal Energy Regulatory Commission (“FERC”)-regulated, 565-mile interstate pipeline system, that extends from southeastern Oklahoma through Arkansas and into southeastern Missouri and has throughput capacity of approximately 322 MMcf/d;
	•		two natural gas processing plants with aggregate capacity of approximately 230 MMcf/d and one treating facility with a capacity of approximately 200 MMcf/d, all located in Oklahoma; and
	•		1,765 miles of active natural gas gathering systems located in Oklahoma, Arkansas, northern Texas and the Texas panhandle, which transport gas from wells and central delivery points in the Mid-Continent region to our natural gas processing plants or Ozark Gas Transmission.

     We own and operate through our Appalachian operations 1,500 miles of intrastate natural gas gathering systems located in eastern Ohio, western New York and western Pennsylvania. Through an omnibus agreement and other agreements between us and Atlas America, the parent of our general partner and a leading sponsor of natural gas drilling investment partnerships in the Appalachian Basin, we gather substantially all of the natural gas for our Appalachian Basin operations from wells operated by Atlas America. Among other things, the omnibus agreement requires Atlas America to connect to our gathering systems wells it operates that are located within 2,500 feet of our gathering systems. We are also party to natural gas gathering agreements with Atlas America under which we receive gathering fees generally equal to a percentage, typically 16%, of the selling price of the natural gas we transport. These agreements are continuing obligations and have no specified term except that they will terminate if our general partner is removed without cause.

     Since our initial public offering in January 2000, we have completed five acquisitions at an aggregate cost of approximately $521.1 million, including, most recently, our October 2005 acquisition of Atlas Arkansas Pipeline LLC (“Atlas Arkansas”), which owns a 75% interest in NOARK Pipeline System Limited Partnership (“NOARK”), and our April 2005 acquisition of Elk City.

     Both our 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 and our gathering systems are connected to approximately 6,300 central delivery points or wells, giving us significant scale in our service areas. We provide gathering and processing services to the wells connected to our systems, primarily under long-term contracts. We provide fee-based, FERC-regulated transmission services through Ozark Gas Transmission under both long-term and short-term contractual arrangements. We intend to increase the portion of the transmission services provided under long-term contracts.

Recent Acquisition

     On October 31, 2005, we acquired from Enogex, Inc., a wholly-owned subsidiary of OGE Energy Corp. (NYSE: OGE), all of the outstanding equity of Atlas Arkansas, which owns a 75% interest in NOARK, for $179.8 million, including $16.8 million for working capital adjustments and other related transaction costs. The remaining 25% interest in NOARK is owned by Southwestern Energy Pipeline Company, a wholly-owned subsidiary of Southwestern Energy Company (NYSE: SWN). Prior to the closing of our acquisition, Atlas Arkansas converted from an Oklahoma corporation into an Oklahoma limited liability company and changed its name from Enogex Arkansas Pipeline Company. The NOARK acquisition further expands our activities in the Mid-Continent region and provides an additional source of fee-based cash flows from a FERC-regulated interstate pipeline system and an intrastate gas gathering system. NOARK’s geographic position relative to our other businesses and interconnections with major interstate pipelines also provides us with organic growth opportunities. NOARK’s principal assets include:

	•		The Ozark Gas Transmission system, a 565-mile FERC-regulated interstate pipeline system which extends from southeastern Oklahoma through Arkansas and into southeastern Missouri and has a throughput capacity of approximately 322 MMcf/d. The system includes approximately 30 supply and delivery interconnections and two compressor stations.
	•		The Ozark Gas Gathering system, a 365-mile intrastate natural gas gathering system, located in eastern Oklahoma and western Arkansas, and 11 associated compressor stations.

     We temporarily financed the acquisition by borrowing under our revolving credit facility and have since reduced those borrowings with proceeds from our November 2005 equity offering and senior notes issuance. We expect the NOARK acquisition to be immediately accretive to our distributable cash flow per unit.

     Ozark Gas Transmission transports natural gas from receipt points in eastern Oklahoma and western Arkansas, where the Arkoma Basin is located, to interstate pipelines in northeastern and central Arkansas and to local distribution companies in Arkansas and Missouri. Ozark Gas Gathering provides access to natural gas supplies that are then transported through Ozark Gas Transmission. Ozark Gas Transmission’s revenues are comprised of FERC-regulated transmission fees that are based on firm transportation rates and, to the extent capacity is available following the reservation of firm system capacity, interruptible transportation rates.

     Our gas supply strategy in the Mid-Continent region is to establish long-term, value-oriented relationships with our producing customers. We have long-standing relationships with many of our Mid-Continent customers which account for a substantial majority of our gathering and processing throughput. The Mid-Continent region, one of the most prolific natural gas-producing regions in North America, has recently experienced a significant increase in oil and gas drilling activity driven by long-term projections of continued growth in U.S. natural gas demand and the application of new drilling and production technologies.

     NOARK’s subsidiary, NOARK Pipeline Finance, L.L.C., has $39.0 million in principal amount outstanding of 7.15% notes due in 2018 as of December 31, 2005. The liability under the notes is allocated 100% to Southwestern, but Atlas Arkansas and Southwestern are several guarantors for the amount outstanding. Under the NOARK partnership agreement, interest and principal payments on the notes will be made from amounts otherwise distributable to Southwestern and, if that amount is insufficient, Southwestern is required to make a capital contribution to NOARK. NOARK distributes available cash to the partners in accordance with their ownership interests after deduction of their respective portion of amounts payable on the notes.

Contracts and Customer Relationships

     In our Mid-Continent operations, we either purchase gas from producers, or intermediaries, into receipt points on our systems and then sell the gas, and produced natural gas liquids (“NGLs”), if any, off of delivery points on our systems, or we transport gas across our systems, from receipt to delivery point, without taking title to the gas. Beyond the distinction of purchasing or transporting gas, we have a variety of contractual relationships with our producers and shippers, including fixed-fee, percentage-of-proceeds and keep-whole. Ozark Gas Transmission’s revenues are comprised of FERC-regulated transmission fees that are based on firm transportation rates and, to the extent capacity is available following the reservation of firm system capacity, interruptible transportation rates. Under the fixed fee contracts, we provide gathering, compression, treating and dehydration services to our customers for a flat fee. Gross margin from fee-based services depends solely on throughput volume and is not affected by changes in commodity prices. Under the percentage-of-proceeds contracts, we purchase natural gas at the wellhead, process the natural gas and sell the plant residue gas and NGLs at market-based prices, remitting to producers a percentage of the proceeds. Under keep-whole contracts, we gather natural gas from the producer, process the natural gas and sell the resulting NGLs at market price. The extraction of the NGLs lowers the British thermal unit (“Btu”) content of the natural gas. Therefore, under keep-whole contracts, we must replace these Btus by either purchasing natural gas at market prices or making a

cash payment to the producer and our profitability is dependent upon the spread between the price of natural gas, our feedstock, and NGLs, our “manufactured” product. The gross margin associated with each of these contractual arrangements can vary from period to period due to a variety of factors, including changing prices of natural gas and NGLs, producers’ optionality between contract types (e.g., percentage-of-proceeds and keep-whole), and producers’ optionality between transporting and selling gas.

     Substantially all of the gas we transport in our Appalachian operations is under a percentage-of-proceeds contract with Atlas America where we calculate our transportation fee as a percentage of the price of the natural gas we transport. The natural gas we transport in our Appalachian operations does not require processing.

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 our Velma service area, 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 gas. Natural gas processing plants generally treat (remove carbon dioxide and hydrogen sulfide) and remove the NGLs, enabling the treated, “dry” gas (stripped of liquids) to meet pipeline specification for long-haul transport to end users. After being separated from natural gas at the processing plant, the mixed NGL stream, commonly referred to as “y-grade” or “raw mix,” is typically transported on pipelines to a centralized facility for fractionation into discrete NGL purity products: ethane, propane, normal butane, isobutane, and natural gasoline.

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

Our Mid-Continent Operations

     We own and operate a 565-mile interstate natural gas pipeline, approximately 2,565 miles of intrastate natural gas gathering systems, including approximately 800 miles of inactive pipeline, located in Oklahoma, Arkansas, southeastern Missouri, northern Texas and the Texas panhandle, and two processing plants and one stand-alone treating facility in Oklahoma. Our Mid-Continent operations were formed through our acquisition of Spectrum, also referred to as our Velma system, in July 2004 and expanded through our Elk City acquisition in April 2005 and the NOARK acquisition in October 2005. 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. Ozark Gas Gathering provides access to natural gas supplies that are then transported through Ozark Gas Transmission. Our 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 and the Golden Trend area of Oklahoma. Our 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, our Mid-Continent systems have approximately 1,160 receipt points, consisting primarily of individual connections and, secondarily, of central delivery points which are linked to multiple wells. Our gathering systems currently connect 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, Texas Eastern Transmission Corp., Mississippi River Transmission Corp. 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 North and West 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

     We own a 75% interest in NOARK, which owns a 565-mile FERC-regulated natural gas interstate pipeline extending from southeastern Oklahoma through Arkansas and into southeastern Missouri. Ozark Gas Transmission delivers natural gas via 30 supply and delivery interconnects with major intrastate and interstate pipelines, including Mississippi River Transmission Corp., Natural Gas Pipeline Company of America and Texas Eastern Transmission Corp., and receives natural gas from eight interconnects with intrastate pipelines, including Enogex, BP’s Vastar gathering system, Arkansas Oklahoma Gas Corporation, Arkansas Western Gas Company and ONEOK Gas Transmission.

Gathering Systems

     Velma. The Velma gathering system is located in the Golden Trend area of Southern Oklahoma and the Barnett Shale area of North Texas. As of December 31, 2005, the gathering system had approximately 1,100 miles of active pipeline with approximately 580 receipt points consisting primarily of individual connections and, secondarily, of 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.

     Elk City. The Elk City gathering system includes approximately 300 miles of natural gas pipelines located in the Anadarko Basin in western Oklahoma and the Texas panhandle. The Elk City gathering system connects to over 300 receipt points, with a majority of the western end of the system located in close proximity to areas of high drilling activity. We recently completed three new gathering and compression projects which will increase gathered volumes and, we believe, have a significant positive effect on our gross margin.

     Ozark Gas Gathering. NOARK owns Ozark Gas Gathering, 365 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 Shale. This system connects to approximately 250 receipt points and compresses and transports gas to interconnections with Ozark Gas Transmission.

Processing Plants

     Velma. The Velma processing plant, located in Stephens County, Oklahoma, is a single-train twin-expander cryogenic facility with a natural gas capacity of approximately 100 MMcf/d. 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 gas. We sell natural gas to purchasers at the tailgate of the Velma plant and sell NGL production to ONEOK Hydrocarbons Company. Our Velma operations gather and process natural gas for approximately 150 producers. We have 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 our competitors, which results in higher revenues from higher efficiency and lower fuel costs.

     Elk City. The Elk City processing plant, located in Beckham County, Oklahoma, is a twin-train cryogenic natural gas processing plant with a total capacity of approximately 130 MMcf/d. We sell natural gas to purchasers at the tailgate of our Elk City processing plant and sell NGL production to ONEOK Hydrocarbons Company. The Prentiss treating facility, also located in Beckham County, is an amine treating facility with a total capacity of approximately 200 MMcf/d. Our Elk City operations gather and process gas for more than 135 producers.

     Sweetwater. We plan to complete construction of the Sweetwater gas processing facility near our Prentiss treatment plant during the third quarter of 2006. The new plant will initially be scaled to 120 MMcf/d of processing capacity. Along with the plant, we will construct a gathering system to be located primarily in Beckham and Roger Mills counties in Oklahoma and Hemphill County, Texas. We anticipate that construction of the plant and associated gathering system will cost approximately $40.0 million and generate cash flow of $8.0 million to $10.0 million annually.

     Enville. Our Enville, Oklahoma gas plant is currently inactive and is used as a field compression booster station.

NOARK Partnership

     NOARK is an Arkansas limited partnership in which Atlas Arkansas owns a 74% general partner interest and a 1% limited partner interest and Southwestern owns a 25% general partner interest. The current configuration of NOARK’s assets was completed in 1998 when Enogex acquired its interest in the partnership, which at that point owned Ozark Gas Gathering, and acquired Ozark Gas Transmission and certain Warren Petroleum gathering assets and contributed them to the partnership.

     The partnership is managed by a five-member management committee comprised of the partnership’s project leader appointed by Atlas Arkansas, subject to Southwestern’s consent which cannot be unreasonably withheld, two members appointed by Atlas Arkansas and two members appointed by Southwestern. The management committee determines whether to distribute cash, may issue mandatory capital calls to the partners and may conduct expansion projects. It is NOARK’s policy to distribute the maximum amount of cash available after taking into account anticipated future sources of cash and working capital, and cash requirements to meet current and anticipated future obligations. An expansion to the system not included in an approved budget requires an 80% vote of the partners; if a partner does not consent to an expansion within 30 days, the other partner may fund the project and receive a cash distribution equal to all of the net operating income attributable to the project until it has received 200% of its capital contribution, before the non-consenting partner receives distributions attributable to the project.

