Atlas Resources Public #18-2008 Program 424B3 Prospectus supplement

MINNESOTA USE ONLY

PROSPECTUS DATED AUGUST 11, 2009

ATLAS RESOURCES PUBLIC #18-2008 PROGRAM

Up to 27,035.5 Investor General Partner Units, which will be automatically converted to Limited Partner Units after drilling is completed in the partnership, and up to 534 Limited Partner Units, which are collectively referred to as the “units,” (1) at $10,000 per Unit

$2 Million (200 Units) Minimum Aggregate Subscriptions

$275,695,000 (27,569.5 Units) Maximum Aggregate Subscriptions

The partnership reserves the right to adjust the number of Investor General Partner Units, Limited Partner Units and Investor General Partner Units converted to Limited Partner Units set forth above so long as they do not exceed 60,000 units in the aggregate, including units sold in the first two partnerships

(1)You may elect to buy either investor general partner units in the partnership then being offered that will be automatically converted to limited partner units after the partnership’s drilling is completed, or limited partner units. The type of unit you buy will not change your share of the partnership’s costs, revenues and cash distributions, however, there are material differences in the federal income tax effects and liability between investor general partner units and limited partner units as discussed in “Summary of the Offering – Description of Units.”

Atlas Resources Public #18-2008 Program is a series of up to three limited partnerships which will drill primarily natural gas development wells. The first partnership in the program, Atlas Resources Public #18-2008(A) L.P., completed its offering on December 31, 2008 and received offering proceeds of $201,242,770 for the sale of 20,152.5 units, including discounted units as permitted by the prospectus and the second partnership in the program, Atlas Resources Public #18-2009(B) L.P., completed its offering on June 26, 2009 and received offering proceeds of $122,574,170 for the sale of 12,278 units, including discounted units as permitted by the prospectus. This prospectus relates to the offering of securities of the program’s remaining limited partnership, Atlas Resources Public #18-2009(C) L.P. See “Terms of the Offering – Subscription to a Partnership,” beginning on page 53, for a detailed description of the offering of this limited partnership. The limited partnership will be managed by Atlas Resources, LLC of Pittsburgh, Pennsylvania.

If you invest in the partnership, you will not have any interest in the other partnerships unless you also made a separate investment in the other partnerships.

The units will be offered on a “best efforts” “minimum-maximum” basis. This means the broker/dealers must sell at least 200 units and receive subscription proceeds of at least $2 million in order for the partnership to close, and they must use only their best efforts to sell the remaining units in the partnership.

Subscription proceeds for the partnership will be held in an interest bearing escrow account until $2 million has been received. The offering of Atlas Resources Public #18-2009(C) L.P. will not extend beyond December 31, 2009. If the minimum subscription proceeds are not received by the partnership’s offering termination date, then your subscription will be promptly returned to you from the escrow account with interest and without deduction for any fees.

The Offering: In addition to the information in the table below for not less than 95% of the units (26,191.5 units), up to 5% of the units (1,378 units), in the aggregate, may be sold at $9,000 per unit to the managing general partner, its officers, directors and affiliates, and investors who buy units through the officers and directors of the managing general partner; or at $9,300 per unit to registered investment advisors and their clients, and selling agents and their registered representatives and principals. These discounted prices reflect certain fees, sales commissions and reimbursements which will not be paid for these sales. (See “Plan of Distribution.”) To the extent that units are sold at discounted prices, the partnership’s subscription proceeds will be reduced.

			Total		Total
	Per Unit		Minimum		Maximum
Public Price	$	10,000	$	2,000,000	$	275,695,000

Dealer-manager fee and sales commissions and bona fide due diligence reimbursements (1)	$	1,000	$	200,000	$	27,569,500
Proceeds to partnership	$	10,000	$	2,000,000	$	275,695,000

(1)	These fees, sales commissions and reimbursements will be paid by the managing general partner as a part of its capital contribution and not from subscription proceeds. See “Plan of Distribution” regarding the limits on bona fide due diligence reimbursements.

·	The partnership’s drilling operations involve the possibility of a total or partial loss of your investment that may be substantial because the partnership may drill wells that are productive, but do not produce enough revenue to return the investment made, and from time to time dry holes.

·	The partnership’s revenues are directly related to its ability to market the natural gas produced from the wells it drills and natural gas and oil prices, which are volatile and uncertain. If natural gas and oil prices decrease, then your investment return will decrease.

·	Unlimited joint and several liability for partnership obligations if you choose to invest as an investor general partner until you are converted to a limited partner.

·	Lack of liquidity or a market for the units, which makes it extremely difficult for you to sell your units.

·	Lack of conflict of interest resolution procedures.

·	Total reliance on the managing general partner and its affiliates.

·	Authorization of substantial fees to the managing general partner and its affiliates.

·	You and the managing general partner will share in costs disproportionately to your sharing of revenues.

·	Possible allocation of taxable income to you in excess of your cash distributions from your partnership.

·	No guaranty of cash distributions.

These securities are speculative and involve a high degree of risk. You should purchase these securities only if you can afford a complete loss of your investment. (See “Risk Factors,” Page 12.)

Neither the SEC 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.

Anthem Securities, Inc. – Dealer-Manager

TABLE OF CONTENTS

SUITABILITY STANDARDS		1
In General		1
General Suitability Requirements for Purchasers of Limited Partner Units		1
General Suitability Requirements for Purchasers of Investor General Partner Units		1
Special Suitability Requirements for Purchasers of Investor General Partner Units		2
Fiduciary Accounts		3
Restrictions Imposed by the USA Patriot Act and Related Acts		3

SUMMARY OF THE OFFERING		4
Business of the Partnerships and the Managing General Partner		4
Risk Factors		4
Terms of the Offering		6
Description of Units		7
Investor General Partner Units		7
Limited Partner Units		8
Federal Tax Consequences		9
Use of Proceeds		9
Five Year-50% Subordination, Participation in Costs and Revenues, and Distributions		9
Compensation		10

RISK FACTORS		12
Risks Related To The Partnership’s Oil and Gas Operations		12
No Guarantee of Return of Investment or Rate of Return on Investment Because of Speculative Nature of Drilling Natural Gas and Oil Wells		12
Because Some Wells May Not Return Their Drilling and Completion Costs, It May Take Many Years to Return Your Investment in Cash, If Ever		12
The Managing General Partner Has Limited Experience in Drilling Wells to the Marcellus Shale and Less Information Regarding Reserves and Decline Rates in the Marcellus Shale Than Other Areas, and Wells Drilled to the Marcellus Shale Will Be Deeper, More Expensive and More Susceptible to Mechanical Problems in Drilling and Completing Than Wells in the Other Primary Area		12
The Managing General Partner Has Limited Experience in Drilling Horizontal Wells, and Horizontal Wells are More Expensive and Difficult to Drill and Complete Than Vertical Wells.		13
Nonproductive Wells May be Drilled Even Though the Partnership’s Operations are Primarily Limited to Development Drilling		13
Partnership Distributions May be Reduced if There is a Decrease in the Price of Natural Gas and Oil		14
Adverse Events in Marketing the Partnership’s Natural Gas Could Reduce Partnership Distributions		14
Possible Leasehold Defects		17
Transfer of the Leases Will Not Be Made Until Well is Completed		17
Participation with Third-Parties in Drilling Wells May Require the Partnership to Pay Additional Costs		17
Risks Related to an Investment in the Partnership		18
If You Choose to Invest as a General Partner, Then You Have Greater Risk Than a Limited Partner		18
The Managing General Partner May Not Meet Its Capital Contributions, Indemnification and Purchase Obligations If Its Liquid Net Worth Is Not Sufficient		18
An Investment in the Partnership Must be for the Long-Term Because the Units Are Illiquid and Not Readily Transferable		19
Spreading the Risks of Drilling Among a Number of Wells Will be Reduced if Less than the Maximum Subscription Proceeds are Received and Fewer Wells are Drilled		19
Increases in the Costs of the Wells May Adversely Affect Your Return		20
The Partnership Does Not Own Any Prospects, the Managing General Partner Has Complete Discretion to Select Which Prospects Are Acquired By the Partnership, and the Possible Lack of Information for a Majority of the Prospects Decreases Your Ability to Evaluate the Feasibility of the Partnership		20
Drilling Prospects in One Area May Increase Risk		21
Lack of Production Information Increases Your Risk and Decreases Your Ability to Evaluate the Feasibility of the Partnership’s Drilling Program		22
The Partnerships In This Program and Other Partnerships Sponsored by the Managing General Partner May Compete With Each Other for Prospects, Equipment, Subcontractors, and Personnel		22
Managing General Partner’s Subordination is Not a Guarantee of the Return of Any of Your Investment		22
Borrowings by the Managing General Partner Could Reduce Funds Available for Its Subordination Obligation		22
Compensation and Fees to the Managing General Partner Regardless of Success of the Partnership’s Activities Will Reduce Cash Distributions		23
The Intended Monthly Distributions to Investors May be Reduced or Delayed		23
There Are Conflicts of Interest Between the Managing General Partner and the Investors		23
The Presentment Obligation May Not Be Funded and the Presentment Price May Not Reflect Full Value		24
The Managing General Partner May Not Devote the Necessary Time to the Partnership Because Its Management Obligations Are Not Exclusive		25
Prepaying Subscription Proceeds to the Managing General Partner May Expose the Subscription Proceeds to Claims of the Managing General Partner’s Creditors		25
Lack of Independent Underwriter May Reduce Due Diligence Investigation of the Partnership and the Managing General Partner		25
A Lengthy Offering Period May Result in Delays in the Investment of Your Subscription and Any Cash Distributions From the Partnership to You		25
The Partnership is Subject to Comprehensive Federal, State and Local Laws and Regulations That Could Increase the Cost and Alter the Manner or Feasibility of the Partnership’s Doing Business		25
Your Interests May Be Diluted		26
Due to the Accounting Treatment of the Partnership’s Derivative Contracts, Increases in Prices for Natural Gas and Oil Could Result in Non-Cash Balance Sheet Reductions		26
A Decrease in Natural Gas Prices Could Subject the Partnership’s and the Managing General Partner’s Oil and Gas Properties to an Impairment Loss under Generally Accepted Accounting Principles		27
Federal Income Tax Risks		27

TABLE OF CONTENTS

Changes in the Law May Reduce Your Tax Benefits From an Investment in the Partnership		27
Your Deduction for Intangible Drilling Costs May Be Limited for Purposes of the Alternative Minimum Tax		27
Limited Partners Need Passive Income to Use Their Deduction for Intangible Drilling Costs		27
You May Owe Taxes in Excess of Your Cash Distributions from Your Partnership		28
Investment Interest Deductions of Investor General Partners May Be Limited		28
Your Tax Benefits from an Investment in the Partnership Are Not Contractually Protected		28
An IRS Audit of Your Partnership May Result in an IRS Audit of Your Personal Federal Income Tax Returns		28
The Partnership’s Deductions May be Challenged by the IRS		28
It May Be Many Years Before You Receive Any Marginal Well Production Credits, If Ever		29

ADDITIONAL INFORMATION		29

FORWARD LOOKING STATEMENTS AND ASSOCIATED RISKS		30

INVESTMENT OBJECTIVES		30

ACTIONS TO BE TAKEN BY MANAGING GENERAL PARTNER TO REDUCE RISKS OF ADDITIONAL PAYMENTS BY INVESTOR GENERAL PARTNERS		32

CAPITALIZATION AND SOURCE OF FUNDS AND USE OF PROCEEDS		35
Source of Funds		35
Use of Proceeds		35

COMPENSATION		39
Dealer-Manager Fees		40
Natural Gas and Oil Revenues		40
Lease Costs		41
Drilling Contracts		42
Per Well Charges		45
Gathering Fees		46
Interest and Other Compensation		47
Estimate of Administrative Costs and Direct Costs to be Borne by the Partnership		47

TERMS OF THE OFFERING		53
Subscription to the Partnership		53
Partnership Closings and Escrow		54
Acceptance of Subscriptions		54

PRIOR ACTIVITIES		55

MANAGEMENT		66
Managing General Partner and Operator		66
Officers, Directors and Other Key Personnel of Managing General Partner		68
Organizational Diagrams and Security Ownership of Beneficial Owners		72
Atlas America, Inc., a Delaware Company		76
Atlas Energy Resources, LLC (“ATN”), a Delaware Limited Liability Company		77
Atlas Energy Management, Inc., a Delaware Company		78
Remuneration of Officers and Directors		79
Code of Business Conduct and Ethics		79
Transactions with Management and Affiliates		79

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, RESULTS OF OPERATIONS, LIQUIDITY AND CAPITAL RESOURCES		82

PROPOSED ACTIVITIES		85
Overview of Drilling Activities		85
Primary Areas of Operations		87
Marcellus Shale Geological Formation in Western Pennsylvania		89
Upper Devonian New Albany Shale Reservoir, Knox and Sullivan Counties, Indiana		89
Secondary Areas of Operations		90
Mississippian Carbonate and Devonian Shale Reservoirs in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee		90
Upper Devonian Antrim Shale Reservoir, Antrim and Alcona Counties, Michigan		90
Acquisition of Leases		91
Deep Drilling Rights Retained by Managing General Partner		92
Interests of Parties		92
Primary Areas		93
Marcellus Shale Geological Formation in Western Pennsylvania		93
Devonian Shale Reservoir in Knox and Sullivan Counties, Indiana		94
Secondary Area		94
Title to Properties		94
Drilling and Completion Activities; Operation of Producing Wells		94
Sale of Natural Gas and Oil Production		96
Policy of Treating All Wells Equitably in a Geographic Area		96
Gathering of Natural Gas		97
Natural Gas Contracts		98
Marketing of Natural Gas Production from Wells in Other Areas of the United States		100
Crude Oil		100
Insurance Claims		100
Use of Consultants and Subcontractors		101

COMPETITION, MARKETS AND REGULATION		101
Natural Gas Regulation		101
Crude Oil Regulation		102
Competition and Markets		102
State Regulations		105
Environmental Regulation		105
Proposed Regulation		106

PARTICIPATION IN COSTS AND REVENUES		106
In General		106
Costs		107
Revenues		109
Subordination of Portion of Managing General Partner’s Net Revenue Share		109
Table of Participation in Costs and Revenues		111
Allocation and Adjustment Among Investors		112
Distributions		112
Liquidation		112

CONFLICTS OF INTEREST		113
In General		113

TABLE OF CONTENTS

Conflicts Regarding Transactions with the Managing General Partner and its Affiliates		114
Conflict Regarding the Drilling and Operating Agreement		114
Conflicts Regarding Sharing of Costs and Revenues		114

Conflicts Regarding Tax Matters Partner		115
Conflicts Regarding Other Activities of the Managing General Partner, the Operator and Their Affiliates		115
Conflicts Involving the Acquisition of Leases		116
Conflicts Regarding Order of Pipeline Construction and Gathering Fees		120
Conflicts Between Investors and the Managing General Partner as an Investor		120
Lack of Independent Underwriter and Due Diligence Investigation		120
Conflicts Concerning Legal Counsel		121
Conflicts Regarding Presentment Feature		121
Conflicts Regarding Managing General Partner Withdrawing or Assigning an Interest		121
Procedures to Reduce Conflicts of Interest		121
Policy Regarding Roll-Ups		123

FIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNER		124
In General		124
Limitations on Managing General Partner Liability as Fiduciary		124

FEDERAL INCOME TAX CONSEQUENCES		125
Introduction		125
Disclosures in Tax Opinion Letter		126
Special Counsel’s Assumptions		126
Managing General Partner’s Representations		126
Special Counsel’s Opinions		127
Discussion of Federal Income Tax Consequences		130
Introduction		130
Partnership Classification		130
Limitations on Passive Activity Losses and Credits		130
Publicly Traded Partnership Rules		132
Conversion from Investor General Partner to Limited Partner		132
Taxable Year and Method of Accounting		133
Taxable Year		133
Method of Accounting		133
Business Expenses		133
Intangible Drilling Costs		134
Drilling Contracts		135
Depletion Allowance		137
Depreciation and Cost Recovery Deductions		138
Marginal Well Production Credits		139
Lease Acquisition Costs and Abandonment		139
Tax Basis of Units		139
“At Risk” Limitation on Losses		140
Distributions From the Partnership		141
Sale of the Properties		141
Disposition of Units		143
Alternative Minimum Tax		144
Limitations on Deduction of Investment Interest		146
Allocations		146
Partnership Borrowings		147
Partnership Organization and Offering Costs		148
Tax Elections		148
Tax Returns and IRS Audits		149
Tax Returns		149
Profit Motive, IRS Anti-Abuse Rule and Judicial Doctrines Limitations on Deductions		150
Federal Interest and Tax Penalties		150
State and Local Taxes		152
Severance and Ad Valorem (Real Estate) Taxes		152
Social Security Benefits and Self-Employment Tax		153
Farmouts		153
Foreign Partners		153

SUMMARY OF PARTNERSHIP AGREEMENT		153
Liability of Limited Partners		153
Amendments		154
Notice		154
Voting Rights		154
Access to Records		155
Withdrawal of Managing General Partner		155
Return of Subscription Proceeds if Funds Are Not Invested in Twelve Months		156

SUMMARY OF DRILLING AND OPERATING AGREEMENT		156

REPORTS TO INVESTORS		157

PRESENTMENT FEATURE		158

TRANSFERABILITY OF UNITS		159
Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership Agreement		159
Conditions to Becoming a Substitute Partner		160

PLAN OF DISTRIBUTION		160
Commissions		160
Indemnification		163
SALES MATERIAL		163

LEGAL OPINIONS		164

EXPERTS		164

LITIGATION		165

FINANCIAL INFORMATION CONCERNING THE MANAGING GENERAL PARTNER AND ATLAS RESOURCES PUBLIC #18-2009(C) L.P.		165

INDEX TO FINANCIAL STATEMENTS		166

Exhibits

Appendix A		Information Regarding Currently Proposed Prospects for Atlas Resources Public #18-2009(C) L.P.

Exhibit (A)		Form of Amended and Restated Certificate and Agreement of Limited Partnership for Atlas Resources Public #18-2009(C) L.P.

Exhibit (I-A)		Form of Managing General Partner Signature Page

Exhibit (I-B)		Form of Subscription Agreement

Exhibit (II)		Form of Drilling and Operating Agreement for Atlas Resources Public #18-2009(C) L.P.

Exhibit (B)		Special Suitability Requirements and Disclosures to Investors

iii

SUITABILITY STANDARDS

In General

It is the obligation of persons selling the units to make every reasonable effort to assure that the units are suitable for you based on your investment objectives and financial situation, regardless of your income or net worth. However, you should invest in the partnership only if you are willing to assume the risk of a speculative, illiquid, and long-term investment. Also, subscriptions to the partnership will not be accepted from IRAs, Keogh plans and qualified retirement plans because the partnership’s income would be characterized as unrelated business taxable income, which is subject to federal income tax.

The decision to accept or reject your subscription will be made by the managing general partner, in its sole discretion, and is final. The managing general partner will not accept your subscription until it has reviewed your apparent qualifications, and the suitability determination must be maintained by the managing general partner during the partnership’s term and for at least six years thereafter.

Pennsylvania Investors: Because the minimum closing amount is less than 10% of the maximum closing amount allowed to the partnership, you are cautioned to carefully evaluate the partnership’s ability to fully accomplish its stated objectives and inquire as to the current dollar volume of partnership subscriptions. In addition, subscription proceeds received by the partnership from Pennsylvania investors will be placed into a short-term escrow (120 days or less) until subscriptions for at least 5% of the maximum offering proceeds have been received by the partnership, which for Atlas Resources Public #18-2009(C) L.P. means that subscriptions for at least $13,784,750 have been received by the partnership from investors, including Pennsylvania investors. If the appropriate minimum has not been met at the end of each escrow period, the partnership must notify the Pennsylvania investors in writing by certified mail or any other means whereby a receipt of delivery is obtained within 10 calendar days after the end of each escrow period that they have a right to have their investment returned to them. If an investor requests the return of such funds within 10 calendar days after receipt of notification, the issuer must return such funds within 15 calendar days after receipt of the investor’s request.

General Suitability Requirements for Purchasers of Limited Partner Units

Limited partner units may be sold to you if you meet either of the following requirements:

a net worth of not less than $330,000, exclusive of home, home furnishings, and automobiles; or

a net worth of not less than $85,000, exclusive of home, home furnishings, and automobiles, and had during the last tax year gross income of at least $85,000, without regard to an investment in the partnership.

In addition, if you are a resident of Iowa, Michigan, Missouri, or Pennsylvania, then you must not make an investment in the partnership which is in excess of 10% of your net worth, exclusive of home, home furnishings and automobiles and if you are a resident of Kentucky, then you must not make an investment in the partnership which is in excess of 10% of your liquid net worth. Further, if you are a resident of Alabama, Ohio or Oregon you must not make an investment in the partnership which would, after including your previous investments in prior Atlas Resources’ programs, if any, and any other similar natural gas and oil drilling programs, exceed 10% of your net worth, exclusive of home, home furnishings and automobiles. Finally, if you are a resident of Kansas or Massachusetts, it is recommended by the Office of the Kansas Securities Commissioner and the Massachusetts Securities Division, respectively, that you should limit your investment in the program and substantially similar programs to no more than 10% of your liquid net worth. Liquid net worth is that portion of your net worth (total assets minus total liabilities) that is comprised of cash, cash equivalents and readily marketable securities. Readily marketable securities may include investments in an IRA or other retirement plan that can be liquidated within a short time, less any income tax penalties that may apply for early distribution.

General Suitability Requirements for Purchasers of Investor General Partner Units

If you are a resident of any of the following states or jurisdictions:

1.	Alaska,	12.	Louisiana,	23.	Rhode Island,
2.	Colorado,	13.	Maryland,	24.	South Carolina,
3.	Connecticut,	14.	Mississippi,	25.	South Dakota,
4.	Delaware,	15.	Missouri,	26.	Utah,
5.	District of Columbia,	16.	Montana,	27.	Vermont,
6.	Florida,	17.	Nebraska,	28.	Virginia,
7.	Georgia,	18.	Nevada,	29.	West Virginia,
8.	Hawaii,	19.	New Hampshire,	30.	Wisconsin, or
9.	Idaho,	20.	New York,	31.	Wyoming,
10.	Illinois,	21.	North Dakota,
11.	Kentucky,	22.	Puerto Rico,

then investor general partner units may be sold to you if you meet either of the following requirements:

a net worth of not less than $330,000, exclusive of home, home furnishings, and automobiles; or

Additionally, if you are a resident of Missouri, then you must not make an investment in the partnership which is in excess of 10% of your net worth, exclusive of home, home furnishings and automobiles, and if you are a resident of Kentucky, then you must not make an investment in the partnership which is in excess of 10% of your liquid net worth.

However, if you are a resident of the states set forth below, then different suitability requirements apply to you if you purchase investor general partner units.

Special Suitability Requirements for Purchasers of Investor General Partner Units

If you are a resident of any of the following states:

1.	Alabama,	8.	Maine,	15.	Ohio,
2.	Arizona,	9.	Massachusetts,	16.	Oklahoma,
3.	Arkansas,	10.	Michigan,	17.	Oregon,
4.	California,	11.	Minnesota,	18.	Pennsylvania,
5.	Indiana,	12.	New Jersey,	19.	Tennessee,
6.	Iowa,	13.	New Mexico,	20.	Texas, or
7.	Kansas,	14.	North Carolina,	21.	Washington

and you subscribe for investor general partner units, then you must meet any one of the following special suitability requirements:

an individual or joint net worth with your spouse of $330,000 or more, without regard to the investment in the partnership, exclusive of home, home furnishings, and automobiles, and a combined gross income of $150,000 or more for the current year and for the two previous years; or

an individual or joint net worth with your spouse in excess of $750,000, exclusive of home, home furnishings, and automobiles; or

a combined “gross income” as defined in Internal Revenue Code Section 61 in excess of $200,000 in the current year and the two previous years.

In addition, if you are a resident of Iowa, Michigan or Pennsylvania, then you must not make an investment in the partnership which is in excess of 10% of your net worth, exclusive of home, home furnishings, and automobiles. Further, if you are a resident of Alabama, Ohio or Oregon, then you must not make an investment in the partnership which would, after including your previous investments in prior Atlas Resources’ programs, if any, and any other similar natural gas and oil drilling programs, exceed 10% of your net worth, exclusive of home, home furnishings and automobiles. Finally, if you are a resident of Kansas or Massachusetts, it is recommended by the Office of the Kansas Securities Commissioner and the Massachusetts Securities Division, respectively, that you should limit your investment in the program and substantially similar programs to no more than 10% of your liquid net worth. Liquid net worth is that portion of your net worth (total assets minus total liabilities) that is comprised of cash, cash equivalents and readily marketable securities. Readily marketable securities may include investments in an IRA or other retirement plan that can be liquidated within a short time, less any income tax penalties that may apply for early distribution.

Fiduciary Accounts

If there is a sale of a unit to a fiduciary account, then all of the suitability standards set forth above must be met by the beneficiary, the fiduciary account, or the donor or grantor who directly or indirectly supplies the funds to purchase the units if the donor or grantor is the fiduciary.

Generally, you are required to execute your own subscription agreement, and the managing general partner will not accept any subscription agreement that has been executed by someone other than you. The only exception is if you have given someone else the legal power of attorney to sign on your behalf and you meet all of the conditions in this prospectus.

RESTRICTIONS IMPOSED BY THE USA PATRIOT ACT AND RELATED ACTS

In accordance with the Uniting and Strengthening America by Providing Appropriate Tools Required to Intercept and Obstruct Terrorism Act of 2001, as amended (the “USA PATRIOT Act”), the units offered hereby may not be offered, sold, transferred or delivered, directly or indirectly, to any ‘‘Prohibited Shareholder,’’ which means anyone who is:

a ‘‘designated national,’’ ‘‘specially designated national,’’ ‘‘specially designated terrorist,’’ ‘‘specially designated global terrorist,’’ ‘‘foreign terrorist organization,’’ or ‘‘blocked person’’ within the definitions set forth in the Foreign Assets Control Regulations of the U.S. Treasury Department;

acting on behalf of, or an entity owned or controlled by, any government against whom the U.S. maintains economic sanctions or embargoes under the Regulations of the U.S. Treasury Department;

within the scope of Executive Order 13224 — Blocking Property and Prohibiting Transactions with Persons who Commit, Threaten to Commit, or Support Terrorism, effective September 24, 2001;

subject to additional restrictions imposed by the following statutes or regulations, and executive orders issued thereunder: the Trading with the Enemy Act, the Iraq Sanctions Act, the National Emergencies Act, the Antiterrorism and Effective Death Penalty Act of 1996, the International Emergency Economic Powers Act, the United Nations Participation Act, the International Security and Development Cooperation Act, the Nuclear Proliferation Prevention Act of 1994, the Foreign Narcotics Kingpin Designation Act, the Iran and Libya Sanctions Act of 1996, the Cuban Democracy Act, the Cuban Liberty and Democratic Solidarity Act and the Foreign Operations, Export Financing and Related Programs Appropriation Act or any other law of similar import as to any non-U.S. country, as each such act or law has been or may be amended, adjusted, modified or reviewed from time to time; or

designated or blocked, associated or involved in terrorism, or subject to restrictions under laws, regulations, or executive orders as may apply in the future similar to those set forth above.

SUMMARY OF THE OFFERING

This is a summary and does not include all of the information that may be important to you. You should read this entire prospectus and the attached exhibits and appendix before you decide to invest in the partnership. Throughout this prospectus when there is a reference to you it is a reference to you as a potential investor or participant in the partnership.

Business of the Partnerships and the Managing General Partner

Atlas Resources Public #18-2008 Program, which is sometimes referred to in this prospectus as the “program,” consists of up to three Delaware limited partnerships. The first partnership in the program, Atlas Resources Public #18-2008(A) L.P., completed its offering on December 31, 2008 and received offering proceeds of $201,242,770 for the sale of 20,152.5 units, including discounted units as permitted by the prospectus. The second partnership in the program, Atlas Resources Public #18-2009(B) L.P., completed its offering on June 26, 2009 and received offering proceeds of $122,574,170 for the sale of 12,278 units, including discounted units as permitted by the prospectus. This prospectus relates to the offering of the remaining unsold 27,569.5 units by the program’s remaining limited partnership, Atlas Resources Public #18-2009(C) L.P. See “Terms of the Offering” for a discussion of the terms and conditions involved in making an investment in the partnership. The partnership has a maximum 50 year term, although the managing general partner intends to terminate the partnership when its wells become uneconomical for the partnership to continue to operate, which may be approximately 15 years or longer.

The partnership will be a separate business entity from the other partnerships. A limited partnership agreement will govern the rights and obligations of the partners of the partnership. A form of the limited partnership agreement is attached to this prospectus as Exhibit (A). For a summary of the material provisions of the limited partnership agreement that are not covered elsewhere in this prospectus see “Summary of Partnership Agreement.” You will be a partner only in the partnership in which you invest. You will have no interest in the business, assets or tax benefits of the first two partnerships in the program, unless you also made a separate investment in the other partnerships. Thus, your investment return will depend solely on the operations and success or lack of success of the partnership or partnerships in which you invested.

The offering proceeds of the partnership will be used to drill primarily natural gas development wells in the Appalachian Basin. The wells to be drilled by the partnership will be located primarily in western Pennsylvania and Indiana as described in “Proposed Activities.” A development well means a well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive. Currently, the partnership does not hold any interests in any properties or prospects on which the wells will be drilled by the partnership.

The managing general partner of the partnership is Atlas Resources, LLC, a Pennsylvania limited liability company, which was originally formed as a corporation in 1979 and then changed to a limited liability company in March, 2006. The managing general partner is sometimes referred to in this prospectus as “Atlas Resources.” As set forth in “Prior Activities,” the managing general partner has sponsored and serves as managing general partner of 38 private drilling partnerships and 21 public drilling partnerships. Atlas Resources also will serve as the partnership’s general drilling contractor and operator and it will supervise the drilling, completing and operating of the wells to be drilled by the partnership. As discussed in “Compensation,” the managing general partner and its affiliates will receive substantial fees and profits in connection with this offering.

The address and telephone number of the partnership and the managing general partner are Westpointe Corporate Center One, 1550 Coraopolis Heights Road, 2nd Floor, Moon Township, Pennsylvania 15108, (412) 262-2830.

Risk Factors

This offering involves numerous risks, including risks related to the partnership’s oil and gas operations, risks related to an investment in the partnership, and tax risks. You should carefully consider a number of significant risk factors inherent in and affecting the business of the partnership and this offering, including the following:

The drilling operations of the partnership involve the possibility of a total or partial loss of your investment that may be substantial because your partnership may drill wells that are productive, but do not produce enough revenue to return the investment made, and from time to time dry holes.

Your partnership will drill wells in the Marcellus Shale in western Pennsylvania, which is a new area with a very limited production history for both the managing general partner and the natural gas and oil industry.

Your partnership’s revenues are directly related to its ability to market the natural gas produced from the wells it drills and natural gas and oil prices, which are volatile and uncertain. If natural gas and oil prices decrease then your investment return will decrease.

Unlimited joint and several liability for partnership obligations if you choose to invest as an investor general partner until you are converted to a limited partner.

Lack of liquidity or a market for the units makes it extremely difficult for you to sell your units and necessitates a long-term investment commitment from you.

Total reliance on the managing general partner and its affiliates to manage your partnership and its business.

Authorization of substantial fees to the managing general partner and its affiliates.

Possible allocation of taxable income to you and the other investors in excess of your respective cash distributions from your partnership.

Your partnership must receive minimum subscription proceeds of $2 million to close this offering, and the maximum amount of subscription proceeds is $275,695,000. There are no other requirements regarding the size of the partnership and the subscription proceeds of the partnership may be substantially more or less than the subscription proceeds of the other partnerships in the program. If only the minimum subscription proceeds are received by the partnership, its ability to spread the risks of drilling will be greatly reduced as described in “Compensation – Drilling Contracts.”

There are certain conflicts of interest between the managing general partner and you and the other investors, and a lack of procedures to resolve the conflicts.

You and the other investors and the managing general partner will share in the partnership’s costs disproportionately to the sharing of its revenues.

Currently, the partnership does not hold any interests in any properties or prospects on which the wells will be drilled. Although the managing general partner has absolute discretion in determining which properties or prospects will be drilled by the partnership, the managing general partner intends that the partnership will drill the prospects described in “Appendix A – Information Regarding Currently Proposed Prospects for Atlas Resources Public #18-2009(C) L.P.” These prospects may represent only a portion of the wells to be drilled by Atlas Resources Public #18-2009(C) L.P. depending primarily on the amount of subscription proceeds it receives. If there are material adverse events with respect to any of the currently proposed prospects before drilling begins on the prospect, the managing general partner will substitute a new prospect.

In the partnership the managing general partner will subordinate a portion of its share of the partnership’s net production revenues to increase the partnership’s distributions to you and the other investors if you and the partnership’s other investors do not receive cumulative cash distributions equal to a minimum of 10% of capital, based on a subscription price of $10,000 per unit, regardless of the actual subscription price you paid for your units, in each of the first five 12-month periods beginning with the partnership’s first cash distribution from operations. This subordination, however, is not a guaranty by the managing general partner of your distributions from your partnership. If the wells in your partnership produce small volumes of natural gas and oil and/or natural gas and oil prices decrease, then even with subordination your cash flow from the partnership may not return the intended distributions during the subordination period or, over the term of the partnership, all of your investment.

In the partnership monthly cash distributions to its investors may be deferred if revenues are used for partnership operations or reserves.

President Obama’s administration has proposed, among other tax changes, the repeal of certain oil and gas tax benefits, including the repeal of the percentage depletion allowance, the election to expense intangible drilling costs (including the further option to amortize intangible drilling costs over a 60 month period), the passive activity exception for working interests and the marginal production tax credit. (See “Federal Income Tax Consequences.”) These proposals may or may not be enacted into law. The repeal of the percentage depletion allowance, if it happens, would result in a substantial decrease in your future tax benefits from an investment in your partnership. Since the repeal of the intangible drilling costs deduction is not proposed until 2011, it will not affect your claim to deduct your share of the partnership’s intangible drilling costs in 2009. Also, other changes in the tax laws could be made that would reduce your tax benefits from an investment in the partnership.

Terms of the Offering

The time period for the offer and sale of the partnership’s units will begin on the date of this prospectus. The partnership will offer a minimum of 200 units, which is $2 million, and the maximum subscription proceeds for the partnership will be $275,695,000.

Units are offered at a subscription price of $10,000 per unit, provided that up to 5% of the units in the partnership may be sold to certain investors at discounted prices as described in “Plan of Distribution.” All subscriptions must be paid 100% in cash at the time of subscribing. Your minimum subscription in the partnership is one unit ($10,000). Larger fractional subscriptions will be accepted in $1,000 increments, beginning, for example, with $11,000, $12,000, etc.

You may elect to purchase units as either an investor general partner or a limited partner as described in “– Description of Units,” below. Under the partnership agreement no investor, including investor general partners, may participate in the management of the partnership or its business. The managing general partner will have exclusive management authority for the partnership.

The partnership has been formed as a limited partnership under the Delaware Revised Uniform Limited Partnership Act. Subscription proceeds for the partnership will be held in a separate interest bearing escrow account at Wells Fargo Bank, N.A. until receipt of the minimum subscription proceeds, excluding any subscriptions by the managing general partner or its affiliates. On receipt of the minimum subscription proceeds, the managing general partner on behalf of the partnership will break escrow, transfer the escrowed subscription proceeds to a partnership account, and begin the partnership’s activities, including drilling. After breaking escrow, additional subscription proceeds may be paid directly to a partnership account for the partnership. In this regard, subscription proceeds will earn interest until they are paid to the managing general partner for use in the partnership’s drilling activities, and will be credited to your account and paid to you at the same time as the partnership’s first cash distribution from operations. (See “Terms of the Offering.”) If subscription proceeds of $2 million are not received by the offering termination date for your partnership, which is December 31, 2009 for Atlas Resources Public #18-2009(C) L.P., then your subscription amount will be promptly returned to you from the escrow account with interest and without deduction for any fees as described in “– Five Year-50% Subordination, Participation in Costs and Revenues, and Distributions,” below.

Pennsylvania Investors: Because the minimum closing amount is less than 10% of the maximum closing amount allowed to the partnership in this offering, you are cautioned to carefully evaluate the partnership’s ability to fully accomplish its stated objectives and inquire as to the current dollar volume of partnership subscriptions. In addition, subscription proceeds received by the partnership from Pennsylvania investors will be placed into a short-term escrow (120 days or less) until subscriptions for at least 5% of the maximum offering proceeds have been received by the partnership, which for Atlas Resources Public #18-2009(C) L.P. means that subscriptions for at least $13,784,750 have been received by the partnership from investors, including Pennsylvania investors. If the appropriate minimum has not been met at the end of each escrow period, the partnership must notify the Pennsylvania investors in writing by certified mail or any other means whereby a receipt of delivery is obtained within 10 calendar days after the end of each escrow period that they have a right to have their investment returned to them. If an investor requests the return of such funds within 10 calendar days after receipt of notification, the issuer must return such funds within 15 calendar days after receipt of the investor’s request.

Description of Units

On subscribing for units in the partnership, you may elect to buy either:

investor general partner units; or

limited partner units.

The partnership will not issue certificates for its units, but your ownership of your unit(s) will be recorded on the partnership’s books and records. Also, the type of unit you buy will not affect the allocation of your partnership’s costs, revenues, and cash distributions among you and its other investors. There are, however, material differences in the federal income tax effects and liability associated with each type of unit.

Investor General Partner Units.

Tax Effect. If you invest in the partnership as an investor general partner, then your share of the partnership’s deduction for intangible drilling costs will not be subject to the passive activity limitations on losses. (See “Federal Income Tax Consequences – Limitations on Passive Activity Losses and Credits.”)

Intangible drilling costs generally means those costs of drilling and completing a well that are currently deductible, as compared to lease costs which must be recovered through the depletion allowance and costs for equipment in the well which must be recovered through depreciation deductions. For example, intangible drilling costs include all expenditures made for any well before production in commercial quantities for wages, fuel, repairs, hauling, supplies and other costs and expenses incident to and necessary for drilling the well and preparing the well for production of natural gas or oil. Intangible drilling costs also include the expense of plugging and abandoning any well before a completion attempt, and the costs (other than equipment costs and lease acquisition costs) to re-enter and deepen an existing well, complete the well to deeper reservoirs, or plug and abandon the well if it is nonproductive from the targeted deeper reservoirs.

Liability. If you invest in the partnership as an investor general partner, then you will have unlimited liability regarding the partnership’s activities. This means that if:

the partnership’s insurance proceeds from any source;

the managing general partner’s indemnification of you and the other investor general partners; and

the partnership’s assets;

were not sufficient to satisfy a partnership liability for which you and the other investor general partners were also liable solely because of your status as general partners of the partnership, then the managing general partner would require you and the other investor general partners to make additional capital contributions to the partnership to satisfy the liability. In addition, you and the other investor general partners will have joint and several liability, which means generally that a person with a claim against the partnership may sue all or any one or more of the partnership’s general partners, including you, for the entire amount of the liability. You will be able to determine if your units are subject to assessibility based on whether you buy investor general partner units, which are subject to assessibility, or limited partner units, which are not subject to assessibility. (See “Actions To Be Taken By Managing General Partner To Reduce Risks of Additional Payments by Investor General Partners” and “Proposed Activities – Insurance Claims.”)

Although past performance is no guarantee of future results, the investor general partners in the managing general partner’s prior partnerships have not had to make any additional capital contributions to their partnerships because of their status as investor general partners. (See “Prior Activities.”)

Your investor general partner units in the partnership will be automatically converted by the managing general partner to limited partner units after all of the partnership’s wells have been drilled and completed. In this regard, a well is deemed to be completed when production equipment is installed on a well, even though the well may not yet be connected to a pipeline for production of natural gas. The conversion will not create any tax liability to you or the other investors.

Once your units are converted, you will have the lesser liability of a limited partner under Delaware law for partnership obligations and liabilities arising after the conversion. However, you will continue to have the responsibilities of a general partner for partnership liabilities and obligations incurred before the effective date of the conversion. For example, you might become liable for partnership liabilities in excess of your subscription amount during the time the partnership is engaged in drilling activities and for environmental claims that arose during drilling activities, but were not discovered until after the conversion.

Limited Partner Units.

Tax Effect. If you invest in the partnership as a limited partner, then your use of your share of the partnership’s deduction for intangible drilling costs will be limited to offsetting your net passive income from “passive” trade or business activities. Passive trade or business activities generally include the partnership and other limited partner investments, but passive income does not include salaries, dividends or interest. This means that you will not be able to deduct your share of the partnership’s intangible drilling costs in the year in which you invest unless you have net passive income from investments other than the partnership. However, any portion of your share of the partnership’s deduction for intangible drilling costs that you cannot use in the year in which you invest, because you do not have sufficient net passive income in that year, may be carried forward indefinitely until you can use it to offset your net passive income from the partnership or your other passive activities, if any, in subsequent tax years. (See “Federal Income Tax Consequences – Limitations on Passive Activity Losses and Credits.”)

Liability. If you invest in the partnership as a limited partner, then you will have limited liability for the partnership’s liabilities and obligations. This means that you will not be liable for any partnership liabilities or obligations beyond the amount of your initial investment in the partnership and your share of the partnership’s undistributed net profits, subject to certain exceptions set forth in “Summary of Partnership Agreement – Liability of Limited Partners.”

Federal Income Tax Consequences

Use of Proceeds

The partnership must receive minimum subscription proceeds of $2 million to close, and the maximum subscription proceeds of Atlas Resources Public #18-2009(C) L.P. may not exceed $275,695,000. In the partnership, regardless of whether the partnership receives the minimum or the maximum subscription proceeds from you and the other investors:

85% of the subscription proceeds will be used to pay 100% of the intangible drilling costs, as defined above in “– Description of Units,” of drilling and completing the partnership’s wells; and

15% of the subscription proceeds will be used to pay equipment costs of drilling and completing the partnership’s wells.

The managing general partner will contribute all of the leases to the partnership covering the acreage on which the partnership’s wells will be drilled and pay all of the equipment costs of drilling and completing the partnership’s wells that exceed 15% of the partnership’s subscription proceeds. The managing general partner also will be charged with 100% of the organization and offering costs for the partnership. A portion of these contributions to the partnership will be in the form of payments to itself, its affiliates and third-parties and the remainder will be in the form of services related to organizing this offering. The managing general partner will receive a credit towards its required capital contribution to the partnership for these payments and services as discussed in “Participation in Costs and Revenues.” (See “Capitalization and Source of Funds and Use of Proceeds” and “Federal Income Tax Consequences – Intangible Drilling Costs.”)

Five Year-50% Subordination, Participation in Costs and Revenues, and Distributions

The partnership will be a separate business entity from the prior two partnerships in the program, and you will be a partner only in the partnership in which you invest. You will have no interest in the business, assets or tax benefits of the other partnerships in the program unless you also made an investment in the other partnerships. Thus, your investment return will depend solely on the operations and success or lack of success of the particular partnership in which you invest. If you and the other investors do not receive cumulative cash distributions equal to a minimum of 10% of capital, based on a subscription price of $10,000 per unit, regardless of the actual subscription price you paid for your units, in each of the first five 12-month periods beginning with the partnership’s first cash distribution from operations, the managing general partner will subordinate up to 50% of its share of partnership net production revenues. (See “Participation in Costs and Revenues – Subordination of Portion of Managing General Partner’s Net Revenue Share.”)

The partnership’s 60-month subordination period will begin with the partnership’s first cash distribution from operations to you and its other investors. The estimated maximum time from its final closing for the partnership to begin distributions is eight months from the closing as discussed in “Investment Objectives.” Subordination distributions will be determined by debiting or crediting current period partnership revenues to the managing general partner as may be necessary to provide the distributions to you and the other investors. At any time during the subordination period, but not after, the managing general partner is entitled to an additional share of partnership revenues to recoup previous subordination distributions to the extent your cash distributions from the partnership exceed the 10% return of capital described above. The specific formula for determining subordination distributions is set forth in Section 5.01(b)(4)(a) of the partnership agreement.

The following table sets forth how the partnership’s costs and revenues will be charged and credited between the managing general partner and you and the other investors in the partnership after deducting from the partnership’s gross revenues the landowner royalties and any other lease burdens.

	Managing
	General
	Partner		Investors
Partnership Costs
Organization and offering costs		100%		0%
Lease costs		100%		0%
Intangible drilling costs (1)		0%		100%
Equipment costs		(2)		(2)
Operating costs, administrative costs, direct costs, and all other costs		(3)		(3)

Partnership Revenues
Interest income		(4)		(4)
Equipment proceeds		(2)		(2)
All other revenues including production revenues		(5)(6)		(5)(6)

(1)	Eighty-five percent of the subscription proceeds of you and the other investors in the partnership will be used to pay 100% of the intangible drilling costs incurred by the partnership in drilling and completing its wells.

(2)

Fifteen percent of the subscription proceeds of you and the other investors in the partnership will be used to pay equipment costs incurred by the partnership in drilling and completing its wells. All equipment costs in excess of 15% of the partnership’s subscription proceeds will be paid by the managing general partner. Equipment proceeds, if any, will be credited in the same percentage in which the equipment costs were charged.

(3)

These costs will be charged to the parties in the same ratio as the related production revenues are being credited. These costs also include the plugging and abandonment costs of the wells after their economic reserves have been produced and depleted as described in “Participation in Costs and Revenues.”

(4)

Your subscription proceeds will earn interest until they are paid to the managing general partner for use in the partnership’s drilling activities, and will be credited to your account and paid to you at the same time as the partnership’s first cash distribution from operations. After the subscription proceeds from a closing are transferred to a partnership account and before they are paid to the managing general partner for use in the partnership’s natural gas and oil operations, any interest income from temporary investments will be allocated pro rata to the investors in the partnership providing those subscription proceeds. All other interest income, including interest earned on the deposit of operating revenues, will be credited as natural gas and oil production revenues are credited.

(5)

The managing general partner and you and the other investors will share in all of the partnership’s other revenues in the same percentage as their respective capital contributions bears to the partnership’s total capital contributions, except that the managing general partner will receive an additional 10% of the partnership revenues.

(6)

The actual allocation of partnership net production revenues between the managing general partner and you and the other investors will vary from the allocation described in (5) above if a portion of the managing general partner’s share of partnership net production revenues is subordinated as described above.

The managing general partner will review the partnership’s accounts at least monthly to determine whether cash distributions are appropriate and the amount to be distributed, if any. The partnership will distribute funds to you and its other investors that the managing general partner does not believe are necessary for the partnership to retain. (See “Participation in Costs and Revenues.”)

Compensation

As discussed in “Compensation,” the managing general partner and its affiliates will receive substantial fees and profits in connection with this offering. The items of compensation paid to the managing general partner and its affiliates from the partnership are as follows:

The managing general partner will receive a share of the partnership’s revenues. The managing general partner’s revenue share will be in the same percentage as its capital contribution bears to the partnership’s total capital contributions plus an additional 10% of partnership revenues. A portion of the managing general partner’s revenue share will be subject to its subordination obligation.

The managing general partner will receive a credit to its capital account in an amount equal to the cost of the leases contributed to the partnership by the managing general partner, or the fair market value of the leases if the managing general partner has reason to believe that cost is materially more than the fair market value.

The partnership will enter into the drilling and operating agreement with the managing general partner to drill and complete the partnership’s wells at competitive rates as described in “Compensation – Drilling Contracts.”

When the partnership’s wells begin producing natural gas or oil in commercial quantities, the managing general partner, as operator of the wells, will receive:

reimbursement at actual cost for all direct expenses incurred by it on behalf of the partnership;

well supervision fees for operating and maintaining the wells during producing operations at a competitive rate: and

compensation at a competitive rate for any services the managing general partner, as operator, provides to the partnership relating to disposal or injection wells and the transportation of waste water from the partnership’s productive wells.

The managing general partner will receive gathering fees at competitive rates for its services in gathering and transporting the partnership’s natural gas production.

Subject to certain exceptions described in “Plan of Distribution,” Anthem Securities, Inc., the dealer-manager of this offering and an affiliate of the managing general partner, which is sometimes referred to in this prospectus as “Anthem Securities,” will receive on each unit sold to an investor a 2.5% dealer-manager fee, a 7% sales commission and up to a .5% reimbursement of the selling agents’ bona fide due diligence expenses.

The managing general partner and its affiliates will receive a nonaccountable, fixed payment reimbursement for their administrative costs, which has been determined by the managing general partner to be $75 per well per month. The managing general partner may not increase this fee during the term of the partnership.

(See “Compensation.”)

RISK FACTORS

An investment in the partnership involves a high degree of risk and is suitable only if you have substantial financial means and no need of liquidity in your investment.

Risks Related To The Partnership’s Oil and Gas Operations

No Guarantee of Return of Investment or Rate of Return on Investment Because of Speculative Nature of Drilling Natural Gas and Oil Wells. Natural gas and oil exploration is an inherently speculative activity. Before the drilling of a well the managing general partner cannot predict with absolute certainty:

the volume of natural gas and oil recoverable from the well; or

the time it will take to recover the natural gas and oil.

You may not recover any or all of your investment in the partnership, or if you do recover your investment in the partnership you may not receive a rate of return on your investment that is competitive with other types of investment. You will be able to recover your investment only through distributions of the partnership’s net proceeds from the sale of its natural gas and oil from productive wells. The quantity of natural gas and oil in a well, which is referred to as its reserves, decreases over time as the natural gas and oil is produced until the well is no longer economical to operate. All of these distributions to you will be considered a return of capital until you have received 100% of your investment. This means that you are not receiving a return on your investment in the partnership, excluding tax benefits, until your total cash distributions from the partnership exceed 100% of your investment. (See “Prior Activities.”)

Because Some Wells May Not Return Their Drilling and Completion Costs, It May Take Many Years to Return Your Investment in Cash, If Ever. Even if a well is completed by the partnership and produces natural gas and oil in commercial quantities, it may not produce enough natural gas and oil to pay for the costs of drilling and completing the well, even if tax benefits are considered. For example, the managing general partner has formed 59 partnerships since 1985 as set forth in “Prior Activities,” however, 39 of the 59 partnerships have not yet returned to the investor 100% of his capital contributions without taking tax savings into account. Thus, it may take many years to return your investment in cash, if ever. (See “– Risks Related to an Investment in the Partnership – A Decrease in Natural Gas Prices Could Subject the Partnership’s and the Managing General Partner’s Oil and Gas Properties to an Impairment Loss under Generally Accepted Accounting Principles” and “Prior Activities.”)

The partnership’s primary drilling areas are primarily located in the most active drilling areas in the Appalachian Basin. As a result, many of the leases which will be drilled by the partnership are in areas that have already been partially depleted or drained by earlier offset drilling. This may reduce the partnership’s ability to find economically recoverable quantities of natural gas in those areas.

The Managing General Partner Has Limited Experience in Drilling Wells to the Marcellus Shale and Less Information Regarding Reserves and Decline Rates in the Marcellus Shale Than Other Areas, and Wells Drilled to the Marcellus Shale Will Be Deeper, More Expensive and More Susceptible to Mechanical Problems in Drilling and Completing Than Wells in the Other Primary Area. The managing general partner anticipates that approximately 79% of the partnership’s maximum subscription proceeds will be used to drill wells to the Marcellus Shale formation, although as the date of this prospectus only a portion of the Marcellus Shale prospects have been specified. Through the first quarter of 2009, the managing general partner and affiliated investment partnerships have drilled 135 vertical wells to the Marcellus Shale, 118 of which have been completed as productive, but have been producing for only a short period of time. The other 17 wells have not yet been completed and fraced. See “– The Managing General Partner Has Limited Experience in Drilling Horizontal Wells, and Horizontal Wells are More Expensive and Difficult to Drill and Complete Than Vertical Wells,” below, regarding the number of horizontal wells drilled by the managing general partner. Also, the managing general partner and other operators in the Appalachian Basin have relatively limited experience in drilling wells to the Marcellus Shale, including limited production information for the Marcellus Shale. As discussed in “– Risks Related to an Investment in the Partnership – Lack of Production Information Increases Your Risk and Decreases Your Ability to Evaluate the Feasibility of the Partnership’s Drilling Program,” the Pennsylvania Department of Environmental Resources keeps production data confidential for the first five years from the time a well starts producing. Thus, the managing general partner has limited information with respect to the ultimate recoverable reserves and the production decline rate in the Marcellus Shale as compared with the other areas of the Appalachian Basin as described in “Proposed Activities – Primary Areas of Operations.”

Also, the wells to be drilled in the Marcellus Shale will be drilled deeper than the wells to be drilled in the other primary area, which makes the Marcellus Shale wells more expensive to drill and complete as described in “Compensation – Drilling Contracts.” In addition, porosities and permeabilities in the Marcellus Shale are very low, so to unlock the hydrocarbons and make the wells productive large frac treatments using large amounts of water must be performed as discussed in “Proposed Activities – Primary Areas of Operations – Marcellus Shale Geological Formation in Western Pennsylvania.” Porosity is the percentage of void space between sand grains that is available for occupancy by either liquids or gases; and permeability is the property of porous rock that allows fluids or gas to flow through it. The large amounts of water used in completing wells in the Marcellus Shale must be disposed of pursuant to plans approved by the Pennsylvania Department of Environmental Resources, which may increase the costs of the partnership’s wells and operations. See “– Risks Related to an Investment in the Partnership – The Partnership is Subject to Comprehensive Federal, State and Local Laws and Regulations That Could Increase the Cost and Alter the Manner or Feasibility of the Partnership Doing Business.”

Wells drilled to the Marcellus Shale also will be more susceptible to mechanical problems associated with the drilling and completion of the wells, such as casing collapse and lost equipment in the wellbore. Additionally, this risk is increased with the horizontal wells that will be drilled in the Marcellus Shale as discussed below in “– The Managing General Partner Has Limited Experience in Drilling Horizontal Wells, and Horizontal Wells are More Expensive and Difficult to Drill and Complete Than Vertical Wells.” Further, fracing the Marcellus Shale wells will be more extensive and complicated, which will result in more than one frac in the wells drilled vertically, and multiple fracs in the horizontal wells, than fracing wells in the geological formations in the other primary area as discussed in “Proposed Activities – Primary Areas of Operations – Marcellus Shale Geological Formation in Western Pennsylvania.”

The Managing General Partner Has Limited Experience in Drilling Horizontal Wells, and Horizontal Wells are More Expensive and Difficult to Drill and Complete Than Vertical Wells. In the north central Tennessee secondary area approximately one-half of the wells will be drilled horizontally, rather than vertically, and all the wells drilled in the New Albany Shale (Indiana) primary area will be drilled horizontally. Also, approximately 12% of the wells drilled in the Marcellus Shale primary area will be horizontal wells and, although not anticipated, some horizontal wells may be drilled in the Antrim Shale (Michigan) secondary area. The managing general partner has limited experience in drilling horizontal wells and to date has participated in drilling only 88 horizontal wells and has served as operator on 83 of the horizontal wells, 21 of which were located in the north central Tennessee secondary area, 13 of which were located in the New Albany Shale (Indiana) primary area, 10 of which were located the Marcellus Shale primary area, and 44 of which were located in the Antrim Shale (Michigan) secondary area. Also, the managing general partner has little information with respect to the ultimate recoverable reserves and the production decline rate associated with horizontal wells in these areas.

Horizontal wells are more expensive to drill and complete than vertical wells as described in “Compensation – Drilling Contracts,” because of increased costs associated with the drilling rigs needed to drill a horizontal well, including fracing the wells, and casing for the wells. For example, in the Marcellus Shale, a horizontal well may cost three times the amount of a vertical well. This increased cost to the partnership may not result in greater recoverable reserves. In addition, horizontal wells will be more susceptible to mechanical problems associated with completing the wells, such as casing collapse and lost equipment, than vertical wells. Further, fracing the formation in a horizontal well is more complicated than fracing the same geological formation in a vertical well. Thus, there is a greater risk of loss of the well or cost overruns associated with horizontal drilling as compared with vertical drilling.

Nonproductive Wells May be Drilled Even Though the Partnership’s Operations are Primarily Limited to Development Drilling. The partnership may drill some development wells that are nonproductive, which is referred to as a “dry hole,” and must be plugged and abandoned. If one or more of the partnership’s wells are nonproductive, then the partnership’s productive wells may not produce enough revenues to offset the loss of investment in the nonproductive wells. (See “Prior Activities.”)

Partnership Distributions May be Reduced if There is a Decrease in the Price of Natural Gas and Oil. The prices at which the partnership’s natural gas and oil will be sold are uncertain and, as discussed in “– Adverse Events in Marketing the Partnership’s Natural Gas Could Reduce Partnership Distributions,” the partnership is not guaranteed a specific natural gas price for the sale of its natural gas production. Changes in natural gas and oil prices will have a significant impact on the partnership’s cash flow and the value of its reserves. Lower natural gas and oil prices may not only decrease the partnership’s revenues, but also may reduce the amount of natural gas and oil that the partnership can produce economically as discussed in “– Risks Related to an Investment in the Partnership – A Decrease in Natural Gas Prices Could Subject the Partnership’s and the Managing General Partner’s Oil and Gas Properties to an Impairment Loss under Generally Accepted Accounting Principles.” In May of 2009, the price of natural gas dropped to $3.32 per mcf, which was its lowest price since September 2002.

Historically, natural gas and oil prices have been volatile and it is likely that they will continue to be volatile in the future. Prices for natural gas and oil will depend on supply and demand factors largely beyond the control of the partnership and prices may fluctuate 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 the partnership’s control, as described in “Competition, Markets and Regulations – Competition and Markets.”

These factors make it extremely difficult to predict natural gas and oil price movements with any certainty.

If natural gas and oil prices decrease in the future, then your partnership distributions will decrease accordingly. Also, natural gas and oil prices may decrease during the first years of production from your partnership’s wells, which is when the wells typically achieve their greatest level of production. This would have a greater adverse effect on your partnership distributions than price decreases in later years when the wells have a lower level of production. Also, your return level will decrease during the term of the partnership, even if there are rising natural gas prices, because of declining production volumes from the wells over time. See “Appendix A – Information Regarding Currently Proposed Prospects for Atlas Resources Public #18-2009(C) L.P.” for a discussion of flush production and “Proposed Activities – Sale of Natural Gas and Oil Production.”

Further, as discussed in “Federal Income Tax Consequences – Depletion Allowance,” the managing general partner has represented that some of the natural gas and oil production from your partnership’s productive wells will be marginal production under the Internal Revenue Code and could qualify for potentially higher rates of percentage depletion. Thus, the partnership will be more sensitive to price declines, including reducing the volume of natural gas and oil that the partnership can produce economically (i.e., the volume of natural gas and oil reserves), than if its wells produced at a higher average rate of production that did not qualify for the potentially higher rate of percentage depletion.

Adverse Events in Marketing the Partnership’s Natural Gas Could Reduce Partnership Distributions. In addition to the risk of decreased natural gas and oil prices described above, certain material adverse events in marketing the partnership’s natural gas could reduce the partnership’s distributions to you and its other investors. These risks are set forth below.

Competition from other natural gas producers and marketers in the Appalachian Basin and other areas where the partnership’s wells are situated as well as competition from alternative energy sources as discussed in “Competition, Markets and Regulation,” may make it more difficult to market the partnership’s natural gas. Additionally, a new natural gas interstate pipeline and related transmission facilities are being constructed from Missouri to Ohio by a joint venture composed of independent third-parties to extend the supply of Rocky Mountain Basin natural gas to major markets in the upper midwest and eastern United States. According to a press release, the pipeline is expected to be fully in service to eastern Ohio by November 1, 2009. The resulting increased supply of natural gas to the regions in the upper Midwest and eastern United States from the Rocky Mountain Basin will increase competition and may have the effect of placing downward pressure on Appalachian Basin natural gas pricing.

As set forth in “Proposed Activities,” the managing general partner has identified two primary areas where it intends to drill the partnership’s wells. The managing general partner anticipates that the partnership’s natural gas production in each of the primary areas initially will be sold to a limited number of purchasers in each area as described in “Proposed Activities – Sale of Natural Gas and Oil Production.” If the partnership loses a natural gas purchaser in a given area, the partnership may be unable to locate a new natural gas purchaser in the area that will buy the partnership’s natural gas on as favorable terms as the initial purchaser.

Also, all of these natural gas purchase contracts provide that the price paid by the natural gas purchaser may be adjusted upward or downward in accordance with the spot market price and market conditions as described in “Proposed Activities – Sale of Natural Gas and Oil Production.” In May of 2009, the price of natural gas dropped to $3.32 per mcf, which was its lowest price since September 2002. Thus, the partnership will not be guaranteed a specific natural gas price, other than through hedging. To limit exposure to changing natural gas prices, Atlas Energy Resources, LLC, which is sometimes referred to in this prospectus as “ATN,” uses financial and physical hedges for its natural gas production, including natural gas production from the partnership and the managing general partner’s other partnerships. ATN, its affiliates or the partnership will enter into financial 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 60 months in the future. In addition, ATN, its affiliates or the partnership may enter into physical hedges, which are not deemed hedging for accounting purposes because physical hedges require firm delivery of natural gas and are considered normal sales of natural gas. The percentages of natural gas that are hedged through either financial hedges or physical hedges, or are not hedged at all, will change from time to time in the discretion of ATN or the partnership. If the hedges are with ATN or its affiliates, rather than the partnership, it is difficult to project what portion of the hedges will be allocated to the partnership by the managing general partner because of uncertainty about the quantity, timing, and delivery locations of natural gas that may be produced by the partnership.

By removing the price volatility from a portion, which may be substantial, of the natural gas production from the partnership, the managing general partner and its affiliates will reduce, but not eliminate, the potential effects of changing natural gas prices on a portion, which may be substantial, of the cash flow from the partnership for the periods covered by the hedges. Furthermore, while intended to help reduce the effects of volatile natural gas prices, such transactions, depending on the hedging instrument used, may limit the potential gains for the partnership if natural gas prices were to rise substantially over the price established by the hedge. Also, the partnership could incur liability on the financial hedges. For example, the partnership would be exposed to the risk of a financial loss if any of the following occur:

the partnership’s production is substantially less than expected;

the counterparties to the futures contracts fail to perform under the contracts, the risk of which is increased because of the current credit crisis in the United States; or

there is a sudden, unexpected event materially impacting natural gas prices.

(See “Proposed Activities – Sale of Natural Gas and Oil Production – Natural Gas Contracts.”)

All of the natural gas contracts, including those described above, may be between the natural gas purchaser and either ATN or an affiliate, including the partnership. Either ATN or an affiliate will receive the sales proceeds from the natural gas purchasers and then distribute the sales proceeds to each partnership based on the volume of natural gas produced by each partnership. Until the sales proceeds are distributed to a partnership, they will be subject to the claims of ATN’s or its affiliates’ creditors.

There is a credit risk associated with a natural gas purchaser’s ability to pay. The partnership may not be paid, or may experience delays in receiving payment, for its natural gas that has already been delivered to the purchaser. In accordance with industry practice, the partnership typically will deliver natural gas to a purchaser for a period of up to 60 to 90 days before it receives payment. Thus, it is possible that the partnership may not be paid for natural gas that already has been delivered if the natural gas purchaser fails to pay for any reason, including bankruptcy. This ongoing credit risk also may delay or interrupt the sale of the partnership’s natural gas or the partnership’s negotiation of different terms and arrangements for selling its natural gas to other purchasers. Finally, this credit risk may reduce the price benefit derived by the partnership from the managing general partner’s or the partnership’s natural gas hedging arrangements as described above and in “Proposed Activities – Sale of Natural Gas and Oil Production – Natural Gas Contracts,” since from time to time the managing general partner and its affiliates have implemented a portion of the natural gas hedges through the natural gas purchasers.

The partnership’s net revenues will decrease the farther its natural gas is transported for sale because of increased transportation costs.

Production from the partnership’s wells drilled in certain areas, such as wells drilled in the Anderson, Campbell, Morgan, Scott and Roane Counties, Tennessee area, may be delayed until construction of the necessary gathering lines and production facilities is completed. Also, from time to time the managing general partner and its affiliates will have to increase gathering capacity for transportation of the natural gas as more wells are drilled which connect into the gathering system. (See “Proposed Activities – Sale of Natural Gas and Oil Production – Gathering of Natural Gas.”)

The managing general partner will use the gathering system owned by Laurel Mountain Midstream, LLC, which is sometimes referred to in this prospectus as “Laurel Mountain,” for all of the partnership’s natural gas production in the Marcellus Shale primary area in western Pennsylvania, which the managing general partner anticipates will be the majority of the partnership’s natural gas. Laurel Mountain is a joint venture which closed on June 1, 2009, between a subsidiary of Atlas Pipeline Partners, which is sometimes referred to in this prospectus as “APL Laurel Mountain” and owns a 49% equity interest in Laurel Mountain, and an indirect subsidiary of The Williams Companies, Inc., which owns a 51% equity interest in Laurel Mountain and is sometimes referred to in this prospectus as “Williams.” Laurel Mountain’s operations are determined by its management committee, which is composed of two representatives with one member appointed by APL Laurel Mountain and one member appointed by Williams. Williams controls the day-to-day operation of the natural gas gathering system at the direction of Laurel Mountain’s management committee. (See “Management – Organizational Diagrams and Security Ownership of Beneficial Owners” and “Proposed Activities – Sale of Natural Gas and Oil Production – Gathering of Natural Gas.”)

Also, certain of the managing general partner’s affiliates, including Atlas America, LLC, and ATN, but not the partnership, are obligated through their agreement with Laurel Mountain to pay the difference between the amount the partnership pays for gathering fees to the managing general partner as set forth in “Compensation – Gathering Fees,” and the greater of $.35 per mcf or 16% of the gross sales price for the partnership’s natural gas transported through Laurel Mountain’s gathering system. This creates a conflict of interest between the managing general partner and the partnership, because the managing general partner has an economic incentive to increase the amount of gathering fees paid by the partnership to reduce the amount of gathering fees paid by Atlas America, LLC, ATN or their affiliates, which does not include the partnership for this purpose, to Laurel Mountain. Any increase in the partnership’s gathering fees, however, cannot exceed a competitive rate. Any increase in the gathering fees that your partnership pays, which cannot exceed competitive rates, would reduce your cash distributions from the partnership.

For the natural gas produced in the Marcellus Shale primary area by the partnership, the only gathering system available to the partnership is that owned by Laurel Mountain. The partnership will depend on that gathering system to deliver the natural gas produced from the partnership’s wells to interstate pipeline systems, local distribution companies and/or end users in the area and the partnership’s natural gas production in Laurel Mountain’s area of interest has been dedicated to that gathering system. Because there is only one gathering system in the Marcellus Shale primary area for the partnership’s natural gas, the partnership may have to pay more for the gathering services than the amount set forth in “Compensation.” Also, there may be a reduction in the volume of the partnership’s natural gas that may be transported. Further, affiliates of the managing general partner no longer unilaterally control the development of the gathering system, including increasing capacity for transporting production from the partnership’s Marcellus Shale wells and/or connecting the partnership’s wells to the gathering system, since Williams controls the day-to-day operation of the gathering system.

Possible Leasehold Defects. There may be defects in the partnership’s title to its leases. Although the managing general partner will obtain a favorable formal title opinion for the leases before each well is drilled, it will not obtain a division order title opinion after the well is completed. Thus, the partnership may experience losses from title defects which arose during drilling that would have been disclosed by a division order title opinion, such as liens arising during drilling operations or transfers of interests in the leases after drilling begins. Also, the managing general partner may use its own judgment in waiving title requirements for the partnership’s leases and it will not be liable for any failure of title of leases transferred to the partnership. See “Proposed Activities – Title to Properties” and “Litigation” regarding the acquisition of leases in Tennessee.

Transfer of the Leases Will Not Be Made Until Well is Completed. Because the leases will not be transferred from the managing general partner to the partnership until after the wells are drilled and completed, the transfer could be set aside by a creditor of the managing general partner, or the trustee in the event of the voluntary or involuntary bankruptcy of the managing general partner, if it were determined that the managing general partner received less than a reasonably equivalent value for the leases. In this event, the leases and the wells would revert to the creditors or trustee, and the partnership would either recover nothing or only the amount it paid for the leases and the cost of drilling the wells. Assigning the leases to the partnership after the wells are drilled and completed, however, will not affect the availability of the tax deductions for intangible drilling costs since the partnership will have an economic interest in the wells under the drilling and operating agreement before the wells are drilled. (See “Proposed Activities – Title to Properties.”)

Participation with Third-Parties in Drilling Wells May Require the Partnership to Pay Additional Costs. Third-parties will participate with the partnership in drilling some of the wells and additional financial risks exist when the costs of drilling, equipping, completing, and operating wells is shared by more than one person. If the partnership pays its share of the costs, but another interest owner does not pay its share of the costs, then the partnership would have to pay the costs of the defaulting party. In this event, the partnership would receive the defaulting party’s revenues from the well, if any, under penalty arrangements set forth in the operating agreement, which may, or may not, cover all of the additional costs paid by the partnership.

If the managing general partner is not the actual operator of the well for all of the working interest owners of the well, then there is a risk that the managing general partner cannot supervise the third-party operator closely enough. For example, decisions related to the following would be made by the third-party operator and may not be in the best interests of the partnership and you and the other investors:

how the well is operated;

expenditures related to the well; and

possibly the marketing of the natural gas and oil production from the well.

Further, the third-party operator may have financial difficulties and fail to pay for materials or services on the wells it drills or operates, which would cause the partnership to incur extra costs in discharging materialmen’s and workmen’s liens. The managing general partner may not be the operator of a well for all of the working interest owners of the well if the partnership owns less than a 50% working interest in the well, or if the managing general partner acquired the working interest in the well from a third-party under arrangements that required the third-party to be named operator as one of the terms of the acquisition.

Risks Related to an Investment in the Partnership

If You Choose to Invest as a General Partner, Then You Have Greater Risk Than a Limited Partner. If you elect to invest in the partnership as an investor general partner for the tax benefits instead of as a limited partner, then under Delaware law you will have unlimited liability for your partnership’s activities until you are converted to limited partner status, subject to certain exceptions described in “Actions To Be Taken by Managing General Partner To Reduce Risks of Additional Payments By Investor General Partners – Conversion of Investor General Partner Units to Limited Partner Units.” This could result in you being required to make payments, in addition to your original investment, in amounts that are impossible to predict because of their uncertain nature. Under the terms of the partnership agreement, if you are an investor general partner you agree to pay only your proportionate share, as among all of your partnership’s investor general partners, of your partnership’s obligations and liabilities. This agreement, however, does not eliminate your liability to third-parties if another investor general partner does not pay his proportionate share of your partnership’s obligations and liabilities.

Also, the partnership will own less than 100% of the working interest in some of its wells. If a court holds you and the other third-party working interest owners of the well liable for the development and operation of a well and the third-party working interest owners do not pay their proportionate share of the costs and liabilities associated with the well, then the partnership and you and the other investor general partners also would be liable for those costs and liabilities.

As an investor general partner you may become subject to the following:

contract liability, which is not covered by insurance;

liability for pollution, abuses of the environment, and other environmental damages as discussed in “Competition, Markets and Regulation – Environmental Regulation,” including but not limited to the release of toxic gas, spills or uncontrollable flows of natural gas, oil or well fluids, including underground or surface contamination, against which the managing general partner cannot insure because coverage is not available or against which it may elect not to insure because of high premium costs or other reasons; and

liability for drilling hazards that result in property damage, personal injury, or death to third-parties in amounts greater than the insurance coverage. The drilling hazards include, but are not limited to, well blowouts, fires, craterings and explosions.

If your partnership’s insurance proceeds and assets, the managing general partner’s indemnification of you and the other investor general partners, and the liability coverage provided by major subcontractors were not sufficient to satisfy the liability, then the managing general partner would call for additional funds from you and the other investor general partners to satisfy the liability. See “Actions To Be Taken By Managing General Partner To Reduce Risks of Additional Payments by Investor General Partners,” including the managing general partner’s current insurance coverage of $10 million for pollution liability, which may not be adequate. Additionally, any of the drilling hazards may result in the loss of the well and the associated revenues. Finally, an investor general partner may have liability if the partnership does not properly plug and abandon a well. See “Participation in Costs and Revenues – Costs – Operating Costs, Direct Costs, Administrative Costs and All Other Costs” relating to the costs associated with plugging and abandoning wells.

The Managing General Partner May Not Meet Its Capital Contributions, Indemnification and Purchase Obligations If Its Liquid Net Worth Is Not Sufficient. The managing general partner has made commitments to you and the other investors in the partnership regarding the following:

the payment of organization and offering costs and a portion of equipment costs;

indemnification of the investor general partners for liabilities in excess of their pro rata share of partnership assets and insurance proceeds, which commitment the managing general partner has made in 56 of the partnerships it has sponsored; and

purchasing units presented by an investor, although this feature may be suspended by the managing general partner if it determines, in its sole discretion, that it does not have the necessary cash flow or cannot borrow funds for this purpose on reasonable terms.

A significant financial reversal for the managing general partner could adversely affect its ability to honor these obligations.

The managing general partner’s net worth is based primarily on the estimated value of its producing natural gas properties and is not available in cash without borrowings or a sale of the properties. Also, if natural gas prices decrease, then the estimated value of the properties and the managing general partner’s net worth will be reduced. Further, price decreases will reduce the managing general partner’s revenues, and may make some oil and gas reserves uneconomic to produce. This would reduce the managing general partner’s reserves and cash flow, and could cause the lenders of the managing general partner and its affiliates to reduce the borrowing base for the managing general partner and its affiliates.

In this regard, see “Management’s Discussion and Analysis of Financial Condition, Results of Operations, Liquidity and Capital Resources” regarding the managing general partner’s liability under the terms of ATN’s credit facility. The borrowing base of the credit facility was increased to $850 million in connection with ATN’s acquisition of DTE Gas & Oil Company as described in “Management.” On January 18, 2008, ATN sold $250 million of senior unsecured notes due in 2018 in a private placement at a coupon rate of 10.75%. On May 5, 2008, ATN sold an additional $150 million of its 10.75% senior unsecured notes in a follow-on offering at 9.85%. The unsecured notes are guaranteed by ATN’s affiliates, including Atlas America and the managing general partner. Upon the sale of the senior unsecured notes, the borrowing base on the revolving credit facility was reduced by 25% of the principal of the senior notes, or $100 million. With the redetermination of the borrowing base on April 1, 2008 and the subsequent reductions to the senior unsecured note offerings in May 2008, the borrowing base on the revolving credit facility was $697.5 million. Also, the borrowing base as a result of the April 1, 2009 redetermination was $650.0 million. The revolving credit facility is redetermined semi-annually on April 1 and October 1, subject to changes in the oil and gas reserves.

Further, because the majority of the managing general partner’s proved reserves are currently natural gas reserves, the managing general partner’s net worth is more susceptible to movements in natural gas prices than in oil prices.

The managing general partner’s net worth may not be sufficient, either currently or in the future, to meet its financial commitments under the partnership agreement. These risks are increased because the managing general partner has made similar financial commitments in most of its other partnerships and will make this same commitment in future partnerships. In addition, because of the current credit crisis in the United States, there is a risk that ATN’s credit facility could be adversely affected. See “Financial Information Concerning the Managing General Partner and Atlas Resources Public #18-2009(C) L.P.”

An Investment in the Partnership Must be for the Long-Term Because the Units Are Illiquid and Not Readily Transferable. If you invest in the partnership, then you must assume the risks of an illiquid investment. The transferability of the units is limited by the securities laws, the tax laws, and the partnership agreement. The units generally cannot be liquidated since there is not a readily available market for the sale of the units. Further, the partnership does not intend to list the units on any exchange. (See “Transferability of Units – Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership Agreement.”)

Also, a sale of your units could create adverse tax and economic consequences for you. The sale or exchange of all or part of your units held for more than 12 months generally will result in a recognition of long-term capital gain or loss. However, previous deductions for depreciation, depletion and intangible drilling costs may be recaptured as ordinary income rather than capital gain regardless of how long you have owned your units. If you have held your units for 12 months or less, then the gain or loss generally will be short-term gain or loss. Also, your pro rata share of the partnership’s liabilities, if any, as of the date of the sale or exchange of your units must be included in the amount realized by you. Thus, the gain recognized by you may result in a tax liability greater than the cash proceeds, if any, received by you from the sale or other disposition of your units, if permitted under the partnership agreement. (See “Federal Income Tax Consequences – Disposition of Units” and “Presentment Feature.”)

Spreading the Risks of Drilling Among a Number of Wells Will be Reduced if Less than the Maximum Subscription Proceeds are Received and Fewer Wells are Drilled. The partnership must receive minimum subscription proceeds of $2 million to close the offering, and the subscription proceeds may not exceed $275,695,000. There are no other requirements regarding the size of the partnership. A partnership with a smaller amount of subscription proceeds will drill fewer wells, which would decrease the partnership’s ability to spread the risks of drilling. For example, the managing general partner anticipates that the partnership will drill approximately one .98 net well if the minimum subscriptions of $2 million are received, which is compared with approximately 164.75 net wells if the maximum subscription proceeds of $275,695,000 are received. See “Compensation – Drilling Contracts” for a discussion of the estimated average well cost in each of the primary and secondary areas discussed in “Proposed Activities.” A gross well is a well in which a partnership owns a working interest. This is compared with a net well which is the sum of the fractional working interests owned in the gross wells. For example, a 50% working interest owned in three wells is three gross wells, but 1.5 net wells.

On the other hand, to the extent more than the minimum subscription proceeds are received by the partnership and the number of wells drilled increases, the partnership’s overall investment return may decrease if the managing general partner is unable to find enough suitable wells to be drilled. (See “Proposed Activities – Acquisition of Leases.”) Also, to the extent the partnership’s subscription proceeds and number of wells it drills increase, greater demands will be placed on the managing general partner’s management capabilities.

In addition, the cost of drilling and completing a well is often uncertain and there may be cost overruns in drilling and completing the wells, because the wells will not be drilled and completed on a turnkey basis for a fixed price that would shift certain risks of loss from the partnership to the managing general partner as drilling contractor. In this regard, all of the intangible drilling costs and a majority of the equipment costs of the partnership’s wells will be charged to you and the other investors in the partnership, and the managing general partner will pay the remaining portion of the equipment costs. If the partnership incurs a cost overrun in drilling or completing a well or wells that is allocable to you and the other investors for your share of those costs, then the managing general partner anticipates that it would use the partnership’s subscription proceeds, if available, to pay the portion of the cost overrun charged to you and the other investors under the partnership agreement or advance the necessary funds to the partnership. Using subscription proceeds to pay cost overruns charged to you and the other investors under the partnership agreement may result in the partnership drilling fewer wells. See “Appendix A – Information Regarding Currently Proposed Prospects for Atlas Resources Public #18-2009(C) L.P.”

Increases in the Costs of the Wells May Adversely Affect Your Return. Increases in natural gas and oil prices over the last several years increased the demand for drilling rigs and other related equipment and the costs of drilling and completing natural gas and oil wells also increased. As of the date of this prospectus, however, the demand for drilling rigs, as well as equipment costs, have decreased since 2008. Because the partnership’s wells will be drilled on a modified cost plus basis as described in “Compensation – Drilling Contracts,” the cost to drill and complete the partnership’s wells could be greater than those estimated by the managing general partner in “Use of Proceeds” and “Compensation”. For example, as compared with 2007, the managing general partner estimates that its drilling and completion costs for vertical wells increased by approximately 9% in 2008. This means that if an increase in natural gas and oil prices occurs before the partnership drills its wells, and causes the drilling costs for the partnership’s wells to increase, which is not assured since the prices are volatile, then fewer wells will be drilled by the partnership than it would have drilled if the drilling and completion costs of the wells had not increased.

On the other hand, if the price of natural gas and oil decreases before the partnership’s wells are drilled, the drilling and completion costs of the wells to be drilled by the partnership would, in all likelihood, not be affected since the managing general partner believes that, in the short term, drilling and completion costs are not likely to be reduced by a drop in natural gas and oil prices. Also, a reduced availability of drilling rigs and other related equipment may make it more difficult to drill the partnership’s wells in a timely manner or to comply with the prepaid intangible drilling costs rules discussed in “Federal Income Tax Consequences – Drilling Contracts.”

The Partnership Does Not Own Any Prospects, the Managing General Partner Has Complete Discretion to Select Which Prospects Are Acquired By the Partnership, and the Possible Lack of Information for a Majority of the Prospects Decreases Your Ability to Evaluate the Feasibility of the Partnership. The partnership does not currently hold any interests in any prospects on which the wells will be drilled, and the managing general partner has absolute discretion in determining which prospects will be acquired to be drilled. The managing general partner has identified in “Proposed Activities” the general areas where the partnership will drill wells and the managing general partner intends that the partnership will drill the prospects described in “Appendix A – Information Regarding Currently Proposed Prospects for Atlas Resources Public #18-2009(C) L.P.” These prospects represent only some of the wells to be drilled by the partnership if it receives the maximum subscription proceeds.

If there are material adverse events with respect to any of the currently proposed prospects, the managing general partner will substitute a new prospect. With respect to the identified prospects to be drilled by the partnership, the managing general partner has the right on behalf of the partnership to:

substitute prospects;

take a lesser working interest in the prospects;

drill in other areas; or

do any combination of the foregoing.

Thus, you do not have any geological or production information to evaluate any additional and/or substituted prospects and wells. Also, if the subscription proceeds received by the partnership are insufficient to drill all of the identified prospects, then the managing general partner will choose those prospects which it believes are most suitable for the partnership. You must rely entirely on the managing general partner to select the prospects and wells for the partnership.

In addition, the partnership does not have the right of first refusal in the selection of prospects from the inventory of the managing general partner and its affiliates, and they may sell their prospects to other partnerships, companies, joint ventures, or other persons at any time. Also, the managing general partner and its affiliates may elect to drill a well for their own account because of the prospective economic benefits. For example, because the partnership agreement limits the amount of revenue that may be received by the managing general partner and its affiliates from the partnership, it may be more advantageous for the managing general partner and its affiliates to drill the well for their own account since other arrangements are not subject to these limits. See “Appendix A – Information Regarding Currently Proposed Prospects for Atlas Resources Public #18-2009(C) L.P.”

Drilling Prospects in One Area May Increase Risk. If multiple wells are drilled by the partnership in one area at approximately the same time, which is anticipated because of drilling commitments, rig availability or commitments made by ATN, then there is a greater risk that two or more of the wells will be marginal or nonproductive since the managing general partner will not be using the drilling results of one or more of those wells to decide whether or not to continue drilling prospects in that area or to substitute other prospects in other areas. This is contrasted with the situation in which the partnership drills one well in an area, and then assesses the drilling results before it decides to drill a second well in the same area or to substitute a different prospect in another area. (See “Appendix A – Information Regarding Currently Proposed Prospects for Atlas Resources Public #18-2009(C) L.P.”)

This risk is further increased with respect to wells for which the drilling and completing costs are prepaid in one year, and the drilling of the wells must begin within the first 90 days of the immediately following year under the tax laws associated with deducting the intangible drilling costs of the prepaid wells in the year in which the prepayment is made, rather than the year in which the wells are drilled. For example, even though the partnership may prepay in the year you invest the costs of drilling one or more wells to be drilled in the next year, potential bad weather conditions during the first 90 days of the next year could delay beginning the drilling of one or more of the prepaid wells beyond the 90 day time limit under the tax laws. This would have a greater adverse effect on the partnership’s deduction in the year you invest in the partnership for prepaid intangible drilling costs if the managing general partner is required to begin drilling many wells at the same time, rather than only a few wells, and would increase the risk as described above. Also, “frost laws” prohibit drilling rigs and other heavy equipment from using certain roads during the winter, which may delay beginning the drilling of the prepaid wells within the 90 day time limit in the next tax year under the tax laws. In addition, there could be shortages of drilling rigs, equipment, supplies and personnel during this time period, or unexpected operational events and drilling conditions, which could delay the partnership’s drilling activities.

As discussed in “Risk Factors – Federal Income Tax Risks – The Partnership’s Deductions May be Challenged by the IRS,” each well prepaid in 2009 by the partnership must be spudded by March 31, 2010 or the deduction for intangible drilling costs will not be available for the 2009 tax year and will be deferred to the 2010 tax year in which the wells are actually drilled. See “Federal Income Tax Consequences – Drilling Contracts” regarding prepaid wells and the 90 day time constraint.

Lack of Production Information Increases Your Risk and Decreases Your Ability to Evaluate the Feasibility of the Partnership’s Drilling Program. Production information from wells previously drilled in the area surrounding the location where a new well is proposed to be drilled is an important indicator in evaluating the economic potential of the well proposed to be drilled. However, generally there will be little or no production information from surrounding wells for the majority of the wells to be drilled by your partnership, which results in greater uncertainty to you and the other investors. This lack of production information results primarily from the managing general partner, as operator, proposing wells to be drilled by the partnership that are adjacent to wells it has previously drilled as operator in prior partnerships that have not yet been completed, have not yet been put on-line to sell production, or have been producing for only a short period of time so there is little or no production information available. This risk is further increased for vertical and horizontal wells proposed to be drilled in the Marcellus Shale primary area and horizontal wells proposed to be drilled in the north central Tennessee secondary area and the New Albany Shale (Indiana) primary area since the managing general partner has limited production information for vertical wells drilled to the Marcellus Shale and limited experience in drilling horizontal wells in the Marcellus Shale, north central Tennessee, and New Albany Shale (Indiana) areas. Also, there is little or no production information for offsetting horizontal wells in these areas. See “Appendix A – Information Regarding Currently Proposed Prospects for Atlas Resources Public #18-2009(C) L.P.” and the production data associated with each of the primary areas as set forth in Appendix A.

Additionally, if the managing general partner was not the operator of a previously drilled well in Pennsylvania or Indiana, then the production information is not available if the well was drilled within the last five years in Pennsylvania since the Pennsylvania Department of Environmental Resources keeps production data confidential for the first five years from the time a well starts producing, and production information in Indiana is not publicly available through the Indiana Department of Natural Resources.

The Partnerships In This Program and Other Partnerships Sponsored by the Managing General Partner May Compete With Each Other for Prospects, Equipment, Subcontractors, and Personnel. The partnerships in this program and other partnerships sponsored by the managing general partner or joint ventures in which the managing general partner and its affiliates participate may have unexpended capital funds at the same time. Thus, these partnerships or joint ventures may compete for suitable prospects, equipment, subcontractors, and the services of the managing general partner’s personnel. For example, a partnership previously organized by the managing general partner may still be acquiring prospects to drill when the partnership is attempting to acquire its prospects. This may make it more difficult for the partnership to complete its prospect acquisition and drilling activities and may make the partnership less profitable. Conversely, it is possible that the partnership and other affiliated partnerships may enter into joint ventures with respect to drilling activities, which would reduce this risk to some degree. Also, the managing general partner and its affiliates may choose to drill certain wells for their own account.

Managing General Partner’s Subordination is Not a Guarantee of the Return of Any of Your Investment. If your cumulative cash distributions from the partnership are less than a 10% return of capital for each of the first five 12-month periods beginning with the partnership’s first cash distribution from operations, then the managing general partner has agreed to subordinate a portion of its share of the partnership’s net production revenues. However, if the wells produce only small natural gas and oil volumes, and/or natural gas and oil prices decrease, then even with subordination you may not receive the 10% return of capital for each of the first five years as described above, or a return of your capital during the term of the partnership. Also, at any time during the subordination period the managing general partner is entitled to an additional share of partnership revenues to recoup previous subordination distributions to the extent your cash distributions from the partnership exceed the 10% return of capital described above. (See “Participation in Costs and Revenues – Subordination of Portion of Managing General Partner’s Net Revenue Share.”)

Borrowings by the Managing General Partner Could Reduce Funds Available for Its Subordination Obligation. With respect to the partnership, the managing general partner has, or will, pledge either its partnership interest and/or an undivided interest in the partnership’s assets equal to or less than its revenue interest, which will be no less than 25%, but depends on the amount of its capital contribution to the partnership, to secure borrowings for its and its affiliates’ general purposes. (See “Participation in Costs and Revenues” and “Conflicts of Interest – Conflicts Regarding Managing General Partner Withdrawing or Assigning an Interest.”) Under agreements previously entered into as described in “Management’s Discussion and Analysis of Financial Condition, Results of Operations, Liquidity and Capital Resources,” the managing general partner’s lenders have required a first lien on the managing general partner’s interest in the natural gas and oil properties and other assets of the partnership, and the lenders will have priority over the managing general partner’s subordination obligation under the partnership agreement for the partnership. The borrowing base of the credit facility increased to $850 million in connection with Atlas Energy Resources, LLC’s acquisition of DTE Gas & Oil Company in 2007 as described in “Management.” If there was a default by the managing general partner to the lenders under this pledge arrangement, or if there was a default by an affiliate of the managing general partner under this pledge arrangement or another loan secured by this pledge arrangement, the amount of the partnership’s net production revenues available to the managing general partner for its subordination obligation to you and the other investors would be reduced or eliminated. Also, under certain circumstances, if the managing general partner made a subordination distribution to you and the other investors after a default to its lenders, then the lenders may be able to recoup that subordination distribution from you and the other investors. In addition, there is a risk that the current credit crisis in the United States could adversely affect ATN’s credit facility.

Compensation and Fees to the Managing General Partner Regardless of Success of the Partnership’s Activities Will Reduce Cash Distributions. The managing general partner and its affiliates will profit from their services in drilling, completing, and operating the partnership’s wells, and will receive the other fees and reimbursement of direct costs described in “Compensation,” regardless of the success of the partnership’s wells. These fees and direct costs will reduce the amount of cash distributions to you and the other investors. The amount of the fees is subject to the complete discretion of the managing general partner, other than the fees must not exceed competitive fees charged by unaffiliated third-parties in the same geographic area engaged in similar businesses and they must comply with any other restrictions set forth in “Compensation.” With respect to direct costs, the managing general partner has sole discretion on behalf of the partnership to select the provider of the services or goods and the provider’s compensation as discussed in “Compensation.”

The Intended Monthly Distributions to Investors May be Reduced or Delayed. Cash distributions to you and the other investors may not be paid each month. Distributions may be reduced or deferred, in the discretion of the managing general partner, to the extent the partnership’s revenues are used for any of the following:

compensation and fees to the managing general partner as described above in “– Compensation and Fees to the Managing General Partner Regardless of Success of the Partnership’s Activities Will Reduce Cash Distributions”;

repayment of borrowings;

cost overruns;

remedial work to improve a well’s producing capability, including additional fracs for wells in the Marcellus Shale;

direct costs and general and administrative expenses of the partnership;

reserves, including a reserve for the estimated costs of eventually plugging and abandoning the wells; or

indemnification of the managing general partner and its affiliates by the partnership for losses or liabilities incurred in connection with the partnership’s activities.

(See “Participation in Costs and Revenues – Distributions.”)

There Are Conflicts of Interest Between the Managing General Partner and the Investors. There are conflicts of interest between you and the other investors and the managing general partner and its affiliates. These conflicts of interest, which are not otherwise discussed in this “Risk Factors” section, include the following:

the managing general partner has determined the compensation and reimbursement that it and its affiliates will receive in connection with the partnership without any unaffiliated third-party dealing at arms’ length on behalf of you and the other investors;

the managing general partner must monitor and enforce, on behalf of the partnership, its own compliance with the drilling and operating agreement and the partnership agreement and the compliance of it and its affiliate, Laurel Mountain, with the gas gathering agreements;

because the managing general partner will receive a percentage of revenues greater than the percentage of costs that it pays, there may be a conflict of interest concerning which wells will be drilled based on each wells’ risk and profit potential;

the allocation of all intangible drilling costs and the majority of the equipment costs to you and the other investors and only a portion of the equipment costs to the managing general partner may create a conflict of interest concerning whether to complete a well;

if the managing general partner, as tax matters partner, represents the partnership before the IRS, potential conflicts include, for example, whether or not to expend partnership funds to contest a proposed adjustment by the IRS, if any, to the amount of your deduction for intangible drilling costs, or the credit to the managing general partner’s capital account for contributing the leases to the partnership;

which wells will be drilled by the managing general partner’s and its affiliates’ other affiliated partnerships, third-party programs or joint ventures with third-parties, in which they serve as driller/operator and which wells will be drilled by the partnership, and the terms on which the partnership’s leases will be acquired;

ATN’s policies and procedures for allocating hedging production volumes and hedging settlements between it and its partnerships, including the partnership, as described in “Proposed Activities – Sale of Natural Gas and Oil Production – Natural Gas Contracts,” are not set forth in any formal written agreements. Also, as the managing general partner continues to sponsor natural gas and oil drilling partnerships in the future, the interests of its existing partnerships, including the partnership, in the risks and benefits of ATN’s hedging agreements may be diluted unless ATN continues its hedging activities as the new partnerships produce additional natural gas reserves;

subject to certain limitations described in “Conflicts of Interest – Conflicts Involving the Acquisition of Leases,” the managing general partner will have complete discretion in determining the terms on which it or its affiliated limited partnerships may purchase producing wells from the partnership;

the managing general partner and its officers, directors, and affiliates may purchase units at a reduced price, which would dilute the voting rights of you and the other investors on certain matters;

the same legal counsel represents the managing general partner and the partnership;

Laurel Mountain, an affiliate of the managing general partner, has the right to determine the order of priority for constructing gathering lines for the partnership’s wells that will connect to its gathering system; and

Laurel Mountain, an affiliate of the managing general partner, will benefit from the partnership drilling wells that will connect to its gathering system.

Other than certain guidelines set forth in “Conflicts of Interest,” the managing general partner has no established procedures to resolve a conflict of interest. Also, the partnership does not have an independent investment committee. Thus, certain matters, including conflicts of interest between the partnership and the managing general partner and its affiliates such as those described above or set forth in “Conflicts of Interest,” may not be resolved as favorably to you and the other investors as they would be if there was an independent investment committee.

The Presentment Obligation May Not Be Funded and the Presentment Price May Not Reflect Full Value. Subject to certain conditions, beginning with the fifth calendar year after the offering of units in the partnership closes you may present your units to the managing general partner for purchase. However, the managing general partner may determine, in its sole discretion, that it does not have the necessary cash flow or cannot borrow funds for this purpose on reasonable terms. In either event the managing general partner may suspend the presentment feature. This risk is increased because the managing general partner has and will incur similar presentment obligations in other partnerships.

Further, the presentment price for your units may not reflect the full value of the partnership’s property or your units because of the difficulty in accurately estimating natural gas and oil reserves. 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 the reserve estimate is a function of the quality of the available data and of engineering and geological interpretation and judgment. Also, the reserves and future net revenues are based on various assumptions as to natural gas and oil prices, taxes, development expenses, capital expenses, operating expenses and availability of funds. Any significant variance in these assumptions, including the price of natural gas, could materially affect the estimated quantity of the reserves. As a result, the managing general partner’s estimates are inherently imprecise and may not correspond to realizable value. Thus, the presentment price paid for your units and the amount of any partnership distributions received by you before the presentment may be less than the subscription amount you paid for your units. However, because the presentment price is a contractual price under the partnership agreement, it is not reduced by discounts for minority interests and lack of marketability that generally are used to value partnership interests for tax and other purposes, but it is subject to discounts for purposes of determining present value and the amount to be paid. (See “Presentment Feature.”)

Finally, see “– An Investment in the Partnership Must be for the Long-Term Because the Units Are Illiquid and Not Readily Transferable,” above, concerning the tax effects on you of presenting your units for purchase.

The Managing General Partner May Not Devote the Necessary Time to the Partnership Because Its Management Obligations Are Not Exclusive. The partnership does not have any employees and must rely on the managing general partner and its affiliates for the management of the partnership and its business, and the managing general partner and its affiliates may not devote the necessary time to the partnership, which is in the managing general partner’s discretion. Also, the managing general partner depends on its indirect parent companies, Atlas America and ATN and their affiliates, for management and administrative functions as discussed in “Management – Transactions with Management and Affiliates.”

The managing general partner and its affiliates will be engaged in other oil and gas activities, including other partnerships, joint ventures and drilling and unrelated business ventures for their own account or for the account of others, during the term of the partnership. Thus, the competition for time and services of the managing general partner and its affiliates could result in insufficient attention to the management and operation of the partnership.

Prepaying Subscription Proceeds to the Managing General Partner May Expose the Subscription Proceeds to Claims of the Managing General Partner’s Creditors. Under the drilling and operating agreement, the partnership will be required to immediately pay the managing general partner, acting as general drilling contractor, the investors’ share of the entire estimated price for drilling and completing the partnership’s wells. Thus, these funds could be subject to claims of the managing general partner’s creditors. (See “Financial Information Concerning the Managing General Partner and Atlas Resources Public #18-2009(C) L.P.”)

Lack of Independent Underwriter May Reduce Due Diligence Investigation of the Partnership and the Managing General Partner. There has not been an extensive in-depth “due diligence” investigation of the existing and proposed business activities of the partnership and the managing general partner that would be provided by independent underwriters. Anthem Securities, which is affiliated with the managing general partner, serves as dealer-manager and will receive reimbursement of bona fide due diligence expenses, which it will reallow to the selling agents, for certain due diligence investigations conducted by the selling agents. However, Anthem Securities’ due diligence examination concerning the partnership cannot be considered to be independent, nor as comprehensive as an investigation that would have been conducted by an independent broker/dealer. (See “Conflicts of Interest.”)

A Lengthy Offering Period May Result in Delays in the Investment of Your Subscription and Any Cash Distributions From the Partnership to You. Because the offering period for the partnership can extend for many months, there may be a delay in the investment of your subscription proceeds. This may create a delay in the partnership’s cash distributions to you which will be paid only after a portion of the partnership’s wells have been drilled, completed and placed on-line for the delivery and sale of natural gas and/or oil, and payment has been received from the purchaser of the natural gas and/or oil. Also, distributions of the partnership’s net production revenues will be made only after payment of the managing general partner’s fees and expenses and only if there is sufficient cash available in the managing general partner’s discretion. See “Terms of the Offering” for a discussion of the procedures involved in the offering of the units and the formation of the partnership.

The Partnership is Subject to Comprehensive Federal, State and Local Laws and Regulations That Could Increase the Cost and Alter the Manner or Feasibility of the Partnership’s Doing Business. Your partnership’s 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, the partnership could also be liable for personal injuries, property damage and other damages. In addition, failure to comply with these laws and regulations may result in the suspension or termination of the partnership’s operations and subject the partnership to administrative, civil and criminal penalties.

Part of the regulatory environment in which the partnership will operate includes, in some cases, legal requirements for obtaining environmental assessments, water disposal plans, environmental impact studies and/or plans of development before beginning drilling and production activities. In addition, the partnership’s activities are subject to regulations regarding conservation practices and protection of correlative rights. Further, 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, thus, reduce the partnership’s profitability. The partnership may be put at a competitive disadvantage as compared to larger companies in the oil and gas industry that can spread these additional regulatory compliance costs over a greater number of wells. See “Proposed Activities – Primary Areas of Operation” and “ – Secondary Areas of Operations” for a discussion of water disposal from partnership wells, and “Competition, Markets and Regulation,” for a more detailed description of the laws and regulations that affect the partnerships.

Your Interests May Be Diluted. The equity interests of you and the other investors in the partnership may be diluted. You and the other investors will share in the partnership’s production revenues from all of its wells in proportion to your respective number of units, based on $10,000 per unit, regardless of:

when you subscribe;

which wells are drilled with your subscription proceeds; or

the actual subscription price you paid for your units as described below.

Thus, investors who pay discounted prices for their units will receive higher returns on their investments in the partnership as compared to investors who pay the entire $10,000 per unit.

Although subscription proceeds received by the partnership in different closings may be used to pay the costs of drilling different wells depending on when the subscriptions are received, 85% of the subscription proceeds of you and the other investors in the partnership will be used to pay intangible drilling costs regardless of when you subscribe. However, the revenues from all of the wells drilled in the partnership will be commingled regardless of when you subscribe and regardless of which wells were drilled with the subscription proceeds in your closing and the results of those wells.

Also, some investors, including the managing general partner and its officers and directors as described in “Plan of Distribution,” may buy up to 5% of the total units in the partnership at discounted prices because the dealer-manager fee, the sales commission and the reimbursement for bona fide due diligence expenses will not be paid for those sales.

Due to the Accounting Treatment of the Partnership’s Derivative Contracts, Increases in Prices for Natural Gas and Oil Could Result in Non-Cash Balance Sheet Reductions. Atlas America, its affiliates and its partnerships enter into natural gas and oil derivative contracts and account for these derivative contracts by applying the provisions of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Due to the mark-to-market accounting treatment for these contracts, Atlas America, its affiliates and its partnerships could recognize incremental hedge liabilities between reporting periods resulting from increases in reference prices for natural gas and oil, which could result in Atlas America, its affiliates and the partnerships recognizing a non-cash loss in their accumulated other comprehensive income (loss) and a consequent non-cash decrease in their members’ equity between reporting periods. Any such decrease could be substantial.

A Decrease in Natural Gas Prices Could Subject the Partnership’s and the Managing General Partner’s Oil and Gas Properties to an Impairment Loss under Generally Accepted Accounting Principles. Generally accepted accounting principles require oil and gas properties and other long-lived assets to be 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 partnership and the managing general partner will test their oil and gas properties on a field-by-field basis, by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the partnership’s or the managing general partner’s own economic interests and their 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 partnership and the managing general partner estimate prices based on current contracts in place at the impairment testing date, adjusted for basis differentials and 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. Accordingly, declines in the price of natural gas have caused the carrying values of properties in many Atlas partnerships to exceed the expected future cash flow. In this regard, in May 2009 the price of natural gas dropped to $3.32 per mcf, which was its lowest price since September, 2002. See “Prior Activities” for the Atlas partnerships that have suffered impairment losses in their respective financial statements. Further declines in the price of natural gas may cause the carrying value of the partnership’s or the managing general partner’s oil and gas properties to exceed the expected future cash flows, and require an impairment loss to be recognized. (See “Prior Activities.”)

Federal Income Tax Risks

Changes in the Law May Reduce Your Tax Benefits From an Investment in the Partnership. Your tax benefits from an investment in the partnership may be affected by changes in the tax laws. For example, President Obama’s administration has proposed, among other tax changes, the repeal on January 1, 2011, of certain oil and gas tax benefits, including the repeal of the percentage depletion allowance, the election to expense intangible drilling costs (including the further option to amortize intangible drilling costs over a 60 month period), the passive activity exception for working interests and the marginal production tax credit. (See “Federal Income Tax Consequences.”) These proposals may or may not be enacted into law. The repeal of the percentage depletion allowance, if it happens, would result in a substantial decrease in your future tax benefits from an investment in your partnership. Since the repeal of the intangible drilling costs deduction is not proposed until 2011, it will not affect your claim to deduct your share of the partnership’s intangible drilling costs in 2009. Also, President Obama’s administration is proposing to raise the top federal income tax rate of 35% to 38.6% beginning with the 2011 taxable year which would increase your potential federal income tax liability from your share of the partnership’s net taxable income, if any. Also, federal income tax rates could be changed even before January 1, 2011, and other changes in the tax laws could be made that would reduce your tax benefits from an investment in the partnership. (See “Federal Income Tax Consequences.”)

Your Deduction for Intangible Drilling Costs May Be Limited for Purposes of the Alternative Minimum Tax. You will be allocated a share of your partnership’s deduction for intangible drilling costs in the year you invest in an amount equal to 85% of the subscription price you pay for your units. Under current tax law, however, your alternative minimum taxable income in the year you invest cannot be reduced by more than 40% by your deduction for intangible drilling costs without creating a tax preference. (See “Federal Income Tax Consequences – Alternative Minimum Tax.”)

Limited Partners Need Passive Income to Use Their Deduction for Intangible Drilling Costs. If you invest in the partnership as a limited partner (except as discussed below), your share of the partnership’s deduction for intangible drilling costs in the year you invest will be a passive loss that cannot be used to offset “active” income, such as salary and bonuses, or portfolio income, such as dividends and interest income. Thus, you may not have enough passive income from the partnership or net passive income from your other passive activities, if any, in the year you invest, to offset a portion or all of your passive deduction for intangible drilling costs in the year you invest. However, any unused passive loss from intangible drilling costs may be carried forward indefinitely by you to offset your passive income in subsequent taxable years. Also, except as described below, the passive activity limitations on your share of the partnership’s deduction for intangible drilling costs in the year you invest do not apply to you if you invest in the partnership as a limited partner and you are a C corporation which:

is not a personal service corporation or a closely held corporation;

is a personal service corporation in which employee-owners hold 10% (by value) or less of the stock, but is not a closely held corporation; or

is a closely held corporation (i.e., five or fewer individuals own more than 50% (by value) of the stock), but is not a personal service corporation in which employee-owners own more than 10% (by value) of the stock, in which case you may use your passive losses to offset your net active income (calculated without regard to your passive activity income and losses or portfolio income and losses).

(See “Federal Income Tax Consequences – Limitations on Passive Activity Losses and Credits.”)

You May Owe Taxes in Excess of Your Cash Distributions from Your Partnership. You may become subject to income tax liability for your share of your partnership’s income in any taxable year in an amount that is greater than the cash and any marginal well production credits you receive from the partnership in that taxable year. For example:

if the partnership borrows money, your share of partnership revenues used to pay principal on the loan will be included in your income from the partnership and will not be deductible;

income from sales of natural gas and oil may be included in your income from the partnership in one tax year, although payment is not actually received by the partnership and, thus, cannot be distributed to you, until the next tax year;

if there is a deficit in your capital account, the partnership may allocate income or gain to you even though you do not receive a corresponding distribution of partnership revenues;

the partnership’s revenues may be expended by the managing general partner for nondeductible costs or retained in the partnership to establish a reserve for future estimated costs, including a reserve for the estimated costs of eventually plugging and abandoning the wells, which will reduce your cash distributions from the partnership without a corresponding tax deduction; and

the taxable disposition of the partnership’s property or your units may result in income tax liability to you in excess of the cash you receive from the transaction.

Investment Interest Deductions of Investor General Partners May Be Limited. If you invest in the partnership as an investor general partner, your share of the partnership’s deduction for intangible drilling costs in the year you invest will reduce your investment income and may limit the amount of your deductible investment interest expense, if any.

