Atlas Energy Resources S1 IPO registration

Atlas Energy Resources Inactive S-1IPO registration

As filed with the Securities and Exchange Commission on July 28, 2006

Registration No. 333-

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM S-1

REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933

ATLAS ENERGY RESOURCES, LLC

(Exact name of registrant as specified in its charter)

Delaware

1311

75-3218520

(State or other jurisdiction of incorporation or organization)

(Primary Standard Industrial Classification Code Number)

(I.R.S. Employer

Identification No.)

311 Rouser Road

Moon Township, Pennsylvania 15108

(412) 262-2830

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive office)

Edward E. Cohen

Atlas Energy Resources, LLC

311 Rouser Road

Moon Township, Pennsylvania 15108

(412) 262-2830

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Please send copies of communications to:


J. Baur Whittlesey		Thomas P. Mason
Lisa A. Ernst		Catherine S. Gallagher
Ledgewood		Vinson & Elkins L.L.P.
1900 Market Street		1001 Fannin Street
Philadelphia, Pennsylvania 19103		Houston, Texas 77002
(215) 731-9450		(713) 758-2222

Approximate date of commencement of proposed sale to the public: As soon as practicable after this registration statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. ¨

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

Calculation of Registration Fee

Title of each class of

securities to be registered

Proposed maximum aggregate
offering price(1)(2)

Amount of registration
fee(1)

Common units representing Class B limited liability
company interests

138,862,500

14,859

(1)

Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act.

(2)

Includes common units issuable upon exercise of the underwriters’ over-allotment option.

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until this registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.


PROSPECTUS		SUBJECT TO COMPLETION		July 28, 2006

5,750,000 Common Units

[Logo]

ATLAS ENERGY RESOURCES, LLC

Representing Class B Limited Liability Company Interests

This is the initial public offering of our common units. No public market currently exists for our common units. We expect the initial public offering price to be between $ and $ per common unit.

We intend to apply to list our common units on the New York Stock Exchange under the symbol “ .”

Investing in our common units involves risks. Please read “Risk factors” beginning on page 25.

These risks include:

We may not have sufficient cash flow from operations to pay our initial quarterly distribution following the establishment of cash reserves and payment of fees and expenses, including payments to our manager.

If commodity prices decline significantly, our cash flow from operations may decline and we may have to lower our distribution or may not be able to pay distributions at all.

Unless we replace our reserves, our reserves and production will decline, which would reduce our cash flows from operations and impair our ability to make distributions.

Our operations require substantial capital expenditures, which will reduce our cash available for distribution. We may not be able to obtain needed capital or financing on satisfactory terms.

Our fee-based revenues may decline if we are unsuccessful in continuing to sponsor investment partnerships.

Our business depends on gathering and transportation facilities owned by Atlas Pipeline Partners, L.P. Any limitation in the availability of those facilities would interfere with our ability to market the natural gas we produce and could reduce our revenues and cash available for distribution.

Atlas America, Inc. and its affiliates will own a controlling interest in us upon completion of this offering.

Members of our board of directors and Atlas America and its affiliates, including our manager, may have conflicts of interest with us.

Termination by us of our management agreement with our manager is difficult.

You will experience immediate and substantial dilution of $16.25 per common unit.

You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.


	Per Common Unit	Total
Public offering price	$	$
Underwriting discounts and commissions(1)	$	$
Proceeds, before expenses, to us	$	$

(1)

Excludes structuring fee of $ payable to UBS Securities LLC.

The underwriters may also purchase up to an additional 862,500 common units at the public offering price, less the underwriting discounts and commission payable by us, to cover over-allotments, if any, within 30 days from the date of this prospectus. If the underwriters exercise this option in full, the total underwriting discounts and commissions will be $ and our total proceeds, before expenses will be $ .

The underwriters are offering the common units as set forth under “Underwriting.” Delivery of the common units will be made on or about , 2006.

UBS Investment Bank

The date of this prospectus is , 2006

TABLE OF CONTENTS


PROSPECTUS SUMMARY		1
Atlas Energy Resources		1
Business Strategy		6
Competitive Strengths		7
Risk Factors		7
Our LLC Structure		7
The Offering		10
Summary Historical and Pro Forma Financial Data		17
Summary Reserve and Operating Data		20
Non-GAAP Financial Measures		22
RISK FACTORS		25
Risks Inherent in Our Business		25
Risks Inherent in an Investment in Us		37
Tax Risks to Unitholders		42
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS		45
USE OF PROCEEDS		46
CAPITALIZATION		47
DILUTION		48
HOW WE MAKE CASH DISTRIBUTIONS		50
Initial Quarterly Distribution		50
Distributions of Available Cash		50
Operating Surplus and Capital Surplus		50
Distributions of Available Cash from Operating Surplus		54
Management Incentive Interests		54
Percentage Allocations of Available Cash from Operating Surplus		56
Distributions from Capital Surplus		57
Distributions of Cash Upon Liquidation		58
CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS		60
General		60
Our Initial Quarterly Distribution Rate		62
Financial Forecast		63
Estimated Cash Available for Distribution		64
Estimated EBITDA		65
Sensitivity Analysis		70
Unaudited Pro Forma Available Cash for Distributions		71


SELECTED HISTORICAL FINANCIAL DATA		74
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		76
General		76
Comparability of Financial Statements		78
Business Segments		78
General Trends and Outlook		79
Results of Operations		80
Liquidity and Capital Resources		88
Cash Flows		89
Changes in Prices and Inflation		91
Environmental Regulation		91
Dividends		91
Contractual Obligations and Commercial Commitments		92
Critical Accounting Policies		92
Recently Issued Financial Accounting Standards		94
Quantitative and Qualitative Disclosures About Market Risk		95
BUSINESS		98
Overview		98
Business Strategy		99
Competitive Strengths		100
Appalachian Basin Overview		102
Gas and Oil Production		102
Productive Wells		103
Developed and Undeveloped Acreage		104
Drilling Activity		105
Investment Partnerships		105
Tennessee Joint Venture Agreement		106
Natural Gas and Oil Reserves		107
Natural Gas Sales		109
Crude Oil Sales		110
Dismantlement, Restoration, Reclamation and Abandonment Costs		110
Natural Gas Hedging		110
Natural Gas Gathering		111
Availability of Oil Field Services		112


Major Customers		112
Competition		113
Markets		113
Natural Gas and Oil Leases		113
Seasonal Nature of Business		114
Environmental Matters and Regulation		114
Other Regulation of the Natural Gas and Oil Industry		117
Litigation		118
MANAGEMENT		119
Our Board of Directors and Executive Officers		119
Governance Matters		121
Compensation Committee Interlocks and Insider Participation		122
Compensation of Directors		122
Executive Compensation		122
Employment Agreement		123
Atlas Energy Management		124
Officers of Our Manager		124
Other Significant Employees		125
Reimbursement of Expenses of Our Manager and its Affiliates		126
Atlas Energy Resources Long-Term Incentive Plan		126
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS		128
Distributions and Payments to our Manager and Atlas America		128
Agreements Governing the Transactions		129
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES		133
Conflicts of Interest		133
Fiduciary Duties		135
SECURITY OWNERSHIP OF PRINCIPAL BENEFICIAL OWNERS AND MANAGEMENT		136
DESCRIPTION OF THE COMMON UNITS		137
The Common Units		137
Transfer Agent and Registrar		137
Transfer of Common Units		137
OUR LIMITED LIABILITY COMPANY AGREEMENT		139


Organization		139
Purpose		139
Fiduciary Duties		139
Agreement to be Bound by Limited Liability Company Agreement; Power of Attorney		139
Capital Contributions		140
Limited Liability		140
Voting Rights		140
Elimination of Special Voting Rights of Class A Units		141
Issuance of Additional Securities		141
Election of Members of Our Board of Directors		142
Amendment of Our Limited Liability Company Agreement		142
Merger, Sale or Other Disposition of Assets		144
Termination and Dissolution		144
Liquidation and Distribution of Proceeds		144
Anti-Takeover Provisions		145
Limited Call Right		146
Meetings; Voting		146
Non-Citizen Assignees; Redemption		147
Indemnification		147
Books and Reports		148
Right To Inspect Our Books and Records		148
Registration Rights		149
UNITS ELIGIBLE FOR FUTURE SALE		150
MATERIAL TAX CONSEQUENCES		151
Partnership Status		152
Unitholder Status		153
Tax Consequences of Unit Ownership		154
Tax Treatment of Operations		160
Disposition of Common Units		164
Uniformity of Common Units		166
Tax-Exempt Organizations and Other Investors		167
Administrative Matters		168
State, Local and Other Tax Considerations		170
UNDERWRITING		172
LEGAL MATTERS		177


ENGINEERS		177
EXPERTS		177
WHERE YOU CAN FIND MORE INFORMATION		177
INDEX TO FINANCIAL STATEMENTS		F-1


Appendix A – Form of Amended and Restated Limited Liability Company Agreement of Atlas Energy Resources, LLC		A-1
Appendix B – Glossary of Terms		B-1
Appendix C – Reserve Report Summary		C-1

You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, offering to sell our common units or seeking offers to buy our common units in any jurisdiction where offers and sales are not permitted. The information contained in this prospectus is accurate only as of the date on the front cover of this prospectus, regardless of the time of delivery of this prospectus or any sale of the common units offered hereby.

iii

Prospectus summary

This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the historical and pro forma financial statements and the notes to those financial statements. The information presented in this prospectus assumes (1) an initial public offering price of $20.00 per common unit, the mid-point of the price range set forth on the front cover of this prospectus, and (2) that the underwriters do not exercise their option to purchase additional common units.

You should read “Risk factors” beginning on page 25 for information about important factors that you should consider carefully before buying our common units. We include a glossary of some of the industry terms used in this prospectus in Appendix B. The reserve information presented throughout this prospectus, other than in “Management’s discussion and analysis of financial condition and results of operations,” includes only the reserves that Atlas America will contribute to us and does not include all of the reserves of our predecessor, Atlas America E&P Operations. As described under “—Summary Historical and Pro Forma Financial Data,” Atlas America will retain interests in 94 wells formerly owned by Atlas Energy Group, Inc. and which are included in Atlas America E&P Operations. The reserve information presented in “Management’s discussion and analysis of financial condition and results of operations” is that of Atlas America E&P Operations. Wright and Company, Inc., an independent engineering firm, provided the estimates of our proved natural gas and oil reserves as of March 31, 2006 included in this prospectus. A summary prepared by Wright and Company of its reserve report is located at the back of this prospectus as Appendix C, and is referred to in this prospectus as the reserve report. References in this prospectus to “Atlas Energy Resources,” “we,” “our,” “us,” or like terms, when used in an historical context or in the present tense, refer to the subsidiaries that Atlas America will contribute to Atlas Energy Resources in connection with this offering and, when used prospectively, refer to Atlas Energy Resources, LLC and its subsidiaries. References to fiscal 2005 are to Atlas America E&P Operations’ most recent fiscal year end, which was September 30, 2005. Our first fiscal year will end on December 31, 2006. References to “our manager” or “Atlas Energy Management” refer to Atlas Energy Management, Inc.

ATLAS ENERGY RESOURCES

We are a limited liability company focused on the development and production of natural gas and, to a lesser extent, oil principally in the Appalachian Basin. We sponsor and manage tax-advantaged investment partnerships, in which we coinvest, to finance the exploitation and development of our acreage. Our goal is to increase the distributions to our unitholders by continuing to grow the net production from our natural gas and oil production business as well as the fee-based revenues from our partnership management business.

We were formed in June 2006 to own and operate substantially all of the natural gas and oil assets and the investment partnership management business of Atlas America, Inc. (Nasdaq: ATLS). Atlas America has been involved in the energy industry since 1968, expanding its operations in 1998 when it acquired The Atlas Group, Inc. and in 1999 when it acquired Viking Resources Corporation, both engaged in the development and production of natural gas and oil and the sponsorship of investment partnerships.

We are managed by Atlas Energy Management, Inc., a subsidiary of Atlas America. Through our manager, the Atlas America personnel currently responsible for managing our assets and capital raising will continue to do so on our behalf upon completion of this offering.

As of March 31, 2006, our principal assets consisted of:

working interests in 6,114 gross producing gas and oil wells;

overriding royalty interests in 632 gross producing gas and oil wells;

our investment partnership business, which includes equity interests in 91 investment partnerships and a registered broker-dealer which acts as the dealer-manager of our investment partnership offerings;

proved reserves of 170.4 Bcfe, including the reserves net to our equity interest in the investment partnerships and our direct interests in producing wells;

approximately 528,400 gross (476,500 net) acres, primarily in the Appalachian Basin, over half of which, or 274,900 gross (261,500 net) acres, are undeveloped; and

an interest in a joint venture that gives us the right to drill up to 300 net wells before June 30, 2007 on approximately 209,000 acres in Tennessee.

According to Rigdata.com, we were the 9^th most active operator in the United States based on well starts from January 1, 2006 through June 22, 2006. As of March 31, 2006, we had identified approximately 435 proved undeveloped drilling locations and over 2,200 additional potential drilling locations on our acreage and our Tennessee joint venture acreage.

We fund the drilling of natural gas and oil wells on our acreage by sponsoring and managing tax-advantaged investment partnerships. We generally structure our investment partnerships so that, upon formation of a partnership, we coinvest in and contribute leasehold acreage to it, enter into drilling and well operating agreements with it and become its managing general partner.

We derive substantially all of our revenues from our equity interest in the oil and gas produced by the investment partnerships as well as the fees paid by the partnerships to us for acting as the managing general partner as follows:

Gas and oil production. We receive an interest in each investment partnership proportionate to the value of our coinvestment in it and the value of the acreage we contribute to it, typically 27% to 30% of the overall capitalization of a particular partnership. We also receive an incremental interest in each partnership, typically 7%, for which we do not make any additional capital contribution. Consequently, our equity interest in the reserves and production of each partnership is typically between 34% and 37%.

Partnership management. As managing general partner of our investment partnerships, we receive the following fees:

Well construction and completion. For each well that is drilled by an investment partnership, we receive a 15% mark-up on those costs incurred to drill and complete the well.

Administration and oversight. For each well drilled by an investment partnership, we receive a fixed fee of approximately $15,000. Additionally, the partnership pays us a monthly per well administrative fee of $75 for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well.

Well services. Each partnership pays us a monthly per well operating fee, currently $200 to $362, for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well.

Gathering. Historically, each partnership paid us a gathering fee which was typically insufficient to cover all of the gathering fees due to Atlas Pipeline. After the closing of this offering, pursuant to the terms of our contribution agreement with Atlas America, our gathering revenues and costs will net to $0. Please read “Certain relationships and related transactions—Agreements Governing the Transactions—The contribution agreement.”

The following table shows our revenues and gross operating margin and investment partnership and reserves data for the last five fiscal years and the six months ended March 31, 2006.


	Years ended September 30,															Six months ended March 31, 2006
	2001			2002			2003			2004			2005			Six months ended March 31, 2006
	(unaudited)															(unaudited)
Operating results (in thousands):
Revenues:
Gas and oil production	$	36,681		$	28,916		$	38,639		$	48,526		$	63,499		$	46,952
Partnership management:
Well construction and completion		43,464			55,736			52,879			86,880			134,338			93,028
Administration and oversight(1)		—			—			—			—			285			4,482
Well services		7,403			7,585			7,635			8,430			9,552			5,327
Gathering(3)		3,448			3,497			3,898			4,191			4,359			3,694

Total partnership management		54,315			66,818			64,412			99,501			148,534			106,531

Total revenues		90,996			95,734			103,051			148,027			212,033			153,483
Gross operating margin(2):
Gas and oil production		28,849			20,652			30,153			39,688			54,429			38,830
Partnership management:
Well construction and completion		6,862			7,293			6,897			11,332			17,522			12,134
Administration and oversight(1)		—			—			—			—			285			4,482
Well services		4,443			3,838			3,862			4,032			4,385			2,074
Gathering(3)		(9,795	)		(7,307	)		(10,695	)		(13,051	)		(17,622	)		(12,263	)

Total partnership management		1,510			3,824			64			2,313			4,570			6,427

Total gross operating margin(2)		30,359			24,476			30,217			42,001			58,999			45,257
Investment partnership and reserves data:
Funds raised (in millions)	$	44.8		$	41.1		$	66.1		$	107.7		$	148.7		$	52.5
Gross wells completed(4)		258			252			296			505			662			372
Developed acres:
Gross		252,346			265,000			225,800			233,800			245,000			253,500
Net		189,624			194,000			188,500			197,200			206,700			215,000
Undeveloped acres:
Gross		244,124			223,000			205,400			249,800			267,300			274,900
Net		219,482			213,000			190,500			236,000			253,900			261,500
Total acres:
Gross		496,470			488,000			431,200			483,600			512,300			528,400
Net		409,106			407,000			379,000			433,200			460,600			476,500
Total reserves managed (Bcfe) (end of period)		303.6			317.1			332.2			365.1			401.1			397.5	(5)
Proved reserves, net to us (Bcfe) (end of period)		129.0			134.5			144.4			155.8			171.6			170.4	(5)
% natural gas		91.6	%		91.6	%		92.3	%		91.2	%		92.1	%		92.6	%(5)
% proved developed		70.3	%		70.7	%		68.3	%		69.6	%		68.5	%		70.1	%(5)
Production (Mmcfe/d)(6)		20.3			22.3			21.7			22.9			23.5			23.7
Reserves to production ratio (years)		17.4	x		16.5	x		18.2	x		18.6	x		20.0	x		19.8	x(5)(7)

(1)

Administration and oversight represents supervision and administrative fees earned for drilling wells for our investment partnerships. Due to a change in our more recent drilling agreements, beginning in the fourth quarter of fiscal 2005, we classify these fees as revenue. Before then, we classified these fees as reimbursements of our general and administrative costs in accordance with our then existing drilling agreements.

(2)

Please see “—Non-GAAP Financial Measures” for a definition of gross operating margin and a reconciliation of gross operating margin to our net income.

(3)

We charge gathering fees to our investment partnership wells that are connected to Atlas Pipeline’s gathering systems. We in turn pay these fees, plus an additional amount to bring the total gathering charge up to, generally, 16% of the gas sales price, to Atlas Pipeline in accordance with our gathering agreements with it. Upon the completion of this offering, we will not be obligated to pay gathering fees to Atlas Pipeline. We will be obligated to pay the gathering fees we receive from our investment partnerships to Atlas America, with the result that our gathering revenues and expenses will net to $0. We also pay our proportionate share of gathering fees based on our percentage interest in the well, which are included in gas and oil production and exploration expense. We also own several small gathering systems. The expenses associated with these are shown as gathering fees on our combined statements of income. We will not own these gathering systems upon completion of this offering.

(4)

Wells in which we completed drilling during the periods indicated, regardless of when we initiated drilling. See “Business—Drilling activity.”

(5)

Includes only the reserves that Atlas America will contribute to us and does not include all of the reserves of our predecessor, Atlas America E&P Operations. As described under “—Summary Historical and Pro Forma Financial Data,” Atlas America will retain interests in 94 wells formerly owned by Atlas Energy Group and which are included in Atlas America E&P Operations.

(6)

Production quantities consist of the sum of (i) our proportionate share of production from wells in which we have a direct interest, based on our proportionate net revenue interest in such wells, and (ii) our proportionate share of production from wells owned by the investment partnerships in which we have an interest, based on our equity interest in each such partnership and based on each partnership’s proportionate net revenue interest in these wells. All amounts are for Atlas America E&P Operations. Production for the six months ended March 31, 2006 includes volumes associated with the 94 wells which will not be contributed to us.

(7)

Based on annualized production for the six months ended March 31, 2006 of 23.7 Mmcfe/d.

Gas and oil production

Our drilling operations are concentrated in the Appalachian Basin. The Appalachian Basin is a mature producing region with well known geologic characteristics. It is the most mature oil and gas producing region in the United States, having established the first oil production in 1860. Shallow reserves in the Appalachian Basin are typically in blanket formations and have a high degree of step-out development success; that is, as development progresses, reserves from newly completed wells are reclassified from the proved undeveloped to the proved developed category and additional adjacent locations are added to proved undeveloped reserves. As a result, the cumulative amount of total proved reserves tends to increase as development progresses. Wells in the Appalachian Basin generally produce little or no water, contributing to a low cost of operation. In addition, most wells produce dry natural gas, which does not require processing.

In September 2004, we expanded our operations into Tennessee through a joint venture with Knox Energy, LLC that gives us an exclusive right to drill up to 300 net wells before June 30, 2007 on approximately 209,000 acres owned by Knox Energy. As of March 31, 2006, we had identified approximately 435 proved undeveloped drilling locations and over 2,200 additional potential drilling locations on our acreage and our Tennessee joint venture acreage which, based on our drilling activity for the twelve months ended March 31, 2006, represents approximately four years’ worth of drilling site inventory.

Because the Appalachian Basin is located near the energy-consuming regions of the mid-Atlantic and northeastern United States, Appalachian producers have historically sold their natural gas at a premium

to the benchmark price for natural gas on the NYMEX. For the fiscal year ended September 30, 2005, the average premium over NYMEX for natural gas delivered to our primary delivery points in the Appalachian Basin was $0.37 per MMBtu. In addition, most of our natural gas production has a high Btu content, resulting in an additional premium to NYMEX natural gas prices.

Partnership management

We generally fund our drilling activities through sponsorship of tax-advantaged investment partnerships. Accordingly, the amount of development activities we undertake depends in part upon our ability to obtain investor subscriptions to the partnerships. We raised $148.7 million in fiscal 2005. We expect to raise approximately $200.0 million in the twelve months ending September 30, 2006. During fiscal 2005, our investment partnerships invested $157.0 million in drilling and completing wells, of which we contributed $57.3 million.

Our investment partnerships provide tax advantages to their investors because an investor’s share of the partnership’s intangible drilling cost deduction may be used to offset ordinary income. Intangible drilling costs include items that do not have salvage value, such as labor, fuel, repairs, supplies and hauling. Historically, under our partnership agreements, approximately 90% of the subscription proceeds received by each partnership have been used to pay 100% of the partnership’s intangible drilling costs. For example, an investment of $10,000 has generally permitted the investor to deduct approximately $9,000 in the year in which the investor invests.

Natural gas hedging

We seek to provide greater stability in our cash flows through our use of financial hedges and forward sales transactions. 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 36 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 management 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. As of March 31, 2006, we had financial hedges and forward sales in place for approximately 61% of our expected production for the twelve months ending June 30, 2007.

BUSINESS STRATEGY

The key elements of our business strategy are:

Expand our gas and oil production through continued growth in our sponsorship of investment partnerships. We generate a significant portion of our revenue and net income from gas and oil production. We believe our program of sponsoring investment partnerships to exploit our acreage position provides us with a better economic return than if we were to drill the wells for our own account outside of our partnership management business. From October 1, 1998 through September 30, 2005, we sponsored 13 private and 7 public investment partnerships, and increased the annual amount of capital raised through investment partnerships by approximately 840% from $15.7 million in fiscal 1999 to $148.7 million in fiscal 2005. We intend to continue to finance the growth in our drilling and production activities through growth in our investment partnerships.

Expand our fee-based revenue through continued growth in our sponsorship of investment partnerships. We generate substantial revenue and net income from fees paid by the investment partnerships to us for acting as the managing general partner.As we continue to sponsor investment partnerships, we expect that our fee revenues from our drilling and operating agreements with our investment partnerships will continue to increase.

Expand operations through strategic acquisitions. We continually evaluate opportunities to expand our operations through acquisitions of developed and undeveloped properties or companies that can increase our cash available for distribution. We will continue to seek strategic opportunities in our current areas of operation, as well as other regions of the United States.

Expand the number of our drilling locations in the Appalachian Basin through an active leasing program and joint ventures. We have approximately 274,900 gross (261,500 net) undeveloped acres, principally in the Appalachian Basin, which we believe offer significant, low risk exploitation-type drilling opportunities. In addition, we are party to a joint venture agreement that encompasses approximately 209,000 acres in Tennessee and entitles us to drill 300 net wells through June 30, 2007. As of March 31, 2006, we had identified an inventory of approximately 435 proved undeveloped drilling locations and over 2,200 additional potential drilling locations on our acreage and our Tennessee joint venture acreage. Over the past three fiscal years, we drilled 1,463 wells, 98% of which were successful in producing natural gas in commercial quantities. We intend to continue to develop this acreage, which, due to the generally high degree of step-out development success, should continue to add drilling locations to our inventory. Between July 2003 and March 2006, we added 140,388 net acres to our inventory. In addition, we will continue to pursue farmouts and joint venture opportunities from other oil and gas producers that can significantly add to our inventory of drilling locations.

Maintain control of operations. We believe it is important to be the operator of wells in which we or our investment partnerships have an interest because we believe it will allow us to achieve operating efficiencies and control costs. Upon completion of this offering, we will continue to be the operator of approximately 85% of the properties in which we or our investment partnerships had a working interest at March 31, 2006.

Continue to manage our exposure to commodity price risk. To limit our exposure to changing natural gas prices, we use financial hedges and forward sales transactions, or physical hedges, for a portion of our natural gas production. We use fixed price swaps as the mechanism for the financial hedging of our natural gas commodity prices. We enter into forward sales contracts with Hess Corporation and other third-party marketers to which we sell gas. As of March 31, 2006, we had financial hedges and forward sales in place for approximately 61% of our expected production for the twelve months ending June 30, 2007.

COMPETITIVE STRENGTHS

We believe our competitive strengths favorably position us to execute our business strategy and to maintain and grow our distributions to unitholders. Our competitive strengths are:

Our partnership management business improves the economic rates of return associated with our gas and oil production activities.

Fee-based revenues from our investment partnerships provide a stable foundation for our distributions.

We are a leading sponsor of tax-advantaged investment partnerships.

We have a high quality, long-lived reserve base.

We have a significant inventory of future drilling locations and undeveloped acreage.

We have long-standing relationships with regional drilling contractors, service providers and equipment vendors.

Our relationship with Atlas Pipeline gives us reliable access to the markets we serve and reduces capital expenditures we would otherwise incur.

Through our manager, we have significant engineering, geologic and management experience in our core Appalachian Basin operating area.

RISK FACTORS

An investment in our common units involves risks associated with our business, regulatory and legal matters, our limited liability company structure and the tax characteristics of our common units. Please carefully read “Risk factors” immediately following this section beginning on page 25.

THE TRANSACTIONS AND OUR LLC STRUCTURE

General. We were formed in June 2006 as a Delaware limited liability company to own and operate the natural gas and oil assets and the investment partnership management business of Atlas America. Our operations will be conducted through, and our operating assets will be owned by, subsidiary entities.We will have no significant assets other than our interest in our subsidiaries.

Contribution of Assets by Atlas America. At the closing of this offering, Atlas America will contribute to us the stock of its natural gas and oil development and production subsidiaries. Before the closing, some of these subsidiaries will distribute to Atlas America, and thus we will not acquire, interests in 94 wells formerly owned by Atlas Energy Group, Inc. and a small gathering system. We anticipate paying the net proceeds of this offering, after payment of offering expenses, to Atlas America as reimbursement of capital expenditures incurred by it on our behalf and partial consideration for its contribution of assets to us.

Our Management. We will enter into a management agreement with Atlas Energy Management pursuant to which it will be responsible for managing our day-to-day operations, subject to the supervision and direction of our board of directors. Neither we nor our manager will directly employ any of the persons responsible for our management or operations. Rather, personnel of Atlas America currently involved in managing our assets will manage and operate our business. Atlas Energy Management will be entitled to distributions on our Class A units and management incentive interests. For more information about our management, please read “Management” and “Certain relationships and related transactions.”

Units Outstanding after this Offering. After giving effect to this offering and the related formation transactions:

Atlas America will own 27,550,000 common units, representing approximately an 81.0% membership interest in us;

Richard D. Weber, our President, Chief Operating Officer and a director, will own approximately 50,000 common units, representing approximately a 0.1% membership interest in us;

Atlas Energy Management will own 680,612 Class A units, representing an aggregate 2.0% membership interest in us, and all of the management incentive interests; and

the public unitholders will own 5,750,000 common units, representing approximately an aggregate 16.9% membership interest in us.

We will use any net proceeds from the exercise of the underwriters’ over-allotment option to redeem from Atlas America the number of common units equal to the number of common units issued upon the exercise of the underwriters’ over-allotment option. If the underwriters’ over-allotment option is exercised in full, Atlas America’s ownership will be reduced to 26,687,500 common units, or approximately 78.4% of our membership interests, and the ownership interest of the public unitholders will increase to 6,612,500 common units, or approximately 19.4% of our membership interests.

Principal Executive Offices and Internet Address. Our principal executive offices are located at 311 Rouser Road, Moon Township, Pennsylvania 15108 and our telephone number is (412) 262-2830. Our internet address is .

Organizational Chart. The following chart shows the organization and ownership of Atlas Energy Resources and its subsidiaries after giving effect to this offering and the related transactions.

LOGO

(1)

Pursuant to his employment agreement with Atlas America, Richard D. Weber will receive a number of our common units determined by dividing $1.0 million by the initial public offering price of our common units upon completion of this offering. Amount shown is based on assumed offering price at the mid-point of the range shown on the front cover of this prospectus. These units are subject to forfeiture, vesting 25% on each anniversary of April 17, 2006.

The offering

Units offered

5,750,000 common units; 6,612,500 common units if the underwriters exercise their over-allotment option in full.

Units outstanding after this offering

33,350,000 common units; and 680,612 Class A units which will be owned by our manager.

Use of proceeds

The following table sets forth the estimated sources and uses of the funds we expect to receive from the sale of common units in this offering and related transactions. The actual sources and uses of these funds may differ from those set forth below. Please read “Use of proceeds.”


Sources of funds:
Estimated proceeds, net of estimated underwriting discounts and commissions and offering expenses, received from this offering(1)		$	105.5 million


Uses of funds:
Distribution to Atlas America(1)(2)		$	100.5 million
Working capital	��	$	5.0 million

		$	105.5 million

(1)

Assumes the mid-point of the price range set forth on the cover page of this prospectus.

(2)

If the initial public offering price exceeds the mid-point of the price range, we will distribute the excess net proceeds to Atlas America. If the initial public offering price is less than the mid-point of the price range, we will reduce the payment to Atlas America in an amount equal to the reduction in net proceeds. The distribution constitutes a reimbursement of capital expenditures incurred by Atlas America on our behalf and partial consideration for its contribution of assets to us.

We will use the net proceeds from any exercise of the underwriters’ over-allotment option to purchase additional common units to redeem an equal number of common units from Atlas America.

Cash distributions

We intend to make an initial quarterly distribution, or IQD, of $0.40 per common unit to the extent we have sufficient available cash from operations after we establish appropriate cash reserves and pay fees and expenses, including payments to our manager for reimbursement of costs and expenses it incurs on our behalf. We refer to this cash as “available cash,” and we define its meaning in more detail in our limited liability company agreement found in Appendix A and in “How we make cash distributions—Distributions of Available Cash—Definition of available cash.” Our board of directors has broad discretion in establishing reserves. The cash reserves that our board of directors may establish include reserves for future cash distributions on the common units, Class A units and management incentive interests. These reserves, which could be substantial, will reduce the amount of cash available for distribution to you.

Our board of directors has adopted a policy that it will raise our quarterly cash distribution only when it believes that we have sufficient reserves and liquidity for the proper conduct of our business, including the maintenance of our asset base, and can maintain the increased distribution level for a sustained period. While this is our current policy, our board of directors may alter the policy in the future. Our limited liability company agreement requires that, within 45 days after the end of each calendar quarter beginning with the quarter ending September 30, 2006, we distribute all of our available cash to holders of record of our units on the applicable record date.

We will adjust IQD for the period from the closing of this offering through September 30, 2006, based on the actual length of the period.

The amount of available cash in any quarter may be greater or less than the aggregate amount associated with payment of the IQD on all our common units.

In general, we will pay any cash distributions we make in the following manner:

first, 98% to the holders of our common units and 2% to the holder of our Class A units, pro rata, until each unitholder has received $0.46

per unit, which we refer to as the First Target Distribution; and

after that, any amount distributed with respect to any quarter in excess of the First Target Distribution will be distributed 98% to the holders of our common units, pro rata, and 2% to the holder of our Class A units until distributions become payable with respect to our management incentive interests as described under “Management incentive interests” below.

The holder of our Class A units, initially our manager, will be entitled to 2% of our cash distributions without any obligation to make future capital contributions to us.

Management incentive interests

We refer to a distribution with respect to the management incentive interests as a “management incentive distribution.” Our manager will initially hold all of the management incentive interests. The table below summarizes the cash distributions attributable to common units, Class A units, and the management incentive interests.


	Quarterly distribution level	Marginal % interest in distributions
	Quarterly distribution level	Class A units		Common units		Management incentive interests
IQD	$0.40	2.0	%	98.0	%	0.0	%

First Target Distribution per unit	above $0.40 up to $0.46	2.0	%	98.0	%	0.0	%

Second Target Distribution per unit	above $0.46 up to $0.56	2.0	%	83.0	%	15.0	%

After that	above $0.56	2.0	%	73.0	%	25.0	%

We will make management incentive payments to our manager if two tests are met.

The first test is the 12-Quarter Test, which requires that for the 12 full, consecutive, non-overlapping calendar quarters that begin with the first calendar quarter for which we pay per unit cash distributions from operating surplus to holders of Class A and common units in an amount equal to or greater than the First Target Distribution, which period we refer to as the Incentive Trigger Period:

we pay cash distributions from operating surplus to holders of our outstanding Class A and common units in an amount that on average exceeds the First Target Distribution on all of the outstanding Class A units and common units over the Incentive Trigger Period;

we generate adjusted operating surplus, which is defined in “How we make cash distributions,” during the Incentive Trigger Period that on average is in an amount at least equal to all cash distributions on the outstanding Class A and common units plus the amount of any management incentive distributions that would have been payable if both the 12-Quarter Test and 4-Quarter Test were met; and

we do not reduce the amount distributed per unit for any of the 12 quarters.

The second test is the 4-Quarter Test, which requires that for each of (i) the last four full, consecutive, non-overlapping calendar quarters in the Incentive Trigger Period, or (ii) in any four full, consecutive and non-overlapping quarters occurring after such last four quarters in the Incentive Trigger Period, provided that we have paid at least the IQD in each calendar quarter occurring between the end of the Incentive Trigger Period and the beginning of the four full, consecutive and non-overlapping quarters that satisfy the 4-Quarter Test, or (iii) in any four full, consecutive and non-overlapping quarters occurring partially within and partially after such last four quarters of the Incentive Trigger Period:

we pay cash distributions from operating surplus to the holders of our outstanding Class A and common units that exceed the First Target Distribution;

we do not reduce the amount distributed per unit for any of the four quarters.

If both tests have been met, then:

We will make a one-time management incentive distribution to the holder of our management

incentive interests, at the same time that we pay the distribution to our Class A and common units for the last calendar quarter in the 4-Quarter Test, equal to the cumulative amount of the management incentive distributions that would have been paid based on the level of distributions made on our Class A and common units during the Incentive Trigger Period if the management incentive distributions were payable on a quarterly basis rather than after completion of the Incentive Trigger Period.

For each calendar quarter after the two tests are satisfied:

the holder of our Class A units will receive 2%, the holders of our common units will receive 83% and the holder of our management incentive interests will receive 15% of cash distributions from available cash from operating surplus that we pay for the quarter in excess of the First Target Distribution up to $0.56, which we refer to as the Second Target Distribution; and

the holder of our Class A units will receive 2%, the holders of our common units will receive 73% and the holder of our management incentive interests will receive 25% of cash distributions from available cash from operating surplus that we pay for the quarter in excess of the Second Target Distribution.

For a further discussion of the management incentive interests, please read the information set forth under the caption “How we make cash distributions—Management Incentive Interests.”

Pro forma and expected ability to pay the IQD

We believe, based on the assumptions and considerations included under the caption “Cash distribution policy and restrictions on distributions,” that we will have sufficient cash available for distribution to enable us to pay the IQD of $0.40 on all of the common units and Class A units for each quarter for the twelve months ending June 30, 2007. If we had completed this offering and the related transactions on October 1, 2004, the amount of pro forma available cash generated during the fiscal year ended September 30, 2005 would have been

insufficient by approximately $43.9 million to pay the IQD on all of our common units and Class A units. If we had completed this offering and the related transactions on April 1, 2005, the amount of pro forma available cash generated during the twelve months ended March 31, 2006 would have been insufficient by approximately $36.0 million to pay the full IQD. For a calculation of our ability to make distributions to you based on our pro forma results for the fiscal year ended September 30, 2005 and the twelve months ended March 31, 2006, please read “Cash distribution policy and restrictions on distributions.”

Issuance of additional units

We can issue an unlimited number of additional units without the consent of our unitholders. Please read “Risk factors—Risks Inherent in an Investment in Us—We may issue additional units without your approval, which would dilute your existing ownership interests,” “Units eligible for future sale” and “Our limited liability company agreement—Issuance of Additional Securities.”

Agreement to be bound by limited liability company agreement; common unit voting rights

By purchasing a common unit, you will be admitted as a member of our limited liability company and be deemed to have agreed to be bound by all of the terms of our limited liability company agreement. Pursuant to our limited liability company agreement, as a common unitholder you will be entitled to vote on the following matters:

annual election of the members of our board of directors;

specified amendments to our limited liability company agreement;

merger of our company or the sale of all or substantially all of our assets; and

dissolution of our company.

Atlas America and its affiliates will own approximately 82.6% of our common units and all of our Class A units upon completion of this offering. This will give Atlas America the ability to determine virtually all matters submitted to a unitholder vote.

Management agreement

Our management agreement with Atlas Energy Management provides for the day-to-day management of our operations and requires Atlas Energy Management to manage our business affairs in conformity with the policies that are approved and monitored by our board of directors. Our manager’s services are under the supervision and direction of our board of directors.

The management agreement does not have a specified term, however, our manager may not terminate the management agreement before its tenth anniversary. We may terminate the management agreement upon the affirmative vote of the holders of at least two-thirds of our outstanding common units, including units held by Atlas America and its affiliates.

Limitations on common unitholder actions

Our limited liability company agreement prohibits common unitholders from taking unitholder action by written consent and nullifies the common unitholder voting rights of any person other than Atlas America or its affiliates that holds 20% or more of our outstanding common units.

Limited call right

Estimated ratio of taxable income to distributions

We estimate that if you hold the common units that you purchase in this offering through the record date for distributions for the period ending December 31, , you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than % of the cash distributed to you with respect to that period. Please read “Material tax consequences—Tax Consequences of Unit Ownership” for the basis of this estimate.

Material tax consequences

For discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individuals or citizens of the United States, please read “Material tax consequences.”

Exchange listing and trading symbol

We intend to apply to list our common units on the New York Stock Exchange under the symbol “ .”

SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA

The following table sets forth summary historical combined financial and operating data for our predecessor, Atlas America E & P Operations, and pro forma financial data for Atlas Energy Resources, LLC, as of and for the periods indicated. Atlas America E & P Operations are the subsidiaries of Atlas America which hold its natural gas and oil development and production assets and liabilities, substantially all of which Atlas America will transfer to us upon the completion of this offering. We derived the historical financial data as of September 30, 2004 and 2005 and for the years ended September 30, 2003, 2004 and 2005 from Atlas America E & P Operations’ financial statements, which were audited by Grant Thornton LLP, independent registered public accounting firm, and are included in this prospectus. We derived the historical financial data for the six months ended March 31, 2005 and 2006 and the balance sheet information as of March 31, 2006 from Atlas America E & P Operations’ unaudited financial statements included in this prospectus.

The summary pro forma financial data for the year ended September 30, 2005 and six months ended March 31, 2006 are derived from the unaudited pro forma financial statements of Atlas Energy Resources, LLC included in this prospectus. The pro forma adjustments have been prepared as if the transactions listed below had taken place on March 31, 2006, in the case of the pro forma balance sheet, or as of October 1, 2004, in the case of the pro forma statements of income. These transactions include:

the retention by Atlas America of interests in 94 wells formerly owned by Atlas Energy Group and their related accounts receivable and asset retirement obligations and the operations associated with a small gathering system;

the completion of this offering and the application of the net proceeds therefrom as described in “Use of proceeds;” and

the execution of the contribution agreement described under “Certain relationships and related transactions—Agreements Governing the Transactions—The Contribution Agreement,” pursuant to which Atlas America will assume our obligation to pay gathering fees to Atlas Pipeline.

You should read the following summary financial data in conjunction with “Management’s discussion and analysis of financial condition and results of operations” and our financial statements and related notes appearing elsewhere in this prospectus. You should also read the pro forma information together with the unaudited pro forma financial statements and related notes included elsewhere in this prospectus.

The following table includes the non-GAAP financial measures of EBITDA and gross operating margin. For a definition of the measures and a reconciliation to their most directly comparable financial measures calculated and presented in accordance with generally accepted accounting principles, which we refer to as GAAP, please read “—Non-GAAP Financial Measures.”


	Predecessor historical															Atlas Energy Resources pro forma
	Years ended September 30,									Six months ended March 31,						Year ended September 30, 2005			Six months ended March 31, 2006
	2003			2004			2005			2005			2006			Year ended September 30, 2005			Six months ended March 31, 2006
										(unaudited)						(unaudited)
	(in thousands)
Income statement data:
Revenues:
Gas and oil production	$	38,639		$	48,526		$	63,499		$	28,618		$	46,952		$	63,211		$	46,762
Partnership management:
Well construction and completion		52,879			86,880			134,338			72,009			93,028			134,338			93,028
Administration and oversight(1)		—			—			285			—			4,482			285			4,482
Well services		7,635			8,430			9,552			4,598			5,327			9,552			5,327
Gathering		3,898			4,191			4,359			2,058			3,694			4,359			3,694

Total revenues		103,051			148,027			212,033			107,283			153,483			211,745			153,293
Operating costs:
Gas and oil production and exploration		8,486			8,838			9,070			4,215			8,122			9,016			8,095
Partnership management:
Well construction and completion		45,982			75,548			116,816			62,617			80,894			116,816			80,894
Administration and oversight(1)		—			—			—			—			—			—			—
Well services		3,773			4,398			5,167			2,507			3,253			5,167			3,253
Gathering		29			53			52			27			133			—			—
Gathering fee—Atlas America		14,564			17,189			21,929			10,302			15,824			4,359			3,694

Total operating costs		72,834			106,026			153,034			79,668			108,226			135,358			95,936
Gross operating margin:
Gas and oil production		30,153			39,688			54,429			24,403			38,830			54,195			38,667
Partnership management:
Well construction and completion		6,897			11,332			17,522			9,392			12,134			17,522			12,134
Administration and oversight(1)		—			—			285			—			4,482			285			4,482
Well services		3,862			4,032			4,385			2,091			2,074			4,385			2,074
Gathering		(10,695	)		(13,051	)		(17,622	)		(8,271	)		(12,263	)		—			—

Total gross operating margin		30,217			42,001			58,999			27,615			45,257			76,387			57,357
Other income (expense):
General and administrative expense(1)		(3,300	)		(1,763	)		(2,992	)		680			(8,984	)		(3,756	)		(9,241	)
Compensation reimbursement—affiliate		(1,400	)		(1,050	)		(602	)		(457	)		(578	)		(602	)		(578	)
Depreciation, depletion and amortization		(9,938	)		(12,064	)		(14,061	)		(6,385	)		(9,576	)		(14,016	)		(9,553	)
Interest		—			—			—			—			—			(2,910	)		(1,954	)
Other—net		358			444			79			61			171			79			171

Net income	$	15,937		$	27,568		$	41,423		$	21,514		$	26,290		$	55,182		$	36,202

Other financial information (unaudited):
EBITDA	$	25,875		$	39,632		$	55,484		$	27,899		$	35,866		$	72,108		$	47,709


	Predecessor historical															Atlas Energy Resources pro forma
	As of and for the years ended September 30,									As of and for six months ended March 31,						Atlas Energy Resources pro forma
	2003			2004			2005			2005			2006			March 31, 2006
										(unaudited)						(unaudited)
	(in thousands)
Cash flow data:
Cash provided by operating activities	$	26,120		$	34,821		$	87,875		$	55,919		$	31,026
Cash used in investing activities		(22,112	)		(32,709	)		(59,050	)		(28,966	)		(32,352	)
Cash provided by (used in) financing activities		(5,721	)		(7,214	)		(22,751	)		(19,758	)		90
Capital expenditures		22,607			33,252			59,124			29,064			32,477
Balance sheet data (at period end):
Total assets	$	178,451		$	198,454		$	270,402		$	232,349		$	316,652		$	320,767
Liabilities associated with drilling contracts		22,157			29,375			60,971			23,060			24,862			24,862
Advances from affiliates		34,776			30,008			13,897			48,436			51,798			—
Long term debt, including current portion		194			420			81			110			134			51,396	(2)
Total debt		34,970			30,428			13,978			48,546			51,932			51,396
Combined equity		102,031			109,461			146,142			128,274			163,745			168,745

(1)

Administration and oversight represents supervision and administrative fees earned for drilling wells for our investment partnerships. Due to a change in our more recent drilling agreements, beginning in the fourth quarter of fiscal 2005 we classify administrative and oversight fees as revenue. Before then, we classified these fees as reimbursements of our general and administrative costs in accordance with our then existing drilling agreements.

(2)

Reflects pro forma borrowings under our proposed credit facility to repay advances from affiliates. After March 31, 2006, and before completion of this offering, we anticipate repaying these amounts with cash proceeds from our most recently formed investment partnership which will not yet have been applied to the drilling and completion of wells.

SUMMARY RESERVE AND OPERATING DATA

The following tables show estimated net proved reserves of Atlas America E&P Operations and Atlas Energy Resources, based on reserve reports prepared by our independent petroleum engineers, and certain summary unaudited information with respect to production and sales of natural gas and oil related to Atlas America E&P Operations. You should refer to “Risk factors,” “Management’s discussion and analysis of financial condition and results of operations,” “Business—Natural Gas and Oil Reserves” and the summary reserve report included as Appendix C in this prospectus in evaluating the material presented below. The following table includes the non-GAAP financial measure of PV-10. For a reconciliation of PV-10 to standardized measure, its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “—Non-GAAP Financial Measures.”


	Atlas America E&P Operations as of September 30,						Pro forma Atlas Energy Resources as of March 31, 2006
	2004			2005			Pro forma Atlas Energy Resources as of March 31, 2006
Reserve data:
Estimated net proved reserves:
Natural gas (Bcf)		142.1			158.0			157.8
Oil (MMBbls)		2.3			2.3			2.1
Total (Bcfe)		155.8			171.6			170.4
Proved developed (Bcfe)		108.5			117.5			119.5
Proved undeveloped (Bcfe)		47.3			54.1			50.9
Proved developed reserves as % of total proved reserves		69.6	%		68.5	%		70.1	%
PV-10 value (in millions)(1)	$	320.4		$	845.7		$	410.4
Standardized measure (in millions)(1)	$	233.0		$	606.7		$	410.4
Weighted average reserve natural gas and oil prices(2):
Natural gas—per Mcf	$	6.91		$	14.75		$	8.04
Oil—per Bbl	$	46.00		$	63.29		$	63.52


	Atlas America E&P Operations
	Years ended September 30,				Six months ended March 31,
	2004		2005		2005		2006
Net production:
Total production (Mmcfe)		8,371		8,573		4,071		4,319
Average daily production (Mcfe/d)		22,875		23,490		22,368		23,732
Average natural gas sales prices per Mcf:
Average sales prices (including hedges)	$	5.84	$	7.26	$	6.93	$	10.99
Average sales prices (excluding hedges)	$	5.84	$	7.26	$	6.93	$	10.24
Average oil sales prices per Bbl:
Average sales prices	$	32.85	$	50.91	$	46.18	$	59.07
Average unit costs per Mcfe:
Production costs(3)	$	0.63	$	0.71	$	0.71	$	0.84
Depletion	$	1.22	$	1.42	$	1.34	$	2.00

(1)

administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. Standardized measure is the present value of estimated future cash inflows from proved natural gas and oil reserves, less future development and production costs and future income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes. Amounts shown for September 30, 2004 and 2005 reflect values for Atlas America E&P Operations, which pay income taxes. Amounts shown for March 31, 2006 reflect values for the reserves of Atlas Energy Resources on a pro forma basis to reflect the contribution of assets of Atlas America to Atlas Energy Resources at the closing of this offering, excluding 94 wells that will be retained by Atlas America. Since we are a limited liability company that allocates our taxable income to our unitholders, no provision for federal or state income taxes has been included in the March 31, 2006 calculation of standardized measure, which is, therefore, the same as the PV-10 value. Amounts shown include forward sales but not financial hedging transactions. We estimate that if natural gas prices decline by $1.00 per Mcf, then the PV-10 value of our proved reserves as of March 31, 2006 would decrease from $410.4 million to $346.9 million. For a description of our hedging transactions, please read “Business—Natural Gas Hedging.”

(2)

Natural gas and oil prices were based on NYMEX prices per Mcf and Bbl at the applicable date, with the representative price of natural gas adjusted for basis premium and Btu content to arrive at the appropriate net price. Amounts shown include forward sales but not financial hedging transactions.

(3)

Excludes charges for gathering fees.

NON-GAAP FINANCIAL MEASURES

We include in this prospectus the non-GAAP financial measures of EBITDA, gross operating margin and PV-10. We provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with GAAP.