     Under the partnership agreement, day-to-day management of the partnership’s operations is the responsibility of the project leader, who will be an employee of Atlas America. Atlas Arkansas has the sole power to remove the project leader and, upon a vacancy in that position, to propose a new project leader, subject to the consent of Southwestern, not to be unreasonably withheld.

     NOARK’s subsidiary, NOARK Pipeline Finance, L.L.C., has $39.0 million in principal amount outstanding of 7.15% notes due in 2018 as of December 31, 2005. The liability under the notes is allocated 100% to Southwestern, but Atlas Arkansas and Southwestern are several guarantors for the amount outstanding. Under the partnership agreement, interest and principal payments on the notes will be made from amounts

otherwise distributable to Southwestern and, if that amount is insufficient, Southwestern is required to make a capital contribution to NOARK. NOARK distributes available cash to the partners in accordance with their ownership interests after deduction of their respective portion of amounts payable on the notes.

Natural Gas Supply

     In the Mid-Continent, we have gas purchase, gathering and processing agreements with approximately 250 producers with terms ranging from one month to 15 years. These agreements provide for the purchase or gathering of 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 gas and to operate the Velma and Elk City processing plants. In addition, the producers generally bear their proportionate share of gathering system line loss and, except for keep-whole arrangements, bear gas plant “shrinkage,” or the gas consumed in the production of NGL.

     We have enjoyed long-term relationships with the majority of our Mid-Continent producers. For instance, on the Velma system, where we have producer relationships going back over 20 years, our top four producers, which accounted for a significant portion of our Velma volumes for the year ended December 31, 2005, have recently executed renegotiated contracts with primary terms running into 2009 and 2010. At the end of the primary terms, most of the contracts with producers on our gathering systems have evergreen term extensions

Natural Gas and NGL Marketing

     We sell natural gas to purchasers at the tailgate of both the Velma and Elk City plants and at various delivery points on Ozark Gas Gathering. We currently sell the majority of our residue natural gas at the average of ONEOK Gas Transportation, LLC and Southern Star Central Gas Pipeline first-of-month indices as published in Inside FERC. The Velma plant has access to ONEOK Gas Transportation, an intrastate pipeline, and Southern Star Central Gas Pipeline, an interstate pipeline. In our Elk City operations, we sell substantially all of our residue gas to ONEOK Energy Marketing, at first-of-month index pricing. The Elk City plant has 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 and Enogex. Ozark Gas Gathering gas prices are generally based on Texas Eastern “East LA” index as published in Inside FERC and have historically been sold to affiliates of Enogex and Southwestern.

     We sell our NGL production to ONEOK Hydrocarbons Company under two separate agreements. Under the Velma agreement, we have the right to elect on a monthly basis until January 31, 2006 whether the NGLs are sold into the Mont Belvieu or Conway markets. After that, NGLs will be sold on a 50% Mont Belvieu/50% Conway combined price. NGLs are priced at the average monthly Oil Price Information Service, or OPIS, price for the selected market. The Velma agreement has an initial term expiring February 1, 2011. NGL production from our Elk City plant is also sold to ONEOK Hydrocarbons Company based on Conway OPIS postings. The Elk City agreement has an initial term expiring October 1, 2008.

     Condensate is collected at the Velma gas plant and around the Velma gathering system and sold for our account to SemGroup, L.P. and EnerWest Trading while that collected at Elk City is sold to TEPPCO Crude Oil, L.P.

Natural Gas and NGL Hedging

     Our 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. We mitigate 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.

     We (a) purchase natural gas and subsequently sell processed natural gas and the resulting NGLs, or (b) purchase natural gas and subsequently sell the unprocessed gas, or (c) transport and/or process the natural gas for a fee without taking title to the commodities. Scenario (b) exposes us to a generally neutral price risk (long sales approximate short purchases) while scenario (c) does not expose us to any price risk; in both scenarios, risk management is not required. Scenario (a) does involve some amount of commodity risk.

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

	•		Percentage-of-proceeds: require us to pay a percentage of revenue to the producer. This results in our being net long physical natural gas and NGLs.
	•		Keep-whole: require us to deliver the same quantity of natural gas at the delivery point as we received at the receipt point; any resulting NGLs produced belong to us. This results in our being long physical NGLs and short physical natural gas.

     We hedge 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.

     We recognize gains and losses from the settlement of our hedges in revenue when we sell 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 we sell the physical residue natural gas or NGLs. All of our hedges are characterized as cash flow hedges as defined in SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” We determine 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, we have established a hedging committee to review our hedges for compliance with our hedging policies and procedures. Our revolving credit facility prohibits speculative hedging and limits our overall hedge position to 80% of our equity volumes. In addition, we do not enter into a hedge where we cannot offset the hedge with physical residue natural gas or NGL sales.

     For additional information on our hedging activities and a summary of our outstanding hedging instruments as of December 31, 2005, please see Item 7A, “Quantitative and Qualitative Disclosures About Market Risk.”

Our Appalachian Basin Operations

     We own and operate approximately 1,500 miles of intrastate gas gathering systems located in eastern Ohio, western New York and western Pennsylvania. Our Appalachian operations serve approximately 5,150 wells with an average throughput of 55.2 MMcf/d of natural gas for the year ended December 31, 2005. Our 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, our gathering systems transport natural gas directly to customers. Our gathering systems connect with public utility pipelines operated by Peoples Natural Gas Company, National Fuel Gas Supply, Tennessee Gas Pipeline Company, National Fuel Gas Distribution Company, East Ohio Gas Company, Columbia Gas of Ohio,

Consolidated Natural Gas Co., Texas Eastern Pipeline, Columbia Gas Transmission Corp., Equitrans Pipeline Company, Gatherco Incorporated and Equitable Utilities. Our 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.

Appalachian Basin Overview

     The Appalachian Basin includes the states of Kentucky, Maryland, New York, Ohio, Pennsylvania, Virginia, West Virginia and Tennessee. It is the most mature oil and gas producing region in the United States, having established the first oil production in 1859. In addition, the Appalachian Basin is strategically located near the energy-consuming regions of the mid-Atlantic and northeastern United States, which has historically resulted in Appalachian producers selling their natural gas at a premium to the benchmark price for natural gas on the NYMEX.

Natural Gas Supply

     Substantially all of the natural gas we transport in the Appalachian Basin is derived from wells operated by Atlas America, a leading sponsor of natural gas drilling investment partnerships in the Appalachian Basin. Atlas America is the corporate parent of our general partner and, through it, has a 2% general partner interest and a 12.8% limited partner interest in us. We are party to an omnibus agreement with Atlas America which is intended to maximize the use and expansion of our gathering systems and the amount of natural gas which we transport in the region. Among other things, the omnibus agreement requires Atlas America to connect to our gathering systems wells it operates that are located within 2,500 feet of our gathering systems. Atlas America can require us to extend our lines to connect an Atlas America-operated well located more than 2,500 feet from our gathering system if it extends a flow line to within 1,000 feet; for other Atlas America-operated wells located more than 2,500 feet from our gathering systems, we have a right to extend our lines. We are also a party to natural gas gathering agreements with Atlas America, under which we receive gathering fees generally equal to a percentage, typically 16%, of the selling price of the natural gas we transport. From the inception of our operations in January 2000 through December 31, 2005, we connected 2,135 new wells to our Appalachian gathering system, 433 of which were added through acquisitions of other gathering systems. For the year ended December 31, 2005, we connected 451 wells to our gathering system. Our ability to increase the flow of natural gas through our gathering systems and to offset the natural decline of the production already connected to our gathering systems will be determined primarily by the number of wells drilled by Atlas America and connected to our gathering systems and by our ability to acquire additional gathering assets.

Natural Gas Revenues

     Our Appalachian Basin revenues are determined primarily by the amount of natural gas flowing through our gathering systems and the price received for this natural gas. We have an agreement with Atlas America under which it pays us gathering fees generally equal to a percentage, typically 16%, of the gross or weighted average sales price of the natural gas we transport subject, in most cases, to minimum prices of $0.35 or $0.40 per Mcf. For the year ended December 31, 2005, we received gathering fees averaging $1.21 per Mcf. We charge other operators fees negotiated at the time we connect their wells to our gathering systems or, in a pipeline acquisition, that were established by the entity from which we acquired the pipeline.

     Because we do not buy or sell gas in connection with our Appalachian operations, we do not engage in hedging. Atlas America maintains a hedging program. Since we receive transportation fees from Atlas America generally based on the selling price received by Atlas America inclusive of the effects of financial and physical hedging, these financial and physical hedges mitigate the risk of our percentage-of-proceeds arrangements.

Our Relationship with Atlas America

     We began our operations in January 2000 by acquiring the gathering systems of Atlas America. Atlas America owns a 12.8% limited partner interest and a 2% general partner interest in us through its ownership of our general partner. Atlas America 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. Our gathering systems are connected to approximately 4,600 wells developed and operated by Atlas America in the Appalachian Basin. Through agreements between us and Atlas America, we gather substantially all of the natural gas for our Appalachian Basin operations from wells operated by Atlas America.

Omnibus Agreement

     Under the omnibus agreement, Atlas America and its affiliates agreed to add wells to the gathering systems and provide consulting services when we construct new gathering systems or extend existing systems. The omnibus agreement also imposes conditions upon our general partner’s disposition of its general partner interest in us. The omnibus agreement is a continuing obligation, having no specified term or provisions regarding termination except for a provision terminating the agreement if our general partner is removed as general partner 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 the reasonable discretion of our general partner, such amendment will adversely affect the common unitholders.

     Well Connections. Under the omnibus agreement, with respect to any well Atlas America drills and operates for itself or an affiliate that is within 2,500 feet of one of our gathering systems, Atlas America 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 America well is located more than 2,500 feet from one of our gathering systems, but Atlas America has extended the flow line from the well to within 1,000 feet of the gathering system, Atlas America has the right to require us, at our cost and expense, to extend our gathering system to connect to that well. With respect to other Atlas America wells that are more than 2,500 feet from our gathering systems, we have the right, at our cost and expense, to extend our gathering system to within 2,500 feet of the well and to require Atlas America, at its cost and expense, to construct up to 2,500 feet of flow line to connect to the gathering system extension. If we elect not to exercise our right to extend our gathering systems, Atlas America may connect an Atlas America well to a natural gas gathering system owned by someone other than us or one of our subsidiaries or to any other delivery point; however, we will have the right to assume the cost of construction of the necessary flow lines, which then become our property and part of our gathering systems.

     Consulting Services. The omnibus agreement requires Atlas America to assist us in identifying existing gathering systems for possible acquisition and to provide consulting services to us in evaluating and making a bid for these systems. Atlas America must give us notice of identification by it or any of its affiliates of any gathering system as a potential acquisition candidate, and must provide us with information about the gathering system, its seller and the proposed sales price, as well as any other information or analyses compiled by Atlas America with respect to the gathering system. We will have 30 days to determine whether we want to acquire the identified system and advise Atlas America of our intent. If we intend to acquire the system, we have an additional 60 days to complete the acquisition. If we do not complete the acquisition, or advise Atlas America that we do not intend to acquire the system, then Atlas America may do so.

     Gathering System Construction. The omnibus agreement requires Atlas America to provide us with construction management services if we determine to expand one or more of our gathering systems. We must reimburse Atlas America for its costs, including an allocable portion of employee salaries, in connection with its construction management services.

     Disposition of Interest in Our General Partner. Direct and indirect wholly-owned subsidiaries of Atlas America act as the general partners, operators or managers of the drilling investment partnerships sponsored by Atlas America. Our general partner is a subsidiary of Atlas America. Under the omnibus agreement, those subsidiaries, including our general partner, that currently act as the general partners, operators or managers of partnerships sponsored by Atlas America must also act as the general partners, operators or managers for all new drilling investment partnerships sponsored by Atlas America. Atlas America and its affiliates may not divest their ownership of our general partner entity without divesting their ownership of the other entities to the same acquirer, except that Atlas America is permitted to transfer its interest in our general partner to a wholly- or majority-owned direct or indirect subsidiary as long as Atlas America continues to control the new entity. For these purposes, divestiture means a sale of all or substantially all of the assets of an entity, the disposition of more than 50% of the capital stock or equity interest of an entity, or a merger or consolidation that results in Atlas America and its affiliates, on a combined basis, owning, directly or indirectly, less than 50% of the entity’s capital stock or equity interest, but excludes pledges to a lender in connection with a secured funding arrangement. Our general partner has pledged its interests in us as security for the revolving credit facility of Atlas America.

     Atlas America’s wholly-owned subsidiary, Atlas Pipeline Holdings, L.P., recently filed a registration statement with the Securities and Exchange Commission for an initial public offering of 3.6 million common units, representing an approximate 17.1% ownership interest in it. Upon completion of this offering, Atlas Pipeline Holdings, L.P. will own our general partner. The registration statement has not yet become effective. This report does not constitute an offer to sell or a solicitation of an offer to buy any such securities.