Your Tax Benefits from an Investment in the Partnership Are Not Contractually Protected. An investment in the partnership does not give you any contractual protection against the possibility that part or all of the intended tax benefits of your investment will be disallowed by the IRS. No one provides any insurance, tax indemnity or similar agreement for the tax treatment of your investment in the partnership. You have no right to rescind your investment in the partnership or to receive a refund of any of your investment in the partnership if a portion or all of the intended tax consequences of your investment in the partnership is ultimately disallowed by the IRS or the courts. Also, none of the fees paid by the partnership to the managing general partner, its affiliates or independent third-parties (including special counsel which issued the tax opinion letter) are refundable or contingent on whether the intended tax consequences of your investment in the partnership are ultimately sustained if challenged by the IRS.

An IRS Audit of Your Partnership May Result in an IRS Audit of Your Personal Federal Income Tax Returns. The IRS may audit the partnership’s annual federal information income tax returns, particularly since the partnership’s investors will be eligible to claim a deduction equal to not less than 85% of their investment amount in the year they invest, which includes their respective deductions for intangible drilling costs. If the partnership is audited, the IRS also may audit your personal federal income tax returns, including prior years’ returns and items that are unrelated to the partnership. (See “Federal Income Tax Consequences.”)

The Partnership’s Deductions May be Challenged by the IRS. If the IRS audits the partnership, it may challenge the amount of the partnership’s deductions and the taxable year in which the deductions were claimed, including the deductions for intangible drilling costs and depreciation. Any adjustments made by the IRS to the federal information income tax returns of the partnership could lead to adjustments on your personal federal income tax returns and could reduce the amount of your deductions from the partnership in the year you invest and subsequent tax years. The IRS also could seek to recharacterize a portion of the partnership’s intangible drilling costs for drilling and completing its wells as some other type of expense, such as lease costs or equipment costs, which would reduce or defer your share of the partnership’s deductions for those costs. (See “Federal Income Tax Consequences – Business Expenses,” “– Depreciation and Cost Recovery Deductions,” and “– Drilling Contracts.”)

In addition, depending primarily on when its subscription proceeds are received, it is possible that the partnership may prepay in the year you invest most or all of its intangible drilling costs for wells the drilling of which will not begin until the next year. In that event, you will not receive a deduction in the year you invest for your share of the partnership’s prepaid intangible drilling costs for those wells unless the drilling of the prepaid wells begins on or before the 90th day following the close of the partnership’s taxable year in which the prepayment was made. Under the drilling and operating agreement, the drilling of all of the partnership’s prepaid wells, if any, will be required to begin within that 90 day time period. However, the drilling of any partnership well may be delayed due to circumstances beyond the control of the managing general partner, acting as general drilling contractor, without liability to the managing general partner. For example, if prepayment of a well is made in the year you invest and for any reason the drilling of the well does not begin within the required 90 day time period in the next tax year, your deduction for prepaid intangible drilling costs for that well must be claimed for your tax year in which the drilling of the well begins, instead of the tax year in which you invest.

Also, there is a greater risk that the IRS will attempt to defer your share of the partnership’s deduction for intangible drilling costs for drilling and completing any prepaid partnership wells from the tax year in which the prepayment is made by the partnership to the next tax year if there are other additional working interest owners of a prepaid well, because those other working interest owners will not be required to prepay their share of the costs of drilling and completing the wells. (See “Federal Income Tax Consequences – Drilling Contracts.”)

It May Be Many Years Before You Receive Any Marginal Well Production Credits, If Ever. Currently there is a federal income tax credit for the sale of qualified marginal natural gas and oil production, which may be repealed as discussed above. The managing general partner anticipates that some of the partnership’s natural gas and oil production will be qualified production for purposes of this tax credit. However, natural gas and oil production sold by the partnership may be sold at prices above the applicable reference prices at which the marginal well production credit is reduced to zero, and this could happen in the early years of the partnership when the production from the partnership’s wells generally is the greatest. Thus, you may not receive any marginal well production credits from the partnership for many years, if ever. (See “Federal Income Tax Consequences – Marginal Well Production Credits.”)

ADDITIONAL INFORMATION

The program and the partnerships composing the program, other than Atlas Resources Public #18-2008(A) L.P., which closed its offering on December 31, 2008, currently are not required to file reports with the SEC. However, a registration statement on Form S-1 has been filed on behalf of the program with the SEC. Certain portions of the registration statement have been deleted from this prospectus under SEC rules and regulations. You are urged to refer to the registration statement, as amended, including its post-effective amendments, for further information concerning the provisions of certain documents referred to in this prospectus.

You may read and copy any materials filed as a part of the registration statement, including the tax opinion included as Exhibit 8.1, at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Also, the SEC maintains an internet world wide web site that contains registration statements, reports, proxy statements, and other information about issuers who file electronically with the SEC, including the partnerships composing the program. The address of that site is http://www.sec.gov. Additionally, you may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Finally, a copy of the tax opinion may be obtained by you or your advisors from the managing general partner at no cost. The delivery of this prospectus does not imply that its information is correct as of any time after its date.

FORWARD LOOKING STATEMENTS AND ASSOCIATED RISKS

Statements, other than statements of historical facts, included in this prospectus and its exhibits address activities, events or developments that the managing general partner and the partnership anticipate will or may occur in the future. For example, the words “believes,” “anticipates,” “will” and “expects” are intended to identify forward-looking statements. These forward-looking statements include such things as:

investment objectives;

references to future success in the partnership’s drilling and marketing activities;

business strategy;

estimated future capital expenditures;

competitive strengths and goals; and

other similar matters.

These statements are based on certain assumptions and analyses made by the partnership and the managing general partner in light of their experience and their perception of historical trends, current conditions, and expected future developments. However, whether actual results will conform with these expectations is subject to a number of risks and uncertainties, many of which are beyond the control of the partnership and the managing general partner, including, but not limited to:

general economic, market, or business conditions;

changes in laws or regulations, including the federal income tax laws;

the risk that the wells are productive, but do not produce enough revenue to return the investment made;

the risk that the wells are dry holes; and

uncertainties concerning the price of natural gas and oil, which may decrease.

Thus, all of the forward-looking statements made in this prospectus and its exhibits are qualified by these cautionary statements. There can be no assurance that actual results will conform with the managing general partner’s and the partnership’s expectations.

INVESTMENT OBJECTIVES

The partnership’s principal investment objectives are to invest its subscription proceeds in natural gas development wells which will:

Provide monthly cash distributions to you from the partnership until the wells are depleted.

The partnership currently does not hold any interests in any prospects on which the wells will be drilled.

Obtain tax deductions from the partnership in the year that you invest from intangible drilling costs to offset a portion of your taxable income from sources other than the partnership, subject to the passive activity limitations on losses if you invest as a limited partner.

Most states also allow this type of a deduction against the state income tax. If the partnership begins selling natural gas and oil production from its wells in the year in which you invest, however, then you may be allocated a share of partnership income in that year that will be offset by a portion of your intangible drilling cost deduction and your share of the other partnership deductions discussed below.

Offset a portion of any gross production income generated by your partnership with tax deductions from percentage depletion, which is 15%, although gross production income from “marginal wells,” as defined in the Code, is eligible for potentially higher rates of percentage depletion. In this regard, the managing general partner anticipates that some of the natural gas and oil production from the partnership’s productive wells will be classified as marginal production for federal tax purposes. The applicable percentage depletion rate for gross income from marginal production is 15% in 2009. During the lifetime of the partnership’s marginal wells, however, the applicable percentage depletion rate may fluctuate from year to year, depending on the price of oil, but under current tax law it will not be less than the statutory rate of 15% nor more than 25%.

Obtain tax deductions through depreciation of the equipment costs of the wells over a seven-year cost recovery period, beginning in the year the wells are drilled, completed and placed in service for the production of natural gas or oil in the partnership.

If you are self-employed and invest in the partnership as an investor general partner, then you may use your share of the partnership’s deduction for intangible drilling costs to offset a portion of your net earnings from self-employment in the year you invest. Also, if wells in the partnership are drilled and completed and placed in service in the year you invest, you will begin receiving the depreciation deductions discussed above which, to the extent they exceed your share of your partnership’s income, if any, in the year in which you invest, also will reduce your net earnings from self-employment in the year you invest.

The proposed repeal of the percentage depletion allowance, if it happens, would result in a substantial decrease in your future tax benefits from an investment in your partnership. Since the repeal of the intangible drilling costs deduction is not proposed to take effect until 2011, however, it will not affect your claim to deduct your share of the partnership’s intangible drilling costs in 2009. (See “Risk Factors – Federal Income Tax Risks – Changes in the Law May Reduce Your Tax Benefits from an Investment in the Partnership.”)

Attainment of these investment objectives by your partnership will depend on many factors, including the ability of the managing general partner to select suitable wells that will be productive and produce enough revenue to return the investment made. The success of your partnership depends largely on future economic conditions, especially the future price of natural gas, which is volatile and may decrease. Also, the extent to which your partnership attains the foregoing investment objectives will be different as compared with the prior partnerships in the program, because each partnership is a separate business entity which:

generally will drill different wells;

may receive a different amount of subscription proceeds, which generally will be the primary factor in determining the number of wells that can be drilled by a partnership; and

may drill wells situated in different geographical areas with different formations, reservoirs or depths, which will affect the cost of the wells and, thus, will also affect the number of wells that can be drilled by a partnership.

There can be no guarantee that the foregoing objectives will be attained.

ACTIONS TO BE TAKEN BY MANAGING GENERAL
PARTNER TO REDUCE RISKS OF ADDITIONAL
PAYMENTS BY INVESTOR GENERAL PARTNERS

You may choose to invest in the partnership as an investor general partner so that you can claim an immediate federal income tax deduction for your share of the partnership’s intangible drilling costs, which can be used against any type of income. To help reduce the risk that you and other investor general partners could be required to make additional payments to the partnership, the managing general partner will take the actions set forth below.

Insurance. The managing general partner will obtain and maintain insurance coverage in amounts and for purposes that would be carried by a reasonable, prudent general contractor and operator in accordance with industry standards. The partnership will be included as an insured under these general, umbrella, and excess liability policies. In addition, the managing general partner requires all of its subcontractors to certify that they have acceptable insurance coverage for worker’s compensation and general, auto, and excess liability coverage. Major subcontractors are required to carry general and auto liability insurance with a minimum of $1 million combined single limit for bodily injury and property damage in any one occurrence or accident. In the event of a loss caused by a major subcontractor, the managing general partner or the partnership may attempt to draw on the insurance policy of the particular subcontractor before the insurance of the managing general partner or that of the partnership, but currently may be unable to do so since only some of its major subcontractors may have insurance which would allow this. Also, even if a major subcontractor’s insurance was initially available, the managing general partner or the partnership may choose to draw on its own insurance coverage before that of the major subcontractor so that its insurance carrier will control the payment of claims.

The managing general partner’s current insurance coverage satisfies the following specifications:

worker’s compensation insurance in full compliance with the laws of the Commonwealth of Pennsylvania and any other applicable state laws where the wells will be drilled;

commercial general liability covering bodily injury and property damage third party liability, including products/completed operations, blow out, cratering, and explosion with limits of $1 million per occurrence/$2 million general aggregate; and $1 million products/completed operations aggregate;

underground resources and equipment property damages liability to others with a limit of $1 million;

automobile liability with a $1 million combined single limit;

employer’s liability with a $500,000 policy limit;

pollution liability resulting from a “pollution incident,” which is defined as the discharge, dispersal, seepage, migration, release or escape of one or more pollutants directly from a well site, with a limit of $1 million for bodily injury and property damage and a limit of $100,000 for clean-up for third-parties; however, coverage does not apply to pollution damage to the well site itself or the property of the insured;

control-of-well for pre-completion activities with varying limits on a well-by-well basis, up to $15 million per well for horizontal Marcellus Shale wells with respect to cost of well control and fire fighting, restoration of a blown-out well, seepage/pollution control and down-hole coverage for contractors’ tools, although each insured well has a single combined limit, which means that coverage amounts must be allocated among the four items covered in this paragraph on a well-by-well basis;

commercial umbrella liability composed of:

primary umbrella limit of $25 million over general liability, automobile liability, and employer’s liability and a $10 million sublimit for pollution liability; and

excess liability providing excess limits of $24 million over the $25 million provided in the commercial umbrella, which is for general liability only.

Because the managing general partner is driller and operator of wells for other partnerships, the insurance available to the partnership could be substantially less if insurance claims are made in the other partnerships.

This insurance has deductibles, which would first have to be paid by the partnership, of:

$2,500 per occurrence for bodily injury and property damage; and

$10,000 per pollution incident for pollution damage.

The control-of-well insurance described above is subject to separate deductibles on a well-by-well basis which are determined based on the depth of the insured well, and the minimum deductible is $100,000 per well and the maximum deductible is $300,000 per well.

The insurance also has terms, including exclusions, that are standard for the natural gas and oil industry. On request the managing general partner will provide you or your representative a copy of its insurance policies. The managing general partner will use its best efforts to maintain insurance coverage that meets its current coverage, but it may be unsuccessful if the coverage becomes unavailable or too expensive.

If you are an investor general partner and there is going to be a material adverse change in your partnership’s insurance coverage, which the managing general partner does not anticipate, then the managing general partner will notify you at least 30 days before the effective date of the change. You will then have the right to convert your units into limited partner units before the change in insurance coverage by giving written notice to the managing general partner.

Conversion of Investor General Partner Units to Limited Partner Units. Your investor general partner units will be automatically converted by the managing general partner to limited partner units after all of the wells in your partnership have been drilled and completed. In this regard, a well is deemed to be completed when production equipment is installed on a well, even though the well may not yet be connected to a pipeline for production of natural gas. The managing general partner anticipates that all of the wells will be drilled and completed no more than 12 months after the offering of your partnership closes, and the conversion will occur before the end of the succeeding tax year. However, if the maximum subscription proceeds are received by the partnership, then it may take longer for all of its wells to be drilled and completed than if fewer units were sold in the partnership and there were fewer wells to be drilled and completed. This would delay conversion of the investor general partner units to limited partner units since the managing general partner will not convert the investor general partner units to limited partner units in the partnership until after all of the partnership’s wells have been drilled and completed.

Once your units are converted, which is a nontaxable event, you will have the lesser liability of a limited partner in your partnership under Delaware law for obligations and liabilities arising after the conversion. However, you will continue to have the responsibilities of a general partner for partnership liabilities and obligations incurred before the effective date of the conversion. For example, you might become liable for partnership liabilities in excess of your subscription amount during the time the partnership is engaged in drilling activities and for environmental claims that arose during drilling activities, but were not discovered until after the conversion.

Nonrecourse Debt. The partnership does not anticipate that it will borrow funds. However, if borrowings are required, then the partnership will be permitted to borrow funds only from the managing general partner or its affiliates and without recourse against non-partnership assets. Thus, if there is a default by your partnership under this loan arrangement you cannot be required to contribute funds to the partnership. Any borrowings by the partnership will be repaid from the partnership’s revenues and assets.

The amount that may be borrowed at any one time by the partnership may not exceed an amount equal to 5% of the investors’ subscription proceeds in the partnership. However, because you do not bear the risk of repaying these borrowings with non-partnership assets, the borrowings will not increase the extent to which you are allowed to deduct your individual share of partnership losses. (See “Federal Income Tax Consequences – Tax Basis of Units” and “– ‘At Risk’ Limitation on Losses.”) Notwithstanding, this limitation will not affect the partnership’s ability to enter into agreements and financial instruments relating to hedging the partnership’s natural gas and oil and pledging up to 100% of the partnership’s assets and reserves in connection therewith.

Indemnification. The managing general partner will indemnify you from any liability incurred in connection with your partnership that is in excess of your interest in the partnership’s:

undistributed net assets; and

insurance proceeds, if any, from all potential sources.

The managing general partner’s indemnification obligation, however, will not eliminate your potential liability if the managing general partner’s assets are insufficient to satisfy its indemnification obligation. There can be no assurance that the managing general partner’s assets, including its liquid assets, will be sufficient to satisfy its indemnification obligation. The managing general partner has agreed to this indemnification obligation in 56 of its prior partnerships.

CAPITALIZATION AND SOURCE OF FUNDS AND USE OF PROCEEDS

Source of Funds

The partnership must receive minimum subscription proceeds of $2 million to close, and the subscription proceeds may not exceed $275,695,000, which is the remaining portion of the unsold units from the original $600 million registration. There are no other requirements regarding the size of the partnership. (See “Terms of the Offering – Subscription to the Partnership.”)

On completion of the offering of units in the partnership, the partnership’s source of funds will be as follows assuming each unit is sold for $10,000:

the subscription proceeds of you and the other investors, which will be:

$2 million if 200 units are sold; and

$275,695,000 if 27,569.5 units are sold; and

the managing general partner’s capital contribution, which must be at least 15% of all capital contributions to the partnership and includes its credit for organization and offering costs, contributing the leases and paying the portion of the Tangible Costs in excess of 15% of the partnership’s subscription proceeds, including its administration and oversight fee and 18% mark up on the portion of the Tangible Costs paid by it, which will be:

approximately $352,941 if 200 units are sold; and

approximately $48,652,059 if 27,569.5 units are sold.

Thus, the total amount available to the partnership will be not less than approximately $2,352,941 if 200 units are sold ranging to not less than approximately $324,347,059 if 27,569.5 units are sold.

The managing general partner has made the largest single capital contribution in each of its prior partnerships and no individual investor has contributed more, although the total investor contributions in each partnership have exceeded the managing general partner’s contribution. The managing general partner also expects to make the largest single capital contribution in the partnership.

Use of Proceeds

The subscription proceeds received from you and the other investors will be used by the partnership as follows:

85% of the subscription proceeds will be used to pay 100% of the intangible drilling costs of drilling and completing the partnership’s wells; and

15% of the subscription proceeds will be used to pay equipment costs of drilling and completing the partnership’s wells.

In this regard, the managing general partner anticipates that the maximum subscription proceeds of the partnership will be allocated among the partnership’s proposed drilling areas as follows:

approximately 79% in the Marcellus Shale primary area in western Pennsylvania;

approximately 13% in the New Albany Shale (Indiana) primary area;

approximately 4% in the north central Tennessee secondary area; and

approximately 4% in the Antrim Shale secondary area in Michigan.

(See “Appendix A – Information Regarding Currently Proposed Prospects for Atlas Resources Public #18-2009(C) L.P.”)

The managing general partner considers a proposed drilling area to be a primary area if it expects to use 10% or more of the partnership’s subscription proceeds to drill wells in the area. The percentages set forth above, however, are estimates and may change materially depending on actual drilling results. (See “Proposed Activities – Primary Areas of Operation” and “– Secondary Areas of Operations.”)

The managing general partner will contribute all of the leases to the partnership covering the acreage on which the partnership’s wells will be drilled, and pay all of the equipment costs of drilling and completing the partnership’s wells that exceed 15% of the partnership’s subscription proceeds. The managing general partner also will be charged with 100% of the organization and offering costs for the partnership. A portion of these contributions to the partnership will be in the form of payments to itself, its affiliates and third-parties and the remainder will be in the form of services related to organizing this offering. The managing general partner will receive a credit towards its required capital contribution to the partnership for these payments and services as discussed in “Participation in Costs and Revenues.”

The following tables present information concerning the partnership’s use of the proceeds provided by both you and the other investors and the managing general partner. The tables are based in part on the managing general partner’s estimate of its capital contribution to the partnership based on the applicable number of units sold as shown in the table. The managing general partner’s estimated capital contribution shown in the tables is greater than its minimum required capital contribution of 15% of total capital contributions. Anthem Securities, an affiliate of the managing general partner, will be the dealer-manager of the offering and it will receive the dealer-manager fee, the sales commissions and the up to .5% reimbursement for bona fide due diligence expenses. A portion of these payments and reimbursements, including all of the reimbursement for bona fide due diligence expenses, will be reallowed by the dealer-manager to the broker/dealers, which are referred to as selling agents as discussed in “Plan of Distribution.” Subject to the above, the partnership’s organizational costs will be paid to the managing general partner, its affiliates and various third-parties, and the intangible drilling costs and tangible costs of drilling and completing the partnership’s wells will be paid to the managing general partner as general drilling contractor and operator under the drilling and operating agreement.

The tables are presented based on:

the sale of 200 units ($2 million), which is the minimum number of units for the partnership; and

the sale of 27,569.5 units ($275,695,000), which are all of the remaining unsold units from the original 60,000 units ($600 million) registered.

Substantially all of the proceeds available to the partnership will be expended for the following purposes and in the following manner:

INVESTOR CAPITAL

NATURE OF PAYMENT	200 UNITS SOLD		% (1)			27,569.5 UNITS SOLD		% (1)
Organization and Offering Expenses

Dealer-manager fee, sales commissions and reimbursement for bona fide due diligence expenses (2)		- 0 -		- 0 -			- 0 -		- 0 -
Organization costs		- 0 -		- 0 -			- 0 -		- 0 -
Amount Available for Investment:

Intangible drilling costs (3)	$	1,700,000		85	%	$	234,340,750		85	%
Equipment costs (3)	$	300,000		15	%	$	41,354,250		15	%
Leases		- 0 -		- 0 -			- 0 -		- 0 -
Total Investor Capital	$	2,000,000		100	%	$	275,695,000		100	%

(1)	The percentage is based on the investors’ total subscription proceeds, and excludes the managing general partner’s estimate of its capital contributions as set forth in the “– Managing General Partner Capital” table below.

(2)	See “Plan of Distribution” regarding the limits on reimbursements for bona fide due diligence expenses.

(3)

Eighty-five percent of the subscription proceeds provided by you and the other investors to the partnership will be used to pay 100% of the partnership’s intangible drilling costs. Fifteen percent of the subscription proceeds provided by you and the other investors to the partnership will be used to pay the majority of the partnership’s equipment costs. (See “Participation in Costs and Revenues.”) The managing general partner will pay all of the remaining equipment costs of the partnership. In this regard, the managing general partner’s share of the partnership’s equipment costs as set forth in the “– Managing General Partner Capital” and “– Total Partnership Capital” tables below is based on the managing general partner’s estimate of the average cost of drilling and completing wells in the partnership as discussed in “Compensation – Drilling Contracts.”

MANAGING GENERAL PARTNER CAPITAL

NATURE OF PAYMENT	200 UNITS SOLD		% (1)			27,569.5 UNITS SOLD		% (1)
Organization and Offering Expenses
Dealer-manager fee, sales commissions and reimbursement for bona fide due diligence expenses (2)	$	200,000		45.24	%	$	27,569,500		54.06	%
Organization costs (2)	$	100,000		22.62	%	$	5,193,943		10.19	%
Amount Available for Investment:
Intangible drilling costs		- 0 -		- 0 -			- 0 -		- 0 -
Equipment costs (3)	$	122,469		27.70	%	$	13,843,503		27.15	%
Leases (4)	$	19,600		4.44	%	$	4,387,980		8.60	%
Total Managing General Partner Capital	$	442,069		100	%	$	50,994,926		100	%

(1)	The percentage is based on the managing general partner’s estimate of its capital contributions, and excludes the investors’ total subscription proceeds set forth in the “– Investor Capital” table above.

(2)

As discussed in “Participation in Costs and Revenues,” if these fees, sales commissions, reimbursements and organization costs exceed 15% of the investors’ total subscription proceeds in the partnership, then the excess will be charged to the managing general partner, but will not be included as part of its capital contribution. See “Plan of Distribution” regarding the limits on reimbursements for bona fide due diligence expenses. Also, if all of the remaining units are sold the managing general partner’s organization costs may be up to 5% of the investors’ subscription proceeds (i.e., up to $13,784,750), which is materially greater than the estimated organization costs set forth above.

(3)

The managing general partner’s share of equipment costs is described in “Compensation – Drilling Contracts” and “Participation in Costs and Revenues.” However, these costs will vary depending on the actual equipment costs of drilling and completing the wells. Also, see footnote (3) to the “– Investor Capital” table above.

(4)

Instead of contributing cash for the leases, the managing general partner will assign to the partnership the leases covering the acreage on which the partnership’s wells will be drilled. Generally, as described in “Compensation – Lease Costs,” the managing general partner’s lease costs are approximately $20,000 per prospect for vertical wells in the Marcellus Shale primary area, horizontal wells in the north central Tennessee secondary area and vertical wells in the Antrim Shale (Michigan) secondary area, $45,000 per prospect for wells drilled horizontally in the Marcellus Shale primary area as described in “Proposed Activities – Primary Areas of Operations – Marcellus Shale Geological Formation in Western Pennsylvania,” $50,000 per prospect for the horizontal wells in the New Albany Shale (Indiana) primary area, and $11,310 per prospect in the north central Tennessee secondary area for wells that are not drilled horizontally. For purposes of this table, the managing general partner’s lease costs have been quantified based on its estimate of the number of net wells that will be drilled with the amount of subscription proceeds available as set forth in the “– Managing General Partner Capital” table above. The actual number of net wells drilled by the partnership is likely to vary from the managing general partner’s estimate, based primarily on where the wells are drilled and the actual costs of drilling and completing the wells. Also, the managing general partner’s lease costs on a prospect may be significantly higher than the above-referenced amounts, and its credit for the leases contributed will equal its cost, unless it has a reason to believe that cost is materially more than fair market value of the property, in which case its credit for its lease contribution must not exceed fair market value.

TOTAL PARTNERSHIP CAPITAL

NATURE OF PAYMENT	200 UNITS SOLD		% (1)			27,569.5 UNITS SOLD		% (1)
Organization and Offering Expenses
Dealer-manager fee, sales commissions and reimbursement for bona fide due diligence expenses (2)	$	200,000		8.19	%	$	27,569,500		8.44	%
Organization costs (2)	$	100,000		4.10	%	$	5,193,943		1.59	%
Amount Available for Investment:
Intangible drilling costs (3)	$	1,700,000		69.61	%	$	234,340,750		71.73	%
Equipment costs (3)	$	422,469		17.30	%	$	55,197,753		16.90	%
Leases (4)	$	19,600		0.80	%	$	4,387,980		1.34	%
Total Partnership Capital	$	2,442,069		100	%	$	326,689,926		100	%

(1)	The percentage is based on investors’ total subscription proceeds in the “– Investor Capital” table above, and the managing general partner’s estimate of its capital contributions in the “– Managing General Partner Capital” table above.

(2)

(3)

The managing general partner’s share of equipment costs is described in “Compensation – Drilling Contracts” and “Participation in Costs and Revenues.” Although these costs will vary depending on the actual equipment costs of drilling and completing the wells, 85% of the subscription proceeds provided by you and the other investors will be used to pay intangible drilling costs and 15% will be used to pay equipment costs. Also, see footnote (3) to the “– Investor Capital” table, above.

(4)	Instead of contributing cash for the leases, the managing general partner will assign to the partnership the leases covering the acreage on which the partnership’s wells will be drilled as set forth in footnote (4) to the “– Managing General Partner Capital” table above.

COMPENSATION

The items of compensation to be paid to the managing general partner and its affiliates from the partnership are set forth below. Also, following the narrative discussion for all items of compensation is a tabular presentation based on the narrative discussion. Most of these items of compensation depend on how many wells the partnership drills and how much of the working interest in each of the wells is owned by the partnership. In this regard, the managing general partner estimates that approximately a .98 net well, which is 1 gross well, will be drilled if the minimum required subscription proceeds are received by the partnership, and approximately 164.75 net wells, which is approximately 170 gross wells, will be drilled if the maximum subscription proceeds are received by the partnership. A gross well is a well in which a partnership owns a working interest. This is compared with a net well, which is the sum of the fractional working interests owned in the gross wells. For example, a 50% working interest owned in three wells is three gross wells, but 1.5 net wells.

If $275,695,000 is raised by the partnership, which represents the remaining subscription proceeds from the program, after deducting the subscription proceeds of $324,305,000, including discounted units as permitted by the prospectus, received by Atlas Resources Public #18-2008(A) L.P. and Atlas Public Resources #18-2009(B) L.P., the managing general partner has provided its estimate of:

the number of wells that will be drilled by Atlas Resources Public #18-2009(C) L.P.;

the partnership’s weighted average cost to drill and complete a well in each of the two primary drilling areas and the two secondary areas; and

the managing general partner’s estimated compensation from the partnership for its services as general drilling contractor and operator during the drilling and completion operations for all of the estimated number of the partnership’s wells. (See “– Lease Costs” and “– Drilling Contracts.”)

However, these estimates by the managing general partner are based on certain assumptions including, but not limited to, the following:

the number of partnership wells that will be drilled and completed in each primary and secondary area;

the amount of subscription proceeds received by the partnership;

the cost of equipment and services to be provided by both third-party and affiliated subcontractors, and

the partnership’s percentage of the working interest in the wells and prospects in each primary and secondary area.

The actual results of the partnership’s drilling activities will be different from the managing general partner’s assumptions and estimates for various reasons, including those set forth in “Risk Factors – Risks Related to an Investment in the Partnership – The Partnership Does Not Own Any Prospects, the Managing General Partner Has Complete Discretion to Select Which Prospects Are Acquired By the Partnership, and the Possible Lack of Information for a Majority of the Prospects Decreases Your Ability to Evaluate the Feasibility of the Partnership.” Thus, the actual results of the drilling and completion operations of the partnership, including the amount of the managing general partner’s compensation from your partnership for serving as general drilling contractor and operator during your partnership’s drilling and completion operations, will vary from the managing general partner’s assumptions and estimated well costs, and the variations could be material.

Dealer-Manager Fees

Subject to certain exceptions described in “Plan of Distribution,” Anthem Securities, the dealer-manager and an affiliate of the managing general partner, will receive on each unit sold to an investor:

a 2.5% dealer-manager fee;

a 7% sales commission; and

an up to .5% reimbursement of the selling agents’ bona fide due diligence expenses.

Assuming the above amounts are paid for all units sold, the dealer-manager will receive:

$200,000 if subscription proceeds of $2 million are received by the partnership; and

$27,569,500 if subscription proceeds of $275,695,000 are received.

All of the reimbursement of the selling agents’ bona fide due diligence expenses, and generally all of the sales commissions, will be reallowed to the selling agents. A portion of the 2.5% dealer-manager fee will be reallowed to the wholesalers who are associated with the managing general partner and registered through Anthem Securities for subscriptions obtained through their efforts. Also, a portion of the dealer-manager fee may be reallowed to the selling agents as described in “Plan of Distribution.” The dealer-manager will retain any of the compensation that is not reallowed. See “Management” for the ownership of Anthem Securities.

Natural Gas and Oil Revenues

Subject to the managing general partner’s subordination obligation, the investors and the managing general partner will share in the partnership’s revenues in the same percentages as their respective capital contributions bear to the total partnership capital contributions to the partnership, except that the managing general partner will receive an additional 10% of the partnership’s revenues.

For example, if the managing general partner contributes the minimum of 15% of the partnership’s total capital contributions and the investors contribute 85% of the partnership’s total capital contributions, then the managing general partner will receive 25% of the partnership’s revenues and the investors will receive 75% of the partnership’s revenues as shown in the bar chart set forth below.

As noted above, up to 50% of the managing general partner’s share of partnership net production revenues is subject to its subordination obligation as described in “Participation in Costs and Revenues – Subordination of Portion of Managing General Partner’s Net Revenue Share” and the accompanying tables. For example, if the managing general partner’s revenue share is 25% of the partnership’s revenues, then up to 12.5% of the managing general partner’s partnership net production revenues could be used for its subordination obligation.

Lease Costs

Under the partnership agreement the managing general partner will contribute to the partnership all the undeveloped leases necessary to cover each of the partnership’s prospects. The managing general partner will receive a credit to its capital account equal to:

the cost of the leases; or

the fair market value of the leases if the managing general partner has reason to believe that cost is materially more than the fair market value.

The managing general partner anticipates that its lease costs in the Marcellus Shale primary area for vertical wells, the (horizontal) north central Tennessee secondary area and vertical wells in the Antrim Shale secondary area in Michigan will be approximately $20,000 per prospect, assuming the partnership acquires 100% of the working interest in the prospect. In other areas, including the Devonian Shale reservoirs with respect to vertical wells in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee, the managing general partner’s estimated lease costs generally are approximately $11,310 per prospect, assuming the partnership acquires 100% of the working interest in the prospect. Lease costs will be approximately $45,000 per prospect for horizontal wells in the Marcellus Shale primary area and $50,000 per prospect for the horizontal wells in the New Albany Shale (Indiana) primary area, assuming the partnership acquires 100% of the working interest in the prospect. The managing general partner averaged the lease costs of its leases in the areas described above, which it believes is less than fair market value based on information it has concerning lease costs of third-party operators in the areas described above.

Notwithstanding, the managing general partner’s lease costs on a prospect may be significantly higher than the average lease costs set forth above, and in that event the managing general partner’s credit to its capital contribution to the partnership and its capital account under the partnership agreement will be the greater amount. The cost of the leases includes a portion of the managing general partner’s reasonable, necessary and actual expenses for geological, engineering, drafting, accounting, legal and other like services allocated to the leases in conformity with generally accepted accounting principles and industry standards.

The managing general partner’s credit for its lease costs for a prospect will be proportionally reduced to the extent the partnership acquires less than 100% of the working interest in the prospect. In this regard, a working interest generally means an interest in the lease under which the owner of the working interest must pay some portion of the cost of development, operation, or maintenance of the well. The managing general partner estimates that its total credit for lease costs will be approximately:

$19,600 if the minimum subscription proceeds are received; and

$4,387,980 if the maximum subscription proceeds are received.

Drilling the partnership’s wells also may provide the managing general partner with offset prospects to be drilled by it, its affiliates or its other partnerships by allowing it to determine at the partnership’s expense the value of adjacent acreage in which the partnership would not have any interest. Further, the managing general partner may cause the partnership to drill wells on leases that are scheduled to expire in order to prevent the expiration of the lease.

Drilling Contracts

The partnership will enter into the drilling and operating agreement with the managing general partner, acting as a third-party general drilling contractor and operator, to drill and complete the partnership’s wells for an amount equal to the sum of the following items: (i) the cost of permits, supplies, materials, equipment, and all other items used in the drilling and completion of a well provided by third-parties, or if the foregoing items are provided by affiliates of the managing general partner, then those items will be charged at competitive rates; (ii) fees for third-party services; (iii) fees for services provided by the managing general partner’s affiliates, which will be charged at competitive rates; (iv) an administration and oversight fee which generally is $15,000 per well, but which is $62,087 per vertical well in the Marcellus Shale primary area and per horizontal well in the north central Tennessee secondary area, $46,577 per horizontal well in the New Albany Shale (Indiana) primary area, $15,526 per vertical well in the north central Tennessee and Antrim Shale (Michigan) secondary areas, and $248,349 per horizontal well in the Marcellus Shale primary area, which will be charged to you and the other investors as part of each well’s intangible drilling costs and the portion of equipment costs paid by you and the other investors; and (v) a mark-up in an amount equal to 18% of the sum of (i), (ii), (iii) and (iv), above, for the managing general partner’s services as general drilling contractor. Notwithstanding, if the managing general partner drills a well for the partnership that it determines is not an average well in the area because of the well’s depth, complexity associated with either drilling or completing the well or as otherwise determined by the managing general partner, the administration and oversight fee for the well described in §4.02(d)(1)(iv) of the partnership agreement may be increased to a competitive rate as determined by the managing general partner. In this regard, the managing general partner has determined that the administration and oversight fee for a well drilled in the Marcellus Shale and the New Albany Shale (Indiana) primary areas, and a well drilled horizontally in the north central Tennessee secondary area, should be higher than for the wells drilled in other areas, because a well drilled in those areas will be drilled either substantially deeper or horizontally, which makes the well more complex to drill and complete and takes a longer period of time to drill and complete. Based on those factors, the managing general partner has determined that the administration and oversight fees listed above are reasonable and competitive.

The managing general partner has determined that the cost of drilling and completing the partnership’s wells as set forth above is a competitive rate based on:

information it has concerning drilling rates of third-party operators in the areas where the partnership’s wells will be drilled;

the estimated costs of non-affiliated persons to drill and equip wells in the Appalachian Basin as reported for 2006 in a survey prepared by the Independent Petroleum Association of America; and

information it has concerning increases in drilling costs in these areas since 2006.

If the cost of drilling and completing the partnership’s wells as set forth above subsequently exceeds competitive rates available from non-affiliated persons in the area engaged in the business of rendering or providing comparable services or equipment, then the rate will be adjusted to the competitive rate. Additionally, the 18% mark-up will not be increased by the managing general partner during the term of the partnership.

During drilling operations, the managing general partner’s duties as operator and general drilling contractor will include:

making the necessary arrangements for drilling and completing the wells and related facilities for which it has responsibility under the drilling and operating agreement;

managing and conducting all field operations in connection with drilling, testing, and equipping the wells; and

making the technical decisions required in drilling and completing the wells.

See “Proposed Activities – Drilling and Completion Activities; Operation of Producing Wells” for a more detailed discussion of the services to be provided to the partnership by the managing general partner as general drilling contractor. The managing general partner expects to subcontract some of the actual drilling and completion of the partnership’s wells to third-parties selected by it as well as to its affiliates. The managing general partner may not benefit by interpositioning itself between the partnership and the actual provider of drilling contractor services, and may not profit by drilling in contravention of its fiduciary obligations to the partnership. However, the managing general partner’s affiliates may charge a competitive rate for their services if they meet the requirements described in “Conflicts of Interest – Conflicts Regarding Transactions with the Managing General Partner and its Affiliates.”

The cost of each partnership well includes all of the ordinary costs of drilling, testing and completing the well. This includes the cost of the following items with respect to each natural gas well, which will be the classification of the majority of the wells:

multiple fracs and completions, which generally means treating separately all potentially productive geological formations in an attempt to enhance the natural gas production from the well;

installing gathering lines of up to 2,500 feet per well to connect the well’s natural gas production to a pipeline; and

the necessary surface facilities for producing natural gas from the well.

The amount paid to the managing general partner for drilling and completing a partnership well will be proportionately reduced to the extent the partnership acquires less than 100% of the working interest in the prospect. In addition, the amount of compensation that the managing general partner could earn as a result of these arrangements depends on many other factors as well, including the following:

where the wells are drilled and their depths;

the method used to complete the well; and

the number of wells drilled.

The managing general partner’s estimated average cost for the partnership to drill and complete one net well in each of the primary and secondary areas, which includes the portion of equipment costs (“Tangible Costs”) paid by the managing general partner, but does not include the lease costs or organization and offering costs paid or contributed to the partnership by the managing general partner, is set forth in the table below:

Area (1)	Administration and Oversight Fee		Total Estimated Weighted Average Cost Per Net Well, Excluding Lease Costs, But Including 18% Mark-Up and Administration and Oversight Fee		Estimated % of Tangible Costs of Well			Estimated % of Intangible Costs of Well

(1) Vertical Well in Marcellus Shale in Western Pennsylvania (2)	$	62,241	$	2,174,935		19.5	%		80.5	%
(2) Horizontal Well in Marcellus Shale in Western Pennsylvania (2)	$	248,964	$	5,275,633		12.3	%		87.7	%
(3) Vertical Well in Mississippian Carbonate and Devonian Shale Reservoirs in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee (3)	$	15,700	$	379,476		20.9	%		79.1	%
(4) Horizontal Well in Mississippian Carbonate and Devonian Shale Reservoirs in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee (3)	$	62,241	$	1,112,017		14.6	%		85.4	%
(5) Horizontal Well in Upper Devonian New Albany Shale Reservoir, Knox and Sullivan Counties, Indiana	$	47,018	$	1,293,095		21.9	%		78.1	%
(6) Vertical Well in Upper Devonian Antrim Shale Reservoir, Antrim and Alcona Counties, Michigan	$	15,700	$	441,773		34.3	%		65.7	%

(1)

The partnership’s cost of drilling and completing any given well in the areas described above, excluding lease costs, may be considerably more or less than the amounts estimated by the managing general partner as described above, depending primarily on the area where the well is situated and unanticipated cost overruns.

(2)

The managing general partner anticipates that approximately 79% of the partnership’s maximum subscription proceeds will be expended on drilling approximately 88.75 net wells, which is approximately 94 gross wells, in the Marcellus Shale primary area. At the date of this prospectus only a portion of the Marcellus Shale prospects for Atlas Resources Public #18-2009(C) L.P. have been specified in Appendix A. Also, it is anticipated that approximately 12% of the partnership’s wells in the Marcellus Shale may be drilled horizontally.

(3)

Approximately one-half of the wells drilled in Tennessee will be drilled horizontally rather than vertically.

Based on the well costs set forth above, the managing general partner anticipates that the partnership’s weighted average cost of drilling and completing approximately 164.75 net wells, which is approximately 170 gross wells, excluding lease costs, but including the portion of Tangible Costs paid by the managing general partner, will be approximately $1,783,129 per net well, which includes the administration and oversight fee described in the table above and the 18% mark-up per well paid to the managing general partner for its services as general drilling contractor. This estimate also was based on the managing general partner’s estimate of:

the number of wells, including horizontal wells, that will be drilled in each primary and secondary area by the partnership;

the percentage of working interest that the partnership will acquire in the prospects in each area; and

the estimated drilling and completion costs of the wells to be drilled by the partnership, which are different for wells in each area, primarily because of different depths of the wells and different completion methods.

Thus, the managing general partner’s estimated weighted average cost of drilling and completing one net partnership well as set forth above will vary from the actual weighted average cost of drilling and completing wells in each of the primary and secondary areas and for the partnership’s wells as a whole. Based on the assumptions set forth above, the managing general partner’s estimated weighted average administration and oversight fee of $64,502 per net well, plus its estimated weighted average 18% mark-up of approximately $259,346 per net well will total $323,848 per net well with respect to the intangible drilling costs and the portion of equipment costs paid by you and the other investors. Also, if only the minimum subscription proceeds are received by the partnership, the managing general partner anticipates that the partnership will drill only one vertical well in the Marcellus Shale primary area in western Pennsylvania. The actual compensation received by the managing general partner as a result of the partnership’s drilling operations will vary from these estimates, and the managing general partner anticipates that the partnership will acquire less than 100% of the working interest in some of its prospects.

Subject to the foregoing, the managing general partner estimates that its administration and oversight fee and its 18% mark-up paid by you and the other investors will be:

$317,371 if the minimum subscription proceeds are received by the partnership, which is one .98 net vertical Marcellus Shale well times $323,848; and

$53,353,958 if the maximum subscription proceeds are received by the partnership, which is 164.75 net wells times $323,848.

Additionally, affiliates of the managing general partner will provide subcontracting services, equipment and materials in drilling, completing or operating the partnership’s wells for which they will receive competitive rates, because they meet the requirements described in “Conflicts of Interest – Conflicts Regarding Transactions with the Managing General Partner and its Affiliates.” Thus, the total compensation paid to the managing general partner and its affiliates per net partnership well will be greater than the estimated amount to be paid to the managing general partner for the partnership’s wells as described above to the extent compensation is paid by the partnership to the managing general partner’s affiliates for services, equipment or supplies they provide to the partnership.

The managing general partner’s estimated weighted average cost of $1,783,129, including horizontal wells, for one net partnership well to be drilled and completed as discussed above, consists of intangible drilling costs of approximately $1,445,134 (81%), and equipment costs of approximately $337,995 (19%).

Per Well Charges

Under the drilling and operating agreement the managing general partner, as operator of the wells, will receive the following compensation from the partnership when the wells begin producing natural gas or oil:

reimbursement at actual cost for all direct expenses incurred on behalf of the partnership; and

well supervision fees at a competitive rate for operating and maintaining the wells during producing operations.

The direct expenses are third-party expenses such as water hauling and chart calibration.

Currently the competitive rate for well supervision fees is $392 per well per month in the primary areas and the secondary areas discussed in “Proposed Activities,” except that in the Marcellus Shale primary area and the (horizontal) north central Tennessee secondary area the well supervision fee is $975 per well per month, in the New Albany Shale (Indiana) primary area the well supervision fee is $1,500 per well per month and in the Antrim Shale secondary area in Michigan the well supervision fee is $600 per well per month.

The well supervision fees described above will be proportionately reduced to the extent the partnership acquires less than 100% of the working interest in the well. Also, the managing general partner’s well supervision fees may be adjusted annually beginning with the first calendar year after the partnership closes for inflation since January 1, 2009. If the managing general partner’s well supervision fee would exceed a competitive rate in the area where the well is situated, then the rate will be adjusted to the competitive rate. Conversely, if in the future the managing general partner’s well supervision fees set forth above would be less than a competitive rate in an area where a well is situated, then regardless of the inflation adjustment, the rate may be increased automatically to the competitive rate from time to time by the managing general partner, as operator, as determined in its sole discretion. The managing general partner may not benefit by interpositioning itself between the partnership and the actual provider of operator services. In no event will any consideration received for operator services be duplicative of any consideration or reimbursement received under the partnership agreement.

The well supervision fee covers all normal and regularly recurring operating expenses for the production, delivery, and sale of natural gas and oil, such as:

well tending, routine maintenance, and adjustment;

reading meters, recording production, pumping, maintaining appropriate books and records; and

preparing reports to the partnership and to government agencies.

The well supervision fees do not include costs and expenses related to:

the purchase of equipment, materials, or third-party services;

water hauling; and

rebuilding of access roads.

These costs will be charged to the partnership at the invoice cost of the materials purchased or the third-party services performed.

The managing general partner estimates that it will receive well supervision fees for the partnership’s first 12 months of operation in the primary and secondary areas discussed in “Proposed Activities” after all of the wells have been placed in production of:

$11,466 if the minimum subscription proceeds are received, which is one .98 net vertical Marcellus Shale well at $975 per net well per month; and

$1,925,607 if the maximum subscription proceeds are received, which is 164.75 net wells at various well supervision fees as described above.

Gathering Fees

Under the partnership agreement the managing general partner will be responsible for gathering and transporting the natural gas produced by the partnership to interstate pipeline systems, local distribution companies, and/or end-users in the area (the “gathering services”). The managing general partner anticipates that it will use the gathering system owned by Laurel Mountain for the partnership’s natural gas production in the Marcellus Shale primary area, which it expects will comprise the majority of the partnership’s natural gas production, as described in “Proposed Activities – Sale of Natural Gas and Oil Production – Gathering of Natural Gas.” Also, Atlas America, LLC, ATN and certain of their affiliates as described in “Proposed Activities – Sale of Natural Gas and Oil Production – Gathering of Natural Gas,” which are sometimes referred to collectively in this prospectus as the “Atlas entities,” and do not include the partnership, have an agreement with Laurel Mountain under which generally all of the gas produced by their affiliated partnerships, which does include the partnership, will be gathered and transported through the gathering system owned by Laurel Mountain and the Atlas entities must pay the greater of $.35 per mcf or 16% of the gross sales price to Laurel Mountain for each mcf transported by these affiliated partnerships, including the partnership, through Laurel Mountain’s gathering system. Gross sales price means the price that is actually received, adjusted to take into account proceeds received or payments made pursuant to hedging arrangements. Subject to the gas gathering agreements with Laurel Mountain, described above, in providing the gathering services the managing general partner may use gathering systems owned by Laurel Mountain, independent third-parties and/or affiliates of Atlas America other than Laurel Mountain to gather gas for the partnership.

The partnership will pay a gathering fee directly to the managing general partner at competitive rates for the gathering services. The gathering fee paid by the partnership to the managing general partner may be increased from time-to-time by the managing general partner, in its sole discretion, but may not be increased beyond competitive rates as determined by the managing general partner. Currently, the managing general partner has determined that the competitive rate in each of its primary and secondary areas where it intends to drill its wells as described in “Proposed Activities” is as follows:

an amount equal to 13% of the gross sales price received by the partnership for its natural gas in the Marcellus Shale (western Pennsylvania) primary area, and for this purpose gross sales price means the price that is actually received, adjusted to take into account proceeds received or payments made pursuant to hedging arrangements;

$1.00 per mcf (1,000 cubic feet of natural gas) in the New Albany Shale (Indiana) primary area;

$0.55 per mcf in the north central Tennessee secondary area; and

$0.30 per mcf in the Antrim Shale (Michigan) secondary area.

The payment of a competitive fee to the managing general partner for its gathering services will be subject to the following conditions:

If the gathering system owned by Laurel Mountain is used by the partnership, then the managing general partner will apply the gathering fee it receives from the partnership towards the payments owed by the Atlas entities under their agreement with Laurel Mountain.

If a third-party gathering system is used by the partnership, then the managing general partner’s gathering fee charged to the partnership will be the actual transportation and compression fees charged by the third-party gathering system with respect to the partnership’s natural gas in the area and the managing general partner will pay all of the gathering fee it receives from the partnership to the third-party gathering the natural gas. The managing general partner may not receive any gathering fees from the partnership that exceed the payments it makes to the third-party gas gatherer.

If both a third-party gathering system and the gathering system owned by Laurel Mountain, or a gas gathering system owned by an affiliate of Atlas America other than Laurel Mountain, are used by the partnership, then the managing general partner will receive an amount equal to a competive fee as described above for the natural gas transported by the segment provided by Laurel Mountain’s gathering system, or a gas gathering system owned by an affiliate of Atlas America other than Laurel Mountain, plus the amount charged by the third-party gathering system for the natural gas transported by the segment provided by the third-party.

The actual amount of gathering fees to be paid by the partnership to the managing general partner cannot be quantified, because the volume of natural gas that will be produced and transported from the partnership’s wells cannot be predicted.

Interest and Other Compensation

The managing general partner or an affiliate will have the right to charge a competitive rate of interest on any loan it may make to or on behalf of the partnership. If the managing general partner provides equipment, supplies, and other services to the partnership, then it may do so at competitive industry rates. The managing general partner will determine competitive industry rates for equipment, supplies and other services by conducting a survey of the interest and/or fees charged by unaffiliated third-parties in the same geographic area engaged in similar businesses. If possible, the managing general partner will contact at least two unaffiliated third-parties, however, the managing general partner will have sole discretion in determining the amount to be charged the partnership.

Estimate of Administrative Costs and Direct Costs to be Borne by the Partnership

The managing general partner and its affiliates will receive from the partnership a nonaccountable, fixed payment reimbursement for their administrative costs, which has been determined by the managing general partner to be $75 per well per month. This payment per well is subject to the following:

it will not be increased in amount during the term of the partnership;

it will be proportionately reduced to the extent the partnership acquires less than 100% of the working interest in the well;

it will be the entire payment to reimburse the managing general partner for the partnership’s administrative costs; and

it will not be received for plugged or abandoned wells.

The managing general partner estimates that the nonaccountable, fixed payment reimbursement for administrative costs allocable to the partnership’s first 12 months of operation after all of its wells have been placed into production will not exceed approximately:

$882 if the minimum subscription proceeds are received, which is one .98 net vertical Marcellus Shale well at $75 per well per month; and

$148,275 if the maximum subscription proceeds are received, which is 164.75 net wells at $75 per well per month.

Direct costs will be determined by the managing general partner, in its sole discretion, including the provider of the services or goods and the amount of the provider’s compensation. Direct costs will be billed directly to and paid by the partnership to the extent practicable. The anticipated direct costs set forth below for the partnership’s first 12 months of operation after all of its wells have been placed into production may vary from the estimates shown for numerous reasons that cannot accurately be predicted. These reasons include:

the number of the partnership’s investors;

the number of wells drilled by the partnership;

the partnership’s degree of success in its activities;

the extent of any production problems encountered by the partnership;

inflation; and

various other factors involving the administration of the partnership.

	Minimum Subscriptions		Maximum Subscriptions
Direct Costs
External Legal	$	6,000	$	20,000
Accounting Fees for Audit and Tax Preparation		30,000		60,000
Independent Engineering Reports		1,500		15,000
TOTAL	$	37,500	$	95,000

Set forth below is a tabular presentation of the narrative discussion of the compensation set forth above. In all cases, the tabular presentation is subject to the discussion set forth above.

Offering Stage

Entity receiving compensation	Type and method of compensation	Estimated amount

Anthem Securities, Inc.	Dealer-Manager Fees. Subject to certain exceptions described in “Plan of Distribution,” Anthem Securities, the dealer-manager and an affiliate of the managing general partner, will receive on each unit sold to an investor: · a 2.5% dealer-manager fee; · a 7% sales commission; and · up to a .5% reimbursement of the selling agents’ bona fide due diligence expenses.	Assuming the dealer-manager will receive the dealer-manager fee, the sales commissions and the up to .5% reimbursement of the selling agents’ bona fide due diligence expenses on all units sold, these amounts will be approximately: · $200,000 if the minimum subscription proceeds are received by the partnership; and · $27,569,500 if the maximum subscription proceeds are received by the partnership.

Drilling Stage

Entity receiving compensation	Type and method of compensation	Estimated amount

Managing general partner and its affiliates	Lease Costs. Under the partnership agreement the managing general partner will contribute to the partnership all the undeveloped leases necessary to cover each of the partnership’s prospects. The managing general partner will receive a credit to its capital account equal to: · the cost of the leases; or · the fair market value of the leases if the managing general partner has reason to believe that cost is materially more than the fair market value.	Based on the assumptions and the estimated average lease costs described in “Compensation – Lease Costs,” the managing general partner estimates that its total credit for lease costs will be approximately: · $19,600 if the minimum subscription proceeds are received; and · $4,387,980 if the maximum subscription proceeds are received.

Managing general partner and its affiliates	Drilling Contracts. The partnership will enter into the drilling and operating agreement with the managing general partner, acting as a third-party general drilling contractor and operator, to drill and complete the partnership’s wells for an amount equal to the sum of the following items: (i) the cost of permits, supplies, materials, equipment, and all other items used in the drilling and completion of a well provided by third-parties, or if the foregoing items are provided by affiliates of the managing general partner, then those items will be charged at competitive rates; (ii) fees for third-party services; (iii) fees for services provided by the managing general partner’s affiliates, which will be charged at competitive rates; (iv) an administration and oversight fee which generally is $15,000 per well, but which is $62,087 per vertical well in the Marcellus Shale primary area and per horizontal well in the north central Tennessee secondary area, $46,577 per horizontal well in the New Albany Shale (Indiana) primary area, $15,526 per vertical well in the north central Tennessee and Antrim Shale (Michigan) secondary areas, and $248,349 per horizontal well in the Marcellus Shale primary area, which will be charged to you and the other investors as part of the well’s intangible drilling costs and the portion of equipment costs paid by you and the other investors; and (v) a mark-up in an amount equal to 18% of the sum of (i), (ii), (iii) and (iv), above, for the managing general partner’s services as general drilling contractor. Additionally, if the managing general partner drills a well for the partnership that it determines is not an average well in the area because of the well’s depth, complexity associated with either drilling or completing the well or as otherwise determined by the managing general partner, the administration and oversight fee for the well described in §4.02(d)(1)(iv) of the partnership agreement may be increased to a competitive rate as determined by the managing general partner.	Based on the assumptions and the estimated weighted average cost for one net partnership well as set forth in “– Drilling Contracts” above, the managing general partner estimates that its administration and oversight fee and its 18% mark-up paid by you and the other investors will be: · $317,371 if the minimum subscription proceeds are received, which is one .98 net vertical Marcellus Shale well times $323,848; and · $53,353,958 if the maximum subscription proceeds are received, which is 164.75 net wells times $323,848. Additionally, affiliates of the managing general partner will provide subcontracting services, equipment and materials in drilling, completing or operating the partnership’s wells for which they will receive competitive rates, because they meet the requirements described in “Conflicts of Interest – Conflicts Regarding Transactions with the Managing General Partner and its Affiliates.” Thus, the total compensation paid to the managing general partner and its affiliates per net well will be greater than the estimated amount to be paid to the managing general partner as described above to the extent compensation is paid by the partnership to the managing general partner’s affiliates for services, equipment or supplies they provide to the partnership.

Operational Stage

Entity receiving compensation	Type and method of compensation	Estimated amount

Managing general partner and its affiliates	Natural Gas and Oil Revenues. Subject to the managing general partner’s subordination obligation, the investors and the managing general partner will share in the partnership’s revenues in the same percentages as their respective capital contributions bear to the total capital contributions to the partnership, except that the managing general partner will receive an additional 10% of the partnership’s revenues.	For example, if the managing general partner contributes the minimum of 15% of the partnership’s total capital contributions and the investors contribute 85% of the partnership’s total capital contributions, then the managing general partner will receive 25% of the partnership’s revenues and the investors will receive 75% of the partnership’s revenues.

Managing general partner and its affiliates	Per Well Charges. Under the drilling and operating agreement the managing general partner, as operator of the wells, will receive from the partnership reimbursement at actual cost for all direct expenses incurred on behalf of the partnership and well supervision fees at a competitive rate for operating and maintaining the wells during producing operations when the wells begin producing natural gas or oil.	Based on the assumptions and the estimated well supervision fees described in “– Per Well Charges,” above, the managing general partner estimates that it will receive well supervision fees for the partnership’s first 12 months of operation after all of the wells have been placed in production of: · $11,466 if the minimum subscription proceeds are received, which is one .98 net vertical Marcellus Shale well times $975 per net well per month; and · $1,925,607 if the maximum subscription proceeds are received, which is 164.75 net wells at the various well supervision fees discussed above.

Operational Stage

Entity receiving compensation	Type and method of compensation	Estimated amount

Managing general partner and its affiliates

Gathering Fees. Under the partnership agreement the managing general partner will be responsible for gathering and transporting the natural gas produced by the partnership to interstate pipeline systems, local distribution companies, and/or end-users in the area (the “gathering services”). The managing general partner anticipates that it will use the gathering system owned by Laurel Mountain for the partnership’s natural gas production in the Marcellus Shale primary area, which it expects will comprise the majority of the partnership's natural gas production. (See “Proposed Activities – Sale of Natural Gas and Oil Production – Gathering of Natural Gas.”) The partnership will pay a gathering fee directly to the managing general partner at competitive rates for the gathering services. The gathering fee paid by the partnership to the managing general partner may be increased from time-to-time by the managing general partner, in its sole discretion, but may not be increased beyond competitive rates as determined by the managing general partner. Currently, the managing general partner has determined that the competitive rate in each of its primary and secondary areas where the partnership will drill its wells as described in “Proposed Activities” is as follows:

· an amount equal to 13% of the gross sales price received by the partnership for its natural gas in the Marcellus Shale (western Pennsylvania) primary area, and for this purpose gross sales price means the price that is actually received, adjusted to take into account proceeds received or payments made pursuant to hedging arrangements;

· $1.00 per mcf (1,000 cubic feet of natural gas) in the New Albany Shale (Indiana) primary area;

· $0.55 per mcf in the north central Tennessee secondary area; and

· $0.30 per mcf in the Antrim Shale (Michigan) secondary area.

The payment of a competitive fee to the managing general partner for its gathering services will be subject to the conditions described in “– Gathering Fees,” above.

Operational Stage

Entity receiving compensation	Type and method of compensation	Estimated amount

Managing general partner and its affiliates	Interest and Other Compensation. The managing general partner or an affiliate will have the right to charge a competitive rate of interest on any loan it may make to or on behalf of the partnership. If the managing general partner provides equipment, supplies, and other services to the partnership, then it may do so at competitive industry rates.	The actual amount of interest and other compensation is not determinable at this time.

Managing general partner and its affiliates	Administrative Costs. The managing general partner and its affiliates will receive from the partnership a nonaccountable, fixed payment reimbursement for their administrative costs, which has been determined by the managing general partner to be $75 per well per month.	Based on the assumptions set forth in “– Estimate of Administrative and Direct Costs to be Borne by the Partnerships,” above, the managing general partner estimates that the nonaccountable, fixed payment reimbursement for administrative costs allocable to the partnership’s first 12 months of operation after all of its wells have been placed into production will not exceed approximately: · $882 if the minimum subscription proceeds are received, which is one .98 net well times $75 per well per month; and · $148,275 if the maximum subscription proceeds are received, which is 164.75 net wells times $75 per well per month.

Managing general partner and its affiliates and various third-parties	Direct Costs. Direct costs will be determined by the managing general partner, in its sole discretion, including the provider of the services or goods and the amount of the provider’s compensation. Direct costs will be billed directly to and paid by the partnership to the extent practicable.	Assuming the maximum subscription proceeds are received, the managing general partner estimates that the maximum amount of direct costs to be borne by the partnership will be $95,000, which is composed of: · $20,000 for external legal costs; · $60,000 for accounting fees for audit and tax preparation; and · $15,000 for independent engineering reports.

Managing general partner and its affiliates and various third-parties	Costs of Water Disposal Wells. Compensation at a competitive rate for any services provided to the partnership relating to disposal or injection wells and the transportation of waste water from the partnership’s productive wells.	The actual amount of compensation is not determinable at this time.

TERMS OF THE OFFERING

Subscription to a Partnership

Atlas Resources Public #18-2008 Program was formed to offer for sale an aggregate of $600 million of units in a series of up to three limited partnerships, each of which has been formed under the Delaware Revised Uniform Limited Partnership Act. The first partnership in the program, Atlas Resources Public #18-2008(A) L.P., completed its offering on December 31, 2008 and received offering proceeds of $201,242,770, which included units sold on a discounted basis as described in “Plan of Distribution.” The second partnership in the program, Atlas Resources Public #18-2009(B) L.P., completed its offering on June 26, 2009 and received offering proceeds of $122,574,170, which included units sold on a discounted basis as described in “Plan of Distribution.” Thus, the total maximum subscriptions remaining from the original $600 million, based on the number of units previously sold, is $275,695,000, which is 27,569.5 units at $10,000 per unit assuming no units are sold at the discounted prices described in “Plan of Distribution.”

Thus, the partnership will offer a minimum of 200 units, which is $2 million, and a maximum of 27,569.5 units, which is $275,695,000.

Also, set forth below is the targeted ending date of the offering of units for the partnership, which is not binding except that the units in the partnership may not be offered beyond the partnership’s offering termination date as set forth below. The managing general partner may close the offering of units in the partnership at any time before the partnership’s offering termination date once the partnership is in receipt of the minimum required subscriptions, and the managing general partner may withdraw the offering of units in the partnership at any time.

Partnership Name		Required Minimum Subscription			Maximum Subscription Proceeds (1)			Nonbinding Targeted Ending Date		Offering Termination Date
Atlas Resources Public #18-2009(C) L.P.		$	2 million		$	275,695,000		12/31/09		12/31/09

(1)

The partnership or the managing general partner may accept a greater or lesser amount of subscriptions for the partnership.

Units are offered at a subscription price of $10,000 per unit, subject to certain exceptions described in “Plan of Distribution,” and must be paid 100% in cash at the time of subscribing. The subscription price of the units has been arbitrarily determined by the managing general partner because the partnership does not have any prior operations, assets, earnings, liabilities or present value. Your minimum subscription is one unit ($10,000). Larger fractional subscriptions will be accepted in $1,000 increments, beginning with $11,000, $12,000, etc.

You may elect to purchase units in the partnership as either an investor general partner or a limited partner. However, even though you may elect to subscribe as an investor general partner the managing general partner will have exclusive management authority for the partnership. The partnership will be a separate business entity from the other partnerships in the program. Thus, as an investor, you will be a partner only in the partnership in which you invest. You will have no interest in the business, distributions, assets or tax benefits of the other partnership or partnerships unless you also invested in the other partnership or partnerships. Thus, your investment return will depend solely on the operations and success or lack of success of the particular partnership in which you invest.

Partnership Closings and Escrow

You and the other investors should make your checks for units payable to “Wells Fargo Bank, N.A., Escrow Agent, Atlas Resources Public #18-2009(C) L.P.,” and give your check to your broker/dealer for submission to the dealer-manager and escrow agent. Subscription proceeds for the partnership will be held in a separate interest bearing escrow account at Wells Fargo Bank, N.A., Four Gateway Center, Suite 1400, Pittsburgh, Pennsylvania 15222, until the partnership has received subscription proceeds of at least $2 million, excluding the subscription price discounts described in “Plan of Distribution” and excluding any subscriptions by the managing general partner or its affiliates. However, on receipt of the minimum subscription proceeds and written instructions to the escrow agent from the managing general partner and the dealer-manager, the managing general partner on behalf of the partnership will break escrow and transfer the escrowed subscription proceeds to a partnership account, enter into the drilling and operating agreement with itself or an affiliate as general drilling contractor and operator, and begin drilling operations for the partnership.

If the minimum subscription proceeds are not received by the partnership by December 31, 2009, then the subscription proceeds deposited in the escrow account will be promptly returned to you and the other subscribers with interest and without deduction for any fees. Although the managing general partner and its affiliates may buy up to 5% of the total units sold in the partnership, currently they do not anticipate purchasing any units. If they do buy units, then those units will not be applied towards the minimum subscription proceeds required for the partnership to break escrow and begin operations. Also, any units purchased by the managing general partner and its affiliates must be purchased for investment purposes only, and not with a view toward redistribution.

You will receive interest on your subscription proceeds from the time they are deposited in the escrow account, or a partnership account if you subscribe after the minimum subscription proceeds have been received and escrow has been broken, until your subscription proceeds are paid by the partnership to the managing general partner for use in the partnership’s drilling activities. All interest distributions will be made in the ratio that the number of units held by each investor multiplied by the number of days the investor’s subscription proceeds were held in the escrow account, or a partnership account after the minimum number of units have been received, bears to the sum of that calculation for all investors whose subscription proceeds are paid to the managing general partner at the same time. Also, interest distributions will be made when the partnership pays its first production distribution from the sale of its natural gas and oil since the amount of interest is expected by the managing general partner to be nominal because subscription proceeds are expected to be quickly paid to the managing general partner for use in the partnership’s operations and the current interest rate on the subscriptions is relatively low.

During the partnership’s escrow period its subscription proceeds will be invested only in institutional investments comprised of, or secured by, securities of the United States government. After the funds are transferred to the partnership account and before they are paid to the managing general partner for use in partnership operations, they may be temporarily invested in income producing short-term, highly liquid investments, in which there is appropriate safety of principal, such as U.S. Treasury Bills. If the managing general partner determines that the partnership may be deemed to be an investment company under the Investment Company Act of 1940, then the investment activity will cease. Subscription proceeds will not be commingled with the funds of the managing general partner or its affiliates, nor will subscription proceeds be subject to their creditors’ claims, before they are paid to the managing general partner under the drilling and operating agreement.

Acceptance of Subscriptions

Your execution of the subscription agreement constitutes your offer to buy units in the partnership and to hold the offer open until either:

your subscription is accepted or rejected by the managing general partner; or

you withdraw your offer.

To rescind or withdraw your subscription agreement, you must give written notice to the managing general partner before your subscription agreement is accepted by the managing general partner.

Also, the managing general partner will:

not complete a sale of units to you until at least five business days after the date you receive a final prospectus; and

send you a confirmation of purchase.

Subject to the foregoing, your subscription agreement will be accepted or rejected by the partnership within 30 days of its receipt. The managing general partner’s acceptance of your subscription is discretionary, and the managing general partner may reject your subscription for any reason without incurring any liability to you for this decision. If your subscription is rejected, then all of your funds will be promptly returned to you together with any interest earned on your subscription proceeds and without deduction for any fees.

When you will be admitted to the partnership depends on whether your subscription is accepted before or after the partnership breaks escrow. If your subscription is accepted:

before breaking escrow, then you will be admitted to the partnership not later than 15 days after the release from escrow of the investors’ subscription proceeds to the partnership; or

after breaking escrow, then you will be admitted to the partnership not later than the last day of the calendar month in which your subscription was accepted by the partnership.

Your execution of the subscription agreement and the managing general partner’s acceptance also constitutes your:

execution of the partnership agreement and agreement to be bound by its terms as a partner; and

grant of a special power of attorney to the managing general partner to file amended certificates of limited partnership and governmental reports, and perform certain other actions on behalf of you and the other investors as partners of the partnership.

PRIOR ACTIVITIES

The following tables reflect certain historical data with respect to the private drilling partnerships and the public drilling partnerships that the managing general partner has sponsored. The tables do not include Atlas Resources Public #18-2009(B) L.P. because it closed on June 26, 2009, and does not have any operating results to report as of the date of the tables. The tables, however, reflect certain historical data with respect to 1999 Viking Resources LP, a private drilling program that raised $4,555,210, and is the only drilling program sponsored by Viking Resources after it was acquired by Resource America, Inc. in August 1999. Information concerning this program and other programs sponsored by Viking Resources before it was acquired by Resource America will be provided to you on written request to the managing general partner. The tables also do not include information concerning wells acquired by Atlas Resources through merger or other form of acquisition, and this information also will be available to you on written request to the managing general partner.

Although past performance is no guarantee of future results, the investor general partners in the managing general partner’s prior partnerships have not had to make additional capital contributions to their partnerships because of their status as investor general partners.

The managing general partner sponsored each of its prior drilling partnerships with the intention to produce natural gas or oil from the partnership’s wells until such time as it became no longer economical for the partnership to continue to operate the wells, rather than selling the partnership’s productive wells during the term of the partnership. The managing general partner anticipates that when each partnership’s wells become depleted, which means generally that the wells cannot produce enough natural gas and oil at the then current prices to economically justify the continued operation of the partnership and its wells, its wells will be sold, plugged and abandoned or otherwise disposed of, and the partnership will be liquidated.

As disclosed in their respective offering documents, each of the managing general partner’s prior partnerships has a maximum term of 50 years before it is to be liquidated under its partnership agreement, except as set forth below:

Program		Maximum Term of Program
1. Atlas Energy Partners Limited (1986)		December 31, 2025 (i.e., 39 years)
2. Atlas Energy Partners Limited 1987		December 31, 2025 (i.e., 38 years)
3. Atlas Energy Partners Limited 1988		December 31, 2028 (i.e., 40 years)
4. Atlas Energy Partners Limited 1989		December 31, 2029 (i.e., 40 years)

No other date or time period at which any of the managing general partner’s prior partnerships might be liquidated was disclosed in their respective offering documents.

As of the date of the followings tables, none of the managing general partner’s prior partnerships had been liquidated or reached its maximum term under its partnership agreement and each partnership continued to produce natural gas or oil from its wells.

It should not be assumed that you and the other investors in the partnership will experience returns, if any, comparable to those experienced by investors in the prior drilling partnerships for several reasons, including, but not limited to, differences in:

partnership terms;

property locations;

partnership size; and

economic considerations.

The results of the prior drilling partnerships should be viewed only as a measure of the level of activity and experience of the managing general partner with respect to drilling partnerships.

Finally, as discussed in “Risk Factors – Risks Related to an Investment in the Partnership – A Decrease in Natural Gas Prices Could Subject the Partnership’s and the Managing General Partner’s Oil and Gas Properties to an Impairment Loss under Generally Accepted Accounting Principles,” the following partnerships have all suffered financial impairments to some or all of their properties.

Partnership	Total Impairment Recorded As of 12/31/08
1. A.E. Nineties-Public #8 Ltd.	$	4,366,700
2. Atlas America Public #9 Ltd.		2,104,700
3. Atlas America Public #10 Ltd.		796,700
4. Atlas America Public #11-2002 LP		4,897,000
5. Atlas America Public #12-2003 LP		3,659,800
6. Atlas America Series 25-2004(A) LP		2,141,400
7. Atlas America Series 25-2004(B) LP		15,731,200
8. Atlas America Public #14-2004 LP		25,746,700
9. Atlas America Public #14-2005(A) LP		40,895,300
10. Atlas America Series 26-2005 LP		21,549,500
11. Atlas America Public #15-2005(A) LP		31,145,800
12. Atlas America Public #15-2006(B) LP		95,874,400
13. Atlas America Series 27-2006 LP		51,955,700
14. Atlas Resources Public #16-2007(A) LP		172,716,500
15. Atlas Resources Public #17-2007(A) LP		122,041,700
16. Atlas Resources Public #17-2008(B) LP		125,158,600

Table 1 sets forth certain sales information of previous development drilling partnerships sponsored by the managing general partner and its affiliates.

TABLE 1

EXPERIENCE IN RAISING FUNDS

AS OF MARCH 31, 2009

					Managing							Years
		Number			General					Date	Date of	Wells	Previous
		of Original	Investor		Partner			Total		Operations	First	In	Assess-
	Partnership	Investors	Capital		Capital			Capital		Began	Distributions	Production	ments

1.	Atlas L.P. 1 - 1985	19	$	600,000	$	114,800		$	714,800	12/31/85	07/02/86	22.81	-0-
2.	A.E. Partners Limited (1986)	24	631,250		120,400			751,650		12/31/86	04/02/87	21.81	-0-
3.	A.E. Partners Limited 1987	17	721,000		158,269			879,269		12/31/87	04/02/88	20.81	-0-
4.	A.E. Partners Limited 1988	21	617,050		135,450			752,500		12/31/88	04/02/89	19.81	-0-
5.	A.E. Partners Limited 1989	21	550,000		120,731			670,731		12/31/89	04/02/90	18.81	-0-
6.	A.E. Partners Limited-1990	27	887,500		244,622			1,132,122		12/31/90	04/02/91	17.81	-0-
7.	Atlas-Energy Partners 1990 L.P.(Series 10)	60	2,200,000		484,380			2,684,380		12/31/90	03/31/91	17.59	-0-
8.	Atlas-Energy Partners 1991 L.P.(Series 11)	25	750,000		268,003			1,018,003		09/30/91	01/31/92	16.76	-0-
9.	A.E. Partners Limited-1991	26	868,750		318,063			1,186,813		12/31/91	04/02/92	16.59	-0-
10.	Atlas-Energy for the Nineties-1 LP (Series 12)	87	2,212,500		791,833			3,004,333		12/31/91	04/30/92	16.51	-0-
11.	Atlas JV 92 Limited Partnership	155	4,004,813		1,414,917			5,419,730		10/28/92	04/05/93	15.84	-0-
12.	A.E. Partners Limited-1992	21	600,000		176,100			776,100		12/14/92	07/02/93	15.34	-0-
13.	A.E. Nineties-Public #1 Ltd.	221	2,988,960		528,934			3,517,894		12/31/92	07/15/93	15.09	-0-
14.	A.E. Nineties-1993 Ltd.	125	3,753,937		1,264,183			5,018,120		10/08/93	02/10/94	14.76	-0-
15.	A.E. Partners Limited-1993	21	700,000		219,600			919,600		12/31/93	07/02/94	14.51	-0-
16.	A.E. Nineties-Public #2 Ltd.	269	3,323,920		587,340			3,911,260		12/31/93	06/15/94	14.26	-0-
17.	A.E. Nineties-Series 14 Ltd.	263	9,940,045		3,584,027			13,524,072		08/11/94	01/10/95	13.76	-0-
18.	A.E. Partners Limited-1994	23	892,500		231,500			1,124,000		12/31/94	07/02/95	13.51	-0-
19.	A.E. Nineties-Public #3 Ltd.	391	5,800,990		928,546			6,729,536		12/31/94	06/05/95	13.51	-0-
20.	A.E. Nineties-Series 15 Ltd.	244	10,954,715		3,435,936			14,390,651		09/12/95	02/07/96	12.68	-0-
21.	A.E. Partners Limited-1995	23	600,000		244,725			844,725		12/31/95	10/02/96	12.26	-0-
22.	A.E. Nineties-Public #4 Ltd.	324	6,991,350		1,287,752			8,279,102		12/31/95	07/08/96	12.51	-0-
23.	A.E. Nineties-Series 16 Ltd.	274	10,955,465		1,643,320			12,598,785		07/31/96	01/12/97	11.84	-0-
24.	A.E. Partners Limited-1996	21	800,000		367,416			1,167,416		12/31/96	07/02/97	11.51	-0-
25.	A.E. Nineties-Public #5 Ltd.	378	7,992,240		1,654,740			9,646,980		12/31/96	06/08/97	11.51	-0-
26.	A.E. Nineties-Series 17 Ltd.	217	8,813,488		2,113,947			10,927,435		08/29/97	12/12/97	10.93	-0-
27.	A.E. Nineties-Public #6 Ltd.	393	9,901,025		1,950,345			11,851,370		12/31/97	06/08/98	10.51	-0-
28.	A.E. Partners Limited-1997	13	506,250		231,050			737,300		12/31/97	07/02/98	10.34	-0-
29.	A.E. Nineties-Series 18 Ltd.	225	11,391,673		3,448,751			14,840,424		07/31/98	01/07/99	9.59	-0-
30.	A.E. Nineties-Public #7 Ltd.	366	11,988,350		3,812,150			15,800,500		12/31/98	07/10/99	9.26	-0-
31.	A.E. Partners Limited-1998	26	1,740,000		756,360			2,496,360		12/31/98	07/02/99	9.26	-0-
32.	A.E. Nineties-Series 19 Ltd.	288	15,720,450		4,776,598			20,497,048		09/30/99	01/14/00	8.76	-0-
33.	A.E. Nineties-Public #8 Ltd.	380	11,088,975		3,148,181			14,237,156		12/31/99	06/09/00	8.26	-0-
34.	A.E. Partners Limited-1999	8	450,000		196,500			646,500		12/31/99	10/02/00	8.26	-0-
35.	1999 Viking Resources LP	131	4,555,210		1,678,038			6,233,248		12/31/99	06/01/00	8.26	-0-
36.	Atlas America Series 20 Ltd.	361	18,809,150		6,297,945			25,107,095		09/30/00	01/30/01	8.01	-0-
37.	Atlas America Public #9 Ltd.	530	14,905,465		6,256,271			21,161,736		12/31/00	07/13/01	7.61	-0-
38.	Atlas America Series 21-A Ltd.	282	12,510,713		4,535,799			17,046,512		05/15/01	11/16/01	7.36	-0-
39.	Atlas America Series 21-B Ltd.	360	17,411,825		6,442,761			23,854,586		09/19/01	03/02/02	6.76	-0-
40.	Atlas America Public #10 Ltd.	818	21,281,170		7,227,432			28,508,602		12/31/01	06/20/02	6.51	-0-
41.	Atlas America Series 22-2002 Ltd.	258	10,156,375		3,481,591			13,637,966		05/31/02	11/12/02	6.01	-0-
42.	Atlas America Series 23-2002 Ltd.	246	9,644,550		3,214,850			12,859,400		09/30/02	02/18/03	5.76	-0-
43.	Atlas America Public #11-2002 LP	1,017	31,178,145		13,295,300			44,473,445		12/31/02	7/15/2003	5.51	-0-
44.	Atlas America Series 24-2003(A) Ltd., LP	325	14,363,955		5,137,628			19,501,583		05/31/03	12/05/03	5.01	-0-
45.	Atlas America Series 24-2003(B) Ltd., LP	422	20,542,850		8,100,983			28,643,833		08/29/03	02/05/04	4.76	-0-
46.	Atlas America Public #12-2003 LP	1,102	40,170,308		17,285,400			57,455,708		12/31/03	6/15/04	4.51	-0-
47.	Atlas America Series 25-2004(A) LP	635	27,601,053		11,641,600			39,242,653		05/31/04	11/5/04	4.26	-0-
48.	Atlas America Series 25-2004(B) LP	634	31,531,035		14,080,200			45,611,235		08/31/04	2/5/05	3.84	-0-
49.	Atlas America Public #14-2004 LP	1,494	52,506,570		21,794,700			74,301,270		11/15/04	7/15/05	3.34	-0-
50.	Atlas America Public #14-2005(A) LP	2,192	69,674,900		27,250,400			96,925,300		06/17/05	2/15/06	3.17	-0-
51.	Atlas America Series 26-2005 LP	579	34,886,465		14,081,700			48,968,165		09/16/05	6/5/06	3.01	-0-
52.	Atlas America Public #15-2005(A) LP	1,625	52,245,720		18,677,400		(1)	70,923,120		12/31/05	8/15/06	2.84	-0-
53.	Atlas America Public #15-2006(B) LP	4,108	147,513,130		52,353,600		(1)	199,866,730		08/31/06	3/15/07	2.33	-0-
54.	Atlas America Series 27-2006 LP	1,359	70,882,965		24,126,600		(1)	95,009,565		12/29/06	7/1/07	1.92	-0-
55.	Atlas Resources Public #16-2007(A) LP	5,007	199,685,750		87,034,800		(1)	286,720,550		09/18/07	2/5/08	1.50	-0-
56.	Atlas Resources Public #17-2007(A) LP	3,211	163,010,430		58,554,300		(1)	221,564,730		12/31/07	8/5/08	0.83	-0-
57.	Atlas Resources Public # 17-2008(B) LP	5,073	236,026,950		83,519,800		(1)	319,546,750		07/31/08	2/5/09	0.50	-0-
58.	Atlas Resources Public #18-2008(A) LP	4,429	201,242,770		37,516,500		(1)	238,759,270		12/31/08	(2)	-	-0-

(1)	Managing General Partner's Capital contributions are through the date of this table and are subject to further changes.

(2)	This partnership closed December 31, 2008 with distributiions expected to begin Summer 2009.

Table 2 reflects the drilling activity of previous development drilling partnerships sponsored by the managing general partner and its affiliates. All the wells were development wells. You should not assume that the past performance of prior partnerships is indicative of the future results of the partnerships.

TABLE 2

WELL STATISTICS - DEVELOPMENT WELLS

AS OF MARCH 31, 2009

		GROSS WELLS (1)			NET WELLS (2)
	Partnership	Oil	Gas	Dry (3)	Oil	Gas	Dry (3)
1.	Atlas L.P. 1 - 1985	0	7	0	0	3.37	0.00
2.	A.E. Partners Limited (1986)	0	8	0	0	3.50	0.00
3.	A.E. Partners Limited 1987	0	9	0	0	4.09	0.00
4.	A.E. Partners Limited 1988	0	9	0	0	3.50	0.00
5.	A.E. Partners Limited 1989	0	10	0	0	3.28	0.00
6.	A.E. Partners Limited-1990	0	12	0	0	5.02	0.00
7.	Atlas-Energy Partners 1990 L.P.(Series 10)	0	12	0	0	11.46	0.00
8.	Atlas-Energy Partners 1991 L.P.(Series 11)	0	14	0	0	4.35	0.00
9.	A.E. Partners Limited-1991	0	12	0	0	4.95	0.00
10.	Atlas-Energy for the Nineties-1 LP (Series 12)	0	14	0	0	12.61	0.00
11.	Atlas JV 92 Limited Partnership	0	52	0	0	24.44	0.00
12.	A.E. Partners Limited-1992	0	7	0	0	3.50	0.00
13.	A.E. Nineties-Public #1 Ltd.	0	14	0	0	14.00	0.00
14.	A.E. Nineties-1993 Ltd.	0	20	1	0	19.40	1.00
15.	A.E. Partners Limited-1993	0	8	0	0	4.00	0.00
16.	A.E. Nineties-Public #2 Ltd.	0	16	0	0	15.31	0.00
17.	A.E. Nineties-Series 14 Ltd.	0	53	2	0	53.00	2.00
18.	A.E. Partners Limited-1994	0	12	0	0	5.25	0.00
19.	A.E. Nineties-Public #3 Ltd.	0	26	1	0	24.50	1.00
20.	A.E. Nineties-Series 15 Ltd.	0	61	1	0	55.50	1.00
21.	A.E. Partners Limited-1995	0	6	0	0	3.00	0.00
22.	A.E. Nineties-Public #4 Ltd.	0	32	0	0	31.50	0.00
23.	A.E. Nineties-Series 16 Ltd.	0	51	6	0	42.97	4.50
24.	A.E. Partners Limited-1996	0	13	0	0	4.34	0.00
25.	A.E. Nineties-Public #5 Ltd.	0	36	0	0	35.91	0.00
26.	A.E. Nineties-Series 17 Ltd.	0	46	5	0	37.50	3.50
27.	A.E. Nineties-Public #6 Ltd.	0	55	0	0	44.45	0.00
28.	A.E. Partners Limited-1997	0	6	0	0	2.81	0.00
29.	A.E. Nineties-Series 18 Ltd.	0	64	0	0	58.50	0.00
30.	A.E. Nineties-Public #7 Ltd.	0	64	0	0	57.50	0.00
31.	A.E. Partners Limited-1998	0	19	0	0	9.50	0.00
32.	A.E. Nineties-Series 19 Ltd.	0	82	4	0	75.74	4.00
33.	A.E. Nineties-Public #8 Ltd.	0	58	0	0	54.66	0.00
34.	A.E. Partners Limited-1999	0	5	0	0	2.47	0.00
35.	1999 Viking Resources LP	0	23	2	0	23.00	2.00
36.	Atlas America Series 20 Ltd.	0	106	1	0	99.24	1.00
37.	Atlas America Public #9 Ltd.	0	83	2	0	78.75	2.00
38.	Atlas America Series 21-A Ltd.	0	68	0	0	62.50	0.00
39.	Atlas America Series 21-B Ltd.	0	89	2	0	82.05	1.00
40.	Atlas America Public #10 Ltd.	0	107	3	0	103.15	3.00
41.	Atlas America Series 22-2002 Ltd.	0	51	1	0	49.55	1.00
42.	Atlas America Series 23-2002 Ltd.	0	47	1	0	47.00	1.00
43.	Atlas America Public #11-2002 LP	0	167	0	0	160.50	0.00
44.	Atlas America Series 24-2003(A) Ltd., LP	0	76	0	0	69.50	0.00
45.	Atlas America Series 24-2003(B) Ltd., LP	0	121	1	0	113.00	1.00
46.	Atlas America Public #12-2003 LP	0	221	6	0	209.25	6.00
47.	Atlas America Series 25-2004(A) LP	0	137	4	0	129.05	4.00
48.	Atlas America Series 25-2004(B) LP	0	171	4	0	147.05	4.00
49.	Atlas America Public #14-2004 LP	0	258	6	0	233.88	5.88
50.	Atlas America Public #14-2005(A) LP	0	327	16	0	301.29	16.00
51.	Atlas America Series 26-2005 LP	0	142	2	0	132.53	2.00
52.	Atlas America Public #15-2005(A) LP	0	187	1	0	182.50	1.00
53.	Atlas America Public #15-2006(B) LP	0	548	3	0	498.92	3.00
54.	Atlas America Series 27-2006 LP	0	254	2	0	204.11	1.25
55.	Atlas Resources Public #16-2007(A) LP	0	649	3	0	606.01	3.00
56.	Atlas Resources Public #17-2007(A) LP	0	373	2	0	346.83	2.00
57.	Atlas Resources Public # 17-2008(B) LP	0	506	0	0	474.51	0.00
58.	Atlas Resources Public #18-2008(A) LP	0	223	0	0	192.50	0.00
		0	5,847	82	0	5,282.55	77.13

	(1) A “gross well” is one in which a leasehold interest is owned.
	(2) A “net well” equals the actual leasehold interest owned in one gross well divided by one hundred. For example, a 50% leasehold interest in a well is one gross well, but a .50 net well.
	(3) For purposes of this Table only, a “Dry Hole” means a well which is plugged and abandoned with or without a completion attempt because the operator has determined that it will not be productive of gas and/or oil in commercial quantities.

Table 3 provides information concerning the operating results of previous development drilling partnerships sponsored by the managing general partner and its affiliates. You should not assume that the past performance of prior partnerships is indicative of the future results of the partnerships.

TABLE 3

INVESTOR OPERATING RESULTS - INCLUDING EXPENSES

AS OF MARCH 31, 2009

											Present Value of
										Estimated Future	Estimated Future Net
									Latest Quarterly	Net Cash Flows from	Cash Flows from Proved
			TOTAL COSTS			Cash		Cash	Cash Distribution	Proved Reserves as of	Reserves Discounted at 10%
	Partnership	Investor Capital	Operating (5)	Admin.	Direct	Distributions (1)(3)		Return (3)	As of Date of Table	December 31, 2008 (7) (8)	as of December 31, 2008 (7) (9)
1.	Atlas L.P. 1 - 1985	$600,000	$309,238	$56,897	$26,789	$1,901,965		317%	18,381	384,361	220,818
2.	A.E. Partners Limited (1986)	631,250	239,883	91,829	23,925	960,434		152%	9,541	162,323	94,515
3.	A.E. Partners Limited 1987	721,000	249,492	78,998	23,405	962,216		133%	8,457	187,341	115,735
4.	A.E. Partners Limited 1988	617,050	221,381	77,917	21,648	867,751		141%	7,300	119,428	77,579
5.	A.E. Partners Limited 1989	550,000	221,980	83,903	22,742	1,048,202		191%	7,238	93,605	63,525
6.	A.E. Partners Limited-1990	887,500	316,506	124,250	32,738	1,640,095		185%	17,434	343,450	215,474
7.	Atlas-Energy Partners 1990 L.P.(Series 10)	2,200,000	1,006,231	119,734	10,446	2,553,483		116%	29,485	607,366	370,387
8.	Atlas-Energy Partners 1991 L.P.(Series 11)	750,000	430,207	132,630	18,689	1,338,026		178%	10,468	192,235	124,793
9.	A.E. Partners Limited-1991	868,750	295,385	160,286	44,042	1,764,170		203%	19,907	378,028	223,901
10.	Atlas-Energy for the Nineties-1 LP (Series 12)	2,212,500	923,396	114,769	66,623	2,646,427		120%	24,961	743,808	382,905
11.	Atlas JV 92 Limited Partnership	4,004,813	1,697,567	220,421	172,673	5,322,680	(2)	133%	42,981	814,727	491,943
12.	A.E. Partners Limited-1992	600,000	180,961	79,388	28,436	1,119,954		187%	12,147	215,903	129,948
13.	A.E. Nineties-Public #1 Ltd.	2,988,960	1,214,829	139,622	45,976	2,932,023		98%	26,991	492,771	298,192
14.	A.E. Nineties-1993 Ltd.	3,753,937	1,183,277	144,296	15,470	2,463,467		66%	7,096	53,763	43,070
15.	A.E. Partners Limited-1993	700,000	230,555	57,675	28,053	1,299,594		186%	8,943	263,359	133,519
16.	A.E. Nineties-Public #2 Ltd.	3,323,920	1,011,294	123,981	130,842	2,740,675		82%	18,324	308,661	189,529
17.	A.E. Nineties-Series 14 Ltd.	9,940,045	3,410,272	412,783	22,928	7,591,144		76%	61,424	1,106,183	686,166
18.	A.E. Partners Limited-1994	892,500	276,327	74,586	35,781	1,577,703		177%	19,591	623,820	317,585
19.	A.E. Nineties-Public #3 Ltd.	5,800,990	1,718,129	224,328	148,427	5,172,851		89%	56,289	1,346,297	732,652
20.	A.E. Nineties-Series 15 Ltd.	10,954,715	534,390	429,337	8,748	10,555,706		96%	127,042	2,774,633	1,614,795
21.	A.E. Partners Limited-1995	600,000	155,994	32,808	23,575	478,452		80%	4,035	34,413	25,076
22.	A.E. Nineties-Public #4 Ltd.	6,991,350	1,899,989	243,978	11,602	4,633,873		66%	60,554	1,023,680	633,290
23.	A.E. Nineties-Series 16 Ltd.	10,955,465	3,153,122	340,507	27,325	8,310,886		76%	122,770	2,986,813	1,634,379
24.	A.E. Partners Limited-1996	800,000	240,010	44,454	63,786	839,053		105%	15,630	428,462	231,579
25.	A.E. Nineties-Public #5 Ltd.	7,992,240	1,983,685	257,048	158,412	5,594,507		70%	73,426	1,378,785	842,979
26.	A.E. Nineties-Series 17 Ltd.	8,813,488	2,508,811	382,515	89,685	8,099,827		92%	136,502	3,161,550	1,788,544
27.	A.E. Nineties-Public #6 Ltd.	9,901,025	2,596,698	317,919	188,380	8,846,776		89%	158,636	3,548,652	2,000,642
28.	A.E. Partners Limited-1997	506,250	142,437	26,777	48,494	710,023		140%	17,251	457,746	248,887
29.	A.E. Nineties-Series 18 Ltd.	11,391,673	3,228,524	355,715	285,358	9,119,432		80%	139,566	3,106,759	1,858,563
30.	A.E. Nineties-Public #7 Ltd.	11,988,350	2,593,663	303,399	30,443	6,853,051		57%	122,316	2,207,482	1,314,020
31.	A.E. Partners Limited-1998	1,740,000	454,038	53,525	83,665	1,801,450		104%	32,414	722,395	418,493
32.	A.E. Nineties-Series 19 Ltd.	15,720,450	3,700,381	414,745	70,162	10,426,931		66%	156,375	3,955,935	2,273,106
33.	A.E. Nineties-Public #8 Ltd.	11,088,975	2,194,998	261,509	229,251	7,317,807		66%	107,939	2,302,373	1,355,984
34.	A.E. Partners Limited-1999	450,000	106,147	9,459	30,856	494,112		110%	5,044	89,937	59,949
35.	1999 Viking Resources LP	4,555,210	2,078,029	0	9,509	8,774,562		193%	99,465	2,216,236	1,186,641
36.	Atlas America Series 20 Ltd.	18,809,150	4,332,418	461,192	15,462	20,311,483		108%	330,473	6,552,754	3,803,090
37.	Atlas America Public #9 Ltd.	14,905,465	3,408,332	320,678	30,307	12,637,725		85%	198,468	4,753,400	2,773,551
38.	Atlas America Series 21-A Ltd.	12,510,713	2,366,730	272,448	10,228	10,614,797		85%	232,658	5,717,447	3,127,125
39.	Atlas America Series 21-B Ltd.	17,411,825	4,136,876	284,954	11,232	12,654,635		73%	241,759	6,307,597	3,467,057
40.	Atlas America Public #10 Ltd.	21,281,170	4,022,159	362,363	211,318	16,854,987		79%	345,517	7,431,188	4,241,551
41.	Atlas America Series 22-2002 Ltd.	10,156,375	1,747,749	184,542	9,066	8,875,102		87%	164,699	4,359,875	2,371,174
42.	Atlas America Series 23-2002 Ltd.	9,644,550	1,601,803	176,154	9,036	7,006,579		73%	128,115	2,439,653	1,487,109
43.	Atlas America Public #11-2002 LP	31,178,145	4,650,340	529,130	51,372	21,298,395		68%	357,315	8,343,815	4,853,651
44.	Atlas America Series 24-2003(A) Ltd., LP	14,363,955	1,998,779	202,919	10,142	10,475,481		73%	248,502	6,460,419	3,595,162
45.	Atlas America Series 24-2003(B) Ltd., LP	20,542,850	3,190,255	319,764	10,901	15,480,883		75%	280,754	7,348,799	3,947,760
46.	Atlas America Public #12-2003 LP	40,170,308	5,368,657	473,792	52,562	23,910,148		60%	496,501	11,598,231	6,491,316
47.	Atlas America Series 25-2004(A) LP	27,601,053	3,954,916	313,448	48,924	21,205,834		77%	446,647	11,301,714	6,442,356
48.	Atlas America Series 25-2004(B) LP	31,531,035	3,609,886	337,121	56,785	14,923,128		47%	423,920	7,880,022	4,611,785

TABLE 3

INVESTOR OPERATING RESULTS - INCLUDING EXPENSES

AS OF MARCH 31, 2009

										Present Value of
									Estimated Future	Estimated Future Net
								Latest Quarterly	Net Cash Flows from	Cash Flows from Proved
			TOTAL COSTS			Cash	Cash	Cash Distribution	Proved Reserves as of	Reserves Discounted at 10%
	Partnership	Investor Capital	Operating (5)	Admin.	Direct	Distributions (1)(3)	Return (3)	As of Date of Table	December 31, 2008 (7) (8)	as of December 31, 2008 (7) (9)
49.	Atlas America Public #14-2004 LP	52,506,570	5,389,114	468,810	83,170	20,992,659	40%	812,596	13,063,725	7,578,127
50.	Atlas America Public #14-2005(A) LP	69,674,900	7,091,709	537,444	76,702	27,690,939	40%	890,040	18,859,791	10,738,579
51.	Atlas America Series 26-2005 L.P.	34,886,465	3,012,078	208,579	54,554	12,368,523	35%	519,940	8,612,011	5,066,299
52.	Atlas America Public #15-2005(A) L.P.	52,245,720	4,181,396	293,330	80,330	17,228,181	33%	787,655	15,950,727	8,894,733
53.	Atlas America Public #15-2006(B) L.P.	147,513,130	9,911,539	639,965	111,656	38,055,365	26%	2,771,612	40,116,991	23,188,885
54.	Atlas America Series 27-2006 L.P.	70,882,965	3,834,375	223,746	92,482	13,320,222	19%	1,496,643	15,578,028	9,388,306
55.	Atlas Resources Public # 16-2007 (A) LP (4)	199,685,750	8,496,839	423,627	200,823	27,608,679	14%	4,591,156	40,095,547	25,544,913
56.	Atlas Resources Public # 17-2007 (A) LP (4)	163,010,430	5,732,271	168,137	130,780	20,079,059	12%	4,425,057	62,675,406	33,968,288
57.	Atlas Resources Public # 17-2008 (B) LP (4)	236,026,950	4,840,062	120,011	51,064	13,848,195	6%	6,680,922	(6)	(6)
58.	Atlas Resources Public # 18-2008 (A) LP (4)	201,242,770	0	0	0	0	0%	(10)	(6)	(6)
	(1) All cash distributions were from the sale of gas, except that the following partnerships also include revenue from the sale of properties: A.E. Nineties-16 ($4,776), A.E. Nineties-19 ($1,607), Atlas America Series 20 ($6,662), Atlas America Series 22 ($34), Atlas America Series 23 ($38), Atlas America Series 24-2003(A) ($11,331), Atlas America Series 24-2003(B) ($22,577), Atlas America Series 25-2004(A) ($595), Atlas America Series 25-2004(B) ($1,052), Atlas America Series 26-2005 ($4,620), A.E. Nineties-Public #1 ($2,452), A.E. Nineties-Public #2 ($3,292), A.E. Nineties-Public #3 ($2,491), A.E. Nineties-Public #5 ($8,639), A.E. Nineties-Public #7 ($2,206), Atlas America Public #10 ($4,687) Atlas America Public #11-2002 ($2,789), Atlas America Public #12-2003 ($1,568), Atlas America Public #14-2004 ($920) and Atlas America Public #14-2005(A) ($345).
	(2) A portion of the cash distributions was used to drill three reinvestment wells at a cost of $307,434 in accordance with the terms of the offering.
	(3) This column reflects total cash distributions beginning with the first production from the program as a percentage of the total amount invested in the program and includes the return of the investors' capital.
	(4) As of the date of this table there is not twelve months of production and/or not all of the wells are drilled or on-line to sell production.
	(5) Operating costs consist of gathering fees, water hauling fees, meter reading fees, repairs and maintenance, insurance and severance tax.
	(6) Reserve information for Atlas Resources Public #17-2008(B) L.P. which closed at 7/31/08 and Atlas Resources Public #18-2008(A)L.P. which closed at 12/31/08 are incomplete and not provided since not all of its wells were drilled at 12/31/08.
	(7) The information presented in this column has been prepared in conformity with SEC guidelines by making the standardized estimates of future net cash flow from proved reserves using natural gas and oil prices in effect as of the date of the estimates, which was a weighted average price of $5.51 per mcf for the natural gas, $44.60 per barrel for the oil, and which are held constant throughout the life of the properties. The $5.51 does not reflect the effects of the financial hedges. The information presented for future net cash flows based on estimated proved reserves was prepared by an independent petroleum consultant, Wright & Company, Inc., as noted below with respect to the managing general partner's prior 20 public partnerships and 23 Regulation D offerings other than the following 15 partnerships: Atlas LP 1-1985, A.E. Partners Limited (1986), A.E. Partners Limited 1987, A.E. Partners Limited 1988, A.E. Partners Limited 1989, A.E. Partners Limited-1990, A.E. Partners Limited-1991, A.E. Partners Limited-1992, A.E. Partners Limited-1993, A.E. Partners Limited-1994, A.E. Partners Limited-1995, A.E. Partners Limited-1996, A.E. Partners Limited-1997, A.E. Partners Limited-1998 and A.E. Partners Limited-1999. The future net cash flows for these 15 partnerships were not prepared or reviewed by Wright & Company, Inc., but instead the reserve information was prepared by the managing general partner's reservoir engineer. You should understand that reserve estimates are imprecise and may change. There are inherent uncertainties in interpreting the engineering data and the projection of future rates of production. Also, prices received from the sale of natural gas and oil may be different from those estimates in preparing the reports, and the amounts and timing of future operating and development costs may also differ from those used. The cash flow information based on estimated proved reserves shown for a partnership does not include this information for the managing general partner.
	(8) This column represents a partnership's estimate of future net cash flows from its proved reserves using natural gas sales prices in effect as of the dates of the estimates which are held constant throughout the life of the partnership's properties. As natural gas prices change, these estimates will change. The information in this column has not been discounted.
	(9) This column represents a partnership's estimate of future net cash flows from its proved reserves using natural gas sales prices in effect as of the dates of the estimates which are held constant throughout the life of the partnership's properties. As natural gas prices change, these estimates will change. The present value of estimated future net cash flows is calculated by discounting estimated future net cash flows by 10% annually in accordance with SEC guidelines. You should not construe the estimated PV-10 values as representative of the fair market value of a partnership's properties.
	(10) Partnership closed December 31, 2008 with distributions expected to begin summer 2009.

Table 3A provides information concerning the operating results of previous development drilling partnerships sponsored by the managing general partner and its affiliates.

TABLE 3A

MANAGING GENERAL PARTNER

OPERATING RESULTS - INCLUDING EXPENSES

AS OF MARCH 31, 2009

		Managing General		Total Costs						Cash			Latest Quarterly Cash Distribution As of
	Partnership	Partner Capital		Operating (3)		Admin.		Direct		Distributions (1)		Cash Return	Date of Table

1.	Atlas L.P. 1 - 1985	$	114,800	$	58,902	$	10,837	$	5,103	$	360,028	314%	3,501
2.	A.E. Partners Limited (1986)	120,400		45,692		17,491		4,557		181,122		150%	1,817
3.	A.E. Partners Limited 1987	158,269		71,935		22,777		6,748		274,995		174%	2,438
4.	A.E. Partners Limited 1988	135,450		71,296		25,093		6,972		277,144		205%	2,351
5.	A.E. Partners Limited 1989	120,731		48,727		18,418		4,992		303,997		252%	1,589
6.	A.E. Partners Limited-1990	244,622		105,502		0		0		509,401		208%	6,668
7.	Atlas-Energy Partners 1990 L.P.(Series 10)	484,380		335,410		0		0		906,336		187%	10,885
8.	Atlas-Energy Partners 1991 L.P.(Series 11)	268,003		184,374		56,841		2,952		569,188		212%	4,486
9.	A.E. Partners Limited-1991	318,063		98,462		0		0		629,378		198%	7,617
10.	Atlas-Energy for the Nineties-1 LP (Series 12)	791,833		395,741		49,187		3,046		1,123,486		142%	10,697
11.	Atlas JV 92 Limited Partnership	1,414,917		836,115		108,565		3,508		4,024,152		284%	21,170
12.	A.E. Partners Limited-1992	176,100		60,320		0		0		396,967		225%	4,674
13.	A.E. Nineties-Public #1 Ltd.	528,934		383,630		44,091		2,712		875,149		165%	8,523
14.	A.E. Nineties-1993 Ltd.	1,264,183		507,119		61,841		3,048		587,922		47%	3,041
15.	A.E. Partners Limited-1993	219,600		76,852		0		0		452,771		206%	3,456
16.	A.E. Nineties-Public #2 Ltd.	587,340		319,356		39,152		41,319		693,652		118%	5,787
17.	A.E. Nineties-Series 14 Ltd.	3,584,027		1,679,686		203,311		4,114		2,543,339		71%	30,254
18.	A.E. Partners Limited-1994	231,500		92,109		0		0		550,462		238%	7,141
19.	A.E. Nineties-Public #3 Ltd.	928,546		572,710		74,776		49,476		1,643,528		177%	18,763
20.	A.E. Nineties-Series 15 Ltd.	3,435,936		229,024		184,002		3,749		3,518,341		102%	54,446
21.	A.E. Partners Limited-1995	244,725		51,998		0		0		175,549		72%	1,820
22.	A.E. Nineties-Public #4 Ltd.	1,287,752		633,330		81,326		3,867		1,341,850		104%	20,185
23.	A.E. Nineties-Series 16 Ltd.	1,643,320		863,594		93,260		2,678		1,844,244		112%	33,625
24.	A.E. Partners Limited-1996	367,416		80,003		0		0		307,276		84%	5,786
25.	A.E. Nineties-Public #5 Ltd.	1,654,740		661,228		85,683		52,804		1,476,260		89%	24,475
26.	A.E. Nineties-Series 17 Ltd.	2,113,947		904,537		137,914		2,991		2,724,085		129%	49,215
27.	A.E. Nineties-Public #6 Ltd.	1,950,345		865,566		105,973		62,793		2,798,824		144%	52,879
28.	A.E. Partners Limited-1997	231,050		47,479		0		0		247,320		107%	6,218
29.	A.E. Nineties-Series 18 Ltd.	3,448,751		1,484,650		163,577		18,352		3,923,542		114%	64,180
30.	A.E. Nineties-Public #7 Ltd.	3,812,150		1,165,269		136,310		13,677		2,105,732		55%	54,954
31.	A.E. Partners Limited-1998	756,360		151,346		0		0		621,393		82%	11,582
32.	A.E. Nineties-Series 19 Ltd.	4,776,598		1,701,635		190,722		32,264		4,273,924		89%	71,910
33.	A.E. Nineties-Public #8 Ltd.	3,148,181		896,549		106,814		93,638		2,646,981		84%	44,088
34.	A.E. Partners Limited-1999	196,500		35,382		0		0		176,069		90%	2,027
35.	1999 Viking Resources LP	1,678,038		692,676		0		3,170		2,891,699		172%	33,155
36.	Atlas America Series 20 Ltd.	6,297,945		1,602,401		170,578		5,719		7,395,456		117%	122,230
37.	Atlas America Public #9 Ltd.	6,256,271		1,579,693		151,204		16,681		5,568,924		89%	109,234
38.	Atlas America Series 21-A Ltd.	4,535,799		1,210,206		139,314		5,230		5,308,814		117%	118,968
39.	Atlas America Series 21-B Ltd.	6,442,761		2,131,118		146,795		5,786		6,403,644		99%	124,543
40.	Atlas America Public #10 Ltd.	7,227,432		1,892,789		170,524		99,444		7,772,150		108%	162,597
41.	Atlas America Series 22-2002 Ltd.	3,481,591		842,662		88,975		4,371		4,199,698		121%	79,408
42.	Atlas America Series 23-2002 Ltd.	3,214,850		753,806		82,896		4,253		3,237,048		101%	60,291
43.	Atlas America Public #11-2002 LP	13,295,300		2,440,153		281,159		27,662		11,036,378		83%	192,400
44.	Atlas America Series 24-2003(A) Ltd., LP	5,137,628		995,915		123,838		4,912		5,014,034		98%	124,344
45.	Atlas America Series 24-2003(B) Ltd., LP	8,100,983		1,657,016		165,036		5,870		7,713,148		95%	151,175

Table 3A provides information concerning the operating results of previous development drilling partnerships sponsored by the managing general partner and its affiliates.