EBITDA

We define EBITDA as earnings before interest, taxes, depreciation, depletion and amortization. EBITDA is not a measure of performance calculated in accordance with 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 may be different from the EBITDA calculation under our credit facility. In addition, EBITDA does not represent funds available for discretionary use. The following reconciles EBITDA to our net income for the periods indicated:


	Predecessor historical														Atlas Energy Resources pro forma
	Years ended September 30,										Six months ended March 31,				Year ended September 30,		Six months ended March 31,
	2001		2002		2003		2004		2005		2005		2006		2005		2006
	(unaudited)										(unaudited)				(unaudited)
	(in thousands)
Net income	$	13,532	$	11,197	$	15,937	$	27,568	$	41,423	$	21,514	$	26,290	$	55,182	$	36,202
Plus interest expense		—		—		—		—		—		—		—		2,910		1,954
Plus depreciation, depletion and amortization		9,594		9,409		9,938		12,064		14,061		6,385		9,576		14,016		9,553

EBITDA	$	23,126	$	20,606	$	25,875	$	39,632	$	55,484	$	27,899	$	35,866	$	72,108	$	47,709

Gross operating margin

We define gross operating margin as total operating revenues less total related operating costs for each of our operating segments. Our gross operating margin equals the sum of our gas and oil production and partnership management segments’ gross margins. We include gross operating margin as a supplemental disclosure because it represents the aggregate results of our operating segments. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross operating margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross operating margin in the same manner. The following reconciles gross operating margin to our net income for the periods indicated:


	Predecessor historical																					Atlas Energy Resources pro forma
	Years ended September 30,															Six months ended March 31,						Year ended September 30, 2005			Six months ended March 31, 2006
	2001			2002			2003			2004			2005			2005			2006			Year ended September 30, 2005			Six months ended March 31, 2006

	(unaudited)															(unaudited)						(unaudited)
	(in thousands)
Gross operating margin:
Gas and oil production	$	28,849		$	20,652		$	30,153		$	39,688		$	54,429		$	24,403		$	38,830		$	54,195		$	38,667
Partnership management:
Well construction and completion		6,862			7,293			6,897			11,332			17,522			9,392			12,134			17,522			12,134
Administration and oversight		—			—			—			—			285			—			4,482			285			4,482
Well services		4,443			3,838			3,862			4,032			4,385			2,091			2,074			4,385			2,074
Gathering		(9,795	)		(7,307	)		(10,695	)		(13,051	)		(17,622	)		(8,271	)		(12,263	)		—			—

Total partnership management		1,510			3,824			64			2,313			4,570			3,212			6,427			22,192			18,690

Total gross operating margin		30,359			24,476			30,217			42,001			58,999			27,615			45,257			76,387			57,357
Less general and administrative expense		(7,280	)		(4,240	)		(3,300	)		(1,763	)		(2,992	)		680			(8,984	)		(3,756	)		(9,241	)
Less compensation reimbursement—affiliate		(1,150	)		(1,181	)		(1,400	)		(1,050	)		(602	)		(457	)		(578	)		(602	)		(578	)
Less depreciation, depletion and amortization		(9,594	)		(9,409	)		(9,938	)		(12,064	)		(14,061	)		(6,385	)		(9,576	)		(14,016	)		(9,553	)
Less interest expense		—			—			—			—			—			—			—			(2,910	)		(1,954	)
Plus other—net		1,197			1,551			358			444			79			61			171			79			171

Net income	$	13,532		$	11,197		$	15,937		$	27,568		$	41,423		$	21,514		$	26,290		$	55,182		$	36,202

PV-10

PV-10 is the present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to financial hedging activities (but including our forward sales), non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. Standardized measure is the present value of estimated future cash inflows from proved natural gas and oil reserves, less future development and production costs and future income tax expenses,

discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.

PV-10 may be considered a non-GAAP measure by the SEC. We believe the presentation of the PV-10 value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves before taking into account future corporate income taxes for which we will not liable. Our PV-10 values as of September 30, 2004 and 2005 reflect values for Atlas America E & P Operations, which pay income taxes. Amounts shown for March 31, 2006 reflect values for our reserves. Since we are a limited liability company that allocates our taxable income to our unitholders, no provision for federal or state income taxes has been included in the March 31, 2006 calculation of standardized measure, which is, therefore, the same as the PV-10 value. We further believe investors and creditors utilize our PV-10 value as a basis for comparison of the relative size and value of our reserves to other companies. Neither PV-10 value nor standardized measure reflect the impact of financial hedging transactions. The following reconciles the PV-10 value to the standardized measure (in millions):


	Atlas America E&P Operations as of September 30,						Pro forma Atlas Energy Resources as of March 31, 2006
	2004			2005			Pro forma Atlas Energy Resources as of March 31, 2006
PV-10 value	$	320.4		$	845.7		$	410.4
Income tax effect		(87.4	)		(239.0	)		0

Standardized measure	$	233.0		$	606.7		$	410.4

Risk factors

Member interests in a limited liability company are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should consider carefully the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units. If any of the events described below were to occur, our business, financial condition, results of operations and cash flows could be materially adversely affected. In that case, we may not be able to pay the IQD or make future cash distributions on our common units, the trading price of our common units could decline and you could lose part or all of your investment in our company.

RISKS INHERENT IN OUR BUSINESS

We may not have sufficient cash flow from operations to pay the IQD following the establishment of cash reserves and payment of fees and expenses, including payments to our manager.

We may not have sufficient cash flow from operations each quarter to pay the IQD. Under the terms of our limited liability company agreement, the amount of cash otherwise available for distribution will be reduced by our operating expenses and the amount of any cash reserve amounts that our board of directors establishes to provide for future operations, future capital expenditures, future debt service requirements and future cash distributions to our unitholders and the holders of the management incentive interests. The amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

the amount of natural gas and oil we produce;

the price at which we sell our natural gas and oil;

the level of our operating costs;

our ability to acquire, locate and produce new reserves;

results of our hedging activities;

the level of our interest expense, which depends on the amount of our indebtedness and the interest payable on it; and

the level of our capital expenditures.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

our ability to make working capital borrowings to pay distributions;

the cost of acquisitions, if any;

fluctuations in our working capital needs;

timing and collectibility of receivables;

restrictions on distributions imposed by lenders;

payments to our manager;

Risk factors

the amount of our estimated maintenance capital expenditures;

prevailing economic conditions; and

the amount of cash reserves established by our board of directors for the proper conduct of our business.

As a result of these factors, the amount of cash we distribute in any quarter to our unitholders may fluctuate significantly from quarter to quarter and may be significantly less than the IQD amount that we expect to distribute.

We would not have generated sufficient available cash on a pro forma basis to have paid the IQD on all of our outstanding common units and Class A units for the fiscal year ended September 30, 2005 and the twelve months ended March 31, 2006.

The amount of available cash we will need to pay the IQD for four quarters on the common units and Class A units to be outstanding immediately after this offering is approximately $54.4 million. If we had completed the transactions contemplated in this prospectus on October 1, 2004, pro forma available cash generated during the fiscal year ended September 30, 2005 would have been approximately $10.6 million, which would have been sufficient to allow us to pay approximately 19% of the IQD on our common units and Class A units during this period. If we had completed the transactions on April 1, 2005, pro forma available cash generated during the twelve months ended March 31, 2006 would have been approximately $18.4 million, which would have been sufficient to allow us to pay approximately 34% of our IQD on our common units and Class A units during this period. For a calculation of our ability to make distributions to you based on our pro forma results for the fiscal year ended September 30, 2005 and the twelve months ended March 31, 2006, please read “Cash distribution policy and restrictions on distributions.”

If we are unable to achieve the estimated EBITDA set forth in “Cash distribution policy and restrictions on distributions,” we may be unable to pay the full, or any, amount of the IQD on the common units, in which event the market price of our common units may decline substantially.

The estimated EBITDA set forth in “Cash distribution policy and restrictions on distributions” is for the twelve month period ending June 30, 2007. Our management has prepared this information and we have not received an opinion or report on it from any independent accountants. In addition, “Cash distribution policy and restrictions on distributions” includes a calculation of estimated EBITDA. The assumptions underlying this calculation are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those expected. If we do not achieve the expected results, we may not be able to pay the full, or any, amount of the IQD, in which event the market price of our common units may decline substantially.

If commodity prices decline significantly, our cash flow from operations will decline and we may have to lower our distribution or may not be able to pay distributions at all.

Our revenue, profitability and cash flow substantially depend upon the prices and demand for natural gas and oil. The natural gas and oil markets are very volatile and a drop in prices can significantly affect our financial results and impede our growth. Changes in natural gas and oil prices will have a significant impact on the value of our reserves and on our cash flow. Prices for natural gas and oil may fluctuate

Risk factors

widely in response to relatively minor changes in the supply of and demand for natural gas or oil, market uncertainty and a variety of additional factors that are beyond our control, such as:

the level of the domestic and foreign supply and demand;

the price and level of foreign imports;

the level of consumer product demand;

weather conditions and fluctuating and seasonal demand;

overall domestic and global economic conditions;

political and economic conditions in natural gas and oil producing countries, including those in the Middle East and South America;

the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

the impact of the U.S. dollar exchange rates on natural gas and oil prices;

technological advances affecting energy consumption;

domestic and foreign governmental relations, regulations and taxation;

the impact of energy conservation efforts;

the cost, proximity and capacity of natural gas pipelines and other transportation facilities; and

the price and availability of alternative fuels.

In the past, the prices of natural gas and oil have been extremely volatile, and we expect this volatility to continue. For example, during the three months ended March 31, 2006, the NYMEX Henry Hub natural gas index price ranged from a high of $9.87 per MMBtu to a low of $6.31 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $68.35 per Bbl to a low of $57.65 per Bbl.

Lower natural gas and oil prices may not only decrease our revenues, but also reduce the amount of natural gas and oil that we can produce economically, which would also decrease our revenues.

Unless we replace our reserves, our reserves and production will decline, which would reduce our cash flow from operations and impair our ability to make distributions to our unitholders.

Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Based on our March 31, 2006 reserve report, our average annual decline rate for proved developed producing reserves is approximately 11% during the first five years, approximately 6% in the next five years and less than 7% thereafter. Because total estimated proved reserves include proved undeveloped reserves at March 31, 2006, production will decline at this rate even if those proved undeveloped reserves are developed and the wells produce as expected. This rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can change when we drill additional wells, make acquisitions and under other circumstances. Thus, our future natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. Our ability to find and acquire additional recoverable reserves to replace current and future production at acceptable costs depends on our generating sufficient cash flow from operations and other sources of capital, principally

Risk factors

our sponsored investment partnerships, all of which are subject to the risks discussed elsewhere in this section.

Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Underground accumulations of natural gas and oil cannot be measured in an exact way. Natural gas and oil reserve engineering requires subjective estimates of underground accumulations of natural gas and oil and assumptions concerning future natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Our independent petroleum engineers prepare estimates of our proved reserves. Over time, our internal engineers may make material changes to reserve estimates taking into account the results of actual drilling and production. Some of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, we make certain assumptions regarding future natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions by actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of natural gas and oil attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. For example, if natural gas prices decline by $1.00 per Mcf, then the PV-10 value of our proved reserves as of March 31, 2006 would decrease from $410.4 million to $346.9 million. Our PV-10 is calculated using natural gas prices that include our forward sales but not our financial hedges. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of natural gas and oil we ultimately recover being different from our reserve estimates.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on prices and costs in effect on the day of estimate. However, actual future net cash flows from our natural gas properties also will be affected by factors such as:

actual prices we receive for natural gas;

the amount and timing of actual production;

the amount and timing of our capital expenditures;

supply of and demand for natural gas; and

changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

Any significant variance in our assumptions could materially affect the quantity and value of reserves, the amount of PV-10 described in this prospectus, and our financial condition and results of operations. In addition, our reserves or PV-10 may be revised downward or upward based upon production history,

Risk factors

results of future exploitation and development activities, prevailing natural gas and oil prices and other factors. A material decline in prices paid for our production can reduce the estimated volumes of our reserves because the economic life of our wells could end sooner. Similarly, a decline in market prices for natural gas or oil may reduce our PV-10. Any of these negative effects on our reserves or PV-10 may decrease the value of our common units.

Our operations require substantial capital expenditures, which will reduce our cash available for distribution. In addition, each quarter we are required to deduct estimated maintenance capital expenditures from operating surplus, which may result in less cash available to unitholders than if actual maintenance capital expenditures were deducted.

We will need to make substantial capital expenditures to maintain our capital asset base over the long term. These maintenance capital expenditures may include the drilling and completion of additional wells to offset the production decline from our producing properties or additions to our inventory of unproved or proved reserves. These expenditures could increase as a result of:

changes in our reserves;

changes in natural gas prices;

changes in labor and drilling costs;

our ability to acquire, locate and produce reserves;

changes in leasehold acquisition costs; and

government regulations relating to safety and the environment.

Our significant maintenance capital expenditures will reduce the amount of cash we have available for distribution to our unitholders. In addition, our actual maintenance capital expenditures will vary from quarter to quarter. Our limited liability company agreement requires us to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus will be subject to review and approval by our board of directors, including a majority of our conflicts committee, at least once a year. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders will be lower than if we deducted actual maintenance capital expenditures from operating surplus. If we underestimate the appropriate level of estimated maintenance capital expenditures, we may have less cash available for distribution in future periods when actual capital expenditures begin to exceed our previous estimates. Over time, if we do not set aside sufficient cash reserves or have available sufficient sources of financing and make sufficient expenditures to maintain our capital asset base, we will be unable to pay distributions at the anticipated level and may have to reduce our distributions.

We will be required to make substantial capital expenditures to increase our asset base. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to make cash distributions may be diminished.

The natural gas and oil industry is capital intensive. We intend to finance our future capital expenditures with capital raised through our sponsored investment partnerships, cash flow from operations and bank borrowings. In particular, our forecast of cash available for distribution for the twelve month period ending June 30, 2007 assumes that we will raise $211.0 million from third parties through our investment partnerships. This amount of capital is significantly more than the $148.7 million we raised

Risk factors

during fiscal 2005 and significantly more than the average annual amount of $107.5 million we raised for the last three fiscal years. If we are unable to obtain sufficient capital funds on satisfactory terms, we may be unable to increase or maintain our inventory of properties and reserve base, or be forced to curtail drilling or other activities. This would result in a decline in our revenues and our ability to increase cash distributions may be diminished. If we do not make sufficient or effective expansion capital expenditures, including with funds from third-party sources, we will be unable to expand our business operations and will be unable to raise the level of our future cash distributions.

Changes in tax laws may impair our ability to obtain capital funds through investment partnerships.

Under current federal tax laws, there are tax benefits to investing in 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 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 investment partnerships relatively less attractive than investments in assets likely to yield capital gains or qualifying dividends.

Our proposed credit facility will have substantial restrictions and financial covenants. A default under these provisions could cause all of our debt to be immediately due and restrict our payment of distributions to our unitholders.

We anticipate that our proposed revolving credit facility will restrict our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. We will also likely be required to comply with specified financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the credit facility could result in a default, which could cause our existing indebtedness to be immediately due and restrict our payment of distributions to our unitholders.

Our future debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.

Following this offering, we anticipate that we will have the ability to borrow $ million under our proposed credit facility, subject to borrowing base limitations in the credit agreement. Our future indebtedness could have important consequences to us, including:

our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

covenants contained in our credit arrangements will likely require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders; and

Risk factors

our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all.

We may not be able to continue to raise funds through our investment partnerships at the levels we have recently experienced, which may in turn restrict our ability to maintain our drilling activity at the levels recently experienced.

We have sponsored limited and general partnerships to raise funds from investors to finance our development drilling activities. Accordingly, the amount of development activities we undertake depends in large part upon our ability to obtain investor subscriptions to invest in these partnerships. During the past three fiscal years we have raised successively larger amounts of funds through these investment partnerships, raising $66.1 million in 2003, $107.7 million in 2004 and $148.7 million in 2005. In the future, we may not be successful in raising funds through these investment partnerships at the same levels we have recently experienced, and we also may not be successful in increasing the amount of funds we raise as we have done in recent years. Our ability to raise funds through our investment partnerships depends in large part upon the perception of investors of their potential return on their investment and their tax benefits from investing in them, which perception is influenced significantly by our historical track record of generating returns and tax benefits to the investors in our existing partnerships.

In the event that our investment partnerships do not achieve satisfactory returns on investment or the anticipated tax benefits, we may have difficulty in continuing to increase the amount of funds we raise through these partnerships or in maintaining the level of funds we have recently raised through these partnerships. In this event, we may need to obtain financing for our drilling activities on a less attractive basis than the financing we realize through these partnerships or we may determine to reduce our drilling activity.

Our fee-based revenues may decline if we are unsuccessful in continuing to sponsor investment partnerships, and our fee-based revenue may not increase at the same rate as recently experienced if we are unable to raise funds at the same or higher levels than we have recently experienced.

Our fee-based revenues are based on the number of investment partnerships we sponsor and the number of partnerships and wells we manage or operate. If we are unsuccessful in sponsoring future investment partnerships, our fee-based revenues may decline. In addition, our fee-based revenue may not increase at the same rate as recently experienced if we are unable to raise funds at the same or higher levels than we have recently experienced.

Competition in the natural gas and oil industry is intense, which may hinder our ability to acquire gas and oil properties and companies and to obtain capital, contract for drilling equipment and secure trained personnel.

We operate in a highly competitive environment for acquiring properties and other natural gas and oil companies, attracting capital through our investment partnerships, contracting for drilling equipment

Risk factors

and securing trained personnel. For example, the Pennsylvania Bureau of Oil and Gas Management estimates that there were 747 well operators bonded in Pennsylvania, one of our core operating areas, in 2005. We will 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 drilling equipment 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. All of these challenges could make it more difficult for us to execute our growth strategy. We may not be able to compete successfully in the future in acquiring leasehold acreage or prospective reserves or in raising additional capital.

Furthermore, 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.

Our business depends on the gathering and transportation facilities of Atlas Pipeline. Any limitation in the availability of those facilities would interfere with our ability to market the natural gas we produce and could reduce our revenues and cash available for distribution.

Atlas Pipeline gathers more than 90% of our current production. The marketability of our natural gas production depends in part on the availability, proximity and capacity of gathering and pipeline systems owned by Atlas Pipeline and other third parties. The amount of natural gas that can be produced and sold is subject to curtailment in circumstances such as pipeline interruptions due to scheduled and unscheduled maintenance or excessive pressure or physical damage to the gathering or transportation system. The curtailments arising from these and similar circumstances may last from a few days to several months.

We depend on certain key customers for sales of our natural gas. To the extent these customers reduce the volumes of natural gas they purchase from us, our revenues and cash available for distribution could decline.

Our natural gas is sold under contracts with various purchasers. Under a natural gas supply agreement with Hess Corporation, which expires on December 31, 2008, Hess Corporation has a last right of refusal to buy all of the natural gas produced and delivered by us and our affiliates, including our investment partnerships. During fiscal 2005, natural gas sales to Hess Corporation accounted for 13% of our total revenues, and during the six months ended March 31, 2006, Hess Corporation accounted for 11% of our total revenues. To the extent Hess Corporation and our other key customers reduce the amount of natural gas they purchase from us, our revenues and cash available for distributions to unitholders could temporarily decline in the event we are unable to sell to additional purchasers.

Shortages of drilling rigs, equipment and crews could delay our operations and reduce our cash available for distribution.

Higher natural gas and oil prices generally increase the demand for drilling rigs, equipment and crews and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Shortages of, or increasing costs for, experienced drilling crews and oil field equipment and services

Risk factors

could restrict our ability to drill the wells and conduct the operations which we currently have planned. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues and cash available for distribution.

Because we handle natural gas and oil, we may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment.

The operations of our wells and other facilities are subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example:

the federal Clean Air Act and comparable state laws and regulations that impose obligations related to air emissions;

the federal Clean Water Act and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated bodies of water;

the federal Resource Conservation and Recovery Act, or RCRA, and comparable state laws that impose requirements for the handling and disposal of waste from our facilities; and

the Comprehensive Environmental Response, Compensation and Liability Act of 1980, or CERCLA, also known as “Superfund,” and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which we have sent waste for disposal.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including the RCRA, CERCLA, the federal Oil Pollution Act and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

There is an inherent risk that we may incur environmental costs and liabilities due to the nature of our business and the substances we handle. For example, an accidental release from one of our wells could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies may be enacted or adopted and could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover remediation costs under our insurance policies. Please read “Business — Environmental Matters and Regulation.”

Many of our leases are in areas that have been partially depleted or drained by offset wells.

Our key project areas are located in active drilling areas in the Appalachian Basin. As a result, many of our leases are in areas that have already been partially depleted or drained by earlier offset drilling. This may inhibit our ability to find economically recoverable quantities of natural gas in these areas.

Risk factors

Our identified drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, resulting in temporarily lower cash from operations, which may impact our ability to pay distributions.

Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. As of March 31, 2006, we had identified 435 proved undeveloped drilling locations and over 2,200 additional potential drilling locations. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, natural gas prices, costs and drilling results. In addition, Wright and Company, Inc. has not assigned any proved reserves to the over 2,200 unproved potential drilling locations we have identified and therefore there may exist greater uncertainty with respect to the success of drilling wells at these drilling locations. Our final determination on whether to drill any of these drilling locations will be dependent upon the factors described above as well as, to some degree, the results of our drilling activities with respect to our proved drilling locations. Because of these uncertainties, we do not know if the numerous drilling locations we have identified will be drilled within our expected timeframe or will ever be drilled or if we will be able to produce natural gas and oil from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified. In the event that we are unable to continue to identify drilling locations that we believe will provide us attractive development opportunities in sufficient quantities to support our growth plans, we may be required to reduce the amount of funds raised through our investment partnerships, which in turn would result in a reduction in the fee-based revenue that we would otherwise realize.

Some of our undeveloped leasehold acreage is subject to leases that may expire in the near future.

Leases covering approximately 16,500 of our 476,500 net acres, or 3.5%, are scheduled to expire on or before June 30, 2007. If we are unable to renew these leases, or any leases scheduled for expiration beyond June 30, 2007, on favorable terms, we will lose the right to develop the acreage that is covered by an expired lease and our production would decline, which would reduce our cash flows from operations and could impair our ability to make distributions.

Drilling for and producing natural gas are high risk activities with many uncertainties.

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for natural gas can be uneconomic, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

the high cost, shortages or delivery delays of equipment and services;

unexpected operational events and drilling conditions;

adverse weather conditions;

facility or equipment malfunctions;

title problems;

pipeline ruptures or spills;

Risk factors

compliance with environmental and other governmental requirements;

unusual or unexpected geological formations;

formations with abnormal pressures;

injury or loss of life;

environmental accidents such as gas leaks, ruptures or discharges of toxic gases, brine or well fluids into the environment or oil leaks, including groundwater contamination;

fires, blowouts, craterings and explosions; and

uncontrollable flows of natural gas or well fluids.

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 investment partnerships, which may make it more difficult to finance our drilling operations through sponsorship of future partnerships. In addition, any of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties.

Although we will maintain insurance against various losses and liabilities arising from our operations, insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could reduce our results of operations and impair our ability to make distributions to our unitholders.

Seasonal weather conditions may impair our ability to conduct drilling activities in some of the areas where we operate.

Natural gas and oil operations in the Appalachian Basin are impaired by seasonal weather conditions, primarily in the spring. Many municipalities impose weight restrictions on the paved roads that lead to our jobsites due to the muddy conditions caused by spring thaws. This will limit our access to these jobsites and our ability to service wells in these areas.

Properties that we buy may not produce as projected and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.

One of our growth strategies is to capitalize on opportunistic acquisitions of natural gas reserves. However, our reviews of acquired properties are inherently incomplete because it generally is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well we acquire. Potential problems, such as deficiencies in the mechanical integrity of equipment or environmental conditions that may require significant remedial expenditures, are not necessarily observable even when we inspect a well. Any unidentified problems could result in material liabilities and costs that negatively impact our financial condition and results of operations.

Risk factors

Even if we are able to identify problems with an acquisition, the seller may be unwilling or unable to provide effective contractual protection or indemnity against all or part of these problems. Even if a seller agrees to provide indemnity, the indemnity may not be fully enforceable and may be limited by floors and caps on such indemnity.

Hedging and forward sales transactions may limit our potential gains or cause us to lose money.

Pricing for natural gas has been volatile and unpredictable for many years. To limit exposure to changing natural gas prices, we use financial hedges and/or enter into forward sales for our natural gas production. 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 smaller quantities than those projected to be available at any delivery point. In addition, we may enter into hedges, which 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 36 months in the future.

By removing the price volatility from a significant portion of our natural gas production, we have reduced, but not eliminated, the potential effects of changing natural gas prices on our cash flow from operations for those periods. Furthermore, while intended to help reduce the effects of volatile natural gas prices, such transactions, depending on the hedging instrument used, may limit our potential gains if natural gas prices were to rise substantially over the price established by the hedge. Under circumstances in which, among other things, 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 natural gas prices, we may be exposed to the risk of financial loss.

We may be exposed to financial and other liabilities as the managing general partner in investment partnerships.

We serve as the managing general partner of 91 investment partnerships and will be the managing general partner of new investment partnerships that we sponsor. As a general partner, we are contingently liable for the obligations of these partnerships to the extent that partnership assets or insurance proceeds are insufficient. We have agreed to indemnify each investor partner in our investment partnerships from any liability that exceeds such partner’s share of the investment partnership’s assets. Furthermore, investor partners in some of our investment partnerships have the right to present their interests for purchase by us, as managing general partner, up to 5% to 10% of the total limited partner interests in any calendar year.

Our revenues may decrease if investors in our investment partnerships do not receive a minimum return.

We have agreed to subordinate up to 50% of our share of production revenues to specified returns to the investor partners in our investment partnerships, typically 10% per year for the first five years of distributions. Thus, our revenues from a particular partnership will decrease if it does not achieve the specified minimum return and our ability to make distributions to unitholders may be impaired. We have not subordinated our share of revenues from any of our investment partnerships since March 2005, but did subordinate $91,000 in fiscal 2005, $335,000 in fiscal 2004 and $362,000 in fiscal 2003.

Risk factors

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common units.

We are subject to comprehensive federal, state, local and other laws and regulations that could increase the cost and alter the manner or feasibility of our doing business.

Our operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon natural gas and oil wells. Under these laws and regulations, we could also be liable for personal injuries, property damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.

Part of the regulatory environment in which we operate includes, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. In addition, our activities are subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of natural gas we may produce and sell. A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could inhibit our ability to develop our properties. Additionally, the natural gas and oil regulatory environment could change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, consequently, reduce our profitability. Furthermore, we may be put at a competitive disadvantage to larger companies in our industry who can spread these additional costs over a greater number of wells and larger operating staff. Please read “Business—Environmental Matters and Regulation” and “Business—Other Regulation of the Natural Gas and Oil Industry” for a description of the laws and regulations that affect us.

RISKS INHERENT IN AN INVESTMENT IN US

Atlas America and its affiliates will own a controlling interest in us upon completion of this offering.

Upon completion of this offering, Atlas America and its affiliates will own approximately 82.6% of our common units and all of our Class A units. Accordingly, Atlas America will possess a controlling vote on all matters submitted to a vote of our unitholders, including election of our board of directors. As long as

Risk factors

Atlas America owns a controlling interest in us, it will be able to approve or disapprove matters submitted to members for a vote irrespective of the vote of persons buying common units in this offering. Atlas America will be able to cause a change of control of our company. This concentration of ownership may have the effect of preventing or discouraging transactions involving an actual or a potential change of control of our company, regardless of whether a premium is offered over then-current market prices. Moreover, even if subsequent issuances result in Atlas America holding less than a majority of the common units, it will be able to determine matters requiring class voting so long as it controls the Class A units.

Members of our board of directors and Atlas America and its affiliates, including our manager, may have conflicts of interest with us.

Conflicts of interest may arise between us and our unitholders and members of our board of directors and Atlas America and its affiliates, including our manager. These potential conflicts may relate to the divergent interests of these parties. Situations in which the interests of members of our board of directors and Atlas America and its affiliates, may differ from interests of owners of common units include, among others, the following situations:

Our limited liability company agreement gives our board of directors broad discretion in establishing cash reserves for the proper conduct of our business, which will affect the amount of cash available for distribution. For example, our board of directors will use its reasonable discretion to establish and maintain cash reserves sufficient to maintain our asset base.

Our manager will recommend to our board of directors the timing and extent of our drilling program and related capital expenditures, asset purchases and sales, and financing alternatives and reserve adjustments, all of which will affect the amount of cash that we distribute to our unitholders.

In some instances our board of directors may cause us to borrow funds in order to permit us to pay cash distributions to our unitholders, even if the purpose or effect of the borrowing is to make management incentive distributions.

Except as provided in our omnibus agreement with Atlas America, members of our board of directors and Atlas America and its affiliates, including our manager, are not prohibited from investing or engaging in other businesses or activities that compete with us.

We do not have any employees and rely solely on employees of our manager and its affiliates. Our officers and the officers of our manager who provide services to us are not required to work full time on our affairs. These officers may devote significant time to the affairs of our manager’s affiliates. There may be significant conflicts between us and our affiliates regarding the availability of these officers to manage us.

You will experience immediate and substantial dilution of $16.25 per common unit.

The assumed initial public offering price of $20.00 per common unit exceeds our pro forma net tangible book value of $3.75 per common unit. Based on the assumed initial public offering price, you will incur immediate and substantial dilution of $16.25 per common unit. Please read “Dilution.”

We may issue additional units without your approval, which would dilute your existing ownership interests.

We may issue an unlimited number of units of any type, including common units, without the approval of our unitholders. The issuance of additional units or other equity securities may have the following effects:

your proportionate ownership interest in us may decrease;

Risk factors

the amount of cash distributed on each common unit may decrease;

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

the market price of the common units may decline.

Our limited liability company agreement provides for a limited call right that may require you to sell your common units at an undesirable time or price.

If, at any time, any person owns more than 87.5% of the common units then outstanding, such person has the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining common units then outstanding at a price not less than the then-current market price of the common units. As a result, you may be required to sell your common units at an undesirable time or price and therefore may receive a lower or no return on your investment. You may also incur tax liability upon a sale of your units. For additional information about the call right, please read “Our limited liability company agreement—Limited Call Right.”

Unitholders may have limited liquidity for their common units, a trading market may not develop for the units and you may not be able to resell your units at the initial public offering price.

There has been no public market for the common units before this offering. After the offering, there will be 5,750,000 publicly-traded common units outstanding, assuming no exercise of the underwriters’ option to purchase additional common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the units.

If the unit price declines after the initial public offering, you could lose a significant part of your investment.

The market price of our common units could be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:

changes in securities analysts’ recommendations and their estimates of our financial performance;

the public’s reaction to our press releases, announcements and our filings with the SEC;

fluctuations in broader securities market prices and volumes, particularly among securities of natural gas and oil companies and securities of publicly-traded limited partnerships and limited liability companies;

changes in market valuations of similar companies;

departures of key personnel;

commencement of or involvement in litigation;

variations in our quarterly results of operations or those of other natural gas and oil companies;

variations in the amount of our quarterly cash distributions;

future issuances and sales of our units; and

changes in general conditions in the U.S. economy, financial markets or the natural gas and oil industry.

Risk factors

In recent years, the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.

Unitholders may have liability to repay distributions.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 18-607 of the Delaware Revised Limited Liability Company Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, unitholders who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited liability company for the distribution amount. A purchaser of common units who becomes a unitholder is liable for the obligations of the transferring unitholder to make contributions to the limited liability company that are known to such purchaser of units at the time it became a member and for unknown obligations if the liabilities could be determined from our limited liability company agreement.

Our manager may transfer its interests in us to a third party without common unitholder consent.

Our manager may transfer its Class A units and management incentive interests to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our common unitholders. Furthermore, Atlas America is not restricted from transferring its equity interest in our manager.

Atlas America may sell common units in the future, which could reduce the market price of our outstanding units.

Following the completion of this offering, Atlas America will own 27,550,000 common units. In addition, our manager will have the right to convert its Class A units and management incentive interests into common units if we terminate the management agreement, and its Class A units will automatically convert into common units, and it will have the option of converting its management incentive interests, if the common unitholders vote to eliminate the special voting rights of our Class A units. We have agreed to register for sale common units held by Atlas America and its affiliates. These registration rights allow Atlas America, our manager and their affiliates to request registration of their common units and to include any of those units in a registration of other securities by us. If Atlas America and its affiliates were to sell a substantial portion of their units, it could reduce the market price of our outstanding common units. Please also read “Material tax consequences—Disposition of Common Units—Constructive termination.”

We depend on our manager and Atlas America, and may not find suitable replacements if the management agreement terminates.

We have no employees. Our support personnel are employees of Atlas America. We have no separate facilities and completely rely on our manager and, because our manager has no direct employees, Atlas America. If our management agreement terminates, we may be unable to find a suitable replacement for them.

Our management agreement was not negotiated at arm’s-length and, as a result, may not be as favorable to us as if it had been negotiated with a third party.

Our officers and four of our directors, Edward E. Cohen, Jonathan Z. Cohen, Richard D. Weber and Matthew A. Jones, are officers or directors of our manager, and Messrs. Cohen are directors of Atlas

Risk factors

America. As a consequence, our management agreement was not the result of arm’s-length negotiations and its terms may not be as favorable to us as if it had been negotiated with an unaffiliated third party.

Expense reimbursements due to our manager under our management agreement will reduce cash available for distribution to our unitholders.

Before making any distribution on our common units, we will reimburse our manager for all expenses that it incurs on our behalf pursuant to the management agreement. These expenses will include all costs incurred on our behalf, including costs for providing corporate staff and support services to us. Our manager will charge on a fully allocated cost basis for services provided to us. This fully allocated cost basis is based on the percentage of time spent by personnel of our manager and its affiliates on our matters and includes the compensation paid by our manager and its affiliates to such persons and their allocated overhead. The allocation of compensation expense for such persons will be determined based on a good faith estimate of the value of each such person’s services performed on our business and affairs, subject to the periodic review and approval of our audit or conflicts committee.

Termination of the management agreement by us is difficult.

Termination of our management agreement is difficult: we may terminate the management agreement only upon the affirmative vote of at least two-thirds of our outstanding common units, including units owned by Atlas America and its affiliates. Upon any termination, our manager will have the right to convert its Class A units into common units on a one-for-one basis and convert its management incentive interests into common units based on their fair market value if the successor manager does not purchase them. Atlas America will be able to prevent the removal of our manager so long as it owns at least two-thirds of our common units.

Our manager’s liability is limited under the management agreement, and we have agreed to indemnify our manager against certain liabilities.

Our manager will not assume any responsibility under the management agreement other than to render the services called for under it, and will not be responsible for any action of our board of directors in following or declining to follow its advice or recommendations. Our manager, its directors, officers, employees and affiliates will not be liable to us, any subsidiary of ours, our directors or our unitholders for acts performed in good faith and in accordance with the management agreement, except by reason of acts constituting bad faith, willful misconduct, fraud or criminal conduct. We have agreed to indemnify the parties for all damages and claims arising from acts not constituting bad faith, willful misconduct, fraud or criminal conduct and performed in good faith in accordance with and pursuant to the management agreement.

Our limited liability company agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Our limited liability company agreement restricts the voting rights of common unitholders by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than Atlas America, our manager, their affiliates or transferees and persons who acquire such units with the prior approval of our board of directors, cannot vote on any matter. Our limited liability company agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting common unitholders’ ability to influence the manner or direction of management.

Risk factors

If the holders of our common units vote to eliminate the special voting rights of the holders of our Class A units, the Class A units will automatically convert into common units on a one-for-one basis and our manager will have the option of converting the management incentive interests into common units at their fair market value, which may be dilutive to you.

The holders of our Class A units have the right to vote as a separate class on extraordinary transactions submitted to a unitholder vote such as a merger or sale of all or substantially all of our assets. This right can be eliminated upon a vote of the holders of not less than two-thirds of our outstanding common units. If such elimination is so approved, the Class A units will automatically convert into common units on a one-for-one basis and our manager will have the right to convert its management incentive interests into common units based on their then fair market value, which may be dilutive to you.

An increase in interest rates may cause the market price of our common units to decline.

Like all equity investments, an investment in our common units is subject to risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly-traded limited liability company interests. Reduced demand for our common units resulting from investors seeking other investment opportunities may cause the trading price of our common units to decline.

TAX RISKS TO UNITHOLDERS

For a discussion of the expected material federal income tax consequences of owning and disposing of common units, see “Material tax consequences.”

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, taxes paid, if any, would reduce the amount of cash available for distribution.

The anticipated after-tax benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects us.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed as corporate distributions, and no income, gain, loss, deduction or credit would flow through to you. Because a tax may be imposed on us as a corporation, our cash available for distribution to our unitholders could be reduced. Therefore, our treatment as a corporation could result in a material reduction in the anticipated cash flow and after-tax return to our unitholders and therefore result in a substantial reduction in the value of our common units.

Risk factors

Current law or our business may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to you would be reduced. Our limited liability company agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the IQD amount and the incentive distribution amounts will be adjusted to reflect the impact of that law on us.

You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

You will be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from your share of our taxable income.

A successful IRS contest of the federal income tax positions we take may harm the market for our common units, and the costs of any contest will reduce cash available for distribution.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter that affects us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and a court may disagree with some or all of those positions. Any contest with the IRS may lower the price at which our common units trade. In addition, our costs of any contest with the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts, or IRAs, and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.

We will treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased. The IRS may challenge this treatment, which could reduce the value of the common units.

Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could reduce the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain on the sale of common units and could have a negative impact on the value of our common units or result in audits of and adjustments to our unitholders’ tax returns. Please read “Material tax consequences — Uniformity

Risk factors

of Common Units” for a further discussion of the effect of the depreciation and amortization positions we will adopt.

Tax gain or loss on the disposition of our common units could be more or less than expected because prior distributions in excess of allocations of income will decrease your tax basis in your units.

If you sell any of your common units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in those units. Prior distributions to you in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that unit, will, in effect, become taxable income to you if the unit is sold at a price greater than your tax basis in that unit, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to you. In addition, you may incur a tax liability in excess of the amount of cash you receive from the sale.

We will be considered to have terminated for tax purposes due to a sale or exchange of 50% or more of our interests within a twelve-month period.

You may be subject to state and local taxes and return filing requirements in states where you do not live as a result of investing in our common units.

In addition to federal income taxes, you will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if you do not reside in any of those jurisdictions. You will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We will initially do business and own assets in Pennsylvania, New York, Ohio and Tennessee. As we make acquisitions or expand our business, we may do business or own assets in other states in the future. It is the responsibility of each unitholder to file all United States federal, foreign, state and local tax returns that may be required of such unitholder. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in the common units.

Cautionary note regarding forward-looking statements

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

business strategy;

financial strategy;

drilling locations;

natural gas and oil reserves;

realized natural gas and oil prices;

production volumes;

lease operating expenses, general and administrative expenses and finding and development costs;

future operating results; and

plans, objectives, expectations and intentions.

All of these types of statements, other than statements of historical fact included in this prospectus, are forward-looking statements. These forward-looking statements may be found in the “Prospectus summary,” “Risk factors,” “Cash distribution policy and restrictions on distributions,” “Management’s discussion and analysis of financial condition and results of operations,” “Business” and other sections of this prospectus. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.

The forward-looking statements contained in this prospectus are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this prospectus are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors listed in the “Risk factors” section and elsewhere in this prospectus. All forward-looking statements speak only as of the date of this prospectus. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

Use of proceeds


Sources of funds (in millions):
Estimated proceeds, net of estimated underwriting discounts and commissions and offering expenses, received from this offering(1)	$	105.5

Uses of funds (in millions):
Distribution to Atlas America(1)(2)	$	100.5
Working capital		5.0

	$	105.5

(1)

We estimate that we will receive net proceeds of approximately $105.5 million from the sale of the 5,750,000 common units offered by this prospectus, assuming an initial public offering price of $20.00 per common unit (the mid-point of the price range set forth on the cover of this prospectus) and after deducting estimated underwriting discounts and commissions of $8.1 million and estimated offering expenses of $1.5 million.

(2)

If the underwriters’ over-allotment option is exercised, we will use the additional net proceeds to purchase a number of units from Atlas America equal to the number of units issued upon exercise of the option. If the underwriters’ over-allotment option is exercised in full, Atlas America’s ownership will be reduced from 27,550,000 common units to 26,687,500 common units, reducing Atlas America’s limited liability company interest in us from approximately 81.0% to approximately 78.4%.

Capitalization

The following table sets forth our capitalization as of March 31, 2006 (1) on an historical basis and (2) on a pro forma basis to give effect to the offering and related transactions and the application of the net proceeds of this offering as described in “Use of Proceeds.” In each case, the table assumes an initial public offering price of $20.00 per common unit, the mid-point of the price range set forth on the front cover of this prospectus, and further assumes that the underwriters’ over-allotment option is not exercised. The table is derived from, and should be read in conjunction with, and is qualified in its entirety by reference to, the pro forma and historical financial statements and notes thereto included elsewhere in this prospectus. You should also read this table in conjunction with “Prospectus summary—The Transactions and Our LLC Structure” and “Management’s discussion and analysis of financial condition and results of operations.”


	As of March 31, 2006
	Historical		Pro forma
	(in thousands)
Cash and cash equivalents	$	5,010	$	8,510

Credit facility(1)		—		51,262
Advances from affiliates		51,798		—
Other debt		134		134

Total debt		51,932		51,396
Equity
Combined equity		163,745		—
Held by public:
Common units		—		105,450
Held by Atlas America and affiliates(2):
Common units		—		59,920
Held by our manager:
Class A units		—		3,375

Total equity		163,745		168,745

Total capitalization	$	215,677	$	220,141

(1)

Reflects pro forma borrowings of $51.3 million under our proposed credit facility to repay the advances from affiliates. Because we cannot immediately invest all of the funds we raise in our investment partnerships, we reduce outstanding indebtedness and advances from affiliates with the funds until such time as we can invest them. We do not anticipate having any debt outstanding or advances from affiliates at the time of the offering because we expect to utilize partnership funds to repay them.

(2)

Includes 50,000 restricted common units estimated to be issued to Richard D. Weber upon completion of this offering.

Dilution

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the net tangible book value per unit after the offering. Net tangible book value is our total tangible assets less total liabilities. Assuming an initial public offering price of $20.00 per common unit, on a pro forma basis as of March 31, 2006, after giving effect to the formation transactions and this offering and the application of the net proceeds of this offering, and assuming the underwriters’ over-allotment option is not exercised, our net tangible book value would have been approximately $127.7 million or $3.75 per common unit. Purchasers of common units in the offering will experience substantial and immediate dilution in net tangible book value per unit for financial accounting purposes, as illustrated in the following table:


Assumed initial public offering price per unit				$	20.00
Pro forma net tangible book value per common unit before the offering(1)	$	4.52
Decrease in net tangible book value per common unit attributable to purchasers in the offering	$	(0.77	)

Less: Pro forma net tangible book value per common unit after the offering(2)				$	3.75

Immediate dilution in net tangible book value per common unit				$	16.25

(1)

Determined by dividing the total number of common units (27,600,000) and Class A units (680,612) to be issued to Atlas America and its affiliates into the pro forma net tangible book value of the contributed assets and liabilities.

(2)

Determined by dividing the total number of common units (33,350,000) and Class A units (680,612) to be outstanding after the offering into our pro forma net tangible book value, after giving effect to the application of the net proceeds of the offering.

The following table sets forth the number of Class A and common units that will be issued by us and the total consideration contributed to us by Atlas America and its affiliates with respect to their Class A and common units and by the purchasers of common units in this offering upon the consummation of the transactions contemplated by this prospectus:


	Class A and common units acquired			Total consideration
	Number	Percent		Amount (in thousands)		Percent
Atlas America and its affiliates(1)	28,230,612	83.0	%	$	63,295	36	%
Richard D. Weber(2)	50,000	0.1	%		—	—
New investors	5,750,000	16.9	%		115,000	64	%

Total	34,030,612	100	%	$	178,295	100	%

Dilution

(1)

Atlas America’s assets contributed to us will be recorded at historical book value, rather than fair value, in accordance with GAAP. The difference between historical book value and the purchase price has been recorded as a reduction in unitholders’ equity. Book value of the consideration provided by Atlas America and its affiliates, as of March 31, 2006, after giving effect to the application of the net proceeds of the offering, is as follows:


	(in thousands)
Book value of net assets contributed by Atlas America	$	163,745
Less: distribution of the net proceeds from the sale of common units		(100,450	)

Total consideration	$	63,295

(2)

How we make cash distributions

INITIAL QUARTERLY DISTRIBUTION

The amount of distributions paid under our cash distribution policy and the decision to make any distribution will be determined by our board of directors, taking into account the terms of our limited liability company agreement. We intend to distribute to the holders of common units and Class A units on a quarterly basis at least the IQD of $0.40 per unit, or $1.60 per unit per year to the extent we have sufficient available cash after we establish appropriate reserves and pay fees and expenses, including payments to our manager in reimbursement of costs and expenses it incurs on our behalf. Our IQD is intended to reflect the level of cash that we expect to be available for distribution per common unit and Class A unit each quarter. There is no guarantee we will pay the IQD in any quarter and we will be prohibited from making any distributions to unitholders if it would cause an event of default or an event of default is existing under our proposed credit agreement. Please read “Management’s discussion and analysis of financial condition and results of operations.” It is the current policy of our board of directors that we should raise our quarterly cash distribution only when the board believes that (i) we have sufficient reserves and liquidity for the proper conduct of our business, including the maintenance of our capital asset base, and (ii) we can maintain such an increased distribution level for a sustained period. While this is our current policy, our board of directors may alter the policy in the future when and if it determines such alteration to be appropriate.

DISTRIBUTIONS OF AVAILABLE CASH

Overview

Our limited liability company agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending September 30, 2006, we distribute all of our available cash to unitholders of record on the applicable record date.

Definition of available cash

Available cash generally means, for each fiscal quarter, all cash on hand at the end of the quarter:

less the amount of cash reserves established by our board of directors to:

provide for the proper conduct of our business (including reserves for future capital expenditures and credit needs);

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

provide funds for distributions (1) to our unitholders for any one or more of the next four quarters or (2) with respect to our management incentive interests;

plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.

Working capital borrowings are borrowings that are made under our credit facility or another arrangement and used solely for working capital purposes or to pay distributions to unitholders.

OPERATING SURPLUS AND CAPITAL SURPLUS

General

All cash we distribute to unitholders will be characterized as either “operating surplus” or “capital surplus.” Our limited liability company agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus.

How we make cash distributions

Definition of operating surplus

Operating surplus generally means:

$40.0 million (as described below); plus

all of our cash receipts after the closing of this offering, including working capital borrowings but excluding cash from (1) borrowings that are not working capital borrowings, (2) sales of equity and debt securities and (3) sales or other dispositions of assets outside the ordinary course of business; plus

working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; plus

cash distributions paid on equity securities issued to finance all or a portion of the construction, replacement or improvement of a capital asset (such as equipment or reserves) during the period from such financing until the earlier to occur of the date the capital asset is placed into service or the date that it is abandoned or disposed of; less

our operating expenditures (as defined below); less

the amount of cash reserves established by our board of directors to provide funds for future operating expenditures.

Operating expenditures generally means all of our cash expenditures, including taxes, reimbursement of expenses to our manager, director and officer compensation, repayment of working capital borrowings, debt service payments and estimated maintenance capital expenditures, but do not include:

payments (including prepayments and prepayment penalties) of principal and premium on indebtedness, other than working capital borrowings;

expansion capital expenditures;

actual maintenance capital expenditures;

investment capital expenditures;

payment of transaction expenses relating to interim capital transactions; or

distributions to our members (including distributions with respect to our management incentive interests).

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $40.0 million of cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including certain cash distributions on equity securities in operating surplus would be to increase operating surplus by the amount of the cash distributions. As a result, we may also distribute as operating surplus up to the amount of the cash distributions we receive from non-operating sources.

None of actual maintenance capital expenditures, investment capital expenditures or expansion capital expenditures are subtracted from operating surplus. Because actual maintenance capital expenditures, investment capital expenditures and expansion capital expenditures include interest payments (and related fees) on debt incurred and distributions on equity issued to finance all of the portion of the construction, replacement or improvement of a capital asset (such as equipment or reserves) during the period from such financing until the earlier to occur of the date any such capital asset is placed into

How we make cash distributions

service or the date that it is abandoned or disposed of, such interest payments and equity distributions are also not subtracted from operating surplus (except, in the case of maintenance capital expenditures, to the extent such interest payments and distributions are included in estimated maintenance capital expenditures).

Capital expenditures

Maintenance Capital Expenditures

For purposes of determining operating surplus, maintenance capital expenditures are those capital expenditures we expect to make on an ongoing basis to maintain our capital asset base at a steady level over the long term. Examples of maintenance capital expenditures include capital expenditures associated with the replacement of equipment and oil and natural gas reserves (including non-proved reserves attributable to undeveloped leasehold acreage), whether through the development, exploitation and production of an existing leasehold or the acquisition or development of a new oil or natural gas property, and plugging and abandonment costs. Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of a replacement asset during the period from the financing until the earlier to occur of the date the replacement asset is placed into service or the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered maintenance capital expenditures.

