ARKHAN 10-K 2005 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended September 30, 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: 333-112653

ATLAS AMERICA, INC.

(Exact name of registrant as specified in its charter)

Delaware	51-0404430
(State or other jurisdiction or incorporation or organization)	(I.R.S. Employer Identification No.)
311 Rouser Road
Moon Township, PA	15108
(Address of principal executive offices)	Zip Code
Registrant’s telephone number, including area code:	412-262-2830
Securities registered pursuant to Section 12(b) of the Act:	None

Title of each class	Name of each exchange on which registered
None	None

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

Common stock, par value $.01 per share

Title of class

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 xNo 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 an accelerated filer (as defined in Exchange Act Rule 12b-2) of the Act. Yes xNo o

The aggregate market value of the voting common stock held by non-affiliates of the registrant, based on the closing price of such stock on the last business day of the registrant’s most recently completed second fiscal quarter, March 31, 2005, was $95.7 million. .

The number of outstanding shares of the registrant’s common stock on November 30, 2005 was 13,355,641 shares.

DOCUMENTS INCORPORATED BY REFERENCE

[None]

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ATLAS AMERICA, INC. AND SUBSIDIARIES

INDEX TO ANNUAL REPORT

ON FORM 10-K

PART I			Page
	Item 1:	Business	4-16
	Item 1A:	Risk Factors	17-21
	Item 1B:	Unresolved Staff Comments	21
	Item 2:	Properties	21-24
	Item 3:	Legal Proceedings	25
	Item 4:	Submission of Matters to a Vote of Security Holders	25
PART II
	Item 5:	Market for Registrant's Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities	25
	Item 6:	Selected Financial Data	26
	Item 7:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27-41
	Item 7A:	Quantitative and Qualitative Disclosures about Market Risk	41-44
	Item 8:	Financial Statements and Supplementary Data	45-86
	Item 9:	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	86
	Item 9A:	Controls and Procedures	86-88
	Item 9B:	Other Information	89
PART III
	Item 10:	Directors and Executive Officers of the Registrant	89-91
	Item 11:	Executive Compensation	91-95
	Item 12:	Security Ownership of Certain Beneficial Owners and Management	95-96
	Item 13:	Certain Relationships and Related Transactions	97-98
	Item 14:	Principal Accounting Fees and Services	99
PART IV
	Item 15:	Exhibit, Financial Statement Schedules	99-100
			101
SIGNATURES

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PART I

ITEM 1: BUSINESS

THE FOLLOWING DISCUSSION CONTAINS FORWARD-LOOKING STATEMENTS REGARDING EVENTS AND FINANCIAL TRENDS WHICH MAY AFFECT OUR FUTURE OPERATING RESULTS AND FINANCIAL POSITION. SUCH STATEMENTS ARE SUBJECT TO RISKS AND UNCERTAINTIES THAT COULD CAUSE OUR ACTUAL RESULTS AND FINANCIAL POSITION TO DIFFER MATERIALLY FROM THOSE ANTICIPATED IN SUCH STATEMENTS. THESE RISKS INCLUDE THE NEED FOR ADDITIONAL CAPITAL AND ABILITY TO RAISE THAT CAPITAL FROM INVESTORS IN OUR DRILLING PROGRAMS, RISKS ASSOCIATED WITH EXPLORING, DEVELOPING AND OPERATING NATURAL GAS AND OIL WELLS, AND FLUCTUATIONS IN THE MARKET FOR NATURAL GAS AND OIL. FOR A MORE COMPLETE DISCUSSION OF THE RISKS AND UNCERTAINTIES TO WHICH WE ARE SUBJECT, SEE “RISK FACTORS” IN THIS ITEM 1.

General

We are an energy company engaged primarily in the development and production of natural gas and, to a lesser extent, oil in the western New York, eastern Ohio, western Pennsylvania and Tennessee region of the Appalachian Basin for our own account and for investors through the offering of tax-advantaged investment programs. We have been involved in the energy industry since 1968. We began to expand our operations at the end of fiscal 1998 when we acquired The Atlas Group, Inc. and a year later when we acquired Viking Resources Corporation, both energy finance and production companies. We also wholly-own Atlas Pipeline Partners GP, LLC (“Atlas Pipeline Partners GP”), the general partner of Atlas Pipeline Partners, L.P. (NYSE: APL) which owns a 2% general partner interest and 1,641,026 common units constituting a 13.2% limited partner interest for a total partnership interest of 15.2%. Atlas Pipeline owns and operates approximately 3,800 miles of intrastate and interstate natural gas pipelines in Arkansas, Missouri, New York, Ohio, Oklahoma, Pennsylvania and Texas connected to approximately 6,250 miles of central delivery points or wells and gas processing facilities in Oklahoma.

As of or during the year ended September 30, 2005:

· proved reserves net to our interest grew to 171.6 billion cubic feet of natural gas equivalents, or bcfe, from 155.8 bcfe at September 30, 2004, and the PV-10 value of these reserves grew to $845.7 million from $320.4 million. During the same period, proved reserves we manage for our drilling investment partnerships and others grew to 229.5 bcfe from 209.4 bcfe, and the PV-10 value of these reserves grew to $1.176 billion from $457.1 million;

· we had an acreage position of approximately 512,300 gross (460,600 net) acres, of which 267,300 gross (253,900 net) acres were undeveloped as compared to 483,600 gross (433,200 net) acres, of which 249,800 gross (236,000 net) were undeveloped at September 30, 2004;

· we had, either directly or through our sponsored drilling partnerships, interests in 6,379 gross wells, including royalty and overriding royalty interests in 621 wells, as compared to interests in 5,755 gross wells, including royalty and overriding royalty interests in 628 wells, at September 30, 2004. We operate approximately 91% of the wells in which we have interests;

· wells in which we had an interest produced, net to our interest, approximately 20.9 million cubic feet, or mmcf, of natural gas and 433 barrels, or bbls, of oil per day during fiscal 2005, compared to 19.9 mmcf of natural gas and 495 bbls of oil per day during the year ended September 30, 2004;

· the number of wells we drilled, net to both our interest and that of our sponsored drilling investment partnerships, increased to 615 wells in fiscal 2005 from 450 wells in fiscal 2004.; and

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· distributions we received from Atlas Pipeline increased from $5.6 million in fiscal 2004 to $10.8 million in fiscal 2005

Initial Public Offering. In May 2004, we completed an initial public offering of 2,645,000 shares of our common stock at a price of $15.50 per common share. The net proceeds of the offering of $37.0 million, after deducting underwriting discounts and costs, were distributed to our then parent, Resource America, Inc. (“RAI”) (NASDAQ: REXI) in the form of a non-taxable dividend.

On June 30, 2005, RAI distributed its remaining 10.7 million shares of our common stock to its stockholders in the form of a tax-free dividend. Each stockholder of RAI received 0.59367 shares of our common stock for each share of RAI common stock owned as of June 24, 2005, the record date. Although the distribution itself was tax-free to RAI stockholders, as a result of the deconsolidation there may be some tax liability arising from prior unrelated corporate transactions among us and some of our subsidiaries. Any liability arising from this transaction will be reimbursed by us to RAI. We are no longer consolidated with RAI as of June 30, 2005. In connection with the spin-off, we entered into a series of agreements with RAI, including a master separation and distribution agreement and a tax matters agreement, which govern the future contractual obligations between the two companies.

Possible Public Offering of Atlas Pipeline Partners, GP.    We recently announced that we are considering transferring our ownership interest in Atlas Pipeline Partners GP to a new wholly-owned subsidiary and then making a registered initial public offering of a minority interest in the subsidiary. This report does not constitute an offer to sell or a solicitation of an offer to buy any such securities.

Drilling Activities

We fund our drilling activities through the sponsorship of drilling investment partnerships. Although we have been raising capital through drilling investment partnerships since 1968, the amount of the capital raised through these partnerships has increased substantially since 1998. We completed our fund raising for calendar year 2005 in November 2005 with a total of $55.0 million raised after our fiscal year end, bringing the total for the calendar year 2005 to $116.6 million; in calendar year 2004 we raised $111.9 million (historically our fund-raising cycle has been on a calendar year basis). We act as the general partner of our sponsored drilling investment partnerships and receive both an interest proportionate to the amount of capital and the value of the properties we contribute, typically 25 to 28%, and a carried interest, typically 7%, both of which are subordinated to specified returns to the investor partners for the first five years of distributions. Accordingly, the amount of development activities we undertake depends upon our ability to obtain investor subscriptions to the partnerships. During fiscal 2005, 2004 and 2003, our drilling investment partnerships invested $157.0 million, $125.0 million and $68.6 million, respectively, in drilling and completing wells, of which we contributed $57.3 million, $31.9 million and $15.7 million, respectively.

We generally structure our drilling investment partnerships so that, upon formation of a partnership, we contribute leaseholds to it, enter into drilling and well operating agreements with it and become its general or managing partner. In addition to providing capital for our drilling activities, our drilling investment partnerships are a source of fee-based revenue. We drill all of the partnership wells under “cost plus” contracts for which we are paid the costs of drilling the wells plus a fee equal to 15% of those costs. We also act as well operator and partnership manager, for which we receive monthly operating fees of approximately $275 to $285 per well, approximately $187 to $194 net of our interest, and monthly administrative fees of approximately $75 per well, approximately $51 net of our interest.

Our business strategy for increasing our reserve base includes acquisitions of undeveloped properties or companies with significant amounts of undeveloped property. At September 30, 2005, we had $65.6 million available under our credit facility, which could be employed to finance such acquisitions.

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Pipeline Operations

We conduct our natural gas transportation and processing operations through Atlas Pipeline. Atlas Pipeline consists of gathering systems in the Appalachian Basin area (“Appalachia”) and through acquisitions, transmission, gathering and processing facilities in the Mid-Continent area (“Mid-Continent”) of Arkansas, Missouri, Oklahoma and Texas. Atlas Pipeline’s gathering systems had an average daily throughput of 292.9 mmcf, 63.5 mmcf and 52.7 mmcf of natural gas in fiscal 2005, 2004 and 2003, respectively. We also directly own approximately 400 miles of natural gas gathering systems in Ohio and Pennsylvania.

As general partner, we have the right to receive incentive distributions if Atlas Pipeline exceeds its minimum quarterly distribution obligations to the common units. Once Atlas Pipeline distributes available cash to all unitholders of the minimum quarterly distribution of $0.42, it distributes remaining available cash as follows:

· until the common units have received distributions of $0.10 per unit in excess of the $0.42 minimum quarterly distribution, available cash is allocated 85% to unit holders (including to us as a limited partner holder) and 15% to us as a general partner;

· after that, additional available cash is allocated 75% to unit holders and 25% to us as a general partner until the common units have received distributions of an additional $0.08 per unit, and;

· after that, available cash is allocated 50% to unit holders and 50% to us as a general partner.

We have agreements with Atlas Pipeline that require us to:

· pay gathering fees to Atlas Pipeline for natural gas produced by us and our drilling investment partnerships and gathered by the gathering systems equal to the greater of $0.35 per mcf ($0.40 per mcf in certain instances) or 16% of the gross sales price of the natural gas transported. For the years ended September 30, 2005, 2004 and 2003, these gathering fees averaged $1.10, $0.88 and $0.75 per mcf, respectively. The cost to us of paying these fees is offset by the transportation fees paid to us by our drilling investment partnerships, reimbursements and distributions to us from Atlas Pipeline and connection costs and other expenses paid by Atlas Pipeline, and

· connect wells owned or controlled by us that are within specified distances of Atlas Pipeline’s gathering systems to those gathering systems.

We believe that we comply with all the requirements of these agreements.

Public Offerings. In November 2005, Atlas Pipeline completed a public offering of 2.7 million common units, realizing net proceeds of $110.0 million, including a $2.3 million capital contribution from us as general partner and after deducting underwriting discounts, commissions and estimated offering expenses of $5.7 million. Atlas Pipeline used the net proceeds of the offering to repay a portion of the amounts outstanding under its credit facility. Our interest in Atlas Pipeline decreased to 15.2% as a result of this offering. In June 2005, Atlas Pipeline completed a public offering of 2.3 million common units. The net proceeds after underwriting discounts, commissions and costs were approximately $93.7 million, including $1.9 million from us in order to maintain our 2% general partner interest in Atlas Pipeline. Atlas Pipeline used these proceeds to repay in full its $45.0 million term loan and to reduce outstanding indebtedness under the revolving credit portion of its credit facility.

In April and July 2004, Atlas Pipeline completed public offerings of 750,000 and 2.1 million common units, respectively. The net proceeds after underwriting discounts, commissions and costs were $25.2 million and $67.5 million, respectively.

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Acquisition of Atlas Arkansas Pipeline, LLC and Controlling Interest in NOARKPipeline System, Limited Partnership.    On October 31, 2005, Atlas Pipeline acquired from Enogex, Inc., a wholly-owned subsidiary of OGE Energy Corp. (NYSE: OGE), all of the outstanding equity of Atlas Arkansas Pipeline, LLC ("Atlas Arkansas"), which owns a 75% interest in NOARK Pipeline System, Limited Partnership ("NOARK"), for $165.3 million, including estimated related transaction costs, plus $10.2 million for working capital adjustments. The remaining 25% interest in NOARK is owned by Southwestern Energy Pipeline Company (“Southwestern”), a wholly-owned subsidiary of Southwestern Energy Company (NYSE: SWN). Before the closing of the 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 Atlas Pipeline's 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 Atlas Pipeline's other businesses and interconnections with major interstate pipelines also provides it 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 southeast Oklahoma through Arkansas and into southeast Missouri and has a throughout capacity of approximately 322 mmcf per day. 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.

Atlas Pipeline financed the acquisition by borrowing under its revolving credit facility.

Acquisition of Elk City. On April 14, 2005, Atlas Pipeline acquired all of the outstanding equity interests in ETC Oklahoma Pipeline, Ltd. (“Elk City”), a Texas limited partnership, for $196.0 million, including related transaction costs. Elk City’s principal assets include 318 miles of natural gas pipelines located in the Anadarko Basin in western Oklahoma, a natural gas processing facility in Elk City, Oklahoma, with total capacity of 130 million cubic feet of gas per day ("mmcf/d") and a gas treatment facility in Prentiss, Oklahoma, with a total capacity of 100 mmcf/d. Total gas throughput is currently approximately 242 mmcf/d. Total compression horsepower (“hp”) consists of 21,000 hp at six field stations and 12,000 hp within the Elk City and Prentiss facilities. The system gathers and processes gas from more than 300 receipt points representing more than fifty producers and delivers that gas into multiple interstate pipeline systems. The acquisition expands Atlas Pipeline’s activities in the Mid-Continent area and provides the potential for further growth in its operations based in Tulsa, Oklahoma.

To finance the Elk City acquisition, Atlas Pipeline entered into a new $270 million credit facility which replaced its existing $135 million facility. The facility was comprised of a five year $225.0 million revolving line of credit and a five year $45.0 million term loan administered by Wachovia Bank. The term loan portion of the credit facility was repaid and retired through a portion of the net proceeds from Atlas Pipeline’s June 2005 equity offering.

Acquisition of Spectrum Field Services. In July 2004, Atlas Pipeline acquired Spectrum Field Services, Inc., (“Spectrum”), for approximately $141.6 million, including transaction costs and taxes due as a result of the transaction. This acquisition significantly increased Atlas Pipeline's size and diversified the natural gas supply basins in which it operates and the natural gas midstream services it provides to its customers. Spectrum was a privately owned natural gas gathering and processing company headquartered in Tulsa, Oklahoma. Spectrum’s business includes gathering natural gas from oil and gas wells and processing this raw natural gas into merchantable natural gas, or residue gas, by extracting natural gas liquids, or NGLs, and removing impurities. Spectrum’s principal assets consist of a gas processing plant in Velma, Oklahoma and approximately 1,100 miles of active and 760 miles of inactive natural gas gathering pipelines in south central Oklahoma and north Texas.

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Atlas Pipeline financed the Spectrum acquisition, including approximately $4.2 million of transaction costs, as follows:

· borrowing $100.0 million under the term loan portion of its $135.0 million senior secured term loan and revolving credit facility administered by Wachovia Bank, National Association;

· using the $20.0 million of net proceeds received from the sale to Resource America and us of preferred units in Atlas Pipeline Operating Partnership; and

· using $22.4 million of the net proceeds from Atlas Pipeline’s April 2004 common unit offering.

Atlas Pipeline used a portion of the net proceeds of its July 2004 offering to repay $40.0 million of the borrowings under its credit facility and to repurchase for $20.4 million the preferred units issued to Resource America and us.

Alaska Pipeline Terminated Acquisition. In September 2003, Atlas Pipeline entered into an agreement with SEMCO Energy, Inc. to purchase all of the stock of Alaska Pipeline Company (“APC”). In order to complete the acquisition, Atlas Pipeline needed the approval of the Regulatory Commission of Alaska. The Regulatory Commission initially approved the transaction, but on June 4, 2004, it vacated its order of approval based upon a motion for clarification or reconsideration filed by SEMCO. On July 1, 2004, SEMCO sent Atlas Pipeline a notice purporting to terminate the transaction. Atlas Pipeline pursued its remedies under the acquisition agreement. In connection with the acquisition, subsequent termination, and settlement of the legal action, Atlas Pipeline incurred costs of approximately $1.2 million in the year ended September 30, 2005 which were included in arbitration settlement, net on the Company’s Consolidated Statements of Income. Atlas Pipeline also incurred $3.0 million of costs in the year ended September 30, 2004. On December 30, 2004, Atlas Pipeline entered into an agreement with SEMCO settling all issues and matters related to SEMCO’s termination of the sale of APC to Atlas Pipeline and SEMCO paid Atlas Pipeline $5.5 million which was also included in arbitration settlement, net.

Operating Segment Information

For financial information concerning our operating segments, including revenues from external customers, profit (loss) and total assets, see Note 14 to our Notes to Consolidated Financial Statements.

Natural Gas and Oil Properties

For information concerning our natural gas and oil properties, including the number of wells in which we have a working interest, reserve and acreage information, see Item 2: “Properties.”

Production

For information concerning our natural gas and oil production quantities, average sales prices and average production costs, see Item 2: “Properties.”

Natural Gas Sales− Appalachian Basin

We have a natural gas supply agreement with Amerada Hess Corporation (“Amerada Hess”) which is valid through March 31, 2009. The agreement was formerly with FirstEnergy Solutions Corporation, and was acquired by Amerada Hess in 2005. Subject to certain exceptions, Amerada Hess has a last right of refusal to buy all of the natural gas produced and delivered by us and our affiliates, including our drilling investment partnerships, at certain delivery points with the facilities of:

· East Ohio Gas Company, National Fuel Gas Distribution, Columbia of Ohio, and Peoples Natural Gas Company, which are local distribution companies; and

· National Fuel Gas Supply, Columbia Gas Transmission Corporation, Tennessee Gas Pipeline Company, and Texas Eastern Transmission Company, which are interstate pipelines.

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A portion of our and our drilling investment partnerships' natural gas is subject to the agreement with Amerada Hess, with the following exceptions:

· natural gas we sell to Warren Consolidated, an industrial end-user and direct delivery customer;

· natural gas that at the time of the agreement was already dedicated for the life of the well to another buyer;

· natural gas that is produced by a company which was not an affiliate of ours at the time of the agreement;

· natural gas sold through interconnects established subsequent to the agreement;

· natural gas that is delivered to interstate pipelines or local distribution companies other than those described above; and

· natural gas that is produced from wells operated by a third-party or subject to an agreement under which a third-party was to arrange for the gathering and sale of the natural gas.

Based on the most recent monthly production data available to us as of November 30, 2005, we anticipate that we and our affiliates, including our drilling investment partnerships, will sell approximately 40% of our natural gas production under the Amerada Hess agreement. The agreement also permits us to implement forward sales transactions through Amerada Hess, as described below under “—Natural Gas Hedging − Appalachian Basin.”

The agreement established an indexed price formula for each of the delivery points during an initial period of one to two years, and requires the parties to negotiate a new pricing arrangement at each delivery point for subsequent periods. If, at the end of any applicable period, the parties cannot agree to a new price for any delivery point, then we may solicit offers from third-parties to buy the natural gas for that delivery point. If Amerada Hess does not match this price, then we may sell the natural gas to the third-party. This process is repeated at the end of each contract period, which is usually one year. We market the remainder of our natural gas, which is principally located in the Fayette County, PA area, primarily to Colonial Energy, Inc., UGI Energy Services, and others.

Our pricing arrangements with Amerada Hess and the other third-parties are tied to the New York Mercantile Exchange, or NYMEX, monthly futures contract price, which is reported daily in The Wall Street Journal. The total price received for gas is a combination of the monthly NYMEX futures price plus a negotiated fixed basis premium.

The agreement with Amerada Hess may be suspended for force majeure, which generally means such things as an act of God, fire, storm, flood, pipeline curtailments and explosion.

We expect that natural gas produced from wells drilled in areas of the Appalachian Basin other than described above will be primarily tied to the spot market price and supplied to:

· gas marketers;

· local distribution companies;

· industrial or other end-users; and/or

· companies generating electricity.

Crude Oil Sales − Appalachian Basin

Crude oil produced from our wells flows directly into storage tanks where it is picked up by the oil company, a common carrier, or pipeline companies acting for the oil company which is purchasing the crude oil. Unlike natural gas, crude oil does not present any transportation problem. We anticipate selling any oil produced by our wells to regional oil refining companies at the prevailing spot market price for Appalachian crude oil in spot sales.

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Natural Gas and NGL Supply and Sales - Mid-Continent

Atlas Pipeline’s revenues in the Mid-Continent area are determined primarily by the fees it earns from the following types of arrangements:

Fee-Based Contracts. Under these contracts, Atlas Pipeline receives a set fee for gathering and processing raw natural gas. Revenue is a function of the volume of gas that is gathered and processed and is not directly dependent on the value of that gas.

Percent of Proceeds (“POP”) Contracts. Under these contracts, Atlas Pipeline retains a negotiated percentage of the sale proceeds from residue natural gas and NGLs gathered and processed, with the remainder being remitted to the producer. In this situation, Atlas Pipeline and the producer are directly dependent on the volume of the commodity and its value; we own a percentage of that commodity and are directly subject to its ultimate market value.

Keep Whole Contracts. As a result of the acquired Elk City gathering systems, Atlas Pipeline has “keep whole” contracts. “Keep whole” contracts require the processor to bear the economic risk (called 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 the processor paid for the unprocessed natural gas. However, since gas received into the Elk City system 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.

As a result of the POP and keep whole contracts, Atlas Pipeline’s 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 the past year, mainly due to recent significant increases in natural gas prices, which could result in sustained increases in drilling activity during 2006. 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.

Dismantlement, Restoration, Reclamation and Abandonment Costs

When we determine that a well is no longer capable of producing natural gas or oil in economic quantities, we must dismantle the well and restore and reclaim the surrounding area before we can abandon the well. We contract these operations to independent service providers to whom we pay a fee. The contractor will also salvage the equipment on the well, which we then sell in the used equipment market. Under the partnership agreements of our drilling investment partnerships, which own the majority of our wells, we are allocated abandonment costs in proportion to our partnership interest (generally between 27% and 35%) and are allocated between 65% and 100% of the salvage proceeds. As a consequence, we generally receive proceeds from salvaged equipment at least equal to, and typically exceeding, our share of the related costs. See Note 2 of our Notes to Consolidated Financial Statements, “− Asset Retirement Obligations.”

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Natural Gas Hedging − Appalachian Basin

Pricing for natural gas and oil production has been volatile and unpredictable for many years. To limit exposure to changing natural gas prices, from time to time we use hedges for our Appalachian Basin natural gas production. Through our hedges, we seek to provide a measure of stability in the volatile environment of natural gas prices. These hedges may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. The futures contracts are commitments to purchase or sell natural gas at future dates and generally cover one-month periods for up to 24 months in the future. To assure that the financial instruments will be used solely for hedging price risks and not for speculative purposes, we have a committee to assure that all financial trading is done in compliance with our hedging policies and procedures. We do not intend to contract for positions that we cannot offset with actual production.

Amerada Hess and other third-party marketers to which we sell gas, such as Colonial Energy, Inc. and UGI Energy Services, also use NYMEX-based financial instruments to hedge their pricing exposure and make price hedging opportunities available to us. We enter into forward sales transactions which are not deemed hedges for accounting purposes because they require firm delivery of natural gas and are considered normal sales of natural gas. We generally limit these arrangements to much smaller quantities than those projected to be available at any delivery point. The price paid by Amerada Hess, Colonial Energy, Inc., UGI Energy Services, and any other third-party marketers for certain volumes of natural gas sold under these sales agreements may be significantly different from the underlying monthly spot market value. Fixed prices are defined as the price we have established with the related purchaser and are not subject to change in the future.

The portion of natural gas that we engage in forward sales and the manner in which it is sold (e.g., fixed pricing, floor and/or floor price with a cap, which we refer to as costless collar) changes from time to time. As of September 30, 2005, our overall forward sales position for the future months ending March 2007 for our natural gas production was approximately as follows:

· 65% was sold with a fixed price;

· 1% was sold with a floor price and/or costless collar price; and

· 34% was not sold and was subject to market-based pricing

We implemented approximately 58% of these forward sales through Amerada Hess. For information concerning our natural gas hedging, see Item 7: “Management's Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” and Note 6 of our Notes to Consolidated Financial Statements.

Natural Gas and NGL Hedging - Mid-Continent

Atlas Pipeline, through its subsidiary, Atlas Pipeline Mid-Continent, LLC (“Mid-Continent”), also uses hedges to limit its exposure to changing natural gas and NGL prices. These hedges include floating-for-fixed swaps and collars. In a floating-for-fixed swap, Mid-Continent sells future production to the counterparty at a fixed price and agrees to purchase production from the counterparty at a price that will be established on the date of hedge settlement by reference to a specified index price. In a collar, Mid-Continent purchases a put option for specified production quantities while simultaneously selling a call option on the same amount of production. These hedges cover periods of up to four years from the date of the hedge. To insure that these financial instruments will be used solely for hedging price risks and not for speculative purposes, Mid-Continent has established a hedging committee to review its hedges for compliance with its hedging policies and procedures. In addition, Mid-Continent does not enter into a hedge where it cannot offset the hedge with physical residue natural gas or NGL sales.

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Mid-Continent has hedged portions of natural gas, NGLs and condensate volumes for fixed prices for various periods through 2009. The following table summarizes the hedge positions through December 31, 2006:

Commodity	Average Percentage of Anticipated Volumes Hedged	Average Fixed Price
Natural gas	48%	$6.55/mmbtu
NGLs	54%	$0.68/gallon
Condensate	62%	$49.51/bbl

Mid-Continent recognizes gains and losses from the settlement of its hedges in revenue when it sells the associated physical residue natural gas or NGLs. Any gain or loss realized as a result of hedging is substantially offset in the market when Mid-Continent sells the physical residue natural gas or NGLs. All of Mid-Continent’s hedges are characterized as cash flow hedges as defined in Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Accounting.” Mid-Continent determines gains or losses on open and closed hedging transactions as the difference between the hedge price and the physical price. This mark-to-market uses daily closing NYMEX prices when applicable and an internally-generated algorithm for hedged commodities that are not traded on a market.

Availability of Oil Field Services

We contract for drilling rigs and purchase goods and services necessary for the drilling and completion of wells from a number of drillers and suppliers, none of which supplies a significant portion of our annual needs. During fiscal 2005, we faced no shortage of these goods and services. We cannot predict the duration of the current supply and demand situation for drilling rigs and other goods and services with any certainty due to numerous factors affecting the energy industry and the demand for natural gas and oil.