TABLE 3A

MANAGING GENERAL PARTNER

OPERATING RESULTS - INCLUDING EXPENSES

AS OF MARCH 31, 2009

		Managing General		Total Costs			Cash		Latest Quarterly Cash Distribution As of
	Partnership	Partner Capital		Operating (3)	Admin.	Direct	Distributions (1)	Cash Return	Date of Table

46.	Atlas America Public #12-2003 LP	17,285,400		2,785,265	415,633	28,303	12,301,026	71%	267,347
47.	Atlas America Series 25-2004(A) LP	11,641,600		2,128,703	168,780	26,343	11,121,073	96%	240,502
48.	Atlas America Series 25-2004(B) LP	14,080,200		1,951,147	181,527	30,577	7,815,476	56%	228,265
49.	Atlas America Public #14-2004 LP	21,794,700		2,899,495	252,436	44,784	10,871,288	50%	172,369
50.	Atlas America Public #14-2005(A) LP	27,250,400		3,821,149	289,393	41,301	13,828,691	51%	479,252
51.	Atlas America Public 26-2005 LP	14,081,700		1,870,526	124,136	33,878	7,055,568	50%	309,443
52.	Atlas America Public #15-2005(A) LP	18,677,400	(4)	2,359,189	158,434	45,323	16,440,521	26%	425,429
53	Atlas America Public #15-2006(B) LP (2)	52,353,600	(4)	5,156,170	332,922	58,085	18,355,275	35%	1,508,722
54.	Atlas America Series 27-2006 L.P. (2)	24,126,600	(4)	1,854,609	108,221	44,731	5,718,823	24%	416,773
55.	Atlas Resources Public # 16-2007 (A) LP (2)	87,034,800	(4)	5,194,490	258,982	122,772	14,071,621	16%	2,806,775
56.	Atlas Resources Public # 17-2007 (A) LP (2)	58,554,300	(4)	2,697,539	90,535	70,420	7,366,589	13%	2,666,676
57.	Atlas Resources Public # 17-2008 (B) LP (2)	83,519,800	(4)	2,439,321	60,484	25,736	3,612,202	4%	3,367,088
58.	Atlas Resources Public # 18-2008 (A) LP (2)	37,516,500	(4)	0	0	0	(5)	0%	(5)
	(1) All cash distributions were from the sale of gas, except that the following partnerships also include revenue from the sale of properties: Atlas L.P. 1-1985 ($1,250), A.E Nineties-JV92 ($2,680) A.E. for the Nineties-1993 LTD ($8,837), A.E. Nineties-14 ($7,964), A.E. Nineties-15 ($4,776), A.E. Nineties-19 ($2,472), Atlas America Series 20 ($8,562), Atlas America Series 22 ($66), Atlas America Series 23 ($74), Atlas America Series 24-2003(A) ($19,196), Atlas America Series 24-2003(B) ($43,825), Atlas America Series 25-2004(A) ($1,445), Atlas America Series 25-2004(B) ($2,831), Atlas America Series 26-2005 ($1,939), A.E. Nineties-Public #1 ($25), A.E. Nineties-Public #2 ($33), A.E. Nineties-Public #3 ($25), A.E. Nineties-Public #5 ($1,406), A.E. Nineties-Public #7 ($2,296), Atlas America Public #9 ($4,446), Atlas America Public #10 ($2,415), Atlas America Public #11 ($5,696), Atlas America Public #12-2003 ($3,582), Atlas America Public #14-2004 ($2,374) and Atlas America Public # 14-2005 (A) ($954).
	(2) As of the date of this table there is not twelve months of production and/or not all wells are drilled or on-line to sell production.
	(3) Operating costs consist of gathering fees, water hauling fees, meter reading fees, repairs and maintenance, insurance and severance tax.
	(4) The managing general partner's capital contributions are through the date of this table and subject to further change.
	(5) Atlas Resources Public # 18-2008 (A) LP closed December 31, 2008 with distributions expected to begin summer 2009.

Table 4 sets forth the managing general partner's estimate of the federal tax savings to investors in the managing general partner's prior development drilling partnerships, based on the maximum marginal tax rate in each year, the share of tax deductions as a percentage of their subscriptions, and the aggregate cash distributions. You are urged to consult with your own tax advisors concerning your specific tax situation and should not assume that the past performance of prior partnerships is indicative of the future results of the partnerships.

TABLE 4

SUMMARY OF INVESTOR TAX BENEFITS AND CASH DISTRIBUTION RETURNS

AS OF MARCH 31, 2009

												Cumulative
											Total	Percent of Cash
			1st Year	Eff	Estimated Federal Tax Savings From (1):					Cash Distribution	Cash Dist.	Dist. And Tax
		Investor	Tax	Tax	1st Year I.D.C.	Depletion		Section 29		As of	And Tax	Savings to
	Partnership	Capital	Deduct.	Rate	Deduct. (2)	Allowance (2)	Depreciation (2)	Tax Credit (3)	Total	Date of Table (4) (5)	Savings (4) (5)	Date (4)(5)(6)
1.	Atlas L.P. 1 - 1985	$ 600,000	99%	50.0%	$ 298,337	$148,780	N/A	$ 55,915	$503,032	$ 1,901,965	$2,404,996	401%
2.	A.E. Partners Limited (1986)	631,250	99%	50.0%	312,889	87,650	N/A	13,507	414,046	960,434	1,374,480	218%
3.	A.E. Partners Limited 1987	721,000	99%	38.5%	356,895	70,395	N/A	N/A	427,290	962,216	1,389,506	193%
4.	A.E. Partners Limited 1988	617,050	99%	33.0%	244,351	63,687	N/A	N/A	308,038	867,751	1,175,789	191%
5.	A.E. Partners Limited 1989	550,000	99%	33.0%	179,685	83,220	N/A	N/A	262,905	1,048,202	1,311,108	238%
6.	A.E. Partners Limited-1990	887,500	99%	33.0%	275,125	123,461	N/A	281,660	680,246	1,640,095	2,320,341	261%
7.	Atlas-Energy Partners 1990 L.P.(Series 10)	2,200,000	100%	33.0%	726,000	221,547	N/A	521,602	1,469,149	2,553,483	4,022,632	183%
8.	Atlas-Energy Partners 1991 L.P.(Series 11)	750,000	100%	31.0%	232,500	116,597	N/A	329,800	678,897	1,338,026	2,016,922	269%
9.	A.E. Partners Limited-1991	868,750	100%	31.0%	269,313	137,954	N/A	315,893	723,161	1,764,170	2,487,331	286%
10.	Atlas-Energy for the Nineties-1 LP (Series 12)	2,212,500	100%	31.0%	685,875	235,243	N/A	617,285	1,538,402	2,646,427	4,184,829	189%
11.	Atlas JV 92 Limited Partnership	4,004,813	92.5%	31.0%	1,322,905	421,198	N/A	1,002,109	2,746,212	5,322,680	8,068,892	201%
12.	A.E. Partners Limited-1992	600,000	100%	31.0%	186,000	94,387	N/A	224,631	505,018	1,119,954	1,624,973	271%
13.	A.E. Nineties-Public #1 Ltd.	2,988,960	80.5%	36.0%	877,511	265,878	254,729	N/A	1,398,118	2,932,023	4,330,141	145%
14.	A.E. Nineties-1993 Ltd.	3,753,937	92.5%	39.6%	1,378,377	231,602	N/A	N/A	1,609,979	2,463,467	4,073,446	109%
15.	A.E. Partners Limited-1993	700,000	100%	39.6%	273,216	103,270	N/A	N/A	376,486	1,299,594	1,676,080	239%
16.	A.E. Nineties-Public #2 Ltd.	3,323,920	78.7%	39.6%	1,036,343	235,600	279,039	N/A	1,550,981	2,740,675	4,291,657	129%
17.	A.E. Nineties-Series 14 Ltd.	9,940,045	95%	39.6%	3,739,445	653,854	N/A	N/A	4,393,299	7,591,144	11,984,443	121%
18.	A.E. Partners Limited-1994	892,500	100%	39.6%	353,430	114,175	N/A	N/A	467,605	1,577,703	2,045,309	229%
19.	A.E. Nineties-Public #3 Ltd.	5,800,990	76.2%	39.6%	1,752,761	433,337	521,115	N/A	2,707,213	5,172,851	7,880,064	136%
20.	A.E. Nineties-Series 15 Ltd.	10,954,715	90.0%	39.6%	3,904,261	833,111	N/A	N/A	4,737,372	10,555,706	15,293,078	140%
21.	A.E. Partners Limited-1995	600,000	100%	39.6%	237,600	35,529	N/A	N/A	273,129	478,452	751,582	125%
22.	A.E. Nineties-Public #4 Ltd.	6,991,350	80.0%	39.6%	2,214,860	394,597	537,551	N/A	3,147,008	4,633,873	7,780,880	111%
23.	A.E. Nineties-Series 16 Ltd.	10,955,465	86.8%	39.6%	3,361,289	637,179	873,254	N/A	4,871,721	8,310,886	13,182,607	120%
24.	A.E. Partners Limited-1996	800,000	100%	39.6%	316,800	65,435	N/A	N/A	382,235	839,053	1,221,288	153%
25.	A.E. Nineties-Public #5 Ltd.	7,992,240	84.9%	39.6%	2,530,954	429,633	602,746	N/A	3,563,333	5,594,507	9,157,839	115%
26.	A.E. Nineties-Series 17 Ltd.	8,813,488	85.2%	39.6%	2,966,366	607,045	476,907	N/A	4,050,318	8,099,827	12,150,145	138%
27.	A.E. Nineties-Public #6 Ltd.	9,901,025	80.0%	39.6%	3,166,406	669,007	728,024	N/A	4,563,437	8,846,776	13,410,213	135%
28.	A.E. Partners Limited-1997	506,250	100%	39.6%	200,475	50,053	N/A	N/A	250,528	710,023	960,551	190%
29.	A.E. Nineties-Series 18 Ltd.	11,391,673	90.0%	39.6%	4,030,884	561,073	434,325	N/A	5,026,282	9,119,432	14,145,715	124%
30.	A.E. Nineties-Public #7 Ltd.	11,988,350	85.0%	39.6%	4,043,670	484,158	650,266	N/A	5,178,094	6,853,051	12,031,145	100%
31.	A.E. Partners Limited-1998	1,740,000	100.0%	39.6%	689,040	133,043	N/A	N/A	822,083	1,801,450	2,623,533	151%
32.	A.E. Nineties-Series 19 Ltd.	15,720,450	90.0%	39.6%	5,602,767	754,639	587,460	N/A	6,944,866	10,426,931	17,371,796	111%
33.	A.E. Nineties-Public #8 Ltd.	11,088,975	85.0%	39.6%	3,734,654	523,551	618,600	N/A	4,876,805	7,317,807	12,194,611	110%
34.	A.E. Partners Limited-1999	450,000	100.0%	39.6%	178,200	33,748	N/A	N/A	211,948	494,112	706,060	157%
35.	1999 Viking Resources LP	4,555,210	92.0%	39.6%	1,678,038	594,781	N/A	N/A	2,272,819	8,774,562	11,047,381	243%
36.	Atlas America Series 20 Ltd.	18,809,150	90.0%	39.6%	6,712,802	1,296,944	686,514	N/A	8,696,259	20,311,483	29,007,742	154%
37.	Atlas America Public #9 Ltd.	14,905,465	91.0%	39.6%	5,349,744	873,617	N/A	N/A	6,223,361	12,637,725	18,861,085	127%
38.	Atlas America Series 21-A Ltd.	12,510,713	91.0%	39.1%	4,468,617	665,591	324,564	N/A	5,458,771	10,614,797	16,073,569	128%
39.	Atlas America Series 21-B Ltd.	17,411,825	91.0%	39.1%	6,197,907	797,774	420,012	N/A	7,415,693	12,654,635	20,070,327	115%
40.	Atlas America Public #10 Ltd.	21,281,170	91.0%	39.1%	7,550,729	1,045,555	691,737	N/A	9,288,021	16,854,987	26,143,009	123%
41.	Atlas America Series 22-2002 Ltd.	10,156,375	91.0%	38.6%	3,564,312	491,795	302,416	N/A	4,358,523	8,875,102	13,233,626	130%
42.	Atlas America Series 23-2002 Ltd.	9,644,550	91.0%	38.6%	3,404,803	406,481	267,669	N/A	4,078,953	7,006,579	11,085,533	115%
43.	Atlas America Public #11-2002 LP	31,178,145	91.0%	38.6%	11,003,503	1,248,371	849,597	N/A	13,101,470	21,298,395	34,399,866	110%
44.	Atlas America Series 24-2003(A) Ltd., LP	14,363,955	91.0%	35.0%	4,578,250	567,440	397,749	N/A	5,543,440	10,475,481	16,018,921	112%
45.	Atlas America Series 24-2003(B) Ltd., LP	20,542,850	91.0%	35.0%	6,514,764	867,492	609,966	N/A	7,992,222	15,480,883	23,473,105	114%
46.	Atlas America Public #12-2003 LP	40,170,308	91.0%	35.0%	12,879,332	1,295,436	1,042,571	N/A	15,217,339	23,910,148	39,127,487	97%
47.	Atlas America Series 25-2004(A) LP	27,601,053	90.0%	35.0%	8,694,332	1,147,911	1,029,909	N/A	10,872,152	21,205,834	32,077,986	116%
48.	Atlas America Series 25-2004(B) LP	31,531,035	90.0%	35.0%	9,932,276	802,304	1,052,471	N/A	11,787,052	14,923,128	26,710,180	85%
49.	Atlas America Public #14-2004 LP	52,506,570	90.0%	35.0%	16,543,643	1,132,148	1,304,150	N/A	18,979,941	20,992,659	39,972,600	76%
50.	Atlas America Public #14-2005(A) LP	69,674,900	91.0%	35.0%	22,107,994	1,432,993	1,455,054	N/A	24,996,041	27,690,939	52,686,980	76%

TABLE 4

SUMMARY OF INVESTOR TAX BENEFITS AND CASH DISTRIBUTION RETURNS

AS OF MARCH 31, 2009

													Cumulative
												Total	Percent of Cash
				1st Year	Eff	Estimated Federal Tax Savings From (1):					Cash Distribution	Cash Dist.	Dist. And Tax
			Investor	Tax	Tax	1st Year I.D.C.	Depletion		Section 29		As of	And Tax	Savings to
	Partnership		Capital	Deduct.	Rate	Deduct. (2)	Allowance (2)	Depreciation (2)	Tax Credit (3)	Total	Date of Table (4) (5)	Savings (4) (5)	Date (4)(5)(6)
51.	Atlas America Series 26-2005 LP		34,886,465	90.0%	35.0%	10,989,458	614,302	729,850	N/A	12,333,610	12,368,523	24,702,132	71%
52.	Atlas America Public #15-2005(A) LP		52,245,720	90.0%	35.0%	16,457,402	834,998	1,011,789	N/A	18,304,188	17,228,181	35,532,369	68%
53.	Atlas America Public #15-2006(B) LP		147,513,130	90.0%	35.0%	46,466,636	1,886,362	2,188,177	N/A	50,541,176	38,055,365	88,596,541	60%
54.	Atlas America Series 27-2007 L.P.		70,882,965	90.0%	35.0%	22,328,134	695,314	727,769	N/A	23,751,217	13,320,222	37,071,439	52%
55.	Atlas Resources Public #16-2007(A) LP	(7)	199,685,750	100.0%	35.0%	69,890,013	1,772,034	N/A	N/A	71,662,047	27,608,679	99,270,725	50%
56.	Atlas Resources Public #17-2007(A) LP	(7)	163,010,430	92.3%	35.0%	52,649,796	1,378,132	839,771	N/A	54,867,699	20,079,059	74,946,758	46%
57.	Atlas Resources Public # 17-2008(B) LP	(7)	236,026,950	95.0%	35.0%	77,600,994	30,921	551,092	N/A	78,183,008	13,848,195	92,031,203	39%
58.	Atlas Resources Public #18-2008 (A) L.P.	(7)	201,242,770	85.0%	35.0%	59,869,724	0	0	N/A	59,869,724	(8)	59,869,724	30%
	1. These columns reflect the savings in taxes which would have been paid by an investor, assuming full use of deductions available to the investor through the 2008 tax year.
	2. The I.D.C. Deductions, Depletion Allowance and MACRS depreciation deductions have been reduced to credit equivalents.
	3. The Section 29 tax credit is not available with respect to wells drilled after December 31, 1992. N/A means not applicable.
	4. These distributions were all from production revenues, except that the following partnerships also include revenue from the sale of properties: A.E. Nineties-16 ($4,776), A.E. Nineties-19 ($1,607), Atlas America Series 20 ($6,662), Atlas America Series 22 ($34), Atlas America Series 23 ($38), Atlas America Series 24-2003(A) ($11,331), Atlas America Series 24-2003(B) ($22,557), Atlas America Series 25-2004(A) ($595), Atlas America Series 25-2004(B) ($1,052), Atlas America Series 26-2005 ($4,620) A.E. Nineties-Public #1 ($2,452), A.E. Nineties-Public #2 ($3,292), A.E. Nineties-Public #3 ($2,491), A.E. Nineties-Public #5 ($8,639), A.E. Nineties-Public #7 ($2,206), Atlas America Public # 10 ($4,687), Atlas America Public #11-2002 ($2,789), Atlas America Public #12-2003 ($1,568), Atlas America Public #14-2004 ($920) and Atlas America Public # 14-2005 (A) ($345).
	5. This column reflects total cash distributions beginning with the first production from the program and includes the return of investor's capital.
	6. These percentages are calculated by dividing the entry for each partnership in the "Total Cash Dist. And Tax Savings" column by that partnership 's entry in the "Investor Capital" column.
	7. As of the date of this table there is not twelve months of production and/or not all wells are drilled or on-line to sell production.
	8. This partnership closed December 31, 2008 with distributions expected to begin Summer 2009.

Table 5 sets forth payments made to the managing general partners and its affiliates from its previous partnerships.

TABLE 5

SUMMARY OF PAYMENTS TO THE MANAGING GENERAL PARTNER AND AFFILIATES

FROM PRIOR PARTNERSHIPS (1)

AS OF MARCH 31, 2009

									Cumulative
					Leasehold				Reimbursement
				Cumulative	Drilling and			Cumulative	of General and
		Investor		Gathering	Completion			Operator's	Administrative
	Partnership	Capital		Fees (1)	Costs (2)			Charges	Overhead

1.	Atlas L.P. 1 - 1985	$	600,000	0	$	600,000		368,140	$67,734
2.	A.E. Partners Limited (1986)	631,250		0	631,250			285,575	109,321
3.	A.E. Partners Limited 1987	721,000		0	721,000			321,427	101,776
4.	A.E. Partners Limited 1988	617,050		0	617,050			292,677	103,010
5.	A.E. Partners Limited 1989	550,000		0	550,000			270,708	102,320
6.	A.E. Partners Limited-1990	887,500		0	887,500			422,008	124,250
7.	Atlas-Energy Partners 1990 L.P.(Series 10)	2,200,000		0	2,200,000			1,341,641	119,734
8.	Atlas-Energy Partners 1991 L.P.(Series 11)	750,000		0	761,802		(3)	614,581	189,471
9.	A.E. Partners Limited-1991	868,750		0	867,500			393,847	160,286
10.	Atlas-Energy for the Nineties-1 LP (Series 12)	2,212,500		0	2,272,017		(3)	1,319,137	163,955
11.	Atlas JV 92 Limited Partnership	4,004,813		0	4,157,700			2,533,681	328,986
12.	A.E. Partners Limited-1992	600,000		0	600,000			241,282	79,388
13.	A.E. Nineties-Public #1 Ltd.	2,988,960		0	3,026,348		(3)	1,598,459	183,713
14.	A.E. Nineties-1993 Ltd.	3,753,937		0	3,480,656		(3)	1,690,396	206,138
15.	A.E. Partners Limited-1993	700,000		0	689,940			307,407	57,675
16.	A.E. Nineties-Public #2 Ltd.	3,323,920		0	3,324,668		(3)	1,330,651	163,133
17.	A.E. Nineties-Series 14 Ltd.	9,940,045		0	9,512,015		(3)	5,089,958	616,094
18.	A.E. Partners Limited-1994	892,500		0	892,500			368,436	74,586
19.	A.E. Nineties-Public #3 Ltd.	5,800,990		0	5,800,990			2,290,839	299,105
20.	A.E. Nineties-Series 15 Ltd.	10,954,715		0	9,859,244		(3)	763,415	613,339
21.	A.E. Partners Limited-1995	600,000		0	600,000			207,992	32,808
22.	A.E. Nineties-Public #4 Ltd.	6,991,350		0	6,991,350			2,533,319	325,304
23.	A.E. Nineties-Series 16 Ltd.	10,955,465		0	10,955,465			4,016,715	433,767
24.	A.E. Partners Limited-1996	800,000		0	800,000			320,014	44,454
25.	A.E. Nineties-Public #5 Ltd.	7,992,240		0	7,992,240			2,644,913	342,731
26.	A.E. Nineties-Series 17 Ltd.	8,813,488		0	8,813,488			3,413,349	520,429
27.	A.E. Nineties-Public #6 Ltd.	9,901,025		0	9,901,025			3,462,264	423,892
28.	A.E. Partners Limited-1997	506,250		0	506,250			189,915	26,777
29.	A.E. Nineties-Series 18 Ltd.	11,391,673		0	11,391,673			4,713,174	519,292
30.	A.E. Nineties-Public #7 Ltd.	11,988,350		0	11,988,350			3,758,932	439,708
31.	A.E. Partners Limited-1998	1,740,000		0	1,740,000			605,384	53,525
32.	A.E. Nineties-Series 19 Ltd.	15,720,450		0	15,720,450			5,402,016	605,467
33.	A.E. Nineties-Public #8 Ltd.	11,088,975		0	11,088,975			3,091,547	368,323
34.	A.E. Partners Limited-1999	450,000		0	450,000			141,529	9,459
35.	1999 Viking Resources LP	4,555,210		0	4,555,210			2,770,705	0
36.	Atlas America Series 20 Ltd.	18,809,150		0	18,809,150			5,934,819	631,770
37.	Atlas America Public #9 Ltd.	14,905,465		1,666,393	14,905,465			3,321,632	471,881
38.	Atlas America Series 21-A Ltd.	12,510,713		1,265,754	12,510,713			2,311,182	411,761
39.	Atlas America Series 21-B Ltd.	17,411,825		1,654,713	17,411,825			4,613,281	431,749
40.	Atlas America Public #10 Ltd.	21,281,170		2,282,142	21,281,170			3,632,806	532,887
41.	Atlas America Series 22-2002 Ltd.	10,156,375		1,134,304	10,156,375			1,456,107	273,518
42.	Atlas America Series 23-2002 Ltd.	9,644,550		1,026,856	9,644,550			1,328,753	259,050
43.	Atlas America Public #11-2002 LP	31,178,145		2,626,767	31,178,145			4,463,726	810,288
44.	Atlas America Series 24-2003(A) Ltd., LP	14,363,955		1,141,494	14,363,955			1,853,200	326,756
45.	Atlas America Series 24-2003(B) Ltd., LP	20,542,850		1,862,800	20,542,850			2,984,470	484,800
46.	Atlas America Public #12-2003 LP	40,170,308		3,201,547	40,170,308			4,952,375	889,425
47.	Atlas America Series 25-2004(A) LP	27,601,053		3,126,048	27,601,053			2,957,572	482,228
48.	Atlas America Series 25-2004(B) LP	31,531,035		2,157,346	31,531,035			3,403,687	518,648
49.	Atlas America Public #14-2004 LP	52,506,570		3,199,394	52,506,570			5,089,216	721,246
50.	Atlas America Public #14-2005(A) LP	69,674,900		5,111,895	69,674,900			5,800,963	826,837
51.	Atlas America Series 26-2005 LP	34,886,465		2,509,428	34,886,465			2,373,176	332,715
52.	Atlas America Public #15-2005(A) LP	52,245,720		3,799,529	52,245,720			2,741,057	451,764
53.	Atlas America Public #15-2006(B) LP	147,513,130		8,299,063	147,513,130			6,768,646	972,887
54.	Atlas America Series 27-2006 LP	70,882,965		2,961,193	70,882,965			2,727,791	331,968
55.	Atlas Resources Public #16-2007(A) LP	199,685,750		6,203,088	199,685,750			7,488,241	682,609
56.	Atlas Resources Public #17-2007(A) LP	163,010,430		4,255,391	163,010,430			4,174,419	258,672
57.	Atlas Resources Public # 17-2008 (B) LP	236,026,950		3,556,747	236,026,950			3,722,636	180,494
58.	Atlas Resources Public #18-2008 (A) LP	201,242,770		0	201,242,770			0	0
	(1) The amount of gathering fees paid to the managing general partner and its affiliates from 2001 to the date of this table are shown for those partnerships which began operations on or after December 31, 2000. The books and records of the earlier partnerships do not separately allocate all of the gathering fees paid by them. Additional information concerning the gathering fees paid by those partnerships will be provided to you on written request to the managing general partner.
	(2) Excluding the managing general partner's capital contributions.
	(3) Includes additional drilling costs paid with production revenues.

MANAGEMENT

Managing General Partner and Operator

The partnership will have no officers, directors or employees. Instead, Atlas Resources, LLC, a Pennsylvania limited liability company, which was originally formed as a corporation in 1979 and then changed to a limited liability company on March 28, 2006, will serve as the managing general partner of the partnership. However, see “– Transactions with Management and Affiliates,” below, regarding the managing general partner’s dependence on its indirect parent companies, Atlas America (ATLS), ATN and their affiliates, for facilities, management and administrative functions. Atlas America and ATN, which have entered into a definitive merger agreement, as discussed below, are headquartered at Westpointe Corporate Center One, 1550 Coraopolis Heights Road, 2nd Floor, Moon Township, Pennsylvania 15108, near the Pittsburgh International Airport, which is also the managing general partner’s primary office. Since 1985 the managing general partner has sponsored 21 public and 38 private partnerships to conduct natural gas drilling and development activities primarily in the Appalachian Basin in the states of Pennsylvania, Ohio, New York and Tennessee as set forth in “Prior Activities.” In these partnerships the managing general partner and its affiliates acted as the operator and the general drilling contractor and were responsible for drilling, completing, and operating the wells. The managing general partner has a 97% completion rate for wells drilled by its development partnerships. Currently, the managing general partner and its affiliates operate more than 7,500 natural gas and oil wells located in those areas.

Set forth below is a discussion of certain corporate actions that have been taken since September 1998 when Atlas Energy Group, Inc., the former parent company of the managing general partner, merged into Atlas America, a Delaware holding company, which was then a subsidiary of Resource America, Inc., a publicly-traded company, which is sometimes referred to in this prospectus as Resource America. In May 2004 Resource America conducted a public offering of a portion of its common stock (the “shares”) in Atlas America and 2,645,000 shares were registered and sold at a price of at $15.50 per share resulting in gross proceeds of $41 million. Further, in May 2004, in connection with the Atlas America offering, the following officers and key employees of the managing general partner and Atlas America set forth in “– Officers, Directors and Other Key Personnel of Managing General Partner,” below, resigned their positions with Resource America and all of its subsidiaries that are not also subsidiaries of Atlas America: Mr. Freddie M. Kotek, Mr. Frank P. Carolas, Mr. Jeffrey C. Simmons, and Ms. Marci Bleichmar. After the public offering of Atlas America, Resource America continued to own approximately 80.2% of Atlas America’s common stock until it distributed all of its remaining 10.7 million shares of common stock in Atlas America to its common stockholders on June 30, 2005. The distribution was in the form of a spin-off by means of a tax free dividend of approximately 0.6 shares of Atlas America to Resource America common stockholders for each share of Resource America common stock owned. After the spin-off, Resource America’s rights are defined by agreements between Resource America and Atlas America.

In December 2006, Atlas America transferred to ATN, a newly-formed, limited liability company subsidiary of Atlas America, substantially all of its natural gas and oil exploration and production assets pursuant to the completion of an initial public offering of 7,273,750 Class B limited liability company interests of ATN. At the end of the offering, pursuant to the contribution, conveyance and assumption agreement among Atlas America, ATN and Atlas Energy Operating Company, LLC (“Atlas Energy Operating”), the operating subsidiary of ATN, Atlas America contributed to ATN all of the stock of Atlas America’s natural gas and oil development and production subsidiaries as well as the development and production assets owned by it. As consideration for this contribution, on December 18, 2006 ATN distributed to Atlas America $139,944,000 net proceeds of the offering, 29,352,996 common units, 748,456 Class A units, and the management incentive interests. Pursuant to the contribution agreement, Atlas America contributed to its subsidiary, Atlas Energy Management, Inc. (“Atlas Management”), the 748,456 Class A units and the management incentive interests. Atlas America retained approximately 81% of the limited liability company interests of ATN. In connection with the above transaction, the following actions or agreements were entered into by the parties. Also, see the discussion below concerning the intended merger of Atlas America and ATN.

Pursuant to the contribution agreement until December 18, 2007, Atlas America was to indemnify ATN against certain potential environmental liabilities associated with the operation of the assets and occurring before December 18, 2006. However, Atlas America’s obligation was not to exceed $25 million, and it did not have any indemnification obligation unless ATN’s losses exceeded $500,000 in the aggregate, and then only to the extent such aggregate losses exceeded $500,000.

Additionally, Atlas America will indemnify ATN for losses attributable to title defects to the oil and gas property interests until December 18, 2009, and indefinitely for losses attributable to retained liabilities and income taxes attributable to pre-closing operations and the formation transactions. ATN will indemnify Atlas America for all losses attributable to the post-closing operations of the assets contributed to it, to the extent not subject to Atlas America’s indemnification obligations.

ATN became a party to a master natural gas gathering agreement between Atlas America and Atlas Pipeline Partners, L.P. Also, Atlas Pipeline Partners and Atlas Pipeline Operating Partnership, L.P. (collectively, “Atlas Pipeline”), gathered substantially all of the natural gas from wells operated by ATN. The gathering fees paid to Atlas Pipeline under the master natural gas gathering agreement were generally greater than the gathering fees paid by the partnerships or the managing general partner’s other partnerships for gathering their natural gas. Pursuant to the contribution agreement, Atlas America assumed ATN’s obligation to pay these gathering fees to Atlas Pipeline and ATN paid Atlas America the gathering fees it received from the partnerships and the managing general partner’s other partnerships and fees associated with production to its interest. However, this agreement has been replaced with new gas gathering agreements with Laurel Mountain. (See “Proposed Activities – Sale of Natural Gas and Oil Production – Gathering of Natural Gas.”)

Atlas America and ATN entered into an Omnibus Agreement, which provides that if a business opportunity with respect to an investment in or acquisition of a domestic gas or oil production or development business is presented to ATN or Atlas America or its affiliates, ATN will have the first right to pursue the business opportunity if the opportunity is a control investment, that is, majority control of the voting securities of an entity. If the opportunity is a non-control investment, then 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 ATN. However, if the opportunity involves an investment in natural gas or oil wells or other natural gas or oil rights, even a non-control investment, ATN will have the right of first refusal. The omnibus agreement will remain in effect so long as Atlas America or one of its affiliates has the power, directly or indirectly, to direct ATN’s management and policies.

ATN, Atlas Energy Operating Company, LLC and Atlas Energy Management, Inc., entered into a management agreement in connection with the initial public offering of ATN as discussed in “– Transactions with Management and Affiliates.”

On June 29, 2007, ATN announced that it completed its acquisition of DTE Gas & Oil Company (“DGO”), formerly a wholly owned subsidiary of DTE Energy Company. The total consideration paid by ATN, including adjustments for capital expenditures and working capital was approximately $1.273 billion in cash, subject to final closing adjustments. DGO owns interests in approximately 2,150 natural gas wells producing from the Antrim Shale, located in Michigan’s northern lower peninsula.

The financing for the acquisition was obtained through a new revolving loan facility and the proceeds of a private placement to institutional investors, both of which are described below. The revolving loan facility was entered into by Atlas Energy Operating with J.P. Morgan Securities, Inc. as sole bookrunner and lead arranger, JP Morgan Chase Bank, N.A. as administrative agent, and a syndicate of lenders. The revolving loan facility is for five-years with an initial borrowing base of $850 million.

Atlas Energy Operating borrowed $713.9 million under the revolving loan facility on June 29, 2007 to finance a portion of the purchase price of the DGO acquisition and to repay indebtedness under the prior credit facility entered into on December 18, 2006 with Wachovia Bank, N.A. The revolving loan facility may also be used to finance working capital and for other general corporate purposes.

As with the credit facility that was replaced, the managing general partner and various energy subsidiaries of ATN are guarantors of borrowings under the revolving loan facility, and the borrowings will be collateralized by substantially all of the assets of ATN, the managing general partner and the other guarantors (collectively the “obligors”). This includes the managing general partner’s interests in its partnerships, including the partnerships composing the program, but does not include your units or any other investor’s units in the partnership. See “Management’s Discussion and Analysis of Financial Condition, Results of Operations, Liquidity and Capital Resources” for further details on this credit facility.

To finance the remainder of the purchase price for the DGO acquisition, on June 29, 2007, ATN completed a private placement with net proceeds of $597.5 million of equity securities to third party investors, consisting of 7,298,181 common units and 16,702,828 Class D units, at a negotiated, weighted average price per unit of $25.00 (the “private placement”). All of the Class D units were automatically converted into common units on a one-to-one basis on November 10, 2007. The converted common units, together with the common units issued with respect to this acquisition, represent an equity interest of approximately 39% in ATN. Additionally, ATN entered into a registration rights agreement in connection with the sale of the units which required ATN to prepare and file a registration statement covering the resale of such units by January 31, 2008 and have such registration statement declared effective by May 30, 2008. ATN filed this registration statement on January 3, 2008, which was declared effective February 20, 2008. On May 7, 2008, ATN sold 600,000 of its Class B common units to Atlas America, Inc. in a private placement at $42 per common unit increasing Atlas America’s ownership of ATN’s common units to 29,952,996 common units. The proceeds of $25.2 million were used to repay a portion of ATN’s outstanding balance under its revolving credit facility. On May 16, 2008, ATN announced a public offering of 2,070,000 of its Class B common units with UBS Investment Bank and Wachovia Securities acting as joint book-running managers and underwriters of this offering. The proceeds of approximately $82.5 million were used to repay a portion of ATN’s outstanding balance under its revolving credit facility. The increased borrowing capacity will be used by ATN to fund additional acreage acquisitions and accelerated development of the Marcellus Shale as well as further development of its other drilling programs and lease acquisition activities. See “– Organizational Diagrams and Security Ownership of Beneficial Owners” for the current voting ownership of ATN.

ATN, its parent company Atlas America, and their affiliate, Atlas Energy Management, Inc., have entered into an Agreement and Plan of Merger (the “Merger Agreement”) as of April 27, 2009, pursuant to which a Delaware limited liability company to be formed as a wholly owned subsidiary of Atlas America (“Merger Sub”) will merge into ATN, with ATN continuing as the surviving company and as a wholly owned subsidiary of Atlas America, and Atlas America will change its name to Atlas Energy, Inc. If the merger is completed, the combination of Atlas America and ATN will result in one board of directors, that will consist of the ten independent directors of Atlas America and ATN serving at the time the merger is completed, as well as Messrs. Edward E. Cohen and Jonathan Z. Cohen, Chief Executive Officer and Vice Chairman, respectively, of both Atlas America and ATN as set forth below.

Completion of the merger is subject to:

the approval by a majority of ATN’s Class B common units and a majority of Atlas America’s common stock;

ATN’s lenders; and

other customary closing conditions.

Notwithstanding, the managing general partner expects the merger to be completed in the third quarter of 2009. See “Litigation,” however, regarding the merger.

As of April 27, 2009, Atlas America and its subsidiaries (other than ATN and its subsidiaries) beneficially owned 29,952,996 Class B common units of ATN, representing approximately 47.26% of the outstanding ATN Class B common units.

If the merger is completed, subject to the closing conditions set forth above, each outstanding ATN Class B common unit, other than ATN Class B common units owned by Atlas America and its subsidiaries and ATN Class B common units held in treasury, will be cancelled and converted into the right to receive 1.16 shares of Atlas America’s common stock and the ATN Class B common units will be delisted from the New York Stock Exchange.

Also, the intended merger does not provide for the termination or amendment of Atlas Energy Management, Inc.’s existing management agreement to manage ATN’s business affairs as discussed in “– Transactions with Management and Affiliates.”

Officers, Directors and Other Key Personnel of Managing General Partner

The officers and directors of the managing general partner will serve until their successors are elected. The officers, directors, and key personnel of the managing general partner are as follows:

NAME	AGE	POSITION OR OFFICE
Freddie M. Kotek	53	Chairman of the Board of Directors, Chief Executive Officer and President
Frank P. Carolas	49	Executive Vice President – Land and Geology and a Director
Jeffrey C. Simmons	50	Executive Vice President – Operations and a Director
Richard D. Weber	45	Director
Jack L. Hollander	53	Senior Vice President – Direct Participation Programs
Matthew A. Jones	47	Chief Financial Officer
Sean P. McGrath	38	Chief Accounting Officer
John F. Hammond	37	Secretary
Michael G. Hartzell	53	Vice President – Land Administration
Donald R. Laughlin	61	Vice President – Drilling and Production
Marci F. Bleichmar	39	Senior Vice President of Marketing
Sherwood S. Lutz	58	Senior Geologist/Manager of Geology
Michael W. Brecko	51	Director of Energy Marketing
Karen A. Black	48	Vice President – Partnership Administration
Justin T. Atkinson	36	Director of Due Diligence
Winifred C. Loncar	68	Director of Investor Services
Sharon L. Miller	45	Vice President and Assistant Chief Accounting Officer
Tommy L. Thompson	53	Vice President – Horizontal Drilling

With respect to the biographical information set forth below, the approximate amount of an individual’s professional time devoted to the business and affairs of the managing general partner, Atlas America, ATN and Atlas Management, have been aggregated.

Freddie M. Kotek. President and Chief Executive Officer since January 2002 and Chairman of the Board of Directors since September 2001. Mr. Kotek has been Executive Vice President of Atlas America since February 2004, and served as a director from September 2001 until February 2004 and served as Chief Financial Officer from February 2004 until March 2005. Mr. Kotek was a Senior Vice President of Resource America and President of Resource Leasing, Inc. (a wholly-owned subsidiary of Resource America) from 1995 until May 2004 when he resigned from Resource America and all of its subsidiaries which are not subsidiaries of Atlas America. Mr. Kotek was President of Resource Properties from September 2000 to October 2001 and its Executive Vice President from 1993 to August 1999. Mr. Kotek has been a registered representative and principal of Anthem Securities since May 2000. Mr. Kotek received a Bachelor of Arts degree from Rutgers College in 1977 with high honors in Economics. He also received a Master in Business Administration degree from the Harvard Graduate School of Business Administration in 1981. Mr. Kotek will devote approximately 95% of his professional time to the business and affairs of the managing general partner, Atlas America, ATN and Atlas Management, and the remainder of his professional time to the business and affairs of the managing general partner’s other affiliates.

Frank P. Carolas. Executive Vice President – Land and Geology and a Director since January 2001. Mr. Carolas has been an Executive Vice President of Atlas America since January 2001 and served as a Director of Atlas America from January 2002 until February 2004. Mr. Carolas has been a Senior Vice President of Atlas Energy Management, Inc. since 2006. Mr. Carolas was a Vice President of Resource America from April 2001 until May 2004 when he resigned from Resource America. Mr. Carolas served as Vice President of Land and Geology for the managing general partner from July 1999 until December 2000 and for Atlas America from 1998 until December 2000. Before that Mr. Carolas served as Vice President of Atlas Energy Group, Inc. from 1997 until 1998, which was the former parent company of the managing general partner. Mr. Carolas is a certified petroleum geologist and has been with the managing general partner and its affiliates since 1981. He received a Bachelor of Science degree in Geology from Pennsylvania State University in 1981 and is an active member of the American Association of Petroleum Geologists. Mr. Carolas devotes approximately 100% of his professional time to the business and affairs of the managing general partner, Atlas America, ATN and Atlas Management.

Jeffrey C. Simmons. Executive Vice President – Operations and a Director since January, 2001. Mr. Simmons has been an Executive Vice President of Atlas America since January 2001 and was a Director of Atlas America from January 2002 until February 2004. Mr. Simmons has been a Senior Vice President of Atlas Energy Management, Inc. since 2006. Mr. Simmons was a Vice President of Resource America from April 2001 until May 2004 when he resigned from Resource America. Mr. Simmons served as Vice President of Operations for the managing general partner from July 1999 until December 2000 and for Atlas America from 1998 until December 2000. Mr. Simmons joined Resource America in 1986 as a senior petroleum engineer and has served in various executive positions with its energy subsidiaries since then. Mr. Simmons received his Bachelor of Science degree with honors in Petroleum Engineering from Marietta College in 1981 and his Masters degree in Business Administration from Ashland University in 1992. Mr. Simmons devotes approximately 90% of his professional time to the business and affairs of the managing general partner, Atlas America, ATN and Atlas Management, and the remainder of his professional time to the business and affairs of the managing general partner’s other affiliates, primarily Viking Resources and Resource Energy.

Richard D. Weber. A Director since July 1, 2009. Mr. Weber also has been the President, Chief Operating Officer and a director of ATN since its formation in 2006 and President, Chief Operating Officer and a director of Atlas 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.

Jack L. Hollander. Senior Vice President – Direct Participation Programs since January 2002 and before that he served as Vice President – Direct Participation Programs from January 2001 until December 2001. Mr. Hollander also serves 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 earned a Bachelor of Science degree from the University of Rhode Island in 1978, his law degree from Brooklyn Law School in 1981, and a Master of Law degree in Taxation from New York University School of Law Graduate Division in 1982. Mr. Hollander is a member of the New York State bar and the Chairman of the Investment Program Association, which is an industry association, as of March 2005. Mr. Hollander has been a registered representative of Anthem Securities since November 2004. Mr. Hollander devotes approximately 100% of his professional time to the business and affairs of the managing general partner, Atlas America, ATN and Atlas Management.

Matthew A. Jones, Chief Financial Officer since March 2006. Mr. Jones has been Chief Financial Officer since January 2006 and a director since February 2006 of Atlas Pipeline Holdings, L.P., and has been the Chief Financial Officer of Atlas Pipeline Partners GP and Atlas America since March 2005. He has been the Chief Financial Officer and a director of Atlas Energy Management since its formation. From 1996 to 2005, Mr. Jones worked in the Investment Banking Group at Friedman Billings Ramsey, concluding as Managing Director. Mr. Jones worked in Friedman Billings Ramsey’s Energy Investment Banking Group from 1999 to 2005, and in Friedman Billings Ramsey’s Specialty Finance and Real Estate Group from 1996 to 1999. Mr. Jones is a Chartered Financial Analyst. Mr. Jones devotes approximately 50% of his professional time to the business and affairs of the managing general partner, Atlas America, ATN and Atlas Management.

Sean P. McGrath. Chief Accounting Officer since December 31, 2008. Mr. McGrath also has been the Chief Accounting Officer of Atlas America, Inc. and ATN since December 31, 2008. Mr. McGrath has been the Chief Accounting Officer of Atlas Pipeline Partners GP since May 2005 and Chief Accounting Officer of Atlas Pipeline Holdings GP since January 2006. Mr. McGrath was the Controller of Sunoco Logistics Partners L.P., a publicly-traded partnership that transports, terminals and stores refined products and crude oil from 2002 to 2005. Mr. McGrath is a Certified Public Accountant and received his Bachelor of Science degree in accounting from LaSalle University in 1993. Mr. McGrath will devote approximately 70% of his professional time to the business and affairs of the managing general partner and Atlas America, and the remainder of his professional time to the business and affairs of the managing general partner’s other affiliates, including Atlas Pipeline Partners GP.

John F. Hammond. Secretary since July 1, 2009. Mr. Hammond has been the Vice President and General Counsel of ATN since September 2008. Prior to joining ATN, Mr. Hammond was the Assistant General Counsel of CNX Gas Corporation from November 2005 until August 2008. Mr. Hammond was a Senior Attorney at CONSOL Energy Inc. from 2004 until his transition to CNX Gas. Prior to his employment with CONSOL Energy Inc., Mr. Hammond was a lawyer at the law firm of Cohen & Grigsby, P.C. Mr. Hammond received a Bachelor of Arts degree from Harvard College in 1994, a Master of Studies degree from Oxford University in 1996 and a Juris Doctor degree from Cornell Law School in 2000. Mr. Hammond will devote approximately 90% of his professional time to the business and affairs of the managing general partner and ATN, and the remainder of his professional time to the business and affairs of the managing general partner’s other affiliates.

Michael G. Hartzell. Vice President – Land Administration since September 2001. Mr. Hartzell has been Vice President – Land Administration of Atlas America since January 2002, and before that served as Senior Land Coordinator from January 1999 to January 2002. Mr. Hartzell has been Vice President – Land Administration of Atlas Energy Management, Inc. since 2006. Mr. Hartzell has been with the managing general partner and its affiliates since 1980 when he began his career as a land department representative. Mr. Hartzell manages all Land Department functions. Mr. Hartzell serves on the Environmental Committee of the Independent Oil and Gas Association of Pennsylvania and is a past Chairman of the Committee. Mr. Hartzell received his Bachelor of Science degree in Business Management from the University of Phoenix in 2004. Mr. Hartzell devotes approximately 100% of his professional time to the business and affairs of the managing general partner, Atlas America, ATN and Atlas Management.

Donald R. Laughlin. Vice President – Drilling and Production since September 2001. Mr. Laughlin also serves as Vice President – Drilling and Production for Atlas America since January 2002, and before that served as Senior Drilling Engineer since May 2001 when he joined Atlas America. Mr. Laughlin has been Vice President – Drilling and Production of Atlas Energy Management, Inc. since 2006. 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. from 1977 until 1989 as Vice President—Operations, and Columbia Gas from 1970 to 1977 as Drilling Engineer and Gas Storage Engineer. Mr. Laughlin received his Petroleum Engineering degree from the University of Pittsburgh in 1970. He is a member of the Society of Petroleum Engineers. Mr. Laughlin devotes approximately 100% of his professional time to the business and affairs of the managing general partner, Atlas America, ATN and Atlas Management.

Marci F. Bleichmar. Senior Vice President of Marketing since May 2008 and before that, Vice President of Marketing from February 2001 through May 2008. Ms. Bleichmar also serves as Senior Vice President of Marketing for Atlas America since February 2001 and was with Resource America from February 2001 until May 2004 when she resigned from Resource America. 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 LP. From November 1994 until 1998, Ms. Bleichmar was an Associate on the Derivatives Trading Desk of JP Morgan. Ms. Bleichmar has been a registered representative of Anthem Securities since October 2001. Ms. Bleichmar received a Bachelor of Arts degree from the University of Wisconsin in 1992. Ms. Bleichmar devotes approximately 100% of her professional time to the business and affairs of the managing general partner, Atlas America, ATN and Atlas Management.

Sherwood S. Lutz. Senior Geologist/Manager of Geology. In 1996 Mr. Lutz joined Viking Resources, which was purchased by Resource America in 1999 as senior geologist. Since 1999 Mr. Lutz has been a senior geologist for the managing general partner and Atlas America. Mr. Lutz received his Bachelor of Science degree in Geological Sciences from the Pennsylvania State University in 1973. Mr. Lutz is a certified petroleum geologist with the American Association of Petroleum Geologists as well as a licensed professional geologist in Pennsylvania. Mr. Lutz devotes approximately 100% of his professional time to the business and affairs of the managing general partner, Atlas America, ATN and Atlas Management.

Michael W. Brecko. Director of Energy Marketing since November 2002. Mr. Brecko has over 19 years of natural gas marketing experience in the oil and natural gas industry. Mr. Brecko is a 1980 graduate from The Pennsylvania State University with a Bachelor of Science degree in Civil Engineering. His career in natural gas marketing began when he joined Equitable Gas Company, a local distribution company, as a marketing representative in the commercial/ industrial marketing division from May 1986 to August 1992. He subsequently joined O&R Energy, a subsidiary of Orange and Rockland Utilities, as regional marketing manager from August 1992 to November 1993. Beginning in December 1993 through July 2001, Mr. Brecko worked for Cabot Oil & Gas Corporation, a mid-sized Appalachian oil and natural gas producer, as an account executive and he was promoted in August 1998 to natural gas trader. In November 2001, he joined Sprague Energy Corporation, a multi-energy sourced company, as a regional account manager before joining Atlas America in 2002. Mr. Brecko devotes approximately 100% of his professional time to the business and affairs of the managing general partner, Atlas America, ATN and Atlas Management.

Karen A. Black. Vice President – Partnership Administration since February 2003. Ms. Black is also Vice President and Financial and Operations Principal of Anthem Securities since October 2002. Ms. Black joined the managing general partner and Atlas America in July 2000 and served as manager of production, revenue and partnership accounting from July 2000 through October 2001, after which she served as manager and financial analyst until her appointment as Vice President – Partnership Administration. Before joining the managing general partner in 2000, Ms. Black was associated with Texas Keystone, Inc. as controller from April 1997 through June 2000. Ms. Black was employed as a tax accountant for Sobol Bosco & Associates, Inc. from May 1996 through March 1997. Ms. Black received a Bachelor of Arts degree from the University of Pittsburgh, Johnstown in 1982. Ms. Black devotes approximately 50% of her professional time to the business and affairs of the managing general partner, Atlas America, ATN and Atlas Management, and the remainder of her professional time to the business and affairs of Anthem Securities, with which she has been affiliated since April 2002.

Justin T. Atkinson. Director of Due Diligence since February 2003. Mr. Atkinson also serves as President of Anthem Securities since February 2004 and as Chief Compliance Officer since October 2002. Before that Mr. Atkinson served as assistant compliance officer of Anthem Securities from December 2001 until October 2002 and Vice President from October 2002 until February 2004. Before his employment with the managing general partner, Mr. Atkinson was a manager of investor and broker/dealer relations with Viking Resources Corporation from 1996 until November 2001. Mr. Atkinson earned a Bachelor of Arts degree in Business Management in 1995 from Walsh University in North Canton, Ohio. Mr. Atkinson devotes approximately 25% of his professional time to the business and affairs of the managing general partner, Atlas America, ATN and Atlas Management, and the remainder of his professional time to the business and affairs of Anthem Securities, with which he has been affiliated since April 2001.

Winifred C. Loncar. Director of Investor Services since February 2003. Ms. Loncar previously held the position of manager of investor services from the inception of the investor service department in 1990 to February 2003. Ms. Loncar has also been associated with Anthem Securities as an unregistered, but fingerprinted, person since March 2006. Before that she was executive secretary to the managing general partner. Ms. Loncar received a Bachelor of Science degree in Business from Point Park University in 1998. Ms. Loncar devotes approximately 100% of her professional time to the business and affairs of the managing general partner, Atlas America, ATN and Atlas Management.

Sharon L. Miller. Vice President and Assistant Chief Accounting Officer since December 31, 2008. Also, Ms. Miller has been the Vice President and Chief Accounting Officer of ATN since January 2009, and was previously the Director of Finance of Atlas America, Inc. since July 2004 and ATN since December 2006. Ms. Miller was a manager with Hall, Kistler and Company, LLC, a certified public accounting firm that specializes in oil and gas clients, from 1998 to June 2004. Ms. Miller is a Certified Public Accountant and received her Bachelor of Science degree in accounting from the University of Akron in 1985. Ms. Miller devotes approximately 100% of her professional time to the business and affairs of the managing general partner, Atlas America, ATN and Atlas Management.

Tommy L. Thompson. Vice President – Horizontal Drilling since January 2009. Mr. Thompson previously served as Drilling Manager with Wagner & Brown, Ltd. from February 2008 to December 2009 and Occidental Petroleum from February 1995 to November 2007. He attended the University of Arkansas and received his Bachelor of Science degree in engineering from Louisiana Tech University in 1979. Mr. Thompson devotes approximately 100% of his professional time to the business and affairs of the managing general partner, Atlas America, ATN and Atlas Management.

Organizational Diagrams and Security Ownership of Beneficial Owners

Subject to the merger of Atlas America and ATN discussed above, Atlas America and its subsidiaries (other than ATN and its subsidiaries) own approximately 47.3% of the Class B common units of ATN. The only other beneficial owners of more than 5% of the outstanding limited liability company interests that are known to ATN are Cobalt Capital Management, Inc. and Omega Advisors, Inc.

ATN owns 100% of the limited liability company interests of Atlas Energy Operating Company, LLC, which owns 100% of the limited liability company interests of AIC, LLC, which owns 100% of the limited liability company interests of Atlas Resources, LLC, the managing general partner of the three partnerships composing the Atlas Resources Public #18-2008 Program. The three partnerships are Atlas Resources Public #18-2008(A) L.P., Atlas Resources Public #18-2009(B) L.P. and Atlas Resources Public #18-2009(C) L.P.

The officers and directors of Atlas America and ATN are set forth below. The directors of AIC, LLC are Jonathan Z. Cohen, and Jeffrey C. Simmons. The biography of Mr. Simmons is set forth above and the biography of Mr. Cohen is set forth below.

Set forth below are a current organizational chart of Atlas America and its subsidiaries before the intended merger with ATN and a pro forma organizational chart of Atlas America and certain of its subsidiaries after the intended merger with ATN. Also included is an organizational chart of Atlas Pipeline Partners after the sale of its Appalachian gathering system to Laurel Mountain.

ORGANIZATIONAL DIAGRAM

* See below for Laurel Mountain and its affiliates

PRO FORMA ORGANIZATIONAL DIAGRAM OF ATLAS AMERICA AFTER THE INTENDED MERGER (1)

(1)

Under the merger agreement, Atlas America would form a new wholly owned subsidiary corporation, Merger Sub, LLC. (“Merger Sub”). Merger Sub would merge into ATN, with ATN surviving as a wholly owned subsidiary of Atlas America. In the intended merger, each outstanding ATN Class B common unit (other than those held by Atlas America) would be converted into 1.16 shares of Atlas America common stock, and the ATN Class B common units would be delisted from the New York Stock Exchange. Simultaneously with the merger, Atlas America would be renamed “Atlas Energy, Inc.” The relative percentage of common stock in the parent entity (i.e., Atlas America) held by former public ATN unitholders and Atlas America stockholders will depend on the exchange ratio.

ORGANIZATIONAL DIAGRAM OF ATLAS PIPELINE PARTNERS

Atlas America, Inc., a Delaware Company

As of June 2009, the executive officers and directors for Atlas America include the following:

NAME	AGE	POSITION
Edward E. Cohen	69	Chairman, Chief Executive Officer and President
Frank P. Carolas	49	Executive Vice President
Freddie M. Kotek	53	Executive Vice President
Jeffrey C. Simmons	50	Executive Vice President
Matthew A. Jones	47	Chief Financial Officer
Sean P. McGrath	38	Chief Accounting Officer
Jonathan Z. Cohen	38	Vice Chairman
Carlton M. Arrendell	47	Director
William R. Bagnell	45	Director
Donald W. Delson	57	Director
Nicholas DiNubile	56	Director
Dennis A. Holtz	68	Director
Harmon S. Spolan	73	Director

See “– Officers, Directors and Other Key Personnel of Managing General Partner,” above, for biographical information on Messrs. Frank P. Carolas, Freddie M. Kotek, Jeffrey C. Simmons, Matthew A. Jones and Sean P. McGrath. Biographical information on the other officers and directors is set forth below.

Edward E. Cohen has been the Chairman of the Board of Directors, the Chief Executive Officer and President of Atlas America since its organization in September 2000. Mr. Cohen has been the Chairman of the Board and Chief Executive Officer of ATN and its manager, Atlas Management, since their formation in June 2006. Mr. Cohen has been the 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, and 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. In addition, Mr. Cohen has been Chairman of the Board of Directors of Resource America, Inc. (a publicly-traded specialized asset management company) since 1990, and was its Chief Executive Officer from 1988 until 2004, and President from 2000 until 2003; Chairman of the Board of Resource Capital Corp. (a publicly-traded real estate investment trust) since its formation in September 2005; a director of TRM Corporation (a publicly-traded consumer services company) from 1998 to July 2007; and Chairman of the Board of Brandywine Construction & Management, Inc. (a property management company) since 1994. Mr. Cohen is the father of Jonathan Z. Cohen.

Jonathan Z. Cohen has been Vice Chairman of the Board of Directors of Atlas America since its formation. Mr. Cohen has been Vice Chairman of the Board of ATN and Atlas Management since their formation in June 2006. Mr. Cohen has been Vice Chairman of the Managing Board of Atlas Pipeline Partners GP since its formation in 1999 and Vice Chairman of the Board of Atlas Pipeline Holdings GP since its formation in January 2006. Mr. Cohen has been a senior officer of Resource America since 1998, serving as the Chief Executive Officer since 2004, President since 2003 and a director since 2002. Mr. Cohen has been Chief Executive Officer, President and a director of Resource Capital Corp. since its formation in 2005, and was the trustee and secretary of RAIT Financial Trust (a publicly-traded real estate investment trust) from 1997, and its Vice Chairman from 2003, until December 2006. Mr. Cohen is a son of Edward E. Cohen.

Carlton M. Arrendell has been a director of Atlas America since February 2004. Mr. Arrendell has been a vice president and chief investment officer of Full Spectrum of NY LLC since the spring of 2007. Before joining Full Spectrum, Mr. Arrendell was a special real estate consultant to the AFL-CIO Investment Trust Corporation following six years of service as Investment Trust Corporation’s chief investment officer beginning in 1997.

William R. Bagnell has been a director of Atlas America since February 2004. Mr. Bagnell has been involved in the energy industry in various capacities since 1986. He has been Vice President—Energy for Planalytics, Inc. (an energy industry risk management and software company) since March 2000, and was Director of Sales for Fisher Tank Company (a national manufacturer of carbon and stainless steel bulk storage tanks) from September 1998 to January 2000. Before that, he served as Manager of Business Development for Buckeye Pipeline Partners, L.P. (a refined petroleum products transportation company) from October 1992 until September 1998. Mr. Bagnell served as an independent member of the Managing Board of Atlas Pipeline Partners GP from its formation in November 1999 until May 2004.

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

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

Dennis A. Holtz has been a director of Atlas America since February 2004. Mr. Holtz maintained a corporate law practice with D.A. Holtz, Esquire & Associates in Philadelphia and New Jersey from 1988 until his retirement in January 2008.

Harmon S. Spolan has been a director of Atlas America since August 2006. Since January 2007, Mr. Spolan has served as of counsel to the law firm Cozen O’Connor, where he is chairman of the firm’s charitable foundation. From 1999 until January 2007, Mr. Spolan was a member of the firm and served as chairman of its Financial Services Practice Group and as co-marketing partner. Prior to joining Cozen O’Connor, Mr. Spolan served as President, Chief Operating Officer, and a director of JeffBanks, Inc., and its subsidiary bank for 22 years. Mr. Spolan has served as director of TRM Corporation since June 2002.

The managing general partner and its affiliates under Atlas America employ more than 900 persons.

Atlas Energy Resources, LLC (“ATN”), a Delaware Limited Liability Company

As of February 2, 2009, the executive officers and directors for ATN include the following:

NAME	AGE	POSITION OR OFFICE
Edward E. Cohen	69	Chairman of the Board and Chief Executive Officer
Jonathan Z. Cohen	38	Vice Chairman of the Board
Richard D. Weber	45	President, Chief Operating Officer and Director
Matthew A. Jones	47	Chief Financial Officer and Director
Sean P. McGrath	38	Chief Accounting Officer
Lisa Washington	41	Chief Legal Officer and Secretary
Richard L. Redmond, Jr.	52	Senior Vice President
Sharon L. Miller	45	Vice President and Assistant Chief Accounting Officer
Walter C. Jones	46	Director
Ellen F. Warren	52	Director
Bruce M. Wolf	60	Director
Jessica K. Davis	32	Director

See “– Officers, Directors and Other Key Personnel of Managing General Partner” and “– Atlas America, Inc., a Delaware Company,” above for biographical information on Ms. Miller and Messrs. Edward E. Cohen, Jonathan Z. Cohen, Matthew A. Jones, Richard D. Weber and Sean P. McGrath. Biographical information on the other officers and directors of ATN is set forth below. R. Randle Scarborough, an ATN board member who had served since August 2008, passed away on January 29, 2009. ATN is in the process of filling the vacancy created by Mr. Scarborough’s death.

Lisa Washington has been the Chief Legal Officer and Secretary of ATN since its formation in 2006 and Chief Legal Officer and Secretary of Atlas Management since its formation. Ms. Washington has been the Vice President, Chief Legal Officer and Secretary of Atlas America and Atlas Pipeline Partners GP since November 2005. She has been the Chief Legal Officer and Secretary of Atlas Pipeline Holdings GP since January 2006. From 1999 to November 2005, Ms. Washington was an attorney in the business department of the law firm of Blank Rome LLP.

Richard L. Redmond, Jr. has been a Senior Vice President of ATN and President and Chief Executive Officer of Atlas Gas and Oil since June 2007. Mr. Redmond served as President of DTE Gas & Oil and DTE Gas Resources from 2002 until June 2007 and Executive Director of MCN Oil and Gas Company from 1999 to 2001. Before that, he served for ten years as Vice President of Operations of CMS Oil and Gas Company.

Walter C. Jones has been a member of the Board of Directors of ATN since December 2006. Since June 2007, Mr. Jones has been an advisor to GRAVITAS Capital Advisors, LLC, an independent investment advisory firm. From May 2005 until June 2007, he was 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.

Jessica K. Davis is currently an attorney with the Drinker, Biddle & Reath LLP law firm, in Philadelphia, Pennsylvania since August 2005. Prior to joining Drinker, Biddle & Reath LLP, Ms. Davis was a corporate litigation attorney with the Stroock & Stroock & Lavan law firm in New York, New York from September 2002 to August 2005.

Atlas Energy Management, Inc., a Delaware Company

Since July 28, 2006, the executive officers and directors for Atlas Energy Management, Inc. (“Atlas Management”) include the following:

NAME	AGE	POSITION OR OFFICE
Edward E. Cohen	69	Chairman of the Board, Chief Executive Officer and Director
Jonathan Z. Cohen	38	Director
Richard D. Weber	45	President, Chief Operating Officer and Director
Jeffrey C. Simmons	50	Senior Vice President
Frank P. Carolas	49	Senior Vice President
Matthew A. Jones	47	Chief Financial Officer
Sean P. McGrath	38	Chief Accounting Officer
Donald R. Laughlin	61	Vice President – Drilling and Production
Michael G. Hartzell	53	Vice President – Land Administration
Lisa Washington	41	Chief Legal Officer and Secretary

See “– Officers, Directors and Other Key Personnel of Managing General Partner,” “– Atlas America, Inc., a Delaware Company” and “– Atlas Energy Resources, LLC (“ATN”), a Delaware Limited Liability Company,” above for biographical information on the above individuals.

Remuneration of Officers and Directors

No officer or director of the managing general partner will receive any remuneration or other compensation from the partnership. These persons will receive compensation solely from affiliated companies of the managing general partner.

Code of Business Conduct and Ethics

Because the partnership does not employ any persons, the managing general partner has determined that the partnership will rely on a Code of Business Conduct and Ethics adopted by ATN that applies to the principal executive officer, principal financial officer and principal accounting officer of the managing general partner, as well as to persons performing services for the managing general partner generally. You may obtain a copy of this Code of Business Conduct and Ethics by a request to the managing general partner at Atlas Resources, LLC, Westpointe Corporate Center One, 1550 Coraopolis Heights Road, 2nd Floor, Moon Township, Pennsylvania 15108.

Transactions with Management and Affiliates

The partnership’s policies and procedures for reviewing, approving or ratifying related party transactions with the managing general partner are set forth in the partnership agreement, and the material terms of those policies and procedures are discussed in greater detail in “Conflicts of Interest.” In this regard, the partnership considers related party transactions to be certain transactions between the partnership and the managing general partner or its affiliates as identified in the partnership agreement. Section 4.03(d) “Transactions with the Managing General Partner” of the partnership agreement deals with transactions between the partnership and the managing general partner and its affiliates. Those include the following:

the transfer of leases from the managing general partner to the partnership concerning the amount of acreage that must be transferred in the prospect to the partnership, including the transfer of an equal proportionate interest;

the possible subsequent enlargement of the prospect;

the transfer to the partnership of less than the managing general partner’s and its affiliates’ entire interest in the prospect;

the limitations on sale of undeveloped and developed leases by the partnership to the managing general partner;

the limitations on activities of the managing general partner and its affiliates on leases acquired by the partnership;

the transfer of leases between affiliated limited partnerships;

the sale of all of the partnership’s assets;

the providing of services to the partnership by the managing general partner and its affiliates at competitive rates;

loans from the managing general partner to the partnership and no loans from the partnership to the managing general partner or its affiliates;

farmouts to and from the managing general partner and the partnership;

commitments of the partnership’s future production;

sharing in gas marketing arrangements;

advance payments from the partnership to the managing general partner;

the partnership participating in other partnerships;

the requirement that transactions between the partnership and the managing general partner must be fair and reasonable;

roll-up limitations (see “Conflicts of Interest” for a more complete discussion); and

the compensation and reimbursement of expenses to be paid by the partnership to the managing general partner and its affiliates (see “Compensation” for a more complete discussion).

The officers of the managing general partner are responsible for applying the partnership’s policies and procedures set forth in the partnership agreement with respect to transactions between the partnership and the managing general partner and its affiliates, just as they are responsible for applying all of the other provisions of the partnership agreement.

The managing general partner depends on its indirect parent companies, Atlas America, ATN, and their affiliates, for all management and administrative functions. The managing general partner previously paid a management fee of 7% of subscription funds raised to, and reimbursed Atlas America for, management and administrative services and expenses incurred on its behalf based on an allocation of total revenues. Such fees and reimbursements amounted to $64.1 million, $13.9 million, and $47.5 million for the year ended December 31, 2006, the three months ended December 31, 2005, and the year ended September 30, 2005, respectively. Beginning with the 2007 calendar year, the management fee of 7% of subscription funds raised, fees and reimbursements were payable to ATN, and amounted to $82.5 million for the year ended December 31, 2007, and $71.8 million for the nine months ended September 30, 2008. Only a portion of the amounts reimbursable to ATN will be attributable to services that will be provided to the partnership. Additionally, in connection with the initial public offering of ATN described above, ATN, Atlas Energy Operating and Atlas Management entered into a management agreement. In this regard, the intended merger between Atlas America and ATN does not provide for the termination or amendment of this arrangement.

Subject to any changes resulting from the intended merger between Atlas America and ATN, the management agreement provides that Atlas Management will manage ATN’s business affairs under the supervision of ATN’s board of directors (the “board”). Atlas Management will provide ATN, including the managing general partner, with all services necessary or appropriate for the conduct of their business. This includes the following:

providing executive and administrative personnel, office space and office services required in rendering services to ATN and its subsidiaries;

investigating, analyzing and proposing possible acquisition and investment opportunities;

evaluating and recommending to the board and ATN’s officers hedging strategies and engaging in hedging activities on ATN’s behalf, consistent with such strategies;

negotiating agreements on ATN’s behalf;

at the direction of the audit committee of the board, causing ATN 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 ATN to qualify to do business in all applicable jurisdictions and to obtain and maintain all appropriate licenses;

assisting ATN in complying with all regulatory requirements applicable to it with respect to its 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 Securities Exchange Act;

handling and resolving all claims, disputes or controversies (including all litigation, arbitration, settlement or other proceedings or negotiations) in which ATN may be involved or to which it may be subject arising out of its day-to-day operations, subject to such limitations or parameters as may be imposed from time to time by the board;

advising ATN with respect to obtaining financing for ATN’s operations;

performing such other services as may be required from time to time for management and other activities relating to ATN’s assets as the board reasonably requests or Atlas Management deems appropriate under the particular circumstances;

obtaining and maintaining, on ATN’s behalf, insurance coverage for ATN’s business and operations, including errors and omissions insurance with respect to the services provided by Atlas Management, in each case in the types and minimum limits as Atlas Management determines to be appropriate and as is consistent with standard industry practice; and

using commercially reasonable efforts to cause ATN to comply with all applicable laws.

In exercising its powers and discharging its duties under the management agreement, Atlas Management must act in good faith. ATN will reimburse Atlas Management for all expenses that it incurs on ATN’s behalf pursuant to the management agreement. These expenses will include costs for providing corporate staff and support services to ATN, including the managing general partner and its partnerships. Atlas Management will charge on a fully-allocated cost basis for services provided to ATN. This fully-allocated cost basis is based on the percentage of time spent by personnel of Atlas Management and its affiliates on ATN’s matters and includes the compensation paid by Atlas Management 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 ATN’s business and affairs, subject to the periodic review and approval of the board’s audit or conflicts committee.

Atlas Management, its stockholders, directors, officers, employees and affiliates will not be liable to ATN, and any subsidiary of ATN, for acts or omissions performed in good faith and in accordance with and pursuant to the management agreement, except by reason of acts constituting gross negligence, bad faith, willful misconduct, fraud or a knowing violation of criminal law. ATN will indemnify Atlas Management, its stockholders, directors, officers, employees and affiliates for all expenses and losses arising from acts of Atlas Management, its stockholders, directors, officers, employees and affiliates not constituting gross negligence, bad faith, willful misconduct, fraud or a knowing violation of criminal law performed in good faith in accordance with and pursuant to the management agreement. Atlas Management and its affiliates will indemnify ATN for all expenses and losses arising from acts of Atlas Management or its affiliates constituting gross negligence, bad faith, willful misconduct, fraud or a knowing violation of criminal law or any claims by employees of Atlas Management or its affiliates relating to the terms and conditions of their employment. Atlas Management and/or Atlas America will carry errors and omissions and other customary insurance.

The management agreement may not be amended without the prior approval of the conflicts committee of the board if the proposed amendment will, in the reasonable discretion of the board, adversely affect common unitholders of ATN. The management agreement does not have a specific term; however, Atlas Management may not terminate the agreement before December 18, 2016. ATN may terminate the management agreement only upon the affirmative vote of holders of at least two-thirds of its outstanding common units, including units held by Atlas America and its affiliates. If ATN terminates the management agreement, Atlas Management 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.

See “Financial Information Concerning the Managing General Partner and Atlas Resources Public #18-2009(C) L.P.,” concerning the indebtedness owed by the managing general partner to Atlas America and/or ATN.

The managing general partner and its officers, directors and affiliates have in the past invested, and may in the future invest, in partnerships sponsored by the managing general partner. They may also subscribe for units in the partnership as described in “Plan of Distribution.”

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION, RESULTS OF OPERATIONS,

LIQUIDITY AND CAPITAL RESOURCES

Atlas Resources Public #18-2009(C) L.P. has been formed as a limited partnership under the Delaware Revised Uniform Limited Partnership Act. However, it has not included any historical information in this prospectus since it has no net worth, does not own any properties on which wells will be drilled, has no third-party investors, and has not conducted any operations. (See “Capitalization and Source of Funds and Use of Proceeds,” “Proposed Activities,” “Competition, Markets and Regulation,” and “Financial Information Concerning the Managing General Partner and Atlas Resources Public #18-2009(C) L.P.”)

The partnership will depend on the proceeds of this offering and the managing general partner’s capital contributions to carry out its proposed activities. The partnership intends to use its subscription proceeds to pay the following:

the intangible drilling costs of the partnership’s wells;

the investors’ share of equipment costs of the partnership’s wells; and

the investors’ share of any cost overruns of drilling and completing the partnership’s wells.

The managing general partner believes that the partnership’s liquidity requirements will be satisfied from the following:

subscription proceeds of this offering;

the managing general partner’s capital contributions;

cash flow from future operations; and

partnership borrowings, if necessary.

The managing general partner also anticipates that no additional funds will be required for operating costs before the partnership begins receiving production revenues from its wells.

Substantially all of the subscription proceeds of you and the other investors in the partnership will be committed or expended after the offering of the partnership closes. If the partnership requires additional funds for cost overruns or additional development or remedial work after a well begins producing, then these funds may be provided by:

subscription proceeds, if available, which will result in drilling fewer wells, or acquiring a lesser working interest in one or more wells;

borrowings from the managing general partner or its affiliates; or

retaining partnership revenues.

There will be no borrowings from third-parties. The amount that may be borrowed by the partnership from the managing general partner and its affiliates may not at any time exceed 5% of the partnership’s subscription proceeds from you and the other investors and must be without recourse to you and the other investors. Notwithstanding, this limitation will not affect the partnership’s ability to enter into agreements and financial instruments relating to hedging the partnership’s natural gas and oil and pledging up to 100% of the partnership’s assets and reserves in connection therewith. The partnership’s repayment of any borrowings would be from partnership production revenues and would reduce or delay your cash distributions.

If the managing general partner loans money to the partnership, which it is not required to do, then:

the interest charged to the partnership must not exceed the managing general partner’s interest cost or the interest that would be charged to the partnership without reference to the managing general partner’s financial abilities or guarantees by unrelated lenders, on comparable loans for the same purpose; and

the managing general partner may not receive points or other financing charges or fees, although the actual amount of the charges incurred from third-party lenders may be reimbursed to the managing general partner.

On June 29, 2007, Atlas Energy Operating entered into a credit agreement with J.P. Morgan Securities, Inc., as sole bookrunner and lead arranger, JP Morgan Chase Bank, N.A., as administrative agent, and a syndicate of lenders (the “Credit Agreement”), pursuant to which an $850 million five-year revolving loan facility (the “revolving loan facility”) was made available. ATN and all existing or future direct or indirect material domestic subsidiaries of ATN, other than Anthem Securities, Inc., act as guarantors under the credit agreement, which includes the managing general partner. Up to $50 million of the revolving loan facility may be used for standby letters of credit. Borrowings under the revolving loan facility are secured by a first priority lien and security interest on not less than 80% of the engineered value of the oil and gas interests included in the determination of the borrowing base and a first priority lien and security interest on all of the equity interests of each guarantor other than ATN and all of the other material assets of ATN and its subsidiaries. Negotiations with the lenders and other parties to the Credit Agreement are being conducted by ATN, since the majority of the lenders must approve the intended merger between Atlas America and ATN. In this regard, if the merger is approved the Credit Agreement must be revised to permit the merger and other revisions to the Credit Agreement will be made, such as restrictions on the amount of cash that can be distributed to the surviving company after the merger.

Atlas Energy Operating borrowed $713.9 million under the revolving loan facility on June 29, 2007 to finance a portion of the purchase price of the acquisition of DGO as described in “Management” and to repay indebtedness under its prior revolving facility entered into on December 18, 2006 with Wachovia Bank, N.A. The proceeds of the revolving loan facility may also be used to finance working capital and for other general corporate purposes.

Borrowings bear interest at a rate per annum equal to either: (i) the higher of (a) the rate of interest publicly announced by the administrative agent as its prime rate in effect (“alternate base rate”) and (b) the federal funds effective rate from time to time plus 0.5%; or (ii) the rate two business days prior to the beginning of the interest period at which eurodollar deposits in the London interbank market for one, two, three or six months are quoted on the Reuters screen, as adjusted for actual statutory reserve requirements for Eurocurrency liabilities (“adjusted libo rate”), each plus the applicable margin based on borrowing base utilization percentage, elected at Atlas Energy’s option.

Amounts under the revolving loan facility may be repaid and re-borrowed until June 29, 2012. Mandatory prepayments of the revolving loan facility are required any time the aggregate amount of the outstanding revolving credit loans and letters of credit under the revolving loan facility exceed 100% of the borrowing base.

The revolving loan facility contains covenants that, among other things, limit ATN’s ability to:

incur additional indebtedness;

grant certain liens;

enter into certain leases;

make certain loans, acquisitions, capital expenditures and investments;

enter into hedging arrangements that exceed (A) during the 24-month period immediately following the date on which a swap agreement is entered: the lesser of (1) 90% of the anticipated production from proved oil and gas properties and (2) 100% of the anticipated production from proved developed producing oil and gas properties and (B) after the 24-month period immediately following the swap date, 85% of proved reserves;

make any change to the character of its business or the business of its investment partnerships;

merge or consolidate; or

engage in certain asset dispositions, including a sale of all or substantially all of its assets.

The revolving loan facility requires the following:

Atlas Energy Operating to maintain a current ratio (defined as the ratio of current assets to current liabilities) of not less than 1.0 to 1.0; and

a funded debt to EBITDA ratio of the following: (i) for the period beginning on the closing date through December 31, 2008: 4.0:1, (ii) for the period beginning after December 31, 2008 through December 31, 2009: 3.75:1, and (iii) thereafter: 3.5:1.

If an event of default exists under the revolving loan facility, the lenders will be able to accelerate the maturity of the revolving loan facility and exercise other customary rights and remedies, including prohibiting ATN from paying distributions. Each of the following is an event of default:

failure to pay any principal when due or any interest, fees or other amounts under the revolving loan facility;

failure to pay any principal or interest on any other debt aggregating $25 million or more;

a representation, warranty or certification made under the loan documents or in any certificate furnished thereunder is false or misleading as of the time made or furnished in any material respect;

failure to perform under any obligation set forth in the revolving loan facility, subject to a grace period in certain circumstances;

an event having a material adverse effect on ATN, any of the guarantors or the collateral used to secure indebtedness;

admission in writing of the inability to, or being generally unable to, pay debts as they become due;

bankruptcy or insolvency events;

commencement of a proceeding or case in any court of competent jurisdiction, without application or consent, involving liquidation, reorganization, dissolution or winding-up or the appointment of a trustee, receiver, custodian, liquidator or the like;

commencement of a proceeding or case in any court of competent jurisdiction which could reasonably be expected to result in liability in excess of $25 million;

an ERISA event which could reasonably be expected to result in liability in excess of $25 million;

the entry of, and failure to pay, one or more judgments in excess of $25 million;

the loan documents cease to be in full force and effect or cease to create a valid, binding and enforceable lien;

a change of control, generally defined as (i) a group or person acquiring 35% or more of ATN’s outstanding voting units, (ii) occupation of a majority of the seats (other than vacant seats) on the board of directors of ATN by persons who were neither nominated by the board of directors of ATN nor appointed by directors so nominated, (iii) ATN’s failure to own 100% of Atlas Energy Operating or (iv) the failure of Atlas America or any of its wholly-owned subsidiaries to own at least 51% of the equity of Atlas Management; and

concealment of property with the intent to hinder, delay or defraud any lender with respect to their rights to such property.

The borrowing base is redetermined semi-annually on April 1 and October 1, subject to changes in the oil and gas reserves. In addition, because of the current credit crisis in the United States, there is a risk that this credit facility could be adversely affected.

On January 18, 2008, ATN sold $250 million of senior unsecured notes due in 2018 in a private placement at a coupon rate of 10.75%. On May 5, 2008, ATN sold an additional $150 million of its 10.75% senior unsecured notes in a follow-on offering of 9.85%. The notes are guaranteed by ATN’s affiliates, including the managing general partner. ATN used the proceeds of the note offerings to reduce the balance outstanding on its senior secured revolving loan facility described above. ATN will benefit from a reduction of 75 basis points in the interest rate on the remaining approximately $400 million outstanding on the revolving loan facility, and will increase the long term availability of funds on the revolving loan facility by approximately $180 million. Upon the sale of the senior unsecured notes, the borrowing base on the revolving loan facility was reduced by 25% of the principal of the senior notes, or $100 million, in accordance with the Credit Agreement. With the redetermination of the borrowing base on April 1, 2008 and the subsequent reductions due to the senior unsecured note offerings in May 2008, the borrowing base on the revolving credit facility was $697.5 million. The borrowing base as a result of the October 1, 2008 redetermination remained $697.5 million. Additionally, ATN entered into an interest rate swap contract for $150 million. ATN will swap the floating rate incurred on a portion of its existing senior secured revolving loan facility for a three year fixed swap rate of 3.11%. The interest rate swap contract will mature in January 2011.

The managing general partner depends on ATN and its affiliates for management and administrative functions. Prior to the initial public offering of ATN, the managing general partner paid a management fee and expense reimbursements to Atlas America for management and administrative services as described in “Management – Transactions with Management and Affiliates.” See the footnotes to the managing general partner’s audited financial statements and the footnotes to the managing general partner’s unaudited financial statements for more details concerning the credit facility and inter-company borrowings in “Financial Information Concerning the Managing General Partner and Atlas Resources Public #18-2009(C) L.P.”

PROPOSED ACTIVITIES

Overview of Drilling Activities

The managing general partner anticipates that the subscription proceeds of the partnership will be used to drill primarily natural gas development wells, which means a well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive. Stratigraphic means a layer of rock which has characteristics that differentiate it from the rocks above and below it. Stratigraphic horizon generally means that part of a formation or layer of rock with sufficient porosity and permeability to form a petroleum reservoir. Currently, the partnership does not hold any interests in any properties or prospects on which the wells will be drilled.

Although the majority of the wells to be drilled by the partnership will be classified as natural gas wells, which may produce a small amount of oil, some of the wells may be classified as oil wells or combination oil and natural gas wells.

The partnership will be a separate business entity from the other partnerships in the program, and you will be a partner only in the partnership in which you invest. You will have no interest in the business, assets or tax benefits of the other partnerships unless you also invested in the other partnership or partnerships. Thus, your investment return will depend solely on the operations and success or lack of success of the particular partnership in which you invest.

Each partnership in the program generally will drill different wells, but they may own working interests and participate in drilling and completing one or more of the same wells. The number of wells to be drilled by the partnership cannot be determined precisely before the funding of the partnership and is determined primarily by:

the amount of subscription proceeds raised by the partnership;

the geographical areas in which wells are drilled by the partnership;

the partnership’s percentage of working interest owned in the wells, which could range from 25% to 100%; and

the cost of the partnership’s wells, including any cost overruns for intangible drilling costs and equipment costs of the wells which are charged to you and the other investors under the partnership agreement.

For the estimated number of wells to be drilled at the minimum subscription proceeds and the maximum subscription proceeds for the partnership, see “Risk Factors – Risks Related to an Investment in the Partnership – Spreading the Risks of Drilling Among a Number of Wells Will be Reduced if Less than the Maximum Subscription Proceeds are Received and Fewer Wells are Drilled.”

In this regard, the managing general partner anticipates that the maximum subscription proceeds of the partnership will be allocated among the partnership’s proposed primary drilling areas described in “Appendix A – Information Regarding Currently Proposed Prospects for Atlas Resources Public #18-2009(C) L.P.” as follows:

approximately 79% in the Marcellus Shale primary area in western Pennsylvania; and

approximately 13% in the New Albany Shale (Indiana) primary area.

The managing general partner considers a proposed drilling area to be a primary area if it expects to use 10% or more of the partnership’s subscription proceeds to drill wells in the area. The percentages set forth above, however, are estimates and may change materially depending on actual drilling results. (See “– Primary Areas of Operations” and “– Secondary Areas of Operations,” below.)

Before the managing general partner selects a prospect on which a well will be drilled by the partnership, it will review all available geologic and production data for wells located in the vicinity of the proposed well including, but not limited to:

various well logs;

completion reports;

plugging reports; and

production reports.

In selecting prospects for drilling, the managing general partner will use the following criteria from adjacent prospects or in the immediate area to the extent available to it, such as production information, sand thickness, porosities and water saturations which lead the managing general partner to believe that the proposed well locations will be productive. For example, production information from surrounding wells in the area is an important indicator in evaluating the economic potential of a proposed well to be drilled. It has been the managing general partner’s experience that natural gas production from wells drilled to the formations or the reservoirs in the areas of operations discussed below in “– Primary Areas of Operations,” is reasonably consistent with nearby wells, although from time to time there can be great differences in the natural gas volumes and performance of wells located on contiguous prospects. However, generally there will be a little or no production information from surrounding wells for the majority of the wells to be drilled by the partnership, which results in greater uncertainty to you and the other investors. This lack of production information results primarily from the managing general partner, as operator, proposing wells to be drilled in the partnership that are adjacent to wells it has previously drilled as operator in prior partnerships that have not yet been completed, have not yet been put on-line to sell production, or have been producing for only a short period of time so there is little or no production information available. This risk is further increased for both vertical and horizontal wells drilled to the Marcellus Shale primary area, and the horizontal wells drilled in the north central Tennessee secondary area and the New Albany Shale (Indiana) primary area and any horizontal wells drilled in the Antrim Shale secondary area in Michigan since the managing general partner has limited production information for vertical wells drilled to the Marcellus Shale and limited experience in drilling horizontal wells in the other areas. See “Appendix A – Information Regarding Currently Proposed Prospects for Atlas Resources Public #18-2009(C) L.P.” and the production data associated with each of the primary areas as set forth in Appendix A.

Production information is only one factor, and the managing general partner may propose a well to be drilled by the partnership because geologic trends in the immediate area, such as sand thickness, porosities and water saturations, lead the managing general partner to believe that the proposed well location will be productive. In most cases, a prospect must be classified as proved undeveloped before the managing general partner will drill the well, which generally means that the well is being drilled to a geologic feature which contains proved reserves and is adjacent to a prospect that has or had a productive well. See the partnership agreement for the complete definition of a prospect.

Primary Areas of Operations

The managing general partner will not decide on all of the specific wells to be drilled by the partnership until the offering of units in the partnership has ended. However, the managing general partner intends that the partnership will drill the prospects described in “Appendix A – Information Regarding Currently Proposed Prospects for Atlas Resources Public #18-2009(C) L.P.” These prospects represent some of the wells to be drilled if the maximum subscription proceeds are received by the partnership. The managing general partner will substitute a new prospect if there are material adverse events with respect to any of the currently proposed prospects. For example, the managing general partner will substitute a prospect if:

the latest geological and production data in the area from new wells being drilled indicates that the well may be non-productive or less productive than anticipated;

there are potential title problems;

drilling rigs, tubular goods and services in the area will not be available;

approvals by federal and state departments or agencies cannot be obtained; or

other properties are available that appear to be of a higher quality.

Because not all of the prospects for the partnership will be specified, or if a prospect is specified, it may be withdrawn, you will not be able to evaluate all of the prospects that will be drilled by your partnership. However, by waiting as long as possible before selecting all of the prospects to be drilled by the partnership, the managing general partner may acquire additional information to help it select better prospects for the partnership, and it may be able to include prospects that were not available when this prospectus was written or even when the offering of units in the partnership is closed.

The following discussion includes a general description of the areas where the managing general partner anticipates partnership wells may be drilled. The majority of the areas are situated in mature producing regions in the United States. The areas have well known geologic characteristics as described below, although the geological aspects of each area listed below are continually being evaluated by the managing general partner. Thus, each area discussed below may ultimately include other counties which are not set forth below. For purposes of this prospectus, however, the counties listed below are generally descriptive of the respective drilling areas being discussed. The two primary areas for the partnerships’ drilling activities are:

the Marcellus Shale geological formation in western Pennsylvania; and

the Upper Devonian Shale reservoir, which includes the New Albany Shale, in Knox and Sullivan Counties, Indiana.

Generally, the areas which will be drilled, including the secondary areas described below, have the following similarities:

geological features such as structure and faulting generally are not factors used to find commercial production from a well drilled to this formation or these reservoirs and the governing factors appear to be sand or oolite (carbonate sand) quality in terms of net pay zone thickness, porosity, the effectiveness of fracture stimulation in the well and with respect to the shale formations, encountering natural fractures can enhance the productivity of the well;

a well drilled to this formation or these reservoirs usually requires hydraulic fracturing of the formation to stimulate productive capacity, with the exception of wells drilled in the New Albany Shale (Indiana) primary area, which are produced unstimulated;

generally, natural gas from a well drilled to this formation or these reservoirs is produced at rates which decline rapidly during the first few years of operations and, although the well can produce for many years, a proportionately larger amount of the well’s production can be expected within the first several years; and

it has been the managing general partner’s experience that natural gas production from wells drilled to this formation or these reservoirs is reasonably consistent with nearby wells, although from time to time there can be great differences in the natural gas volumes and performance of wells on contiguous prospects. Thus, as drilling 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.

With respect to the Marcellus Shale primary area, in 2006 the managing general partner decided that it and its affiliated investment partnerships would begin drilling deeper wells to the Marcellus Shale. Thus, to date the managing general partner has limited production information in this area. In the period from the fourth quarter of 2006 through the first quarter 2009, the managing general partner and its affiliated investment partnerships drilled 135 vertical wells to the Marcellus Shale geological formation, 118 of which were completed as productive. The other 17 wells have not been completed and fraced. Also, the managing general partner and its affiliated investment partnerships have drilled 10 horizontal wells in this area, 3 of which are productive. The other 7 wells have not been completed and fraced.

The managing general partner’s decision to begin targeting the Marcellus Shale was based on its review of wells drilled during the past several years by other oil and gas operators to the Marcellus Shale in Washington County, Pennsylvania and geologically similar shale formations in other areas of the United States, which the managing general partner believes has confirmed the feasibility of using a large frac treatment to complete productive wells in the Marcellus Shale as described in more detail in “– Marcellus Shale Geological Formation in Western Pennsylvania,” below.

The managing general partner anticipates that most of the subscription proceeds of the partnership will be expended in the Marcellus Shale and New Albany Shale (Indiana) primary areas, although some of the remaining subscription proceeds will be expended in the north central Tennessee and Antrim Shale (Michigan) secondary areas or in other secondary areas or areas that are not currently known. See “Capitalization and Source of Funds and Use of Proceeds – Use of Proceeds” for the estimated percentage of funds that will be used to drill wells in each area and “Compensation – Drilling Contracts” for the total estimated weighted average cost per well for each of the primary areas and the secondary areas.

There are increased risks associated with horizontal drilling in the areas described below as set forth in “Risk Factors – Risks Related To The Partnership’s Oil and Gas Operations – The Managing General Partner Has Limited Experience in Drilling Horizontal Wells, and Horizontal Wells are More Expensive and Difficult to Drill and Complete Than Vertical Wells.”

Marcellus Shale Geological Formation in Western Pennsylvania. The managing general partner anticipates that approximately 79% of the partnership’s maximum subscription proceeds will be used to drill wells in the Marcellus Shale. The Marcellus Shale is a highly organic, black shale found throughout the Appalachian Basin. The shale is encountered at depths from approximately 4,500 feet in northern Pennsylvania to 8,500 feet in southern Pennsylvania. Well control throughout the western portion of Pennsylvania, primarily from deeper Oriskany tests, have proven that the Marcellus Shale is a blanket formation varying in thickness from about 75 feet in the north to over 200 feet in the south. Estimated thicknesses of the shale in the managing general partner’s drilling areas are quite predictable due to the vast well control mentioned above. This shale is referred to as a ”resource shale”, which means hydrocarbons are generated in the formation. Porosities and permeabilities in this shale are very low, so to unlock the hydrocarbons and make the well productive a large frac treatment using large amounts of water must be performed. Porosity is the percentage of void space between sand grains that is available for occupancy by either liquids or gases; and permeability is the property of porous rock that allows fluids or gas to flow through it. Before the large amounts of water used in fracing wells in the Marcellus Shale can be disposed of, water disposal plans approved by the Pennsylvania Department of Environmental Resources must be obtained, which may delay drilling the wells and could increase the costs of disposing of the waste water from the partnership’s wells in Pennsylvania. For example, a typical frac treatment for an Upper Devonian Sandstone reservoir well in western Pennsylvania would consist of approximately 200,000 pounds of sand and 4,000 barrels of water as compared with an average vertical Marcellus Shale large well frac treatment of approximately one million pounds of sand and 25,000 barrels of water. Also, two frac treatments are anticipated per Marcellus Shale vertical well. Further, it is anticipated that the partnership will drill approximately 12% of its wells in the Marcellus Shale horizontally. With respect to the horizontal wells that are drilled in this area, there are increased risks and expenses associated with drilling the wells as described in “Risk Factors – Risks Related to the Partnership’s Oil and Gas Operations – The Managing General Partner Has Limited Experience in Drilling Horizontal Wells, and Horizontal Wells are More Expensive and Difficult to Drill and Complete Than Vertical Wells.”

The wells in the Marcellus Shale geological formation will be:

primarily situated in Fayette, Greene, Westmoreland, Washington, McKean, Indiana, Clarion and Butler Counties, Pennsylvania;

situated on approximately 20 acres for a vertical well, and which may include the vertical well and additional horizontal drilling in one or more different directions, all of which would be situated on the same prospect, plus additional acreage for any horizontal wells situated on the same prospect as the vertical well based on 125 feet on either side of each lateral in the horizontal well multiplied by the length of the lateral as described in the following bullet point that can be used for completion;

drilled to approximately 4,500 feet in northern Pennsylvania and 8,200 feet in southern Pennsylvania in depth, with each horizontal drilling on the location, if any, extending approximately 2,000 to 4,000 feet;

classified as natural gas wells that may produce a small amount of oil; and

primarily connected to the gathering system owned by Laurel Mountain, and have their natural gas production primarily marketed to UGI Energy Services, Colonial Energy, Inc., South Jersey Resources Group, ConocoPhillips Company, Dominion Field Services, Inc., EQT Energy LLC, Equitable Gas Company, Sequent Energy Management, L.P., and NJR Energy Services as discussed below in “– Sale of Natural Gas and Oil Production.”

Upper Devonian New Albany Shale Reservoir, Knox and Sullivan Counties, Indiana. The New Albany Shale Reservoir is an upper Devonian age organic-rich black shale in the Illinois basin which is stratigraphically the equivalent of the Antrim Shale of the Michigan Basin. Due to the permeability present in the shale, a horizontal natural fracture system through horizontal drilling is the preferred method for drilling these wells and all of the wells in this area will be drilled horizontally. The wells in the New Albany Shale (Indiana) will be:

primarily situated in Knox and Sullivan Counties, Indiana;

situated on approximately 160 acres;

drilled to approximately 1,500 to 3,000 feet in depth, with horizontal drilling extending approximately 4,000 feet;

classified as natural gas wells;

tied into new gathering systems and treating facilities prior to sales into existing pipeline infrastructure;

have their natural gas production primarily marketed to Atmos Energy with other transmission and local distribution company options available; and

the horizontal wells will produce a significant amount of water which must be disposed of as the natural gas is produced from the wells.

Secondary Areas of Operations

Mississippian Carbonate and Devonian Shale Reservoirs in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee. The Mississippian carbonate reservoirs in this secondary area are discontinuous lens shaped accumulations found in the southern Appalachian states of West Virginia, Virginia, Kentucky and Tennessee. These reservoirs have porosities ranging from 6% to 20% with attendant permeabilities. The Devonian shale is found throughout the Appalachian Basin. When the shale is highly fractured it becomes a reservoir. The partnership’s wells in the Mississippian carbonate and Devonian Shale reservoirs will be:

situated on 20 acres for a vertical well, and approximately 40 acres for a horizontal well;

drilled to approximately 2,000 to 6,000 feet in depth, with horizontal drilling for approximately one-half of the wells extending approximately 3,000 feet;

classified as natural gas wells that may produce a small amount of oil;

primarily connected to the gathering system owned by Atlas Pipeline Partners, and have their natural gas production primarily marketed to Atmos Energy as discussed below in “– Sale of Natural Gas and Oil Production;” and

any horizontal wells drilled by the partnership will produce a significant amount of water which must be disposed of when the natural gas is produced.

Upper Devonian Antrim Shale Reservoir, Antrim and Alcona Counties, Michigan. The Upper Devonian age Antrim Shale secondary area is a biogenic shale gas play in the Michigan Basin. Gas is generated by the interaction of bacteria and organic rich shales found at shallow depths. Wells drilled to the Antrim Shale in this secondary area will produce large volumes of water that must be removed from the wells and disposed of before full production of natural gas or oil from the wells is possible. This dewatering process is expected to take up to approximately 6 months. The partnership’s wells will be located in the Blue Sky and Mt. Maria projects and will be:

primarily situated in Antrim and Alcona Counties, Michigan;

situated on approximately 80 acres for vertical wells, and approximately 160 acres for any horizontal wells;

drilled to approximately 700 to 1,200 feet in depth, with horizontal drilling, if any, extending approximately 3,000 feet;

classified as either natural gas wells or oil wells;

primarily connected to new or existing Atlas Oil & Gas gathering systems and have their natural gas production primarily marketed to DTE or on the spot market;

drilled on leases with a net revenue interest of 76%, assuming a 100% working interest; and

if any horizontal wells are drilled in this area they will produce a significant amount of water which must be disposed of as the natural gas is produced from the wells.

It is not anticipated that wells drilled in Michigan will be separately metered. If the wells were drilled with another partnership or entity pursuant to a joint venture, the managing general partner as operator would have a conflict of interest in determining the volume of natural gas provided to each entity. The managing general partner as operator would attempt to resolve this conflict of interest using a prudent operator standard. In addition, some horizontal wells may be drilled in this area. There are increased risks associated with horizontal drilling in this area as described in “Risk Factors – Risks Related To The Partnership’s Oil and Gas Operations – The Managing General Partner Has Limited Experience in Drilling Horizontal Wells, and Horizontal Wells are More Expensive and Difficult to Drill and Complete Than Vertical Wells.” Also, the managing general partner has not drilled any horizontal wells in Michigan.

The managing general partner also has reserved the right to use a portion of the subscription proceeds of the partnership to drill development wells in other areas of the Appalachian Basin and elsewhere in the United States. The conditions that will prompt the managing general partner to select properties in secondary areas are access to prospects that meet the same criteria as the primary areas, which are described in “– Overview of Drilling Activities.” However, the managing general partner does not have available to it as many prospects in secondary areas as it does in the primary areas.

Acquisition of Leases

The managing general partner will have the right, in its sole discretion, to select the prospects which the partnership will drill. The managing general partner intends that the partnership will drill the prospects described in “Appendix A – Information Regarding Currently Proposed Prospects for Atlas Resources Public #18-2009(C) L.P.”

The leases covering each prospect on which a partnership well is drilled will be acquired by the partnership from the managing general partner or its affiliates and credited to the managing general partner as a part of its required capital contribution to the partnership. Neither the managing general partner nor its affiliates will receive any royalty or overriding royalty interest on any well.

The managing general partner anticipates that it will select the prospects for the partnership, including any additional and/or substituted prospects, from the following:

leases in its and its affiliates’ existing leasehold inventory;

leases that are subsequently acquired by it or its affiliates; or

leases owned by independent third-parties that may participate with the partnership in drilling wells.

The majority of the prospects acquired by the partnership will be in areas where the managing general partner or its affiliates have previously conducted drilling operations. The managing general partner believes that its and its affiliates’ leasehold inventory and leases acquired from third-parties will be sufficient to provide all the development prospects to be drilled by the partnership if the maximum subscription proceeds are received. In this regard, the managing general partner and its affiliates are continually engaged in acquiring additional leasehold acreage in Pennsylvania, Ohio, and other areas of the United States. As of March 31, 2009, the managing general partner’s and its affiliates’ undeveloped leasehold acreage was as follows:

	Undeveloped Lease Acreage
	Gross		Net (1)
Kentucky		9,060		4,530
Montana		2,650		2,650
New York		45,035		45,035
Ohio		31,984		31,984
Pennsylvania		420,255		420,255
West Virginia		14,362		11,948
Wyoming		80		80
Michigan		39,411		30,487
Indiana		244,571		118,922
Tennessee		116,842		116,842
Total		924,250		782,733

(1)	The net acreage as to which leases expire from June 15, 2009 through December 31, 2009 are as follows: Pennsylvania: 34,366 acres.

Also, some of the prospects to be selected for the partnership in the Marcellus Shale primary area are expected by the managing general partner to be multiple well proved undeveloped prospects that are classified as developmental. Thus, both a vertical well and one or more horizontal wells may be drilled on those Marcellus Shale prospects, and the number of prospects that the managing general partner will assign to the partnership may not be the same as the number of wells that the partnership has the funds to drill. This also means that the partnership, in all likelihood, will not farmout any acreage associated with those prospects. However, the need for a farmout might arise, for example, if during drilling or subsequently the managing general partner determines there might be a productive horizon situated above (i.e. uphole) the target horizon, but the partnership does not have the funds to complete the well in the horizon or the completion of the horizon would be inconsistent with the partnership’s objectives. In this event, the managing general partner might decide to farmout the activity for the well. Generally, a farmout is an agreement in which the owner of the lease or existing well agrees to assign its interest in certain acreage under the lease or the existing well to an assignee subject to the assignee drilling one or more wells or completing or recompleting the existing well in one or more horizons. The owner would retain some interest in the assigned acreage or well. See “Conflicts of Interest – Conflicts Involving the Acquisition of Leases” for the procedure for a farmout, and “Federal Income Tax Consequences – Farmouts.”

Deep Drilling Rights Retained by Managing General Partner. The lease assignments to the partnership generally will be limited to a depth from the surface to the deepest depth penetrated at the cessation of drilling operations. The managing general partner will retain the deeper drilling rights, including ownership of any coal bed methane production that might be obtained from the deeper formations. Conversely, as between the partnership and the managing general partner, the partnership will own any coal bed methane production that might be obtained from the shallower formations that are not included in the deeper drilling rights retained by the managing general partner.

The amount of the credit the managing general partner receives for the leases it contributes to the partnership will not include any value allocable to the deeper drilling rights retained by it. If the managing general partner undertakes any activities with respect to the deeper formations in the future, then the partnership would not share in the profits from these activities, nor would the partnership pay any of the associated costs.

Interests of Parties

Generally, production and revenues from a well drilled by the partnership will be net of the applicable landowner’s royalty interest, which is typically 1/8th (12.5%) of gross production, and any interest in favor of third-parties such as an overriding royalty interest. Landowner’s royalty interest generally means an interest that is created in favor of the landowner when an oil and gas lease is obtained; and overriding royalty interest generally means an interest that is created in favor of someone other than the landowner. In either case, the owner of the interest receives a specific percentage of the natural gas and oil production free and clear of all costs of development, operation, or maintenance of the well. This is compared with a working interest, which generally means an interest in the lease under which the owner of the interest must pay some portion of the cost of development, operation, or maintenance of the well. Also, the leases will be subject to terms that are customary in the industry such as free gas to the landowner-lessor for home heating requirements, etc.

The managing general partner anticipates that the partnership generally will have a net revenue interest in its leases in its primary drilling areas as set forth in the charts below. Net revenue interest generally means the percentage of revenues the owner of an interest in a well is entitled to receive under the lease. The following charts express the percentage of production revenues that the managing general partner, the landowner, other third-parties, and you and the other investors in a partnership will share in from the wells in the primary drilling areas. The chart assumes that the partnership owns 100% of the working interest in the well. If the partnership acquires a lesser percentage working interest in a well, then the partnership’s net revenue interest in that well will decrease proportionately.

The actual number, identity and percentage of working interests or other interests in prospects to be acquired by the partnership will depend on, among other things:

the amount of subscription proceeds received by the partnership;

the latest geological and production data;

potential title or spacing problems;

availability and price of drilling services, tubular goods and services;

approvals by federal and state departments or agencies;

agreements with other working interest owners in the prospects;

farmins and farmouts; and

continuing review of other prospects that may be available.

Primary Areas.

Marcellus Shale Geological Formation in Western Pennsylvania.

	Partnership	Third Party	87.5% Partnership
Entity	Interest	Royalty Interest	Net Revenue Interest (2)

Managing General Partner	25% partnership interest (1)			21.875%
Investors	75% partnership interest (1)			65.625%
Third Party		12.5% Landowner Royalty Interest		12.500%
				100.000%

(1)

These percentages are for illustration purposes only, and assume that the partnership has a 100% working interest and the managing general partner contributes its minimum required capital contribution of 15% to the partnership and the capital contributions from you and the other investors are 85%. The actual percentages are likely to be different because they will be based on the actual capital contributions of the managing general partner and you and the other investors.

(2)	The net revenue interest on some leases may be as low as 82.5%, which would reduce the investors’ net revenue interest in the above example to 61.875%, if presented on a 100% working interest basis and the investors received 75% of the partnership revenues.

��

Devonian Shale Reservoir in Knox and Sullivan Counties, Indiana.

	Partnership	Third Party		80% Partnership
Entity	Interest	Royalty Interest		Net Revenue Interest

Managing General Partner	25% partnership interest (1)		7.50%		20.00%
Investors	75% partnership interest (1)		7.50%		60.00%
Third Party			12.5% Landowner Royalty Interest		20.00%
					100.00%

(1)

Secondary Areas

Although the managing general partner anticipates that the partnership will have a net revenue interest ranging from 76% to 87.5% in its leases in the secondary areas, including an 83% net revenue interest in the Mississippian Carbonate and Devonian Shale Reservoirs in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee, and a 76% net revenue interest in the Antrim Shale (Michigan) secondary areas described in “– Secondary Areas of Operations,” above, assuming it owns 100% of the working interest, there is no minimum net revenue interest that the partnership is required to own before drilling a well in other areas of the United States. The leases in these other areas may be subject to interests in favor of third-parties that are not currently known such as overriding royalty interests, net profits interests, carried interests, production payments, reversionary interests pursuant to farmouts or non-consent elections under joint operating agreements, or other retained or carried interests.

Title to Properties

Title to all leases acquired by the partnership ultimately will be held in the name of the partnership. However, to facilitate the partnership’s acquisition of the leases title to the leases may initially be held in the name of the managing general partner, the operator, their affiliates, or any nominee designated by the managing general partner. Title to the partnership’s leases will be transferred to the partnership and filed for record from time to time after the wells are drilled and completed.

The managing general partner will take the steps it deems necessary to assure that the partnership has acceptable title for its purposes. However, it is not the practice in the natural gas and oil industry to warrant title or obtain title insurance on leases and the managing general partner will provide neither for the leases it assigns to the partnership. The managing general partner will obtain a favorable formal title opinion for the leases before each well is drilled, but will not obtain a division order title opinion after the well is completed. The managing general partner may use its own judgment in waiving title requirements and will not be liable for any failure of title of the leases transferred to the partnership. Also, the partnership may experience losses from title defects excluded from, or not disclosed by, the formal title opinion that is provided to the managing general partner before a well is drilled or that would have been disclosed by a division order title opinion after the well is drilled, if the partnership obtained division order title opinions, which it will not do. Although past performance is no guarantee of future results, the previous drilling partnerships sponsored by the managing general partner and its affiliates have participated in drilling more than 3,220 wells in the Appalachian Basin since 1985, and none of the wells have been lost because of title failure. See “Prior Activities” and “Litigation” regarding the acquisition of leases in Tennessee.

Drilling and Completion Activities; Operation of Producing Wells

On receipt of the minimum subscription proceeds of the partnership, the managing general partner on behalf of the partnership will do the following:

release the funds from the escrow account;

transfer the escrowed funds to a partnership account;

enter into the drilling and operating agreement, which is attached to the partnership agreement as Exhibit II, with itself or an affiliate of the managing general partner as operator; and

begin drilling the partnership’s wells.