Because our maintenance capital expenditures can be very large and irregular, the amount of our actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus, adjusted operating surplus and cash available for distribution to our unitholders if we subtracted actual maintenance capital expenditures from operating surplus. To eliminate the effect on operating surplus of these fluctuations, our limited liability company agreement will require that an estimate of the average quarterly maintenance capital expenditures (including estimated plugging and abandonment costs) necessary to maintain our asset base over the long term be subtracted from operating surplus each quarter as opposed to the actual amounts spent. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and approval by our board of directors, including a majority of our conflicts committee, at least once a year. We will make the estimate at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will impact our business. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only. For a discussion of the amounts we have allocated toward estimated maintenance capital expenditures, please read “Cash distribution policy and restrictions on distributions.”

The use of estimated maintenance capital expenditures in calculating operating surplus will have the following effects:

it will reduce the risk that maintenance capital expenditures in any one quarter will be large enough to render operating surplus less than the IQD to be paid on all the units for that quarter and subsequent quarters;

it will increase our ability to distribute as operating surplus cash we receive from non-operating sources;

it will be more difficult for us to raise our distribution above the IQD and pay management incentive distributions; and

How we make cash distributions

it will reduce the likelihood that a large maintenance capital expenditure during the Incentive Trigger Period will prevent the payment of a management incentive distribution in respect of the Incentive Trigger Period since the effect of an estimate is to spread the expected expense over several periods, thereby mitigating the effect of the actual payment of the expenditure on any single period.

Expansion Capital Expenditures

Expansion capital expenditures are those capital expenditures that we expect to make to expand our capital asset base for the longer than short term. Examples of expansion capital expenditures include the acquisition of reserves or equipment, the acquisition of new leasehold interests, or the development, exploitation and production of an existing leasehold interests, to the extent such expenditures are incurred to increase our capital asset base. Expansion capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of a capital improvement during the period from the financing until the earlier to occur of the date the capital improvement is placed into service or the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered expansion capital expenditures.

Investment Capital Expenditures

Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes or development of our undeveloped properties in excess of maintenance capital expenditures, but which are not expected to expand our asset base for more than the short term.

Capital expenditures that are made in part for maintenance capital purposes and in part for investment capital or expansion capital purposes will be allocated as maintenance capital expenditures, investment capital expenditures or expansion capital expenditure by our board of directors, including a majority of our conflicts committee, based upon its good faith determination.

Definition of capital surplus

Capital surplus will generally be generated only by:

borrowings other than working capital borrowings;

sales of debt and equity securities; and

sales or other disposition of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirements or replacements of assets.

Characterization of cash distributions

We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent date of determination of available cash. We will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

How we make cash distributions

DISTRIBUTIONS OF AVAILABLE CASH FROM OPERATING SURPLUS

We will make distributions of available cash from operating surplus for any quarter in the following manner:

first, 98% to the common unitholders, pro rata, and 2% to the holder of our Class A units, until we distribute $0.46 per unit for the quarter (the “First Target Distribution”); and

after that, any amount distributed with respect to the quarter in excess of the First Target Distribution per common unit will be distributed 98% to the holders of the common units, pro rata, and 2% to the holder of our Class A units until distributions become payable with respect to our management incentive interests as described in “—Management Incentive Interests” below.

The Class A units will be entitled to 2% of all cash distributions from operating surplus, without any requirement for future capital contributions by the holders of such Class A units, even if we issue additional common units or other senior or subordinated equity securities in the future. The percentage interests shown above for the Class A units assume they have not been converted into common units. If the Class A units have been converted, the common units will receive the 2% of distributions originally allocated to the Class A units.

MANAGEMENT INCENTIVE INTERESTS

Management incentive interests represent the right to receive increasing amounts of quarterly distributions of available cash from operating surplus after we have made payments in excess of the First Target Distribution and the tests described below have been met. Our manager currently holds the management incentive interests, which are evidenced by the Class C limited liability company interests, but may transfer these rights separately from its Class A units, subject to restrictions in our limited liability company agreement.

Before the end of the Incentive Trigger Period, which we define below, we will not pay any management incentive distributions. To the extent, however, that during the Incentive Trigger Period we distribute available cash from operating surplus in excess of the First Target Distribution, our board of directors intends to cause us to reserve an amount for payment of a one-time management incentive distribution earned during the Incentive Trigger Period, after such period ends. If during the Incentive Trigger Period we fail to satisfy a condition specified in the next paragraph, our board of directors will cause any such reserved amount to be released from that reserve and restored to available cash.

The 12-Quarter Test and the 4-Quarter Test

We will make management incentive payments if two tests are met. The first test is the 12-Quarter Test, which requires that for the 12 full, consecutive, non-overlapping calendar quarters that begin with the first calendar quarter with respect to which we pay per unit cash distributions from operating surplus to holders of Class A and common units in an amount equal to or greater than the First Target Distribution (we refer to such 12-quarter period as the Incentive Trigger Period):

we generate adjusted operating surplus (which we define below) during the Incentive Trigger Period that on average is in an amount at least equal to all cash distributions on the outstanding Class A and common units plus the amount of any management incentive distributions that would have been

How we make cash distributions

payable if both the 12-Quarter Test and the 4-Quarter Test were met. This equates to: (i) 100% of all distributions on the outstanding Class A and common units up to the First Target Distribution plus (ii) 117.65% of any distributions in excess of the First Target Distribution up to $0.56 (the “Second Target Distribution”) plus (iii) 133.33% of any distributions in excess of the Second Target Distribution; and

we do not reduce the amount distributed per unit for any such 12 quarters;

we pay cash distributions from operating surplus to the holders of our outstanding Class A and common units that exceed the First Target Distribution on all of the outstanding Class A and common units;

we generate adjusted operating surplus during each quarter in an amount at least equal to all cash distributions on the outstanding Class A and common units plus the amount of any management incentive distributions that would have been payable if both tests were met. This equates to (i) 100% of all distributions on the outstanding Class A and common units up to the First Target Distribution plus (ii) 117.65% of any distributions in excess of the First Target Distribution up to the Second Target Distribution plus (iii) 133.33% of any distributions in excess of the Second Target Distribution; and

we do not reduce the amount distributed per unit with respect to any of such four quarters.

If both the 12-Quarter Test and 4-Quarter Test have been met, then:

We will make a one-time management incentive distribution to the holder of our management incentive interests (contemporaneously with the distribution paid with respect to the Class A and common units for the last calendar quarter in the 4-Quarter Test) equal to the cumulative amount of the management incentive distributions that would have been paid based on the level of distributions made on our Class A and common units during the Incentive Trigger Period if the management incentive distributions were payable on a quarterly basis rather than after completion of the Incentive Trigger Period, that is, (x) 17.65% of the sum of any cumulative amounts by which quarterly cash distributions per unit paid on the outstanding Class A and common units during the Incentive Trigger Period exceeded the First Target Distribution up to the Second Target Distribution and (y) 33.33% of the sum of any cumulative amounts by which quarterly cash distributions per unit paid on the outstanding Class A and common units during the Incentive Trigger Period exceeded the Second Target Distribution.

For each calendar quarter after the two tests are satisfied, the holders of our Class A units, common units and management incentive interests will receive:

2%, 83% and 15%, respectively, of cash distributions from available cash from operating surplus that we pay for the quarter in excess of the First Target Distribution up to the Second Target Distribution; and

2%, 73% and 25%, respectively, of cash distributions from available cash from operating surplus that we pay for the quarter in excess of the Second Target Distribution.

How we make cash distributions

Our board of directors has adopted a policy that it will raise our quarterly cash distribution only when it believes that (i) we have sufficient reserves and liquidity for the proper conduct of our business, including the maintenance of our asset base, and (ii) we can maintain such increased distribution level for a sustained period. While this is our current policy, our board of directors may alter the policy in the future when and if it determines such alteration to be appropriate.

Definition of adjusted operating surplus

Adjusted operating surplus generally means, for any period:

operating surplus generated with respect to that period; less

any net increase in working capital borrowings with respect to that period; less

any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

any net decrease in working capital borrowings with respect to that period; plus

any net increase in cash reserves for operating expenditures made with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Adjusted operating surplus is intended to reflect the cash generated from our operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods.

PERCENTAGE ALLOCATIONS OF AVAILABLE CASH FROM OPERATING SURPLUS

The following table illustrates the percentage allocations of the available cash from operating surplus between the unitholders and the owner of our management incentive interests up to various distribution levels. The amounts set forth under “Marginal percentage interest in distributions” are the percentage interests of our Class A unitholders and common unitholders and the holders of our management incentive interests in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Quarterly distribution level,” until available cash from operating surplus we distribute reaches the next distribution level, if any. The percentage interests shown for the IQD are also applicable to quarterly distribution amounts that are less than the IQD. The percentage interests shown in the table below assume that the Class A units have not been converted into common units as described herein.


		Marginal percentage interest in distributions
	Quarterly distribution level	Class A unitholders		Common unitholders		Management incentive interests
IQD	$0.40	2	%	98	%	0	%
First Target Distribution	above $0.40 up to $0.46	2	%	98	%	0	%
Second Target Distribution*	above $0.46 up to $0.56	2	%	83	%	15	%
After that*	above $0.56	2	%	73	%	25	%

Assumes the 12-Quarter Test and the 4-Quarter Test have been met. Until the 12-Quarter Test and the 4-Quarter Test are met and distributions with respect to the management incentive interests become payable, quarterly distributions in excess of the First Target Distribution will be made 2% to the holder of the Class A units and 98% to the holders of common units, pro rata.

How we make cash distributions

DISTRIBUTIONS FROM CAPITAL SURPLUS

How we will make distributions from capital surplus

We will make distributions of available cash from capital surplus, if any, in the following manner:

First, 2% to the holder of our Class A units and 98% to all common unitholders, pro rata, until we distribute for each common unit that was issued in this offering an amount of available cash from capital surplus equal to the initial public offering price; and

After that, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

Effect of a distribution from capital surplus

Our limited liability company agreement treats a distribution of capital surplus as the repayment of the initial common unit price from this initial public offering, which is a return of capital. We refer to the initial public offering price less any distributions of capital surplus per common unit as the “unrecovered initial common unit price.” Each time we make a distribution of capital surplus, the IQD, the First Target Distribution and the Second Target Distribution will be reduced in the same proportion as the corresponding reduction in the unrecovered initial common unit price. Because distributions of capital surplus will reduce the IQD, after we make any of these distributions, it may be easier for our manager to receive management incentive distributions. However, any distribution of capital surplus before the unrecovered initial common unit price is reduced to zero cannot be applied to the payment of the IQD.

Once we distribute capital surplus on a common unit issued in this offering in an amount equal to the initial common unit price, we will reduce the IQD, the First Target Distribution and the Second Target Distribution to zero. We will then make all future distributions from operating surplus, with 2% being distributed to the holder of our Class A units, 73% being distributed to our common unitholders, pro rata, and 25% being distributed to the holder of our management incentive interests. The percentage interests shown above for the Class A units assume they have not been converted into common units. If the Class A units have been converted, the common units will receive the 2% of distributions originally allocated to the Class A units.

Adjustment to the IQD and target distribution levels

In addition to adjusting the IQD, First Target Distribution and Second Target Distribution to reflect a distribution of capital surplus, if we combine our common units into fewer common units or subdivide our common units into a greater number of common units, we will proportionately adjust:

the IQD;

the First Target Distribution and Second Target Distribution; and

the unrecovered initial common unit price.

For example, if a two-for-one split of the common units should occur, the First Target Distribution, the Second Target Distribution and the unrecovered initial common unit price would each be reduced to 50% of its initial level. We will not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if legislation is enacted or if existing law is modified or interpreted by a court of competent jurisdiction so that we become taxable as a corporation or otherwise subject to taxation as an entity for

How we make cash distributions

federal, state or local income tax purposes, we will reduce the IQD, the First Target Distribution and the Second Target Distribution for each quarter by multiplying each by a fraction, the numerator of which is available cash for that quarter (after deducting our board of directors’ estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation) and the denominator of which is the sum of available cash for that quarter plus our board of directors’ estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, we will account for the difference in subsequent quarters.

DISTRIBUTIONS OF CASH UPON LIQUIDATION

General

If we dissolve in accordance with our limited liability company agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and our manager in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

Manner of adjustments for gain

The manner of the adjustment for gain is set forth in our limited liability company agreement, and requires that we will allocate any gain to the unitholders and holders of the Class A units in the following manner:

First, to the holders of common units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

Second, 2% to the holder of our Class A units and 98% to the common unitholders, pro rata, until the capital account for each common unit is equal to the sum of:

(1)

the unrecovered initial common unit price; and

(2)

the amount of the IQD for the quarter during which our liquidation occurs; and

Third, 2% to the holder of our Class A units and 98% to the common unitholders, pro rata, until the capital account for each common unit is equal to the sum of:

(1)

the amount described above under the second bullet point of this paragraph; and

(2)

the excess of (I) over (II), where

(I)

equals the sum of the excess of the First Target Distribution per common unit over the IQD for each quarter of our existence; and

(II)

equals the cumulative amount per common unit of any distributions of available cash from operating surplus in excess of the IQD per common unit that we distributed 98% to our common unitholders, pro rata, for each quarter of our existence; and

Fourth, 2% to the holder of our Class A units, 83% to the common unitholders, pro rata, and 15% to the holder of our management incentive interests until the capital account for each common unit is equal to the sum of:

(1)

the amount described above under the second bullet point of this paragraph; and

How we make cash distributions

(2)

the excess of (I) over (II), where

(I)

equals the sum of the excess of the Second Target Distribution per common unit over the First Target Distribution for each quarter of our existence; and

(II)

equals the cumulative amount per common unit of any distributions of available cash from operating surplus in excess of the First Target Distribution per common unit that we distributed 83% to our common unitholders, pro rata, for each quarter of our existence; and

After that, 2% to the holder of our Class A units, 73% to all common unitholders, pro rata, and 25% to the holder of our management incentive interests.

Manner of adjustments for losses

Upon our liquidation, we will generally allocate any loss 2% to the holder of the Class A units and 98% to the holders of the outstanding common units, pro rata.

Adjustments to capital accounts

We will make adjustments to capital accounts upon the issuance of additional common units. In doing so, we will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the holder of the Class A units, the common unitholders, and the holders of the management incentive interests in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional common units, we will allocate any later negative adjustments to the capital accounts resulting from the issuance of additional common units or upon our liquidation in a manner which results, to the extent possible, in the capital account balances of the holders of the management incentive interests equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.

Cash distribution policy and restrictions on distributions

You should read the following discussion of our cash distribution policy in conjunction with specific assumptions included in this section. For more detailed information regarding the factors and assumptions upon which our cash distribution policy is based, please read “—Estimated EBITDA” below. In addition, you should read “Cautionary note regarding forward-looking statements” and “Risk factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

For additional information regarding our historical and pro forma results of operations, you should refer to our historical and pro forma consolidated financial statements for the fiscal year ended September 30, 2005 and the six months ended March 31, 2006, included elsewhere in this prospectus as well as “Management’s discussion and analysis of financial condition and results of operations.”

GENERAL

Rationale for our cash distribution policy

Our cash distribution policy reflects a basic judgment that our unitholders will be better served by our distributing our available cash rather than our retaining it. It is the current policy of our board of directors that we should increase our level of quarterly cash distributions per unit only when, in its judgment, it believes that (i) we have sufficient reserves and liquidity for the proper conduct of our business, including the maintenance of our asset base, and (ii) we can maintain such an increased distribution level for a sustained period. The amount of available cash will be determined by our board of directors for each calendar quarter after the closing of the offering and will be based upon recommendations from our management. Because we believe we will generally finance any expansion capital expenditures and investment capital expenditures from external financing sources, we believe that our investors are best served by our distributing all of our available cash. In addition, since we are not subject to an entity-level federal income tax, we have more cash to distribute to you than would be the case if we were subject to federal income tax. Our cash distribution policy is consistent with the terms of our limited liability company agreement, which requires that we distribute all of our available cash quarterly. We are a recently formed limited liability company and have not made any cash distributions. For a more detailed discussion, please read “How we make cash distributions” elsewhere in this prospectus.

Restrictions and limitations on our ability to make quarterly distributions

We cannot guarantee that unitholders will receive quarterly cash distributions from us or that we can or will maintain any increases in our quarterly cash distributions. Our distribution policy may be changed at any time and is subject to certain restrictions, including:

Other than the obligation under our limited liability company agreement to distribute available cash on a quarterly basis, which is subject to our board of directors’ authority to establish reserves and other limitations, our unitholders have no contractual or other legal right to receive distributions.

Our board of directors will have broad discretion to establish reserves for the prudent conduct of our business and for future cash distributions, including, during the Incentive Trigger Period, reserves related to the potential payment of the one-time management incentive distribution with respect to the Incentive Trigger Period, and the establishment of those reserves could result in a reduction in cash distributions to you from the levels we currently anticipate pursuant to our stated distribution policy.

Cash distribution policy and restrictions on distributions

Our ability to make distributions of available cash will depend primarily on our cash flow from operations, which will fluctuate from quarter to quarter primarily based on commodity prices, production volumes, investor funds raised and the number of wells we drill. Although our limited liability company agreement provides for quarterly distributions of available cash, we have no prior history of making distributions to our members.

We anticipate that we will be subject to restrictions on distributions under our proposed credit agreement, including customary financial covenants. Should we be unable to satisfy these restrictions or another default or event of default occurs under our credit agreement, we anticipate we would be prohibited from making a distribution to you notwithstanding our stated distribution policy.

Even if we do not modify our cash distribution policy, the amount of distributions we pay and the decision to make any distribution will be determined by our board of directors, taking into consideration the terms of our limited liability company agreement.

We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including the amount of natural gas and oil we produce, the price at which we sell our natural gas and oil, the level of our operating costs, our ability to acquire, locate and produce new reserves, results of our hedging activities, the number of wells we drill, the amount of funds we raise through our investment partnerships, the level of our interest expense and the level of our capital expenditures. See “Risk factors” for information regarding these factors.

Although our limited liability company agreement requires us to distribute our available cash, our limited liability company agreement may be amended with the approval of our board of directors and a majority of our outstanding units, voting as a single class. At the closing of this offering, Atlas America and its affiliates will own approximately 83.0% of the outstanding units (approximately 80.4% if the underwriters exercise their option to purchase additional common units in full) and will have the ability to amend our limited liability company agreement with the approval of our board of directors.

Our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state limited liability company laws and other laws and regulations, including state laws and policies.

Our cash distribution policy limits our ability to grow

Because we distribute our available cash, our growth may not be as significant as businesses that reinvest their available cash to expand ongoing operations. If we issue additional common units or incur debt to fund acquisitions and expansion and investment capital expenditures, the payment of distributions on those additional units or interest on that debt could increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our limited liability company agreement on our ability to issue additional units, including units ranking senior to the common units.

Our ability to grow is dependent on our ability to access external expansion capital

Because we expect that we will distribute our available cash from operations to our unitholders each quarter in accordance with the terms of our limited liability company agreement, we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund any expansion and investment capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow our capital asset base.

Cash distribution policy and restrictions on distributions

OUR INITIAL QUARTERLY DISTRIBUTION RATE

Our cash distribution policy

Upon completion of this offering, our board of directors will adopt a cash distribution policy pursuant to which we will pay an IQD of $0.40 per common unit and Class A unit for each complete quarter. Beginning with the quarter ending September 30, 2006, we will pay our quarterly distribution within 45 days after the end of each quarter ending March, June, September and December to holders of record on the record date established for the distribution. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. In November 2006, we expect to pay a distribution to our unitholders equal to the IQD prorated for the portion of the quarter ending September 30, 2006 that we are public. These distributions will not be cumulative. Consequently, if we do not pay distributions on our common units and Class A units with respect to any fiscal quarter, our unitholders will not be entitled to receive such payments in the future.

If the underwriters exercise their option to purchase additional common units from us, we will use the additional net proceeds from such exercise to redeem from Atlas America an equal number of common units. Accordingly, the exercise of the underwriters’ option will not affect the total amount of units outstanding or the amount of cash needed to pay the IQD rate on all units. Our ability to make cash distributions at the IQD rate pursuant to this policy will be subject to the factors described above under the caption “—Restrictions and limitations on our ability to make quarterly distributions.”

The following table sets forth the assumed number of outstanding common and Class A units upon the closing of this offering and the estimated aggregate amount of available cash from operating surplus, which we also refer to as cash available for distributions, we need to pay the IQD on such units for one full quarter (at the initial rate of $0.40 per unit per quarter) and for four full quarters (at the initial rate of $1.60 per unit on an annualized basis):


		Initial quarterly distribution
	Number of units	One quarter		Four quarters
Common units	33,350,000	$	13,340,000	$	53,360,000
Class A units	680,612		272,245		1,088,979

Total	34,030,612	$	13,612,245	$	54,448,979

The Class A units will be entitled to 2% of all distributions that we make prior to our liquidation. The 2% sharing ratio of the Class A units will not be reduced if we issue additional equity securities in the future.

We do not have a legal obligation to pay distributions at our IQD rate or at any other rate. Our limited liability company agreement requires that we distribute all of our available cash quarterly. Available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount our board of directors determines is necessary or appropriate to provide for the conduct of our business, to comply with applicable law, any of our debt instruments or other agreements or to provide for payment of the one-time management incentive distribution for the Incentive Trigger Period or for future distributions to our unitholders for any one or more of the upcoming four quarters.

Cash distribution policy and restrictions on distributions

In the sections that follow, we present in detail the basis for our belief that we will have sufficient available cash from operating surplus to pay the IQD on all outstanding common units and Class A units for each full calendar quarter through June 30, 2007. In those sections, we present the following two tables:

“Estimated cash available for distribution,” in which we present our estimated EBITDA necessary for us to have sufficient cash available for distribution to pay distributions at the IQD rate on all the outstanding common units and Class A units for each quarter for the twelve months ending June 30, 2007. In the footnotes to this table, we present the significant assumptions and considerations underlying our belief that we will generate this estimated EBITDA.

“Unaudited pro forma cash available for distribution,” in which we present the amount of pro forma available cash we would have had available for distribution to our unitholders in the fiscal year ended September 30, 2005 and the twelve months ended March 31, 2006, based on our pro forma financial statements included elsewhere in this prospectus. Our calculation of pro forma available cash in this table should only be viewed as a general indication of the amount of available cash that we might have generated had we been formed in an earlier period.

FINANCIAL FORECAST

We do not as a matter of course make public projections of financial information. Our forecast information below presents, to our best knowledge and belief, our expected results of operations and cash flows for the twelve-month period ending June 30, 2007. Our forecast financial information reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending June 30, 2007. The assumptions disclosed in the footnotes to the table under the caption “—Estimated cash available for distribution—Estimated EBITDA” below are those that we believe are significant to our forecasted information, but we cannot assure you that our forecast results will be achieved. There will likely be differences between our forecast and actual results, and those differences could be material. If we do not achieve the forecast, we may not be able to pay the full IQD or any distribution amount on our outstanding units.

Our forecast financial information is a forward-looking statement and should be read together with the historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus and together with “Management’s discussion and analysis of financial condition and results of operations” and “Cautionary note regarding forward-looking statements.” In the view of our management, however, such information was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions and considerations on which we base our belief that we can generate the estimated EBITDA necessary for us to have sufficient available cash for distribution on the common units and Class A units at the IQD rate. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

Neither our independent registered public accounting firm, nor any other independent accountants, have compiled, examined or performed any procedures with respect to the prospective financial information contained in this section, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and they assume no responsibility for, and disclaim any association with, the prospective financial information. The independent registered public accounting firm’s reports included elsewhere in this prospectus relate to the appropriately described historical financial information contained in this section. These reports do not extend to the tables and related information

Cash distribution policy and restrictions on distributions

contained in this section and should not be read to do so. In addition, we did not prepare the forecasted financial information:

with a view toward compliance with published guidelines of the SEC or the guidelines established by the American Institute of Certified Public Accountants for preparation and presentation of prospective financial information;

in accordance with GAAP; or

in accordance with procedures applied under the auditing standards of the Public Company Accounting Oversight Board (United States).

We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date in this prospectus. Therefore, you should not place undue reliance on this information.

As a result of the factors described in “—Estimated Cash Available for Distribution” and in the footnotes to the table in that section, we believe we will be able to pay distributions at the IQD rate of $0.40 per unit on all outstanding common units and Class A units for each full calendar quarter in the twelve-month period ending June 30, 2007.

ESTIMATED CASH AVAILABLE FOR DISTRIBUTION

In order to pay the IQD to our unitholders of $0.40 per unit per quarter for the twelve month period ending June 30, 2007, our available cash for distribution must be at least approximately $54.4 million over that period. We estimate that our EBITDA for the twelve-month period ending June 30, 2007 must be approximately $91.1 million in order to generate cash available for distribution to the holders of our common units and Class A units of approximately $54.4 million over that period. We refer to this amount as “Estimated EBITDA.” Estimated EBITDA is intended to be an indicator or benchmark of the amount management considers to be the amount of EBITDA necessary to generate sufficient available cash for us to make cash distributions to our unitholders at our IQD rate of $0.40 per unit per quarter (or $1.60 per common unit and Class A unit per year).

EBITDA is a significant performance metric used by our management to indicate (prior to the establishment of any reserves by our board of directors) the cash distributions we expect to pay to our unitholders. Specifically, this financial measure indicates to investors whether or not we are generating operating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. EBITDA means the sum of net income (loss) plus:

interest (income) expense;

tax expense; and

depreciation, depletion and amortization.

In calculating the estimated cash available for distribution for the twelve month period ending June 30, 2007, we have included amounts for estimated maintenance and investment capital expenditures, as well as average borrowings of $16.5 million for the period to fund a portion of investment capital expenditures. If we do not finance such expenditures with borrowings or issuances of additional common units, we would experience a shortfall in the amount of cash generated from our operations to pay both the aggregate cash distributions on our common units and Class A units and make the investment capital

Cash distribution policy and restrictions on distributions

expenditures we expect to make. Our estimated maintenance, expansion and investment capital expenditures are as follows:

Maintenance capital expenditures are capital expenditures that we expect to make on an ongoing basis to maintain our capital asset base at a steady level over the long term. Examples of maintenance capital expenditures include plugging and abandonment costs and capital expenditures associated with the replacement of equipment and oil and natural gas reserves (including non-proved reserves attributable to undeveloped leasehold acreage), whether through the development, exploitation and production of an existing leasehold or the acquisition or development of a new oil or natural gas property, including to offset expected production declines from our producing properties.

Expansion capital expenditures are those capital expenditures that we expect to make to expand our capital asset base for the longer than short term. The expenditures would include amounts expended to increase the rate of development and production of our existing properties at a rate in excess of that necessary to offset our expected depletion rate decline of existing producing properties and which excess production or operating capacity we expect to extend for longer than the short term. Examples of expansion capital expenditures include the acquisition of reserves or equipment, the acquisition of new leasehold interests, or the development, exploitation and production of an existing leasehold interests, to the extent such expenditures are incurred to increase our capital asset base. For the twelve months ending June 30, 2007, we have not estimated any expansion capital expenditures.

Investment capital expenditures are capital expenditures that are neither maintenance nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Our estimated investment capital expenditures for the twelve months ending June 30, 2007 consist of capital expenditures we expect to make to drill and complete additional development wells in excess of the level of such operations that are necessary to offset our expected depletion rate of our producing properties and replace reserves.

ESTIMATED EBITDA

You should read the information in the footnotes under the caption “—Estimated Cash Available for Distribution” for a discussion of the material assumptions underlying our belief that we will be able to generate Estimated EBITDA of approximately $91.1 million necessary for us to have sufficient cash available for distribution to pay distributions at the IQD rate on all outstanding common units and Class A units for each quarter for the twelve-month period ending June 30, 2007. Our belief is based on those assumptions and reflects our judgment, as of the date of this prospectus, regarding the conditions we expect to exist and the course of action we expect to take over the twelve month period ending June 30, 2007. The assumptions we disclose below are those that we believe are significant to our ability to generate the necessary Estimated EBITDA. If our estimates prove to be materially incorrect, we may not be able to pay the IQD or any amount on our outstanding common units and Class A units during the four calendar quarters ending June 30, 2007.

As shown in the table below, we have also determined that if we achieve the Estimated EBITDA, we would be permitted under the terms of our credit facility to make distributions to our unitholders. In addition, we expect that we will be permitted to make distributions at the IQD rate under our credit facility. Our proposed credit facility will likely limit our ability to pay distributions to the extent we are not in compliance with its terms.

When considering our Estimated EBITDA, you should keep in mind the risk factors and other cautionary statements under the heading “Risk factors” and elsewhere in this prospectus. Any of these risk factors

Cash distribution policy and restrictions on distributions

or the other risks discussed in this prospectus could cause our financial condition and results of operations to vary significantly from those set forth in the table below.

The following table illustrates (i) our Estimated EBITDA that we expect to generate for the twelve months ending June 30, 2007 based on the assumptions and considerations described in the footnotes to the table and (ii) the estimated cash available to pay distributions for the twelve-month period ending June 30, 2007, assuming that the offering was consummated on July 1, 2006. We explain each of the adjustments presented below in the footnotes to the table. All of the amounts for the twelve-month period ending June 30, 2007 in the table and footnotes are estimates.

Estimated cash available for distribution


	Twelve months ending June 30, 2007
	(in thousands, except per unit data and ratios)
Estimated EBITDA(a)	$	91,114
Less:
Cash interest expense(b)		(1,665	)
Estimated maintenance capital expenditures(c)		(35,000	)
Investment capital expenditures(d)		(34,983	)
Plus:
Borrowings and other sources for investment capital expenditures(e)		34,983
Excess proceeds from initial public offering available for distribution(f)		5,000

Estimated cash available for distribution	$	59,449

Expected cash distributions
Annualized IQD per unit(g)	$	1.60

Distributions to our common unitholders	$	53,360
Distributions to our Class A unitholder		1,089

Total distributions to our unitholders(g)	$	54,449

Debt covenant ratios
Funded debt/EBITDA ratio(h)		0.3x
Interest coverage ratio(h)		54.7x
Current ratio(h)		1.2x

Cash distribution policy and restrictions on distributions

(a)

As reflected in the table below, to generate our Estimated EBITDA for the twelve months ending June 30, 2007, we have assumed the following regarding our operations, revenues and expenses:


Gas and oil production key assumptions:
Net natural gas production volume(1)	9,071,142 Mcf
Average natural gas price on hedged volumes(2)	$9.27 per Mcf
Average natural gas price on unhedged volumes(2)	$8.58 per Mcf
Percentage of net gas production assumed to be hedged	61	%
Net crude oil production volume(1)	141,543 Bbls
Average crude oil price(2)	$76.62 per Bbl
Partnership management key assumptions:
Well construction and completion cost mark-up(3)	15	%
Administration and oversight(3)	$15,000 per well
Administration and oversight(3)	$75 per well per month
Gross well services fee range(3)	$200 – $362 per well per month


Estimated EBITDA (in thousands):
Gas and oil production gross operating margin	$ 71,983
Partnership management gross operating margin	41,059

Total gross operating margin(4)	$113,042
General and administrative expense(5)	(22,562	)
Other	634

Estimated EBITDA	$ 91,114

(1)

Our forecasted natural gas and oil production volumes, net to our equity interest in the production of our investment partnerships and including our direct interests in producing wells, for the twelve months ending June 30, 2007 assumes that currently producing wells will produce at the rates forecasted in our March 31, 2006 reserve report. New production from gas and oil wells connected on behalf of our investment partnerships are assumed to produce at rates consistent with wells of similar characteristics. Additionally, we have assumed no significant interruptions of production volumes due to mechanical issues such as compressor breakdowns and sales line maintenance. Further, we have assumed no significant logistical issues related to new well hookups, such as delays in pipeline construction, permitting and right-of-ways which we primarily depend on Atlas Pipeline to complete. The following table outlines historical and estimated natural gas and oil production volumes, net to our equity interest in the production of our investment partnerships and including our direct interests in producing wells:


	Natural gas production (Mcf per day)	Oil production (Bbl per day)	Overall production (Mcfe per day)
Twelve months ended March 31, 2006	21,571	433	24,169
Twelve months ending June 30, 2007	24,852	388	27,180

(2)

Our weighted average net natural gas sales price of $9.00 per Mcf is calculated by taking into account the fact that we have hedged 5,529,859 Mcf (or approximately 61% of our forecasted production volume for the twelve months ended June 30, 2007) at a weighted average natural gas sales price of approximately $9.27 per Mcf, and have unhedged production volumes (3,541,283 Mcf) at an assumed price of $8.58 per Mcf, which is based on the twelve month NYMEX strip at July 10, 2006 for the twelve months ending June 30, 2007.

Cash distribution policy and restrictions on distributions

We have assumed that all of our crude oil production will be sold at spot market prices. Our average natural gas prices for both hedged and unhedged volumes include a positive basis differential and Btu adjustment of $0.46. The following table indicates the commodity prices we expect to receive, inclusive of all basis differential and Btu adjustments.


	Overall natural gas prices per Mcf (inclusive of hedging)		Natural gas prices per Mcf (unhedged portion)		Oil prices per Bbl (spot prices)
Twelve months ending June 30, 2007	$	9.00	$	8.58	$	76.62

(3)

We have assumed that we will raise approximately $211.0 million through investment partnerships in the twelve-month period ending June 30, 2007 and that our equity interest in such partnerships will be approximately 35%. We have assumed that we will drill 805 gross (770 net) wells on behalf of the partnerships, and for each we will receive a 15% mark-up on the investors’ cost to drill and complete the well and a $15,000 administration and oversight fee. We have assumed that we will, on average, operate approximately 6,400 wells per month on behalf of our partnerships, and receive a gross monthly $75 per well administrative fee and a gross monthly well services fee that ranges from $200 to $362 per well. We expect that our well services profit margin will be approximately 44%.

(4)

We have assumed total gross operating margin of $113.0 million for the twelve months ending June 30, 2007, as compared to pro forma total gross operating margin of $97.7 million for the twelve months ended March 31, 2006. The increase in our operating margin is due to anticipated increases in natural gas and oil volumes produced, number of wells drilled and higher commodity prices.

(5)

We have assumed general and administrative expense of $22.6 million for the twelve months ending June 30, 2007, as compared to $13.4 million of pro forma general and administrative expense for the twelve months ended March 31, 2006. The substantial increase in our estimated general and administrative expense is attributable to the fact that, historically, we classified our administrative and oversight fees as reimbursements of our general and administrative costs in accordance with our then existing drilling agreements. Due to a change in our more recent drilling agreements, beginning in the fourth quarter of fiscal 2005, we classify these fees as revenue. As a result, our general and administrative expense has increased since the fourth quarter of fiscal 2005.

(b)

Our estimated cash interest is comprised of the following components:

(i)

Approximately $1.2 million attributable to estimated average borrowings of $16.5 million under our proposed credit facility for the twelve month period ending June 30, 2007 at an estimated interest rate of 7.2% to fund a portion of the $35.0 million of estimated investment capital expenditures. We expect to fund the remaining portion of estimated investment capital expenditures with a portion of estimated funds received from our investment partnerships for the twelve months ending June 30, 2007 which have not yet been applied to the drilling and completion of wells.

(ii)

Approximately $0.5 million of annual commitment fees for the estimated unused portion of our credit facility for the twelve months ending June 30, 2007.

(c)

Our limited liability company agreement requires us to deduct from operating surplus each quarter estimated maintenance capital expenditures as opposed to actual maintenance capital expenditures in order to reduce disparities in operating surplus caused by fluctuations in our actual maintenance capital expenditures. Because of the substantial maintenance capital expenditures we are required to make to maintain our asset base, we estimate that our initial annual estimated maintenance capital

Cash distribution policy and restrictions on distributions

expenditures for purposes of calculating operating surplus will be approximately $35.0 million per year as described in the next paragraph. Our board of directors, including a majority of our conflicts committee, may determine to adjust the annual amount of our estimated maintenance capital expenditures. In years when estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders will be lower than if actual maintenance capital expenditures were deducted from operating surplus.

We estimate that our initial annual estimated maintenance capital expenditures will be approximately $35.0 million per year. Our drilling program assumes that we will drill a total of 805 gross (770 net) wells during the twelve months ending June 30, 2007, of which 366 gross (350 net) wells will constitute maintenance capital projects required to maintain our current production volumes, which comprises $35.0 million of the $70.0 million projected for total capital expenditures. We also have included estimated maintenance capital expenditures of approximately $350,000 per year for potential costs that we may incur for lease renewals and similar expenditures that will enable us to maintain our capital asset base.

(d)

Our investment capital expenditures projected for the twelve-month period ending June 30, 2007 of approximately $35.0 million are expected to be incurred to drill 439 gross (420 net) wells during such period. These newly drilled gross wells would be in excess of the 366 gross (350 net) wells that we project need to be drilled in the twelve months ending June 30, 2007 to offset the expected production decline rate from our existing producing wells. We expect to fund investment capital expenditures as described in (e) below.

(e)

Reflects funding of the $35.0 million of estimated investment capital expenditures for the twelve months ending June 30, 2007 with $16.5 million of estimated average borrowings under our credit facility and a portion of estimated funds received from our investment partnerships for the twelve months ending June 30, 2007 which have not yet been applied to the drilling and completion of wells. In the future, we anticipate that we will continue to utilize these sources of financing to fund investment and expansion capital expenditures. As a result, we do not expect any such capital expenditures to have an immediate impact on available cash for distribution.

(f)

We will retain $5.0 million of the net proceeds from this offering within working capital for the purposes of providing cash available for coverage of the IQD amounts and thus has been included within the estimated cash available to pay distributions. While the $5.0 million will be available to pay distributions, we do not currently expect to use such cash to pay distributions for the forecast period.

(g)

The table below sets forth the assumed number of outstanding common units and Class A units upon the closing of this offering and the full IQD payable on the outstanding common units and Class A units for the twelve-month period ending June 30, 2007.


	Number of units	Estimated distribution per unit		Estimated annual distributions
Common units	33,350,000	$	1.60	$	53,360,000
Class A units	680,612		1.60	$	1,088,979

Total	34,030,612			$	54,448,979

(h)

We would have been in compliance on a pro forma basis with these covenants for the fiscal year

Cash distribution policy and restrictions on distributions

ended September 30, 2005 and the twelve months ended March 31, 2006 and believe we will be in compliance with the funded debt and interest coverage covenants for the twelve months ended June 30, 2007. We expect that our credit facility will permit us to have a lower current ratio for at least the first year of the facility. In addition, we anticipate that a default by us on the payment of any indebtedness in excess of $2.5 million will constitute an event of default under our credit agreement that would prohibit us from making distributions. We expect that our credit facility will permit us to make distributions to our unitholders as long as we are neither in default nor, following such distribution, would not be in default.

In preparing the estimates above, we have assumed that there will be no material change in the following matters, and thus they will have no impact on our Estimated EBITDA:

There will not be any material expenditures related to new federal, state or local regulations in the areas where we operate.

There will not be any material change in the natural gas industry or in market, regulatory and general economic conditions that would affect our cash flow.

We will not undertake any extraordinary transactions that would materially affect our cash flow.

There will be no material nonperformance or credit-related defaults by suppliers, customers or vendors.

While we believe that the assumptions we used in preparing the estimates set forth above are reasonable based upon management’s current expectations concerning future events, they are inherently uncertain and are subject to significant business, economic regulatory and competitive risks and uncertainties, including those described in “Risk factors,” that could cause actual results to differ materially from those we anticipate. If our assumptions are not realized, the actual available cash that we generate could be substantially less than the amount we currently estimate and could, therefore, be insufficient to permit us to pay the full IQD or any amount on all our outstanding common units and Class A units with respect to the four calendar quarters ending June 30, 2007 or thereafter, in which event the market price of the common units may decline materially.

SENSITIVITY ANALYSIS

Our ability to generate sufficient cash from our operations to pay distributions to our unitholders of not less than the IQD per unit for the twelve months ending June 30, 2007 is a function of the following primary variables:

the amount of natural gas and oil we produce;

the price at which we sell our natural gas and oil; and

the amount of funds raised from our investment partnerships.

In the paragraphs below, we discuss the impact that changes in these variables, holding all other variables constant, would have on our ability to generate sufficient cash from our operations to pay the IQD on our outstanding units.

Production volume changes. For purposes of our estimates set forth above, we have assumed that our net gas production totals 9,071,142 Mcf during the twelve months ending June 30, 2007. If our actual net gas production realized during such twelve-month period is 5% more (or 5% less) than such estimate

Cash distribution policy and restrictions on distributions

(that is, if actual net realized production is 9,525,000 Mcf or 8,617,000 Mcf), we estimate that our estimated cash available to pay distributions would change by approximately $3.8 million.

Natural gas price changes. For purposes of our estimates set forth above, we have assumed that our weighted average net realized natural gas sales price for our net production volumes is $9.00 per Mcf. If the average realized natural gas sales price for our net production volumes that are unhedged were to change by $1.00 per Mcf, we estimate that our estimated cash available to pay distributions would change by approximately $3.5 million, assuming no changes in any other variables, and assuming we have hedged approximately 61% of our forecast proved developed production from currently producing wells.

Funds raised changes. For purposes of our estimates set forth above, we have assumed funds raised from our investment partnerships will total $211.0 million during the twelve months ending June 30, 2007. If actual funds raised during such period are 5% more than our estimate, we estimate that our estimated cash available would increase by approximately $1.1 million. If actual funds raised during the period are 5% less than our estimate, we estimate that our estimated cash available would decrease by approximately $1.3 million.

UNAUDITED PRO FORMA AVAILABLE CASH FOR DISTRIBUTION

If we had completed the transactions contemplated in this prospectus on October 1, 2004, our pro forma available cash for distribution would have been $10.6 million for the fiscal year ended September 30, 2005. This amount would have been insufficient by approximately $43.9 million to pay the IQD rate of $0.40 per unit ($1.60 on an annualized basis) on our outstanding common units and Class A units.

If we had completed the transactions contemplated in this prospectus on April 1, 2005, our pro forma available cash for distribution would have been $18.4 million for the twelve months ended March 31, 2006. This amount would have been insufficient by approximately $36.0 million to pay the IQD rate of $0.40 per unit ($1.60 on an annualized basis) on our outstanding common units and Class A units.

Pro forma cash available for distributions excludes any cash from working capital or other borrowings. As described in “How we make cash distributions—Operating Surplus and Capital Surplus,” we may also use cash from these sources for distributions. Pursuant to the terms of our limited liability company agreement, our board of directors would have had the discretionary authority to cause us to borrow funds under our proposed credit facility to make up some or all of this estimated shortfall.

The following table illustrates, on a pro forma basis for fiscal 2005 and the twelve months ended March 31, 2006, cash available to pay distributions, assuming, in each case, that this offering and the related transactions had been consummated at the beginning of the period.

The pro forma financial statements, from which pro forma available cash is derived, do not purport to present our results of operations had the transactions contemplated above actually been completed as of the dates indicated. Furthermore, available cash is a cash accounting concept, while our pro forma financial statements have been prepared on an accrual basis. We derived the amounts of pro forma available cash stated above in the manner described in the table below. As a result, the amount of pro forma available cash should only be viewed as a general indication of the amount of available cash that we might have generated had we been formed and completed the transactions contemplated below in earlier periods.

Cash distribution policy and restrictions on distributions

Unaudited pro forma available cash for distribution


	Pro forma
	Twelve months ended September 30, 2005			Twelve months ended March 31, 2006
	(in thousands, except per unit data and ratios)
Pro forma net income	$	55,182		$	63,233
Plus:
Interest expense		2,910			3,316
Depreciation, depletion and amortization		14,016			17,208

EBITDA(a)		72,108			83,757
Less:
Pro forma cash interest expense(b)		(2,410	)		(2,816	)
Capital expenditures(c)		(59,124	)		(62,537	)

Pro forma available cash	$	10,574		$	18,404

Cash distributions:(d)
Expected distribution per unit	$	1.60		$	1.60

Distributions to our common unitholders	$	53,360		$	53,360
Distributions to our Class A unitholder		1,089			1,089

Cash necessary to pay the IQD to our Class A and common unitholders	$	54,449		$	54,449

Shortfall	$	(43,875	)	$	(36,045	)

Debt covenant ratios
Funded debt/EBITDA(e)		0.2x			0.6x
Interest coverage ratio(e)		29.9x			29.7x
Current ratio(e)		1.1x			0.7x

(a)

EBITDA represents net income before net interest expense, income taxes, and depreciation, depletion and amortization. EBITDA is not a measure of performance calculated in accordance with 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.

(b)

Reflects an increase from historical interest expense, excluding amortization of deferred financing costs, as a result of interest expense principally related to average borrowings under Atlas America’s credit facility for the fiscal year ended September 30, 2005 and the twelve months ended March 31, 2006.

(c)

Gives effect to the capital expenditures for the drilling and completion of new wells and wells that were in the process of being drilled. It also gives effect to other capital expenditures such as facilities and other support equipment. During the twelve months ended September 30, 2005, we drilled and completed a total of 662 gross (216 net) wells. During the twelve months ended March 31, 2006, we drilled and completed 665 gross (221 net) wells. During such periods, we did not characterize capital expenditures as maintenance, investment or expansion and did not plan capital expenditures in a manner intended to maintain or expand our production or asset base. As a result, we have not attempted to characterize the pro forma capital expenditures reflected here as maintenance, investment or expansion.

Cash distribution policy and restrictions on distributions

(d)

The table below sets forth the assumed number of outstanding common units and Class A units upon the closing of this offering and the full IQD payable on them for the twelve month period ending June 30, 2007:


	Number of units	Estimated distribution per unit		Estimated annual distributions
Common units	33,350,000	$	1.60	$	53,360,000
Class A units	680,612		1.60		1,088,979

Total	34,030,612			$	54,448,979

(e)

We have assumed that our new credit facility will contain financial covenants identical to those contained in Atlas America’s current credit facility, which would require us to maintain, as of the end of each fiscal quarter, a ratio of funded debt to EBITDA measured for the preceding twelve months, of not more than 3.5 to 1.0; a consolidated interest coverage ratio measured for the preceding twelve months, of not less than 2.5 to 1.0 and a current ratio of not less than 1.0 to 1.0. We would have been in compliance on a pro forma basis with the funded debt and interest coverage covenants for the fiscal year ended September 30, 2005 and the twelve months ended March 31, 2006. We expect that our credit facility will permit us to have a lower current ratio for at least the first year of the facility. In addition, we anticipate that a default by us on the payment of any indebtedness in excess of $2.5 million will constitute an event of default under our credit agreement that would prohibit us from making distributions. We expect that our credit facility will permit us to make distributions to our unitholders as long as we are neither in default nor, following such distribution, would not be in default.

Selected historical financial data

The following table sets forth selected historical combined financial and operating data for our predecessor, Atlas America E & P Operations, as of and for the periods indicated. Atlas America E & P Operations are the subsidiaries of Atlas America which hold its natural gas and oil development and production assets and liabilities, substantially all of which Atlas America will transfer to us upon the completion of this offering. We derived the historical financial data as of September 30, 2004 and 2005 and for the years ended September 30, 2003, 2004 and 2005 from Atlas America E & P Operations’ financial statements, which were audited by Grant Thornton LLP, independent registered public accounting firm, and are included in this prospectus. We derived the historical financial data as of September 30, 2001, 2002 and 2003 and for the years ended September 30, 2001 and 2002 from Atlas America E&P Operations’ unaudited financial statements, which are not included in this prospectus. We derived the historical financial data for the six months ended March 31, 2005 and 2006 and the balance sheet information as of March 31, 2006 from Atlas America E & P Operations’ unaudited financial statements included in this prospectus.

You should read the following financial data in conjunction with “Management’s discussion and analysis of financial condition and results of operations” and our financial statements and related notes appearing elsewhere in this prospectus.

The following table includes the non-GAAP financial measure of EBITDA. For a definition of EBITDA and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Prospectus summary—Non-GAAP Financial Measures.”