Major Customers

Our NGLs and natural gas are sold under contract to various purchasers. During fiscal 2005, NGL sales to Koch Hydrocarbon and its successor, ONEOK Hydrocarbons Company, accounted for 20% of our total revenues. During fiscal 2004 and 2003, gas sales to Amerada Hess (formerly FirstEnergy Solutions) accounted for 11% and 18%, respectively, of our total revenues.

Competition

The energy industry is intensely competitive in all of its aspects. Competition arises not only from numerous domestic and foreign sources of natural gas and oil but also from other industries that supply alternative sources of energy. Competition is intense for the acquisition of leases considered favorable for the development of natural gas and oil in commercial quantities. Product availability and price are the principal means of competition in selling oil and natural gas. Many of our competitors possess greater financial and other resources than ours which may enable them to identify and acquire desirable properties and market their natural gas and oil production more effectively than we do. While it is impossible for us to accurately determine our comparative industry position, we do not consider our operations to be a significant factor in the industry. Moreover, we also compete with a number of other companies that offer interests in drilling investment partnerships. As a result, competition for investment capital to fund drilling investment partnerships is intense.

Atlas Pipeline’s Appalachian Basin operations do not encounter direct competition in their service areas since we control the majority of the drillable acreage in each area. However, because its Appalachian Basin operations principally serve wells drilled by us, Atlas Pipeline is affected by competitive factors affecting our ability to obtain properties and drill wells, which affects Atlas Pipeline’s ability to expand their gathering systems and to maintain or increase the volume of natural gas they transport and, thus, their transportation revenues. We may also encounter competition in obtaining drilling services from third-party providers. Any competition we encounter could delay us in drilling wells for our sponsored partnerships, and thus delay the connection of wells to Atlas Pipeline’s gathering systems.

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As Atlas Pipeline’s omnibus agreement with us generally requires us to connect wells we operate to its system, Atlas Pipeline does not expect any direct competition in connecting wells drilled and operated by us in the future. In addition, Atlas Pipeline occasionally connects wells operated by third parties.

In its Mid-Continent service area, Atlas Pipeline competes for the acquisition of well connections with several other gathering/servicing operations. These operations include plants and gathering systems operated by Duke Energy Field Services, ONEOK Field Services and Enbridge Energy Partners, L.P. 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 Atlas Pipeline's electric compressors operate more efficiently than the gas-operated compressors used by its competitors. As a result, we believe that Atlas Pipeline can operate as or more cost-effectively than its competitors. We also believe that Atlas Pipeline's relationships with operators connected to its system are good and that it presents an attractive alternative for producers. However, if Atlas Pipeline cannot compete successfully, it may be unable to obtain new well connections and, possibly, could lose wells already connected to its systems.

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

Markets

The availability of a ready market for natural gas and oil and the price obtained, depends upon numerous factors beyond our control, as described in “− Risk Factors ― Risks Relating to Our Business.” During fiscal 2005, 2004 and 2003, neither Atlas Pipeline nor we experienced problems in selling our natural gas and oil, although prices have varied significantly during and after those periods.

Governmental Regulation

Regulation of Production.The production of natural gas and oil is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of natural gas and oil that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exemptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

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Regulation by FERC of Interstate Natural Gas Pipelines.    FERC regulates Atlas Pipeline's interstate natural gas pipeline interests. Through Atlas Arkansas, it owns 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.

Gathering Pipeline Regulation.    Section 1(b) of the Natural Gas Act exempts natural gas gathering facilities from the jurisdiction of the FERC. Atlas Pipeline owns 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. Atlas Pipeline's operating subsidiary has been granted an exemption by the Public Utilities Commission of Ohio for its Ohio facilities. The New York Public Service Commission imposes traditional public utility regulation on the transportation of natural gas by companies subject to its regulation. This regulation includes rates, services and sitting authority for the construction of certain facilities. Atlas Pipeline's gas gathering operations currently are not subject to regulation by the New York Public Service Commission. Atlas Pipeline's operations in Pennsylvania currently are not subject to the Pennsylvania Public Utility Commission’s regulatory authority since they do not provide service to the public generally and, accordingly, do not constitute the operation of a public utility. Similarly, its operations in Arkansas are not subject to regulatory oversight by the Arkansas Public Service Commission.

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Atlas Pipeline is 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 Atlas Pipeline's 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 Atlas Pipeline's 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.

Atlas Pipeline's gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Environmental and Safety Regulation. Under the Comprehensive Environmental Response, Compensation and Liability Act, the Toxic Substances Control Act, the Resource Conservation and Recovery Act, the Oil Pollution Act of 1990, the Clean Air Act, and other federal and state laws relating to the environment, owners and operators of wells producing natural gas or oil, and pipelines, can be liable for fines, penalties and clean-up costs for pollution caused by the wells or the pipelines. Moreover, the owners’ or operators’ liability can extend to pollution costs from situations that occurred prior to their acquisition of the assets. Natural gas pipelines are also subject to safety regulation under the Natural Gas Pipeline Safety Act of 1968 and the Pipeline Safety Act of 1992 which, among other things, dictate the type of pipeline, quality of pipeline, depth, and methods of welding and other construction-related standards. State public utility regulators have either adopted federal standards or promulgated their own safety requirements consistent with the federal regulations.

We do not anticipate that we will be required in the near future to expend amounts that are material in relation to our revenues by reason of environmental laws and regulations, but since these laws and regulations change frequently, we cannot predict the ultimate cost of compliance.

Credit Facilities

Our Credit Facility. We have a $75.0 million credit facility administered by Wachovia Bank, National Association. The revolving credit facility is guaranteed by our subsidiaries. Up to $50.0 million of the borrowings under the facility may be in the form of standby letters of credit. Borrowings under the facility are secured by our assets, including the stock of our subsidiaries. At September 30, 2005, $8.0 million was outstanding under this facility.

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Loans under the facility bear interest at one of the following two rates, at our election:

· the base rate plus the applicable margin; or

· the adjusted London Interbank Offered Rate, or LIBOR, plus the applicable margin.

The base rate for any day equals the higher of the federal funds rate plus ½ of 1% or the Wachovia Bank prime rate. Adjusted LIBOR is LIBOR divided by 1.00 minus the percentage prescribed by the Board of Governors of the Federal Reserve System for determining the reserve requirement for euro currency funding. The applicable margin is as follows:

· where utilization of the borrowing base is equal to or less than 50%, the applicable margin is 0.25% for base rate loans and 1.75% for LIBOR loans;

· where utilization of the borrowing base is greater than 50% but equal to or less than 75%, the applicable margin is 0.50% for base rate loans and 2.00% for LIBOR loans; and

· where utilization of the borrowing base is greater than 75%, the applicable margin is 0.75% for base rate loans and 2.25% for LIBOR loans.

At September 30, 2005, the weighted average interest rate on the outstanding Wachovia credit facility borrowings was 6.1%.

The Wachovia credit facility requires us to maintain a specified net worth and specified ratios of current assets to current liabilities and debt to earnings before interest, taxes, depreciation, depletion and amortization, or EBITDA. In addition, the facility limits sales, leases or transfers of assets and the incurrence of additional indebtedness. The facility limits the dividends payable by us to 50% of our cumulative net income from January 1, 2004 to the date of determination plus $5.0 million and prohibits us from declaring or paying a dividend during an event of default under the facility or if the dividend would cause an event of default. As of September 30, 2005, we would be permitted to pay dividends of $27.1 million under these restrictions. We complied with all covenants as of September 30, 2005. The facility terminates in March 2007 when all outstanding borrowings must be repaid.

Atlas Pipeline Credit Facility. On April 14, 2005, Atlas Pipeline entered into a new $270.0 million credit facility (“Credit Facility”) with a syndicate of banks, which replaced its existing $135.0 million facility. The facility was comprised of a five-year $225.0 million revolving line of credit and a five-year $45.0 million term loan. The term loan portion of the Credit Facility was repaid and retired through a portion of the net proceeds from its June 2005 equity offering. Concurrently with Atlas Pipeline's completion of the NOARK acquisition, the facility was increased to $400.0 million. The revolving portion of the Credit Facility bears interest, at Atlas Pipeline’s option, at either (i) Adjusted LIBOR plus an applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). The weighted average interest rate on the outstanding credit facility borrowings at September 30, 2005 was 6.6%. Up to $50.0 million of the revolving Credit Facility may be utilized for letters of credit, of which $7.7 million is outstanding at September 30, 2005 and are not reflected as borrowings on our consolidated balance sheets. Borrowings under the facility are secured by a lien on and security interest in all of Atlas Pipeline’s property and that of its subsidiaries, and by the guaranty of each of Atlas Pipeline’s subsidiaries (except NOARK).

The Credit Facility contains customary covenants, including limitation of Atlas Pipeline’s ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in Atlas Pipeline’s subsidiaries. The credit facility also requires Atlas Pipeline to maintain a specified interest coverage ratio, a specified ratio of funded debt to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”), adjusted as provided in the credit facility and a specified ratio of senior secured debt to such adjusted EBITDA. Atlas Pipeline is in compliance with these covenants as of September 30, 2005. Atlas Pipeline is required to prepay $175.0 million of the credit facility with the net proceeds of any assets sales or issuances of debt or equity. With the proceeds received from Atlas Pipeline’s November 2005 equity offering, a principal payment of $108.3 million was made in accordance with the requirement above.

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Employees

As of September 30, 2005, we employed 340 persons.

ITEM 1A: RISK FACTORS

Statements made by us in written or oral form to various persons, including statements made in filings with the SEC that are not strictly historical facts, are “forward-looking” statements that are based on current expectations about our business and assumptions made by management. These statements are subject to risks and uncertainties that exist in our operations and business environment that could result in actual outcomes and results that are materially different than predicted. The following includes some, but not all, of those factors or uncertainties:

Natural gas and oil prices are volatile. A substantial decrease in prices, particularly natural gas prices, would decrease our revenues and the value of our natural gas and oil properties and could make it more difficult for us to obtain financing for our drilling operations through drilling investment partnerships.

Our future financial condition and results of operations, and the value of our natural gas and oil properties, will depend upon market prices for natural gas and oil. Natural gas and oil prices historically have been volatile and will likely continue to be volatile in the future. Prices we have received during our past three fiscal years for our natural gas have ranged from a high of $7.87 per Mcf in the quarter ended September 30, 2005 to a low of $3.39 per Mcf in the quarter ended December 31, 2001. Prices for natural gas and oil are dictated by supply and demand. Factors affecting supply the following:

· the availability of pipeline capacity;

· the viability of economic exploration and development of oil and gas reserves:

· domestic and foreign governmental regulations and taxes;

· political instability or armed conflict in oil producing regions or other market uncertainties; and

· the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil prices and production controls.

The factors affecting demand include:

· weather conditions;

· the price and availability of alternative fuels;

· the price and level of foreign imports; and

· the overall economic environment.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and gas price movements with any certainty. Price fluctuations can materially adversely affect us because:

· price decreases will reduce the amount of cash flow available to us for drilling and production operations and for our capital contributions to our drilling investment partnerships;

· price decreases may make it more difficult to obtain financing for our drilling and development operations through sponsored drilling investment partnerships, borrowing or otherwise;

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· price decreases may make some reserves uneconomic to produce, reducing our reserves and cash flow; and

· price decreases may cause the lenders under our credit facility to reduce our borrowing base because of lower revenues or reserve values, reducing our liquidity and, possibly, requiring mandatory loan repayment.

Further, oil and gas prices do not necessarily move in tandem. Because approximately 92% of our proved reserves are currently natural gas reserves, we are more susceptible to movements in natural gas prices.

Drilling wells is highly speculative. The amount of recoverable natural gas and oil reserves may vary significantly from well to well. While our average estimated ultimate recovery from our wells is 149,656 Mmcfe per well, recoverable natural gas from individual wells ranges up to 1.68 Bcfe. We may drill wells that, while profitable on an operating basis, do not produce sufficient net revenues to return a profit after drilling, operating and other costs are taken into account. The geologic data and technologies available do not allow us to know conclusively before drilling a well that natural gas or oil is present or may be produced economically. The cost of drilling, completing and operating a well is often uncertain. For example, from 2003 through early 2005 we experienced an increase in the cost of tubular steel as a result of rising steel prices which will increase well costs. Further, our drilling operations may be curtailed, delayed or cancelled as a result of many factors, including:

· title problems;

· environmental or other regulatory concerns;

· costs of, or shortages or delays in the availability of, oil field services and equipment;

· unexpected drilling conditions;

· unexpected geological conditions;

· adverse weather conditions; and

· equipment failures or accidents.

Any one or more of the factors discussed above could reduce or delay our receipt of drilling and production revenues, thereby reducing our earnings, and could reduce revenues in one or more of our drilling investment partnerships, which may make it more difficult to finance our drilling operations through sponsorship of future partnerships.

Properties that we acquire may not produce as projected, and we may be unable to identify liabilities associated with the properties or obtain protection from sellers against them. As part of our business strategy, we continually seek acquisitions of gas and oil properties. The successful acquisition of natural gas and oil properties requires assessment of many factors, which are inherently inexact and may be inaccurate, including the following:

· future oil and natural gas prices;

· the amount of recoverable reserves;

· future operating costs;

· future development costs;

· costs and timing of plugging and abandoning wells; and

· potential environmental and other liabilities.

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Our assessment will not necessarily reveal all existing or potential problems, nor will it permit us to become familiar enough with the properties to assess fully their capabilities and deficiencies. With respect to properties on which there is current production, we may not inspect every well, platform or pipeline in the course of our due diligence. Inspections may not reveal structural and environmental problems such as pipeline corrosion or groundwater contamination. We may not be able to obtain or recover on contractual indemnities from the seller for liabilities that it created. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

Estimates of proved reserves are uncertain and, as a result, revenues from production may vary significantly from our expectations. We base our estimates of our proved natural gas and oil reserves and future net revenues from those reserves upon analyses that rely upon various assumptions, including those required by the Securities and Exchange Commission, as to natural gas and oil prices, taxes, development expenses, capital expenses, operating expenses and availability of funds. Any significant variance in these assumptions, and, in our case, assumptions concerning natural gas prices, could materially affect the estimated quantity of our reserves. As a result, our estimates of our proved natural gas and oil reserves are inherently imprecise. Actual future production, natural gas and oil prices, taxes, development expenses, operating expenses, availability of funds and quantities of recoverable natural gas and oil reserves may vary substantially from our estimates or estimates contained in our reserve report. Our properties also may be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, our proved reserves may be revised downward or upward based upon production history, results of future exploration and development, prevailing natural gas and oil prices, governmental regulation and other factors, many of which are beyond our control.

At September 30, 2005, approximately 30% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling operations. The reserve data assumes that we will obtain the necessary capital and conduct these operations successfully which, for the reasons discussed elsewhere in this section, may not occur.

If we cannot replace reserves, our revenues and production will decline. Our proved reserves will decline as reserves are produced unless we acquire or lease additional properties containing proved reserves, successfully develop new or existing properties or identify additional formations with primary or secondary reserve opportunities on our properties. If we are not successful in expanding our reserve base, our future natural gas and oil production and drilling activities, the primary source of our energy revenues, will decrease. Our ability to find and acquire additional reserves depends on our generating sufficient cash flow from operations and other sources of capital, principally our sponsored drilling investment partnerships, all of which are subject to the risks discussed elsewhere in this report.

If we are unable to acquire assets from others or obtain capital funds through our drilling investment partnerships, our revenues may decline. The growth of our energy operations has resulted from both our acquisition of energy companies and assets and from our ability to obtain capital funds through our sponsored drilling investment partnerships. If we are unable to identify acquisitions on acceptable terms, or cannot obtain sufficient capital funds through sponsored drilling investment partnerships, we may be unable to increase or maintain our inventory of properties and reserve base, or be forced to curtail drilling, production or other activities. This would result in a decline in our revenues.

Changes in tax laws may impair our ability to obtain capital funds through our drilling investment partnerships. Under current federal tax laws, there are tax benefits to investing in drilling investment partnerships such as those we sponsor, including deductions for intangible drilling costs and depletion deductions. Changes to federal tax law that reduce or eliminate these benefits may make investment in our drilling investment partnerships less attractive and, thus, reduce our ability to obtain funding from this significant source of capital funds. A recent change to federal tax law that may affect us is the Jobs and Growth Tax Relief Reconciliation Act of 2003, which reduced the maximum federal income tax rate on long-term capital gains and qualifying dividends to 15% through 2008. These changes may make investment in our drilling investment partnerships relatively less attractive than investments in assets likely to yield capital gains or qualifying dividends.

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Competition in the oil and natural gas industry is intense, which may hinder our ability to acquire gas and oil properties and companies and to obtain capital. We operate in a highly competitive environment for acquiring properties and other natural gas and oil companies and attracting capital through our drilling investment partnerships. For example, we have been advised by the Pennsylvania Bureau of Oil and Gas Management that there are 679 well operators currently bonded in Pennsylvania, one of our core operating areas. We also compete with the exploration and production divisions of public utility companies for natural gas and oil property acquisitions. Our competitors may be able to pay more for natural gas and oil properties and to evaluate, bid for and purchase a greater number of properties than our financial or personnel resources permit. Moreover, our competitors for investment capital may have better track records in their programs, lower costs or better connections in the securities industry segment that markets oil and gas investment programs than we do. We may not be able to compete successfully in the future in acquiring prospective reserves and raising additional capital.

We may be exposed to financial and other liabilities as the general partner in drilling investment partnerships. We currently serve as the managing general partner of 90 drilling investment partnerships and will be the general partner of new drilling investment partnerships that we sponsor. As general partner, we are contingently liable for the obligations of these partnerships to the extent that partnership assets or insurance proceeds are insufficient.

We are subject to complex laws that can affect the cost, manner or feasibility of doing business. Exploration, development, production and sale of natural gas and oil are subject to extensive federal, state and local regulation. We discuss our regulatory environment in more detail in “Business - Governmental Regulation.” We may be required to make large expenditures to comply with these regulations. Failure to comply with these regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Other regulations may limit our operations. For example, “frost laws” prohibit drilling and other heavy equipment from using certain roads during winter, a principal drilling season for us, which may delay us in drilling and completing wells. Moreover, governmental regulations could change in ways that substantially increase our costs, thereby reducing our return on invested capital, revenues and net income.

Our operations may incur substantial liabilities to comply with environmental laws and regulations. Our natural gas and oil operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities, and concentration of substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas, and impose substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, incurrence of investigatory or remedial obligations, or the imposition of injunctive relief. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance or could restrict our methods or times of operation. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or if our operations were standard in the industry at the time they were performed. We discuss the environmental laws that affect our operations in more detail in “Business—Governmental Regulation.”

Pollution and environmental risks generally are not fully insurable. We may elect to self-insure if we believe that insurance, although available, is excessively costly relative to the risks presented. The occurrence of an event that is not covered, or not fully covered, by insurance could reduce our revenues and the value of our assets.

Well blowouts, pipeline ruptures and other operating and environmental problems could result in substantial losses to us. Well blowouts, cratering, explosions, uncontrollable flows of natural gas, oil or well fluids, fires, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas and other environmental hazards and risks are inherent operating hazards for us. The occurrence of any of those hazards could result in substantial losses to us, including liabilities to third parties or governmental entities for damages resulting from the occurrence of any of those hazards and substantial investigation, litigation and remediation costs.

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We may be required to write-down the carrying value of our proved properties; any such write-downs would be a charge to our earnings. We may be required to write-down the carrying value of our natural gas and oil properties when natural gas and oil prices are low. In addition, write-downs may occur if we have:

· downward adjustments to our estimated proved reserves;

· increases in our estimates of development costs; or

· deterioration in our exploration and development results.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oil field services could delay our exploration and development plans and decrease net revenues from drilling operations. Shortages of drilling rigs, equipment, supplies or personnel could delay our development and exploration plans, thereby reducing our revenues from drilling operations and delaying our receipt of production revenues from wells we planned to drill. Moreover, increased costs, whether due to shortages or other causes, will reduce the number of wells we can drill for existing drilling investment partnerships and, by making our drilling investment partnerships less attractive as investments, may reduce the amount of financing for drilling operations we can obtain from them. This may reduce our revenues not only from drilling operations but also, if fewer wells are drilled, from production of natural gas and oil.

Hedging transactions may limit our potential gains or cause us to lose money. In order to manage our exposure to price risks in the marketing of oil and gas, we periodically enter into oil and gas price hedging arrangements, typically costless collars. While intended to reduce the effects of volatile oil and gas prices, such transactions, depending on the hedging instrument used, may limit our potential gains if oil and gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

• production is substantially less than expected:

• the counterparties to our futures contracts fail to perform under the contracts; or

• A sudden, unexpected event materially impacts gas or oil prices.

Terrorist attacks aimed at our facilities could adversely affect our business. The United States has been the target of terrorist attacks of unprecedented scale. The U.S. government has issued warnings that U.S. energy assets may be the future targets of terrorist organizations. These developments have subjected our operations to increased risks. Any future terrorist attack at our facilities, or those of our purchasers, could have a material adverse effect on our business.

ITEM 1B: UNRESOLVED STAFF COMMENTS

None

ITEM 2: PROPERTIES

Office Properties

We own a 24,000 square foot office building in Moon Township, Pennsylvania, a 17,000 square foot field office and warehouse facility in Jackson Center, Pennsylvania and an office in Deerfield, Ohio. We lease a 1,400 square foot field office in Ohio under a lease expiring in 2009 and one 4,600 square foot field office in Pennsylvania under a lease expiring in 2009. We also rent 12,100 square feet of office space in Uniontown, Ohio under a lease expiring in February 2006, 2,500 square feet in New York City, NY through July 2008 and 12,300 square feet of office space in Tulsa, Oklahoma through November 2009. In addition, we lease other field offices in Ohio and New York on a month-to-month basis.  

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Productive Wells

The following table sets forth information as of September 30, 2005 regarding productive natural gas and oil wells in which we have a working interest:

	Number of productive wells
	Gross (1)		Net (1)
Oil wells		454		322
Gas wells		5,304		2,649
Total		5,758		2,971

(1) Includes our interest in wells owned by 90 drilling investment partnerships for which we serve as general partner and various joint ventures. Does not include our royalty or overriding interests in 621 wells.

Production

The following table sets forth the quantities of our natural gas and oil production, average sales prices and average production costs per equivalent unit of production for the periods indicated.

									Average
									production
	Production				Average sales price				cost per
Period	Oil (bbls)		Gas (mcf)		per bbl		per mcf(1)		mcfe (2)
Fiscal 2005		157,904		7,625,695	$	50.91	$	7.26	$	.95
Fiscal 2004		181,021		7,285,281	$	32.85	$	5.84	$	.87
Fiscal 2003		160,048		6,966,899	$	26.91	$	4.92	$	.84

(1) Average sales price before the effects of financial hedging was $7.26, $5.84 and $5.08 for fiscal year 2005, 2004 and 2003, respectively.

(2) Production costs include labor to operate the wells and related equipment, repairs and maintenance, materials and supplies, property taxes, severance taxes, insurance, gathering charges and production overhead.

Developed and Undeveloped Acreage

The following table sets forth information about our developed and undeveloped natural gas and oil acreage as of September 30, 2005. The information in this table includes our interest in acreage owned by drilling investment partnerships sponsored by us.

	Developed acreage				Undeveloped acreage
	Gross		Net		Gross		Net
Arkansas		2,560		403		-		-
Kansas		160		20		-		-
Kentucky		924		462		9,060		4,530
Louisiana		1,819		206		-		-
Mississippi		40		3		-		-
Montana		-		-		2,650		2,650
New York		20,517		15,053		37,072		37,072
North Dakota		639		96		-		-
Ohio		114,964		95,707		38,102		34,635
Oklahoma		4,323		468		-		-
Pennsylvania		91,588		91,588		169,482		169,482
Tennessee		1,960		1,825		-		-
Texas		4,520		329		-		-
West Virginia		1,078		539		10,806		5,403
Wyoming		-		-		80		80
		245,092		206,699		267,252		253,852

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The leases for our developed acreage generally have terms that extend for the life of the wells, while the leases on our undeveloped acreage have terms that vary from less than one year to five years. We paid rentals of approximately $577,000 in fiscal 2005 to maintain our leases.

We believe that we hold good and indefeasible title to our producing properties, in accordance with standards generally accepted in the natural gas industry, subject to exceptions stated in the opinions of counsel employed by us in the various areas in which we conduct our activities. We do not believe that these exceptions detract substantially from our use of any property. As is customary in the natural gas industry, we conduct only a perfunctory title examination at the time we acquire a property. Before we commence drilling operations, we conduct an extensive title examination and we perform curative work on defects that we deem significant. We have obtained title examinations for substantially all of our managed producing properties. No single property represents a material portion of our holdings.

Our properties are subject to royalty, overriding royalty and other outstanding interests customary in the industry. Our properties are also subject to burdens such as liens incident to operating agreements, taxes, development obligations under natural gas and oil leases, farm-out arrangements and other encumbrances, easements and restrictions. We do not believe that any of these burdens will materially interfere with our use of our properties.

Drilling Activity

The following table sets forth information with respect to the number of wells in which we have completed drilling during the periods indicated, regardless of when drilling was initiated.

	Development Wells								Exploratory Wells
	Productive				Dry				Productive				Dry
Fiscal Year	Gross		Net(1)		Gross		Net(1)		Gross		Net(1)		Gross		Net(1)
2005		644.0		300.0		18.0		6.3		-		-		-		-
2004		493.0		160.5		11.0		3.8		-		-		1.0		1.0
2003		295.0		92.9		1.0		0.3		-		-		-		-

(1) Includes only our interest in the wells and not those of the other partners in our drilling investment partnerships.

Natural Gas and Oil Reserves

The following tables summarize information regarding our estimated proved natural gas and oil reserves as of the dates indicated. All of our reserves are located in the United States. We base our estimates relating to our proved natural gas and oil reserves and future net revenues of natural gas and oil reserves upon reports prepared by Wright & Company, Inc, energy consultants. In accordance with SEC guidelines, we make the standardized and PV-10 estimates of future net cash flows from proved reserves using natural gas and oil sales prices in effect as of the dates of the estimates which are held constant throughout the life of the properties. We based our estimates of proved reserves upon the following weighted average prices:

	Years ended September 30,
	2005		2004		2003
Natural gas (per mcf)	$	14.75	$	6.91	$	4.96
Oil (per bbl)	$	63.29	$	46.00	$	26.00

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Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, estimates of natural gas and oil reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production and the timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Reserve reports of other engineers might differ from the reports of our consultants, Wright & Company. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of this estimate. Future prices received from the sale of natural gas and oil may be different from those estimated by Wright & Company in preparing its reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, the reserves set forth in the following tables ultimately may not be produced and the proved undeveloped reserves may not be developed within the periods anticipated. You should not construe the estimated PV-10 values as representative of the fair market value of our proved natural gas and oil properties. PV-10 values are based upon projected cash inflows, which do not provide for changes in natural gas and oil prices or for the escalation of expenses and capital costs. The meaningfulness of these estimates depends upon the accuracy of the assumptions upon which they were based.

We evaluate natural gas reserves at constant temperature and pressure. A change in either of these factors can affect the measurement of natural gas reserves. We deduct operating costs, development costs and production-related and ad valorem taxes in arriving at the estimated future cash flows. We base the estimates on operating methods and conditions prevailing as of the dates indicated. We cannot assure you that these estimates are accurate predictions of future net cash flows from natural gas and oil reserves or their present value. For additional information concerning our natural gas and oil reserves and estimates of future net revenues, see Note 17 of our Notes to Consolidated Financial Statements.