Under the drilling and operating agreement, the responsibility for drilling and either completing or plugging partnership wells will be on the managing general partner or an affiliate of the managing general partner as the operator and the general drilling contractor. Under the drilling and operating agreement, the partnership is required to prepay the investors’ share of the drilling and completion costs of its wells to the managing general partner as the general drilling contractor and operator. If one or more of the partnership’s wells will be drilled in the calendar year after the year in which the advance payment is made, the required advance payment allows the partnership to secure tax benefits of prepaid intangible drilling costs based on a substantial business purpose for the advance payment under the drilling and operating agreement. The managing general partner, as operator and general drilling contractor, expects that it will begin drilling all of the partnership’s wells no later than the 90th day of the next year immediately following the year in which the offering of units in the partnership closes. (See “Federal Income Tax Consequences – Drilling Contracts.”)

During drilling operations the managing general partner’s duties as operator and general drilling contractor will include:

making the necessary arrangements for drilling and completing partnership wells and related facilities for which it has responsibility under the drilling and operating agreement, such as:

determining the exact location where the well bore will be drilled after reviewing geologic information it has compiled, which includes:

selecting the provider of the drilling rig; and

determining whether to use a pull down drilling rig or a conventional rotary drilling rig;

managing and conducting all field operations in connection with drilling, testing, and equipping the wells, which includes receiving and paying invoices from the subcontractors, reviewing that the invoices are reasonable, and monitoring compliance by each subcontractor with its contract; and

making the technical decisions required in drilling and completing the wells, such as:

determining how much casing should be placed in the well, which in turn depends primarily on the depth of the well;

designing the fracturing program for the well, which includes how much and what kind of fluid or gel to pump into the well bore, whether sand or foam should be pumped into the well bore and, if so, how much, and whether or not nitrogen should be pumped into the well bore;

designing the cementing program for the well, including a plan to contain any water that may be encountered in the well bore, such as cementing certain formations in the well; and

designing the completion program for the well, which includes reviewing and analyzing the wells’ logs, and determining which formations to perforate, and how and where to shoot holes in the formation and, in the case of natural gas wells, generally means treating separately all potentially productive geological formations in an attempt to enhance the natural gas production from the well.

All partnership wells will be drilled to a sufficient depth to test thoroughly the objective geological formation unless the managing general partner determines in its sole discretion that the well should be completed in a formation uphole from the objective geological formation. With respect to the horizontal wells that are drilled in the Marcellus Shale and the New Albany Shale (Indiana) primary areas and the north central Tennessee and Antrim Shale (Michigan) secondary areas, there are increased risks associated with drilling the wells as described in “Risk Factors – Risks Related to the Partnership’s Oil and Gas Operations – The Managing General Partner Has Limited Experience in Drilling Horizontal Wells, and Horizontal Wells are More Expensive and Difficult to Drill and Complete Than Vertical Wells.”

Under the drilling and operating agreement the managing general partner, as operator and general drilling contractor, will complete each well if there is a reasonable probability of obtaining commercial quantities of natural gas or oil. However, based on its past experience, the managing general partner anticipates that some of the development wells drilled by the partnership in the primary and secondary areas will have to be completed before the managing general partner can determine the well’s productivity. If the managing general partner, as operator and general drilling contractor, determines that a well should not be completed, then the well will be plugged and abandoned.

During producing operations the managing general partner’s duties, as operator, will include:

managing and conducting all field operations in connection with operating and producing the wells;

making the technical decisions required in operating the wells; and

maintaining the wells, equipment, and facilities in good working order during their useful life.

The managing general partner, as operator, will be reimbursed for its direct expenses and will receive well supervision fees at competitive rates for operating and maintaining the wells during producing operations as discussed in “Compensation.” As discussed in “Summary of Drilling and Operating Agreement,” the drilling and operating agreement contains a number of other material provisions which you are urged to review.

Certain wells may be drilled by the partnership with third-parties owning a portion of the working interest in the wells. Any other working interest owner in a well will have a separate agreement with the managing general partner for drilling and operating the well with differing terms and conditions from those contained in the partnership’s drilling and operating agreement. (See “Federal Income Tax Consequences – Drilling Contracts.”)

Additionally, the managing general partner, as operator, will provide all services that may be needed under the drilling and operating agreement with respect to any disposal wells, injection wells, transportation of waste water or similar matter.

Sale of Natural Gas and Oil Production

Policy of Treating All Wells Equitably in a Geographic Area. Under the partnership agreement, all benefits and liabilities from marketing and hedging arrangements or other relationships affecting the property of the managing general partner or its affiliates and the partnership must be fairly and equitably apportioned according to the respective interests of each party in the property. For natural gas sold in Pennsylvania during its previous four fiscal years, the managing general partner received an average selling price after deducting all expenses, including transportation expenses, and after the effects of hedging arrangements, of approximately:

$6.72 per mcf, which means 1,000 cubic feet of natural gas, in 2005;

$7.37 per mcf in 2006;

$8.13 per mcf in 2007; and

$8.67 per mcf in 2008.

Notwithstanding, in May 2009 the price of natural gas dropped to $3.32 per mcf, which was its lowest price since September 2002.

If all of the natural gas produced in an area cannot be sold by the managing general partner and its affiliates, including the partnership, because of limited gathering line or pipeline capacity, or limited demand for the natural gas, which increases pipeline pressure, then the production that is sold will be from those wells that have the greatest well pressure and are able to feed into the pipeline, regardless of which partnerships own the wells. The proceeds from these natural gas sales will be credited only to the partnerships whose wells produced the natural gas sold.

Gathering of Natural Gas. Under the partnership agreement the managing general partner will be responsible for gathering and transporting the natural gas produced by the partnership to interstate pipeline systems, local distribution companies, and/or end-users in the area. In the Marcellus Shale primary area, which the managing general partner anticipates will account for the majority of the partnership’s natural gas production, the managing general partner will use the gathering system owned by Laurel Mountain. Atlas Pipeline Partners acquired the natural gas gathering system and related facilities of Atlas America, Resource Energy, and Viking Resources in February 2000 and sold it to Laurel Mountain as of June 1, 2009 as discussed below. The gathering system consists of more than 1,400 miles of intrastate pipelines located in western Pennsylvania, eastern Ohio, and western New York.

If the partnership’s natural gas is not transported through the Laurel Mountain gathering system, it is because the well is situated in Indiana, Tennessee or Michigan, where the gathering system is owned by a third-party or an affiliate of the managing general partner other than Laurel Mountain. (See “Compensation – Gathering Fees.”)

On March 31, 2009, Atlas Pipeline Partners entered into a formation and exchange agreement (the “formation agreement”) with Williams Field Services Group, LLC and Williams Laurel Mountain, LLC (“Williams Laurel Mountain”), which are subsidiaries of The Williams Companies, Inc. (“Williams”), and Atlas Pipeline Partners’ subsidiaries, Atlas Pipeline Operating Partnership, L.P. (“Atlas Pipeline Operating”) and Atlas Pipeline Partners Laurel Mountain, LLC (“APL Laurel Mountain”). Under the formation agreement, a joint venture known as Laurel Mountain Midstream, LLC (“Laurel Mountain”) was formed, and as of June 1, 2009 the Laurel Mountain joint venture acquired ownership of, and began operating, the existing Appalachian Basin natural gas gathering system formerly owned by Atlas Pipeline Partners.

Pursuant to the terms of the formation agreement:

Williams Laurel Mountain contributed $102 million in cash to Laurel Mountain, issued a $25.5 million note to Laurel Mountain that is guaranteed by Williams, and retains a 51% equity interest in Laurel Mountain; and

APL Laurel Mountain exchanged the equity interests in Atlas Pipeline Partners’ Appalachian Basin operating subsidiaries with Laurel Mountain for approximately $90 million in cash and a 49% equity interest in Laurel Mountain, which includes preferred distribution rights entitling APL Laurel Mountain to receive all payments made under the Williams Laurel Mountain promissory note and, subject to a 3-year amortization schedule, to apply those payments to future capital contributions required to be made by it to Laurel Mountain.

The formation agreement closed June 1, 2009, and Laurel Mountain is now the owner of the gathering system.

As a condition of the formation agreement, ATN, Atlas Energy Operating, Atlas America, LLC, and Atlas Noble, LLC, in addition to Resource Energy, LLC and Viking Resources, LLC, which are sometimes referred to in this prospectus as the “Atlas entities,” entered into natural gas gathering agreements with Laurel Mountain as discussed below. These natural gas gathering agreements supersede the former master natural gas gathering agreement and omnibus agreement, both dated February 2, 2000, between Atlas Pipeline Partners and Atlas America, Resource Energy and Viking Resources, which are discussed in “Management – Managing General Partner and Operator.”

Under the natural gas gathering agreements, the Atlas entities and their affiliates, including the partnership, have dedicated their natural gas production in certain areas in the northern Appalachian Basin, which includes the Marcellus Shale primary area, to Laurel Mountain for transportation to interstate pipeline systems, local distribution companies, and/or end users in the area, subject to certain limited exceptions that may or may not apply to the partnership. In return, Laurel Mountain agreed to accept and transport the dedicated natural gas in the area subject to certain conditions.

Under the gas gathering agreements with Laurel Mountain, the Atlas entities are required to pay a gathering fee to Laurel Mountain, which is the same as the gathering fee previously paid to Atlas Pipeline Partners under the terminated agreements, of the greater of $0.35 per mcf or 16% of the gross sales price for each mcf of natural gas transported through Laurel Mountain’s gathering system except for certain existing contracts with lower minimum gathering fees. If the partnership pays a lesser competitive amount of gathering fees, which currently is 13% of the gross sales price in the Marcellus Shale primary area as set forth in “Compensation – Gathering Fees” for the natural gas it transports using Laurel Mountain’s gathering system, then the Atlas entities, and not the partnership, must pay the difference to Laurel Mountain. This creates a conflict of interest between the Atlas entities and the partnership because the managing general partner has an economic incentive to increase the amount of gathering fees paid by the partnership to Laurel Mountain in order to reduce the amount paid by the Atlas entities to Laurel Mountain. Any increase in the partnership’s gathering fees, however, cannot exceed a competitive rate. (See “Conflicts of Interest – Conflicts Regarding Order of Pipeline Construction and Gathering Fees.”)

Unlike the previous master gas gathering agreement with Atlas Pipeline Partners discussed above, which has been superseded by the gas gathering agreements with Laurel Mountain, Atlas America will not assume or guarantee the Atlas entities’ obligation under the gas gathering agreements with Laurel Mountain to pay the gathering fees required to be paid by the Atlas entities as discussed above. Thus, the Atlas entities must pay Laurel Mountain for the excess of the amount of gathering fees under the new gas gathering agreements over the amount of the competitive gathering fee (which is currently 13% of the gross sale price in the Marcellus Shale primary area) the managing general partner receives from the partnership as discussed in “Compensation – Gathering Fees.” However, as discussed above, the managing general partner may increase the amount of the gathering fees to competitive rates if competitive gathering fees increase in the future as determined by the managing general partner.

To the extent that the Atlas entities and their affiliates, including the partnership, own wells or propose wells that are within 2.500 feet of Laurel Mountain’s gathering system, they must, at their own cost, construct up to 2,500 feet of flowline as necessary to connect their wells to Laurel Mountain’s gathering system. To the extent that the Atlas entities and their affiliates, including the partnership, own wells or propose to drill wells in Laurel Mountain’s area of interest as defined in its gas gathering agreements with the Atlas entities, that are more than 2,500 feet from Laurel Mountain’s gathering system, they and Laurel Mountain have various options to connect those wells to the gathering system. If the Atlas entities and their affiliates, including the partnership, construct a flow line to within 1,000 feet of Laurel Mountain’s gathering system, then Laurel Mountain must, at its own cost, extend its gathering system to connect to the flowline.

In this regard, the only principal gathering system currently available to the partnership with respect to the natural gas produced by the partnership in the Marcellus Shale primary area, which the managing general partner anticipates will account for a majority of the partnership’s natural gas production, is Laurel Mountain’s gathering system. Since Williams has day-to-day management control of Laurel Mountain’s gathering system, subject to the direction of Laurel Mountain's management committee, the Atlas entities will:

have less control over the volume of the partnership’s natural gas that may be transported through the gathering system;

no longer exclusively control the expansion of the gathering system or increasing capacity for transporting production from the partnership’s Marcellus Shale wells; and

have the election to expand the gathering system at their expense, subject to certain conditions, including those discussed above, if Laurel Mountain decides not to expand the gathering system to wells to be drilled by the Atlas entities, including wells to be drilled by the partnership.

However, Laurel Mountain’s management committee, which is composed of one member selected by APL Laurel Mountain and one member selected by Williams, will determine certain major decisions of Laurel Mountain as set forth in the formation agreement, including the selection of the entity that controls the day to day operations of Laurel Mountain.

Natural Gas Contracts. As set forth in “– Primary Areas of Operations,” the partnership has two primary areas where it will drill its wells as set forth below. The natural gas purchaser or purchasers for each area are set forth below.

The natural gas produced from the Marcellus Shale in western Pennsylvania will be sold primarily to UGI Energy Services, Colonial Energy, Inc., South Jersey Resources Group, ConocoPhillips Company, Dominion Field Services, Inc., EQT Energy LLC, Equitable Gas Company, Sequent Energy Management, L.P., and NJR Energy Services pursuant to contracts which end March 31, 2010.

The natural gas produced from the New Albany Shale (Indiana) primary area will be sold primarily to Atmos Energy pursuant to contracts which end March 31, 2014.

All of the natural gas contracts, including those described above, are between the natural gas purchaser and ATN or its affiliates. Either ATN or its affiliates will receive the sales proceeds from the natural gas purchasers and then distribute the sales proceeds to each partnership based on the volume of natural gas produced by the partnership. Until the sales proceeds are distributed to the partnership, they will be subject to the claims of ATN’s or its affiliates’ creditors.

The pricing and delivery arrangements with the vast majority of the natural gas purchasers described above are tied to the settlement of the New York Mercantile Exchange Commission (“NYMEX”) monthly futures contracts price, which is reported daily in the Wall Street Journal, with an additional premium, which is referred to as the basis, paid for natural gas production in the Appalachian Basin because of the location of the natural gas in relation to the natural gas market. The premium over quoted prices on the NYMEX received by the managing general partner and its affiliates for areas in the Appalachian Basin, which includes the Marcellus Shale primary area and the north central Tennessee secondary area, has ranged between $0.54 to $0.84 per mcf, which includes both basis and btu adjustments, during the managing general partner’s past three fiscal years. These figures are based on the overall weighted average that the managing general partner and its affiliates used in their annual reserve reports for their past three fiscal years, and do not include the New Albany Shale (Indiana) primary area or the Antrim Shale (Michigan) secondary area, since these areas are not situated in the Appalachian Basin. Generally, the purchase agreements may be suspended for force majeure, which generally means an Act of God.

Pricing for natural gas and oil has been volatile and uncertain for many years. To limit the managing general partner’s and its partnerships’ exposure to decreases in natural gas prices, the managing general partner and its affiliates, including ATN, use financial hedges through contracts such as regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties and may use physical hedges through their natural gas purchasers, as discussed below. The futures contracts employed by the managing general partner are commitments to purchase or sell natural gas at future dates and generally cover one-month periods for up to 60 months in the future. To assure that the financial instruments will be used solely for hedging price risks and not for speculative purposes, the managing general partner has established a committee to assure that all financial trading is done in compliance with the managing general partner’s hedging policies and procedures. The managing general partner does not intend to contract for positions that it cannot offset with actual production. Any physical hedges require firm delivery of natural gas and, therefore, are considered normal sales of natural gas, rather than hedges, for accounting purposes.

As of April 30, 2009, ATN and its affiliates have entered into financial hedges through banking counter-parties (JP Morgan, Wachovia, Wells Fargo, Royal Bank of Scotland and Key Bank), on behalf of the partnership and the other partnerships sponsored by the managing general partner through December 2013. For the twelve month periods ending December 31, 2009 and December 31, 2010, ATN has hedged approximately 89% and 81%, respectively, of the natural gas production using fixed-for-floating financial swaps and financial costless collars. ATN and its affiliates are also negotiating with other banking counter-parties to implement financial hedges. In this regard, the partnership has confirmed its authorization to ATN to enter into the hedging agreements, and has ratified all actions previously taken by ATN and its affiliates in connection therewith. It is anticipated that since the transfer by Atlas America of the managing general partner to ATN, a subsidiary of ATN rather than Atlas America, will enter into these hedging arrangements, subject to the intended merger between Atlas America and ATN discussed in “Management.” Also, the partnership may enter into its own agreements and financial instruments relating to hedging its natural gas and oil and the pledging of up to 100% of its assets and reserves in connection therewith.

The percentages of natural gas that are hedged through either financial hedges, physical hedges or not hedged at all will change from time to time in the discretion of ATN and the managing general partner. If the hedges are with ATN or its affiliates, rather than the partnership, it is difficult to project what portion of these hedges will be allocated to the partnership by the managing general partner because of uncertainty about the quantity, timing, and delivery locations of natural gas that may be produced by the partnership. Although hedging provides the partnership some protection against falling prices, these activities also could reduce the potential benefits of price increases and the partnership could incur liability on the financial hedges. For example, the partnership would be exposed to the risk of a financial loss if any of the following occur:

the partnership’s production is substantially less than expected;

the counterparties to the futures contracts fail to perform under the contracts, the risk of which is increased because of the current credit crisis in the United States; or

there is a sudden, unexpected event materially impacting natural gas prices.

Subject to the managing general partner’s and its affiliates’ interest in their natural gas contracts or pipelines and gathering systems, all benefits and liabilities from marketing and hedging or other relationships affecting the property of the managing general partner or its affiliates or the partnerships must be fairly and equitably apportioned according to the interests of each in the property. In this regard, the benefits and liabilities of the hedging agreements will be equitably allocated by ATN and the managing general partner to the partnership and the other partnerships sponsored by the managing general partner and its affiliates pro rata based on actual production, consistent with past practice, and the partnership and the other partnerships sponsored by the managing general partner and its affiliates will be severally liable for their respective allocated share of the liabilities under the hedging agreements, but will not be jointly and severally liable for the entire amount of the liabilities under the hedging agreements. Additionally, ATN will not be liable for any of those liabilities, or be entitled to any of those benefits, to the extent they are allocated to the partnership and the other partnerships sponsored by the managing general partner and its affiliates. Also, the partnership may enter into its own agreements and financial instruments relating to hedging its natural gas and oil and the pledging of up to 100% of its assets and reserves in connection therewith.

As of June 30, 2009, none of the managing general partner’s and its affiliates’ natural gas is subject to physical hedges and the managing general partner and its affiliates anticipate using financial hedges as discussed above for all of their natural gas that is hedged, although this may change from time to time.

Marketing of Natural Gas Production from Wells in Other Areas of the United States. The managing general partner expects that any natural gas produced by the partnership from its wells, 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. Crude oil produced from the partnership’s 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. The managing general partner anticipates selling any oil produced by the wells to regional oil refining companies at the prevailing spot market price for Appalachian crude oil in spot sales. The managing general partner received an average selling price for oil during its previous four fiscal years of approximately $50.00 per barrel in 2005, $62 per barrel in 2006, $70 per barrel in 2007 and $92 per barrel in 2008. During the term of the partnership it is anticipated that the price of oil will be uncertain and volatile.

Insurance Claims

Since 1972 the managing general partner and its affiliates, including its partnerships, have been involved in drilling more than 7,500 wells, most of which were developmental wells, in Ohio, Pennsylvania, and other areas of the Appalachian Basin. They have made only the following material insurance claims.

In February 2004, one of the wells in another investment partnership incurred an uncontrolled flow of natural gas and oil with a fire during drilling. These problems with the well were subsequently controlled, but they resulted in the loss of a subcontractor’s drilling rig and third-party claims. As of June 4, 2009, the managing general partner’s insurance carrier had paid approximately $1.6 million to third-parties for property damage claims. The managing general partner’s insurance company is exploring all avenues for subrogation.

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In February 2006, there was a well fire during the drilling of a well in Fayette County, Pennsylvania which resulted in a claim against the managing general partner’s insurance carrier. The managing general partner’s insurance carrier paid $161,500 for all claimants and the claim is closed.

Also, in April 2007 there was a well fire during the drilling of a well in Morgan County, Tennessee, in which two of the drilling contractor’s employees sustained minor injuries and there was damage to the drilling contractor’s equipment. The drilling contractor’s insurance company is expected to cover the loss and the managing general partner does not believe this will result in a claim against its insurance carrier. Further, in connection with one of the wells being drilled by Atlas Resources Public #17-2007(A) L.P. in Greene County, Pennsylvania to the Mississippian/Upper Devonian Sandstone Reservoir, there was an explosion of underground pressure, which blew a valve killing one man and injuring another. The men were employed by a subcontractor, which was contracted by the managing general partner to drill the well. The well had been drilled and the men were in the process of disconnecting the drilling rig from the well when pressure blew the coupling off. Gas from the well was shut off and there was no fire. Currently, the managing general partner has notified its insurance carrier, but no claim has been filed.

See “Actions to be Taken by Managing General Partner to Reduce Risks of Additional Payments by Investor General Partners – Insurance” for a discussion of the insurance coverage the managing general partner intends to be available for the partnership’s benefit. To date, ATN has not received any notice from the insurance carrier that any insurance coverage would be dropped or rates increased due to those incidents.

Use of Consultants and Subcontractors

The partnership agreement authorizes the managing general partner to use the services of independent outside consultants and subcontractors on behalf of the partnership. The services will normally be paid on a per diem or other cash fee basis and will be charged to the partnership as either a direct cost or as a direct expense under the drilling and operating agreement. These charges will be in addition to the costs of subcontractor services provided by the managing general partner’s affiliates, which will be charged at competitive rates, the oversight and administration fee that will be paid to the managing general partner during drilling operations, and the well supervision fees paid to the managing general partner as operator as discussed in “Compensation.”

COMPETITION, MARKETS AND REGULATION

Natural Gas Regulation

Governmental agencies regulate the production and transportation of natural gas. Generally, the regulatory agency in the state where a producing natural gas well is located supervises production activities and the transportation of natural gas sold into intrastate markets, and the Federal Energy Regulatory Commission (“FERC”) regulates the interstate transportation of natural gas.

Natural gas prices have not been regulated since 1993, and the price of natural gas is subject to the supply and demand for natural gas along with factors such as the natural gas’ BTU content and where the wells are located. Since 1985 FERC has sought to promote greater competition in natural gas markets in the United States. Traditionally, natural gas was sold by producers to interstate pipeline companies that served as wholesalers and resold the natural gas to local distribution companies for resale to end-users. FERC changed this market structure by requiring interstate pipeline companies to transport natural gas for third-parties. In 1992 FERC issued Order 636 and a series of related orders that required pipeline companies to, among other things, separate their sales services from their transportation services and provide an open access transportation service that is comparable in quality for all natural gas producers or suppliers. The premise behind FERC Order 636 was that the interstate pipeline companies had an unfair advantage over other natural gas producers or suppliers because they could bundle their sales and transportation services together. FERC Order 636 is designed to ensure that no natural gas seller has a competitive advantage over another natural gas seller because it also provides transportation services.

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In 2000 FERC issued Order 637 and subsequent orders to further enhance competition by removing price ceilings on short-term capacity release transactions. It also enacted other regulatory policies that are intended to enhance competition in the natural gas market and increase the flexibility of interstate natural gas transportation. FERC also has required pipeline companies to develop electronic bulletin boards to provide standardized access to information concerning capacity and prices.

Crude Oil Regulation

Oil prices are not regulated, and the price is subject to the supply and demand for oil, along with qualitative factors such as the gravity of the crude oil and sulfur content differentials.

Competition and Markets

Many companies engage in natural gas and oil drilling operations in the areas where the partnership’s wells will be located. According to the April 2009 Monthly Energy Review of the Energy Information Administration (the “EIA”), the independent statistical and analytical agency within the U.S. Department of Energy, in 2008 approximately 24 quadrillion BTU of natural gas was consumed in the United States which represented approximately 24% of the total energy used. According to the EIA’s Natural Gas Annual 2007 Report, the Appalachian Basin accounted for approximately 4% of the total domestic natural gas production in the United States in 2007. Also, according to the EIA’s Natural Gas Reserves Summary as of December 31, 2007, the Appalachian Basin’s economically recoverable natural gas reserves represented approximately 6.1% of total domestic natural gas reserves.

The natural gas and oil industry is highly competitive in all phases. In this regard, the partnership will operate in a highly competitive environment for acquiring leases, contracting for drilling equipment, securing trained personnel and marketing natural gas and oil production from its wells. For example, the Pennsylvania Bureau of Oil and Gas Management estimates that in 2007 there were 836 well operators bonded in Pennsylvania, which includes the partnership’s Marcellus Shale primary drilling area. Product availability and price are the principal means of competing in selling natural gas and oil. Many of the partnership’s competitors will have financial resources and staffs larger than those available to the partnership. This may enable them to identify and acquire desirable leases and market their natural gas and oil production more effectively than the managing general partner and the partnership. While it is impossible to accurately determine the partnership’s industry position, the managing general partner does not consider that the partnership’s intended operations will be a significant factor in the industry.

The natural gas and oil industry has from time to time experienced periods of rapid cost increases. The increase in natural gas and oil prices over the last several years also increased the demand for drilling rigs and other related equipment and the costs of drilling and completing natural gas and oil wells. Additionally, the managing general partner and its affiliates experienced an increase in the cost of tubular steel used in drilling wells as recently as 2008. As of the date of this prospectus, however, the partnership expects no problem in obtaining drilling rigs and equipment costs have decreased since 2008. Because the partnership’s wells will be drilled on a modified cost plus basis as described in “Compensation – Drilling Contracts,” any increased costs will increase the partnership’s costs to drill and complete its wells. Also, any reduced availability of drilling rigs and other related equipment may reduce the number of wells the partnership can drill and may make it more difficult to drill the partnership’s wells in a timely manner or to comply with the prepaid intangible drilling costs rules discussed in “Federal Income Tax Consequences – Drilling Contracts.” Further, over the term of the partnership there may be fluctuating or increasing costs in doing business, such as those associated with disposing of the water in the Marcellus Shale and New Albany Shale (Indiana) primary areas, and the north central Tennessee and Antrim Shale (Michigan) secondary areas, and any increase in water disposal equipment costs would directly affect the managing general partner’s ability to operate the partnership’s wells at acceptable price levels.

The natural gas and oil produced by your partnership’s wells must be marketed in order for you to receive revenues. During 2008 and its fiscal years ending in 2007, 2006 and 2005, the managing general partner did not experience any problems in selling natural gas and oil, although the prices varied significantly during those periods. As set forth above, natural gas and oil prices are not regulated, but instead are subject to factors which are generally beyond the partnership’s and the managing general partner’s control such as the supply and demand for natural gas and oil. For example, reduced natural gas demand and/or excess natural gas supplies will result in lower prices. Other factors affecting the price and/or marketing of natural gas and oil production, which are also beyond the control of the managing general partner and the partnership and cannot be accurately predicted, are the following:

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

the price and availability of other energy sources such as coal, nuclear energy, solar and wind;

the price and availability of alternative fuels, including when large consumers of natural gas are able to convert to alternative fuel use systems;

changes in federal income tax laws affecting the oil and gas industry;

local, state, and federal regulations regarding production, conservation, and transportation;

overall domestic and global economic conditions;

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 general level of supply and market demand for natural gas and oil on a regional, national and worldwide basis;

weather conditions and fluctuating seasonal supply and demand for natural gas and oil because of various factors such as home heating requirements in the winter months, although seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation, and certain natural gas users with natural gas storage facilities purchase a portion of the natural gas they anticipate they will need for the winter during the summer, which also can lessen seasonal demand fluctuations;

economic and political instability, including war or terrorist acts in natural gas and oil producing countries, including those of the Middle East and South America;

the amount of domestic production of natural gas and oil; and

the amount and price of imports of natural gas and oil from foreign sources, including liquid natural gas from Canada and other countries (which the managing general partner believes becomes economic when natural gas prices are at or above $3.50 per mcf), and the actions of the members of the Organization of Petroleum Exporting Countries (“OPEC”), which include production quotas for petroleum products from time to time with the intent of increasing, maintaining, or decreasing price levels.

For example, the North American Free Trade Agreement (“NAFTA”) eliminated trade and investment barriers in the United States, Canada, and Mexico. From time to time since then there have been increased imports of Canadian natural gas into the United States. Without a corresponding increase in demand in the United States, the imported natural gas would have an adverse effect on both the price and volume of natural gas sales from the partnership’s wells. Also, a pipeline is being built to extend the supply of Rocky Mountain Basin natural gas to major markets in the upper Midwest and Eastern United States. The resulting increased supply of natural gas to the region from the Rocky Mountain Basin will increase competition and may have the effect of placing downward pressure on Appalachian Basin natural gas pricing. (See “Risk Factors – Risks Related to The Partnership’s Oil and Gas Operations – Adverse Events in Marketing the Partnership’s Natural Gas Could Reduce Partnership Distributions.”)

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The managing general partner is unable to predict what effect the various factors set forth above will have on the future price of the natural gas and oil sold from the partnership’s wells. According to the EIA’s Annual Energy Outlook 2009 with Projections to 2030 (the “Annual Energy Outlook 2009 Report”), total natural gas consumption is projected to increase from 21.7 trillion cubic feet in 2006 to 23.5 trillion cubic feet by 2030. Over that same period, total natural gas supplies are projected to grow by approximately 1.5 trillion cubic feet, with domestic natural gas production expected to account for almost all of the total growth in gas supply. Notwithstanding, wellhead natural gas prices are projected to decline in the early years of the forecast as a result of the following responses to the high prices in recent years:

an increase in drilling levels;

the coming online of new natural gas production; and

an increase in liquid natural gas (“LNG”) imports.

However, due to the current relatively low price and high inventory of natural gas as of the date of this prospectus, as compared to recent years, the report discussed above may not be accurate as of the date of this prospectus and the next report could include adverse projections for the natural gas industry.

In this regard, in May of 2009 the price of natural gas on NYMEX decreased to $3.32 per mcf, which was its lowest price since September 2002. According to the EIA report, after some fluctuations through 2021 natural gas prices are projected to increase in response to the higher exploration and development costs associated with smaller and deeper natural gas deposits in the remaining domestic natural gas resource base, which could adversely change as discussed above. Also, the managing general partner believes there have been several developments that may increase the demand for natural gas, but may or may not be offset by the current low price for natural gas and increase in the supply of natural gas, which the managing general partner is unable to predict. For example, the Clean Air Act Amendments of 1990 contain incentives for the future development of “clean alternative fuel,” which includes natural gas and liquefied petroleum gas for “clean-fuel vehicles.” Also, the accelerating deregulation of electricity transmission has caused a convergence between the natural gas and electric industries. According to the EIA’s April 2009 Monthly Energy Review, in 2008 the breakout of energy sources for the generation of electricity in the United States, which may adversely change as discussed above, was as follows:

natural gas fired power plants were used to produce approximately 21%;

coal-fired power plants were used to produce approximately 48%;

nuclear power plants were used to produce approximately 20%;

large scale hydroelectric projects were used to produce approximately 6.0%; and

other sources, in the aggregate, were used to produce approximately 5.0%.

In recent years, the electricity industry has increased its use of natural gas because of increased competition and the enforcement of stringent environmental regulations. For example, the Environmental Protection Agency has sought to enforce environmental regulations which increase the cost of operating coal-fired power plants, although the federal government’s current budget proposal includes enhancements intended to increase the use of coal, which may or may not be enacted into law. If these proposals are enacted, there may be adverse affects on the amount of natural gas used, for example, to generate electricity in power plants. According to the EIA’s Annual Energy Outlook 2008 Report, the demand for natural gas by producers of electricity is expected to increase through 2016, although this may adversely change as discussed above. Also, the last nuclear power plant to come online in the United States was in June 1996, although the existing nuclear power plants have increased their capacity and the recent energy act includes tax credits for constructing new nuclear power plants. In this regard, according to a USA Today article dated December 12, 2007, power companies are beginning to file applications to build up to approximately 32 nuclear plants. If the price of natural gas increases to a point where it becomes uneconomic as an energy source as compared to alternate energy sources, the managing general partner believes that demand for natural gas may decrease if producers of electricity increase their use of dirtier-burning alternative fuels, such as coal and oil. In this regard, some of the new natural gas fired power plants which are coming into service are not designed to allow for switching to other fuels.

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State Regulations

Natural gas and oil operations are regulated in Pennsylvania by the Department of Environmental Resources, in Tennessee by the Department of Environment and Conservation and in Indiana by the Department of Natural Resources. Pennsylvania, Tennessee, Indiana and the other states where the partnership’s wells may be situated also impose a comprehensive statutory and regulatory scheme for natural gas and oil operations, including supervising the production activities and the transportation of natural gas sold in intrastate markets, which creates additional financial and operational burdens. Among other things, these regulations involve:

new well permit and well registration requirements, procedures, and fees;

landowner notification requirements;

certain bonding or other security measures;

minimum well spacing requirements;

restrictions on well locations and underground gas storage;

certain well site restoration, groundwater protection, including water disposal plans, and safety measures;

discharge permits for drilling operations;

various reporting requirements; and

well plugging standards and procedures.

These state regulatory agencies also have broad regulatory and enforcement powers including those associated with pollution and environmental control laws, which are discussed below.

Environmental Regulation

The partnership’s drilling and producing operations will be subject to various federal, state, and local laws covering the discharge of materials into the environment, or otherwise relating to the protection of the environment. The Environmental Protection Agency and state and local agencies will require the partnership to obtain permits and take other measures with respect to:

the discharge of pollutants into navigable waters;

disposal of wastewater; and

air pollutant emissions.

If these requirements or permits are violated there can be substantial civil and criminal penalties that will increase if there was willful negligence or misconduct by the partnership. In addition, the partnership may be subject to fines, penalties and unlimited liability for cleanup costs under various federal laws such as the Federal Clean Water Act, the Clean Air Act, the Resource Conservation and Recovery Act, the Oil Pollution Act of 1990, the Toxic Substance Control Act and the Comprehensive Environmental Response, Compensation and Liability Act of 1980 for oil and/or hazardous substance contamination or other pollution caused by the partnership’s drilling activities or its wells and its production activities.

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The partnership and its investor general partners may incur environmental costs and liabilities due to the nature of the partnership’s business and substances from the partnership’s wells as described “Risk Factors.” For example, an accidental release from one of the partnership’s wells could subject the partnership 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 in the future which could significantly increase the partnership’s compliance costs and the cost of any remediation that may become necessary.

Also, the partnership’s liability can extend to pollution costs that occurred on the leases before they were acquired by the partnership. Although the managing general partner will not transfer any lease to the partnership if it has actual knowledge that there is an existing potential environmental liability on the lease, there will not be an independent environmental audit of the leases before they are transferred to the partnership. Thus, there is a risk that the leases will have potential environmental liability even before drilling begins.

The partnership’s required compliance with these environmental laws and regulations may cause delays or increase the cost of the partnership’s drilling and producing activities. Because these laws and regulations are frequently changed, the managing general partner is unable to predict the ultimate costs of complying with present and future environmental laws and regulations. Also, the managing general partner is unable to obtain insurance to protect against many environmental claims, including remediation costs.

Proposed Regulation

From time to time there are a number of proposals considered in Congress and in the legislatures and agencies of various states that if enacted would significantly and adversely affect the natural gas and oil industry and the partnership. The proposals involve, among other things:

limiting the disposal of waste water from wells or the emission of greenhouse gases, which could substantially increase the partnership’s operating costs and make the partnership’s wells uneconomical to produce;

imposing federal laws on hydraulic fracturing of wells;

changes in the federal income tax benefits for drilling natural gas and oil wells as discussed in “Risk Factors – Federal Income Tax Risks – Changes in the Law May Reduce Your Tax Benefits From an Investment in the Partnership”;

tax credits and other incentives for the creation or expansion of alternative energy sources to natural gas and oil; and

establishing a cap and trade system for carbon emissions as part of the effort to combat global warming and reduce reliance on oil, natural gas and coal.

Also, Congress could re-enact price controls or additional taxes on natural gas and oil in the future. However, it is impossible to accurately predict what proposals, if any, will be enacted and their subsequent effect on the partnership’s activities.

PARTICIPATION IN COSTS AND REVENUES

In General

The partnership agreement provides for the sharing of partnership costs and revenues among the managing general partner and you and the other investors. A tabular summary of the following discussion appears below. The partnership will be a separate business entity from the other partnerships in the program, and you will be a partner only in the partnership or partnerships in which you invest. You will have no interest in the business, assets, or tax benefits of the other partnership or partnerships unless you also made an investment in the other partnership or partnerships. Thus, your investment return will depend solely on the operations and success or lack of success of the particular partnership in which you invest.

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Costs

Organization and Offering Costs. Organization and offering costs will be charged 100% to the managing general partner. However, the managing general partner will not receive any credit towards its required capital contribution or its revenue share for any organization and offering costs charged to it in excess of 15% of the partnership’s subscription proceeds.

Organization and offering costs generally means all costs of organizing and selling the offering and includes the dealer-manager fee, sales commissions and the reimbursement for bona fide due diligence expenses.

The managing general partner will pay a portion of the partnership’s organization and offering costs to itself, its affiliates and independent third-parties and it will contribute the remainder to the partnership in the form of services related to organizing this offering. The managing general partner will receive a credit for these payments and services towards its required capital contribution in the partnership. The managing general partner’s credit for its contribution of services for organization costs will be determined based on generally accepted accounting principles. The definition of organization and offering costs is set forth in the partnership agreement.

2.	Lease Costs. The partnership’s leases will be contributed to it by the managing general partner. The managing general partner will be credited with a capital contribution for each lease valued at:

its cost; or

fair market value if the managing general partner has reason to believe that cost is materially more than fair market value.

The cost of the leases includes a portion of the managing general partner’s reasonable, necessary and actual expenses for geological, geophysical, engineering, drafting, accounting, legal and other like services allocated to the leases in conformity with generally accepted accounting principles and industry standards. Also, the managing general partner has averaged the cost of its leases by area as described in “Compensation – Lease Costs.” The managing general partner believes its average lease costs per prospect will be less than fair market value in the two primary areas and the two secondary areas described in “Proposed Activities” based on information it has concerning lease costs of third-party operators in the areas.

3.	Intangible Drilling Costs. Eighty-five percent of the subscription proceeds of you and the other investors in the partnership will be used to pay 100% of the intangible drilling costs incurred by the partnership in drilling and completing its wells.

Intangible drilling costs generally means those costs of drilling and completing a well that are currently deductible, as compared with lease costs, which must be recovered through the depletion allowance, and equipment costs, which must be recovered through depreciation deductions. For example, intangible drilling costs include all expenditures made for any well before production in commercial quantities for wages, fuel, repairs, hauling, supplies and other costs and expenses incident to and necessary for drilling the well and preparing the well for production of natural gas or oil. Intangible drilling costs also include the expense of plugging and abandoning any well before a completion attempt, and the costs (other than equipment costs and lease acquisition costs) to re-enter and deepen an existing well, complete the well to deeper reservoirs, or plug and abandon the well if it is nonproductive from the targeted deeper reservoirs.

Although subscription proceeds of the partnership may be used to pay the costs of drilling different wells depending on when the subscriptions are received, 85% of the subscription proceeds of you and the other investors will be used to pay intangible drilling costs regardless of when you subscribe. Also, even if the IRS successfully challenged the managing general partner’s characterization of a portion of these costs as deductible intangible drilling costs, and instead recharacterized the costs as some other item that may not be currently deductible, such as equipment costs and/or lease acquisition costs, this recharacterization by the IRS would have no effect on the allocation and payment of the costs by you and the other investors as intangible drilling costs under the partnership agreement. The allocation of the partnership’s costs of drilling and completing its wells between intangible drilling costs, as defined in the partnership agreement, and equipment costs, as defined as “tangible costs” in the partnership agreement, will be made by the managing general partner, in its sole discretion, when the wells are drilled.

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Equipment Costs. Fifteen percent of the subscription proceeds of you and the other investors in the partnership will be used to pay the majority of the equipment costs incurred by the partnership. All equipment costs of the partnership’s wells that exceed 15% of the subscription proceeds of you and the other investors will be charged to the managing general partner.

Equipment costs generally means the costs of drilling and completing a well that are not currently deductible and are not lease costs.

Operating Costs, Direct Costs, Administrative Costs and All Other Costs. Operating costs, direct costs, administrative costs, and all other partnership costs of your partnership not specifically charged under the partnership agreement will be charged between the managing general partner and you and the other investors in the partnership in the same ratio as the related production revenues are being credited.

These costs generally include all costs of partnership administration and producing and maintaining the partnership’s wells.

Each well in the partnership will have a different productive life and when a well becomes uneconomic to produce, it will be plugged and abandoned. The costs of plugging and abandoning a well (other than those incurred in connection with drilling a nonproductive well) are shared between the managing general partner and you and the other investors in the same percentage as the related production revenues are being shared. For example, if the investors are receiving 75% of the partnership revenues and the managing general partner is receiving 25% of the partnership revenues, then the cost of plugging and abandoning the wells will be shared in the same percentages.

Typically, the managing general partner will apply the salvage value of the equipment towards this obligation. The salvage value of the equipment will be shared between you and the other investors and the managing general partner based on the total amount of the actual equipment costs paid by each. Since you and the other investors in the partnership will have paid a majority of the partnership’s total equipment costs, as compared to the total amount of the partnership’s equipment costs paid by the managing general partner, you and the other investors will also receive a majority of the salvage value of the partnership’s equipment. See “Compensation – Drilling Contracts,” for a discussion of the managing general partner’s estimated equipment costs for an average partnership well in the primary drilling areas and the Antrim Shale (Michigan) secondary area.

To cover any shortfall that you and the other investors might incur between your share of the salvage value of the equipment in a well and your share of the plugging and abandoning costs of the well, the managing general partner has the right, beginning one year after the partnership well begins producing, to retain up to $200 per month of the partnership revenues in partnership reserves to cover future plugging and abandonment costs of the well. This $200 also includes the managing general partner’s share of revenues. The managing general partner’s retained revenues will be used exclusively for the managing general partner’s share of the plugging and abandonment costs of the well. To the extent any portion of those reserves ultimately is not required for the plugging and abandonment costs of the well, then it will be returned to the general operating revenues of the partnership.

6.	The Managing General Partner’s Required Capital Contribution. The managing general partner’s aggregate capital contributions to the partnership must not be less than 15% of all capital contributions to the partnership. This includes such items as the managing general partner’s:

credit for the cost of the leases it contributes to the partnership, or the fair market value of the leases if the managing general partner has a reason to believe that cost is materially more than fair market value as set forth in “Compensation – Lease Costs”;

credit for the partnership’s organization and offering costs paid or incurred by the managing general partner, including the costs of services contributed by the managing general partner to the partnership as organization costs; and

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share of the partnership’s equipment costs, including its administration and oversight fee and 18% mark up, paid by the managing general partner to itself as operator under the drilling and operating agreement.

The managing general partner’s capital contributions must be paid or made at the time the costs are required to be paid by the partnership, but in any event not later than the end of the year immediately following the year in which the partnership had its final closing.

Revenues

The partnership’s production revenues from all of its wells will be commingled. Thus, regardless of when you subscribe to the partnership you will share in the production revenues from all of the partnership wells on the same basis as the other investors in the partnership in proportion to your number of units.

Proceeds from the Sale of Leases. If a partnership well is sold, a portion of the sales proceeds will be allocated to the partners in the same proportion as their share of the adjusted tax basis of the property. In addition, proceeds will be allocated to the managing general partner to the extent of the pre-contribution appreciation in value of the property, if any. Any excess will be credited as provided in 4, below.

Interest Proceeds. Interest income earned on your subscription proceeds until they are paid to the managing general partner for use in the drilling activities of the partnership in which you subscribed will be credited to your account and paid to you not later than the partnership’s first cash distribution from operations. Until your partnership’s subscription proceeds are invested in your partnership’s operations, any interest income from temporary investments will be allocated pro rata to you and the other investors providing the subscription proceeds. All other interest income, including interest earned on the deposit of production revenues, will be credited as provided in 4, below.

3.	Equipment Proceeds. Proceeds from the sale or other disposition of equipment will be credited to the parties charged with the costs of the equipment in the ratio in which the costs were charged.

Production Revenues. Subject to the managing general partner’s subordination obligation as described below, the managing general partner and you and the other investors in the partnership will share in all of the partnership’s other revenues, including production revenues, in the same percentage as their respective capital contribution bears to the partnership’s total capital contributions, except that the managing general partner will receive an additional 10% of the partnership’s revenues. For example, if the managing general partner contributes the minimum of 15% of the partnership’s total capital contributions and the investors contribute 85% of the partnership’s total capital contributions, then the managing general partner will receive 25% of the partnership revenues and the investors will receive 75% of the partnership revenues. See “Compensation – Natural Gas and Oil Revenues” for a graphic presentation of this amount.

Subordination of Portion of Managing General Partner’s Net Revenue Share

If you and the other investors do not receive cumulative cash distributions equal to a minimum of 10% of capital, based on a subscription price of $10,000 per unit, regardless of the actual subscription price you paid for your units, in each of the first five 12-month periods beginning with the partnership’s first cash distributions from operations, the managing general partner will subordinate up to 50% of its share, as managing general partner, of partnership net production revenues, which will be at least 12.5% of the total partnership net production revenues, depending on the amount of its capital contributions, during this subordination period.

Partnership net production revenues means gross revenues after deduction of the related operating costs, direct costs, administrative costs, and all other costs not specifically allocated.

The partnership’s 60-month subordination period will begin with the partnership’s first cash distribution from operations to you and the other investors. The estimated maximum time from the closing of the offering of units in the partnership for the partnership to begin distributions is eight months from the closing as discussed in “Investment Objectives.” Subordination distributions will be determined by debiting or crediting current period partnership revenues to the managing general partner as may be necessary to provide the distributions to you and the other investors. At any time during the subordination period the managing general partner is entitled to an additional share of partnership revenues to recoup previous subordination distributions to the extent your cash distributions from the partnership exceed the 10% return of capital described above. The specific formula for determining subordination distributions is set forth in Section 5.01(b)(4)(a) of the partnership agreement.

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The managing general partner anticipates that you will benefit from the subordination if the price of natural gas and oil received by the partnership and/or the results of the partnership’s drilling activities, such as the volume of natural gas and oil produced from the partnership’s wells, are unable to provide the required return of capital. However, if the wells produce small natural gas and oil volumes or natural gas and oil prices decrease, then even with subordination your cash flow may be very small and you may not receive the 10% return of capital for each of the first five years beginning with the partnership’s first cash distribution from operations.

As of May 31, 2009, the managing general partner was subordinating its partnership net production revenues in two of the 11 limited partnerships that currently have the subordination feature in effect. Since 1993 the managing general partner has had the same or a similar subordination feature in 39 of its partnerships and from time to time it has subordinated its partnership net production revenues in 18 of those partnerships. The managing general partner is entitled to recoup those subordination distributions during the respective subordination period of those previous partnerships to the extent cash distributions of those previous partnerships to their respective investors would exceed the specified return to the investors.

Example of Net Revenue Sharing During a Subordination Period.

Entity	Percentage of Partnership Capital Contributions (1)			Percentage of Partnership Net Revenues Without Subordination (1)			Maximum Amount of Managing General Partner’s Share of Partnership Net Revenues Available for Subordination (2)			Net Revenues to Managing General Partner and Investors if Maximum Amount of Managing General Partner’s Share of Partnership Net Revenues is Subordinated (1)(2)

Managing General Partner		15	%		25	%		12.5	%		12.5	%
Investors		85	%		75	%					87.5	%

(1)

These percentages are for illustration purposes only and assume the managing general partner’s minimum required capital contribution of 15% to the partnership and capital contributions of 85% from you and the other investors. The actual percentages are likely to be different because they will be based on the actual capital contributions of the managing general partner and you and the other investors.

(2)

If you and the other investors do not receive cumulative cash distributions equal to a minimum of 10% of capital, based on a subscription price of $10,000 per unit, regardless of the actual subscription price you paid for your units, in each of the first five 12-month periods beginning with the partnership’s first cash distributions from operations, the managing general partner will subordinate up to 50% of its share of partnership net production revenues, which will depend on the amount of its capital contributions, during this subordination period.

Example of Net Revenue Sharing After the End of a Subordination Period.

Entity	Percentage of Partnership Capital Contributions (1)			Percentage of Partnership Net Revenues Without Subordination (1)			Maximum Amount of Managing General Partner’s Share of Partnership Net Revenues Available for Subordination			Net Revenues to Managing General Partner and Investors When None of Managing General Partner’s Share of Partnership Net Revenues is Subordinated (1)

Managing General Partner		15	%		25	%		0	%		25	%
Investors		85	%		75	%					75	%

(1)

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Table of Participation in Costs and Revenues

The following table sets forth certain partnership costs and revenues charged and credited between the managing general partner and you and the other investors in the partnership, after deducting from the partnership’s gross revenues the landowner royalties and any other lease burdens.

	Managing
	General
	Partner		Investors
Partnership Costs
Organization and offering costs		100%		0%
Lease costs		100%		0%
Intangible drilling costs (1)		0%		100%
Equipment costs		(2)		(2)
Operating costs, administrative costs, direct costs, and all other costs		(3)		(3)

Partnership Revenues
Interest income		(4)		(4)
Equipment proceeds		(2)		(2)
All other revenues including production revenues		(5)(6)		(5)(6)

Participation in Deductions and Credits
Intangible drilling costs		0%		100%
Depreciation		(2)		(2)
Percentage depletion allowance		(5)(6)(7)		(5	)(6)(7)
Marginal well production credits		(5)(6)(7)		(5	)(6)(7)

(1)	Eighty-five percent of the subscription proceeds of you and the other investors in the partnership will be used to pay 100% of the intangible drilling costs incurred by the partnership in drilling and completing its wells.

(2)

Fifteen percent of the subscription proceeds of you and the other investors in the partnership will be used to pay the majority of the equipment costs incurred by the partnership in drilling and completing its wells. All equipment costs in excess of 15% of the partnership’s subscription proceeds will be paid by the managing general partner. Equipment proceeds, if any, will be credited in the same percentage in which the equipment costs were charged. Thus, you and the other investors in the partnership will receive the majority of the partnership’s equipment proceeds, if any.

(3)	These costs, which also include plugging and abandonment costs of the wells after the wells have been drilled, produced, and depleted, will be charged to the parties in the same ratio as the related production revenues are being credited.

(4)

Interest earned on your subscription proceeds until they are paid to the managing general partner for use in the drilling activities of the partnership will be credited to your account and paid to you not later than the partnership’s first cash distribution from operations. Until your partnership’s subscription proceeds are invested in its operations, any interest income from temporary investments will be allocated pro rata to the investors providing the subscription proceeds. All other interest income in the partnership, including interest earned on the deposit of operating revenues, will be credited as production revenues are credited.

(5)

In the partnership the managing general partner and you and the other investors will share in all of the partnership’s other revenues in the same percentage that their respective capital contributions bear to the partnership’s total capital contributions, except that the managing general partner will receive an additional 10% of the partnership revenues.

(6)	If a portion of the managing general partner’s partnership net production revenues is subordinated, then the actual allocation of partnership net production revenues between the managing general partner and you and the other investors will vary from the allocation described in (5) above.

(7)	The percentage depletion allowances and any marginal well production credits will be credited between the managing general partner and you and the other investors in the same percentages as the production revenues are being credited.

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Allocation and Adjustment Among Investors

The investors’ share as a group of the partnership’s revenues, gains, income, costs, marginal well production credits (if any), expenses, losses, and other charges and liabilities generally will be charged and credited among you and the other investors in the partnership in accordance with the ratio that your respective number of units bears to the number of units held by all investors as a group in the partnership, based on a subscription price of $10,000 per unit regardless of the actual subscription price you paid for your units. These allocations will take into account any investor general partner’s status as a defaulting investor general partner. Certain investors, however, will pay a discounted subscription price for their units as described in “Plan of Distribution.” Thus, intangible drilling costs and the investors’ share of the equipment costs of drilling and completing the partnership’s wells will be charged among you and the other investors in the partnership as set forth above, except that these allocations (i.e., intangible drilling costs and equipment costs) will be based on the respective subscription amount paid by you and the other investors for your respective units as set forth on your respective subscription agreements, rather than a subscription price of $10,000 per unit for all of the units.

Distributions

The managing general partner will review the partnership’s accounts at least monthly to determine whether cash distributions are appropriate and the amount to be distributed, if any, taking into account its subordination obligation discussed above in “– Subordination of Portion of Managing General Partner’s Net Revenue Share.” Your partnership will distribute funds to you and the other investors that the managing general partner, in its sole discretion, does not believe are necessary for the partnership to retain. Distributions may be reduced or deferred to the extent partnership revenues are used for any of the following:

repayment of partnership borrowings;

cost overruns;

remedial work to improve a well’s producing capability, including additional fracs in the Marcellus Shale;

compensation and fees to the managing general partner as described in “Risk Factors – Risks Related to an Investment in the Partnership – Compensation and Fees to the Managing General Partner Regardless of Success of the Partnership’s Activities Will Reduce Cash Distributions”;

direct costs and general and administrative expenses of the partnership;

reserves, including a reserve for the estimated costs of eventually plugging and abandoning the wells; or

indemnification of the managing general partner and its affiliates by the partnership for losses or liabilities incurred in connection with the partnership’s activities.

Also, funds will not be advanced or borrowed by the partnership for the purpose of making distributions to you and the other investors if the amount advanced or borrowed would exceed the partnership’s accrued and received revenues for the previous four quarters, less paid and accrued operating costs with respect to the revenues. Any cash distributions from the partnership to the managing general partner will be made only in conjunction with distributions to you and the other investors in the partnership and only out of funds properly allocated to the managing general partner’s account.

Liquidation

The partnership will continue for 50 years unless it is terminated earlier by a final terminating event as described below, or an event which causes the dissolution of a limited partnership under the Delaware Revised Uniform Limited Partnership Act. However, if the partnership terminates on an event which causes a dissolution of the partnership under state law and it is not a final terminating event, then a successor limited partnership will automatically be formed. Thus, only on a final terminating event will the partnership be liquidated. A final terminating event is any of the following:

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the election to terminate the partnership by the managing general partner or the affirmative vote of investors whose units equal a majority of the total units;

the termination of the partnership under Section 708(b)(1)(A) of the Internal Revenue Code because no part of its business is being carried on; or

the partnership ceases to be a going concern.

On the partnership’s liquidation you will receive your interest in the partnership. Generally, your interest in the partnership means an undivided interest in the partnership’s assets, after payments to the partnership’s creditors, in the ratio that your positive capital account bears to the positive capital accounts of all of the partners in the partnership (including the managing general partner) until all of the capital accounts have been reduced to zero. Thereafter, your interest in the remaining partnership assets will equal your interest in the related partnership revenues.

Any in-kind property distributions to you from the partnership must be made to a liquidating trust or similar entity, unless you affirmatively consent to receive an in-kind property distribution after being told the risks associated with the direct ownership of the property or unless there are alternative arrangements in place which assure that you will not be responsible for the operation or disposition of the partnership’s properties. If the managing general partner has not received your written consent to a proposed in-kind property distribution within 30 days after it is mailed, then it will be presumed that you have not consented. The managing general partner may then sell the asset at the best price reasonably obtainable from an independent third-party, or to itself or its affiliates at fair market value as determined by an independent expert selected by the managing general partner. Also, if the partnership is liquidated the managing general partner will be repaid any debts owed to it by the partnership before there are any payments to you and the other investors in the partnership.

CONFLICTS OF INTEREST

In General

Conflicts of interest are inherent in natural gas and oil partnerships involving non-industry investors because the transactions are entered into without arms’ length negotiation. Your interests and those of the managing general partner and its affiliates may be inconsistent in some respects or in certain instances, and the managing general partner’s actions may not be the most advantageous to you. The following discussion describes all material possible conflicts of interest that may arise for the managing general partner and its affiliates in the course of the partnership. For some of the conflicts of interest, but not all, there are certain limitations on the managing general partner that are designed to reduce, but will not eliminate, the conflicts. Other than these limitations the managing general partner has no procedures to resolve a conflict of interest and under the terms of the partnership agreement the managing general partner may resolve the conflict of interest in its sole discretion and best interest.

Further, the managing general partner depends on its indirect parent companies, Atlas America and ATN and their affiliates, for management and administrative functions. Neither the partnership agreement nor any other agreement requires Atlas America or ATN to pursue a future business strategy that favors the partnership. The directors and officers of Atlas America and ATN and their affiliates have a fiduciary duty to make decisions in the best interests of their respective stockholders. Because the managing general partner is allowed to take into account the interests of parties other than the partnership, such as Atlas America, ATN, and their affiliates in resolving partnership conflicts of interest, this has the effect of creating a conflict of interest. However, this conflict of interest is not allowed to limit the managing general partner’s fiduciary duty to the partnership. See “Management – Managing General Partner and Operator” concerning the intended merger between Atlas America and ATN.

The following discussion is materially complete; however, other transactions or dealings may arise in the future that could result in conflicts of interest for the managing general partner and its affiliates.

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Conflicts Regarding Transactions with the Managing General Partner and its Affiliates

Although the managing general partner believes that the compensation and reimbursement that it and its affiliates will receive in connection with the partnership are reasonable, the compensation has been determined solely by the managing general partner and did not result from negotiations with any unaffiliated third-party dealing at arms’ length. The managing general partner and its affiliates will receive compensation and reimbursement from the partnership for their services in drilling, completing, and operating the partnership’s wells under the drilling and operating agreement and will receive the other fees described in “Compensation” regardless of the success of the partnership’s wells. The managing general partner and its affiliates providing the services or equipment can be expected to profit from the transactions, and it is usually in the managing general partner’s best interest to enter into contracts with itself and its affiliates, rather than unaffiliated third-parties even if the contract terms, skill, and experience, offered by the unaffiliated third-parties are comparable.

When the managing general partner or any affiliate provides services or equipment to the partnership the partnership agreement provides that their fees must be competitive with the fees charged by unaffiliated third-parties in the same geographic area engaged in similar businesses. Also, before the managing general partner or any affiliate may receive competitive fees for providing services or equipment to the partnership they must be engaged, independently of the partnership and as an ordinary and ongoing business, in rendering the services or selling or leasing the equipment and supplies to a substantial extent to other persons in the natural gas and oil industry in addition to the partnership in which the managing general partner or an affiliate has an interest. If the managing general partner or the affiliate is not engaged in such a business, then the compensation must be the lesser of its cost or the competitive rate that could be obtained in the area.

Any services not otherwise described in this prospectus or the partnership agreement for which the managing general partner or an affiliate is to be compensated by the partnership must be:

set forth in a written contract that describes the services to be rendered and the compensation to be paid; and

cancelable without penalty on 60 days written notice by investors whose units equal a majority of the total units.

The compensation paid by the partnership to the managing general partner or its affiliates for additional services to the partnership under these contracts, if any, will be reported to you in the partnership’s annual and semiannual reports, and a copy of the contract will be provided to you on request.

There is also a conflict of interest concerning the purchase price if the managing general partner or an affiliate purchases a property from the partnership, which they may do in certain limited circumstances as described in “– Conflicts Involving the Acquisition of Leases – (6) Limitations on Sale of Undeveloped and Developed Leases to the Managing General Partner,” below.

Conflict Regarding the Drilling and Operating Agreement

The managing general partner anticipates that all of the wells to be drilled by the partnership will be drilled and operated under the drilling and operating agreement. This creates a continuing conflict of interest because the managing general partner must monitor and enforce, on behalf of the partnership, its own compliance, as operator with the drilling and operating agreement and as managing general partner with the partnership agreement, and the compliance of its affiliates, including Laurel Mountain in the Marcellus Shale primary area, with the gas gathering agreements.

Conflicts Regarding Sharing of Costs and Revenues

The managing general partner will receive a percentage of partnership revenues that is greater than the percentage of partnership costs that it pays. This sharing arrangement may create a conflict of interest between the managing general partner and you and the other investors in the partnership concerning the determination of which wells will be drilled by the partnership based on the risk and profit potential associated with the wells.

In addition, the allocation of all of the intangible drilling costs and the majority of the equipment costs to you and the other investors and the remaining portion of the equipment costs to the managing general partner creates a conflict of interest between the managing general partner and you and the other investors concerning whether to complete a well. For example, the completion of a marginally productive well might prove beneficial to you and the other investors, but not to the managing general partner. When a completion decision is made, you and the other investors will have already paid the majority of your costs so you will want to pay your share of the additional costs to complete the well if there is a reasonable opportunity to recoup your share of the completion costs plus at least a portion of the costs of the well paid by you before the completion attempt.

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On the other hand, the managing general partner will have paid only a portion of its equipment costs for the well before this time, and it will want to pay its additional equipment costs to complete the well only if it is reasonably certain of recouping its share of the completion costs and making a profit. In any event, the managing general partner will not cause any well to be plugged and abandoned without a completion attempt unless it makes the decision in accordance with generally accepted oil and gas field practices in the geographic area of the well location.

Conflicts Regarding Tax Matters Partner

The managing general partner will serve as the partnership’s tax matters partner and represent the partnership before the IRS. The managing general partner will have broad authority to act on behalf of you and the other investors in the partnership in any administrative or judicial proceeding involving the IRS or other tax authorities, and this authority may involve conflicts of interest. For example, potential conflicts include:

whether or not to expend partnership funds to contest a proposed adjustment by the IRS, if any, that would decrease:

the amount of the partnership’s deduction for intangible drilling costs, which is allocated 100% to you and the other investors in the partnership;

the amount of the partnership’s depreciation deductions, the majority of which are allocated to you and the other investors;

the credit to the managing general partner’s capital account for contributing the leases to the partnership which would also decrease the managing general partner’s capital contributions to the partnership and its liquidation interest in the partnership; or

the amount charged to the partnership by the managing general partner as reimbursement for expenses incurred by the managing general partner in its role as the tax matters partner.

Conflicts Regarding Other Activities of the Managing General Partner, the Operator and Their Affiliates

The managing general partner will be required to devote to the partnership the time and attention that it considers necessary for the proper management of the partnership’s activities. However, the managing general partner has sponsored and continues to manage other natural gas and oil drilling partnerships, which may be concurrent, and it and its affiliates will engage in oil and gas activities, including drilling, either for its own account or on behalf of other partnerships, joint ventures, corporations, or other entities in which it has an interest. This creates a continuing conflict of interest in allocating management time, services, and other activities between the partnership and the managing general partner’s other activities.

The managing general partner will determine the allocation of its management time, services, and other functions on an as-needed basis consistent with its fiduciary duties among the partnership and its other activities. However, the managing general partner depends on its indirect parent companies, Atlas America, ATN and their affiliates, for management and administrative functions as described in “Management – Transactions with Management and Affiliates.” Thus, the competition for the time and services of the managing general partner and its affiliates could result in insufficient attention to the management and operation of the partnership.

Subject to its fiduciary duties, the managing general partner will not be restricted from participating in other businesses or activities, even if these other businesses or activities compete with the partnerships’ activities and operate in the same areas as the partnership. However, the managing general partner and its affiliates may pursue business opportunities that are consistent with the partnership’s investment objectives for their own account only after they have determined that the opportunity either:

cannot be pursued by the partnership because of insufficient funds; or

it is not appropriate for the partnership under the existing circumstances.

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Conflicts Involving the Acquisition of Leases

The managing general partner will select, in its sole discretion, the wells to be drilled by the partnership. Conflicts of interest may arise concerning which wells will be drilled by the partnership and which wells will be drilled by the managing general partner’s and its affiliates’ for their own account, other affiliated partnerships, third-party programs or joint ventures in which they serve as driller/operator. It may be in the managing general partner’s or its affiliates’ advantage to have the partnership bear the costs and risks of drilling a particular well rather than another affiliate or itself. Conversely, the managing general partner and its affiliates may elect to drill a well for their own account because of the prospective economic benefits. For example, because the partnership agreement limits the amount of partnership revenues that may be received by the managing general partner and its affiliates, it may be more advantageous for the managing general partner and its affiliates to drill the well for their own account, since other arrangements are not subject to these limits.

These potential conflicts of interest will be increased if the managing general partner organizes and allocates wells to more than one partnership at a time. To lessen this conflict of interest the managing general partner generally takes a similar interest in the other partnerships when it serves as managing general partner of the other partnership. Also, the managing general partner may cause the partnership to drill wells on leases that are scheduled to expire in order to prevent the expiration of the lease.

When the managing general partner must provide prospects to two or more partnerships at the same time it will attempt to treat each partnership fairly on a basis consistent with:

the funds available to the partnerships; and

the time limitations on the investment of funds for the partnerships.

The partnership agreement gives the managing general partner the authority to cause the partnership to acquire undivided interests in natural gas and oil properties, and to participate with other parties, including other drilling programs previously or subsequently conducted by the managing general partner or its affiliates, in the conduct of its drilling operations on those properties. If conflicts between the interest of the partnership and other drilling partnerships do arise, then the managing general partner may be unable to resolve those conflicts to the maximum advantage of the partnership because the managing general partner must deal fairly with the investors in all of its drilling partnerships.

In addition, subject to the restrictions set forth below, the managing general partner decides which prospects and what interest in the prospects to transfer to the partnership. This will result in a subsequent partnership sponsored by the managing general partner and its affiliates benefiting from knowledge gained through the partnership’s drilling experience in an area and acquiring a prospect adjacent to the partnership’s prospect. In this regard, as drilling 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.

No procedures, other than the guidelines set forth below and in “– Procedures to Reduce Conflicts of Interest,” have been established by the managing general partner to resolve any conflicts that may arise. The partnership agreement provides that the managing general partner and its affiliates will abide by the guidelines set forth below. However, with respect to (2), (3), (4), (5), (7) and (9) there is an exception in the partnership agreement for another program in which the interest of the managing general partner is substantially similar to or less than its interest in the partnership.

(1)

Transfers at Cost. All leases will be acquired by the partnership from the managing general partner and credited towards its required capital contribution to the partnership at the cost of the lease, unless the managing general partner has a reason to believe that cost is materially more than the fair market value of the property. If the managing general partner believes that cost is materially more than fair market value, then the managing general partner’s credit for the contribution must be at a price not in excess of the fair market value. See “Compensation – Lease Costs” regarding the managing general partner averaging its lease costs and “Participation in Costs and Revenues – Costs – Lease Costs.”

A determination of fair market value must be supported by an appraisal from an independent expert and maintained in the partnership’s records for at least six years.

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(2)	Equal Proportionate Interest. When the managing general partner sells or transfers an oil and gas interest to the partnership, it must, at the same time, sell or transfer to the partnership an equal proportionate interest in all of its other property in the same prospect.

The term “prospect” generally means an area which is believed to contain commercially productive quantities of natural gas or oil.

However, a prospect will be limited to the drilling or spacing unit on which one well will be drilled if the following two conditions are met:

the well is being drilled to a geological feature which contains proved reserves as defined below; and

the drilling or spacing unit protects against drainage.

Also, horizontal wells may be drilled on the same prospect as the vertical well. The managing general partner believes that for a prospect located in the primary and secondary drilling areas as described in “Proposed Activities – Primary Areas of Operations” and “– Secondary Areas of Operations,” a prospect will consist of the drilling and spacing unit because it will meet the test in the preceding sentence.

Proved reserves, generally, are the estimated quantities of natural gas and oil which have been demonstrated to be recoverable in future years with reasonable certainty under existing economic and operating conditions. Proved reserves include proved undeveloped reserves which generally are reserves expected to be recovered from existing wells where a relatively major expenditure is required for recompletion or from new wells on undrilled acreage. Reserves on undrilled acreage will be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved Reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation or there is continuity of the reservoir.

In the primary and secondary areas the managing general partner anticipates that the drilling of these wells by the partnership may provide the managing general partner with offset sites by allowing it to determine, at the partnership’s expense, the value of adjacent acreage in which the partnership would not have any interest. The managing general partner owns acreage throughout the primary and secondary areas where the partnership’s wells will be situated.

The managing general partner believes that none of the prospects transferred to the partnership will result in drainage from the surrounding wells.

(3)	Subsequently Enlarging Prospect. In areas where the prospect is not limited to the drilling or spacing unit and the area constituting the partnership’s prospect is subsequently enlarged based on geological information which is later acquired, there is the following special provision:

if the prospect is enlarged to cover any area where the managing general partner owns a separate property interest and the partnership activities were material in establishing the existence of proved undeveloped reserves which are attributable to the separate property interest, then the separate property interest or a portion thereof must be sold to the partnership in accordance with (1), (2) and (4).

(4)	Transfer of Less than the Managing General Partner’s and its Affiliates’ Entire Interest. If the managing general partner sells or transfers to the partnership less than all of its ownership in any prospect, then it must comply with the following conditions:

the retained interest must be a proportionate working interest;

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the managing general partner’s obligations and the partnership’s obligations must be substantially the same after the sale of the interest by the managing general partner or its affiliates; and

the managing general partner’s revenue interest must not exceed the amount proportionate to its retained working interest.

For example, if the managing general partner transfers 50% of its working interest in a prospect to the partnership and retains a 50% working interest, then the partnership will not pay any of the costs associated with the managing general partner’s retained working interest as a part of the transfer. This limitation does not prevent the managing general partner and its affiliates from subsequently dealing with their retained working interest as they may choose with unaffiliated parties or affiliated partnerships. For example, the managing general partner may sell its retained working interest to a third-party for a profit.

(5)

Limitations on Activities of the Managing General Partner and its Affiliates on Leases Acquired by the Partnership. For a five year period after the final closing of the partnership, if the managing general partner proposes to acquire an interest from an unaffiliated person in a prospect in which the partnership owns an interest or in a prospect in which the partnership’s interest has been terminated without compensation within one year before the proposed acquisition, then the following conditions apply:

if the managing general partner does not currently own property in the prospect separately from the partnership, then the managing general partner may not buy an interest in the prospect; and

if the managing general partner currently owns a proportionate interest in the prospect separately from the partnership, then the interest to be acquired must be divided in the same proportion between the managing general partner and the partnership as the other property in the prospect. However, if the partnership does not have the cash or financing to buy the additional interest, then the managing general partner is also prohibited from buying the additional interest.

(6)

Limitations on Sale of Undeveloped and Developed Leases to the Managing General Partner. The managing general partner and its affiliates, other than an affiliated partnership as set forth in (7) below, may not purchase undeveloped leases or receive a farmout from the partnership other than at the higher of cost or fair market value. Farmouts to the managing general partner and its affiliates also must comply with the conditions set forth in (9) below.

The managing general partner and its affiliates, other than an affiliated income program, may not purchase any producing natural gas or oil property from the partnership unless:

the sale is in connection with the liquidation of the partnership; or

the managing general partner’s well supervision fees under the drilling and operating agreement for the well have exceeded the net revenues of the well, determined without regard to the managing general partner’s well supervision fees for the well, for a period of at least three consecutive months.

In both cases, the sale must be at fair market value supported by an appraisal of an independent expert selected by the managing general partner. The appraisal of the property must be maintained in the partnership’s records for at least six years.

(7)

Transfer of Leases Between Affiliated Limited Partnerships. The partnership may joint venture in the drilling of wells with affiliated drilling limited partnerships. In this regard, the transfer of an undeveloped lease from the partnership to an affiliated drilling limited partnership must be made at fair market value if the undeveloped lease has been held by the partnership for more than two years. Otherwise, the transfer may be made at cost if the managing general partner deems it to be in the best interest of the partnership.

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An affiliated income program may purchase a producing natural gas and oil property from the partnership at any time at:

fair market value as supported by an appraisal from an independent expert if the property has been held by the partnership for more than six months or there have been significant expenditures made in connection with the property; or

cost as adjusted for intervening operations if the managing general partner deems it to be in the best interest of the partnership.

However, these prohibitions do not apply to joint ventures or farmouts among affiliated partnerships, provided that:

the respective obligations and revenue sharing of all parties to the transaction are substantially the same; and

the compensation arrangement or any other interest or right of either the managing general partner or its affiliates is the same in each affiliated partnership or if different, the aggregate compensation of the managing general partner or the affiliate is reduced to reflect the lower compensation arrangement.

(8)

Leases Will Be Acquired Only for Stated Purpose of the Partnership. The partnership must acquire only leases that are reasonably expected to meet the stated purposes of the partnership. Also, no leases may be acquired for the purpose of a subsequent sale, farmout or other disposition unless the acquisition is made after a well has been drilled to a depth sufficient to indicate that the acquisition would be in the partnership’s best interest.

(9)

Farmout. The managing general partner may not assign the working interest in a prospect to the partnership for the purpose of a subsequent farmout, sale or other disposition, nor may the managing general partner enter into a farmout to avoid paying its share of the costs related to drilling a well on an undeveloped lease. However, the managing general partner’s decision with respect to making a farmout and the terms of a farmout from the partnership involve conflicts of interest since the managing general partner may benefit from cost savings and reduction of its risk.

The partnership may farmout an undeveloped lease or well activity to the managing general partner, its affiliates or an unaffiliated third-party only if the managing general partner, exercising the standard of a prudent operator, determines that:

the partnership lacks the funds to complete the oil and gas operations on the lease or well and cannot obtain suitable financing;

drilling on the lease or the intended well activity would concentrate excessive funds in one location, creating undue risks to the partnership;

the leases or well activity have been downgraded by events occurring after assignment to the partnership so that development of the leases or well activity would not be desirable; or

the best interests of the partnership would be served.

If the partnership farmouts a lease or well activity, the managing general partner must retain on behalf of the partnership the economic interests and concessions as a reasonably prudent oil and gas operator would or could retain under the circumstances prevailing at the time, consistent with industry practices. However, if the farmout is made to the managing general partner or its affiliates there is a conflict of interest since the managing general partner will represent both the partnership and itself or an affiliate. Although the conflict of interest may be resolved to the managing general partner’s benefit, the managing general partner must still retain on behalf of the partnership the economic interests and concessions as a reasonably prudent oil and gas operator would or could retain under the circumstances prevailing at the time, consistent with industry practices.

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Conflicts Regarding Order of Pipeline Construction and Gathering Fees

There are conflicts between you and the managing general partner and its affiliates, because the managing general partner must monitor and enforce on behalf of the partnership the compliance of its affiliates, including Laurel Mountain in the Marcellus Shale primary area, with the gas gathering agreements. Also, the managing general partner may choose well locations for the partnership that are situated near the gathering systems owned by its affiliates, including Laurel Mountain, which would benefit the managing general partner’s indirect parent companies, Atlas America and ATN, by providing more gathering fees, even if there are other well locations available in the same area or other areas which offer the partnership a greater potential return. (See “Management – Managing General Partner” regarding the intended merger of Atlas America and ATN.

In addition, Williams will manage the day-to-day operations of Laurel Mountain’s gathering system under the direction of Laurel Mountain’s management committee, which is discussed below. Although APL Laurel Mountain, a subsidiary of Atlas Pipeline Partners, owns a 49% equity interest in Laurel Mountain and it has one of two members on Laurel Mountain’s management committee, the expansion of the Laurel Mountain’s gathering system will not be within APL Laurel Mountain’s exclusive control. Notwithstanding, the managing general partner and APL Laurel Mountain will attempt to have Laurel Mountain’s gathering system in the Marcellus Shale primary area expanded to those areas with the greatest number of partnership wells with the greatest potential reserves as described in “Proposed Activities – Sale of Natural Gas and Oil Production – Gathering of Natural Gas.”

Further, certain of the managing general partner’s affiliates, including Atlas America, LLC and/or ATN, are obligated through their agreement with Laurel Mountain to pay the difference between the amount the partnership pays for gathering fees to the managing general partner and the greater of $.35 per mcf or 16% of the gross sales price for the partnership’s natural gas that is transported through Laurel Mountain’s gathering system, which will include natural gas produced from the partnership’s wells in the Marcellus Shale primary area. (See “Compensation – Gathering Fees.”) This creates a conflict of interest between the managing general partner and the partnership because the managing general partner has an economic incentive to increase the amount of gathering fees paid by the partnership so as to reduce the amount paid by the Atlas entities to Laurel Mountain which would reduce your cash distributions from the partnership, but any increase cannot exceed a competitive rate.

Conflicts Between Investors and the Managing General Partner as an Investor

The managing general partner, its officers, directors, and its affiliates may subscribe for units in the partnership and the subscription price of their units will be reduced by 10% as described in “Plan of Distribution.” Even though they pay a reduced price for their units, these investors generally will:

share in the partnership’s costs, revenues, and distributions on the same basis as the other investors as described in “Participation in Costs and Revenues”; and

have the same voting rights, except as discussed below.

Any subscription for units by the managing general partner, its officers, directors, or affiliates in the partnership will dilute the voting rights of you and the other investors and there may be a conflict with respect to certain matters. The managing general partner and its officers, directors and affiliates, however, are prohibited from voting with respect to certain matters as described in “Summary of Partnership Agreement – Voting Rights.”

Lack of Independent Underwriter and Due Diligence Investigation

The terms of this offering, the partnership agreement, and the drilling and operating agreement were determined by the managing general partner without arms’ length negotiations. You and the other investors have not been separately represented by legal counsel, who might have negotiated more favorable terms for you and the other investors in this offering and the agreements.

Also, there was not an extensive in-depth “due diligence” investigation of the existing and proposed business activities of the partnership and the managing general partner that would be provided by independent underwriters. Although Anthem Securities, which is affiliated with the managing general partner, serves as dealer-manager of this offering and will receive reimbursement of bona fide due diligence expenses for certain due diligence investigations conducted by the selling agents, all of which will be reallowed by Anthem Securities to the selling agents, its due diligence examination concerning this offering cannot be considered to be independent or as comprehensive as a due diligence examination that would have been conducted by an independent underwriter.

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Conflicts Concerning Legal Counsel

The managing general partner anticipates that its legal counsel will also serve as legal counsel to the partnership and that this dual representation will continue in the future. However, if a future dispute arises between the managing general partner and you and the other investors in the partnership, then the managing general partner will cause you and the other investors to retain separate counsel. Also, if counsel advises the managing general partner that counsel reasonably believes its representation of the partnership will be adversely affected by its responsibilities to the managing general partner, then the managing general partner will cause you and the other investors in the partnership to retain separate counsel.

Conflicts Regarding Presentment Feature

You and the other investors in the partnership have the right to present your units in the partnership to the managing general partner for purchase beginning with the fifth calendar year after the end of the calendar year in which your partnership closes. This creates the following conflicts of interest between you and the managing general partner.

The managing general partner may suspend the presentment feature if it does not have the necessary cash flow or it cannot borrow funds for this purpose on terms which it deems reasonable. Both of these determinations are subjective and will be made in the managing general partner’s sole discretion.

The managing general partner will also determine the purchase price based on a reserve report that it prepares and is reviewed by an independent expert that it chooses. The formula for arriving at the purchase price has many subjective determinations that are within the discretion of the managing general partner.

Conflicts Regarding Managing General Partner Withdrawing or Assigning an Interest

A conflict of interest is created with you and the other investors by the managing general partner’s right to do any of the following:

mortgage its managing general partner interest in the partnership;

withdraw an interest in the partnership’s wells equal to or less than its revenue interest to be used as collateral for a loan to the managing general partner; or

assign, subject to the managing general partner’s subordination obligation, its managing general partner interest in the partnership to its affiliates which also may mortgage the interests as collateral for their loans, if any.

If the managing general partner assigned a portion or all of its managing general partner interest in the partnership to an affiliate, the amount of partnership net production revenues available to the managing general partner or an affiliated assignee for their respective subordination obligations to you and the other investors could be reduced or eliminated if there was a default under a loan to the managing general partner or the affiliated assignee. Also, under certain circumstances, if the managing general partner or an affiliated assignee, if a portion or all of the managing general partner’s managing general partner interest in the partnership was assigned by the managing general partner to an affiliate as discussed above, made a subordination distribution to you and the other investors after a default to its lenders, then the lenders may be able to recoup that subordination distribution from you and the other investors.

Procedures to Reduce Conflicts of Interest

In addition to the procedures set forth in “– Conflicts Involving the Acquisition of Leases,” the managing general partner and its affiliates will comply with the following procedures in the partnership agreement to reduce some of the conflicts of interest with you and the other investors. The managing general partner does not have any other conflict of interest resolution procedures. Thus, conflicts of interest between the managing general partner and you and the other investors may not necessarily be resolved in your best interests. However, the managing general partner believes that its significant capital contribution to the partnership will reduce the conflicts of interest.

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(1)

Fair and Reasonable. The managing general partner may not sell, transfer, or convey any property to, or purchase any property from, the partnership except pursuant to transactions that are fair and reasonable; nor take any action with respect to the assets or property of the partnership which does not primarily benefit the partnership.

(2)

No Compensating Balances. The managing general partner may not use the partnership’s funds as a compensating balance for its own benefit. Thus, the partnership’s funds may not be used to satisfy any deposit requirements imposed by a bank or other financial institution on the managing general partner for its own corporate purposes.

(3)	Future Production. The managing general partner may not commit the future production of a partnership well exclusively for the managing general partner’s own benefit.

(4)	Disclosure. Any agreement or arrangement that binds the partnership must be fully disclosed in this prospectus.

(5)	No Loans from the Partnership. The partnership may not loan money to the managing general partner.

(6)	No Rebates. The managing general partner may not participate in any business arrangements which would circumvent these guidelines including receiving rebates or give-ups.

(7)	Sale of Assets. The sale of all or substantially all of the assets of the partnership may only be made with the consent of investors whose units equal a majority of the total units.

(8)	Participation in Other Partnerships. If the partnership participates in other partnerships or joint ventures, then the terms of the arrangements must not circumvent any of the requirements contained in the partnership agreement, including the following:

there may be no duplication or increase in organization and offering expenses, the managing general partner’s compensation, partnership expenses, or other fees and costs;

there may be no substantive change in the fiduciary and contractual relationship between the managing general partner and you and the other investors; and

there may be no diminishment in your voting rights.

(9)	Investments. The partnership’s funds may not be invested in the securities of another person except in the following instances:

investments in working interests made in the ordinary course of the partnership’s business;

temporary investments in income producing short-term highly liquid investments, in which there is appropriate safety of principal, such as U.S. Treasury Bills;

multi-tier arrangements meeting the requirements of (8) above;

investments involving less than 5% of the total subscription proceeds of the partnership that are a necessary and incidental part of a property acquisition transaction; and

investments in entities established solely to limit the partnership’s liabilities associated with the ownership or operation of property or equipment, provided that duplicative fees and expenses are prohibited.

(10)

Safekeeping of Funds. The managing general partner may not employ, or permit another to employ, the funds or assets of the partnership in any manner except for the exclusive benefit of the partnership. The managing general partner has a fiduciary responsibility for the safekeeping and use of all funds and assets of the partnership whether or not in the managing general partner’s possession or control.

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(11)	Advance Payments. Advance payments by the partnership to the managing general partner and its affiliates are prohibited except when advance payments are required to secure the tax benefits of prepaid intangible drilling costs and for a business purpose.

Policy Regarding Roll-Ups

It is possible at some indeterminate time in the future that the partnership may become involved in a roll-up. In general, a roll-up means a transaction involving the acquisition, merger, conversion, or consolidation of the partnership with or into another partnership, corporation or other entity, and the issuance of securities by the roll-up entity to you and the other investors. A roll-up will also include any change in the rights, preferences, and privileges of you and the other investors in the partnership. These changes could include the following:

increasing the compensation of the managing general partner;

amending your voting rights;

listing the units on a national securities exchange or on NASDAQ;

changing the partnership’s fundamental investment objectives; or

materially altering the partnership’s duration.

If a roll-up should occur in the future, the partnership agreement provides various policies which include the following:

an independent expert must appraise all partnership assets as discussed in §4.03(d)(16)(a) of the partnership agreement, and you must receive a summary of the appraisal in connection with a proposed roll-up;

if you vote “no” on the roll-up proposal, then you will be offered a choice of:

accepting the securities of the roll-up entity; or

one of the following:

remaining a partner in the partnership and preserving your units in the partnership on the same terms and conditions as existed previously; or

receiving cash in an amount equal to your pro-rata share of the appraised value of the partnership’s net assets; and

the partnership will not participate in a proposed roll-up:

unless approved by investors whose units equal a majority of the total units;

which would result in the diminishment of your voting rights under the roll-up entity’s chartering agreement;

which includes provisions which would operate to materially impede or frustrate the accumulation of shares by you of the securities of the roll-up entity;

in which your right of access to the records of the roll-up entity would be less than those provided by the partnership agreement; or

in which any of the transaction costs would be borne by the partnership if the proposed roll-up is not approved by investors whose units equal a majority of the total units.

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FIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNER

In General

The managing general partner will manage your partnership and its assets. In conducting your partnership’s affairs the managing general partner is accountable to you as a fiduciary, which under Delaware law generally means that the managing general partner must exercise due care and deal fairly with you and the other investors. Neither the partnership agreement nor any other agreement between the managing general partner and the partnership may contractually limit any fiduciary duty owed to you and the other investors by the managing general partner under applicable law. See “Conflicts of Interest – In General” regarding the managing general partner’s dependence on its indirect parent companies, Atlas America and ATN and their affiliates, for management and administrative functions and the organizational diagrams in “Management.” In this regard, the partnership agreement does permit the managing general partner and its affiliates to:

have business interests or activities that may conflict with the partnership if they determine that the business opportunity either:

cannot be pursued by the partnership because of insufficient funds; or

it is not appropriate for the partnership under the existing circumstances;

devote only so much of their time as is necessary to manage the affairs of the partnership, as determined by the managing general partner in its sole discretion;

conduct business with the partnership in a capacity other than as managing general partner or sponsor as described in §§4.01, 4.02, 4.03, 4.04, 4.05 and 4.06 of the partnership agreement;

manage multiple programs simultaneously; and

be indemnified and held harmless as described below in “– Limitations on Managing General Partner Liability as Fiduciary.”

The fiduciary duty owed by the managing general partner to the partnership is analogous to the fiduciary duty owed by directors to a corporation and its stockholders, which is commonly referred to as the “business judgment rule.” This rule provides that directors are not liable for mistakes made in the good faith exercise of honest business judgment or for losses incurred in the good faith performance of their duties when performed with such care as an ordinarily prudent person would use.

If the managing general partner breaches its fiduciary responsibilities, then you are entitled to an accounting and the recovery of any economic loss caused by the breach. The Delaware Revised Uniform Limited Partnership Act provides that a limited partner may institute legal action (a “derivative” action) on a partnership’s behalf to recover damages from a third-party when the managing general partner refuses to institute the action or where an effort to cause the managing general partner to do so is not likely to succeed. In addition, the statutory or case law may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners (a “class action”) to recover damages from the managing general partner for violations of its fiduciary duties to the limited partners. This is a rapidly expanding and changing area of the law, and if you have questions concerning the managing general partner’s duties you are urged to consult your own counsel.

Limitations on Managing General Partner Liability as Fiduciary

Under the terms of the partnership agreement the managing general partner, the operator, and their affiliates have limited their liability to the partnership and to you and the other investors for any loss suffered by your partnership or you and the other investors in the partnership which arises out of any action or inaction on their part if:

they determined in good faith that the course of conduct was in the best interest of the partnership;

they were acting on behalf of, or performing services for, the partnership; and

their course of conduct did not constitute negligence or misconduct.

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In addition, the partnership agreement provides for indemnification of the managing general partner, the operator, and their affiliates by the partnership against any losses, judgments, liabilities, expenses, and amounts paid in settlement of any claims sustained by them in connection with the partnership provided that they meet the standards set forth above. However, there is a more restrictive standard for indemnification for losses arising from or out of an alleged violation of federal or state securities laws. Also, to the extent that any indemnification provision in the partnership agreement purports to include indemnification for liabilities arising under the Securities Act of 1933, as amended, you should be aware that in the SEC’s opinion this indemnification provision would be contrary to public policy and therefore unenforceable.

Payments to the managing general partner or its affiliates arising from the indemnification or agreement to hold harmless provisions of the partnership agreement are recoverable only out of the partnership’s tangible net assets, which include its revenues and any insurance proceeds from the types of insurance for which the managing general partner, the operator and their affiliates may be indemnified under the partnership agreement. Still, the use of partnership funds or assets to indemnify the managing general partner, the operator, or an affiliate would reduce amounts available for partnership operations or for distribution to you and the other investors.

The partnership may not pay the cost of the portion of any insurance that insures the managing general partner, the operator, or an affiliate against any liability for which they cannot be indemnified. However, the partnership’s funds can be advanced to them for legal expenses and other costs incurred in any legal action for which indemnification is being sought if the partnership has adequate funds available and certain conditions in the partnership agreement are met.

The effect of the foregoing provisions and the business judgment rule may be to limit your recourse against the managing general partner.

FEDERAL INCOME TAX CONSEQUENCES

Introduction

No advance ruling on any federal tax issue of an investment in the partnership will be requested from the IRS. Thus, the IRS could disagree with one or more tax positions taken by the partnership. However, the managing general partner has obtained a tax opinion letter from Kunzman & Bollinger, Inc., Oklahoma City, Oklahoma, special counsel for this offering, with respect to the material and any significant federal income tax issues involving an investment in a partnership offered in this program, including the partnership, by a “typical investor” as that term is defined in “– Managing General Partner’s Representations,” below. You are urged to read the entire tax opinion letter, which has been filed as Exhibit 8.1 to the registration statement of which this prospectus is a part. See “Additional Information” for information on how to obtain a copy of special counsel’s tax opinion letter.

Although special counsel’s tax opinions express what it believes a court would probably conclude if presented with the applicable federal tax issues, special counsel’s tax opinions are only predictions, and are not guarantees, of the outcome of the particular tax issues being addressed. The IRS could challenge special counsel’s tax opinions, and the challenge could be sustained in the courts if litigated and cause adverse tax consequences to you and your partnership’s other investors. Special counsel’s tax opinions are based on current law and in part on representations and statements made by the managing general partner in the tax opinion letter and in this prospectus, including forward looking statements relating to the partnership and its proposed activities. (See “Forward Looking Statements and Associated Risks.”)

President Obama’s administration has proposed, among other tax changes, the repeal of certain oil and gas tax benefits, including the repeal of the percentage depletion allowance, the election to expense intangible drilling costs (including the further option to amortize intangible drilling costs over a 60 month period), the passive activity exception for working interests and the marginal production tax credit. These proposals may or may not be enacted into law. The repeal of the percentage depletion allowance, if it happens, would result in a substantial decrease in your future tax benefits from an investment in your partnership. Since the repeal of the intangible drilling costs deduction is not proposed until 2011, it will not affect your claim to deduct your share of the partnership’s intangible drilling costs in 2009. Also, other changes in the tax laws could be made that would reduce your tax benefits from an investment in the partnership. In this regard, see “Risk Factors – Federal Income Tax Risks – Changes in the Law May Reduce Your Tax Benefits from an Investment in the Partnership.”

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Disclosures in Tax Opinion Letter

Similar disclosures to those set forth below are made in special counsel’s tax opinion letter.

The tax opinion letter was written to support the promotion or marketing of units in the partnership to potential investors, and special counsel to the partnership has helped the managing general partner organize and document the offering of units in the partnership.

The tax opinion letter is not confidential. There are no limitations on the disclosure by the managing general partner or any potential investor in the partnership to any other person of the tax treatment or tax structure of the partnership.

Investors in the partnership have no contractual protection against the possibility that a portion or all of their intended tax benefits from an investment in the partnership ultimately are not sustained if challenged by the IRS. (See “Risk Factors – Federal Income Tax Risks – Your Tax Benefits from an Investment in the Partnership Are Not Contractually Protected.”)

Each potential investor is urged to seek advice based on his particular circumstances from an independent tax advisor with respect to the federal tax consequences to him of an investment in the partnership.

Special Counsel’s Assumptions

Set forth below is a synopsis of the principal assumptions made by special counsel in giving its federal income tax opinions.

You will not borrow money to buy units in the partnership from any other investor in the partnership.

You will be personally liable to repay any money you borrow to buy units in the partnership.

You will not protect yourself through nonrecourse financing, guarantees, stop loss agreements or other similar arrangements from losing the money you invest in the partnership.

Managing General Partner’s Representations

In giving its opinions for each partnership offered in the program, special counsel relied in part on representations from the managing general partner set forth in the tax opinion letter, including the principal representations summarized below.

A “typical investor” in each partnership will be a natural person who purchases units in this offering and is a U.S. citizen.

The investor general partner units in the partnership will be converted by the managing general partner to limited partner units after all of the wells in the partnership have been drilled and completed. (See “Actions to be Taken by Managing General Partner to Reduce Risks of Additional Payments by Investor General Partners.”)

Each partnership will elect to currently deduct all of the intangible drilling costs of all of its wells.

The managing general partner anticipates that the partnership’s entire subscription proceeds will be expended in the year in which its investors invest in the partnership, and you will include your share of your partnership’s deduction for intangible drilling costs on your individual federal income tax return for the year in which you invest in the partnership, subject to your right to elect to capitalize and amortize over a 60-month period a portion or all of your share of your partnership’s deduction for intangible drilling costs.

Each partnership may have its final closing as late in the year as December 31 of the year in which its investors invest in the partnership. Thus, depending primarily on when its subscription proceeds are received, each partnership may prepay in the year in which the partnership’s investors invest in the partnership most, if not all, of its intangible drilling costs for wells the drilling of which will not begin until the next year.

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Each partnership will have a calendar year taxable year.

The managing general partner anticipates that some of each partnership’s natural gas and oil production from its productive wells will be “marginal production,” as that term is defined under §613A(c)(6)(D) of the Code, and will qualify for the potentially higher rates of percentage depletion and potentially available marginal well production credits, depending primarily on the applicable reference prices for natural gas and oil, which may vary from year to year.

The principal purpose of each partnership is to locate, produce and market natural gas and oil on a profitable basis to its investors, apart from tax benefits, as discussed in this prospectus.

Each partnership’s total abandonment losses under §165 of the Code, which could include, for example, abandonment losses incurred by a partnership for wells drilled that are nonproductive (i.e. a “dry hole”), and abandonment losses incurred by a partnership for productive wells which have been operated until their commercial natural gas and oil reserves have been depleted, will be less than $2 million, in the aggregate, in any taxable year of each partnership and less than $4 million, in the aggregate, during each partnership’s first six taxable years.

Additional details, assumptions of special counsel, representations of the managing general partner, and other matters affecting special counsel’s opinions are contained in special counsel’s tax opinion letter. You are urged to read the entire tax opinion letter, which is attached as Exhibit 8.1 to the Registration Statement of which this prospectus is a part, to assist your understanding of the federal tax benefits and risks of an investment in the partnership.

Special Counsel’s Opinions

Taxpayers bear the burden of proof to support claimed deductions and tax credits, and special counsel’s tax opinions are not binding on the IRS or the courts. Special counsel’s tax opinions with respect to an investment in a partnership offered in this program, including the partnership, by a typical investor, who is sometimes referred to in special counsel’s opinions as a “Participant,” “Investor General Partner” or “Limited Partner,” are set forth below.

(1)

Partnership Classification. Each Partnership will be classified as a partnership for federal income tax purposes, and not as a corporation.

(2)

Limitations on Passive Activity Losses and Credits. The passive activity limitations on losses and credits under §469 of the Code:

will apply to the initial Limited Partners in a Partnership; and

will not apply to the Investor General Partners in a Partnership until after their Investor General Partner Units are converted to Limited Partner Units.

(3)

Not a Publicly Traded Partnership. The Partnerships will not be treated as publicly traded partnerships under the Code.

(4)

Business Expenses. Business expenses, including payments for personal services actually rendered in the taxable year in which accrued by a Partnership, which are reasonable, ordinary and necessary and do not include amounts for items such as Lease acquisition costs, Tangible Costs, Organization and Offering Costs and other items that are required to be capitalized under the Code, are currently deductible.

Potential Limitations on Deductions. A Participant’s ability in any taxable year to use his share of these deductions of a Partnership on his individual federal income tax returns may be reduced, eliminated or deferred by the following limitations:

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the Participant’s personal tax situation, such as the amount of his regular taxable income, alternative minimum taxable income, losses, itemized deductions, personal exemptions, etc., which are not related to his investment in a Partnership;

the amount of the Participant’s adjusted basis in his Units at the end of the Partnership’s taxable year;

the amount of the Participant’s “at risk” amount in the Partnership in which he invests at the end of the Partnership’s taxable year; and

the passive activity limitations on losses, and credits, if any, of a Partnership in the case of Limited Partners (including Investor General Partners after their Units are converted to Limited Partner Units) who are natural persons or are entities that also are subject to the passive activity limitations on losses and credits under §469 of the Code.

(5)

Intangible Drilling Costs. Although each Partnership will elect to deduct currently all of its Intangible Drilling Costs, each Participant in a Partnership may still elect to capitalize and deduct all or part of his share of his Partnership’s Intangible Drilling Costs (which do not include drilling and completion costs of a re-entry well that are not related to deepening the well, if any) ratably over a 60-month period. Subject to the foregoing, Intangible Drilling Costs paid by a Partnership under the terms of bona fide drilling contracts for the Partnership’s wells will be deductible by Participants in that Partnership who elect on their individual federal income tax returns to currently deduct their share of their Partnership’s Intangible Drilling Costs in the taxable year in which the payments are made and the drilling services are rendered.

A Participant’s ability in any taxable year to use his share of these Partnership deductions on his personal federal income tax returns may be reduced, eliminated or deferred by the “Potential Limitations on Deductions” set forth in opinion (4) above.

(6)

Prepaid Intangible Drilling Costs. Subject to each Participant’s election to capitalize and amortize a portion or all of his share of his Partnership’s Intangible Drilling Costs as set forth in opinion (5) above, any prepayments of Intangible Drilling Costs by a Partnership in the year in which the Participant invests in the Partnership for wells the drilling of which begins within the first 90 days of the next year, will be deductible by the Participant in the year he invests.

(7)

Depletion Allowance. The greater of the cost depletion allowance or the percentage depletion allowance will be available to qualified Participants as a current deduction against their share of their Partnership’s gross income from the sale of natural gas and oil production in each taxable year, subject to the following limitations:

a Participant’s cost depletion allowance cannot exceed his adjusted tax basis in the natural gas or oil property to which it relates; and

a Participant’s percentage depletion allowance:

may not exceed 100% of his taxable income from each natural gas and oil property before his deduction for percentage depletion, although this limitation was previously suspended for 2009 with respect to marginal properties, it may not be suspended again for 2010 and subsequent years depending on future legislation by Congress; and

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is limited to 65% of his taxable income for the year computed without regard to percentage depletion, net operating loss carry-backs and capital loss carry-backs and, in the case of a Participant that is a trust, any distributions to its beneficiaries.

(8)

MACRS. Each Partnership’s reasonable Tangible Costs for equipment placed in its productive wells that cannot be deducted immediately will be eligible for cost recovery deductions under the Modified Accelerated Cost Recovery System (“MACRS”) over a seven year “cost recovery period” on a well-by-well basis, beginning in the taxable year each well is drilled, completed and made capable of production, i.e. placed in service.

(9)

Tax Basis of Units. Each Participant’s initial adjusted tax basis in his Units will be the amount of money that he paid for his Units.

(10)

At Risk Limitation on Losses. Each Participant’s initial “at risk” amount in the Partnership in which he invests will be the amount of money that he paid for his Units.

(11)

Allocations. The allocations in the Partnership Agreement of income, gain, loss, deduction, credit, and distributions, or items thereof, for each Partnership including the allocations of basis and amount realized with respect to a Partnership’s natural gas and oil properties, will govern each Participant’s allocable share of those items to the extent the allocations do not cause or increase a deficit balance in his Capital Account in the Partnership in which he invests.

(12)

Subscription. No gain or loss will be recognized by the Participants on payment of their subscriptions to the Partnership in which they invest.

(13)

Profit Motive, IRS Anti-Abuse Rule and Potentially Relevant Judicial Doctrines. The Partnership will possess the requisite profit motive under §183 of the Code. Also, the IRS anti-abuse rule in Treas. Reg. §1.701-2 and potentially relevant judicial doctrines will not have a material adverse effect on the tax consequences of an investment in a Partnership by a Participant as described in our opinions.

(14)

Reportable Transactions. The Partnerships are not, and should not be in the future, reportable transactions under §6707A(c) of the Code.

(15)

Overall Conclusion. Our overall conclusion is that the federal tax treatment of a typical Participant’s investment in a Partnership as set forth in our opinions above is the proper federal tax treatment and will be upheld on the merits if challenged by the IRS and litigated. Our evaluation of the federal income tax laws and the expected activities of the Partnerships as represented to us by the Managing General Partner in this tax opinion letter and as described in the Prospectus causes us to believe that the deduction by a typical Participant of all, or substantially all, of his allocable share of his Partnership’s Intangible Drilling Costs in the year he invests (even if the drilling of most or all of his Partnership’s wells begins within the first 90 days of the next year), is the principal tax benefit offered by each Partnership to its respective Participants and also is the proper federal tax treatment, subject to each Participant’s option to elect to capitalize and amortize a portion or all of his share of his Partnership’s deduction for Intangible Drilling Costs.

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The discussion in the Prospectus under the caption “FEDERAL INCOME TAX CONSEQUENCES,” insofar as it contains statements of federal income tax law, is correct in all material respects.

Discussion of Federal Income Tax Consequences

Introduction

Special counsel’s tax opinions are limited to those set forth above. Subject to the foregoing, the following is a discussion of all material federal income tax issues or consequences, and any significant federal tax issues, related to the purchase, ownership and disposition of the partnership’s units that will apply to typical investors in the partnership. Except as otherwise noted below, however, different tax consequences from those discussed below may apply to foreign persons, corporations, IRAs and other tax-exempt entities, partnerships, trusts and other prospective investors that are not treated as typical investors for federal income tax purposes. Also, the proper treatment of the partnership’s tax attributes by a typical investor on his individual federal income tax returns may vary from that of another typical investor. This is because the practical utility of the tax aspects of any investment depends largely on each investor’s particular income tax position in the year in which items of income, gain, loss, deduction, or credit, if any, are properly taken into account in computing his federal income tax liability. In addition, the IRS may challenge the deductions, and credits, if any, claimed by the partnership or you and the other investors in the partnership, or the taxable year in which the deductions, and credits, if any, are claimed, and it is possible that the challenge would be upheld if litigated. Accordingly, you are urged to seek advice based on your particular circumstances from an independent tax advisor in evaluating the potential tax consequences to you of an investment in the partnership.

Partnership Classification

For federal income tax purposes the partnership is not a taxable entity. Thus, the partners, rather than the partnership, receive and report any deductions and tax credits, if any, as well as the income, from the partnership’s operations. The partnership has been formed as a limited partnership under the Delaware Revised Uniform Limited Partnership Act, which describes the partnership as a “partnership.” Thus, the partnership automatically will be classified as a partnership for federal tax purposes since the managing general partner has represented that the partnership will not elect to be taxed as a corporation. Treas. Reg. §301.7701-2.

Limitations on Passive Activity Losses and Credits

Under the passive activity rules of §469 of the Code, all income of a taxpayer who is subject to the rules is categorized as:

income from passive activities, such as limited partners’ interests in a business;

active income, such as salary, bonuses, etc.; or

portfolio income, such as gain, interest, dividends and royalties unless earned in the ordinary course of a trade or business, and gain not derived in the ordinary course of a trade or business on the sale of property that generates portfolio income or is held for investment.

Losses generated by passive activities can offset only passive income and cannot be applied against active income or portfolio income. Similar rules apply with respect to tax credits. (See “– Marginal Well Production Credits,” below.)

The passive activity rules apply to:

individuals, estates, and trusts;

closely held C corporations, which under §§469(j)(1), 465(a)(1)(B) and 542(a)(2) of the Code are regular corporations with five or fewer individuals who own directly or indirectly more than 50% in value of the outstanding stock at any time during the last half of the taxable year (for this purpose, U.S. trusts forming part of a stock bonus, pension or profit-sharing plan of an employer for the exclusive benefit of its employees or their beneficiaries that constitutes a “qualified trust” under §401(a) of the Code, trusts forming part of a plan providing for the payment of supplemental employee unemployment compensation benefits that meet the requirements of §501(c)(17) of the Code, domestic or foreign “private foundations” described in §501(c)(3) of the Code, and a portion of a trust permanently set aside or to be used exclusively for the charitable purposes described in §642(c) of the Code or a corresponding provision of a prior income tax law, are considered to be individuals); and

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personal service corporations, which under §§469(j)(2), 269A(b) and 318(a)(2)(C) of the Code are corporations the principal activity of which is the performance of personal services and those services are substantially performed by employee-owners. For this purpose, the term “employee-owners” includes any employee who owns, on any day during the taxable year, any of the outstanding stock of the personal service corporation, and an employee is considered to own:

the employee’s proportionate share of any stock of the personal service corporation owned, directly or indirectly, by or for a partnership or estate in which the employee is a partner or beneficiary;

the employee’s proportionate share of any stock of the personal service corporation owned, directly or indirectly, by or for a trust (other than an employee’s trust that is a qualified pension, profit-sharing, or stock bonus plan and is exempt from tax) if the employee is a beneficiary;

all of the stock of the personal service corporation owned, directly or indirectly, by or for any portion of a trust that the employee is considered to own under the Code; and

if any stock in a corporation is owned, directly or indirectly, for or by the employee, the employee’s proportionate share of the stock of the personal service corporation owned, directly or indirectly, by or for that corporation.

However, a corporation will not be treated as a personal service corporation for purposes of §469 of the Code unless more than 10% of the stock (by value) in the corporation is held by employee-owners (as described above). I.R.C. §469(j)(2)(B).

Also, if a closely held C corporation, other than a personal service corporation in which employee-owners own more than 10% (by value) of the stock, has net active income (i.e., taxable income determined without regard to any income or loss from a passive activity and without regard to any item of portfolio income, expense (including interest expense), or gain or loss) for a taxable year, its passive loss for that taxable year can be applied against its net active income for that taxable year. Similar rules apply to its passive credits, if any. I.R.C. §469(e)(2).

Passive activities include any trade or business in which the taxpayer does not materially participate on a regular, continuous, and substantial basis. Under the partnership agreement, limited partners will not have material participation in the partnership. Thus, if you are subject to the passive activity rules as described above and you invest in the partnership as a limited partner, your investment in the partnership will be subject to the passive activity limitations on losses and credits. (See “Risk Factors – Federal Income Tax Risks – Limited Partners Need Passive Income to Use Their Deduction for Intangible Drilling Costs.”)