Selected historical financial data


	Years ended September 30,															Six months ended March 31,
	2001			2002			2003			2004			2005			2005			2006
	(unaudited)															(unaudited)
	(in thousands)
Income statement data:
Revenues:
Gas and oil production	$	36,681		$	28,916		$	38,639		$	48,526		$	63,499		$	28,618		$	46,952
Partnership management:
Well construction and completion		43,464			55,736			52,879			86,880			134,338			72,009			93,028
Administration and oversight(1)		—			—			—			—			285			—			4,482
Well services		7,403			7,585			7,635			8,430			9,552			4,598			5,327
Gathering		3,448			3,497			3,898			4,191			4,359			2,058			3,694

Total revenues		90,996			95,734			103,051			148,027			212,033			107,283			153,483
Operating costs:
Gas and oil production and exploration		7,832			8,264			8,486			8,838			9,070			4,215			8,122
Partnership management:
Well construction and completion		36,602			48,443			45,982			75,548			116,816			62,617			80,894
Well services		2,960			3,747			3,773			4,398			5,167			2,507			3,253
Gathering		103			48			29			53			52			27			133
Gathering fee – Atlas Pipeline		13,140			10,756			14,564			17,189			21,929			10,302			15,824

Total operating costs		60,637			71,258			72,834			106,026			153,034			79,668			108,226
Other income (expense):
General and administrative(1)		(7,280	)		(4,240	)		(3,300	)		(1,763	)		(2,992	)		680			(8,984	)
Compensation reimbursement – affiliate		(1,150	)		(1,181	)		(1,400	)		(1,050	)		(602	)		(457	)		(578	)
Depreciation, depletion and amortization		(9,594	)		(9,409	)		(9,938	)		(12,064	)		(14,061	)		(6,385	)		(9,576	)
Other – net		1,197			1,551			358			444			79			61			171

Net income	$	13,532		$	11,197		$	15,937		$	27,568		$	41,423		$	21,514		$	26,290

Cash flow data:
Cash provided by operating activities	$	40,764		$	2,180		$	26,120		$	34,821		$	87,875		$	55,919		$	31,026
Cash used in investing activities		(24,608	)		(15,943	)		(22,112	)		(32,709	)		(59,050	)		(28,966	)		(32,352	)
Cash provided by (used in) financing activities		(394	)		2,289			(5,721	)		(7,214	)		(22,751	)		(19,758	)		90
Capital expenditures		19,105			16,832			22,607			33,252			59,124			29,064			32,477
Other financial information (unaudited):
EBITDA	$	23,126		$	20,606		$	25,875		$	39,632		$	55,484		$	27,899		$	35,866
Balance sheet data (at period end):
Total assets	$	173,319		$	161,464		$	178,451		$	198,454		$	270,402		$	232,349		$	316,652
Liabilities associated with drilling contracts		13,770			4,948			22,157			29,375			60,971			23,060			24,862
Advances from affiliates		53,938			75,602			34,776			30,008			13,897			48,436			51,798
Long-term debt, including current maturities		—			160			194			420			81			110			134
Total debt		53,938			75,762			34,970			30,428			13,978			48,546			51,932
Combined equity		80,228			67,398			102,031			109,461			146,142			128,274			163,745

(1)

Administration and oversight represents supervision and administrative fees earned for drilling wells for our investment partnerships. Due to a change in our more recent drilling agreements, beginning in the fourth quarter of fiscal 2005 we classify administrative and oversight fees as revenue. Before then, we classified these fees as reimbursements of our general and administrative costs in accordance with our then existing drilling agreements.

Management’s discussion and analysis of financial condition and results of operations

The historical financial statements included in this prospectus reflect substantially all the assets, liabilities and operations of various wholly-owned subsidiaries of Atlas America, Inc. to be contributed to us upon the closing of this offering. We refer to these subsidiaries’ assets, liabilities and operations as Atlas America E & P Operations or our predecessor. The following discussion analyzes the financial condition and results of operations of Atlas America E & P Operations. You should read the following discussion of the financial condition and results of operations for Atlas America E & P Operations in conjunction with the historical combined financial statements and notes of Atlas America E & P Operations and the pro forma financial statements for Atlas Energy Resources, LLC included elsewhere in this prospectus. In addition, you should read “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” for information regarding some of the risks inherent in our business.

GENERAL

We were formed in 2006 to own and operate substantially all of the natural gas and oil assets and the investment partnership management business of Atlas America, Inc. (Nasdaq: ATLS). We are managed by Atlas Energy Management, Inc., a subsidiary of Atlas America. Through our manager, the Atlas America personnel currently responsible for managing our assets and capital raising will continue to do so on our behalf upon completion of this offering.

As of March 31, 2006, our assets consisted generally of:

working interests in 6,114 gross producing gas and oil wells;

overriding royalty interests in 632 gross producing gas and oil wells;

proved reserves of 170.4 Bcfe, including the reserves net to our equity interest in the investment partnerships and our direct interests in producing wells;

approximately 528,400 gross (476,500 net) acres, primarily in the Appalachian Basin, over half of which, or 274,900 gross (261,500 net) acres, are undeveloped; and

an interest in a joint venture that gives us the right to drill up to 300 net wells before June 30, 2007 on approximately 209,000 acres in Tennessee.

For the twelve month period ended March 31, 2006, we produced 24,169 Mcfe/d net to our interest in the production of our investment partnerships and including our direct interests in producing wells, which resulted in an average proved reserves to production ratio, or average reserve life, of approximately 19 years based on our proved reserves at March 31, 2006. As of March 31, 2006, we had identified approximately 435 proved undeveloped drilling locations and over 2,200 additional potential drilling locations on our acreage and our Tennessee joint venture acreage.

We fund the drilling of natural gas and oil wells on our acreage by sponsoring and managing tax-advantaged investment partnerships.

Management’s discussion and analysis of financial condition and results of operations

Partnership management. As managing general partner of our investment partnerships, we receive the following fees:

Well construction and completion. For each well that is drilled by an investment partnership, we receive a 15% mark-up on those costs incurred to drill and complete the well.

Well services. Each partnership pays us a monthly per well operating fee, currently $200 to $362, for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well.

Gathering. Historically, each partnership paid us a gathering fee which was typically insufficient to cover all of the gathering fees due to Atlas Pipeline. After the closing, pursuant to the terms of our contribution agreement with Atlas America, our gathering revenues and costs will net to $0. Please read “Certain relationships and related transactions—Agreements Governing the Transactions—The contribution agreement.”

Our revenue, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Historically, natural gas and oil prices have been volatile and may fluctuate widely in the future. Sustained periods of low prices for natural gas or oil could materially and adversely affect our financial position, our results of operations, the quantities of natural gas and oil reserves that we can economically produce and our access to capital.

We utilize the successful efforts method of accounting for our natural gas and oil properties. Unproved properties are assessed periodically within specific geographic areas and impairments are charged to expense. Geological and geophysical expenses and delay rentals are charged to expense as incurred. Drilling costs are capitalized, but charged to expense if the well is determined to be unsuccessful. Generally, if a well does not find proved reserves within one year following completion of drilling, the costs of drilling the well are charged to expense.

Higher natural gas and oil prices have led to higher demand for drilling rigs, operating personnel and field supplies and services and have caused increases in the costs of those goods and services. To date, the higher sales prices have more than offset the higher drilling and operating costs.

Management’s discussion and analysis of financial condition and results of operations

We face the challenge of natural production declines. As initial reservoir pressures are depleted, natural gas production from a given well decreases. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. Our future growth will depend in part on our ability to continue to add reserves in excess of production.

COMPARABILITY OF FINANCIAL STATEMENTS

The historical financial statements of Atlas America E&P Operations included in this prospectus may not be comparable to our results of operations following this offering for the following reasons:

Atlas America will retain 94 wells formerly owned by Atlas Energy Group which includes 573,000 Mcfe of reserves at March 31, 2006, and included in our predecessor’s financial statements. The oil and gas revenues, production costs and depletion expense associated with these assets will not be reflected in our operating results after the completion of this offering.

Historically, pursuant to an agreement with Atlas America, Atlas Pipeline received gathering fees generally equal to 16% of the gas sales price of gas gathered through its system. Each partnership pays us gathering fees generally equal to 10% of the gas sales price. After the closing of this offering, we will pay the amount we receive from the partnerships to Atlas America so that our gathering revenues will net to $0. Atlas America will then remit the full amount due to Atlas Pipeline pursuant to an agreement we will enter into with Atlas America upon the closing of this offering.

Atlas America will also retain a small gathering system with no book value, which accounted for the gathering expense in our predecessor’s income statement.

Because Atlas America did not previously allocate debt or interest expense to its subsidiaries, our historical results of operations do not include interest expense. We anticipate we will incur indebtedness after the closing of this offering which will create interest expense.

BUSINESS SEGMENTS

We operate two business segments:

Our gas and oil production segment, which consists of our interests in oil and gas properties.

Our partnership management segment, which consists of well construction and completion, administration and oversight, well services and gathering activities.

Gas and oil production

As of March 31, 2006, we owned interests in 6,746 gross wells, principally in the Appalachian Basin, of which we operated 5,705. Over the past three fiscal years we have drilled 1,463 wells, 98% of which were successful in producing natural gas in commercial quantities. In September 2004, we expanded our operations into Tennessee through a joint venture with Knox Energy, LLC that gives us an exclusive right to drill up to 300 net wells before June 30, 2007 on approximately 209,000 acres owned by Knox Energy. As of March 31, 2006, we had identified approximately 435 proved undeveloped drilling locations and over 2,200 additional potential drilling locations on our acreage and our Tennessee joint venture acreage which, based on our drilling activity for the twelve months ended March 31, 2006, represents approximately four years’ worth of drilling site inventory.

Our results of operations for our gas and oil production segment are impacted by increases and decreases in the volume of natural gas that we produce, which we refer to as production volumes. Production

Management’s discussion and analysis of financial condition and results of operations

volumes and pipeline capacity utilization rates generally are driven by wellhead production and the number of new wells drilled and connected in our areas of operation and more broadly, by demand for natural gas.

Our results of operations for our gas and oil production segment are also impacted by the prices we receive and the margins we generate. Because of the volatility of the prices for natural gas, as of March 31, 2006 we had financial hedges and forward sales in place for approximately 61% of our expected production for the twelve months ending June 30, 2007. Therefore, we have substantially reduced our exposure to commodity price movements with respect to those volumes under these types of contractual arrangements for this period. For additional information regarding our hedging activities, please read “—Quantitative and Qualitative Disclosures about Market Risk.”

Partnership management

We generally fund our drilling activities through sponsorship of tax-advantaged investment partnerships. Accordingly, the amount of development activities we undertake depends in part upon our ability to obtain investor subscriptions to the partnerships. Historically, our fund-raising cycle has been on a calendar year basis. We raised $148.7 million in fiscal 2005. During fiscal 2005, our investment partnerships invested $157.0 million in drilling and completing wells, of which we contributed $57.3 million.

We generally structure our investment partnerships so that, upon formation of a partnership, we coinvest in and contribute leasehold acreage 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 investment partnerships are a source of fee-based revenues which are not directly dependent on natural gas and oil prices. We generally agree to subordinate up to 50% of our share of production revenues to specified returns to the investor partners, typically 10% per year for the first five years of distributions.

Our investment partnerships provide tax advantages to their investors because an investor’s share of the partnership’s intangible drilling cost deduction may be used to offset ordinary income. Intangible drilling costs include items that do not have salvage value, such as labor, fuel, repairs, supplies and hauling. Historically, under our partnership agreements, 90% of the subscription proceeds received by each partnership are used to pay 100% of the partnership’s intangible drilling costs. For example, an investment of $10,000 has generally permitted the investor to deduct approximately $9,000 in the year in which the investor invests.

Our results of operations for our partnership management segment are impacted by increases and decreases in the number of wells that we drill and the number of wells we operate. Well construction activity is generally driven by commodity prices and demand for natural gas and oil. In addition, the level of funds we raise through investment partnerships will affect the number of wells we drill. Investor funds raised will be also depend on commodity prices and tax laws associated with natural gas and oil.

GENERAL TRENDS AND OUTLOOK

We expect our business to continue to be affected by the risks described in “Risk factors” as well as the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

Management’s discussion and analysis of financial condition and results of operations

Natural gas supply and outlook. We believe that current natural gas prices will continue to cause relatively high levels of natural gas-related drilling in the United States as producers seek to increase their level of natural gas production. Although the number of natural gas wells drilled in the United States has increased overall in recent years, a corresponding increase in production has not been realized, primarily as a result of smaller discoveries and the decline in production from existing wells. We believe that an increase in United States drilling activity, additional sources of supply such as liquefied natural gas, and imports of natural gas will be required for the natural gas industry to meet the expected increased demand for, and to compensate for the slowing production of, natural gas in the United States. The areas in which we operate are experiencing significant drilling activity as a result of recent high natural gas prices, new increased drilling for deeper natural gas formations and the implementation of new exploration and production techniques.

While we anticipate continued high levels of exploration and production activities in the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new natural gas reserves. Drilling activity generally decreases as natural gas prices decrease. We have no control over the level of drilling activity in the areas of our operations.

Impact of inflation. Inflation in the United States did not have a material impact on our results of operations for the three-year period ended September 30, 2005 or the six-month period ended March 31, 2006. It may in the future, however, increase the cost to acquire or replace property, plant and equipment, and may increase the costs of labor and supplies. To the extent permitted by competition and our existing agreements, we have and will continue to pass along increased costs to our investors and customers in the form of higher fees.

RESULTS OF OPERATIONS

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:


										Six months ended
	Years ended September 30,									March 31,
	2003			2004			2005			2005			2006
Production revenues (in thousands):
Gas(1)	$	34,276		$	42,532		$	55,376		$	24,982		$	42,344
Oil	$	4,307		$	5,947		$	8,039		$	3,589		$	4,592
Production volumes:
Gas (Mcf/d)(1)(2)		19,087			19,905			20,892			19,806			21,170
Oil (Bbls/d)		438			495			433			427			427
Total (Mcfe/d)		21,715			22,875			23,490			22,368			23,732
Average sales prices:
Gas (per Mcf)(3)	$	4.92		$	5.84		$	7.26		$	6.93		$	10.99
Oil (per Bbl)	$	26.91		$	32.85		$	50.91		$	46.18		$	59.07
Production costs(4):
As a percent of production revenues		13	%		11	%		10	%		10	%		8	%
Per Mcfe	$	0.61		$	0.63		$	0.71		$	0.71		$	0.84
Depletion per Mcfe	$	1.01		$	1.22		$	1.42		$	1.34		$	2.00

(1)

Excludes sales of residual gas and sales to landowners.

Management’s discussion and analysis of financial condition and results of operations

(2)

(3)

Our average sales price before the effects of financial hedging was $5.08 and $10.24 for fiscal 2003 and six months ended March 31, 2006, respectively; we did not have any financial hedges in the other periods presented.

(4)

Production costs include labor to operate the wells and related equipment, repairs and maintenance, materials and supplies, property taxes, severance taxes, insurance and production overhead and do not include gathering fees.

Our well construction and completion revenues and costs and expenses incurred represent the billings and costs associated with the completion of wells for 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 (dollars in thousands):


	Years ended September 30,						Six months ended March 31,
	2003		2004		2005		2005		2006
Average construction and completion revenue per well	$	187	$	193	$	218	$	210	$	257
Average construction and completion cost per well		163		168		190		183		223

Average construction and completion gross profit per well	$	24	$	25	$	28	$	27	$	34

Gross profit margin	$	6,897	$	11,332	$	17,522	$	9,392	$	12,134

Net wells drilled		282		450		615		343		362

Six months ended March 31, 2006 compared to six months ended March 31, 2005

Gas and Oil Production

Our natural gas revenues were $42.3 million in the six months ended March 31, 2006, an increase of $17.3 million (69%) from $25.0 million in the six months ended March 31, 2005. The increase was attributable to an increase in the average sales price of natural gas of 59% and an increase of 7% in the volume of natural gas produced in the six months ended March 31, 2006. The $17.3 million increase in natural gas revenues consisted of $14.6 million attributable to increases in natural gas sales prices and $2.7 million attributable to increased production volumes.

The increase in our gas production volumes resulted from production associated with new wells drilled for our investment partnerships. We believe that gas volumes will be favorably impacted in the remainder of fiscal 2006 as ongoing projects to extend and enhance the gathering systems of Atlas Pipeline in the Appalachian Basin are completed and wells drilled are connected in these areas of expansion.

Our oil revenues were $4.6 million in the six months ended March 31, 2006, an increase of $1.0 million (28%) from $3.6 million in the six months ended March 31, 2005, primarily due to an increase in the average sales price of oil of 28% for the six months ended March 31, 2006 as compared to the prior year similar period. The $1.0 million increase consisted of $998,000 attributable to increases in sales prices and $2,000 attributable to increased production volumes.

Management’s discussion and analysis of financial condition and results of operations

Our production costs were $5.8 million in the six months ended March 31, 2006, an increase of $1.9 million (48%) from $3.9 million in the six months ended March 31, 2005. This increase includes an increase in labor and maintenance costs associated with an increase in the number of wells we own and operate from the prior year period. The decrease in production costs as a percent of production revenues in the six months ended March 31, 2006 as compared to March 31, 2005 was due to an increase in our average sales price, which more than offset the slight increase in production costs per Mcfe.

Well Construction and Completion

Our well construction and completion gross margin was $12.1 million in the six months ended March 31, 2006, an increase of $2.7 million (29%) from $9.4 million in the six months ended March 31, 2005. During the six months ended March 31, 2006, the increase of $2.7 million was attributable to an increase in the gross profit per well ($2.1 million) and an increase in the number of wells drilled ($637,000). 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 in the six months ended March 31, 2006 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.

It should be noted that “Liabilities associated with drilling contracts” on our balance sheet includes $8.8 million of funds raised in our investment programs in calendar 2005 that have not been applied to the completion of wells as of March 31, 2006 due to the timing of drilling operations, and thus have not been recognized as well construction and completion revenue. We expect to recognize this amount as revenue in the remainder of fiscal 2006. During the six months ended March 31, 2006, we raised $52.5 million and plan to raise approximately $148 million in the third fiscal quarter of 2006. We anticipate oil and gas prices will continue to favorably impact our fundraising and therefore our drilling revenues in the remainder of fiscal 2006.

Administration and Oversight

Administration and oversight represents supervision and administrative fees earned for drilling wells for our investment partnerships. Due to a change in our more recent drilling agreements, beginning in the fourth quarter of fiscal 2005 we classify these fees as revenue. Before then, we classified these fees as reimbursements of our general and administrative costs in accordance with our then existing drilling agreements.

Well Services

Our well services revenues were $5.3 million in the six months ended March 31, 2006, an increase of $728,000 (16%) from $4.6 million in the six months ended March 31, 2005. This increase resulted from an increase in the number of wells operated for our investment partnerships due to additional wells drilled in the twelve months ended March 31, 2006.

Our well services expenses were $3.3 million in six months ended March 31, 2006, an increase of $746,000 (30%) from $2.5 million in the six months ended March 31, 2005. This increase was attributable to an increase in wages, benefits, and field office expenses associated with an increase in employees due to the increase in the number of wells we operate for our investment partnerships.

Gathering

We charge transportation fees to our investment partnership wells that are connected to Atlas Pipeline’s gathering systems. We in turn pay these fees, plus an additional amount to bring the total transportation

Management’s discussion and analysis of financial condition and results of operations

charge up to, generally, 16% of the gas sales price, to Atlas Pipeline in accordance with our gathering agreements with it. Our gathering fee-Atlas Pipeline was $15.8 million for the six months ended March 31, 2006, an increase of $5.5 (53%) million from $10.3 in the six months ended March 31, 2005. The increase in the six months ended March 31, 2006 is primarily a result of higher natural gas prices and increased volumes of gas transported due to an increase in the number of wells we drilled. We also pay our proportional share of gathering fees based on our percentage interest in the well, which are included in gas and oil production and exploration expense. We also own several small gathering systems; the expenses associated with these are shown as gathering fees on our combined statements of income.

Upon the completion of this offering, we will not be obligated to pay gathering fees to Atlas Pipeline. We will be obligated to pay the gathering fees we receive from our investment partnerships to Atlas America, with the result that our gathering revenues and expenses will net to $0.

Other Income, Costs and Expenses

General and administrative. Our general and administrative expenses were $9.0 million in the six months ended March 31, 2006, an increase of $9.7 million from income of $680,000 in the six months ended March 31, 2005. 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.

The increase in the six months ended March 31, 2006 is principally attributed to the following:

General and administrative expense reimbursements from our investment partnerships decreased by $6.5 million as prior year amounts were reduced by reimbursements and credits from our investment partnerships. These reimbursements are now included in revenue as administrative and oversight fees in accordance with a change in our more recent drilling agreements.

Salaries and wages increased $1.5 million due to an increase in executive salaries and in the number of employees as a result of Atlas America’s spin-off from Resource America, Inc.

Professional and legal fees increased $515,000 primarily due to higher audit fees and implementation of Sarbanes-Oxley Section 404 compliance.

Expense recognized in connection with our non-cash stock compensation increased $770,000; there were no such expenses in the prior year similar period.

Directors’ fees increased $566,000 as a result of Atlas America’s spin-off from Resource America.

Compensation reimbursement—affiliate. Our compensation reimbursement—affiliate was $578,000 in the six months ended March 31, 2006, an increase of $121,000 (26%) from $457,000 in the six months ended March 31, 2005. This increase resulted from an increase in allocations from Resource America for executive management and administrative services, including rent allocations for our offices in Philadelphia, PA and New York City.

Depletion. Our depletion of oil and gas properties as a percentage of oil and gas revenues was 18% in the six months ended March 31, 2006, compared to 19% in the six months ended March 31, 2005. Depletion expense per Mcfe was $2.00 in the six months ended March 31, 2006, an increase of $0.66 (49%) per Mcfe from $1.34 in the six months ended March 31, 2005. Increases in our depletable basis and production volumes caused depletion expense to increase to $8.6 million in the six months ended March 31, 2006 compared to $5.5 million in the six months ended March 31, 2005. The variances from period to period are directly attributable to changes in our oil and gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our oil and gas properties.

Management’s discussion and analysis of financial condition and results of operations

Year ended September 30, 2005 compared to year ended September 30, 2004

Gas and Oil Production

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. Rates charged to us for transportation vary based upon agreements put in place at the time the wells are drilled; some of these agreements have escalation clauses. 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 were incurred in 2005.

Well Construction and Completion

Our well construction and completion 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). 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.

It should be noted that “Liabilities associated with drilling contracts” on our balance sheet as of September 30, 2005 included $49.9 million of funds raised in our investment partnerships in fiscal 2005 that had 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 construction and completion revenues. We will recognize this amount as income in the year ending September 30, 2006.

Administration and Oversight

Management’s discussion and analysis of financial condition and results of operations

fourth quarter of 2005 we classify these fees as revenue. Before then, we classified these fees as reimbursements of our general and administrative costs in accordance with our then existing drilling agreements.

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 $769,000 (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.

Gathering

Our gathering fee—Atlas Pipeline was $21.9 million in fiscal 2005, an increase of $4.7 million (27%) from $17.2 million in fiscal 2004. The increase was primarily a result of higher natural gas prices and increased volumes of gas transported due to our increase in the number of wells drilled. We also pay our proportional share of gathering fees based on our percentage interest in the well, which are included in gas and oil production and exploration expense. We also own several small gathering systems; the expenses associated with these are shown as gathering fees on our combined statements of income.

Other Income, Costs and Expenses

General and administrative. Our general and administrative expenses were $3.0 million in fiscal 2005, an increase of $1.2 million (70%) from $1.8 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 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 expense reimbursements from our investment partnerships increased by $3.1 million as we continued to increase the number of wells we drill and manage.

Salaries and wages increased $2.1 million due to an increase in executive salaries and in the number of employees in anticipation of Atlas America’s spin-off from Resource America.

Professional fees and insurance increased $1.5 million, which includes the implementation of Sarbanes-Oxley Section 404.

Office operations, including rent and travel expenses increased $503,000 due to an increase in the number of employees as a result of our continued growth.

Compensation reimbursement—affiliate. Our compensation reimbursement—affiliate was $602,000 in fiscal 2005, a decrease of $448,000 (43%) from $1,050,000 in fiscal 2004. This decrease resulted from a decrease in allocations from Resource America for executive management and administrative services.

Depletion. 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. Increases in our depletable basis and production volumes caused depletion expense to increase $2.0 million to $12.2 million in fiscal 2005 compared to

Management’s discussion and analysis of financial condition and results of operations

$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.

Year ended September 30, 2004 compared to year ended September 30, 2003

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 2004, 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:

The benefit we received for our contribution of well sites to our 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.

Well Construction and Completion

Our well construction and completion 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). The increase in our average cost per well resulted from an increase in the cost of tangible equipment, leases and reclamation expenses.

It should be noted that “Liabilities associated with drilling contracts” on our balance sheet includes $26.5 million of funds raised in our investment partnerships in the fourth quarter of fiscal 2004 that had 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 construction and completion revenues. We recognized this amount as income in fiscal 2005.

Management’s discussion and analysis of financial condition and results of operations

Well Services

Our well services revenues were $8.4 million in fiscal 2004, an increase of $795,000 (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.

Gathering

Our gathering fees—Atlas Pipeline were $17.2 million in fiscal 2004, an increase of $2.6 million (18%) from $14.6 million in fiscal 2005. This increase was primarily a result of higher natural gas sales prices as these fees are generally based on 16% of gas sales ultimately payable to Atlas Pipeline in accordance with its gas gathering agreement with Atlas America.

Other Income, Costs and Expenses

General and administrative. Our general and administrative expenses were $1.8 million in fiscal 2004, a decrease of $1.5 million (47%) from $3.3 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 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 continued to increase the number of wells we drill and manage.

Salaries and wages increased $1.3 million due to an increase in executive salaries and in the number of employees in anticipation of Atlas America’s spin-off from Resource America.

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 $787,000, which includes the implementation of Sarbanes-Oxley Section 404.

Compensation reimbursement—affiliate. Our compensation reimbursement—affiliate was $1.1 million in fiscal 2004, a decrease of $350,000 (25%) from $1.4 million in fiscal 2003. This decrease resulted from a decrease in allocations from Resource America for executive management and administrative services.

Depletion. 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 $0.21 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.

Management’s discussion and analysis of financial condition and results of operations

LIQUIDITY AND CAPITAL RESOURCES

General

We fund our development and production operations with a combination of cash generated by operations, capital raised through investment partnerships, and if required, advances from Atlas America. The following table sets forth our sources and uses of cash (in thousands):


	Years ended September 30,									Six months ended March 31,
	2003			2004			2005			2005			2006
Provided by operations	$	26,120		$	34,821		$	87,875		$	55,919		$	31,026
Used in investing activities		(22,112	)		(32,709	)		(59,050	)		(28,966	)		(32,532	)
Provided by (used in) financing activities		(5,721	)		(7,214	)		(22,751	)		(19,758	)		90

Increase (decrease) in cash and cash equivalents	$	(1,713	)	$	(5,102	)	$	6,074		$	7,195		$	(1,236	)

We had $5.0 million in cash and cash equivalents at March 31, 2006, as compared to $6.2 million at September 30, 2005. We had negative working capital of $78.5 million at March 31, 2006, an increase in working capital of $703,000 from ($79.2) million in September 30, 2005.

Capital requirements

During the six months ended March 31, 2006, our capital expenditures related primarily to investments in our investment partnerships, in which we invested $32.1 million. For the six months ended March 31, 2006 and the remaining quarters of fiscal 2006, we funded and expect to continue to fund these capital expenditures through cash on hand, from operations and, until the closing of this offering, from advances from Atlas America. In fiscal 2005, 2004 and 2003 our capital expenditures related to investments in our investment partnerships totaled $57.9 million, $32.2 million and $21.3 million, respectively.

The level of capital expenditures we must devote to our development and production operations depends upon the level of funds raised through our investment partnerships. We have budgeted to raise up to $200.0 million in fiscal 2006 through investment partnerships. Through the six months ended March 31, 2006 we had raised $52.5 million, as compared to $62.3 million through the six months ended March 31, 2005. We believe cash flows from operations and amounts available under our proposed 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. During fiscal 2005, 2004 and 2003 we raised $148.7 million, $107.7 million and $66.1 million, respectively.

We expect to fund our maintenance capital expenditures with cash flow from operations and the temporary use of funds raised in our investment partnerships in the period before we invest these funds, while funding our investment capital expenditures and any expansion capital expenditures that we might incur with borrowings under our new credit facility as well as with the temporary use of funds raised in our investment partnerships in the period before we invest the funds. We estimate investment capital expenditures of $35.0 million during the twelve month period ending June 30, 2007, and no expansion capital expenditures, although that may change if opportunities are available to us in that period. We also estimate that we will have sufficient cash flow from operations after funding our maintenance capital expenditures to enable us to make our quarterly cash distributions in the amount of the IQD to unitholders through June 30, 2007. See “Cash distribution policy and restrictions on cash distributions.”

Management’s discussion and analysis of financial condition and results of operations

We continuously evaluate acquisitions of gas and oil 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.

Proposed credit facility

Simultaneously with the closing of this offering, we anticipate entering into a senior secured revolving credit facility. We anticipate that the credit facility will be substantially similar to Atlas America’s current credit facility and that it will allow us to borrow up to the determined amount of the borrowing base, which will be based upon the loan collateral value assigned to our various natural gas and oil properties.

CASH FLOWS

Six months ended March 31, 2006 compared to March 31, 2005

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 investment partnerships. Net cash provided by operating activities decreased $24.9 million in the six months ended March 31, 2006 to $31.0 million from $55.9 million in the six months ended March 31, 2005, substantially as a result of the following:

Advances from affiliates were $1.9 million lower in the six months ended March 31, 2006 as compared to the six months ended March 31, 2005.

Changes in operating assets and liabilities decreased operating cash flow by $31.7 million in the six months ended March 31, 2006, compared to the six months ended March 31, 2005. 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 investment partnerships.

These decreases were partially offset by an increase in net income before depreciation and amortization of $8.0 million in the six months ended March 31, 2006 as compared to the prior year period, principally as a result of higher natural gas and oil prices and drilling profits.

Investing activities. Cash used in our investing activities increased $3.4 million in the six months ended March 31, 2006 to $32.4 million from $29.0 million in the six months ended March 31, 2005 primarily as a result of an increase in capital expenditures of $3.4 to $32.5 million due to an increase in the number of wells we drilled.

Financing activities. Cash provided by our financing activities increased $19.8 million in the six months ended March 31, 2006 to $90,000 from cash used of $19.8 million in the six months ended March 31, 2005 as a result of payments to Resource America primarily related to our share of income taxes included in Resource America’s income tax return which were $19.4 million in the six months ended March 31, 2005. As a result of Atlas America’s spin-off from Resource America, there was no such payment made in the six months ended March 31, 2006.

Year ended September 30, 2005 compared to year ended September 30, 2004

Operating activities. Net cash provided by operating activities increased $53.1 million in fiscal 2005 to $87.9 million from $34.8 million in fiscal 2004, substantially as a result of the following:

A decrease in net advances to affiliates increased operating cash flows by $14.3 million.

Management’s discussion and analysis of financial condition and results of operations

An increase in net income before depreciation, depletion and amortization of $15.9 million in fiscal 2005 as compared to the prior fiscal year principally a result of higher natural gas prices and drilling profits.

Changes in operating assets and liabilities increased operating cash flows by $22.2 million in fiscal 2005, compared to fiscal 2004, primarily due to increases in accounts payable, accrued liabilities and advance payments on our drilling contracts. 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 investment partnerships.

Investing activities. Net cash used in our investing activities increased $26.3 million in fiscal 2005 to $59.0 million from $32.7 million in fiscal 2004 primarily from a $25.9 million increase in capital expenditures related to the increase in the number of wells drilled.

Financing activities. Net cash used in our financing activities increased $15.6 million in fiscal 2005 to $22.8 million from $7.2 million in fiscal 2004, as a result of the following:

Payments to Resource America 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 by Atlas America to Resource America in fiscal 2004 as part of the transactions leading to Atlas America’s spin-off from Resource America.

We received proceeds of $37.0 million in fiscal 2004 from Atlas America’s initial public offering common stock; there were no such offerings in fiscal 2005.

Year ended September 30, 2004 compared to year ended September 30, 2003

Operating activities. Net cash provided by operating activities increased $8.7 million in fiscal 2004 to $34.8 million from $26.1 million in fiscal 2003, substantially as a result of the following:

Changes in operating assets and liabilities decreased operating cash flow by $16.1 million in fiscal 2004 compared to fiscal 2003, primarily due to increases in accounts payable, accrued liabilities and advance payments on our drilling contracts. 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 investment partnerships.

An increase in net income before depreciation, depletion and amortization of $13.8 million in fiscal 2004 as compared to the prior fiscal year principally a result of higher natural gas prices and drilling profits.

A decrease in repayments to affiliate increased operating cash flows by $11.1 million.

Investing activities. Net cash used in our investing activities increased $10.6 million in fiscal 2004 to $32.7 million from $22.1 million in fiscal 2003 primarily as a result of increases in our capital expenditures related to the increase in the number of wells we drilled.

Financing activities. Net cash used in our financing activities increased $1.5 million in fiscal 2004 to $7.2 million from $5.7 million in fiscal 2003, as a result of the following:

We received proceeds of $37.0 million from Atlas America’s initial public offering in fiscal 2004.

Management’s discussion and analysis of financial condition and results of operations

Payments to Resource America in the form of repayments of advances and dividends increased by $38.7 million, principally as a result of a one-time special dividend paid by Atlas America to Resource America in fiscal 2004 as part of the transactions leading to Atlas America’s spin-off from Resource America.

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 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 the six months ended March 31, 2006 and 2005, we received an average of $10.99 and $6.93 per Mcf of natural gas and $59.07 and $46.18 per Bbl of oil, respectively. 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 of oil 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. For instance, we are evaluating the impact of spill prevention plan requirements on our operations, including pending changes by United Stated Environmental Protection Agency to the federal regulations that require compliance by October 31, 2007. 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 six months ended March 31, 2006 or year ended September 30, 2005. In the year ended September 30, 2004, Atlas America paid dividends of $52.1 million to Resource America.

Following the closing of this offering, we intend to make cash distributions to our common units and Class A units at an initial distribution rate of $0.40 per unit per quarter ($1.60 per unit on an annualized basis). As required by our limited liability company agreement, we expect to distribute all of our available cash. As a result, we expect that we will rely upon external financing sources, including commercial borrowings and other debt and common unit issuances, to fund our acquisition and expansion capital expenditures, as well as our working capital needs.

Management’s discussion and analysis of financial condition and results of operations

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

The following table summarizes our contractual obligations at March 31, 2006.


			Payments due by period (in thousands)
Contractual cash obligations:	Total		Less than 1 year		2 – 3 Years		4 – 5 Years		After 5 years
Total debt	$	134	$	81	$	53	$	—	$	—
Secured revolving credit facilities		—		—		—		—		—
Operating lease obligations		1,487		442		680		363		2
Capital lease obligations		—		—		—		—		—
Unconditional purchase obligations		—		—		—		—		—
Other long-term obligations		—		—		—		—		—

Total contractual cash obligations	$	1,621	$	523	$	733	$	363	$	2


			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	$	6,475	$	6,475	$	—	$	—	$	—
Guarantees		—		—		—		—		—
Standby replacement commitments		—		—		—		—		—
Other commercial commitments		—		—		—		—		—

Total commercial commitments	$	6,475	$	6,475	$	—	$	—	$	—

CRITICAL ACCOUNTING POLICIES

The discussion and analysis of our financial condition and results of operations are based upon our combined 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, 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.

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

Management’s discussion and analysis of financial condition and results of operations

energy customers. At March 31, 2006 and September 30, 2005 and 2004, our credit evaluation indicated that we have no need for an allowance for possible losses for our oil and gas receivables.

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. As of March 31, 2006, 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.

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 $35.2 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

Management’s discussion and analysis of financial condition and results of operations

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, our investment partnerships. These investment partnerships raise capital from investors to drill gas and oil wells. We serve as the managing general partner of the investment partnerships and assume customary rights and obligations for them. As a 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 investment partnerships to drill partnership wells. The contracts require that the investment 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 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.

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

Management’s discussion and analysis of financial condition and results of operations

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. 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 was 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. The adoption of FIN 47 did not have a significant impact on our financial position or results of operations.

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 March 31, 2006. Only the potential impacts of hypothetical assumptions are analyzed. The analysis does not consider other possible effects that could impact our business.

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 forward sales contracts. 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.

Management’s discussion and analysis of financial condition and results of operations

We also negotiate with certain purchasers for delivery of a portion of 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. Our risk management objective is to lock in a range of pricing for expected production volumes. Considering those volumes for which we have entered into forward sales or hedge agreements for the period ending March 31, 2007, 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 $2.5 million.

We also enter into natural gas futures and option contracts. At any point in time, such contracts may include regulated 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.

We formally document 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. We assess, 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. Changes in fair value are recognized in combined equity and recognized within the combined statements of income in the month the hedged commodity 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 reference prices underlying a hedging instrument and actual commodity prices, we will discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will be recognized immediately into earnings.

For the twelve month period ending March 31, 2007, we have hedged, through both forward sales and financial hedges, approximately 65% of our natural gas volumes. At March 31, 2006, we had allocated to us 108 open natural gas futures contracts related to natural gas sales covering 34.6 million MMBtus of natural gas, maturing through December 31, 2009 at a combined average settlement price of $8.94 per MMBtu. We recognized a gain of $1.4 million on settled contracts covering natural gas production for the six months ended March 31, 2006. We recognized no gains or losses during the six months ended March 31, 2006 for hedge ineffectiveness or as a result of the discontinuance of these cash flow hedges. We did not recognize any gains or losses on hedging in the six months ended March 31, 2005.

At September 30, 2005 and 2004, we had no open natural gas futures contracts allocated to us related to natural gas sales and accordingly, had no unrealized loss or gain related to open NYMEX contracts at that date. We recognized a loss of $1.1 million on settled contracts covering natural gas production for the year ended September 30, 2003. We recognized no losses on settled contracts for the years ended September 30, 2004 and 2005. We 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.

Management’s discussion and analysis of financial condition and results of operations

As of March 31, 2006, we had the following natural gas hedged volumes allocated to us:


Twelve month period ending March 31,	Volumes(1) (MMBtu)	Average fixed price (per MMBtu)		Fair value liability(2) (in thousands)
2007	4,080,000	$	10.76	$	8,299
2008	14,640,000		8.76		(11,153	)
2009	12,210,000		8.71		(495	)
2010	3,690,000		8.35		1,244

	34,620,000			$	(2,105	)

(1)

Includes volumes hedged on behalf of our investment partnerships. Reflects financial hedges only.

(2)

Fair value based on forward NYMEX natural gas prices, as applicable, on March 31, 2006.

Of the $2.1 million net unrealized hedge loss, our retained portion is $696,000 and $1.4 million has been reallocated to our investment partnerships.

Business

OVERVIEW

We were formed in 2006 to own and operate substantially all of the natural gas and oil assets and the investment partnership management business of Atlas America, Inc. (Nasdaq: ATLS). Atlas America has been involved in the energy industry since 1968, expanding its operations in 1998 when it acquired The Atlas Group and in 1999 when it acquired Viking Resources Corporation, both engaged in the development and production of natural gas and oil and the sponsorship of investment partnerships.

As of March 31, 2006, our principal assets consisted of:

working interests in 6,114 gross producing gas and oil wells;

overriding royalty interests in 632 gross producing gas and oil wells;

proved reserves of 170.4 Bcfe, including the reserves net to our equity interest in the investment partnerships and our direct interests in producing wells;

approximately 528,400 gross (476,500 net) acres, primarily in the Appalachian Basin, over half of which, or 274,900 gross (261,500 net) acres, are undeveloped; and

an interest in a joint venture that gives us the right to drill up to 300 net wells before June 30, 2007 on approximately 209,000 acres in Tennessee.

Business

Gas and oil production. We receive an interest in each investment partnership proportionate to the value of our coinvestment in it and the value of the acreage we contribute to it, typically 27% to 30% of the overall capitalization of a particular partnership. We also receive an incremental interest in each partnership, typically 7%, for which we do not make any additional capital contribution. Consequently, our equity interest in the reserves and production of each partnership is typically between 34% and 37%.

Partnership management. As managing general partner of our investment partnerships, we receive the following fees:

Well construction and completion. For each well that is drilled by an investment partnership, we receive a 15% mark-up on those costs incurred to drill and complete the well.

Administration and oversight. For each well drilled by an investment partnership, we receive a fixed fee of approximately $15,000. Additionally, the partnership pays us a monthly per well administrative fee of $75 for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well.

Gathering. Historically, each partnership paid us a gathering fee which was typically insufficient to cover all of the gathering fees due to Atlas Pipeline. After the closing, pursuant to the terms of our contribution agreement with Atlas America, our gathering revenues and costs will net to $0. Please read “Certain relationships and related transactions—Agreements Governing the Transactions—The contribution agreement.”

BUSINESS STRATEGY

The key elements of our business strategy are:

Expand our fee-based revenue through continued growth in our sponsorship of investment partnerships. We generate substantial revenue and net income from fees paid by the investment partnerships to us for acting as the managing general partner. As we continue to sponsor investment partnerships, we expect that our fee revenues from our drilling and operating agreements with our investment partnerships will continue to increase.

Business

COMPETITIVE STRENGTHS

We believe our competitive strengths favorably position us to execute our business strategy and to maintain and grow our distributions to unitholders. Our competitive strengths are:

Our partnership management business improves the economic rates of return associated with our gas and oil production activities. A well drilled, net to our equity interest, in our partnership management business will generate a higher rate of return to us than if we had taken a 100% economic interest in such well and drilled it outside of our partnership management business. For each well drilled in a partnership we receive an upfront 15% markup on the investors’ well construction and completion costs and an approximate $15,000 fixed administration and oversight fee. Further, we receive an approximate 7% incremental equity interest in each well, for which we do not make any corresponding capital contribution. Consequently, our economic interest in each well is significantly greater than our proportional contribution to the total cash costs which enhances our overall rate of return. Additionally, we receive monthly per well fees from the partnership for the life of each individual well, which also increases our rate of return.

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Fee-based revenues from our investment partnerships provide a stable foundation for our distributions. Our investment partnerships provide stable, fee-based revenues which diminish the influence of commodity price fluctuations on our cash flows. Our fees for managing our investment partnerships accounted for 29% of our gross margin in fiscal 2005, 28% in fiscal 2004 and 26% in fiscal 2003. In addition, because our investment partnerships reimburse us on a cost-plus basis for drilling capital expenses, we are partially protected against increases in drilling costs.

We are a leading sponsor of tax-advantaged investment partnerships. Through our predecessors, we have sponsored limited and general partnerships to raise funds from investors to finance our development drilling activities since 1968, and we believe that we are one of the leading sponsors of such investment partnerships in the country. We believe that our lengthy association with many of the broker-dealers that act as placement agents for our investment partnerships provide us with a competitive advantage over entities with similar operations. We also believe that our sponsorship of investment partnerships has allowed us to generate attractive returns on drilling, operating and production activities.

We have a high quality, long-lived reserve base. Our natural gas properties are located principally in the Appalachian Basin and are characterized by long-lived reserves, a high success rate in drilling and completing wells, favorable pricing for our production and readily available transportation. For the twelve month period ended March 31, 2006, we produced 24,169 Mcfe/d to our interest, which resulted in an average reserve life of approximately 19 years based on our proved reserves at March 31, 2006. Moreover, because our production in the Appalachian Basin is located near markets in the northeast United States, we believe we will generally receive a premium over quoted prices on the NYMEX for the natural gas we produce. This premium has ranged between $0.33 to $0.46 per Mcf during the past three fiscal years.

We have a significant inventory of future drilling locations and undeveloped acreage. We have 261,461 net undeveloped acres relative to 214,954 net developed acres. We believe our inventory of undeveloped acreage, as well as identified drilling opportunities, will permit us to sustain our projected levels of drilling activity for several years without additions to our property holdings. Further, we believe that the size of our undeveloped acreage position relative to our developed acreage position provides us with organic opportunities to significantly expand our production base.

We have long-standing relationships with regional drilling contractors, service providers and equipment vendors. We have drilled and operated wells in the Appalachian Basin since 1968. Over this extended period of time, we have provided reliable, consistent and repeated business to small regional drilling contractors, service providers and equipment vendors which has resulted in unique, long-standing relationships that we believe provide us with a competitive advantage over other Appalachian exploration and production companies.

Our relationship with Atlas Pipeline gives us reliable access to the markets we serve and reduces capital expenditures we would otherwise incur. We transport our natural gas through gathering lines operated by Atlas Pipeline (NYSE: APL), for which an affiliate of Atlas America acts as general partner. Atlas Pipeline’s 1,500 miles of gathering systems in the Appalachian Basin are situated throughout the areas in which we drill other than Tennessee, are readily accessible by us, and are connected to major regional and interstate utility pipelines. Atlas Pipeline is required to extend its gathering system to our well if we extend sales and flow lines to within 1,000 feet of the gathering system, while we must connect to the gathering system any well we drill and operate that is within 2,500 feet of it. Our relationship with Atlas Pipeline permits us to have reliable access to the natural gas markets we serve and significantly reduces

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the capital we would otherwise expend to connect our wells to a pipeline system in order to transport the gas to those markets.

Through our manager, we have significant engineering, geologic and management experience in our core Appalachian Basin operating area. Our manager’s technical team of 14 geologists and engineers has extensive industry experience, principally in the Appalachian Basin. We believe that we have been one of the most active drillers in our core operating area and, as a result, that we have accumulated extensive geological and geographical knowledge about the area.

APPALACHIAN BASIN OVERVIEW

The Appalachian Basin includes the states of Kentucky, Maryland, New York, Ohio, Pennsylvania, Virginia, West Virginia and Tennessee. It is the most mature oil and gas producing region in the United States, having established the first oil production in 1860. Because the Appalachian Basin is located near the energy-consuming regions of the mid-Atlantic and northeastern United States, Appalachian producers have historically sold their natural gas at a premium to the benchmark price for natural gas on the NYMEX. For the year ended September 30, 2005, the average premium over NYMEX for natural gas delivered to our primary delivery points in the Appalachian Basin was $0.37 per MMBtu. In addition, most of our natural gas production has a high Btu content, resulting in an additional premium to NYMEX natural gas prices.

During the first several years of production, Appalachian Basin wells generally experience higher initial production rates and decline rates which are followed by an extended period of significantly lower production rates and decline rates.

Shallow reserves in the Appalachian Basin are typically in blanket formations and have a high degree of step-out development success; that is, as development progresses, reserves from newly completed wells are reclassified from the proved undeveloped to the proved developed category and additional adjacent locations are added to proved undeveloped reserves. As a result, the cumulative amount of total proved reserves tends to increase as development progresses. Wells in the Appalachian Basin generally produce little or no water, contributing to a low cost of operation. In addition, most wells produce dry natural gas, which does not require processing.

GAS AND OIL PRODUCTION

In September 2004, we expanded our operations into Tennessee through a joint venture with Knox Energy that gives us an exclusive right to drill up to 300 wells before June 30, 2007 on approximately 209,000 acres owned by Knox Energy. Please read “—Tennessee Joint Venture Agreement.” As of March 31, 2006, we had identified approximately 435 proved undeveloped drilling locations and over 2,200 additional potential drilling locations on our acreage and our Tennessee joint venture acreage which, based on our drilling activity for the twelve months ended March 31, 2006, represents approximately four years’ worth of drilling site inventory.

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The following table sets forth, for the periods indicated, revenues, net production of oil and natural gas sold, average sales price per unit of oil and natural gas and costs and expenses associated with the production of natural gas and oil. Revenues shown in this table do not reflect the impact of any hedges for the periods indicated in order to show revenues on a consistent basis for the periods presented.


	For the fiscal year ended September 30,						For the six months ended March 31, 2006
	2003		2004		2005		For the six months ended March 31, 2006
	(dollars in thousands, except where indicated)
Sales:
Natural gas
Revenue(1)	$	34,276	$	42,532	$	55,376	$	39,441
Production sold (Mcf/d)		19,087		19,905		20,892		21,170
Average sales price per Mcf(1)	$	5.08	$	5.84	$	7.26	$	10.24
Oil
Revenue	$	4,307	$	5,947	$	8,039	$	4,592
Production sold (Bbl/d)		438		495		433		427
Average sales price per Bbl	$	26.91	$	32.85	$	50.91	$	59.07
Costs and expenses:
Production costs per Mcfe(2)	$	0.61	$	0.63	$	0.71	$	0.84
Depletion per Mcfe	$	1.01	$	1.22	$	1.42	$	2.00

(1)

Excludes the effects of any hedges and price risk management activities.

(2)

Excludes charges for gathering fees.

PRODUCTIVE WELLS

The following table sets forth information as of March 31, 2006 regarding productive natural gas and oil wells in which we have a working interest. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, directly or through our ownership interests in investment partnerships, and net wells are the sum of our fractional working interests in gross wells, based on the percentage interest we own in the investment partnership that owns the well.


	Number of productive wells
	Gross(1)	Net(1)
Oil wells	491	335
Gas wells	5,623	2,766

Total	6,114	3,101

(1)

Includes our proportionate interest in wells owned by 91 investment partnerships for which we serve as managing general partner and various joint ventures. Does not include royalty or overriding interests in 621 wells.

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DEVELOPED AND UNDEVELOPED ACREAGE

The following table sets forth information about our developed and undeveloped natural gas and oil acreage as of March 31, 2006. The information in this table includes our proportionate interest in acreage owned by investment partnerships. The table does not include the approximately 209,000 acres in Tennessee covered by our joint venture with Knox Energy because we do not own this acreage.


	Developed acreage(1)		Undeveloped acreage(2)
	Gross(3)	Net(4)	Gross(3)	Net(4)
Arkansas	2,560	403	0	0
Kansas	160	20	0	0
Kentucky	924	462	9,060	4,530
Louisiana	1,819	206	0	0
Mississippi	40	3	0	0
Montana	0	0	2,650	2,650
New York	20,517	15,053	38,563	38,563
North Dakota	639	96	0	0
Ohio	114,674	95,417	38,022	34,555
Oklahoma	4,323	468	0	0
Pennsylvania	98,248	98,248	175,680	175,680
Tennessee	4,040	3,710	0	0
Texas	4,520	329	0	0
West Virginia	1,078	539	10,806	5,403
Wyoming	0	0	80	80

Total	253,542	214,954	274,861	261,461

(1)

Developed acres are acres spaced or assigned to productive wells.

(2)

Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil, regardless of whether such acreage contains proved reserves.