Natural Gas Gathering Agreements

     Under the master natural gas gathering agreement, we receive a fee from Atlas America 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 our 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 America that drill wells on or after December 1, 1999 that are connected to our gathering systems (ii) natural gas from well interests allocable to Atlas America or its affiliates (excluding general or limited partnerships sponsored by them) that are connected to our gathering systems after February 2, 2000, and (iii) well interests allocable to third parties in wells connected to our 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 America and drilled after December 1, 1999 that are connected to a gathering system that is not owned by us and for which we assume 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 America receives gathering fees from contracts or other arrangements with third party owners of well interests connected to our gathering systems. However, Atlas America must pay gathering fees owed to us 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 our general partner is removed as our general partner without cause, then no gathering fees will be due under the agreement with respect to new wells drilled

by Atlas America. 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 the common unitholders.

     In addition to the master natural gas gathering agreement, we have three other gas gathering agreements with subsidiaries of Atlas America. Under two of these agreements, relating to wells located in southeastern Ohio which Atlas America acquired from Kingston Oil Corporation and wells located in Fayette County, Pennsylvania which Atlas America acquired from American Refining and Exploration Company, we receive a fee of $0.80 per Mcf. Under the third agreement, which covers wells owned by third parties unrelated to Atlas America or the investment partnerships it sponsors, we receive 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 we transport.

     We recently amended the gas gathering agreements with Atlas America to provide that the “gross sales price,” for purposes of the agreements, will mean the price that is actually received, adjusted to take into account proceeds received or payments made pursuant to financial hedging arrangements.

Competition

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

     Mid-Continent. In our Mid-Continent service area, we compete 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, Eagle Rock Midstream Resources, L.P., and Enbridge. We believe 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.

     We believe that our relationships with operators connected to our system are good and that we present an attractive alternative for producers. However, if we cannot compete successfully, we may be unable to obtain new well connections and, possibly, could lose wells already connected to our 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. Our Appalachian Basin operations do not encounter direct competition in their service areas since Atlas America controls the majority of the drillable acreage in each area. However, because our Appalachian Basin operations principally serve wells drilled by Atlas America, we are affected by competitive factors affecting Atlas America’s ability to obtain properties and drill wells, which affects our ability to expand our gathering systems and to maintain or increase the volume of natural gas we transport and, thus, our transportation revenues. Atlas America also may encounter competition in obtaining drilling services from third-party providers. Any competition it encounters could delay Atlas America in drilling wells for its

sponsored partnerships, and thus delay the connection of wells to our gathering systems. These delays would reduce the volume of gas we otherwise would have transported, thus reducing our potential transportation revenues.

     As our omnibus agreement with Atlas America generally requires it to connect wells it operates to our system, we do not expect any direct competition in connecting wells drilled and operated by Atlas America in the future. In addition, we occasionally connect wells operated by third parties. For the year ended December 31, 2005, we connected 16 third party wells.

Regulation

     Regulation by FERC of Interstate Natural Gas Pipelines. FERC regulates our interstate natural gas pipeline interests. Through Atlas Arkansas, we own a 75% interest in NOARK, which owns Ozark Gas Transmission. 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 our 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 not charge rates that have been determined not to be just and reasonable by FERC. In addition, FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.

     The rates, 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 our 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. We own a number of intrastate natural gas pipelines in New York, Pennsylvania, Ohio, Arkansas, Texas and Oklahoma that we believe 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 our 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 our gathering systems for public safety purposes. Our operating subsidiary has been granted an exemption by the Public Utilities Commission of Ohio for our Ohio facilities. The New York Public Service Commission imposes traditional public utility regulation on the transportation of natural gas by companies subject to its regulation. This regulation includes rates, services and siting authority for the construction of certain facilities. Our gas gathering operations currently are not subject to regulation by the New York Public Service Commission. Our 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, our operations in Arkansas are not subject to regulatory oversight by the Arkansas Public Service Commission. In the event the Arkansas, Ohio, New York or Pennsylvania authorities seek to regulate our operations, we believe that our operating costs could increase and our transportation fees could be adversely affected, thereby reducing our net revenues and ability to make distributions to unitholders.

     We are currently subject to state ratable take and common purchaser statutes in Texas and Oklahoma. The ratable take statutes generally require gatherers to take, without discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas.

     The state of Oklahoma has adopted a complaint-based statute that allows the Oklahoma Corporation Commission to resolve grievances relating to natural gas gathering access and to remedy discriminatory rates for providing gathering service where the parties are unable to agree. In a similar way, the Texas Railroad Commission sponsors a complaint procedure for resolving grievances about natural gas gathering access and rate discrimination. No such complaints have been made against our Mid-Continent operations to date in Oklahoma or Texas.

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

     Our gathering operations also may be or 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 our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

     Sales of Natural Gas. A portion of our revenues is tied to the price of natural gas. The 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 our 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 we will be affected by any such FERC action materially differently than other companies with whom we compete.

     Energy Policy Act of 2005. On August 8, 2005, the Energy Policy Act of 2005 was signed into law. 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 our 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, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

	•		restricting the way we can handle or dispose of our wastes;
	•		limiting or prohibiting construction and operating activities in sensitive areas such as wetlands, coastal regions, or areas inhabited by endangered species;
	•		requiring remedial action to mitigate pollution conditions caused by our operations or attributable to former operators; and
	•		enjoining some or all of the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations.

     Failure to comply with these laws and regulations may result in the assessment of administrative, civil 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 our 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 our business, financial position or results of operations. Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Moreover, we cannot assure you that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause us to incur significant costs.

     Hazardous Waste. Our 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 our ordinary operations we 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, we could be subject to joint and several, strict liability for the costs of cleaning up and restoring sites where hazardous substances have been released, for damages to natural resources, and for the costs of certain health studies.

     We currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for the measurement, gathering, field compression and processing of natural gas. Although we used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such substances have been taken for disposal. In fact, there is evidence that petroleum spills or releases have occurred at some of the properties owned or leased by us. 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,

we could be required to remove previously disposed wastes (including waste disposed of by prior owners or operators), remediate contaminated property (including groundwater contamination, whether from prior owners or operators or other historic activities or spills), or perform remedial closure operations to prevent future contamination.

     Air Emissions. Our operations are subject to the federal Clean Air Act, as amended, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our processing plants and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We 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 our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

     Water Discharges. Our operations are subject to the Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state and federal waters. 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 our pipelines or facilities could result in administrative, civil and criminal penalties as well as significant remedial obligations.

     Pipeline Safety. Our pipelines are subject to regulation by the U.S. Department of Transportation, or the 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 our 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 our operations but there is no assurance that this trend will continue in the future.

     Employee Health and Safety. We are 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 our operations and that this information be provided to employees, state and local government authorities and citizens.

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

Properties

     As of December 31, 2005, our principal facilities in Appalachia include approximately 1,500 miles of 2 to 12 inch diameter pipeline. Our principal facilities in the Mid-Continent area consist of three natural gas processing plants, one treating facility, and approximately 3,130 miles of active and inactive 2 to 42 inch diameter pipeline. Substantially all of our gathering systems are constructed within rights-of-way granted by property owners named in the appropriate land records. In a few cases, property for gathering system purposes was purchased in fee. All of our compressor stations are located on property owned in fee or on property obtained via long-term leases or surface easements.

     Our property or rights-of-way are subject to encumbrances, restrictions and other imperfections. These imperfections have not interfered, and our general partner does not expect that they will materially interfere, with the conduct of our business. In many instances, lands over which rights-of-way have been obtained are subject to prior liens which have not been subordinated to the right-of-way grants. In a few instances, our rights-of-way are revocable at the election of the land owners. In some cases, not all of the owners named in the appropriate land records have joined in the 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 our 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 or operations. In general, employees of Atlas America manage our gathering systems and operate our business. To carry out our operations, Atlas America employed approximately 210 people at December 31, 2005 who provide direct support to our operations. Affiliates of our general partner will conduct business and activities of their own in which we will have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition between us, our general partner and affiliates of our general partner for the time and effort of the officers and employees who provide services to our general partner. The officers of our general partner who provide services to us are not required to work full time on our affairs. These officers may devote significant time to the affairs of our general partner’s affiliates and be compensated by these affiliates for the services rendered to them. There may be significant conflicts between us and affiliates of our general partner regarding the availability of these officers to manage us.

Available Information

     We make our periodic reports under the Securities Exchange Act of 1934, including our annual report on Form 10-K, our quarterly reports on Form 10-Q and our current reports on Form 8-K, available through our website at www.atlaspipelinepartners.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 311 Rouser Road, Moon Township, Pennsylvania 15108, telephone number (412) 262-2830. A complete list of our filings is available on the Securities and Exchange Commission’s website at www.sec.gov. Any of our filings are also available at the Securities and Exchange Commission’s Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. The Public Reference Room may be contacted at telephone number (800) 732-0330 for further information.

ITEM 1A. RISK FACTORS

     Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks we encounter are similar to those that would be faced by a corporation engaged in a similar business. If any of these risks actually occurs, our business, financial condition or results of operations could be materially adversely affected.

Risks Relating to Our Business

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

     The actual amounts of cash we generate will depend upon numerous factors relating to our business which may be beyond our control, including:

	•		the demand for and price of natural gas and NGLs;
	•		the volume of natural gas we transport;
	•		expiration of significant contracts;
	•		continued development of wells for connection to our gathering systems;
	•		the availability of local, intrastate and interstate transportation systems;
	•		the expenses we incur in providing our gathering services;
	•		the cost of acquisitions and capital improvements;
	•		our issuance of equity securities;
	•		required principal and interest payments on our debt;
	•		fluctuations in working capital;
	•		prevailing economic conditions;
	•		fuel conservation measures;
	•		alternate fuel requirements;

	•		government regulation and taxation; and
	•		technical advances in fuel economy and energy generation devices.

     Our financial and operating performance may fluctuate significantly from quarter to quarter. We may be unable to continue to generate sufficient cash flow to make distributions to our unitholders or to meet our working capital, capital expenditure or debt service requirements. If we are unable to do so, we may be required to sell assets or equity, reduce capital expenditures, refinance all or a portion of our existing indebtedness or obtain additional financing. We may be unable to do so on acceptable terms, or at all.

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

     We derive a substantial portion of our revenues from percentage-of-proceeds contracts. As a result, our income depends to a significant extent upon the prices at which the natural gas we transport, treat or process and the natural gas liquids, or NGLs, we produce are sold. Additionally, changes in natural gas prices may indirectly impact our profitability since prices can influence drilling activity and well operations and thus the volume of gas we gather and process. 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 our control, including those we describe in “—The amount of cash we generate depends in part on factors beyond our control,” above. We expect this volatility to continue. This volatility may cause our gross margin and cash flows to vary widely from period to period. Our 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 “— Our hedging strategies may fail to protect us and could reduce our gross margin and cash flow.”

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

     Production of natural gas from a well generally declines over time until the well can no longer economically produce natural gas and is plugged and abandoned. Failure to connect new wells to our gathering systems could, therefore, result in the amount of natural gas we transport reducing substantially over time and could, upon exhaustion of the current wells, cause us to abandon one or more of our gathering systems and, possibly, cease operations. The primary factors affecting our ability to connect new supplies of natural gas to our gathering systems include our success in contracting for existing wells that are not committed to other systems, the level of drilling activity near our gathering systems and, in the Mid-Continent region, our ability to attract natural gas producers away from our 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. We have no control over the level of drilling activity in our service areas, the amount of reserves underlying wells that connect to our systems and the rate at which production from a well will decline. In addition, we have no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulation and the availability and cost of capital. Because our operating costs are fixed to a significant degree, a reduction in the natural gas volumes we transport or process would result in a reduction in our gross margin and cash flows.

The success of our Appalachian operations depends upon Atlas America’s ability to drill and complete commercial producing wells.

     Substantially all of the wells we connect to our gathering systems in our Appalachian service area are drilled and operated by Atlas America for drilling investment partnerships sponsored by it. As a result, our Appalachian operations depend principally upon the success of Atlas America in sponsoring drilling investment partnerships and completing wells for these partnerships. Atlas America operates in a highly competitive environment for acquiring undeveloped leasehold acreage and attracting capital. Atlas America 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 America is not required to connect wells for which it is not the operator to our gathering systems. If Atlas America 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 our Appalachian gathering systems would substantially decrease and could, upon exhaustion of the wells currently connected to our gathering systems, cause us to abandon one or more of our Appalachian gathering systems, thereby materially reducing our gross margin, and cash flows.

The failure of Atlas America to perform its obligations under our natural gas gathering agreements with it may adversely affect our business.

     Substantially all of our Appalachian operating system revenues currently consist of the fees we receive under the master natural gas gathering agreement and other transportation agreements we have with Atlas America and its affiliates. We expect to derive a material portion of our gross margin from the services we provide under our contracts with Atlas America for the foreseeable future. Any factor or event adversely affecting Atlas America’s business or its ability to perform under its contracts with us or any default or nonperformance by Atlas America of its contractual obligations to us, could reduce our gross margin, and cash flows.