Investor general partners also will not materially participate in the partnership. However, under what we refer to as the “passive activity exception for working interests,” because the partnership will own only “working interests,” as defined by the Code, in its wells, and investor general partners will not have limited liability for partnership liabilities and obligations under the Delaware Revised Uniform Limited Partnership Act until they are converted to limited partners, their deductions and any credits from their partnership will not be treated as passive deductions or credits under the Code before the conversion unless they invest in the partnership through an entity which limits their liability. (See “Risk Factors – Federal Income Tax Risks – Changes in the Law May Reduce Your Tax Benefits From an Investment in the Partnership.”) For example, if an individual invests in the partnership indirectly as an investor general partner by using an entity that limits his personal liability under state law to purchase his units, such as a limited partnership in which he is not a general partner, a limited liability company or an S corporation, then he will not be eligible for the passive activity exception for working interests. Instead, he will be subject to the passive activity limitations on deductions and credits the same as if he had invested in the partnership as a limited partner. (See “– Conversion from Investor General Partner to Limited Partner” and “– Marginal Well Production Credits,” below.)

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As compared with limitations on liability under state law as discussed above, contractual limitations on the liability of investor general partners under the partnership agreement, such as insurance, limited indemnification by the managing general partner, etc. will not cause investor general partners to be subject to the passive activity limitations on losses and credits. Investor general partners, however, may be subject to an additional limitation on their deduction of investment interest expense as a result of their non-passive deduction of intangible drilling costs. (See “– Limitations on Deduction of Investment Interest,” below.)

A limited partner’s “at risk” amount is reduced by losses allowed under §465 of the Code even if the losses are suspended by the passive activity limitations. (See “– ‘At Risk’ Limitation on Losses,” below.) Similarly, a limited partner’s basis is reduced by deductions even if the deductions are suspended under the passive activity limitations. (See “– Tax Basis of Units,” below.)

Suspended passive losses and passive credits that cannot be used by a taxpayer in his current tax year may be carried forward indefinitely, but not back, and can be used to offset passive income in future years or, in the case of passive credits, can be used to offset regular federal income tax liability attributable to passive income in future years. I.R.C. §469(b). A suspended passive loss, but not a suspended passive credit, is allowed in full when a taxpayer’s entire interest in a passive activity is sold to an unrelated third-party in a fully taxable transaction, and in part on the taxable disposition of substantially all of a taxpayer’s interest in a passive activity if the suspended passive loss as well as current gross income and deductions of the passive activity can be allocated to the part disposed of with reasonable certainty. I.R.C. §469(g)(1). In an installment sale of a taxpayer’s entire interest in a passive activity, passive losses become available in the same ratio that gain recognized each year bears to the total gain on the sale. I.R.C. §469(g)(3). (See “Transferability of Units – Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership Agreement.”)

Any suspended passive losses remaining at a taxpayer’s death are allowed as deductions on the decedent’s final return, subject to a reduction to the extent the amount of the suspended passive losses is greater than the excess of the basis of the property in the hands of the transferee over the property’s adjusted basis immediately before the decedent’s death. I.R.C. §469(g)(2). If a taxpayer makes a gift of his entire interest in a passive activity, the basis in the property of the person receiving the gift is increased by any suspended passive losses and no deductions are allowed. If the interest is later sold at a loss, the basis in the property of the person receiving the gift is limited to the fair market value of the property on the date the gift was made. I.R.C. §469(j)(6).

Publicly Traded Partnership Rules

Net losses and most net credits of a partner from a publicly traded partnership are suspended and carried forward to be netted against income or regular federal income tax liability, respectively, from that publicly traded partnership only. In addition, net losses from other passive activities may not be used to offset net passive income from a publicly traded partnership. I.R.C. §§469(k)(2) and 7704. A publicly traded partnership is a partnership in which interests in the partnership are traded on an established securities market or are readily tradable on either a secondary market or the substantial equivalent of a secondary market. However, in special counsel’s opinion the partnership will not be treated as a publicly traded partnership under the Code. This opinion is based primarily on the substantial restrictions in the partnership agreement on the ability of you and the other investors to transfer your units in your partnership. (See “Transferability of Units – Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership Agreement.”) Also, the managing general partner has represented that the partnership’s units will be not traded on an established securities market.

Conversion from Investor General Partner to Limited Partner

If you invest in the partnership as an investor general partner, then under current law your share of the partnership’s deduction for intangible drilling costs in the year you invest will not be subject to the passive activity limitations on losses and credits. This is because the investor general partner units in the partnership will not be converted to limited partner units under §6.01(b)(1) of the partnership agreement until after all of the wells in the partnership have been drilled and completed. (See “Actions to be Taken by Managing General Partner to Reduce Risks of Additional Payments by Investor General Partners,” and “– Drilling Contracts,” below.) After the investor general partner units have been converted to limited partner units, each former investor general partner will have limited liability with respect to his partnership’s activities after the conversion as a limited partner under the Delaware Revised Uniform Limited Partnership Act.

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Concurrently, the former investor general partner will become subject to the passive activity limitations on losses and credits as a limited partner. However, the former investor general partner previously will have received a non-passive loss as an investor general partner in the year he invested in his partnership as a result of his share of his partnership’s deduction for intangible drilling costs. Therefore, the Code requires that his net income from the partnership’s wells after his conversion to a limited partner must continue to be characterized as non-passive income that cannot be offset with passive losses. For a discussion of the effect of this rule on an investor general partner’s tax credits, if any, from his partnership, see “– Marginal Well Production Credits,” below. The conversion of the investor general partner units into limited partner units should not have any other adverse tax consequences on an investor general partner unless his share of his partnership liabilities, if any, is reduced as a result of the conversion. (See “– Tax Basis of Units,” below.)

Taxable Year and Method of Accounting

The partnership will adopt a calendar year taxable year and will use the accrual method of accounting for federal income tax purposes.

Taxable Year. The partnership will have a calendar year taxable year. I.R.C. §§706(a) and (b). The taxable year of the partnership is important to you because your share of the partnership’s deductions, tax credits, if any, income and other items of tax significance must be taken into account on your personal federal income tax return for your taxable year within or with which the partnership’s taxable year ends.

Method of Accounting. The partnership will use the accrual method of accounting for federal income tax purposes. I.R.C. §448(a). Under the accrual method of accounting, income is taken into account for the year in which all events have occurred that fix the right to receive it and the amount is determinable with reasonable accuracy, rather than the time of receipt. Consequently, you and the other investors in the partnership may have income tax liability resulting from the partnership’s accrual of income in one tax year even though it does not receive the income in cash until the next tax year. Expenses are deducted for the year in which all events have occurred that determine the fact of the liability, the amount is determinable with reasonable accuracy and the economic performance test is satisfied. Under §461(h) of the Code, if the liability of the taxpayer arises out of the providing of services or property to the taxpayer by another person, economic performance occurs as the services or property, respectively, are provided. If the liability of the taxpayer arises out of the use of the property by the taxpayer, economic performance occurs as the property is used.

A special rule in the Code, however, provides that there is economic performance in the current taxable year with respect to amounts paid in that taxable year for intangible drilling costs of drilling and completing a natural gas or oil well so long as the drilling of the well begins before the close of the 90th day after the close of the taxable year in which the payments were made. I.R.C. §461(i). See “– Drilling Contracts,” below, for a discussion of the federal income tax treatment of any prepaid intangible drilling costs by the partnership and “Risk Factors – Federal Income Tax Risks – Changes in the Law May Reduce Your Tax Benefits from an Investment in the Partnership.”

Business Expenses

Ordinary and necessary business expenses, including reasonable compensation for personal services actually rendered, are deductible in the year incurred. In this regard, the managing general partner has represented that the amounts payable by the partnership to it and its affiliates under the drilling and operating agreement to drill, frac and complete the partnership’s wells are reasonable and competitive amounts that ordinarily would be paid for similar services in similar transactions between persons having no affiliation and dealing with each other at “arms length” in the proposed areas of the partnership’s operations. (See Treas. Reg. §1.162-7(b)(3), “Compensation” and “– Drilling Contracts,” below.) The fees paid to the managing general partner and its affiliates by the partnership will not be currently deductible, however, to the extent it is determined by the IRS or the courts that they are:

in excess of reasonable compensation;

properly characterized as organization or syndication fees or other capital costs, such as lease acquisition costs or equipment costs (i.e., “Tangible Costs”); or

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not “ordinary and necessary” business expenses.

In the event of an IRS audit of the partnership, payments to the managing general partner and its affiliates by the partnership would be scrutinized by the IRS to a greater extent than payments to an unrelated party.

Your ability in any taxable year to use your share of these partnership deductions on your personal federal income tax returns may be reduced, eliminated or deferred by the “Potential Limitations on Deductions” set forth in special counsel’s opinion (4) in “– Special Counsel’s Opinions,” above.

Although the partnership will engage in the production of natural gas and oil from wells drilled in the United States, the partnership will not qualify for the “U.S. production activities deduction.” This is because the deduction cannot exceed 50% of the IRS Form W-2 wages paid by a taxpayer for a tax year, and the partnership will not pay any Form W-2 wages since it will not have any employees. Instead, the partnership will rely on the managing general partner and its affiliates to manage it and its business. In addition, President Obama’s administration has proposed repealing this deduction for oil and gas companies. (See “Risk Factors – Federal Income Tax Risks – Changes in the Law May Reduce Your Tax Benefits From an Investment in the Partnership” and “Management.”)

Intangible Drilling Costs

You may elect to deduct your share of your partnership’s intangible drilling costs, which include items that do not have salvage value, such as labor, fuel, repairs, supplies and hauling necessary to the drilling of a well and preparing it for the production of natural gas or oil, in the taxable year in which your partnership’s wells are drilled and completed. I.R.C. §263(c), Treas. Reg. §1.612-4(a). In this regard, President Obama’s administration has proposed the repeal of a taxpayer’s election to expense its intangible drilling costs beginning on January 1, 2011, which would not affect your ability to elect to deduct or amortize your share of the partnership’s intangible drilling costs in the year you invest in the partnership. (See “Risk Factors – Federal Income Tax Risks – Changes in the Law May Reduce Your Tax Benefits From an Investment in the Partnership.”) For a discussion of the deduction in the year you invest in the partnership of intangible drilling costs that are prepaid by your partnership in the year you invest in the partnership for wells the drilling of which will not begin until the next year, if any, see “– Drilling Contracts,” below.

Your share of your partnership’s gain (if your partnership sells a well at a gain), or your gain (if you sell your units in your partnership at a gain), will be treated as ordinary income, rather than capital gain, to the extent of the previous deductions for intangible drilling costs you have claimed, but not for the deductions for operating expenses related to a re-entry well, if any. (See “– Sale of the Properties” and “– Disposition of Units,” below.) Also, productive-well intangible drilling costs may subject you to an alternative minimum tax in excess of regular tax unless you elect to deduct all or part of these costs ratably over a 60 month period. (See “Risk Factors – Federal Income Tax Risks – Changes in the Law May Reduce Your Tax Benefits From an Investment in the Partnership” and “– Alternative Minimum Tax,” below.)

Under the partnership agreement, 85% of the subscription proceeds received by the partnership from its investors will be used to pay 100% of the partnership’s intangible drilling costs of drilling and completing its wells. (See “Capitalization and Source of Funds and Use of Proceeds” and “Participation in Costs and Revenues.”) The IRS could challenge the characterization of a portion of these costs as currently deductible intangible drilling costs and recharacterize the costs as some other item that may not be currently deductible, such as lease acquisition expenses, equipment costs or syndication fees. However, this would have no effect on the allocation and payment of the intangible drilling costs by you and the other investors under the partnership agreement.

In the case of corporations, other than S corporations, which are “integrated oil companies,” the amount allowable as a deduction for intangible drilling costs in any taxable year is reduced by 30%. I.R.C. §291(b)(1). Integrated oil companies are:

those taxpayers who directly or through a related person engage in the retail sale of natural gas and oil and whose gross receipts for the taxable year from those activities exceed $5 million; or

those taxpayers and related persons who have average daily refinery runs in excess of 75,000 barrels for the taxable year. I.R.C. §291(b)(4).

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Amounts of an integrated oil company’s intangible drilling costs that are disallowed as a current deduction under §291 of the Code are allowable, however, as a deduction ratably over the 60-month period beginning with the month in which the costs are paid or incurred. The partnership will not be treated as an integrated oil company under the Code.

You are urged to seek advice based on your particular circumstances from an independent tax advisor concerning the tax benefits to you of your share of the deduction for intangible drilling costs of the partnership.

Drilling Contracts

The partnership will enter into the drilling and operating agreement with the managing general partner to drill and complete the partnership’s wells for the compensation described in “Compensation – Drilling Contracts.” The actual cost of drilling and completing the wells, however, including the managing general partner’s 18% mark-up, may be more or less than the dollar amounts estimated by the managing general partner in “Compensation – Drilling Contracts,” due primarily to the uncertain nature of drilling operations. The managing general partner believes that the compensation payable to it and its affiliates under the drilling and operating agreement is competitive in the proposed areas of operation. Nevertheless, the amount of fees and profit realized by the managing general partner under the drilling and operating agreement could be challenged by the IRS as being unreasonable and disallowed as a deductible intangible drilling cost.

Depending primarily on when its subscription proceeds are received, the managing general partner anticipates that the partnership may prepay in the year in which its investors invest in the partnership most, if not all, of its intangible drilling costs for wells the drilling of which will begin within the first 90 days of the next tax year. In Keller v. Commissioner, 79 T.C. 7 (1982), aff’d 725 F.2d 1173 (8th Cir. 1984), the Tax Court applied a two-part test for the current deductibility of prepaid intangible drilling and development costs. The test is:

the expenditure must be a payment rather than a refundable deposit; and

the deduction must not result in a material distortion of income taking into substantial consideration the business purpose aspects of the transaction.

The drilling partnership in Keller entered into footage and daywork drilling contracts that permitted it to terminate the contracts at any time, without a default by the driller, and receive a return of the prepaid amounts less amounts earned by the driller. The Tax Court found that the right to receive, by unilateral action, a refund of the prepayments on the footage and daywork drilling contracts rendered the prepayments deposits instead of payments. Therefore, the prepayments were held to be nondeductible in the year they were paid to the extent they had not been earned by the driller. The Tax Court further found that the drilling partnership failed to show a convincing business purpose for the prepayments under the footage and daywork drilling contracts.

The drilling partnership in Keller also entered into turnkey drilling contracts that permitted it to stop work under the contract at any time and apply the unearned balance of the prepaid amounts to another well to be drilled on a turnkey basis. The Tax Court found that these prepayments constituted “payments” and not nondeductible deposits, despite the right of substitution. Further, the Tax Court noted that the turnkey drilling contracts obligated “the driller to drill to the contract depth for a stated price regardless of the time, materials or expenses required to drill the well,” thereby locking in prices and shifting the risks of drilling from the drilling partnership to the driller. Since the drilling partnership, a cash basis taxpayer, received the benefit of the turnkey obligation in the year of prepayment, the Tax Court found that the amounts prepaid on turnkey drilling contracts clearly reflected income and were deductible in the year of prepayment.

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In Leonard T. Ruth, TC Memo 1983-586, a drilling program entered into nine separate turnkey contracts with a general contractor, the parent corporation of the drilling program’s corporate general partner, to drill nine program wells. Each contract identified the prospect to be drilled, stated the turnkey price, and required the full price to be paid in 1974. The program paid the full turnkey price to the general contractor on December 31, 1974; the receipt of which was found by the court to be significant in the general contractor’s financial planning. The program had no right to receive a refund of any of the payments. The actual drilling of the nine wells was subcontracted by the general contractor to independent contractors who were paid by the general contractor in accordance with their individual contracts. The drilling of all of the wells began in 1975 and all of the wells were completed in 1975. The amount paid by the general contractor to the independent driller for its work on the nine wells was approximately $365,000 less than the amount prepaid by the program to the general contractor. The program claimed a deduction for intangible drilling and development costs in 1974. The IRS challenged the timing of the deduction, contending that there was no business purpose for the payments in 1974, that the turnkey arrangements were merely “contracts of convenience” designed to create a tax deduction in 1974, and that the turnkey contracts constituted assets having a life beyond the taxable year and that to allow a deduction for their entire costs in 1974 distorted income. The Tax Court, relying on Keller, held that the program could deduct the full amount of the payments in 1974. The court found that the program entered into turnkey contracts, paid a premium to secure the turnkey obligations, and thereby locked in the drilling price and shifted the risks of drilling to the general contractor. Further, the court found that by signing and paying the turnkey obligation, the program got its bargained-for benefit in 1974, therefore the deduction of the payments in 1974 clearly reflected income.

The partnership will attempt to comply with the guidelines set forth in Keller with respect to any prepaid intangible drilling costs. In this regard, the drilling and operating agreement will require the partnership to prepay in the year in which the partnership’s investors invest in the partnership all of the partnership’s share of the estimated intangible drilling costs, and all of the investors’ share of the partnership’s share of the estimated equipment costs, for drilling and completing specified wells for the partnership, the drilling of which may begin in the next year. These prepayments of intangible drilling costs should not result in a loss of a current deduction for the intangible drilling costs in the year in which the partnership’s investors invest in the partnership if:

the guidelines set forth in Keller are complied with;

there is a legitimate business purpose for the required prepayment;

the drilling of the prepaid wells begins on or before the first 90 days of the next year;

the contract is not merely a sham to control the timing of the deduction; and

there is an enforceable contract of economic substance.

In this regard, the drilling and operating agreement will require the partnership to prepay the managing general partner’s estimate of the intangible drilling costs and the investor’s share of the equipment costs to drill and complete the wells specified in the drilling and operating agreement in order to enable the operator to:

begin site preparation for the wells;

obtain suitable subcontractors at the then current prices; and

insure the availability of equipment and materials.

Under the drilling and operating agreement excess prepaid intangible drilling costs, if any, will not be refundable to the partnership, but instead will be applied only to intangible drilling cost overruns, if any, on the other specified wells being drilled or completed by the partnership or to intangible drilling costs to be incurred by the partnership in drilling and completing substitute wells. Under Keller, a provision for substitute wells should not result in the prepayments being characterized as refundable deposits.

The likelihood that prepayments of intangible drilling costs will be challenged by the IRS on the grounds that there is no business purpose for the prepayments is increased if prepayments are not required with respect to 100% of the working interest in the well. In this regard, the managing general partner anticipates that less than 100% of the working interest will be acquired by the partnership in one or more of its wells, and prepayments of intangible drilling costs will not be required of the other owners of working interests in those wells. In the view of special counsel, however, a legitimate business purpose for the required prepayments of intangible drilling costs by the partnership may exist under the guidelines set forth in Keller, even though prepayments are not required by the drilling contractor with respect to a portion of the working interest in the wells.

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In addition, a current deduction for prepaid intangible drilling costs is available only if the drilling of the wells begins before the close of the 90th day after the close of the taxable year in which the prepayment was made. See the discussion of §461(i) of the Code in “– Method of Accounting,” above. Therefore, under the drilling and operating agreement, the managing general partner, serving as operator and general drilling contractor, must begin drilling the wells that are prepaid by the partnership, if any, in the year in which its respective investors invest in the partnership no later than the close of the 90th day in the next year. However, the drilling of any partnership well may be delayed due to circumstances beyond the control of the managing general partner and the drilling subcontractors. These circumstances include, for example:

the unavailability of drilling rigs;

decisions of third-party operators to delay drilling the wells;

poor weather conditions;

inability to obtain drilling permits or access right to the drilling site; or

title problems;

and the managing general partner will have no liability under the partnership agreement or the drilling and operating agreement to the partnership or its investors if these types of events (i.e., “force majeure”) delay beginning the drilling of any partnership prepaid well beyond the 90 day limit imposed by §461(i) of the Code.

If the drilling of a prepaid partnership well does not begin within the 90 day time constraint imposed by §461(i) of the Code, deductions claimed by you and the other investors in the partnership for prepaid intangible drilling costs for the well in the year you invest in the partnership, would not be lost, but those deductions would be deferred to the next year when the well is actually drilled. Thus, each well prepaid in 2009 by the partnership must be spudded by March 31, 2010 or the deduction for that well’s intangible drilling costs will not be available for the 2009 tax year, but instead, must be claimed for the 2010 tax year in which the well was actually drilled. (See “Risk Factors – Federal Income Tax Risks – Changes in the Law May Reduce Your Tax Benefits from an Investment in the Partnership” and “– Intangible Drilling Costs,” above.)

Depletion Allowance

Proceeds from the sale of the partnership’s natural gas and oil production will constitute ordinary income. A portion of that income will not be taxable under the depletion allowance, which permits the deduction from gross income for federal income tax purposes of either the percentage depletion allowance or the cost depletion allowance, whichever is greater. I.R.C. §§611, 613 and 613A. President Obama’s administration, however, has proposed repealing the percentage depletion allowance beginning January 1, 2011, which if enacted into law, would substantially reduce your future tax benefits from your investment in the partnership, but would not affect your ability to claim your share of the partnership’s deduction for intangible drilling costs in the year you invest in the partnership. (See “Risk Factors – Federal Income Tax Risks – Changes in the Law May Reduce Your Tax Benefits From an Investment in the Partnership.”)

Your share of your partnership’s gain (if your partnership sells a well at a gain), or your gain (if you sell your units at a gain), will be treated as ordinary income rather than capital gain to the extent of your previous deductions for depletion that reduced your adjusted basis in the property or your units. (See “– Sale of the Properties” and “– Disposition of Units,” below.)

Cost depletion for any year is determined by dividing the adjusted tax basis for the property by the total units of natural gas or oil expected to be recoverable from the property and then multiplying the resultant quotient by the number of units actually sold during the year. Cost depletion cannot exceed the adjusted tax basis of the property to which it relates.

Percentage depletion is available to taxpayers other than “integrated oil companies,” as that term is defined in “– Intangible Drilling Costs,” above, which does not include the partnership. Your percentage depletion allowance is based on your share of your partnership’s gross production income (excluding rents or royalties paid) from its natural gas and oil properties. Under §613A(c) of the Code, percentage depletion is available with respect to 6 million cubic feet of average daily production of domestic natural gas or 1,000 barrels of average daily production of domestic crude oil. However, taxpayers who have both natural gas and oil production may allocate the production limitation between the production.

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The rate of percentage depletion is 15%. However, the managing general partner anticipates that some of the natural gas and oil production from the partnership’s productive wells will be classified as marginal wells for federal tax purposes. In this regard, percentage depletion for marginal production increases 1%, up to a maximum increase of 10%, for each whole dollar that the domestic wellhead price of crude oil for the immediately preceding year is less than $20 per barrel without adjustment for inflation. I.R.C. §613A(c)(6). The term “marginal production” includes natural gas and oil produced from a domestic stripper well property, which is defined in §613A(c)(6)(E) of the Code as any property that produces a daily average of 15 or less equivalent barrels of oil, which is equivalent to 90 mcf of natural gas, per producing well on the property in the calendar year. In this regard, some wells that do not qualify as marginal wells initially, may become marginal wells subsequently as their natural gas and oil production declines as the wells age. The managing general partner has represented that some of the natural gas and oil production from the partnership’s productive wells will be classified as marginal production under this definition in the Code, discussed above, and will qualify for these potentially higher rates of percentage depletion. The percentage depletion rate for marginal production is 15% in 2009. This rate may fluctuate from year to year for natural gas and oil production from marginal wells, depending on the price of oil, but will not be less than the statutory rate of 15% nor more than 25%.

Also, percentage depletion:

may not exceed 100% of the taxable income from each natural gas and oil property before the deduction for depletion, although this limitation was suspended with respect to natural gas and oil production in 2009 from marginal properties, which the managing general partner has represented will include some of the partnership’s productive wells, absent future legislation by Congress this limitation will not be suspended in 2010 and subsequent years; and

is limited to 65% of the taxpayer’s taxable income for the year computed without regard to percentage depletion, net operating loss carry-backs and capital loss carry-backs and, in the case of an investor that is a trust, any distributions to its beneficiaries. Any disallowed percentage depletion deductions under this limitation may be carried forward to the next taxable year.

The availability in any taxable year of the percentage depletion allowance must be computed separately by you and not by your partnership or for investors in your partnership as a whole. You are urged to seek advice based on your particular circumstances from an independent tax advisor with respect to the availability of the percentage depletion allowance to you.

Depreciation and Cost Recovery Deductions

Fifteen percent of the partnership’s subscription proceeds from you and the other investors in your partnership will be used to pay equipment costs (i.e.; “Tangible Costs”), and the managing general partner will pay all of the equipment costs of drilling and completing the partnership’s wells that exceed 15% of the partnership’s subscription proceeds. The related depreciation deductions, i.e.; cost recovery deductions under the modified accelerated cost recovery system (“MACRS”), will be allocated under the partnership agreement between the managing general partner, on the one hand, and you and the other investors in your partnership, on the other hand, in proportion to the actual amount of the partnership’s equipment costs paid by each.

The partnership’s reasonable Tangible Costs for equipment placed in its wells that cannot be deducted immediately will be recovered through depreciation deductions over a seven year cost recovery period, using the 200% declining balance method with a switch to straight-line to maximize the deduction, beginning in the taxable year in which each well is drilled, completed and made capable of production, (i.e., “placed in service”) by the partnership. I.R.C. §168(c). In this regard, the managing general partner anticipates that it may take up to 12 months after the partnership’s final closing before all of the partnership’s wells are drilled, completed and placed in service for the production of natural gas or oil. In the case of a short partnership tax year, the MACRS deduction will be prorated on a 12-month basis. No distinction is made between new and used property and salvage value is disregarded. Under §168(d)(1) of the Code, all property assigned to the 7-year class is treated as placed in service, or disposed of, in the middle of the year, unless more than 40% of the total cost of all equipment in the partnership’s wells placed in service during the year is placed in service during the last three months of the year. If that happens, then under §168(d)(3) of the Code the depreciation for the full year will be multiplied by a fraction based on the quarter the equipment is placed in service: 87.5% for the first quarter, 62.5% for the second, 37.5% for the third, and 12.5% for the fourth. All of these cost recovery deductions claimed by the partnership and you and the other investors in the partnership are subject to recapture as ordinary income rather than capital gain on the sale or other taxable disposition of the property by the partnership or your units by you. (See “– Sale of the Properties” and “– Disposition of Units,” below.) Depreciation for alternative minimum tax purposes, however, is computed using the 150% declining balance method switching to straight-line, for most personal property. This will result in adjustments in computing the alternative minimum taxable income of you and the other investors in your partnership in taxable years in which the partnership claims depreciation deductions. (See “– Alternative Minimum Tax,” below.)

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Marginal Well Production Credits

Subject to the passive activity rules, see “– Limitations on Passive Activity Losses and Credits,” above, under current law there is a marginal well production credit of 50¢ per mcf of qualified natural gas production and $3 per barrel of qualified oil production for purposes of the regular federal income tax, but not the alternative minimum tax. (See “– Alternative Minimum Tax,” below.) However, President Obama’s administration has proposed repealing this credit, which Congress may or may not do. (See “Risk Factors – Federal Income Tax Risks – Changes in the Law May Reduce Your Tax Benefits From an Investment in the Partnership.”) A tax credit, unlike a tax deduction, reduces tax liability on a dollar-for-dollar basis. Natural gas and oil production that qualifies as marginal production under the percentage depletion rules of §613A(c)(6) of the Code as discussed above in “– Depletion Allowance,” which the managing general partner anticipates will include some of the natural gas and oil production from the partnership’s productive wells, also will qualify as marginal production for purposes of this credit. Also, the credit will be reduced proportionately if the reference prices for the previous calendar year are between $1.67 and $2.00 per mcf for natural gas and $15 and $18 per barrel for oil, adjusted in both cases for inflation, which have been volatile for many years. Based on the prices for natural gas and oil in recent years compared with the prices at which the credit phases out completely, it may appear unlikely that the partnership’s natural gas and oil marginal production will ever qualify for this credit. However, prices for natural gas and oil are volatile and could decrease in the future. (See “Risk Factors – Risks Related To The Partnership’s Oil and Gas Operations – Partnership Distributions May be Reduced if There is a Decrease in the Price of Natural Gas and Oil.”) Thus, it is possible that the partnership’s marginal production of natural gas or oil in one or more taxable years after 2009 could qualify for the marginal well production credit, depending primarily on the applicable reference prices for natural gas and oil in the future. However, depending primarily on market prices for natural gas and oil, which are volatile, the partnership’s production of natural gas and oil may not qualify for marginal well production credits for many years, if ever.

Lease Acquisition Costs and Abandonment

Lease acquisition costs, together with the related cost depletion deduction, and any amortization deductions for geological and geophysical expenses incurred by the managing general partner after August 8, 2005, with respect to the partnership’s prospects and any abandonment loss for lease acquisition costs, are allocated under the partnership agreement 100% to the managing general partner, which will contribute the leases to the partnership as a part of its capital contribution.

Tax Basis of Units

Your share of your partnership’s losses is allowable only to the extent of the adjusted basis of your units at the end of your partnership’s taxable year. I.R.C. §704(d). The adjusted basis of your units will be adjusted, but not below zero, for any gain or loss to you from a sale or other taxable disposition by your partnership of a natural gas or oil property, and will be increased by your:

cash subscription payment;

share of partnership income; and

share, if any, of partnership debt.

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The adjusted basis of your units will be reduced by your:

share of partnership losses;

share of partnership expenditures that are not deductible in computing its taxable income and are not properly chargeable to capital account;

depletion deductions, but not below zero;

cash distributions from the partnership; and

any reduction in your share of your partnership’s debt, if any. I.R.C. §§705, 722 and 742.

The reduction in your share of partnership liabilities, if any, is considered a cash distribution to you. Although you will not be personally liable on any partnership loans, if you invest in the partnership as an investor general partner you will be liable for other obligations of the partnership. (See “Risk Factors – Risks Related to an Investment In the Partnership – If You Choose to Invest as a General Partner, Then You Have Greater Risk Than a Limited Partner.”) Should cash distributions to you from your partnership exceed the tax basis of your units immediately before the distributions, taxable gain would result to you to the extent of the excess. (See “– Distributions From the Partnership,” below.)

“At Risk” Limitation on Losses

You may use your share of your partnership’s losses to offset income from other sources to the extent that your use of those losses is not limited by the adjusted tax basis of your units or the passive activity limitations on losses and credits, but only to the extent of the amount you have “at risk” in the partnership under §465 of the Code at the end of a taxable year. (See “– Limitations on Passive Activity Losses and Credits” and “– Tax Basis of Units,” above.) “Loss,” for purposes of the “at risk” rules, means the excess of your share of the allocable deductions for a taxable year from the partnership over the amount of income actually received or accrued by you during the year from the partnership. This “at risk” limitation on your share of your partnership’s losses, however, does not apply to you if you are a corporation that is neither an S corporation nor a corporation in which at any time during the last half of the taxable year five or fewer individuals owned more than 50% (in value) of the outstanding stock under §542(a)(2) of the Code. See “– Limitations on Passive Activity Losses and Credits,” above, relating to the application of §469 of the Code to closely held C corporations for additional information on the stock ownership requirements under §542(a)(2) of the Code.

Your initial “at risk” amount in the partnership will be equal to the amount of money you paid for your units. However, any amounts borrowed by you to buy your units will not be considered “at risk” if the amounts are borrowed from another investor in your partnership or anyone related to another investor in your partnership. In this regard, the managing general partner has represented that it and its affiliates will not make or arrange financing for you or any other potential investors to use to purchase units in the partnership. Also, the amount you have “at risk” in your partnership will not include the amount of any loss that you are protected against through:

nonrecourse loans;

guarantees;

stop loss agreements; or

other similar arrangements.

The amount of any loss that exceeds your “at risk” amount in the partnership at the end of any taxable year must be carried forward by you to the next taxable year, and will then be available to the extent you are “at risk” in the partnership at the end of that taxable year. Further, your “at risk” amount in subsequent taxable years of the partnership will be reduced by any portion of a partnership loss that is allowable to you as a deduction.

Since income, gains, losses and distributions of the partnership will affect your “at risk” amount in the partnership, the extent to which you are “at risk” in the partnership must be determined annually. Previously allowed losses must be included in your gross income if your “at risk” amount is reduced below zero. The amount included in your income, however, may be deducted in the next taxable year to the extent of any increase in the amount that you have “at risk” in your partnership.

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Distributions From the Partnership

A cash distribution from your partnership to you in excess of the adjusted basis of your units immediately before the distribution is treated as gain to you from the sale or exchange of your units to the extent of the excess. I.R.C. §731(a)(1). Different rules apply, however, to payments by the partnership to a deceased investor’s successor in interest and to payments for an investor’s share of his partnership’s unrealized receivables and inventory items as those terms are defined in §751 of the Code. Under §731(a)(2) of the Code, no loss can be recognized by you on these types of distributions unless the distribution is made to liquidate your units in your partnership, and then only to the extent of the excess, if any, of your adjusted basis in your units over the sum of the amount of money distributed to you plus your share of the basis (as determined under §732 of the Code) of any unrealized receivables and inventory items of your partnership. See “– Disposition of Units,” below, for a discussion of the partnership’s unrealized receivables and inventory items under §751 of the Code.

No gain or loss will be recognized by the partnership on cash distributions to you and its other investors. I.R.C. §731(b). If property is distributed by the partnership to the managing general partner and you and the other investors in the partnership, basis adjustments to the partnership’s properties may be made by the partnership, and adjustments to the basis in their respective interests in the partnership may be made by the managing general partner and you and the other investors. I.R.C. §§732, 733, 734, and 754. (See §5.04(d) of the Partnership Agreement and “– Tax Elections,” below.) Other distributions of cash, disproportionate distributions of property, if any, and liquidating distributions of the partnership may result in taxable gain or loss to you and the other investors.

Sale of the Properties

The maximum tax rate on a noncorporate taxpayer’s adjusted net capital gain on the sale of most capital assets held more than a year is 15%, or 5% to the extent the gain would have been taxed at a 10% or 15% rate if it had been ordinary income, respectively, for most capital assets. In addition, the 5% tax rate on adjusted net capital gain was reduced to 0%. The former maximum tax rates of 18% and 8%, respectively, on qualified five-year gain have been eliminated. These capital gain rates also apply for purposes of the alternative minimum tax. (See “– Alternative Minimum Tax,” below.) However, the former tax rates on adjusted net capital gain of 20% and 10%, respectively, are scheduled to be reinstated on January 1, 2011, and may be reinstated or even increased by Congress before January 1, 2011.

Under §1(h)(3) of the Code, “adjusted net capital gain” means net capital gain determined without taking qualified dividend income into account:

reduced (but not below zero) by:

any amount of qualified dividend income taken into account as investment income under §163(d)(4)(B)(iii) of the Code;

net capital gain that is taxed a maximum rate of 28% (such as gain on the sale of most collectibles and gain on the sale of qualified small business stock qualified under §1202 of the Code); and

net capital gain that is taxed at a maximum rate of 25% (gain attributable to real estate depreciation); and

increased by the amount of qualified dividend income.

“Net capital gain” means the excess of net long-term gain (the excess of long-term gains over long-term losses) over net short-term loss (the excess of short-term gains over short-term losses). The annual capital loss limitation for noncorporate taxpayers is the amount of capital gains plus the lesser of $3,000, which is reduced to $1,500 for married persons filing separate returns, or the excess of capital losses over capital gains. I.R.C. §1211(b)

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Gains from the sale by the partnership of a natural gas and oil property held by it for more than 12 months will be treated as long-term capital gain, except to the extent of depreciation recapture on equipment and recapture of intangible drilling costs and depletion deductions as discussed below, while a net loss will be an ordinary deduction. In addition, gain on the sale of the partnership’s natural gas and oil properties may be recaptured as ordinary income to the extent of non-recaptured §1231 losses (as defined below) for the five most recent preceding taxable years on previous sales, if any, of the partnership’s natural gas and oil properties or other assets. I.R.C. §1231(c). If, for any taxable year, the §1231 gains exceed the §1231 losses, the gains and losses will be treated as long-term capital gains or long-term capital losses, as the case may be. If the §1231 gains do not exceed the §1231 losses, the gains and losses will not be treated as gains and losses from sales or exchanges of capital assets. For this purpose, the term “§1231 gain” means any recognized gain:

on the sale or exchange of a property used in a trade or business; and

from the involuntary conversion into other property or money of:

property used in a trade or business; or

any capital assets that are held for more than one year and are held in connection with a trade or business or a transaction entered into for profit.

The term “§1231 loss” means any recognized loss from a sale or exchange or conversion described above.

The term “property used in a trade or business” means depreciable property and real property that are used in a trade or business and are held for more than one year, which are not inventory and are not held primarily for sale to customers in the ordinary course of a trade or business.

Net §1231 gain will be treated as ordinary income to the extent the gain does not exceed the non-recaptured net §1231 losses. The term “non-recaptured net §1231 losses” means the excess of:

the aggregate amount of the net §1231 losses for the five most recent taxable years; over

the portion of those losses taken into account to determine whether the net §1231 gain for any taxable year should be treated as ordinary income to the extent the gain does not exceed the non-recaptured net §1231 losses, as discussed above, for those preceding taxable years.

Other gains and losses on sales of natural gas and oil properties held by the partnership for less than 12 months, if any, will result in ordinary gains or losses.

As discussed above deductions for intangible drilling costs and depletion allowances that are incurred in connection with a natural gas or oil property may be recaptured as ordinary income when the property is sold or otherwise disposed of in a taxable transaction by the partnership. The amount of gain recaptured as ordinary income is the lesser of:

the aggregate amount of expenditures that have been deducted as intangible drilling costs with respect to the property and which, but for being deducted, would have been included in the adjusted basis of the property, plus deductions for depletion that reduced the adjusted basis of the property; or

the excess of:

the amount realized, in the case of a sale, exchange or involuntary conversion; or

the fair market value of the property, in the case of any other taxable disposition;

over the adjusted basis of the property. I.R.C. §1254(a).

(See “– Intangible Drilling Costs” and “– Depletion Allowance,” above.)

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Also, all gain on the sale or other taxable disposition of equipment by the partnership will be treated as ordinary income to the extent of MACRS deductions previously claimed by the partnership. I.R.C. §1254(a). (See “– Depreciation and Cost Recovery Deductions,” above.)

Disposition of Units

If you invest in the partnership, then you must assume the risks of an illiquid investment. The transferability of the units is limited by the securities laws, the tax laws and the partnership agreement. (See “Transferability of Units – Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership Agreement.”) If you are able to sell or exchange all or some of your units in the partnership, you are required under §6050K of the Code to notify the partnership within 30 days or by January 15 of the following year, if earlier. After receiving the notice, the partnership must file a return with the IRS setting forth the name and address of both you, as the transferor, and the transferee, the fair market value of the portion of the partnership’s unrealized receivables and appreciated inventory (i.e., §751 assets) allocable to the units sold or exchanged by you (which are subject to recapture as ordinary income instead of capital gain as discussed below) and any other information as may be required by the IRS. The partnership also must provide each person whose name is set forth in the return a written statement showing the information set forth on the return.

The sale or exchange, including a purchase by the managing general partner, of all or some of your units, if held by you as a capital asset for more than 12 months, will result in your recognition of long-term capital gain or loss, except for your share of your partnership’s “§751 assets” (i.e. inventory items and unrealized receivables). “Unrealized receivables” includes any right to payment for goods delivered, or to be delivered, to the extent the proceeds would be treated as amounts received from the sale or exchange of non-capital assets, services rendered or to be rendered, to the extent not previously includable in income under your partnership’s accounting methods, and deductions previously claimed by you for depreciation, depletion and intangible drilling costs with respect to the partnership. “Inventory items” includes property properly includable in inventory and property held primarily for sale to customers in the ordinary course of business and any other property that would produce ordinary income if sold, including accounts receivable for goods and services. These tax items are sometimes referred to in this discussion as “§751 assets.” All of these tax items may be recaptured as ordinary income rather than capital gain regardless of how long you have owned your units. (See “– Sale of the Properties,” above.)

If your units are held for 12 months or less, your gain or loss will be short-term gain or loss. Also, your pro rata share of your partnership’s liabilities, if any, as of the date of the sale or exchange, must be included in the amount realized by you. Thus, the gain recognized by you may result in a tax liability to you greater than the cash proceeds, if any, received by you from the disposition of your units. In addition to gain from a passive activity, a portion of any gain recognized by a limited partner on the sale or other taxable disposition of his units will be characterized as portfolio income under the passive activity loss rules to the extent the gain is attributable to portfolio income, e.g. interest income on investments of working capital. Treas. Reg. §1.469-2T(e)(3). (See “– Limitations on Passive Activity Losses and Credits,” above.)

A gift of your units may result in federal and/or state income tax and gift tax liability to you. Also, interests in different partnerships do not qualify for tax-free like-kind exchanges. I.R.C. §1031(a)(2)(D). Other types of dispositions of your units may or may not result in recognition of taxable gain. However, no gain should be recognized by an investor general partner on the conversion of his investor general partner units to limited partner units so long as there is no change in his share of his partnership’s liabilities, if any, or §751 assets as a result of the conversion. Revenue Ruling 84-52, 1984-1 C.B. 157.

If you die, or sell or exchange all of your units, the taxable year of your partnership will close with respect to you, but not the remaining investors, on the date of death, sale or exchange, and there will be a proration of partnership items for the partnership’s taxable year. If you sell less than all of your units, the partnership’s taxable year will not terminate with respect to you, but your proportionate share of the partnership’s items of income, gain, loss, deduction and credit will be determined by taking into account your varying interests in the partnership during the taxable year.

You are urged to seek advice based on your particular circumstances from an independent tax advisor before any sale or other disposition of your units, including any purchase of your units by the managing general partner.

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Alternative Minimum Tax

With limited exceptions, under §55 of the Code you must pay an alternative minimum tax if it exceeds your regular federal income tax for the year. Alternative minimum taxable income (“AMTI”) is regular federal taxable income, plus or minus various adjustments, plus tax preference items. The tax rate for noncorporate taxpayers is 26% for the first $175,000, $87,500 for married individuals filing separately, of a taxpayer’s AMTI in excess of the applicable exemption amount (as set forth below); and additional AMTI is taxed at 28%. However, the regular tax rates on capital gains also will apply for purposes of the alternative minimum tax. (See “– Sale of the Properties,” above.) Exemption amounts for alternative minimum tax purposes are different from the regular tax personal exemptions, which are not allowed, and the types and amounts of itemized deductions allowed for minimum tax purposes are more limited than those allowed for regular tax purposes as discussed below. For example, in 2009 only, the alternative minimum tax exemption amounts for individuals were as follows:

married individuals filing jointly and surviving spouses, $70,950, less 25% of AMTI exceeding $150,000 (zero exemption when AMTI is $433,800);

unmarried individuals other than surviving spouses, $46,700, less 25% of AMTI exceeding $112,500 (zero exemption when AMTI is $299,300); and

married individuals filing separately, $35,475, less 25% of AMTI exceeding $75,000 (zero exemption when AMTI is $216,900). Also, AMTI of married individuals filing separately is increased by the lesser of $35,475 or 25% of the excess of AMTI (without regard to the exemption reduction) over $216,900.

Absent future legislation from Congress, however, the exemption amounts for individuals for alternative minimum tax purposes in 2010 and subsequent years will be reduced substantially from those set forth above for 2009.

Code sections suspending losses, such as the rules concerning your “at risk” amount in the partnership, the amount of your passive activity losses from the partnership, and your basis in your units, are recomputed for alternative minimum tax purposes, and the amounts of the deductions that are suspended, or capital gains that are recaptured as ordinary income, may differ for regular income tax and alternative minimum tax purposes. Due to the inherently factual nature of these determinations and each investor’s different tax situation, special counsel is unable to express an opinion as to whether any investor will incur, or increase, his alternative minimum tax liability because of an investment in the partnership.

Some of the principal adjustments to taxable income that are used to determine an individual’s AMTI include those summarized below:

Depreciation deductions of the costs of the equipment placed in service in the wells (“Tangible Costs”) generally may not exceed deductions computed using the 150% declining balance method. These adjustments are discussed in greater detail below. (See “– Depreciation and Cost Recovery Deductions,” above.)

Miscellaneous itemized deductions are not allowed.

Medical expenses are deductible only to the extent they exceed 10% of adjusted gross income.

State and local income, property and general sales taxes, at your election instead of state and local income taxes, are not deductible unless they are deductible in computing adjusted gross income for regular income taxes.

Interest deductions are restricted.

The standard deduction and personal exemptions are not allowed.

Only some types of operating losses are deductible.

Passive activity losses are computed differently.

Earlier recognition of income from incentive stock options may be required.

The principal tax preference items that must be added to taxable income for alternative minimum tax purposes include:

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excess intangible drilling costs, as discussed below; and

tax-exempt interest earned on certain private activity bonds, other than private activity bonds issued after December 31, 2008, and before January 1, 2011, less any deductions that would have been allowable if the interest were included in gross income for regular income tax purposes.

For taxpayers other than “integrated oil companies” as that term is defined in “– Intangible Drilling Costs,” above, which does not include the partnership, the 1992 National Energy Bill repealed:

the preference for excess intangible drilling costs; and

the excess percentage depletion preference for natural gas and oil.

The repeal of the excess intangible drilling costs preference, however, under current law may not result in more than a 40% reduction in the amount of the taxpayer’s AMTI computed as if the excess intangible drilling costs preference had not been repealed. I.R.C. §57(a)(2)(E). Under the prior rules, the amount of intangible drilling costs that is not deductible for alternative minimum tax purposes is the excess of the “excess intangible drilling costs” over 65% of net income from natural gas and oil properties. Net natural gas and oil income is determined for this purpose without subtracting excess intangible drilling costs. Excess intangible drilling costs is the regular intangible drilling costs deduction minus the amount that would have been deducted under 120-month straight-line amortization, or, at the taxpayer’s election, under the cost depletion method. There is no preference item for costs of nonproductive wells. Also, you may elect under §59(e) of the Code to capitalize all or part of your share of your partnership’s intangible drilling costs (which does not include your share of the partnership’s intangible drilling costs of a re-entry well that are treated under the Code as operating costs, if any) and deduct the costs ratably over a 60-month period beginning with the month in which the costs were paid or incurred by the partnership. This election also applies for regular tax purposes and can be revoked only with the IRS’ consent. Making this election, therefore, will include the following principal consequences to you:

your regular federal income tax deduction for intangible drilling costs in the year you invest will be reduced because you must spread the deduction for the amount of intangible drilling costs that you elect to capitalize over the 60-month amortization period; and

the capitalized intangible drilling costs will not be treated as a preference that is included in your alternative minimum taxable income.

However, see “Risk Factors – Federal Income Tax Risks – Changes in the Law May Reduce Your Tax Benefits From an Investment in the Partnership” regarding President Obama’s administration’s proposal to repeal on January 1, 2011 the election to expense intangible drilling costs, and to repeal the further option to capitalize and deduct intangible drilling costs over a 60-month period.

Other than intangible drilling costs as discussed above, and passive activity losses and credits in the case of limited partners, the principal tax item that may have an impact on your AMTI as a result of investing in the partnership is depreciation of the partnership’s equipment expenses. (See “– Limitations on Passive Activity Losses and Credits,” above.) As noted in “– Depreciation and Cost Recovery Deductions,” above, the partnership’s cost recovery deductions for regular income tax purposes will be computed differently than for alternative minimum tax purposes. Consequently, in the early years of the cost recovery period of your partnership’s equipment, but not in the later years, your depreciation deductions from the partnership generally will be smaller for alternative minimum tax purposes than your depreciation deductions for regular income tax purposes on the same equipment. This could cause you to incur, or may increase your, alternative minimum tax liability in those taxable years. Conversely, this adjustment may decrease your AMTI in the later years of the cost recovery period. Also, under current law, your share of your partnership’s marginal well production credits, if any, may not be used to reduce your alternative minimum tax liability, if any. In addition, the rules relating to the alternative minimum tax for corporations are different from those for individuals that are discussed above.

All prospective investors contemplating purchasing units in the partnership are urged to seek advice based on their particular circumstances from an independent tax advisor as to the likelihood of them incurring or increasing any alternative minimum tax liability as a result of an investment in the partnership.

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Limitations on Deduction of Investment Interest

Investment interest expense is deductible by a noncorporate taxpayer only to the extent of net investment income each year, with an indefinite carryforward of disallowed investment interest expense deductions to subsequent taxable years. I.R.C. §163(d). An investor general partner’s share of any interest expense incurred by the partnership before his investor general partner units are converted to limited partner units will be subject to the investment interest limitation. I.R.C. §163(d)(5)(A)(ii). In addition, an investor general partner’s share of the partnership’s loss in the year he invests as a result of the deduction for intangible drilling costs will reduce his net investment income and may reduce or eliminate the deductibility of his investment interest expenses, if any, in the year he invests, with the disallowed portion to be carried forward to subsequent taxable years. This limitation on the deduction of investment interest expenses, however, will not apply to any income or expenses taken into account by limited partners in computing their income or loss from the partnership as a passive activity under §469 of the Code. I.R.C. §163(d)(4)(D). (See “– Limitations on Passive Activity Losses and Credits,” above.)

Allocations

The partnership agreement allocates to you your share of your partnership’s income, gains, losses, deductions, and credits, if any, including the deductions for intangible drilling costs and depreciation. Your capital account in the partnership will be adjusted to reflect your share of these allocations, and your capital account, as adjusted, will be given effect by the partnership in making distributions to you on liquidation of the partnership or your units. Also, the basis of the natural gas and oil properties owned by your partnership for purposes of computing cost depletion and gain or loss on disposition of a property will be allocated and reallocated when necessary in the ratio in which the expenditure giving rise to the tax basis of each property was charged as of the end of the year. (See §5.03(b) of the partnership agreement.)

Your capital account in the partnership will be:

increased by the amount of money you contribute to the partnership and allocations of partnership income and gain to you; and

decreased by the value of property or cash distributed to you by the partnership and allocations of partnership losses and deductions to you.

Allocations under the partnership agreement of some tax items are made in ratios that are different from allocations of other tax items (i.e., “special allocations”). These special allocations will not be given effect under the Code unless they have “substantial economic effect.” I.R.C. §704(b). Economic effect means that if there is an economic benefit or burden that corresponds to an allocation, the partner to whom the allocation is made must receive the economic benefit or bear the economic burden. The economic effect of an allocation is substantial if there is a reasonable possibility that the allocation will affect substantially the dollar amounts to be received by the partners from the partnership, independent of tax consequences and taking into account the partners’ tax attributes that are unrelated to the partnership. The allocations under the partnership agreement will have economic effect if throughout the term of the partnership in which you invest:

the partners’ capital accounts are increased and decreased as described above;

liquidation proceeds are distributed in accordance with the partners’ capital accounts; and

any partner with a deficit balance in his capital account following the liquidation of his interest in the partnership is required to restore the amount of the deficit to the partnership.

Even though you and the other investors are not required under the partnership agreement to restore any deficit balance in your capital accounts in your partnership by making additional capital contributions to the partnership, an allocation that is not attributable to nonrecourse debt or tax credits will still be considered to have economic effect under the Treasury Regulations to the extent it does not cause or increase a deficit balance in your capital account if:

the partners’ capital accounts are increased and decreased as described above;

the partnership’s liquidation proceeds are distributed in accordance with the partners’ capital accounts; and

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the partnership agreement provides that if you unexpectedly incur a deficit balance in your capital account because of certain adjustments, allocations, or distributions of the partnership, then you will be allocated an additional amount of partnership income and gain that is sufficient to eliminate the deficit balance as quickly as possible.

Treas. Reg. §1.704-1(b)(2)(ii)(d). These provisions are included in the partnership agreement (See §§5.02, 5.03(h), and 7.02(a) of the partnership agreement.)

Special provisions of the Treasury Regulations apply to deductions that are related to nonrecourse debt and tax credits, since allocations of those tax items cannot have substantial economic effect under the Treasury Regulations. If the managing general partner or an affiliate makes a nonrecourse loan to the partnership (a “partner nonrecourse liability”), then the partnership’s losses, deductions, or §705(a)(2)(B) expenditures attributable to the loan must be allocated to the managing general partner. Also, if there is a net decrease in partner nonrecourse liability minimum gain with respect to the loan, the managing general partner must be allocated income and gain equal to the net decrease. (See §§5.03(a)(1) and 5.03(i) of the partnership agreement.) In addition, any marginal well production credits of the partnership will be allocated among the managing general partner and you and the other investors in the partnership in accordance with each partner’s respective interest in the partnership’s production revenues from the sale of its natural gas and oil marginal production. (See §5.03(g) of the partnership agreement, “Participation in Costs and Revenues,” and “– Marginal Well Production Credits,” above.)

If you sell or transfer your unit in the partnership, or on the death of an investor or the admission of an additional partner, the partnership’s income, gain, loss, credits and deductions will be allocated among its partners according to their varying interests in the partnership during the taxable year. In addition, the Code may require the partnership’s property to be revalued on the admission of additional partners, if any, if disproportionate distributions are made to the partners, or if there are “built-in” losses on the transfer of a partner’s units or any distribution of the partnership’s property to its partners. (See “– Tax Elections,” below.)

It also should be noted that your share of items of income, gain, loss, deduction, and credit, if any, in the partnership must be taken into account by you whether or not you receive any cash distributions from the partnership. For example, your share of partnership revenues applied by your partnership to the repayment of loans, if any, or the reserve for plugging wells, will be included in your gross income in a manner analogous to an actual distribution of the revenues (and income) to you. Thus, you may have tax liability on taxable income from your partnership for a particular year in excess of any cash distributions from the partnership to you with respect to that year. To the extent the partnership has cash available for distribution, however, it is the managing general partner’s policy that partnership cash distributions to you and the other investors in the partnership will not be less than the managing general partner’s estimate of the investors’ income tax liability (as a group) with respect to the partnership’s income.

If any allocation under the partnership agreement is not recognized for federal income tax purposes, your share of the items subject to the allocation will be determined under the Code in accordance with your interest in the partnership by considering all of the relevant facts and circumstances. To the extent deductions or credits allocated by the partnership agreement exceed deductions or credits that would be allowed under a reallocation of those tax items by the IRS, you may incur a greater tax burden.

Partnership Borrowings

Under the partnership agreement, only the managing general partner and its affiliates may make loans to the partnership. The use of partnership revenues taxable to you to repay borrowings by your partnership, if any, could create income tax liability for you in excess of your cash distributions from the partnership, since repayments of principal are not deductible for federal income tax purposes. In addition, interest on the loans will not be deductible unless the loans are bona fide loans that will not be treated by the IRS as capital contributions to the partnership by the managing general partner or its affiliates in light of all of the surrounding facts and circumstances. Also, the “at risk” amounts of you and the other investors in the partnership, which limit the amount of partnership losses you and the other investors can claim as discussed in “– ‘At Risk’ Limitation on Losses,” above, will not be increased by the amount of any partnership borrowings from the managing general partner or its affiliates, because you and the other investors will not bear any risk of repaying the borrowings from your non-partnership assets, even if you invest in the partnership as an investor general partner.

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Partnership Organization and Offering Costs

Expenses connected with the offer and sale of units in the partnership, such as the dealer-manager fee, sales commissions, and other selling expenses, professional fees, and printing costs, which are charged under the partnership agreement 100% to the managing general partner as organization and offering costs, are not deductible. Although expenses incident to the creation of the partnership may be amortized over a period of not less than 180 months, these expenses also will be paid by the managing general partner as part of the partnership’s organization costs. Thus, any related deductions, which the managing general partner does not anticipate will be material in amount as compared to the total amount of subscription proceeds of the partnership, will be allocated under the partnership agreement to the managing general partner.

Tax Elections

The partnership may elect to adjust the basis of its property (other than cash) on the transfer of a unit in the partnership by sale or exchange or on the death of an investor, and on the distribution of property (other than money) by the partnership to an investor (the §754 election). If the §754 election is made, the transferees of the units are treated, for purposes of depreciation and gain, as though they had acquired a direct interest in the partnership assets and the partnership is treated for these purposes, on distributions to the investors, as though it had newly acquired an interest in the partnership assets and therefore acquired a new cost basis for the assets. Any election, once made, may not be revoked without the consent of the IRS.

In this regard, due to the complexities and added expense of the tax accounting required to implement a §754 election to adjust the basis of the partnership’s property when units are sold, taking into account the limitations on the sale of the partnership’s units as described in “Transferability of Units,” the managing general partner anticipates that the partnership will not make the §754 election, although it reserves the right to do so. Even if the partnership does not make the §754 election, however, the basis adjustment described above is mandatory under the Code with respect to the transferee partner only, if at the time a unit is transferred by sale or exchange, or on the death of an investor, the partnership’s adjusted basis in its property exceeds the fair market value of the property by more than $250,000 immediately after the transfer of the unit. Similarly, a basis adjustment is mandatory under the Code if the partnership distributes property in-kind to a partner and the sum of the partner’s loss on the distribution and the basis increase to the distributed property is more than $250,000. I.R.C. §§734 and 743. In this regard, under §7.02 of the partnership agreement, the partnership will not distribute its assets in-kind to its investors, except to a liquidating trust or similar entity for the benefit of its investors on the dissolution and termination of the partnership, unless at the time of the distribution its investors have been offered the election of receiving in-kind property distributions, and you or any other investor in the partnership accepts the offer after being advised of the risks associated with direct ownership; or there are alternative arrangements in place that assure you and the other investors in the partnership will not, at any time, be responsible for the operation or disposition of the partnership’s properties.

If the basis of the partnership’s assets must be adjusted as discussed above, the primary effect on the partnership, other than the federal income tax consequences discussed above, would be an increase in its administrative and accounting expenses to make the required basis adjustments to its properties and separately account for those adjustments after they are made. In this regard, the partnership will not make in-kind property distributions to its investors except in the limited circumstances described above, and the units will have no readily available market and will be subject to substantial restrictions on their transfer. (See “Transferability of Units – Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership Agreement.”) These factors will tend to reduce the likelihood that the partnership will be required to make mandatory basis adjustments to its properties.

In addition to the §754 election, the partnership may make various elections under the Code for federal tax reporting purposes that could result in the deductions of intangible drilling costs, depreciation and the depletion allowance being treated differently for tax purposes than for accounting purposes. Also, under §195 of the Code “start-up expenditures” may be capitalized and amortized over a 180-month period. The term “start-up expenditure” for this purpose includes any amount:

paid or incurred in connection with:

investigating the creation or acquisition of an active trade or business;

creating an active trade or business; or

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any activity engaged in for profit and for the production of income before the day on which the active trade or business begins, in anticipation of that activity becoming an active trade or business; and

that would be allowable as a deduction if paid or incurred in connection with the expansion of an existing business.

If it is ultimately determined by the IRS or the courts that any of the partnership’s expenses constituted start-up expenditures, the partnership’s deductions for those expenses, including your share, if any, of those deductions under the partnership agreement would be amortized over the 180-month period.

Tax Returns and IRS Audits

The tax treatment of most partnership items is determined at the partnership, rather than the partner, level. Accordingly, you are required under the Code to treat the tax items of the partnership on your individual federal income tax returns in a manner that is consistent with the treatment of the partnership items on the partnership’s federal information income tax returns, unless you disclose to the IRS, by attaching the required IRS notice to your individual federal income tax return, that your tax treatment of the partnership’s tax items on your personal federal income tax returns is different from the partnership’s tax treatment of those partnership tax items. I.R.C. §§6221 and 6222. Treasury Regulations define partnership tax items for this purpose as including distributive share items that must be allocated among the partners, such as partnership liabilities, data pertaining to the computation of the depletion allowance, and guaranteed payments. Treas. Reg. §301.6231(a)(3)-1.

In most cases, the IRS must make an administrative determination as to partnership tax items at the partnership level before conducting deficiency proceedings against a partner, and the partners must file a request for an IRS administrative determination with respect to the partnership before filing suit for any credit or refund. Also, the period for assessing tax against you and the other investors because of a partnership tax item may be extended by agreement between the IRS and the managing general partner, which will serve as the partnership’s representative (“Tax Matters Partner”) in all administrative tax proceedings and tax litigation, if any, conducted at the partnership level.

The Tax Matters Partner may enter into a settlement on behalf of, and binding on, any investor owning less than a 1% profits interest in the partnership if there are more than 100 partners in the partnership, unless that investor timely files a statement with the Secretary of the Treasury providing that the Tax Matters Partner does not have authority to enter into a settlement agreement on behalf of that investor. Based on its past experience, the managing general partner anticipates that there will be more than 100 investors in the partnership. However, by executing the Subscription Agreement you also are executing the partnership agreement if your Subscription Agreement is accepted by the managing general partner. Under the partnership agreement, you and the other investors in the partnership agree that you will not form or exercise any right as a member of a notice group and will not file a statement notifying the IRS that the Tax Matters Partner does not have binding settlement authority. In addition, a partnership with at least 100 partners may elect to be governed under simplified tax reporting and audit rules as an “electing large partnership.” However, most limitations affecting the calculation of the taxable income and tax credits of an electing large partnership are applied at the partnership level and not the partner level. Thus, the managing general partner does not anticipate that the partnership will make this election, although it reserves the right to do so.

All expenses of any tax proceedings involving the partnership and the managing general partner acting as Tax Matters Partner, which might be substantial, will be paid for by the partnership and not by the managing general partner from its own funds. The managing general partner, however, is not obligated to contest any adjustments made by the IRS to the partnership’s federal information income tax returns, even if the adjustment also would affect the individual federal income tax returns of you and the other investors in the partnership. The managing general partner will notify you and the other investors in your partnership of any IRS audits or other tax proceedings involving your partnership, and will provide you and the other investors any other information regarding the proceedings as may be required by the partnership agreement or law.

Tax Returns. Your individual income tax returns are your responsibility. The partnership will provide its investors with the tax information applicable to their investment in the partnership necessary to prepare their tax returns.

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Profit Motive, IRS Anti-Abuse Rule and Judicial Doctrines Limitations on Deductions

Under §183 of the Code, your ability to deduct your share of your partnership’s deductions could be limited or lost if the partnership lacks the appropriate profit motive as determined from an examination of all facts and circumstances at the time. Section 183 of the Code creates a presumption that an activity is engaged in for profit if, in any three of five consecutive taxable years, the gross income derived from the activity exceeds the deductions attributable to the activity. Thus, if your partnership fails to show a profit in at least three out of five consecutive years this presumption will not be available and the possibility that the IRS could successfully challenge the partnership deductions claimed by you would be substantially increased. The fact that the possibility of ultimately obtaining profits is uncertain, standing alone, does not appear under the Treasury Regulations to be sufficient grounds for the denial of losses. Also, if a principal purpose of the partnership is to reduce substantially the partners’ federal income tax liability in a manner that is inconsistent with the intent of the partnership rules of the Code, based on all the facts and circumstances, the IRS is authorized under Treasury Regulation §1.701-2 to remedy the abuse. Finally, under potentially relevant judicial doctrines such as the step transaction, business purpose, economic substance, substance over form, and sham transaction doctrines, tax deductions and tax credits from a transaction, including the partnership’s deduction for intangible drilling costs in the year its investors invest in the partnership, would be disallowed if your partnership were found by the IRS or the courts to have no economic substance apart from the tax benefits. In this regard, President Obama’s proposed budget includes a provision to codify the economic substance doctrine beginning with transactions entered into after the date of enactment which, if it is enacted into law, could adversely affect your tax benefits from an investment in the partnership.

With respect to these issues, special counsel has given its opinions under current law that the partnership will possess the requisite profit motive, and the IRS anti-abuse rule in Treas. Reg. §1.701-2 and the potentially relevant judicial doctrines listed above will not have a material adverse effect on the tax consequences of an investment in the partnership by a typical investor as described in special counsel’s opinions. These opinions are based in part on the results of the previous partnerships sponsored by the managing general partner as set forth in “Prior Activities” and the managing general partner’s representations to special counsel, which are set forth in its tax opinion letter attached as Exhibit 8.1 to the registration statement of which this prospectus is a part. The managing general partner’s representations include that the partnership will be operated as described in this prospectus (see “Management” and “Proposed Activities”) and the principal purpose of the partnership is to locate, produce and market natural gas and oil on a profitable basis to its investors, apart from tax benefits, as described in this prospectus. Also, see the information concerning the partnership’s proposed drilling areas in “Proposed Activities,” and the geological evaluations and other information for the specific prospects proposed to be drilled by Atlas Resources Public #18-2009(C) L.P. included in Appendix A to this prospectus, which represent a portion of the prospects to be drilled if the maximum subscription proceeds are received as described in “Terms of the Offering – Subscription to the Partnership.”

Federal Interest and Tax Penalties

Taxpayers must pay tax and interest on underpayments of federal income taxes, and the Code contains various penalties, including penalties for negligence and substantial valuation misstatements with respect to a taxpayer’s individual federal income tax returns. In addition, there is a penalty equal to 20% of the amount of a substantial understatement of federal income tax liability. There is a substantial understatement by a noncorporate taxpayer if the correct income tax, as finally determined by the IRS or the courts, exceeds the income tax liability shown on the taxpayer’s federal income tax return by the greater of 10% of the correct tax, or $5,000. In the case of a corporation, other than an S corporation or a personal holding company as defined in §542 of the Code, an understatement is substantial if it exceeds the lesser of: (i) 10% of the correct tax (or, if greater, $10,000); or (ii) $10 million). I.R.C. §6662. A noncorporate taxpayer may avoid this penalty if the understatement was not attributable to a “tax shelter,” as that term is defined below, and there is or was substantial authority for the taxpayer’s tax treatment of the item that caused the understatement, or if the relevant facts were adequately disclosed on the taxpayer’s individual federal income tax return or a statement attached to the return and the taxpayer had a “reasonable basis” for the tax treatment of that item. In the case of an understatement that is attributable to a “tax shelter,” however, which may include the partnership for this purpose, the penalty may be avoided by a noncorporate taxpayer only if there was reasonable cause for the underpayment and the taxpayer acted in good faith, or there is or was substantial authority for the taxpayer’s treatment of the item that caused the understatement, and the taxpayer reasonably believed that his or her treatment of the item on his individual federal income tax return was more likely than not the proper treatment.

For purposes of this penalty, the term “tax shelter” includes a partnership if a significant purpose of the partnership is the avoidance or evasion of federal income tax. Because the IRS has not explained what a “significant” purpose of avoiding or evading federal income taxes means, special counsel cannot give an opinion as to whether the partnership is a “tax shelter” as defined by the Code for purposes of this penalty.

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Also, under §6662A of the Code, there is a 20% penalty for reportable transaction understatements of federal income taxes on a taxpayer’s individual federal income tax return for any tax year. However, if the disclosure rules for reportable transactions under the Code and the Treasury Regulations are not met by the taxpayer, this penalty is increased from 20% to 30%, and a “reasonable cause” exception to the penalty that is set forth in §6664(d) of the Code will not be available to the taxpayer. Under Treasury Regulation §1.6011-4, a taxpayer who participates in a reportable transaction in any taxable year must attach to his individual federal income tax return IRS Form 8886 “Reportable Transaction Disclosure Statement,” and file it with the IRS as directed in the Treasury Regulation, in order to comply with the disclosure rules.

A tax item is subject to the reportable transaction rules if the tax item is attributable to:

any listed transaction, which is a transaction that is the same as, or substantially similar to, a transaction that the IRS has publicly pronounced to be a tax avoidance transaction; or

any additional types of reportable transactions, if a significant purpose of the transaction is federal income tax avoidance or evasion.

A “loss transaction” is one type of reportable transaction, but only if a “significant” purpose of the transaction is federal income tax avoidance or evasion. As set forth above, special counsel cannot give an opinion with respect to whether or not the partnership has a “significant” purpose of avoiding federal income taxes, because the IRS has not explained what that phrase means for purposes of this penalty. Subject to the foregoing, under Treasury Regulation §1.6011-4(b)(5), there is a loss transaction if a partnership or any of its noncorporate partners claims a loss under §165 of the Code of at least $2 million, in the aggregate, in any taxable year of the partnership, or at least $4 million, in the aggregate, over the partnership’s first six years. In this regard, however, special counsel has given its opinion that the partnership is not, and should not be in the future, a reportable transaction under the Code.

For purposes of the “loss transaction” rules, a §165 loss includes an amount deductible under a provision of the Code that treats a transaction as a sale or other disposition of property, or otherwise results in a deduction under §165. A §165 loss includes, for example, a loss resulting from a sale or exchange of a partnership interest, such as an investor’s units in the partnership. The amount of a §165 loss is adjusted for any salvage value and for any insurance or other compensation received. However, a §165 loss for this purpose does not take into account offsetting gains or other income limitations under the Code.

The partnership will incur a tax loss in the year in which its investors invest in the partnership in excess of $2 million if the partnership receives subscription proceeds of approximately $2,353,000 or more, due primarily to the amount of intangible drilling costs for productive wells that the partnership intends to claim as a deduction. Notwithstanding the foregoing, in special counsel’s opinion the partnership’s losses resulting from deductions claimed for intangible drilling costs for productive wells properly should be treated as losses under §263(c) of the Code and Treas. Reg. §1.612-4(a), and should not be treated as §165 losses for purposes of the “loss transaction” rules under Treas. Reg. 1.6011-4(b)(5). However, the partnership may incur losses under §165 of the Code, such as losses for the abandonment by the partnership of:

wells drilled that are nonproductive (i.e. a “dry hole”), if any, in which case the intangible drilling costs, the tangible costs, and possibly the lease acquisition costs of the abandoned wells would be deducted as §165 losses; and

wells that have been operated until their commercial natural gas and oil reserves have been depleted, in which case the undepreciated tangible costs, if any, and possibly the lease acquisition costs, would be deducted as §165 losses.

In this regard, based primarily on its past experience (as shown in “Prior Activities”), including Atlas America’s 97% completion rate for wells drilled by its previous development drilling partnerships in the Appalachian Basin (see “Management”), the managing general partner has represented the following with respect to the partnerships in the program:

when a well is plugged and abandoned by a partnership, the salvage value of the well’s equipment usually will cover a substantial amount of the costs of abandoning and reclaiming the well site;

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each partnership will drill relatively few non-productive wells (i.e., “dry holes”), if any;

each productive well drilled by a partnership will have a different productive life and the partnership’s wells will not all be depleted and abandoned in the same taxable year; and

each productive well drilled by a partnership will produce natural gas and oil for more than six years.

State and Local Taxes

The partnership will operate in states and localities that may impose a tax on it, or on you and the partnership’s other investors, based on the partnership’s assets or income or your share of its assets or income. Also, 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 on your partnership as an entity, the partnership’s cash available for distribution to you and its other investors would be reduced. The partnership also may be subject to state income tax withholding requirements on its income allocable to you and its other investors, whether or not the revenues that created the income are distributed to you and its other investors. For example, your partnership will withhold Pennsylvania income taxes at a rate of 3.07% on your share of its income from its wells situated in Pennsylvania if you are not a resident of Pennsylvania.

If you are an individual, and not a corporation, and you are also not a resident of Pennsylvania, then unless you affirmatively elect in your Subscription Agreement to be included in your partnership’s consolidated state or local income tax returns, which will include your share of the partnership’s income and deductions (including the intangible drilling costs deduction, which the managing general partner anticipates will be amortized over an eight-year period for the partnership’s Pennsylvania income tax purposes only), you likely will be required to file your own tax returns for Pennsylvania and likely the other states where your partnership’s wells are situated. Consolidated partnership state income tax returns currently are filed by the partnership in New York, Pennsylvania and West Virginia if partnership wells are situated in those states. Also, the partnership may elect to file consolidated partnership tax returns in any other state where its wells may be situated. For partnership purposes, any payments to state or local tax authorities on your behalf by your partnership will be treated by the partnership as if those payments had actually been distributed to you and then you paid the taxes yourself.

Partnership deductions and credits, including marginal well production credits, if any, which may be available to you for federal income tax purposes, may not be available to you for state or local income tax purposes. If you reside in a state or locality that imposes income taxes on its residents, you likely will be required under those income tax laws to include your share of your partnership’s net income or net loss in determining your reportable income for state or local tax purposes in the jurisdiction in which you reside. To the extent that you pay tax to another state because of partnership operations within that state, you may be entitled to a deduction or credit against tax owed to your state of residence with respect to the same income. Also, due to the partnership’s operations in a state or local jurisdiction, state or local estate or inheritance taxes may be payable on the death of an investor in addition to taxes imposed by his own domicile.

The partnership’s units may be sold in all 50 states, the District of Columbia and other jurisdictions, and it is not practical for special counsel to evaluate the many different state and local tax laws that may affect an investment in the partnership. You are urged to seek advice based on your particular circumstances from an independent tax advisor to determine the effect state and local taxes may have on you in connection with an investment in the partnership.

Severance and Ad Valorem (Real Estate) Taxes

The partnership will incur various ad valorem or severance taxes imposed by state or local taxing authorities on its natural gas and oil wells and/or natural gas and oil production from the wells. Although Pennsylvania currently does not impose a severance tax on natural gas and oil production from wells situated in Pennsylvania, in February 2009 its governor proposed a new two-part tax on natural gas production statewide, including wells in the Marcellus Shale, composed of:

a 5% tax on the value of all the gas produced; plus

a $0.047 tax on every thousand cubic feet of gas produced.

The managing general partner is unable to predict whether ot not this proposed tax in Pennsylvania will become law. These taxes will reduce the amount of the partnership’s cash available for distribution to you and its other investors.

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Social Security Benefits and Self-Employment Tax

A limited partner’s share of income or loss from the partnership is excluded from the definition of “net earnings from self-employment.” No increased benefits under the Social Security Act will be earned by limited partners and if any limited partners are currently receiving Social Security benefits, their shares of partnership taxable income will not be taken into account in determining any reduction in benefits because of “excess earnings.”

An investor general partner’s share of income or loss from the partnership will constitute “net earnings from self-employment” for these purposes. The ceiling for social security tax of 12.4% in 2009 is $106,800, which will be adjusted annually for inflation in subsequent years. There is no ceiling for Medicare tax of 2.9%. Self-employed individuals can deduct one-half of their self-employment tax.

Farmouts

Under a farmout by the partnership, if a property interest, other than an interest in the drilling unit assigned to the partnership well in question, is earned by the farmee (i.e., anyone other than the partnership) from the farmor (i.e., the partnership) as a result of the farmee drilling or completing the well, then the farmee must recognize income equal to the fair market value of the outside interest earned, and the farmor must recognize gain or loss on a deemed sale equal to the difference between the fair market value of the outside interest and the farmor’s tax basis in the outside interest. Neither the farmor nor the farmee would have received any cash to pay the tax. The managing general partner has represented that it will attempt to eliminate or reduce any gain to the partnership from a farmout, if any. However, if the IRS claims that a farmout by the partnership results in taxable income to the partnership, you and the other investors in the partnership may be required to include your share of the resulting taxable income on your individual income tax returns, even though the partnership and you and the other investors in the partnership received no cash from the farmout.

Foreign Partners

The partnership generally will be required to withhold and pay income tax to the IRS at the highest rate under the Code applicable to partnership income allocable to its foreign investors, even if no cash distributions are made to them. In the event of overwithholding, a foreign investor must seek a refund on his individual United States federal income tax return. For withholding purposes, a foreign investor means an investor who is not a United States person and includes a nonresident alien individual, a foreign corporation, a foreign partnership, and a foreign trust or estate, unless the investor has certified to his partnership the investor’s status as a U.S. person on Form W-9 or any other form permitted or required by the IRS for that purpose. Foreign investors are urged to seek advice based on their particular circumstances from an independent tax advisor regarding the applicability of these rules and the other tax consequences of an investment in the partnership to them.

You are urged to seek advice based on your particular circumstances from an independent tax advisor with respect to the impact of recent federal tax legislation on an investment in the partnership and the status of federal and state legislative, regulatory or administrative tax developments and tax proposals and their potential effect on the tax consequences to you of an investment in the partnership. (See “Risk Factors – Federal Income Tax Risks – Changes in the Law May Reduce Your Tax Benefits From an Investment in the Partnership.”)

SUMMARY OF PARTNERSHIP AGREEMENT

The rights and obligations of the managing general partner and you and the other investors in the partnership are governed by the form of partnership agreement, a copy of which attached as Exhibit (A) to this prospectus. You are urged to thoroughly review the partnership agreement before you decide to invest in the partnership. The following is a summary of the material provisions in the partnership agreement that are not covered elsewhere in this prospectus. Thus, this prospectus summarizes all of the material provisions of the partnership agreement.

Liability of Limited Partners

The partnership will be governed by the Delaware Revised Uniform Limited Partnership Act. If you invest as a limited partner, then generally you will not be liable to third-parties for the obligations of your partnership unless you:

also invest as an investor general partner;

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take part in the control of the partnership’s business in addition to the exercise of your rights and powers as a limited partner; or

fail to make a required capital contribution to the extent of the required capital contribution.

In addition, you may be required to return any distribution you receive from the partnership if you knew at the time the distribution was made that it was improper because it rendered the partnership insolvent.

Amendments

Amendments to the partnership agreement of the partnership may be proposed in writing by:

the managing general partner and adopted with the consent of investors whose units equal a majority of the total units in the partnership; or

investors whose units equal 10% or more of the total units in the partnership and adopted by an affirmative vote of investors whose units equal a majority of the total units in the partnership.

The partnership agreement of the partnership may also be amended by the managing general partner without the consent of the investors for certain limited purposes. However, an amendment that materially and adversely affects the investors can only be made with the consent of the affected investors. For example, an amendment may not do the following without the approval of the investors:

increase the duties or liabilities of the investors;

decrease the duties or liabilities of the managing general partner;

decrease the investors’ profit sharing interest;

increase the investors’ loss sharing interest;

increase the required capital contribution of the investors; or

decrease the required capital contribution of the managing general partner.

Also, any amendment may not affect the classification of partnership income and loss for federal income tax purposes without the unanimous approval of all investors.

Notice

The following provisions apply regarding notices:

when the managing general partner gives you and other investors notice it begins to run from the date of mailing the notice and is binding even if it is not received;

the notice periods are frequently quite short, a minimum of 22 calendar days, and apply to matters that may seriously affect your rights; and

if you fail to respond in the specified time to the managing general partner’s second request for approval of or concurrence in a proposed action, then you will conclusively be deemed to have approved the action unless the partnership agreement expressly requires your affirmative approval.

Voting Rights

Other than as set forth below, you generally will not be entitled to vote on any partnership matters at any partnership meeting. At any time, however, investors whose units equal 10% or more of the total units in the partnership may call a meeting to vote, or vote without a meeting, on the matters set forth below without the concurrence of the managing general partner. On the matters being voted on you are entitled to one vote per unit or if you own a fractional unit that fraction of one vote equal to the fractional interest in the unit. Investors whose units equal a majority of the total units in the partnership may vote to:

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dissolve the partnership;

remove the managing general partner and elect a new managing general partner;

elect a new managing general partner if the managing general partner elects to withdraw from the partnership;

remove the operator and elect a new operator;

approve or disapprove the sale of all or substantially all of the partnership’s assets;

cancel any contract for services with the managing general partner, the operator, or their affiliates without penalty on 60 days notice; and

amend the partnership agreement, however, any amendment may not:

without the approval of you or the managing general partner increase the duties or liabilities of you or the managing general partner, or increase or decrease the profits or losses or required capital contribution of you or the managing general partner; or

without the unanimous approval of all investors in the partnership, affect the classification of partnership income and loss for federal income tax purposes.

The managing general partner, its officers, directors, and affiliates may also subscribe for units in the partnership on a discounted basis, and they may vote on all matters, including the issues set forth above, other than:

removing the managing general partner and operator; and

any transaction between the managing general partner or its affiliates and the partnership.

Any units owned by the managing general partner and its affiliates will not be included in determining the requisite number of units necessary to approve any partnership matter on which the managing general partner and its affiliates may not vote or consent.

Access to Records

You will have access to all records of your partnership at any reasonable time on adequate notice. However, logs, well reports, and other drilling and operating data may be kept confidential for reasonable periods of time. Also, your ability to obtain the list of investors is subject to additional requirements set forth in the partnership agreement.

Withdrawal of Managing General Partner

After 10 years the managing general partner may voluntarily withdraw as managing general partner of your partnership for any reason by giving 120 days’ written notice to you and the other investors in the partnership. Although the withdrawing managing general partner is not required to provide a substitute managing general partner, a new managing general partner may be substituted by the affirmative vote of investors whose units equal a majority of the total units in the partnership. If the investors, however, choose not to continue the partnership and do not select a substitute managing general partner, then the partnership would dissolve and terminate, which could result in adverse tax and other consequences to you.

Also, the managing general partner may assign its general partner interest in the partnership to its affiliates, and it may withdraw a property interest in the form of a working interest in the partnership’s wells equal to or less than its revenue interest at any time if the withdrawal is:

to satisfy the bona fide request of its creditors; or

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approved by investors in the partnership whose units equal a majority of the total units.

(See “Management – Managing General Partner and Operator” and “Conflicts of Interest – Conflicts Regarding the Managing General Partner Withdrawing or Assigning an Interest.”

Return of Subscription Proceeds if Funds Are Not Invested in Twelve Months

Although the managing general partner anticipates that your partnership will spend all of its subscription proceeds soon after the offering of the partnership closes, the partnership will have 12 months in which to use or commit its subscription proceeds to drilling activities. If within the 12-month period the partnership has not used, or committed for use, all of its subscription proceeds, then the managing general partner will distribute the remaining subscription proceeds to you and the other investors in the partnership in accordance with your respective subscription amounts as a return of capital.

SUMMARY OF DRILLING AND OPERATING AGREEMENT

The managing general partner will serve as the operator under the drilling and operating agreement, Exhibit (II) to the partnership agreement. The operator may be replaced at any time on 60 days’ advance written notice by the managing general partner acting on behalf of your partnership on the affirmative vote of investors whose units equal a majority of the total units in the partnership. You are urged to thoroughly review the drilling and operating agreement before you decide to invest in the partnership. The following is a summary of the material provisions of the drilling and operating agreement that are not covered elsewhere in this prospectus. Thus, this prospectus summarizes all of the material provisions of the drilling and operating agreement.

The drilling and operating agreement includes the material provisions set forth below.

The operator’s right to resign after five years.

The operator’s right beginning one year after your partnership well begins producing to retain $200 per month to cover future plugging and abandonment costs of the well.

The grant of a first lien and security interest in the wells and related production to secure payment of amounts due to the operator by your partnership.

The prescribed insurance coverage to be maintained by the operator.

Limitations on the operator’s authority to incur extraordinary costs with respect to producing wells in excess of $5,000 per well.

Restrictions on your partnership’s ability to transfer its interest in fewer than all wells unless the transfer is of an equal undivided interest in all of the wells.

The limitation of the operator’s liability to your partnership under §4.05 of the partnership agreement, which provides that the operator will not have any liability for any loss suffered by the partnership or the participants which arises out of any action or inaction of the operator if the operator determined in good faith that the course of conduct was in the best interest of the partnership, the operator was performing services for the partnership and the operator’s course of conduct did not constitute negligence or misconduct.

The excuse for nonperformance by the operator due to force majeure which generally means acts of God, catastrophes and other causes which preclude the operator’s performance and are beyond its control.

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REPORTS TO INVESTORS

Under the partnership agreement for your partnership you and certain state securities commissions will be provided the reports and information set forth below for your partnership, which your partnership will pay as a direct cost.

Beginning with the calendar year in which your partnership closes, you will be provided an annual report within 120 days after the close of the calendar year, and beginning with the following calendar year, a report within 75 days after the end of the first six months of its calendar year, containing at least the following information.

Audited financial statements of the partnership prepared on an accrual basis in accordance with generally accepted accounting principles with a reconciliation for information furnished for income tax purposes. Independent certified public accountants will audit the financial statements to be included in the annual report, but semiannual reports will not be audited.

A summary of the total fees and compensation paid by the partnership to the managing general partner, the operator, and their affiliates. In this regard, the independent certified public accountant will provide written attestation annually, which will be included in the annual report, that the method used to make allocations was consistent with the method described in §4.04(a)(2)(c) of the partnership agreement and that the total amount of costs allocated did not materially exceed the amounts described in §4.04(a)(2)(c) of the partnership agreement.

If the managing general partner subsequently decides to allocate expenses in a manner different from that described in §4.04(a)(2)(c) of the partnership agreement, then the change must be reported to you and the other investors with an explanation of the reason for the change and the basis used for determining the reasonableness of the new allocation method.

A description of each prospect owned by the partnership, including the cost, location, number of acres, and the interest.

A list of the wells drilled or abandoned by the partnership indicating:

whether each of the wells has or has not been completed; and

a statement of the cost of each well completed or abandoned.

A description of all farmouts, farmins, and joint ventures.

A schedule reflecting:

the total partnership costs;

the costs paid by the managing general partner and the costs paid by the investors;

the total partnership revenues; and

the revenues received or credited to the managing general partner and the revenues received or credited to you and the other investors.

On request the managing general partner will provide you the information specified by Form 10-Q (if that report is required to be filed with the SEC) within 45 days after the close of each quarterly fiscal period. Also, this information is available at the SEC website www.sec.gov.

By March 15 of each year you will receive the information that is required for you to file your federal and state income tax returns.

Beginning with the second calendar year after your partnership closes, and every year thereafter, you will receive a computation of the partnership’s total natural gas and oil proved reserves and its dollar value. The reserve computations will be based on engineering reports prepared by the managing general partner and reviewed by an independent expert.

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PRESENTMENT FEATURE

Beginning with the fifth calendar year after the offering of units in your partnership closes, you and the other investors in your partnership may present your units to the managing general partner to purchase your units. However, you are not required to offer your units to the managing general partner, and you may receive a greater return if you retain your units. The managing general partner will not purchase less than one unit unless the fractional unit represents your entire interest in the partnership.

The managing general partner has no obligation or intention to establish a reserve to satisfy the presentment feature and it may immediately suspend the presentment obligation by notice to you if it determines, in its sole discretion, that it:

does not have the necessary cash flow; or

cannot borrow funds for this purpose on terms it deems reasonable.

If fewer than all units presented at any time are to be purchased by the managing general partner, then the units to be purchased will be selected by lot.

The managing general partner’s obligation to purchase the units presented may be discharged for its benefit by a third-party or an affiliate. If you sell your unit it will be transferred to the party who pays for it, and you will be required to deliver an executed assignment of your unit along with any other documents that the managing general partner requests. Your presentment of your units to the managing general partner for purchase is subject to the following conditions:

the managing general partner will not purchase more than 5% of the total outstanding units in the partnership in any calendar year;

your presentment request must be made within 120 days of the partnership reserve report discussed below;

in accordance with Treas. Reg. §1.7704-1(f) the managing general partner may not purchase your units until at least 60 calendar days after you notify the partnership in writing of your intent to present your units for purchase; and

the purchase of your units will not be considered effective until the presentment price has been paid to you in cash.

The amount of the presentment price for your units that is attributable to the partnership’s natural gas and oil reserves, as discussed below, will be determined based on the last reserve report prepared by the managing general partner and reviewed by an independent expert. Beginning with the second calendar year after your partnership closes and every year thereafter, the managing general partner will estimate the present worth of future net revenues attributable to your partnership’s interest in proved reserves. In making this estimate, the managing general partner will use:

a 10% discount rate;

a constant oil price; and

base natural gas prices on the existing natural gas contracts at the time of the presentment.

Your presentment price will be based on your share of your partnership’s net assets and liabilities as described below, based on the ratio that your number of units bears to the total number of units in your partnership. The presentment price will include the sum of the following partnership items:

an amount based on 70% of the present worth of future net revenues from the proved reserves determined as described above;

cash on hand;

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prepaid expenses and accounts receivable, less a reasonable amount for doubtful accounts; and

the estimated market value of all assets not separately specified above, determined in accordance with standard industry valuation procedures.

There will be deducted from the foregoing sum the following partnership items:

an amount equal to all debts, obligations, and other liabilities, including accrued expenses; and

any distributions made to you between the date of your presentment request and the date the presentment price is paid to you. However, if any cash distributed to you by the partnership, after your presentment request was derived from the sale of oil, natural gas, or a producing property, the amount of those cash distributions will be discounted at the same rate used to take into account the risk factors employed to determine the present worth of the partnership’s proved reserves for purposes of determining the reduction of the presentment price.

The presentment price may be further adjusted by the managing general partner for estimated changes from the date of the reserve report discussed above to the date of payment of the presentment price to you due to the following:

the production or sales of, or additions to, reserves and lease and well equipment, sale or abandonment of leases, and similar matters occurring before the presentment request; and

any of the following occurring before payment of the presentment price to you;

changes in well performance;

increases or decreases in the market price of oil, natural gas, or other minerals;

revision of regulations relating to the importing of hydrocarbons;

changes in income, ad valorem, and other tax laws such as material variations in the provisions for depletion; and

similar matters.

As of May 31, 2009, approximately 510 units have been presented to and accepted by the managing general partner for purchase in its previous 59 limited partnerships.

TRANSFERABILITY OF UNITS

Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership Agreement

Your ability to sell or otherwise transfer your units in your partnership is restricted by the securities laws, the tax laws, and the partnership agreement as described below. Also, the sale or other transfer of your units may create negative tax consequences to you as described in “Federal Income Tax Consequences – Disposition of Units.”

First, due to the tax laws, the partnership agreement provides that you will not be able to sell, assign, exchange, or transfer your unit if it would, in the opinion of counsel for the partnership, result in the following:

the termination of your partnership for tax purposes; or

your partnership being treated as a “publicly traded” partnership for tax purposes.

Second, under the partnership agreement sales or other transfers of the units are subject to the following additional limitations:

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except as provided by operation of law, the partnership will recognize the transfer of only one or more whole units unless you own less than a whole unit, in which case your entire fractional interest must be transferred;

the costs and expenses associated with the transfer must be paid by the person transferring the unit;

the transfer documents must be in a form satisfactory to the managing general partner; and

the terms of the transfer must not contravene those of the partnership agreement.

Your transfer of a unit will not:

relieve you of your responsibility for any obligations related to your units under the partnership agreement;

grant rights under the partnership agreement, as among your transferees, to more than one party unanimously designated by the transferees to the managing general partner; nor

require an accounting of the partnership by the managing general partner.

If the assignee of the unit does not become a substituted partner as described below in “– Conditions to Becoming a Substitute Partner,” the transfer will be effective as of midnight of the last day of the calendar month in which it is made or, at the managing general partner’s election, 7:00 A.M. of the following day.

Finally, before you are able to sell, assign, pledge, hypothecate, or transfer your unit the managing general partner, in its sole discretion, may require that you provide an opinion of counsel acceptable to the managing general partner that registration and qualification under any applicable federal or state securities laws are not required.

Conditions to Becoming a Substitute Partner

An assignee of a unit will not be entitled to any of the rights granted to a partner under the partnership agreement, other than the right to receive all or part of the share of the profits, losses, income, gain, credits and cash distributions or returns of capital to which his assignor would otherwise be entitled, unless the assignee becomes a substituted partner in accordance with the provisions set forth below. The conditions to become a substitute partner are as follows:

the assignor gives the assignee the right;

the assignee pays all costs and expenses incurred in connection with the substitution; and

the assignee executes and delivers, in a form acceptable to the managing general partner, the instruments necessary to establish that a legal transfer has taken place and to confirm his agreement to be bound by all of the terms and provisions of the partnership agreement.

A substitute partner is entitled to all of the rights of full ownership of the assigned units, including the right to vote. The partnership will amend its records at least once each calendar quarter to effect the substitution of substituted partners.

PLAN OF DISTRIBUTION

Commissions

The units in your partnership will be offered on a “best efforts” basis by Anthem Securities, which is an affiliate of the managing general partner, acting as dealer-manager of this offering, and by other selected registered broker/dealers that are members of the Financial Industry Regulatory Authority, or FINRA, formerly known as the National Association of Securities Dealers, Inc., or NASD, acting as selling agents. Anthem Securities was formed for the purpose of serving as dealer-manager of partnerships sponsored by the managing general partner and became a FINRA member firm in April, 1997.

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The dealer-manager will manage and oversee the offering of the units as described above. Best efforts generally means that the dealer-manager and selling agents will not guarantee that a certain number of units will be sold. Units may also be sold by the officers and directors of the managing general partner, other than those individuals who are associated persons of Anthem Securities, in those states where they are licensed to do so or are exempt from licensing. All offers and sales of units by the managing general partner’s officers and directors who are not associated persons of Anthem Securities will be made under the SEC safe harbor from broker/dealer registration provided by Rule 3a4-1. In this regard, none of the officers and directors of the managing general partner who may offer and sell units:

is subject to a statutory disqualification, as that term is defined in Section 3(a)(39) of the Act, at the time of his participation;

is compensated in connection with his participation by the payment of commissions or other remuneration based either directly or indirectly on transactions in securities; and

is at the time of his participation an associated person of a broker or dealer.

Also, each of the officers and directors who may offer and sell units:

performs, or is intended primarily to perform at the end of the offering, substantial duties for or on behalf of the managing general partner otherwise than in connection with transactions in securities;

was not a broker or dealer, or an associated person of a broker or dealer, within the preceding 12 months; and

will not participate in selling an offering of securities for any issuer more than once every 12 months, with the understanding that for securities issued pursuant to Rule 415 under Securities Act of 1933, the 12 month period begins with the last sale of any security included within one Rule 415 registration.

Subject to the exceptions described below, the dealer-manager will receive on each unit sold:

a 2.5% dealer-manager fee;

a 7% sales commission; and

an up to .5% reimbursement of the selling agent’s bona fide due diligence expenses.

All of the reimbursement of the selling agents’ bona fide due diligence expenses and generally all of the 7% sales commission will be reallowed by the dealer-manager to the selling agents. With respect to the up to .5% reimbursement of a selling agent’s bona fide due diligence expenses, any bill presented by a selling agent to the dealer-manager for reimbursement of costs associated with its due diligence activities must be for actual costs, including overhead, incurred by the selling agent and may not include a profit margin. It is the responsibility of the managing general partner and the dealer-manager to ensure compliance with the above guideline. If the selling agent provides the dealer-manager an itemized bill for actual due diligence expenses which are in excess of .5%, then the excess over .5% will not be included within the FINRA 10% compensation guideline, but instead will be included within the 4.5% organization and offering cost guideline under FINRA Conduct Rule 2810.

From the 2.5% dealer-manager fee, the dealer-manager may pay the selling agents up to a ..5% marketing fee if they provide marketing support. Additionally, the dealer-manager may use a portion of its dealer-manager fee to pay for permissible non-cash compensation. Under Rule 2810 of the FINRA Conduct Rules, non-cash compensation means any form of compensation received in connection with the sale of the units that is not cash compensation, including but not limited to merchandise, gifts and prizes, travel expenses, meals and lodging. Permissible non-cash compensation includes the following:

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an accountable reimbursement for training and education meetings for associated persons of the selling agents;

gifts that do not exceed $100 per year and are not preconditioned on achievement of a sales target;

an occasional meal, a ticket to a sporting event or the theater, or comparable entertainment which is neither so frequent nor so extensive as to raise any question of propriety and is not preconditioned on achievement of a sales target; and

contributions to a non-cash compensation arrangement between a selling agent and its associated persons, provided that neither the managing general partner nor the dealer-manager directly or indirectly participates in the selling agent’s organization of a permissible non-cash compensation arrangement.

In no event shall the selling agents receive non-cash compensation and marketing fees if they represent more than .5% of the total units sold.

The managing general partner is also using the services of wholesalers who are employed by it or its affiliates and are registered through Anthem Securities. The wholesalers include six Regional Marketing Directors. A portion of the 2.5% dealer-manager fee will be reallowed to the affiliated wholesalers for subscriptions obtained through their efforts and reimbursement of their expenses. The dealer-manager will retain the remainder of the dealer-manager fee not reallowed to the wholesalers or the selling agents as described in the prior paragraph.

The offering will be made in compliance with Rule 2810 of the FINRA Conduct Rules and all compensation, including non-cash compensation, to broker/dealers and wholesalers, regardless of the source, will not exceed 10% of the gross proceeds of the offering plus the .5% reimbursement for bona fide due diligence expenses in each subscription. Also, the offering will be made in compliance with Rule 2810(b)(2)(C) of the FINRA Conduct Rules and the broker/dealers and wholesalers will not execute a transaction for the purchase of units in a discretionary account without the prior written approval of the transaction by the customer. Finally, the offering will be conducted in compliance with SEC Rule 15c2-4.

Subject to the following, you and the other investors will pay $10,000 per unit and generally will share costs, revenues, and distributions in the partnership in proportion to your respective number of units. However, the subscription price for certain investors will be reduced as set forth below:

the subscription price for the managing general partner, its officers, directors, and affiliates, and investors who buy units through the officers and directors of the managing general partner, will be reduced by an amount equal to the 2.5% dealer-manager fee, the 7% sales commission and the .5% reimbursement for bona fide due diligence expenses, which will not be paid with respect to these sales; and

the subscription price for registered investment advisors and their clients, and selling agents and their registered representatives and principals, will be reduced by an amount equal to the 7% sales commission, which will not be paid with respect to these sales.

No more than 5% of the total units in the partnership may be sold with the discounts described above. These investors who pay a reduced price for their units generally will share in the partnership’s costs, revenues, and distributions on the same basis as the other investors who pay $10,000 per unit as discussed in “Participation in Costs and Revenues – Allocation and Adjustment Among Investors.” Although the managing general partner and its affiliates may buy up to 5% of the units, they do not currently anticipate buying any units. If they do buy units, then those units will not be applied towards the minimum subscription proceeds required for the partnership to begin operations.

To help assure an orderly market for the units, the managing general partner, the dealer-manager and the selling agents may use such methods as they deem appropriate to allocate units among interested investors if they anticipate that demand for units will exceed the available supply, provided that no changes to compensation may be made. These methods may include, but will not be limited to:

allocations of units to selling agents;

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priority acceptance of subscriptions from previous investors in partnerships sponsored by the managing general partner;

priority treatment for investors whose subscriptions were declined by earlier partnerships sponsored by the managing general partner because the number of units available was not sufficient to accommodate their subscriptions; or

any other methods as may be approved by the managing general partner.

After the minimum subscription proceeds are received by the partnership and the checks have cleared the banking system, the dealer-manager fee and the sales commissions will be paid to the dealer-manager and selling agents approximately every two weeks until the offering closes.

Indemnification

The dealer-manager is an underwriter as that term is defined in the 1933 Act and the sales commissions and dealer-manager fees will be deemed underwriting compensation. The managing general partner and the dealer-manager have agreed to indemnify each other, and it is anticipated that the dealer-manager and each selling agent will agree to indemnify each other against certain liabilities, including liabilities under the 1933 Act.

SALES MATERIAL

In addition to the prospectus, the managing general partner intends to use the following sales material with the offering of the units:

a brochure entitled “Atlas Resources Public #18-2008 Program”;

an article entitled “Tax Rewards with Oil and Gas Partnerships”;

a brochure entitled “How an Investment in Atlas Resources Public #18-2008 Program Can Help Achieve an Investor’s Tax Objectives”;

an article entitled “AMT – A Little History and Reducing AMT through Natural Gas Partnerships”;

a brochure entitled “Frequently Asked Questions”;

a brochure entitled “Investing in Atlas Resources Public #18-2008 Program”;

an article entitled “Investment Insights – Tax Time”;

a brochure entitled “Outline of Tax Consequences of Oil and Gas Drilling Programs”;

a brochure entitled “The Drilling Process”;

a PowerPoint presentation and script entitled “Atlas Resources Public #18-2008 Program”;

a brochure entitled “Introduction to Shale Gas”;

a brochure entitled “Vertical and Horizontal Fracturing”;

a flyer entitled “Key Tax Points”; and

possibly other supplementary materials.

The managing general partner has not authorized the use of other sales material and the offering of units is made only by means of this prospectus. The sales material is subject to the following considerations:

163

it must be preceded or accompanied by this prospectus;

it is not complete;

it does not contain any information which is inconsistent with this prospectus; and

it should not be considered a part of or incorporated into this prospectus or the registration statement of which this prospectus is a part.

In addition, supplementary materials, including prepared presentations for group meetings, must be submitted to the state administrators before they are used and their use must either be preceded by or accompanied by a prospectus. Also, all advertisements of, and oral or written invitations to, “seminars” or other group meetings at which the units are to be described, offered, or sold will clearly indicate the following:

that the purpose of the meeting is to offer the units for sale;

the minimum purchase price of the units;

the suitability standards to be employed; and

the name of the person selling the units.

Also, no cash, merchandise, or other items of value may be offered as an inducement to you or any other prospective investor to attend the meeting. All written or prepared audiovisual presentations, including scripts prepared in advance for oral presentations to be made at the meetings, must be submitted to the state administrators within a prescribed review period. These provisions, however, will not apply to meetings consisting only of the registered representatives of the selling agents.

You should rely only on the information contained in this prospectus in making your investment decision. No one is authorized to provide you with information that is different.

LEGAL OPINIONS

Kunzman & Bollinger, Inc., has issued its opinion to the managing general partner regarding the validity and due issuance of the units, including assessibility, and its opinion on the material and any significant federal tax issues involving individual typical investors in the partnership. However, the factual statements in this prospectus are those of the partnership or the managing general partner, and counsel has not given any opinions with respect to any of the tax or other legal aspects of this offering except as expressly set forth above.

EXPERTS

The financial statements included in this registration statement and related prospectus as of December 31, 2008 and 2007 for each of the three years in the period ended December 31, 2008 for Atlas Resources, LLC, the managing general partner, and the balance sheet for Atlas Resources Public #18-2009(C) L.P. as of June 9, 2009, have been so included in reliance upon the reports of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing in giving said reports.

The information concerning the estimated future net cash flows from proved reserves presented under “Prior Activities – Table 3 Investor Operating Results-Including Expenses” was prepared by Wright & Company, Inc., Brentwood, Tennessee, independent petroleum consultants, which is not affiliated with the managing general partner or its affiliates, and is included in this prospectus in reliance on Wright & Company, Inc. as an expert in petroleum consulting.

The geologic evaluations of DC Energy Consultants, Inc., which is not affiliated with the managing general partner or its affiliates, appearing elsewhere in this prospectus have been included in this prospectus on the authority of DC Energy Consultants, Inc. as an expert with respect to the matters covered by the evaluations and in the giving of the evaluations.

164

LITIGATION

On June 20, 2008, the managing general partner’s affiliate, Atlas America, LLC, was named as a co-defendant in the matter captioned CNX Gas Company, LLC (“CNX”) v. Miller Petroleum, Inc. (“Miller”), et al. (Chancery Court, Campbell County, Tennessee). In its complaint, CNX alleged that Miller breached a contract to assign to CNX certain leasehold rights representing approximately 30,000 acres in Campbell County, Tennessee and that ATN and another defendant, Wind City Oil & Gas, LLC, interfered with the closing of this assignment on June 6, 2008. ATN purchased the leases from Miller for approximately $19.1 million. On December 15, 2008, the Chancery Court dismissed the matter in its entirety, holding that there had been no breach of the contract by Miller and, therefore, that Atlas America could not have tortiously interfered with the contract. The Chancery Court dismissed all claims against Atlas America. CNX has appealed the decision.

Following the announcement of the merger agreement between Atlas America and ATN on April 27, 2009, as discussed in “Management – Managing General Partner and Operator,” the following actions have been filed in Delaware Chancery Court purporting to challenge the merger:

Alonzo v. Atlas Energy Resources, LLC, et al., C.A. No. 4553-VCN (Del. Ch. filed 4/30/09);

Operating Engineers Constructions Industry and Miscellaneous Pension Fund v. Atlas America, Inc., et al., C.A. No. 4589-VCN (Del. Ch. filed 5/13/09);

Vanderpool v. Atlas Energy Resources, LLC, et al., C.A. No. 4604-VCN (Del. Ch. filed 5/15/09);

Farrell v. Cohen, et al., C.A. No. 4607-VCN (Del. Ch. filed 5/19/09); and

Montgomery County Employees’ Retirement Fund v. Atlas Energy Resources, L.L.C., et al., C.A. No. 4613-VCN (Del. Ch. filed 5/21/09).

All the plaintiffs other than Farrell moved for an order consolidating all the lawsuits and designating Operating Engineers and Montgomery County as lead plaintiffs. That order was granted by Vice Chancellor Noble on June 15, 2009. The five complaints filed to date advance claims of breach of fiduciary duty and/or breach of the ATN operating agreement in connection with the merger agreement and seek monetary damages or injunctive relief, or both. Predicting the outcome of these lawsuits is difficult. An adverse judgment for monetary damages could have a material adverse effect on the operations of the combined company after the merger. A preliminary injunction could delay or jeopardize the completion of the merger, and an adverse judgment granting permanent injunctive relief could indefinitely enjoin completion of the merger. Based on the facts known to date, the defendants believe the claims asserted against them in these five lawsuits are without merit, and intend to defend themselves vigorously against the claims.

FINANCIAL INFORMATION CONCERNING THE MANAGING GENERAL

PARTNER AND ATLAS RESOURCES PUBLIC #18-2009(C) L.P.

Financial information concerning the managing general partner and the third partnership in the program, Atlas Resources Public #18-2009(C) L.P., is reflected in the following financial statements. With respect to the managing general partner’s financial information, the managing general partner was changed from a corporation to a limited liability company in March 2006. (See “Management – Managing General Partner and Operator.”)

The securities offered by this prospectus are not securities of, nor are you acquiring an interest in the managing general partner, its affiliates, or any other entity other than Atlas Resources Public #18-2009(C) L.P.

165

INDEX TO FINANCIAL STATEMENTS

ATLAS RESOURCES PUBLIC #18-2009(C) L.P. FINANCIAL STATEMENT
Report of Independent Registered Public Accounting Firm	F-1
Balance Sheet as of June 9, 2009 (audited)	F-2
Notes to Financial Statement dated June 9, 2009	F-3

ATLAS RESOURCES, LLC CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm	F-8
Balance Sheets as of December 31, 2008 and 2007	F-9
Consolidated Statements of Income for the years ended December 31, 2008, 2007 and 2006	F-10
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2008, 2007 and 2006	F-11
Consolidated Statements of Changes in Member’s Equity for the years ended December 31, 2008, 2007, 2006 and 2005	F-12
Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006	F-13
Notes to Consolidated Financial Statements dated December 31, 2008	F-14

ATLAS RESOURCES, LLC FINANCIAL STATEMENTS (UNAUDITED)
Balance Sheets as of March 31, 2009 (Unaudited) and December 31, 2008 (Audited)	F-34
Statements of Income for the three months ended March 31, 2009 and 2008 (Unaudited)	F-35
Statement of Changes in Member’s Equity for the three months ended March 31, 2009 and 2008 (Unaudited)	F-36
Statements of Cash Flows for the three months ended March 31, 2009 and 2008 (Unaudited)	F-37
Statements of Comprehensive Income (Loss) for the three months ended March 31, 2009 and 2008 (Unaudited)	F-38
Notes to Financial Statements dated March 31, 2009 (Unaudited)	F-39

166

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Atlas Resources Public #18-2009(C) L.P.