(3)

A gross acre is an acre in which we own a working interest. The number of gross acres is the total number of acres in which we own a working interest.

(4)

Net acres is the sum of the fractional working interests owned in gross acres. For example, a 50% working interest in an acre is one gross acre but is 0.50 net acre.

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 and $335,000 for the six months ended March 31, 2006 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.

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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 number of wells we drill will vary depending on the amount of money we raise through our investment partnerships, the cost of each well, the estimated recoverable reserves attributable to each well and accessibility to the well site. 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 we initiated drilling.


	Development wells				Exploratory wells
	Productive		Dry		Productive		Dry
	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)
Six months ended March 31, 2006	372.0	123.4	—	—	—	—	—	—
Fiscal year 2005	644.0	210.0	18.0	6.3	—	—	—	—
Fiscal year 2004	493.0	160.5	11.0	3.8	—	—	1.0	1.0
Fiscal year 2003	295.0	92.9	1.0	0.3	—	—	—	—

(1)

Includes the number of physical wells in which we hold any working interest, regardless of our percentage interest.

(2)

Includes (i) our percentage interest in wells in which we have a direct ownership interest and (ii) with respect to wells in which we have an indirect ownership interest through our investment partnerships, our percentage interest in the wells based on our percentage interest in our investment partnerships and not those of the other partners in our investment partnerships.

INVESTMENT PARTNERSHIPS

We generally fund our drilling activities through sponsorship of tax-advantaged investment partnerships. Accordingly, the amount of development activities we undertake depends in part upon our ability to obtain investor subscriptions to the partnerships. We raised $148.7 million in fiscal 2005 through our investment partnerships. During fiscal 2005, our investment partnerships invested $157.0 million in drilling and completing wells, of which we contributed $57.3 million.

We generally structure our investment partnerships so that, upon formation of a partnership, we coinvest in and contribute leasehold acreage to it, enter into drilling and well operating agreements with it and become its managing general partner. In addition to providing capital for our drilling activities, our investment partnerships are a source of fee-based revenues which are not directly dependent on natural gas and oil prices. We receive an interest in our investment partnerships proportionate to the amount of capital and the value of the leasehold acreage we contribute, typically 27% to 30% of the overall capitalization in a particular partnership. We also receive an additional interest in each partnership, typically 7%, for which we do not make any additional capital contribution.

We generally agree to subordinate up to 50% of our share of production revenues to specified returns to the investor partners, typically 10% per year for the first five years of distributions. We have not subordinated our share of revenues from any of our investment partnerships since March 2005, but did subordinate $91,000 in fiscal 2005, $335,000 in fiscal 2004 and $362,000 in fiscal 2003. We do not believe any amounts which may be subordinated in the future will be material to our operations.

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The following table sets forth, as of March 31, 2006, information with respect to our investment partnerships formed since January 1, 2001. In addition to these partnerships, we also manage 76 other investment partnerships which we acquired or formed before January 1, 2001.


Partnership	Investor capital		Our capital		Total capital		Date opera- tions began	Gross wells			Net wells			Cumula- tive gather- ing fees		Cumulative operator’s charges		Cumulative reimburse- ment of general and adminis- trative overhead
Partnership	Investor capital		Our capital		Total capital		Date opera- tions began	Oil	Gas	Dry	Oil	Gas	Dry	Cumula- tive gather- ing fees		Cumulative operator’s charges
Atlas America—Series 21-A	$	12,510,713	$	4,535,799	$	17,046,512	05/15/01	0	68	0	0	62.50	0.00	$	647,967	$	1,417,186	$	248,854
Atlas America—Series 21-B		17,411,825		6,442,761		23,854,586	09/19/01	0	89	2	0	84.05	1.00		837,874		1,743,123		297,215
Atlas America—Public #10		21,281,170		7,227,432		28,508,602	12/31/01	0	107	3	0	103.15	3.00		1,164,755		1,793,259		343,159
Atlas America—Series 22		10,156,375		3,481,591		13,637,966	05/31/02	0	51	1	0	49.55	1.00		527,848		815,415		152,254
Atlas America—Series 23		9,644,550		3,214,850		12,859,400	09/30/02	0	47	1	0	47.00	1.00		496,656		722,010		139,200
Atlas America—Public #11-2002		31,178,145		13,295,226		44,473,371	12/31/02	0	167	0	0	160.50	0.00		1,253,649		2,489,460		414,963
Atlas America—Series #24-2003(A)		14,363,955		4,949,143		19,313,098	05/31/03	0	76	0	0	69.50	0.00		419,341		880,379		150,731
Atlas America—Series #24-2003(B)		20,542,850		7,300,020		27,842,870	08/29/03	0	121	1	0	113.00	1.00		720,172		1,352,650		207,075
Atlas America—Public #12-2003		40,170,308		13,708,076		53,878,384	12/31/03	0	226	1	0	214.25	1.00		1,083,640		2,041,839		344,625
Atlas America—Series #25-2004(A)		27,601,053		10,266,771		37,867824	05/31/04	0	137	4	0	130.80	4.00		733,337		1,026,744		138,593
Atlas America—Series #25-2004(B)		31,531,035		16,006,953		47,537,988	08/31/04	0	171	4	0	153.40	4.00		412,378		1,028,214		131,299
Atlas America—Public #14-2004		52,506,570		25,971,721		78,478,291	11/15/04	0	262	5	0	245.50	5.00		458,381		1,081,562		125,768
Atlas America—Public #14-2005(A)		69,674,900		30,912,583		100,587,483	06/17/05	0	332	4	0	313.69	4.00		279,021		754,019		72,967
Atlas America—Series #26-2005		34,886,465		15,903,570		50,790,035	09/16/05	0	110	1	0	105.31	1.00		5,551		0		0
Atlas America—Public #15-2005(A)		52,245,720		21,412,609		73,658,329	12/31/05	0	46	0	0	45.50	0.00		466		0		0

TENNESSEE JOINT VENTURE AGREEMENT

We have a drilling and operating agreement, dated September 15, 2004, with Knox Energy which creates an Area of Mutual Interest, which we refer to as the AMI, covering approximately 209,000 acres in Anderson, Campbell, Scott and Morgan counties in Tennessee. The agreement gives us the exclusive right to propose and drill up to 300 net wells through June 30, 2007. At the option of Knox Energy, the agreement may be extended through June 30, 2009, giving us the right to propose and drill an additional

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200 net wells. We are the named operator of all the wells drilled under the agreement and pay Knox Energy our proportionate share of a site fee of $4,000 and a well completion fee of $2,000. If the agreement is extended, the site fee and well completion fee increase to $5,000 and $2,500, respectively. Knox Energy has the right to participate on well-by-well basis in up to 50% of the working interest in each well drilled. Further, Knox Energy receives a 1/64^thoverriding royalty interest for each well it fully participates, and a 1/32^nd overriding royalty interest for wells in which it chooses not to participate. For wells in which Knox Energy chooses to participate, but at less than a 50% working interest, it receives a proportionate overriding royalty interest. Each party pays its proportionate share of well construction costs, while Knox Energy is also allocated its proportionate share general and administrative costs for each well in which it participates. As part of the agreement, we must drill a minimum number of wells on certain acreage within the AMI. As of March 31, 2006, we are in compliance with our minimum well commitments and have drilled 98 net wells under the agreement.

NATURAL GAS AND OIL RESERVES

The following tables summarize information regarding the estimated proved natural gas and oil reserves of Atlas America E&P Operations as of September 30, 2003, 2004 and 2005, and of Atlas Energy Resources as of March 31, 2006 on a pro forma basis to reflect the contribution of assets of Atlas America to Atlas Energy Resources at the closing of this offering, excluding 94 wells that will be retained by Atlas America. The estimated reserves of Atlas America E&P Operations and Atlas Energy Resources include reserves attributable to the direct ownership interests in oil and gas properties as well as the reserves attributable to the percentage interests of Atlas America E&P Operations and Atlas Energy Resources in the oil and gas properties owned by investment partnerships in which Atlas America E&P Operations or Atlas Energy Resources owns partnership interests. All of the reserves are located in the United States. We base these estimates 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. A summary of the reserve report related to estimated proved reserves of Atlas Energy Resources at March 31, 2006 is included in this prospectus as Appendix C. In accordance with SEC guidelines, we make the standardized measure 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 as of the dates indicated:


	Atlas America E&P Operations September 30,						Atlas Energy Resources March 31, 2006
	2003		2004		2005		Atlas Energy Resources March 31, 2006
Natural gas (per Mcf)	$	4.96	$	6.91	$	14.75	$	8.04
Oil (per Bbl)	$	26.00	$	46.00	$	63.29	$	63.52

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

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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. Please read “Risk factors—Risks Inherent in Our Business.” You should not construe the estimated PV-10 and standardized measure values as representative of the current or future fair market value of our proved natural gas and oil properties. PV-10 and standardized measure 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.


	Proved natural gas and oil reserves for Atlas America E&P Operations at September 30,						Proved natural gas and oil reserves for Atlas Energy Resources at March 31, 2006
	2003		2004		2005
Natural gas reserves (Mmcf):
Proved developed reserves		87,760		95,788		104,786		107,574
Proved undeveloped reserves		45,533		46,345		53,241		50,221

Total proved reserves of natural gas		133,293		142,133		158,027		157,795

Oil reserves (Mbbl):
Proved developed reserves		1,825		2,126		2,116		1,974
Proved undeveloped reserves		30		149		143		120

Total proved reserves of oil		1,855		2,275		2,259		2,094

Total proved reserves (MMcfe)		144,423		155,782		171,581		170,359

PV-10 estimate of cash flows of proved reserves (in thousands)(1)
Proved developed reserves	$	164,617	$	265,516	$	617,445	$	347,775
Proved undeveloped reserves		26,802		54,863		228,206		62,632

Total PV-10 estimate(2)	$	191,419	$	320,379	$	845,651	$	410,407

Standardized measure of discounted future cash flows (in thousands)(1)(2)	$	144,351	$	232,998	$	606,697	$	410,407

(1)

Amounts shown for September 30, 2003, 2004 and 2005 reflect values for Atlas America E&P Operations, which pays income taxes. Amounts shown for March 31, 2006 reflect values for the reserves of Atlas Energy Resources on a pro forma basis to reflect the contribution of assets of Atlas America to Atlas Energy Resources at the closing of this offering, excluding 94 wells that will be retained by Atlas America. Since we are a limited liability company that allocates our taxable income to our unitholders, no provision for federal or state income taxes has been included in the March 31, 2006 calculation of standardized measure which is, therefore, the same as the PV-10 value. Amounts include forward sales but not financial hedging transactions. We estimate that if natural gas prices decline by $1.00 per Mcf, then the PV-10 value of our proved reserves as of March 31, 2006 would decrease from $410.4 million to $346.9 million. For a description of our hedging transactions, please read “—Natural Gas Hedging.”

(2)

The following reconciles the PV-10 value to the standardized measure:

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	Atlas America E&P Operations as of September 30,									Pro forma Atlas Energy Resources as of March 31, 2006
	2003			2004			2005			Pro forma Atlas Energy Resources as of March 31, 2006
PV-10 value	$	191,419		$	320,379		$	845,651		$	410,407
Income tax effect		(47,068	)		(87,381	)		(238,954	)		0

Standardized measure	$	144,351		$	232,998		$	606,697		$	410,407

Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production.

NATURAL GAS SALES

We have a natural gas supply agreement with Hess Corporation which is valid through March 31, 2009. Subject to certain exceptions, Hess Corporation has a last right of refusal to buy all of the natural gas produced and delivered by us and our affiliates, including our 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.

A portion of our and our investment partnerships’ natural gas is subject to the agreement with Hess Corporation, 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 March 31, 2006, we anticipate that we and our affiliates, including our investment partnerships, will sell approximately 35% of our natural gas production during fiscal 2006 under the Hess Corporation agreement. The agreement requires the parties to negotiate a new pricing arrangement at each annual delivery point. 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 Hess Corporation does not

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match this price, then we may sell the natural gas to the third party. 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. See “—Major Customers.” During the six months ended March 31, 2006, we received an average of $10.99 per Mcf of natural gas, compared to $7.26 per Mcf in fiscal 2005, $5.84 per Mcf in fiscal 2004 and $4.92 per Mcf in fiscal 2003.

We expect that natural gas produced from our wells drilled in areas of the Appalachian Basin other than those 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

Crude oil produced from our wells will flow directly into storage tanks where it will be 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.

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 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.

NATURAL GAS HEDGING

Pricing for natural gas and oil production has been volatile and unpredictable for many years. To limit our exposure to changing natural gas prices, we use hedges for a portion of our 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 36 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 management 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. As of March 31, 2006, we had financial hedges and forward sales in place for approximately 61% of our expected production for the twelve months ending June 30, 2007.

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Hess Corporation 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 Hess Corporation, 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. For a description of our financial hedges, please read “Management’s discussion and analysis of financial condition and results of operations—Quantitative and Qualitative Disclosures About Market Risk.”

NATURAL GAS GATHERING

We conduct our natural gas transportation and processing operations through Atlas America’s affiliate, Atlas Pipeline. Atlas Pipeline owns approximately 1,500 miles of gathering systems located in eastern Ohio, western New York and western Pennsylvania serving approximately 5,100 wells.

Upon completion of this offering, we will become a party to an existing omnibus agreement between Atlas America and Atlas Pipeline which set forth the obligations that we, Atlas America and Atlas Pipeline will have to connect wells to the Atlas Pipeline gathering systems and that we will have to provide consultation services in the construction of new gathering systems or the extension of existing system. Atlas America will continue to be obligated to pay transportation fees to Atlas Pipeline under natural gas gathering agreements pursuant to which Atlas Pipeline will gather substantially all of the natural gas from wells operated by us.

Omnibus agreement

Well connections. We will be required to construct, at our sole cost and expense, up to 2,500 feet of small diameter (two inches or less) sales or flow lines from the wellhead of any well we drill and operate to a point of connection to Atlas Pipeline’s gathering systems. Where we have extended sales and flow lines to within 1,000 feet of one of Atlas Pipeline’s gathering systems, we may require Atlas Pipeline to extend its system to connect to that well. With respect to other wells that are more than 2,500 feet from Atlas Pipeline’s gathering systems, Atlas Pipeline will have the right, at its cost and expense, to extend its gathering system to within 2,500 feet of the well and to require us, at our cost and expense, to construct up to 2,500 feet of flow line to connect to the gathering system extension. If Atlas Pipeline elects not to exercise its right to extend its gathering systems, we may connect a well to a natural gas gathering system owned by a third party or to any other delivery point; however, Atlas Pipeline will have the right to assume the cost of construction of the necessary flow lines, which then become its property and part of its gathering systems.

Consulting services. The agreement also requires us to assist Atlas Pipeline in seeking to identify existing gathering systems for possible acquisition and provide consulting services in evaluating and making a bid for these systems. We will also agree that any gathering system we identify as a potential acquisition will first be offered to Atlas Pipeline. Atlas Pipeline will have 30 days to determine whether it wants to acquire the identified system and advise us of its intent. If Atlas Pipeline intends to acquire the system, it will have an additional 60 days to complete the acquisition. If Atlas Pipeline does not complete the acquisition, or advises us that it does not intend to acquire the system, then we may do so.

Gathering system construction. We will provide Atlas Pipeline with construction management services if Atlas Pipeline determines to expand one or more of its gathering systems. We will be entitled to

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reimbursement for our costs, including an allocable portion of employee salaries, in connection with our construction management services.

The omnibus agreement has no specified term but will terminate if Atlas Pipeline Partners GP is removed as the general partner of Atlas Pipeline without cause.

Natural gas gathering agreements

Under natural gas gathering agreements, Atlas America will pay Atlas Pipeline a fee for gathering our natural gas. We will receive gathering fees from contracts or other arrangements with third party owners of well interests connected to Atlas Pipeline’s gathering systems, which we will remit to Atlas America. However, Atlas America must pay gathering fees owed to Atlas Pipeline from its own resources regardless of the amounts we pay to it from under those contracts or arrangements.

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 and six months ended March 31, 2006, we faced no shortage of these goods and services. We cannot predict the duration or stability of the current level of supply and demand for drilling rigs and other goods and services required for our operations with any certainty due to numerous factors affecting the energy industry, including the demand for natural gas and oil.

MAJOR CUSTOMERS

Our natural gas is sold under contract to various purchasers. For the years ended September 30, 2003, 2004 and 2005 and the six months ended March 31, 2006, gas sales to Hess Corporation (formerly FirstEnergy Solutions Corp.) accounted for 18%, 13%, 13% and 11%, respectively, of our total revenues. No other single customer accounted for more than 10% of our total revenues during these periods.

COMPETITION

The energy industry is intensely competitive in all of its aspects. We operate in a highly competitive environment for acquiring properties and other natural gas and oil companies, attracting capital through our investment partnerships, contracting for drilling equipment and securing trained personnel. For example, the Pennsylvania Bureau of Oil and Gas Management estimates that there were 747 well operators bonded in Pennsylvania, one of our core operating areas, in 2005. We also compete with the exploration and production divisions of public utility companies for natural gas and oil property acquisitions. Competition is intense for the acquisition of leases considered favorable for the development of natural gas and oil in commercial quantities. 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. Furthermore, 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. 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.

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Moreover, we also compete with a number of other companies that offer interests in investment partnerships. As a result, competition for investment capital to fund investment partnerships is intense.

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 Inherent in Our Business.” Product availability and price are the principal means of competition in selling oil and natural gas. During the six months ended March 31, 2006 and fiscal 2005, 2004 and 2003, we did not experience problems in selling our natural gas and oil, although prices have varied significantly during those periods.

NATURAL GAS AND OIL LEASES

The typical natural gas and oil lease agreement provides for the payment of royalties to the mineral owner for all natural gas and oil produced from any well(s) drilled on the lease premises. In the Appalachian Basin this amount is typically 1/8^th(12.5%) resulting in a 87.5% net revenue interest to us for most leases directly acquired by us. In certain instances, this royalty amount may increase to 1/6^th(16.66%) when leases are taken from larger landowners or mineral owners such as coal and timber companies.

Because the acquisition of natural gas and oil leases is a very competitive process, and involves certain geological and business risks to identify productive areas, prospective leases are often held by other natural gas and oil operators. In order to gain the right to drill these leases we may elect to farm-in leases and/or purchase leases from other natural gas and oil operators. Typically the assignor of such leases will reserve an overriding royalty interest, ranging from 1/32^ndto 1/16^th(3.125% to 6.25%), which further reduces the net revenue interest available to us to between 84.375% and 81.25%.

Sometimes these third party owners of natural gas and oil leases retain the option to participate in the drilling of wells on leases farmed out or assigned to us. Normally the retained interest is a 25% working interest. In this event, our working interest ownership will be reduced by the amount retained by the third party operator. In all other instances we anticipate owning a 100% working interest in newly drilled wells.

In almost all of the areas we operate in the Appalachian Basin, the surface owner is normally the natural gas and oil owner allowing us to deal with a single owner. This simplifies the research process required to identify the proper owners of the natural gas and oil rights and reduces the per acre lease acquisition cost and the time required to successfully acquire the desired leases.

SEASONAL NATURE OF BUSINESS

Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations in certain areas of the Appalachian region and, as a result, we will generally perform the majority of our drilling during the summer months. These seasonal anomalies may pose challenges for meeting our well construction objectives and increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations. Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.

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ENVIRONMENTAL MATTERS AND REGULATION

General

Our operations are subject to comprehensive and stringent federal, state and local laws and regulations governing, among other things, where and how we install wells, how we handle wastes from our operations and the discharge of materials into the environment. Our operations will be subject to the same environmental laws and regulations as other companies in the natural gas and oil industry. Among other requirements and restrictions, these laws and regulations:

require the acquisition of various permits before drilling commences;

require the installation of expensive pollution control equipment;

restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;

limit or prohibit drilling activities on lands lying within or, in some cases, adjoining wilderness, wetlands and other protected areas;

require remedial measures to reduce, mitigate or respond to releases of pollutants or hazardous substances from former operations, such as pit closure and plugging of abandoned wells;

impose substantial liabilities for pollution resulting from our operations; and

with respect to operations affecting federal lands or leases, require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement.

These laws, rules and regulations may also restrict the rate of natural gas and oil production below the rate that would otherwise be possible. The regulatory burden on the natural gas and oil industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently enact new, and revise existing, environmental laws and regulations, and any new laws or changes to existing laws that result in more stringent and costly waste handling, disposal and clean-up requirements for the natural gas and oil industry could have a significant impact on our operating costs. We believe that our operations on the whole substantially comply with all currently applicable environmental laws and regulations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict how environmental laws and regulations that may take effect in the future may impact our properties or operations. For the year ended September 30, 2005 and the six months ended March 31, 2006, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities. As of the date of this prospectus, we are not aware of any environmental issues or claims that will require material capital expenditures during 2006 or that will otherwise have a material impact on our financial position or results of operations.

Environmental laws and regulations that could have a material impact on the natural gas and oil exploration and production industry include the following:

National Environmental Policy Act

Natural gas and oil exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major federal agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will typically require an Environmental

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Assessment to assess the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that will be made available for public review and comment. All of our proposed exploration and production activities on federal lands require governmental permits, many of which are subject to the requirements of NEPA. This process has the potential to delay the development of natural gas and oil projects.

Waste Handling

The Solid Waste Disposal Act, including the Resource Conservation and Recovery Act, or RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and the disposal of non-hazardous wastes. Under the auspices of the United States Environmental Protection Agency, or EPA, individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil and natural gas constitute “solid wastes”, which are regulated under the less stringent non-hazardous waste provisions, but there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation.

We believe that our operations are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes to be significant, any more stringent regulation of natural gas and oil exploitation and production wastes could increase our costs to manage and dispose of such wastes.

Comprehensive Environmental Response, Compensation and Liability Act

The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the “Superfund” law, imposes joint and several liability, without regard to fault or legality of conduct, on persons who are considered under the statute to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substance at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

Our operations are, in many cases, conducted at properties that have been used for natural gas and oil exploitation and production for many years. Although we believe Atlas America utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.

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Water Discharges

The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other natural gas and oil wastes, into navigable waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or the relevant state. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. The Clean Water Act also requires specified facilities to maintain and implement spill prevention, control and countermeasure plans and to take measures to minimize the risks of petroleum spills. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for failure to obtain or non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. We believe our operations on the whole are in substantial compliance with the requirements of the Clean Water Act.

Air Emissions

The Clean Air Act, and associated state laws and regulations, regulate emissions of various air pollutants through permits and other requirements. In addition, EPA has developed, and continues to develop, stringent regulations governing emissions of toxic and other air pollutants at specified sources. Some of our new facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to comply with new emission limitations. These regulations may increase the costs of compliance for some facilities, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance. These laws and regulations also apply to entities that use natural gas as fuel, and may increase the costs of compliance of our customers to the point where demand for natural gas is affected. We believe that our operations are in substantial compliance with the requirements of the Clean Air Act.

OSHA and Other Regulations

We are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

Other Laws and Regulation

The Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as greenhouse gases, that are suspected of contributing to global warming. The United States is not currently a participant in the Protocol, and Congress has resisted recent proposed legislation directed at reducing greenhouse gas emissions. However, there has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. The natural gas and oil industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. Our operations are not adversely impacted by current state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

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OTHER REGULATION OF THE NATURAL GAS AND OIL INDUSTRY

The natural gas and oil industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the natural gas and oil industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the natural gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the natural gas and oil industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including natural gas and oil facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Drilling and Production

Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we will operate also regulate one or more of the following:

the location of wells;

the method of drilling and casing wells;

the surface use and restoration of properties upon which wells are drilled;

the plugging and abandoning of wells; and

notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of natural gas and oil properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of natural gas and oil we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

Natural Gas Regulation

The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. The Federal Energy Regulatory Commission’s

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regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas.

Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.

State Regulation

The various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Tennessee currently imposes a 3% severance tax on natural gas and oil production and Ohio imposes a severance tax of $0.25 per Mcf of natural gas and $0.10 per Bbl of oil. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect upon the unitholders.

LITIGATION

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, including spills of oil or releases of pollutants, we are not currently a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings pending against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject as to which specific disclosure would be required under the securities laws.

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OUR BOARD OF DIRECTORS AND EXECUTIVE OFFICERS

Upon completion of this offering, our board of directors will consist of seven directors, including the director nominees named below who have consented to serve as directors, three of which will satisfy the independence standards of the New York Stock Exchange. Our officers are all officers of our manager and may spend a substantial amount of time managing the business and affairs of Atlas America and its affiliates. Our officers will devote as much time to our management as is necessary for the proper conduct of our business and affairs.

Our current directors, and nominees, and executive officers are as follows:


Name	Age	Title
Edward E. Cohen	67	Chairman of the Board and Chief Executive Officer
Jonathan Z. Cohen	35	Vice Chairman of the Board
Richard D. Weber	42	President, Chief Operating Officer and Director
Matthew A. Jones	44	Chief Financial Officer and Director
Nancy J. McGurk	50	Chief Accounting Officer
Walter C. Jones	43	Director Nominee
Ellen F. Warren	49	Director Nominee
Bruce M. Wolf	58	Director Nominee

Edward E. Cohenhas been our Chairman of the Board and Chief Executive Officer since our formation in 2006 and Chairman of the Board and Chief Executive Officer of Atlas Energy Management since its formation in 2006. He has been the Chief Executive Officer and President of Atlas America since its formation in September 2000. He has been Chairman of the board of directors of Resource America, Inc. (a publicly-traded specialized asset management company) since 1990 and was its Chief Executive Officer from 1988 until 2004, and President from 2000 until 2003. In addition, Mr. Cohen has been Chairman of the managing board of Atlas Pipeline Partners GP, LLC, the general partner of Atlas Pipeline Partners, L.P., since its formation in 1999, Chairman of the Board and Chief Executive Officer of Atlas Pipeline Holdings GP, LLC, the general partner of Atlas Pipeline Holdings, L.P., since its formation in January 2006, Chairman of the Board of Resource Capital Corp. (a publicly-traded real estate investment trust) since its formation in September 2005, a director of TRM Corporation (a publicly-traded consumer services company) since 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 the Board since our formation in 2006 and Vice Chairman of Atlas Energy Management since its formation in 2006. He has been the Vice Chairman of Atlas America since its formation in September 2000. He has been a senior officer of Resource America since 1998, serving as the Chief Executive Officer since 2004, President since 2003 and a director since 2002. Mr. Cohen has been Vice Chairman of the managing board of Atlas Pipeline Partners GP since its formation in 1999, Vice Chairman of the Board of Atlas Pipeline Holdings GP since its formation in January 2006, a director of Resource Capital Corp. since its formation in 2005, a trustee and secretary of RAIT Investment Trust (a publicly-traded real estate investment trust) since 1997 and its Vice Chairman since 2003, and Chairman of the board of directors of The Richardson Company (a sales consulting company) since 1999. Mr. Cohen is a son of Edward E. Cohen.

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Richard D. Weber has been our President, Chief Operating Officer and a director since our formation in 2006 and President, Chief Operating Officer and a director of Atlas Energy Management since its formation in 2006. Mr. Weber served from June 1997 until March 2006 as Managing Director and Group Head of the Energy Group of KeyBanc Capital Markets, a division of KeyCorp, and its predecessor, McDonald & Company Securities, Inc. As part of his duties, he oversaw the bank’s activities with oil and gas producers, pipeline companies and utilities. He has a particular expertise in the Appalachian Basin, where he led over 40 transactions, including the IPOs of Atlas America and Atlas Pipeline and the sale of Viking Resources Corporation to Atlas America.

Matthew A. Jones has been our Chief Financial Officer and a director since our formation and Chief Financial Officer of Atlas Energy Management since its formation. He has been the Chief Financial Officer of Atlas America and of Atlas Pipeline Partners GP since March 2005. He has been the Chief Financial Officer of Atlas Pipeline Holdings GP since January 2006 and a director since February 2006. From 1996 to 2005, Mr. Jones worked in the Investment Banking group at Friedman Billings Ramsey, which we refer to as FBR, concluding as Managing Director. Mr. Jones worked in FBR’s Energy Investment Banking Group from 1999 to 2005 and in FBR’s Specialty Finance and Real Estate Group from 1996 to 1999. Mr. Jones is a Chartered Financial Analyst.

Nancy J. McGurk has been our Chief Accounting Officer since our formation in 2006 and Chief Accounting Officer of Atlas Energy Management since its formation. She has been the Chief Accounting Officer of Atlas America since January 2001 and Senior Vice President since January 2002. 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.

Walter C. Jones has been the General Counsel and Senior Director of Private Equity for GRAVITAS Capital Advisors, LLC, an independent investment advisory firm since May 2005. From May 1994 to May 2005, Mr. Jones was at the Overseas Private Investment Corporation, where he served as Manager for Asia, Africa, the Middle East, Latin America and the Caribbean, as well as for seven years a senior officer in the Finance Department.

Ellen F. Warren is founder and President of OutSource Communications, a marketing communications firm that services corporate and nonprofit clients. Prior to founding OutSource Communications in August 2005, she was President of Levy Warren Marketing Media, a public relations and marketing firm she co-founded in March 1998. Before that, she was Vice President of Marketing/Communications for Jefferson Bank, a Philadelphia-based financial institution from September 1992 to February 1998.

Bruce M. Wolf has been President of Homard Holdings, LLC, a wine manufacturer and distributor, since September 2003. Mr. Wolf has been of counsel with Picadio, Sneath, Miller & Norton, P.C., Pittsburgh, PA, since May 2003. Additionally, since June 1999, Mr. Wolf has been a consultant in connection with energy and securities matters, conducting research and providing expert testimony and litigation support. Mr. Wolf was a Senior Vice President of Atlas America from October 1998 to May 1999 and, before that, Secretary and General Counsel of Atlas Energy Group from 1980.

The board intends to appoint two functioning committees immediately following the pricing of this offering: an audit committee and a conflicts committee. We are not required under NYSE rules to have a nominating/corporate governance committee or compensation committee so long as we are a controlled company, which is defined as a company in which more than 50% of the voting power is held by an individual, a group or another company.

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Audit Committee

We currently contemplate that the audit committee will consist of at least three directors. Immediately following the pricing of this offering, all members of the audit committee will be independent under the independence standards established by NYSE and SEC rules, and the committee expects to have an “audit committee financial expert,” as defined under SEC rules. The audit committee will recommend to the board the independent public accountants to audit our financial statements and establish the scope of, and oversee, the annual audit. The committee also will approve any other services provided by public accounting firms. The audit committee will provide assistance to the board in fulfilling its oversight responsibility to the unitholders, the investment community and others relating to the integrity of our financial statements, our compliance with legal and regulatory requirements, the independent auditor’s qualifications and independence and the performance of our internal audit function. The audit committee will oversee our system of disclosure controls and procedures and system of internal controls regarding financial, accounting, legal compliance and ethics that management and the board have established. In doing so, it will be the responsibility of the audit committee to maintain free and open communication between the committee and our independent auditors, the internal accounting function and management of our company.

Conflicts Committee

We currently contemplate that the conflicts committee will consist of at least three directors. The conflicts committee will review specific matters that the board believes may involve conflicts of interest. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to our company. Our limited liability company agreement will provide that members of the committee may not be officers or employees of our company, Atlas America or our manager or directors, officers or employees of any of our or their affiliates and must meet the independence standards for service on an audit committee of a board of directors as established by NYSE and SEC rules. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to our company and approved by all of our unitholders.

GOVERNANCE MATTERS

Independence of Board Members

Pursuant to the NYSE listing standards, a director will be considered independent if the board determines that he or she does not have a material relationship with us (either directly or as a member, unitholder or officer of an organization that has a material relationship with us). We are not required under the NYSE rules to have a majority of independent members of our board so long as we are a controlled company.

Heightened Independence for Audit Committee Members

As required by the Sarbanes-Oxley Act of 2002, the SEC has adopted rules that direct national securities exchanges and associations to prohibit the listing of securities of a public company if members of its audit committee do not satisfy a heightened independence standard. In order to meet this standard, a member of an audit committee may not receive any consulting fee, advisory fee or other compensation from the public company other than fees for service as a director or committee member and may not be considered an affiliate of the public company. Our board of directors expects that all members of its audit committee will satisfy this heightened independence requirement.

Audit Committee Financial Expert

An audit committee plays an important role in promoting effective corporate governance, and it is imperative that members of an audit committee have requisite financial literacy and expertise. As required by the Sarbanes-Oxley Act of 2002 and SEC rules promulgated thereunder, a public company

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must disclose whether its audit committee has a member that is an “audit committee financial expert.” An “audit committee financial expert” is defined as a person who, based on his or her experience, possesses all of the following attributes:

An understanding of generally accepted accounting principles and financial statements;

An ability to assess the general application of such principles in connection with the accounting for estimates, accruals and reserves;

Experience preparing, auditing, analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and level of complexity of issues that can reasonably be expected to be raised by a company’s financial statements, or experience actively supervising one or more persons engaged in such activities;

An understanding of internal controls and procedures for financial reporting; and

An understanding of audit committee functions.

Walter C. Jones will be our initial audit committee financial expert.

Executive Sessions of Board

Our board of directors will hold regular executive sessions in which non-management board members meet without any members of management present. The purpose of these executive sessions is to promote open and discussion among the non-management directors. During such executive sessions, one director is designated as the “presiding director” and is responsible for leading and facilitating such executive sessions.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

We do not have a compensation committee. There are no interlocks with other companies within the meaning of the SEC’s rules.

COMPENSATION OF DIRECTORS

We do not pay additional remuneration to our officers or to officers or employees of our manager who also serve as directors. Each non-employee director will receive an annual retainer of $35,000 in cash and an annual grant of phantom units with distribution equivalent rights in an amount equal to the lesser of 500 units or $15,000 worth of units, based upon the market price of our common units, pursuant to our long-term incentive plan. Please see “—Atlas Energy Resources Long-Term Incentive Plan” below. In addition, each independent board member is reimbursed for his out-of-pocket expenses in connection with attending meetings of the board or committees. We will indemnify our directors for actions associated with being board members to the extent permitted under Delaware law.

EXECUTIVE COMPENSATION

All of our current officers and directors have to date been employees of Atlas America, and they have received no additional compensation from us. Our manager will manage our operations and activities through its and its affiliates’ officers and employees pursuant to the management agreement under the direction of our board of directors. We will reimburse our manager for direct and indirect general and administrative expenses incurred on our behalf.

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EMPLOYMENT AGREEMENT

We have no employment agreements for specific terms with our officers.

Atlas America and Richard D. Weber have entered into an employment agreement, dated April 5, 2006, pursuant to which Mr. Weber will serve as our President and Chief Operating Officer and the President and Chief Operating Officer of our manager. A brief description of the material terms and conditions of the agreement is as follows:

The term of the agreement is April 17, 2006 through April 17, 2008. After the first year of the agreement, the term will automatically renew daily so that on any day that the agreement is in effect, it will have a remaining term of at least one year.

Mr. Weber will receive an annual base salary of at least $300,000. During the first year of the agreement, Mr. Weber will also earn a bonus of at least $700,000.

Mr. Weber will also receive equity compensation as follows:

At the time that we complete this offering, Mr. Weber will receive a grant of restricted common units with a value of $1,000,000. These units will vest 25% per year for four years; any unvested units will be forfeited in the event that Mr. Weber is no longer employed by us or our manager.

Upon the completion of this offering, Mr. Weber will receive options to acquire 1% of the number of our common units then outstanding, less the number of restricted common units issued to Mr. Weber, with a strike price equal to the public offering price, vesting period of 25% per year for four years and a term of 10 years.

Upon execution of the agreement, Mr. Weber was granted options to purchase 50,000 shares of Atlas America stock at the fair market value of such stock, with a vesting period of 25% per year for four years and a term of 10 years.

All of the securities issued as set forth above will be registered with the Securities and Exchange Commission by the appropriate issuer, if they were not so registered at the time of issuance.

If any payments received by Mr. Weber as a result of a change of us, control of our manager or Atlas America are subject to excise tax, our manager will agree to make Mr. Weber whole for such tax and any income tax that would result from such payment.

Mr. Weber’s employment may be terminated without cause upon 45 days written notice, or for cause upon written notice setting forth the conduct constituting cause. Mr. Weber may terminate his employment for good reason or for any other reason upon 30 days’ written notice.

Key termination benefits under the agreement are as follows:

If Mr. Weber’s employment is terminated due to his death, our manager will pay Mr. Weber’s designated beneficiaries a cash payment consisting of the following amounts:

any earned but unpaid portion of Mr. Weber’s base salary;

an amount representing the bonus that Mr. Weber received from the prior fiscal year pro rated for the time employed during the current fiscal year;

any accrued but unpaid bonus and vacation pay; and

Mr. Weber’s spouse will have health insurance paid for one year.

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If Mr. Weber’s employment is terminated for cause, our manager will pay to Mr. Weber his annual base salary and vacation pay accrued through the date of such termination.

If Mr. Weber’s employment is terminated by him other than for good cause, our manager will pay to Mr. Weber his annual base salary accrued through the date of termination.

If Mr. Weber’s employment is terminated other than for cause or death, or Mr. Weber terminates his employment for good reason, our manager will pay amounts equal to Mr. Weber’s annual base salary, bonus, equity compensation and compensation and benefits otherwise payable to Mr. Weber upon his death, as if Mr. Weber remained employed pursuant to the agreement.

The agreement includes standard restrictive covenants for a period of two years following termination, including non-compete and non-solicitation provisions.

ATLAS ENERGY MANAGEMENT

We will enter into a management agreement with Atlas Energy Management pursuant to which it will be responsible for managing our day-to-day operations, subject to the supervision and direction of our officers and board of directors. See “Certain relationships and related transactions—Agreements Governing the Transactions—The management agreement.” Neither we nor our manager will directly employ any of the persons responsible for our operations. Rather, personnel of Atlas America currently involved in managing our assets will manage and operate our business. Officers of our manager may spend a substantial amount of time managing the business and affairs of Atlas America and its affiliates and may face a conflict regarding the allocation of their time between our business and affairs and their other business interests. Our manager intends to cause its officers to devote as much time to our management as is necessary for the proper conduct of our business and affairs.

OFFICERS OF OUR MANAGER

The following table sets forth information with respect to the officers of our manager.


Name	Age	Position with manager
Edward E. Cohen	67	Chairman of the Board and Chief Executive Officer
Richard D. Weber	42	President, Chief Operating Officer and Director
Jeffrey C. Simmons	47	Senior Vice President
Frank P. Carolas	46	Senior Vice President
Matthew A. Jones	44	Chief Financial Officer
Nancy J. McGurk	50	Chief Accounting Officer
Donald R. Laughlin	58	Vice President – Drilling and Production
Michael G. Hartzell	50	Vice President – Land Administration
Lisa Washington	38	Chief Legal Officer and Secretary

Please see “—Our Board of Directors and Executive Officers” for biographical information for Messrs. E. Cohen, R. Weber and M. Jones and Ms. McGurk.

Jeffrey C. Simmons has been a Senior Vice President since Atlas Energy Management’s formation. He has been an Executive Vice President of Atlas America since 2001 and was a director from January 2002 until February 2004. He has been Executive Vice President—Operations and a director of Atlas Resources, LLC, which acts as the general partner of some of our investment partnerships, since January 2001. Mr. Simmons was a Vice President of Resource America from April 2001 until May 2004. Mr. Simmons joined Resource America in 1986 as a senior petroleum engineer and served in various executive positions with its energy subsidiaries thereafter.

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Frank P. Carolas has been a Senior Vice President since Atlas Energy Management’s formation. Mr. Carolas has been an Executive Vice President of Atlas America 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 since January 2001. Mr. Carolas was Vice President of Atlas Resources from July 1999 to January 2001. Mr. Carolas is a certified petroleum geologist and has been employed by Atlas Resources and its affiliates since 1981.

Donald R. Laughlinhas been Vice President—Drilling and Production of Atlas Energy Management since its formation. Mr. Laughlin has been Vice President—Drilling and Production of Atlas Resources since September 2001. Mr. Laughlin has also served as Vice President—Drilling and Production for Atlas America since January 2002, and before that served as Senior Drilling Engineer from May 2001, when he joined Atlas America. Mr. Laughlin has over thirty years of experience as a petroleum engineer in the Appalachian Basin, having been employed by Columbia Gas Transmission Corporation from October 1995 to May 2001 as a senior gas storage engineer and team leader, Cabot Oil & Gas Corporation from 1989 to 1995 as Manager of Drilling Operations and Technical Services, Doran & Associates, Inc.

Michael G. Hartzell has been Vice President—Land Administration for Atlas Energy Management since its formation. Mr. Hartzell has been Vice President—Land Administration of Atlas Resources since September 2001 and of Atlas America since January 2002. Before that Mr. Hartzell served as Senior Land Coordinator of Atlas Resources from January 1999 to January 2002. Mr. Hartzell has been with Atlas Resources and its affiliates since 1980, when he began his career as a land department representative. Mr. Hartzell serves on the Environmental Committee of the Independent Oil and Gas Association of Pennsylvania and is a past Chairman of the Committee.

Lisa Washington has been the Chief Legal Officer and Secretary of Atlas Energy Management since its formation. She has been the Chief Legal Officer and Secretary of Atlas Pipeline Holdings GP since January 2006. Ms. Washington has been the Vice President, Chief Legal Officer and Secretary of Atlas America and Atlas Pipeline Partners GP since November 2005. From 1999 to November 2005, Ms. Washington was an attorney in the business department of the law firm of Blank Rome LLP.

OTHER SIGNIFICANT EMPLOYEES

Freddie M. Kotek, 50, has been an Executive Vice President of Atlas America since February 2004 and served as Chief Financial Officer from February 2004 until March 2005 and a director from September 2001 until February 2004. Mr. Kotek was a Senior Vice President 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.

Jack L. Hollander, 50, has been Senior Vice President—Direct Participation Programs of Atlas Resource since January 2002 and before that he served as Vice President—Direct Participation Programs. Mr. Hollander also has served as Senior Vice President—Direct Participation Programs of Atlas America since January 2002. Mr. Hollander practiced law with Rattet, Hollander & Pasternak, concentrating in tax matters and real estate transactions, from 1990 to January 2001, and served as in-house counsel for Integrated Resources, Inc. (a diversified financial services company) from 1982 to 1990. Mr. Hollander is a member of the New York bar and the Chairman of the Investment Program Association, an industry association, as of March 2005.

Marci F. Bleichmar, 36, has been Vice President—Marketing of Atlas Resources since February 2001. Ms. Bleichmar has also served as Vice President of Marketing for Atlas America since February 2001 and

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was with Resource America from February 2001 until May 2004. From March 2000 until February 2001, Ms Bleichmar served as Director of Marketing for Jacob Asset Management (a mutual fund manager), and from March 1998 until March 2000, she was an account executive at Bloomberg Financial Services, L.P.

Daniel C. Herz, 29, has been Vice President of Corporate Development of Atlas America and Atlas Pipeline Partners GP since December 2004 and of Atlas Pipeline Holdings GP since January 2006. Mr. Herz joined Atlas America and Atlas Pipeline Partners GP in January 2004. He was an Associate Investment Banker with Banc of America Securities from 2002 to 2003 and an Analyst from 1999 to 2002.

REIMBURSEMENT OF EXPENSES OF OUR MANAGER AND ITS AFFILIATES

ATLAS ENERGY RESOURCES LONG-TERM INCENTIVE PLAN

Before the closing of this offering, we will adopt the Atlas Energy Resources Long-Term Incentive Plan for our officers and directors and the employees, directors and consultants of our manager and its affiliates, including Atlas America, who perform services for us. The long-term incentive plan will consist of phantom units, unit options and tandem distribution equivalent rights with respect to phantom units. The long-term incentive plan will be administered by our board of directors or a committee delegated by the board, which may be the compensation committee of the board of directors of Atlas America. We refer to the body responsible for administering the plan as the administrator.

The administrator may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. It will also have the right to alter or amend the long-term incentive plan or any part of the long-term incentive plan from time to time, including increasing the number of common units that may be granted, subject to unitholder approval as may be required by the exchange upon which our common units are listed at that time, if any. Subject to adjustment as provided in the long-term incentive plan documents, the aggregate number of our common units that may be awarded to participants is 3,400,000. However, no change in any outstanding grant may be made that would materially reduce the benefits of the participant without the consent of the participant. Units with respect to awards forfeited, terminated or paid without the delivery of common units are available for delivery pursuant to other awards. The long-term incentive plan will expire upon its termination by the administrator or, if earlier, when no units remain available under the long-term incentive plan for awards. Upon termination of the long-term incentive plan, awards then outstanding will continue pursuant to the terms of their grants.

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Phantom Units

A phantom unit entitles the grantee to receive a unit upon the vesting of the phantom unit or, in the discretion of the administrator, cash equivalent to the value of a unit. The administrator may make grants of phantom units under the plan to eligible participants containing such terms as it determines. The administrator will determine the period over which phantom units will vest. The administrator, in its discretion, may base its determination upon the achievement of specified financial objectives or other events. In addition, the phantom units will vest upon a change in control. If a grantee’s employment, consulting or board membership relationship with our manager or its affiliates terminates for any reason, the grantee’s phantom units will be automatically forfeited unless the compensation committee or the terms of the award agreement provide otherwise.

We intend that the issuance of any units upon vesting of the phantom units under the plan serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of our common units. Therefore, plan participants will not pay any consideration for the units they receive, and we will receive no remuneration for the units.

DERs

A distribution equivalent right or DER is a right granted in the administrator’s discretion with respect to a phantom unit that entitles the grantee to receive cash equal to the cash distributed on a common unit on such terms and conditions as the administrator may proscribe.

Options

An option entitles the grantee to receive a unit upon payment of the exercise price for the option, which exercise price may be equal to or more than the fair market value of a unit on the date of grant of the option. The administrator will determine the eligible participants to whom options are granted, the number of options, their vesting provisions, exercise price and other terms and conditions.

Common units to be delivered upon the vesting of phantom units or the exercise of options may be units acquired by us in the open market, units acquired by us from any other person or any combination of the foregoing. If we issue new common units upon vesting of the phantom units or the exercise of options, the total number of common units outstanding will increase.

U.S. Federal Income Tax Consequences of Awards Under the Long-Term Incentive Plan

Generally, when phantom units or options are granted, there are no income tax consequences for the participant or us. Upon the payment to the participant of units and/or cash with respect to the vesting of phantom units or DERs or the exercise of units, the participant recognizes compensation equal to the fair market value of the cash and/or units as of the date of payment.

On October 22, 2004, the American Jobs Creation Act of 2004 added a new Section 409A to the Internal Revenue Code, or the Code, which significantly alters the rules relating to the taxation of deferred compensation. Section 409A broadly applies to deferred compensation and potentially results in additional tax to participants. The Department of Treasury and IRS have issued guidance and proposed regulations under Section 409A, however further guidance is anticipated. Based on current guidance, the award of options to employees, consultants and directors of certain of our affiliates may be very limited in order to meet the requirements of Section 409A. However, we expect that we will be able to structure awards under the plan in a manner that complies with Section 409A. Because we expect additional guidance to be issued under Section 409A, we may be required to alter provisions of the plan and future awards.

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Certain relationships and related transactions

After this offering, assuming no exercise of the underwriters’ option to purchase additional common units:

Our manager will own 680,612 Class A units, representing a 2% limited liability company interest in us, and all of the management incentive interests; and

Atlas America will own 27,550,000 common units, representing an approximate 81% limited liability company interest in us.

DISTRIBUTIONS AND PAYMENTS TO OUR MANAGER AND ATLAS AMERICA

The following table summarizes the distributions and payments to be made by us to our manager and Atlas America in connection with our formation, ongoing operation and any liquidation. These distributions and payments were determined among affiliated entities and, consequently, are not the result of arm’s-length negotiations.


Formation Stage
Consideration received by our manager and Atlas America in our restructuring		Ø 680,612 Class A units; Ø 27,550,000 common units; Ø the management incentive interests; and Ø the net proceeds of this offering, after payment of offering expenses and retention of working capital.
Operational Stage
Distributions of available cash to our manager and Atlas America		We will generally make cash distributions 98% to common unitholders, including Atlas America, and 2% to our manager with respect to its Class A units. In addition, if distributions exceed the First Target Distribution and certain other requirements are met, our manager will be entitled with respect to its management incentive interests to 15% of distributions above the First Target Distribution and 25% of distributions above the Second Target Distribution. For a discussion of the management incentive interests, please read “How we make cash distributions—Management Incentive Interests.” Assuming we have sufficient available cash to pay the IQD on all of our outstanding units for four quarters, but no distributions in excess of the full IQD, our manager would receive an annual distribution of approximately $1.1 million on its Class A units and Atlas America would receive an annual distribution of approximately $44.1 million on its common units.

Payments to our manager		Pursuant to our management agreement with our manager, we will be obligated to reimburse our manager for the costs it incurs in providing services to us.

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Certain relationships and related transactions



Conversion of Class A units and management incentive interests		If we terminate the management agreement, our manager will have the option to convert: Ø its Class A units into common units on a one for one basis; and Ø its management incentive interests into common units based on their then fair market value, unless the successor manager purchases them. If the common unitholders vote to eliminate the special voting rights of the Class A units, the Class A units will automatically convert to common units and our manager will have the option to convert the management incentive interests into common units based on their then fair market value.
Liquidation Stage
Liquidation		Upon our liquidation, the unitholders, including Atlas America as a common unitholder, and our manager, as the holder of the Class A units, will be entitled to receive liquidating distributions according to their respective capital account balances. Please read “How we make cash distributions—Distributions of Cash Upon Liquidation.”