	Proved natural gas and oil reserves at September 30,
	2005		2004		2003
Natural gas reserves (mmcf):
Proved developed reserves		104,786		95,788		87,760
Proved undeveloped reserves		53,241		46,345		45,533
Total proved reserves of natural gas		158,027		142,133		133,293
Oil reserves (mbbl):
Proved developed reserves		2,116		2,126		1,825
Proved undeveloped reserves		143		149		30
Total proved reserves of oil		2,259		2,275		1,855
Total proved reserves (mmcfe)		171,581		155,782		144,423
Standardized measure of discounted future cash flows (in thousands)	$	606,697	$	232,998	$	144,351
PV-10 estimate of cash flows of proved reserves (in thousands):
Proved developed reserves	$	617,445	$	265,516	$	164,617
Proved undeveloped reserves		228,206		54,863		26,802
Total PV-10 estimate	$	845,651	$	320,379	$	191,419

(1) Projected natural gas and oil volumes for each of fiscal 2006 and the remaining successive years are:

	Fiscal 2006		Remaining successive years		Total
Natural gas (mmcf)		9,683		148,344		158,027
Oil (mbbl)		159		2,100		2,259

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ITEM 3: LEGAL PROCEEDINGS

One of our subsidiaries, Resource Energy, Inc., together with Resource America, is a defendant in a class action originally filed in February 2000 in the New York Supreme Court, Chautauqua County, by individuals, putatively on their own behalf and on behalf of similarly situated individuals, who leased property to us. The complaint alleges that we are not paying landowners the proper amount of royalty revenues with respect to natural gas produced from the leased properties. The complaint seeks damages in an unspecified amount for the alleged difference between the amount of royalties actually paid and the amount of royalties that allegedly should have been paid. The action is currently in its discovery phase. We believe the complaint is without merit and are defending ourselves vigorously.

We are also a party to various routine legal proceedings arising out of the ordinary course of our business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of results of operations.

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

No matters were submitted to a vote of security holders during the quarter ended September 30, 2005.

PART II

ITEM 5: MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is quoted on the Nasdaq National Market under the symbol "ATLS." The following table sets forth the high and low sale prices, as reported by Nasdaq, on a quarterly basis since our initial public offering in May 2004.

	High		Low
Fiscal 2005
Fourth Quarter	$	52.72	$	36.74
Third Quarter	$	39.43	$	29.64
Second Quarter	$	43.59	$	31.60
First Quarter	$	36.79	$	21.43
Fiscal 2004
Fourth Quarter	$	21.90	$	18.08
Third Quarter (since May 11, 2004)	$	22.81	$	16.75

As of November 30, 2005, there were 13,355,641 million shares of common stock outstanding held by 324 holders of record.

Since May 11, 2004, the date of our initial public offering, we have not paid any cash dividends on our common stock. Our credit facility limits the dividends payable by us to 50% of our cumulative net income from January 1, 2004 to the date of determination plus $5.0 million and prohibits us from declaring or paying a dividend during an event of default under the facility or if the dividend would cause an event of default.

For information concerning common stock authorized for issuance under our stock incentive plan, see Note 9 of our Notes to Consolidated Financial Statements.

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ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth selected financial data as of and for the fiscal years ended September 30, 2001 through 2005. We derived the financial data as of September 30, 2005 and 2004 and for the years ended September 30, 2005, 2004 and 2003 from our financial statements, which were audited by Grant Thornton LLP, independent accountants, and are included in this report. We derived the financial data as of September 30, 2003, 2002 and 2001 and for the years ended September 30, 2002 and 2001 from our financial statements, which were audited by Grant Thornton LLP, and are not included in this report.

	Years Ended September 30,
	2005		2004		2003		2002		2001
	(in thousands, except per share data)
Income statement data:
			��
Revenues	$	474,511	$	180,088	$	105,053	$	97,626	$	93,263
Income from continuing operations		32,940		21,187		13,720		8,882		12,442
Basic net income per share from continuing operations	$	2.47	$	1.81	$	1.28	$	.83	$	1.16
Diluted net income per share from continuing operations	$	2.46	$	1.81	$	1.28	$	.83	$	1.16

	As of and for the Years Ended September 30,
	2005		2004		2003		2002		2001
	(in thousands, except operating data)
Other financial information:
Net cash provided by operating activities	$	130,118	$	57,314	$	49,174	$	5,452	$	36,190
Capital expenditures	$	99,185	$	41,162	$	28,029	$	21,291	$	14,050
EBITDA (1)	$	89,320	$	50,177	$	34,033	$	26,601	$	31,551
Balance sheet data:
Total assets	$	759,711	$	423,709	$	232,388	$	192,614	$	199,785
Long-term Debt	$	191,727	$	85,640	$	31,194	$	49,505	$	43,284
Stockholders’ equity	$	120,351	$	91,003	$	87,511	$	73,366	$	66,347

(1) We define EBITDA as earnings before interest, taxes, depreciation, depletion and amortization. EBITDA is not a measure of performance calculated in accordance with accounting principles generally accepted in the United States, or GAAP. Although not prescribed under GAAP, we believe the presentation of EBITDA is relevant and useful because it helps our investors to understand our operating performance and makes it easier to compare our results with other companies that have different financing and capital structures or tax rates. EBITDA should not be considered in isolation of, or as a substitute for, net income as an indicator of operating performance or cash flows from operating activities as a measure of liquidity. EBITDA, as we calculate it, may not be comparable to EBITDA measures reported by other companies and is different from the EBITDA calculation under our credit facility. See “Business-Credit Facilities - Our Credit Facility.” In addition, EBITDA does not represent funds available for discretionary use. The following reconciles EBITDA to our income from continuing operations for the periods indicated.

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	Years Ended September 30,
	2005		2004		2003		2002		2001
	(in thousands)
Income from continuing operations	$	32,940	$	21,187	$	13,720	$	8,882		12,442
Plus interest expense		11,467		2,881		1,961		2,200		1,714
Plus income taxes		20,018		11,409		6,757		4,683		6,613
Plus depreciation, depletion and amortization		24,895		14,700		11,595		10,836		10,782
EBITDA	$	89,320	$	50,177	$	34,033	$	26,601	$	31,551

ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview of Years Ended September 30, 2005, 2004 and 2003

During the year ended September 30, 2005, we continued to grow our operations, increasing our total assets, revenues, number of wells drilled and number of wells operated.

We finance our drilling operations principally through funds raised from investors in our public and private drilling investment partnerships. The $148.7 million raised in fiscal 2005 represented a 38% increase over the $107.7 million raised in fiscal 2004 and a 125% increase from the $66.1 million raised in fiscal 2003.

Our gross revenues depend, to a significant extent, on the price of natural gas and oil which can fluctuate significantly. We seek to balance this volatility with the more stable net income from our well drilling and well servicing operations which are principally fee-based.  Our business strategy for increasing our reserve base includes acquisitions of undeveloped properties or companies with significant amounts of undeveloped property. At September 30, 2005, we had $65.6 million available under our credit facility, which could be employed to finance such acquisitions.

Our financial condition and results of operations have been affected by initiatives taken by Atlas Pipeline Partners, L.P. (“Atlas Pipeline”). In June 2005 and in fiscal 2004, Atlas Pipeline completed public offerings of its common units, realizing $91.7 million and $92.7 million, respectively, of offering proceeds, net of expenses.  The principal financial effect of these offerings was an increase in the minority interest in our financial statements.

On April 14, 2005, Atlas Pipeline acquired all of the outstanding equity interests in Elk City for $196.0 million, including related transaction costs. The assets acquired consist of a gas processing plant in Elk City, Oklahoma, a gas treatment facility in Prentiss, Oklahoma and approximately 318 miles of natural gas gathering lines. The acquisition expanded Atlas Pipeline’s activities in the mid-continent area and provides the potential for further growth in Atlas Pipeline’s operation based in Tulsa, Oklahoma.

To finance the Elk City acquisition, Atlas Pipeline entered into a new $270 million credit facility which replaced its existing $135 million facility. The facility was comprised of a five-year $225.0 million revolving line of credit and a five-year $45.0 million term loan administered by Wachovia Bank. The term loan portion of the credit facility was repaid and retired through a portion of the net proceeds from Atlas Pipeline’s June 2005 equity offering.

In July 2004, Atlas Pipeline acquired Spectrum Field Services, Inc., which subsequently changed its name to Atlas Pipeline Mid-Continent, LLC (“Mid-Continent”), for approximately $141.6 million, including transaction costs and the payment of anticipated taxes due as a result of the transaction.  This acquisition significantly increased Atlas Pipeline's size and diversified the natural gas supply basins in which it operates and the natural gas midstream services it provides to its customers. Spectrum was a privately owned natural gas gathering and processing company headquartered in Tulsa, Oklahoma.

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Spin-off by Resource America

On June 30, 2005, Resource America, Inc. (NASDAQ: REXI), or RAI, distributed its remaining 10.7 million shares of us to its stockholders in the form of a tax-free dividend. Each stockholder of RAI received 0.59367 shares of our common stock for each share of RAI common stock owned on June 24, 2005, the record date. Although the distribution itself was tax-free to RAI’s stockholders, as a result of the deconsolidation there may be some tax liability arising from prior unrelated corporate transactions among us and some of our subsidiaries. We anticipate that all or a portion of any liability arising from this transaction may be paid by us to RAI. In addition, we were required to make a non-recurring income tax payment, payable to Resource America, of $1.2 million associated with the spin-off.

Recent Developments

Acquisition of Atlas Arkansas and Controlling Interest in NOARK.    On October 31, 2005, Atlas Pipeline 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 $165.3 million, including estimated related transaction costs, plus $10.2 million for working capital adjustments. The remaining 25% interest in NOARK is owned by Southwestern, a wholly-owned subsidiary of Southwestern Energy Company (NYSE: SWN). Before the closing of the 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 Atlas Pipeline's 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 Atlas Pipeline's other businesses and interconnections with major interstate pipelines also provides it 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 southeast Oklahoma through Arkansas and into southeast Missouri and has a throughout 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.

Atlas Pipeline financed the acquisition by borrowing under its revolving credit facility.

Atlas Pipeline Equity Offering. In November 2005, Atlas Pipeline completed a public offering of 2.7 million common units, realizing net proceeds of $110.0 million, including a $2.3 million capital contribution from us as general partner and after deducting underwriting discounts, commissions and estimated offering expenses of $5.7 million. Atlas Pipeline used the net proceeds of the offering to repay a portion of the amounts outstanding under its credit facility. Our interest in Atlas Pipeline decreased to 15.2% as a result of this offering.

Possible Public Offering of Atlas Pipeline Partners, GP.    We recently announced that we are considering transferring our ownership interest in Atlas Pipeline Partners GP to a new wholly-owned subsidiary and then making a registered initial public offering of a minority interest in the subsidiary. This report does not constitute an offer to sell or a solicitation of an offer to buy any such securities.

Results of Operations Year Ended September 30, 2005 Compared to Year Ended September 30, 2004

Well Drilling

Our well drilling revenues and costs and expenses incurred represent the billings and costs associated with the completion of wells for drilling investment partnerships we sponsor.  The following table sets forth information relating to these revenues and the related costs, gross profit margins and number of net wells drilled during the periods indicated:

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	Years Ended September 30,
	2005			2004			2003
	(dollars in thousands)
Average drilling revenue per well	$	218		$	193		$	187
Average drilling cost per well		190			168			163
Average drilling gross profit per well	$	28		$	25		$	24
Gross profit margin	$	17,522		$	11,332		$	6,897
Gross margin percent		13	%		13	%		13	%
Net wells drilled		615			450			282

Our well drilling gross margin was $17.5 million in the year ended September 30, 2005, an increase of $6.2 million (55%) from $11.3 million in the year ended September 30, 2004. During the year ended September 30, 2005, the increase in gross margin was attributable to an increase in the number of wells drilled ($4.7 million) and an increase in the gross profit per well ($1.5 million). Since our drilling contracts are on a “cost plus” basis (typically cost plus 15%), an increase in our average cost per well also results in an increase in our average revenue per well. The increase in our average cost per well resulted from an increase in the cost of tangible equipment, leases, site preparation and reclamation expenses, as well as increased costs due to drilling into deeper formations. In addition, it should be noted that "Liabilities associated with drilling contracts" on our balance sheet as of September 30, 2005 includes $49.9 million of funds raised in our drilling investment partnerships in fiscal 2005 that have not been applied to drill wells as of September 30, 2005 due to the timing of drilling operations, and thus had not been recognized as well drilling revenues. We expect to recognize this amount as income in the first half of fiscal 2006. We completed our fundraising for calendar year 2005 in November 2005 with a total of $55.0 million raised after our fiscal year end, bringing the total for the calendar year to $116.6 million, and therefore, we anticipate drilling revenues and related costs to be higher in fiscal 2006 than in fiscal 2005.

Gas and Oil Production

The following table sets forth information relating to our production revenues, production volumes, sales prices, production costs and depletion for our operations during the periods indicated:

	Years Ended September 30,
	2005			2004			2003
Production revenues (in thousands):
Gas (1)	$	55,376		$	42,532		$	34,276
Oil	$	8,039		$	5,947		$	4,307
Production volumes:
Gas (mcf/day) (1) (2)		20,892			19,905			19,087
Oil (bbls/day)		433			495			438
Total (mcfe/day)		23,490			22,875			21,715
Average sales prices:
Gas (per mmcf) (2)	$	7.26		$	5.84		$	4.92
Oil (per bbl)	$	50.91		$	32.85		$	26.91
Production costs (3):
As a percent of production revenues		13	%		15	%		18	%
Per mcfe	$	.95		$	.87		$	.84
Depletion per equivalent mcfe	$	1.42		$	1.22		$	1.01

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(1) Excludes sales of residual gas and sales to landowners.

(2) Our average sales price before the effects of financial hedging was $7.26, $5.84 and $5.08 for fiscal year 2005, 2004 and 2003, respectively.

(3) Production costs include labor to operate the wells and related equipment, repairs and maintenance, materials and supplies, property taxes, severance taxes, insurance, gathering charges and production overhead.

Our natural gas revenues were $55.4 million in fiscal 2005, an increase of $12.9 million (30%) from $42.5 million in fiscal 2004. The increase was due to a 24% increase in the average sales price of natural gas and a 5% increase in production volumes. The $12.9 million increase in natural gas revenues consisted of $10.4 million attributable to price increases and $2.5 million attributable to volume increases.

Our oil revenues were $8.0 million in fiscal 2005, an increase of $2.1 million (35%) from $5.9 million in fiscal 2004. The increase resulted from a 55% increase in the average sales price of oil, partially offset by a 13% decrease in production volumes. The $2.1 million increase in oil revenues consisted of $3.3 million attributable to price increases, partially offset by $1.2 million attributable to volume decreases, as we drill primarily for natural gas rather than oil.

Our production costs were $8.2 million in fiscal 2005, an increase of $900,000 (12%) from $7.3 million in fiscal 2004. This increase includes normal operating expenses and coincides with the increased production volumes we realized from the increased number of wells we operate. In addition, there were increases in transportation expense as a result of increased natural gas prices as a portion of our wells are charged transportation based on the sales price of the gas transported. Production costs as a percent of sales decreased from 15% in fiscal 2004 to 13% in fiscal 2005 as a result of an increase in our average sales price which more than offset the increase in production costs per mcfe.

Our exploration costs were $900,000 in the year ended September 30, 2005, a decrease of $600,000 (42%) from $1.5 million in fiscal 2004. The decrease was primarily due to the dry hole costs of $704,000 incurred in 2004 upon determination that a well drilled in an exploratory area of our operations was not capable of economic production. No dry hole costs have been incurred in 2005.

Gathering, Transmission and Processing

Our gathering, transmission and processing revenues were $266.8 million, an increase of $230.6 million over fiscal 2004. The increase was primarily attributable to contributions from Elk City, acquired in April 2005, and a full year of revenues from Spectrum, acquired in July 2004.

Our gathering, transmission and processing expenses were $229.8 million, an increase of $202 million over fiscal 2005. The increase was primarily attributable to costs associated with the operations of Elk City acquired in April 2005, and a full year of expense associated with the operations of Spectrum acquired in July 2004.

Well Services

Our well services revenues were $9.6 million in fiscal 2005, an increase of $1.2 million (13%) from $8.4 million in fiscal 2004. The increase resulted from an increase in the number of wells operated for our investment partnerships due to additional wells drilled in fiscal 2005.

Our well services expenses were $5.2 million in fiscal 2005, an increase of $800,000 (17%) from $4.4 million in fiscal 2004. The increase resulted from an increase in wages, benefits, and field office expenses associated with an increase in employees due to the increase in number of wells operated for our investment partnerships in fiscal 2005 as compared to fiscal 2004.

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Other Income, Costs and Expenses

Our general and administrative expenses were $13.5 million in fiscal 2005, an increase of $8.5 million (168%) from $5.0 million in fiscal 2004. These expenses include, among other things, salaries and benefits not allocated to a specific energy activity, costs of running our energy corporate office, partnership syndication activities and outside services. These expenses are partially offset by reimbursements we receive from our drilling investment partnerships. The increase in the year ended September 30, 2005 as compared to the prior year period is attributable principally to the following:

· general and administrative expenses related to Atlas Pipeline’s Mid-Continent operations were $3.8 million, an increase of $3.3 million primarily attributable to costs associated with operations of Elk City acquired in April 2005, and a full year of expense associated with operations of Spectrum acquired in July 2004;

· costs associated with Atlas Pipeline’s long term incentive plan were $3.2 million, an increase of $2.9 million over fiscal 2004;

· salaries and wages increased $3.0 million due to an increase in executive salaries and in the number of employees as a result of our spin-off from our parent; and

· professional fees and insurance increased $1.7 million, which includes the implementation of Sarbanes-Oxley Section 404 compliance.

These increases were partially offset by $3.1 million of increased credits received for costs incurred in organizing and offering our partnership investments as we continue to increase the number of wells we drill and manage.

Our compensation reimbursements-affiliates were $602,000, a decrease of $448,000 over fiscal 2004. This resulted from a reduction in allocations from our former parent for executive management and administrative services as we now directly employ many of the individuals, a portion of whose compensation was previously being allocated to us and therefore includes their compensation in our general and administrative expenses.

Depletion of oil and gas properties as a percentage of oil and gas revenues was 19% in fiscal 2005 compared to 21% in fiscal 2004. Depletion was $1.42 per mcfe in fiscal 2005, an increase of $.20 per mcfe (16%) from $1.22 per mcfe in fiscal 2004. Increase in our depletable basis and production volumes caused depletion expense to increase $2.0 million to $12.2 million in fiscal 2005 compared to $10.2 million in fiscal 2004. The variances from period to period are directly attributable to changes in our oil and gas reserve quantities, product prices and changes in the depletable cost basis of our oil and gas properties.

Depreciation and amortization increased $8.2 million, to $12.7 million in fiscal 2005 compared to $4.5 million in fiscal 2004. This was primarily due to the increased asset base associated with the Atlas Pipeline Mid-Continent acquisitions.

Our interest expense was $11.5 million in fiscal 2005, an increase of $8.6 million from $2.9 million in fiscal 2004. This increase resulted primarily from an increase in outstanding borrowings by Atlas Pipeline to fund the acquisitions of Spectrum and Elk City, as well as $1.0 million of accelerated amortization of deferred financing costs associated with the retirement of the term portion of the Atlas Pipeline credit facility in April 2005.

On December 30, 2004, Atlas Pipeline entered into a settlement agreement with SEMCO Energy, Inc. settling all issues and matters related to SEMCO’s termination of the sale of Alaska Pipeline Company to Atlas Pipeline. SEMCO paid Atlas Pipeline $5.5 million, which is included in arbitration settlement-net on our statements of income. In connection with the acquisition, subsequent termination, and settlement of the legal action, Atlas Pipeline incurred costs of approximately $1.2 million in fiscal 2005, which are also included in arbitration settlement-net on our statements of income. Atlas Pipeline also incurred $3.0 million of costs in our year ended September 30, 2004.

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At September 30, 2005, we owned 18.9% of the partnership interest in Atlas Pipeline through our general partner interest and limited partner units. The limited partner units were subordinated until January 1, 2005, when the subordination term expired and they converted to common units in accordance with the terms of the partnership agreement. Our ownership interest has decreased 32% from 51% as a result of the completion by Atlas Pipeline of common unit offerings in May 2003, April and July 2004, and June 2005.

Because we control the operations of Atlas Pipeline, we include it in our consolidated financial statements and show the ownership by the public as a minority interest. The minority interest in Atlas Pipeline’s earnings was $14.8 million for fiscal 2005 and $5.0 million for fiscal 2004, an increase of $9.8 million for the year. These increases are a result of an increase in the percentage interest of public unit holders and an increase in Atlas Pipeline’s net income.

Our effective tax rate increased to 37.8% for the year ended September 30, 2005 as compared to 35% for the year ended September 30, 2004 as a result of a $1.2 million income tax charge related to our spin-off from Resource America.

Results of Operations Year Ended September 30, 2004 Compared to Year Ended September 30, 2003

Well Drilling

Our well drilling gross margin was $11.3 million in the year ended September 30, 2004, an increase of $4.4 million (64%) from $6.9 million in the year ended September 30, 2003. During the year ended September 30, 2004, the increase in gross margin was attributable to an increase in the number of wells drilled ($4.2 million) and an increase in the gross profit per well ($204,000). Since our drilling contracts are on a “cost plus” basis (typically cost plus 15%), an increase in our average cost per well also results in an increase in our average revenue per well. The increase in our average cost per well resulted from an increase in the cost of tangible equipment, leases and reclamation expenses. In addition, it should be noted that "Liabilities associated with drilling contracts" on our balance sheet includes $26.5 million of funds raised in our drilling investment partnerships in the fourth quarter of fiscal 2004 that have not been applied to drill wells as of September 30, 2004 due to the timing of drilling operations, and thus had not been recognized as well drilling revenues. We recognized this amount as income in fiscal 2005.

Gas and Oil Production

Our natural gas revenues were $42.5 million in fiscal 2004, an increase of $8.3 million (24%) from $34.2 million in fiscal 2003. The increase was due to a 19% increase in the average sales price of natural gas and a 4% increase in production volumes. The $8.3 million increase in natural gas revenues consisted of $6.4 million attributable to price increases and $1.9 million attributable to volume increases.

Our oil revenues were $5.9 million in fiscal 2005, an increase of $1.6 million (38%) from $4.3 million in fiscal 2003. The increase resulted from a 22% increase in the average sales price of oil and a 13% increase in production volumes. The $1.6 million increase in oil revenues consisted of $951,000 attributable to price increases and $689,000 attributable to volume increases.

Our production costs were $7.3 million in fiscal 2004, an increase of $519,000 (8%) from $6.8 million in fiscal 2003. This increase includes normal operating expenses and coincides with the increased production volumes we realized from the increased number of wells we operate. Production costs as a percent of sales decreased from 18% in fiscal 2003 to 15% in fiscal 2004 as a result of an increase in our average sales price which more than offset the slight increase in production costs per mcfe.

Our exploration costs were $1.5 million in the year ended September 30, 2004, a decrease of $166,000 (10%) from fiscal 2003. We attribute the decrease in fiscal 2004 as compared to the prior period is principally due to the following:

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· the benefit we received for our contribution of well sites to our drilling investment partnerships increased $813,000 in fiscal 2004 as compared to fiscal 2003 as a result of more wells drilled; which was offset in part by;

· $704,000 in dry hole costs we incurred upon making the determination that a well drilled in an exploratory area of our operations was not capable of economic production.

Gathering, Transmission and Processing

Our gathering, transmission and processing revenues were $36.3 million, of which $30.0 million was associated with the operations of Spectrum which was acquired on July 16, 2004. These revenues reflect two and one half months of operations in fiscal 2004.

Our gathering, transmission and processing expenses were $27.9 million, of which $25.5 million was associated with the operations of Spectrum which was acquired on July 16, 2004. These costs reflect two and one half months of operations in fiscal 2004.

Well Services

Our well services revenues were $8.4 million in fiscal 2004, an increase of $796,000 (10%) from $7.6 million in fiscal 2003. The increase resulted from an increase in the number of wells operated due to additional wells drilled in fiscal 2004.

Our well services expenses were $4.4 million in fiscal 2004, an increase of $625,000 (17%) from $3.8 million in fiscal 2003. The increase resulted from an increase in costs associated with a greater number of wells operated in fiscal 2004 as compared to fiscal 2003.

Other Income, Costs and Expenses

Our general and administrative expenses and compensation reimbursement - affiliate were $6.1 million in the aggregate in fiscal 2004, a decrease of $456,000 (7%) from $6.5 million in fiscal 2003. These expenses include, among other things, salaries and benefits not allocated to a specific energy activity, costs of running our energy corporate office, partnership syndication activities and outside services. These expenses are partially offset by reimbursements we receive from our drilling investment partnerships. The decrease in the year ended September 30, 2004 as compared to the prior year period is attributable principally to the following:

· general and administrative expense reimbursements from our investment partnerships increased by $4.8 million as we continue to increase the number of wells we drill and manage;

· salaries and wages increased $1.6 million due to an increase in executive salaries and in the number of employees in anticipation of our spin-off from our parent;

· net syndication costs increased $930,000 as we continue to increase our syndication activities and the drilling funds we raise in our public and private partnerships;

· legal and professional fees increased $925,000, which includes the implementation of Sarbanes-Oxley Section 404 compliance and the filing of two tax returns for 2003 for Atlas Pipeline. Two tax returns were required as a result of our ownership percentage in it falling below 50% due to its offering of common units in May 2003;

· general and administrative expenses increased $484,000 due to the acquisition of Spectrum on July 16, 2004; and

· director’s fees increased $251,000 due to our initial public offering and our anticipated spin-off from Resource America.

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Depletion of oil and gas properties as a percentage of oil and gas revenues was 21% in both fiscal 2004 and fiscal 2003. Depletion was $1.22 per mcfe in fiscal 2004, an increase of $.21 per mcfe (21%) from $1.01 per mcfe in fiscal 2003. Higher volumes produced on our new wells in their first year of production caused depletion per mcfe to increase in fiscal 2004 as compared to fiscal 2003. The variances from period to period are directly attributable to changes in our oil and gas reserve quantities, product prices and changes in the depletable cost basis of our oil and gas properties.

Discontinued Operation

In accordance with SFAS 144, “Accounting for the Impairment or Disposal of Long Lived Assets,” our decision in fiscal 2002 to dispose of Optiron Corporation, our former energy technology subsidiary, resulted in the presentation of Optiron as a discontinued operation for the years ended September 30, 2004 and 2003. We had held a 50% equity interest in Optiron; as a result of the disposition, we currently hold a 10% equity interest.

The plan of disposal required Optiron to pay us 10% of its revenues if they exceeded $2.0 million in the 12-month period following the closing of the transaction. As a result, in fiscal 2003 Optiron became obligated to pay us $295,000. The payment was made in March 2004.