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

     Unlike our Appalachian operations, none of the drillers or operators in our Mid-Continent service area is an affiliate of ours. Moreover, our agreements with most of the drillers and operators with which our Mid-Continent operations do business do not require them to dedicate significant amounts of undeveloped acreage to our systems. As a result, we do not have assured sources to provide us with new wells to connect to our Mid Continent gathering systems. Failure to connect new wells to our Mid-Continent operations will, as described in “— The amount of natural gas we transport will decline over time unless we are able to attract new wells to connect to our gathering systems,” above, reduce our gross margin and cash flows.

Our 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 our revenues.

     During 2005, Chesapeake Energy Corporation, Kaiser-Francis Oil Company, Burlington Resources Inc., St. Mary Land and Exploration Company and Samson Resources Co. supplied our Mid-Continent systems with a majority of their natural gas supply. If these producers reduce the volumes of natural gas that they supply to us, our gross margin and cash flows would be reduced unless we obtain comparable supplies of natural gas from other producers.

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

     We currently have one processing plant for our Elk City operation and one active processing plant for our Velma operation. If operations at either plant were to be curtailed, or closed, whether due to accident, natural catastrophe, environmental regulation or for any other reason, our ability to process natural gas from the relevant gathering system and, as a result, our ability to extract and sell NGLs, would be harmed. If this curtailment or stoppage were to extend for more than a short period, our gross margin, and cash flows would be materially reduced.

We may face increased competition in the future in our Mid-Continent service areas.

     Our 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 our Velma service area. In our Elk City service area, ONEOK Field Services, Eagle Rock Midstream Resources, L.P., Enbridge Energy Partners, L.P., CenterPoint Energy, Inc. and Enogex operate competing gathering systems and processing plants. Some of our competitors have greater financial and other resources than we do. If these companies become more active in our Mid-Continent service areas, we may not be able to compete successfully with them in securing new well connections or retaining current well connections. If we do not compete successfully, the amount of natural gas we transport, process and treat will decrease, reducing our gross margin, and cash flows.

The amount of natural gas we transport, treat or process may be reduced if the public utility and interstate pipelines to which we deliver gas cannot or will not accept the gas.

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

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

     We acquired Elk City in April 2005 and completed the NOARK acquisition in October 2005 and are currently in the process of integrating their operations with ours. We also have an active, on-going program to identify other potential acquisitions. The integration of previously independent operations with ours can be a complex, costly and time-consuming process. The difficulties of combining Elk City and NOARK, as well as any operations we may acquire in the future, with us 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 our indebtedness; and
	•		potential environmental or regulatory liabilities and title problems.

     The process of combining companies or the failure to integrate them successfully could harm our business or future prospects, and result in significant decreases in our gross margin and cash flows.

The acquisitions of our Velma, Elk City and NOARK operations have substantially changed our business, making it difficult to evaluate our business based upon our historical financial information.

     The acquisitions of our Velma, Elk City and NOARK operations have significantly increased our size and substantially redefined our business plan, expanded our geographic market and resulted in large changes to our revenues and expenses. As a result of these acquisitions, and our continued plan to acquire and integrate additional companies that we believe present attractive opportunities, our financial results for any period or changes in our results across periods may continue to dramatically change. Our historical financial results, therefore, should not be relied upon to accurately predict our future operating results, thereby making the evaluation of our business more difficult.

Before acquiring its Velma and Elk City operations, Atlas had no previous experience either in its Mid-Continent service area or in operating natural gas processing plants.

     Our Mid-Continent gathering systems are located principally in Oklahoma and northern Texas, areas in which it has been involved only since July 2004 as a result of the Velma acquisition and, subsequently, Elk City acquisition in April 2005 and the NOARK acquisition in October 2005. In addition, as a result of these acquisitions, Atlas began to operate natural gas processing plants, a business in which it had no prior operating experience. Atlas depends upon the experience, knowledge and business relationships that have been developed by the senior management of its Mid-Continent operations to operate successfully in the region. The loss of the services of one or more members of Atlas’ Mid-Continent senior management, in particular, Robert R. Firth, President, and David D. Hall, Chief Financial Officer, could limit its growth or ability to maintain its current level of operations in the Mid-Continent region.

Due to our lack of asset diversification, negative developments in our operations would reduce our ability to make distributions to our unitholders.

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

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

     One of the ways we may grow our business is through the construction of new assets, such as the Sweetwater plant. The construction of additions or modifications to our existing systems and facilities, and the construction of new assets, involve numerous regulatory, environmental, political and legal uncertainties beyond our control and require the expenditure of significant amounts of capital. Any projects we undertake

may not be completed on schedule at the budgeted cost, or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand a gathering system, the construction may occur over an extended period of time, and we will not receive any material increases in revenues until the project is completed. Moreover, we may construct facilities to capture anticipated future growth in production in a region in which growth does not materialize. Since we are not engaged in the exploration for and development of natural gas reserves, we often do not have access to estimates of potential reserves in an area before constructing facilities in the area. To the extent we rely on estimates of future production in our decision to construct additions to our systems, the estimates may prove to be inaccurate 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 our expected investment return, which could impair our results of operations and financial condition. In addition, our actual revenues from a project could materially differ from expectations as a result of the price of natural gas, the NGL content of the natural gas processed and other economic factors described in this section.

     In addition to the risks discussed above, expected revenue from the Sweetwater gas plant could be reduced or delayed due to the following reasons:

	•		difficulties in obtaining equity or debt financing for construction and operating costs;
	•		difficulties in obtaining permits or other regulatory or third party consents;
	•		construction and operating costs exceeding budget estimates;
	•		revenue being less than expected due to lower commodity prices or lower demand;
	•		difficulties in obtaining consistent supplies of natural gas; and
	•		terms in operating agreements that are not favorable to us.

If we are unable to obtain new rights-of-way or the cost of renewing existing rights-of-way increases, then we may be unable to fully execute our growth strategy and our cash flows could be reduced.

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

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

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

     FERC regulation will still affect our business and the market for our products. FERC’s policies and practices affect a range of our 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 assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity.

     Other state and local regulations will also affect our business. Matters subject to regulation include rates, service and safety. Our gathering lines are subject to ratable take and common purchaser statutes in Texas and Oklahoma. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas.

     Federal law leaves any economic regulation of natural gas gathering to the states. 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, in Texas and Oklahoma, with respect to rate discrimination. Should a complaint be filed or regulation by the Texas Railroad Commission or Oklahoma Corporation Commission become more active, our revenues could decrease.

     Increased regulatory requirements relating to the integrity of the Ozark Transmission pipeline will require it to spend additional money to comply with these requirements. Ozark Gas Transmission is subject to extensive laws and regulations related to pipeline integrity. For example, 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 our ability to establish rates that would allow us 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 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 capacity and transportation facilities. Any successful complaint or protest against Ozark Gas Transmission’s rates could reduce our revenues associated with providing transmission services. We cannot assure you that we will be able to recover all of Ozark Gas Transmission’s costs through existing or future rates.

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 our 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 our 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 of 2005, FERC has civil penalty authority under the Natural Gas Act to impose penalties for current violations of up to $1,000,000 per day for each violation.

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

Compliance with pipeline integrity regulations issued by the United States Department of Transportation and state agencies could result in substantial expenditures for testing, repairs and replacement.

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

	•		perform ongoing assessments of pipeline integrity;
	•		identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
	•		improve data collection, integration and analysis;
	•		repair and remediate the pipeline as necessary; and
	•		implement preventative and mitigating actions.

     We do not believe that the cost of implementing integrity management program testing along certain segments of our pipeline will have a material effect on our 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.

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

     The operations of our 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 our business activities in many ways, including restricting the manner in which we dispose 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 our business due to our handling of natural gas and other petroleum products, air emissions related to our operations, historical industry operations including releases of substances into the environment, and waste disposal practices. For example, an accidental release from one of our pipelines or processing facilities could subject us to substantial liabilities arising from 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 our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover some or any of these costs from insurance.

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

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

	•		we may not be able to identify suitable acquisition candidates;
	•		we may not be able to make acquisitions on economically acceptable terms;
	•		our costs in seeking to make acquisitions may be material, even if we cannot complete any acquisition we have pursued;
	•		irrespective of estimates at the time we make an acquisition, the acquisition may prove to be dilutive to earnings and operating surplus;
	•		we may encounter difficulties in integrating operations and systems; and

•

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

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

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

Our hedging strategies may fail to protect us and could reduce our gross margin and cash flow.

     We pursue various hedging strategies to seek to reduce our exposure to losses from adverse changes in the prices for natural gas and NGLs. Our hedging activities will vary in scope based upon the level and volatility of natural gas and NGL prices and other changing market conditions. Our hedging activity may fail to protect or could harm us 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 we seek protection;
	•		the duration of the hedge may not match the duration of the risk against which we seek 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.

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

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

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

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

     Our operations are subject to all operating hazards and risks incidental to 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 our pipeline infrastructure, production facilities, transmission and distribution facilities and surrounding properties.

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

The IRS could treat us as a corporation for tax purposes, which would substantially reduce the cash available to us for payment of principal and, in some instances, interest on the notes.

     If we were treated as a corporation for U.S. federal income tax purposes for any taxable year for which the statute of limitations remains open or any future year, we would pay federal income tax on our taxable income for such year at the corporate tax rates, currently at a maximum rate of 35%, and would likely pay state income tax at varying rates. Because a tax would be imposed on us as a corporation, our cash available for payment of distributions to our unitholders would be substantially reduced.

Risks Related to Our Ownership Structure

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

     Atlas America and its affiliates own and control our general partner, which also owns a 13% limited partner interest in us. We do not have any employees and rely solely on employees of Atlas America and its affiliates who serve as our agents, including all of the senior managers who operate our business. A number of officers and employees of Atlas America also own interests in us. Conflicts of interest may arise between Atlas America, our general partner and their affiliates, on the one hand, and us, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over our interests and the interests of our unitholders. These conflicts include, among others, the following situations:

	•		Employees of Atlas America who provide services to us also devote significant time to the businesses of Atlas America in which we have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the employees who provide services to our general partner, which could result in insufficient attention to the management and operation of our business.
	•		Neither our partnership agreement nor any other agreement requires Atlas America to pursue a future business strategy that favors us or, apart from our agreements with Atlas America relating to our Appalachian region operations, use our assets for transportation or processing services we provide. Atlas America directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of Atlas America.
	•		Our general partner is allowed to take into account the interests of parties other than us, such as Atlas America, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to us.
	•		Our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including our agreements with Atlas America.

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

Cost reimbursements due our general partner may be substantial and will reduce the cash available for distributions to our unitholders.

     We reimburse Atlas America, our general partner and their affiliates, including officers and directors of Atlas America, for all expenses they incur on our behalf. Our general partner has sole discretion to determine the amount of these expenses. In addition, Atlas America and its affiliates provide us with services for which we are charged reasonable fees as determined by Atlas America in its sole discretion. The reimbursement of expenses or payment of fees could adversely affect our ability to make distributions to our unitholders.

ITEM 2. PROPERTIES

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

ITEM 3. LEGAL PROCEEDINGS

     On March 9, 2004, the Oklahoma Tax Commission filed a petition against Spectrum alleging that Spectrum, prior to our acquisition of its operations, underpaid gross production taxes beginning in June 2000. The OTC is seeking a settlement of $5.0 million plus interest and penalties. We are defending ourselves vigorously. We have asserted a claim for indemnification by Chevron under the provisions of our contract with it. Chevron has acknowledged our claim notice pursuant to which Chevron will be responsible for the payment of any underpayment of taxes, which would be the basis for any monetary judgment against us, but Chevron will reserve the issues of payment of penalties and reimbursement of our attorney fees and costs for determination by arbitration following the end of the litigation. In addition, under the terms of the Spectrum purchase agreement, $14.0 million has been placed in escrow to cover the costs of any adverse settlement resulting from the petition and other indemnification obligations of the purchase agreement.

     We are not subject to any other pending material legal proceedings.

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, 2005.

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 “APL”. At the close of business on February 23, 2006, the closing price for the common units was $41.21 and there were approximately 84 record holders and beneficial owners (held 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 limited partner units for the years ended December 31, 2005 and 2004:

										Distributions
		High				Low				Declared
2005
Fourth Quarter		$	49.21			$	39.45			$	0.83
Third Quarter		$	49.72			$	43.75			$	0.81
Second Quarter		$	46.39			$	41.25			$	0.77
First Quarter		$	49.00			$	40.00			$	0.75
2004
Fourth Quarter		$	42.90			$	37.67			$	0.72
Third Quarter		$	38.32			$	33.46			$	0.69
Second Quarter		$	40.03			$	32.60			$	0.63
First Quarter		$	41.50			$	34.00			$	0.63

     Our partnership agreement requires that we distribute 100% of available cash to our 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 our cash receipts, less cash disbursements and net additions to reserves, including any reserves required under debt instruments for future principal and interest payments.

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

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

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

     We make distributions of available cash to unitholders regardless of whether the amount distributed is less than the minimum quarterly distribution. Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate amount of cash being distributed. The general partner’s incentive distributions declared were $9.1 million for the year ended December 31, 2005.