AGREEMENTS GOVERNING THE TRANSACTIONS

We and our manager and its affiliates will enter into the various agreements that will effect the offering transactions, including the contribution by Atlas America of its natural gas and oil development and production subsidiaries to us. These agreements will not be the result of arm’s-length negotiations, and they, or any of the transactions that they provide for, may not be effected on terms at least as favorable to the parties to these agreements as they could have been obtained from unaffiliated third parties. All of the transaction expenses incurred in connection with these transactions will be paid from the proceeds of this offering.

The contribution agreement

Contribution of Atlas America Subsidiaries. Before the closing of this offering, the assets we will own are held, directly or indirectly, by subsidiaries of Atlas America. In connection with this offering, Atlas America will enter into a contribution agreement pursuant to which, at closing, it will contribute to us all of the outstanding stock or other securities of its natural gas and oil development and production subsidiaries. As consideration for this contribution, we will distribute the net proceeds we receive from this offering as well as 27,550,000 of our common units, assuming no exercise of the underwriters’ option to purchase additional common units to Atlas America. As part of the contribution agreement, Atlas America will indemnify us for all liabilities relating to the contributed subsidiaries that arose or are attributable to the period before the closing, including environmental liabilities, and we will indemnify Atlas America for liabilities that arise or are attributable to the period after the closing.

Atlas America’s Assumption of Obligations under Gas Agreements with Atlas Pipeline. Atlas America and its subsidiaries, including subsidiaries which Atlas America will contribute to us, are obligated to pay gathering fees to Atlas Pipeline for wells owned by us or our investment partnerships that are connected to Atlas Pipeline’s systems. We will be separately obligated to connect wells owned by us or our

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Certain relationships and related transactions

investment partnerships to Atlas Pipeline’s systems pursuant to an omnibus agreement with Atlas Pipeline that we will become party to upon the closing of this offering. Please see “Business—Natural Gas Gathering.” The gathering fees payable to Atlas Pipeline generally exceed the amount we receive from our investment partnerships for gathering. Atlas America will agree to assume the obligation of our subsidiaries to pay these gathering fees to Atlas Pipeline; we will agree to pay Atlas America only the gathering fees we receive from our investment partnerships.

The management agreement

Duties. Before completion of the offering, we will enter into a management agreement with Atlas Energy Management that will require it to manage our business affairs under the supervision of our board of directors and officers, in conformity with the policies that are approved by our board of directors. Atlas Energy Management will provide us with all services necessary or appropriate for us to conduct our business, including, without limitation, the following:

providing executive and administrative personnel, office space and office services required in rendering services to us;

investigating, analyzing and proposing possible acquisition and investment opportunities;

evaluating and recommending to our board of directors and officers hedging strategies and engaging in hedging activities on our behalf, consistent with such strategies;

negotiating agreements on our behalf;

communicating on our behalf with the holders of any of our equity or debt securities as required to satisfy the reporting and other requirements of any governmental bodies or agencies or trading markets and to maintain effective relations with such holders;

counseling us in connection with policy decisions to be made by our board of directors;

furnishing reports and statistical and economic research to us regarding our activities and services performed for us by Atlas Energy Management;

monitoring our operating performance and providing periodic reports with respect thereto to our board of directors, including comparative information with respect to such operating performance and budgeted or projected operating results;

at the direction of the audit committee of our board of directors, causing us to retain qualified accountants to assist in developing appropriate accounting procedures, compliance procedures and testing systems with respect to financial reporting obligations, and to conduct quarterly compliance reviews with respect thereto;

causing us to qualify to do business in all applicable jurisdictions and to obtain and maintain all appropriate licenses;

assisting us in complying with all regulatory requirements applicable to us with respect to our business activities, including preparing or causing to be prepared all financial statements required under applicable regulations and contractual undertakings, all required tax filings and all reports and documents, if any, required under the Exchange Act;

handling and resolving all claims, disputes or controversies (including all litigation, arbitration, settlement or other proceedings or negotiations) in which we may be involved or to which we may be subject arising out of our day-to-day operations, subject to such limitations or parameters as may be imposed from time to time by our board of directors;

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Certain relationships and related transactions

using commercially reasonable efforts to cause expenses incurred by or on behalf of us to be commercially reasonable or commercially customary and within any budgeted parameters or expense guidelines set by our board of directors from time to time;

advising us with respect to obtaining financing for our operations;

performing such other services as may be required from time to time for management and other activities relating to our assets as our board of directors shall reasonably request or Atlas Energy Management shall deem appropriate under the particular circumstances; and

using commercially reasonable efforts to cause us to comply with all applicable laws.

Pursuant to the management agreement, Atlas Energy Management will not assume any responsibility beyond the duties specified in the management agreement and will not be responsible for any action of our board of directors in following or declining to follow its advice or recommendations. Atlas Energy Management, its directors, officers, employees and affiliates will not be liable to us, any subsidiary of ours, our directors or our unitholders for acts or omissions performed in good faith and in accordance with and pursuant to the management agreement, except by reason of acts constituting bad faith, willful misconduct, fraud or criminal conduct. We will agree to indemnify Atlas Energy Management and its affiliates with respect to all expenses, losses, damages, liabilities, demands, charges and claims arising from acts of Atlas Energy Management or its affiliates not constituting bad faith, willful misconduct, fraud or criminal conduct performed in good faith in accordance with and pursuant to the management agreement. Atlas Energy Management and its affiliates will agree to indemnify us, our directors and officers with respect to all expenses, losses, damages, liabilities, demands, charges and claims arising from acts of Atlas Energy Management or its affiliates constituting bad faith, willful misconduct, fraud or criminal conduct or any claims by employees of Atlas Energy Management or its affiliates relating to the terms and conditions of their employment. Atlas Energy Management and/or Atlas America will carry errors and omissions and other customary insurance upon the completion of the offering.

Termination

The management agreement does not have a specific term, however, Atlas Energy Management may not terminate the agreement before its tenth anniversary. We may terminate the management agreement only upon the affirmative vote of holders of at least two-thirds of our outstanding common units, including units held by Atlas America and its affiliates.

In the event we terminate the management agreement, the manager will have the option to require the successor manager, if any, to purchase the Class A units and management incentive interests for their fair market value as determined by agreement between the departing manager and the successor manager. If no agreement is reached, an independent expert selected by the departing manager and the successor manager will determine the fair market value. If the departing manager and the successor manager cannot agree on an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value. If the purchase option is not exercised by either the departing manager or the successor manager, the Class A units will be converted into common units on a one for one basis and the management incentive interests will convert into common units equal to the fair market value of those interests as determined by an independent expert selected in the manner described above.

Reimbursement of Expenses

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Certain relationships and related transactions

allocated overhead. The allocation of compensation expense for such persons will be determined based on a good faith estimate of the value of each such person’s services performed on our business and affairs, subject to the periodic review and approval of our audit or conflicts committee.

Standard of Care

In exercising its powers and discharging its duties under the management agreement, Atlas Energy Management will be required to act in good faith.

Amendments

The management agreement may not be amended without the prior approval of the conflicts committee of our board of directors if the proposed amendment will, in the reasonable discretion of our board of directors, adversely affect holders of our common units.

The omnibus agreement

Upon the closing of this offering, we will enter into an omnibus agreement with Atlas America that will govern our relationship with it and its affiliates, and with Resource America and its affiliates, with respect to certain matters not governed by the management agreement. We will also become party to an existing omnibus agreement between Atlas America and Atlas Pipeline as described in “Business—Natural Gas Gathering.”

Business Opportunities

If a business opportunity with respect to an investment in or acquisition of a domestic natural gas or oil production or development business is presented to us or Atlas America or its affiliates, we will have the first right to pursue the business opportunity as follows:

If the opportunity is a control investment, that is, majority control of the voting securities of an entity, we will have the first right of refusal.

If the opportunity is a non-control investment, that is, less than majority control of the voting securities of an entity, Atlas America and its affiliates will not be restricted in their ability to pursue the opportunity and will not have an obligation to present the opportunity to us.

Notwithstanding the foregoing, if the opportunity involves an investment in natural gas or wells or other natural gas or oil mineral rights, even a non-control investment, we will have the right of first refusal.

Anthem Securities, Inc

One of the subsidiaries we will acquire from Atlas America at the closing of this offering is Anthem Securities, Inc., a registered broker-dealer which acts as the dealer-manager on our investment partnership offerings. Under the omnibus agreement, Anthem Securities will continue to provide services to Atlas America and its affiliates and Resource America and its affiliates, upon their request, on the same terms that currently apply.

Registration rights

Under our limited liability company agreement, we have agreed to register for sale under the Securities Act and applicable state securities laws (subject to certain limitations) any common units proposed to be sold by Atlas America, our manager or any of their affiliates if an exemption from the registration requirements is not available. These registration rights require us to file up to three registration statements. We have also agreed to include any securities held by Atlas America, our manager or any of their affiliates in any registration statement that we file to offer securities for cash, except an offering relating solely to an employee benefit plan and other similar exceptions. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read “Units eligible for future sale.”

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Conflicts of interest and fiduciary duties

CONFLICTS OF INTEREST

General

Upon the closing of this offering, Atlas America and its affiliate, Atlas Energy Management, will own 27,550,000 common units and all of our Class A units and management incentive interests. In addition, we will enter into a management agreement with Atlas Energy Management, and following this offering we will be dependent on Atlas Energy Management for the management of our operations. Please read “Certain relationships and related party transactions—Agreements Governing the Transactions—The Management Agreement.” Conflicts of interest exist and may arise in the future as a result of the relationships between members of our board of directors and Atlas America and its affiliates, including our manager, on the one hand, and us and our unitholders, on the other hand. These potential conflicts may relate to the divergent interests of these parties.

Pursuant to the omnibus agreement to be entered into in connection with the closing of this offering, we will agree to certain business opportunity arrangements to address potential conflicts that may arise between us and Atlas America as described in “Certain relationships and related transactions—Agreements Governing the Transactions—The Omnibus Agreement.”

Whenever a conflict arises between Atlas America, our manager or their affiliates, on the one hand, and us or any other unitholder, on the other, our board of directors will resolve that conflict. A conflicts committee of our board of directors will, at the request of our board of directors, review conflicts of interest. The conflicts committee will consist of the independent directors, initially Ms. Warren and Messrs. Jones and Wolf. No breach of obligation will occur under our limited liability company agreement with respect to any conflict of interest if the resolution is:

approved by the conflicts committee of our board of directors, although our board of directors is not obligated to seek such approval;

approved by the vote of a majority of the outstanding units, excluding any common or Class A units owned by Atlas America, our manager or any of their affiliates, although our board of directors is not obligated to seek such approval;

on terms no less favorable to us than those generally provided to or available from unrelated third parties; or

fair to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

If our board of directors does not seek approval from the conflicts committee and our board determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors, including board members affected by the conflict of interest, acted in good faith, and in any proceeding brought by or on behalf of any member of the company, the person bringing the proceeding will have the burden of overcoming the presumption. Unless the resolution of a conflict is specifically provided for in our limited liability company agreement, our board of directors or its conflicts committee may consider any factors in good faith when resolving a conflict. When our limited liability company agreement requires someone to act in good faith, it requires that person to reasonably believe that he is acting in our best interests, unless the context otherwise requires.

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Conflicts of interest and fiduciary duties

In resolving a conflict, our board of directors or the conflicts committee may consider any factors it determines in good faith to be appropriate, including:

the relative interest of the parties involved in the conflict or affected by the action;

any customary or accepted industry practices or historical dealings with a particular person or entity; and

generally accepted accounting practices or principles and other factors as it considers relevant, if applicable.

Conflicts of interest could arise in the situations described below, among others:

Actions taken by our board of directors will affect the amount of cash available for distribution to unitholders.

The amount of cash that is available for distribution to unitholders is affected by decisions of our board of directors regarding various matters, including:

amount and timing of asset purchases and sales;

cash expenditures;

borrowings;

issuances of additional units; and

the creation, reduction or increase of reserves in any quarter.

In addition, our borrowings do not constitute a breach of any duty owned by our board of directors to the unitholders, including borrowings that have the purpose or effect of enabling our manager to receive management incentive distributions.

Atlas America and its affiliates may compete with us.

Except as provided in our omnibus agreement with Atlas America described in “Certain relationships and related transactions—Agreements Governing the Transactions—The omnibus agreement,” none of Atlas America or any of its affiliates is restricted from competing with us.

Neither we nor our manager have any employees and rely on the employees of Atlas America and its affiliates.

Neither we nor our manager have any employees and rely solely on employees of Atlas America and its affiliates. Atlas America and its affiliates will conduct business and activities of their own in which we will have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition between us, Atlas America and their affiliates for the time and effort of the officers and employees who provide services to our manager. All of our officers are also officers of our manager. Our officers and the officers of our manager who provide services to us are not required to work full time on our affairs. These officers may devote significant time to the affairs of our manager’s affiliates. There may be significant conflicts between us and affiliates of our manager regarding the availability of these officers to manage us.

We must reimburse our manager and its affiliates for expenses.

We must reimburse our manager and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services properly allocable to us. See “Management—Reimbursement of Expenses of Our Manager and its Affiliates.”

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Conflicts of interest and fiduciary duties

Contracts between us, on the one hand, and our manager and Atlas America and its affiliates, on the other, will not be the result of arm’s-length negotiations.

Our limited liability company agreement, the management agreement, the contribution agreement, the omnibus agreement and any of the other agreements, contracts and arrangements between us on the one hand, and Atlas America, our manager and their affiliates on the other, are not or will not be the result of arm’s length negotiations.

FIDUCIARY DUTIES

Our limited liability company agreement provides that our business and affairs shall be managed under the direction of our board of directors. Our limited liability company agreement further provides that the authority and function of our board of directors and officers shall be identical to the authority and functions of a board of directors and officers of a corporation organized under the Delaware General Corporation Law. Finally, our limited liability company agreement provides that our board of directors and officers must act in good faith. If our conflicts committee approves a transaction involving potential conflicts, or if a transaction is on terms generally available from unaffiliated third parties or an action is taken that is fair and reasonable to the company, unitholders will not be able to assert that such approval constituted a breach of fiduciary duties owed to them by our directors and officers.

We are unlike publicly-traded partnerships whose business and affairs are managed by a general partner with fiduciary duties to the partnership. While our manager will manage our day-to-day operations pursuant to the management agreement, subject to the oversight of our board of directors, we have no general partner with fiduciary duties to us. Our manager’s duties to us are contractual in nature and arise solely under the management agreement. As a consequence, none of Atlas America, our manager, or their affiliates will owe to us a fiduciary duty similar to that owed by a general partner to its limited partners.

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Security ownership of principal beneficial owners and management

The following table sets forth the beneficial ownership of our units immediately following the consummation of this offering and the formation transactions, assuming no exercise of the underwriters’ option to purchase additional common units, and held by:

each unitholder who then will be a beneficial owner of more than 5% of our outstanding units;

each of our officers and directors and named executive officers of our manager; and

our directors and executive officers of our manager as a group.

The amounts and percentage of units beneficially owned are reported on the basis of the SEC rules governing the determination of beneficial ownership of securities. Under the SEC rules, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, and/or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities and a person may be deemed a beneficial owner of securities as to which he has no economic interest. Except as indicated by footnote, to our knowledge the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

The address for all entities and persons named below is 311 Rouser Road, Moon Township, PA 15108.


	Common units to be beneficially owned			Class A units to be beneficially owned			Percentage of total units to be beneficially owned
Name	Number	Percentage		Number	Percentage		Percentage of total units to be beneficially owned
Atlas America	27,550,000	82.6	%	—	—		81.0	%
Atlas Energy Management	—	—		680,612	100	%	2	%
Edward E. Cohen	—	—		—	—		—
Jonathan Z. Cohen	—	—		—	—		—
Richard D. Weber(1)	50,000	*		—	—		*
Matthew A. Jones	—	—		—	—		—
Nancy J. McGurk	—	—		—	—		—
Walter C. Jones	—	—		—	—		—
Ellen F. Warren	—	—		—	—		—
Bruce M. Wolf	—	—		—	—		—
All directors and executive officers as a group (8 persons)	50,000	*		—	—		*

Less than 1%.

(1)

Amount shown based on assumed offering price at the mid-point of the range shown on the front cover of this prospectus. These units are subject to forfeiture, vesting 25% on each anniversary of April 17, 2006, and therefore Mr. Weber has voting power but not investment power.

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Description of the common units

THE COMMON UNITS

The common units represent limited liability company interests in us. The holders of common units are entitled to participate in distributions and exercise the rights or privileges available to unitholders under our limited liability company agreement. For a description of the relative rights and preferences of holders of common units in and to distributions, please read this section and “How we make cash distributions.” For a description of the rights and privileges of unitholders under our limited liability company agreement, including voting rights, please read “Our limited liability company agreement.”

TRANSFER AGENT AND REGISTRAR

The American Stock Transfer and Trust Company will serve as registrar and transfer agent for the common units. We pay all fees charged by the transfer agent for transfers of common units, except the following fees that will be paid by unitholders:

surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

special charges for services requested by a holder of a common unit; and

other similar fees or charges.

There will be no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their shareholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

The transfer agent may at any time resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, we are authorized to act as the transfer agent and registrar until a successor is appointed.

TRANSFER OF COMMON UNITS

By transfer of common units in accordance with our limited liability company agreement, each transferee of common units will be admitted as a unitholder with respect to the units transferred when such transfer and admission is reflected on our books and records. Additionally, each transferee of common units:

becomes the record holder of the units;

automatically agrees to be bound by the terms and conditions of, and is deemed to have executed our limited liability company agreement;

represents that the transferee has the capacity, power and authority to enter into our limited liability company agreement;

grants powers of attorney to our officers and any liquidator of our company as specified in our limited liability company agreement; and

makes the consents and waivers contained in our limited liability company agreement.

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Description of the common units

An assignee will become a unitholder of our company for the transferred common units upon the recording of the name of the assignee on our books and records.

Until a common unit has been transferred on our books, we and the transfer agent, notwithstanding any notice to the contrary, may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

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Our limited liability company agreement

The following is a summary of the material provisions of our limited liability company agreement. The form of our limited liability company agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of the form of this agreement upon request at no charge.

We summarize the following provisions of our limited liability company agreement elsewhere in this prospectus:

with regard to distributions of available cash, please read “How we make cash distributions;”

with regard to the transfer of common units, please read “Description of the units—Transfer of Common Units;” and

with regard to allocations of taxable income and taxable loss, please read “Material tax consequences.”

ORGANIZATION

Our company was formed in June 2006 and will remain in existence until dissolved in accordance with our limited liability company agreement.

PURPOSE

Under our limited liability company agreement, we are permitted to engage, directly or indirectly, in any activity that our board of directors approves and that a limited liability company organized under Delaware law lawfully may conduct; provided, that our board of directors shall not cause us to engage, directly or indirectly, in any business activities that it determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our board of directors has the ability to cause us and our operating subsidiaries to engage in activities other than the exploitation, development and production of natural gas reserves, our board of directors has no current plans to do so. Our board of directors is authorized in general to perform all acts it deems to be necessary or appropriate to carry out our purposes and to conduct our business.

FIDUCIARY DUTIES

For a description of fiduciary duties, please read “Conflicts of interest and fiduciary duties.”

AGREEMENT TO BE BOUND BY LIMITED LIABILITY COMPANY AGREEMENT; POWER OF ATTORNEY

By purchasing a common unit in us, you will be admitted as a member of our company and will be deemed to have agreed to be bound by the terms of our limited liability company agreement. Pursuant to this agreement, each unitholder and each person who acquires a common unit from a unitholder grants to our board of directors (and, if appointed, a liquidator) a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our board of directors the authority to make certain amendments to, and to make consents and waivers under and in accordance with, our limited liability company agreement.

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Our limited liability company agreement

CAPITAL CONTRIBUTIONS

Unitholders (including holders of common units) are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

LIMITED LIABILITY

The Delaware Limited Liability Company Act, which we refer to as the Delaware Act, provides that any unitholder who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the company for the amount of the distribution for three years. Under the Delaware Act, a limited liability company may not make a distribution to any unitholder if, after the distribution, all liabilities of the company, other than liabilities to unitholders on account of their limited liability company interests and liabilities for which the recourse of creditors is limited to specific property of the company, would exceed the fair value of the assets of the company. For the purpose of determining the fair value of the assets of a company, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the company only to the extent that the fair value of that property exceeds the nonrecourse liability. Under the Delaware Act, an assignee who becomes a substituted unitholder of a company is liable for the obligations of his assignor to make contributions to the company, except the assignee is not obligated for liabilities unknown to him at the time he became a unitholder and that could not be ascertained from the limited liability company agreement.

Our subsidiaries will initially conduct business only in New York, Ohio, Pennsylvania and Tennessee. We may decide to conduct business in other states, and maintenance of limited liability for us, as a member of our operating subsidiaries, may require compliance with legal requirements in the jurisdictions in which the operating subsidiaries conduct business, including qualifying our subsidiaries to do business there. Limitations on the liability of unitholders for the obligations of a limited liability company have not been clearly established in many jurisdictions. We will operate in a manner that our board of directors considers reasonable and necessary or appropriate to preserve the limited liability of our unitholders.

VOTING RIGHTS

Holders of our common units and our Class A units have voting rights on most matters. Upon the completion of this offering, Atlas Energy Management will own all of our Class A units and Atlas America will own 27,550,000 of our common units. The following matters require a unitholder vote:

Election of members of the board of directors

Following our initial public offering, our board of directors will consist of seven members, as required by our limited liability company agreement. At the first annual meeting of our unitholders following this offering, Class A and common unitholders, voting as a single class, will elect the board members. Please read “—Election of Members of Our Board of Directors.”

Issuance of additional securities including common units

No approval right.

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Our limited liability company agreement

Amendment of our limited liability company agreement

Certain amendments may be made by our board of directors without unitholder approval. Other amendments generally require the approval of our common units and Class A units, voting as a single class. Please read “—Amendments of Our Limited Liability Company Agreement.”

Merger of our company or the sale of all or substantially all of our assets

Common unit majority and Class A unit majority. Please read “—Merger, Sale or Other Disposition of Assets.”

Dissolution of our company

Common unit majority and Class A unit majority. Please read “—Termination or Dissolution.”

Matters requiring the approval of a common unit majority require the approval of a majority of the outstanding common units voting together as a single class and matters requiring the approval of a Class A unit majority require the approval of a majority of the outstanding Class A units voting together as a single class.

ELIMINATION OF SPECIAL VOTING RIGHTS OF CLASS A UNITS

The class voting right of the Class A units can be eliminated only upon a proposal submitted by or with the consent of our board of directors and the vote of the holders of at least 66²/3% of our outstanding common units. If such elimination is so approved, the Class A units will automatically convert into common units on a one-for-one basis and our manager will have the right to convert its management incentive interests into common units based on their then fair market value.

ISSUANCE OF ADDITIONAL SECURITIES

Our limited liability company agreement authorizes us to issue an unlimited number of additional securities and authorizes us to buy securities for the consideration and on the terms and conditions determined by our board of directors without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional units or other equity securities. Holders of any additional units we issue will be entitled to share equally with the then-existing holders of common units, Class A units and management incentive interests in our distributions of available cash. In addition, the issuance of additional units or other equity securities may dilute the value of the interests of the then-existing holders of units in our net assets.

In accordance with Delaware law and the provisions of our limited liability company agreement, we may also issue additional securities that, as determined by our board of directors, may have special voting or other rights to which the units are not entitled.

The holders of units will not have preemptive or preferential rights to acquire additional units or other securities.

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Our limited liability company agreement

ELECTION OF MEMBERS OF OUR BOARD OF DIRECTORS

At our first annual meeting of members following this offering, all of the members of our board of directors will be elected by our Class A units and our common unitholders, voting together as a single class. The board of directors will be subject to a re-election on an annual basis at our annual meeting of members.

Removal of members of our board of directors

Any director may be removed, with or without cause, by the holders of a majority of the outstanding common units and Class A units then entitled to vote at an election of directors, voting as a single class.

Increase in the size of our board of directors

The size of our board of directors may increase only with the approval of a majority of the directors. If the size of our board of directors is so increased, the vacancy created thereby shall be filled by a person appointed by our board of directors until the next annual meeting of members.

AMENDMENT OF OUR LIMITED LIABILITY COMPANY AGREEMENT

General

Amendments to our limited liability company agreement may be proposed only by or with the consent of our board of directors. To adopt a proposed amendment, other than the amendments discussed below, our board of directors is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the unitholders to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a majority of the common units and the Class A units, voting together as a single class.

Prohibited amendments

No amendment may be made that would:

enlarge the obligations of any unitholder without its consent, unless approved by at least a majority of the type or class of member interests so affected; or

provide that we are not dissolved upon an election to dissolve our company by our board of directors that is approved by a common unit majority and a Class A unit majority.

The provision of our limited liability company agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 75% of the outstanding common units, voting together as a single class, and 75% of the outstanding Class A units, voting together as a single class.

No unitholder approval

Our board of directors may generally make amendments to our limited liability company agreement without the approval of any unitholder or assignee to reflect:

a change in our name, the location of our principal place of our business, our registered agent or our registered office;

the admission, substitution, withdrawal or removal of members in accordance with our limited liability company agreement;

the merger of our company or any of our subsidiaries into, or the conveyance of all of our assets to, a newly-formed entity if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity;

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Our limited liability company agreement

a change that our board of directors determines to be necessary or appropriate for us to qualify or continue our qualification as a company in which our members have limited liability under the laws of any state or to ensure that neither we, our operating subsidiaries nor any of its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

an amendment that is necessary, in the opinion of our counsel, to prevent us, our board of directors or our officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

an amendment that our board of directors determines to be necessary or appropriate for the authorization of additional securities or rights to acquire securities;

any amendment expressly permitted in our limited liability company agreement to be made by our board of directors acting alone;

an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our limited liability company agreement;

any amendment that our board of directors determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our limited liability company agreement;

a change in our fiscal year or taxable year and related changes;

a merger, conversion or conveyance effected in accordance with our limited liability company agreement; and

any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our board of directors may make amendments to our limited liability company agreement without the approval of any unitholder or assignee if our board of directors determines that those amendments:

do not adversely affect the unitholders (including any particular class of unitholders as compared to other classes of unitholders) in any material respect;

are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

are necessary or appropriate to facilitate the trading of units or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the units are or will be listed for trading, compliance with any of which our board of directors deems to be in the best interests of us and our unitholders;

are necessary or appropriate for any action taken by our board of directors relating to splits or combinations of units under the provisions of our limited liability company agreement; or

are required to effect the intent expressed in this prospectus or the intent of the provisions of our limited liability company agreement or are otherwise contemplated by our limited liability company agreement.

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Opinion of counsel and unitholder approval

Our board of directors will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to our unitholders or result in our being treated as an entity for federal income tax purposes if one of the amendments described above under “—No Unitholder Approval” should occur. No other amendments to our limited liability company agreement will become effective without the approval of holders of at least 90% of the outstanding common units and Class A units unless we obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any unitholder of our company.

Any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action is required to be approved by the affirmative vote of unitholders whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.

MERGER, SALE OR OTHER DISPOSITION OF ASSETS

Our board of directors is generally prohibited, without the prior approval of the holders of a common unit majority and Class A unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries, provided that our board of directors may mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our board of directors may also sell all or substantially all of our assets under a foreclosure or other realization upon the encumbrances above without that approval.

If the conditions specified in our limited liability company agreement are satisfied, our board of directors may merge our company or any of its subsidiaries into, or convey all of our assets to, a newly-formed entity if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity. Our unitholders are not entitled to dissenters’ rights of appraisal under our limited liability company agreement or applicable Delaware law in the event of a merger or consolidation, a sale of all or substantially all of our assets or any other transaction or event.

TERMINATION AND DISSOLUTION

We will continue as a company until terminated under our limited liability company agreement. We will dissolve upon: (1) the election of our board of directors to dissolve us, if approved by the holders of a common unit majority and Class A unit majority; (2) the sale, exchange or other disposition of all or substantially all of the assets and properties of our company and our subsidiaries; or (3) the entry of a decree of judicial dissolution of our company.

LIQUIDATION AND DISTRIBUTION OF PROCEEDS

Upon our dissolution, the liquidator authorized to wind up our affairs will, acting with all of the powers of our board of directors that the liquidator deems necessary or desirable in its judgment, liquidate our assets and apply the proceeds of the liquidation as described in “How we make cash distributions—Distributions of Cash Upon Liquidation.”

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The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to unitholders in kind if it determines that a sale would be impractical or would cause undue loss to our unitholders.

ANTI-TAKEOVER PROVISIONS

Our limited liability company agreement contains specific provisions that are intended to discourage a person or group from attempting to take control of our company without the approval of our board of directors. Specifically, our limited liability company agreement provides that we will elect to have Section 203 of the DGCL apply to transactions in which an interested common unitholder (as described below) seeks to enter into a merger or business combination with us. Under this provision, such a holder will not be permitted to enter into a merger or business combination with us unless:

before such time, our board of directors approved either the business combination or the transaction that resulted in the common unitholder’s becoming an interested common unitholder;

upon consummation of the transaction that resulted in the common unitholder becoming an interested common unitholder, the interested common unitholder owned at least 85% of our outstanding common units at the time the transaction commenced, excluding for purposes of determining the number of common units outstanding those common units owned:

by persons who are directors and also officers; and

by employee common unit plans in which employee participants do not have the right to determine confidentially whether common units held subject to the plan will be tendered in a tender or exchange offer; or

at or after such time the business combination is approved by our board of directors and authorized at an annual or special meeting of our common unitholders, and not by written consent, by the affirmative vote of the holders of at least 66²/3% of our outstanding voting common units that are not owned by the interested common unitholder.

Section 203 defines “business combination” to include:

any merger or consolidation involving the company and the interested common unitholder;

any sale, transfer, pledge or other disposition of 10% or more of the assets of the company involving the interested common unitholder;

subject to certain exceptions, any transaction that results in the issuance or transfer by the company of any common units of the company to the interested common unitholder;

any transaction involving the company that has the effect of increasing the proportionate share of the units of any class or series of the company beneficially owned by the interested common unitholder; or

the receipt by the interested common unitholder of the benefit of any loans, advances, guarantees, pledges or other financial benefits provided by or through the company.

In general, an “interested common unitholder” is any person or entity, other than Atlas America, our manager, their affiliates or transferees, that beneficially owns (or within three years did own) 15% or more of the outstanding common units of the company and any entity or person affiliated with or controlling or controlled by such entity or person.

The existence of this provision would be expected to have an anti-takeover effect with respect to transactions not approved in advance by our board of directors, including discouraging attempts that might result in a premium over the market price for common units held by common unitholders.

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Our limited liability agreement also restricts the voting rights of common unitholders by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than Atlas America, our manager, their affiliates or transferees and persons who acquire such units with the prior approval of our board of directors, cannot vote on any matter.

LIMITED CALL RIGHT

If at any time any person owns more than 87.5% of the then-issued and outstanding membership interests of any class, such person will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the remaining membership interests of the class held by unaffiliated persons as of a record date to be selected by our management, on at least 10 but not more than 60 days’ notice. The unitholders are not entitled to dissenters’ rights of appraisal under our limited liability company agreement or applicable Delaware law if this limited call right is exercised. The purchase price in the event of this purchase is the greater of:

the highest cash price paid by such person for any membership interests of the class purchased within the 90 days preceding the date on which such person first mails notice of its election to purchase those membership interests; or

the closing market price as of the date three days before the date the notice is mailed.

As a result of this limited call right, a holder of membership interests in our company may have his membership interests purchased at an undesirable time or price. Please read “Risk factors—Risks Related to Our Structure.” The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his units in the market. Please read “Material tax consequences—Disposition of Common Units.”

MEETINGS; VOTING

Except as described below regarding a person or group owning 20% or more of units then outstanding, unitholders on the record date will be entitled to notice of, and to vote at, meetings of our unitholders and to act upon matters for which approvals may be solicited.

All notices of meetings of unitholders shall be sent or otherwise given in accordance with our limited liability company agreement not less than 10 days nor more than 60 days before the date of the meeting. The notice shall specify the place, date and hour of the meeting and (i) in the case of a special meeting, the general nature of the business to be transacted (no business other than that specified in the notice may be transacted) or (ii) in the case of the annual meeting, those matters which the board of directors, at the time of giving the notice, intends to present for action by the unitholders (but any proper matter may be presented at the meeting for such action). The notice of any meeting at which directors are to be elected shall include the name of any nominee or nominees who, at the time of the notice, the board of directors intends to present for election. Any previously scheduled meeting of the unitholders may be postponed, and any special meeting of the unitholders may be cancelled, by resolution of the board of directors upon public notice given prior to the date previously scheduled for such meeting of unitholders.

Units that are owned by an assignee who is a record holder, but who has not yet been admitted as a member, shall be voted at the written direction of the record holder by a proxy designated by our board of directors. Absent direction of this kind, the units will not be voted, except that units held by us on behalf of non-citizen assignees shall be voted in the same ratios as the votes of unitholders on other units are cast.

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Any action required or permitted to be taken by our unitholders must be effected at a duly called annual or special meeting of unitholders and may not be effected by any consent in writing by such unitholders.

Any action that is required or permitted to be taken by our unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units as would be necessary to authorize or take that action at a meeting. Special meetings of the unitholders may be called only by our board of directors. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional units having special voting rights could be issued. Please read “—Issuance of Additional Securities” above. However, if at any time any person or group, other than Atlas America, our manager and their affiliates, or a direct or subsequently approved transferee of Atlas America, our manager or their affiliates, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of units will be delivered to the record holder by us or by the transfer agent.

NON-CITIZEN ASSIGNEES; REDEMPTION

If we or any of our subsidiaries are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our board of directors, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any unitholder or assignee, we may redeem, upon 30 days’ advance notice, the units held by the unitholder or assignee at their current market price. To avoid any cancellation or forfeiture, our board of directors may require each unitholder or assignee to furnish information about his nationality, citizenship or related status. If a unitholder or assignee fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our board of directors determines after receipt of the information that the unitholder or assignee is not an eligible citizen, the unitholder or assignee may be treated as a non-citizen assignee. In addition to other limitations on the rights of an assignee who is not a substituted unitholder, a non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation.

INDEMNIFICATION

Under our limited liability company agreement and subject to specified limitations, we will indemnify to the fullest extent permitted by law from and against all losses, claims, damages or similar events any person who is or was our director or officer, or while serving as our director or officer, is or was serving as a tax matters member or, at our request, as a director, manager, officer, tax matters member, employee, partner, fiduciary or trustee of us or any of our subsidiaries. Additionally, we shall indemnify to the fullest

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extent permitted by law and authorized by our board of directors, from and against all losses, claims, damages or similar events any person is or was an employee or agent (other than an officer) of our company.

Any indemnification under our limited liability company agreement will only be out of our assets. We are authorized to purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our limited liability company agreement.

BOOKS AND REPORTS

We are required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of unitholders can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

RIGHT TO INSPECT OUR BOOKS AND RECORDS

Our limited liability company agreement provides that a unitholder can, for a purpose reasonably related to his interest as a unitholder, upon reasonable demand and at his own expense, have furnished to him:

a current list of the name and last known address of each unitholder;

a copy of our tax returns;

information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each unitholder and the date on which each became a unitholder;

copies of our limited liability company agreement, the certificate of formation of the company, related amendments and powers of attorney under which they have been executed;

information regarding the status of our business and financial condition; and

any other information regarding our affairs as is just and reasonable.

Our board of directors may, and intends to, keep confidential from our unitholders information that it believes to be in the nature of trade secrets or other information, the disclosure of which our board of directors believes in good faith is not in our best interests, information that could damage our company or our business, or information that we are required by law or by agreements with a third party to keep confidential.

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REGISTRATION RIGHTS

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After the sale of the common units offered by this prospectus, Atlas America will own 27,550,000 common units and Atlas Energy Management will own all of our 680,612 Class A units and management incentive interests that may be converted into common units, at Atlas Energy Management’s election, if we terminate the management agreement or if the common unitholders vote to eliminate the special voting rights of the Class A units. The sale of these common units could have an adverse impact on the price of the common units or on any trading market that may develop.

The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units owned by an “affiliate” of us cannot be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption from those requirements under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

1% of the total number of the securities outstanding or

the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, notice requirements and the availability of current public information about us. A person who is not deemed to have been our affiliate at any time during the three months preceding a sale, and who has beneficially owned his or her common units for at least two years, can sell units under Rule 144 without regard to the public information requirements, volume limitations, manner of sale provisions or notice requirements of Rule 144.

The limited liability company agreement does not restrict our ability to issue additional equity securities. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. See “Our limited liability company agreement—Issuance of Additional Securities.”

Under the limited liability company agreement, Atlas America, our manager and their affiliates have the right to demand that we register under the Securities Act and state laws the offer and sale of any units that they hold. Subject to the terms and conditions of the limited liability company agreement, these registration rights allow Atlas America, our manager and their affiliates or their assignees to require registration of these units and to include these units in a registration by us of other units. These registration rights will continue in effect for two years following any withdrawal or removal of our manager as manager. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses of the registration.

Atlas America, our officers and directors and our manager, its officers and directors have agreed with the underwriters not to dispose of any units they beneficially own for a period of 180 days after the date of this prospectus, subject to certain exceptions. Please read “Underwriting.”

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This section is a discussion of the material tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Ledgewood, P.C., counsel to us and our manager, insofar as it relates to matters of United States federal income tax law and legal conclusions with respect to those matters. This section is based on current provisions of the Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to us and our and our subsidiaries.

This section does not address all federal income tax matters that affect us or the unitholders. Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, non-resident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), employee benefit plans, real estate investment trusts (REITs) or mutual funds. Accordingly, we urge each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of our common units.

No ruling has been or will be requested from the IRS regarding any matter that affects us or prospective unitholders. Instead, we will rely on opinions and advice of Ledgewood. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made in this discussion may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for our common units and the prices at which our common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and thus will be borne directly by our unitholders. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

All statements regarding matters of law and legal conclusions set forth below, unless otherwise noted, are the opinion of Ledgewood and are based on the accuracy of the representations made by us. Statements of fact do not represent opinions of Ledgewood.

For the reasons described below, Ledgewood has not rendered an opinion with respect to the following specific federal income tax issues:

(1)

the treatment of a unitholder whose units are loaned to a short seller to cover a short sale of units (please read “—Tax Consequences of Unit Ownership— Treatment of Short Sales”);

(2)

whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “—Disposition of Common Units—Allocations Between Transferors and Transferees”);

(3)

whether percentage depletion will be available to a unitholder or the extent of the percentage depletion deduction available to any unitholder (please read “—Tax Treatment of Operations—Depletion Deductions”);

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(4)

whether the deduction related to United States production activities will be available to a unitholder or the extent of such deduction to any unitholder (please read “—Tax Treatment of Operations—Deduction for United States Production Activities”); and

(5)

whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “—Tax Consequences of Unit Ownership—Section 754 Election” and “—Uniformity of Common Units”).

PARTNERSHIP STATUS

Except as discussed in the following paragraph, a limited liability company that has more than one member and that has not elected to be treated as a corporation is treated as a partnership for federal income tax purposes and, therefore, is not a taxable entity and incurs no federal income tax liability. Instead, each partner is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, even if no cash distributions are made to him. Distributions by a partnership to a partner are generally not taxable to the partner unless the amount of cash distributed to him is in excess of his adjusted basis in his partnership interest.

Section 7704 of the Code provides that publicly-traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to in this discussion as the “Qualifying Income Exception,” exists with respect to publicly-traded partnerships 90% or more of the gross income of which for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the exploration, development, mining or production, processing, transportation and marketing of natural resources, including oil, natural gas, and products thereof. Other types of qualifying income include fee-based income derived from the drilling, management and operation of oil and natural gas wells for our investment partnerships, interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than % of our current income does not constitute qualifying income; however, this estimate could change from time to time. Based on and subject to this estimate, the factual representations made by us, and a review of the applicable legal authorities, Ledgewood is of the opinion that more than 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income can change from time to time.

No ruling has been or will be sought from the IRS, and the IRS has made no determination as to our status or the status of our operating subsidiaries for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Code. Instead, we will rely on the opinion of Ledgewood. Ledgewood is of the opinion, based upon the Code, its regulations, published revenue rulings, court decisions and the representations described below, that we will be classified as a partnership, and each of our operating subsidiaries will be disregarded as an entity separate from us, for federal income tax purposes.

In rendering its opinion, Ledgewood has relied on factual representations made by us. The representations made by us upon which Ledgewood has relied include:

(a)

Neither we, nor any of our subsidiaries, have elected nor will we elect to be treated as a corporation; and

(b)

For each taxable year, more than 90% of our gross income will be income that Ledgewood has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Code.

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If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation would be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to the unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as taxable dividend income to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital to the extent of the unitholder’s tax basis in his units, or taxable capital gain, after the unitholder’s tax basis in his units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The remainder of this section is based on Ledgewood’s opinion that we will be classified as a partnership for federal income tax purposes.

UNITHOLDER STATUS

Unitholders who become our members will be treated as our partners for federal income tax purposes. Also, assignees who have executed and delivered transfer applications, and are awaiting admission as members, and unitholders whose units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their units will be treated as our partners for federal income tax purposes.

Because there is no direct authority addressing the federal tax treatment of assignees of units who are entitled to execute and deliver transfer applications and thereby become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, the opinion of Ledgewood does not extend to these persons. Furthermore, a purchaser or other transferee of units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of units unless the units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those units.

A beneficial owner of units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales.”

Items of our income, gain, loss, or deduction are not reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore be fully taxable as ordinary income. These unitholders are urged to consult their own tax advisors with respect to the consequences of their status as partners in us for federal income tax purposes.

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TAX CONSEQUENCES OF UNIT OWNERSHIP

Flow-through of taxable income

We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year or years ending with or within his taxable year. Our taxable year ends on September 30.

Treatment of distributions

Distributions made by us to a unitholder generally will not be taxable to him for federal income tax purposes to the extent of his tax basis in his units immediately before the distribution. Cash distributions made by us to a unitholder in an amount in excess of his tax basis in his units generally will be considered to be gain from the sale or exchange of those units, taxable in accordance with the rules described under “—Disposition of Common Units” below. To the extent that cash distributions made by us cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “—Limitations on Deductibility of Losses.”

Any reduction in a unitholder’s share of our liabilities for which no partner bears the economic risk of loss, known as “non-recourse liabilities,” will be treated as a distribution of cash to that unitholder. A decrease in a unitholder’s percentage interest in us because of our issuance of additional units will decrease his share of our nonrecourse liabilities and thus will result in a corresponding deemed distribution of cash, which may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including recapture of intangible drilling costs, depletion and depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in Section 751 of the Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having received his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income. That income will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of taxable income to distributions

We estimate that a purchaser of our common units in this offering who holds those units from the date of closing of this offering through the record date for distributions for the period ending , will be allocated an amount of federal taxable income for that period that will be less than % of the cash distributed to the unitholder with respect to that period. The ratio of taxable income allocable to cash distributions to the unitholders may increase after that. These estimates are based upon the assumption that gross income from operations will be sufficient to make estimated distributions on all common units and other assumptions with respect to capital expenditures, cash flow and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we intend to adopt and with which the IRS could disagree. Accordingly, these estimates may not prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower, and any differences could be material and could materially affect the value of the common units.

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Basis of common units

A unitholder’s initial tax basis for his common units will be the amount he paid for the units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis generally will be decreased, but not below zero, by distributions to him from us, by his share of our losses, by depletion deductions taken by him to the extent such deductions do not exceed his proportionate share of the adjusted tax basis of the underlying producing properties, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder’s share of our nonrecourse liabilities will generally be based on his share of our profits. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

Limitations on deductibility of losses

The deduction by a unitholder of his share of our losses will be limited to his tax basis in his common units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of its stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that amount is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction in a later year to the extent that his tax basis or at-risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a common unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.

In general, a unitholder will be at risk to the extent of his tax basis in his common units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the common units for repayment. A unitholder’s at-risk amount will increase or decrease as the tax basis of the unitholder’s common units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities. Moreover, a unitholder’s at risk amount will decrease by the amount of the unitholder’s depletion deductions and will increase to the extent of the amount by which the unitholder’s percentage depletion deductions with respect to our property exceed the unitholder’s share of the basis of that property.

The at risk limitation applies on an activity-by-activity basis, and in the case of natural gas and oil properties, each property is treated as a separate activity. Thus, a taxpayer’s interest in each oil or gas property is generally required to be treated separately so that a loss from any one property would be limited to the at risk amount for that property and not the at risk amount for all the taxpayer’s natural gas and oil properties. It is uncertain how this rule is implemented in the case of multiple natural gas and oil properties owned by a single entity treated as a partnership for federal income tax purposes. However, for taxable years ending on or before the date on which further guidance is published, the IRS will permit aggregation of oil or gas properties we own in computing a unitholder’s at risk limitation with respect to us. If a unitholder must compute his at risk amount separately with respect to each oil or gas property we own, he may not be allowed to utilize his share of losses or deductions attributable to a particular property even though he has a positive at risk amount with respect to his common units as a whole.

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The passive loss limitation generally provides that individuals, estates, trusts and some closely held corporations and personal service corporations are permitted to deduct losses from passive activities, which are generally defined as trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitation is applied separately with respect to each publicly-traded partnership. Consequently, any losses we generate will be available to offset only our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments, a unitholder’s investments in other publicly-traded partnerships, or a unitholder’s salary or active business income. If we dispose of all or only part of our interest in an oil or gas property, unitholders will be able to offset their suspended passive activity losses from our activities against the gain, if any, on the disposition. Any previously suspended losses in excess of the amount of gain recognized will remain suspended. Notwithstanding whether a natural gas and oil property is a separate activity, passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted by the unitholder in full only when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after certain other applicable limitations on deductions, including the at-risk rules and the tax basis limitation.

A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly-traded partnerships.

Limitation on interest deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

interest on indebtedness properly allocable to property held for investment;

our interest expense attributable to portfolio income; and

the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a common unit.

Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that net passive income earned by a publicly-traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-level collections

If we are required or elect under applicable law to pay any federal, state or local income tax on behalf of any unitholder or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a unitholder whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our limited liability company agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of common units and to adjust later distributions, so that after giving effect to these

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distributions, the priority and characterization of distributions otherwise applicable under our limited liability company agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of a unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of income, gain, loss and deduction

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among the unitholders in accordance with their percentage interests in us. If we have a net loss for an entire year, the loss will be allocated to our unitholders according to their percentage interests in us to the extent of their positive capital account balances.

Specified items of our income, gain, loss and deduction will be allocated under Section 704(c) of the Code to account for the difference between the tax basis and fair market value of our assets at the time of this offering, which assets are referred to in this discussion as “Contributed Property.” These allocations are required to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and the “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “book-tax disparity.” The effect of these allocations to a unitholder who purchases common units in this offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of the offering. In the event we issue additional units or engage in certain other transactions in the future, Section 704(c) allocations will be made to all holders of partnership interests, including purchasers of common units in this offering, to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of the future transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by other unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by Section 704(c), will generally be given effect for federal income tax purposes in determining a unitholder’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a unitholder’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

his relative contributions to us;

the interests of all the unitholders in profits and losses;

the interest of all the unitholders in cash flow; and

the rights of all the unitholders to distributions of capital upon liquidation.

Ledgewood is of the opinion that, with the exception of the issues described in “—Tax Consequences of Unit Ownership—Section 754 Election,” “—Uniformity of Common units” and “—Disposition of Common Units—Allocations Between Transferors and Transferees,” allocations under our limited liability company agreement will be given effect for federal income tax purposes in determining a unitholder’s share of an item of income, gain, loss or deduction.

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Treatment of short sales

A unitholder whose common units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be a partner for tax purposes with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

none of our income, gain, loss or deduction with respect to those units would be reportable by the unitholder;

any cash distributions received by the unitholder with respect to those units would be fully taxable; and

all of these distributions would appear to be ordinary income.

Ledgewood has not rendered an opinion regarding the treatment of a unitholder whose units are loaned to a short seller. Therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “—Disposition of Common Units—Recognition of Gain or Loss.”

Alternative minimum tax

Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for non-corporate taxpayers is 26% on the first $175,000 ($87,500 in the case of married individuals filing separately) of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult their tax advisors with respect to the impact of an investment in our units on their liability for the alternative minimum tax.

Tax rates

In general, the highest effective federal income tax rate for individuals currently is 35% and the maximum federal income tax rate for net capital gains of an individual currently is 15% if the asset disposed of was held for more than 12 months at the time of disposition.

Section 754 election

We will make the election permitted by Section 754 of the Code. That election is irrevocable without the consent of the IRS. That election will generally permit us to adjust a unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Code to reflect his purchase price. The Section 743(b) adjustment does not apply to a person who purchases units directly from us, and it belongs only to the purchaser and not to other unitholders. Please also read, however, “—Allocation of Income, Gain, Loss and Deduction” above. For purposes of this discussion, a unitholder’s inside basis in our assets has two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.