We have audited the accompanying balance sheet of Atlas Resources Public #18-2009(C) L.P. (a Delaware Limited Partnership) as of June 9, 2009. This financial statement is the responsibility of the Partnership’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 statement is free of material misstatement. The Partnership 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 Partnership’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 statement, 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 financial statement referred to above presents fairly, in all material respects, the financial position of Atlas Resources Public #18-2009(C) L.P. as of June 9, 2009, in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

July 6, 2009

F-1

Atlas Resources Public #18-2009 (C) L.P.

(A Delaware Limited Partnership)

BALANCE SHEET

June 9, 2009

ASSETS

Cash

100

PARTNER'S CAPITAL

Partner's capital

100

The accompanying notes to financial statement are an integral part of this statement.

F-2

Atlas Resources Public #18-2009 (C) L.P.

(A Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENT

June 9, 2009

1.	ORGANIZATION AND DESCRIPTION OF BUSINESS

Atlas Resources Public #18-2009 (C) L.P. (the “Partnership”) is a Delaware Limited Partnership in which Atlas Resources, LLC (“Atlas Resources”) of Pittsburgh, Pennsylvania (a second-tier wholly-owned subsidiary of Atlas America, Inc., a publicly traded company), will be Managing General Partner ("MGP") and Operator, and subscribers to units will be either Limited Partners or Investor General Partners depending upon their individual elections.

The Partnership will be funded to drill development wells which are proposed to be located in the Marcellus Shale primary area in western Pennsylvania, the New Albany Shale (Indiana) primary area, the North central Tennessee secondary area, and the Antrim Shale secondary area in Michigan. The managing general partner considers a proposed drilling area to be a primary area if it expects to use 10% or more of a partnership’s subscription proceeds to drill wells in the area.

Subscriptions at a cost of $10,000 per unit, subject to discounts for certain investors, generally will be sold using wholesalers and through broker-dealers including Anthem Securities, Inc., an affiliated company, which will receive on each unit sold to an investor, a 2.5% dealer-manager fee, a 7% sales commission and up to a .5% reimbursement of the selling agents’ bona fide due diligence expenses. Commencement of Partnership operations is subject to the receipt of a minimum Partnership subscription of $2,000,000 by December 31, 2009.

2.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Accounting

The Partnership prepares its financial statements in accordance with accounting principles generally accepted in the United States of America.

Oil and Gas Properties

The Partnership will use the successful efforts method of accounting for oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties and to drill and equip wells will be capitalized. Depreciation and depletion will be computed on a field-by field basis by the unit-of-production method based on periodic estimates of oil and gas reserves. Undeveloped leaseholds and proved properties will be assessed periodically or whenever events or circumstances indicate that the carrying amount of these assets may not be recoverable. Proved properties will be assessed based on estimates of future cash flows.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

F-3

Atlas Resources Public #18-2009 (C) L.P.

(A Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENT (continued)

June 9, 2009

3.	FEDERAL INCOME TAXES

The Partnership will not be treated as a taxable entity for federal income tax purposes. Any item of income, gain, loss, deduction or credit would flow through to the partners as though each partner has incurred such item directly. As a result, each partner must take into account his or her pro-rata share under the Partnership agreement of all items of Partnership income and deductions in computing his or her federal income tax liability.

4.	PARTICIPATION IN REVENUES AND COSTS

The Managing General Partner and the investor partners will participate in revenues and costs in the following manner:

	Managing
	General		Investor
	Partner		Partners
Partnership Costs
Organization and offering costs		100%		0%
Lease costs		100%		0%
Intangible drilling costs (1)		0%		100%
Equipment costs		(2)		(2)
Operating costs, administrative costs, direct costs, and all other costs		(3)		(3)

Partnership Revenues
Interest income		(4)		(4)
Equipment proceeds		(2)		(2)
All other revenues including production revenues	(5) (6)		(5) (6)

Participation in deductions and credits
Intangible drilling costs		0%		100%
Depreciation		(2)		(2)
Percentage depletion allowance	(5) (6) (7)		(5) (6) (7)
Marginal well production credits	(5) (6) (7)		(5) (6) (7)

(1)

An amount equal to 85% of the subscription proceeds of investor partners in the Partnership will be used to pay 100% of the intangible drilling costs incurred by the Partnership in drilling and completing its wells.

(2)

An amount equal to 15% of the subscription proceeds of investor partners in the Partnership will be used to pay the majority of the equipment costs incurred by the Partnership in drilling and completing its wells. All equipment costs in excess of that amount will be charged to the MGP. Equipment proceeds, if any, will be credited in the same percentage in which the equipment costs were charged.

(3)

These costs will be charged to the parties in the same ratio as the related production revenues are being credited. These costs also include plugging and abandonment costs of the wells after the wells have been drilled and produced.

(4)

The subscription proceeds will earn interest until they are paid to the managing general partner for use in the Partnership's drilling activities, and will be credited to the investor partners' account and paid not later than the Partnership's first cash distribution from operations. After the subscription proceeds from a closing are transferred to a Partnership account and before they are paid to the MGP for use in a Partnership's natural gas and oil operations, any interest income from temporary investments will be allocated pro rata to the investors in that Partnership providing those subscription proceeds. All other interest income, including interest earned on the deposit of operating revenues, will be credited as natural gas and oil production revenues are credited.

F-4

Atlas Resources Public #18-2009 (C) L.P.

(A Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENT (continued)

June 9, 2009

4.	PARTICIPATION IN REVENUES AND COSTS (continued)

(5)

The MGP and the investor partners in the Partnership will share in all of the Partnership’s other revenues in the same percentage as their respective capital contributions bear to the total Partnership capital contributions except that the managing general partner will receive an additional 10% of the Partnership revenues.

(6)

The actual allocation of Partnership revenues between the managing general partner and the investor partners will vary from the allocation described in (5) above if a portion of the MGP’s Partnership net production revenues is subordinated as described in note 7.

(7)

The percentage depletion allowances and any marginal well production credits will be credited between the MGP and you the other investors in the same percentages as the production revenues are being credited.

5.	TRANSACTIONS WITH ATLAS RESOURCES AND ITS AFFILIATES

The Partnership intends to enter into the following significant transactions with Atlas Resources and its affiliates as provided under the Partnership agreement:

The Partnership will enter into a drilling and operating agreement with the MGP to drill and complete that Partnership's wells for an amount equal to the sum of the following items: (i) the cost of permits, supplies, materials, equipment, and all other items used in the drilling and completion of a well provided by third-parties, or if the foregoing items are provided by affiliates of the managing general partner, then those items will be charged at competitive rates; (ii) fees for third-party services; (iii) fees for services provided by the managing general partner’s affiliates, which will be charged at competitive rates; (iv) an administration and oversight fee of $15,700 per well, which is $62,200 per well in the Marcellus Shale primary area and the (horizontal) north central Tennessee secondary area, $47,000 for the New Albany Shale (Indiana) primary area and $249,000 for the horizontal Marcellus primary area, which will be charged to you and the other investors as part of each well’s intangible drilling costs and the portion of equipment costs paid by you and the other investors; and (v) a mark-up in an amount equal to 18% of the sum of (i), (ii), (iii) and (iv), above, for the managing general partner’s services as general drilling contractor. Notwithstanding, if the managing general partner drills a well for a Partnership that it determines is not an average well in the area because of the well's depth, complexity associated with either drilling or completing the well or as otherwise determined by the managing general partner, the administration and oversight fee for the well described in §4.02(d) (1) (iv) of the Partnership agreement may be increased to a competitive rate as determined by the MGP. This will be proportionately reduced if the Partnership’s working interest in a well is less than 100%. The cost of the wells will include all ordinary and actual costs of drilling, testing and completing the wells.

Atlas Resources will receive an unaccountable, fixed payment reimbursement for its administrative costs at $75 per well per month, which will be proportionately reduced if the Partnership’s working interest in a well is less than 100%.

Atlas Resources will receive well supervision fees at competitive rates for operating and maintaining the wells. Currently the competitive rate is $392 per well per month, other than the Marcellus Shale, the (horizontal) north central Tennessee, and the New Albany Shale (Indiana) areas. Wells drilled to the Marcellus Shale and the horizontal wells in north central Tennessee the competitive rate is $975 per well per month, respectively. The rate for the Michigan wells is $600 per well per month. The supervision fee for wells in the New Albany Shale (Indiana) will be charged a monthly supervision fee of $1,500 per well per month. The well supervision fees will be proportionately reduced if the Partnership’s working interest in a well is less than 100%.

F-5

Atlas Resources Public #18-2009 (C) L.P.

(A Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENT (continued)

June 9, 2009

5.	TRANSACTIONS WITH ATLAS RESOURCES AND ITS AFFILIATES (Continued)

Atlas Resources will charge the Partnership a fee for gathering and transportation at a competitive rate (currently 13% of the natural gas price).

Atlas Resources will contribute all the undeveloped leases necessary to cover each of the Partnership’s prospects and will receive a credit for its capital account in the Partnership equal to the cost of the leases. The anticipated lease costs in the Marcellus Shale, the New Albany Shale (Indiana), the (horizontal) north central Tennessee areas, and the Antrim Shale area in Michigan, will be approximately $20,000 per prospect. Lease costs for Marcellus horizontal wells will be approximately $45,000 and $50,000 for New Albany shale respectively. In other areas with respect to vertical wells the estimated lease costs are approximately $11,310 per prospect. The cost of the leases will be proportionately reduced if the Partnership’s working interest in the prospect is less than 100%).

As the MGP, Atlas Resources will perform all administrative and management functions for the Partnership including billing and collecting revenues and paying expenses. Atlas Resources will be reimbursed for all direct costs expended on behalf of the Partnership.

6.	PURCHASE COMMITMENT

Subject to certain conditions, investor partners may present their interests after five years from the Partnership’s first cash distribution from operations for purchase by the MGP. The MGP is not obligated to purchase more than 5% of the units in any calendar year. In the event that the Managing General Partner is unable to obtain the necessary funds, the MGP may suspend its purchase obligation.

7.	SUBORDINATION OF PORTION OF BY MANAGING GENERAL PARTNER'S NET PRODUCER REVENUE SHARE

The MGP will subordinate up to 50% of its share of production revenues of the Partnership, net of related operating costs, direct costs, administrative costs, and all other costs not specifically allocated, to the receipt by the investor partners of cash distributions from the Partnership equal to at least 10% per unit, based on $10,000 per unit regardless of the actual price paid, determined on a cumulative basis, in each of the first five 12-month periods beginning with the Partnership’s first cash distribution from operations.

8.	INDEMNIFICATION

In order to limit the potential liability of the investor general partners for Partnership liabilities and obligations, Atlas Resources has agreed to indemnify each investor general partner from any liability incurred which exceeds such partner’s share of undistributed Partnership net assets and insurance proceeds.

F-6

Atlas Resources, LLC

Financial Statements

December 31, 2008

F-7

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors

Atlas Resources, LLC

We have audited the accompanying balance sheets of Atlas Resources, LLC (a Pennsylvania limited liability corporation and successor to Atlas Resources, Inc. and subsidiary, hereinafter collectively referred to as Atlas Resources, LLC) as of December 31, 2008 and 2007 and the related consolidated statements of income, changes in member’s equity, cash flows and comprehensive income (loss) for each of the three years in the period ended December 31, 2008. 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 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 audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Atlas Resources, LLC as of December 31, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, the Company recorded a cumulative effect adjustment in 2006 in connection with the adoption of FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations.”

/s/ GRANT THORNTON LLP

Cleveland, Ohio

March 16, 2009

F-8

ATLAS RESOURCES, LLC

BALANCE SHEETS

(in thousands)

	December 31,
	2008		2007
ASSETS
Current assets:
Cash and cash equivalents	$	2,549	$	15,064
Accounts receivable		21,983		18,165
Prepaid expenses and other		10,794		6,363
Current portion of derivative asset due from affiliate		26,313		5,823
Total current assets		61,639		45,415

Property, plant and equipment, net		566,705		355,181
Long-term derivative asset due from affiliate		18,160		871
Goodwill		20,868		20,868
Intangible and other assets, net		1,681		1,946
	$	669,053	$	424,281

LIABILITIES AND MEMBER'S EQUITY
Current liabilities:
Accounts payable	$	17,728	$	10,969
Current portion of long-term debt		—		30
Liabilities associated with drilling contracts		96,700		132,517
Advances from parent		383,507		163,890
Current portion of derivative liability due to affiliate		2,143		137
Accrued liabilities		18,149		12,453
Total current liabilities		518,227		319,996

Asset retirement obligations		15,166		12,359
Long-term debt, less current portion		—		—
Long-term derivative liability due to affiliate		1,927		8,749

Commitments and contingencies

Member's equity:
Accumulated other comprehensive income (loss)		40,403		(2,192	)
Member's capital		93,330		85,369
Total member's equity		133,733		83,177
	$	669,053	$	424,281

See accompanying notes to financial statements.

F-9

ATLAS RESOURCES, LLC

CONSOLIDATED STATEMENTS OF INCOME

(in thousands)

	Years Ended December 31,
	2008			2007		2006
REVENUES
Well construction and completion	$	415,036		$	321,471	$	198,567
Gas and oil production		90,581			69,206		58,120
Well services		11,916			9,205		7,280
Gathering		6,643			8,441		5,610
Administration and oversight		19,142			17,917		11,533
Total revenues		543,318			426,240		281,110

COSTS AND EXPENSES
Well construction and completion		359,609			279,540		172,666
Gas and oil production and exploration		17,706			11,498		8,118
Well services		4,742			4,057		3,337
General and administrative		12,061			8,221		6,127
Fees and reimbursements – parent		104,539			82,541		64,119
Depreciation, depletion and amortization		36,691			25,358		19,542
Income tax benefit (See Note 2)		—			—		(16,261	)
Interest expense - affiliates		381			378		284
Other (income) loss – net		(372	)		150		(75	)
		535,357			411,743		257,857

Net income before cumulative effect of accounting change		7,961			14,497		23,253
Cumulative effect of accounting change		—			—		3,362
Net income	$	7,961		$	14,497	$	26,615

See accompanying notes to financial statements.

F-10

ATLAS RESOURCES, LLC

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

	Years Ended December 31,
	2008			2007			2006

Net income	$	7,961		$	14,497		$	26,615
Other comprehensive income (loss):
Unrealized holding gains (losses) on hedging contracts		47,700			(11,376	)		28,199
Less: reclassification adjustment for gains realized in net income		(5,105	)		(11,135	)		(6,796	)
		42,595			(22,511	)		21,403

Comprehensive income (loss)	$	50,556		$	(8,014	)	$	48,018

See accompanying notes to financial statements.

F-11

ATLAS RESOURCES, LLC

CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY

(in thousands, except share data)

										Accumulated
							Additional			Other											Total
	Common Stock						Paid-In			Comprehensive			Retained			Stockholder’s			Member’s		Member’s
	Shares			Amount			Capital			Income (Loss)			Earnings			Equity			Capital		Equity

Balance, December 31, 2005		200		$	2		$	30,505		$	(1,084	)	$	13,750		$	43,173		$	―	$	―

Conversion of corporation to LLC		(200	)		(2	)		(30,505	)		―			(13,750	)		(43,173	)		44,257		43,173

Other comprehensive income		―			―			―			21,403			―			―			―		21,403

Net income		―			―			―			―			―			―			26,615		26,615

Balance, December 31, 2006		―			―			―			20,319			―			―			70,872		91,191

Other comprehensive loss		―			―			―			(22,511	)		―			―			―		(22,511	)

Net income		―			―			―			―			—			―			14,497		14,497

Balance, December 31, 2007		―			―			―			(2,192	)		―			―			85,369		83,177

Other comprehensive loss		—			—			—			42,595			—			—			—		42,595

Net income		—			—			—			—			—			—			7,961		7,961

Balance, December 31, 2008	$	—		$			$	—		$	40,403		$	—		$	—		$	93,330	$	133,733

See accompanying notes to financial statements.

F-12

ATLAS RESOURCES, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Years Ended December 31,
	2008			2007			2006

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	7,961		$	14,497		$	26,615
Adjustments to reconcile net income to net cash provided by operating activities:
Cumulative effect of accounting change		—			—			(3,362	)
Depreciation, depletion and amortization		36,691			25,358			19,542
Fees and reimbursements from parent		104,539			82,541			64,119
Gain on disposal of assets		(29	)		(20	)		(10	)
Deferred tax benefit		—			—			(16,896	)
Change in operating assets and liabilities:
(Increase) decrease in accounts receivable		(3,818	)		5,320			(11,977	)
Increase (decrease) in accrued liabilities and accounts payable		11,214			6,112			(4,177	)
(Decrease) increase in liabilities associated with drilling contracts		(35,817	)		45,752			16,251
Increase in prepaid expenses and other		(4,431	)		(4,196	)		(65	)
Net cash provided by operating activities		116,310			175,364			90,040

CASH FLOWS USED IN INVESTING ACTIVITIES:
Capital expenditures		(243,723	)		(153,756	)		(68,224	)
Proceeds from sale of assets		31			53			11
Net cash used in investing activities		(243,692	)		(153,703	)		(68,213	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Net payments on borrowings		(30	)		(37	)		(89	)
Net advances (payments) to parent		115,110			(16,657	)		(31,180	)
Other		(213	)		—			—
Net cash provided (used) in financing activities		114,867			(16,694	)		(31,269	)

(Decrease) increase in cash and cash equivalents		(12,515	)		4,967			(9,442	)
Cash and cash equivalents at beginning of period		15,064			10,097			19,539
Cash and cash equivalents at end of period	$	2,549		$	15,064		$	10,097

See accompanying notes to financial statements.

F-13

ATLAS RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2008

NOTE 1 – NATURE OF OPERATIONS

Atlas Resources, LLC (“the Company”), a Pennsylvania limited liability company, is a wholly-owned subsidiary of Atlas Energy Resources, LLC (NYSE:ATN), (the “Parent” or “Atlas Energy”). The Company is engaged in the leasing, development and production of natural gas and oil properties primarily in the Appalachian Basin area. In addition, the Company performs contract drilling and well operation services. The Company’s operations are dependent upon the resources and services provided by Atlas Energy. Atlas Energy conducts its operations through Atlas Energy Operating Company, LLC, its wholly owned subsidiary. The Company is also a leading sponsor of and manages tax-advantaged direct investment partnerships (the “Partnerships”), in which it coinvests to finance the exploitation and development of its acreage. The Company typically is the managing general partner and has a material interest in these partnerships.

Atlas America, Inc. (“Atlas,” NASDAQ:ATLS), in anticipation of an initial public offering of Atlas Energy, formed the Company on March 24, 2006 and Atlas Resources, Inc. was merged into it. The Company became an indirect subsidiary of the newly-formed Atlas Energy. The results of operations up through March 23, 2006 are from Atlas Resources, Inc. and its subsidiary. On the effective date of the merger, the Company became a single member LLC and each common share of Atlas Resources, Inc. was cancelled.

Public Offering of Atlas Energy Resources, LLC

In December 2006, Atlas contributed substantially all of its natural gas and oil assets and its investment partnership management business to Atlas Energy, a then wholly-owned subsidiary. Concurrent with this transaction, Atlas Energy issued 7,273,750 Class B common units, representing a 19.4% ownership interest, in an initial public offering at a price of $21.00 per unit. The net proceeds of approximately $139.9 million after underwriting discounts and commissions were distributed to Atlas in the form of a nontaxable dividend and repayment of debt.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of consolidation

The consolidated financial statements include the accounts of the Company and, prior to its merger with the Company, the accounts of Atlas Resources, Inc., and its wholly owned subsidiary. The Company also owns individual interests in the assets, and is separately liable for its share of the liabilities of energy partnerships, whose activities include only development and production activities. In accordance with established practice in the oil and gas industry, the Company includes its pro-rata share of assets, liabilities, income, and lease operating and general and administrative costs and expenses of the investment partnerships in which it has an interest. Such interests typically range from 15% to 35%. The Company’s financial statements do not include proportional consolidation of the depletion or impairment expenses of the Partnerships. Rather, the Company calculates these items specific to its own economics as further explained under the heading “Oil and Gas Properties” below. All material intercompany transactions have been eliminated.

Use of Estimates

Reclassifications

Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation.

F-14

Cash Equivalents

The Company considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. These cash equivalents consist principally of temporary investments of cash in short-term money market instruments.

Comprehensive Income (Loss)

Comprehensive income (loss) 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 (loss)” and for the Company include only changes in the fair value of unrealized derivative 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 customers’ current creditworthiness, as determined by the Company’s review of its customers’ credit information. The Company extends credit on an unsecured basis to many of its energy customers. At December 31, 2008 and December 31, 2007, the Company’s credit evaluation indicated that it has no need for an allowance for possible losses.

Property, Plant and Equipment

Property, plant, and equipment are stated at cost. Depreciation, depletion and amortization of oil and gas properties is calculated based on cost less estimated salvage value primarily using the unit-of-production method. Other fixed assets are depreciated using the 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, plant, and equipment are as follows:

Buildings and improvements	10-40 years
Furniture and equipment	3-7 years
Other	3-10 years

Property, plant, and equipment consists of the following at the dates indicated (in thousands):

	December 31,
	2008			2007
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	84,065		$	10,673
Wells and related equipment		555,092			410,564
		639,157			421,237
Unproved properties		27,527			463
Support equipment		5,459			3,944
		672,143			425,644
Land, buildings and improvements		4,489			4,080
Other		790			745
		677,422			430,469
Accumulated depreciation, depletion and amortization:		(110,717	)		(75,288	)
	$	566,705		$	355,181

F-15

Oil and Gas Properties

The Company follows the successful efforts method of accounting for oil and gas producing activities. Acquisition costs of leases and development activities are capitalized. 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.

Depletion, depreciation and amortization expense is determined on a field-by-field basis using the units-of-production method, with depletion, depreciation and amortization rates for leasehold acquisition costs based on estimated proved reserves and depletion, depreciation and amortization rates for well and related equipment costs based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include the Company’s costs of property interests in uncontrolled but proportionately consolidated from investment partnerships, wells drilled solely by the Company, properties purchased and working interests with other outside operators.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to income. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and 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.

Goodwill

The Company has recorded goodwill of $20.9 million in connection with several acquisitions of assets. Goodwill and intangibles with infinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. Under the principles of SFAS No. 142, an impairment loss should be recognized if the carrying value of an entity’s reporting units exceeds its estimated fair value. The Company has essentially one reporting unit that combines its Appalachian gas and oil production and partnership management business segments. Because quoted market prices for the Company’s reporting units are not available, the Company must apply judgment in determining the estimated fair value of this reporting unit. The Company uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. In addition, substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity’s individual equity. In most industries, including the Company’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, the Company also considers a control premium to the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in our industry. The resultant fair values calculated for the reporting unit is then compared to observable metrics on large mergers and acquisitions in the Company’s industry to determine whether those valuations appear reasonable in the Company’s judgment. The Company’s evaluation of goodwill at December 31, 2008 and 2007, respectively, indicated there was no impairment loss.

Impairment of Oil and Gas Properties and Long-Lived Assets

The Company’s oil and gas properties and other 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.

F-16

The review of the Company’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation 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 current contracts in place at December 31, 2008, adjusted for basis differentials and 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 the expected future 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.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, the Company’s reserve estimates for its investment in the limited partnerships are based on its own assumptions rather than its proportionate share of the limited partnership’s reserves. These assumptions include the Company’s actual capital contributions, an additional carried interest (generally 7% to 10%), a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs.

The Company’s lower operating and administrative costs result from the limited partners paying to the Company their proportionate share of these expenses plus a profit margin. These assumptions could result in the Company’s calculation of depletion and impairment being different than its proportionate share of the limited partnership’s calculations for these items. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Company cannot predict what reserve revisions may be required in future periods.

The Company’s method of calculating its reserves may result in reserve quantities and values which are greater than those which would be calculated by the Partnerships which the Company sponsors and owns an interest in but does not control. The Company’s reserve quantities include reserves in excess of its proportionate share of reserves in a partnership which the Company may be unable to recover due to the partnership legal structure. The Company may have to pay additional consideration in the future as a well or Partnership becomes uneconomic under the terms of the partnership agreement in order for the Company to recover these excess reserves and to acquire any additional residual interests in the wells held by other partnership investors. The acquisition of any well interest from the Partnership by the Company is governed under the partnership agreement and must be at fair market value supported by an appraisal of an independent expert selected by the Company.

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. There were no impairments of oil and gas properties or unproved properties recorded by the Company for the years ended December 31, 2008, 2007 and 2006, respectively.

Capitalized Interest

The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and gas wells and other capital projects. Interest is capitalized only during the periods in which these assets are brought to their intended use. The weighted average interest rate used to capitalize interest was 7.3% and 6.7% for the years ended December 31, 2008 and 2007, respectively, which resulted in interest capitalized of $4.7 million and $2.6 million, respectively. There was no interest capitalized for the year ended December 31, 2006.

F-17

Asset Retirement Obligations

The Company accounts for asset retirement obligations as required under SFAS No. 143, Accounting for Retirement Asset Obligations (“SFAS 143”). SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, with the associated asset retirement costs being capitalized as a part of the carrying amount of the long-lived asset. The Company has asset retirement obligations related to the plugging and abandonment of its oil and gas wells. SFAS 143 requires the Company to consider estimated salvage value in the calculation of depreciation, depletion, and amortization.

In March 2005, the Financial Accounting Standards Board (“FASB”) issued FIN 47. FIN 47 clarified that the term “conditional asset retirement obligation” as used in SFAS 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Since the obligation to perform the asset retirement activity is unconditional, FIN 47 provides that a liability for the fair value of a conditional asset obligation should be recognized if that fair value can be reasonably estimated, even though uncertainty exists about the timing and/or method of settlement. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of a conditional asset retirement obligation under SFAS 143.

Under SFAS 143, the Company had recorded its asset retirement obligation based on a probability factor which considered the Company’s history of selling its wells or otherwise disposing of them without incurring a disposal cost.

FIN 47 requires the Company to record its retirement obligation without regard to its prior practice and accrue for obligations for all wells owned by the Company without regard to their probability of being sold or otherwise disposed of without incurring a disposal cost. Accordingly, the Company adopted FIN 47 as of December 31, 2006 and recognized $3.4 million in 2006 as a cumulative effect of an accounting change. Additionally, the Company’s Balance Sheet recognized an increase as of December 31, 2006 in its asset retirement obligation of $3.5 million, and a net increase in property, plant, and equipment of approximately $6.9 million.

Had the Company implemented FIN 47 retroactively to October 1, 2002, the following pro forma information summarizes the impact for the periods presented (in thousands):

	December 31,
	2006

Net income as reported	$	26,615
Proforma asset retirement obligation adjustment		915
Proforma net income as adjusted		27,530
Proforma asset retirement obligation	$	9,660

Fair Value of Financial Instruments

The carrying amount of the Company’s financial instruments, including cash and cash equivalents, accounts receivables and accounts payable approximate fair values because of their short maturities and are represented in the Company’s consolidated balance sheets. For further information with regard to the Company’s financial instruments, see “Recently Issued Financial Accounting Standards” and Note 7, Derivative Instruments, “Fair Value of Financial Instruments.”

Derivative Instruments

The Company enters into certain financial contracts to manage its exposure to movement in commodity prices. The Company applies the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No.133”). SFAS No. 133 requires each derivative instrument to be recorded in the balance sheet as either an asset or liability measured at fair value. Changes in a derivative instrument’s fair value are recognized currently in the Company’s consolidated statements of income unless specific hedge accounting criteria are met (see Note 7).

F-18

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 December 31, 2008 and 2006, the Company had $2.7 million and $15.2 million, respectively, in deposits at various banks, of which $2.6 million and $15.1 million, respectively, was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments to date.

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 as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are also 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 years ended December 31, 2008 and 2007, the Company had no environmental contingencies requiring specific disclosure or the recording of a liability.

Revenue Recognition

The Company conducts certain energy activities through, and a portion of its revenues is 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 titled “Liabilities Associated with Drilling Contracts” on its consolidated balance sheets. The Company recognizes gathering revenues at the time the natural gas is delivered, and recognizes well services revenues at the time the services are performed. The Company is also entitled to receive administration and oversight fees according to the respective partnership agreements. The Company recognizes such fees as income when services are performed.

The Company generally sells natural gas and crude oil at prevailing market prices. Revenue is recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil in which the Company has an interest with other producers are recognized on the basis of the Company’s percentage ownership of working interest or overriding royalty. Generally, the Company’s sales contracts are based on pricing provisions that are tied to a market index, with certain adjustments based on proximity to gathering and transmission lines and the quality of its natural gas.

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 December 31, 2008 and 2007 of $15.2 million and $15.6 million, respectively, which are included in accounts receivable on its consolidated balance sheets.

F-19

Supplemental Cash Flow Information

The Company considers temporary investments with a maturity at the date of acquisition of 90 days or less to be cash equivalents. The Company did not pay cash for income taxes in any period presented.

Supplemental disclosure of cash flow information is as follows (in thousands):

	Years Ended December 31,
	2008		2007		2006

Cash paid during the period for:
Interest	$	2	$	405	$	56
Income taxes	$	—	$	—	$	279

Income Taxes

The Company was included in the Federal income tax return of its Parent up through the merger date in March 2006. From January 1, 2006 to March 23, 2006, income taxes were presented as if the Company had filed an income tax return on a separate company basis utilizing its calculated effective rate of 31%. The Company’s effective tax rate was lower than the Federal statutory rate due to the benefit of percentage depletion. Separate company state tax returns are filed in those states in which the Company is registered to do business. The net balance of Atlas Resources, Inc.'s deferred tax liability of $16.9 million was eliminated through a credit to the Company's earnings before taxes in accordance with Financial Accounting Standard Board Statement No. 109, Accounting for Income Taxes ("SFAS 109"). In addition, a tax expense of $635,000 incurred from January 1, 2006 up to the merger at March 23, 2006 was charged to income from operations.

After the merger, the Company became a single member limited liability company, thus no provision for Federal income tax is required because taxable income or loss is included in the tax return of the individual member.

Recently Issued Financial Accounting Standards

The Financial Accounting Standards Board, (“FASB”) recently issued the following standards, which were reviewed by the Company to determine the potential impact on its financial statements upon adoption.

In May 2008, the FASB issued Statement of Financial Accounting Standards No. 162, The Hierarchy of Generally Accepted Accounting Policies ("SFAS 162"), which reorganizes the GAAP hierarchy. The purpose of the new standard is to improve financial reporting by providing a consistent framework for determining what accounting principles should be used when preparing United States Generally Accepted Accounting Principles ("U.S. GAAP") financial statements. The standard is effective 60 days after the SEC's approval of the PCAOB's amendments to AU Section 411. The Company adopted the provisions of SFAS No. 162 on November 15, 2008, and it had no impact on its financial position or results of operations.

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

F-20

In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, Disclosures about Derivative Instruments and Hedging Activities, (“SFAS 161”), an amendment of FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, (“SFAS 133”). SFAS 161 requires entities to provide qualitative disclosures about the objectives and strategies for using derivatives, quantitative data about the fair value of and gains and losses on derivative contracts, and details of credit-risk-related contingent features in their hedged positions. The standard is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged, but not required.

SFAS 161 also requires entities to disclose more information about the location and amounts of derivative instruments in financial statements; how derivatives and related hedges are accounted for under SFAS 133 and how the hedges affect the entity’s financial position, financial performance, and cash flows. The Company will apply the requirements of SFAS 161 on its adoption on January 1, 2009 and does not expect it to have an impact on its financial position or results of operations.

In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, ("SFAS 159"). SFAS 159 permits entities to choose to measure eligible financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. By electing the fair value option in conjunction with a derivative, an entity can achieve an accounting result similar to a fair value hedge without having to comply without complex hedge accounting rules. The statement was effective for the Company as of January 1, 2008. The Company adopted SFAS 159 at January 1, 2008, and has elected not to apply the fair value option to any of its financial instruments not already carried at fair value in accordance with other accounting standards, and therefore the adoption of SFAS 159 did not impact the Company's financial statements for the year ended December 31, 2008.

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair Value Measurement, ("SFAS 157"). SFAS 157 addresses the need for increased consistency in fair value measurements, defining fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. It also establishes a framework for measuring fair value and expands disclosure requirements. In February 2008, the FASB issued FSP FAS 157-2, "Effective date of FASB Statement No. 157," (FSP FAS 157-2"). FSP FAS 157-2, which was effective upon issuance, delays the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value at least once a year, to fiscal years beginning after November 15, 2008. On January 1, 2009, the Company will adopt SFAS 157 for nonfinancial assets and liabilities that are not measured at fair value on a recurring basis. For the Company, the nonfinancial assets and liabilities will be limited to the initial recognition of asset retirement obligations. FSP FAS 157-2 also covers interim periods within the fiscal years for items within its scope. The delay is intended to allow the FASB and its constituents the time to consider the various implementation issues associated with SFAS 157. The Company adopted SFAS 157 as of January 1, 2008 with respect to its commodity derivative instruments which are measured at fair value within its consolidated financial statements. See Note 7 for disclosures pertaining to the provisions of SFAS 157 with regard to the Company’s fair value measurements.

NOTE 3 – INTANGIBLE AND OTHER ASSETS

The following table provides information about intangible and other assets at the dates indicated (in thousands):

	December 31,
	2008			2007
Management and operating contracts	$	6,352		$	6,352
Other		267			54
Total costs		6,619			6,406
Accumulated amortization		(4,938	)		(4,460	)
	$	1,681		$	1,946

F-21

Partnership management and operating contracts which were acquired through previous acquisitions were recorded at fair value on their acquisition dates. The Company amortizes these contracts 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 December 31, 2008 and 2007 were $478,000 and $478,000 respectively.

The aggregate estimated annual amortization expense of partnership management and operating contracts for the next five years ending December 31 is as follows: 2009 – $478,000; 2010 – $478,000 and 2011 – $459,000.

NOTE 4 – ASSET RETIREMENT OBLIGATION

The Company follows SFAS No. 143 and FIN 47 “Accounting for Conditional Asset Retirement Obligations,” which require the Company to recognize an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities. Under SFAS No. 143, the Company must currently recognize a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. SFAS No. 143 requires the Company to consider estimated salvage value in the calculation of depreciation, depletion and amortization.

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

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

	Years Ended December 31,
	2008			2007			2006
Asset retirement obligation, beginning of period	$	12,359		$	9,660		$	6,195
Cumulative effect of adoption of FIN 47								3,480
Liabilities incurred		2,010			2,143			1,570
Liabilities settled		(3	)		(5	)		(23	)
Revisions in estimates		—			—			(2,074	)
Accretion expense		800			561			512
Asset retirement obligation, end of period	$	15,166		$	12,359		$	9,660

The above accretion expense is included in depreciation, depletion, and amortization in the Company's statements of income.

F-22

NOTE 5 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Relationship with Atlas Energy

Advances from parent shown on the Company’s balance sheets represents amounts owed for advances and other transactions in the normal course of business. The Company depends on its parent company, Atlas Energy and its affiliates for all management and administrative functions. The Company pays a management fee of 7% of subscription funds raised and reimburses Atlas Energy for management and administrative services and expenses, including interest expense, incurred on its behalf based on an allocation of total revenues. Such fees and reimbursements amounted to $104.5 million and $82.5 million for the years ended December 31, 2008 and 2007, respectively. This fee and expense reimbursement is shown as Fees and reimbursements-affiliate on the Company’s statements of income. The advances are subordinated to any third party debt. The Company incurred interest expense related to intercompany transactions for the years ended December 31, 2008 and 2007 of $379,000 and $378,000, respectively.

Relationship with Company Sponsored Investment Partnerships

The Company conducts certain activities through, and a substantial portion of its revenues are attributable to, the 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.

NOTE 6 –- COMMITMENTS AND CONTINGENCIES

General Commitments

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

Legal Proceedings

On June 20, 2008, a subsidiary of the Parent, Atlas America, LLC, was named as a co-defendant in the matter captioned CNX Gas Company, LLC (“CNX”) v. Miller Petroleum, Inc. (“Miller”), et al. (Chancery Court, Campbell County, Tennessee). In its complaint, CNX alleges that Miller breached a contract to assign to CNX certain leasehold rights, ("Leases") representing approximately 30,000 acres in Campbell County, Tennessee and that the Parent and another defendant, Wind City Oil & Gas, LLC, interfered with the closing on this assignment on June 6, 2008. The Parent purchased the Leases from Miller, for approximately $19.1 million. On December 15, 2008, the Chancery Court dismissed the matter in its entirety, holding that there had been no breach of the contract by Miller and, therefore, that Atlas Energy could not have tortuously interfered with the contract. The Chancery Court dismissed all claims against Atlas America, LLC; however, CNX has appealed this decision.

The Company is 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 position or results of operations.

F-23

NOTE 7 – DERIVATIVE INSTRUMENTS

From time to time, Atlas Energy enters into natural gas and crude oil future option contracts and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in natural gas prices and oil 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. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.

The Company has a $40.4 million unrealized net asset related to financial derivatives on its gas and oil production at December 31, 2008, compared to a net unrealized liability of $2.2 million at December 31, 2007. If the fair values of the instruments remain at current market values, the Company will reclassify $24.2 million of unrealized gains to its consolidated statements of income over the next twelve-month period as these contracts settle and $16.2 million of unrealized gains will be reclassified in later periods.

The Company recognized a loss of $4.8 million and gains of $11.1 million and $6.8 million on settled contracts covering natural gas production for the years ended December 31, 2008, 2007 and 2006, respectively. The Company recognized a loss of $299,000 on settled oil production for the year ended December 31, 2008, and there were no gains or (losses) on oil settlements for the years ended December 31, 2007 and 2006. These gains and losses are included with gas and oil production in the Company’s consolidated statements of income. As the underlying prices and terms in the Company’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the years ended December 31, 2008, 2007 and 2006 for derivative ineffectiveness or as a result of the discontinuance of any cash flow hedges.

At December 31, 2008, Atlas Energy had allocated the following natural gas and oil volumes hedged on behalf of the Company:

Natural Gas Fixed Price Swaps

Twelve Month			Average
Period Ending	Volumes		Fixed Price		Fair Value
December 31,	(MMbtu) (1)		(per MMbtu)		Asset (2)
					(in thousands)

2009		8,737,000	$	8.55	$	21,371
2010		6,041,000		8.11		5,853
2011		4,281,000		7.84		2,216
2012		3,163,000		8.05		2,487
2013		344,000		8.73		481

					$	32,408

F-24

Natural Gas Costless Collars

Twelve Month				Average
Period Ending	Option	Volumes		Floor & Cap		Fair Value
December 31,	Type	(MMbtu) (1)		(per MMbtu)		Asset (2)
						(in thousands)

2009	Puts purchased		55,000	$	11.00	$	271
2009	Calls sold		55,000		15.35		—
2010	Puts purchased		770,000		7.84		766
2010	Calls sold		770,000		9.01		—
2011	Puts purchased		1,719,000		7.48		850
2011	Calls sold		1,719,000		8.44		—
2012	Puts purchased		234,000		7.00		51
2012	Calls sold		234,000		8.32		—
2013	Puts purchased		69,000		7.00		16
2013	Calls sold		69,000		8.25		—
						$	1,954

Crude Oil Fixed Price Swaps

Twelve Month			Average
Period Ending	Volumes		Fixed Price		Fair Value
December 31,	(Bbl)		(per Bbl)		Asset (3)
					(in thousands)

2009		38,000	$	100.14	$	1,768
2010		31,000		97.40		1,030
2011		27,000		96.44		723
2012		21,000		96.00		497
2013		6,000		96.06		140

					$	4,158

F-25

Crude Oil Costless Collars

Twelve Month				Average
Period Ending	Option	Volumes		Floor & Cap		Fair Value
December 31,	Type	(Bbl)		(per Bbl)		Asset (3)
						(in thousands)

2009	Puts purchased		23,100	$	85.00	$	761
2009	Calls sold		23,100		118.63		—
2010	Puts purchased		19,600		85.00		478
2010	Calls sold		19,600		112.92		—
2011	Puts purchased		17,100		85.00		341
2011	Calls sold		17,100		110.81		—
2012	Puts purchased		13,600		85.00		240
2012	Calls sold		13,600		110.06		—
2013	Puts purchased		3,800		85.00		63
2013	Calls sold		3,800		110.09		—
						$	1,883

				Total Net Asset		$	40,403

(1)	MMBTU represents million British Thermal Units.

(2)	Fair value based on forward NYMEX natural gas prices.

(3)	Fair value based on forward WTI crude oil prices.

The fair value of the derivatives is included in the Company's Balance Sheets at the dates indicated (in thousands):

	December 31,
	2008			2007
Current portion of derivative asset	$	26,313		$	5,823
Long-term derivative asset		18,160			871
Current portion of derivative liability		(2,143	)		(137	)
Long-term derivative liability		(1,927	)		(8,749	)
	$	40,403		$	(2,192	)

Fair Value of Financial Instruments

Derivative Instruments

The Company adopted the provisions of SFAS No. 157 at January 1, 2008. SFAS No. 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS No. 157’s hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1– Quoted prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

Level 3 – Unobservable inputs that reflect the entity’s own assumptions about the assumptions that market participants would use in the pricing of the asset or liability and are consequently not based on market activity, but rather through particular valuation techniques.

F-26

The Company uses the fair value methodology outlined in SFAS No. 157 to value the assets and liabilities for its outstanding derivative contracts. All of the Company’s derivative contracts are defined as Level 2. The Company’s natural gas and crude oil derivative contracts are valued based on prices quoted on the NYMEX or WTI and adjusted by the respective counterparty using various assumptions including quoted forward prices, time value, volatility factors, and contractual prices for the underlying instruments. In accordance with SFAS No. 157, the following table represents the Company’s fair value hierarchy for its financial instruments at December 31, 2008 (in thousands):

	Level 2		Total
Commodity-based derivatives	$	40,403	$	40,403
Total	$	40,403	$	40,403

Other Financial Instruments

The estimated fair value of the Company’s other financial instruments has been determined based upon its assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that the Company could realize upon the sale or refinancing of such financial instruments. The Company’s other current assets and liabilities on its consolidated balance sheets are financial instruments and their estimated fair value approximate their carrying amounts due to their short-term nature.

NOTE 8 – ACQUISITION OF DTE GAS & OIL COMPANY BY ATLAS ENERGY

On June 29, 2007, Atlas Energy acquired all of the outstanding equity interests of DTE Gas & Oil Company (“DGO”) from DTE Energy Company (NYSE:DTE) and MCN Energy Enterprises for $1.273 billion, including adjustments for working capital of $15.0 million and current year capital expenditures of $19.0 million. Assets acquired include interests in approximately 2,150 natural gas wells with estimated proved reserves of approximately 613.7 billion cubic feet of natural gas equivalents, located in the northern lower peninsula of Michigan, 228,000 developed acres and 66,000 undeveloped acres. Subsequent to the acquisition of DGO, Atlas Energy changed its name to Atlas Gas & Oil Company (“AGO”).

To fund the acquisition, Atlas Energy borrowed $713.9 million on its new credit facility and completed a private placement of 7,298,181 Class B common units and 16,702,828 Class D units to a group of institutional investors at a weighted average price of $25.00 per unit for net proceeds of $597.5 million. Proceeds of $52.5 million were used to pay the outstanding balance of Atlas Energy's credit facility with Wachovia Bank.

NOTE 9 – ATLAS ENERGY LONG-TERM DEBT

Atlas Energy Credit Facility

Upon the closing of its acquisition of DTE Gas & Oil, the Parent replaced its credit facility with a new 5-year credit facility with an initial borrowing base of $850.0 million with J.P. Morgan Chase Bank, N.A. (“J.P. Morgan”) as administrative agent, Wachovia Bank, N. A. as syndication agent, and other lenders. The borrowing base is redetermined semiannually on April 1 and October 1 subject to changes in the Parent’s oil and gas reserves and reduced by 25% of the amount of any issuance of senior unsecured notes by the Parent. The borrowing base at December 31, 2008 is $697.5 million. Up to $50.0 million of the facility may be in the form of standby letters of credit. The facility is secured by substantially all of the Parent’s assets and is guaranteed by each of the Parent’s subsidiaries (other than Anthem Securities, Inc.) and bears interest at either the base rate plus the applicable margin or at adjusted LIBOR plus the applicable margin, elected at the Parent’s option. At December 31, 2008 and 2007, the weighted average interest rate on outstanding borrowings was 2.9% and 7.2%, respectively. The weighted average interest rate for the years ended December 31, 2008 and 2007 was 4.5% and 7.2%, respectively.

The base rate for any day equals the higher of the federal funds rate plus 0.50% or the J.P. Morgan prime rate. Adjusted LIBOR is LIBOR divided by 1.00 minus the percentage prescribed by the Federal Reserve Board for determining the reserve requirement for Eurocurrency liabilities. The applicable margin ranges from 0.0% to 0.75% for base rate loans and 1.00% to 1.75% for LIBOR loans.

F-27

The credit facility requires the Parent to maintain specified financial ratios as defined in the credit agreement of current assets to current liabilities of not less than 1.0 to 1.0 and a debt to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”) ratio of 4.0 to 1.0, decreasing to 3.75 to 1.0 commencing January 1, 2009, and decreasing to 3.5 to 1.0 commencing January 1, 2010. According to the definitions contained in the Parent’s credit facility, the Parent’s ratio of current assets to current liabilities was 1.60 to 1.0 and its ratio of total debt to EBITDA was 2.89 to 1.0 at December 31, 2008.

In addition, the credit agreement limits sales, leases or transfers of assets and the incurrence of additional indebtedness. The credit agreement limits the distributions payable by the Parent if an event of default has occurred and is continuing or would occur as a result of such distribution. The Parent is in compliance with these covenants as of December 31, 2008. The facility terminates in June 2012, when all outstanding borrowings must be repaid. At December 31, 2008 and December 31, 2007, $467.0 million and $740.0 million, respectively, were outstanding under this facility. In addition, letters of credit of $1.2 million and $1.1 million were outstanding at each date, which are not reflected as borrowings on the Parent’s consolidated balance sheets.

Atlas Energy Senior Unsecured Notes

In January 2008, the Parent completed a private placement of $250.0 million of its 10.75% senior unsecured notes (“Senior Notes”) due 2018 to institutional buyers pursuant to rule 144A under the Securities Act of 1933. In May 2008, the Parent issued an additional $150.0 million of Senior Notes at 104.75% to par to yield 9.85% to the par call on February 1, 2016. The Parent intends to treat these issuances as a single class of debt securities, which were subsequently registered for resale on September 19, 2008. The Parent received proceeds of approximately $398.0 million from these offerings, including a $7.1 million premium and net of $9.2 million in underwriting fees. In addition, the Parent received approximately $4.7 million related to accrued interest. The Parent used the net proceeds to reduce the balance outstanding on its revolving credit facility. Interest on the Senior Notes is payable semi-annually in arrears on February 1 and August 1 of each year. The Senior Notes are redeemable at any time at specified redemption prices, together with accrued and unpaid interest to the date of redemption. In addition, before February 1, 2011, the Parent may redeem up to 35% of the aggregate principal amount of the Senior Notes with the proceeds of equity offerings at a stated redemption price. The Senior Notes are also subject to repurchase by the Parent at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if the Parent does not reinvest the net proceeds within 360 days. The Senior Notes are junior in right of payment to the Parent’s secured debt, including its obligations under its credit facility. The indenture governing the Senior Notes contains covenants, including limitations of the Parent’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets. The Parent is in compliance with the covenants as of December 31, 2008.

NOTE 10 – SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Results of operations from oil and gas producing activities for the periods indicated are as follows (in thousands):

	Years Ended December 31,
	2008			2007			2006
Revenues	$	90,581		$	69,206		$	58,120
Production costs		(17,706	)		(11,498	)		(8,118	)
Exploration expenses (1)		(2,208	)		(1,831	)		(5	)
Income taxes		—			—			—
Depreciation, depletion and amortization		(35,182	)		(24,154	)		(18,489	)
Results of operations from oil and gas producing activities	$	35,485		$	31,723		$	31,508

(1) Represents the Company’s land and leasing activities.

F-28

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 (in thousands):

	At December 31,
	2008			2007
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	84,065		$	10,673
Wells and related equipment		555,092			410,564
		639,157			421,237
Unproved properties		27,527			463
Support equipment		5,459			3,944
		672,143			425,644
Accumulated depreciation, depletion and amortization:		(107,211	)		(72,814	)
	$	564,932		$	352,830

Costs Incurred in Oil and Gas Producing Activities. The costs incurred by the Company in its oil and gas activities during the periods indicated are as follows (in thousands):

	Years Ended December 31,
	2008		2007		2006
Property acquisition costs:
Proved properties	$	43,737	$	9,618	$	—
Unproved properties		27,064		—		—
Exploration costs (1)		2,208		1,831		5
Development costs		174,169		141,657		78,575
	$	247,178	$	153,106	$	78,580

(1) Represents the Company’s land and leasing activities.

The development costs above for the periods noted 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. 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.

F-29

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.

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.

F-30

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

	Gas			Oil
	(Mcf)			(Bbls)
Balance December 31, 2005		108,434,747			234,386
Extensions, discoveries and other additions		46,198,871			12,384
Sales of reserves in-place		(48,765	)		(703	)
Purchase of reserves in-place		130,896			66
Transfers to limited partnerships		(6,671,754	)		(19,235	)
Revisions		(17,852,149	)		(96,195	)
Production		(5,781,832	)		(26,406	)
Balance December 31, 2006		124,410,014			104,297
Extensions, discoveries and other additions (1)		68,473,867			23,362
Sales of reserves in-place		(33,688	)		—
Purchase of reserves in-place		643,255			1,509
Transfers to limited partnerships		(11,507,307	)		—
Revisions		(921,557	)		47,052
Production		(6,789,549	)		(31,084	)
Balance December 31, 2007		174,275,035			145,136
Extensions, discoveries and other additions (1)		195,950,548			109,375
Sales of reserves in-place		(29,208	)		—
Purchase of reserves in-place		14,902			54
Transfers to limited partnerships		(6,026,785	)		—
Revisions (2)		(32,802,816	)		32,942
Production		(8,543,403	)		(30,789	)
Balance December 31, 2008		322,838,273			256,718

Proved developed reserves at:
December 31, 2005		59,185,072			99,743
December 31, 2006		63,551,783			100,927
December 31, 2007		87,954,996			139,551
December 31, 2008		99,328,083			208,674

(1)	Includes a significant increase in reserves due to the addition of proved undeveloped reserves for Marcellus wells.

(2)	Represents a decrease of the year-end price of natural gas and oil compared to the price of natural gas and oil at the beginning of the year.

F-31

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 the period ends indicated below 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 December 31,
	2008			2007			2006
Future cash inflows	$	2,085,600		$	1,344,398		$	823,988
Future production costs		(822,603	)		(393,710	)		(202,451	)
Future development costs		(463,353	)		(208,483	)		(149,583	)
Future income tax expense		—			—			—
Future net cash flows		799,644			742,205			471,954
Less 10% annual discount for estimated timing of cash flows		(639,438	)		(503,966	)		(320,239	)
Standardized measure of discounted future net cash flows	$	160,206		$	238,239		$	151,715

The future cash flows estimated to be spent to develop proved undeveloped properties in the years ended December 31, 2009, 2010 and 2011 are $155.1 million, $154.4 million, and $153.8 million respectively.

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

	Years Ended December 31,
	2008			2007			2006

Balance, beginning of period	$	238,239		$	151,715		$	380,004

Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs		(72,874	)		(55,993	)		(48,732	)
Net changes in prices and production costs(1)		(71,736	)		18,213			(195,835	)
Revisions of previous quantity estimate		(1,224	)		(129	)		(25,489	)
Development costs incurred		14,583			8,387			3,426
Changes in future development costs		(41,110	)		7,049			(8,514	)
Transfers to limited partnerships		(615	)		(11,689	)		(7,766	)
Extensions, discoveries, and improved recovery less					76,256			44,787
related cost		33,890
Purchases of reserves in-place		196			1,477			254
Sales of reserves in-place		(83	)		(42	)		(259	)
Accretion of discount		23,549			14,960			38,000
Estimated settlement of asset retirement obligation		(2,807	)		(2,699	)		(3,465	)
Estimated proceeds on disposals of well equipment		3,131			3,606			4,547
Changes in production rates (timing) and other		37,067			27,110			(29,243	)

Balance, end of period	$	160,206		$	238,239		$	151,715

(1)	Includes changes in the year-end price of natural gas and oil compared to the price of natural gas and oil at the beginning of the year, net of increases or decreases in production costs.

F-32

Atlas Resources, LLC

Financial Statements

(Unaudited)

March 31, 2009

F-33

ATLAS RESOURCES, LLC

BALANCE SHEETS

	March 31,		December 31,
	2009		2008
	(In thousands)
	(Unaudited)		(Audited)
ASSETS
Current assets:
Cash and cash equivalents	$	2,669	$	2,549
Accounts receivable		22,908		23,843
Prepaid expenses		8,084		10,794
Short-term hedge receivable due from affiliate		29,032		26,313
Total current assets		62,693		63,499

Property, plant and equipment, net		623,257		585,477
Long-term hedge receivable due from affiliate		20,065		18,160
Goodwill		20,868		20,868
Other assets		1,533		1,681
	$	728,416	$	689,685

LIABILITIES AND MEMBER'S EQUITY
Current liabilities:
Accounts payable	$	36,196	$	17,728
Liabilities associated with drilling contracts		30,276		96,883
Advances from parent		438,896		383,507
Accrued liability		57,497		38,598
Current portion of derivative liability due to affiliate		64		2,143
Total current liabilities		562,929		538,859

Asset retirement obligation		15,814		15,166
Long-term derivative liability due to affiliate		5		1,927

Commitments and contingencies (Note 6)

Member's equity:
Accumulated other comprehensive income		49,028		40,403
Member's capital		100,640		93,330
Total member's equity		149,668		133,733
	$	728,416	$	689,685

See accompanying notes to financial statements.

F-34

ATLAS RESOURCES, LLC

STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended
	March 31,
	2009			2008
	(In thousands)
REVENUES
Well construction and completion	$	112,368		$	104,138
Gas and oil production		24,885			20,651
Well services		3,315			3,269
Gathering		2,659			2,111
Administration and oversight		3,798			4,962
Total revenues		147,025			135,131

COSTS AND EXPENSES
Well construction and completion		95,397			90,555
Gas and oil production		5,680			4,164
Well services		1,137			1,011
General and administrative		3,415			2,718
Fees and reimbursements-affiliate		21,015			18,860
Depreciation, depletion and amortization		12,982			7,679
Interest expense - affiliates		93			96
Other expense-net		(4	)		(172	)
		139,715			124,911
	$	7,310		$	10,220

See accompanying notes to financial statements.

F-35

ATLAS RESOURCES, LLC

STATEMENT OF CHANGES IN MEMBER’S EQUITY

(In thousands)

(Unaudited)

	Accumulated
	Other				Total
	Comprehensive		Member’s		Member’s
	Income		Capital		Equity

Balance, January 1, 2009	$	40,403	$	93,330	$	133,733

Other comprehensive income		8,625		—		8,625

Net income		—		7,310		7,310

Balance, March 31, 2009	$	49,028	$	100,640	$	149,668

See accompanying notes to financial statements.

F-36

ATLAS RESOURCES, LLC

STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended
	March 31,
	2009			2008
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	7,310		$	10,220
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		12,982			7,679
Fees and reimbursements - affiliate		21,015			18,860
Gain on disposal of assets		(9	)		(21	)
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable		935			(1,077	)
Increase in accrued liabilities and accounts payable		33,219			12,738
Decrease in liabilities associated with drilling contracts		(66,607	)		(86,522	)
Decrease (increase) in prepaid expenses and other assets		2,739			(847	)
Net cash provided by (used in) operating activities		11,584			(38,970	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(45,929	)		(43,840	)
Proceeds from sale of assets		91			26
Net cash used in investing activities		(45,838	)		(43,814	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Net payments on borrowings		—			(8	)
Net advances from affiliates		34,374			72,647
Net cash provided by financing activities		34,374			72,639

Increase (decrease) in cash and cash equivalents		120			(10,145	)
Cash and cash equivalents at beginning of period		2,549			15,064
Cash and cash equivalents at end of period	$	2,669		$	4,919

See accompanying notes to financial statements.

F-37

ATLAS RESOURCES, LLC

STATEMENTS OF COMPREHENSIVE INCOME / (LOSS)

(Unaudited)

	Three Months Ended
	March 31,
	2009			2008
	(In thousands)
Net income	$	7,310		$	10,220
Other comprehensive income (loss):
Unrealized holding gains (losses) on hedging contracts		14,591			(25,241	)
Less: reclassification adjustment for gains realized in net income		(5,966	)		(2,611	)
		8,625			(27,852	)
Comprehensive income/(loss)	$	15,935		$	(17,632	)

See accompanying notes to financial statements.

F-38

ATLAS RESOURCES, LLC

NOTES TO FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

NOTE 1 – NATURE OF OPERATIONS AND PRINCIPLES OF CONSOLIDATION

Atlas Resources, LLC (“the Company”), a Pennsylvania limited liability company, is a wholly-owned subsidiary of Atlas Energy Resources, LLC (NYSE: ATN), (the “Parent” or “Atlas Energy”). The Company is engaged in the exploration, development, and production of natural gas and to a lesser extent, oil in Northern Michigan’s Antrim Shale, Indiana’s New Albany Shale and the Appalachian Basin. In addition, the Company performs contract drilling and well operation services. The Company’s operations are dependent upon the resources and services provided by Atlas Energy. Atlas Energy conducts its operations through Atlas Energy Operating Company, LLC, its wholly owned subsidiary. Atlas Energy is also a leading sponsor of and manages tax-advantaged direct investment partnerships, in which it coinvests to finance the exploitation and development of its acreage ("the Partnership's"). The Company typically is the managing general partner and has a material interest in the Partnerships.

The accompanying financial statements, which are unaudited except that the balance sheet at December 31, 2008 is derived from audited financial statements, are presented in accordance with accounting principles generally accepted in the United States for interim reporting. They do not include all disclosures normally made in audited financial statements. In management's opinion, all adjustments necessary for a fair presentation of the Company's financial position, results of operations and cash flows for the periods disclosed have been made. These interim financial statements should be read in conjunction with the audited financial statements and notes thereto for the year ended December 31, 2008. The results of operations for the three-month period ended March 31, 2009 may not necessarily be indicative of the results of operations for the full year ending December 31, 2009.

In accordance with established practice in the oil and gas industry, the Company includes in its financial statements its pro-rata share of assets, liabilities, income, and lease operating and general and administrative costs and expenses of the investment partnerships in which it has an interest. Such interests typically range from 15% to 35%. The Company’s financial statements do not include proportional consolidation of the depletion or impairment expenses of the Partnerships in which it has an interest. Rather, the Company calculates these items specific to its own economics as further explained under the heading “Oil and Gas Properties” in Note 2, below.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

Preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues, costs and expenses during the reporting period. The Company’s financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, fair value of derivative instruments, the probability of forecasted transactions, and the allocation of purchase price to the fair value of assets acquired. Actual results could differ from these estimates.

Reclassifications

Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation, including $18.8 million of pre-development costs shown as a component of “Property, plant, and equipment, net” which was previously combined with “Liabilities associated with drilling contracts” on the Company’s balance sheets.

F-39

ATLAS RESOURCES, LLC

NOTES TO FINANCIAL STATEMENTS

March 31, 2009

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Accounts Receivable 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 customers’ current creditworthiness, as determined by the Company’s review of its customers’ credit information. The Company extends credit on an unsecured basis to many of its energy customers. At March 31, 2009 and December 31, 2008, the Company’s credit evaluation indicated that it has no need for an allowance for possible losses.

Revenue Recognition

Partnership Management. The Company conducts certain energy activities through, and a portion of its revenues are attributable to, sponsored investment partnerships. The Company contracts with the investment partnerships to drill partnership wells. The contracts require that the investment partnerships 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 for each shallow well drilled and may take several months to complete deeper or horizontal wells. Contract payments the Company has received and for which the revenue has not been earned is classified as a current liability titled “Liabilities Associated with Drilling Contracts” on its balance sheets. The Company recognizes gathering revenues at the time the natural gas is delivered, and recognizes well services revenues at the time the services are performed. The Company is also entitled to receive administration and oversight fees according to the respective partnership agreements. The Company recognizes such fees as income when services are performed.

Gas and Oil Production. The Company generally sells natural gas and crude oil at prevailing market prices. Revenue is recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale are reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil in which the Company has an interest with other producers are recognized on the basis of the Company’s percentage ownership of working interest or overriding royalty. Generally, the Company’s sales contracts are based on pricing provisions that are tied to a market index, with certain adjustments based on proximity to gathering and transmission lines and the quality of its natural gas.

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 fees, which are, in turn, based upon applicable product prices. The Company had unbilled trade receivables at March 31, 2009 and December 31, 2008 of $10.9 million, and $15.3 million, respectively, which are included in accounts receivable on its Balance Sheets.

Capitalized Interest

The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new gas and oil wells and other capital projects. Interest is capitalized only during the periods in which these assets are brought to their intended use. The weighted average interest rate used to capitalize interest was 6.6% and 5.4% for the three months ended March 31, 2009 and 2008, respectively, which resulted in interest capitalized of $1,642,000 and $581,000 for the periods, respectively.

F-40

ATLAS RESOURCES, LLC

NOTES TO FINANCIAL STATEMENTS (CONTINUED)

March 31, 2009

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Property, Plant and Equipment

Property, plant, and equipment are stated at cost. Depreciation, depletion, and amortization are based on cost less estimated salvage value primarily using the unit-of-production method or straight-line method over the assets' estimated useful lives. Other fixed assets are depreciated using the 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.

Property, plant, and equipment consist of the following at the dates indicated (in thousands):

	March 31,			December 31,
	2009			2008
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	94,447		$	84,065
Predevelopment costs		15,838			18,772
Wells and related equipment		597,961			555,091
		708,246			657,928
Unproved properties		27,540			27,528
Support equipment		5,275			5,459
		741,061			690,915
Land, buildings and improvements		4,523			4,489
Other		800			790
		746,384			696,194
Accumulated depreciation, depletion and amortization		(123,127	)		(110,717	)
	$	623,257		$	585,477

Oil and Gas Properties

The Company follows the successful efforts method of accounting for oil and gas producing activities. Acquisition costs of leases and development activities are capitalized. 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.

Depletion depreciation and amortization expense is determined on a field-by-field basis using the units-of-production method, with depletion, depreciation and amortization rates for leasehold acquisition costs based on estimated proved reserves and depletion, depreciation and amortization rates for well and related equipment costs based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include the Company’s costs of property interests in uncontrolled but proportionately consolidated from investment partnerships, wells drilled solely by the Company, properties purchased and working interests with other outside operators.

F-41

ATLAS RESOURCES, LLC

NOTES TO FINANCIAL STATEMENTS (CONTINUED)

March 31, 2009

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Impairment of Oil and Gas Properties and Long-Lived Assets

The Company’s oil and gas properties and long-lived assets are reviewed for impairment annually or 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 of the Company’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation 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 current contracts in place, adjusted for basis differentials and 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.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, the Company’s reserve estimates for its investment in its limited partnerships are based on its own assumptions rather than its proportionate share of the limited partnership’s reserves. These assumptions include the Company’s actual capital contributions, an additional carried interest (generally 7% to 10%), a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs.

The Company’s lower operating and administrative costs result from the limited partners paying to the Company their proportionate share of these expenses plus a profit margin. These assumptions are used in the calculation of the Company’s reserve analysis and could result in the Company’s calculation of depletion and impairment being different than its proportionate share of the limited partnership calculations for these items. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Company cannot predict what reserve revisions may be required in future periods.

F-42

ATLAS RESOURCES, LLC

NOTES TO FINANCIAL STATEMENTS (CONTINUED)

March 31, 2009

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

The Company’s method of calculating its reserves may result in reserve quantities and values which are greater than those which would be calculated by the investment partnerships which the Company sponsors and owns an interest in but does not control. The Company’s reserve quantities include reserves in excess of its proportionate share of reserves in a partnership which the Company may be unable to recover due to the partnership legal structure. The Company may have to pay additional consideration in the future as a well or investment partnership becomes uneconomic under the terms of the partnership agreement in order for the Company to recover these excess reserves and to acquire any additional residual interests in the wells held by other partnership investors. The acquisition of any well interest from the partnership by the Company is governed under the partnership agreement and must be at fair market value supported by an appraisal of an independent expert selected by the Company.

Goodwill

The Company has recorded goodwill of $20.9 million in connection with several acquisitions of assets. Goodwill and intangibles with infinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. Under the principles of SFAS No. 142, “Goodwill and Other Intangible Assets”, (“SFAS No. 142”), an impairment loss should be recognized if the carrying value of an entity’s reporting units exceeds its estimated fair value. Because quoted market prices for the Company’s equity securities or reporting units are not available, the Company must apply judgment in determining the estimated fair value of these reporting units. The Company uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. The Company also recognizes that substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity’s individual equity securities. In most industries, including the Company’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, the Company also considers a control premium to the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in the Company’s industry. The resultant fair values calculated for the reporting units are then compared to observable metrics on large mergers and acquisitions in the Company’s industry to determine whether those valuations appear reasonable in the Company’s judgment. The Company’s evaluation of goodwill at December 31, 2008, indicated there was no impairment loss and no impairment indicators arose during the three months ended March 31, 2009. 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, in its consolidated financial statements in that period.

Fair Value of Financial Instruments

As of January 1, 2008, the Company adopted the provisions of SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”) to its financial assets and liabilities. SFAS No. 157 establishes a single authoritative definition of fair value based upon the assumptions market participants would use when pricing an asset or liability and creates a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, additional disclosures are required, including disclosures of fair value measurements by level within the fair value hierarchy (see Note 7).

F-43

ATLAS RESOURCES, LLC

NOTES TO FINANCIAL STATEMENTS (CONTINUED)

March 31, 2009

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Recently Issued Financial Accounting Standards

In May of 2009, the FASB issued Statement of Accounting Standards No. 165, “Subsequent Events” (“SFAS 165”). The objective of SFAS 165 is to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS 165 is effective for interim and annual financial periods ending after June 15, 2009. The Company will adopt SFAS 165 as of June 30, 2009, and the Company does not anticipate the adoption of SFAS 165 to have any material impact on its financial position, results of operations or accompanying footnote disclosure.

In April 2008, the FASB issued Staff Position No. 142-3, “Determination of Useful Life of Intangible Assets” (“FSP FAS 142-3”). FSP FAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”). The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141(R), “Business Combinations” (“SFAS No. 141(R)”). The Company adopted the requirements of FSP FAS 142-3 on January 1, 2009, and its adoption did not have any impact on its financial position and results of operations.

In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS No. 161”), an amendment of FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”). SFAS No. 161 requires entities to provide qualitative disclosures about the objectives and strategies for using derivatives, quantitative data about the fair value of and gains and losses on derivative contracts, and details of credit-risk-related contingent features in their hedged positions. The standard is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged but not required. SFAS No. 161 also requires entities to disclose more information about the location and amounts of derivative instruments in financial statements; how derivatives and related hedges are accounted for under SFAS No. 133, and how the hedges affect the entity’s financial position, financial performance, and cash flows. The Company adopted the requirements of SFAS No. 161 on January 1, 2009 and its adoption resulted in additional disclosures related to its commodity and interest rate derivatives (see Note 7).

In December 2007, the FASB issued SFAS No. 141(R). SFAS No. 141(R) replaces SFAS No. 141, “Business Combinations”; however, it retains the fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. SFAS No. 141(R) requires an acquirer to recognize the assets acquired, liabilities assumed, and any noncontrolling interest in the acquiree at the acquisition date, be measured at their fair values as of that date, with specified limited exceptions. Changes subsequent to that date are to be recognized in earnings, not goodwill. Additionally, SFAS No. 141 (R) requires costs incurred in connection with an acquisition be expensed as incurred. Restructuring costs, if any, are to be recognized separately from the acquisition. The acquirer in a business combination achieved in stages must also recognize the identifiable assets and liabilities, as well as the noncontrolling interests in the acquiree, at the full amounts of their fair values. The Company adopted the requirements of SFAS No. 141(R) on January 1, 2009 and it did not have a material impact on its financial position and results of operations.

F-44

ATLAS RESOURCES, LLC

NOTES TO FINANCIAL STATEMENTS (CONTINUED)

March 31, 2009

NOTE 3 – OTHER ASSETS

The following table provides information about other assets at the dates indicated (in thousands):

	March 31,			December 31,
	2009			2008

Management and operating contracts	$	6,352		$	6,352
Deposits		238			267
		6,590			6,619
Accumulated amortization		(5,057	)		(4,938	)
	$	1,533		$	1,681

Partnership management and operating contracts which were acquired through previous acquisitions were recorded at fair value on their acquisition dates. The Company amortizes these contracts 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 three months ended March 31, 2009 and 2008 was $119,000.

The aggregate estimated annual amortization expense of the above contracts for the next three years ending December 31 is as follows: 2010-$358,200, 2011-$477,600, 2012-$459,300.

NOTE 4 – ASSET RETIREMENT OBLIGATION

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.

F-45

ATLAS RESOURCES, LLC

NOTES TO FINANCIAL STATEMENTS (CONTINUED)

March 31, 2009

NOTE 4 – ASSET RETIREMENT OBLIGATION (Continued)

A reconciliation of the Company’s liability for well plugging and abandonment costs for the periods indicated are as follows (in thousands):

	Three Months Ended
	March 31,
	2009		2008

Asset retirement obligation, beginning of period	$	15,166	$	12,359
Liabilities incurred		421		496
Liabilities settled		—		(1	)
Accretion expense		227		188
Asset retirement obligation, end of period	$	15,814	$	13,042

The above accretion expense is included in depreciation, depletion, and amortization in the Company's statements of income.

NOTE 5 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Relationship with Atlas Energy. Advances from parent shown on the Company’s Balance Sheets represents amounts owed for advances and other transactions in the normal course of business. The Company depends on its parent company, Atlas Energy and its affiliates, for all management and administrative functions. The Company pays a management fee of 7% of subscription funds raised and reimburses Atlas Energy for management and administrative services and expenses, including interest expense, incurred on its behalf based on an allocation of total revenues. Such fees and reimbursements amounted to $21.0 million and $18.9 million for the three months ended March 31, 2009 and 2008, respectively. This fee and expense reimbursement is shown as Fees and reimbursements-affiliate on the Company’s statements of income. The advances are subordinated to any third party debt. The Company incurred interest expense related to intercompany transactions for the three months ended March 31, 2009 and 2008 of $93,000 and $96,000, respectively.

Relationship with Company Sponsored Investment Partnerships. The Company conducts certain activities through, and a substantial portion of its revenues are attributable to, the 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.

NOTE 6 - COMMITMENTS AND CONTINGENCIES

The Company is the managing general partner of various energy partnerships, and has agreed to indemnify each investor partner from any liability that exceeds such partner’s share of partnership assets. Subject to certain conditions, investor partners in certain energy partnerships have the right to present their interests for purchase by the Company, as managing general partner. The Company is not obligated to purchase more than 5% of the units in any calendar year. Based on past experience, the Company believes that any liability incurred would not be material. The Company may also be required to subordinate a part of its net partnership revenues to the receipt by investor partners of cash distributions from the energy partnerships equal to at least 10% of their agreed subscriptions determined on a cumulative basis, in accordance with the terms of the partnership agreements. For the three months ended March 31, 2009, $172,400 of the Company’s net revenues was subordinated, which reduced its cash distribution received in April 2009. No subordination was required for the three months ended March 31, 2008.

F-46

ATLAS RESOURCES, LLC

NOTES TO FINANCIAL STATEMENTS (CONTINUED)

March 31, 2009

NOTE 6 - COMMITMENTS AND CONTINGENCIES (Continued)

Atlas Energy, certain officers and members of the Atlas Energy board of directors and Atlas America are named as defendants in five purported class action lawsuits brought by Atlas Energy unitholders in Delaware Chancery Court challenging the proposed merger, seeking, among other things, to enjoin the defendants from consummating the merger on the agreed-upon terms. Plaintiffs in four of the lawsuits moved for an order consolidating all the actions, which was granted on June 15, 2009. The action seeks a preliminary and permanent injunction from proceeding with the merger, compensatory damages in an unspecified amount, including plaintiff’s costs and expenses, and an order directing defendants to account to the plaintiffs for their damages. Atlas Energy believes that the allegations and purported claims in the complaint lack merit and that it has meritorious defenses to them, and the Parent intends to contest the lawsuit vigorously. The Company is not presently able to estimate the impact, or potential losses, if any, related to this lawsuit.

On June 20, 2008, the Company’s wholly-owned subsidiary, Atlas America, LLC, was named as a co-defendant in the matter captioned CNX Gas Company, LLC (“CNX”) v. Miller Petroleum, Inc. (“Miller”), et al. (Chancery Court, Campbell County, Tennessee). In its complaint, CNX alleged that Miller breached a contract to assign to CNX certain leasehold rights (“Leases”) representing approximately 30,000 acres in Campbell County, Tennessee and that the Company and another defendant, Wind City Oil & Gas, LLC, interfered with the closing of this assignment on June 6, 2008. The Company purchased the Leases from Miller for approximately $19.1 million. On December 15, 2008, the Chancery Court dismissed the matter in its entirety, holding that there had been no breach of the contract by Miller and, therefore, that Atlas America could not have tortuously interfered with the contract. The Chancery Court dismissed all claims against Atlas America, LLC; however, CNX has appealed this decision.

NOTE 7 - DERIVATIVE AND FINANCIAL INSTRUMENTS

The Company is exposed to certain risks relating to its ongoing business operations. These risks are managed by using derivative instruments related to commodity price risk namely, forward contracts associated with forecasted sales of natural gas and crude oil. In accordance with SFAS No. 133, the Company designates these derivatives as cash flow hedges and the derivative instruments have been recorded as either assets or liabilities at fair value in the balance sheet. The effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income and reclassified to earnings in the same period during which the hedged transaction affects earnings. The following table summarizes the fair value of derivative instruments as of March 31, 2009 and December 31, 2008, as well as the gain or loss recognized for the three months ended March 31, 2009 and 2008. There were no gains or losses recognized in income for ineffective derivative instruments for the three months ended March 31, 2009 and 2008, respectively.

F-47

ATLAS RESOURCES, LLC

NOTES TO FINANCIAL STATEMENTS (CONTINUED)

March 31, 2009

NOTE 7 - DERIVATIVE AND FINANCIAL INSTRUMENTS (Continued)

Fair Value of Derivative Instruments:
	Asset Derivatives					Liability Derivatives
Derivatives in		Fair Value					Fair Value
SFAS 133 Cash Flow	Balance Sheet	March 31,		December 31,		Balance Sheet	March 31,			December 31,
Hedging Relationships	Location	2009		2008		Location	2009			2008

Commodity contracts:	Current assets	$	29,032	$	26,313	Current liabilities	$	(64	)	$	(2,143	)
	Long-term assets		20,065		18,160	Long-term liabilities		(5	)		(1,927	)

Total derivatives under SFAS No. 133		$	49,097	$	44,473		$	(69	)	$	(4,070	)

Effects of Derivative Instruments on Statements of Net Income:

Derivatives in

Gain/(Loss)

Location of Gain/(Loss)

Gain/(Loss)

SFAS 133 Cash Flow

Recognized in OCI on Derivative

Reclassified from Accumulated

Reclassified from OCI into Income

Hedging Relationship

(Effective Portion)

OCI into Income

(Effective Portion)

Three Months Ended

(Effective Portion)

Three Months ended

March 31,

2009

2008

2009

2008

Commodity contracts

14,591

(25,241

)

Gas and oil production

5,966

2,611

Atlas Energy from time to time enters into natural gas and oil futures option contracts and collar contracts on the Company’s behalf to achieve more predictable cash flows by hedging its exposure to changes in natural gas and crude oil 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. Crude oil contracts are based on a West Texas Intermediate ("WTI”) index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.

The Company has $49.0 million of unrealized net gains shown in accumulated other comprehensive income at March 31, 2009. If the fair values of the instruments remain at current market values, the Company will reclassify $29.0 million of net gains to its statement of income over the next twelve-month period as these contracts settle, and $20.0 million of net gains will be reclassified in later periods.

The Company recognized gains on settled contracts covering natural gas production of $5.4 million and $2.6 million for the three months ended March 31, 2009 and 2008, respectively. The Company recognized gains on settled contracts covering oil production of $589,000 for the three months ended March 31, 2009. There were no oil settlements for the three months ended March 31, 2008. As the underlying prices and terms in the Company's hedge contracts were consistent with the indices used to sell its natural gas and crude oil, the Company had no gains or losses during the three months ended March 31, 2009 and 2008 for hedge ineffectiveness or as a result of the discontinuance of these cash flow hedges.

F-48

ATLAS RESOURCES, LLC

NOTES TO FINANCIAL STATEMENTS (CONTINUED)

March 31, 2009

NOTE 7 - DERIVATIVE AND FINANCIAL INSTRUMENTS (Continued)

Natural Gas Fixed Price Swaps

Production
Period Ending			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset (1)
	(MMbtu) (1)		(per MMbtu)		(in thousands)

2009		5,637,000	$	8.24	$	22,231
2010		4,790,000		8.11		10,300
2011		3,395,000		7.84		3,822
2012		2,508,000		8.06		2,607
2013		273,000		8.73		404
					$	39,364

Natural Gas Costless Collars

Production
Period Ending	Option			Average		Fair Value
December 31,	Type	Volumes		Floor & Cap		Asset (1)
		(MMbtu)		(per MMbtu)		(in thousands)

2009	Puts purchased		33,000	$	11.00	$	218
2009	Calls sold		33,000		15.35		—
2010	Puts purchased		611,000		7.84		1,278
2010	Calls sold		611,000		9.01		—
2011	Puts purchased		1,363,000		7.48		1,408
2011	Calls sold		1,363,000		8.44		—
2012	Puts purchased		185,000		7.00		74
2012	Calls sold		185,000		8.32		—
2013	Puts purchased		55,000		7.00		12
2013	Calls sold		55,000		8.25		—
						$	2,990

Crude Oil Fixed Price Swaps

Production
Period Ending			Average		Fair Value
December 31,	Volumes		Fixed Price		Asset (2)
	(Bbls)		(per Bbl)		(in thousands)

2009		35,000	$	99.73	$	1,616
2010		36,000		97.40		1,263
2011		31,000		96.44		898
2012		25,000		96.00		610
2013		7,000		96.06		170
					$	4,557

F-49

ATLAS RESOURCES, LLC

NOTES TO FINANCIAL STATEMENTS (CONTINUED)

March 31, 2009

NOTE 7 - DERIVATIVE AND FINANCIAL INSTRUMENTS (Continued)

Crude Oil Costless Collars

Production
Period Ending	Option			Average		Fair Value
December 31,	Type	Volumes		Floor & Cap		Asset (2)
		(Bbl)		(per Bbl)		(in thousands)

2009	Puts purchased		21,000	$	85.00	$	692
2009	Calls sold		21,000		117.48		—
2010	Puts purchased		23,000		85.00		599
2010	Calls sold		23,000		112.92		—
2011	Puts purchased		20,000		85.00		442
2011	Calls sold		20,000		110.81		—
2012	Puts purchased		16,000		85.00		305
2012	Calls sold		16,000		110.06		—
2013	Puts purchased		4,000		85.00		79
2013	Calls sold		4,000		110.09		—
						$	2,117

				Total Net Asset		$	49,028

(1)

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

(2)

Fair value bases on forward WTI crude oil prices, as applicable.

Fair Value of Financial Instruments

The Company adopted the provisions of SFAS 157 at January 1, 2008. SFAS 157 establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. SFAS 157's hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1– Quoted prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2– Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

Level 3– Unobservable inputs that reflect the entities own assumptions about the assumptions that market participants would use in the pricing of the asset or liability and are consequently not based on market activity, but rather through particular valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Company has certain assets and liabilities that are reported at fair value on a recurring basis in its consolidated balance sheets. The following methods and assumptions were used to estimate fair values.

F-50

ATLAS RESOURCES, LLC

NOTES TO FINANCIAL STATEMENTS (CONTINUED)

March 31, 2009

NOTE 7 - DERIVATIVE AND FINANCIAL INSTRUMENTS (Continued)

Derivative Instruments. All of the Company’s derivative contracts are defined as Level 2. The Company’s natural gas and crude oil derivative contracts are valued based on prices quoted on the NYMEX or WTI and adjusted by the respective counterparty using various assumptions including quoted forward prices, time value, volatility factors, and contractual prices for the underlying instruments. Information for assets and liabilities measured at fair value on a recurring basis at March 31, 2009 and December 31, 2008 is as follows (in thousands):

	As of March 31, 2009				As of December 31, 2008
	Level 2		Total		Level 2		Total

Commodity-based derivatives	$	49,028	$	49,028	$	40,403	$	40,403

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

The Company has certain assets and liabilities that are reported at fair value on a nonrecurring basis in its consolidated balance sheets. The following methods and assumptions were used to estimate fair values.

Asset Retirement Obligations. The Company estimates the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements; the credit-adjusted risk-free rate of the Company; and estimated inflation rates. See Note 4 – “Asset Retirement Obligations” for a summary of activity for the three months ended March 31, 2009 and 2008.

Oil and Gas Property Impairments. In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the Company reviews its proved oil and gas properties for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties. See Note 2 for a summary of the Company’s accounting policy related to the methodology and determination of impairment of its oil and gas properties. The Company’s evaluation indicated there was no impairment of its oil and gas properties for the three months ended March 31, 2009 and 2008.

Information for assets that are measured at fair value on a nonrecurring basis for the three months ended March 31, 2009 and 2008 is as follows (in thousands):

	Three Months Ended				Three Months Ended
	March 31, 2009				March 31, 2008
	Level 3		Total		Level 3		Total

Asset retirement obligations incurred in the current period	$	421	$	421	$	496	$	496

F-51

ATLAS RESOURCES, LLC

NOTES TO FINANCIAL STATEMENTS (CONTINUED)

March 31, 2009

NOTE 8 – DEBT

Revolving Credit Facility. At March 31, 2009, Atlas Energy Resources had a credit facility with a syndicate of banks with a borrowing base of $697.5 million that matures in June 2012. The borrowing base will be redetermined semiannually on April 1 and October 1 subject to changes in Atlas Energy Resources oil and gas reserves. Up to $50.0 million of the facility may be in the form of standby letters of credit, of which $1.2 million was outstanding at March 31, 2009, which are not reflected as borrowings on Atlas Energy’s consolidated balance sheets. The credit facility is secured by substantially all of Atlas Energy’s assets and is guaranteed by each of its subsidiaries and bears interest at either the base rate plus the applicable margin or at adjusted LIBOR plus the applicable margin, elected at its option.

The credit facility requires Atlas Energy to maintain specific financial ratios of current assets to current liabilities and debt to earnings before interest, taxes, depreciation, depletion, and amortization ("EBITDA") as disclosed in the credit agreement. In addition, the credit agreement limits sales, leases or transfer of assets and the incurrence of additional indebtness. The credit agreement limits the distributions payable by Atlas Energy if an event of default has occurred and is continuing or would occur as a result of such distribution. Atlas Energy was in compliance with these covenants as of March 31, 2009 and December 31, 2008.

Senior Unsecured Notes. In January 2008, the Company completed a private placement of $250.0 million of its 10.75% senior unsecured notes (“Senior Notes”) due 2018 to institutional buyers pursuant to rule 144A under the Securities Act of 1933. In May 2008, the Company issued an additional $150.0 million of Senior Notes at 104.75% to par to yield 9.85% to the par call on February 1, 2016. Atlas Energy considers these issuances as a single class of debt securities which were registered for resale on September 19, 2008. Atlas Energy received proceeds of approximately $398.0 million from these offerings, including a $7.1 million premium and net of $9.2 million in underwriting fees. In addition, Atlas Energy received approximately $4.7 million related to accrued interest. Atlas Energy used the net proceeds to reduce the balance outstanding on its revolving credit facility. Interest on the Senior Notes is payable semi-annually in arrears on February 1 and August 1 of each year. The Senior Notes are redeemable at any time at specified redemption prices, together with accrued and unpaid interest to the date of redemption. In addition, before February 1, 2011, Atlas Energy may redeem up to 35% of the aggregate principal amount of the Senior Notes with the proceeds of equity offerings at a stated redemption price. The Senior Notes are also subject to repurchase by Atlas Energy at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if Atlas Energy does not reinvest the net proceeds within 360 days. The Senior Notes are junior in right of payment to Atlas Energy’s secured debt, including its obligations under its credit facility. The indenture governing the Senior Notes contains covenants, including limitations of Atlas Energy’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of its assets. Atlas Energy was in compliance with the covenants as of March 31, 2009 and December 31, 2008.

F-52

ATLAS RESOURCES, LLC

NOTES TO FINANCIAL STATEMENTS (CONTINUED)

March 31, 2009

NOTE 9 – SUBSEQUENT EVENTS

On April 27, 2009 Atlas Energy and Atlas America, Inc. (“Atlas America”) (NASDAQ: ATLS), Atlas Energy’s ultimate parent, executed a definitive merger agreement, pursuant to which a newly formed subsidiary of Atlas America will merge with and into Atlas Energy Resources, with Atlas Energy Resources surviving as a wholly-owned subsidiary of Atlas America. In the merger, each Class B common unit of Atlas Energy not currently held by Atlas America will be converted into 1.16 shares of Atlas America common stock, and Atlas America will be renamed “Atlas Energy, Inc.” The Atlas America board of directors has approved the merger agreement and has resolved to recommend that Atlas America stockholders vote in favor of the transactions contemplated by the merger agreement. Atlas Energy’s board of directors and a special committee of its directors comprised entirely of independent directors have also approved the merger agreement and have resolved to recommend that Atlas Energy unitholders vote in favor of the merger. Pending consummation of the merger, Atlas Energy has suspended distributions to its Class A and Class B members’ interests. The transaction will be subject to approval by holders of a majority of the outstanding Atlas America common stock and by holders of a majority of Atlas Energy outstanding Class B units, consent of a majority of the lenders under Atlas Energy’s credit agreement and other customary closing conditions.

In March 2009, Atlas Energy entered into an agreement to sell two natural gas processing plants and associated pipelines located in southwestern Pennsylvania for cash of $12.0 million to Laurel Mountain Midstream, LLC (“Laurel Mountain”), a newly-formed joint venture between our affiliate, Atlas Pipeline Partners, L.P. (NYSE: APL) (“Atlas Pipeline”), and The Williams Companies, Inc. (NYSE: WMB). (“Williams”). This agreement was entered into in connection with Atlas Pipeline’s March 31, 2009 agreement with Williams that it will form Laurel Mountain and, upon contributing its Appalachia Basin natural gas gathering system to Laurel Mountain, will receive $90.0 million in cash, a preferred equity right to proceeds under a $25.5 million obligation by Laurel Mountain and a 49% equity interest in Laurel Mountain. Atlas Pipeline is a subsidiary of our indirect parent company, Atlas America, Inc. (NASDAQ: ATLS), (“Atlas America”). The joint venture will own and operate all of Atlas Pipeline’s northern Appalachian assets, excluding its northern Tennessee operations, of which we will be the largest customer.

Effective April 9, 2009, Atlas Energy entered into a second amendment to our credit agreement with a syndicate of banks. Among other things, the amendment adjusts the credit facility borrowing base to $650 million and amends the definition of applicable margin to, among other items, adjust the Eurodollar Loans rate from a range of 100 to 175 basis points to a range of 200 to 300 basis points, subject to amounts drawn against the facility.

In May 2009, Atlas Energy received approximately $28.5 million in proceeds from the early settlement of natural gas hedge positions related to periods from 2011 through 2013. In conjunction with the hedge monetization, these hedge positions were effectively replaced with similar hedge contracts at current prevailing prices. The net proceeds from the hedge monetization were used to reduce indebtedness.

F-53

APPENDIX A

INFORMATION REGARDING

CURRENTLY PROPOSED PROSPECTS

FOR

ATLAS RESOURCES PUBLIC #18-2009(C) L.P.

INFORMATION REGARDING CURRENTLY PROPOSED PROSPECTS

The partnership does not currently hold any interests in any prospects on which the wells will be drilled, and the managing general partner has absolute discretion in determining which prospects will be acquired to be drilled. However, set forth below is information relating to certain proposed prospects and the wells which will be drilled on the prospects by Atlas Resources Public #18-2009(C) L.P., which is the third partnership in the program. It is referred to in this section as the “2009(C) Partnership.” One vertical well generally will be drilled on each development prospect, and for purposes of this discussion the well and prospect are referred to together as the “well.” Notwithstanding, a horizontal well may be drilled in one or more directions on the same prospect on which a vertical well is also drilled. The managing general partner does not anticipate that the wells will be selected in the order in which they are set forth below. Also, the wells currently proposed to be drilled by the 2009(C) Partnership when its subscription proceeds are released from escrow, and from time to time thereafter, are subject to the managing general partner’s right to:

withdraw the wells and to substitute other wells;

take a lesser working interest in the wells;

add other wells; or

any combination of the foregoing.

The specified wells represent a portion of the wells to be drilled on the parntership’s primary areas if the maximum subscription proceeds are raised and the 2009(C) Partnership takes the working interests in the wells that are set forth below in the “Lease Information” for each area. In this regard, the managing general partner anticipates that approximately 79% of the maximum subscription proceeds for the 2009(C) Partnership, if received, will be expended on drilling wells to the Marcellus Shale.

See “Compensation – Drilling Contracts” for the total estimated weighted average cost per well for each of the primary areas set forth below. The managing general partner has not proposed any other wells if:

a greater amount of subscription proceeds is raised;

a lesser working interest in the wells is acquired; or

other wells are substituted for the proposed wells for any of the reasons set forth below.

The managing general partner has not authorized any person to make any representations to you concerning the possible inclusion of any other wells which will be drilled by the 2009(C) Partnership, and you should rely only on the information in this prospectus. The currently proposed wells will be assigned to the 2009(C) Partnership unless there are circumstances which, in the managing general partner’s opinion, lessen the relative suitability of the wells. These considerations include:

the amount of the subscription proceeds received by the 2009(C) Partnership;

the latest geological and production data available;

potential title or spacing problems;

availability and price of drilling services, tubular goods and services;

approvals by federal and state departments or agencies;

agreements with other working interest owners in the wells;

farmins; and

continuing review of other properties which may be available.

Any substituted and/or additional wells will meet the same general criteria that the managing general partner used in selecting the currently proposed wells, and generally will be located in areas where the managing general partner or its affiliates have previously conducted drilling operations. You, however, will not have the opportunity to evaluate for yourself the relevant production and geological information for the substituted and/or additional wells.

The information regarding the currently proposed wells is intended to help you evaluate the economic potential and risks of drilling the proposed wells. This includes production information for wells in the same general area as the proposed well, which the managing general partner believes is an important indicator in evaluating the economic potential of any well to be drilled. However, generally there is little or no production information from surrounding wells for the majority of the wells to be drilled by the partnership, which results in greater uncertainty to you and the other investors. This lack of production information results primarily because the managing general partner, as operator, is proposing wells to be drilled in the partnership that are adjacent to wells it has previously drilled as operator in prior partnerships that have not yet been completed, have not yet been put on-line to sell production, or have been producing for only a short period of time so there is little or no production information available. This risk is further increased for proposed horizontal wells, since the managing general partner has limited experience in drilling horizontal wells. See the production data set forth for each of the primary areas.

Also, if the managing general partner was not the operator of a previously drilled well in Pennsylvania or Indiana, then the production information is not available if the well was drilled within the last five years in Pennsylvania since the Pennsylvania Department of Environmental Resources keeps production data confidential for the first five years from the time a well starts producing, and production information in Indiana is not publicly available through the Indiana Department of Natural Resources. See “Risk Factors – Risks Related to an Investment In the Partnership – Lack of Production Information Increases Your Risk and Decreases Your Ability to Evaluate the Feasibility of the Partnership’s Drilling Program.” The wells proposed to be drilled for which there is no production data for other wells in the immediate area have been proposed by the managing general partner because geologic trends in the immediate area, such as sand thickness, porosities and water saturations, lead the managing general partner to believe that the proposed wells also will be productive.

When reviewing production information, if any, for each well offsetting or in the general area of a proposed well to be drilled, you should consider the factors set forth below.

The length of time that the well has been on-line, and the time period for which production information is shown. Generally, the shorter the period for which production information is shown the less reliable the information is in predicting the ultimate recovery of reserves from a well.

Production from a well declines throughout the life of the well. The rate of decline, the “decline curve,” varies based on which geological formation is producing, and may be affected by the operation of the well. For example, the wells in north central Tennesseee will have a different decline curve from the wells in the Marcellus Shale. Also, each well in the same geological formation or reservoir will have a different rate of decline.

The greatest volume of production (“flush production”) from a well usually occurs in the early period of well operations and may indicate a greater reserve volume (generally, the ultimate amount of natural gas and oil recoverable from a well) than the well actually will produce. This period of flush production can vary depending on how the well is operated and the location of the well.

There is no production information for the majority of the wells as discussed above.

Production information for wells located close to a proposed well tends to be more relevant than production information for wells located farther away, although performance and volume of production from wells located on contiguous prospects can be much different since the geological conditions in these areas can change in a short distance.

Consistency in production among wells tends to confirm the reliability and predictability of the production information.

The information set forth below is included to help you become familiar with the proposed wells.

A map of western Pennsylvania and eastern Ohio showing their counties.

Western Pennsylvania (Marcellus Shale)

Lease information for the Marcellus Shale in Fayette, Greene, Indiana and Westmoreland Counties, Pennsylvania

Location and Production Maps for the Marcellus Shale in Fayette, Greene, Indiana and Westmoreland Counties, Pennsylvania showing the proposed wells and the wells in the area

Production data for the Marcellus Shale in Fayette, Greene, Indiana and Westmoreland Counties, Pennsylvania

DC Energy Consultants, Inc.’s geologic evaluation for the currently proposed wells in the Marcellus Shale in Fayette, Greene, Indiana and Westmoreland Counties, Pennsylvania

Knox, Greene and Sullivan Counties, Indiana (Upper Devonian New Albany Shale Reservoir)

Lease information for Knox, Greene and Sullivan Counties, Indiana.

Location and Production Maps for Knox, Greene and Sullivan Counties, Indiana showing the proposed wells.

Production Data for Knox County, Indiana.

DC Energy Consultants, Inc.’s geologic evaluation for the currently proposed wells in Knox, Greene and Sullivan Counties, Indiana.

MAP OF WESTERN PENNSYLVANIA

AND

EASTERN OHIO

LEASE INFORMATION

FOR

THE MARCELLUS SHALE IN FAYETTE, GREENE, INDIANA AND

WESTMORELAND COUNTIES, PENNSYLVANIA

PUBLIC 18-2009(C) - VERTICAL & HORIZONTAL MARCELLUS DRILLING PROGRAM

VERTICAL PROSPECT NAME		MAP NO.	COUNTY	TOWNSHIP	EFFECTIVE DATE	EXPIRATION DATE	LANDOWNER ROYALTY INTEREST (1)	OVERRIDING ROYALTY INTEREST	OVERRIDING ROYALTY 3rd PARTY	NET REVENUE INTEREST	WORKING INTEREST	NET ACRES	ACRES TO BE ASSIGNED TO PARTNERSHIP
1	Bertovich #25	1	Fayette	Nicholson	2/4/2004	HBP	12.5%	0%	0%	87.5%	100%	109.00	20.00
2	Filiaggi #7	1	Fayette	Nicholson	12/22/2008	12/22/2009	18.0%	0%	0%	82.0%	100%	194.65	20.00
3	Gabeletto #5	1	Fayette	Nicholson	7/31/2003	HBP	12.5%	0%	0%	87.5%	100%	50.00	20.00
4	Kovalic #12	1	Fayette	Nicholson	5/10/2004	HBP	12.5%	0%	0%	87.5%	100%	48.00	20.00
5	Vignali #2	1	Fayette	Nicholson	1/28/2005	HBP	12.5%	0%	0%	87.5%	100%	29.00	20.00
6	Burchianti #58	1	Greene	Greene	12/22/2008	12/22/2009	18.0%	0%	0%	82.0%	100%	753.50	20.00
7	Consol / USX #30	1	Greene	Monongahela	9/13/2006	HBP	14.5%	0%	0%	85.5%	100%	940.00	20.00
8	Glendenning #1	2	Greene	Cumberland	12/15/2006	12/15/2009	12.5%	0%	0%	87.5%	100%	20.33	20.00
9	Groves #8	2	Greene	Cumberland	9/21/2002	HBP	12.5%	0%	0%	87.5%	100%	107.02	20.00
10	Rush #18	2	Greene	Cumberland	10/12/2007	HBP	12.5%	0%	0%	87.5%	100%	95.60	20.00
11	Watters #14	2	Greene	Cumberland	1/10/2008	HBP	12.5%	0%	0%	87.5%	100%	88.86	20.00
12	Mitchell #20	2	Greene	Jefferson	10/12/2002	HBP	12.5%	0%	0%	87.5%	100%	75.00	20.00
13	Springer #19	2	Greene	Jefferson	9/11/2006	HBP	12.5%	0%	0%	87.5%	100%	137.75	20.00
14	Fairbank Rod & Gun Club #3	3	Fayette	Menallen	1/31/2000	HBP	12.5%	0%	0%	87.5%	100%	240.26	20.00
15	Fairbank Rod & Gun Club #6	3	Fayette	Menallen	1/31/2000	HBP	12.5%	0%	0%	87.5%	100%	240.26	20.00
16	Dancho / Brown #5	3	Fayette	Redstone	8/13/2001	HBP	12.5%	0%	0%	87.5%	100%	98.00	20.00
17	Jackson Farms #25	3	Fayette	Redstone	10/14/1998	HBP	12.5%	0%	0%	87.5%	100%	107.32	20.00
18	Jackson Farms #26	3	Fayette	Redstone	10/14/1998	HBP	12.5%	0%	0%	87.5%	100%	107.32	20.00
19	Jackson Farms Unit #33	3	Fayette	Redstone	10/14/1998	HBP	12.5%	0%	0%	87.5%	100%	80.38	20.00
20	Keslar #10	3	Fayette	Redstone	4/5/1999	HBP	12.5%	0%	0%	87.5%	100%	223.00	20.00
21	Szuhay Unit #6	3	Fayette	Redstone	11/17/2007	HBP	12.5%	0%	0%	87.5%	100%	156.00	20.00
22	Burnside #8	4	Fayette	Washington	10/3/2000	HBP	12.5%	0%	0%	87.5%	100%	112.00	20.00
23	Clarke #14	5	Fayette	Dunbar	12/7/2006	HBP	12.5%	0%	0%	87.5%	100%	150.00	20.00
24	Cottom #3	5	Fayette	Lower Tyrone	6/27/2007	6/27/2012	12.5%	0%	0%	87.5%	100%	145.66	20.00
25	Derr #1	5	Fayette	Lower Tyrone	6/27/2007	6/27/2012	12.5%	0%	0%	87.5%	100%	59.87	20.00
26	Pritts #1	5	Fayette	Lower Tyrone	2/26/2008	2/26/2010	12.5%	0%	0%	87.5%	100%	138.00	20.00
27	Gretz #1	5	Fayette	Upper Tyrone	1/24/2008	1/24/2013	12.5%	0%	0%	87.5%	100%	174.35	20.00
28	Babich #3	6	Westmoreland	S. Huntingdon	11/15/2006	HBP	12.5%	0%	0%	87.5%	100%	87.70	20.00
29	Babich #4	6	Westmoreland	S. Huntingdon	11/15/2006	HBP	12.5%	0%	0%	87.5%	100%	87.70	20.00
30	Smouse #5	6	Westmoreland	S. Huntingdon	7/12/2006	HBP	12.5%	0%	0%	87.5%	100%	54.57	20.00
31	Smouse #6	6	Westmoreland	S. Huntingdon	7/12/2006	HBP	12.5%	0%	0%	87.5%	100%	54.57	20.00
32	Labuda #6	6	Westmoreland	Sewickley	11/22/2004	HBP	12.5%	0%	0%	62.5%	75%	90.00	20.00
33	Lauffer #6	6	Westmoreland	Sewickley	6/14/2005	HBP	12.5%	0%	0%	62.5%	75%	98.17	20.00
34	Morris #10	6	Westmoreland	Sewickley	7/11/2006	HBP	12.5%	0%	3.125%	62.5%	75%	21.90	20.00
35	Blankenship #2	7	Indiana	W. Wheatfield	5/8/2007	5/8/2010	12.5%	0%	0%	75.0%	87.5%	82.50	20.00
36	Huczko #2	7	Indiana	W. Wheatfield	6/27/2007	6/27/2010	12.5%	0%	0%	75.0%	87.5%	37.00	20.00

HORIZONTAL PROSPECT NAME		MAP NO.	COUNTY	TOWNSHIP	EFFECTIVE DATE	EXPIRATION DATE	LANDOWNER ROYALTY INTEREST (1)	OVERRIDING ROYALTY INTEREST	OVERRIDING ROYALTY 3rd PARTY	NET REVENUE INTEREST	WORKING INTEREST	NET ACRES	ACRES TO BE ASSIGNED TO PARTNERSHIP
1	Jackson Farms #31H	3	Fayette	Redstone	10/14/1998	HBP	12.5%	0%	0%	87.5%	100%	42.15	(2)
2	Jackson Farms #32H	3	Fayette	Redstone	10/14/1998	HBP	12.5%	0%	0%	87.5%	100%	93.78	(2)

(1)

Drill site tract only; subject to change due to subsequent unitization.

(2)

Additional acreage to the vertical twin (Jackson Farms Unit #33 - 20 ac), based upon 125' on both sides of the lateral borehold multiplied by the length of the lateral.