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

ITEM 6. SELECTED FINANCIAL DATA

     The following table should be read together with our consolidated financial statements and notes thereto included within Item 8, “Financial Statements and Supplementary Data” and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this report. We have derived the selected financial data set forth in the table for each of the years ended December 31, 2005, 2004 and 2003 and at December 31, 2005 and 2004 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, 2003, 2002 and 2001 and for the years ended December 31, 2002 and 2001 from our financial statements, which were audited by Grant Thornton LLP and are not included within this report.

		Years Ended December 31,
		2005(1)				2004(2)				2003				2002				2001
		(in thousands, except per unit and operating data)
Statement of income data:
Revenue:
Natural gas and liquids		$	340,297			$	72,109			$	—			$	—			$	—
Transportation and compression			30,309				18,800				15,651				10,660				13,095
Interest income and other			894				382				98				7				35
Total revenue and other income			371,500				91,291				15,749				10,667				13,130
Costs and Expenses:
Natural gas and liquids			288,180				58,707				—				—				—
Plant operating			10,557				2,032				—				—				—
Transportation and compression			4,053				2,260				2,421				2,062				1,929
General and administrative			13,608				4,643				1,661				1,482				1,113
Depreciation and amortization			13,954				4,471				1,770				1,475				1,356
Loss (gain) on arbitration settlement, net			138				(1,457	)			—				—				—
Interest			14,175				2,301				258				250				176
Minority interest in NOARK (3)			1,083				—				—				—				—
Total costs and expenses			345,748				72,957				6,110				5,269				4,574
Net income			25,752				18,334				9,639				5,398				8,556
Premium on preferred unit redemption			—				(400	)			—				—				—
Net income attributable to partners		$	25,752			$	17,934			$	9,639			$	5,398			$	8,556

		Years Ended December 31,
		2005(1)				2004(2)				2003				2002				2001
Net income attributable to partners per limited partner unit:
Basic		$	1.86			$	2.53			$	2.17			$	1.54			$	2.30
Diluted		$	1.84			$	2.53			$	2.17			$	1.54			$	2.30
Balance sheet data (at period end):
Property, plant and equipment, net		$	445,066			$	175,259			$	29,628			$	23,764			$	20,009
Total assets			742,726				216,785				49,512				28,515				26,002
Total debt, including current portion			298,625				54,452				—				6,500				2,089
Total partners’ capital			329,510				136,704				44,245				19,686				21,674
Cash flow data:
Net cash provided by operating activities		$	50,917			$	25,193			$	13,702			$	8,138			$	10,268
Net cash used in investing activities			(411,004	)			(151,797	)			(9,154	)			(5,230	)			(3,128	)
Net cash provided by (used in) financing activities			376,110				129,740				8,671				(3,211	)			(7,021	)
Other financial data:
Gross margin (4)		$	80,516			$	32,202			$	15,651			$	10,660			$	13,095
EBITDA (5)			53,146				25,106				11,667				7,123				10,088
Adjusted EBITDA (5)			57,956				24,349				11,667				7,123				10,088
Maintenance capital expenditures		$	1,922			$	1,516			$	3,109			$	170			$	159
Expansion capital expenditures			50,576				8,527				4,526				5,060				1,569
Total capital expenditures		$	52,498			$	10,043			$	7,635			$	5,230			$	1,728
Operating data:
Appalachia:
Average throughput volumes (Mcf/d)			55,204				53,343				52,472				50,363				46,918
Average transportation rate per Mcf		$	1.21			$	0.96			$	0.82			$	0.58			$	0.76
Mid-Continent:
Velma system:
Gathered gas volume (Mcf/d)			67,075				56,441				—				—				—
Processed gas volume (Mcf/d)			62,538				55,202				—				—				—
Residue gas volume (Mcf/d)			50,880				42,659				—				—				—
NGL production (Bbl/d)			6,643				5,799				—				—				—
Condensate volume (Bbl/d)			256				185				—				—				—
Elk City system:
Gathered gas volume (Mcf/d)			250,717				—				—				—				—
Processed gas volume (Mcf/d)			119,324				—				—				—				—
Residue gas volume (Mcf/d)			109,553				—				—				—				—
NGL production (Bbl/d)			5,303				—				—				—				—
Condensate volume (Bbld/d)			127				—				—				—				—
NOARK system:
Average throughput volume (Mcf/d)			255,777				—				—				—				—

		Years Ended December 31,
		2005				2004				2003				2002				2001
		(in thousands)
Net income		$	25,752			$	18,334			$	9,639			$	5,398			$	8,556
Plus (minus):
Interest income and other			(894	)			(382	)			(98	)			(7	)			(35	)
Plant operating			10,557				2,032				—				—				—
Transportation and compression			4,053				2,260				2,421				2,062				1,929
General and administrative			13,608				4,643				1,661				1,482				1,113
Depreciation and amortization			13,954				4,471				1,770				1,475				1,356
Loss (gain) on arbitration settlement, net			138				(1,457	)			—				—				—
Interest expense			14,175				2,301				258				250				176
Minority interest in NOARK net income			1,083				—				—				—				—
Minority interest share of gross margin for NOARK			(1,910	)			—				—				—				—
Gross margin		$	80,516			$	32,202			$	15,651			$	10,660			$	13,095

		Years Ended December 31,
		2005				2004				2003				2002				2001
		(in thousands)
Net income		$	25,752			$	18,334			$	9,639			$	5,398			$	8,556
Plus:
Interest expense			14,175				2,301				258				250				176
Depreciation and amortization			13,954				4,471				1,770				1,475				1,356
Minority interest share of depreciation and amortization and interest expense for NOARK			(735	)			—				—				—				—
EBITDA		$	53,146			$	25,106			$	11,667			$	7,123			$	10,088
Adjustments:
Non-cash compensation expense			4,672				700				—				—				—
Loss (gain) on arbitration settlement, net			138				(1,457	)			—				—				—
Adjusted EBITDA		$	57,956			$	24,349			$	11,667			$	7,123			$	10,088

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

     The following information is provided 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

     Atlas Pipeline Partners, L.P. is a Delaware limited partnership formed in May 1999 to acquire, own and operate natural gas gathering systems previously owned by Atlas America, Inc. and its affiliates (“Atlas America”), a publicly traded company (NASDAQ: ATLS). We provide midstream energy services through the transmission, gathering and processing of natural gas in the Appalachian and Mid-Continent areas of the United States, specifically Pennsylvania, Ohio, New York, Oklahoma, Texas, Arkansas and Missouri. We conduct our business through two operating segments: our Mid-Continent operations and our Appalachian operations.

     We own and operate through our Mid-Continent operations:

	•		a 75% interest in a FERC-regulated, 565-mile interstate pipeline system, that extends from southeastern Oklahoma through Arkansas and into southeastern Missouri and which has throughput capacity of approximately 322 MMcf/d;
	•		two natural gas processing plants with aggregate capacity of approximately 230 MMcf/d and one treating facility with a capacity of approximately 200 MMcf/d, all located in Oklahoma; and
	•		1,765 miles of active natural gas gathering systems located in Oklahoma, Arkansas, northern Texas and the Texas panhandle, which transport gas from wells and central delivery points in the Mid-Continent region to our natural gas processing plants or transmission lines.

     We own and operate through our Appalachian operations 1,500 miles of intrastate natural gas gathering systems located in eastern Ohio, western New York and western Pennsylvania. Through an omnibus agreement and other agreements between us and Atlas America, the parent of our general partner and a leading sponsor of natural gas drilling investment partnerships in the Appalachian Basin, we gather substantially all of the natural gas for our Appalachian Basin operations from wells operated by Atlas America. Among other things, the omnibus agreement requires Atlas America to connect to our gathering systems wells it operates that are located within 2,500 feet of our gathering systems. We are also party to natural gas gathering agreements with Atlas America under which we receive gathering fees generally equal to a percentage, typically 16%, of the selling price of the natural gas we transport. These agreements are continuing obligations and have no specified term except that they will terminate if our general partner is removed without cause.

Significant Acquisitions

     From the date of our initial public offering in January 2000 through December 2005, we have completed five acquisitions at an aggregate cost of approximately $521.1 million, including, most recently:

•

In October 2005, we acquired from Enogex, a wholly-owned subsidiary of OGE Energy Corp., all of the outstanding equity of Atlas Arkansas, which owns a 75% interest in NOARK, for $179.8 million, including $16.8 million for working capital adjustments and other 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. The remaining 25% interest in NOARK is owned by Southwestern.

	•		In April 2005, we acquired all of the outstanding equity interests of Elk City for $196.0 million, including related transaction costs. Elk City’s principal assets include approximately 300 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 200 MMcf/d and a gas treatment facility in Prentiss, Oklahoma, with a total capacity of approximately 200 MMcf/d.
	•		In July 2004, we acquired Spectrum for $141.6 million, including transaction costs and the payment of taxes due as a result of the transaction. Spectrum’s principal assets consist of 1,100 miles of active and 800 miles of inactive natural gas gathering pipelines in the Golden Trend area of southern Oklahoma and the Barnett Shale area of North Texas and a natural gas processing facility in Stephens County, Oklahoma, with a total capacity of approximately 100 MMcf/d.

Contractual Revenue Arrangements

     Our principal revenue is generated from the transportation and sale of natural gas and NGLs. Variables which affect our revenue are:

	•		the volumes of natural gas we gather, transport and process which, in turn, depend upon the number of wells connected to our gathering systems, the amount of natural gas they produce, and the demand for natural gas and NGLs; and
	•		the transportation and processing fees we receive which, in turn, depend upon the price of the natural gas and NGLs we transport and process, 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 Appalachia, substantially all of the natural gas we transport is for Atlas America under percentage-of-proceeds, or POP, contracts, as described below, where we earn a fee equal to a percentage, generally 16%, of the selling price of the gas subject, in most cases, to a minimum of $0.35 or $0.40 per Mcf. Since our inception in January 2000, our Appalachian transportation fee has always exceeded this minimum. The balance of the Appalachian gas we transport is for third-party operators generally under fixed fee contracts.

     Our revenue in the Mid-Continent region is determined primarily by the fees earned from our transmission, gathering and processing operations. We either purchase gas from producers and move it into receipt points on our pipeline systems, and then sell the natural gas, or produced NGLs, if any, off of delivery points on our systems, or we transport natural gas across our systems, from receipt to delivery point, without taking title to the gas. Revenues associated with our FERC-regulated transmission pipeline are comprised of firm transportation rates and, to the extent capacity is available following the reservation of firm system capacity, interruptible transportation rates and are 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 our gathering and processing operations, we enter 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. Our revenue is a function of the volume of gas that we gather and process and is not directly dependent on the value of the natural gas.

POP Contracts. These contracts provide for us to retain a negotiated percentage of the sale proceeds from residue natural gas and NGLs we gather and process, with the remainder being remitted to the producer. In this situation, we and the producer are directly dependent on the value of the commodity and its value; we own a percentage of that commodity and are directly subject to its market value.

Keep-Whole Contracts. These contracts require us, as the processor, to bear 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 we paid for the unprocessed natural gas. However, since the gas received by the Elk City system, which is currently our only gathering system with keep-whole contracts, is generally low in liquids content and meets downstream pipeline specifications without being processed, the gas can be bypassed around the Elk City processing plant and delivered directly into downstream pipelines during periods of margin risk. Therefore, the processing margin risk associated with such type of contracts is minimized.

     As a result of our POP and keep-whole contracts, our results of operations and financial condition substantially depend upon the price of natural gas 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.

     We closely monitor the risks associated with these commodity price changes and their potential impact on our operations and, where appropriate, use various commodity instruments such as natural gas, crude oil and NGL contracts to hedge a portion of such price risks. We do not realize the full impact of commodity price changes because some of our sales volumes were previously hedged at prices different than actual market prices for the period.

Results of Operations

     The following table illustrates selected volumetric information related to our operating segments for the periods indicated:

		Years Ended December 31,
		2005				2004				2003
Operating data:
Appalachia:
Average throughput volumes (Mcf/d)			55,204				53,343				52,472
Average transportation rate per Mcf		$	1.21			$	0.96			$	0.82
Mid-Continent:
Velma system:
Gathered gas volume (Mcf/d)			67,075				56,441				—
Processed gas volume (Mcf/d)			62,538				55,202				—
Residue gas volume (Mcf/d)			50,880				42,659				—
NGL production (Bbl/d)			6,643				5,799				—
Condensate volume (Bbl/d)			256				185				—
Elk City system:
Gathered gas volume (Mcf/d)			250,717				—				—
Processed gas volume (Mcf/d)			119,324				—				—
Residue gas volume (Mcf/d)			109,553				—				—
NGL production (Bbl/d)			5,303				—				—
Condensate volume (Bbld/d)			127				—				—
NOARK system:
Average throughput volume (Mcf/d)			255,777				—				—

Year Ended December 31, 2005 Compared to Year Ended December 31, 2004

     Revenue. Natural gas and liquids revenue was $340.3 million for the year ended December 31, 2005, an increase of $268.2 million from $72.1 million for the prior year. The increase was attributable to revenue contributions from the NOARK system acquired in October 2005 of $14.6 million and the Elk City system acquired in April 2005 of $122.5 million, and an increase in Velma natural gas and liquids revenue of $131.1 million due to a full year’s contribution after its acquisition in July 2004 and higher commodity prices. Gross natural gas gathered averaged 67.1 MMcf/d on the Velma system for the year ended December 31, 2005, an increase of 19% from the prior period from its date of acquisition through December 31, 2004. Gross natural gas gathered on the Elk City system averaged 250.7 MMcf/d from its date of acquisition through December 31, 2005. For the NOARK system, average throughput volume was 255.8 MMcf/d from October 31, 2005, its date of acquisition, to December 31, 2005.