Treasury Regulations under Section 743 of the Code require, if the remedial allocation method is adopted (which we will adopt), a portion of the Section 743(b) adjustment attributable to recovery property to be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain. Under Treasury Regulation Section 1.167(c)-l(a)(6), a Section 743(b) adjustment attributable to property

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subject to depreciation under Section 167 of the Code rather than cost recovery deductions under Section 168 is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our limited liability company agreement, we are authorized to take a position to preserve the uniformity of units even if that position is not consistent with these Treasury Regulations. Please read “—Tax Treatment of Operations—Uniformity of Common Units.”

Although Ledgewood is unable to opine on the validity of this approach because there is no clear authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized book-tax disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of the property, or treat that portion as non-amortizable to the extent attributable to property the common basis of which is not amortizable. This method is consistent with the regulations under Section 743 but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent a Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized book-tax disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “—Tax Treatment of Operations—Uniformity of Common Units.”

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depletion and depreciation deductions and his share of any gain on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally a built-in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our tangible assets to goodwill instead. Goodwill, an intangible asset, is generally either nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

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TAX TREATMENT OF OPERATIONS

Accounting method and taxable year

Our initial taxable year will end on September 30, 2006 because Atlas America, our majority owner, currently has a fiscal year ending September 30. Atlas America recently announced that it would change to a December 31 fiscal year. Therefore, our taxable year is expected to change after September 30, 2006. If holders of a majority of the interests in our capital and profits use a single taxable year, we must use that year. If there is no such majority interest taxable year, we must use the same taxable year as Atlas America, provided that no person with a taxable year different from Atlas America owns a 5% or greater interest in our capital or profits. If there is no majority interest taxable year and there is no owner of 5% or more of our capital and profits other than Atlas America, we must use the taxable year that produces the “least aggregate deferral” to holders of membership interests. In general, these determinations will be made on the first date of each taxable year.

We expect to change our taxable year to the calendar year at the same time Atlas America does so. As a result, in the absence of circumstances which we consider unlikely to apply, we expect our taxable year that begins on October 1, 2006 to end on December 31, 2006. We expect to use the calendar taxable year for all subsequent years.

If Atlas America does not change its taxable year to the calendar year as described above, our taxable year may remain a fiscal year ending September 30 or may change to the calendar year as described above or another taxable year, depending upon a number of factors. We believe it is unlikely that our taxable year will not change to the calendar year after September 30, 2006, as described above.

Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. For example, a unitholder who uses the calendar year will be required to include in his income for 2006 his share of our income, gain, loss and deduction for our taxable year ending September 30, 2006 and, if we change to the calendar year as described above, for our taxable year ending December 31, 2006. In addition, a unitholder who has a different taxable year than our taxable year and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read “—Disposition of Common Units—Allocations Between Transferors and Transferees.”

Depletion deductions

Subject to the limitations on deductibility of losses discussed above, unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to our natural gas and oil interests. Although the Code requires each unitholder to compute his own depletion allowance and maintain records of his share of the adjusted tax basis of the underlying property for depletion and other purposes, we intend to furnish each of our unitholders with information relating to this computation for federal income tax purposes.

Percentage depletion is generally available with respect to unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, natural gas, or derivative products or the operation of a major refinery. Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the unitholder’s gross income from the depletable property for the taxable year. The percentage depletion

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deduction with respect to any property is limited to 100% of the taxable income of the unitholder from the property for each taxable year, computed without the depletion allowance. A unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the unitholder’s daily production of domestic crude oil, or the natural gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between natural gas and oil production, with 6,000 cubic feet of domestic natural gas production regarded as equivalent to one barrel of crude oil. The 1,000 barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.

In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a unitholder’s total taxable income from all sources for the year, computed without the depletion allowance, net operating loss carrybacks, or capital loss carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the unitholder’s total taxable income for that year. The carryover period resulting from the 65% net income limitation is indefinite.

Unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (i) dividing the unitholder’s share of the adjusted tax basis in the underlying mineral property by the number of mineral units (barrels of oil and Mcf of natural gas) remaining as of the beginning of the taxable year and (ii) multiplying the result by the number of mineral units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the unitholder’s share of the total adjusted tax basis in the property.

All or a portion of any gain recognized by a unitholder as a result of either the disposition by us of some or all of our natural gas and oil interests or the disposition by the unitholder of some or all of his units may be taxed as ordinary income to the extent of recapture of depletion deductions, except for percentage depletion deductions in excess of the basis of the property. The amount of the recapture is generally limited to the amount of gain recognized on the disposition.

The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury Regulations relating to the availability and calculation of depletion deductions by the unitholders. Further, because depletion is required to be computed separately by each unitholder and not by our partnership, no assurance can be given, and counsel is unable to express any opinion, with respect to the availability or extent of percentage depletion deductions to the unitholders for any taxable year. We encourage each prospective unitholder to consult his tax advisor to determine whether percentage depletion would be available to him.

Deductions for intangible drilling and development costs

Under our existing investment partnership agreements, all intangible drilling and development costs, which we refer to as IDCs, are allocated to investors in the partnerships and none to us. IDCs generally include our expenses for wages, fuel, repairs, hauling, supplies and other items that are incidental to, and necessary for, the drilling and preparation of wells for the production of oil, natural gas, or geothermal energy. The option to currently deduct IDCs applies only to those items that do not have a salvage value.

In future investment partnerships, a portion of IDCs may be allocated to us. In addition, we may undertake drilling for our own account. Should we be entitled to IDCs, we will elect to currently deduct them.

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Although we will elect to currently deduct IDCs that may be available to us, each unitholder will have the option of either currently deducting IDCs or capitalizing all or part of the IDCs and amortizing them on a straight-line basis over a 60-month period, beginning with the taxable month in which the expenditure is made. If a unitholder makes the election to amortize the IDCs over a 60-month period, no IDC preference amount will result for alternative minimum tax purposes.

Integrated oil companies must capitalize 30% of all their IDCs (other than IDCs paid or incurred with respect to natural gas and oil wells located outside of the United States) and amortize these IDCs over 60 months beginning in the month in which those costs are paid or incurred. If the taxpayer ceases to be an integrated oil company, it must continue to amortize those costs as long as it continues to own the property to which the IDCs relate. An “integrated oil company” is a taxpayer that has economic interests in crude oil deposits and also carries on substantial retailing or refining operations. An oil or gas producer is deemed to be a substantial retailer or refiner if it is subject to the rules disqualifying retailers and refiners from taking percentage depletion. In order to qualify as an “independent producer” that is not subject to these IDC deduction limits, a unitholder, either directly or indirectly through certain related parties, may not be involved in the refining of more than 75,000 barrels of oil (or the equivalent amount of natural gas) on average for any day during the taxable year or in the retail marketing of natural gas and oil products exceeding $5 million per year in the aggregate.

IDCs previously deducted that are allocable to property (directly or through ownership of an interest in a partnership) and that would have been included in the adjusted basis of the property had the IDC deduction not been taken are recaptured to the extent of any gain realized upon the disposition of the property or upon the disposition by a unitholder of interests in us. Recapture is generally determined at the unitholder level. Where only a portion of the recapture property is sold, any IDCs related to the entire property are recaptured to the extent of the gain realized on the portion of the property sold. In the case of a disposition of an undivided interest in a property, a proportionate amount of the IDCs with respect to the property is treated as allocable to the transferred undivided interest to the extent of any gain recognized. See “—Disposition of Common Units—Recognition of Gain or Loss.”

Deduction for United States production activities

Subject to the limitations on the deductibility of losses discussed above and the limitation discussed below, unitholders will be entitled to a deduction, herein referred to as the Section 199 deduction, equal to a specified percentage of our qualified production activities income that is allocated to such unitholder. The percentages are 3% for qualified production activities income generated in the year 2006; 6% for the years 2007, 2008, and 2009; and 9% thereafter.

Qualified production activities income is generally equal to gross receipts from domestic production activities reduced by cost of goods sold allocable to those receipts, other expenses directly associated with those receipts, and a share of other deductions, expenses and losses that are not directly allocable to those receipts or another class of income. The products produced must be manufactured, produced, expanded or extracted in whole or in significant part by the taxpayer in the United States.

For a partnership, the Section 199 deduction is determined at the partner level. To determine his Section 199 deduction, each unitholder will aggregate his share of the qualified production activities income allocated to him from us with the unitholder’s qualified production activities income from other sources. Each unitholder must take into account his distributive share of the expenses allocated to him from our qualified production activities regardless of whether we otherwise have taxable income. However, our expenses that otherwise would be taken into account for purposes of computing the Section 199 deduction are only taken into account if and to the extent the unitholder’s share of losses

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and deductions from all of our activities is not disallowed by the basis rules, the at-risk rules or the passive activity loss rules. Please read “—Tax Consequences of Unit Ownership—Limitations on Deductibility of Losses.”

The amount of a unitholder’s Section 199 deduction for each year is limited to 50% of the IRS Form W-2 wages paid by the unitholder during the calendar year that are deducted in arriving at qualified production activities income. Each unitholder is treated as having been allocated IRS Form W-2 wages from us equal to the unitholder’s allocable share of our wages that are deducted in arriving at our qualified production activities income for that taxable year. It is not anticipated that we or our subsidiaries will pay material wages that will be allocated to our unitholders.

This discussion of the Section 199 deduction does not purport to be a complete analysis of the complex legislation and Treasury authority relating to the calculation of domestic production gross receipts, qualified production activities income, or IRS Form W-2 Wages, or how such items are allocated by us to unitholders. Further, because the Section 199 deduction is required to be computed separately by each unitholder, no assurance can be given, and counsel is unable to express any opinion, as to the availability or extent of the Section 199 deduction to the unitholders. Each prospective unitholder is encouraged to consult his tax advisor to determine whether the Section 199 deduction would be available to him.

Lease Acquisition Costs

The cost of acquiring natural gas and oil leaseholder or similar property interests is a capital expenditure that must be recovered through depletion deductions if the lease is productive. If a lease is proved worthless and abandoned, the cost of acquisition less any depletion claimed may be deducted as an ordinary loss in the year the lease becomes worthless. Please read “Tax Treatment of Operations—Depletion Deductions.”

Geophysical Costs

The costs of geophysical exploration incurred in connection with the exploration and development of oil and gas properties in the United States are deduced ratably over a 24-month period beginning on the date that such expense is paid or incurred.

Operating and Administrative Costs

Amounts paid for operating a producing well are deductible as ordinary business expenses, as are administrative costs to the extent they constitute ordinary and necessary business expenses which are reasonable in amount.

Tax basis, depreciation and amortization

The tax basis of our assets, such as casing, tubing, tanks, pumping units and other similar property, will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to (i) this offering will be borne by our existing unitholders, and (ii) any other offering will be borne by our unitholders as of that time. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Code.

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If we dispose of depreciable property by sale, foreclosure, or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction” and “—Disposition of Common Units—Recognition of Gain or Loss.”

The costs incurred in selling our common units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which we may be able to amortize, and as syndication expenses, which we may not amortize. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and tax basis of our properties

The federal income tax consequences of the ownership and disposition of common units will depend in part on our estimates of the relative fair market values and the tax bases of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

DISPOSITION OF COMMON UNITS

Recognition of gain or loss

Gain or loss will be recognized on a sale of common units equal to the difference between the unitholder’s amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will equal the sum of the cash or the fair market value of other property he receives plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder’s tax basis in that unit will, in effect, become taxable income if the unit is sold at a price greater than the unitholder’s tax basis in that unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. A portion of this gain or loss, which may be substantial, however, will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to assets giving rise to “unrealized receivables” or “inventory items” that we own. The term “unrealized receivables” includes potential recapture items, including depreciation, depletion, and IDC recapture. Ordinary income attributable to unrealized receivables and inventory items may exceed net taxable gain realized on the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital loss may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gain in the case of corporations.

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The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method. Treasury Regulations under Section 1223 of the Code allow a selling unitholder who can identify units transferred with an ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling, a unitholder will be unable to select high or low basis units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of units transferred must consistently use that identification method for all subsequent sales or exchanges of units. A unitholder considering the purchase of additional units or a sale of units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and those Treasury Regulations.

Specific provisions of the Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

a short sale;

an offsetting notional principal contract; or

a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer who enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations between transferors and transferees

In general, our taxable income or loss will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to as the allocation date. However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the allocation date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Code and most publicly-traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Accordingly, Ledgewood is unable to opine on the validity of this method of allocating income and deductions between unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

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A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification requirements

A unitholder who sells any of his units, other than through a broker, generally is required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A person who purchases units from another unitholder is required to notify us in writing of that purchase within 30 days after the purchase, unless a broker or nominee will satisfy such requirement. We are required to notify the IRS of any such transfers of units and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of units may lead to the imposition of substantial penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker.

Constructive termination

We will be considered to have terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and unitholders receiving two Schedule K-1s) for one fiscal year and the cost of the preparation of these returns will be borne by all unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

UNIFORMITY OF COMMON UNITS

Because we cannot match transferors and transferees of common units, we must maintain uniformity of the economic and tax characteristics of the common units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the common units. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.”

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized book-tax disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of that property, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Code. This method is consistent with the Treasury Regulations applicable to property depreciable under the accelerated cost recovery system or the modified accelerated cost recovery system, which we expect will apply to substantially all, if not all, of our depreciable property. We also intend to use this method with respect to property that we own, if any, depreciable under Section 167 of the Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6). We do not expect Section 167 to apply to a material portion, if any, of our

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assets. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized book-tax disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If we adopt this position, it may result in lower annual deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. We will not adopt this position if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. Our counsel, Ledgewood, is unable to opine on the validity of any of these positions. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

TAX-EXEMPT ORGANIZATIONS AND OTHER INVESTORS

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.

A regulated investment company, or “mutual fund,” is required to derive at least 90% of its gross income from certain permitted sources. Income from the ownership of units in a “qualified publicly-traded partnership” is generally treated as income from a permitted source. We expect that we will meet the definition of a qualified publicly-traded partnership.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Under rules applicable to publicly-traded partnerships, we will withhold tax, at the highest effective applicable rate, from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8 BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for

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changes in the foreign corporation’s “U.S. net equity,” that is effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Code.

Under a ruling issued by the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent the gain is effectively connected with a United States trade or business of the foreign unitholder. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.

ADMINISTRATIVE MATTERS

Information returns and audit procedures

We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction.

We cannot assure you that those positions will yield a result that conforms to the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor counsel can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability and possibly may result in an audit of his own return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Code requires that one partner be designated as the tax matters partner for these purposes. The limited liability company agreement appoints our manager as our tax matters partner.

The tax matters partner will make some elections on our behalf and on behalf of unitholders. In addition, the tax matters partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The tax matters partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the tax matters partner. The tax matters partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the tax matters partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

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A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

the name, address and taxpayer identification number of the beneficial owner and the nominee;

a statement regarding whether the beneficial owner is:

a person that is not a United States person,

a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing, or

a tax-exempt entity;

the amount and description of units held, acquired or transferred for the beneficial owner; and

specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-related penalties

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

for which there is, or was, “substantial authority,” or

as to which there is a reasonable basis and the relevant facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders could result in that kind of an “understatement” of income for which no “substantial authority” exists, we would be required to disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns to avoid liability for this penalty. More stringent rules would apply to an understatement of tax resulting from ownership of units if we were classified as a “tax shelter.” We believe we will not be classified as a tax shelter.

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A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 200% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for a corporation other than an S Corporation or a personal holding company). If the valuation claimed on a return is 400% or more than the correct valuation, the penalty imposed increases to 40%.

Reportable transactions

If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses in excess of $2 million. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) is audited by the IRS. Please read “—Information Returns and Audit Procedures” above.

Moreover, if we were to participate in a listed transaction or a reportable transaction (other than a listed transaction) with a significant purpose to avoid or evade tax, you could be subject to the following provisions of the American Jobs Creation Act of 2004:

accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “—Accuracy-related Penalties,”

for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability, and

in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any reportable transactions.

STATE, LOCAL AND OTHER TAX CONSIDERATIONS

In addition to federal income taxes, you will be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. We currently do business and own property in Pennsylvania, Ohio, New York and Tennessee. We may also own property or do business in other states in the future. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. You may not be required to file a return and pay taxes in some states because your income from that state falls below the filing and payment requirement. You will be required, however, to file state income tax returns and to pay state income taxes in many of the states in which we may do business or own property, and you may be subject to penalties for failure to comply with those requirements. In some states, tax losses may not produce a tax benefit in the year incurred and also may not be available to offset income in subsequent taxable years. Some of the states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the state, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “—Tax Consequences of Unit Ownership—Entity-Level Collections.” Based on current law and our estimate of our future operations, we anticipate that any amounts required to be withheld will not be material.

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It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of his investment in us. Ledgewood has not rendered an opinion on the state local, or foreign tax consequences of an investment in us. We strongly recommend that each prospective unitholder consult, and depend on, its own tax counsel or other advisor with regard to those matters. It is the responsibility of each unitholder to file all tax return that may be required.

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Underwriting

We are offering our common units described in this prospectus through the underwriters named below. UBS Securities LLC is the representative of the underwriters and the sole book-running manager of this offering. Subject to the terms and conditions of an underwriting agreement, which will be filed as an exhibit to the registration statement of which this prospectus forms a part, each of the underwriters has severally agreed to purchase the number of common units listed next to its name in the following table:


Underwriters		Number of common units
UBS Securities LLC

Total		5,750,000

The underwriting agreement provides that the underwriters must buy all of the common units if they buy any of them. However, the underwriters are not required to take or pay for the common units covered by the underwriters’ option to purchase additional common units described below.

Our common units and the common units to be sold upon the exercise of the underwriters’ option to purchase additional common units, if any, are offered subject to a number of conditions, including:

receipt and acceptance of our common units by the underwriters, and

the underwriters’ right to reject orders in whole or in part.

We have been advised by the representatives that the underwriters intend to make a market in our common units, but that they are not obligated to do so and may discontinue making a market at any time without notice.

OPTION TO PURCHASE ADDITIONAL COMMON UNITS

We have granted the underwriters an option to buy up to an aggregate 862,500 additional common units. This option may be exercised if the underwriters sell more than 5,750,000 common units in connection with this offering. The underwriters have 30 days from the date of this prospectus to exercise this option. If the underwriters exercise this option, they will each purchase additional common units approximately in proportion to the amounts specified in the table above.

COMMISSIONS AND DISCOUNTS

Common units sold by the underwriters to the public will initially be offered at the initial offering price set forth on the cover of this prospectus. Any common units sold by the underwriters to securities dealers may be sold at a discount of up to $ per common unit from the initial public offering price. Any of these securities dealers may resell any common units purchased from the underwriters to other brokers or dealers at a discount of up to $ per common unit from the initial public offering price. If all the common units are not sold at the initial public offering price, the representatives may change the offering price and the other selling terms. Sales of common units made outside of the United States may

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be made by affiliates of the underwriters. Upon execution of the underwriting agreement, the underwriters will be obligated to purchase the common units at the prices and upon the terms stated therein, and, as a result, will thereafter bear any risk associated with changing the offering price to the public or other selling terms. The representative of the underwriters has informed us that it does not expect to sell more than an aggregate of common units to accounts over which such representative exercises discretionary authority.

The following table shows the per unit and total underwriting discounts and commissions we will pay to the underwriters assuming both no exercise and full exercise of the underwriters’ option to purchase up to an additional 862,500 units.

We estimate that the total expenses of this offering payable by us, not including the underwriting discounts and commissions and structuring fees, will be approximately $1.5 million.

In addition, we will pay the representatives a structuring fee of $ of the gross proceeds of this offering and any exercise of the underwriters’ option to purchase additional common units for their role in the evaluation, analysis and structuring of our limited liability company.

NO SALES OF SIMILAR SECURITIES

We, our subsidiaries, our officers and directors, substantially all of our existing unitholders, including Atlas America, our manager and its affiliates, including the executive officers and directors of our manager, and the participants in our directed unit program have entered into lock-up agreements with the underwriters. Under these agreements, subject to certain exceptions, we and each of these persons may not, without the prior written approval of UBS Securities LLC, offer, sell, contract to sell or otherwise dispose of or hedge our common units or securities convertible into or exchangeable for our common units, enter into any swap or other agreement that transfers, in whole or in part, any of the economic consequences of ownership of the common units, make any demand for or exercise any right or file or cause to be filed a registration statement with respect to the registration of any common units or securities convertible, exercisable or exchangeable into common units or any of our other securities or publicly disclose the intention to do any of the foregoing. These restrictions will be in effect for a period of 180 days after the date of this prospectus. The lock-up period will be extended under certain circumstances where we release, or pre-announce a release of, our earnings or announce material news or a material event during the 18 days before or 16 days after the termination of the 180-day period in which case the restrictions described above will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or material event.

At any time and without public notice, UBS Securities LLC may, in its discretion, release all or some of the securities from these lock-up agreements. When determining whether or not to release common units from these restrictions, the primary factors that UBS Securities LLC will consider include the requesting unitholder’s reasons for requesting the release, the number of common units for which the release is being requested and the prevailing economic and equity market conditions at the time of the request. UBS Securities LLC has no present intent to release any of the securities from these lock-up agreements.

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INDEMNIFICATION

We and Atlas America have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act and liabilities incurred in connection with the directed unit program referred to below, and to contribute to payments that the underwriters may be required to make for these liabilities. If we are unable to provide this indemnification, we will contribute to payments the underwriters may be required to make with respect to those liabilities.

DIRECTED UNIT PROGRAM

At our request, certain of the underwriters have reserved up to common units for sale at the initial public offering price to our officers and directors as well as the officers, directors and employees of our manager and certain other persons associated with us. The sales will be made by UBS Financial Services Inc., a selected dealer affiliated with UBS Securities LLC, through a directed unit program. The minimum investment amount for participation in the program is $ . We do not know if these persons will choose to purchase all or any portion of these reserved units, but any purchases they do make will reduce the number of units available to the general public. Any reserved units not so purchased will be offered by the underwriters to the general public on the same basis as the other units offered by this prospectus. These persons must commit to purchase no later than before the open of business on the day following the date of this prospectus, but in any event these persons are not obligated to purchase common units and may not commit to purchase common units before the effectiveness of the registration statement relating to this offering.

Any participant purchasing in excess of $ worth of reserved common units will be prohibited from offering, selling, contracting to sell or otherwise disposing of the common units for a period of 180 days after the date of this prospectus.

LISTING

We intend to apply to list our common units on the New York Stock Exchange under the trading symbol “ .”

PRICE STABILIZATION, SHORT POSITIONS

In connection with this offering, the underwriters may engage in activities that stabilize, maintain or otherwise affect the price of our common units including:

stabilizing transactions;

short sales;

purchases to cover positions created by short sales;

imposition of penalty bids; and

syndicate covering transactions.

Stabilizing transactions consist of bids or purchases made for the purpose of preventing or retarding a decline in the market price of our common units while this offering is in progress. These transactions may also include making short sales of our common units, which involves the sale by the underwriters of a greater number of common units than they are required to purchase in this offering, and purchasing

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common units on the open market to cover positions created by short sales. Short sales may be “covered” shorts, which are short positions in an amount not greater than the underwriters’ option to purchase additional common units referred to above, or may be “naked” shorts, which are short positions in excess of that amount.

The underwriters may close out any covered short position by either exercising their option to purchase additional common units, in whole or in part, or by purchasing common units in the open market. In making this determination, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through their option to purchase additional common units.

Naked short sales are in excess of the underwriters’ option to purchase additional common units. The underwriters must close out any naked short position by purchasing common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market that could adversely affect investors who purchased in this offering.

The underwriters also may impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the representatives have repurchased common units sold by or for the account of that underwriter in stabilizing or short covering transactions.

As a result of these activities, the price of our common units may be higher than the price that otherwise might exist in the open market. If these activities are commenced, they may be discontinued by the underwriters at any time. The underwriters may carry out these transactions on the New York Stock Exchange, in the over-the-counter market or otherwise.

DETERMINATION OF OFFERING PRICE

Before this offering, there has been no public market for our common units. The initial public offering price will be determined by negotiation by us and the representatives of the underwriters. The principal factors to be considered in determining the initial public offering price include:

the information set forth in this prospectus and otherwise available to the representatives;

our history and prospects, and the history and prospects of the industry in which we compete;

our past and present financial performance and an assessment of the directors and officers of our manager;

our prospects for future earnings and cash flow and the present state of our development;

the general condition of the securities markets at the time of this offering;

the recent market prices of, and demand for, publicly-traded common units of generally comparable companies; and

other factors deemed relevant by the underwriters and us.

ELECTRONIC DISTRIBUTION

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in

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this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

DISCRETIONARY SALES

The underwriters have informed us that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of units offered by them.

STAMP TAXES

If you purchase common units offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

AFFILIATIONS

The underwriters and their affiliates may from time to time in the future engage in transactions with us and perform services for us in the ordinary course of their business. In addition, some of the underwriters have engaged in, and may in the future engage in, transactions with us and our predecessor and perform services for us in the ordinary course of their business.

Because the National Association of Securities Dealers, Inc. views the common units offered hereby as interests in a direct participation program, this offering is being made in compliance with Rule 2810 of the NASD’s Conduct Rules. In no event will the maximum amount of compensation to be paid to NASD members in connection with this offering exceed 10%. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on the New York Stock Exchange or a national securities exchange.

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Legal matters

The validity of the common units and the description of federal income tax consequences in “Risk factors—Tax Risks to Unitholders” and “Material tax consequences” will be passed upon for us by Ledgewood, Philadelphia, Pennsylvania. Certain legal matters in connection with the common units offered by this prospectus are being passed upon for the underwriters by Vinson & Elkins L.L.P.

Engineers

The estimated reserve evaluations and related calculations of Wright & Company, Inc., independent petroleum engineering consultants, included in this prospectus have been included in reliance on the authority of that firm as experts in petroleum engineering.

Experts

The combined financial statements of Atlas America E&P Operations as of September 30, 2005 and 2004 and for each of the three years in the period ended September 30, 2005, and the balance sheet of Atlas Energy Resources, LLC dated as of July 14, 2006 have been audited by Grant Thornton LLP, independent registered public accounting firm, as indicated in their reports with respect thereto, and are included in this prospectus in reliance upon the authority of such firm as experts in giving such reports.

Where you can find more information

We have filed with the SEC under the Securities Act a registration statement on Form S-1 with respect to the common units offered by this prospectus. This prospectus, which constitutes part of the registration statement, does not contain all the information set forth in the registration statement or the exhibits and schedules which are part of the registration statement, portions of which are omitted as permitted by the rules and regulations of the SEC. Statements made in this prospectus regarding the contents of any contract or other document are summaries of the material terms of the contract or document. With respect to each contract or document filed as an exhibit to the registration statement, reference is made to the corresponding exhibit. For further information pertaining to us and the common units offered by this prospectus, reference is made to the registration statement, including the exhibits and schedules thereto, copies of which may be inspected without charge at the public reference facilities of the SEC at 100 F Street, N.E., Washington, D.C. 20549. Copies of all or any portion of the registration statement may be obtained from the SEC at prescribed rates. Information on the public reference facilities may be obtained by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains a web site that contains reports, proxy and information statements and other information that is filed through the SEC’s EDGAR system. The web site can be accessed athttp://www.sec.gov.

177

Index to Financial Statements


ATLAS ENERGY RESOURCES, LLC UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS
Introduction		F-2
Unaudited Pro Forma Combined Balance Sheet as of March 31, 2006		F-3
Unaudited Pro Forma Combined Statement of Income for the six months ended March 31, 2006		F-4
Unaudited Pro Forma Combined Statement of Income for the year ended September 30, 2005		F-5
Notes to Unaudited Pro Forma Combined Financial Statements		F-6

ATLAS AMERICA E&P OPERATIONS COMBINED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm		F-8
Combined Balance Sheets as of September 30, 2004 and 2005 and March 31, 2006		F-9
Combined Statements of Income for the years ended September 30 2003, 2004 and 2005 and six months ended March 31, 2005 and 2006		F-10
Combined Statements of Comprehensive Income for the years ended September 30 2003, 2004 and 2005 and six months ended March 31, 2005 and 2006		F-11
Combined Statements of Combined Equity for the years ended September 30 2003, 2004 and 2005 and six months ended March 31, 2006		F-12
Combined Statements of Cash Flows for the year ended September 30, 2003, 2004 and 2005 and the six months ended March 31, 2005 and 2006		F-13
Notes to Combined Financial Statements		F-14

ATLAS ENERGY RESOURCES, LLC BALANCE SHEET
Report of Independent Registered Public Accounting Firm		F-32
Balance Sheet as of July 14, 2006		F-33
Note to Balance Sheet		F-34

F-1

ATLAS ENERGY RESOURCES, LLC

UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

Introduction

The unaudited pro forma combined financial statements of Atlas Energy Resources, LLC as of March 31, 2006, for the year ended September 30, 2005 and for the six months ended March 31, 2006 are based upon the historical combined financial position and results of operations of Atlas America E & P Operations. Upon the completion of its initial public offering, Atlas Energy Resources, LLC (“Atlas Energy Resources”) will own the subsidiaries and operate the businesses of Atlas America E & P Operations, other than the retained assets described in the notes to these financial statements. The contribution of assets to Atlas Energy Resources will be recorded at historical cost because it is considered to be a reorganization of entities under common control. Unless the context otherwise requires, references herein to Atlas Energy Resources include Atlas Energy Resources and its operating subsidiaries. The unaudited pro forma combined financial statements for Atlas Energy Resources have been derived from the historical combined financial statements of Atlas America E & P Operations set forth elsewhere in this prospectus and are qualified in their entirety by reference to such historical combined financial statements and related notes contained therein. The pro forma financial statements have been prepared on the basis that Atlas Energy Resources will be treated as a partnership for federal income tax purposes.

The unaudited pro forma balance sheet and the pro forma statements of income were derived by adjusting the historical combined financial statements of Atlas America E & P Operations. The adjustments are based upon currently available information and certain estimates and assumptions; therefore, actual adjustments will differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma combined financial statements.

The unaudited pro forma combined financial statements are not necessarily indicative of the results that actually would have occurred if Atlas Energy Resources had assumed the operations of Atlas America E & P Operations on the dates indicated or the results that would be obtained in the future.

F-2

ATLAS ENERGY RESOURCES, LLC

MARCH 31, 2006

UNAUDITED PRO FORMA COMBINED BALANCE SHEET

(in thousands)


	Atlas America E & P Operations historical		Pro forma adjustments			Atlas Energy Resources pro forma
ASSETS
Current assets:
Cash and cash equivalents	$	5,010	$	115,000	(a)	$	8,510
				(8,050	)(b)
				(1,500	)(c)
				(100,450	)(d)
				(1,500	)(g)
				51,262	(f)
				(51,262	)(h)
Accounts receivable		20,742		(55	)(e)		20,687
Unrealized hedge gain		8,299		—			8,299
Prepaid expenses		5,955		—			5,955

Total current assets		40,006		3,445			43,451
Property and equipment, net		223,816		(830	)(e)		222,986
Other assets		11,793		1,500	(g)		13,293
Intangible assets, net		5,871		—			5,871
Goodwill		35,166		—			35,166

	$	316,652	$	4,115		$	320,767


LIABILITIES AND COMBINED EQUITY
Current liabilities:
Current portion of long-term debt	$	81	$	—		$	81
Accounts payable		29,050		—			29,050
Liabilities associated with drilling contracts		24,862		—			24,862
Advances from affiliates		51,798		(536	)(e)		—
				(51,262	)(h)
Accrued liabilities		12,673		—			12,673

Total current liabilities		118,464		(51,798	)		66,666
Long term debt		53		51,262	(f)		51,315
Unrealized hedge loss		15,090		—			15,090
Asset retirement obligations		19,300		(349	)(e)		18,951
Commitments and contingencies		—		—			—
Combined equity		163,745		(100,450	)(d)		168,745
				115,000	(a)
				(8,050	)(b)
				(1,500	)(c)

	$	316,652	$	4,115		$	320,767

See accompanying notes to unaudited pro forma combined financial statements

F-3

ATLAS ENERGY RESOURCES, LLC

SIX MONTHS ENDED MARCH 31, 2006

UNAUDITED PRO FORMA COMBINED STATEMENT OF INCOME

(in thousands, except for per unit data)


	Atlas America E & P Operations historical			Pro forma adjustments			Atlas Energy Resources pro forma
REVENUES
Gas and oil production	$	46,952		$	(190	)(i)	$	46,762
Well construction and completion		93,028			—			93,028
Administration and oversight		4,482			—			4,482
Well services		5,327			—			5,327
Gathering		3,694			—			3,694

		153,483			(190	)		153,293
COSTS AND EXPENSES
Gas and oil production and exploration		8,122			(27	)(i)		8,095
Well construction and completion		80,894			—			80,894
Well services		3,253			—			3,253
Gathering fee—Atlas Pipeline		15,824			(12,130	)(m)		3,694
Gathering		133			(133	)(i)		—
General and administrative		8,984			(1	)(i)		9,241
					258	(j)
Compensation reimbursement—affiliate		578			—			578
Depreciation, depletion and amortization		9,576			(23	)(i)		9,553
Interest		—			1,704	(k)		1,954
					250	(l)
Other—net		(171	)		—			(171	)

		127,193			(10,102	)		117,091

Net income	$	26,290		$	9,912		$	36,202

Net income per unit							$	1.06

Weighted average units outstanding								34,030,612

See accompanying notes to unaudited pro forma combined financial statements

F-4

ATLAS ENERGY RESOURCES, LLC

YEAR ENDED SEPTEMBER 30, 2005

UNAUDITED PRO FORMA COMBINED STATEMENT OF INCOME

(in thousands, except for per unit data)


	Atlas America E & P Operations historical			Pro forma adjustments			Atlas Energy Resources pro forma
REVENUES
Gas and oil production	$	63,499		$	(288	)(i)	$	63,211
Well construction and completion		134,338			—			134,338
Administration and oversight		285			—			285
Well services		9,552			—			9,552
Gathering		4,359			—			4,359

		212,033			(288	)		211,745
COSTS AND EXPENSES
Gas and oil production and exploration		9,070			(54	)(i)		9,016
Well construction and completion		116,816			—			116,816
Well services		5,167			—			5,167
Gathering fee—Atlas Pipeline		21,929			(17,570	)(m)		4,359
Gathering		52			(52	)(i)		—
General and administrative		2,992			(3	)(i)		3,756
					767	(j)
Compensation reimbursement-affiliate		602			—			602
Depreciation, depletion and amortization		14,061			(45	)(i)		14,016
Interest		—			2,410	(k)		2,910
					500	(l)
Other—net		(79	)		—			(79	)

		170,610			(14,047	)		156,563

Net income	$	41,423		$	13,759		$	55,182

Net income per unit							$	1.62

Weighted average units outstanding								34,030,612

See accompanying notes to unaudited pro forma combined financial statements

F-5

ATLAS ENERGY RESOURCES, LLC

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

1. Basis of Presentation, the Offering and Other Transactions

The historical financial information is derived from the historical combined financial statements of Atlas America E & P Operations. The pro forma adjustments have been prepared as if the transactions to be effected at the closing of this offering had taken place on March 31, 2006, in the case of the pro forma balance sheet, or as of October 1, 2004, in the case of the pro forma statement of income for the year ended September 30, 2005 and for the six months ended March 31, 2006.

The pro forma financial statements reflect the following transactions:

the contribution of assets by Atlas America to Atlas Energy Resources in exchange for the issuance of 27,550,000 common units, 680,612 Class A units and the management incentive interests;

the sale by Atlas Energy Resources of 5,750,000 common units to the public in this offering;

the issuance by Atlas Energy Resources of 50,000 common units to Richard D. Weber;

the payment of estimated underwriting commissions and other offering expenses totalling $8.1 million;

the net proceeds received from borrowings of $51.3 million under our new credit facility;

the distribution to Atlas America of the net proceeds from this offering and from borrowings under the new credit facility after giving effect to the retention of $5.0 million for working capital purposes;

the retention by Atlas America of interests in 94 wells formerly owned by Atlas Energy Group, Inc. and their related accounts receivable and asset retirement obligations and the operations associated with a small gathering system not owned by Atlas Pipeline; and

the execution of the contribution agreement described under “Certain Relationships and Related Transactions—Agreements Governing the Transactions—The Contribution Agreement,” pursuant to which Atlas America will assume our obligation to pay gathering fees to Atlas Pipeline.

2. Pro Forma Adjustments and Assumptions

(a)

Reflects the gross proceeds to Atlas Energy Resources of $115.0 million from the issuance and sale of 5,750,000 common units at an assumed initial public offering price of $20.00 per unit.

(b)

Reflects the payment of estimated underwriting commissions of $8.1 million, which will be allocated to the public common units.

(c)

Reflects the payment of $1.5 million for the estimated costs associated with the offering, which will be allocated to the public common units.

(d)

Reflects the payment of the net proceeds from the initial public offering to Atlas America after giving effect to the retention of $5.0 million for working capital purposes.

(e)

Reflects the retention by Atlas America of interests in 94 wells formerly owned by Atlas Energy Group, Inc. with a carrying amount of $830,000, asset retirement obligation of $349,000, associated accounts receivable in the amount of $55,000 and a gathering system with no book value.

(f)

Reflects $51.3 million of borrowings under the new credit facility and payment of this amount to Atlas America to eliminate advances from it.

(g)

Reflects estimated deferred financing costs of $1.5 million associated with the new credit facility.

(h)

Reflects the payment to Atlas America to eliminate advances from it.

F-6

ATLAS ENERGY RESOURCES, LLC

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS — (CONTINUED)

(i)

Reflects the removal of revenue and expenses associated with the interests in wells and a gathering system retained by Atlas America.

(j)

Reflects additional expense related to amortization of incentive plan compensation for our president in effect at the initial public offering.

(k)

Reflects the interest expense related to the borrowings described in (f) above. The interest expense is based on average interest rates of 6.65% and 4.7% for the six months ended March 31, 2006 and the year ended September 30, 2005, respectively, which reflects the average borrowing rates experienced by Atlas America during those periods. An increase or decrease in interest rates of 1% would have changed pro forma interest expense by $256,000 for the six months ended March 31, 2006 and $513,000 for fiscal 2005.

(l)

Reflects the amortization of deferred financing costs related to Atlas Energy Resources’ new credit facility.

(m)

Reflects the reduction to gathering fees resulting from the retention by Atlas America of the obligation to pay the difference between gathering fees paid to us by the investment partnerships and gathering fees due to Atlas Pipeline under the Gas Gathering Agreement. Historically, the gathering fees we received from the partnerships were insufficient to cover the gathering expenses paid to Atlas Pipeline. After the closing of this offering, pursuant to the terms of our contribution agreement with Atlas America, we will pay Atlas America the gathering revenues we receive from the partnerships and Atlas America will pay all amounts due to Atlas Pipeline. Accordingly, our gathering revenues and costs will net to $0.

3. Pro Forma Net Income Per Unit

Pro forma net income per unit is determined by dividing the pro forma net income by the number of Class A and common units expected to be outstanding at the closing of the offering. For purposes of this calculation, the number of units assumed to be outstanding was 34,030,612. All units were assumed to have been outstanding since October 1, 2005 for the pro forma net income calculation for the six months ended March 31, 2006, and October 1, 2004 for the pro forma net income calculation for the year ended September 30, 2005. Basic and diluted pro forma net income per unit are equivalent as there are no dilutive units at the date of closing of the initial public offering of the common units of Atlas Energy Resources. To the extent that the quarterly distributions exceed certain targets, Atlas Energy Resources’ manager is entitled to receive certain incentive distributions that will result in more net income proportionately being allocated to Atlas Energy Resources’ manager than to the holders of common units. The pro forma net income per unit calculations assume that no incentive distributions were made to Atlas Energy Resources’ manager because no such distribution would have been payable.

Staff Accounting Bulletin 1:B:3 requires that certain distributions to owners prior to or coincident with an initial public offering be considered as distributions in contemplation of that offering. We anticipate paying the net proceeds of this offering of approximately $100.5 million, after payment of offering expenses and retention of $5.0 million in working capital, to Atlas America as reimbursement of capital expenditures incurred by it on our behalf and partial consideration for its contribution of assets to us. In addition, our pro forma financial statements reflect approximately $51.3 million of indebtedness under a revolving credit facility that we expect to enter into upon the completion of this offering in order to reimburse Atlas America for other advances made on our behalf. Assuming additional common units and Class A units were issued to give effect to this distribution, pro forma net income per unit would have been $1.04 and $1.62 for the six months ended March 31, 2006 and the year ended September 30, 2005, respectively.

F-7

Report of Independent Registered Public Accounting Firm

Board of Directors

Atlas America, Inc

We have audited the accompanying combined balance sheets of Atlas America E & P Operations (the “Company”—see Note 1 to the combined financial statements) as of September 30, 2004 and 2005, and the related combined statements of income, comprehensive income, 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also 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 combined financial statements referred to above present fairly, in all material respects, the financial position of Atlas America E & P Operations as of September 30, 2004 and 2005, and the results of its 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.

/s/ Grant Thornton LLP

Cleveland, Ohio

June 15, 2006

F-8

ATLAS AMERICA E & P OPERATIONS

COMBINED BALANCE SHEETS

(in thousands)


	September 30,				March 31, 2006
	2004		2005		March 31, 2006
					(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	172	$	6,246	$	5,010
Accounts receivable		12,772		17,714		20,742
Unrealized hedge gain		—		—		8,299
Prepaid expenses		1,625		3,466		5,955

Total current assets		14,569		27,426		40,006
Property and equipment, net		140,779		201,263		223,816
Other assets		697		237		11,793
Intangible assets, net		7,243		6,310		5,871
Goodwill		35,166		35,166		35,166

	$	198,454	$	270,402	$	316,652

LIABILITIES AND COMBINED EQUITY
Current liabilities:
Current portion of long-term debt	$	339	$	59	$	81
Accounts payable		19,880		24,220		29,050
Liabilities associated with drilling contracts		29,375		60,971		24,862
Advances from affiliates		30,008		13,897		51,798
Accrued liabilities		4,421		7,440		12,673

Total current liabilities		84,023		106,587		118,464
Long term debt		81		22		53
Unrealized hedge loss		—		—		15,090
Asset retirement obligations		4,889		17,651		19,300

Commitments and contingencies (Note 7)
Combined equity		109,461		146,142		164,441
Accumulated other comprehensive loss		—		—		(696	)

Total equity		109,461		146,142		163,745

	$	198,454	$	270,402	$	316,652

See accompanying notes to combined financial statements

F-9

ATLAS AMERICA E & P OPERATIONS

COMBINED STATEMENTS OF INCOME

(in thousands)


	Years Ended September 30,									Six Months Ended March 31,
	2003			2004			2005			2005			2006
										(unaudited)
REVENUES
Gas and oil production	$	38,639		$	48,526		$	63,499		$	28,618		$	46,952
Well construction and completion		52,879			86,880			134,338			72,009			93,028
Administration and oversight		—			—			285			—			4,482
Well services		7,635			8,430			9,552			4,598			5,327
Gathering		3,898			4,191			4,359			2,058			3,694

		103,051			148,027			212,033			107,283			153,483
COSTS AND EXPENSES
Gas and oil production and exploration		8,486			8,838			9,070			4,215			8,122
Well construction and completion		45,982			75,548			116,816			62,617			80,894
Well services		3,773			4,398			5,167			2,507			3,253
Gathering		29			53			52			27			133
Gathering fee—Atlas Pipeline		14,564			17,189			21,929			10,302			15,824
General and administrative		3,300			1,763			2,992			(680	)		8,984
Compensation reimbursement-affiliate		1,400			1,050			602			457			578
Depreciation, depletion and amortization		9,938			12,064			14,061			6,385			9,576
Other—net		(358	)		(444	)		(79	)		(61	)		(171	)

		87,114			120,459			170,610			85,769			127,193


Net income	$	15,937		$	27,568		$	41,423		$	21,514		$	26,290

See accompanying notes to combined financial statements

F-10

ATLAS AMERICA E & P OPERATIONS

COMBINED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)


	Years Ended September 30,							Six Months Ended March 31,
	2003			2004		2005		2005		2006
								(unaudited)
Net income	$	15,937		$	27,568	$	41,423	$	21,514	$	26,290
Other comprehensive income:
Unrealized holding loss on hedging contracts		(765	)		—		—		—		(2,116	)
Less: reclassification adjustment for losses realized in net income		1,108			—		—		—		1,420

		343			—		—		—		(696	)

Comprehensive income	$	16,280		$	27,568	$	41,423	$	21,514	$	25,594

See accompanying notes to combined financial statements

F-11

ATLAS AMERICA E & P OPERATIONS

COMBINED STATEMENTS OF COMBINED EQUITY

(in thousands)


	Accumulated Other Comprehensive Income (Loss)			Net Affiliate Investment			Combined Equity
Balance, October 1, 2002	$	(343	)	$	67,741		$	67,398
Net change in affiliate advances		—			18,353			18,353
Other comprehensive income		343			—			343
Net income		—			15,937			15,937

Balance, September 30, 2003		—			102,031			102,031
Net change in affiliate advances		—			(20,138	)		(20,138	)
Net income		—			27,568			27,568

Balance, September 30, 2004		—			109,461			109,461
Net change in affiliate advances		—			(4,742	)		(4,742	)
Net income		—			41,423			41,423

Balance, September 30, 2005		—			146,142			146,142
Net change in affiliate advances		—			(7,991	)		(7,991	)
Other comprehensive loss		(696	)		—			(696	)
Net income		—			26,290			26,290

Balance March 31, 2006 (unaudited)	$	(696	)	$	164,441		$	163,745

See accompanying notes to combined financial statements

F-12

ATLAS AMERICA E & P OPERATIONS

COMBINED STATEMENTS OF CASH FLOWS

(in thousands)


	Years Ended September 30,									Six Months Ended March 31,
	2003			2004			2005			2005			2006
										(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	15,937		$	27,568		$	41,423		$	21,514		$	26,290
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		9,938			12,064			14,061			6,385			9,576
Write down of note receivable		—			—			487			—			—
Non-cash compensation on long-term incentive plans		6			64			300			114			884
Gain on asset dispositions		(11	)		(43	)		(52	)		(30	)		(27	)
Advances from (to) affiliate		(33,572	)		(22,474	)		(8,167	)		25,137			23,232
Changes in operating assets and liabilities		33,822			17,642			39,823			2,799			(28,929	)

Net cash provided by operating activities		26,120			34,821			87,875			55,919			31,026

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(22,607	)		(33,252	)		(59,124	)		(29,064	)		(32,477	)
Proceeds from sale of assets		179			218			111			66			33
Decrease (increase) in other assets		316			325			(37	)		32			92

Net cash used in investing activities		(22,112	)		(32,709	)		(59,050	)		(28,966	)		(32,352	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings		228			282			—			—			91
Principal payments on borrowings		(194	)		(56	)		(339	)		(310	)		(38	)
Issuance of common stock by AAI		—			36,991			—			—			—
Dividend to Resource America, Inc.		—			(52,133	)		(22,431	)		—			—
Advances from (payments to) former parent		(5,755	)		7,702			—			(19,448	)		—
Decrease in other assets		—			—			19			—			37

Net cash provided by (used in) financing activities		(5,721	)		(7,214	)		(22,751	)		(19,758	)		90

Increase (decrease) in cash and cash equivalents		(1,713	)		(5,102	)		6,074			7,195			(1,236	)
Cash and cash equivalents at beginning of period		6,987			5,274			172			172			6,246

Cash and cash equivalents at end of period	$	5,274		$	172		$	6,246		$	7,367		$	5,010

See accompanying notes to combined financial statements

F-13

ATLAS AMERICA E & P OPERATIONS

NOTES TO COMBINED FINANCIAL STATEMENTS

NOTE 1—DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

Atlas America E & P Operations (“the Company”) is 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 its own account and for investors through the sponsorship and management of tax-advantaged investment partnerships, in which it also co-invests.

The accompanying combined financial statements and related notes of the Company are prepared in connection with the proposed initial public offering of limited liability company units in Atlas Energy Resources, LLC (“Atlas Energy Resources”) and include subsidiaries of Atlas America, Inc. (“AAI”) which hold the oil and gas exploration and production assets, liabilities, equity and operations of AAI. AAI intends to transfer substantially all of the assets, liabilities and operations of its natural gas and oil development and production subsidiaries to Atlas Energy Resources and make an initial public offering of a minority interest of approximately 20% in Atlas Energy Resources.

AAI was incorporated in Delaware on September 27, 2000 and in May 2004 it completed an initial public offering. AAI trades under the symbol ATLS on the NASDAQ system. In June 2005 Resource America, Inc. (“RAI”) spun off its remaining interest in AAI to its shareholders.

The combined financial statements of the Company have been prepared from the separate records maintained by AAI and may not necessarily be indicative of the conditions that would have existed or the results of operations if the Company had been operated as an unaffiliated entity. Because a direct ownership relationship did not exist among all the various entities comprising the Company, AAI’s net investment in the Company is shown as combined equity in the combined financial statements. Transactions between the Company and other AAI operations have been identified in the combined statements as transactions between affiliates (see Note 5). In the opinion of management, all adjustments have been reflected that are necessary for a fair presentation of the combined financial statements. 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 investment partnerships in which it has an interest.