Liquidity and Capital Resources

General. We fund our exploration and production operations from a combination of cash generated by operations, capital raised through drilling investment partnerships and, if required, use of our credit facility. We fund our gathering, transmission and processing operations, which are conducted through Atlas Pipeline, through a combination of cash generated by operations, Atlas Pipeline’s credit facility and the sales of Atlas Pipeline’s common units. The following table sets forth our sources and uses of cash for the periods indicated:

	Years Ended September 30,
	2005			2004			2003
	(in thousands)
Provided by operations	$	130,118		$	57,314		$	49,174
Used in investing activities		(294,891	)		(182,084	)		(28,475	)
Provided by (used in) financing activities		153,862			128,295			(4,249	)
Provided by discontinued operation		-			295			−
Increase (decrease) in cash and cash equivalents	$	(10,911	)	$	3,820		$	16,450

We had $18.3 million in cash and cash equivalents on hand at September 30, 2005, as compared to $29.2 million at September 30, 2004. Our ratio of earnings from continuing operations before income taxes, minority interest and interest expense to fixed charges was 7.0 to 1.0 in fiscal 2005 as compared to 14.0 to 1.0 in fiscal 2004. We had working capital deficits of $76.8 million and $19.3 million at September 30, 2005 and September 30, 2004, respectively. The decrease in our working capital reflects an increase in our current assets of $46.4 million, offset by an increase in our current liabilities of $103.9 million. The increase in our current assets is primarily due to an increase in accounts receivable ($29.9 million) and the current portion of hedge receivable ($15.0 million) both of which are associated with Atlas Pipeline’s Mid-Continent operations. The increase in our current liabilities is primarily due to the following:

· an increase in accrued expenses of $67.2 million associated with natural gas and liquids, ad valorem taxes and hedging liabilities associated with Atlas Pipeline’s Mid-Continent operations and its Elk City acquisition;

· an increase of $31.6 million in the remaining amount of our drilling obligations due to an increase in our funding raising associated with our drilling investment partnerships;

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· an increase of $10.1 million in our trade accounts payable related to an increase in drilling activity associated with our investment partnerships; and

· a decrease of $3.3 million in current maturities of long-term debt related to Atlas Pipeline’s borrowings under its credit facility.

Our long-term debt (including current maturities) was 159% of our total capital at September 30, 2005 and 94% at September 30, 2004. This increase is attributable to $183.6 million in borrowings associated with Atlas Pipeline’s acquisitions of Spectrum and Elk City. Stockholders’ equity increased principally due to net earnings of $32.9 million for the year ended September 30, 2005.

In September 2004, the borrowing base under our credit facility was increased to $75.0 million from $65.0 million. At September 30, 2005, we had $65.6 million available on our credit facility. See Note 7 to our Consolidated Financial Statements for information on Atlas Pipeline’s new credit facility which closed April 14, 2005. After borrowing on Atlas Pipeline’s new $270 million credit facility on April 14, 2005, it had $183.6 million outstanding at a weighted average interest rate of 6.6% and $33.8 million available at September 30, 2005.

Cash flows from operating activities.Cash provided by operations is an important source of short-term liquidity for us. It is directly affected by changes in the price of natural gas and oil, interest rates and our ability to raise funds from our drilling investment partnerships. Netcash provided by operating activities increased $72.8 million in fiscal 2005 to $130.1 million from $57.3 million in fiscal 2004, substantially as a result of the following:

· changes in operating assets and liabilities increased operating cash flow by $40.9 million in fiscal 2005, compared to fiscal 2004, primarily due to increases in accounts payable and accrued liabilities. Our level of liabilities is dependent upon the remaining amount of our drilling obligations at any balance sheet date, which is dependent upon the timing of funds raised through our drilling investment partnerships;

· an increase in net income before depreciation, depletion and amortization of $23.7 million in fiscal 2005 as compared to the prior fiscal year principally a result of higher natural gas prices and drilling profits;

· an increase in minority interest of $9.8 million due to an increase in Atlas Pipeline’s earnings and common units outstanding; and

· a decrease in non-cash items included in net income which were added back to cash flows and totaled $2.4 million. These include $3.0 million of terminated acquisition costs, $2.5 million of gains on derivative value, less $3.0 million of compensation on LTIP awards.

Cash flows from investing activities.Net cash used in our investing activities increased $112.8 million in fiscal 2005 to $294.9 million from $182.1 million in fiscal 2004 as a result of the following:

· cash used for business acquisitions increased $53.7 million; and

· capital expenditures increased $58.0 million due to an increase in the number of wells we drilled, as well as an expansion of the Atlas Mid-Continent gathering systems and processing facilities.

Cash flows from financing activities. Net cash provided by our financing activities increased $25.6 million in fiscal 2005 to $153.9 million from $128.3 million in fiscal 2004, as a result of the following:

· payments to RAI in the form of repayments of advances and dividends decreased by $22.0 million, principally as a result of a one-time special dividend paid in fiscal 2004 as part of the transactions leading to our spin-off from RAI; and

· net borrowings increased cash flows by $51.9 million in fiscal 2005 as compared to the prior fiscal year principally as a result of borrowings associated with the acquisition of Elk City.

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These increases were partially offset by the following:

· dividends paid to minority interests increased $10.8 million as a result of higher earnings and more common units outstanding for Atlas Pipeline as a result of its fiscal 2005 and 2004 offerings of common units; and

· we received proceeds of $37.0 million in fiscal 2004 from public offerings of our common stock; there were no offerings in fiscal 2005.

Capital requirements. During fiscal 2005 and 2004, our capital expenditures related primarily to acquisitions, investments in our drilling investment partnerships and pipeline expansions, in which we invested $196.0 million, $57.9 million and $40.1 million, respectively. During fiscal 2005, we funded capital expenditures through cash on hand, borrowings under our credit facilities, and from operations. We have established two credit facilities to facilitate the funding of our capital expenditures.

The level of capital expenditures we must devote to our exploration and production operations depends upon the level of funds raised through our drilling investment partnerships. We have budgeted to raise up to $200.0 million in fiscal 2006 through drilling partnerships. During fiscal 2005 we raised $148.7 million. We believe cash flow from operations and amounts available under our credit facility will be adequate to fund our contributions to these partnerships. However, the amount of funds we raise and the level of our capital expenditures will vary in the future depending on market conditions for natural gas and other factors.

We continuously evaluate acquisitions of gas and oil and pipeline assets. In order to make any acquisition, we believe we will be required to access outside capital either through debt or equity placements or through joint venture operations with other energy companies. There can be no assurance that we will be successful in our efforts to obtain outside capital.

Changes in Prices and Inflation

Our revenues, the value of our assets, our ability to obtain bank loans or additional capital on attractive terms and our ability to finance our drilling activities through drilling investment partnerships have been and will continue to be affected by changes in oil and gas prices. Natural gas and oil prices are subject to significant fluctuations that are beyond our ability to control or predict. During fiscal 2005, we received an average of $7.26 per mcf of natural gas and $50.91 per bbl of oil as compared to $5.84 per mcf and $32.85 per bbl in fiscal 2004 and $4.92 per mcf and $26.91 per bbl in fiscal 2003.

Although certain of our costs and expenses are affected by general inflation, inflation has not normally had a significant effect on us. However, inflationary trends may occur if the price of natural gas were to increase since such an increase may increase the demand for acreage and for energy equipment and services, thereby increasing the costs of acquiring or obtaining such equipment and services.

Environmental Regulation

To date, compliance with environmental laws and regulations has not had a material impact on our capital expenditures, earnings or competitive position. We cannot assure you that compliance with environmental laws and regulations will not, in the future, materially adversely affect our operations through increased costs of doing business or restrictions on the manner in which we conduct our operations.

Dividends

There were no dividends paid in the year ended September 30, 2005. In the year ended September 30, 2004 we paid dividends of $52.1 million to our former parent. The determination of the amount of future cash dividends, if any, is at the sole discretion of our board of directors and will depend on the various factors affecting our financial condition and other matters the board of directors deems relevant.

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Contractual Obligations and Commercial Commitments

The following table summarizes our contractual obligations at September 30, 2005.

			Payments Due By Period (in thousands)
Contractual cash obligations:	Total		Less than 1 Year		1 - 3 Years		4 - 5 Years		After 5 Years
Long-term debt	$	191,727	$	122	$	8,105	$	183,500	$	-
Secured revolving credit facilities		-		-		-		-		-
Operating lease obligations		4,081		2,148		1,581		350		2
Capital lease obligations		-		-		-		-		-
Unconditional purchase obligations		-		-		-		-		-
Other long-term obligations		-		-		-		-		-
Total contractual cash obligations	$	195,808	$	2,270	$	9,686	$	183,850	$	2

Not included in the table above are estimated interest payments calculated at the rates in effect at September 30, 2005: 2006 - $12.8 million; 2007 - $12.5 million; 2008 - $12.3 million; 2009 - $12.3 million and 2010 - $6.6 million.

			Payments Due By Period (in thousands)
Other commercial commitments:	Total		Less than 1 Year		1 - 3 Years		4 - 5 Years		After 5 Years
Standby letters of credit	$	9,137	$	9,112	$	25	$	-	$	-
Guarantees		-		-		-		-		-
Standby replacement commitments		-		-		-		-		-
Other commercial commitments		36,642		36,642		-		-		-
Total commercial commitments	$	45,779	$	45,754	$	25	$	−	$	-

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of our assets, liabilities, revenues and cost and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, we evaluate our estimates, including those related to the provision for possible losses, deferred tax assets and liabilities, goodwill and identifiable intangible assets, and certain accrued liabilities. We base our estimates on historical experience and on various other assumptions that we believe reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.

We have identified the following policies as critical to our business operations and the understanding of our results of operations.

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Accounts Receivable and Allowance for Possible Losses.

Through our business segments, we engage in credit extension, monitoring, and collection. In evaluating our allowance for possible losses, 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 our customer’s credit information. We extend credit on an unsecured basis to many of our energy customers. At September 30, 2005, our credit evaluation indicated that we have no need for an allowance for possible losses for our oil and gas receivables.

We believe that our allowance for possible losses is reasonable based on our experience and our analysis of the net realizable value of our receivables at September 30, 2005.

Reserve Estimates

Our estimates of our proved natural gas and oil reserves and future net revenues from them are based upon reserve analyses that rely upon various assumptions, including those required by the SEC, as to natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Any significant variance in these assumptions could materially affect the estimated quantity of our reserves. As a result, our estimates of our proved natural gas and oil reserves are inherently imprecise. Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves may vary substantially from our estimates or estimates contained in the reserve reports and may affect our ability to pay amounts due under our credit facilities or cause a reduction in our energy credit facilities. In addition, our proved reserves may be subject to downward or upward revision based upon production history, results of future exploration and development, prevailing natural gas and oil prices, mechanical difficulties, governmental regulation and other factors, many of which are beyond our control.

Impairment of Oil and Gas Properties

We review our producing oil and gas properties for impairment on an annual basis and whenever events and circumstances indicate a decline in the recoverability of their carrying values. We estimate the expected future cash flows from our oil and gas properties and compare such future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to their fair value in the current period. The factors used to determine fair value include, but are not limited to, estimates of reserves, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected. Because of the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that will require us to record an impairment of our oil and gas properties. Any such impairment may affect or cause a reduction in our credit facilities.

Dismantlement, Restoration, Reclamation and Abandonment Costs

On an annual basis, we estimate the costs of future dismantlement, restoration, reclamation and abandonment of our natural gas and oil-producing properties. We also estimate the salvage value of equipment recoverable upon abandonment. On October 1, 2002 we adopted SFAS 143, as discussed in Note 2 to our consolidated financial statements. As of September 30, 2005, 2004 and 2003, our estimate of salvage values was greater than or equal to our estimate of the costs of future dismantlement, restoration, reclamation and abandonment. A decrease in salvage values or an increase in dismantlement, restoration, reclamation and abandonment costs from those we have estimated, or changes in our estimates or costs, could reduce our gross profit from operations.

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Goodwill and Other Long-Lived Assets

Goodwill and other intangibles with an indefinite useful life are no longer amortized, but instead are assessed for impairment annually. We have recorded goodwill of $115.4 million in connection with several acquisitions of assets. In assessing impairment of goodwill, we use estimates and assumptions in estimating the fair value of reporting units. If under these estimates and assumptions we determine that the fair value of a reporting unit has been reduced, the reduction can result in an “impairment” of goodwill. However, future results could differ from the estimates and assumptions we use. Events or circumstances which might lead to an indication of impairment of goodwill would include, but might not be limited to, prolonged decreases in expectations of long-term well servicing and/or drilling activity or rates brought about by prolonged decreases in natural gas or oil prices, changes in government regulation of the natural gas and oil industry or other events which could affect the level of activity of exploration and production companies.

In assessing impairment of long-lived assets other than goodwill, where there has been a change in circumstances indicating that the carrying amount of a long-lived asset may not be recoverable, we have estimated future undiscounted net cash flows from the use of the asset based on actual historical results and expectations about future economic circumstances, including natural gas and oil prices and operating costs. Our estimate of future net cash flows from the use of an asset could change if actual prices and costs differ due to industry conditions or other factors affecting our performance.

Revenue Recognition

We conduct certain activities through, and a portion of our revenues are attributable to, sponsored energy limited partnerships. These energy partnerships raise capital from investors to drill gas and oil wells. We serve as general partner of the energy partnerships and assume customary rights and obligations for them. As the general partner, we are liable for partnership liabilities and can be liable to limited partners if we breach our responsibilities with respect to the operations of the partnerships. The income from our general partner interest is recorded when the gas and oil are sold by a partnership.

We contract with the energy partnerships to drill partnership wells. The contracts require that the energy partnerships must pay us the full contract price upon execution. The income from a drilling contract is recognized as the services are performed using the percentage of completion method. The contracts are typically completed in less than 60 days. We classify the difference between the contract payments we have received and the revenue earned as a current liability, included in liabilities associated with drilling contracts.

We recognize gathering, transmission and processing revenues at the time the natural gas is delivered to the purchaser.

 

We recognize well services revenues at the time the services are performed.

We are entitled to receive management fees according to the respective partnership agreements. We recognize such fees as income when earned and include them in well services revenues.

We record the income from the working interests and overriding royalties of wells we own an interest in when the gas and oil are delivered.

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Income Taxes

As part of the process of preparing consolidated financial statements, we are required to estimate income taxes in each of the jurisdictions in which we operate. Significant judgment is required in determining the income tax expense provision. We recognize deferred tax assets and liabilities based on differences between the financial reporting and tax bases of assets and liabilities using the enacted tax rates and laws that are expected to be in effect when the differences are expected to be recovered. We assess the likelihood of our deferred tax assets being recovered from future taxable income. We then provide a valuation allowance for deferred tax assets for which we do not consider realization of such assets to be more likely than not. We consider future taxable income and ongoing prudent and feasible tax planning strategies in assessing the valuation allowance. Any decrease in the valuation allowance could have a material impact on net income in the period in which such determination is made.

Recently Issued Financial Accounting Standards

In May 2005, the Financial Accounting Standards Board, or FASB, issued SFAS No. 154, “Accounting Changes and Error Corrections”, or SFAS 154. SFAS 154 requires retrospective application to prior periods’ financial statements of 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 154 will depend on the nature and extent of any voluntary accounting changes and correction of errors after the effective date, but management does not currently expect SFAS 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” or 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 cost 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 Statement 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. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. Retrospective application of interim financial information is permitted but is not required. Early adoption of this interpretation is encouraged. We do not believe the interpretation will have a significant impact on our financial position or results of operations.

In December 2004, the FASB issued SFAS No. 123 (R) (revised 2004) “Share-Based Payment”, which is a revision of SFAS No. 123, “Accounting for Stock-Based Compensation”.  Statement 123 (R) supersedes Accounting Principal Board, or APB Opinion No. 25, “Accounting for Stock Issued to Employees”, and amends SFAS No. 95, “Statement of Cash Flows”. Generally, the approach to accounting in SFAS 123 (R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values. Currently we account for these payments under the intrinsic value provisions of APB No. 25 with no expense recognition in the financial statements.  SFAS 123 (R) is effective for us beginning October 1, 2005. The Statement offers several alternatives for implementation. At this time, we have not made a decision as to the alternative we may select.

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In December 2004, the FASB issued FASB Staff Position No. FAS 109-1, or FAS 109-1, “Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004”, or AJCA. The AJCA introduces a special tax deduction on qualified production activities. FSP 109-1 concludes that this deduction should be accounted for as a special tax deduction in accordance with SFAS No. 109. As such, the special deduction has no effect on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this deduction will be reported in the same period in which the deduction is claimed in our tax return. FAS 109-1 is not expected to have a material impact on our financial position or results of operations.

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

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 such as forward contracts and interest rate cap and swap agreements.

The following analysis presents the effect on our earnings, cash flows and financial position as if hypothetical changes in market risk factors occurred on September 30, 2005. Only the potential impacts of hypothetical assumptions are analyzed. The analysis does not consider other possible effects that could impact our business.

Interest Rate Risk. At September 30, 2005, the amount outstanding under our credit facility had decreased to $8.0 million from $25.0 million at September 30, 2004. The weighted average interest rate for this facility increased from 4.1% at September 30, 2004 to 6.1% at September 30, 2005 due to an increase in market index rates on these borrowings. Holding all other variables constant, a hypothetical 10% change in the weighted average interest rate would change our net income by approximately $31,000.

At September 30, 2005, Atlas Pipeline had a $225 million revolving credit facility ($183.5 million outstanding). The weighted average interest rate for borrowings under this credit facility was 6.6% at September 30, 2005. Holding all other variables constant, a hypothetical 10% change in the weighted average interest rate would change our net income by approximately $147,000.

Commodity Price Risk. Our major market risk exposure in commodities is fluctuations in the pricing of our gas and oil production. Realized pricing is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas production. Pricing for gas and oil production has been volatile and unpredictable for many years. To limit our exposure to changing natural gas prices, we use financial hedges for a portion of our projected natural gas production. Through our hedges, we seek to provide a measure of stability in the volatile environment of natural gas prices. We do not hold or issue derivative instruments for trading purposes. We recognize gains and losses from the settlement of these hedges in gas revenues when the associated production occurs. The gains and losses realized as a result of hedging are substantially offset in the market when we deliver the associated natural gas. We determine gains or losses on open and closed hedging transactions as the difference between the contract price and a reference price, generally closing prices on NYMEX. We did not recognize any gains or losses on any contracts during the years ended September 30, 2005 and 2004 related to hedging of our natural gas production. We recognized losses of $1.1 million on settled contracts during the year ended September 30, 2003. We had no open hedge transactions related to our natural gas production in place as of September 30, 2005.

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Amereda Hess and other third-party marketers to which we sell gas also use financial hedges to hedge their pricing exposure and make price hedging opportunities available to us. These transactions are similar to NYMEX-based futures contracts, swaps and options, but also require firm delivery of the hedged quantity. Thus, we limit these arrangements to much smaller quantities than those projected to be available at any delivery point. We expect to fulfill all these arrangements with no adverse consequences to us. For the fiscal year ending September 30, 2006, we estimate approximately 66% of our produced natural gas volumes will be sold in this manner, leaving our remaining production to be sold at contract prices in the month produced or at spot market prices. We also negotiate with some purchasers for delivery of a portion of the natural gas we will produce for the upcoming twelve months. The prices under most of our gas sales contracts are negotiated on an annual basis and are index-based. Considering those volumes already designated for the fiscal year ending September 30, 2006, and current indices, a theoretical 10% upward or downward change in the price of natural gas would result in a change in net income of approximately $2.8 million.

The Mid-Continent operations of Atlas Pipeline entered into several swaps that were designed to hedge NGL prices during the year ended September 30, 2005 that did not meet specific hedge accounting criteria. Mid-Continent recognized a loss of $64,000 related to these instruments during year ended September 30, 2005.

Through Atlas Pipeline’s Mid-Continent operations, 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 for 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% upward or downward change in the average price of NGLs, natural gas and crude oil we process and sell would result in a change in income of approximately $2.1 million.

Mid-Continent enters into certain financial swap and option instruments that are classified as cash flow hedges in accordance with SFAS No. 133. Mid-Continent enters into these instruments to hedge a change in 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, Mid-Continent receives a fixed price and pays 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 we determine 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 fair value for the derivative will be recognized immediately within our consolidated statements of income.

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Atlas Pipeline records derivatives on the balance sheet as assets or liabilities at fair value. For derivatives qualifying as hedges, it recognizes the effective portion of changes in fair value in partners’ capital as accumulated other comprehensive income (loss) and reclassify them to earnings as such 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 September 30, 2005 and 2004, Atlas Pipeline reflected net hedging liabilities on its balance sheets of $46.7 million and $6.0 million, respectively. Of the $5.6 million net loss in accumulated other comprehensive income (loss) at September 30, 2005, we will reclassify $2.7 million of losses to our consolidated statements of income over the next twelve month period as these contracts expire, and $2.9 million will be reclassified in later periods if the fair values of the instruments remain at current market values. Actual amounts that will be reclassified will vary as a result of future price changes. Ineffective hedge gains or losses are recorded within our consolidated statements of income while the hedge contract is open and may increase or decrease until settlement of the contract. Atlas Pipeline recognized losses of $5.0 million and $27,000 for the fiscal year ended September 30, 2005 and 2004, respectively, within its consolidated statements of income related to the settlement of qualifying hedge instruments. Atlas Pipeline also recognized losses of $64,000 and $697,000 for the fiscal year ended September 30, 2005 and 2004, respectively, within its consolidated statements of income related to the change in market value of non-qualifying or ineffective hedges.

A portion of Atlas Pipeline’s 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 September 30, 2005, Atlas Pipeline had the following NGLs, natural gas, and crude oil volumes hedged:

Natural Gas Fixed-Price Swaps

Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability(2)
Ended September 30,	(gallons)		(per gallon)		(in thousands)
2006		38,586,000	$	0.673	$	(16,742	)
2007		38,115,000		0.711		(12,188	)
2008		34,587,000		0.702		(9,037	)
2009		7,434,000		0.697		(1,781	)
					$	(39,748	)

Natural Gas Fixed-Price Swaps

Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability(3)
Ended September 30,	(MMBTU)(1)		(per MMBTU)		(in thousands)
2006		3,923,000	$	7.169	$	(5,767	)
2007		1,560,000		7.210		(1,658	)
2008		510,000		7.262		(1,037	)
					$	(8,462	)

43

Natural Gas Basis Swaps

Production			Average			Fair Value
Period	Volumes		Fixed Price			Asset(3)
Ended September 30,	(MMBTU)(1)		(per MMBTU)			(in thousands)
2006		4,262,000	$	(0.517	)	$	1,376
2007		1,560,000		(0.522	)		1,584
2008		510,000		(0.544	)		1,383
						$	4,343

Crude Oil Fixed - Price Swaps

Production			Average		Fair Value
Period	Volumes		Fixed Price		Liability(3)
Ended September 30,	(barrels)		(per barrel)		(in thousands)
2006		67,800	$	51.329	$	(1,056	)
2007		80,400		55.187		(844	)
2008		82,500		58.475		(414	)
					$	(2,314	)

Crude Oil Options

Production				Average		Fair Value
Period		Volumes		Strike Price		Liability(3)
Ended September 30,	Option Type	(barrels)		(per barrel)		(in thousands)
2006	Puts purchased		15,000	$	30.00	$	-
2006	Calls sold		15,000		34.25		(481	)
						$	(481	)
					Total net liability	$	(46,662	)

(1) MMBTU represents million British Thermal Units.

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

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

44

ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

[THE REMAINDER PAGE INTENTIONALLY LEFT BLANK]

45

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors

Atlas America, Inc.

We have audited the accompanying consolidated balance sheets of Atlas America, Inc. (a Delaware corporation) and subsidiaries as of September 30, 2005 and 2004, and the related consolidated statements of income, comprehensive income, changes in stockholder’s equity, and cash flows for each of the three years in the period ended September 30, 2005. These financial statements are the responsibility of the Company'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 audits 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 America, Inc. and subsidiaries as of September 30, 2005 and 2004 and the results of their operations and cash flows for each of the three years in the period ended September 30, 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 America, Inc.’s internal control over financial reporting as of September 30, 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 December 6, 2005 expressed an unqualified opinion thereon.

/s/ Grant Thornton LLP

Cleveland, Ohio

December 6, 2005

46

ATLAS AMERICA, INC.