     Transportation and compression revenue increased to $30.3 million for the year ended December 31, 2005 from $18.8 million for the prior year. This $11.5 million increase was primarily due to contributions from the transportation revenues associated with the NOARK system acquired in October 2005 of $5.5 million and increases in the Appalachia average transportation rate earned and volume of natural gas transported. Our Appalachia average transportation rate was $1.21 per Mcf for the year ended December 31, 2005 as compared with $0.96 per Mcf for the prior year, an increase of $0.25 per Mcf. Appalachia’s average throughput volume was 55.2 MMcf/d for the year ended December 31, 2005 as compared with 53.3 MMcf/d for the prior year, an increase of 1.9 MMcf/d. The increase in the Appalachia average daily throughput volume was principally due to new wells connected to our gathering system and the completion of a capacity expansion project in 2005 on certain sections of our pipeline system during the current period.

     Costs and Expenses. Natural gas and liquids cost of goods sold of $288.2 million and plant operating expenses of $10.6 million for the year ended December 31, 2005 represented increases of $229.5 million and $8.5 million, respectively, from the prior year amounts due primarily to contributions from the acquisitions and an increase in commodity prices. Transportation and compression expenses increased $1.8 million to $4.1 million for the year ended December 31, 2005 due mainly to NOARK system operating costs from its date of acquisition and higher Appalachia operating costs as a result of compressors added during 2005 in connection with our capacity expansion project and higher maintenance expense as a result of additional wells connected to our gathering system.

     General and administrative expenses, including amounts reimbursed to affiliates, increased $9.0 million to $13.6 million for the year ended December 31, 2005 compared with $4.6 million for the prior year. This increase was mainly due to a $4.0 million increase in non-cash compensation expense related to vesting of phantom and common unit awards, $3.8 million of expenses associated with the acquisitions, and higher costs associated with managing our business, including management time related to acquisitions and capital raising opportunities. Depreciation and amortization increased to $14.0 million for the year ended December 31, 2005 compared with $4.5 million for the prior year due principally to the increased asset base associated with the acquisitions.

     Interest expense increased to $14.2 million for the year ended December 31, 2005 as compared with $2.3 million for the prior year. This $11.9 million increase was primarily due to interest associated with borrowings under our credit facility to finance our acquisitions and $1.0 million of accelerated amortization of deferred financing costs. This accelerated amortization was associated with the retirement of the term portion of our credit facility in April 2005.

     Net gain on arbitration settlement of $1.5 million for the year ended December 31, 2004 is the result of a December 30, 2004 settlement agreement with SEMCO settling all issues and matters related to our terminated acquisition of Alaska Pipeline Company from SEMCO. The gain reflects $5.5 million received from SEMCO, net of $4.0 million of associated costs.

     Minority interest in NOARK of $1.1 million for the year ended December 31, 2005 represents Southwestern’s 25% ownership interest in the net income of NOARK from our date of acquisition through December 31, 2005. Our financial results include the consolidated financial statements of NOARK from the date of its acquisition.

Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

     Revenue. Natural gas and liquids revenue of $72.1 million for the year ended December 31, 2004 was associated with the acquisition of our Velma operations in July 2004 and reflects approximately five and one-half months of operations in 2004. Appalachia transportation and compression revenue increased to $18.8 million for the year ended December 31, 2004 from $15.7 million for the prior year. This $3.1 million increase was primarily due to an increase in the average transportation rate earned and an increase in the volumes of natural gas transported. The average transportation rate was $0.96 per Mcf for the year ended December 31, 2004 as compared with $0.82 per Mcf for the prior year, an increase of $0.14 per Mcf. The average daily throughput volumes were 53.3 MMcf/d for the year ended December 31, 2004 as compared with 52.5 MMcf/d for the prior year, an increase of 0.8 MMcf/d. The increase in the average daily throughput volume was principally due to new wells connected to the Appalachia gathering system, partially offset by the natural decline in production volumes from existing wells connected to it.

     Costs and Expenses. Natural gas and liquids cost of goods sold of $58.7 million and plant operating expenses of $2.0 million for the year ended December 31, 2004 were associated with the acquisition of our Velma operations and reflect five and one half months of activity. Appalachian transportation and compression expenses decreased slightly to $2.3 million for the year ended December 31, 2004 as compared with $2.4 million for the prior year. This decrease was primarily due to a decrease in compressor expenses due to the purchase of several compressors that were previously leased at the end of 2003.

     General and administrative expenses, including amounts reimbursed to affiliates, increased $3.0 million to $4.6 million for the year ended December 31, 2004 compared with $1.6 million for the prior year. This increase was mainly due to $1.1 million of general and administrative expenses associated with our Velma operations, $0.8 million of expenses related to compensation expense for phantom units issued under our long-term incentive plan, a $0.5 million increase in allocations of compensation and benefits from Atlas America and its affiliates due to management time associated with acquisitions and public offerings, and $0.3 million of costs associated with the implementation of Sarbanes-Oxley and the preparation and filing of two tax returns for 2003. The filing of two tax returns was a result of our general partner’s ownership interest in us being reduced below 50% as a result of our sale of common units in May 2003, requiring a change in our tax year-end from September 30 to December 31. This necessitated the filing of an additional short year tax return. This expense is non-recurring.

     Depreciation and amortization increased to $4.5 million for the year ended December 31, 2004 compared with $1.8 million for the prior year due principally to the increased asset base associated with our acquisition of the Velma operations and pipeline extensions and compressor upgrades in Appalachia.

     Net gain on arbitration settlement of $1.5 million for the year ended December 31, 2004 is the result of a December 30, 2004 settlement agreement with SEMCO settling all issues and matters related to our terminated acquisition of Alaska Pipeline Company from SEMCO. The gain reflects $5.5 million received from SEMCO, net of $4.0 million of associated costs.

     Interest expense increased to $2.3 million for the year ended December 31, 2004 as compared with $0.3 million for the prior year. This $2.0 million increase was primarily due to interest associated with borrowings under the credit facility to finance our acquisition of the Velma operations.

Liquidity and Capital Resources

General

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

     At December 31, 2005, we had $9.5 million of outstanding borrowings under our credit facility and $11.1 million of outstanding letters of credit which are not reflected as borrowings on our consolidated balance sheet, with $204.4 million of remaining committed capacity under the $225.0 million credit facility, subject to covenant limitations (see “Credit Facility”). In addition to the availability under the credit facility, we have a universal shelf registration statement on file with the Securities and Exchange Commission, which allows us to issue equity or debt securities (see “Shelf Registration Statement”) of which $372.7 million remains available at December 31, 2005. At December 31, 2005, we had a working capital position of $16.8 million compared with $7.3 million at December 31, 2004. This increase was primarily attributable to the working capital provided by the operations of the acquired assets. We believe that we 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 are subject to business and operational risks that could adversely affect our cashflow. We may supplement our cash generation with proceeds from financing activities, including borrowings under our credit facility and other borrowings and the issuance of additional common units.

Cash Flows — Year Ended December 31, 2005 Compared to Year Ended December 31, 2004

     Net cash provided by operating activities of $50.9 million for the year ended December 31, 2005 increased $25.7 million from $25.2 million for the prior year. The increase is derived principally from increases in net income attributable to partners of $7.8 million, depreciation and amortization of $9.5 million, non-cash compensation expense of $4.0 million, and amortization of deferred financing costs of $1.7 million. The increases in net income attributable to partners and depreciation and amortization were principally due to the contribution from the acquisitions of Spectrum in July 2004, Elk City in April 2005, and NOARK in October 2005.

     Net cash used in investing activities was $411.0 million for the year ended December 31, 2005, an increase of $259.2 million from $151.8 million for the prior year. This increase was principally due to the acquisitions mentioned previously and a $42.5 million increase in capital expenditures. See further discussion of capital expenditures under “Capital Requirements.”

     Net cash provided by financing activities was $376.1 million for the year ended December 31, 2005, an increase of $246.4 million from $129.7 million for the prior year. This increase was principally due to the $243.1 million of net proceeds from the issuance of $250.0 million of 10-year, 8.125% senior unsecured notes in December 2005, which were primarily utilized to repay indebtedness incurred under our credit facility to

partially fund our acquisitions, and $119.6 million of additional net proceeds received from sales of common units. This increase was partially offset by a $99.0 million increase in net repayments under our credit facility and an increase of $17.3 million in cash distributions to partners due mainly to increases in our limited partner units outstanding and our cash distribution amount per limited partner unit.

Cash Flows — Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

     Net cash provided by operating activities of $25.2 million for the year ended December 31, 2004 increased $11.5 million from $13.7 million for the prior year. The increase is derived principally from increases in net income attributable to partners of $8.3 million, depreciation and amortization of $2.7 million, and non-cash compensation expense of $0.7 million. The increases in net income attributable to partners and depreciation and amortization were principally due to the acquisition of the Velma operations in July 2004.

     Net cash used in investing activities was $151.8 million for the year ended December 31, 2004, an increase of $142.6 million from $9.2 million for the prior year. This increase was principally due to the acquisition of the Velma operations in July 2004 and a $2.4 million increase in capital expenditures. See further discussion of capital expenditures under “Capital Requirements.”

     Net cash provided by financing activities was $129.7 million for the year ended December 31, 2004, an increase of $121.0 million from $8.7 million for the prior year. This increase was principally due to $67.9 million of additional net proceeds received from our sales of common units and a $60.7 million increase in net borrowings under our credit facility, mainly to fund the acquisition of the Velma operations. This increase was partially offset by an increase of $6.3 million in cash distributions to partners due mainly to increases in our limited partner units outstanding and our cash distribution amount per limited partner unit.

Capital Requirements

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

	•		maintenance capital expenditures to maintain equipment reliability and safety and to address environmental regulations; and
	•		expansion capital expenditures to acquire complementary assets and to expand the capacity of our existing operations.

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

		Years Ended December 31,
		2005				2004				2003
Maintenance capital expenditures		$	1,922			$	1,516			$	3,109
Expansion capital expenditures			50,576				8,527				4,526
Total		$	52,498			$	10,043			$	7,635

     Expansion capital expenditures increased to $50.6 million for the year ended December 31, 2005, due principally to expansions of the Velma and Elk City gathering systems and processing facilities to accommodate new wells drilled in our service areas. Expansion capital expenditures for our Mid-Continent region also include approximately $6.2 million of costs incurred related to the construction of the Sweetwater

gas plant, a new natural gas processing plant in Oklahoma expected to be operational in the third quarter of 2006 (see “– Significant Announced Internal Growth Project”). In addition, expansion capital expenditures increased due to compressor upgrades and gathering system expansions in the Appalachia region. Maintenance capital expenditures for the year ended December 31, 2005 remained relatively consistent compared with the prior year period. As of December 31, 2005, we are committed to expend approximately $19.7 million on pipeline extensions, compressor station upgrades and processing facility upgrades, including $10.8 million related to the Sweetwater gas plant.

     Expansion capital expenditures were $8.5 million for the year ended December 31, 2004, an increase of $4.0 million compared with $4.5 million for the prior year due principally to expansions of the Velma gathering system and processing facilities to accommodate new wells drilled in our service areas and compressor upgrades and gathering system expansions in the Appalachia region. Maintenance capital expenditures were $1.5 million for the year ended December 31, 2004, a decrease of $1.6 million compared with $3.1 million for the prior year due principally to the purchase of Appalachia pipeline compressors in 2003 to replace units which were formerly leased.

Partnership Distributions

     Our partnership agreement requires that we distribute 100% of available cash to our 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 our cash receipts, less cash disbursements and net additions to reserves, including any reserves required under debt instruments for future principal and interest payments.

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

     Available cash is initially distributed 98% to our limited partners and 2% to our general partner. These distribution percentages are modified to provide for incentive distributions to be paid to our general partner if quarterly distributions to unitholders exceed specified targets, as described in Item 5, “Market for Registrant’s Common Equity and Related Unitholder Matters”. Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate amount of cash being distributed. The general partner’s incentive distributions declared for year ended December 31, 2005 was $9.1 million.