LOCATION AND PRODUCTION MAPS FOR

THE MARCELLUS SHALE IN FAYETTE, GREENE, INDIANA AND

WESTMORELAND COUNTIES, PENNSYLVANIA

PRODUCTION DATA

FOR

THE MARCELLUS SHALE IN FAYETTE, GREENE, INDIANA AND

WESTMORELAND COUNTIES, PENNSYLVANIA

PUBLIC 18-2009(C) - MARCELLUS VERTICAL PRODUCTION TABLE

MAP NO		COUNTY	PERMIT NO	OPERATOR	WELL NAME	DATE COMPLETED	TOTAL DEPTH LOGGERS	MONTHS ON LINE	TOTAL CUM PROD THRU 5/31/09 (MCF)	MAY, 2009 PRODUCTION
1	1	Fayette	20153	Drioc Acquistion	Glebis # 1	3/10/1975	8700	N/A	N/A	N/A
2	1	Fayette	23464	Atlas Resources, Inc.	Triplett # 2	05/29/07	8098	23	37,312	982
3	1	Fayette	23989	Atlas Resources, Inc.	Yasenosky # 3	08/26/08	8360	8	329,877	25,375
4	1	Fayette	24053	Atlas Resources, Inc.	Honsaker # 15	03/05/09	8305	1	35,323	35,323
5	1	Fayette	24054	Atlas Resources, Inc.	Honsaker # 16	04/24/09	8154	N/A	N/A	N/A
6	1	Fayette	24055	Atlas Resources, Inc.	Honsaker # 17	05/08/09	N/A	N/A	N/A	N/A
7	1	Greene	24476	Atlas Resources, Inc.	Burchianti # 30	02/10/09	8605	2	30,466	19,378
8	1	Greene	24612	Atlas Resources, Inc.	Burchianti # 33	06/18/08	8566	11	134,164	6,030
9	2	Greene	23659	Eastern American Energy	Phillipi # 2	4/27/2006	8278	N/A	N/A	N/A
10	2	Greene	24036	Atlas Resources, Inc.	Headlee # 6	03/12/07	8148	27	72,818	1,157
11	2	Greene	24338	Atlas Resources, Inc.	Biddle # 12	12/07/07	8414	17	70,080	2,117
12	2	Greene	24342	Atlas Resources, Inc.	Biddle # 22	02/08/08	8285	14	78,340	3,211
13	2	Greene	24353	Atlas Resources, Inc.	Biddle # 14	04/11/08	8398	12	36,303	2,131
14	2	Greene	24394	Atlas Resources, Inc.	Swartz # 4	05/28/08	8507	11	51,173	3,498
15	2	Greene	24482	Atlas Resources, Inc.	Biddle # 27	05/16/08	8410	11	46,853	3,197
16	2	Greene	24483	Atlas Resources, Inc.	Biddle # 28	07/25/08	8248	8	72,090	5,151
17	2	Greene	24558	Atlas Resources, Inc.	Whipkey # 8	4/15/08	8662	11	37,779	2,869
18	2	Greene	24559	Atlas Resources, Inc.	Groves # 7	05/21/08	8474	11	27,696	1,591
19	2	Greene	24666	Eastern American Energy	Morh # 6	7/30/2008	8138	N/A	N/A	N/A
20	2	Greene	24674	Eastern American Energy	Virgili # 1	9/30/2008	8010	N/A	N/A	N/A
21	2	Greene	24693	Atlas Resources, Inc.	Springer # 17	08/05/08	8111	8	60,672	5,605
22	2	Greene	24694	Atlas Resources, Inc.	Springer # 18	08/11/08	8158	8	59,644	5,684
23	2	Greene	24701	Atlas Resources, Inc.	Mack # 7	08/08/08	8506	8	34,822	4,045
24	2	Greene	24716	Eastern American Energy	Cree # 7	8/28/2008	8101	N/A	N/A	N/A
25	2	Greene	24820	Atlas Resources, Inc.	Whipkey # 9	3/12/2009	8454	1	46,488	46,488
26	2	Greene	24826	Atlas Resources, Inc.	Morton # 8	09/26/08	8126	8	45,254	6,219
27	2	Greene	24827	Atlas Resources, Inc.	Morton # 9	01/27/09	8127	3	34,882	11,161
28	2	Greene	24828	Atlas Resources, Inc.	Morton # 10	09/16/08	8284	8	69,250	9,420
29	2	Greene	24905	Atlas Resources, Inc.	Kerr # 9	2/12/2009	8480	2	27,993	16,134
30	2	Greene	24998	Atlas Resources, Inc.	Willis # 24	02/20/09	8150	2	31,647	22,222
31	2	Greene	25035	Atlas Resources, Inc.	Willis # 23	06/11/09	8257	N/A	N/A	N/A
32	3	Fayette	23687	Atlas Resources, Inc.	Skovran # 22	12/14/07	8610	17	122,150	3,707
33	3	Fayette	23688	Atlas Resources, Inc.	Skovran # 23	03/14/08	8115	14	128,859	5,802
34	3	Fayette	23926	Atlas Resources, Inc.	Szuhay # 5	06/04/08	8568	11	91,060	5,474
35	3	Fayette	23961	Atlas Resources, Inc.	Keslar # 9	06/20/08	8512	11	66,410	12,146
36	3	Fayette	23990	Atlas Resources, Inc.	Leichliter # 6	07/29/08	8410	9	38,043	3,263
37	3	Fayette	24009	Atlas Resources, Inc.	Tercho/Shimko # 3	10/31/08	8468	6	94,692	12,231
38	3	Fayette	24023	Atlas Resources, Inc.	Hadenak # 3	09/19/08	8446	8	80,032	6,550
39	3	Fayette	24062	Atlas Resources, Inc.	Skovran # 24	12/03/08	8678	6	70,137	11,753
40	3	Fayette	24190	Atlas Resources, Inc.	Bobbish # 4	N/A	8548	N/A	N/A	N/A
41	4	Fayette	23984	Atlas Resources, Inc.	Olexa # 8	11/18/08	8390	6	97,084	14,733
42	4	Fayette	24194	Atlas Resources, Inc.	Olexa # 9	N/A	N/A	N/A	N/A	N/A
43	5	Fayette	23754	Atlas Resources, Inc.	Palankey # 2	03/04/08	8882	14	33,482	2,773
44	6	Westmoreland	26836	Atlas Resources, Inc.	Hunter # 11	2/21/2008	8099	15	33,422	1,656
45	6	Westmoreland	26838	Atlas Resources, Inc.	Hunter # 13	03/19/08	8162	14	44,282	2,306
46	6	Westmoreland	26870	Atlas Resources, Inc.	Malik # 4	04/02/08	8335	12	45,460	2,378
47	6	Westmoreland	26882	Atlas Resources, Inc.	Fulmer # 11	04/02/08	8261	12	69,540	4,526
48	6	Westmoreland	26883	Atlas Resources, Inc.	Fulmer # 10	03/24/08	8391	14	48,823	2,633
49	6	Westmoreland	26958	Atlas Resources, Inc.	Huber # 13	08/16/07	8097	21	115,856	3,238
50	6	Westmoreland	27089	Atlas Resources, Inc.	Baughman # 1	01/11/08	8203	15	180,954	6,274
51	6	Westmoreland	27241	Atlas Resources, Inc.	Angelcyk # 7	06/10/08	8125	11	67,117	3,621
52	6	Westmoreland	27488	Atlas Resources, Inc.	Angelcyk # 10	07/15/08	8277	9	42,553	3,644
53	6	Westmoreland	27497	Atlas Resources, Inc.	Layman # 6	10/17/08	8358	7	19,980	2,870
54	6	Westmoreland	27503	Atlas Resources, Inc.	Hunter Unit # 24	10/10/08	8376	7	58,055	4,094
55	6	Westmoreland	27509	Atlas Resources, Inc.	Greenawalt # 23	10/03/08	8412	7	38,809	3,849

DCEC’S

GEOLOGIC EVALUATION

FOR THE

CURRENTLY PROPOSED WELLS

THE MARCELLUS SHALE IN FAYETTE, GREENE,

INDIANA AND WESTMORELAND COUNTIES,

PENNSYLVANIA

LEASE INFORMATION

FOR

KNOX, GREENE AND SULLIVAN COUNTIES, INDIANA

PUBLIC 18-2009(C) - INDIANA DRILLING PROGRAM

2009 INDIANA PARTNERSHIP WELLS

PROSPECT NAME		MAP NO	COUNTY	TOWNSHIP	SEC	EFFECTIVE DATE	EXPIRATION DATE	LANDOWNER ROYALTY	OVERRIDING ROY INT	OVERRIDING ROY INT 3rd PARTIES	NET REV INT	WORK INT	NET ACRES	AC TO ASSIGN TO PRTNSHP
1	Alexander A4-23 HD9	1	Sullivan	Gill	23	11/1/2003	11/1/2008	12.50%	0.00%	7.50%	80.00%	99.50%	160	159.20
2	Phillips & Arnett Farms D3-18 HD	1	Sullivan	Hamilton	18	2/4/2009	2/12/2012	12.50%	0.00%	7.50%	80.00%	99.50%	160	159.20
3	Kramer A1-6 HDS	2	Greene	Grant	6	4/7/2004	1/13/2014	12.50%	0.00%	7.50%	80.00%	74.10%	160	118.56
4	Ball B3-11 HDSR	2	Greene	Smith	2,11	4/19/2006	4/19/2011	12.50%	0.00%	7.50%	80.00%	74.10%	160	118.56
5	Beatty B4-10 HDSR7	2	Greene	Smith	3,10	5/24/2006	1/16/2011	12.50%	0.00%	7.50%	80.00%	74.10%	160	118.56
6	Bender & Heaton D4-15 HD1	2	Greene	Smith	15	1/31/2006	1/31/2011	12.50%	0.00%	7.50%	80.00%	74.10%	160	118.56
7	Blanton A4-7 HDSR	2	Greene	Smith	6,7	3/28/2006	2/3/2010	12.50%	0.00%	7.50%	80.00%	74.10%	160	118.56
8	Cruse B2-9 HDSR6	2	Greene	Smith	4,9	11/29/2004	11/29/2009	12.50%	0.00%	7.50%	80.00%	74.10%	160	118.56
9	Egnew D1-30 HD2	2	Greene	Smith	30	2/11/2006	2/11/2011	12.50%	0.00%	7.50%	80.00%	74.10%	160	118.56
10	Ferree B1-26 HD	2	Greene	Smith	23,26	1/23/2006	1/23/2011	12.50%	0.00%	7.50%	80.00%	74.10%	160	118.56
11	Ferree, Reita B1-26 HDS4	2	Greene	Smith	26,35	1/23/2006	1/23/2011	12.50%	0.00%	7.50%	80.00%	74.10%	160	118.56
12	Flynn, Wallace D2-27 HDS	2	Greene	Smith	34	11/30/2005	11/30/2010	12.50%	0.00%	7.50%	80.00%	74.10%	160	118.56
13	Green B4-8 HDSR	2	Greene	Smith	5,8	2/8/2005	2/8/2010	12.50%	0.00%	7.50%	80.00%	74.10%	160	118.56
14	Hiatt D1-17 HDN	2	Greene	Smith	17	1/3/2006	1/22/2011	12.50%	0.00%	7.50%	80.00%	74.10%	160	118.56
15	Hiatt, Jon D1-17 HDS	2	Greene	Smith	20	2/15/2006	2/15/2011	12.50%	0.00%	7.50%	80.00%	74.10%	160	118.56
16	Kirk D3-17 HD	2	Greene	Smith	17	1/13/2005	1/13/2010	12.50%	0.00%	7.50%	80.00%	74.10%	160	118.56
17	Kirk, William D3-17 HDS	2	Greene	Smith	20	5/9/2005	5/9/2010	12.50%	0.00%	7.50%	80.00%	74.10%	160	118.56
18	Martin C3-26 HDS	2	Greene	Smith	26,35	5/5/2006	12/4/2010	12.50%	0.00%	7.50%	80.00%	74.10%	160	118.56
19	Showalter B1-11HDSR8	2	Greene	Smith	2,11	1/17/2006	12/16/2010	12.50%	0.00%	7.50%	80.00%	74.10%	160	118.56
20	Swaby D1-29 HD3	2	Greene	Smith	29	5/22/2006	5/22/2011	18.75%	0.00%	1.25%	80.00%	74.10%	160	118.56
21	Swaby D3-30 HD5	2	Greene	Smith	30	1/15/2006	1/15/2011	12.50%	0.00%	7.50%	80.00%	74.10%	160	118.56
22	Swaby D4-28 HD	2	Greene	Smith	28	1/20/2006	1/20/2011	12.50%	0.00%	7.50%	80.00%	74.10%	160	118.56
23	Swaby, James D4-28 HDS	2	Greene	Smith	33	4/8/2004	12/16/2013	12.50%	0.00%	7.50%	80.00%	74.10%	160	118.56
24	Zimmerly D3-29 HD	2	Greene	Smith	29	1/23/2004	12/15/2013	12.50%	0.00%	7.50%	80.00%	74.10%	160	118.56
25	Zimmerly, Harold D3-29 HDS	2	Greene	Smith	32	4/19/2004	12/15/2013	12.50%	0.00%	7.50%	80.00%	74.10%	160	118.56
26	Pope A3-2 HDS	2	Greene	Stockton	2	4/7/2004	4/7/2014	12.50%	0.00%	7.50%	80.00%	74.10%	160	118.56
27	Kramer D4-36 HD	2	Greene	Wright	36	3/16/2006	3/16/2012	12.50%	0.00%	7.50%	80.00%	74.10%	160	118.56
28	Chattin D2-13 HD	3	Knox	Widner	13	4/6/2006	7/16/2010	12.50%	0.00%	7.50%	80.00%	71.81%	160	114.90
29	Telligman D1-14 HD10	3	Knox	Widner	14	5/18/2009	8/25/2010	12.50%	0.00%	7.50%	80.00%	71.81%	160	114.90
30	Williams A3-33 HD	3	Knox	Widner	33	5/4/2006	5/4/2011	12.50%	0.00%	7.50%	80.00%	71.81%	160	114.90

Notes: See Below

Assumes 20 acre parcel currently open to be leased by Atlas

Small one acre parcel located at the W Quarter Corner may be open. Title unclear.

Assumes 1.5 acre parcel currently open to be leased by Atlas

40 acre lease expired. Assumes renewal of lease by Atlas

11.5 acre parcel in unit open. Assumes lease to Atlas.

11/29/09 lease expiry has option to extend for 5 years. .384 acres in SE corner of unit is state owned. Assumes state of Indiana to lease to Atlas

Jessup et ux lease must ratify production unit. Lease allows 40 acre production units. Assumes small .01 acre lease to be obtained by Atlas.

Jessup et ux lease must ratify production unit. Lease allows 40 acre production units

Alexander lease HBP by CBM well. Other leases in force and effect due to to payments of advanced royalties.

Assumes Atlas to receive O&G lease from Brocksmith to include small parcel in unit.

LOCATION AND PRODUCTION MAPS

FOR

KNOX, GREENE AND SULLIVAN COUNTIES, INDIANA

PRODUCTION DATA

FOR

KNOX COUNTY, INDIANA

PUBLIC 18-2009(C) - INDIANA PRODUCTION TABLE

		MAP				On Line	Days	Cum Gas	Cum Water	Avg Natural Daily Rate
WELL NAME / NO		NO	SEC	COUNTY	TOWNSHIP	Date	On Line	(Nat - Mcfd)	(Bbls)	Gas (Mcfd)	Water (bbls/d)
1	Carnahan A4-36 HDN	Index	AGO	Knox	Vigo	06/04/09	11	2,798	4,460	254	405
2	Carnahan A4-36 HDS	Index	AGO	Knox	Vigo	06/04/09	11	514	1,252	47	114
3	D. Dinkens D4-30 HD	Index	AGO	Knox	Vigo	06/04/09	11	2,607	3,203	237	291
4	Dinkens Farms 1-28 HD	Index	AGO	Knox	Vigo	06/04/09	11	2,526	2,962	230	269
5	Dinkens Farms A2-31 HDS	Index	AGO	Knox	Vigo	06/04/09	11	840	1,072	76	97
6	Johanningsmeier D1-35 HD	Index	AGO	Knox	Vigo	06/04/09	11	2,422	3,516	220	320
7	Lukenbill, Duzan A4-32 HDN	Index	AGO	Knox	Vigo	06/09/09	6	1,696	2,572	283	429
8	Lukenbill, LLC A4-32 HDS	Index	AGO	Knox	Vigo	06/10/09	5	105	225	21	45
9	Worland D4-21 HD (sump)	Index	AGO	Knox	Vigo	06/04/09	11	4,513	6,343	410	577
10	M. Williams 1-17 HD	3	17	Knox	Widner	N/A	N/A	N/A	N/A	N/A	N/A
11	Strange D4-21 HD	3	21	Knox	Widner	06/04/09	11	Shut In	3,757	N/A	342

DCEC’S

GEOLOGIC EVALUATION

FOR THE

CURRENTLY PROPOSED WELLS

KNOX, GREENE AND SULLIVAN COUNTIES, INDIANA

EXHIBIT (A)

FORM OF

AMENDED AND RESTATED CERTIFICATE

AND AGREEMENT OF LIMITED PARTNERSHIP

FOR

ATLAS RESOURCES PUBLIC #18-2009(C) L.P.

TABLE OF CONTENTS

Section No.		Description	Page

I.	FORMATION
	1.01	Formation	1
	1.02	Certificate of Limited Partnership	1
	1.03	Name, Principal Office and Residence	1
	1.04	Purpose	1

II.	DEFINITION OF TERMS
	2.01	Definitions	1

III.	SUBSCRIPTIONS AND FURTHER CAPITAL CONTRIBUTIONS
	3.01	Designation of Managing General Partner and Participants	11
	3.02	Participants	11
	3.03	Subscriptions to the Partnership	11
	3.04	Capital Contributions of the Managing General Partner	13
	3.05	Payment of Subscriptions	14
	3.06	Partnership Funds	14

IV.	CONDUCT OF OPERATIONS
	4.01	Acquisition of Leases	15
	4.02	Conduct of Operations	17
	4.03	General Rights and Obligations of the Participants and Restricted and Prohibited Transactions	21
	4.04	Designation, Compensation and Removal of Managing General Partner and Removal of Operator	31
	4.05	Indemnification and Exoneration	35
	4.06	Other Activities	37

V.	PARTICIPATION IN COSTS AND REVENUES, CAPITAL ACCOUNTS, ELECTIONS AND DISTRIBUTIONS
	5.01	Participation in Costs and Revenues	38
	5.02	Capital Accounts and Allocations Thereto	41
	5.03	Allocation of Income, Deductions and Credits	43
	5.04	Elections	45
	5.05	Distributions	45

VI.	TRANSFER OF UNITS
	6.01	Transferability of Units	46
	6.02	Special Restrictions on Transfers of Units by Participants	47
	6.03	Presentment	48
	6.04	Redemption of Units from Non-Citizen Assignees	50

VII.	DURATION, DISSOLUTION, AND WINDING UP
	7.01	Duration	50
	7.02	Dissolution and Winding Up	51

VIII.	MISCELLANEOUS PROVISIONS
	8.01	Notices	52
	8.02	Time	52
	8.03	Applicable Law	52
	8.04	Agreement in Counterparts	53
	8.05	Amendment	53
	8.06	Additional Partners	53
	8.07	Legal Effect	53

EXHIBITS

	EXHIBIT (I-A)	-	Form of Managing General Partner Signature Page
	EXHIBIT (I-B)	-	Form of Subscription Agreement
	EXHIBIT (II)	-	Form of Drilling and Operating Agreement for Atlas Resources Public #18-2009(C) L.P.

FORM OF AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF

LIMITED PARTNERSHIP FOR ATLAS RESOURCES PUBLIC #18-2009(C) L.P.

THIS AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF LIMITED PARTNERSHIP (“AGREEMENT”), amending and restating the original Certificate of Limited Partnership, is made and entered into as of the date set forth below, by and among Atlas Resources, LLC, referred to as “Atlas” or the “Managing General Partner,” and the remaining parties from time to time signing a Subscription Agreement for Limited Partner Units, these parties sometimes referred to as “Limited Partners,” or for Investor General Partner Units, these parties sometimes referred to as “Investor General Partners.”

ARTICLE I

FORMATION

1.01. Formation. The parties have formed a limited partnership under the Delaware Revised Uniform Limited Partnership Act on the terms and conditions set forth in this Agreement.

1.02. Certificate of Limited Partnership. This document is not only an agreement among the parties, but also is the Amended and Restated Certificate and Agreement of Limited Partnership of the Partnership. This document shall be filed or recorded in the public offices required under applicable law or deemed advisable in the discretion of the Managing General Partner. Amendments to the certificate of limited partnership shall be filed or recorded in the public offices required under applicable law or deemed advisable in the discretion of the Managing General Partner.

1.03. Name, Principal Office and Residence.

1.03(a). Name. The name of the Partnership is Atlas Resources Public #18-2009(C) L.P.

1.03(b). Residence. The residence of the Managing General Partner is its principal place of business at Westpointe Corporate Center One, 1550 Coraopolis Heights Road, 2nd Floor, Moon Township, Pennsylvania 15108, which shall also serve as the principal place of business of the Partnership.

The residence of each Participant shall be as set forth on the Subscription Agreement executed by the Participant.

All addresses shall be subject to change on notice to the parties.

1.03(c). Agent for Service of Process. The name and address of the agent for service of process shall be Andrew M. Lubin at 110 S. Poplar Street, Suite 101, Wilmington, Delaware 19801.

1.04. Purpose. The Partnership shall engage in all phases of the natural gas and oil business. This includes, without limitation, exploration for, development and production of natural gas and oil on the terms and conditions set forth below and any other proper purpose under the Delaware Revised Uniform Limited Partnership Act.

The Managing General Partner may not, without the affirmative vote of Participants whose Units equal a majority of the total Units, do the following:

(i)

change the investment and business purpose of the Partnership; or

(ii)

cause the Partnership to engage in activities outside the stated business purposes of the Partnership through joint ventures with other entities.

ARTICLE II

DEFINITION OF TERMS

2.01. Definitions. As used in this Agreement, the following terms shall have the meanings set forth below:

“Administrative Costs” means all customary and routine expenses incurred by the Sponsor for the conduct of Partnership administration, including: in-house legal, finance, in-house accounting, secretarial, travel, office rent, telephone, data processing and other items of a similar nature. Administrative Costs shall be limited as follows:

(i)

no Administrative Costs charged shall be duplicated under any other category of expense or cost; and

(ii)

no portion of the salaries, benefits, compensation or remuneration of controlling persons of the Managing General Partner shall be reimbursed by the Partnership as Administrative Costs. Controlling persons include directors, executive officers and those holding a 5% or more equity interest in the Managing General Partner or a person having power to direct or cause the direction of the Managing General Partner, whether through the ownership of voting securities, by contract, or otherwise.

“Administrator” means the official or agency administering the securities laws of a state.

“Affiliate” means with respect to a specific person:

(i)

any person directly or indirectly owning, controlling, or holding with power to vote 10% or more of the outstanding voting securities of the specified person;

(ii)

any person 10% or more of whose outstanding voting securities are directly or indirectly owned, controlled, or held with power to vote, by the specified person;

(iii)

any person directly or indirectly controlling, controlled by, or under common control with the specified person;

(iv)

any officer, director, trustee or partner of the specified person; and

(v)

if the specified person is an officer, director, trustee or partner, any person for which the person acts in any such capacity.

“Agreement” means this Amended and Restated Certificate and Agreement of Limited Partnership, including all exhibits to this Agreement.

“Anthem Securities” means Anthem Securities, Inc., whose principal executive offices are located at Westpointe Corporate Center One, 1550 Coraopolis Heights Road, Suite 300, P.O. Box 926, Moon Township, Pennsylvania 15108-0926.

“Assessments” means additional amounts of capital which may be mandatorily required of or paid voluntarily by a Participant beyond his subscription commitment.

“Atlas” means Atlas Resources, LLC, a Pennsylvania limited liability company, whose principal executive offices are located at Westpointe Corporate Center One, 1550 Coraopolis Heights Road, 2nd Floor, Moon Township, Pennsylvania 15108, and any successor entity to Atlas Resources, LLC, whether by merger or any other form of reorganization, or the acquisition of all, or substantially all, of Atlas Resources, LLC’s assets.

“Atlas Resources Public #18-2008 Program” means the offering of Units in a series of up to three limited partnerships entitled Atlas Resources Public #18-2008(A) L.P., Atlas Resources Public #18-2009(B) L.P. and Atlas Resources Public #18-2009(C) L.P.

“Capital Account” or “account” means the account established for each party, maintained as provided in §5.02 and its subsections.

10.

“Capital Contribution” means the amount agreed to be contributed to the Partnership by a Partner pursuant to §§3.04 and 3.05 and their subsections.

11.

“Carried Interest” means an equity interest in the Partnership issued to a Person without consideration, in the form of cash or tangible property, in an amount proportionately equivalent to that received from the Participants.

12.

“Code” means the Internal Revenue Code of 1986, as amended.

13.

“Cost,” when used with respect to the sale or transfer of property to the Partnership, means:

(i)

the sum of the prices paid by the seller or transferor to an unaffiliated person for the property, including bonuses;

(ii)

title insurance or examination costs, brokers’ commissions, filing fees, recording costs, transfer taxes, if any, and like charges in connection with the acquisition of the property;

(iii)

a pro rata portion of the seller’s or transferor’s actual necessary and reasonable expenses for seismic and geophysical services; and

(iv)

rentals and ad valorem taxes paid by the seller or transferor for the property to the date of its transfer to the buyer, interest and points actually incurred on funds used to acquire or maintain the property, and the portion of the seller’s or transferor’s reasonable, necessary and actual expenses for geological, geophysical, engineering, drafting, accounting, legal and other like services allocated to the property cost in conformity with generally accepted accounting principles and industry standards, except for expenses in connection with the past drilling of wells which are not producers of sufficient quantities of oil or gas to make commercially reasonable their continued operations, and provided that the expenses enumerated in this subsection (iv) shall have been incurred not more than 36 months before the sale or transfer to the Partnership.

“Cost,” when used with respect to services, means the reasonable, necessary and actual expense incurred by the seller on behalf of the Partnership in providing the services, determined in accordance with generally accepted accounting principles.

As used elsewhere, “Cost” means the price paid by the seller in an arm’s-length transaction.

14.

“Dealer-Manager” means Anthem Securities, Inc., an Affiliate of the Managing General Partner, the broker/dealer which will manage the offering and sale of the Units.

15.

“Development Well” means a well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic Horizon known to be productive.

16.

“Direct Costs” means all actual and necessary costs directly incurred for the benefit of the Partnership and generally attributable to the goods and services provided to the Partnership by parties other than the Sponsor or its Affiliates. Direct Costs may not include any cost otherwise classified as Organization and Offering Costs, Administrative Costs, Intangible Drilling Costs, Tangible Costs, Operating Costs or costs related to the Leases, but may include the cost of services provided by the Sponsor or its Affiliates if the services are provided pursuant to written contracts and in compliance with §4.03(d)(7) or pursuant to the Managing General Partner’s role as Tax Matters Partner.

17.

“Distribution Interest” means an undivided interest in the Partnership’s assets after payments to the Partnership’s creditors or the creation of a reasonable reserve therefor, in the ratio the positive balance of a party’s Capital Account bears to the aggregate positive balance of the Capital Accounts of all of the parties determined after taking into account all Capital Account adjustments for the taxable year during which liquidation occurs (other than those made pursuant to liquidating distributions or restoration of deficit Capital Account balances). Provided, however, after the Capital Accounts of all of the parties have been reduced to zero, the interest in the remaining Partnership assets shall equal a party’s interest in the related Partnership revenues as set forth in §5.01 and its subsections.

18.

“Drilling and Operating Agreement” means the proposed Drilling and Operating Agreement between the Managing General Partner or an Affiliate as Operator, and the Partnership as Developer, a copy of the proposed form of which is attached to this Agreement as Exhibit (II).

19.

“Exploratory Well” means a well drilled to:

(i)

find commercially productive hydrocarbons in an unproved area;

(ii)

find a new commercially productive Horizon in a field previously found to be productive of hydrocarbons at another Horizon; or

(iii)

significantly extend a known prospect.

20.

“Farmout” means an agreement by the owner of the leasehold or Working Interest to assign his interest in certain acreage or well to the assignees, retaining some interest such as an Overriding Royalty Interest, an oil and gas payment, offset acreage or other type of interest, subject to the drilling of one or more specific wells or other performance as a condition of the assignment.

21.

“Final Terminating Event” means any one of the following:

(i)

the expiration of the Partnership’s fixed term;

(ii)

notice to the Participants by the Managing General Partner of its election to terminate the Partnership’s affairs;

(iii)

notice by the Participants to the Managing General Partner of their similar election through the affirmative vote of Participants whose Units equal a majority of the total Units; or

(iv)

the termination of the Partnership under §708(b)(1)(A) of the Code or the Partnership ceases to be a going concern.

22.

“Horizon” means a zone of a particular formation; that part of a formation of sufficient porosity and permeability to form a petroleum reservoir.

23.

“Independent Expert” means a person with no material relationship to the Sponsor or its Affiliates who is qualified and in the business of rendering opinions regarding the value of natural gas and oil properties based on the evaluation of all pertinent economic, financial, geologic and engineering information available to the Sponsor or its Affiliates.

24.

“Initial Closing Date” means the date after the minimum amount of subscription proceeds has been received when subscription proceeds are first withdrawn from the escrow account.

25.

“Intangible Drilling Costs” or “Non-Capital Expenditures” means those expenditures associated with property acquisition and the drilling and completion of natural gas and oil wells that under present law are generally accepted as fully deductible currently for federal income tax purposes. This includes:

(i)

all expenditures made for any well before production in commercial quantities for wages, fuel, repairs, hauling, supplies and other costs and expenses incident to and necessary for drilling the well and preparing the well for production of natural gas or oil, that are currently deductible pursuant to Section 263(c) of the Code and Treasury Reg. Section 1.612-4, and are generally termed "intangible drilling and development costs";

(ii)

the expense of plugging and abandoning any well before a completion attempt; and

(iii)

the costs (other than Tangible Costs and Lease acquisition costs) to re-enter and deepen an existing well, complete the well to deeper reservoirs, or plug and abandon the well if it is nonproductive from the targeted deeper reservoirs.

26.

“Interim Closing Date” means those date(s) after the Initial Closing Date, but before the Offering Termination Date, that the Managing General Partner, in its sole discretion, applies additional subscription proceeds to additional Partnership activities, including drilling activities.

27.

“Investor General Partners” means:

(i)

the Persons signing the Subscription Agreement as Investor General Partners; and

(ii)

the Managing General Partner to the extent of any optional subscription as an Investor General Partner under §3.03(b)(1).

All Investor General Partners shall be of the same class and have the same rights.

28.

“Landowner’s Royalty Interest” means an interest in production, or its proceeds, to be received free and clear of all costs of development, operation, or maintenance, reserved by a landowner on the creation of a Lease.

29.

“Leases” means full or partial interests in natural gas and oil leases, oil and natural gas mineral rights, fee rights, licenses, concessions, or other rights under which the holder is entitled to explore for and produce oil and/or natural gas, and includes any contractual rights to acquire any such interest.

30.

“Limited Partners” means:

(i)

the Persons signing the Subscription Agreement as Limited Partners;

(ii)

the Managing General Partner to the extent of any optional subscription as a Limited Partner under §3.03(b)(1);

(iii)

the Investor General Partners on the conversion of their Investor General Partner Units to Limited Partner Units pursuant to §6.01(b); and

(iv)

any other Persons who are admitted to the Partnership as additional or substituted Limited Partners.

Except as provided in §3.05(b), with respect to the required additional Capital Contributions of Investor General Partners, all Limited Partners shall be of the same class and have the same rights.

31.

“Managing General Partner” means:

(i)

Atlas; or

(ii)

any Person admitted to the Partnership as a general partner, other than as an Investor General Partner, who is designated to exclusively supervise and manage the operations of the Partnership.

32.

“Managing General Partner Signature Page” means an execution and subscription instrument in the form attached as Exhibit (I-A) to this Agreement, which is incorporated in this Agreement by reference.

33.

“Offering Termination Date” means the date after the minimum amount of subscription proceeds has been received on which the Managing General Partner determines, in its sole discretion, that the Partnership’s subscription period is closed and the acceptance of subscriptions ceases, which may be any date up to and including December 31, 2009.

Notwithstanding the above, the Offering Termination Date may not extend beyond the time that subscriptions for the maximum number of Units set forth in §3.03(c)(1) have been received and accepted by the Managing General Partner.

34.

“Operating Costs” means expenditures made and costs incurred in producing and marketing natural gas or oil from completed wells. These costs include, but are not limited to:

(i)

labor, fuel, repairs, hauling, materials, supplies, utility charges and other costs incident to or related to producing and marketing natural gas and oil;

(ii)

ad valorem and severance taxes;

(iii)

insurance and casualty loss expense; and

(iv)

compensation to well operators or others for services rendered in conducting these operations.

Operating Costs also include disposal and injection wells, transporting waste water by pipeline, truck or barge, reworking, workover, subsequent equipping, and similar expenses relating to any well, the Managing General Partner’s gathering fees set forth in §4.04(a)(2)(d) and the reimbursement of the Managing General Partner’s Administrative Costs set forth in §4.04(a)(2)(c); but do not include the costs to re-enter and deepen an existing well, complete the well to deeper formations or reservoirs, or plug and abandon the well if it is nonproductive from the targeted deeper formations or reservoirs.

35.

“Operator” means Atlas, as operator of Partnership Wells in Pennsylvania, and Atlas or an Affiliate as Operator of Partnership Wells in other areas of the United States.

36.

“Organization and Offering Costs” means all costs of organizing and selling the offering including, but not limited to:

(i)

total underwriting and brokerage discounts and commissions, including fees of the underwriters’ attorneys, the Dealer-Manager fee, sales commissions and reimbursement for bona fide due diligence expenses;

(ii)

expenses for printing, engraving, mailing, salaries of employees while engaged in sales activities, charges of transfer agents, registrars, trustees, escrow holders, depositaries, engineers and other experts;

(iii)

expenses of qualification of the sale of the securities under federal and state law, including taxes and fees, accountants’ and attorneys’ fees; and

(iv)

other front-end fees.

37.

“Organization Costs” means all costs of organizing the offering including, but not limited to:

(i)

(ii)

expenses of qualification of the sale of the securities under federal and state law, including taxes and fees, accountants’ and attorneys’ fees; and

(iii)

other front-end fees.

38.

“Overriding Royalty Interest” means an interest in the natural gas and oil produced under a Lease, or the proceeds from the sale thereof, carved out of the Working Interest, to be received free and clear of all costs of development, operation, or maintenance.

39.

“Participants” means:

(i)

the Managing General Partner to the extent of its optional subscription under §3.03(b)(1);

(ii)

the Limited Partners; and

(iii)

the Investor General Partners.

40.

“Partners” means:

(i)

the Managing General Partner;

(ii)

the Investor General Partners; and

(iii)

the Limited Partners.

41.

“Partnership” means Atlas Resources Public #18-2009(C) L.P.

42.

“Partnership Net Production Revenues” means gross revenues after deduction of the related Operating Costs, Direct Costs, Administrative Costs and all other Partnership costs not specifically allocated.

43.

“Partnership Well” means a well, some portion of the revenues from which is received by the Partnership.

44.

“Person” means a natural person, partnership, corporation, association, trust or other legal entity.

45.

“Production Purchase” or “Income” Program means any program whose investment objective is to directly acquire, hold, operate, and/or dispose of producing oil and gas properties. Such a program may acquire any type of ownership interest in a producing property, including, but not limited to, working interests, royalties, or production payments. A program which spends at least 90% of capital contributions and funds borrowed (excluding offering and organizational expenses) in the above described activities is presumed to be a production purchase or income program.

46.

“Program” means one or more limited or general partnerships or other investment vehicles formed, or to be formed, for the primary purpose of:

(i)

exploring for natural gas, oil and other hydrocarbon substances; or

(ii)

investing in or holding any property interests which permit the exploration for or production of hydrocarbons or the receipt of such production or its proceeds.

47.

“Prospect” means an area covering lands which are believed by the Managing General Partner to contain subsurface structural or stratigraphic conditions making it susceptible to the accumulations of hydrocarbons in commercially productive quantities at one or more Horizons. The area, which may be different for different Horizons, shall be:

(i)

designated by the Managing General Partner in writing before the conduct of Partnership operations; and

(ii)

enlarged or contracted from time to time on the basis of subsequently acquired information to define the anticipated limits of the associated hydrocarbon reserves and to include all acreage encompassed therein.

If the well to be drilled by the Partnership is to a Horizon containing Proved Reserves, then a “Prospect” for a particular Horizon may be limited to the minimum area permitted by state law or local practice, whichever is applicable, to protect against drainage from adjacent wells. Subject to the foregoing sentence, “Prospect” shall be deemed the drilling or spacing unit for the Marcellus Shale reservoir in western Pennsylvania, the Mississippian Carbonate or the Devonian Shale reservoirs in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee, the Upper Devonian New Albany Shale reservoir in Greene, Knox and Sullivan Counties, Indiana and the Antrim Shale reservoir in Antrim and Alcona Counties, Michigan

48.

“Prospectus” means the Prospectus included in the Registration Statement on Form S-1 relating to the offer and sale of the Units which has been filed with the Securities and Exchange Commission (the “Commission”) under the Securities Act of 1933, as amended (the “Act”). As used in this Agreement, the terms “Prospectus” and “Registration Statement” refer solely to the Prospectus and Registration Statement, as amended, described above, except that:

(i)

from and after the date on which any post-effective amendment to the Registration Statement is declared effective by the Commission, the term “Registration Statement” shall refer to the Registration Statement as amended by that post-effective amendment, and the term “Prospectus” shall refer to the Prospectus then forming a part of the Registration Statement; and

(ii)

if the Prospectus filed pursuant to Rule 424(b) or (c) promulgated by the Commission under the Act differs from the Prospectus on file with the Commission at the time the Registration Statement or any post-effective amendment thereto shall have become effective, the term “Prospectus” shall refer to the Prospectus filed pursuant thereto from and after the date on which it was filed.

49.

“Proved Developed Oil and Gas Reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating 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.

50.

“Proved Reserves” means the estimated quantities of crude oil, natural gas, 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, 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.

(i)

Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. 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.

(ii)

(iii)

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 reserves”;

(b)

crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

(c)

crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

(d)

crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

51.

“Proved Undeveloped Reserves” means reserves that are expected to be recovered from either:

(i)

new wells on undrilled acreage; or

(ii)

from existing wells where a relatively major expenditure is required for recompletion.

Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation or there is continuity of the reservoir. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

52.

“Roll-Up” means a transaction involving the acquisition, merger, conversion or consolidation, either directly or indirectly, of the Partnership and the issuance of securities of a Roll-Up Entity. The term does not include:

(i)

a transaction involving securities of the Partnership that have been listed for at least 12 months on a national exchange or traded through the National Association of Securities Dealers Automated Quotation National Market System; or

(ii)

a transaction involving the conversion to corporate, trust or association form of only the Partnership if, as a consequence of the transaction, there will be no significant adverse change in any of the following:

(a)

voting rights;

(b)

the Partnership’s term of existence;

(c)

the Managing General Partner’s compensation; and

(d)

the Partnership’s investment objectives.

53.

“Roll-Up Entity” means a partnership, trust, corporation or other entity that would be created or survive after the successful completion of a proposed roll-up transaction.

54.

“Sales Commissions” means all underwriting and brokerage discounts and commissions incurred in the sale of Units payable to registered broker/dealers, but excluding the following:

(i)

the 2.5% Dealer-Manager fee; and

(ii)

the reimbursement for bona fide due diligence expenses.

55.

“Selling Agents” means the broker/dealers which are selected by the Dealer-Manager to participate in the offer and sale of the Units.

56.

“Sponsor” means any person directly or indirectly instrumental in organizing, wholly or in part, a program or any person who will manage or is entitled to manage or participate in the management or control of a program. The definition includes:

(i)

the managing and controlling general partner(s) and any other person who actually controls or selects the person who controls 25% or more of the exploratory, development or producing activities of the program, or any segment thereof, even if that person has not entered into a contract at the time of formation of the program; and

(ii)

whenever the context so requires, the term “sponsor” shall be deemed to include its affiliates.

“Sponsor” does not include wholly independent third-parties such as attorneys, accountants, and underwriters whose only compensation is for professional services rendered in connection with the offering of units.

57.

“Subscription Agreement” means an execution and subscription instrument in the form attached as Exhibit (I-B) to this Agreement, which is incorporated in this Agreement by reference.

58.

“Tangible Costs” or “Capital Expenditures” means those costs associated with property acquisition and drilling and completing natural gas and oil wells which are generally accepted as capital expenditures under the Code. This includes all of the following:

(i)

costs of equipment, parts and items of hardware used in drilling and completing a well;

(ii)

the costs (other than Intangible Drilling Costs and Lease acquisition costs) to re-enter and deepen an existing well, complete the well to deeper reservoirs, or plug and abandon the well if it is nonproductive from the targeted deeper reservoirs; and

(iii)

those items necessary to deliver acceptable natural gas and oil production to purchasers to the extent installed downstream from the wellhead of any well and which are required to be capitalized under the Code and its regulations.

59.

“Tax Matters Partner” means the Managing General Partner.

60.

“Units” or “Units of Participation” means up to 534 Limited Partner interests in the Partnership and up to 27,035.5 Investor General Partner interests in the Partnership, which will be converted to the same number of Limited Partner Units as set forth in §6.01(b), purchased by Participants in the Partnership under the provisions of §3.03 and its subsections, including any rights to profits, losses, income, gain, credits, deductions, cash distributions or returns of capital or other attributes of the Units. The Partnership reserves the right to adjust the number of Investor General Partner Units, Limited Partner Units and Investor General Partner Units converted to Limited Partner Units set forth above so long as they do not exceed 27,569.5 Units, in the aggregate.

61.

“Working Interest” means an interest in a Lease which is subject to some portion of the cost of development, operation, or maintenance of the Lease.

ARTICLE III

SUBSCRIPTIONS AND FURTHER CAPITAL CONTRIBUTIONS

3.01. Designation of Managing General Partner and Participants. Atlas shall serve as Managing General Partner of the Partnership. Atlas shall further serve as a Participant to the extent of any subscription made by it pursuant to §3.03(b)(1).

Limited Partners and Investor General Partners, including the Managing General Partner and its Affiliates to the extent, if any, they purchase Units, shall serve as Participants.

3.02. Participants.

3.02(a). Limited Partner at Formation. Atlas Energy Resources, LLC, as Original Limited Partner, has acquired one Unit and has made a Capital Contribution of $100. On the admission of one or more Limited Partners, the Partnership shall return to the Original Limited Partner its Capital Contribution and shall reacquire its Unit. The Original Limited Partner shall then cease to be a Limited Partner in the Partnership with respect to that Unit.

3.02(b). Offering of Interests. The Partnership is authorized to admit to the Partnership at the Initial Closing Date, any Interim Closing Date(s), and the Offering Termination Date additional Participants whose Subscription Agreements are accepted by the Managing General Partner if, after the admission of the additional Participants, the total Units sold do not exceed the maximum number of Units set forth in §3.03(c)(1).

3.02(c). Admission of Participants. No action or consent by the Participants shall be required for the admission of additional Participants pursuant to this Agreement.

All subscribers’ funds shall be held in an interest bearing account or accounts by an independent escrow holder and shall not be released to the Partnership until the receipt and acceptance of the minimum amount of subscription proceeds set forth in §3.03(c)(2). Thereafter, subscriptions may be paid directly to a Partnership account.

3.03. Subscriptions to the Partnership.

3.03(a). Subscriptions by Participants.

3.03(a)(1). Subscription Price and Minimum Subscription. The subscription price of a Unit in the Partnership shall be $10,000, except as set forth below, and shall be designated on each Participant’s Subscription Agreement and payable as set forth in §3.05(b)(1). The minimum subscription per Participant shall be one Unit ($10,000). Larger subscriptions shall be accepted in $1,000 increments, beginning with $11,000, $12,000, etc.

Notwithstanding the foregoing, the subscription price for:

(i)

the Managing General Partner, its officers, directors, and Affiliates, and Participants who buy Units through the officers and directors of the Managing General Partner, shall be reduced by an amount equal to the 2.5% Dealer-Manager fee, the 7% Sales Commission and the .5% reimbursement of the Selling Agents’ bona fide due diligence expenses, which shall not be paid with respect to those sales; and

(ii)

Registered Investment Advisors and their clients, and Selling Agents and their registered representatives and principals, shall be reduced by an amount equal to the 7% Sales Commission, which shall not be paid with respect to those sales.

No more than 5% of the total Units in the Partnership shall be sold with the discounts described above.

3.03(a)(2). Effect of Subscription. Execution of a Subscription Agreement shall serve as an agreement by the Participant to be bound by each and every term of this Agreement.

3.03(b). Optional Subscriptions for Units by Managing General Partner.

3.03(b)(1). Managing General Partner’s Optional Subscriptions for Units. In addition to the Managing General Partner’s required Capital Contributions under §3.04(a), on the Initial Closing Date the Managing General Partner may subscribe under the provisions of §3.03(a) and its subsections for up to 5% of the total Units sold in the Partnership as of the Initial Closing Date, which shall not be applied towards the minimum number of Units required to be sold under §3.03(c)(2), and, subject to the limitations on voting rights set forth in §4.03(c)(3), to that extent shall be deemed to be a Participant in the Partnership for all purposes under this Agreement.

3.03(b)(2). Effect of and Evidencing Subscription. The Managing General Partner has executed a Managing General Partner Signature Page which:

(i)

evidences the Managing General Partner’s required Capital Contributions under §3.04(a); and

(ii)

may be amended, from time-to-time, to reflect the amount of any optional subscriptions for Units as a Participant under §3.03(b)(1).

Execution of the Managing General Partner Signature Page serves as an agreement by the Managing General Partner to be bound by each and every term of this Agreement.

3.03(c). Maximum and Minimum Number of Units.

3.03(c)(1). Maximum Number of Units. The maximum number of Units may not exceed 27,569.5 Units, which is $275,695,000 of cash subscription proceeds, excluding the subscription discounts permitted under §3.03(a)(1). Notwithstanding the foregoing, the maximum number of Units in all of the partnerships in the Atlas Resources Public #18-2008 Program, in the aggregate, shall not exceed 60,000 Units which is $600,000,000 of cash subscription proceeds, excluding the subscription discounts permitted under §3.03(a)(1).

3.03(c)(2). Minimum Number of Units. The minimum number of Units shall equal at least 200 Units, but in any event not less than the number of Units that provides the Partnership with cash subscription proceeds of $2,000,000, excluding the subscription discounts permitted under §3.03(a)(1).

If subscriptions for the minimum number of Units have not been received and accepted at the Offering Termination Date, then all monies deposited by subscribers shall be promptly returned to them. They shall receive interest earned on their subscription proceeds from the date the monies were deposited in escrow through the date of refund, without deduction for any fees.

The Partnership may break escrow and begin its drilling activities, in the Managing General Partner’s sole discretion, on receipt and acceptance of the minimum subscription proceeds.

3.03(d). Acceptance of Subscriptions.

3.03(d)(1). Discretion by the Managing General Partner. Acceptance of subscriptions is discretionary with the Managing General Partner. The Managing General Partner may reject any subscription for any reason it deems appropriate.

3.03(d)(2). Time Period in Which to Accept Subscriptions. Subscriptions shall be accepted or rejected by the Managing General Partner within 30 days of their receipt. If a subscription is rejected, then all of the subscriber’s funds shall be returned to the subscriber promptly, with interest earned and without deduction for any fees.

3.03(d)(3). Admission to the Partnership. The Participants shall be admitted to the Partnership as follows:

(i)

not later than 15 days after the release from the escrow account of Participants’ subscription proceeds to the Partnership; or

(ii)

if a Participant’s subscription proceeds are received by the Partnership after the close of the escrow account, then not later than the last day of the calendar month in which his Subscription Agreement was accepted by the Managing General Partner.

3.04. Capital Contributions of the Managing General Partner.

3.04(a). Managing General Partner’s Required Capital Contributions. The Managing General Partner, as a general partner and not as a Participant, is required to pay the costs or make the other required Capital Contributions charged to it under this Agreement, which includes its credit for Organization and Offering Costs under §5.01(a)(1), contributing to the Partnership the Leases which will be drilled by the Partnership on the terms set forth in §4.01(a)(4) and the Managing General Partner’s administration and oversight fee and 18% mark up on the portion of the Partnership’s Tangible Costs paid by the Managing General Partner under §5.01(a)(3), in an amount equal to not less than 15%, in the aggregate, of all Capital Contributions to the Partnership, at the time the costs are required to be paid by the Partnership, but in any event no later than December 31, 2010.

3.04(b). On Liquidation the Managing General Partner Must Contribute Deficit Balance in Its Capital Account. The Managing General Partner shall contribute to the Partnership any deficit balance in its Capital Account on the occurrence of either of the following events:

(i)

the liquidation of the Partnership; or

(ii)

the liquidation of the Managing General Partner’s interest in the Partnership.

This shall be determined after taking into account all adjustments for the Partnership’s taxable year during which the liquidation occurs, other than adjustments made pursuant to this requirement, by the end of the taxable year in which the liquidation occurs or, if later, within 90 days after the date of the liquidation.

3.04(c). Managing General Partner’s Partnership Interest for Capital Contributions. The interest of the Managing General Partner, as Managing General Partner and not as a Participant, in the capital and profits of the Partnership is fully vested and nonforfeitable as of the date of the formation of the Partnership and is in consideration for, and is the only consideration for, its required Capital Contributions to the Partnership.

3.04(d). Managing General Partner’s Right to Assign Its Partnership Interest. Subject to §5.01(b)(4)(a) regarding the Managing General Partner’s subordination obligation, the Managing General Partner has the right at any time, in its discretion, without the consent of the Participants, and without affecting the allocation of costs and revenues to the Participants or the Managing General Partner’s voting rights under this Agreement, to sell, contribute, exchange or otherwise transfer all or any portion of its interest as Managing General Partner or as a Participant (if it purchases Units) in the Partnership, or any interest therein to an Affiliate of the Managing General Partner. In that event, except as otherwise may be permitted under this Agreement, if the Affiliated transferee of the Managing General Partner’s transferred interest in the Partnership does not become a substituted Managing General Partner in the Partnership, the Affiliated transferee, as a partner in the Partnership for tax purposes only, shall have the right to receive the share of the Partnership’s profits, losses, income, gains, deductions, credits and depletion allowances, or items thereof, and cash distributions and returns of capital (including, but not limited to, cash distributions and returns of capital on dissolution and liquidation of the Partnership) to which the Managing General Partner would otherwise be entitled under this Agreement with respect to its transferred interest in the Partnership.

Subject to the foregoing, the transfer of the Managing General Partner’s interest in the Partnership to any of its Affiliates may be made on any terms and conditions as the Managing General Partner determines, in its discretion, and the Partnership and the Participants shall have no right to receive or otherwise share in any consideration received by the Managing General Partner from its Affiliates for the transfer of the Managing General Partner’s interest in the Partnership.

No transfer of the Managing General Partner’s interest in the Partnership to its Affiliates under this §3.04(d) shall require an accounting by the Managing General Partner or the Partnership to the Participants.

3.05. Payment of Subscriptions.

3.05(a). Managing General Partner’s Subscriptions. The Managing General Partner shall pay any optional subscription under §3.03(b)(1) as set forth in §3.05(b)(1).

3.05(b). Participant Subscriptions and Additional Capital Contributions of the Investor General Partners.

3.05(b)(1). Payment of Subscription Agreements. A Participant shall pay the subscription amount designated on his Subscription Agreement 100% in cash at the time of subscribing. A Participant shall receive interest on the amount he pays from the time his subscription proceeds are deposited in the escrow account, or a Partnership account after the minimum number of Units have been received as provided in §3.06(b), until his subscription proceeds are paid by the Partnership to the Managing General Partner under the Drilling and Operating Agreement for use in the Partnership’s drilling activities. All interest distributions shall be in the ratio that the number of Units held by each Participant multiplied by the number of days the Participant’s subscription proceeds were held in the escrow account, or a Partnership account after the minimum number of Units have been received as provided in §3.06(b), bears to the sum of that calculation for all Participants whose subscription proceeds were paid to the Managing General Partner at the same time. Interest on subscription amounts shall be paid as provided in §5.01(b)(2).

3.05(b)(2). Additional Required Capital Contributions of the Investor General Partners. Investor General Partners must make Capital Contributions to the Partnership when called by the Managing General Partner, in addition to their subscription amounts, for their pro rata share of any Partnership obligations and liabilities which are recourse to the Investor General Partners and are represented by their ownership of Units before the conversion of Investor General Units to Limited Partner Units under §6.01(b).

3.05(b)(3). Default Provisions. The failure of an Investor General Partner to timely make a required additional Capital Contribution under this section results in his personal liability to the other Investor General Partners for the amount in default. The remaining Investor General Partners, in proportion to their respective number of Units, must pay the defaulting Investor General Partner’s share of Partnership liabilities and obligations called for by the Managing General Partner. In that event, the remaining Investor General Partners:

(i)

shall have a first and preferred lien on the defaulting Investor General Partner’s interest in the Partnership to secure payment of the amount in default plus interest at the legal rate;

(ii)

shall be entitled to receive 100% of the defaulting Investor General Partner’s cash distributions, in proportion to their respective number of Units, until the amount in default is recovered in full plus interest at the legal rate; and

(iii)

may commence legal action to collect the amount due plus interest at the legal rate.

3.06. Partnership Funds.

3.06(a). Fiduciary Duty. The Managing General Partner has a fiduciary responsibility for the safekeeping and use of all funds and assets of the Partnership, whether or not in the Managing General Partner’s possession or control. The Managing General Partner shall not employ, or permit another to employ, the funds and assets of the Partnership in any manner except for the exclusive benefit of the Partnership.

Neither this Agreement nor any other agreement between the Managing General Partner and the Partnership shall contractually limit any fiduciary duty owed to the Participants by the Managing General Partner under applicable law.

3.06(b). Special Account After the Receipt of the Minimum Partnership Subscriptions. Following the receipt of the minimum number of Units and breaking escrow, the funds of the Partnership shall be held in a separate interest-bearing account maintained for the Partnership and shall not be commingled with funds of any other entity.

3.06(c). Investment.

3.06(c)(1). Investments in Other Entities. Partnership funds shall not be invested in the securities of another person except in the following instances:

(i)

investments in Working Interests or undivided Lease interests made in the ordinary course of the Partnership’s business;

(ii)

temporary investments made as set forth in §3.06(c)(2);

(iii)

multi-tier arrangements meeting the requirements of §4.03(d)(15);

(iv)

investments involving less than 5% of the Partnership’s subscription proceeds which are a necessary and incidental part of a property acquisition transaction; and

(v)

investments in entities established solely to limit the Partnership’s liabilities associated with the ownership or operation of property or equipment, provided that duplicative fees and expenses shall be prohibited.

3.06(c)(2). Permissible Investments Before Investment in Partnership Activities. After the Initial Closing Date and until proceeds from the offering are invested in the Partnership’s operations, the proceeds may be temporarily invested in income producing short-term, highly liquid investments, in which there is appropriate safety of principal, such as U.S. Treasury Bills.

ARTICLE IV

CONDUCT OF OPERATIONS

4.01. Acquisition of Leases.

4.01(a). Assignment to Partnership.

4.01(a)(1). In General. The Managing General Partner shall select, acquire and assign or cause to have assigned to the Partnership full or partial interests in Leases, by any method customary in the natural gas and oil industry, subject to the terms and conditions set forth below.

The Partnership and the other partnerships in the Atlas Resources Public #18-2008 Program may acquire and develop interests in Leases covering one or more of the same Prospects, in the Managing General Partner’s discretion.

The Partnership shall acquire only Leases reasonably expected to meet the stated purposes of the Partnership. No Leases shall be acquired for the purpose of a subsequent sale, Farmout, or other disposition unless the acquisition is made after a well has been drilled to a depth sufficient to indicate that the acquisition would be in the Partnership’s best interest.

4.01(a)(2). Federal and State Leases. The Partnership is authorized to acquire Leases on federal and state lands.

4.01(a)(3). Managing General Partner’s Discretion as to Terms and Burdens of Acquisition. Subject to the provisions of §4.03(d) and its subsections, the acquisitions of Leases or other property may be made under any terms and obligations, including any limitations as to the Horizons to be assigned to the Partnership and subject to any burdens as the Managing General Partner deems necessary in its sole discretion.

4.01(a)(4). Cost of Leases. All Leases shall be:

(i)

contributed to the Partnership by the Managing General Partner or its Affiliates; and

(ii)

credited towards the Managing General Partner's required Capital Contribution set forth in §3.04(a) at the Cost of the Lease as described in the Prospectus under “Compensation – Lease Costs,” unless the Managing General Partner has cause to believe that Cost is materially more than the fair market value of the property, in which case the credit for the contribution must be made at a price not in excess of the fair market value. Also, the Managing General Partner may average the cost of the Leases by area or type of drilling to arrive at an average Lease cost per Prospect for each area as described in the Prospectus under “Compensation – Lease Costs,” which the Managing General Partner believes is less than fair market value. Additionally, from time to time, the Managing General Partner’s Lease costs on a Prospect may be significantly higher than the amount set forth in the Prospectus under “Compensation – Lease Costs,” and in that event the Managing General Partner’s credit to its Capital Contribution to the Partnership and its Capital Account under this Agreement shall be the greater amount.

A determination of fair market value must be supported by an appraisal from an Independent Expert.

4.01(a)(5). The Managing General Partner, Operator or Their Affiliates’ Rights in the Remainder Interests. Subject to the provisions of §4.03(d) and its subsections, to the extent the Partnership does not acquire a full interest in a Lease from the Managing General Partner or its Affiliates, the remainder of the interest in the Lease may be held by the Managing General Partner or its Affiliates. They may either:

(i)

retain and exploit the remaining interest for their own account; or

(ii)

sell or otherwise dispose of all or a part of the remaining interest.

Profits from the exploitation and/or disposition of their retained interests in the Leases shall be for the benefit of the Managing General Partner or its Affiliates to the exclusion of the Partnership and the Participants.

4.01(a)(6). No Breach of Duty. Subject to the provisions of §4.03 and its subsections, acquisition of Leases from the Managing General Partner, the Operator or their Affiliates shall not be considered a breach of any obligation owed by them to the Partnership or the Participants.

4.01(b). No Overriding Royalty Interests. Neither the Managing General Partner, the Operator nor any Affiliate shall retain any Overriding Royalty Interest on the Leases acquired by the Partnership.

4.01(c). Title and Nominee Arrangements.

4.01(c)(1). Legal Title. Legal title to all Leases acquired by the Partnership shall be held on a permanent basis in the name of the Partnership. However, Partnership properties may be held temporarily in the name of:

(i)

the Managing General Partner;

(ii)

the Operator;

(iii)

their Affiliates; or

(iv)

in the name of any nominee designated by the Managing General Partner to facilitate the acquisition of the properties.

4.01(c)(2). Managing General Partner’s Discretion. The Managing General Partner shall take the steps which are necessary in its best judgment to render title to the Leases to be acquired by the Partnership acceptable for the purposes of the Partnership. The Managing General Partner shall be free, however, to use its own best judgment in waiving title requirements.

The Managing General Partner shall not be liable to the Partnership or to the other parties for any mistakes of judgment; nor shall the Managing General Partner be deemed to be making any warranties or representations, express or implied, as to the validity or merchantability of the title to the Leases assigned to the Partnership or the extent of the interest covered thereby except as otherwise provided in the Drilling and Operating Agreement.

4.01(c)(3). Commencement of Operations. The Partnership shall not begin operations on its Leases unless the Managing General Partner is satisfied that necessary title requirements have been satisfied.

4.02. Conduct of Operations.

4.02(a). In General. The Managing General Partner shall establish a program of operations for the Partnership. Subject to the limitations contained in Article III of this Agreement concerning the maximum Capital Contribution which can be required of a Limited Partner, the Managing General Partner, the Limited Partners, and the Investor General Partners agree to participate in the program so established by the Managing General Partner.

4.02(b). Management. Subject to any restrictions contained in this Agreement, the Managing General Partner shall exercise full control over all operations of the Partnership.

4.02(c). General Powers of the Managing General Partner.

4.02(c)(1). In General. Subject to the provisions of §4.03 and its subsections, and to any authority that may be granted the Operator under §4.02(c)(3)(b), the Managing General Partner shall have full authority to do all things deemed necessary or desirable by it in the conduct of the business of the Partnership. Without limiting the generality of the foregoing, the Managing General Partner is expressly authorized to engage in:

(i)

the making of all determinations of which Leases, wells and operations will be participated in by the Partnership, which includes:

(a)

which Leases are developed;

(b)

which Leases are abandoned; or

(c)

which Leases are sold or assigned to other parties, including other investor ventures organized by the Managing General Partner, the Operator, or any of their Affiliates;

(ii)

the negotiation and execution on any terms deemed desirable in its sole discretion of any contracts, conveyances, or other instruments, considered useful to the conduct of the operations or the implementation of the powers granted it under this Agreement, including, without limitation:

(a)

the making of agreements for the conduct of operations, including agreements and financial instruments relating to hedging the Partnership’s natural gas and oil and the pledge of up to 100% of the Partnership’s assets and reserves in connection therewith, and in this regard the Partnership has confirmed its authorization to Atlas America, Inc. and/or Atlas Energy Resources, LLC to enter into hedging agreements on its behalf, and has ratified all actions previously taken by Atlas America, Inc. and/or Atlas Energy Resources, LLC, or their successors in interest by merger or otherwise, in connection therewith;

(b)

the exercise of any options, elections, or decisions under any such agreements; and

(c)

the furnishing of equipment, facilities, supplies and material, services, and personnel;

(iii)

the exercise, on behalf of the Partnership or the parties, as the Managing General Partner in its sole judgment deems best, of all rights, elections and options granted or imposed by any agreement, statute, rule, regulation, or order;

(iv)

the making of all decisions concerning the desirability of payment, and the payment or supervision of the payment, of all delay rentals and shut-in and minimum or advance royalty payments;

(v)

the selection of full or part-time employees and outside consultants and contractors and the determination of their compensation and other terms of employment or hiring;

(vi)

the maintenance of insurance for the benefit of the Partnership and the parties as it deems necessary, but in no event less in amount or type than the following:

(a)

worker’s compensation insurance in full compliance with the laws of the Commonwealth of Pennsylvania and any other applicable state laws;

(b)

liability insurance, including automobile, which has a $1,000,000 combined single limit for bodily injury and property damage in any one accident or occurrence and in the aggregate; and

(c)

liability and excess liability insurance as to bodily injury and property damage with combined limits of $50,000,000 during drilling operations and thereafter, per occurrence or accident and in the aggregate, which includes $1,000,000 of seepage, pollution and contamination insurance which protects and defends the insured against property damage or bodily injury claims from third-parties, other than a co-owner of the Working Interest, alleging seepage, pollution or contamination damage resulting from a pollution incident. The excess liability insurance, which is for general liability only, shall be in place and effective no later than the date drilling operations begin and, for purposes of satisfying this requirement, the Partnership shall have the benefit of the Managing General Partner’s $50,000,000 liability insurance on the same basis as the Managing General Partner and its other Affiliates, including the Managing General Partner’s other Programs;

(vii)

the use of the funds and revenues of the Partnership, and the borrowing on behalf of, and the loan of money to, the Partnership, on any terms it sees fit, for any purpose, including without limitation:

(a)

the conduct or financing, in whole or in part, of the drilling and other activities of the Partnership;

(b)

the conduct of additional operations; and

(c)

the repayment of any borrowings or loans used initially to finance these operations or activities;

(viii)

the disposition, hypothecation, sale, exchange, release, surrender, reassignment or abandonment of any or all assets of the Partnership, including without limitation, the Leases, wells, equipment and production therefrom, provided that the sale of all or substantially all of the assets of the Partnership shall only be made as provided in §4.03(d)(6);

(ix)

the formation of any further limited or general partnership, tax partnership, joint venture, or other relationship which it deems desirable with any parties who it, in its sole discretion, selects, including any of its Affiliates;

(x)

the control of any matters affecting the rights and obligations of the Partnership, including:

(a)

the employment of attorneys to advise and otherwise represent the Partnership;

(b)

the conduct of litigation and incurring other legal expenses; and

(c)

the settlement of claims and litigation;

(xi)

the operation of producing wells drilled on the Leases or on a Prospect which includes any part of the Leases;

(xii)

the exercise of the rights granted to it under the power of attorney created under this Agreement; and

(xiii)

the incurring of all costs and the making of all expenditures in any way related to any of the foregoing.

4.02(c)(2). Scope of Powers. The Managing General Partner’s powers shall extend to any operation participated in by the Partnership or affecting its Leases, or other property or assets, irrespective of whether or not the Managing General Partner is designated operator of the operation by any outside persons participating therein.

4.02(c)(3). Delegation of Authority.

4.02(c)(3)(a). In General. The Managing General Partner may subcontract and delegate all or any part of its duties under this Agreement to any entity chosen by it, including an entity Affiliated with it, which party shall have the same powers in the conduct of the duties as would the Managing General Partner. The delegation, however, shall not relieve the Managing General Partner of its responsibilities under this Agreement.

4.02(c)(3)(b). Delegation to Operator. The Managing General Partner is specifically authorized to delegate any or all of its duties to the Operator by executing the Drilling and Operating Agreement. This delegation shall not relieve the Managing General Partner of its responsibilities under this Agreement.

In no event shall any consideration received for operator services be in excess of competitive rates or duplicative of any consideration or reimbursements received under this Agreement. The Managing General Partner may not benefit by interpositioning itself between the Partnership and the actual provider of operator services.

4.02(c)(4). Related Party Transactions. Subject to the provisions of §4.03 and its subsections, any transaction which the Managing General Partner is authorized to enter into on behalf of the Partnership under the authority granted in this section and its subsections, may be entered into by the Managing General Partner with itself or with any other general partner, the Operator, or any of their Affiliates.

4.02(d). Additional Powers. In addition to the powers granted the Managing General Partner under §4.02(c) and its subsections or elsewhere in this Agreement, the Managing General Partner, when specified, shall have the following additional express powers.

4.02(d)(1). Drilling Contracts. All Partnership Wells shall be drilled under the Drilling and Operating Agreement for an amount equal to the sum of the following items:

(i)

the Cost of permits, supplies, materials, equipment, and all other items used in the drilling and completion of a well provided by third-parties, or if the foregoing items are provided by Affiliates of the Managing General Partner, then those items will be charged at competitive rates;

(ii)

fees for third-party services;

(iii)

fees for services provided by the Managing General Partner’s Affiliates, which will be charged at competitive rates;

(iv)

an administration and oversight fee, as described in the Drilling and Operating Agreement, which will be charged to the Participants as part of each well’s Intangible Drilling Costs and the portion of Tangible Costs paid by the Participants; and

(v)

a mark-up in an amount equal to 18% of the sum of (i), (ii), (iii) and (iv), above, for the Managing General Partner’s services as general drilling contractor.

Additionally, if the Managing General Partner drills a well for the Partnership that the Managing General Partner determines is not an average well in the area because of the well’s depth, complexity associated with either drilling or completing the well, or as otherwise determined by the Managing General Partner, the administration and oversight fee of the well described in §4.02(d)(1)(iv) may be increased to a competitive rate as determined by the Managing General Partner.

The Managing General Partner or its Affiliates, as drilling contractor, may not receive a rate that is not competitive with the rates charged by unaffiliated contractors in the same geographic region, enter into a turnkey drilling contract with the Partnership, profit by drilling in contravention of its fiduciary obligations to the Partnership, or benefit by interpositioning itself between the Partnership and the actual provider of drilling contractor services.

4.02(d)(2). Power of Attorney.

4.02(d)(2)(a). In General. Each Participant appoints the Managing General Partner his true and lawful attorney-in-fact for him and in his name, place, and stead and for his use and benefit, from time to time:

(i)

to create, prepare, complete, execute, file, swear to, deliver, endorse, and record any and all documents, certificates, government reports, or other instruments as may be required by law, or are necessary to amend this Agreement as authorized under the terms of this Agreement, or to qualify the Partnership as a limited partnership or partnership in commendam and to conduct business under the laws of any jurisdiction in which the Managing General Partner elects to qualify the Partnership or conduct business; and

(ii)

to create, prepare, complete, execute, file, swear to, deliver, endorse and record any and all instruments, assignments, security agreements, financing statements, certificates, and other documents as may be necessary from time to time to implement the borrowing powers granted under this Agreement and any agreements entered into by the Partnership to hedge its natural gas and oil reserves and pledge up to 100% of its assets and natural gas and oil reserves in connection therewith.

4.02(d)(2)(b). Further Action. Each Participant authorizes the attorney-in-fact to take any further action which the attorney-in-fact considers necessary or advisable in connection with any of the foregoing powers and rights granted the Managing General Partner under this section and its subsections. Each party acknowledges that the power of attorney granted under §4.02(d)(2)(a):

(i)

is a special power of attorney coupled with an interest and is irrevocable; and

(ii)

shall survive the assignment by the Participant of the whole or a portion of his Units; except when the assignment is of all of the Participant’s Units and the purchaser, transferee, or assignee of the Units is admitted as a successor Participant, the power of attorney shall survive the delivery of the assignment for the sole purpose of enabling the attorney-in-fact to execute, acknowledge, and file any agreement, certificate, instrument or document necessary to effect the substitution.

4.02(d)(2)(c). Power of Attorney to Operator. The Managing General Partner is hereby authorized to grant a Power of Attorney to the Operator on behalf of the Partnership.

4.02(e). Borrowings and Use of Partnership Revenues.

4.02(e)(1). Power to Borrow or Use Partnership Revenues.

4.02(e)(1)(a). In General. If additional funds over the Participants’ Capital Contributions are needed for Partnership operations, then the Managing General Partner may:

(i)

use Partnership revenues for such purposes; or

(ii)

the Managing General Partner and its Affiliates may advance the necessary funds to the Partnership under §4.03(d)(8)(b), although they are not obligated to advance the funds to the Partnership.

4.02(e)(1)(b). Limitation on Borrowing. Partnership borrowings, other than credit transactions on open account customary in the industry to obtain goods and services, shall be subject to the following limitations:

(i)

the borrowings must be without recourse to the Investor General Partners and the Limited Partners except as otherwise provided in this Agreement; and

(ii)

the amount that may be borrowed at any one time may not exceed an amount equal to 5% of the Partnership’s subscription proceeds.

Notwithstanding, the above limitations shall not affect the Partnership’s ability to enter into agreements and financial instruments relating to hedging the Partnership’s natural gas and oil and the pledge of up to 100% of the Partnership’s assets and reserves in connection therewith.

4.02(f). Tax Matters Partner.

4.02(f)(1). Designation of Tax Matters Partner. The Managing General Partner is hereby designated the Tax Matters Partner of the Partnership under Section 6231(a)(7) of the Code. The Managing General Partner is authorized to act in this capacity on behalf of the Partnership and the Participants and to take any action, including settlement or litigation, which it in its sole discretion deems to be in the best interest of the Partnership.

4.02(f)(2). Costs Incurred by Tax Matters Partner. Costs incurred by the Tax Matters Partner shall be considered a Direct Cost of the Partnership.

4.02(f)(3). Notice to Participants of IRS Proceedings. The Tax Matters Partner shall notify all of the Participants of any administrative or other legal proceedings involving the Partnership and the IRS or any other taxing authority, and thereafter shall furnish all of the Participants periodic reports at least quarterly on the status of the proceedings.

4.02(f)(4). Participant Restrictions. Each Participant agrees as follows:

(i)

he will not file the statement described in Section 6224(c)(3)(B) of the Code prohibiting the Managing General Partner as the Tax Matters Partner for the Partnership from entering into a settlement on his behalf with respect to Partnership items, as that term is defined in Section 6231(a)(3) of Code, of the Partnership;

(ii)

he will not form or become and exercise any rights as a member of a group of Partners having a 5% or greater interest in the profits of the Partnership under Section 6223(b)(2) of the Code; and

(iii)

the Managing General Partner is authorized to file a copy of this Agreement, or pertinent portions of this Agreement, with the IRS under Section 6224(b) of the Code if necessary to perfect the waiver of rights under this subsection.

4.03. General Rights and Obligations of the Participants and Restricted and Prohibited Transactions.

4.03(a)(1). Limited Liability of Limited Partners. Limited Partners shall not be bound by the obligations of the Partnership other than as provided under the Delaware Revised Uniform Limited Partnership Act. Limited Partners shall not be personally liable for any debts of the Partnership or any of the obligations or losses of the Partnership beyond the subscription amount designated on the Subscription Agreement executed by each respective Limited Partner unless:

(i)

they also subscribe to the Partnership as Investor General Partners; or

(ii)

in the case of the Managing General Partner, it purchases Limited Partner Units.

4.03(a)(2). No Management Authority of Participants. Participants, other than the Managing General Partner if it buys Units, shall have no power over the conduct of the affairs of the Partnership. No Participant, other than the Managing General Partner if it buys Units, shall take part in the management of the business of the Partnership, or have the power to sign for or to bind the Partnership.

4.03(b). Reports and Disclosures.

4.03(b)(1). Annual Reports and Financial Statements. Beginning with the calendar year in which the Partnership had its Offering Termination Date, the Partnership shall provide each Participant an annual report within 120 days after the close of that calendar year, and beginning with the following calendar year, a report within 75 days after the end of the first six months of its calendar year, containing except as otherwise indicated, at least the information set forth below:

(i)

Audited financial statements of the Partnership, including a balance sheet and statements of income, cash flow, and Partners’ equity, which shall be prepared on an accrual basis in accordance with generally accepted accounting principles with a reconciliation with respect to information furnished for income tax purposes and accompanied by an auditor’s report containing an opinion of an independent public accountant selected by the Managing General Partner stating that his audit was made in accordance with generally accepted auditing standards and that in his opinion the financial statements present fairly the financial position, results of operations, partners’ equity, and cash flows in accordance with generally accepted accounting principles. Semiannual reports are not required to be audited.

(ii)

A summary itemization, by type and/or classification of the total fees and compensation, including any nonaccountable, fixed payment reimbursements for Administrative Costs and Operating Costs, paid by, or on behalf of, the Partnership to the Managing General Partner, the Operator, and their Affiliates.

Also, the independent certified public accountant shall provide written attestation annually, which will be included in the annual report, that the method used to make allocations of the Partnership’s Administrative Costs was consistent with the method described in §4.04(a)(2)(c) of this Agreement and that the total amount of Administrative Costs allocated did not materially exceed the amounts described in §4.04(a)(2)(c). If the Managing General Partner subsequently decides to allocate Administrative Costs in a manner different from that described in §4.04(a)(2)(c) of this Agreement, then the change must be reported to the Participants together with an explanation of the reason for the change and the basis used for determining the reasonableness of the new allocation method.

(iii)

A description of each Prospect in which the Partnership owns an interest, including:

(a)

the cost, location, and number of acres under Lease; and

(b)

the Working Interest owned in the Prospect by the Partnership.

Succeeding reports, however, must only contain material changes, if any, regarding the Prospects.

(iv)

A list of the wells drilled or abandoned by the Partnership during the period of the report, indicating:

(a)

whether each of the wells has or has not been completed;

(b)

a statement of the cost of each well completed or abandoned; and

(c)

justification for wells abandoned after production has begun.

(v)

A description of all Farmouts, farmins, and joint ventures, made during the period of the report, including:

(a)

the Managing General Partner’s justification for the arrangement; and

(b)

a description of the material terms.

(vi)

A schedule reflecting:

(a)

the total Partnership costs;

(b)

the costs paid by the Managing General Partner and the costs paid by the Participants;

(c)

the total Partnership revenues;

(d)

the revenues received or credited to the Managing General Partner and the revenues received and credited to the Participants; and

(e)

a reconciliation of the expenses and revenues in accordance with the provisions of Article V.

Additionally, on request the Managing General Partner will provide the information specified by Form 10-Q (if such report is required to be filed with the SEC) within 45 days after the close of each quarterly fiscal period.

4.03(b)(2). Tax Information. The Partnership shall, by March 15 of each year, prepare, or supervise the preparation of, and transmit to each Participant the information needed for the Participant to file the following:

(i)

his federal income tax return;

(ii)

any required state income tax return; and

(iii)

any other reporting or filing requirements imposed by any governmental agency or authority.

4.03(b)(3). Reserve Report. Beginning with the second calendar year after the Offering Termination Date and every year thereafter, the Partnership shall provide to each Participant the following:

(i)

a summary of the computation of the Partnership’s total natural gas and oil Proved Reserves;

(ii)

a summary of the computation of the present worth of the reserves determined using:

(a)

a discount rate of 10%;

(b)

a constant price for the oil; and

(c)

basing the price of natural gas on the existing natural gas contracts;

(iii)

a statement of each Participant’s interest in the reserves; and

(iv)

an estimate of the time required for the extraction of the reserves with a statement that because of the time period required to extract the reserves the present value of revenues to be obtained in the future is less than if immediately receivable.

The reserve computations shall be based on engineering reports prepared by the Managing General Partner and reviewed by an Independent Expert.

Also, if any event reduces the Partnership’s Proved Reserves by 10% or more, excluding a reduction of reserves as a result of normal production, sales of reserves, or natural gas or oil price changes, then a computation and estimate of the amount of the reduction in reserves must be sent to each Participant within 90 days after the Managing General Partner determines that such a reduction in reserves has occurred.

4.03(b)(4). Cost of Reports. The cost of all reports described in this §4.03(b) shall be paid by the Partnership as Direct Costs.

4.03(b)(5). Participant Access to Records. The Participants and/or their representatives shall be permitted access to all Partnership records, provided that access to the list of Participants shall be subject to §4.03(b)(7) below. Subject to the foregoing, a Participant may inspect and copy any of the Partnership’s records after giving adequate notice to the Managing General Partner at any reasonable time.

Notwithstanding the foregoing, the Managing General Partner may keep logs, well reports, and other drilling and operating data confidential for reasonable periods of time. The Managing General Partner may release information concerning the operations of the Partnership to the sources that are customary in the industry or required by rule, regulation, or order of any regulatory body.

4.03(b)(6). Required Length of Time to Hold Records. The Managing General Partner must maintain and preserve during the term of the Partnership and for six years thereafter all accounts, books and other relevant documents which include:

(i)

a record that a Participant meets the suitability standards established in connection with an investment in the Partnership; and

(ii)

any appraisal of the fair market value of the Leases as set forth in §4.01(a)(4), along with associated supporting information, or the fair market value of any producing property as set forth in §4.03(d)(3).

4.03(b)(7). Participant Lists. The following provisions apply regarding access to the list of Participants:

(i)

an alphabetical list of the names, addresses, and business telephone numbers of the Participants along with the number of Units held by each of them (the “Participant List”) must be maintained as a part of the Partnership’s books and records and be available for inspection by any Participant or his designated agent at the home office of the Partnership on the Participant’s request;

(ii)

the Participant List must be updated at least quarterly to reflect changes in the information contained in the Participant List;

(iii)

a copy of the Participant List must be mailed to any Participant requesting the Participant List within 10 days of the written request, printed in alphabetical order on white paper, and in a readily readable type size in no event smaller than 10-point type and a reasonable charge for copy work will be charged by the Partnership;

(iv)

the purposes for which a Participant may request a copy of the Participant List include, without limitation, matters relating to Participant’s voting rights under this Agreement and the exercise of Participant’s rights under the federal proxy laws; and

(v)

if the Managing General Partner neglects or refuses to exhibit, produce, or mail a copy of the Participant List as requested, the Managing General Partner shall be liable to any Participant requesting the list for the costs, including attorneys fees, incurred by that Participant for compelling the production of the Participant List, and for actual damages suffered by any Participant by reason of the refusal or neglect. It shall be a defense that the actual purpose and reason for the request for inspection or for a copy of the Participant List is to secure the list of Participants or other information for the purpose of selling the list or information or copies of the list, or of using the same for a commercial purpose other than in the interest of the applicant as a Participant relative to the affairs of the Partnership. The Managing General Partner will require the Participant requesting the Participant List to represent in writing that the list was not requested for a commercial purpose unrelated to the Participant’s interest in the Partnership. The remedies provided under this subsection to Participants requesting copies of the Participant List are in addition to, and shall not in any way limit, other remedies available to Participants under federal law or the laws of any state.

4.03(b)(8). State Filings. Concurrently with their transmittal to Participants, and as required, the Managing General Partner shall file a copy of each report provided for in this §4.03(b) with:

(i)

the California Commissioner of Corporations;

(ii)

the Ohio Securities Bureau;

(iii)

the Alabama Securities Commission; and

(iv)

the securities commissions of other states which request the report.

4.03(c). Meetings of Participants.

4.03(c)(1). Procedure for a Participant Meeting.

4.03(c)(1)(a). Meetings May Be Called by Managing General Partner or Participants. Meetings of the Participants may be called as follows:

(i)

by the Managing General Partner; or

(ii)

by Participants whose Units equal 10% or more of the total Units for any matters on which Participants may vote.

The call for a meeting by the Participants as described above shall be deemed to have been made on receipt by the Managing General Partner of a written request from holders of the requisite percentage of Units stating the purpose(s) of the meeting.

4.03(c)(1)(b). Notice Requirement. The Managing General Partner shall deposit in the United States mail within 15 days after the receipt of the request, written notice to all Participants of the meeting and the purpose of the meeting. The meeting shall be held on a date not less than 30 days nor more than 60 days after the date of the mailing of the notice, at a reasonable time and place.

Notwithstanding the foregoing, the date for notice of the meeting may be extended for a period of up to 60 days if, in the opinion of the Managing General Partner, the additional time is necessary to permit preparation of proxy or information statements or other documents required to be delivered in connection with the meeting by the SEC or other regulatory authorities.

4.03(c)(1)(c). May Vote by Proxy. Participants shall have the right to vote at any Participant meeting either:

(i)

in person; or

(ii)

by proxy.

4.03(c)(2). Special Voting Rights. At the request of Participants whose Units equal 10% or more of the total Units, the Managing General Partner shall call for a vote by Participants. Each Unit is entitled to one vote on all matters, and each fractional Unit is entitled to that fraction of one vote equal to the fractional interest in the Unit. Participants whose Units equal a majority of the total Units may, without the concurrence of the Managing General Partner or its Affiliates, vote to:

(i)

dissolve the Partnership;

(ii)

remove the Managing General Partner and elect a new Managing General Partner;

(iii)

elect a new Managing General Partner if the Managing General Partner elects to withdraw from the Partnership;

(iv)

remove the Operator and elect a new Operator;

(v)

approve or disapprove the sale of all or substantially all of the assets of the Partnership;

(vi)

cancel any contract for services with the Managing General Partner, the Operator, or their Affiliates without penalty on 60 days notice; and

(vii)

amend this Agreement; provided however:

(a)

any amendment may not increase the duties or liabilities of any Participant or the Managing General Partner or increase or decrease the profit or loss sharing or required Capital Contribution of any Participant or the Managing General Partner without the approval of the Participant or the Managing General Partner, respectively; and

(b)

any amendment may not affect the classification of Partnership income and loss for federal income tax purposes without the unanimous approval of all Participants.

4.03(c)(3). Restrictions on Managing General Partner’s Voting Rights. With respect to Units owned by the Managing General Partner or its Affiliates, the Managing General Partner and its Affiliates may vote or consent on all matters other than the following:

(i)

the matters set forth in §4.03(c)(2)(ii) and (iv) above; or

(ii)

any transaction between the Partnership and the Managing General Partner or its Affiliates.

In determining the requisite percentage in interest of Units necessary to approve any Partnership matter on which the Managing General Partner and its Affiliates may not vote or consent, any Units owned by the Managing General Partner and its Affiliates shall not be included.

4.03(c)(4). Restrictions on Limited Partner Voting Rights. The exercise by the Limited Partners of the rights granted Participants under §4.03(c), except for the special voting rights granted Participants under §4.03(c)(2), shall be subject to the prior legal determination that the grant or exercise of the powers will not adversely affect the limited liability of Limited Partners. Notwithstanding the foregoing, if in the opinion of counsel to the Partnership the legal determination is not necessary under Delaware law to maintain the limited liability of the Limited Partners, then it shall not be required. A legal determination under this paragraph may be made either pursuant to:

(i)

an opinion of counsel, the counsel being independent of the Partnership and selected on the vote of Limited Partners whose Units equal a majority of the total Units held by Limited Partners; or

(ii)

a declaratory judgment issued by a court of competent jurisdiction.

The Investor General Partners may exercise the rights granted to the Participants whether or not the Limited Partners can participate in the vote if the Investor General Partners represent the requisite percentage of Units necessary to take the action.

4.03(d). Transactions with the Managing General Partner.

4.03(d)(1). Transfer of Equal Proportionate Interest. When the Managing General Partner or an Affiliate (excluding another Program in which the interest of the Managing General Partner or its Affiliates is substantially similar to or less than their interest in the Partnership) sells, transfers or conveys any natural gas, oil or other mineral interests or property to the Partnership, it must, at the same time, sell, transfer or convey to the Partnership an equal proportionate interest in all its other property in the same Prospect. Notwithstanding, a Prospect shall be deemed to consist of the drilling or spacing unit on which the well will be drilled by the Partnership, which is the minimum area permitted by state law or local practice on which one well may be drilled, if the following two conditions are met:

(i)

the geological feature to which the well will be drilled contains Proved Reserves; and

(ii)

the drilling or spacing unit protects against drainage.

Notwithstanding, a horizontal well may be drilled in one or more directions on the same Prospect on which a vertical well is also drilled. If the area constituting the Partnership’s Prospect is subsequently enlarged to encompass any area in which the Managing General Partner or an Affiliate (excluding another Program in which the interest of the Managing General Partner or its Affiliates is substantially similar to or less than their interest in the Partnership) owns a separate property interest and the activities of the Partnership were material in establishing the existence of Proved Undeveloped Reserves that are attributable to the separate property interest, then the separate property interest or a portion thereof must be sold, transferred, or conveyed to the Partnership as set forth in this section and §§4.01(a)(4) and 4.03(d)(2).

Notwithstanding the foregoing, Prospects drilled to the Marcellus Shale reservoir, the Mississippian carbonate or Devonian Shale reservoirs, the Upper Devonian New Albany Shale reservoir or any other formation or reservoir shall not be enlarged or contracted if the Prospect was limited to the drilling or spacing unit because the well was being drilled to Proved Reserves in the geological formation and the drilling or spacing unit protected against drainage.

4.03(d)(2). Transfer of Less than the Managing General Partner’s and its Affiliates’ Entire Interest. A sale, transfer or a conveyance to the Partnership of less than all of the ownership of the Managing General Partner or an Affiliate (excluding another Program in which the interest of the Managing General Partner or its Affiliates is substantially similar to or less than their interest in the Partnership) in any Prospect shall not be made unless:

(i)

the interest retained by the Managing General Partner or the Affiliate is a proportionate Working Interest;

(ii)

the respective obligations of the Managing General Partner or its Affiliates and the Partnership are substantially the same after the sale of the interest by the Managing General Partner or its Affiliates; and

(iii)

the Managing General Partner's interest in revenues does not exceed the amount proportionate to its retained Working Interest.

This section does not prevent the Managing General Partner or its Affiliates from subsequently dealing with their retained interest as they may choose with unaffiliated parties or Affiliated partnerships.

4.03(d)(3). Limitations on Sale of Undeveloped and Developed Leases to the Managing General Partner. Other than another Program managed by the Managing General Partner and its Affiliates as set forth in §§4.03(d)(5) and 4.03(d)(9), the Managing General Partner and its Affiliates shall not receive a Farmout or purchase any undeveloped Leases from the Partnership other than at the higher of Cost or fair market value.

The Managing General Partner and its Affiliates, other than an Affiliated Income Program, shall not purchase any producing natural gas or oil property from the Partnership unless:

(i)

the sale is in connection with the liquidation of the Partnership; or

(ii)

the Managing General Partner’s well supervision fees under the Drilling and Operating Agreement for the well have exceeded the net revenues of the well, determined without regard to the Managing General Partner’s well supervision fees for the well, for a period of at least three consecutive months.

Under both (i) and (ii) above, the sale must be at fair market value supported by an appraisal of an Independent Expert selected by the Managing General Partner.

4.03(d)(4). Limitations on Activities of the Managing General Partner and its Affiliates on Leases Acquired by the Partnership. During a period of five years after the Offering Termination Date of the Partnership, if the Managing General Partner or any of its Affiliates (excluding another Program in which the interest of the Managing General Partner or its Affiliates is substantially similar to or less than their interest in the Partnership) proposes to acquire an interest from an unaffiliated person in a Prospect in which the Partnership possesses an interest or in a Prospect in which the Partnership’s interest has been terminated without compensation within one year preceding the proposed acquisition, then the following conditions shall apply:

(i)

(ii)

if the Managing General Partner or the Affiliate (excluding another Program in which the interest of the Managing General Partner or its Affiliates is substantially similar to or less than their interest in the Partnership) currently owns a proportionate interest in the Prospect separately from the Partnership, then the interest to be acquired shall be divided between the Partnership and the Managing General Partner or the Affiliate in the same proportion as is the other property in the Prospect. Provided, however, if cash or financing is not available to the Partnership to enable it to complete a purchase of the additional interest to which it is entitled, then neither the Managing General Partner nor the Affiliate shall be permitted to purchase any additional interest in the Prospect.

4.03(d)(5). Transfer of Leases Between Affiliated Limited Partnerships. The transfer of an undeveloped Lease from the Partnership to another drilling Program sponsored or managed by the Managing General Partner or its Affiliates must be made at fair market value if the undeveloped Lease has been held by the Partnership for more than two years. Otherwise, if the Managing General Partner deems it to be in the best interest of the Partnership, the transfer may be made at Cost.

An Affiliated Income Program may purchase a producing natural gas and oil property from the Partnership at any time at:

(i)

fair market value as supported by an appraisal from an Independent Expert if the property has been held by the Partnership for more than six months or the Partnership has made significant expenditures have been made in connection with the property; or

(ii)

Cost, as adjusted for intervening operations, if the Managing General Partner deems it to be in the best interest of the Partnership.

However, these prohibitions shall not apply to joint ventures or Farmouts among Affiliated partnerships, provided that:

(i)

the respective obligations and revenue sharing of all parties to the transaction are substantially the same; and

(ii)

the compensation arrangement or any other interest or right of either the Managing General Partner or its Affiliates is the same in each Affiliated partnership or if different, the aggregate compensation of the Managing General Partner or the Affiliate is reduced to reflect the lower compensation arrangement.

4.03(d)(6). Sale of All Assets. The sale of all or substantially all of the assets of the Partnership, including without limitation, Leases, wells, equipment and production therefrom, shall be made only with the consent of Participants whose Units equal a majority of the total Units.

4.03(d)(7). Services.

4.03(d)(7)(a). Competitive Rates. The Managing General Partner and any Affiliate shall not render to the Partnership any oil field, equipage, or other services nor sell or lease to the Partnership any equipment or related supplies unless:

(i)

the person is engaged, independently of the Partnership and as an ordinary and ongoing business, in the business of rendering the services or selling or leasing the equipment and supplies to a substantial extent to other persons in the natural gas and oil industry in addition to the partnerships in which the Managing General Partner or an Affiliate has an interest; and

(ii)

the compensation, price, or rental therefor is competitive with the compensation, price, or rental of other persons in the area engaged in the business of rendering comparable services or selling or leasing comparable equipment and supplies which could reasonably be made available to the Partnership.

If the person is not engaged in such a business, then the compensation, price or rental shall be the Cost of the services, equipment or supplies to the person or the competitive rate which could be obtained in the area, whichever is less.

4.03(d)(7)(b). If Not Disclosed in the Prospectus or This Agreement, Then Services by the Managing General Partner Must be Described in a Separate Contract and Cancelable. Any services for which the Managing General Partner or an Affiliate is to receive compensation, other than those described in this Agreement or the Prospectus, shall be set forth in a written contract which precisely describes the services to be rendered and all compensation to be paid. These contracts shall be cancelable without penalty on 60 days written notice by Participants whose Units equal a majority of the total Units.

4.03(d)(8). Loans.

4.03(d)(8)(a). No Loans from the Partnership. No loans or advances shall be made by the Partnership to the Managing General Partner or its Affiliates.

4.03(d)(8)(b). Loans to the Partnership. Neither the Managing General Partner nor any Affiliate shall loan money to the Partnership if the interest to be charged exceeds either:

(i)

the Managing General Partner’s or the Affiliate’s interest cost; or

(ii)

that which would be charged to the Partnership, without reference to the Managing General Partner’s or the Affiliate’s financial abilities or guarantees, by unrelated lenders, on comparable loans for the same purpose.

Neither the Managing General Partner nor any Affiliate shall receive points or other financing charges or fees, regardless of the amount, although the actual amount of the charges incurred by them from third-party lenders may be reimbursed to the Managing General Partner or the Affiliate.

4.03(d)(9). Farmouts. The Managing General Partner shall not enter into a Farmout to avoid its paying its share of costs related to drilling a well on an undeveloped Lease. The Partnership shall not Farmout an undeveloped Lease or well activity to the Managing General Partner or its Affiliates except as set forth in §4.03(d)(3). Notwithstanding, this restriction shall not apply to Farmouts between the Partnership and another partnership managed by the Managing General Partner or its Affiliates, either separately or jointly, provided that the respective obligations and revenue sharing of all parties to the transactions are substantially the same and the compensation arrangement or any other interest or right of the Managing General Partner or its Affiliates is the same in each partnership, or, if different, the aggregate compensation of the Managing General Partner and its Affiliates is reduced to reflect the lower compensation agreement.

The Partnership may Farmout an undeveloped lease or well activity only if the Managing General Partner, exercising the standard of a prudent operator, determines that:

(i)

the Partnership lacks the funds to complete the oil and gas operations on the Lease or well and cannot obtain suitable financing;

(ii)

drilling on the Lease or the intended well activity would concentrate excessive funds in one location, creating undue risks to the Partnership;

(iii)

the Leases or well activity have been downgraded by events occurring after assignment to the Partnership so that development of the Leases or well activity would not be desirable; or

(iv)

the best interests of the Partnership would be served.

If the Partnership Farmouts a Lease or well activity, the Managing General Partner must retain on behalf of the Partnership the economic interests and concessions as a reasonably prudent oil and gas operator would or could retain under the circumstances prevailing at the time, consistent with industry practices.

If the Partnership acquires an undeveloped Lease pursuant to a Farmout or joint venture from an Affiliated partnership, the Managing General Partner’s and its Affiliates’ aggregate compensation associated with the property and any direct and indirect ownership interest in the property may not exceed the lower of the compensation and ownership interest in the Managing General Partner and/or its Affiliates could receive if the property were separately owned or retained by either the Partnership or the Affiliated partnership.

4.03(d)(10). No Compensating Balances. Neither the Managing General Partner nor any Affiliate shall use the Partnership’s funds as compensating balances for its own benefit.

4.03(d)(11). Future Production. Neither the Managing General Partner nor any Affiliate shall commit the future production of a well developed by the Partnership exclusively for its own benefit.

4.03(d)(12). Marketing Arrangements. Subject to §4.06(c), all benefits from marketing arrangements or other relationships affecting the property of the Managing General Partner or its Affiliates, including its Affiliated partnerships and the Partnership, shall be fairly and equitably apportioned according to the respective interests of each in the property. In this regard, the benefits and liabilities of the hedging agreements shall be equitably allocated by Atlas America and/or Atlas Energy Resources, LLC, or their successors in interest by merger or otherwise, and the Managing General Partner to the Partnership and the other partnerships sponsored by the Managing General Partner and its Affiliates pro rata based on actual production, consistent with past practice, and the Partnership and the other partnerships sponsored by the Managing General Partner and its Affiliates shall be severally liable for their respective allocated share thereof, but shall not be jointly and severally liable for the entire amount of the liabilities under the hedging agreements. Additionally, Atlas America and/or Atlas Energy Resources, LLC, or their successors in interest by merger or otherwise, shall not be liable for any such liabilities, or be entitled to any such benefits, to the extent they are so allocated. Atlas America has transferred ownership of the Managing General Partner to Atlas Energy Resources, LLC and it is anticipated that Atlas Energy Resources, LLC or an Affiliate, rather than Atlas America, subject to the intended merger of Atlas America and ATN discussed in the Prospectus, will enter into future hedging agreements. Notwithstanding, the Partnership may enter into agreements and financial instruments relating to hedging the Partnership’s natural gas and oil and the pledging of up to 100% of the Partnership’s assets and reserves in connection therewith separate from and/or in addition to the hedging agreements described above.

4.03(d)(13). Advance Payments. Advance payments by the Partnership to the Managing General Partner and its Affiliates are prohibited except when advance payments are required to secure the tax benefits of prepaid Intangible Drilling Costs for a business purpose as set forth in the Drilling and Operating Agreement.

4.03(d)(14). No Rebates. No rebates or give-ups may be received by the Managing General Partner or any Affiliate nor may the Managing General Partner or any Affiliate participate in any reciprocal business arrangements that would circumvent the provisions of this section.

4.03(d)(15). Participation in Other Partnerships. If the Partnership participates in other partnerships or joint ventures (multi-tier arrangements), then the terms of any of these arrangements shall not result in the circumvention of any of the requirements or prohibitions contained in this Agreement, including the following:

(i)

there shall be no duplication or increase in Organization and Offering Costs, the Managing General Partner’s compensation, Partnership expenses or other fees and costs;

(ii)

there shall be no substantive alteration in the fiduciary and contractual relationship between the Managing General Partner and the Participants; and

(iii)

there shall be no diminishment in the voting rights of the Participants.

4.03(d)(16). Roll-Up Limitations.

4.03(d)(16)(a). Requirement for Appraisal and Its Assumptions. In connection with a proposed Roll-Up, an appraisal of all Partnership assets shall be obtained from a competent Independent Expert. If the appraisal will be included in a prospectus used to offer securities of a Roll-Up Entity, then the appraisal shall be filed with the SEC and the Administrator as an exhibit to the registration statement for the offering. Thus, an issuer using the appraisal shall be subject to liability for violation of Section 11 of the Securities Act of 1933 and comparable provisions under state law for any material misrepresentations or material omissions in the appraisal.

Partnership assets shall be appraised on a consistent basis. The appraisal shall be based on all relevant information, including current reserve estimates prepared as set forth in §4.03(b)(3), and shall indicate the value of the Partnership’s assets as of a date immediately before the announcement of the proposed Roll-Up transaction. The appraisal shall assume an orderly liquidation of the Partnership’s assets over a 12-month period.

The terms of the engagement of the Independent Expert shall clearly state that the engagement is for the benefit of the Partnership and the Participants. A summary of the independent appraisal, indicating all material assumptions underlying the appraisal, shall be included in a report to the Participants in connection with a proposed Roll-Up.

4.03(d)(16)(b). Rights of Participants Who Vote Against Proposal. In connection with a proposed Roll-Up, Participants who vote “no” on the proposal shall be offered the choice of:

(i)

accepting the securities of the Roll-Up Entity offered in the proposed Roll-Up; or

(ii)

one of the following:

(a)

remaining as Participants in the Partnership and preserving their Units in the Partnership on the same terms and conditions as existed previously; or

(b)

receiving cash in an amount equal to the Participants’ pro rata share of the appraised value of the net assets of the Partnership based on their respective number of Units.

4.03(d)(16)(c). No Roll-Up If Diminishment of Voting Rights. The Partnership shall not participate in any proposed Roll-Up which, if approved, would result in the diminishment of any Participant’s voting rights under the Roll-Up Entity’s chartering agreement. In no event shall the democracy rights of Participants in the Roll-Up Entity be less than those provided for under §§4.03(c)(1) and 4.03(c)(2). If the Roll-Up Entity is a corporation, then the democracy rights of Participants shall correspond to the democracy rights provided for in this Agreement to the greatest extent possible.

4.03(d)(16)(d). No Roll-Up If Accumulation of Shares Would be Impeded. The Partnership shall not participate in any proposed Roll-Up transaction which includes provisions that would operate to materially impede or frustrate the accumulation of shares by any purchaser of the securities of the Roll-Up Entity, except to the minimum extent necessary to preserve the tax status of the Roll-Up Entity. The Partnership shall not participate in any proposed Roll-Up transaction which would limit the ability of a Participant to exercise the voting rights of its securities of the Roll-Up Entity on the basis of the number of Units held by that Participant.

4.03(d)(16)(e). No Roll-Up If Access to Records Would Be Limited. The Partnership shall not participate in a Roll-Up in which Participants’ rights of access to the records of the Roll-Up Entity would be less than those provided for under §§4.03(b)(5), 4.03(b)(6) and 4.03(b)(7).

4.03(d)(16)(f). Cost of Roll-Up. The Partnership shall not participate in any proposed Roll-Up transaction in which any of the costs of the transaction would be borne by the Partnership if Participants whose Units equal a majority of the total Units do not vote to approve the proposed Roll-Up.

4.03(d)(16)(g). Roll-Up Approval. The Partnership shall not participate in a Roll-Up transaction unless the Roll-Up transaction is approved by Participants whose Units equal a majority of the total Units.

4.03(d)(17). Disclosure of Binding Agreements. Any agreement or arrangement which binds the Partnership must be disclosed in the Prospectus.

4.03(d)(18). Transactions Must Be Fair and Reasonable. Neither the Managing General Partner nor any Affiliate shall sell, transfer, or convey any property to or purchase any property from the Partnership, directly or indirectly, except under transactions that are fair and reasonable, nor take any action with respect to the assets or property of the Partnership which does not primarily benefit the Partnership.

4.04. Designation, Compensation and Removal of Managing General Partner and Removal of Operator.

4.04(a). Managing General Partner.

4.04(a)(1). Term of Service. Except as otherwise provided in this Agreement, Atlas shall serve as the Managing General Partner of the Partnership until either it:

(i)

is removed pursuant to §4.04(a)(3); or

(ii)

withdraws pursuant to §4.04(a)(3)(f).

4.04(a)(2). Compensation of Managing General Partner. In addition to the compensation set forth in §§4.01(a)(4) and 4.02(d)(1), the Managing General Partner shall receive the compensation set forth in §§4.04(a)(2)(b) through 4.04(a)(2)(g).

4.04(a)(2)(a). Charges Must Be Necessary and Reasonable. Charges by the Managing General Partner for goods and services must be fully supportable as to:

(i)

the necessity of the goods and services; and

(ii)

the reasonableness of the amount charged.

All actual and necessary expenses incurred by the Partnership may be paid out of the Partnership’s subscription proceeds and revenues.

4.04(a)(2)(b). Direct Costs. The Managing General Partner and its Affiliates shall be reimbursed for all Direct Costs. Direct Costs, however, shall be billed directly to and paid by the Partnership to the extent practicable.

4.04(a)(2)(c). Administrative Costs. The Managing General Partner shall receive a nonaccountable, fixed payment reimbursement for its Administrative Costs of $75 per well per month. The nonaccountable, fixed payment reimbursement of $75 per well per month shall be subject to the following:

(i)

it shall not be increased in amount during the term of the Partnership;

(ii)

it shall be proportionately reduced to the extent the Partnership acquires less than 100% of the Working Interest in the well;

(iii)

it shall be the entire payment to reimburse the Managing General Partner for the Partnership’s Administrative Costs; and

(iv)

it shall not be received for wells plugged or abandoned during drilling operations.

4.04(a)(2)(d). Gas Gathering. The Managing General Partner, not acting as a Partner, shall be responsible for gathering and transporting the natural gas produced by the Partnership to interstate pipeline systems, local distribution companies, and/or end-users in the area (the “gathering services”). In providing the gathering services, the Managing General Partner may use the gathering system owned by Laurel Mountain Midstream, LLC, as described in the Prospectus, and gathering systems owned by independent third-parties and/or Affiliates of Atlas America, Inc. other than Laurel Mountain Midstream, LLC.

The Partnership shall pay a gathering fee directly to the Managing General Partner at competitive rates for the gathering services. The gathering fee paid by the Partnership to the Managing General Partner may be increased from time-to-time by the Managing General Partner, in its sole discretion, but may not increase beyond competitive rates as determined by the Managing General Partner. Currently, the Managing General Partner has determined that the competitive rate is an amount equal to 13% of the gross sales price received by the Partnership for its natural gas in the Marcellus Shale (western Pennsylvania) primary area as described in the Prospectus. Gross sales price means the price that is actually received, adjusted to take into account proceeds received or payments made pursuant to hedging arrangements. In addition, the managing general partner has determined that the competitive rates in the Partnership’s other primary and secondary areas are as follows:

(i)

$1.00 per mcf (1,000 cubic feet of natural gas) in the New Albany Shale (Indiana) primary area;

(ii)

$0.55 per mcf in the north central Tennessee secondary area; and

(iii)

$0.30 per mcf in the Antrim Shale (Michigan) secondary area;

as described in the Prospectus.

The payment of a competitive fee to the Managing General Partner for its gathering services shall be subject to the following conditions:

(i)

If the Partnership’s natural gas production is gathered and transported through the gathering system owned by Laurel Mountain Midstream, LLC, then the Managing General Partner shall apply its gathering fee towards the related gathering fee obligation of Atlas America, LLC, Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC, Atlas Noble LLC, Resource Energy, LLC, and Viking Resources LLC (the “Atlas Entities”) under their agreement with Laurel Mountain Midstream, LLC, as described in the Prospectus.

(ii)

If a third-party gathering system is used by the Partnership, then the Managing General Partner’s gathering fee charged to the Partnership shall be the actual transportation and compression fees charged by the third-party gathering system with respect to the Partnership’s natural gas in the area, and the Managing General Partner shall pay all of the gathering fee it receives from the Partnership to the third-party gathering the natural gas. The Managing General Partner shall not receive any gathering fees from the Partnership that exceed the payments it makes to the third-party gas gatherer.

(iii)

If both a third-party gathering system and the Laurel Mountain Midstream, LLC gathering system, or a gas gathering system owned by an Affiliate other than Laurel Mountain Midstream, LLC, are used by the Partnership, then the Managing General Partner shall receive an amount equal to a competitive fee, as described above, for the natural gas transported by the segment provided by the Laurel Mountain Midstream, LLC gathering system or a gas gathering system owned by an Affiliate other than Laurel Mountain Midstream, LLC, plus the amount charged by the third-party gathering system for the natural gas transported by the segment provided by the third-party.

4.04(a)(2)(e). Dealer-Manager Fee. Subject to §3.03(a)(1), the Dealer-Manager shall receive on each Unit sold to investors:

(i)

a 2.5% Dealer-Manager fee;

(ii)

a 7% Sales Commission; and

(iii)

an up to .5% reimbursement of the Selling Agents’ bona fide due diligence expenses.

4.04(a)(2)(f). Drilling and Operating Agreement. The Managing General Partner and its Affiliates shall receive compensation as set forth in the Drilling and Operating Agreement.

4.04(a)(2)(g). Other Transactions. The Managing General Partner and its Affiliates may enter into transactions pursuant to §4.03(d)(7) with the Partnership and shall be entitled to compensation under that section.

4.04(a)(3). Removal of Managing General Partner.

4.04(a)(3)(a). Majority Vote Required to Remove the Managing General Partner. The Managing General Partner may be removed at any time on 60 days’ advance written notice to the outgoing Managing General Partner by the affirmative vote of Participants whose Units equal a majority of the total Units.

If the Participants vote to remove the Managing General Partner from the Partnership, then Participants must elect by an affirmative vote of Participants whose Units equal a majority of the total Units either to:

(i)

dissolve, wind-up, and terminate the Partnership; or

(ii)

continue as a successor limited partnership under all the terms of this Partnership Agreement as provided in §7.01(c).

If the Participants elect to continue as a successor limited partnership, then the Managing General Partner shall not be removed until a substituted Managing General Partner has been selected by an affirmative vote of Participants whose Units equal a majority of the total Units and installed as such.

4.04(a)(3)(b). Valuation of Managing General Partner’s Interest in the Partnership. If the Managing General Partner is removed, then its interest in the Partnership shall be determined by appraisal by a qualified Independent Expert. The Independent Expert shall be selected by mutual agreement between the removed Managing General Partner and the incoming Managing General Partner. The appraisal shall take into account an appropriate discount, to reflect the risk of recovering natural gas and oil reserves, which shall not be less than that used to calculate the presentment price in the most recent presentment offer under §6.03, if any.

The cost of the appraisal shall be borne equally by the removed Managing General Partner and the Partnership.

4.04(a)(3)(c). Incoming Managing General Partner’s Option to Purchase. The incoming Managing General Partner shall have the option to purchase 20% of the removed Managing General Partner’s interest in the Partnership as Managing General Partner, but not as a Participant, for the value determined by the Independent Expert.

4.04(a)(3)(d). Method of Payment. The method of payment for the removed Managing General Partner’s interest must be fair and protect the solvency and liquidity of the Partnership. The method of payment shall be as follows:

(i)

when the termination is voluntary, the method of payment shall be a non-interest bearing unsecured promissory note with principal payable, if at all, from distributions which the Managing General Partner otherwise would have received under this Agreement had the Managing General Partner not been terminated; and

(ii)

when the termination is involuntary, the method of payment shall be an interest bearing unsecured promissory note coming due in no less than five years with equal installments each year. The interest rate shall be that charged on comparable loans.

4.04(a)(3)(e). Termination of Contracts. At the time of its removal, the removed Managing General Partner shall cause, to the extent it is legally possible to do so, its successor to be transferred or assigned all of its rights, obligations and interests as Managing General Partner of the Partnership in contracts entered into by it on behalf of the Partnership. In any event, the removed Managing General Partner shall cause all of its rights, obligations and interests as Managing General Partner of the Partnership in any such contract to terminate at the time of its removal.

Notwithstanding any other provision in this Agreement, the Partnership or the successor Managing General Partner shall not:

(i)

be a party to any natural gas supply agreement that the Managing General Partner or its Affiliates enters into with a third-party;

(ii)

have any rights pursuant to such natural gas supply agreement; or

(iii)

receive any interest in the Managing General Partner’s and its Affiliates’ (including Laurel Mountain Midstream LLC’s) pipeline or gathering system or compression facilities.

4.04(a)(3)(f). The Managing General Partner’s Right to Voluntarily Withdraw. At any time beginning 10 years after the Offering Termination Date and the Partnership’s primary drilling activities, the Managing General Partner may voluntarily withdraw as Managing General Partner on giving 120 days’ written notice of withdrawal to the Participants. If the Managing General Partner withdraws, then the following conditions shall apply:

(i)

the Managing General Partner’s interest in the Partnership shall be determined as described in §4.04(a)(3)(b) above with respect to removal; and

(ii)

the interest shall be distributed to the Managing General Partner as described in §4.04(a)(3)(d)(i) above.

Any successor Managing General Partner shall have the option to purchase 20% of the withdrawing Managing General Partner’s interest in the Partnership at the value determined as described above with respect to removal.