CONSOLIDATED BALANCE SHEETS

SEPTEMBER 30, 2005 AND 2004

	2005			2004
	(in thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	18,281		$	29,192
Accounts receivable		73,996			24,113
Prepaid expenses		5,063			2,433
Deferred tax asset		6,970			2,212
Total current assets		104,310			57,950
Property and equipment, net		505,967			313,091
Other assets		15,360			7,955
Intangible assets, net		18,708			7,243
Goodwill		115,366			37,470
	$	759,711		$	423,709
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	122		$	3,401
Accounts payable		31,477			20,869
Liabilities associated with drilling contracts		60,971			29,375
Accrued producer liabilities		32,543			8,815
Accrued hedge liability		37,663			3,972
Advances from affiliate		111			-
Accrued liabilities		18,231			10,795
Total current liabilities		181,118			77,227
Long-term debt		191,605			82,239
Advances from parent		-			10,413
Deferred tax liability		28,903			23,654
Other liabilities		47,612			6,949
Minority interest		190,122			132,224
Commitments and contingencies		-			-
Stockholders’ equity:
Preferred stock, $0.01 par value: 1,000,000 authorized shares		-			-
Common stock, $0.01 par value: 49,000,000 authorized shares		133			133
Additional paid-in capital		75,637			75,584
ESOP loan receivable		(583	)		-
Accumulated other comprehensive loss		(5,615	)		(2,553	)
Retained earnings		50,779			17,839
Total stockholders’ equity		120,351			91,003
	$	759,711		$	423,709

See accompanying notes to consolidated financial statements

47

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENTS OF INCOME

YEARS ENDED SEPTEMBER 30, 2005, 2004 AND 2003

	2005			2004			2003
	(in thousands, except per share data)
REVENUES
Well drilling	$	134,338		$	86,880		$	52,879
Gas and oil production		63,499			48,526			38,639
Gathering, transmission and processing		266,837			36,252			5,901
Drilling management fee		285			-			-
Well services		9,552			8,430			7,634
		474,511			180,088			105,053
COSTS AND EXPENSES
Well drilling		116,816			75,548			45,982
Gas and oil production and exploration		9,070			8,838			8,485
Gathering, transmission and processing		229,816			27,870			2,444
Well services		5,167			4,399			3,774
General and administrative		13,466			5,026			5,132
Compensation reimbursement - affiliate		602			1,050			1,400
Depreciation, depletion and amortization		24,895			14,700			11,595
		399,832			137,431			78,812
OPERATING INCOME		74,679			42,657			26,241
OTHER INCOME (EXPENSE)
Interest expense		(11,467	)		(2,881	)		(1,961	)
Minority interest in Atlas Pipeline Partners, L.P.		(14,773	)		(4,961	)		(4,439	)
Arbitration settlement - net		4,290			(2,987	)		-
Other - net		229			768			636
		(21,721	)		(10,061	)		(5,764	)
Income from continuing operations before income taxes		52,958			32,596			20,477
Provision for income taxes		20,018			11,409			6,757
Income from continuing operations		32,940			21,187			13,720
Income from discontinued operation, net of taxes of $103		-			-			192
Net income	$	32,940		$	21,187		$	13,912
Net income (loss) per common share - basic:
From continuing operations	$	2.47		$	1.81		$	1.28
Discontinued operation		-			-			.02
Net income per common share	$	2.47		$	1.81		$	1.30
Weighted average common shares outstanding		13,334			11,683			10,688
Net income (loss) per common share - diluted:
From continuing operations	$	2.46		$	1.81		$	1.28
Discontinued operation		-			-			.02
Net income per common share	$	2.46		$	1.81		$	1.30
Weighted average common shares		13,366			11,684			10,688

See accompanying notes to consolidated financial statements

48

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

YEARS ENDED SEPTEMBER 30, 2005, 2004 AND 2003

	2005			2004			2003
	(in thousands)
Net income	$	32,940		$	21,187		$	13,912
Other comprehensive (loss) income:
Unrealized holding losses on hedging contracts, net of tax benefits of $2,452, $1,384 and $245		(4,360	)		(2,571	)		(520	)
Less: reclassification adjustment for losses realized in net income, net of taxes of $730, $10 and $355		1,298			18			753
		(3,062	)		(2,553	)		233
Comprehensive income	$	29,878		$	18,634		$	14,145

See accompanying notes to consolidated financial statements

49

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

YEARS ENDED SEPTEMBER 30, 2005, 2004, AND 2003

(in thousands, except share data)

							Accumulated
					Additional		Other			ESOP						Total
	Common Stock				Paid-In		Comprehensive			Loan			Retained			Stockholders’
	Shares		Amount		Capital		Income (Loss)			Receivable			Earnings			Equity
Balance, September 30, 2002		10,688,333	$	107	$	38,619	$	(233	)				$	$34,873		$	73,366
Other comprehensive income				-		-		233						-			233
Net income				-		-		-						13,912			13,912
Balance, September 30, 2003		10,688,333	$	107	$	38,619	$	-					$	$48,785		$	87,511
Initial public offering, net of costs		2,645,000		26		36,965		-						-			36,991
Dividend to parent		-		-		-		-						(52,133	)		(52,133	)
Other comprehensive loss		−		−		-		(2,553	)					-			(2,553	)
Net income		−		−		-		-						21,187			21,187
Balance, September 30, 2004		13,333,333	$	133	$	75,584	$	(2,553	)				$	$17,839		$	91,003
Issuance of common stock		1,370				53											53
Other comprehensive income		-						(3,062	)								(3,062	)
Repayment of ESOP loan											19						19
Loan to ESOP		-									(602	)					(602	)
Net income														32,940			32,940
Balance, September 30, 2005		13,334,703	$	133	$	75,637	$	(5,615	)	$	(583	)	$	50,779		$	120,351

See accompanying notes to consolidated financial statements

50

ATLAS AMERICA, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

YEARS ENDED SEPTEMBER 30, 2005, 2004 AND 2003

	2005			2004			2003
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	32,940		$	21,187		$	13,912
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		24,895			14,700			11,595
Amortization of deferred finance costs		2,448			704			560
Non-cash loss (gain) on derivative value		(1,887	)		585			-
Write down of note receivable		487			-			-
Non-cash compensation on long-term incentive plans		3,467			407			-
Terminated acquisition		-			2,987			-
Income on discontinued operation		-			-			(192	)
Minority interest in Atlas Pipeline Partners, L.P.		14,773			4,961			4,439
Gain on asset dispositions		(104	)		(39	)		(14	)
Deferred income taxes		2,275			1,896			-
Changes in operating assets and liabilities		50,824			9,926			18,874
Net cash provided by operating activities of continuing operations		130,118			57,314			49,174
CASH FLOWS FROM INVESTING ACTIVITIES:
Business acquisition, net of cash acquired		(195,262	)		(141,564	)		−
Capital expenditures		(99,185	)		(41,162	)		(28,029	)
Proceeds from sale of assets		170			405			182
Decrease (increase) in other assets		(614	)		237			(628	)
Net cash used in investing activities of continuing operations		(294,891	)		(182,084	)		(28,475	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings		385,750			183,532			68,384
Principal payments on borrowings		(279,590	)		(129,319	)		(86,694	)
Issuance of Atlas Pipeline Partners, L.P. common units		91,720			92,714			25,182
Issuance of Atlas America, Inc. common stock		-			36,991			-
Dividend to Resource America, Inc.		-			(52,133	)		-
Advances from (payments to) parent		(22,431	)		7,702			(5,755	)
Distributions paid to minority interest of Atlas Pipeline Partners, L.P.		(18,073	)		(7,271	)		(4,233	)
Increase in other assets		(3,514	)		(3,921	)		(1,133	)
Net cash provided by (used in) financing activities		153,862			128,295			(4,249	)
Net cash provided by discontinued operation		-			295			-
Increase (decrease) in cash and cash equivalents		(10,911	)		3,820			16,450
Cash and cash equivalents at beginning of year		29,192			25,372			8,922
Cash and cash equivalents at end of year	$	18,281		$	29,192		$	25,372

See accompanying notes to consolidated financial statements

51

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2005

NOTE 1 — NATURE OF OPERATIONS

Atlas America, Inc. (the “Company” or “AAI and its subsidiaries”) was incorporated in Delaware on September 27, 2000 as a wholly-owned subsidiary of Atlas Energy Holdings, Inc. In May 2004, the Company completed an initial public offering of 2,645,000 shares of its common stock at a price of $15.50 per common share including underwriters’ over allotment. The net proceeds of the offering of $37.0 million, after deducting underwriting discounts and costs, were distributed to Resource America, Inc. (“RAI”) (NASDAQ: REXI), the Company’s former parent in the form of a non-taxable dividend. Following the offering, RAI owned approximately 80.2% of the Company’s outstanding common stock. The Company trades under the symbol ATLS on the NASDAQ system.

The Company is an energy company which sponsors drilling partnerships and produces and sells natural gas and, to a significantly lesser extent, oil. The Company finances a substantial portion of its drilling activities through drilling partnerships it sponsors. The Company typically acts as the managing general partner of these partnerships and has a material partnership interest. The Company, through Atlas Pipeline Partners, L.P. (“Atlas Pipeline”) (NYSE: APL), transports natural gas from wells it owns and operates and wells owned by others to interstate pipelines and, in some cases, to end users and operates a natural gas processing facility. Atlas Pipeline is a master limited partnership in which the Company had a 19% interest at September 30, 2005. A subsidiary of the Company is the general partner of Atlas Pipeline. Through its acquisitions of Spectrum Field Services, Inc. (“Spectrum” or “Mid-Continent”) in July 2004 and Elk City in April 2005, Atlas Pipeline processes and transports natural gas and natural gas liquids (“NGLs”) in Oklahoma and Texas. In addition, on September 21, 2005, Atlas Pipeline entered into an agreement with a subsidiary of OGE Energy Corp. to acquire a subsidiary which owns a 75% operating interest in NOARK Pipeline System, Limited Partnership, or NOARK. NOARK’s assets, which will be included within Atlas Pipeline’s Mid-Continent operations, include a FERC regulated interstate pipeline and an unregulated intrastate natural gas gathering system. The acquisition was completed on October 31, 2005 (see Note 16).

Spin-off from Resource America, Inc.

On June 30, 2005, RAI distributed its remaining 10.7 million shares of the Company to its stockholders in the form of a tax-free dividend. Each stockholder of RAI received 0.59367 shares of the Company for each share of RAI common stock owned as of June 24, 2005, the record date. Although the distribution itself is tax-free to RAI stockholders, as a result of the deconsolidation there may be some tax liability arising from prior unrelated corporate transactions among the Company and some of its subsidiaries. The Company anticipates that all or a portion of any liability arising from this transaction may be reimbursed by us to RAI. The Company no longer consolidated with RAI as of June 30, 2005. In connection with the spin-off, RAI and Company entered into a series of agreements. There are two agreements that govern the ongoing relationship between the Company and RAI that are still in effect at September 30, 2005. These agreements are the tax matters agreement and the transition services agreement.

The tax matters agreement governs the respective rights, responsibilities and obligations of the Company and RAI with respect to tax liabilities and benefits, tax attributes, tax contests and other matters regarding income taxes, non-income taxes and related tax returns.

The transition services agreement governs the provision of support services by the Company to RAI and by RAI to the Company, such as:

· cash management and debt service administration;

· accounting and tax;

· investor relations;

· payroll and human resources administration;

· legal;

52

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 1 — NATURE OF OPERATIONS— (Continued)

· information technology;

· data processing;

· real estate management; and

· other general administrative functions.

The Company and RAI pay each other a fee for these services equal to their fair market value. The fee is payable monthly in arrears, 15 days after the close of the month. The Company and RAI also agreed to pay or reimburse each other for any out-of-pocket payments, costs and expenses associated with these services.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are wholly-owned except for Atlas Pipeline. In accordance with established practice in the oil and gas industry, the Company includes its pro-rata share of assets, liabilities, revenues, and costs and expenses of the energy partnerships in which the Company has an interest. All material intercompany transactions have been eliminated.

Use of Estimates

Preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and costs and expenses during the reporting period. Actual results could differ from these estimates.

Reclassifications

Certain reclassifications have been made to the fiscal 2004 and fiscal 2003 consolidated financial statements to conform to the fiscal 2005 presentation.

Stock-Based Compensation

The Company applies the intrinsic value-based method of accounting prescribed by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees (“APB No. 25”), and related interpretations, including the Company’s participation of its employees’ in RAI’s stock option plans prior to its spin-off from RAI. As such, compensation expense is recorded on the date of grant only if the current market price of the underlying stock exceeds the exercise price. The Company adopted the disclosure requirements of Statement of Financial Accounting Standards (“SFAS”) No. 123, “Accounting for Stock-Based Compensation (“SFAS 123”) as amended by the required disclosures SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure.”

53

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES— (Continued)

SFAS 123 requires the disclosure of pro forma net income and earnings per share as if the Company had adopted the fair value method for stock options granted after June 30, 1996. Under SFAS 123, the fair value of stock-based awards to employees is calculated through the use of option pricing models, even though such models were developed to estimate the fair value of freely tradable, fully transferable options without vesting restrictions, which significantly differ from RAI’s stock option awards. These models also require subjective assumptions, including future stock price volatility and expected time to exercise, which greatly affect the calculated values. In fiscal 2005, the Company’s calculations used a binomial (lattice) model, which the Company believes is a more accurate valuation approach than the Black-Scholes option pricing model which was used in fiscal 2004 and 2003. The Company’s calculations were made using the following weighted average assumptions: expected life, 10 years following date of grant; stock volatility, 46%, 23% and 70% in fiscal 2005, 2004 and 2003, respectively; risk-free interest rate, 4.1%, 4.1% and 4.0% in fiscal 2005, 2004 and 2003, respectively; prior to the spin-off, dividends were based on RAI’s historical rate.

No stock-based employee compensation cost is reflected in the Company’s net income, as all options granted under both the plans in which the Company’s employees participate (see Note 9) had an exercise price equal to the market value of the underlying common stock on the date of grant.  The vesting of all unvested options under the RAI was accelerated for all Company employees and all options were subsequently exercised prior to June 30, 2005 in anticipation of the spin-off from RAI. The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS 123 to stock-based employee compensation.

	Years Ended September 30,
	2005			2004			2003
	(in thousands, except per share data)
Net income, as reported	$	32,940		$	21,187		$	13,912
Less total stock-based employee compensation expense determined under the fair value based method for all awards, net of income taxes		(7,283	)		(378	)		(377	)
Pro forma net income	$	25,657		$	20,809		$	13,535
Earnings per share:
Basic - as reported	$	2.47		$	1.81		$	1.30
Basic - pro forma	$	1.92		$	1.78		$	1.27
Earnings per share:
Diluted - as reported	$	2.46		$	1.81		$	1.30
Diluted - pro forma	$	1.92		$	1.78		$	1.27

The pro forma net income in fiscal 2005 above includes $6.7 million in expense (net of taxes) related to options for 500,000 shares issued in fiscal 2005 which were immediately exercisable. The Company issued these options under these terms to avoid a substantial charge to earnings upon adoption of FASB Statement No 123(R) (see Note 2 below).

54

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES— (Continued)

Earnings Per Share

Basic earnings per share are determined by dividing net income by the weighted average number of shares of common stock outstanding during the period. Earnings per share - diluted is computed by dividing net income by the sum of the weighted average number of shares of common stock outstanding and dilutive potential shares issuable from the exercise of stock options and award plans. Dilutive potential shares of common stock consist of the excess of shares issuable under the terms of various stock option agreements over the number of such shares that could have been reacquired (at the weighted average price of shares during the period) with the proceeds received from the exercise of the options.

The components of basic and diluted earnings per share for the periods indicated are as follows:

	Years Ended September 30,
	2005		2004		2003
	(in thousands)
Income from continuing operations	$	32,940	$	21,187	$	13,720
Income from discontinued operation, net of taxes		-		−		192
Net income	$	32,940	$	21,187	$	13,912
Weighted average common shares outstanding-basic		13,334		11,683		10,688
Dilutive effect of stock option and award plans		32		1		−
Weighted average common shares-diluted		13,366		11,684		10,688

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources. These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” and for the Company only include changes in the fair value, net of taxes, of unrealized hedging gains and losses.

Receivables

In evaluating its allowance for possible losses, the Company performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by the Company’s review of its customer’s credit information. The Company extends credit on an unsecured basis to many of its energy customers. At September 30, 2005, the Company’s credit evaluation indicated that it has no need for an allowance for possible losses.

Property and Equipment

Property and equipment is stated at cost. Depreciation, depletion and amortization is based on cost less estimated salvage value primarily using the unit-of-production or straight line method over the assets estimated useful lives. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized.

55

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES— (Continued)

The estimated service lives of property and equipment are as follows:

Pipelines, processing and compression facilities	15-35 years
Rights-of-way - Mid-Continent	40 years
Rights-of-way - Appalachia	20 years
Land, buildings and improvements	10-40 years
Furniture and equipment	3-7 years
Other	3-10 years

Property and equipment consists of the following at the dates indicated:

	At September 30,
	2005			2004
	(in thousands)
Mineral interests:
Proved properties	$	2,852		$	2,544
Unproved properties		1,002			1,002
Wells and related equipment		255,879			184,046
Pipelines, processing and compression facilities		304,523			163,302
Rights-of-way		15,110			14,702
Land, building and improvements		7,793			7,213
Support equipment		3,675			2,902
Other		5,251			4,227
		596,085			379,938
Accumulated depreciation, depletion and amortization:
Oil and gas properties and pipelines		(85,824	)		(63,551	)
Other		(4,294	)		(3,296	)
		(90,118	)		(66,847	)
	$	505,967		$	313,091

In April 2005, Atlas Pipeline completed the acquisition of ETC Oklahoma Pipeline, Ltd. (“Elk City”) for approximately $196 million (see Note 13). The purchase price allocation is based on estimated values determined by Atlas Pipeline, which are subject to adjustment and could change significantly as Atlas Pipeline continues to evaluate this allocation. At September 30, 2005, the purchase price allocated to property, plant and equipment for this acquisition was included within the pipelines, processing and compression facilities category within the above table.

Oil and Gas Properties

The Company follows the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Oil is converted to gas equivalent basis (“mcfe”) at the rate one barrel equals 6 mcf. Depletion is provided on the units-of-production method. Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable and impaired if conditions indicate the Company will not explore the acreage prior to expiration or the carrying value is above fair value.

56

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES— (Continued)

The Company’s long-lived assets are reviewed for impairment annually for events or changes in circumstances that indicate that the carrying amount of an asset may not be recoverable. Long-lived assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets. The review is done by determining if the historical cost of proved properties less the applicable accumulated depreciation, depletion and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company estimates prices based upon market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. If the carrying value exceeds such cash flows, an impairment loss is recognized for the difference between the estimated fair market value, (as determined by discounted future cash flows) and the carrying value of the assets.

Upon the sale or retirement of a complete or partial unit of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to accumulated depletion. Upon the sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the statements of income. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

Asset Retirement Obligations

The fair values of asset retirement obligations are recognized in the period they are incurred if a reasonable estimate of fair value can be made. Asset retirement obligations primarily relate to the abandonment of oil and gas producing facilities and include costs to dismantle and relocate or dispose of production equipment, gathering systems, wells and related structures. Estimates are based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The Company does not provide for a market risk premium associated with asset retirement obligations because a reliable estimate cannot be determined.

Fair Value of Financial Instruments

The Company used the following methods and assumptions in estimating the fair value of each class of financial instrument for which it is practicable to estimate fair value.

For cash and cash equivalents, receivables and payables, the carrying amounts approximate fair value because of the short maturity of these instruments.

For derivatives the carrying value approximates fair value because the Company marks to market all derivatives.

For secured revolving credit facilities and all other debt, the carrying value approximates fair value because of the short term maturity of these instruments and the variable interest rates in the debt agreements.

57

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES— (Continued)

Derivative Instruments

The Company applies the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”). SFAS 133 requires each derivative instrument to be recorded in the balance sheet as either an asset or liability measured at fair value. Changes in a derivative instrument’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met.

Concentration of Credit Risk

Financial instruments, which potentially subject the Company to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. The Company places its temporary cash investments in high-quality short-term money market instruments and deposits with high-quality financial institutions and brokerage firms. At September 30, 2005, the Company had $23.8million in deposits at various banks, of which $22.8million was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments.

Environmental Matters

The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.

The Company accounts for environmental contingencies in accordance with SFAS No. 5 “Accounting for Contingencies.” Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. The Company maintains insurance which may cover in whole or in part certain environmental expenditures. For the three years ended September 30, 2005, the Company had no environmental matters requiring specific disclosure or requiring recording of a liability.

Revenue Recognition

The Company conducts certain energy activities through, and a portion of its revenues are attributable to, sponsored energy limited partnerships. The Company contracts with the energy partnerships to drill partnership wells. The contracts require that the energy partnerships must pay the Company the full contract price upon execution. The income from a drilling contract is recognized as the services are performed using the percentage of completion method. The contracts are typically completed in less than 60 days. On an uncompleted contract, the Company classifies the difference between the contract payments it has received and the revenue earned as a current liability.

The Company recognizes gathering, transmission and processing revenues at the time the natural gas and liquids are delivered.

The Company recognizes well services revenues at the time the services are performed.

The Company is entitled to receive management fees according to the respective partnership agreements. The Company recognizes such fees as income when earned and includes them in well services revenues.

58

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES— (Continued)

The Company records the income from the working interests and overriding royalties of wells in which it owns an interest when the gas and oil are delivered.

Because there are timing differences between the delivery of natural gas, NGLs and oil and the Company’s receipt of a delivery statement, the Company has unbilled revenues. These revenues are accrued based upon volumetric data from the Company’s records and the Company’s estimates of the related transportation and compression fees which are, in turn, based upon applicable product prices. The Company had unbilled trade receivables at September 30, 2005 and September 30, 2004 of $57.1 million and $22.1 million which are included in Accounts Receivable, on its Consolidated Balance Sheets.

Supplemental Cash Flow Information

The Company considers temporary investments with a maturity at the date of acquisition of 90 days or less to be cash equivalents.

Supplemental disclosure of cash flow information:

	Years Ended September 30,
	2005			2004			2003
	(in thousands)
Cash paid for:
Interest	$	8,807		$	2,114		$	1,591
Income taxes paid (refunded)		23		$	(220	)	$	359
					��
Non-cash investing activities include the following:
Fair value of assets acquired	$	199,833		$	160,799		$	-
Liabilities assumed		(4,571	)		(19,235	)		-
Net cash paid	$	195,262		$	141,564		$	-

Income Taxes

The Company records deferred tax assets and liabilities, as appropriate, to account for the estimated future tax effects attributable to temporary differences between the financial statement and tax bases of assets and liabilities and operating loss carryforwards, using currently enacted tax rates. The deferred tax provision or benefit each year represents the net change during that year in the deferred tax asset and liability balances. Separate company state tax returns are filed in those states in which the Company is registered to do business.

59

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)

Recently Issued Financial Accounting Standards

In May 2005, the Financial Accounting Standards Board, (“FASB”) issued Statement No. 154, “Accounting Changes and Error Corrections” (“SFAS 154”). SFAS 154 requires retrospective application to prior periods’ financial statements of 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 154 will depend on the nature and extent of any voluntary accounting changes and correction of errors after the effective date, but management does not currently expect SFAS 154 to have a material impact on the Company’s 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 cost 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. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. Retrospective application of interim financial information is permitted but is not required. Early adoption of this interpretation is encouraged. Management does not believe the interpretation will have a significant impact on the Company’s financial position or results of operations.

In December 2004, the FASB issued Statement No. 123 (R) (revised 2004) “Share-Based Payment”, which is a revision of SFAS No. 123, “Accounting for Stock-Based Compensation”.  Statement 123 (R) supersedes APB No. 25, and amends SFAS No. 95, Statement of Cash Flows.  Generally, the approach to accounting in Statement 123 (R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values.  Currently the Company accounts for these payments under the intrinsic value provisions of APB No. 25 with no expense recognition in the financial statements.  Statement 123 (R) is effective for the Company beginning October 1, 2005.  The Statement offers several alternatives for implementation.  At this time, the Company has not made a decision as to the alternative it may select.

In December 2004, the FASB issued FASB Staff Position No. FAS 109-1 (“FAS 109-1”), “Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004” (“AJCA”). The AJCA introduces a special 9% tax deduction on qualified production activities. FSP 109-1 concludes that this deduction should be accounted for as a special tax deduction in accordance with SFAS No. 109. As such, the special deduction has no effect on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this deduction will be reported in the same period in which the deduction is claimed in the Company’s tax return. FAS 109-1 is not expected to have a material impact on the Company’s financial position or results of operations.

60

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 3 — OTHER ASSETS, INTANGIBLE ASSETS AND GOODWILL

Other Assets

The following table provides information about other assets at the dates indicated.

	At September 30,
	2005		2004
	(in thousands)
Deferred financing costs, net of accumulated amortization of $2,519 and $1,080	$	5,524	$	4,704
Investments		1,647		2,166
Security deposits		1,779		1,062
Deferred organization cost		440		23
Hedge receivable long-term		5,970		-
	$	15,360	$	7,955

Deferred financing costs are recorded at cost and are amortized over the terms of the related loan agreements which range from three to five years. In June 2005, Atlas Pipeline recognized accelerated amortization of $1.0 million related to deferred financing costs associated with the retirement of the term portion of its $270 million credit facility and incurred additional financial costs of $3.2 million associated with its new larger credit facility (see Note 7).

Intangible Assets

Customer contacts. At September 30, 2005, Atlas Pipeline had $12.4 million of intangible assets, net of accumulated amortization of $492,000, which was recorded in connection with natural gas gathering contracts assumed in its acquisition of Elk City (See Note 13). SFAS No. 142 requires that intangible assets with finite useful lives be amortized over their respective 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 shall be amortized over the best estimate of its useful life. At a minimum, Atlas Pipeline will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required. Amortization expense on the customer contract intangible assets, which have an estimated life of 12 years and are amortized on a straight-line basis, was $492,000 for the year ended September 30, 2005.

Partnership and operating contracts. Included in intangible assets are partnership management and operating contracts acquired through previous acquisitions which are recorded at fair value on their acquisition dates. The Company amortizes contracts acquired on the declining balance and straight-line methods, over their respective estimated lives, ranging from five to thirteen years. Amortization expense for these contracts for the years ended September 30, 2005, 2004 and 2003 was $933,000, $1.0 million and $1.1 million, respectively.

The aggregate estimated annual amortization expense of customer and partnership management and operating contracts is approximately $1.9 million for each of the succeeding five years.

The following table provides information about intangible assets at the dates indicated:

61

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 3 — OTHER ASSETS, INTANGIBLE ASSETS AND GOODWILL - (Continued)

	At September 30, 2005					At September 30, 2004
	(in thousands)
	Cost		Accumulated Amortization			Cost		Accumulated Amortization
Customer contracts	$	12,891	$	(492	)	$	-	$	-
Partnership management and operating contracts		14,343		(8,034	)		14,343		(7,100	)
Intangible assets, net	$	27,234	$	(8,526	)	$	14,343	$	(7,100	)

Goodwill

The Company applies the provisions of SFAS No. 142 (“SFAS 142”) “Goodwill and Other Intangible Assets,” which requires that goodwill no longer be amortized, but instead evaluated for impairment at least annually. The evaluation of impairment under SFAS 142 requires the use of projections, estimates and assumptions as to the future performance of the Company’s operations, including anticipated future revenues, expected future operating costs and the discount factor used. Actual results could differ from projections, resulting in revisions to the Company’s assumptions and, if required, recognition of an impairment loss. The Company’s evaluation of goodwill at September 30, 2005 indicated there was no impairment loss. The Company will continue to evaluate its goodwill at least annually or when impairment indicators arise, and will reflect the impairment of goodwill, if any, within the consolidated statements of income in the period in which the impairment is indicated.

	At September 30,
	2005		2004
	(in thousands)
Goodwill at beginning of period, ( net of accumulated amortization of $4,532)	$	37,470	$	37,470
Preliminary addition to goodwill related to Elk City acquisition (see Note 13)		77,896		-
Goodwill at end of period (net of accumulated amortization of $4,532)	$	115,366	$	37,470

NOTE 4 - ASSET RETIREMENT OBLIGATIONS

Effective October 1, 2002, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”) which requires the Company to recognize an estimated liability for the plugging and abandonment of its oil and gas wells and associated pipelines and equipment. Under SFAS 143, the Company must currently recognize a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. SFAS 143 requires the Company to consider estimated salvage value in the calculation of depreciation, depletion and amortization. Consistent with industry practice, historically the Company had determined the cost of plugging and abandonment on its oil and gas properties would be offset by salvage values received. The adoption of SFAS 143 resulted in (i) an increase of total liabilities because retirement obligations are required to be recognized, (ii) an increase in the recognized cost of assets because the retirement costs are added to the carrying amount of the long-lived assets and (iii) a decrease in depletion expense, because the estimated salvage values are now considered in the depletion calculation.

62

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 4 - ASSET RETIREMENT OBLIGATIONS - (Continued)

The estimated liability is based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. The increase in asset retirement obligations in fiscal 2005 was due to an upward revision in the estimated cost of plugging and abandoning wells.

The adoption of SFAS 143 as of October 1, 2002, resulted in a cumulative effect adjustment to record (i) a $1.9 million increase in the carrying values of proved properties, (ii) a $1.5 million decrease in accumulated depletion and (iii) a $3.4 million increase in non-current plugging and abandonment liabilities. The cumulative and pro forma effects of the application of SFAS 143 were not material to the Company’s consolidated statements of income.

The Company has no assets legally restricted for purposes of settling asset retirement obligations. Except for the item previously referenced, the Company has determined that there are no other material retirement obligations associated with tangible long-lived assets.

A reconciliation of the Company’s liability for well plugging and abandonment costs for the periods indicated is as follows:

	Years Ended September 30,
	2005			2004			2003
	(in thousands)
Asset retirement obligations, beginning of year	$	4,888		$	3,131		$	-
Adoption of SFAS 143		-			-			3,380
Liabilities incurred		770			1,724			93
Liabilities settled		(137	)		(58	)		(52	)
Revision in estimates		11,789			(205	)		(494	)
Accretion expense		341			296			204
Asset retirement obligations, end of year	$	17,651		$	4,888		$	3,131

The above accretion expense is included in depreciation, depletion and amortization in the Company’s consolidated statements of income and the asset retirement obligation liabilities are included in other liabilities in the Company’s consolidated balance sheets.

NOTE 5 — CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

In the ordinary course of its business operations, the Company has ongoing relationships with several related entities:

Relationship with Company Sponsored Partnerships. The Company conducts certain activities through, and a substantial portion of its revenues are attributable to, energy limited partnerships (“Partnerships”). The Company serves as general partner of the Partnerships and assumes customary rights and obligations for the Partnerships. As the general partner, the Company is liable for Partnership liabilities and can be liable to limited partners if it breaches its responsibilities with respect to the operations of the Partnerships. The Company is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Partnerships’ revenue, and costs and expenses according to the respective Partnership agreements.