Contractual Obligations and Commercial Commitments

     The following table summarizes our contractual obligations and commercial commitments at December 31, 2005 (in thousands):

						Payments Due By Period
						Less than				1 – 3				4 – 5				After 5
Contractual cash obligations:		Total				1 Year				Years				Years				Years
Total debt (1)		$	298,625			$	1,263			$	2,462			$	11,900			$	283,000
Operating leases			3,828				1,769				1,679				380				—
Total contractual cash obligations		$	302,453			$	3,032			$	4,141			$	12,280			$	283,000

						Amount of Commitment Expiration Per Period
						Less than				1 – 3				4 – 5				After 5
Other commercial commitments:		Total				1 Year				Years				Years				Years
Standby letters of credit		$	11,050			$	11,025			$	25			$	—			$	—
Other commercial commitments			19,665				19,665				—				—				—
Total commercial commitments		$	30,715			$	30,690			$	25			$	—			$	—

     Other commercial commitments relate to commitments to purchase compressors which we had been leasing and for expenditures for pipeline extensions.

Equity Offerings

     On November 28, 2005, we sold 2,700,000 of our 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, we sold 330,000 common units on December 27, 2005 for gross proceeds of $13.9 million, or aggregate total gross proceeds of $127.3 million. The units, which were issued under our previously filed shelf registration statement, resulted in net proceeds of approximately $121.0 million, after underwriting commissions and other transaction costs. We primarily utilized the net proceeds from the sale to repay a portion of the amounts due under our credit facility. As a result of this equity offering, our general partner’s ownership interest in us was 14.8%, including its 2.0% general partner interest.

     In June 2005, we sold 2,300,000 common units in a public offering for total gross proceeds of $96.5 million. The units, which were issued under our previously filed shelf registration statement, resulted in net proceeds of approximately $91.7 million, after underwriting commissions and other transaction costs. We primarily utilized the net proceeds from the sale to repay a portion of the amounts due under our credit facility.

     In July 2004, we sold 2,100,000 common units in a public offering for total gross proceeds of $73.0 million. The units, which were issued under our previously filed shelf registration statement, resulted in net proceeds of approximately $67.9 million, after underwriting commissions and other transaction costs. We utilized the net proceeds from the sale primarily to repay a portion of the amounts due under our credit facility and to redeem preferred units issued in connection with the acquisition of Spectrum in July 2004 for $20.4 million.

     In April 2004, we sold 750,000 common units in a public offering for total gross proceeds of $27.0 million. The units, which were issued under our previously filed shelf registration statement, resulted in net proceeds of approximately $25.2 million, after underwriting commissions and other transaction costs. We utilized the net proceeds from the sale primarily to repay a portion of the amounts due under our credit facility.

     In May 2003, we sold 1,092,500 common units in a public offering for total gross proceeds of $27.3 million. The units, which were issued under our previously filed shelf registration statement, resulted in net proceeds of approximately $25.2 million, after underwriting commissions and other transaction costs. We utilized the net proceeds from the sale primarily to repay a portion of the amounts due under our credit facility.

Shelf Registration Statement

     We have an effective shelf registration statement with the Securities and Exchange Commission that permits us to periodically issue equity and debt securities for a total value of up to $500 million. As of

December 31, 2005, $372.7 million remains available for issuance under the shelf registration statement. The amount, type and timing of any offerings will depend upon, among other things, our funding requirements, prevailing market conditions, and compliance with our credit facility covenants.

Credit Facility

     We have a $225.0 million credit facility with a syndicate of banks which matures in April 2010. The credit facility bears interest, at our option, at either (i) adjusted LIBOR plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). The weighted average interest rate on the $9.5 million of outstanding credit facility borrowings at December 31, 2005 was 7.1%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $11.1 million was outstanding at December 31, 2005. These outstanding letter of credit amounts were not reflected as borrowings on our consolidated balance sheet. Borrowings under the credit facility are secured by a lien on and security interest in all of our property and that of our wholly-owned subsidiaries, and by the guaranty of each of our wholly-owned subsidiaries (see Note 17 to the consolidated financial statements in Item 8, “Financial Statements and Supplementary Data”). The 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 enter into a merger or sale of assets, including the sale or transfer of interests in our subsidiaries.

     The events which constitute an event of default 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, and a change of control of our general partner.

     The credit facility requires us to maintain a ratio of senior secured debt (as defined in the credit facility) to EBITDA (as defined in the credit facility) of not more than 6.0 to 1.0, reducing to 5.75 to 1.0 on March 31, 2006, 4.5 to 1.0 on June 30, 2006, and 4.0 to 1.0 on September 30, 2006; a funded debt (as defined in the credit facility) to EBITDA ratio of not more than 6.0 to 1.0, reducing to 5.75 to 1.0 on March 31, 2006 and to 4.5 to 1.0 on June 30, 2006; and an interest coverage ratio (as defined in the credit facility) of not less than 2.5 to 1.0, increasing to 3.0 to 1.0 on March 31, 2006. The credit facility defines EBITDA to include pro forma adjustments, acceptable to the administrator of the facility, following material acquisitions. As of December 31, 2005, our ratio of senior secured debt to EBITDA was 0.3 to 1.0, our funded debt ratio was 3.9 to 1.0 and our interest coverage ratio was 4.9 to 1.0.

     We are unable to borrow under our credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to our partnership agreement.

Senior Notes

     In December 2005, we and our subsidiary, Atlas Pipeline Finance Corp., issued $250.0 million of 10-year, 8.125% senior unsecured notes (“Senior Notes”) in a private placement transaction pursuant to Rule 144A and Regulation S under the Securities Act of 1933 for net proceeds of $243.1 million, after underwriting commissions and other transaction costs. Interest on the Senior Notes is payable semi-annually in arrears on June 15 and December 15, commencing on June 15, 2006. The Senior Notes are redeemable at any time on or after December 15, 2010 at certain redemption prices, together with accrued and unpaid interest to the date of redemption. The Senior Notes are also redeemable at any time prior to December 15, 2010 at a make-whole redemption price. In addition, prior to December 15, 2008, we may redeem up to 35% of the aggregate principal amount of the Senior Notes with the proceeds of certain equity offerings at a stated redemption price. The Senior Notes are also subject to repurchase by us at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if we do not reinvest the net

proceeds within 360 days. The Senior Notes are junior in right of payment to our secured debt, including our obligations under the credit facility.

     The indenture governing the Senior Notes contains covenants, including limitations of our 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 our assets. We are in compliance with these covenants as of December 31, 2005.

     In connection with a Senior Notes registration rights agreements entered into by us, we agreed to (a) file an exchange offer registration statement with the Securities and Exchange Commission for the Senior Notes by April 19, 2006, (b) cause the exchange offer registration statement to be declared effective by the Securities and Exchange Commission by July 18, 2006, and (c) cause the exchange offer to be consummated by August 17, 2006. If we do not meet the aforementioned deadlines, the Senior Notes will be subject to additional interest, up to 1% per annum, until such time that the deadlines have been met.

NOARK Notes

     Upon our acquisition of NOARK at October 31, 2005, NOARK’s subsidiary, NOARK Pipeline Finance, L.L.C., had $66.0 million in principal amount outstanding of 7.15% notes due in 2018. The notes are governed by an indenture dated June 1, 1998 for which UMB Bank, N.A. serves as trustee. Interest on the notes is payable semi-annually, in cash, in arrears on June 1 and December 1 of each year. Liability under the notes was allocated severally 40% to Atlas Arkansas, our wholly-owned subsidiary, as successor to Enogex, and 60% to Southwestern, and the parties are several guarantors for their respective allocations. The notes are subject to a semi-annual redemption in installments at a redemption price of 100% of the principal, plus accrued and unpaid interest. Additionally, at the option of either Enogex or Southwestern, notes in an aggregate principal amount guaranteed by either company as of a particular payment date may be redeemed at such notes’ redemption price plus a make-whole premium and unpaid interest accrued to that date by giving the trustee at least 60 days notice. As part of the NOARK acquisition, Enogex agreed to redeem its portion of the notes as promptly as practicable after the closing, and at closing it deposited cash sufficient to redeem the notes into an escrow account. The redemption of $26.4 million of the notes was completed on December 5, 2005. At December 31, 2005, $39.0 million of notes remain outstanding and are presented on our consolidated balance sheet, for which Southwestern remains liable. Subsequent to the redemption of a portion of the notes upon acquisition, the remaining notes are subject to semi-annual redemption in installments of $0.6 million each. Under the partnership agreement, payments on the notes will be made from amounts otherwise distributable to Southwestern and, if those amounts are insufficient, Southwestern is required to make a capital contribution to NOARK. NOARK distributes available cash to the partners in accordance with their ownership interests after deduction of their respective portion of amounts payable on the notes.

Significant Announced Internal Growth Project

     On October 19, 2005, we announced plans to complete construction of a new natural gas processing plant in Beckham County, Oklahoma near our Prentiss treating facility, in the third quarter of 2006. The new plant, to be known as the Sweetwater gas plant, will be scaled to 120 MMcf/d of processing capacity. The Sweetwater gas plant will be located west of our Elk City gas plant, and is being built to further access natural gas production actively being developed in western Oklahoma and the Texas panhandle. Along with the Sweetwater gas plant, we will construct a gathering system to be located primarily in western Oklahoma and in the Texas panhandle, more specifically, Beckham and Roger Mills counties in Oklahoma and Hemphill County, Texas. We anticipate that construction of the Sweetwater gas plant and associated gathering system will cost approximately $40.0 million and will generate cash flow of $8.0 million to $10.0 million annually.

Environmental Regulation

     Our operations are subject to federal, state and local laws and regulations governing the release of regulated materials into the environment or otherwise relating to environmental protection or human health or safety. We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of remedial requirements, and issuance of injunctions as to future compliance or other mandatory or consensual measures. We have 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 we will not incur significant costs and liabilities relating to claims for damages to property, the environment, natural resources, or persons resulting from the operation of our business. Moreover, it is possible that other developments, such as increasingly strict environmental laws and regulations and enforcement policies hereunder, could result in increased costs and liabilities to us.

     Environmental laws and regulations have changed substantially and rapidly over the last 25 years, and we anticipate 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 us 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. We will attempt to anticipate future regulatory requirements that might be imposed and to plan accordingly, but there can be no assurance that we will identify and properly anticipate each such charge, or that our efforts will prevent material costs, if any, from arising.

Inflation and Changes in Prices

     Inflation affects the operating expenses of our 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 our future operating costs, we cannot predict the timing or amounts of any such effects. In addition, the value of our 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 believe our estimates are reasonable, actual results could differ from those estimates. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Key estimates used by our management include estimates used to record revenue and expense accruals, depreciation and amortization, asset impairment and fair values 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 that we have identified are discussed below.

     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. Actual results could differ from those estimates.

     Receivables

     In evaluating the realizability of accounts receivable, we perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s current creditworthiness, as determined by our review of the customers’ credit information. We extend credit on an unsecured basis to many of our energy customers. At December 31, 2005 and 2004, no allowance was recorded for uncollectible accounts receivable impairment.

     Revenue Recognition

     Revenue in the Appalachian segment is recognized at the time the natural gas is transported through the gathering systems. Under the terms of our natural gas gathering agreements with Atlas America and its affiliates, we receive fees for gathering natural gas from wells owned by Atlas America, by drilling investment partnerships sponsored by Atlas America or by independent third parties. The fees received for the gathering services are generally the greater of 16% of the gross sales price for gas produced from the wells, or $0.35 or $0.40 per Mcf, depending on the ownership of the well. Substantially all gas gathering revenue is derived under these agreements. Fees for transportation services provided to independent third parties whose wells are connected to our Appalachia gathering systems are at separately negotiated prices.

     Our Mid-Continent segment revenue is determined primarily by the fees earned from our transmission, gathering and processing operations. We either purchase gas from producers and move it into receipt points on our pipeline systems, and then sell the natural gas, or produced natural gas liquids (“NGLs”), if any, off of delivery points on our systems, or we transport natural gas across our systems, from receipt to delivery point, without taking title to the gas. Revenue associated with our 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. The majority of the revenue associated with our gathering and processing operations are based on percentage-of-proceeds (“POP”) and fixed-fee contracts. Under our POP purchasing arrangements, we purchase natural gas at the wellhead, process the natural gas by extracting NGLs and removing impurities and sell the residue gas and NGLs at market-based prices, remitting to producers a contractually-determined percentage of the sale proceeds.

     We accrue unbilled revenue due to timing differences between the delivery of natural gas, NGLs and oil and the receipt of a delivery statement. This revenue is recorded based upon volumetric data from our 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). We had unbilled revenue at December 31, 2005 and 2004 of $48.4 million and $15.3 million, respectively, included in accounts receivable and accounts receivable-affiliates within our consolidated balance sheets.