The combined balance sheets, statements of income, comprehensive income, equity and cash flows as of and for the six months ended March 31, 2006 and 2005 are unaudited. These unaudited interim combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. In the opinion of management, all adjustments have been reflected that are necessary for a fair presentation of the combined financial statements. All significant intercompany balances and transactions within the Company have been eliminated.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

Preparation of the combined financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that

F-14

ATLAS AMERICA E & P OPERATIONS

NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

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.

Comprehensive Income

Comprehensive income includes net income 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, are referred to as “other comprehensive income” and for the Company include only changes in the fair value of unrealized hedging gains and losses.

Accounts Receivables and Allowance for Possible Losses

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 and 2004 and March 31, 2006, 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.

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


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,						At March 31, 2006
	2004			2005			At March 31, 2006
							(unaudited)
	(in thousands)
Mineral interests:
Proved properties	$	2,544		$	2,852		$	2,099
Unproved properties		1,002			1,002			1,002
Wells and related equipment		184,046			255,879			287,033
Land, building and improvements		4,055			4,140			4,146
Support equipment		2,891			3,644			4,389
Other		3,588			4,051			4,378

		198,126			271,568			303,047
Accumulated depreciation, depletion and amortization:
Oil and gas properties		(54,087	)		(66,537	)		(75,234	)
Other		(3,260	)		(3,768	)		(3,997	)

		(57,347	)		(70,305	)		(79,231	)

	$	140,779		$	201,263		$	223,816

F-15

ATLAS AMERICA E & P OPERATIONS

NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

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 and delay rentals 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. Impairment charges are recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value.

The Company’s long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that their carrying amounts 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 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. 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.

F-16

ATLAS AMERICA E & P OPERATIONS

NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

Fair Value of Financial Instruments

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

For 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 debt the carrying value approximates fair value because of the substantially short maturity of these instruments.

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 March 31, 2006 and September 30, 2005, the Company had $9.2 million and $11.8 million in deposits at various banks, of which $8.6 million and $11.2 million, respectively, was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments.

Derivative Instruments

The Company applies the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and its various amendments (“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. All derivative activity reflected in the combined financial statements was transacted by AAI with third parties and allocated to the Company.

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 for environmental contingencies 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 types of environmental contingencies. For the six months ended March 31, 2006 and three years ended September 30, 2005, the Company had no environmental contingencies requiring specific disclosure or the recording of a liability.

F-17

ATLAS AMERICA E & P OPERATIONS

NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

Revenue Recognition

The Company conducts certain energy activities through, and a portion of its revenues are attributable to, investment partnerships. The Company contracts with the investment partnerships to drill partnership wells. The contracts require that the investment 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 revenues at the time the natural gas is delivered.

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

The Company is entitled to receive administration and oversight fees according to the respective partnership agreements. The Company recognizes such fees as income when earned.

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 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, 2004, 2005 and March 31, 2006 of $11.0 million, $16.0 million and $17.9 million, respectively, which are included in Accounts Receivable on its Combined Balance Sheets.

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.

F-18

ATLAS AMERICA E & P OPERATIONS

NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

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 was 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. The adoption of FIN 47 did not have a significant impact on the Company’s financial position or results of operations.

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,				At March 31, 2006
	2004		2005		At March 31, 2006
					(unaudited)
	(in thousands)
Long-term hedge receivable from Partnerships	$	—	$	—	$	6,963
Long-term hedge receivable from AAI		—		—		4,686
Investments		622		102		4
Security deposits		75		120		125
Other		—		15		15

	$	697	$	237	$	11,793

Long-term hedge receivable from Partnerships represents the portion of the long-term unrealized hedge loss on contracts allocated to the Company by AAI that has been reallocated to the Partnerships. Long-term hedge receivable from AAI represents the amounts due from AAI for the unrealized hedge gains on contracts allocated to the Company by AAI.

Intangible Assets

Included in intangible assets are partnership management and operating contracts acquired through previous acquisitions which were 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, 2004 and 2005 were $1.0 million and $933,000, respectively. Amortization expense for these contracts for the six months ended March 31, 2005 and 2006 were $466,000 and $439,000, respectively.

The aggregate estimated annual amortization expense of customer and partnership management and operating contracts for the next five years ending September 30 is as follows: 2006—$879,000; 2007—$831,000; 2008—$788,000; 2009—$751,000 and 2010—$718,000.

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


	At September 30,						At March 31, 2006
	2004			2005			At March 31, 2006
							(unaudited)
	(in thousands)
Cost	$	14,343		$	14,343		$	14,343
Accumulated amortization		(7,100	)		(8,033	)		(8,472	)

	$	7,243		$	6,310		$	5,871

F-19

ATLAS AMERICA E & P OPERATIONS

NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

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 and no impairment indicators arose during the six months ended March 31, 2006. 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.

NOTE 4—ASSET RETIREMENT OBLIGATIONS

The Company recognizes an estimated liability for the plugging and abandonment of its oil and gas wells and equipment whenever 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 assets.

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 $11.8 million increase in asset retirement obligations in fiscal 2005 was primarily 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 resulting from the impact of salvage values now considered under SFAS 143 and (iii) a $3.4 million increase in non-current plugging and abandonment liabilities. The cumulative and pro forma effects of the adoption 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.

F-20

ATLAS AMERICA E & P OPERATIONS

NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

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


	Year Ended September 30,									Six Months Ended March 31,
	2003			2004			2005			2005			2006
										(unaudited)
Asset retirement obligations, beginning of year	$	—		$	3,131		$	4,889		$	4,888		$	17,651
Adoption of SFAS 143		3,380			—			—			—			—
Liabilities incurred		93			1,725			770			1,658			1,402
Liabilities settled		(52	)		(58	)		(137	)		(32	)		—
Revision in estimates		(494	)		(205	)		11,788			—			—
Accretion expense		204			296			341			193			247

Asset retirement obligations, end of year	$	3,131		$	4,889		$	17,651		$	6,707		$	19,300

The accretion expense is included in depreciation, depletion and amortization in the Company’s combined statements of income.

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 AAI

The employees supporting the Company’s operations are employees of AAI. AAI provides centralized corporate functions on behalf of the Company, including legal, accounting, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering. The Company bears substantially all of those costs which are reflected in general and administrative expense in the accompanying combined statements of income.

The Company participates in AAI’s cash management program. All cash activity performed by AAI on behalf of the Company, including collection of receivables, payment of payables, and the settlement of sales and purchases transactions between the Company and AAI have been recorded as parent advances and included in Advances from affiliates on the Company’s combined balance sheets.

All derivative activity reflected in the combined financial statements was transacted by AAI with third parties and allocated to the Company. As such, all amounts classified in the combined balance sheets as Hedge receivable are affiliate related (See Note 6).

In April 2006, AAI increased its credit facility, which is led by Wachovia Bank, N.A. (“Wachovia”), to a maximum of $200.0 million. The revolving credit facility has a current borrowing base of $150.0 million which may be redetermined subject to changes in the Company’s oil and gas reserves. Up to $50.0 million of the facility may be in the form of standby letters of credit. The facility is secured by AAI’s assets, including its subsidiaries. The Company and its subsidiaries are guarantors on the credit facility.

The Wachovia credit facility requires AAI to maintain specified ratios of current assets to current liabilities and debt to earnings before interest, taxes, depreciation, depletion and amortization

F-21

ATLAS AMERICA E & P OPERATIONS

NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

(“EBITDA”). In addition, the facility limits sales, leases or transfers of assets and the incurrence of additional indebtedness and limits the dividends payable by AAI. The facility terminates in April 2011, when all outstanding borrowings must be repaid. At September 30, 2005 and March 31, 2006, $9.5 million and $52.5 million, respectively, were outstanding under this facility, including $1.5 million and $6.5 million, respectively, under letters of credit. The borrowings under this line of credit have been used to fund the Company’s investments in its investment partnerships and are included in Advances from affiliates on the Company’s combined balance sheets. The Company intends to pay to AAI all amounts outstanding under this line of credit with the proceeds of its public offering.

Relationship with Company Sponsored Investment Partnerships. The Company conducts certain activities through, and a substantial portion of its revenues are attributable to, investment partnerships (“Partnerships”). The Company serves as managing general partner of the Partnerships and assumes customary rights and obligations for the Partnerships. As a 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.

Relationship with Atlas Pipeline. AAI has a master gas gathering agreement with Atlas Pipeline which governs the transportation of substantially all of the natural gas the Company produces from the wells it operates. This agreement generally provides for AAI to pay Atlas Pipeline 16% of the sales price received for natural gas produced from wells located on Atlas Pipeline’s gathering systems. The Company charges wells connected to these gathering systems rates, substantially all of which are owned by the Partnerships, generally ranging from $.35 per Mcf to 10% of the sales price received for the natural gas transported. The Company pays this amount to AAI. These fees are shown as Gathering fees—Atlas Pipeline on the Company’s combined statements of income.

Relationship with Ledgewood. Until April 1996, Edward E. Cohen (“E. Cohen”), AAI’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 $400, $51,300 and $108,700 during fiscal 2003, 2004 and 2005, respectively, for legal services rendered to the Company.

NOTE 6—DERIVATIVE INSTRUMENTS

AAI from time to time enters into natural gas futures and option contracts on the Company’s behalf 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.

AAI and the Company formally document 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. AAI and the Company assess, 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.

F-22

ATLAS AMERICA E & P OPERATIONS

NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

Historically these contracts have qualified and been designated as cash flow hedges and recorded at their fair values. Derivatives are recorded on the balance sheet as assets and liabilities at fair value. Gains or losses on future contracts are determined as the difference between the contract price and a reference price, generally prices on NYMEX. For derivatives qualifying as hedges, the effective portion of changes in fair value are included in accumulated other comprehensive income (loss) and reclassified to earnings 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 March 31, 2006, the Company had 108 open natural gas futures contracts allocated to it by AAI related to natural gas sales covering 34.6 million MMBTUs of natural gas, maturing through December 31, 2009 at a combined average settlement price of $8.94 per MMBTU. The Company recognized a gain of $1.4 million on settled contracts covering natural gas production for the six months ended March 31, 2006, which is included in gas and oil production revenues on the Company’s combined statements of income. The Company recognized no gains or losses during the six months ended March 31, 2006 for hedge ineffectiveness or as a result of the discontinuance of these cash flow hedges. The Company did not recognize any gains or losses on hedging in the six months ended March 31, 2005. Of the $696,000 net loss in accumulated other comprehensive loss at March 31, 2006, the Company will reclassify $1.7 million of gains to its combined statements of income over the next twelve month period as these contracts expire and $2.4 million of losses will be reclassified in later periods if the fair values of the instruments remain at current market values.

At September 30, 2004 and 2005, the Company had no open natural gas futures contracts allocated to it by AAI 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 $1.1 million, $0 and $0 on settled contracts covering natural gas production for the years ended September 30, 2003, 2004 and 2005, 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.

As of March 31, 2006, AAI had allocated the following natural gas fixed-price swaps in place to the Company and to the Partnerships:


Twelve Month Period Ending March 31,	Volumes (MMBTU)(1)	Average Fixed Price (per MMBTU)		Fair Value Liability(2) (in thousands)
2007	4,080,000	$	10.76	$	8,299
2008	14,640,000		8.76		(11,153	)
2009	12,210,000		8.71		(495	)
2010	3,690,000		8.35		1,244

	34,620,000			$	(2,105	)

(1)

MMBTU represents million British Thermal Units.

(2)

Fair value based on forward NYMEX natural gas prices, as applicable, on March 31, 2006.

F-23

ATLAS AMERICA E & P OPERATIONS

NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

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


	March 31, 2006
	Book Value			Fair Value
Assets
Derivative instruments	$	12,985		$	12,985

	$	12,985		$	12,985

Liabilities
Derivative instruments	$	(15,090	)	$	(15,090	)

	$	(15,090	)	$	(15,090	)

	$	(2,105	)	$	(2,105	)

The fair value of the derivatives are included in the combined balance sheets as follows:


Unrealized hedge gains—short-term	$	8,299
Other assets-long term (See note 3)		4,686
Unrealized hedge loss—long-term		(15,090	)

	$	(2,105	)

Of the $2.1 million net unrealized hedge loss, the Company’s retained portion of $696,000 is included in accumulated other comprehensive loss and $1.4 million has been reallocated to the Partnerships and included in the combined balance sheet as components of:


Other assets (see note 3)	$	6,963
Accrued liabilities		(5,554	)

	$	1,409

NOTE 7—COMMITMENTS AND CONTINGENCIES

The Company leases office space and equipment under leases with varying expiration dates through 2014. Rental expense was $516,000, $479,000 and $1.2 million for the years ended September 30, 2003, 2004 and 2005, respectively. Future minimum rental commitments for the next five annual periods ending March 31, 2006 are as follows (in thousands):


2007	$	442
2008		347
2009		333
2010		279
2011		84

The Company is the managing general partner of the 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 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.

F-24

ATLAS AMERICA E & P OPERATIONS

NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

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

AAI 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.

AAI 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 AAI. The complaint alleges that AAI 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. AAI believes the complaint is without merit and is defending itself vigorously.

AAI 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 8—LONG-TERM DEBT

Total debt consists of the following on the dates indicated (in thousands):


	At September 30,						At March 31, 2006
	2004			2005			At March 31, 2006
Loans secured by vehicles	$	420		$	81		$	134
Less current maturities		(339	)		(59	)		(81	)

Long-term debt	$	81		$	22		$	53

Maturities of long-term debt are as follows:


Years ended March 31,
2007	$	81
2008		31
2009		22

	$	134

F-25

ATLAS AMERICA E & P OPERATIONS

NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

NOTE 9—OPERATING SEGMENT INFORMATION

The Company’s operations include two reportable operating segments. These operating segments reflect the way the Company manages its operations and makes business decisions. Operating segment data for the periods indicated are as follows:

Six Months Ended March 31, 2006 (in thousands):


	Gas & Oil Production		Partnership Management		Corporate			Total
Revenues from external customers	$	46,952	$	106,531	$	—		$	153,483
Interest income		—		—		84			84
Depreciation, depletion and amortization		8,677		726		173			9,576
Segment profit (loss)		29,939		3,086		(6,735	)		26,290
Goodwill		21,527		13,639		—			35,166
Segment assets		266,416		40,181		10,055			316,652

Six Months Ended March 31, 2005 (in thousands):


	Gas & Oil Production		Partnership Management		Corporate		Total
Revenues from external customers	$	28,618	$	78,665	$	—	$	107,283
Interest income		—		—		32		32
Depreciation, depletion and amortization		5,404		732		249		6,385
Segment profit (loss)		19,020		1,665		829		21,514
Goodwill		21,527		13,639		—		35,166
Segment assets		193,249		28,700		10,400		232,349

Years Ended September 30, 2005 (in thousands):


	Gas & Oil Production		Partnership Management		Corporate			Total
Revenues from external customers	$	63,499	$	148,534	$	—		$	212,033
Interest income		—		—		99			99
Depreciation, depletion and amortization		12,288		1,323		450			14,061
Segment profit (loss)		41,918		1,281		(1,776	)		41,423
Capital expenditures		57,894		747		483			59,124
Goodwill		21,527		13,639		—			35,166
Segment assets		233,855		27,115		9,432			270,402

Years Ended September 30, 2004 (in thousands):


	Gas & Oil Production		Partnership Management			Corporate			Total
Revenues from external customers	$	48,526	$	99,501		$	—		$	148,027
Interest income		—		—			21			21
Depreciation, depletion and amortization		10,319		1,007			738			12,064
Segment profit (loss)		28,981		(485	)		(928	)		27,568
Capital expenditures		32,172		599			481			33,252
Goodwill		21,527		13,639			—			35,166
Segment assets		168,715		28,563			1,176			198,454

F-26

ATLAS AMERICA E & P OPERATIONS

NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

Years Ended September 30, 2003 (in thousands):


	Gas & Oil Production		Partnership Management			Corporate			Total
Revenues from external customers	$	38,639	$	64,412		$	—		$	103,051
Interest income		—		—			167			167
Depreciation, depletion and amortization		8,042		1,298			598			9,938
Segment profit (loss)		21,280		(2,817	)		(2,526	)		15,937
Capital expenditures		21,334		1,063			210			22,607
Goodwill		21,527		13,639			—			35,166
Segment assets		166,212		9,435			2,804			178,451

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.

For the six months ended March 31, 2006 and the years ended September 30, 2003, 2004 and 2005, gas sales to Hess Corporation (formerly FirstEnergy Solutions Corp.) accounted for 11%, 18%, 13% and 13%, respectively, of total revenues. No other operating segments had revenues from a single customer which exceeded 10% of total revenues.

NOTE 10—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Results of operations from oil and gas producing activities:


	Years Ended September 30,
	2003			2004			2005
	(in thousands)
Revenues	$	38,639		$	48,526		$	63,499
Production costs		(6,771	)		(7,289	)		(8,166	)
Exploration expenses		(1,715	)		(1,549	)		(904	)
Depreciation, depletion and amortization		(8,042	)		(10,319	)		(12,288	)

Results of operations from oil and gas producing activities	$	22,111		$	29,369		$	42,141

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,
	2003			2004			2005
	(in thousands)
Mineral interests:
Proved properties	$	844		$	2,544		$	2,852
Unproved properties		563			1,002			1,002
Wells and related equipment		150,657			184,046			255,828
Support equipment		2,185			2,890			3,644
Uncompleted well equipment and facilities		51			1			51

		154,300			190,483			263,377
Accumulated depreciation, depletion and amortization		(43,292	)		(54,087	)		(66,537	)

Net capitalized costs	$	111,008		$	136,396		$	196,840

F-27

ATLAS AMERICA E & P OPERATIONS

NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

Costs Incurred in Oil and Gas Producing Activities. The costs incurred by the Company in its oil and gas activities during fiscal years 2003, 2004 and 2005 are as follows:


	At September 30,
	2003		2004		2005
Property acquisition costs:
Proved properties	$	412	$	1,700	$	308
Unproved properties		—		439		—
Exploration costs		1,715		1,549		904
Development costs		28,007		39,978		72,308

	$	30,134	$	43,666	$	73,520

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

Oil and Gas Reserve Information (Unaudited). The estimates of the Company’s proved and unproved gas and oil reserves are based upon evaluations made by management and verified by Wright & Company, Inc., an independent petroleum engineering firm, as of September 30, 2003, 2004 and 2005. 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 and natural gas 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 and natural gas, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics or economic factors; (c) crude oil and natural gas, 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.

F-28

ATLAS AMERICA E & P OPERATIONS

NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

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 measure 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.

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


	Gas (Mcf)		Oil (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

F-29

ATLAS AMERICA E & P OPERATIONS

NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

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, 2003, 2004 and 2005 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.


	Years Ended September 30,
	2003			2004			2005
Future cash inflows	$	715,539		$	1,096,047		$	2,503,644
Future production costs		(185,442	)		(227,738	)		(296,015	)
Future development costs		(72,476	)		(92,079	)		(117,256	)
Future income tax expense		(125,556	)		(227,862	)		(607,624	)

Future net cash flows		332,065			548,368			1,482,749
Less 10% annual discount for estimated timing of cash flows		(187,714	)		(315,370	)		(876,052	)

Standardized measure of discounted future net cash flows	$	144,351		$	232,998		$	606,697

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.

F-30

ATLAS AMERICA E & P OPERATIONS

NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

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:


	Years Ended September 30,
	2003			2004			2005
	(in thousands)
Balance, beginning of year	$	104,126		$	144,351		$	232,998

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

Balance, end of year	$	144,351		$	232,998		$	606,697

F-31

Report of Independent Registered Public Accounting Firm

To the Owner of Atlas Energy Resources, LLC

We have audited the accompanying balance sheet of Atlas Energy Resources, LLC (the “Company”) as of July 14, 2006. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement 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 the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of the Company at July 14, 2006, in conformity with accounting principles generally accepted in the United States of America.

/s/ Grant Thornton LLP

Cleveland, Ohio

July 14, 2006

F-32

ATLAS ENERGY RESOURCES, LLC

BALANCE SHEET

July 14, 2006


ASSETS
Current assets:
Cash	$	1,000

Total assets	$	1,000

MEMBER’S EQUITY
Member’s equity	$	1,000

Total member’s equity	$	1,000

See accompanying note to balance sheet

F-33

ATLAS ENERGY RESOURCES, LLC

NOTE TO BALANCE SHEET

1. Nature of Operations

Atlas Energy Resources, LLC (the “Company”) is a Delaware limited liability company formed in June 2006 to acquire various subsidiaries of Atlas America, Inc.

The Company intends to offer 5,750,000 common units, representing limited liability interests, pursuant to a public offering and to concurrently issue 27,550,000 common units, representing additional limited liability company interests, to Atlas America, Inc., 50,000 common units to the Company’s president and chief operating officer and 680,612 Class A units, representing a 2% interest in the Company, to Atlas Energy Management, Inc.

Atlas America, Inc. contributed $1,000 as the organizational member on July 14, 2006. There have been no other transactions involving the Company as of July 14, 2006.

F-34

Appendix B

Glossary of Terms

The terms defined in this glossary are used throughout this prospectus.

BBL—One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

BCF—One billion cubic feet of natural gas.

BCFE—One billion cubic feet of natural gas equivalents, converting one Bbl of oil to six Mcf of natural gas.

BTU—British thermal unit.

COMPLETION—The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry well, the reporting of abandonment to the appropriate production.

DEVELOPMENT WELL—A well drilled within the proved boundaries of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

DRY WELL—A development or exploratory well found to be incapable of producing either natural gas or oil in sufficient quantities to justify completion as an oil or natural gas well.

EXPLORATORY WELL—A well drilled to find natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir.

FERC—Federal Energy Regulatory Commission.

FINDING AND DEVEOPMENT COSTS—Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.

GROSS ACRES orGROSS WELLS—The total number of acres or wells, as the case may be, in which a working interest is owned.

IDENTIFIED DRILLING LOCATIONS—Total gross locations specifically identified and scheduled by management as an estimation of our multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, natural gas and oil prices, costs, drilling results and other factors.

MBBL—One thousand barrels of crude oil or other liquid hydrocarbons.

MCF—One thousand cubic feet of natural gas.

MCFE—One thousand cubic feet of natural gas equivalents, converting one Bbl of oil to six Mcf of natural gas.

B-1

MMCFE—One million cubic feet of natural gas equivalents, converting one Bbl of oil to six Mcf of natural gas.

MMCF—One million cubic feet of natural gas.

MMBTU—One million British thermal units.

MMCFE/D—One Mmcfe per day.

NET ACRES orNET WELLS—The sum of the fractional working interests owned in gross acres or gross wells. For example, a 50% working interest in a well is one gross well, but is a 0.50 net well.

NYMEX—New York Mercantile Exchange.

PRESENT VALUE OF FUTURE NET REVENUES (PV-10)—The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to financial hedging activities (but including our forward sales), non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.

PRODUCING WELL,PRODUCTION WELLorPRODUCTIVE WELL—A well that is producing natural gas or oil or that is capable of production.

PROVED DEVELOPED RESERVES—Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

PROVED RESERVES—The estimated quantities of natural gas, crude oil and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

PROVED UNDEVELOPED RESERVES—Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

RECOMPLETION—The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

ROYALTY INTEREST—An interest in a natural gas and oil property entitling the owner to a share of natural gas and oil production free of costs of production.

STANDARIZED MEASURE—The present value of estimated future cash inflows from proved natural gas and oil reserves, less future development and production costs and future income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes. Upon completion of this offering, our PV-10 and standardized measure values will be the same because we are not subject to income taxes.

B-2

TCF—One trillion cubic feet of natural gas.

UNDEVELOPED ACREAGE—Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

WORKING INTEREST—The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

B-3

Appendix C

July 12, 2006

Atlas America, Inc.

311 Rouser Road

Moon Township, PA 15108-2719

ATTENTION: Mr. Jeffrey C. Simmons

Gentlemen:


SUBJECT:		EXECUTIVE SUMMARY REPORT
		Evaluation of Oil and Gas Reserves
		To the Interests of
		Atlas America, Inc. and
		Atlas Energy Resources, LLC
		In Certain Properties Located in Various States
		Pursuant to the Requirements of the
		Securities and Exchange Commission
		Effective March 31, 2006
		Job 06.894

Wright & Company, Inc. (Wright) has performed an evaluation to estimate proved reserves and cash flow from certain oil and gas properties owned by Atlas America, Inc. (AAI). This evaluation was authorized by Mr. Jeffrey C. Simmons of AAI. Atlas Energy Resources, LLC (AER) is a new company being formed as a Delaware limited liability company to own and operate all of the natural gas and oil exploration and production assets which are currently owned by AAI, less 94 producing wells specifically identified by AAI as properties that will not be contributed to AER (the assets to be contributed to AER by AAI are referred to as the AER assets.) It is Wright’s understanding that the AER assets will be contributed by AAI to AER within the 90 days following the date of this report. At the request of AAI, Wright has also included in this report a summary of Wright’s evaluation of the AER assets, which evaluation utilized the same reserve projections, working and net revenue interests, prices and costs as used for AAI (except for the exclusion of the 94 wells referred to above).

Projections of the reserves and cash flow to the evaluated interests were based on economic parameters and operating conditions considered to be applicable as of March 31, 2006, and are pursuant to the financial reporting requirements of the Securities and Exchange Commission (SEC).

C-1

Mr. Jeffrey C. Simmons

Atlas America, Inc.

July 12, 2006

Page 2

Some of the information contained in this report is based on the report prepared by Wright entitled “EXECUTIVE SUMMARY REPORT, Evaluation of Oil and Gas Reserves to the Interests of Atlas America, Inc. In Certain Properties Located in Various States, Pursuant to the Requirements of the Securities and Exchange Commission, Effective September 30, 2005, Job 05.836,” dated October 28, 2005, hereinafter referred to as the Prior Report. The purpose of this report is to update the Prior Report with new information including, but not limited to, new production on certain wells, product prices as of March 31, 2006, and new wells drilled subsequent to September 30, 2005, which were completed on or before March 31, 2006; however, this report does not include the addition of any new proved undeveloped (PUD) reserves as Wright was not requested to evaluate any new well locations for categorization as PUD locations.

The following is a summary of the results of the AAI evaluation, effective March 31, 2006:


	Proved Developed Producing (PDP)	Proved Developed Nonproducing (PDNP)	Proved Developed Nonproducing Behind Pipe (PDBP)	Proved Undeveloped (PUD)	Total Proved
Net Reserves to the Evaluated Interests
Oil, Mbbl:	1,991.897	25.760	0.000	120.318	2,137.975
Gas, Mmcf:	99,588.437	8,270.131	30.009	50,221.487	158,110.064

Cash Flow (BTAX), M$
Undiscounted:	709,084.396	54,221.334	160.559	230,520.954	993,987.243
Discounted at 10%
Per Annum:	321,396.204	28,271.647	73.110	62,631.792	412,372.753

The following is a summary of the results of the AER evaluation, effective March 31, 2006:


	Proved Developed Producing (PDP)	Proved Developed Nonproducing (PDNP)	Proved Developed Nonproducing Behind Pipe (PDBP)	Proved Undeveloped (PUD)	Total Proved
Net Reserves to the Evaluated Interests
Oil, Mbbl:	1,947.813	25.760	0.000	120.318	2,093.891
Gas, Mmcf:	99,273.277	8,270.131	30.009	50,221.487	157,794.904

Cash Flow (BTAX), M$
Undiscounted:	704,576.310	54,221.334	160.559	230,520.954	989,479.157
Discounted at 10%
Per Annum:	319,430.694	28,271.647	73.110	62,631.792	410,407.243

C-2

Mr. Jeffrey C. Simmons

Atlas America, Inc.

July 12, 2006

Page 3

For purposes of this report, unless otherwise noted, AAI and AER will hereinafter be collectively referred to as Atlas.

The individual projections of lease reserves and economics were generated using certain data that describe the production forecasts and all associated evaluation parameters such as interests, severance and ad valorem taxes, product prices, operating expenses, investments, salvage values, and abandonment costs, as applicable. The data reports are not presented in this report individually, but are a part of Wright’s work product and are retained in our files. This report is anEXECUTIVE SUMMARY REPORT as requested by Atlas, and does not include one-line tabulations by well in accordance with their instructions.

The properties evaluated in this report are located in the states of Arkansas, Kansas, Kentucky, Louisiana, New York, North Dakota, Ohio, Oklahoma, Pennsylvania, Tennessee, Texas, West Virginia, and Wyoming. It is the understanding of Wright that the interests evaluated on behalf of Atlas are (i) those interests that may be owned by Atlas through various entities that are direct or indirect wholly owned subsidiaries of Atlas (Atlas Subsidiaries) as well as (ii) interests owned by investment partnerships in which the Atlas Subsidiaries own a minority equity interest (in which case the interests evaluated include the proportionate interest of the Atlas Subsidiaries in the property interests in those other entities).

Net income to the evaluated interests is the cash flow after consideration of royalty revenue payable to others, standard state severance and ad valorem taxes, operating expenses, investments, salvage values, and abandonment costs, as applicable. The cash flow is before federal income tax (BTAX) and excludes consideration of any encumbrances against the properties if such exist.

The Cash Flow (BTAX) values presented in this report were based on projections of annual oil and gas sales. It was assumed there would be no significant delay between the date of oil and gas production and the receipt of the associated revenue for this production.

Unless specifically identified and documented by Atlas as having curtailment problems, gas production forecasts have been assumed to be a function of well productivity and not of market conditions. The effect of “take or pay” clauses in gas contracts, if there were such clauses, was not considered for this evaluation.

Oil and gas reserves were evaluated for the proved developed producing (PDP), proved developed nonproducing (PDNP), proved developed nonproducing behind pipe (PDBP), and proved undeveloped (PUD) categories. The summary classification of proved developed reserves combines the PDP, PDNP, and PDBP categories. For the PDP category, reserves were based primarily on decline curve analysis projections where sufficient production history was available. For reserves assigned to the PDNP category, the production start dates for wells drilled during fiscal 2006 that were not producing at the effective date were estimated by Atlas. Atlas requested that Wright include summaries of shut-in (PDNP-SI) and temporarily abandoned (PDNP-TA) properties for well count purposes only. There is no value associated with the properties in these categories in this report. According to Atlas, there are 552 PDNP-SI and PDNP-TA wells, of which 491 are operated by Atlas, and these properties will also be

C-3

Mr. Jeffrey C. Simmons

Atlas America, Inc.

July 12, 2006

Page 4

transferred to AER. For the PUD category, reserves were based on a mathematical average of the estimated ultimate recovery (EUR) of PDP direct offset wells, or a larger number of wells producing from the same formation in the same township or area.

In preparing this evaluation, no attempt has been made to quantify the element of uncertainty associated with any category. Reserves were assigned to each category as warranted. The attached Definitions of Oil and Gas Reserves describe all categories of proved reserves.

Oil reserves are expressed in thousands of United States (U.S.) barrels (Mbbl), one barrel equaling 42 U.S. gallons. Gas volumes are expressed in millions of standard cubic feet (Mmcf) at 60 degrees Fahrenheit and at the legal pressure base that prevails in the state in which the reserves are located. No adjustment of the individual gas volumes to a common pressure base has been made.

The Cash Flow (BTAX) was discounted at an annual rate of 10.00 percent (10.00 PCT) as requested by Atlas, and in accordance with the reporting requirements of the SEC. Future cash flow was also discounted at several secondary rates as indicated on each reserves and economics page. These additional discounted amounts are displayed as totals only. The cash flow was discounted at the midpoint of the period, compounded annually.

This report includes only those costs and revenues which were provided by Atlas that are directly attributable to the individual leases and areas. There could exist other revenues, overhead costs, or other costs associated with Atlas which are not included in this report. Such additional costs and revenues are outside the scope of this report. It should be noted that no opinion is expressed by Wright as to the fair market value of the evaluated properties. This report is not a financial statement for Atlas and should not be used as the sole basis for any transaction concerning Atlas or the evaluated properties.

All data utilized in the preparation of this report with respect to interests, oil and gas prices, gas contract terms, operating expenses, investments, salvage values, abandonment costs, well information, and current operating conditions, as applicable, were provided by Atlas. Data obtained after the effective date of the report, but prior to the completion of the report, were used only if such data were applied consistently. If such data were used, the reserves category assignments reflect the status of the wells as of the effective date. All production data were provided by Atlas. According to Atlas, some of the historical production provided may be incomplete. Wright has reviewed all data for reasonableness and, unless obvious errors were detected, has accepted the data as correct. It should be emphasized that revisions to the projections of reserves and economics included in this report may be required if the provided data are revised for any reason. No inspection of the properties was made as this was not considered to be within the scope of this evaluation.

The estimates of reserves contained in this report were determined by accepted industry methods and in accordance with the attached Definitions of Oil and Gas Reserves. Methods utilized in this report include extrapolation of historical production trends and analogy to similar producing properties.

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Mr. Jeffrey C. Simmons

Atlas America, Inc.

July 12, 2006

Page 5

Where sufficient production history and other data were available, reserves for producing properties were determined by extrapolation of historical production trends. Analogy to similar producing properties was used for those properties that lacked sufficient production history and other data to yield a definitive estimate of reserves. Subsequent production performance trends may cause the need for revisions to the estimates of reserves. In some cases on newer producing properties with limited production history, field chart readings may have been utilized to establish the estimated performance trends. Reserves projections based on analogy are subject to change due to subsequent changes in the analogous properties or subsequent production from the evaluated properties.

There are significant uncertainties inherent in estimating reserves, future rates of production, and the timing and amount of future costs. Oil and gas reserves estimates must be recognized as a subjective process that cannot be measured in an exact way and estimates of others might differ materially from those of Wright. The accuracy of any reserves estimate is a function of the quality of available data and of subjective interpretations and judgments. It should be emphasized that production data subsequent to the date of these estimates or changes in the analogous properties may warrant revisions of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and gas that ultimately are recovered.

Wright is an independent consulting firm and does not own any interests in the properties covered by this report. No employee, officer, or director of Wright is an employee, officer, or director of Atlas. Neither the employment of nor the compensation received by Wright is contingent upon the values assigned to the properties covered by this report.

For reporting purposes for AAI, Atlas requested summaries of total proved net reserves, cash flow and discounted cash flow (BTAX) for each subsidiary company of AAI that owns, directly or through their respective interests and various investment drilling partnerships managed by these companies, reserves included in this report that are attributed to AAI, including the 94 wells that will not be contributed to AER. These companies consist of Atlas Resources, Inc., Viking Resources Corporation, Resource Energy, Inc., Atlas Energy, Inc., Atlas Noble Corp., REI-NY, Inc., and Atlas Energy Corporation. These summaries, by reserves category, are provided in the Summaries section of this report. Following is a summary, for each of these companies, of the total proved (PDP, PDNP, PDBP, and PUD) reserves in the evaluation, effective March 31, 2006.


COMPANY	Total Proved Net Reserves		Cash Flow (BTAX), M$	10.00 PCT Cum. Disc. (BTAX), M$
	Oil, Mbbl	Gas, Mmcf
Atlas Resources, Inc.	210.508	110,862.401	606,543.493	242,942.514
Viking Resources Corporation	1,426.245	21,957.193	219,346.346	92,534.994
Resource Energy, Inc.	284.050	12,313.374	74,590.214	35,714.055
Atlas Energy, Inc.	110.821	6,887.174	53,513.664	22,540.556
Atlas Noble Corp.	73.851	3,912.474	27,502.857	12,681.927
REI-NY, Inc.	30.261	1,645.980	9,458.006	4,615.037
Atlas Energy Corporation	2.239	531.468	3,032.663	1,343.670

Total	2,137.975	158,110.064	993,987.243	412,372.753

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Mr. Jeffrey C. Simmons

Atlas America, Inc.

July 12, 2006

Page 6

Atlas has identified a pool designation for each property. Summaries for each pool group, by reserves category, are provided in the Summaries section of this report. There are four pool groups:

Clinton/Medina Formation—properties located in New York, Ohio and certain counties in Pennsylvania

Upper Devonian Sandstones—properties located in certain counties of Pennsylvania

Southern Appalachia Devonian Shale—Tennessee and West Virginia properties

Other Areas—Properties located in Kentucky and states other than Appalachia

The following table summarizes the results of the pool group summaries for AAI only:


POOL GROUP	Total Proved Net Reserves		Cash Flow (BTAX), M$	10.00 PCT Cum. Disc. (BTAX), M$
	Oil, Mbbl	Gas, Mmcf
Clinton/Medina Formation	1,929.588	107,356.044	702,163.752	283,909.614
Upper Devonian Sandstones	185.561	44,473.890	258,747.604	116,711.219
Southern Appalachia Devonian Shale	2.616	5,799.798	29,214.994	9,975.234
Other	20.210	480.332	3,860.893	1,776.686

Total	2,137.975	158,110.064	993,987.243	412,372.753

Effective date gas prices were provided by Atlas. According to Atlas, the gas prices were based on certain contract language as applicable. A base NYMEX Henry Hub price of $7.180 per Mmbtu (million British thermal units) as of March 31, 2006 was used. This base gas price may have been adjusted, by lease, for energy content, transportation fees, and regional price differentials. According to Atlas, a small portion of gas sales contracts are based on a Columbia Gas Transmission (TCo) Index or Consolidated Natural Gas (CNG) Appalachia Index in effect as of March 31, 2006, as published inGas Daily. Adjustments were made, as appropriate, based on certain contracts and agreements with the particular gas purchasers. Where appropriate, fixed prices according to contracts were used until the contract expired. At the end of the contract period, the applicable March 31, 2006, base price was used. All contracts and agreements were interpreted by Atlas. Wright did not review any contracts or agreements.

For oil sold in Appalachia, the price was based upon the Ergon Oil Corporation posted price of $63.50 per barrel for oil at March 31, 2006, in New York, Ohio, and Pennsylvania, and $62.25 per barrel in Kentucky and West Virginia. In Tennessee, the posted price based on South Kentucky Purchasing, Inc. was $56.50 per barrel. For oil sold outside of Appalachia, the oil price was based on the West Texas Intermediate (WTI) price on March 31, 2006 of $66.25 per barrel.

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Mr. Jeffrey C. Simmons

Atlas America, Inc.

July 12, 2006

Page 7

No attempt has been made to account for oil or gas price fluctuations that may have occurred in the market subsequent to the effective date of this report. After the effective date, prices were held constant for the life of the properties except where adjusted by contract. All oil and gas prices for this evaluation were provided by Atlas and were used in accordance with their instructions. It should be emphasized that with the current economic uncertainties, fluctuations in market conditions could significantly change the economics in this report.

Operating expenses were provided by Atlas and represented, when possible, the latest available estimated average of all recurring expenses that are billable to the working interest owners. These expenses included, but were not limited to, all direct operating expenses, field overhead costs, and any ad valorem taxes not deducted separately. Expenses for workovers, well stimulations, and other maintenance were not included in the operating expenses unless such work was expected on a recurring basis. Judgments for the exclusion of the nonrecurring expenses were made by Atlas. Any internal indirect overhead costs (general and administrative), which are not billable to the working interest owners, were not included. For new and developing properties where data were unavailable, operating expenses were estimated by Atlas based on analogy with similar properties. Operating costs were held constant for the life of the properties. Contractual transportation expenses were deducted where appropriate. It is Wright’s understanding that operating costs used in this report were based on those used in the Prior Report and were not updated during the six month interim period.

Standard state severance taxes have been deducted as appropriate. All taxes were based on current published rates and were used in accordance with the instructions of Atlas. According to Atlas, any ad valorem taxes not deducted separately were included in the operating expenses.

All capital costs for drilling and completion of wells and nonrecurring hook-up, workover, or operating costs have been deducted as applicable. These costs were provided by Atlas. No adjustments were made to account for the potential effect of inflation on these costs.

In accordance with the instructions of Atlas, neither salvage values nor abandonment costs were included in the projections of reserves and economics. It was assumed that any salvage value would be directly offset by the cost to abandon the property. No consideration was given in this report to potential environmental liabilities that may exist concerning the properties evaluated. There are no costs included in this evaluation for potential liability for restoration and to clean up damages, if any, caused by past or future operating practices.

Wright evaluated 478 PUD locations in Ohio, Pennsylvania, and Tennessee for this report. Reserves for these locations were evaluated for the Prior Report, and were assigned based on the mathematical average EUR’s of direct offsets to existing PDP wells where available, or based on the average EUR of certain PDP wells producing within the same formations in the same townships or areas. In certain townships or areas, the analogy method was not used because of an insufficient sample size. In these cases, analogy to an adjoining township or area was used. Wright’s PUD projections were formed using a generalized type curve for the township or area with initial starting rates and declines based on the reserves

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Mr. Jeffrey C. Simmons

Atlas America, Inc.

July 12, 2006

Page 8

assigned. Atlas provided operating and transportation expenses as appropriate. According to Atlas, some PUD locations have been drilled since the Prior Report, as well as some locations not previously evaluated by Wright or included in the Prior Report. Any wells drilled since the Prior Report have been assigned to the PDNP or PDP reserves category as appropriate. Wright’s reserves projections may be based on test information and/or limited field production data. It should be noted that these projections may change significantly based on future performance. In the opinion of Wright there are a limited number of these new wells and they do not have a significant affect on the total value of the Total Proved Developed value. Wright has not reviewed or assigned any new PUD locations since the Prior Report in accordance with the instructions of Atlas.

Production in Ohio is primarily from the Clinton formation. In northwestern Pennsylvania, production is primarily from the Medina/Whirlpool. For wells in the remaining areas of Pennsylvania, production is primarily from the Upper Devonian formations. In the target sands, the quality of production is affected by the various reservoir characteristics, especially porosity and permeability. Hydraulic fracturing is typically used to increase well productivity.

The Clinton and Medina/Whirlpool Sandstones are generally considered to be blanket sands with a large aerial extent. Under circumstances in which a large number of wells (100 to 200 or more) are to be selectively drilled and monitored, in the opinion of Wright, the chances of obtaining a statistical average (“typical”) EUR could have a relatively high degree of certainty. The term “typical” is used herein to signify the average occurrence throughout the subject area as it relates to these properties.

Wright identified 166 PUD locations in Armstrong, Fayette, Greene, McKean, and Westmoreland Counties, Pennsylvania. For PUD’s in Armstrong, Fayette, Greene, and Westmoreland Counties, Atlas provided drilling costs of 255.751 M$ per location for Upper Devonian locations, and 142.423 M$ for shallow/natural locations. In McKean County, drilling costs of 99.371 M$ per location were provided by Atlas.

Wright assigned reserves to 278 PUD locations in Crawford, Lawrence, Mercer, and Venango Counties in Pennsylvania for which the primary target is the Medina/Whirlpool Sandstone. Drilling costs for these locations are 260.522 M$ according to Atlas.

Wright identified five PUD locations in Noble and Tuscarawas Counties in Ohio. The primary targets include the Clinton and Oriskany formations. Wright assigned reserves to the locations based on direct offset analogy and the average EUR’s assigned to the adjacent PDP wells. Drilling costs for these locations range from 195.154 M$ to 282.768 M$ per location.

The Tennessee properties are located in the Appalachian Plateau portion of northern Tennessee. This historically oil production area has seen recent activity targeting gas productive zones. The gas production in Tennessee is primarily from the Monteagle Limestone (Big Lime equivalent) and the Chattanooga Shale. In addition, a few wells produce from the deeper Trenton and Stones River formations. The Fort Payne, St. Louis, and Warsaw formations, which lie between the Monteagle Limestone and the Chattanooga Shale, are

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Mr. Jeffrey C. Simmons

Atlas America, Inc.

July 12, 2006

Page 9

considered secondary targets. Hydraulic fracturing is typically used to increase well productivity; however, natural production has been established in a few of the deeper wells.

There are 29 PUD locations assigned in Anderson and Scott Counties, Tennessee. Capital costs for these locations ranged from 282.777 M$ to 344.438 M$ per location.

In accordance with the instructions of Atlas, Wright used the following schedule for future drilling of identified PUD locations:


*Fiscal Year	No. of Wells Scheduled to be Drilled	Total Net Investment (M$)
2006	157	32,822.169
2007	186	43,865.958
2008	135	31,078.421

Total	478	107,766.548

Fiscal year runs from October 1 through September 30

It should be especially noted that Atlas did not provide current capital costs or updated Authorization for Expenditures (AFE’s) with respect to the drilling of PUD locations. In accordance with the instructions of Atlas, Wright used the capital costs as contained in the Prior Report. It should be noted that in some areas, rig availability and increased drilling costs may influence the proposed drilling schedule and the total future investment required to realize the PUD reserves.

Atlas represented to Wright that it has or can generate the financial and operational capabilities to accomplish those projects evaluated by Wright that require capital expenditures, specifically the drilling of the PUD locations. Wright recommends that each location have proper spacing from a producing well to reduce the possibility of partial depletion of the reserves. According to Atlas, their assigned spacing has no material adverse effect on potential EUR.

This report should be considered in its entirety and should not be used for any purpose other than that outlined herein without the prior knowledge and express written authorization of an officer of Wright. It has been a pleasure to serve you by preparing this evaluation. All related data will be retained in our files and are available for your review.

Yours very truly,

/s/ Wright & Company, Inc.

Wright & Company, Inc.

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[LOGO]

Until , 2006 (25 days after the date of this prospectus), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution

Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the NASD filing fee and the NYSE listing fee, the amounts set forth below are estimated:


Securities and Exchange Commission registration fee	$	14,859
NASD filing fee		14,386
NYSE listing fee		*
Printing and engraving expenses		*
Legal fees and expenses		*
Accounting fees and expenses		*
Transfer agent and registrar		*
Miscellaneous		*

TOTAL	$	*

To be filed by amendment.

Item 14. Indemnification of Directors and Officers

The section of the prospectus entitled “Our Limited Liability Company Agreement—Indemnification” discloses that we will generally indemnify our directors, officers, managers and affiliates to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference. Subject to any terms, conditions or restrictions set forth in the limited liability company agreement, Section 18-108 of the Delaware Limited Liability Act empowers a Delaware limited liability company to indemnify and hold harmless any member or other persons from and against all claims and demands whatsoever.

To the extent that the indemnification provisions of our limited liability company agreement purport to include indemnification for liabilities arising under the Securities Act of 1933, in the opinion of the SEC, such indemnification is contrary to public policy and is therefore unenforceable.

Item 15. Recent Sales of Unregistered Securities; Use of Proceeds from Registered Securities

In connection with our formation in June 2006, we issued to Atlas America, Inc., in exchange for $1,000, a membership interest representing the right to receive 100% of our distributions. The offering was exempt from registration under Section 4(2) of the Securities Act because the transaction did not involve a public offering.

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Item 16. Exhibits and Financial Statements Schedules

(a) Exhibits:



1.1	(1)	Form of Underwriting Agreement

3.1	(1)	Form of Amended and Restated Limited Liability Company Agreement of Atlas Energy Resources, LLC (included as Appendix A to the prospectus)

3.2		Certificate of Formation of Atlas Energy Resources, LLC

4.1	(1)	Form of common unit certificate (included as Exhibit A to Appendix A to the prospectus)

5.1	(1)	Opinion of Ledgewood, P.C. as to the legality of the securities being registered

8.1	(1)	Opinion of Ledgewood, P.C. relating to tax matters

10.1	(1)	Form of Contribution Agreement

10.2	(1)	Form of Omnibus Agreement

10.3	(1)	Form of Management Agreement

21.1		Subsidiaries of Atlas Energy Resources, LLC

23.1		Consent of Grant Thornton LLP

23.2		Consent of Wright & Company, Inc.

23.3	(1)	Consent of Ledgewood, P.C. (contained in Exhibits 5.1 and 8.1)

24.1		Powers of Attorney (contained on signature page)

99.1		Consents of Director Nominees

99.2	(1)	Employment agreement with Richard D. Weber

(1)

To be filed by amendment.

(b) Financial Statement Schedules

All financial statement schedules are omitted because the information is not required, is not material or is otherwise included in the financial statements or related notes thereto.

Item 17. Undertakings

The undersigned registrant hereby undertakes to provide to the Underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the Underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and

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contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

For purposes of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

The registrant undertakes to send to each unitholder at least on an annual basis a detailed statement of any transactions with the manager or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to the manager or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in Moon Township, Pennsylvania, on July 28, 2006.


ATLAS ENERGY RESOURCES, LLC

By:		/S/ EDWARD E. COHEN
		Edward E. Cohen Chairman of the Board and Chief Executive Officer

KNOWN ALL PERSONS BY THESE PRESENTS, that the persons whose signatures appear below, constitute and appoint Richard D. Weber and Matthew A. Jones, and each of them, as their true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for them and in their names, places and steads, in any and all capacities, to sign the Registration Statement to be filed in connection with the public offering of common units of Atlas Energy Resources, LLC and any and all amendments (including post-effective amendments) to the Registration Statement, and any subsequent registration statement filed pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and the other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as they might or could do in person, hereby ratifying and conforming all that said attorneys-in-fact and agents, or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed below by the following persons in the capacities and on the dates indicated.


/S/ EDWARD E. COHEN Edward E. Cohen	Chairman and Chief Executive Officer	July 28, 2006

/S/ JONATHAN Z. COHEN Jonathan Z. Cohen	Vice Chairman	July 28, 2006

/S/ RICHARD D. WEBER Richard D. Weber	President, Chief Operating Officer and Director	July 28, 2006

/S/ MATTHEW A. JONES Matthew A. Jones	Chief Financial Officer and Director	July 28, 2006

/S/ NANCY J. MCGURK Nancy J. McGurk	Chief Accounting Officer	July 28, 2006

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No exercise

Full exercise