63

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 5 — CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS - (Continued)

Relationship with RAI. On June 30, 2005, RAI completed its spin-off of the Company. The Company reimburses RAI for various costs and expenses it incurs on behalf of the Company, primarily payroll and rent. For fiscal 2005, 2004 and 2003 these costs totaled $602,000, $1.1 million and $1.4 million, respectively. Certain operating expenditures totaling $111,000 that remain to be settled between the Company and RAI are reflected in the Company’s consolidated balance sheets as advance from affiliate (see Note 1).

RAI’s relationship with Anthem Securities (a wholly-owned subsidiary of the Company). Anthem Securities is a wholly-owned subsidiary of the Company and a registered broker-dealer which serves as the dealer-manager of investment programs sponsored by RAI's real estate and equipment finance segments. Some of the personnel performing services for Anthem have been paid by RAI, and Anthem reimburses RAI for the allocable costs of such personnel.  In addition, RAI has agreed to cover some of the operating costs for Anthem's office of supervisory jurisdiction, principally licensing fees and costs.  RAI paid $270,000, $7,000 and $192,000 respectively, toward such operating costs of Anthem in fiscal 2005, 2004 and 2003.  During the same period, Anthem reimbursed RAI $653,000, $156,000 and $179,000, respectively, for the costs allocable to it.

Relationship with Ledgewood. Until April 1996, Edward E. Cohen (“E. Cohen”), the Company’s Chairman of the Board, Chief Executive Officer and President, was of counsel to Ledgewood, a Philadelphia law firm. Mr. E. Cohen receives certain debt service payments from Ledgewood related to the termination of his affiliation with Ledgewood and its redemption of his interest. The Company paid Ledgewood $440,300, $490,400 and $248,400 during fiscal 2005, 2004 and 2003, respectively, for legal services rendered to the Company.

NOTE 6 ─ DERIVATIVE INSTRUMENTS

The Company from time to time enters into natural gas futures and option contracts to hedge its exposure to changes in natural gas prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas.

The Company formally documents all relationships between hedging instruments and the items being hedged, including the Company’s risk management objective and strategy for undertaking the hedging transactions. This includes matching the natural gas futures and options contracts to the forecasted transactions. The Company assesses, both at the inception of the hedge and on an ongoing basis, whether the derivatives are highly effective in offsetting changes in the fair value of hedged items. Historically these contracts have qualified and been designated as cash flow hedges and recorded at their fair values. Gains or losses on future contracts are determined as the difference between the contract price and a reference price, generally prices on NYMEX. Such gains and losses are charged or credited to Accumulated Other Comprehensive Income (Loss) and recognized as a component of sales revenue in the month the hedged gas is sold. If it is determined that a derivative is not highly effective as a hedge or it has ceased to be a highly effective hedge, due to the loss of correlation between changes in gas reference prices under a hedging instrument and actual gas prices, the Company will discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will be recognized immediately into earnings.

At September 30, 2005, the Company had no open natural gas futures contracts related to natural gas sales and accordingly, had no unrealized loss or gain related to open NYMEX contracts at that date. The Company recognized a loss of $0, $0 and $1.1 million on settled contracts covering natural gas production for the years ended September 30, 2005, 2004 and 2003, respectively. The Company recognized no gains or losses during the three year period ended September 30, 2005 for hedge ineffectiveness or as a result of the discontinuance of these cash flow hedges.

64

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 6 - DERIVATIVE INSTRUMENTS - (Continued)

Atlas Pipeline enters 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 Activity”. Atlas Pipeline enters into these instruments to hedge their 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, Atlas Pipeline receives a fixed price and pays a floating price based on certain indices for the relevant contract period.

Atlas Pipeline formally documents all relationships between hedging instruments and the items being hedged, including the risk management objective and strategy for undertaking the hedging transactions. This includes matching the natural gas futures and options contracts to the forecasted transactions. Atlas Pipeline assesses both at the inception of the hedge and on an ongoing basis, whether the derivatives are effective in offsetting changes in the forecasted cash flow of hedged items. If Atlas Pipeline determines 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, Atlas Pipeline will discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will be recognized immediately into earnings.

Derivatives are recorded on the balance sheet as assets or liabilities at fair value. For derivatives qualifying as hedges, the effective portion of changes in fair value are recognized in stockholders’ equity as Accumulated Other Comprehensive Income (Loss) and reclassified to earnings as such transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, changes in fair value are recognized in earnings as they occur. At September 30, 2005 and 2004, Atlas Pipeline reflected net hedging liabilities on its balance sheets of $46.7 million and $6.0 million, respectively. Of the $5.6 million net loss in accumulated other comprehensive income (loss) at September 30, 2005, the Company will reclassify $2.7 million of losses to its consolidated statements of income over the next twelve month period as these contracts expire, and $2.9 million will be reclassified in later periods if the fair values of the instruments remain at current market values. Actual amounts that will be reclassified will vary as a result of future price changes. Ineffective hedge gains or losses are recorded within its consolidated statements of income while the hedge contract is open and may increase or decrease until settlement of the contract. Atlas Pipeline recognized losses of $5.0 million and $27,000 for the fiscal year ended September 30, 2005 and 2004, respectively, within its consolidated statements of income related to the settlement of qualifying hedge instruments. Atlas Pipeline also recognized losses of $64,000 and $697,000 for the fiscal years ended September 30, 2005 and 2004, respectively, within its consolidated statements of income related to the change in market value of non-qualifying or ineffective hedges.

A portion of the Company’s 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 September 30, 2005, Atlas Pipeline had the following NGLs, natural gas, and crude oil volumes hedged:

65

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 6 - DERIVATIVE INSTRUMENTS - (Continued)

Natural Gas Liquids Fixed - Price Swaps

Production Period Ended  September 30,	Volumes		Average Fixed Price		Fair Value Liability(2)
	(gallons)		(per gallon)		(in thousands)
2006		38,586,000	$	0.673	$	(16,742	)
2007		38,115,000		0.711		(12,188	)
2008		34,587,000		0.702		(9,037	)
2009		7,434,000		0.697		(1,781	)
					$	(39,748	)

Natural Gas Fixed - Price Swaps

Production Period Ended  September 30,	Volumes		Average Fixed Price		Fair Value Liability(3)
	(MMBTU)(1)		(per MMBTU)		(in thousands)
2006		3,923,000	$	7.169	$	(5,767	)
2007		1,560,000		7.210		(1,658	)
2008		510,000		7.262		(1,037	)
					$	(8,462	)

Natural Gas Basis Swaps

Production Period Ended  September 30,	Volumes		Average Fixed Price			Fair Value Asset(3)
	(MMBTU)(1)		(per MMBTU)			(in thousands)
2006		4,262,000	$	(0.517	)	$	1,376
2007		1,560,000		(0.522	)		1,584
2008		510,000		(0.544	)		1,383
						$	4,343

Crude Oil Fixed - Price Swaps

Production Period Ended  September 30,	Volumes		Average Fixed Price		Fair Value Liability(3)
	(barrels)		(per barrel)		(in thousands)
2006		67,800	$	51.329	$	(1,056	)
2007		80,400		55.187		(844	)
2008		82,500		58.475		(414	)
					$	(2,314	)

Crude Oil Options

Production Period Ended  September 30,	Option Type	Volumes		Average Strike Price		Fair Value Liability(3)
		(barrels)		(per barrel)		(in thousands)
2006	Puts purchased		15,000	$	30.00	$	-
2006	Calls sold		15,000		34.25		(481	)
						$	(481	)
					Total net liability	$	(46,662	)

66

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 6 - DERIVATIVE INSTRUMENTS - (Continued)

____________

(1) MMBTU represents million British Thermal Units.

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

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

The following table sets forth the book and estimated fair values of derivative instruments at the dates indicated (in thousands):

	September 30, 2005						September 30, 2004
	Book Value			Fair Value			Book Value			Fair Value
Assets
Derivative instruments	$	20,963		$	20,963		$	−		$	−
	$	20,963		$	20,963		$	−		$	−
Liabilities
Derivative instruments	$	(67,625	)	$	(67,625	)	$	(6,032	)	$	(6,032	)
	$	(67,625	)	$	(67,625	)	$	(6,032	)	$	(6,032	)
	$	(46,662	)	$	(46,662	)	$	(6,032	)	$	(6,032	)

NOTE 7 ─ DEBT

Total debt consists of the following at the dates indicated:

	At September 30,
	2005		2004
	(in thousands)
Revolving credit facility - Atlas Pipeline	$	183,500	$	-
Revolving credit facility		8,000		25,000
Term loan - Atlas Pipeline		-		60,000
Other debt		227		640
		191,727		85,640
Less current maturities		122		3,401
	$	191,605	$	82,239

Revolving Credit Facility. The Company has a $75.0 million credit facility led by Wachovia Bank, N.A. (“Wachovia”). The revolving credit facility has a current borrowing base of $75.0 million which may be decreased subject to a decline in the Company’s oil and gas reserves. The facility permits draws based on the remaining proved developed non-producing and proved undeveloped natural gas and oil reserves attributable to the Company’s wells and the projected fees and revenues from operation of its wells and the administration of energy partnerships. Up to $50.0 million of the facility may be in the form of standby letters of credit. The facility is secured by the Company’s assets including 1.6 million units in Atlas Pipeline, and bears interest at either the base rate plus the applicable margin or at the adjusted London Interbank Offered Rate (“LIBOR”) plus the applicable margin elected at the Company’s option.

67

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 7 - DEBT - (Continued)

The base rate for any day equals the higher of the federal funds rate plus 0.50% or the Wachovia prime rate. Adjusted LIBOR is LIBOR divided by 1.00 minus the percentage prescribed by the Federal Reserve Board for determining the reserve requirement for euro currency funding. The applicable margin ranges from 0.25% to 0.75% for base rate loans and 1.75% to 2.25% for LIBOR loans.

The Wachovia credit facility requires the Company to maintain specified net worth and specified ratios of current assets to current liabilities and debt to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”). In addition, the facility limits sales, leases or transfers of assets and the incurrence of additional indebtedness. The facility limits the dividends payable by the Company, on a cumulative basis, to 50% of the Company’s net income from January 1, 2004 to the date of determination plus $5.0 million. The facility terminates in March 2007, when all outstanding borrowings must be repaid. At September 30, 2005 and 2004, $9.5 million and $26.7 million, respectively, were outstanding under this facility, including $1.5 million and $1.7 million, respectively, under letters of credit which are not reflected as borrowings on the Company’s consolidated balance sheet.

Atlas Pipeline Facility. In April 2005, Atlas Pipeline entered into a new $270.0 million credit facility (the “Credit Facility”) with a syndicate of banks, which replaced its existing $135.0 million facility. The facility was comprised of a five-year $225.0 million revolving line of credit and a five-year $45.0 million term loan. The term loan portion of the Credit Facility was repaid and retired from the net proceeds of the June 2005 equity offering (see Note 12). The revolving portion of the Credit Facility bears interest, at Atlas Pipeline’s option, at either (i) Adjusted LIBOR plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the applicable margin). The weighted average interest rate on the outstanding Credit Facility borrowings at September 30, 2005 was 6.6%. Up to $50.0 million of the credit facility may be utilized for letters of credit, of which $7.7 million is outstanding at September 30, 2005 and is not reflected as borrowings on the Company’s consolidated balance sheet. Borrowings under the Credit Facility are secured by a lien on and security interest in all of Atlas Pipeline’s property and that of its subsidiaries, and by the guaranty of each of Atlas Pipeline’s subsidiaries.

The Credit Facility contains customary covenants, including restrictions on Atlas Pipeline’s ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in Atlas Pipeline’s subsidiaries. The Credit Facility also contains covenants requiring Atlas Pipeline to maintain, on a rolling four-quarter basis, a maximum total debt to EBITDA ratio (each as defined in the credit agreement) of 5.5 to 1, reducing to 4.5 to 1 on September 30, 2005 and thereafter; and an interest coverage ratio (as defined in the credit agreement) of at least 3.0 to 1. Atlas Pipeline is in compliance with these covenants as of September 30, 2005. Based upon the definitions set forth within the credit agreement, Atlas Pipeline’s ratio of total debt to EBITDA was 3.7 to 1 and the interest coverage ratio was 4.8 to 1 at September 30, 2005.

Annual debt principal payments over the next five fiscal years ending September 30 are as follows (in thousands):

2006	122
2007	8,085
2008	20
2009	-
2010	183,500

At September 30, 2005, the Company has complied with all financial covenants in its debt agreements.

68

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 8 — INCOME TAXES

The following table details the components of the Company’s provision for income taxes from continuing operations for the periods indicated:

	Years Ended September 30,
	2005		2004		2003
	(in thousands)
Provision for income taxes:
Current:
Federal	$	16,913	$	9,070	$	5,069
State		830		553		60
Deferred		2,275		1,786		1,628
	$	20,018	$	11,409	$	6,757

A reconciliation between the statutory federal income tax rate and the Company’s effective income tax rate is as follows:

	Years Ended September 30,
	2005			2004			2003
Statutory tax rate		35	%		35	%		35	%
Statutory depletion		(2	)		(1	)		(2	)
Reorganization costs		2			-			-
Other, net		1			-			-
Non-conventional fuel credit		-			−			(1	)
State income taxes, net of federal tax benefit		2			1			1
		38	%		35	%		33	%

The components of the Company's net deferred tax liability are as follows:

	September 30,
	2005			2004
	(in thousands)
Deferred tax assets related to:
Unrealized loss on hedging contracts	$	3,159		$	1,374
Accrued liabilities		1,978			1,922
Statutory depletion carryforward		-			668
Other, net		730			762
		5,867			4,726
Deferred tax liabilities related to:
Property and equipment bases differences		(19,065	)		(17,314	)
Other, net		(8,735	)		(8,854	)
		(27,800	)		(26,168	)
Net deferred tax liability	$	(21,933	)	$	(21,442	)

69

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 8 - INCOME TAXES - (Continued)

Deferred income tax assets and liabilities are classified as current or long-term consistent with the classification of the related temporary difference and are recorded in the Company’s consolidated balance sheets as follows:

	September 30,
	2005			2004
	(in thousands)
Current deferred tax asset	$	6,970		$	2,212
Non-current deferred tax liability		(28,903	)		(23,654	)
	$	(21,933	)	$	(21,442	)

The Company had net operating loss carryforwards of $41.3 million at September 30, 2005, primarily related to state income taxes that will expire beginning in fiscal 2014 and ending in 2025 if unused. The Company had deferred tax assets of $1.6 million for the net operating loss carryforwards and a related valuation allowance of $ 243,000 at September 30, 2005, all of which was established prior to 2005 based on the uncertainty of generating future taxable income in certain states during the limited period that the net operating loss carryforwards can be carried forward.

NOTE 9 — BENEFIT PLANS

Employee Stock Ownership Plan. In June 2005, in connection with the spin-off from RAI, the Company established an Employee Stock Ownership Plan ("ESOP"). The ESOP, which is a qualified non-contributory retirement plan, was established to acquire shares of the Company's common stock for the benefit of all employees who are 21 years of age or older and have completed 1,000 hours of service for the Company. In addition, as a result of the spin-off, the ESOP holds 167,000 shares of RAI stock, of which 127,000 are allocated to participants.The Company loaned $602,000 to the ESOP, which was used by the ESOP to acquire the remaining unallocated 40,375 shares of RAI common stock. Contributions to the ESOP are made at the discretion of the Board of Directors. The cost of shares purchased by the ESOP but not yet allocated to participants is shown as a reduction of stockholders’ equity. The unearned benefits expense (a reduction in stockholders' equity) will be reduced by the amount of any loan principal payments made by the ESOP to the Company. Any dividends which may be paid on allocated shares will reduce retained earnings; dividends on unearned ESOP shares will be used to service the related debt.

The common stock purchased by the ESOP with the money borrowed is held by the ESOP trustee in a suspense account. On an annual basis, as the ESOP loan is paid down, a portion of the common stock will be released from the suspense account and allocated to participating employees. As of September 30, 2005, there were 75,000 shares allocated to participants and 24,000 shares which are unallocated. Compensation expense related to the plan amounted to $30,000 for the year ended September 30, 2005. The fair value of unearned ESOP shares was $1.8 million at September 30, 2005.

Employee Savings Plan. Upon the spin-off from RAI, the Company established an Investment Savings Plan under Section 401(k) of the Internal Revenue Code which allows employees to defer up to 15% of their income, subject to certain limitations, on a pretax basis through contributions to the savings plan. The Company matches up to 50% of each employee's contribution, subject to certain limitations. Included in general and administrative expenses are $315,000 for the Company’s contributions for the year ended September 30, 2005.

70

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 9 - BENEFIT PLANS - (Continued)

Stock Incentive Plan. The Company adopted a Stock Incentive Plan (the “Plan”) in fiscal 2004 which authorized the granting of up to 1,333,333 shares of the Company’s common stock to employees, affiliates, consultants and directors of the Company in the form of incentive stock options (“ISOs”), non-qualified stock options, stock appreciation rights (“SARs”), restricted stock and deferred units. In July 2005, options for 777,500 shares were issued under this Plan. Options under the Plan become exercisable as to 25% of the optioned shares each year after the date of grant, except options totaling 500,000 shares awarded to Messrs. Edward Cohen and Jonathan Cohen which are immediately exercisable, and expire not later than ten years after the date of grant.

Additionally, under the Plan, on an annual basis, non-employee directors of the Company are awarded deferred units having a fair market value at the date of grant of $15,000. Each unit represents the right to receive one share of the Company’s common stock upon vesting. The shares vest one-third on the second anniversary of the grant, one-third on the third anniversary of the grant and one-third on the fourth anniversary of the grant. In May 2005 and 2004, 2,485 and 4,835 deferred units, respectively, representing a right to receive a share of common stock over a 4-year vesting period (at an average price of $30.19 and $15.50, respectively, per unit) were awarded to non-employee directors of the Company under this Plan. Units will vest sooner upon a change in control of the Company of death or disability of a grantee, provided the grantee has completed at least six months service. The fair value of the grants awarded ($75,000) in total each year is being charged to operations over the vesting periods. Upon termination of service by a grantee, all unvested units are forfeited.

The following table summarizes certain information about the Plan as of September 30, 2005.

	(a)	(b)	(c)
Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans excluding securities reflected in column (a)
Equity compensation plan approved by security holders	784,820	$        37.85	548,513

Transactions for the Plan are summarized as follows:

71

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 9 - BENEFIT PLANS - (Continued)

	Years ended September 30,
	2005				2004
	Shares		Weighted Average Exercise Price		Shares		Weighted Average Exercise Price
Outstanding - beginning of year		4,835	$	-0-		-
Granted		779,985	$	38.09		4,835	$	-0-
Exercised		-	$	-		-	$	-
Forfeited		-	$	-		-	$	-
Outstanding - end of year		784,820	$	37.85		4,835	$	-0-
Exercisable, at end of year		500,000	$	38.21		-0-	$	-0-
Available for grant		548,513				1,328,498
Weighted average fair value per share of options granted during the year			$	18.85			$	15.50

The following information applies to employee stock options outstanding as of September 30, 2005:

		Outstanding						Exercisable
Range of Exercise prices		Shares		Weighted Average Contractual Life (Years)		Weighted Average Exercise Price		Shares		Weighted Average Exercise Price
$	-0-		7,320		8.96	$	-0-		-0-	$	-0-
$	38.21		777,500		9.75	$	38.21		500,000	$	38.21
			784,820						500,000

Supplemental Employment Retirement Plan (“SERP”). In May 2004, the Company entered into an employment agreement with its Chairman of the Board, Chief Executive Officer and President, Edward E. Cohen, pursuant to which the Company has agreed to provide him with a SERP and with certain financial benefits upon termination of his employment. Under the SERP, Mr. Cohen will be paid an annual benefit equal to the product of (a) 6.5% multiplied by, (b) his base salary at the time of his retirement, death or other termination of employment with the Company, multiplied by, (c) the amount of years he shall be employed by the Company commencing upon the effective date of the SERP agreement, limited to an annual maximum benefit of 65% of his final base salary and a minimum of 26% of his final base salary. During fiscal 2005 and 2004, operations were charged $161,000 and $59,500, respectively, with respect to this commitment.

72

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 9 - BENEFIT PLANS - (Continued)

Atlas Pipeline Plan. Atlas Pipeline has a Long-Term Incentive Plan for officers and non-employee managing board members of its general partner and employees of the general partner, consultants and joint venture partners who perform services for Atlas Pipeline. Atlas Pipeline recognized $3,168,000 in compensation expense related to these grants and their associated distributions for the year ended September 30, 2005. The fair market value associated with these grants was $5.5 million which is amortized into expense over the vesting period of the units.

The following table represents the LTIP phantom unit activity for the periods indicated:

	Years Ended September 30,
	2005			2004
Outstanding, beginning of period	$	58,752		$	-
Granted		67,338			59,598
Performance factor adjusted(1)		82,468			-
Matured		(14,686	)		-
Forfeited		(1,019	)		(846	)
Outstanding, end of period(2)		192,853			58,752
Non-cash compensation expense recognized (in thousands)	$	3,168		$	342

________________

(1) Consist performance-based awards.

(2) Of the units outstanding under the LTIP at September 30, 2005, 31,214 units will vest within the following twelve months.

A summary of the fair market value of equity-based incentive compensation awards of phantom units for the years ended September 30, 2005 and 2004, is listed below (in thousands, except per unit data).

	2005			2004
Incentive compensation awards	$	3,271		$	2,213
Forfeitures		(37	)		(30	)
Total outstanding awards	$	3,234		$	2,183
Weighted average fair-value of phantom units granted	$	48.58		$	37.14

The following table summarizes certain information about Atlas Pipeline’s Long-Term Incentive Plan as of September 30, 2005.

	(a)	(b)	(c)
Plan category	Number of securities to be issued upon exercise of phantom units	Weighted-average exercise price of outstanding phantom units	Number of securities remaining available for future issuance under equity compensation plans excluding securities reflected in column (a)
Equity compensation plans approved by security holders	250,596	$0	167,853

73

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 10 — COMMITMENTS AND CONTINGENCIES

The Company leases office space and equipment under leases with varying expiration dates through 2014. Rental expense was $2.8 million, $1.1 million and $1.6 million for the years ended September 30, 2005, 2004 and 2003, respectively. Future minimum rental commitments for the next five fiscal years are as follows (in thousands):

2006	$	2,148
2007		826
2008		755
2009		320
2010		30

The Company is the managing general partner of various energy partnerships, and has agreed to indemnify each investor partner from any liability that exceeds such partner’s share of partnership assets. Subject to certain conditions, investor partners in certain energy partnerships have the right to present their interests for purchase by the Company, as managing general partner. The Company is not obligated to purchase more than 5% to 10% of the units in any calendar year. Based on past experience, the Company believes that any liability incurred would not be material.

The Company may be required to subordinate a part of its net partnership revenues from its energy partnerships to the receipt by investor partners of cash distributions from the energy partnerships equal to at least 10% of their subscriptions determined on a cumulative basis, in accordance with the terms of the partnership agreements.

The Company is party to employment agreements with certain executives that provide compensation and certain other benefits. The agreements also provide for severance payments under certain circumstances.

The Company is a defendant in a class action originally filed in February 2000 in the New York Supreme Court, Chautauqua County, by individuals, putatively on their own behalf and on behalf of similarly situated individuals, who leased property to the Company. The complaint alleges that the Company is not paying lessors the proper amount of royalty revenues with respect to the natural gas produced from the leased properties. The complaint seeks damages in an unspecified amount for the alleged difference between the amount of royalties actually paid and the amount of royalties that allegedly should have been paid. The action is currently in its discovery stage. The Company believes the complaint is without merit and is defending itself vigorously.

The Company is also a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Company’s financial condition or results of operations.

NOTE 11 — DISCONTINUED OPERATION

In June 2002, the Company adopted a plan to dispose of its 50% interest in Optiron Corporation (“Optiron”), an energy technology subsidiary. The Company subsequently reduced its interest to 10% through a sale to management that was completed in September 2002. In connection with the sale, the Company forgave $4.3 million of the $5.9 million of indebtedness owed by Optiron to the Company. The remaining $1.6 million of indebtedness was retained by the Company in the form of a promissory note secured by all of Optiron’s assets and by the common stock of Optiron’s 90% shareholder. The note bears interest at the prime rate plus 1% payable monthly; an additional 1% will accrue until the maturity date of the note in 2022.

74

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 11 — DISCONTINUED OPERATION - (Continued)

Under the terms of the sale, Optiron was obligated to pay 10% of its revenues to the Company if such revenues exceeded $2.0 million in the twelve month period following the closing of the transaction. As a result, Optiron paid $295,200 to the Company in March 2004.

In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-lived Assets,”, the results of operations have been prepared under the financial reporting requirements for discontinued operations, pursuant to which, all historical results of Optiron are included in the results of discontinued operations rather than the results of continuing operations for all periods presented.

Summarized operating results of the discontinued Optiron operation are as follows:

	Years Ended September 30,
	2005		2004		2003
	(in thousands)
Loss from discontinued operation before taxes	$	-	$	-	$	-
Income tax benefit		-		-		-
Loss from discontinued operations	$	-	$	-	$	-
Income on disposal of discontinued operation before taxes	$	-	$	-	$	295
Income tax (provision)		-		-		(103	)
Income on disposal of discontinued operation	$	-	$	-	$	192
Total gain on discontinued operations	$	-	$	-	$	192

NOTE 12 — OPERATIONS OF ATLAS PIPELINE

In February 2000, the Company’s natural gas gathering operations were sold to Atlas Pipeline in connection with a public offering by Atlas Pipeline of 1,500,000 common units. The Company received net proceeds of $15.3 million for the gathering systems, and Atlas Pipeline issued to the Company 1,641,026 subordinated units then constituting a 51% combined general and limited partner interest in Atlas Pipeline. A subsidiary of the Company is the general partner of Atlas Pipeline and has a 2% general partner interest on a consolidated basis. The Company’s general partner interest also includes a right to receive incentive distributions if the partnership meets or exceeds specified levels of distributions.

In connection with the Company’s sale of the gathering systems to Atlas Pipeline, the Company entered into an agreement that requires it to pay gathering fees to Atlas Pipeline for natural gas gathered by the gathering systems equal to the greater of $.35 per Mcf ($.40 per Mcf in certain instances) or 16% of the gross sales price of the natural gas transported. During fiscal 2005, 2004 and 2003, the fee paid to Atlas Pipeline was calculated based on the 16% rate.

The Company’s subordinated units were a special class of limited partner interest in Atlas Pipeline under which its rights to distributions were subordinated to those of the publicly held common units. In January 2005, these subordinated units were converted to common units as Atlas Pipeline met stipulated financial tests under the terms of the partnership agreement allowing for such conversions. While the Company’s rights as the holder of the subordinated units are no longer subordinated to the rights of the common unitholders, these units have not yet been registered with the Securities and Exchange Commission, and therefore, their resale in the public market is subject to restrictions under the Securities Act.

75

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 12 — OPERATIONS OF ATLAS PIPELINE - (Continued)

In June 2005, Atlas Pipeline completed a public offering of 2,300,000 units, realizing $91.7 million of offering proceeds, net of underwriting discounts, commissions and costs. In connection with this offering, the Company, as the general partner, contributed $1.9 million in order to maintain its 2% general partner interest.