     Intangible Assets

     We recorded intangible assets with finite lives in connection with certain consummated acquisitions (see Note 7 to the consolidated financial statements in Item 8, “Financial Statements and Supplementary Data”). The following table reflects the components of intangible assets being amortized at December 31, 2005 (in thousands):

		December 31, 2005								Estimated
		Gross Carrying				Accumulated				Useful Lives
		Amount				Amortization				in Years
Amortized intangible assets:
Customer contracts		$	23,990			$	(1,339	)			8
Customer relationships			32,960				(742	)			20
		$	56,950			$	(2,081	)

     We did not recognize any such intangible assets at December 31, 2004. Statement of Financial Accounting Standards 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, we 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 our 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 our customer relationship intangible assets is based upon the estimated average length of non-contracted customer relationships in existence at the date of acquisition. Customer contract and customer relationship intangible assets are amortized on a straight-line basis. Amortization expense on intangible assets was $2.1 million for the year ended December 31, 2005. There was no amortization expense on intangible assets recorded during the years ended December 31, 2004 and 2003. Amortization expense related to intangible assets is estimated to be $4.6 million for each of the next five calendar years commencing in 2006.

Goodwill

     At December 31, 2005 and 2004, we had $111.4 million and $2.3 million, respectively, of goodwill which was recorded in connection with consummated acquisitions (see Note 7 to the consolidated financial statements in Item 8, “Financial Statements and Supplementary Data ”). The changes in the carrying amount of goodwill for the years ended December 31, 2005, 2004 and 2003 were as follows (in thousands):

		Years Ended December 31,
		2005				2004				2003
Balance, beginning of year		$	2,305			$	2,305			$	2,305
Goodwill acquired — Elk City acquisition			61,136				—				—
Goodwill acquired — NOARK acquisition			49,088				—				—
Reduction in minority interest deficit acquired			(1,083	)			—				—
Impairment losses			—				—				—
Balance, end of year		$	111,446			$	2,305			$	2,305

     We test our 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 our operations, including anticipated future revenues, expected future operating costs and the discount factor used. Actual results could differ from projections, resulting in revisions to our assumptions and, if required, recognition of an impairment loss. Our test of goodwill at December 31, 2005 resulted in no impairment. We will continue to evaluate our goodwill at least annually and if impairment indicators arise, and will reflect the impairment of goodwill, if any, within our consolidated statements of income in the period in which the impairment is indicated.

     Depreciation and Amortization

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

     Impairment of Assets

     In accordance with Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we 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. We determine if our 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. Our operations are subject to numerous factors which could affect future cash flows which we discuss under Item 1A, “Risk Factors”. We continuously monitor these factors and pursue alternative strategies to maintain or enhance cash flows associated with these assets; however, we cannot assure you that we can mitigate the effects, if any, on future cash flows related to any changes in these factors.

     Fair Value of Derivative Commodity Contracts

     We enter into certain financial swap and option instruments that are classified as cash flow hedges in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, to hedge our 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, we receive a fixed price and pay a floating price based on certain indices for the relevant contract period.

     We formally document all relationships between hedging instruments and the items being hedged, including our risk management objective and strategy for undertaking the hedging transactions. This includes matching the natural gas futures and options contracts to the forecasted transactions. We assess, 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 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, we will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which we determine through utilization of market data, will be recognized immediately within our consolidated statements of income.

     We record derivatives on the consolidated balance sheet as assets or liabilities at fair value. For derivatives qualifying as hedges, we recognize the effective portion of changes in fair value in partners’ capital as accumulated other comprehensive loss and reclassify them to natural gas and liquids revenue within the consolidated statements of income as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, we recognize changes in fair value within the consolidated statements of income as they occur. At December 31, 2005 and 2004, we reflected net hedging liabilities on our consolidated balance sheets of $30.4 million and $2.6 million, respectively. Of the $30.1 million net loss in accumulated other comprehensive loss at December 31, 2005, if fair values of the instruments remain at current market values, we will reclassify $12.2 million of losses to the consolidated statements of income over the next twelve month period as these contracts expire, and $17.9 million will be reclassified in later periods. Actual amounts that will be reclassified will vary as a result of future price changes. Ineffective hedge gains or losses are recorded within natural gas and liquids revenue in the consolidated statements of income while the hedge contract is open and may increase or decrease until settlement of the contract. We recognized losses of $11.1 million and $2,000 for the years ended December 31, 2005 and 2004, respectively, within the consolidated

statements of income related to the settlement of qualifying hedge instruments. We also recognized a gain of $1.6 million and a loss of $0.3 million for the years ended December 31, 2005 and 2004, respectively, within the consolidated statements of income related to the change in market value of non-qualifying or ineffective hedges.

     A portion of our future natural gas 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 revenue.

     Volume Measurement

     We record 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 our business.

     New Accounting Standards

     In May 2005, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections” (“SFAS No. 154”). SFAS No. 154 requires retrospective application to prior periods’ financial statements for changes in accounting principle. It also requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings for that period rather than being reported in an income statement. The statement will be effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The impact of SFAS No. 154 will depend on the nature and extent of any voluntary accounting changes and corrections of errors after the effective date, but we do not currently expect SFAS No. 154 to have a material impact on our financial position or results of operations.

     In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”), which will result in (a) more consistent recognition of liabilities relating to asset retirement obligations, (b) more information about expected future cash outflows associated with those obligations, and (c) more information about investments in long-lived assets because additional asset retirement costs will be recognized as part of the carrying amounts of the assets. FIN 47 clarifies that the term conditional asset retirement obligation as used in SFAS No. 143, “Accounting for Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. We adopted FIN 47 at December 31, 2005 and it had no material impact on our consolidated financial statements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

General

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

     We are exposed to various market risks, principally fluctuating interest rates and changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We manage these risks through regular operating and financing activities and periodically use 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, 2005. Only the potential impact of hypothetical assumptions are analyzed. The analysis does not consider other possible effects that could impact our business.

     Interest Rate Risk. At December 31, 2005, we had a $225.0 million revolving credit facility ($9.5 million outstanding) to fund the expansion of our existing gathering systems, acquire other natural gas gathering systems and fund working capital movements as needed. The weighted average interest rate for these borrowings was 7.1% at December 31, 2005. Holding all other variables constant, a 1% change in interest rates would change interest expense by $0.1 million.

     Commodity Price Risk. We are exposed to commodity prices as a result of being paid for certain services in the form of commodities rather than cash. For gathering services, we receive fees or commodities from the producers to bring the raw natural gas from the wellhead to the processing plant. For processing services, we either receive fees or commodities as payment for these services, based on the type of contractual agreement. Based on our current portfolio of gas supply contracts, we have long condensate, NGL, and natural gas positions. A 10% change in the average price of NGLs, natural gas and condensate we process and sell would result in a change to our 2005 consolidated annual income of approximately $1.6 million.

     We enter into certain financial swap and option instruments that are classified as cash flow hedges in accordance with SFAS No. 133 to hedge our 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, we receive a fixed price and remit a floating price based on certain indices for the relevant contract period.

     We formally document all relationships between hedging instruments and the items being hedged, including our risk management objective and strategy for undertaking the hedging transactions. This includes matching the natural gas futures and options contracts to the forecasted transactions. We assess, 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 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, we will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which we determine through utilization of market data, will be recognized immediately within our consolidated statements of income.

     Derivatives are recorded on our consolidated balance sheet as assets or liabilities at fair value. For derivatives qualifying as hedges, we recognize the effective portion of changes in fair value in partners’ capital as accumulated other comprehensive loss and reclassify them to natural gas and liquids revenue within the consolidated statements of income as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, we recognize changes in fair value within our consolidated statements of income as they occur. At December 31, 2005 and 2004, we reflected net hedging liabilities on our consolidated balance sheets of $30.4 million and $2.6 million, respectively. Of the $30.1 million of net loss in

accumulated other comprehensive loss at December 31, 2005, if fair values of the instruments remain at current market values, we will reclassify $12.2 million of losses to our consolidated statements of income over the next twelve month period as these contracts expire, and $17.9 million will be reclassified in later periods. Actual amounts that will be reclassified will vary as a result of future price changes. Ineffective hedge gains or losses are recorded within natural gas and liquids revenue in our consolidated statements of income while the hedge contracts are open and may increase or decrease until settlement of the contract. We recognized losses of $11.1 million and $2,000 for the years ended December 31, 2005 and 2004, respectively, within our consolidated statements of income related to the settlement of qualifying hedge instruments. We also recognized a gain of $1.6 million and a loss of $0.3 million for the years ended December 31, 2005 and 2004, respectively, within our consolidated statements of income related to the change in market value of non-qualifying or ineffective hedges.

     A portion of our future natural gas 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 revenue.

     As of December 31, 2005, we had the following NGLs, natural gas, and crude oil volumes hedged:

Natural Gas Liquids Fixed – Price Swaps

Production
Period						Average				Fair Value
Ended December 31,		Volumes				Fixed Price				Liability(1)
		(gallons)				(per gallon)				(in thousands)
2006			40,068,000			$	0.683			$	(12,119	)
2007			36,036,000				0.717				(9,157	)
2008			33,012,000				0.697				(7,365	)
										$	(28,641	)

Natural Gas Fixed – Price Swaps

Production
Period						Average				Fair Value
Ended December 31,		Volumes				Fixed Price				Liability(3)
		(MMBTU)(2)				(per MMBTU)				(in thousands)
2006			3,192,500			$	7.186			$	(110	)
2007			1,080,000				7.255				(3,242	)
2008			240,000				7.270				(605	)
										$	(3,957	)

Natural Gas Basis Swaps

Production
Period						Average				Fair Value
Ended December 31,		Volumes				Fixed Price				Asset(3)
		(MMBTU)(2)				(per MMBTU)				(in thousands)
2006			3,527,500			$	(0.521	)		$	(473	)
2007			1,080,000				(0.535	)			3,580
2008			240,000				(0.555	)			808
										$	3,915

     Crude Oil Fixed – Price Swaps

Production
Period						Average				Fair Value
Ended December 31,		Volumes				Strike Price				Liability(3)
		(barrels)				(per barrel)				(in thousands)
2006			77,600			$	51.545			$	(881	)
2007			80,400				56.069				(643	)
2008			62,400				59.267				(223	)
										$	(1,747	)
						Total net liability				$	(30,430	)

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Partners
Atlas Pipeline Partners, L.P.

We have audited the accompanying consolidated balance sheets of Atlas Pipeline Partners, L.P. (A Delaware Limited Partnership) and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of income, comprehensive income (loss), partners’ capital, and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Atlas Pipeline Partners, L.P. and subsidiaries as of December 31, 2005 and 2004 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 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 Partners, L.P.’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 3, 2006 expressed an unqualified opinion.

		/s/ GRANT THORNTON LLP

Cleveland, Ohio
March 3, 2006

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)

		December 31,
		2005				2004
ASSETS
Current assets:
Cash and cash equivalents		$	34,237			$	18,214
Accounts receivable — affiliates			4,649				1,496
Accounts receivable			57,528				13,729
Current portion of hedge asset			11,388				40
Prepaid expenses			2,454				1,056
Total current assets			110,256				34,535
Property, plant and equipment, net			445,066				175,259
Long-term hedge asset			4,388				14
Intangible assets, net			54,869				—
Goodwill			111,446				2,305
Other assets, net			16,701				4,672
		$	742,726			$	216,785
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Current portion of long-term debt		$	1,263			$	2,303
Accounts payable			15,609				2,341
Accrued liabilities			16,064				3,144
Current portion of hedge liability			23,796				1,959
Accrued producer liabilities			36,712				10,996
Distribution payable			—				6,467
Total current liabilities			93,444				27,210
Long-term hedge liability			22,410				722
Long-term debt, less current portion			297,362				52,149
Commitments and contingencies
Partners’ capital:
Limited partners’ interests			349,491				135,769
General partner’s interest			10,094				2,253
Accumulated other comprehensive loss			(30,075	)			(1,318	)
Total partners’ capital			329,510				136,704
		$	742,726			$	216,785

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(in thousands, except per unit data)

		Years Ended December 31,
		2005				2004				2003
Revenue:
Natural gas and liquids		$	340,297			$	72,109			$	—
Transportation and compression – affiliates			24,346				18,724				15,563
Transportation and compression – third parties			5,963				76				88
Interest income and other			894				382				98
Total revenue and other income			371,500				91,291				15,749
Costs and expenses:
Natural gas and liquids			288,180				58,707				—
Plant operating			10,557				2,032				—
Transportation and compression			4,053				2,260				2,421
General and administrative			11,825				3,562				853
Compensation reimbursement – affiliates			1,783				1,081				808
Depreciation and amortization			13,954				4,471				1,770
Interest			14,175				2,301				258
Minority interest in NOARK			1,083				—				—
Loss (gain) on arbitration settlement, net			138				(1,457	)			—
Total costs and expenses			345,748				72,957				6,110
Net income			25,752				18,334				9,639
Premium on preferred unit redemption			—				(400	)			—
Net income attributable to partners		$	25,752			$	17,934			$	9,639
Allocation of net income attributable to partners:
Limited partners’ interest		$	16,355			$	14,864			$	8,651
General partner’s interest			9,397				3,070				988
Net income attributable to partners		$	25,752			$	17,934			$	9,639
Net income attributable to partners per limited partner unit:
Basic		$	1.86			$	2.53			$	2.17
Diluted		$	1.84			$	2.53			$	2.17
Weighted average limited partner units outstanding:
Basic			8,808				5,866				3,981
Diluted			8,872				5,870				3,981