In April and July 2004, Atlas Pipeline completed public offerings of 750,000 and 2,100,000 common units, respectively. The net proceeds after underwriting discounts, commissions and costs were $25.2 million and $67.5 million, respectively.

In May 2003, Atlas Pipeline completed a public offering of 1,092,500 common units of limited partner interest. The net proceeds after underwriting discounts and commissions were approximately $25.2 million. These proceeds were used in part to repay existing indebtedness of $8.5 million.

Upon the completion of these offerings, the Company’s combined general and limited partner interest in Atlas Pipeline was reduced to 18.9% (see Note 16 - Subsequent Events). Because the Company, through its general partner interest, controls the decisions and operations of Atlas Pipeline, Atlas Pipeline is consolidated in the Company’s financial statements.

NOTE 13 - ACQUISITIONS BY ATLAS PIPELINE

Spectrum

On July 16, 2004, Atlas Pipeline acquired Spectrum Field Services, Inc. (“Spectrum”), for approximately $141.6 million, including transaction costs and the payment of taxes due as a result of the transaction. Spectrum’s principal assets included 1,900 miles of natural gas pipelines and a natural gas processing facility in Velma, Oklahoma. The acquisition was accounted for using the purchase method of accounting under SFAS No. 141, “Business Combinations” (“SFAS No. 141”). The following table presents the purchase price allocation, including professional fees and other related acquisition costs, to the assets acquired and liabilities assumed, based on their fair values at the date of acquisition (in thousands):

Cash and cash equivalents	$	803
Accounts receivable		18,505
Prepaid expenses		649
Property, plant and equipment		139,464
Other long-term assets		1,054
Total assets acquired		160,475
Accounts payable and accrued liabilities		(17,153	)
Hedging liabilities		(1,519	)
Long-term debt		(164	)
Total liabilities assumed		(18,836	)
Net assets acquired	$	141,639

76

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 13 - ACQUISITIONS BY ATLAS PIPELINE - (Continued)

Elk City

On April 14, 2005, Atlas Pipeline acquired all of the outstanding equity interests in Elk City, for $196.0 million, including related transaction costs. Elk City’s principal assets included 318 miles of natural gas pipelines located in the Anadarko Basin in western Oklahoma, a natural gas processing facility in Elk City, Oklahoma, with total capacity of 130 million cubic feet of gas per day ("mmcf/d") and a gas treatment facility in Prentiss, Oklahoma, with a total capacity of 100 mmcf/d. The purchase price is subject to post-closing adjustments based upon, among other things, gas imbalances, certain prepaid expenses and capital expenditures, and title defects, if any. The acquisition was accounted for using the purchase method of accounting under SFAS No. 141.

The following table presents the purchase price allocation, including professional fees and other related acquisition costs, to the assets acquired and liabilities assumed, based on their fair values at the date of acquisition (in thousands):

Accounts receivable	$	5,587
Other assets		497
Property, plant and equipment		104,091
Intangible assets		12,890
Goodwill		77,896
Total assets acquired		200,961
Accounts payable and accrued liabilities		(4,970	)
Total liabilities assumed		(4,970	)
Net assets acquired	$	195,991

Due to its recent date of acquisition, the purchase price allocation for Elk City is based upon preliminary data that is subject to adjustment and could change significantly as Atlas Pipeline continues to evaluate this allocation. Atlas Pipeline recognized goodwill in connection with this acquisition as a result of Elk City’s significant cash flow and its strategic industry position. All of the intangible assets, which consist of customer contracts, are subject to amortization and have a weighted-average useful life of 12 years. The goodwill is assigned to the natural gas and liquids segment and is expected to be deductible for tax purposes. The results of the acquisition were included within the consolidated financial statements from its date of acquisition.

The following data presents unaudited pro forma revenues, net income and basic and diluted net income per share of common stock for the Company as if the acquisitions discussed above and the equity offerings in July 2004 and June 2005, the net proceeds of which were utilized to repay debt borrowed to finance the acquisitions (see Note 7), had occurred on October 1, 2003. The Company has prepared these pro forma financial results for comparative purposes only. These pro forma financial results may not be indicative of the results that would have occurred if Atlas Pipeline had completed these acquisitions at the beginning of the periods shown below or the results that will be attained in the future (in thousands except per unit amounts):

77

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 13 - ACQUISITIONS BY ATLAS PIPELINE - (Continued)

	Year Ended September 30, 2005
	As Reported		Pro Forma Adjustments			Pro Forma
Revenues	$	474,511	$	89,279		$	563,790
Net income	$	32,940	$	(1,420	)		31,520
Net income per common shares outstanding - basic:	$	2.47	$	(.11	)	$	2.36
Weighted average common shares - outstanding basic		13,334		-			13,334
Net income per common shares - diluted	$	2.46	$	(.10	)	$	2.36
Weighted average common shares		13,366		-			13,366

	Year Ended September 30, 2004
	As Reported		Pro Forma Adjustments		Pro Forma
Revenues	$	180,088	$	119,854	$	299,942
Net income	$	21,187	$	693	$	21,880
Net income per common shares outstanding - basic	$	1.81	$	.06	$	1.87
Weighted average common shares - outstanding basic		11,683		-		11,683
Net income per common shares - diluted	$	1.81	$	.06	$	1.87
Weighted average common shares		11,684		-		11,684

NOTE 14 — OPERATING SEGMENT INFORMATION AND MAJOR CUSTOMERS

The Company’s operations include four reportable operating segments. In addition to the reportable operating segments, certain other activities are reported in the “Other energy” category. These operating segments reflect the way the Company manages its operations and makes business decisions. The Company does not allocate income taxes to its operating segments. Operating segment data for the periods indicated are as follows:

78

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 14 - OPERATING SEGMENT INFORMATION AND MAJOR CUSTOMERS - (Continued)

Year Ended September 30, 2005 (in thousands):
	Well Drilling		Production and Exploration		Natural Gas and Liquids		Transportation and Compression		Other(a)			Total
Revenues from external customers	$	134,338	$	63,499	$	260,329	$	6,508	$	9,837		$	474,511
Interest income		-		-		60		245		99			404
Interest expense		-		-		80		-		11,387			11,467
Depreciation, depletion and amortization		-		12,288		8,393		2,441		1,773			24,895
Segment profit (loss)		15,634		41,918		15,790		148		(20,532	)		52,958
Capital Expenditures		-		57,894		26,364		13,697		1,230			99,185
Goodwill		6,389		21,527		77,896		2,305		7,249			115,366
Segment assets		8,476		235,039		417,007		63,033		36,156			759,711

Year Ended September 30, 2004 (in thousands):
	Well Drilling		Production and Exploration		Natural Gas and Liquids		Transportation and Compression		Other(a)			Total
Revenues from external customers	$	86,880	$	48,526	$	30,048	$	6,204	$	8,430		$	180,088
Interest income		-		-		-		-		250			250
Interest expense		-		-		3		-		2,878			2,881
Depreciation, depletion and amortization		-		10,319		613		2,024		1,744			14,700
Segment profit (loss)		9,679		28,981		2,069		340		(8,473	)		32,596
Capital Expenditures		-		32,172		595		7,315		1,080			41,162
Goodwill		6,389		21,527		-		2,305		7,249			37,470
Segment assets		8,486		207,302		154,741		36,496		16,684			423,709

Year Ended September 30, 2003 (in thousands):
	Well Drilling		Production and Exploration		Natural Gas and Liquids		Transportation and Compression		Other(a)			Total
Revenues from external customers	$	52,879	$	38,639	$	-	$	5,901	$	7,634		$	105,053
Interest income		-		-		-		-		220			220
Interest expense		-		-		-		-		1,961			1,961
Depreciation, depletion and amortization		-		8,042		-		1,657		1,896			11,595
Segment profit (loss)		5,320		21,280		-		175		(6,298	)		20,477
Capital Expenditures		-		21,334		-		5,421		1,274			28,029
Goodwill		6,389		21,527		-		2,305		7,249			37,470
Segment assets		7,844		167,141		-		30,735		26,668			232,388

79

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 14 - OPERATING SEGMENT INFORMATION AND MAJOR CUSTOMERS - (Continued)

________________

(a) Includes revenues and expenses from well services which does not meet the quantitative threshold for reporting segment information and general corporate expenses not allocable to any particular segment.

Operating profit (loss) per segment represents total revenues less costs and expenses attributable thereto, including interest, provision for possible losses and depreciation, depletion and amortization, excluding general corporate expenses.

The Company’s NGL’s and natural gas are sold under contract to various purchasers. For the year ended September 30, 2005, NGL sales to Koch Hydrocarbon and its successor ONEOK Hydrocarbons Company, accounted for 20% of total revenues. For the years ended September 30, 2004 and 2003, gas sales to Amerada Hess Corporation (formerly FirstEnergy Solutions Corp.) accounted for 11% and 18%, respectively, of total revenues. No other operating segments had revenues from a single customer which exceeded 10% of total revenues.

NOTE 15 − SETTLEMENT OF ALASKA PIPELINE COMPANY ARBITRATION

In September 2003, Atlas Pipeline entered into an agreement with SEMCO Energy, Inc. to purchase all of the stock of Alaska Pipeline Company (“APC”). In order to complete the acquisition, Atlas Pipeline needed the approval of the Regulatory Commission of Alaska. The Regulatory Commission initially approved the transaction, but on June 4, 2004, it vacated its order of approval based upon a motion for clarification or reconsideration filed by SEMCO. On July 1, 2004, SEMCO sent Atlas Pipeline a notice purporting to terminate the transaction. Atlas Pipeline pursued its remedies under the acquisition agreement. In connection with the acquisition, subsequent termination, and settlement of the legal action, Atlas Pipeline incurred costs of approximately $1.2 million in the nine months ended June 30, 2005 which were included in arbitration settlement, net on the Company’s Consolidated Statements of Income. Atlas Pipeline also incurred $3.0 million of costs in the year ended September 30, 2004. On December 30, 2004, Atlas Pipeline entered into an agreement with SEMCO settling all issues and matters related to SEMCO’s termination of the sale of APC to Atlas Pipeline and SEMCO paid Atlas Pipeline $5.5 million which was also included in arbitration settlement, net.

NOTE 16 − SUBSEQUENT EVENTS

Atlas Pipeline’s Acquisition of 75% Interest in NOARK

On October 31, 2005, Atlas Pipeline acquired from Enogex, Inc., a wholly-owned subsidiary of OGE Energy Corp. (NYSE: OGE), of all of the outstanding equity of Atlas Arkansas, which owns a 75% interest in NOARK, for $165.3 million, including estimated related transaction costs, plus $10.2 million for working capital adjustments. The remaining 25% interest in NOARK is owned by Southwestern, a wholly-owned subsidiary of Southwestern Energy Company (NYSE: SWN). Before the closing of the 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 Atlas Pipeline’s 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 Atlas Pipeline’s other businesses and interconnections with major interstate pipelines also provides it with organic growth opportunities. NOARK’s principal assets include:

80

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 16 − SUBSEQUENT EVENTS - (Continued)

• The Ozark Gas Transmission system, a 565-mile FERC-regulated interstate pipeline system which extends from southeast Oklahoma through Arkansas and into southeast Missouri and has a throughout 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.

Atlas Pipeline financed the acquisition by borrowing under its revolving credit facility.

The following table presents the preliminary purchase price allocation, including professional fees and other related acquisition costs, to the assets acquired and liabilities assumed, based on their fair values at the date of acquisition (in thousands):

Cash and cash equivalents	$	9,856
Accounts receivable		4,699
Prepaid expenses		426
Property, plant and equipment		165,300
Total assets acquired		180,281
Accounts payable and accrued liabilities		(4,734	)
Net assets acquired	$	175,547

Due to its recent date of acquisition, the purchase price allocation for NOARK is based upon preliminary data that is subject to adjustment and could change significantly as Atlas Pipeline continues to evaluate this allocation.

Revised Atlas Pipeline Credit Facility

Concurrently with Atlas Pipeline's completion of the NOARK acquisition in October 2005, their facility was increased to $400.0 million. Atlas Pipeline is required to prepay $175.0 million of the credit facility with the net proceeds of any asset sales or issuances of debt or equity. The financial covenants were also amended so that Atlas Pipeline must maintain a ratio of senior secured debt to EBITDA 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 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 of not less than 2.5 to 1.0, increasing to 3.0 to 1.0 on March 31, 2007.

Atlas Pipeline Equity Offering

In November 2005, Atlas Pipeline completed a public offering of 2.7 million common units, realizing net proceeds of $110.0 million, including a $2.3 million capital contribution from us as general partner and after deducting underwriting discounts, commissions and estimated offering expenses of $5.7 million. Atlas Pipeline used the net proceeds of the offering to repay a portion of the amounts outstanding under its credit facility. Our interest in Atlas Pipeline decreased to 15.2% as a result of this offering.

81

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 17 — SUPPLEMENTAL OIL AND GAS INFORMATION

Results of operations from oil and gas producing activities:

	Years Ended September 30,
	2005			2004			2003
	(in thousands)
Revenues	$	63,499		$	48,526		$	38,639
Production costs		(8,166	)		(7,289	)		(6,770	)
Exploration expenses		(904	)		(1,549	)		(1,715	)
Depreciation, depletion and amortization		(12,288	)		(10,319	)		(8,042	)
Income taxes		(15,929	)		(10,279	)		(7,519	)
Results of operations from oil and gas producing activities	$	26,212		$	19,090		$	14,593

Capitalized Costs Related to Oil and Gas Producing Activities. The components of capitalized costs related to the Company's oil and gas producing activities are as follows: 

	At September 30,
	2005			2004			2003
	(in thousands)
Mineral interests:
Proved properties	$	2,852		$	2,544		$	844
Unproved properties		1,002			1,002			563
Wells and related equipment		255,828			184,046			150,657
Support equipment		3,644			2,890			2,185
Uncompleted well equipment and facilities		51			1			51
		263,377			190,483			154,300
Accumulated depreciation, depletion and amortization		(66,536	)		(54,086	)		(43,292	)
Net capitalized costs	$	196,841		$	136,397		$	111,008

Costs Incurred in Oil and Gas Producing Activities. The costs incurred by the Company in its oil and gas activities during fiscal years 2004, 2003 and 2002 are as follows:

	Years Ended September 30,
	2005		2004		2003
	(in thousands)
Property acquisition costs:
Proved properties	$	308	$	1,700	$	412
Unproved properties		-		439		-
Exploration costs		904		1,549		1,715
Development costs		72,308		39,978		28,007
	$	73,520	$	43,666	$	30,134

The development costs above for the years ended September 30, 2005, 2004 and 2003 were substantially all incurred for the development of proved undeveloped properties.

82

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 17 - SUPPLEMENTAL OIL AND GAS INFORMATION - (Continued)

Oil and Gas Reserve Information (Unaudited). The estimates of the Company’s proved and unproved gas reserves are based upon evaluations made by management and verified by Wright & Company, Inc., an independent petroleum engineering firm, as of September 30, 2005, 2004 and 2003. All reserves are located within the United States. Reserves are estimated in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board which require that reserve estimates be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and NGLs which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e. prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

· Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

· Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

· Estimates of proved reserves do not include the following: (a) oil that may become available from known reservoirs but is classified separately as “indicated additional reservoirs”; (b) crude oil, natural gas, and NGLs, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics or economic factors; (c) crude oil, natural gas and NGLs, that may occur in undrilled prospects; and (d) crude oil and natural gas, and NGLs, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operation methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition, the standardized measures of discounted future net cash flows may not represent the fair market value of the Company’s oil and gas reserves or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil and gas prices and in production and development costs and other factors for effects have not been proved.

83

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 17 - SUPPLEMENTAL OIL AND GAS INFORMATION - (Continued)

The Company’s reconciliation of changes in proved reserve quantities is as follows (unaudited):

	Gas			Oil
	(Mcf)			(Bbls)
Balance September 30, 2002		123,221,743			1,877,667
Current additions		27,440,261			44,868
Sales of reserves in-place		(56,480	)		(14,463	)
Purchase of reserves in-place		986,463			18,998
Transfers to limited partnerships		(8,669,521	)		(31,386	)
Revisions		(2,662,812	)		119,038
Production		(6,966,899	)		(160,048	)
Balance September 30, 2003		133,292,755			1,854,674
Current additions		28,761,902			245,509
Sales of reserves in-place		(3,439	)		(1,669	)
Purchase of reserves in-place		232,429			4,000
Transfers to limited partnerships		(10,132,616	)		(29,394	)
Revisions		(2,732,385	)		382,613
Production		(7,285,281	)		(181,021	)
Balance September 30, 2004		142,133,365			2,274,712
Current additions		33,364,097			95,552
Sales of reserves in-place		(226,237	)		(1,010	)
Purchase of reserves in-place		116,934			575
Transfers to limited partnerships		(7,104,731	)		(148,899	)
Revisions		(2,631,044	)		196,263
Production		(7,625,695	)		(157,904	)
Balance September 30, 2005		158,026,689			2,259,289
Proved developed reserves at:
September 30, 2003		87,760,113			1,825,280
September 30, 2004		95,788,656			2,125,813
September 30, 2005		104,786,047			2,116,412

The following schedule presents the standardized measure of estimated discounted future net cash flows relating to proved oil and gas reserves. The estimated future production is priced at fiscal year-end prices, adjusted only for fixed and determinable increases in natural gas and oil prices provided by contractual agreements. The resulting estimated future cash inflows are reduced by estimated future costs to develop and produce the proved reserves based on fiscal year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows are reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at September 30, 2005, 2004 and 2003 and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations (unaudited).

84

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 17 — SUPPLEMENTAL OIL AND GAS INFORMATION - (Continued)

	Years Ended September 30,
	2005			2004			2003
	(in thousands)
Future cash inflows	$	2,503,644		$	1,096,047		$	715,539
Future production costs		(296,015	)		(227,738	)		(185,442	)
Future development costs		(117,256	)		(92,079	)		(72,476	)
Future income tax expense		(607,624	)		(227,862	)		(125,556	)
Future net cash flows		1,482,749			548,368			332,065
Less 10% annual discount for estimated timing of cash flows		(876,052	)		(315,370	)		(187,714	)
Standardized measure of discounted future net cash flows	$	606,697		$	232,998		$	144,351

The future cash flows estimated to be spent to develop proved undeveloped properties in the years ended September 30, 2006, 2007 and 2008 are $45.0 million, $46.0 million and $26.0 million, respectively.

The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves after income taxes (unaudited):

	Years Ended September 30,
	2005			2004			2003
	(in thousands)
Balance, beginning of year	$	232,998		$	144,351		$	104,126
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs		(55,333	)		(41,237	)		(31,869	)
Net changes in prices and production costs		417,798			97,161			44,232
Revisions of previous quantity estimates		(6,073	)		6,265			(229	)
Development costs incurred		4,224			4,838			3,689
Changes in future development costs		(1,577	)		(1,033	)		(166	)
Transfers to limited partnerships		(24,750	)		(9,499	)		(3,313	)
Extensions, discoveries, and improved recovery less related costs		154,215			54,979			24,272
Purchases of reserves in-place		596			594			1,730
Sales of reserves in-place, net of tax effect		(672	)		(33	)		(200	)
Accretion of discount		32,038			19,142			13,247
Net changes in future income taxes		(151,882	)		(40,504	)		(18,749	)
Estimated settlement of asset retirement obligations		(12,763	)		(1,757	)		(3,131	)
Estimated proceeds on disposals of well equipment		12,740			2,055			3,380
Other		5,138			(2,324	)		7,332
Balance, end of year	$	606,697		$	232,998		$	144,351

85

ATLAS AMERICA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SEPTEMBER 30, 2005

NOTE 18 - QUARTERLY RESULTS (Unaudited)

	December 31		March 31		June 30		September 30
	(in thousands, except per share data)
Year ended September 30, 2005
Revenues	$	91,247	$	101,501	$	126,544	$	155,219
Income from continuing operations before income taxes	$	13,894	$	13,307	$	12,013	$	13,744
Net income	$	8,892	$	8,516	$	6,444	$	9,088
Net income per common share - basic and diluted	$	.67	$	.64	$	.48	$	.68

	December 31		March 31		June 30		September 30
Year ended September 30, 2004
Revenues	$	35,691	$	41,749	$	32,837	$	69,811
Income from continuing operations before income taxes	$	7,528	$	7,713	$	6,668	$	10,687
Net income	$	4,893	$	5,166	$	4,182	$	6,946
Net income per common share - basic and diluted	$	.46	$	.48	$	.35	$	.52

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Management’s Report on Internal Control Over Financial Reporting

The management of Atlas America, Inc., is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of management, including our principal executive officers and principal financial officers, we conducted an evaluation of the effectiveness of internal control over financial reporting based upon criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control - Integrated Framework (COSO framework).

An effective internal control system, no matter how well designed, has inherent limitations, including the possibility of human error and circumvention or overriding of controls and therefore can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, effectiveness of an internal control system in future periods can not be guaranteed because the design of any system of internal controls is based in part upon assumptions about the likelihood of future events. There can be no assurance that any control design will succeed in achieving its stated goals under all potential future conditions. Over time certain controls may become inadequate because of changes in business conditions, or the degree of compliance with policies and procedures may deteriorate. As such, misstatements due to error or fraud may occur and not be detected.

86

In conducting our evaluation of the effectiveness of our internal control over financial reporting, for Atlas America, Inc., we excluded from our certification Atlas Pipeline Partner’s (“APL”) operations of newly acquired Elk City from our September 30, 2005, Sarbanes-Oxley 404 review. The Elk City acquisition closed April 2005 and included a 90 days transition services agreement. Consequently APL’s management did not perform full operations of all accounting functions until July 2005. At September 30, 2005, Elk City’s assets were approximately $221 million or 29% of Atlas America, Inc, consolidated total assets of $760 million.  The contribution by Elk City to Atlas America’s net income was approximately $1.7 million for the fiscal year ended September 30, 2005.

Based on our evaluation under the COSO framework, management concluded that internal control over financial reporting was effective as of September 30, 2005. Management's assessment of the effectiveness of internal control over financial reporting as of September 30, 2005, has been audited by Grant Thornton LLP, an independent registered public accounting firm, as stated in their report which is included herein.

87

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors

Atlas America, Inc.

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Atlas America, Inc. (a Delaware corporation) and subsidiaries (“the Company”) maintained effective internal control over financial reporting as of September 30, 2005 based on criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of September 30, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2005, based on criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company and its subsidiaries as of September 30, 2005 and 2004, and related consolidated statements of income, comprehensive income, stockholders’ equity and cash flows for each of the three years in the period ended September 30, 2005, and our report dated December 6, 2005 expressed an unqualified opinion on those financial statements.

/s/ Grant Thornton LLP

Cleveland, Ohio

December 6, 2005

88

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The Board of Directors is divided into three classes with directors in each class serving three year terms. There are no family relationships among the directors and executive officers except that Edward E. Cohen, our Chairman, Chief Executive Officer and President, is the father of Jonathan Z. Cohen, the Vice Chairman of our Board of Directors. Information is set forth below regarding the principal occupation of each of our directors. The following table sets forth information regarding our executive officers and directors:

Name	Age	Position
Edward E. Cohen	66	Chairman, Chief Executive Officer and President
Jonathan Z. Cohen	35	Vice Chairman
Matthew A. Jones	44	Chief Financial Officer
Frank P. Carolas	46	Executive Vice President
Freddie M. Kotek	49	Executive Vice President
Jeffrey C. Simmons	47	Executive Vice President
Michael L. Staines	56	Executive Vice President
Nancy J. McGurk	49	Senior Vice President and Chief Accounting Officer
Carlton M. Arrendell	43	Director
William R. Bagnell	42	Director
Donald W. Delson	54	Director
Nicholas A. DiNubile	53	Director
Dennis A. Holtz	65	Director

Edward E. Cohen has been the Chairman of our Board of Directors, our Chief Executive Officer and Presidentsince our formation in September 2000. He has been Chairman of the Board of Directors of Resource America since 1990 and was its Chief Executive Officer from 1988 until May 2004, and President from September 2000 until October 2003. In addition, Mr. Cohen has been Chairman of the Managing Board of Atlas Pipeline Partners GP, LLC since its formation in November 1999, a director of TRM Corporation (a publicly-traded consumer services company) since June 1998 and Chairman of the Board of Brandywine Construction & Management, Inc. (a property management company) since 1994. Mr. Cohen is the father of Jonathan Z. Cohen.

Jonathan Z. Cohen has been Vice Chairman of our Board of Directors since our formation. He has been the Chief Executive Officer of Resource America since May 2004, President since October 2003 and a director since October 2002. Before being elected Chief Executive Officer, he served as Resource America's Chief Operating Officer from April 2002 to May 2004, Executive Vice President from April 2001 to October 2003 and Senior Vice President from May 1999 to April 2001. Mr. Cohen has been Vice Chairman of the Managing Board of Atlas Pipeline Partners GP since its formation in November 1999, a Trustee and Secretary of RAIT Investment Trust (a publicly-traded real estate investment trust) since 1997 and Vice Chairman since October 2003, and Chairman of the Board of Directors of The Richardson Company (a sales consulting company) since October 1999. Mr. Cohen is a son of Edward E. Cohen.

Matthew A. Jones has been our Chief Financial Officer and that of Atlas Pipeline Partners GP since March 2005. Mr. Jones spent his last nine years with the Investment Banking group at Friedman Billings Ramsey, most recently as Managing Director. For the last five years, Mr. Jones had been with FBR’s Energy Investment Banking Group. Before that, Mr. Jones was with FBR’s Specialty Finance and Real Estate Group. Prior to working at FBR, Mr. Jones held positions with Nationsbank and its predecessors for twelve years in the Commercial and Real Estate Finance Division. Mr. Jones is a Chartered Financial Analyst.

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Frank P. Carolas has been an Executive Vice President since January 2001 and served as a director from January 2002 until February 2004. Mr. Carolas was a Vice President of Resource America from April 2001 until May 2004, and has been Executive Vice President—Land and Geology and a director of Atlas Resources, Inc. (our wholly-owned subsidiary which acts as the managing partner of our drilling partnerships) since January 2001. Mr. Carolas is a certified petroleum geologist and has been employed by Atlas Resources and its affiliates since 1981.

Freddie M. Kotek has been an Executive Vice President since February 2004 and served as a director from September 2001 until February 2004. Mr. Kotek was our Chief Financial Officer from February 2004 until March 2005. Mr. Kotek was a Senior Vice President of Resource America from 1995 until May 2004, President of Resource Leasing, Inc. (a wholly-owned subsidiary of Resource America) from 1995 until May 2004, and has been Chairman of Atlas Resources since September 2001 and Chief Executive Officer and President of Atlas Resources since January 2002.

Jeffrey C. Simmons has been an Executive Vice President since January 2001 and was a director from January 2002 until February 2004. Mr. Simmons has been a Vice President of Resource America from April 2001 until May 2004, and has been Executive Vice President—Operations and a director of Atlas Resources since January 2001. Mr. Simmons joined Resource America in 1986 as a senior petroleum engineer and has served in various executive positions with its energy subsidiaries since then.

Michael L. Staines has been an Executive Vice President since our formation. Mr. Staines was a Senior Vice President of Resource America from 1989 until May 2004, a director from 1989 to February 2000 and Secretary from 1989 to October 1998. Mr. Staines has been President of Atlas Pipeline Partners GP since January 2001 and its Chief Operating Officer and a member of its Managing Board since its formation in November 1999.

Nancy J. McGurk has been our Chief Accounting Officer since January 2001, Senior Vice President since January 2002, and served as our Chief Financial Officer from January 2001 until February 2004. Ms. McGurk was a Vice President of Resource America from 1992 until May 2004, and its Treasurer and Chief Accounting Officer from 1989 until May 2004. Ms. McGurk has been Senior Vice President of Atlas Resources since January 2002 and Chief Financial Officer and Chief Accounting Officer since January 2001.

Independent Directors

The following directors have been determined by our board to be independent directors as defined under NASDAQ rules and the Securities Act.

Carlton M. Arrendell has been a director since February 2004. Mr. Arrendell has been with Investment Trust Corporation (a consultant to the trustee of the AFL-CIO Building Investment Trust) since December 1997 and currently serves as Chief Investment Officer.

William R. Bagnell has been a director since February 2004. Mr. Bagnell has been involved in the energy industry in various capacities since 1990. He has been Vice President—Energy for Planalytics, Inc. (an energy industry software company) since March 2000 and was Director of Sales for Fisher Tank Company (a national manufacturer of carbon and stainless steel bulk storage tanks) from September 1998 to January 2000. Before that, he served as Manager of Business Development for Buckeye Pipeline Partners, L.P. (a refined petroleum products transportation company) from October 1992 until September 1998. Mr. Bagnell served as an independent member of the Managing Board of Atlas Pipeline Partners GP from its formation in November 1999 until May 2004.

Donald W. Delson has been a director since February 2004. Mr. Delson has over 20 years of experience as an investment banker specializing in financial institutions. Mr. Delson has been a Managing Director, Corporate Finance Group, at Keefe, Bruyette & Woods, Inc. since 1997, and before that was a Managing Director in the Corporate Finance Group at Alex. Brown & Sons from 1982 to 1997. Mr. Delson served as an independent member of the Managing Board of Atlas Pipeline Partners GP from June 2003 until May 2004.

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Nicholas A. DiNubile has been a director since February 2004. Dr. DiNubile has been an orthopedic surgeon specializing in sports medicine since 1982. Dr. DiNubile has served as special advisor and medical consultant to the President’s Council on Physical Fitness and as Orthopedic Consultant to the Philadelphia 76ers basketball team. Dr. DiNubile is also Clinical Assistant Professor of the Department of Orthopedic Surgery at the Hospital of the University of Pennsylvania.

Dennis A. Holtz has been a director since February 2004. Mr. Holtz has maintained a corporate law practice with D.A. Holtz, Esquire & Associates in Philadelphia and New Jersey since 1988.

Information Concerning the Audit Committee

Our Board of Directors has a standing Audit Committee. All of the members of the Audit Committee are independent directors as defined by Nasdaq rules. The members of the Audit Committee are Messrs. Arrendell, Bagnell and Delson, with Mr. Arrendell acting as the chairman. Our Board of Directors has determined that Mr. Delson is an “audit committee financial expert,” as defined by SEC rules. The Audit Committee reviews the scope and effectiveness of audits by the independent accountants, is responsible for the engagement of independent accountants and reviews the adequacy of our internal controls.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires our officers, directors and persons who own more than ten percent of a registered class of our equity securities to file reports of ownership and changes in ownership with the SEC and to furnish us with copies of all such reports.

Based solely on our review of the reports we have received, or written representations from certain reporting persons that no filings were required for those persons, we believe that during fiscal 2005 our executive officers, directors and greater than 10% stockholders complied with all applicable filing requirements of Section 16(a) of the Securities Exchange Act, except Mr. E. Cohen inadvertently filed one Form 4 late relating to a transfer of shares from a direct form of ownership to an indirect form of ownership.

Code of Ethics

We have adopted a code of business conduct and ethics applicable to all directors, officers and employees. We believe we meet the definition of a code of ethics under the Securities Act. Our code of business conduct and ethics is also available on our web site atwww.atlasamerica.com.

ITEM 11. EXECUTIVE COMPENSATION

Executive Officer Compensation

The following table sets forth certain information concerning the compensation paid or accrued during each of the last two fiscal years for our Chief Executive Officer and each of our four other most highly compensated executive officers whose aggregate salary and bonus (including amounts of salary and bonus foregone to receive non cash compensation) exceeded $100,000. We were a privately held company until May 10, 2004.

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Summary Compensation Table

							Long-Term Compensation
			Annual Compensation				Awards
Name and Principal Position	Fiscal Year		Salary		Bonus (1)		Restricted Stock Awards(2)		Securities Underlying Options		All Other Compensation (3)
Edward E. Cohen(4) Chairman, Chief Executive Officer and President		2005 2004	$	546,154 401,000	$	800,000 385,000	$	2,345 209,924		300,000 0	$	1,134,200 995,441
Freddie M. Kotek Executive Vice President		2005 2004	$	303,846 267,500	$	300,000 250,000	$	2,345 51,564		40,000 0	$	48,660 6,500
Frank P. Carolas Executive Vice President		2005 2004	$	225,962 192,500	$	125,000 75,000	$	2,345 5,798		30,000 0	$	0 81,357
Jeffrey C. Simmons Executive Vice President		2005 2004	$	225,962 192,500	$	125,000 75,000	$	2,345 102,083		30,000 0	$	0 81,357
Michael L. Staines Executive Vice President		2005 2004	$	225,962 195,500	$	125,000 65,000	$	2,345 99,026		5,000 0	$	194,640 298,000

_____________________

(1) Bonuses in any fiscal year are generally based upon our performance in the prior fiscal year and the individual’s contribution to that performance. From time to time, we may award bonuses in a fiscal year reflecting an individual’s performance during that fiscal year.

(2) Amounts in 2005 reflect allocations of shares to employee accounts under our Employee Stock Ownership Plan (“Atlas ESOP”). Amounts in 2004 reflect allocations of shares to employee accounts under Resource America’s ESOP (“Resource ESOP”) to reconcile shares held to shares which should have been allocated to those accounts in prior years. Share allocations under the Atlas ESOP have been valued at the closing price of our common stock at the end of our fiscal year and share allocations under the Resource ESOP were valued at the closing price of Resource America’s common stock at the end of Resource’s fiscal year. As of September 30, 2005, Messrs. E. Cohen, Kotek, Carolas. Simmons and Staines were fully vested.

(3) Reflects matching payments Resource America made under its 401(k) Plan in 2004 and grants in 2005 and 2004 of phantom units under the Atlas Pipeline Long Term Incentive Plan, valued at the closing price of common units on the respective dates of grants. The amounts set forth for Mr. E. Cohen in fiscal 2005 and 2004 also include $161,000 and $59,500, respectively, of accrued obligations under a Supplemental Employment Retirement Plan established by us in May 2004 in connection with an employment agreement between Mr. E. Cohen and us. See “Employment Agreements.” The phantom unit grants under the Atlas Pipeline Long Term Incentive Plan entitle the recipient, upon vesting, to receive one common unit or its then fair market value in cash and include distribution equivalent rights. The number of phantom units held and the value of those phantom units, valued at the closing market price of Atlas Pipeline common units on September 30, 2005, are: Mr. E. Cohen - 45,000 phantom units ($2,198,250); Mr. Kotek - 1,000 phantom units ($48,850); Mr. Carolas - 2,000 phantom units ($97,700); Mr. Simmons - 2,000 phantom units ($97,700); and Mr. Staines - 12,000 phantom units ($586,200).

(4) Until the completion of our initial public offering in May 2004, we did not directly compensate Mr. E. Cohen. Rather, Resource America allocated his compensation between activities on behalf of us and activities on behalf of Resource America based upon an estimate of the time spent by Mr. E. Cohen on activities for us and for Resource America, and we reimbursed Resource America for the compensation allocated to us. Resource America also similarly allocated compensation for Messrs. E. Cohen, Carolas, Simmons and Staines to Atlas Pipeline.

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Option/SARS Grants and Exercises in Last Fiscal Year and Fiscal Year-End Option Values

The following table provides additional information about the stock options shown in the “Securities Underlying Options” column of the preceding Summary Compensation Table, which were granted in fiscal 2005 to the named executive officers. We did not grant any stock appreciation rights to the named executive officers in fiscal 2005.

Option Grants in Fiscal Year 2005

Name	Number of Securities Underlying Options Granted (1)		Percent of Total Options Granted to Employees in Fiscal 2005			Exercise Price ($/Share)		Expiration Date		Potential Realizable Value at Stock Price Appreciation for Option Term (2)
										@5%		@10%
Edward E. Cohen		300,000		38.6	%	$	38.21		07/01/2015	$	7,209,019	$	18,269,070
Freddie M. Kotek		40,000		5.1	%	$	38.21		07/01/2015		961,203		2,435,876
Frank P. Carolas		30,000		3.9	%	$	38.21		07/01/2015		720,902		1,826,907
Jeffrey C. Simmons		30,000		3.9	%	$	38.21		07/01/2015		720,902		1,826,907
Michael L. Staines		5,000		0.6	%	$	38.21		07/01/2015		120,150		304,484

_________________

(1) All options listed in this table were granted on July 1, 2005 under our Stock Incentive Plan. The options granted to Mr. E. Cohen vested immediately. The options granted to Messrs. Kotek, Carolas, Simmons and Staines vest 25% per year commencing on July 1, 2006.

(2) These assumed rates of appreciation are provided in order to comply with requirements of the Securities and Exchange Commission, and do not represent our estimate or projection as to the actual rate of appreciation of our common stock. The actual value of the options will depend on the performance of our common stock, which may be greater or less than the amounts shown.

The following table sets forth the number of unexercised options and their value on September 30, 2005, held by the named executive officers. No options were exercised and no stock appreciation rights were exercised or held by the named executive officers in fiscal 2005.

Aggregated Option Exercises In Last Fiscal Year

And Fiscal Year-End Option Values

Name	Shares Acquired On Exercise		Value Realized		Number of Securities Underlying Unexercised Options at FY-End Exercisable/ Unexercisable		Value of Unexercised In-the-Money Options at FY-End Exercisable/ Unexercisable (1)
Edward E. Cohen		-		-		300,000/0	$	3,192,000/$0
Freddie M. Kotek		-		-		0/40,000	$	0/$425,600
Frank P. Carolas		-		-		0/30,000	$	0/$319,200
Jeffrey C. Simmons		-		-		0/30,000	$	0/$319,200
Michael L. Staines		-		-		0/5,000	$	0/$53,200

________________

(1) Value is calculated by subtracting the total exercise price from the fair market value of the securities underlying the options at September 30, 2005.

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Employment Agreement

We have an employment agreement with Edward E. Cohen, who currently serves as our Chairman, Chief Executive Officer and President. The agreement requires him to devote such time to us as is reasonably necessary to the fulfillment of his duties, although it permits him to invest and participate in outside business endeavors. The agreement provides for initial base compensation of $350,000 per year, which may be increased by the compensation committee based upon its evaluation of Mr. Cohen's performance. Mr. Cohen is eligible to receive incentive bonuses and stock option grants and to participate in all employee benefit plans in effect during his period of employment. The agreement has a term of three years and, until notice to the contrary, the term is automatically extended so that on any day on which the agreement is in effect it has a then-current three-year term.

The agreement provides for a Supplemental Executive Retirement Plan, or SERP, pursuant to which Mr. Cohen will receive an annual retirement benefit equal to the product of:

· 6.5% multiplied by

· his base salary as of the time Mr. Cohen’s employment with us ceases, multiplied by

· the number of years (or portions thereof) which Mr. Cohen is employed by us.

The maximum benefit under the SERP is limited to 65% of his final base salary. The benefit is guaranteed to his estate for 10 years if he should die before receiving 10 years’ of SERP benefits. If there is a change of control (other than in connection with the proposed spin-off) and his employment with us is terminated, or if we terminate his employment without cause, then the SERP benefit will be the greater of the accrued benefit pursuant to the above formula, or 35% of his final base salary.

The agreement provides the following regarding termination and termination benefits:

· upon termination of employment due to death, Mr. Cohen's estate will receive an amount equal to his final base salary multiplied by the number of years (or portion thereof) that he shall have worked for us (but not to be greater than 3 years’ base salary or less than one year’s base salary);

· we may terminate Mr. Cohen’s employment if he is disabled for 180 days consecutive days during any 12-month period. If his employment is terminated due to disability, he will receive his base salary and benefits for 3 years, and such 3 year period will be deemed a portion of his employment term for purposes of accruing SERP benefits;

· We may terminate his employment without cause upon 30 days’ written notice or upon a change of control after providing at least 30 days’ written notice. He may terminate his employment for good reason or upon a change in control. Good reason is defined as a reduction in his base pay, a demotion, a material reduction in his duties, relocation, his failure to be elected to our Board of Directors or a material breach of the agreement by us. If employment is terminated by us without cause, by Mr. Cohen for good reason or by either party in connection with a change of control, he will be entitled to any amounts then owed to him plus either:

- severance benefits under our then current severance policy, if any, or;

- if Mr. Cohen signs a release, 36 months of continuedhealth insurance coverage and a lump sum payment equal to 3 years of his average compensation (which we define as the average of the 3 highest years of total compensation that he shall have earned under the agreement, or if the agreement is less than three years old, the highest total compensation in any year or portion thereof);

· Mr. Cohen may terminate the agreement without cause with 60 days notice to us, and if he does so after January 1, 2006, and signs a release, he will receive a severance benefit equal to one-half of one year’s base salary then in effect; and

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· we may terminate his employment for cause (defined as a felony conviction or conviction of a crime involving fraud, embezzlement or moral turpitude, intentional and continual failure to perform his material duties after notice, or violation of confidentiality obligations) in which case he will receive only accrued amounts then owed to him.

In the event that any amounts payable to Mr. Cohen upon termination become subject to any excise tax imposed under Section 4999 of the Internal Revenue Code, we must pay Mr. Cohen an additional sum such that the net amounts retained by Mr. Cohen, after payment of excise, income and withholding taxes, equals the termination amounts payable, unless Mr. Cohen’s employment terminates because of his death or disability.

Director Compensation

Each of our independent directors is paid a monthly retainer of $1,000 and a fee of $1,000 for each Board of Directors meeting attended. The chairman of a committee receives an additional monthly retainer of $500 and other committee members receive an additional monthly retainer of $250. In addition, each of our independent directors annually receives deferred units, representing a right to receive a share of our common stock over a four-year vesting period, in an amount equal to $15,000, based on the value of our common stock at the time of the award.

Mr. J. Cohen received $50,000 in fiscal 2005 for his service as Vice Chairman of our Board of Directors. In fiscal 2005, Mr. J. Cohen also received a grant of options to acquire 200,000 shares of common stock at an exercise price of $38.21 per share, which vested immediately, and a grant of 12,500 phantom units under the Atlas Pipeline Long Term Incentive Plan which, upon vesting, entitle Mr. J. Cohen to receive 12,500 common units.

Compensation Committee Interlocks and Insider Participation

The Compensation Committee of the Board of Directors consists of Messrs. Delson, DiNubile and Holtz. There are no Compensation Committee interlocks.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the number and percentage of shares of our common stock owned by beneficial owners of 5% or more of our common stock, by our executive officers and directors and by all of the executive officers and directors as a group as of November 30, 2005. The address for each director and executive officer is 311 Rouser Road, P.O. Box 611, Moon Township, Pennsylvania 15108.

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	Common Stock
Beneficial Owner	Amount and Nature of Beneficial Ownership			Percent of Class
Directors
Carlton M. Arrendell		0			−
William R. Bagnell		0			−
Edward E. Cohen		1,254,817	(1)		9.19	%
Jonathan Z. Cohen		303,963	(2)		2.24	%
Donald W. Delson		0			−
Nicholas A. DiNubile		1,000			*
Dennis A. Holtz		714			*
Non-Director Executive Officers
Frank P. Carolas		18,787			*
Freddie M. Kotek		108,399			*
Matthew A. Jones		48			*
Nancy J. McGurk		59,103			*
Jeffrey C. Simmons		32,825			*
Michael L. Staines		36,599			*
All executive officers and directors as a group (13 persons)		1,788,798			12.91	%
Other Owners of More Than 5% of Outstanding Shares
Cobalt Capital Management, Inc.(3)		1,373,586			10.28	%
Rockbay Capital Advisors, Inc.(4) .		766,996			5.74	%

_________________

* Less than 1%

(1) Includes 14,950 shares held in an individual retirement account of Betsy Z. Cohen, Mr. E. Cohen’s wife (Mr. E. Cohen disclaims beneficial ownership of these shares.); 266,864 shares held by a private charitable foundation of which Mr. E. Cohen serves as co-trustee (Mr. E. Cohen disclaims beneficial ownership of these shares.); and 54,914 shares held in trusts for the benefit of Mr. E. Cohen’s spouse and/or children. (Mr. E. Cohen disclaims beneficial ownership of these shares.) 27,457 of these shares are also included in the shares referred to in footnote 2 below.

(2) Includes 27,457 shares held in a trust of which Mr. J. Cohen is a co-trustee and co-beneficiary. These shares are also included in the shares referred to in footnote 1 above.

(3) This information is based on a Form 4 filed with the SEC on November 22, 2005 reporting beneficial ownership of our common stock. The address for Cobalt Capital Management, Inc. is 237 Park Avenue, Suite 900, New York, New York 10017.

(4) This information is based on a Schedule 13F filed with the SEC reporting beneficial ownership as of September 30, 2005. The address for Rockbay Capital Advisors, Inc. is 1211 Avenue of the Americas, New York, New York 10036-8701.

Equity Compensation Plan Information

The following table summarizes certain information about our compensation plans, in the aggregate, as of September 30, 2005:

	(a)	(b)	(c)
Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans excluding securities reflected in column (a)
Equity compensation plans approved by security holders	784,820	$37.85	548,513

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

In the ordinary course of its business operations, we have ongoing relationships with several related entities:

Relationship with Company Sponsored Partnerships. We conduct certain activities through, and a substantial portion of our revenues are attributable to, energy limited partnerships (“Partnerships”). We serve as general partner of the Partnerships and assume customary rights and obligations for the Partnerships. As the general partner, we are liable for Partnership liabilities and can be liable to limited partners if we breach our responsibilities with respect to the operations of the Partnerships. We are entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Partnerships’ revenue, and costs and expenses according to the respective Partnership agreements.

Relationship with RAI. On June 30, 2005, RAI completed its spin-off of us. We reimburse RAI for various costs and expenses it incurs on our behalf, primarily payroll and rent. For fiscal 2005, these costs totaled $602,000. Certain operating expenditures totaling $111,000 that remain to be settled between the Company and RAI are reflected in the Company’s consolidated balance sheets as advances from affiliate.

RAI’s relationship with Anthem Securities (a wholly- owned subsidiary of ours). Anthem Securities is a wholly-owned subsidiary of ours and a registered broker-dealer which serves as the dealer-manager of investment programs sponsored by RAI's real estate and equipment finance segments. Some of the personnel performing services for Anthem have been paid by RAI, and Anthem reimburses RAI for the allocable costs of such personnel.  In addition, RAI has agreed to cover some of the operating costs for Anthem's office of supervisory jurisdiction, principally licensing fees and costs.  In fiscal 2005, RAI paid $270,000 toward such operating costs of Anthem and Anthem reimbursed RAI $653,000 for the costs allocable to it.

Relationship with Retirement Trust. Upon his retirement, Mr. E. Cohen is entitled to receive payments from a Supplemental Employment Retirement Plan (“SERP”). See “Employment Agreement.”

Relationship with Ledgewood. Until April 1996, Mr. E. Cohen, our Chairman of the Board, Chief Executive Officer and President, was of counsel to Ledgewood, a Philadelphia law firm. Mr. E. Cohen receives certain debt service payments from Ledgewood related to the termination of his affiliation with Ledgewood and its redemption of his interest. We paid Ledgewood $440,300 during fiscal 2005 for legal services rendered.

As part of our initial public offering and spin-off from Resource America, we entered into a tax matters agreement and transition services agreement with Resource America, which govern ongoing relationships between Resource America and us following the completion of our initial public offering.

Tax Matters Agreement

Allocation of Taxes.The tax matters agreement governs the respective rights, responsibilities, and obligations of Resource America and us after our initial public offering with respect to tax liabilities and benefits, tax attributes, tax contests and other matters regarding income taxes, non-income taxes and related tax returns.

In general, under the tax matters agreement:

· Resource America is responsible for any U.S. federal income taxes of the affiliated group for U.S. federal income tax purposes of which Resource America is the common parent. With respect to any periods beginning after our initial public offering, we are responsible for any U.S. federal income taxes attributable to us or any of our subsidiaries.

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· Resource America is responsible for any U.S. state or local income taxes reportable on a consolidated, combined or unitary return that includes Resource America or one of its subsidiaries, on the one hand, and us or one of our subsidiaries, on the other hand. However, in the event that we or one of our subsidiaries are included in such a group for U.S. state or local income tax purposes for periods (or portions thereof) beginning after the date of our initial public offering, we are responsible for our portion of such income tax liability as if we and our subsidiaries had filed a separate tax return that included only us and our subsidiaries for that period (or portion of a period).

· Resource America is responsible for any U.S. state or local income taxes reportable on returns that include only Resource America and its subsidiaries (excluding us and our subsidiaries), and we are responsible for any U.S. state or local income taxes filed on returns that include only us and our subsidiaries.

· Resource America and we are each responsible for any non-income taxes attributable to our business for all periods.

Resource America is primarily responsible for preparing and filing any tax return with respect to the Resource America affiliated group for U.S. federal income tax purposes and with respect to any consolidated, combined or unitary group for U.S. state or local income tax purposes that includes Resource America or any of its subsidiaries. We generally are responsible for preparing and filing any tax returns that include only us and our subsidiaries.

We have generally agreed to indemnify Resource America and its affiliates against any and all tax-related liabilities that may be incurred by them relating to the distribution to the extent such liabilities are caused by our actions. This indemnification applies even if Resource America has permitted us to take an action that would otherwise have been prohibited under the tax-related covenants as described above.

Transition Services Agreement

The transition services agreement governs the provision by Resource America to us and by us to Resource America of support services, such as:

· cash management and debt service administration;

· accounting and tax;

· investor relations;

· payroll and human resources administration;

· legal;

· information technology;

· data processing;

· real estate management; and

· other general administrative functions.

We and Resource America will pay each other a fee for these services equal to their fair market value. The fee will be payable monthly in arrears, 15 days after the close of each month. We have also agreed to pay or reimburse each other for any out-of-pocket payments, costs and expenses associated with these services.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

For the years ended September 30, 2005 and 2004, Grant Thornton LLP’s accounting fees and services (in thousands) were as follows.

	2005		2004
Audit fees(1)	$	888	$	276
Audit-related fees(2)		2		135
Tax fees(3)		-		-
All other fees(4)		-		-
Total accounting fees and services	$	890	$	411

_________________

(1) Audit fees include professional services rendered for the annual audit of our financial statements and for the reviews of the financial statements included in our quarterly reports on Form 10-Q.

(2) Audit related fees of $135,200 for the year ended September 30, 2004 relate primarily to services rendered in connection with our initial public offering in May 2004.

(3) There were no fees for tax services rendered to us during the fiscal years ended September 30, 2005 and 2004.

(4) There were no other fees rendered to us during the fiscal years ended September 30, 2005 and 2004.

Audit Committee Pre-Approval Policies and Procedures

The Audit Committee, on at least an annual basis, reviews audit and non-audit services performed by Grant Thornton, LLP as well as the fees charged by Grant Thornton, LLP for such services. Our policy is that all audit and non-audit services must be pre-approved by the Audit Committee. All of such services and fees were pre-approved during fiscal 2005 and 2004.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)   (1)   Financial Statements

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets at September 30, 2005 and 2004

Consolidated Statements of Operations for the years ended September 30, 2005, 2004 and 2003

Consolidated Statements of Comprehensive Income for the years ended September 30, 2005, 2003 and 2002

Consolidated Statements of Changes in Stockholders' Equity for the years ended

September 30, 2005, 2004 and 2003

Consolidated Statements of Cash Flows for the years ended September 30, 2005, 2004 and 2003

Notes to Consolidated Financial Statements − September 30, 2005

(2) Financial Statement Schedules

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(3) Exhibits:

Exhibit No.		Description
3.1		Amended and Restated Certificate of Incorporation.(1)
3.2		Amended and Restated Bylaws.(1)
10.1		Credit Agreement among Atlas America, Inc., Resource America, Inc., Wachovia Bank, National Association, and other banks party thereto, dated March 12, 2004.(2)
10.1	(a)	First Amendment to Credit Agreement, dated July 10, 2004.(3)
10.1	(b)	Second Amendment to Credit Agreement, dated September 10, 2004.(4)
10.2		Stock Incentive Plan.(3)
10.3		Credit Agreement among Atlas Pipeline Partners, L.P., Wachovia Bank, National Association, and the other parties thereto, dated July 16, 2004.(3)
10.5		Master Separation and Distribution Agreement between Atlas America, Inc. and Resource America, Inc. dated May 14, 2004.(3)
10.6		Registration Rights Agreement between Atlas America, Inc. and Resource America, Inc. dated May 14, 2004.(3)
10.7		Tax Matters Agreement between Atlas America, Inc. and Resource America, Inc. dated May 14, 2004.(3)
10.8		Transition Services Agreement between Atlas America, Inc. and Resource America, Inc. dated May 14, 2004.(3)
10.9		Employment Agreement for Edward E. Cohen dated May 14, 2004.(3)
10.10		Amendment dated October 25,2005 among Atlas America, Inc., Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Resource Energy, Inc., Viking Resources Corporation, Atlas Noble Corporation and Atlas Resources Inc. .(5)
10.11		Atlas America Employee Stock Ownership Plan
10.12		Atlas America, Inc. Investment Savings Plan
21.1		Subsidiaries of Atlas America, Inc.
23.1		Consent of Grant Thorton LLP
31.1		Rule 13(a)-14(a)/15d-14(a) Certification.
31.2		Rule 13(a)-14(a)/15d-14(a) Certification.
32.1		Section 1350 Certification.
32.2		Section 1350 Certification.

                        ______________

(1) Previously filed as an exhibit to our Form 10-Q for the quarter ended March 31, 2004.

(2) Previously filed as an exhibit to our registration statement on Form S-1 on March 17, 2004.

(3) Previously filed as an exhibit to our Form 10-Q for the quarter ended June 30, 2004.

(4) Previously filed as an exhibit to our Form 8-K dated September 10, 2004.

(5) Previously filed as an exhibit to our Form 8-K dated October 31, 2005.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	ATLAS AMERICA, INC.
	(Registrant)
Date: December 15, 2005	By:	/s/ Edward E. Cohen
		Edward E. Cohen
		Chairman, Chief Executive Officer and President

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.

/s/ Edward E. Cohen
Edward E. Cohen	Chairman, Chief Executive Officer and President	December 15, 2005
/s/ Jonathan Z. Cohen
Jonathan Z. Cohen	Vice Chairman	December 15, 2005
/s/ Matthew A. Jones
Matthew A. Jones	Chief Financial Officer	December 15, 2005
/s/ Nancy J. McGurk
Nancy J. McGurk	Senior Vice President and Chief Accounting Officer	December 15, 2005
/s/ Carlton M. Arrendell
Carlton M. Arrendell	Director	December 15, 2005
/s/ William R. Bagnell
William R. Bagnell	Director	December 15, 2005
/s/ Donald W. Delson
Donald W. Delson	Director	December 15, 2005
/s/ Nicholas A. DiNubile
Nicholas A. DiNubile	Director	December 15, 2005
/s/ Dennis A. Holtz
Dennis A. Holtz	Director	December 15, 2005