4.04(a)(3)(g). Right of Managing General Partner to Hypothecate Its Interests. The Managing General Partner shall have the authority without the consent of the Participants and without affecting the allocation of costs and revenues received or incurred under this Agreement, to hypothecate, pledge, or otherwise encumber, on any terms it chooses for its own general purposes, either:

(i)

its Partnership interest; or

(ii)

an undivided interest in the assets of the Partnership equal to or less than its respective interest as Managing General Partner in the revenues of the Partnership.

All repayments of these borrowings and costs, interest or other charges related to the borrowings shall be borne and paid separately by the Managing General Partner. In no event shall the repayments, costs, interest, or other charges related to the borrowing be charged to the account of the Participants.

4.04(a)(3)(h). The Managing General Partner’s Right to Withdraw Property Interest. The Managing General Partner shall have the right to withdraw a property interest held by the Partnership in the form of a Working Interest in the Partnership’s Wells equal to or less than its respective interest as Managing General Partner in the revenues of the Partnership if:

(i)

the withdrawal is necessary to satisfy the bona fide request of its creditors; or

(ii)

the withdrawal is approved by Participants whose Units equal a majority of the total Units.

If the Managing General Partner withdraws a property interest from the Partnership as described above, then the Managing General Partner shall:

(i)

pay the expenses of withdrawing; and

(ii)

fully indemnify the Partnership against any additional expenses which may result from the withdrawal of its property interest, including insuring that a greater amount of Direct Costs or Administrative Costs is not allocated to the Participants.

4.04(a)(4). Removal of Operator. The Operator may be removed and a new Operator may be substituted at any time on 60 days advance written notice to the outgoing Operator by the Managing General Partner acting on behalf of the Partnership on the affirmative vote of Participants whose Units equal a majority of the total Units.

The Operator shall not be removed until a substituted Operator has been selected by an affirmative vote of Participants whose Units equal a majority of the total Units and installed as such.

4.05. Indemnification and Exoneration.

4.05(a)(1). Standards for the Managing General Partner Not Incurring Liability to the Partnership or Participants. The Managing General Partner, the Operator, and their Affiliates shall not have any liability whatsoever to the Partnership, or to any Participant for any loss suffered by the Partnership or the Participants which arises out of any action or inaction of the Managing General Partner, the Operator, or their Affiliates if:

(i)

the Managing General Partner, the Operator, and their Affiliates determined in good faith that the course of conduct was in the best interest of the Partnership;

(ii)

the Managing General Partner, the Operator, and their Affiliates were acting on behalf of, or performing services for, the Partnership; and

(iii)

the course of conduct did not constitute negligence or misconduct of the Managing General Partner, the Operator, or their Affiliates.

4.05(a)(2). Standards for Managing General Partner Indemnification. The Managing General Partner, the Operator, and their Affiliates shall be indemnified by the Partnership against any losses, judgments, liabilities, expenses, and amounts paid in settlement of any claims sustained by them in connection with the Partnership, provided that:

(i)

the Managing General Partner, the Operator, and their Affiliates determined in good faith that the course of conduct which caused the loss or liability was in the best interest of the Partnership;

(ii)

the Managing General Partner, the Operator, and their Affiliates were acting on behalf of, or performing services for, the Partnership; and

(iii)

the course of conduct was not the result of negligence or misconduct of the Managing General Partner, the Operator, or their Affiliates.

Provided, however, payments arising from such indemnification or agreement to hold harmless are recoverable only out of the following:

(i)

the Partnership’s tangible net assets, which include its revenues; and

(ii)

any insurance proceeds from the types of insurance for which the Managing General Partner, the Operator and their Affiliates may be indemnified under this Agreement.

4.05(a)(3). Standards for Securities Law Indemnification. Notwithstanding anything to the contrary contained in this section, the Managing General Partner, the Operator, and their Affiliates and any person acting as a broker/dealer with respect to the offer or sale of the Units, shall not be indemnified for any losses, liabilities or expenses arising from or out of an alleged violation of federal or state securities laws by such party unless:

(i)

there has been a successful adjudication on the merits of each count involving alleged securities law violations as to the particular indemnitee;

(ii)

the claims have been dismissed with prejudice on the merits by a court of competent jurisdiction as to the particular indemnitee; or

(iii)

a court of competent jurisdiction approves a settlement of the claims against a particular indemnitee and finds that indemnification of the settlement and the related costs should be made, and the court considering the request for indemnification has been advised of the position of the SEC, the Massachusetts Securities Division, and any state securities regulatory authority in which plaintiffs claim they were offered or sold Units with respect to the issue of indemnification for violation of securities laws.

4.05(a)(4). Standards for Advancement of Funds to the Managing General Partner and Insurance. The advancement of Partnership funds to the Managing General Partner, the Operator, or their Affiliates for legal expenses and other costs incurred as a result of any legal action for which indemnification is being sought from the Partnership is permissible only if the Partnership has adequate funds available and the following conditions are satisfied:

(i)

the legal action relates to acts or omissions with respect to the performance of duties or services on behalf of the Partnership;

(ii)

the legal action is initiated by a third-party who is not a Participant, or the legal action is initiated by a Participant and a court of competent jurisdiction specifically approves the advancement; and

(iii)

the Managing General Partner or its Affiliates undertake to repay the advanced funds to the Partnership, together with the applicable legal rate of interest thereon, in cases in which such party is found not to be entitled to indemnification.

The Partnership shall not bear the cost of that portion of insurance which insures the Managing General Partner, the Operator, or their Affiliates for any liability for which they could not be indemnified pursuant to §§4.05(a)(1) and 4.05(a)(2).

4.05(b). Liability of Partners. Under the Delaware Revised Uniform Limited Partnership Act, the Investor General Partners are liable jointly and severally for all liabilities and obligations of the Partnership. Notwithstanding the foregoing, as among themselves, the Investor General Partners agree that each shall be solely and individually responsible only for his pro rata share of the liabilities and obligations of the Partnership based on his respective number of Units.

In addition, the Managing General Partner agrees to use its corporate assets to indemnify each of the Investor General Partners against all Partnership related liabilities which exceed the Investor General Partner’s interest in the undistributed net assets of the Partnership and insurance proceeds, if any. Further, the Managing General Partner agrees to indemnify each Investor General Partner against any personal liability as a result of the unauthorized acts of another Investor General Partner.

If the Managing General Partner provides indemnification, then each Investor General Partner who has been indemnified shall transfer and subrogate his rights for contribution from or against any other Investor General Partner to the Managing General Partner.

4.05(c). Order of Payment of Claims. Claims shall be paid as follows:

(i)

first, out of any insurance proceeds;

(ii)

second, out of Partnership assets and revenues; and

(iii)

last, by the Managing General Partner as provided in §§3.05(b)(2) and (3) and 4.05(b).

No Limited Partner shall be required to reimburse the Managing General Partner, the Operator, their Affiliates, or the Investor General Partners for any liability in excess of his agreed Capital Contribution, except:

(i)

for a liability resulting from the Limited Partner’s unauthorized participation in management of the Partnership; or

(ii)

from some other breach by the Limited Partner of this Agreement.

4.05(d). Authorized Transactions Are Not Deemed to Be a Breach. No transaction entered into or action taken by the Partnership, or by the Managing General Partner, the Operator, or their Affiliates, which is authorized by this Agreement shall be deemed a breach of any obligation owed by the Managing General Partner, the Operator, or their Affiliates to the Partnership or the Participants.

4.06. Other Activities.

4.06(a). The Managing General Partner May Pursue Other Natural Gas and Oil Activities for Its Own Account. The Managing General Partner, the Operator, and their Affiliates are now engaged, and will engage in the future, for their own account and for the account of others, including other investors, in all aspects of the natural gas and oil business. This includes without limitation, the evaluation, acquisition, and sale of producing and nonproducing Leases, and the exploration for and production of natural gas, oil and other minerals.

The Managing General Partner is required to devote only so much of its time to the Partnership as it determines in its sole discretion, but consistent with its fiduciary duties, is necessary to manage the affairs of the Partnership. Except as expressly provided to the contrary in this Agreement, and subject to fiduciary duties, the Managing General Partner, the Operator, and their Affiliates may do the following:

(i)

continue their activities, or initiate further such activities, individually, jointly with others, or as a part of any other limited or general partnership, tax partnership, joint venture, or other entity or activity to which they are or may become a party, in any locale and in the same fields, areas of operation or prospects in which the Partnership may likewise be active;

(ii)

reserve partial interests in Leases being assigned to the Partnership or any other interests not expressly prohibited by this Agreement;

(iii)

deal with the Partnership as independent parties or through any other entity in which they may be interested;

(iv)

conduct business with the Partnership as set forth in this Agreement; and

(v)

participate in such other investor operations, as investors or otherwise.

The Managing General Partner and its Affiliates shall not be required to permit the Partnership or the Participants to participate in or share in any profits or other benefits from any of the other operations in which the Managing General Partner and its Affiliates may be interested as permitted under this section. However, except as otherwise provided in this Agreement, the Managing General Partner and its Affiliates may pursue business opportunities that are consistent with the Partnership��s investment objectives for their own account only after they have determined that the opportunity either:

(i)

cannot be pursued by the Partnership because of insufficient funds; or

(ii)

it is not appropriate for the Partnership under the existing circumstances.

4.06(b). Managing General Partner May Manage Multiple Partnerships. The Managing General Partner or its Affiliates may manage multiple Programs simultaneously.

4.06(c). Partnership Has No Interest in Natural Gas Contracts or Pipelines and Gathering Systems. Notwithstanding any other provision in this Agreement, the Partnership shall not:

(i)

be a party to any natural gas supply agreement that the Managing General Partner, the Operator, or their Affiliates, enter into with Laurel Mountain Midstream, LLC or a third-party or have any rights pursuant to such natural gas supply agreement; or

(ii)

receive any interest in the Managing General Partner’s, the Operator’s, and their Affiliates’, including Laurel Mountain Midstream, LLC’s, gathering system, contracts or compression facilities.

ARTICLE V

PARTICIPATION IN COSTS AND REVENUES,

CAPITAL ACCOUNTS, ELECTIONS AND DISTRIBUTIONS

5.01. Participation in Costs and Revenues. Except as otherwise provided in this Agreement, costs and revenues of the Partnership shall be charged and credited to the Managing General Partner and the Participants as set forth in this section and its subsections.

5.01(a). Costs. Costs shall be charged as set forth below.

5.01(a)(1). Organization and Offering Costs. Organization and Offering Costs shall be charged 100% to the Managing General Partner. For purposes of sharing in revenues under §5.01(b)(4), the Managing General Partner shall be credited with Organization and Offering Costs paid by it and for services provided by it as Organization Costs up to an amount equal to 15% of the Partnership’s subscription proceeds. Any Organization and Offering Costs paid and/or provided in services by the Managing General Partner in excess of this amount shall not be credited towards the Managing General Partner’s required Capital Contribution or revenue share set forth in §5.01(b)(4). The Managing General Partner’s credit for services provided to the Partnership as Organization Costs shall be determined based on generally accepted accounting principles.

5.01(a)(2). Intangible Drilling Costs. Eighty-five percent (85%) of the Partnership’s subscription proceeds received from the Participants shall be used by the Partnership to pay 100% of the Intangible Drilling Costs.

5.01(a)(3). Tangible Costs. Fifteen percent (15%) of the Partnership’s subscription proceeds received from the Participants shall be used by the Partnership to pay Tangible Costs. All remaining Tangible Costs in excess of an amount equal to 15% of the Partnership’s subscription proceeds shall be charged 100% to the Managing General Partner.

5.01(a)(4). Operating Costs, Direct Costs, Administrative Costs and All Other Costs. Operating Costs, Direct Costs, Administrative Costs, and all other Partnership costs not specifically allocated shall be charged to the parties in the same ratio as the related production revenues are being credited.

5.01(a)(5). Allocation of Intangible Drilling Costs and Tangible Costs at Partnership Closings. Intangible Drilling Costs and the Participants’ share of Tangible Costs of a well or wells to be drilled and completed with the proceeds of a Partnership closing shall be charged 100% to the Participants who are admitted to the Partnership in that closing and shall not be reallocated to take into account other Partnership closings.

Although the subscription proceeds received by the Partnership in each closing may be used to pay the costs of drilling different wells, 85% of each Participant’s subscription proceeds shall be applied to Intangible Drilling Costs and 15% of each Participant’s subscription proceeds shall be applied to Tangible Costs regardless of when the Participant subscribes for his Units or is admitted to the Partnership.

5.01(a)(6). Lease Costs. The Leases shall be contributed to the Partnership by the Managing General Partner as set forth in §4.01(a)(4).

5.01(b). Revenues. Revenues shall be credited as set forth below.

5.01(b)(1). Allocation of Revenues on Disposition of Property. If the parties’ Capital Accounts are adjusted to reflect the simulated depletion of a natural gas or oil property of the Partnership, then the portion of the total amount realized by the Partnership on the taxable disposition of the property that represents recovery of its simulated tax basis in the property shall be allocated to the parties in the same proportion as the aggregate adjusted tax basis of the property was allocated to the parties or their predecessors in interest. If the parties’ Capital Accounts are adjusted to reflect the actual depletion of a natural gas or oil property of the Partnership, then the portion of the total amount realized by the Partnership on the taxable disposition of the property that equals the parties’ aggregate remaining adjusted tax basis in the property shall be allocated to the parties in proportion to their respective remaining adjusted tax bases in the property. Thereafter, any excess shall be allocated to the Managing General Partner in an amount equal to the difference between the fair market value of the Lease at the time it was contributed to the Partnership and its simulated or actual adjusted tax basis at that time. Finally, any excess shall be credited as provided in §5.01(b)(4), below.

In the event of the Partnership’s sale of developed natural gas and oil properties with equipment on the properties, the Managing General Partner may make any reasonable allocation of the sales proceeds between the equipment and the Leases.

5.01(b)(2). Interest. Interest earned on each Participant’s subscription proceeds under §3.05(b)(1) shall be credited to the accounts of the respective subscribers who paid the subscription proceeds to the Partnership. The interest shall be paid to the Participants not later than the Partnership’s first cash distribution from operations.

After the Offering Termination Date and until proceeds from the offering are invested in the Partnership’s natural gas and oil operations, any interest income from temporary investments shall be allocated pro rata to the Participants providing the subscription proceeds.

All other interest income, including interest earned on the deposit of production revenues, shall be credited as provided in §5.01(b)(4), below.

5.01(b)(3). Sale or Disposition of Equipment. Proceeds from the sale or disposition of equipment shall be credited to the parties charged with the costs of the equipment in the ratio in which the costs were charged.

5.01(b)(4). Other Revenues. Subject to §5.01(b)(4)(a), the Managing General Partner and the Participants shall share in all other Partnership revenues in the same percentage as their respective Capital Contribution bears to the Partnership’s total Capital Contributions, except that the Managing General Partner shall receive an additional 10% of Partnership revenues. For example, if the Managing General Partner contributes 15% of the Partnership’s total Capital Contributions and the Participants contribute 85% of the Partnership’s total Capital Contributions, then the Managing General Partner would receive 25% of the Partnership revenues and the Participants would receive 75% of the Partnership revenues.

5.01(b)(4)(a). Subordination. The Managing General Partner shall subordinate up to 50% of its share of Partnership Net Production Revenues to the receipt by Participants of cash distributions from the Partnership equal to $1,000 per Unit (which is 10% of $10,000 per Unit) regardless of the actual subscription price they paid for their Units, in each of the Partnership’s first five 12-month periods of operations as set forth below. In this regard:

(i)

the aggregate 60-month subordination period shall begin with the first cash distribution from operations to the Participants;

(ii)

subsequent subordination distributions, if any, shall be determined and made at the time of each subsequent distribution of revenues to the Participants; and

(iii)

the Managing General Partner shall not subordinate more than 50% of its share of Partnership Net Production Revenues in any 12-month subordination period.

The Managing General Partner’s subordination obligation shall be determined by:

(i)

carrying forward to subsequent 12-month subordination periods the amount, if any, by which cumulative cash distributions to Participants, including any subordination payments, are less than:

(a)

$1,000 per Unit (10% of $10,000 per Unit) in the first 12-month period;

(b)

$2,000 per Unit (20% of $10,000 per Unit) in the second 12-month period;

(c)

$3,000 per Unit (30% of $10,000 per Unit) in the third 12-month period; or

(d)

$4,000 per Unit (40% of $10,000 per Unit) in the fourth 12-month period (no carry forward is required if the Participant’s cumulative cash distributions are less than $5,000 per Unit (50% of $10,000 per Unit) in the fifth 12-month period, because the Managing General Partner’s subordination obligation terminates on the expiration of the fifth 12-month period); and

(ii)

reimbursing the Managing General Partner for any previous subordination payments to the extent cumulative cash distributions to Participants, including any subordination payments, would exceed:

(a)

$1,000 per Unit (10% of $10,000 per Unit) in the first 12-month period;

(b)

$2,000 per Unit (20% of $10,000 per Unit) in the second 12-month period;

(c)

$3,000 per Unit (30% of $10,000 per Unit) in the third 12-month period;

(d)

$4,000 per Unit (40% of $10,000 per Unit) in the fourth 12-month period; or

(e)

$5,000 per Unit (50% of $10,000 per Unit) in the fifth 12-month period.

The Managing General Partner’s subordination obligation also shall be subject to the following conditions:

(i)

the subordination obligation may be prorated in the Managing General Partner’s discretion (e.g. in the case of a monthly distribution, the Managing General Partner shall not have any subordination obligation if the cumulative monthly distributions to Participants equal $83.33 per Unit (8.333% of $1,000 per Unit) or more, assuming there are no subordination distributions owed for any preceding period);

(ii)

the Managing General Partner shall not be required to return Partnership distributions previously received by it, even though a subordination obligation arises after the distributions;

(iii)

subject to the foregoing provisions of this section, only Partnership revenues in the current distribution period shall be debited or credited to the Managing General Partner as may be necessary to provide, to the extent possible, subordination distributions to the Participants and reimbursements to the Managing General Partner;

(iv)

no subordination distributions to the Participants or reimbursements to the Managing General Partner shall be made after the expiration of the fifth 12-month subordination period; and

(v)

subordination payments to the Participants shall be subject to any lien or priority granted by the Managing General Partner and/or its Affiliates to its lenders pursuant to agreements either entered into by the Managing General Partner and/or its Affiliates before the subordination obligation arose or entered into or renewed by the Managing General Partner and/or its Affiliates after the subordination obligation arose.

5.01(b)(5). Commingling of Revenues From All Partnership Wells. The revenues from all Partnership wells shall be commingled, so regardless of when a Participant subscribes for Units or is admitted to the Partnership, he will share in the Partnership’s revenues from all of its wells on the same basis as the other Participants.

5.01(c). Allocations.

5.01(c)(1). Allocations among Participants. Except as provided otherwise in this Agreement, costs (other than Intangible Drilling Costs and Tangible Costs) and revenues charged or credited to the Participants as a group, which includes all revenue credited to the Participants under §5.01(b)(4), shall be allocated among the Participants, including the Managing General Partner to the extent of any optional subscription for Units under §3.03(b)(1), in the ratio of their respective Units based on $10,000 per Unit regardless of the actual subscription price paid by a Participant for his Units.

Intangible Drilling Costs and Tangible Costs charged to the Participants as a group shall be allocated among the Participants, including the Managing General Partner to the extent of any optional subscription for Units under §3.03(b)(1), in the ratio of the subscription amount designated on their respective Subscription Agreements rather than the number of their respective Units.

5.01(c)(2). Costs and Revenues Not Directly Allocable to a Partnership Well. Costs and revenues not directly allocable to a particular Partnership Well or additional operation shall be allocated among the Partnership Wells or additional operations in any manner the Managing General Partner in its reasonable discretion, shall select, and shall then be charged or credited in the same manner as costs or revenues directly applicable to the Partnership Well or additional operation are being charged or credited.

5.01(c)(3). Managing General Partner’s Discretion in Making Allocations For Federal Income Tax Purposes. In determining the proper method of allocating charges or credits among the parties, allocating any item of income, gain, loss, deduction or credit pursuant to new laws or new IRS or judicial interpretations of existing law, allocating any other item that is not otherwise specifically allocated in this Agreement or is subsequently determined by the Managing General Partner to be clearly inconsistent with a party’s economic interest in the Partnership, or making any other allocations under this Agreement, the Managing General Partner may adopt any method of allocation that it selects, in its sole discretion, after consultation with the Partnership’s legal counsel or accountants. Any new allocation provisions shall be made in a manner that is consistent with the parties’ economic interests in the Partnership and will result in the most favorable aggregate consequences to the Participants that are, as nearly as possible, consistent with the original allocations described in this Agreement.

5.02. Capital Accounts and Allocations Thereto.

5.02(a). Capital Accounts for Each Party to this Agreement. A single, separate Capital Account shall be established for each party, regardless of the number of interests owned by the party, the class of the interests and the time or manner in which the interests were acquired.

5.02(b). Charges and Credits.

5.02(b)(1). General Standard. Except as otherwise provided in this Agreement, the Capital Account of each party shall be determined and maintained in accordance with Treas. Reg. §1.704-l(b)(2)(iv) and shall be increased by:

(i)

the amount of money contributed by him to the Partnership;

(ii)

the fair market value of property contributed by him to the Partnership, without regard to §7701(g) of the Code, net of liabilities secured by the contributed property that the Partnership is considered to assume or take subject to under §752 of the Code; and

(iii)

allocations to him of Partnership income and gain, or items thereof, including income and gain exempt from tax and income and gain described in Treas. Reg. §1.704-l(b)(2)(iv)(g), but excluding income and gain described in Treas. Reg. §1.704-l(b)(4)(i);

and shall be decreased by:

(iv)

the amount of money distributed to him by the Partnership;

(v)

the fair market value of property distributed to him by the Partnership, without regard to §7701(g) of the Code, net of liabilities secured by the distributed property that he is considered to assume or take subject to under §752 of the Code;

(vi)

allocations to him of Partnership expenditures described in §705(a)(2)(B) of the Code; and

(vii)

allocations to him of Partnership loss and deduction, or items thereof, including loss and deduction described in Treas. Reg. §1.704-l(b)(2)(iv)(g), but excluding items described in (vi) above, and loss or deduction described in Treas. Reg. §1.704-l(b)(4)(i) or (iii).

5.02(b)(2). Exception. If Treas. Reg. §1.704-l(b)(2)(iv) fails to provide guidance, Capital Account adjustments shall be made in a manner that:

(i)

maintains equality between the aggregate governing Capital Accounts of the parties and the amount of Partnership capital reflected on the Partnership’s balance sheet, as computed for book purposes;

(ii)

is consistent with the underlying economic arrangement of the parties; and

(iii)

is based, wherever practicable, on federal tax accounting principles.

5.02(c). Payments to the Managing General Partner. The Capital Account of the Managing General Partner shall be reduced by payments to it pursuant to §4.04(a)(2) only to the extent of the Managing General Partner’s distributive share of any Partnership deduction, loss, or other downward Capital Account adjustment resulting from the payments. Also, in the event, and to the extent, that the Managing General Partner is treated under the Code as having been transferred an interest in the Partnership in connection with the performance of services for the Partnership (whether before or after the formation of the Partnership):

(i)

any resulting compensation income shall be allocated 100% to the Managing General Partner;

(ii)

any associated increase in Capital Accounts shall be credited 100% to the Managing General Partner; and

(iii)

any associated deduction to which the Partnership is entitled shall be allocated 100% to the Managing General Partner.

5.02(d). Discretion of Managing General Partner in the Method of Maintaining Capital Accounts. Notwithstanding any other provisions of this Agreement, the method of maintaining Capital Accounts may be changed from time to time, in the discretion of the Managing General Partner, to take into consideration §704 and other provisions of the Code and the related rules, regulations and interpretations as may exist from time to time.

5.02(e). Revaluations of Property. In the discretion of the Managing General Partner the Capital Accounts of the parties may be increased or decreased to reflect a revaluation of Partnership property, including intangible assets such as goodwill, on a property-by-property basis except as otherwise permitted under §704(c) of the Code and the regulations thereunder, on the Partnership’s books, in accordance with Treas. Reg. §1.704-l(b)(2)(iv)(f).

5.02(f). Amount of Book Items. In cases where §704(c) of the Code or §5.02(e) applies, Capital Accounts shall be adjusted in accordance with Treas. Reg. §1.704-l(b)(2)(iv)(g) for allocations of depreciation, depletion, amortization and gain and loss, as computed for book purposes, with respect to the property.

5.03. Allocation of Income, Deductions and Credits.

5.03(a). In General.

5.03(a)(1). Deductions Are Allocated to Party Charged with Expenditure. To the extent permitted by law and except as otherwise provided in this Agreement, all deductions and credits, including, but not limited to, intangible drilling and development costs and depreciation, shall be allocated to the party who has been charged with the expenditure giving rise to the deductions and credits; and to the extent permitted by law, these parties shall be entitled to the deductions and credits in computing taxable income or tax liabilities to the exclusion of any other party. Also, any Partnership deductions that would be nonrecourse deductions if they were not attributable to a loan made or guaranteed by the Managing General Partner or its Affiliates shall be allocated to the Managing General Partner to the extent required by law.

5.03(a)(2). Income and Gain Allocated in Accordance With Revenues. Except as otherwise provided in this Agreement, all items of income and gain, including gain on disposition of assets, shall be allocated in accordance with the related revenue allocations set forth in §5.01(b) and its subsections.

5.03(b). Tax Basis of Each Property. Subject to §704(c) of the Code, the tax basis of each oil and gas property for computation of cost depletion and gain or loss on disposition shall be allocated and reallocated when necessary based on the capital interest in the Partnership as to the property and the capital interest in the Partnership for this purpose as to each property shall be considered to be owned by the parties in the ratio in which the expenditure giving rise to the tax basis of the property has been charged as of the end of the year.

5.03(c). Gain or Loss on Oil and Gas Properties. Each party shall separately compute its gain or loss on the disposition of each natural gas and oil property in accordance with the provisions of §613A(c)(7)(D) of the Code, and the calculation of the gain or loss shall consider the party’s adjusted basis in his property interest computed as provided in §5.03(b) and the party’s allocable share of the amount realized from the disposition of the property.

5.03(d). Gain on Depreciable Property. Gain from each sale or other disposition of depreciable property shall be allocated to each party whose share of the proceeds from the sale or other disposition exceeds its contribution to the adjusted basis of the property in the ratio that the excess bears to the sum of the excesses of all parties having an excess.

5.03(e). Loss on Depreciable Property. Loss from each sale, abandonment or other disposition of depreciable property shall be allocated to each party whose contribution to the adjusted basis of the property exceeds its share of the proceeds from the sale, abandonment or other disposition in the proportion that the excess bears to the sum of the excesses of all parties having an excess.

5.03(f). Allocation If Recapture Treated As Ordinary Income. Any recapture treated as an increase in ordinary income by reason of §§1245, 1250 or 1254 of the Code shall be allocated to the parties in the amounts in which the recaptured items were previously allocated to them; provided that to the extent recapture allocated to any party is in excess of the party’s gain from the disposition of the property, the excess shall be allocated to the other parties but only to the extent of the other parties’ gain from the disposition of the property.

5.03(g). Tax Credits. If a Partnership expenditure, whether or not deductible, that gives rise to a tax credit in a Partnership taxable year also gives rise to valid allocations of Partnership loss or deduction, or other downward Capital Account adjustments, for the year, then the parties’ interests in the Partnership with respect to the credit, or the cost giving rise thereto, shall be in the same proportion as the parties’ respective distributive shares of the loss or deduction, and adjustments. If Partnership receipts, whether or not taxable, that give rise to a tax credit, including a marginal well production credit under §45I of the Code, in a Partnership taxable year also give rise to valid allocations of Partnership income or gain, or other upward Capital Account adjustments, for the year, then the parties’ interests in the Partnership with respect to the credit, or the Partnership’s receipts or production of natural gas and oil production giving rise thereto, shall be in the same proportion as the parties’ respective shares of the Partnership’s production revenues from the sales of its natural gas and oil production as provided in §5.01(b)(4).

5.03(h). Deficit Capital Accounts and Qualified Income Offset. Notwithstanding any provision of this Agreement to the contrary, an allocation of loss or deduction which would result in a party having a deficit Capital Account balance as of the end of the taxable year to which the allocation relates, if charged to the party, to the extent the Participant is not required to restore the deficit to the Partnership, taking into account:

(i)

adjustments that, as of the end of the year, reasonably are expected to be made to the party’s Capital Account for depletion allowances with respect to the Partnership’s natural gas and oil properties;

(ii)

allocations of loss and deduction that, as of the end of the year, reasonably are expected to be made to the party under §§704(e)(2) and 706(d) of the Code and Treas. Reg. §1.751-1(b)(2)(ii); and

(iii)

distributions that, as of the end of the year, reasonably are expected to be made to the party to the extent they exceed offsetting increases to the party’s Capital Account, assuming for this purpose that the fair market value of Partnership property equals its adjusted tax basis, that reasonably are expected to occur during or prior to the Partnership taxable years in which the distributions reasonably are expected to be made;

shall be charged to the Managing General Partner. Further, the Managing General Partner shall be credited with an additional amount of Partnership income or gain equal to the amount of the loss or deduction as quickly as possible to the extent that the chargeback does not cause or increase deficit balances in the parties’ Capital Accounts which are not required to be restored to the Partnership.

Notwithstanding any provision of this Agreement to the contrary, if a party unexpectedly receives an adjustment, allocation, or distribution described in (i), (ii), or (iii) above, or any other distribution, which causes or increases a deficit balance in the party’s Capital Account which is not required to be restored to the Partnership, the party shall be allocated items of income and gain, consisting of a pro rata portion of each item of Partnership income, including gross income and gain for the year, in an amount and manner sufficient to eliminate the deficit balance as quickly as possible.

5.03(i). Minimum Gain Chargeback. To the extent there is a net decrease during a Partnership taxable year in the minimum gain attributable to a Partner nonrecourse debt, then any Partner with a share of the minimum gain attributable to the debt at the beginning of the year shall be allocated items of Partnership income and gain in accordance with Treas. Reg. §1.704-2(i).

5.03(j). Partners’ Allocable Shares. Except as otherwise provided in this Agreement, each party’s allocable share of Partnership income, gain, loss, deductions and credits shall be determined by using any method prescribed or permitted by the Secretary of the Treasury by regulations or other guidelines and selected by the Managing General Partner which takes into account the varying interests of the parties in the Partnership during the taxable year. In the absence of those regulations or guidelines, except as otherwise provided in this Agreement, the allocable share shall be based on actual income, gain, loss, deductions and credits economically accrued each day during the taxable year in proportion to each party’s varying interest in the Partnership on each day during the taxable year.

5.03(k). Contingent Income. Subject to §5.04(d), if it is determined that any taxable income results to any party by reason of its entitlement to a share of capital of the Partnership, or a share of profits or revenues of the Partnership before the profit or revenue has been realized by the Partnership, the resulting deduction, as well as any resulting gain, shall not enter into Partnership net income or loss, but shall be separately allocated to that party.

5.04. Elections.

5.04(a). Election to Deduct Intangible Costs. The Partnership’s federal income tax return shall be made in accordance with an election under the option granted by the Code to deduct intangible drilling and development costs.

5.04(b). No Election Out of Subchapter K. No election shall be made by the Partnership, any Partner, or the Operator for the Partnership to be excluded from the application of the partnership provisions of the Code, including Subchapter K of Chapter 1 of Subtitle A of the Code.

5.04(c). §754 Election. In the event of the transfer of an interest in the Partnership, or on the death of an individual party hereto, or in the event of the distribution of property to any party, the Managing General Partner may choose for the Partnership to file an election in accordance with the applicable Treasury Regulations to cause the basis of the Partnership’s assets to be adjusted for federal income tax purposes as provided by §§734 and 743 of the Code.

5.04(d). §83 Election. The Partnership, the Managing General Partner and each Participant hereby agree to be legally bound by the provisions of this §5.04(d) and further agree that, in the Managing General Partner’s sole discretion, the Partnership and all of its Partners may elect a safe harbor under which the fair market value of a Partnership interest that is transferred in connection with the performance of services is treated as being equal to the liquidation value of that interest for transfers on or after the date final regulations providing the safe harbor are published in the Federal Register. If the Managing General Partner determines that the Partnership and all of its Partners will elect the safe harbor, which determination may be made solely in the best interests of the Managing General Partner, the Partnership, the Managing General Partner and each Participant further agree that:

(i)

the Partnership shall be authorized and directed to elect the safe harbor;

(ii)

the Partnership and each of its Partners (including any Person to whom a Partnership interest is transferred in connection with the performance of services) shall comply with all requirements of the safe harbor with respect to all Partnership interests transferred in connection with the performance of services while the election remains effective; and

(iii)

the Managing General Partner, in its sole discretion, may cause the Partnership to terminate the safe harbor election, which determination may be made in the sole interests of the Managing General Partner.

5.05. Distributions.

5.05(a). In General.

5.05(a)(1). Monthly Review of Accounts. The Managing General Partner shall review the accounts of the Partnership at least monthly to determine whether cash distributions are appropriate and the amount to be distributed, if any.

5.05(a)(2). Distributions. Except as otherwise provided in this Agreement, the Partnership shall distribute funds to the Managing General Partner and the Participants allocated to their respective accounts that the Managing General Partner deems unnecessary for the Partnership to retain.

5.05(a)(3). No Borrowings. In no event shall funds be advanced or borrowed by the Partnership for distributions to the Managing General Partner and the Participants if the amount of the distributions would exceed the Partnership’s accrued and received revenues for the previous four quarters, less paid and accrued Operating Costs with respect to the revenues. The determination of revenues and costs shall be made in accordance with generally accepted accounting principles, consistently applied.

5.05(a)(4). Distributions to the Managing General Partner. Cash distributions from the Partnership to the Managing General Partner shall only be made as follows:

(i)

in conjunction with distributions to Participants; and

(ii)

out of funds properly allocated to the Managing General Partner’s account.

5.05(a)(5). Reserve. At any time after one year from the date each Partnership Well is placed into production, the Managing General Partner shall have the right to deduct each month from the Partnership’s net sales proceeds from the sale of the natural gas and oil production from each of its productive wells up to $200 per well for the purpose of establishing a fund to cover the estimated costs of plugging and abandoning the well. All of these funds shall be deposited in a separate interest bearing account for the benefit of the Partnership, and the total amount so retained and deposited shall not exceed the Managing General Partner’s reasonable estimate of the costs to plug and abandon the well.

5.05(b). Distribution of Uncommitted Subscription Proceeds. Any subscription proceeds not expended or committed for expenditure, as evidenced by a written agreement, by the Partnership within 12 months of the Offering Termination Date, except necessary operating capital, shall be distributed to the Participants in the ratio that the subscription amount designated on each Participant’s Subscription Agreement bears to the total subscription amounts designated on all of the Participants’ Subscription Agreements, as a return of capital. The Managing General Partner shall reimburse the Participants for the selling or other offering expenses, if any, allocable to the return of capital.

For purposes of this subsection, “committed for expenditure” shall mean contracted for, actually earmarked for or allocated by the Managing General Partner to the Partnership’s drilling operations, and “necessary operating capital” shall mean those funds which, in the opinion of the Managing General Partner, should remain on hand to assure continuing operation of the Partnership.

5.05(c). Distributions on Winding Up. On the winding up of the Partnership distributions shall be made as provided in §7.02.

5.05(d). Interest and Return of Capital. No party shall under any circumstances be entitled to any interest on amounts retained by the Partnership. Each Participant shall look only to his share of distributions, if any, from the Partnership for a return of his Capital Contribution.

ARTICLE VI

TRANSFER OF UNITS

6.01. Transferability of Units. A Participant’s transfer of a portion or all his Units, or any interest in his Units, is subject to all of the provisions of this Article VI. For purposes of this Article VI, the term “transfer” shall include any sale, exchange, gift, assignment, pledge, mortgage, hypothecation, redemption or other form of transfer of a Unit, or any interest in a Unit, by a Participant (which may include the Managing General Partner or its Affiliates, if they purchase Units) or by operation of law, including any transfers of Units which a Participant presents to the Managing General Partner for purchase under §6.03.

6.01(a). Rights of Assignee. Unless a transferee of a Participant’s Unit becomes a substitute Participant with respect to that Unit in accordance with the provisions of §6.02(a)(3)(a), he shall not be entitled to any of the rights granted to a Participant under this Agreement, other than the right to receive all or part of the share of the profits, losses, income, gains, deductions, credits and depletion allowances, or items thereof, and cash distributions or returns of capital to which his transferor would otherwise be entitled under this Agreement.

6.01(b). Conversion of Investor General Partner Units to Limited Partner Units.

6.01(b)(1). Automatic Conversion. After all of the Partnership Wells have been drilled and completed, as determined by the Managing General Partner, the Managing General Partner shall file an amended certificate of limited partnership with the Secretary of State of the State of Delaware for the purpose of converting the Investor General Partner Units to Limited Partner Units. In this regard, a well shall be deemed to be completed when production equipment is installed on a well, even though the well may not yet be connected to a pipeline for production of natural gas.

6.01(b)(2). Investor General Partners Shall Have Contingent Liability. On conversion the Investor General Partners shall be Limited Partners entitled to limited liability; however, they shall remain liable to the Partnership for any additional Capital Contribution required for their proportionate share of any Partnership obligation or liability arising before the conversion of their Units as provided in §3.05(b)(2).

6.01(b)(3). Conversion Shall Not Affect Allocations. The conversion shall not affect the allocation to any Participant of any item of Partnership income, gain, loss, deduction or credit or other item of special tax significance other than Partnership liabilities, if any. Further, the conversion shall not affect any Participant’s interest in the Partnership’s natural gas and oil properties and unrealized receivables.

6.01(b)(4). Right to Convert if Reduction of Insurance. Notwithstanding the foregoing, the Managing General Partner shall notify all Participants at least 30 days before the effective date of any material adverse change in the Partnership’s insurance coverage. If the insurance coverage is to be materially reduced, then the Investor General Partners shall have the right to convert their Units into Limited Partner Units before the reduction by giving written notice to the Managing General Partner.

6.02. Special Restrictions on Transfers of Units by Participants.

6.02(a). In General. Transfers of Units by Participants are subject to the following general conditions:

(i)

except as provided by operation of law:

(a)

only whole Units may be transferred unless the Participant owns less than a whole Unit, in which case his entire fractional interest must be transferred; and

(b)

Units may not be transferred to a person who is under the age of 18 or incompetent (unless an attorney-in-fact, guardian, custodian or conservator has been appointed to handle the affairs of that person) without the Managing General Partner’s consent;

(ii)

the costs and expenses associated with the transfer must be paid by the assignor Participant;

(iii)

the transfer documents must be in a form satisfactory to the Managing General Partner; and

(iv)

the terms of the transfer must not contravene those of this Agreement.

Transfers of Units by Participants are subject to the following additional restrictions set forth in §§6.02(a)(1) and 6.02(a)(2).

6.02(a)(1). Tax Law Restrictions. Subject to transfers permitted by §6.03 and transfers by operation of law, no transfer of a Unit by a Participant shall be made which, in the opinion of counsel to the Partnership, would result in the Partnership being either:

(i)

terminated for tax purposes under §708 of the Code; or

(ii)

treated as a “publicly-traded” partnership for purposes of §469(k) of the Code.

6.02(a)(2). Securities Laws Restriction. Subject to transfers permitted by §6.03 and transfers by operation of law, no Unit shall be transferred by a Participant unless there is either:

(i)

an effective registration of the Unit under the Securities Act of 1933, as amended, and qualification under applicable state securities laws; or

(ii)

an opinion of counsel acceptable to the Managing General Partner that the registration and qualification of the Unit is not required, unless this requirement is waived by the Managing General Partner.

Transfers of Units by Participants are also subject to any conditions contained in the Subscription Agreement and Exhibit (B) to the Prospectus.

6.02(a)(3). Substitute Participant.

6.02(a)(3)(a). Procedure to Become Substitute Participant. Subject to §§6.02(a)(1) and 6.02(a)(2), a transferee of a Participant’s Unit shall become a substitute Participant entitled to all the rights of a Participant if, and only if:

(i)

the transferor gives the transferee the right;

(ii)

the transferee pays to the Partnership all costs and expenses incurred by the Partnership in connection with the substitution; and

(iii)

the transferee executes and delivers the instruments necessary to establish that a legal transfer has taken place and to confirm the agreement of the transferee to be bound by all of the terms of this Agreement, in a form acceptable to the Managing General Partner.

6.02(a)(3)(b). Rights of Substitute Participant. A substitute Participant shall be entitled to all of the rights attributable to full ownership of the assigned Units including the right to vote.

6.02(b). Effect of Transfer.

6.02(b)(1). Amendment of Records. The Partnership shall amend its records at least once each calendar quarter to effect the substitution of substitute Participants.

Any transfer of a Unit by a Participant which is permitted under this Article VI, when the transferee does not become a substitute Participant, shall be effective as follows:

(i)

midnight of the last day of the calendar month in which it is made; or

(ii)

at the Managing General Partner’s election, 7:00 A.M. of the following day.

6.02(b)(2). A Transfer of Units Does Not Relieve the Transferor of Certain Costs. No transfer of a Unit by a Participant, including a transfer of less than all of a Participant’s Units or the transfer of a Participant’s Units to more than one party, shall relieve the transferor of its responsibility for its proportionate part of any expenses, obligations and liabilities under this Agreement related to the Units so transferred, whether arising before or after the transfer.

6.02(b)(3). A Transfer of Units Does Not Require A Partnership Accounting. No transfer of a Unit by a Participant shall require an accounting of the Partnership. Also, no transfer of a Unit shall grant rights under this Agreement, including the exercise of any elections, as between the transferring Participant and the Partnership, the Managing General Partner and the remaining Participants to more than one Person unanimously designated by the transferee(s) of the Unit, and, if he has retained an interest in the transferred Unit, the transferor of the Unit.

6.02(b)(4). Required Notice to Managing General Partner of Transfer of Units. Until the Managing General Partner receives from the transferring Participant a written notice in a form acceptable to the Managing General Partner that designates the transferee(s) of a Unit, the Managing General Partner shall continue to account only to the Person to whom it was furnishing notices pursuant to §8.01 and its subsections before the purported transfer of the Unit. This party shall continue to exercise all rights under this Agreement applicable to the Units owned by the purported transferor of the Unit.

6.03. Presentment.

6.03(a). In General. Participants shall have the right to present their Units to the Managing General Partner for purchase subject to the conditions and limitations set forth in this §6.03. A Participant, however, is not obligated to present his Units for purchase.

The Managing General Partner shall not be obligated to purchase more than 5% of the total outstanding Units in any calendar year and this 5% limit may not be waived. The Managing General Partner shall not purchase less than one Unit unless the lesser amount represents the Participant’s entire interest in the Partnership, however, the Managing General Partner may waive this limitation.

A Participant may present his Units in writing to the Managing General Partner every year beginning with the fifth calendar year after the Offering Termination Date subject to the following conditions:

(i)

the presentment request must be made by the Participant within 120 days of the reserve report described in §4.03(b)(3);

(ii)

in accordance with Treas. Reg. §1.7704-1(f), the purchase may not be made until at least 60 calendar days after the Participant notifies the Partnership in writing of the Participant’s intention to exercise the presentment right; and

(iii)

the purchase shall not be considered effective until the presentment price has been paid to the Participant in cash to the Participant.

6.03(b). Requirement for Independent Petroleum Consultant. The amount of the presentment price attributable to Partnership reserves shall be determined based on the last reserve report of the Partnership prepared by the Managing General Partner and reviewed by an Independent Expert. The Managing General Partner shall estimate the present worth of future net revenues attributable to the Partnership’s interest in the Proved Reserves as described in §4.03(b)(3)(ii). The calculation of the presentment price shall be made as set forth in §6.03(c).

6.03(c). Calculation of Presentment Price. The presentment price shall be based on the Partnership’s net assets and liabilities and shall be allocated pro rata to each Participant in the ratio that his number of Units bears to the total number of Units. Subject to the foregoing, the presentment price shall include the sum of the following Partnership items:

(i)

an amount based on 70% of the present worth of future net revenues from the Proved Reserves determined as described in §6.03(b);

(ii)

cash on hand;

(iii)

prepaid expenses and accounts receivable less a reasonable amount for doubtful accounts; and

(iv)

the estimated market value of all assets that are not separately specified above, determined in accordance with standard industry valuation procedures.

There shall be deducted from the foregoing sum the following Partnership items:

(i)

an amount equal to all debts, obligations, and other liabilities, including accrued expenses; and

(ii)

any distributions made to the Participants between the date of the presentment request and the date the presentment price is paid to the selling Participant. However, if any amount of those cash distributions to the Participant by the Partnership was derived from the sale of natural gas, oil or other mineral production, or of a producing property owned by the Partnership, after the date of the presentment request, for purposes of determining the reduction of the presentment price the amount of those cash distributions shall be discounted using the same rate used to take into account the risk factors employed to determine the present worth of the Partnership’s Proved Reserves.

6.03(d). Further Adjustment May Be Allowed. The presentment price may be further adjusted by the Managing General Partner for estimated changes therein from the date of the report to the date of payment of the presentment price to the Selling Participant because of the following:

(i)

the production or sales of, or additions to, reserves and lease and well equipment, sale or abandonment of Leases, and similar matters occurring before the date of the presentment request; and

(ii)

any of the following occurring before payment of the presentment price to the selling Participant:

(a)

changes in well performance;

(b)

increases or decreases in the market price of natural gas, oil or other minerals;

(c)

revisions to regulations relating to the importing of hydrocarbons;

(d)

changes in income, ad valorem, and other tax laws, such as material variations in the provisions for depletion; and

(e)

similar matters.

6.03(e). Selection by Lot. If less than all of the Units presented at any time are to be purchased, then the Participants whose Units are to be purchased will be selected by lot.

The Managing General Partner’s obligation to purchase Units presented may be discharged for its benefit by a third-party or an Affiliate. The Units of the selling Participant shall be transferred to the party who pays for it. A selling Participant shall be required to deliver an executed assignment of his Units, in a form satisfactory to the Managing General Partner, together with any other documentation as the Managing General Partner may reasonably request.

6.03(f). No Obligation of the Managing General Partner to Establish a Reserve. The Managing General Partner shall have no obligation to establish any reserve to satisfy the presentment feature under this section.

6.03(g). Suspension of Presentment Feature. The Managing General Partner may suspend this presentment feature by so notifying Participants at any time if it determines in its sole discretion that it:

(i)

does not have sufficient cash flow; or

(ii)

is unable to borrow funds for this purpose on terms it deems reasonable.

In addition, the presentment feature may be conditioned, in the Managing General Partner’s sole discretion, on the Managing General Partner’s receipt of an opinion of counsel that the transfers will not cause the Partnership to be treated as a “publicly traded partnership” under the Code.

The Managing General Partner shall hold the purchased Units for its own account and not for resale.

6.04. Redemption of Units from Non-Citizen Assignees. If the Partnership, the Managing General Partner or any of its Affiliates become subject to federal, state or local laws or regulations that, in the reasonable determination of the Managing General Partner, create a substantial risk of cancellation or forfeiture of any property that they have an interest in because of the nationality, citizenship or other related status of any Participant or assignee of a Participant’s Units, the Partnership may redeem, on 30 days’ advance notice to the Participant, the Participant’s Units or the Units held by the assignee of a Participant, at a reasonable redemption price per Unit as determined by the Managing General Partner in its sole discretion.

ARTICLE VII

DURATION, DISSOLUTION, AND WINDING UP

7.01. Duration.

7.01(a). Fifty Year Term. The Partnership shall continue in existence for a term of 50 years from the effective date of this Agreement unless sooner terminated as set forth below.

7.01(b). Termination. The Partnership shall terminate following the occurrence of:

(i)

a Final Terminating Event; or

(ii)

any event that causes the dissolution of a limited partnership under the Delaware Revised Uniform Limited Partnership Act.

7.01(c). Continuance of Partnership Except on Final Terminating Event. Other than the occurrence of a Final Terminating Event, the Partnership or any successor limited partnership shall not be wound up, but shall be continued by the parties and their respective successors as a successor limited partnership under all of the terms of this Agreement. The successor limited partnership shall succeed to all of the assets of the Partnership. As used throughout this Agreement, the term “Partnership” shall include the successor limited partnership and the parties to the successor limited partnership.

7.02. Dissolution and Winding Up.

7.02(a). Final Terminating Event. On the occurrence of a Final Terminating Event the affairs of the Partnership shall be wound up and there shall be distributed to each of the parties its Distribution Interest in the remaining Partnership assets.

7.02(b). Time of Liquidating Distribution. To the extent practicable and in accordance with sound business practices in the judgment of the Managing General Partner, liquidating distributions shall be made by:

(i)

the end of the taxable year in which liquidation occurs, determined without regard to §706(c)(2)(A) of the Code; or

(ii)

if later, within 90 days after the date of the liquidation.

Notwithstanding, the following amounts are not required to be distributed within the foregoing time periods so long as the withheld amounts are distributed as soon as practical:

(i)

amounts withheld for reserves reasonably required for liabilities of the Partnership; and

(ii)

installment obligations owed to the Partnership.

7.02(c). In-Kind Distributions. The Managing General Partner shall not be obligated to offer in-kind property distributions to the Participants, but may do so, in its discretion. Any in-kind property distributions to the Participants shall be made to a liquidating trust or similar entity for the benefit of the Participants, unless at the time of the distribution:

(i)

the Managing General Partner offers the individual Participants the election of receiving in-kind property distributions and the Participants accept the offer after being advised of the risks associated with direct ownership; or

(ii)

there are alternative arrangements in place which assure the Participants that they will not, at any time, be responsible for the operation or disposition of Partnership properties.

If the Managing General Partner has not received a Participant’s consent within 30 days after the Managing General Partner mailed the request for consent, then it shall be presumed that the Participant has refused to give his consent.

7.02(d). Sale If No Consent. Any Partnership asset which would otherwise be distributed in-kind to a Participant, except for the failure or refusal of the Participant to give his written consent to the distribution, may instead be sold by the Managing General Partner at the best price reasonably obtainable from an independent third-party, who is not an Affiliate of the Managing General Partner, or to the Managing General Partner itself or its Affiliates, including an Affiliated Income Program, at fair market value as determined by an Independent Expert selected by the Managing General Partner.

ARTICLE VIII

MISCELLANEOUS PROVISIONS

8.01. Notices.

8.01(a). Method. Any notice required under this Agreement shall be:

(i)

in writing; and

(ii)

given by mail or delivered by an overnight delivery company (although one-day delivery is not required) addressed to the party to receive the notice at the address designated in §1.03.

If there is a transfer of Units under this Agreement, no notice to the transferee shall be required, nor shall the transferee have any rights under this Agreement, until notice of the transfer has been given to the Managing General Partner.

Any transfer of Units under this Agreement shall not increase the Managing General Partner’s or the Partnership’s duty to give notice. If there is a transfer of Units under this Agreement to more than one party, then notice to any owner of any interest in the Units shall be notice to all of the owners of the Units.

8.01(b). Change in Address. The address of any party to this Agreement may be changed by notice as follows:

(i)

to the Participants, if there is a change of address by the Managing General Partner; or

(ii)

to the Managing General Partner, if there is a change of address by a Participant.

8.01(c). Time Notice Deemed Given. If the notice is given by the Managing General Partner, then the notice shall be considered given, and any applicable time shall run, from the date the notice is placed in the mail or delivered to the overnight delivery company.

If the notice is given by any Participant, then the notice shall be considered given and any applicable time shall run from the date the notice is received.

8.01(d). Effectiveness of Notice. Any notice to a party other than the Managing General Partner, including a notice requiring concurrence or nonconcurrence, shall be effective, and any failure to respond binding, irrespective of the following:

(i)

whether or not the notice is actually received; or

(ii)

any disability or death on the part of the noticee, even if the disability or death is known to the party giving the notice.

8.01(e). Failure to Respond. Except pursuant to §7.02(c) or when this Agreement expressly requires affirmative approval of a Participant, any Participant who fails to respond in writing within the time specified to a request by the Managing General Partner as set forth below, for approval of, or concurrence in, a proposed action shall be conclusively deemed to have approved the action. Except pursuant to §7.02(c), when this Agreement expressly requires affirmative approval of a Participant, the Managing General Partner shall send a first request and the time period for the Participant’s written response shall not be less than 15 business days from the date of mailing of the request. If the Participant does not respond in writing to the first request, then the Managing General Partner shall send a second request. If the Participant does not respond in writing to the second request within seven calendar days from the date of mailing the second request, then the Participant shall be conclusively deemed to have approved the action.

8.02. Time. Time is of the essence of each part of this Agreement.

8.03. Applicable Law. The terms and provisions of this Agreement shall be construed under the laws of the State of Delaware, other than its conflict of law provisions, however, this section shall not be deemed to limit causes of action for alleged violations of federal or state securities law to the laws of the State of Delaware. Neither this Agreement nor the Subscription Agreement shall require mandatory venue or mandatory arbitration of any or all claims by Participants against the Sponsor.

8.04. Agreement in Counterparts. This Agreement may be executed in counterpart and shall be binding on all of the parties executing this or similar agreements from and after the date of execution by each party.

8.05. Amendment.

8.05(a). Procedure for Amendment. No changes in this Agreement shall be binding unless:

(i)

proposed in writing by the Managing General Partner, and adopted with the consent of Participants whose Units equal a majority of the total Units; or

(ii)

proposed in writing by Participants whose Units equal 10% or more of the total Units and approved by an affirmative vote of Participants whose Units equal a majority of the total Units.

8.05(b). Circumstances Under Which the Managing General Partner Alone May Amend. The Managing General Partner is authorized to amend this Agreement and its exhibits without the consent of Participants in any way deemed necessary or desirable by it to do any or all of the following:

(i)

add, or substitute in the case of an assigning party, additional Participants;

(ii)

enhance the tax benefits of the Partnership to the parties and amend the allocation provisions of this Agreement as provided in §5.01(c)(3);

(iii)

satisfy any requirements, conditions, guidelines, options, or elections contained in any opinion, directive, order, ruling, or regulation of the SEC, the IRS, or any other federal or state agency, or in any federal or state statute, compliance with which it deems to be in the best interest of the Partnership;

(iv)

cure any ambiguity, correct or supplement any provision of this Agreement that may be inconsistent with any other provision of this Agreement, or add any provision to this Agreement with respect to matters, events or issues arising under this Agreement that is not inconsistent with the other provisions of this Agreement; or

(v)

facilitate any agreements entered into by the Partnership to hedge its natural gas and oil reserves and pledge up to 100% of its assets and natural gas and oil reserves in connection therewith.

Notwithstanding the foregoing, no amendment materially and adversely affecting the interests or rights of Participants shall be made without the consent of the Participants whose interests or rights will be so affected.

8.06. Additional Partners. Each Participant consents to the admission to the Partnership of additional Participants as the Managing General Partner, in its discretion, chooses to admit.

8.07. Legal Effect. This Agreement shall be binding on and inure to the benefit of the parties, their heirs, devisees, personal representatives, successors and assigns, and shall run with the interests subject to this Agreement. The terms “Partnership,” “Limited Partner,” “Investor General Partner,” “Participant,” “Partner,” “Managing General Partner,” “Operator,” or “parties” shall equally apply to any successor limited partnership, and any heir, devisee, personal representative, successor or assign of a party.

IN WITNESS WHEREOF, the parties hereto set their hands as of the ________ day of ___________________, 2009.

ATLAS:	ATLAS RESOURCES, LLC
	Managing General Partner

	By:

EXHIBIT (I-A)

FORM OF

MANAGING GENERAL PARTNER SIGNATURE PAGE

EXHIBIT (I-A)

MANAGING GENERAL PARTNER SIGNATURE PAGE

Attached to and made a part of the AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF LIMITED PARTNERSHIP of ATLAS RESOURCES PUBLIC #18-2009(C) L.P.

The undersigned agrees:

to serve as the Managing General Partner of ATLAS RESOURCES PUBLIC #18-2009(C) L.P. (the “Partnership”), and hereby executes, swears to, and agrees to all the terms of the Partnership Agreement;

to pay the required subscription of the Managing General Partner under §3.04(a) of the Partnership Agreement; and

to subscribe to the Partnership as follows:

(a)

$___________________ [________] Unit(s)] under Section 3.03(b)(1) of the Partnership Agreement as a Limited Partner; or

(b)

$___________________ [________] Unit(s)] under Section 3.03(b)(1) of the Partnership Agreement as an Investor General Partner.

Managing General Partner:

Atlas Resources, LLC			Address:

By:			Westpointe Corporate Center One
			1550 Coraopolis Heights Road
			2nd Floor
			Moon Township, Pennsylvania 15108

ACCEPTED this ________ day of __________________, 2009.

			ATLAS RESOURCES, LLC
			MANAGING GENERAL PARTNER

			By:

EXHIBIT (I-B)

FORM OF

SUBSCRIPTION AGREEMENT

ATLAS RESOURCES PUBLIC #18-2009(C) L.P.

SUBSCRIPTION AGREEMENT

I, the undersigned, hereby offer to purchase Units of Atlas Resources Public #18-2009(C) L.P. in the amount set forth on the Signature Page of this Subscription Agreement and on the terms described in the current Prospectus for Atlas Resources Public #18-2008 Program, as supplemented or amended from time to time. I acknowledge and agree that my execution of this Subscription Agreement also constitutes my execution of the Agreement of Limited Partnership (the “Partnership Agreement”) the form of which is attached as Exhibit (A) to the Prospectus and I agree to be bound by all of the terms and conditions of the Partnership Agreement if my subscription is accepted by Atlas Resources, LLC, the Managing General Partner. I understand and agree that I may not assign this offer, nor may it be withdrawn after it has been accepted by the Managing General Partner. I hereby irrevocably constitute and appoint the Managing General Partner, and its duly authorized agents, my agent and attorney-in-fact, in my name, place and stead, to make, execute, acknowledge, swear to, file, record and deliver the Agreement of Limited Partnership and any certificates related thereto. I (other than Massachusetts residents) further understand that following the Signature Page there are certain representations, warranties and covenants which I must make before the Managing General Partner will accept my subscription.

SIGNATURE PAGE OF SUBSCRIPTION AGREEMENT

I, the undersigned, agree to purchase ________ Units at $10,000 per Unit in ATLAS RESOURCES PUBLIC #18-2009(C) L.P. (the “Partnership”) as (check one):

		Subscription Amount
o	INVESTOR GENERAL PARTNER	$__________________________

o	LIMITED PARTNER	(____________________# Units)

Instructions

Make your check payable to: “Wells Fargo Bank, N.A., Escrow Agent, Atlas Resources Public #18-2009(C) L.P.”

Minimum Subscription: one Unit ($10,000). Additional Subscriptions in $1,000 increments. If you are an individual investor you must personally sign this Signature Page and provide the information requested below. Wire instructions available upon request.

Subscriber (All investors must personally sign this Signature Page.)

NAME OF TRUST, CORPORATION, LLC, PARTNERSHIP:

Name

Tax I. D. No.:			Address of Record (Do not Use P.O. Box)

Print Name

X
Signature

Tax I. D. No.:			See the attached “Alternate Distribution Form" for
			electronic and alternate address information.

Print Name

X
Signature

I received my final prospectus on

(CHECK ONE): OWNERSHIP OF THE UNITS-	o	Tenants-in-Common	o	Partnership
	o	Joint Tenancy with Right of Survivorship	o	C Corporation
	o	Individual	o	S Corporation
	o	Community Property with Survivorship Rights	o	Trust
	o	Limited Liability Company	o	Tenants by the Entirety

(Enclose supporting documents.) If a partnership, corporation or trust, then the members, stockholders or beneficiaries thereof are citizens of _________________________.

Date:

My Telephone No.: Home

Business

My E-mail Address:

(CHECK ONE):	o	I am at least twenty-one years of age	o	I am not twenty-one years of age

(CHECK ONE): I am a:	o	Calendar Year Taxpayer	o	Fiscal Year Taxpayer

(CHECK IF APPLICABLE): I am a:	o	Farmer (2/3 or more of my gross income in 2008 or 2009 is from farming)

TO BE COMPLETED BY REGISTERED REPRESENTATIVE (For Commission and Other Purposes)

I hereby represent that I have discharged my affirmative obligations under Rule 2810(b)(2)(B) and (b)(3)(D) of the FINRA Conduct Rules and specifically have obtained information from the above-named subscriber concerning his/her age, net worth, annual income, federal income tax bracket, investment objectives, investment portfolio, and other financial information and have determined that an investment in the Partnership is suitable for such subscriber, that such subscriber is or will be in a financial position to realize the benefits of this investment, and that such subscriber has a fair market net worth sufficient to sustain the risks for this investment. I have also informed the subscriber of all pertinent facts relating to the liquidity and marketability of the Partnership and an investment in the Partnership, of the risks of unlimited liability regarding an investment as an Investor General Partner, and of the passive loss limitations for tax purposes of an investment as a Limited Partner.


Name of Registered Representative and CRD Number		Name of Broker/Dealer


Signature of Registered Representative		Broker/Dealer CRD Number

Registered Representative Office Address:		Broker/Dealer Facsimile Number:

		Broker/Dealer E-mail Address:


Phone Number: _________________________

Facsimile Number: _______________________

E-mail Address: _________________________


Company Name (if other than Broker/Dealer Name)

NOTICE TO BROKER-DEALER:

Send Subscription Documents completed and signed with check MADE PAYABLE TO: “Wells Fargo Bank, N.A., Escrow Agent, Atlas Resources Public #18-2009(C) L.P.” to:

Mr. Justin Atkinson

Anthem Securities, Inc.

Westpointe Corporate Center One

1550 Coraopolis Heights Road, Suite 300

Moon Township, Pennsylvania 15108-0926

(412) 262-1680

(412) 262-7430 (FAX)

Wire or ACH transfers are available. Please call (800) 251-0171 option 2 or email marketingsupport@atlasamerica.com for information.

TO BE COMPLETED BY THE MANAGING GENERAL PARTNER

ACCEPTED THIS __________ day	ATLAS RESOURCES, LLC,
of ______________________, 2009	MANAGING GENERAL PARTNER

	By:

In order to induce the Managing General Partner to accept this subscription, I hereby represent, warrant, covenant and agree as follows:

Notice: Residents of Massachusetts should not complete or initial this page. Instead, residents of Massachusetts should read the statements below and treat them as notices to the Massachusetts investor of the information set forth in those statements.

Investor’s	Co-Investor’s
Initials	Initials

_____	_____	I have received the Prospectus.

_____	_____	I (other than if I am a Minnesota or Maine resident) recognize and understand that before this offering there has been no public market for the Units and it is unlikely that after the offering there will be any such market, the transferability of the Units is restricted, and in case of emergency or other change in circumstances I cannot expect to be able to readily liquidate my investment in the Units.

_____	_____	I am purchasing the Units for my own account, for investment purposes and not for the account of others, and with no present intention of reselling them.

_____	_____	If an individual, I am a citizen of the United States of America and at least twenty-one years of age.

_____	_____	If an individual, I am a foreign investor, and at least twenty-one years of age.

_____	_____	If a partnership, corporation or trust, then I am at least twenty-one years of age and empowered and duly authorized under a governing document, trust instrument, charter, certificate of incorporation, by-law provision or the like to enter into this Subscription Agreement and to perform the transactions contemplated by the Prospectus, including its exhibits.

_____	_____	I am a foreign corporation, partnership, trust or other entity, and empowered and duly authorized under a governing document, trust instrument, charter, certificate of incorporation, by-law provision or the like to enter into this Subscription Agreement and to perform the transactions contemplated by the Prospectus, including its exhibits.

_____	_____	I (other than if I am a Minnesota or Maine resident) understand that if I am an Investor General Partner, then I will have unlimited joint and several liability for Partnership obligations and liabilities including amounts in excess of my subscription to the extent the obligations and liabilities exceed the Partnership’s insurance proceeds, the Partnership’s assets, and indemnification by the Managing General Partner. Also, the insurance may be inadequate to cover these liabilities and there is no insurance coverage for certain claims.

_____	_____	I (other than if I am a Minnesota or Maine resident) understand that if I am a Limited Partner, then I may only use my Partnership losses to the extent of my net passive income from passive activities in the year, with any excess losses being deferred.

_____	_____	I (other than if I am a Minnesota or Maine resident) understand that no state or federal governmental authority has made any finding or determination relating to the fairness for public investment of the Units and no state or federal governmental authority has recommended or endorsed or will recommend or endorse the Units.

_____	_____	I (other than if I am a Minnesota or Maine resident) understand that the Selling Agent or registered representative is required to inform me and the other potential investors of all pertinent facts relating to the Units, including the following: the risks involved in the offering, including the speculative nature of the investment and the speculative nature of drilling for natural gas and oil; the financial hazards involved in the offering, including the risk of losing my entire investment; the lack of liquidity of my investment; the restrictions on transferability of my Units; the background of the Managing General Partner and the Operator; the tax consequences of my investment; and the unlimited joint and several liability of the Investor General Partners.

To meet the suitability requirements for an investment in your state, please check and initial either (a), (b) or (c) depending on your state of residence and whether you are buying limited partner units or investor general partner units. Initial (d) if you are a fiduciary and you meet the requirement. Also, initial (e) to be included in the Partnership’s consolidated state income tax returns if you meet the requirements.

Investor’s	Co-Investor’s
Initials	Initials

_____	_____	(a)	If I purchase limited partner units, then I must have either: a minimum net worth of $330,000, exclusive of home, home furnishings, and automobiles, or a minimum net worth of $85,000, exclusive of home, home furnishings, and automobiles, and had during the last tax year gross income of at least $85,000, without regard to an investment in the Partnership.

			In addition, if:

			·	I am a resident of Iowa, Michigan, Missouri, or Pennsylvania, then I must not make an investment in the Partnership which is in excess of 10% of my net worth, exclusive of home, home furnishings and automobiles.

			·	I am a resident of Kansas or Massachusetts, it is recommended by the Office of the Kansas Securities Commissioner and the Massachusetts Securities Division, respectively, that I should limit my investment in the Partnership and substantially similar programs to no more than 10% of my liquid net worth. Liquid net worth is that portion of my net worth (total assets minus total liabilities) that is comprised of cash, cash equivalents and readily marketable securities. Readily marketable securities may include investments in an IRA or other retirement plan that can be liquidated within a short time, less any income tax penalties that may apply for early distribution.

			·	I am a resident of Kentucky, then I must not make an investment in the Partnership which is in excess of 10% of my liquid net worth.

			·	I am a resident of Alabama, Ohio or Oregon, then I must not make an investment in the Partnership which would, after including my previous investments in prior Atlas Resources programs, if any, and any other similar natural gas and oil drilling programs, exceed 10% of my liquid net worth, exclusive of home, home furnishings and automobiles.

_____	_____	(b)	If I purchase investor general partner units and I am a resident of:

·	Alaska,	·	Louisiana,	·	Puerto Rico,

·	Colorado,	·	Maryland,	·	Rhode Island,

·	Connecticut,	·	Mississippi,	·	South Carolina,

·	Delaware,	·	Missouri,	·	South Dakota,

·	District of Columbia,	·	Montana,	·	Utah,

·	Florida,	·	Nebraska,	·	Vermont,

·	Georgia,	·	Nevada,	·	Virginia,

·	Hawaii,	·	New Hampshire,	·	West Virginia,

·	Idaho,	·	New York,	·	Wisconsin, or

·	Illinois,	·	North Dakota,	·	Wyoming,

·	Kentucky,

then I must have either: a net worth of at least $330,000, exclusive of home, furnishings and automobiles, or a net worth of not less than $85,000, exclusive of home, furnishings and automobiles, and had during the last tax year gross income” of at least $85,000, without regard to an investment in the Partnership.

Investor’s	Co-Investor’s
Initials	Initials

			Additionally, if:

			·	I am a resident of Missouri, then I must not make an investment in the Partnership which is in excess of 10% of my net worth, exclusive of home, home furnishings and automobiles.

			·	I am a resident of Kentucky, then I must not make an investment in the Partnership which is in excess of 10% of my liquid net worth.

_____	_____	(c)	If I purchase investor general partner units and I am a resident of:

·	Alabama,	·	Maine,	·	Ohio,

·	Arizona,	·	Massachusetts,	·	Oklahoma,

·	Arkansas,	·	Michigan,	·	Oregon,

·	California,	·	Minnesota,	·	Pennsylvania,

·	Indiana,	·	New Jersey,	·	Tennessee,

·	Iowa,	·	New Mexico,	·	Texas, or

·	Kansas,	·	North Carolina,	·	Washington,

				then I must meet any one of the following suitability requirements:

				·	an individual or joint net worth with my spouse of $330,000 or more, without regard to the investment in the Partnership, exclusive of home, home furnishings and automobiles, and a combined gross income of $150,000 or more for the current year and for the two previous years; or

				·	an individual or joint net worth with my spouse in excess of $750,000, exclusive of home, home furnishings and automobiles; or

				·	a combined “gross income” as defined in Section 61 of the Internal Revenue Code of 1986, as amended, in excess of $200,000 in the current year and the two previous years.

				Additionally, if:

				·	I am a resident of Iowa, Michigan or Pennsylvania, then I must not make an investment in the Partnership which is in excess of 10% of my net worth, exclusive of home, home furnishings and automobiles.

				·	I am a resident of Alabama, Ohio or Oregon, then I must not make an investment in the Partnership which would, after including my previous investments in prior Atlas Resources programs, if any, and any other similar natural gas and oil drilling programs, exceed 10% of my net worth, exclusive of home, home furnishings and automobiles.

				·	I am a resident of Kansas or Massachusetts, it is recommended by the Office of the Kansas Securities Commissioner and the Massachusetts Securities Division, respectively, that I should limit my investment in the program and substantially similar programs to no more than 10% of my liquid net worth. Liquid net worth is that portion of my net worth (total assets minus total liabilities) that is comprised of cash, cash equivalents and readily marketable securities. Readily marketable securities may include investments in an IRA or other retirement plan that can be liquidated within a short time, less any income tax penalties that may apply for early distribution.

				Further, if I am a resident of California, Iowa, North Carolina or Pennsylvania, then I am aware of the requirements set forth in Exhibit (B) to the Prospectus.

Investor’s	Co-Investor’s
Initials	Initials

_____	_____	(d)	If I am a fiduciary, then I am purchasing for a person or entity having the appropriate income and/or net worth specified in (a), (b) or (c) above.

_____	_____	(e)	I understand that the Partnership may derive income from, and therefore, be required to file a Partnership income tax return in certain states, including Pennsylvania, where income may be derived. If I am a nonresident of any or all of those states I, agree to be included in the Partnership’s consolidated state income tax returns, which will include my share of the Partnership’s income and deductions attributable to those states, except if I am a corporate investor that is not a resident of Pennsylvania, I understand that my corporation cannot be included in a consolidated net income return filed by my Partnership in Pennsylvania. I further understand that by being part of one or more Partnership consolidated income tax returns I will not have to file a nonresident income tax return for those respective states unless I have income derived from those states from other sources, which excludes other Atlas partnerships, and any state income taxes paid on my behalf by the Partnership will be deemed a cash distribution to me.

The above representations do not constitute a waiver of any rights that I may have under the Acts administered by the SEC or by any state regulatory agency administering statutes bearing on the sale of securities.

Instructions to Investor

You are required to execute your own Subscription Agreement and the Managing General Partner will not accept any Subscription Agreement that has been executed by someone other than you unless the person has been given your legal power of attorney to sign on your behalf, and you meet all of the conditions in the Prospectus and this Subscription Agreement. In the case of sales to fiduciary accounts, the minimum standards set forth in the Prospectus and this Subscription Agreement must be met by the beneficiary, the fiduciary account, or by the donor or grantor who directly or indirectly supplies the funds to purchase the Partnership Units if the donor or grantor is the fiduciary.

Your execution of the Subscription Agreement constitutes your binding offer to buy Units in the Partnership. Once you subscribe you may withdraw your subscription only by providing the Managing General Partner with written notice of your withdrawal before your subscription is accepted by the Managing General Partner. The Managing General Partner has the discretion to refuse to accept your subscription without liability to you. Subscriptions will be accepted or rejected by the Partnership within 30 days of their receipt. If your subscription is rejected, then all of your funds will be returned to you promptly. If your subscription is accepted before the first closing, then you will be admitted as a Participant not later than 15 days after the release from escrow of the investors’ funds to the Partnership. If your subscription is accepted after the first closing, then you will be admitted into the Partnership not later than the last day of the calendar month in which your subscription was accepted by the Partnership.

The Managing General Partner will not complete a sale of Units to you and send you a confirmation of purchase until at least five business days after the date you receive a final Prospectus. Before completion of the sale of the Units you will have a right to a return of your subscription.

NOTICE TO CALIFORNIA RESIDENTS: This offering deviates in certain respects from various requirements of Title 10 of the California Administrative Code. These deviations include, but are not limited to the following: the definition of Prospect in the Prospectus, unlike Rule 260.140.127.2(b), and Rule 260.140.121(1) does not require enlarging or contracting the size of the area on the basis of geological data in all cases. If I am a resident of California, I acknowledge the receipt of California Rule 260.141.11 set forth in Exhibit (B) to the Prospectus.

SECTION D

TO BE COMPLETED BY ALL INVESTORS

Taxpayer Identification Number Certification – Check the first box below, unless you are a foreign investor or you are investing as a U.S. grantor trust.

Note: If there is a change in circumstances which makes any of the information provided by you in your certification below incorrect, then you are under a continuing obligation so long as you own units in the Partnership to notify the Partnership and furnish the Partnership a new certificate within thirty (30) days of the change.

¨	Under penalties of perjury, I certify that:

(1)

the number provided in my Subscription Agreement is my correct “TIN” (i.e., social security number or employer identification number);

(2)

I am not subject to backup withholding because (a) I am exempt from backup withholding under §3406(g)(1) of the Internal Revenue Code and the related regulations, or (b) I have not been notified by the Internal Revenue Service (IRS) that I am subject to backup withholding as a result of failure to report all interest or dividends, or (c) the IRS has notified me that I am no longer subject to backup withholding; and

(3)

I am a U.S. person (which includes U.S. citizens, resident aliens, entities or associations formed in the U.S. or under U.S. law, and U.S. estates and trusts.)

(Note: You must cross out item 2 above if you have been notified by the IRS that you are currently subject to backup withholding because you have failed to report all interest and dividends on your tax return.)

Foreign Partner. I am at least 21 years of age, and I have provided the Partnership with the appropriate Form W-8 certification or, if a joint account, each joint account owner has provided the Partnership the appropriate Form W-8 certification, and if any one of the joint account owners has not established foreign status, that joint account owner has provided the Partnership with a certified TIN.

¨	U.S. Grantor Trusts. Under penalties of perjury, I certify that:

(1)

the trust designated as the investor on the Subscription Agreement is a United States grantor trust which I can amend or revoke during my lifetime;

(2)

under subpart E of subchapter J of the Internal Revenue Code (check only one of the boxes below):

(a)

100% of the trust is treated as owned by me;

(b)

the trust is treated as owned in equal shares by me and my spouse; or

(c)

____% of the trust is treated as owned by ________________________, and the remainder is treated as owned _____% by me and _____% by my spouse); and

(3)

each grantor or other owner of any portion of the trust has provided the Partnership with the appropriate Form W-8 or Form W-9 certification.

Note: If you check the box in (2)(c), you must insert the information called for by the blanks.

The Internal Revenue Service does not require your consent to any provision of this document other than the certifications required to avoid backup withholding.

X

X
Investor Signature(s)

ATLAS RESOURCES PUBLIC #18-2009(C) L.P.

ALTERNATE DISTRIBUTION FORM

Atlas Resources, LLC Managing General Partner

Westpointe Corporate Center One

1550 Coraopolis Heights Road, 2nd Floor

Moon Township, PA 15108

Phone: 1-800-251-0171 Fax: 412-262-7430

Investor Name: __________________________________________________________________

Please choose from the following two options. Please note if nothing is selected, distribution checks will be mailed to the address of record.

1. Electronic Transfer via ACH (Automatic Clearing House) Not for wire use

Please attach a voided check to confirm the account is ACH eligible.

Financial institution name: _________________________________________________________________________

ABA/ Routing Transit Number (Nine digits are required): ____ ____ ____ ____ ____ ____ ____ ____ ____

Account Number: ________________________________________________________________________________

Further Reference: _______________________________________________________________________________

Please check the account type:

____________ Checking/Broker

____________ Savings/ Money Market (if the account has check writing privileges it is considered a checking account)

2. Alternate Mailing Address (i.e., P.O. Box alternate mailing or financial institution)

Payee: ________________________________________________________________________________________

Address: _______________________________________________________________________________________

City, State Zip code: ______________________________________________________________________________

Account number: ________________________________________________________________________________

***Investor signature is required

Investor’s Signature: _____________________________________________________________________________

Print Investor’s Name: ____________________________________________________________________________

Office Use Only:

Date Received: ______ Date Entered: _______ Initials: _______ Investor id:_________________

EXHIBIT (II)

FORM OF

DRILLING AND OPERATING AGREEMENT

FOR

ATLAS RESOURCES PUBLIC #18-2009(C) L.P.

INDEX

Section			Page

1.	Assignment of Well Locations; Representations and Indemnification Associated with the Assignment of the Lease; Designation of Additional Well Locations; Outside Activities Are Not Restricted			1

2.	Drilling of Wells; Timing; Depth; Interest of Developer; Right to Substitute Well Locations			2

3.	Operator - Responsibilities in General; Covenants; Term			3

4.	Operator’s Charges for Drilling and Completing Wells; Payment; Completion Determination; Dry Hole Determination; Excess Funds and Cost Overruns – Intangible Drilling Costs; Excess Funds and Cost Overruns – Tangible Costs			5

5.	Title Examination of Well Locations; Developer’s Acceptance and Liability; Additional Well Locations			8

6.	Operations Subsequent to Completion of the Wells; Fee Adjustments; Extraordinary Costs; Pipelines; Price Determinations; Plugging and Abandonment			9

7.	Billing and Payment Procedure with Respect to Operation of Wells; Disbursements; Separate Account for Sale Proceeds; Records and Reports; Additional Information			11

8.	Operator’s Lien; Right to Collect From Oil or Gas Purchaser			13

9.	Successors and Assigns; Transfers; Appointment of Agent			13

10.	Operator’s Insurance; Subcontractors’ Insurance; Operator’s Liability			14

11.	Internal Revenue Code Election; Relationship of Parties; Right to Take Production in Kind			15

12.	Effect of Force Majeure; Definition of Force Majeure; Limitation			16

13.	Term			16

14.	Governing Law; Invalidity			16

15.	Integration; Written Amendment			17

16.	Waiver of Default or Breach			17

17.	Notices			17

18.	Interpretation			17

19.	Counterparts			18

	Exhibit A	Description of Leases and Initial Well Locations
	Exhibits A-l through A-___	Maps of Initial Well Locations
	Exhibit B	Form of Assignment
	Exhibit C	Form of Addendum

DRILLING AND OPERATING AGREEMENT

THIS AGREEMENT made this ______ day of _______________, 2009, by and between ATLAS RESOURCES, LLC, a Pennsylvania limited liability company (hereinafter referred to as “Atlas” or “Operator”),

and

ATLAS RESOURCES PUBLIC #18-2009(C) L.P., a Delaware limited partnership, (hereinafter referred to as the “Developer”).

WITNESSETH THAT:

WHEREAS, the Operator, by virtue of the Oil and Gas Leases (the “Leases”) described on Exhibit A attached to and made a part of this Agreement, has certain rights to develop the ____________ (______) initial well locations (the “Initial Well Locations”) identified on the maps attached to and made a part of this Agreement as Exhibits A-l through A-______;

WHEREAS, the Developer, subject to the terms and conditions of this Agreement, desires to acquire certain of the Operator’s rights to develop the Initial Well Locations and to provide for the development on the terms and conditions set forth in this Agreement of additional well locations (“Additional Well Locations”) that the parties may from time to time designate; and

WHEREAS, the Operator is in the oil and gas exploration and development business, and the Developer desires that Operator, as its independent contractor, perform certain services in connection with its efforts to develop the aforesaid Initial and Additional Well Locations (collectively the “Well Locations”) and to operate the wells completed on the Well Locations, on the terms and conditions set forth in this Agreement;

NOW THEREFORE, in consideration of the mutual covenants herein contained and subject to the terms and conditions hereinafter set forth, the parties hereto, intending to be legally bound, hereby agree as follows:

1.	Assignment of Well Locations; Representations and Indemnification Associated with the Assignment of the Lease; Designation of Additional Well Locations; Outside Activities Are Not Restricted.

(a)

Assignment of Well Locations. The Operator shall execute an assignment of an undivided percentage of Working Interest in the Well Location acreage for each well to the Developer as shown on Exhibit A attached hereto, which assignment shall be limited to a depth from the surface to the deepest depth penetrated at the cessation of drilling operations.

The assignment shall be substantially in the form of Exhibit B attached to and made a part of this Agreement. The amount of acreage included in each Initial Well Location and the configuration of the Initial Well Location are indicated on the maps attached to this Agreement as Exhibits A-l through A-______. The amount of acreage included in each Additional Well Location and the configuration of the Additional Well Location shall be indicated on the maps to be attached as exhibits to the applicable addendum to this Agreement as provided in sub-section (c) below.

(b)

Representations and Indemnification Associated with the Assignment of the Lease. The Operator represents and warrants to the Developer that:

(i)

the Operator is the lawful owner of the Lease and rights and interest under the Lease and of the personal property on the Lease or used in connection with the Lease;

(ii)

the Operator has good right and authority to sell and convey the rights, interest, and property;

(iii)

the rights, interest, and property are free and clear from all liens and encumbrances; and

(iv)

all rentals and royalties due and payable under the Lease have been duly paid.

These representations and warranties shall also be included in each recorded assignment of the acreage included in each Initial Well Location and Additional Well Location designated pursuant to sub-section (c) below, substantially in the form of Exhibit B attached to and made a part of this Agreement.

The Operator agrees to indemnify, protect and hold the Developer and its successors and assigns harmless from and against all costs (including but not limited to reasonable attorneys’ fees), liabilities, claims, penalties, losses, suits, actions, causes of action, judgments or decrees resulting from the breach of any of the above representations and warranties. It is understood and agreed that, except as specifically set forth above, the Operator makes no warranty or representation, express or implied, as to its title or the title of the lessors in and to the lands or oil and gas interests covered by said Leases.

(c)

Designation of Additional Well Locations. If the parties hereto desire to designate Additional Well Locations to be developed in accordance with the terms and conditions of this Agreement, then the parties shall execute an addendum substantially in the form of Exhibit C attached to and made a part of this Agreement specifying:

(i)

the undivided percentage of Working Interest and the Oil and Gas Leases to be included as Leases under this Agreement;

(ii)

the amount and configuration of acreage included in each Additional Well Location on maps attached as exhibits to the addendum; and

(iii)

their agreement that the Additional Well Locations shall be developed in accordance with the terms and conditions of this Agreement.

(d)

Outside Activities Are Not Restricted. It is understood and agreed that the assignment of rights under the Leases and the oil and gas development activities contemplated by this Agreement relate only to the Initial Well Locations and the Additional Well Locations. Nothing contained in this Agreement shall be interpreted to restrict in any manner the right of each of the parties to conduct without the participation of the other party any additional activities relating to exploration, development, drilling, production, or delivery of oil and gas on lands adjacent to or in the immediate vicinity of the Well Locations or elsewhere.

2.	Drilling of Wells; Timing; Depth; Interest of Developer; Right to Substitute Well Locations.

(a)

Drilling of Wells. Operator, as Developer’s independent contractor, agrees to drill, complete (or plug) and operate ____________ (_____) oil and gas wells on the ____________ (______) Initial Well Locations in accordance with the terms and conditions of this Agreement. Developer, as a minimum commitment, agrees to participate in and pay the Operator’s charges for drilling and completing (or plugging) the wells and any extra costs pursuant to Section 4 in proportion to the share of the Working Interest owned by the Developer in the wells with respect to all initial wells. It is understood and agreed that, subject to sub-section (e) below, Developer does not reserve the right to decline participation in the drilling of any of the initial wells to be drilled under this Agreement.

(b)

Timing. Operator shall begin drilling the first well within thirty (30) days after the date of this Agreement, and shall begin drilling each of the other initial wells for which payment is made pursuant to Section 4(b) before the close of the 90th day after the close of the calendar year in which this Agreement is entered into by Operator and the Developer. Subject to the foregoing time limits, Operator shall determine the timing of and the order of drilling the Initial Well Locations.

(c)

Depth. All of the wells to be drilled under this Agreement shall be:

(i)

drilled and completed (or plugged) in accordance with the generally accepted and customary oil and gas field practices and techniques then prevailing in the geographical area of the Well Locations; and

(ii)

drilled to a depth sufficient to test thoroughly the objective formation or the deepest assigned depth, whichever is less, and drilled horizontally to test thoroughly the objective formation if so agreed by the Developer and Operator.

(d)

Interest of Developer. Except as otherwise provided in this Agreement, all costs, expenses, and liabilities incurred in connection with the drilling and other operations and activities contemplated by this Agreement shall be borne and paid, and all wells, gathering lines of up to approximately 2,500 feet on each Well Location in connection with a natural gas well, equipment, materials, and facilities acquired, constructed or installed under this Agreement shall be owned, by the Developer in proportion to the share of the Working Interest owned by the Developer in the wells. Subject to the payment of lessor’s royalties and other royalties and overriding royalties, if any, production of oil and gas from the wells to be drilled under this Agreement shall be owned by the Developer in proportion to the share of the Working Interest owned by the Developer in the wells. Additionally, all costs, expenses, and liabilities incurred in connection with the leasing, developing, drilling, and operation of water disposal or injection wells, and the transportation or injection of waste water from Developer’s productive wells under this Agreement shall be the sole responsibility of Developer. In the event Operator provides any services related to disposal wells, injection wells, transportation of waste water or similar matters under this Agreement, Operator shall be paid a monthly competitive fee, as determined by Developer and Operator.

(e)

Right to Substitute Well Locations. Notwithstanding the provisions of sub-section (a) above, if the Operator or Developer determines in good faith, with respect to any Well Location, before operations begin under this Agreement on the Well Location, that it would not be in the best interest of the parties to drill a well on the Well Location, then the party making the determination shall notify the other party of its determination and the basis for its determination and, unless otherwise instructed by Developer, the well shall not be drilled. This determination may be based on:

(i)

the production or failure of production of any other wells that may have been recently drilled in the immediate area of the Well Location;

(ii)

newly discovered title defects; or

(iii)

any other evidence with respect to the Well Location as may have been obtained.

If the well is not drilled, then Operator shall promptly propose a new well location (including all information for the Well Location as Developer may reasonably request) to be substituted for the original Well Location. Developer shall then have seven (7) business days to either reject or accept the proposed new well location. If the new well location is rejected, then Operator shall promptly propose another substitute well location pursuant to the provisions of this sub-section.

Once the Developer accepts a substitute well location or does not reject it within the seven (7) day period, this Agreement shall terminate as to the original Well Location and the substitute well location shall become subject to the terms and conditions of this Agreement.

3.	Operator - Responsibilities in General; Covenants; Term.

(a)

Operator - Responsibilities in General. Atlas shall be the Operator of the wells and Well Locations subject to this Agreement and, as the Developer’s independent contractor, shall, in addition to its other obligations under this Agreement do the following:

(i)

arrange for drilling and completing (or plugging) the wells and, if a gas well, installing the necessary gas gathering line systems and connection facilities;

(ii)

make the technical decisions required in drilling, testing, completing (or plugging), and operating the wells;

(iii)

manage and conduct all field operations in connection with the drilling, testing, completing (or plugging), equipping, operating, and producing the wells;

(iv)

maintain all wells, equipment, gathering lines if a gas well, and facilities in good working order during their useful lives; and

(v)

perform the necessary administrative and accounting functions.

In performing the work contemplated by this Agreement, Operator is an independent contractor with authority to control and direct the performance of the details of the work.

(b)

Covenants. Operator covenants and agrees that under this Agreement:

(i)

it shall perform and carry on (or cause to be performed and carried on) its duties and obligations in a good, prudent, diligent, and workmanlike manner using technically sound, acceptable oil and gas field practices then prevailing in the geographical area of the Well Locations;

(ii)

all drilling and other operations conducted by, for and under the control of Operator shall conform in all respects to federal, state and local laws, statutes, ordinances, regulations, and requirements;

(iii)

unless otherwise agreed in writing by the Developer, all work performed pursuant to a written estimate shall conform to the technical specifications set forth in the written estimate and all equipment and materials installed or incorporated in the wells and facilities shall be new or used and of good quality;

(iv)

in the course of conducting operations, it shall comply with all terms and conditions, other than any minimum drilling commitments, of the Leases (and any related assignments, amendments, subleases, modifications and supplements);

(v)

it shall keep the Well Locations and all wells, equipment and facilities located on the Well Locations free and clear of all labor, materials and other types of liens or encumbrances arising out of operations;

(vi)

it shall file all reports and obtain all permits and bonds required to be filed with or obtained from any governmental authority or agency in connection with the drilling or other operations and activities; and

(vii)

it will provide competent and experienced personnel to supervise drilling, completing (or plugging), and operating the wells and use the services of competent and experienced service companies to provide any third party services necessary or appropriate in order to perform its duties.

(c)

Term. Atlas shall serve as Operator under this Agreement until the earliest of:

(i)

the termination of this Agreement pursuant to Section 13;

(ii)

the termination of Atlas as Operator by the Developer at any time in the Developer’s discretion, with or without cause on sixty (60) days’ advance written notice to the Operator; or

(iii)

the resignation of Atlas as Operator under this Agreement which may occur on ninety (90) days’ written notice to the Developer at any time after five (5) years from the date of this Agreement, it being expressly understood and agreed that Atlas shall have no right to resign as Operator before the expiration of the five-year period.

Any successor Operator shall be selected by the Developer. Nothing contained in this sub-section shall relieve or release Atlas or the Developer from any liability or obligation under this Agreement that accrued or occurred before Atlas’ removal or resignation as Operator under this Agreement. On any change in Operator under this provision, the then present Operator shall deliver to the successor Operator possession of all records, equipment, materials and appurtenances used or obtained for use in connection with operations under this Agreement and owned by the Developer.

4.	Operator’s Charges for Drilling and Completing Wells; Payment; Completion Determination; Dry Hole Determination; Excess Funds and Cost Overruns-Intangible Drilling Costs; Excess Funds and Cost Overruns-Tangible Costs.

(a)

Operator’s Charges for Drilling and Completing Wells. Each oil and gas well that is drilled and completed under this Agreement shall be drilled and completed for an amount equal to the sum of the following items: (i) the Cost of permits, supplies, materials, equipment, and all other items used in the drilling and completion of a well provided by third-parties, or if the foregoing items are provided by Affiliates of the Developer’s Managing General Partner, then those items shall be charged at competitive rates; (ii) fees for third-party services; (iii) fees for services provided by the Developer’s Managing General Partner’s Affiliates, which shall be charged at competitive rates; (iv) an administration and oversight fee which generally is $15,700 per well, except that the administration and oversight fee is $62,241 per vertical well in the Marcellus Shale primary area and $248,964 per horizontal well in the Marcellus Shale primary area, $47,018 in the New Albany Shale (Indiana) primary area and $62,241 in the (horizontal) north central Tennessee secondary area; and (v) a mark-up in an amount equal to 18% of the sum of (i), (ii), (iii) and (iv), above, for the Developer’s Managing General Partner’s services as general drilling contractor as Operator under this Agreement.

“Cost” shall mean the price paid by Operator in an arm’s-length transaction. Additionally, if the Developer’s Managing General Partner drills a well for the Developer that the Managing General Partner determines is not an average well in the area because of the well’s depth, complexity associated with either drilling or completion activity or as otherwise determined by the Managing General Partner, the administration and oversight fee for the well described in §4.02(d)(1)(iv) of the Developer’s Partnership Agreement may be increased to a competitive rate as determined by the Managing General Partner.

The estimated price for drilling and completing each of the wells shall be set forth in an Authority for Expenditure (“AFE”) that shall be attached to this Agreement as an Exhibit, and shall cover all ordinary costs which may be incurred in drilling and completing (or plugging) each well. This includes without limitation, site preparation, permits and bonds, roadways, surface damages, power at the site, water, Operator’s compensation as set forth above, rights-of-way, drilling rigs, equipment and materials, costs of title examinations, logging, cementing, fracturing, casing, meters (other than utility purchase meters), connection facilities, salt water collection tanks, separators, siphon string, rabbit, tubing, an average of 2,500 feet of gathering line per well in connection with each gas well, and geological, geophysical and engineering services.

(b)

Payment. The Developer shall pay to Operator, in proportion to the share of the Working Interest owned by the Developer in the wells, one hundred percent (100%) of the estimated IDCs and Tangible Costs, as those terms are defined below, for drilling and completing all initial wells on execution of this Agreement. Notwithstanding the foregoing, Atlas’ payments for its share of the estimated Tangible Costs, as that term is defined below, of drilling and completing all initial wells as the Managing General Partner of the Developer shall be paid within five (5) business days of notice from Operator that the costs have been incurred. The Developer’s payment shall be nonrefundable in all events in order to enable Operator to do the following:

(i)

commence site preparation for the initial wells;

(ii)

obtain suitable subcontractors for drilling and completing or plugging the initial wells at currently prevailing prices; and

(iii)

insure the availability of equipment and materials.

For purposes of this Agreement, “Intangible Drilling Costs” or “IDCs” shall mean those expenditures associated with property acquisition and the drilling and completion of oil and gas wells that under present law are generally accepted as fully deductible currently for federal income tax purposes. This includes:

(i)

all expenditures made with respect to any well before the establishment of production in commercial quantities for wages, fuel, repairs, hauling, supplies and other costs and expenses incident to and necessary for the drilling of the well and the preparation of the well for the production of oil or gas, that are currently deductible pursuant to Section 263(c) of the Internal Revenue Code of 1986, as amended (the “Code”), and Treasury Reg. Section 1.612-4, which are generally termed "intangible drilling and development costs";

(ii)

the expense of plugging and abandoning any well before a completion attempt; and

(iii)

the costs (other than Tangible Costs and Lease acquisition costs) to re-enter and deepen an existing well, complete the well to deeper formations or reservoirs, or plug and abandon the well if it is nonproductive from the targeted deeper formations or reservoirs.

“Tangible Costs” shall mean those costs associated with property acquisition and the drilling and completion of oil and gas wells that are generally accepted as capital expenditures pursuant to the provisions of the Code. This includes:

(i)

all costs of equipment, parts and items of hardware used in drilling and completing (or plugging) a well;

(ii)

the costs (other than IDCs and Lease acquisition costs) to re-enter and deepen an existing well, complete the well to deeper formations or reservoirs, or plug and abandon the well if it is nonproductive from the targeted deeper formations or reservoirs; and

(iii)

those items necessary to deliver acceptable oil and gas production to purchasers to the extent installed downstream from the wellhead of any well, which are required to be capitalized under the Code and its regulations.

With respect to each additional well drilled on the Additional Well Locations, if any, the Developer shall pay to Operator, in proportion to the share of the Working Interest owned by the Developer in the wells, one hundred percent (100%) of the estimated IDCs and Tangible Costs for drilling and completing the well on execution of the applicable addendum pursuant to Section l(c) above. Notwithstanding the foregoing, Atlas’ payments for its share of the estimated Tangible Costs of drilling and completing all additional wells as the Managing General Partner of the Developer shall be paid within five (5) business days of notice from Operator that the costs have been incurred.

The Developer’s payment shall be nonrefundable in all events in order to enable Operator to do the following:

(i)

commence site preparation for the additional wells;

(ii)

obtain suitable subcontractors for drilling and completing the additional wells at currently prevailing prices; and

(iii)

insure the availability of equipment and materials.

Developer shall pay, in proportion to the share of the Working Interest owned by the Developer in the wells, any extra costs incurred for each well pursuant to sub-section (a) above within ten (10) business days of its receipt of Operator’s statement for the extra costs.

(c)

Completion Determination. Operator shall determine whether or not to run the production casing for an attempted completion or to plug and abandon any well drilled under this Agreement. However, a well shall be completed only if Operator has made a good faith determination that there is a reasonable possibility of obtaining commercial quantities of oil and/or gas.

(d)

Dry Hole Determination. If Operator determines at any time during the drilling or attempted completion of any well drilled under this Agreement, in accordance with the generally accepted and customary oil and gas field practices and techniques then prevailing in the geographic area of the Well Location that the well should not be completed, then it shall promptly and properly plug and abandon the well.

(e)

Excess Funds and Cost Overruns-Intangible Drilling Costs. Any estimated IDCs (which are the IDCs set forth on the AFE Exhibit) prepaid by Developer with respect to any well that exceed Operator’s price specified in sub-section (a) above for the Intangible Drilling Costs of the well (i.e., the actual IDCs) shall be retained by Operator. This excess of estimated IDCs as reflected on the AFE Exhibit over the actual price of the IDCs for the well shall be applied, in proportion to the share of the Working Interest owned by the Developer in the wells, to:

(i)

the IDCs of an additional well or wells to be drilled on the Additional Well Locations; or

(ii)

any cost overruns owed by the Developer to Operator for IDCs on one or more of the other wells on the Well Locations.

Conversely, if Operator’s price specified in sub-section (a) above for the IDCs of any well (i.e., the actual IDCs) exceeds the estimated IDCs (which are the IDCs set forth on the AFE Exhibit) prepaid by Developer for the well, then:

(i)

Developer shall pay the additional price to Operator within ten (10) business days after notice from Operator that the additional amount is due and owing; or

(ii)

Developer and Operator may agree to delete or reduce Developer’s Working Interest in one or more wells to be drilled under this Agreement that have not yet been spudded to provide funds to pay the additional amounts owed by Developer to Operator. If doing so results in any excess prepaid IDCs, then these funds shall be applied, in proportion to the share of the Working Interest owned by the Developer in the wells, to:

(a)

the IDCs of an additional well or wells to be drilled on the Additional Well Locations; or

(b)

any cost overruns owed by the Developer to Operator for IDCs of one or more of the other wells on the Well Locations.

The Exhibits to this Agreement with respect to the affected wells shall be amended as appropriate.

(f)

Excess Funds and Cost Overruns – Tangible Costs. Any estimated Tangible Costs (which are the Tangible Costs set forth on the AFE Exhibit) prepaid by Developer with respect to any well that exceed Operator’s price specified in sub-section (a) above for the Tangible Costs of the well (i.e., the actual Tangible Costs) shall be retained by Operator. This excess of Tangible Costs as reflected on the AFE Exhibit over the actual price of the Tangible Costs for the well shall be applied, in proportion to the share of the Working Interest owned by the Developer in the wells, to:

(i)

the Developer’s Participants’ share of the Tangible Costs for an additional well or wells to be drilled on the Additional Well Locations; or

(ii)

any cost overruns owed by the Developer to Operator for the Developer’s Participants’ share of the Tangible Costs of one or more of the other wells on the Well Locations.

Conversely, if Operator’s price specified in sub-section (a) above for the Developer’s Participants’ share of Tangible Costs of any well (i.e., the actual Tangible Costs) exceeds the estimated Tangible Costs (which are the Tangible Costs set forth on the AFE Exhibit) prepaid by Developer for the Developer’s Participants’ share of the Tangible Costs for the well, then:

(i)

Developer shall pay the additional price to Operator within ten (10) business days after notice from Operator that the additional price is due and owing; or

(ii)

Developer and Operator may agree to delete or reduce Developer’s Working Interest in one or more wells to be drilled under this Agreement to provide funds to pay the additional amounts owed by Developer to Operator. If doing so results in any excess prepaid Tangible Costs, then these funds shall be applied, in proportion to the share of the Working Interest owed by the Developer in the wells, to:

(a)

the Developer’s Participants’ share of the Tangible Costs of an additional well or wells to be drilled on the Additional Well Locations; or

(b)

any cost overruns owed by the Developer to Operator for the Developer’s Participants’ share of the Tangible Costs of one or more of the other wells on the Well Locations.

(iii)

The Developer’s Participants’ share of the Tangible Costs of all of the wells drilled under this Agreement and any additional wells to be drilled on the Additional Well Locations under any Addendum to this Agreement shall be fifteen percent (15%) of the total price prepaid by Developer to Operator pursuant to Section 4(b) of this Agreement or any Addendum hereto. The Developer’s Managing General Partner shall pay any cost overruns owed by Developer to Operator for Developer’s share of Tangible Costs for the wells drilled under this Agreement, or any Addendum hereto, within five (5) business days of notice from Operator that the cost overruns have been incurred. The Developer’s Participants’ share of the Tangible Costs of any one well drilled under this Agreement shall be determined subject to the preceding sentence, taking into account the Developer’s share of all of the Tangible Costs of all of the wells to be drilled under this Agreement and any Addendum hereto.

The Exhibits to this Agreement with respect to the affected wells shall be amended as appropriate.

5.	Title Examination of Well Locations, Developer’s Acceptance and Liability; Additional Well Locations.

(a)

Title Examination of Well Locations, Developer’s Acceptance and Liability. The Developer acknowledges that Operator has furnished Developer with the title opinions identified on Exhibit A, and other documents and information that Developer or its counsel has requested in order to determine the adequacy of the title to the Initial Well Locations and leased premises subject to this Agreement. The Developer accepts the title to the Initial Well Locations and leased premises and acknowledges and agrees that, except for any loss, expense, cost, or liability caused by the breach of any of the warranties and representations made by the Operator in Section l(b), any loss, expense, cost or liability whatsoever caused by or related to any defect or failure of the title shall be the sole responsibility of and shall be borne entirely by the Developer.

(b)

Additional Well Locations. Before beginning drilling of any well on any Additional Well Location, Operator shall conduct, or cause to be conducted, a title examination of the Additional Well Location, in order to obtain appropriate abstracts, opinions and certificates and other information necessary to determine the adequacy of title to both the applicable Lease and the fee title of the lessor to the premises covered by the Lease. The results of the title examination and such other information as is necessary to determine the adequacy of title for drilling purposes shall be submitted to the Developer for its review and acceptance. No drilling on the Additional Well Location shall begin until the title has been accepted in writing by the Developer or Developer has otherwise authorized the drilling on the Additional Well Location. After any title has been accepted by the Developer or drilling on the Additional Well Location has begun, any loss, expense, cost, or liability whatsoever, caused by or related to any defect or failure of the title shall be the sole responsibility of and shall be borne entirely by the Developer, unless such loss, expense, cost, or liability was caused by the breach of any of the warranties and representations made by the Operator in Section l(b).

6.	Operations Subsequent to Completion of the Wells; Fee Adjustments; Extraordinary Costs; Pipelines; Price Determinations; Plugging and Abandonment.

(a)

Operations Subsequent to Completion of the Wells. Beginning with the month in which a well drilled under this Agreement begins to produce, Operator shall be entitled to an operating fee of $392 per month for each well being operated under this Agreement, but its operating fees shall be $975 per month for each productive well in the Marcellus Shale in western Pennsylvania and each productive horizontal well in north central Tennessee, $1,500 per month for each productive well in the New Albany Shale in Indiana, $600 per month for each productive well in the Antrim Shale in Michigan. The above operating fees shall be proportionately reduced, on a well-by-well basis to the extent the Developer owns less than 100% of the Working Interest in a well. This fee shall be in lieu of any direct charges by Operator for its services or the provision by Operator of its equipment for normal superintendence and maintenance of the wells and related pipelines and facilities.

The operating fees shall cover all normal, regularly recurring operating expenses for the production, delivery and sale of natural gas, including without limitation:

(i)

well tending, routine maintenance and adjustment;

(ii)

reading meters, recording production, pumping, maintaining appropriate books and records;

(iii)

preparing reports to the Developer and government agencies; and

(iv)

collecting and disbursing revenues.

The operating fees shall not cover costs and expenses related to the following:

(i)

the production and sale of oil;

(ii)

the collection and disposal of salt water or other liquids produced by the wells;

(iii)

the rebuilding of access roads; and

(iv)

the purchase of equipment, materials or third party services;

which, subject to the provisions of sub-section (c) of this Section 6, shall be invoiced by Operator to the Developer on a monthly basis, and shall be paid by the Developer within ten (10) business days after notice from Operator that the additional amounts are due and owing in proportion to the share of the Working Interest owned by the Developer in the wells.

Any well that is temporarily abandoned or shut-in continuously for an entire calendar month shall not be considered a producing well for purposes of determining the number of wells in the month subject to the operating fee.

(b)

Fee Adjustments. The monthly operating fee set forth in sub-section (a) above may be adjusted by Operator annually, as of the first day of January (the “Adjustment Date”) of each year, beginning January 1, 2010. This adjustment, if any, shall not exceed the percentage increase in the average weekly earnings of “Crude Petroleum, Natural Gas, and Natural Gas Liquids” workers, as published by the U.S. Department of Labor, Bureau of Labor Statistics, and shown in Employment and Earnings Publication, Monthly Establishment Data, Hours and Earning Statistical Table C-2, Index Average Weekly Earnings of “Crude Petroleum, Natural Gas, and Natural Gas Liquids” workers, SIC Code #131-2, or any successor index thereto, since January l, 2009, in the case of the first adjustment, and since the previous Adjustment Date, in the case of each subsequent adjustment.

In addition, the monthly operating fee set forth in sub-section (a) above for any given well or wells being operated under this Agreement may be increased beyond the annual adjustment described in the prior paragraph without advance notice to the Developer, from time-to-time, to the competitive rate in the area where the well(s) are situated, as determined by the Operator in its sole discretion.

(c)

Extraordinary Costs. Without the prior written consent of the Developer, pursuant to a written estimate submitted by Operator, Operator shall not undertake any single project or incur any extraordinary cost with respect to any well being produced under this Agreement that is reasonably estimated to result in an expenditure of more than $5,000, unless the project or extraordinary cost is necessary for the following:

(i)

to safeguard persons or property; or

(ii)

to protect the well or related facilities in the event of a sudden emergency.

In no event, however, shall the Developer be required to pay for any project or extraordinary cost arising from the negligence or misconduct of Operator, its agents, servants, employees, subcontractors, licensees, or invitees.

All extraordinary costs incurred and the cost of projects undertaken under this section with respect to a well being produced under this Agreement shall be billed to the Developer at the invoice cost of third-party services performed or materials purchased together with a reasonable charge by Operator for any services performed directly by it, in proportion to the share of the Working Interest owned by the Developer in the wells. Operator shall have the right to require the Developer to pay in advance all or a portion of the estimated costs of a project undertaken under this section, before undertaking the project, in proportion to the share of the Working Interest owned by the Developer in the well or wells.

(d)

Pipelines. Developer shall have no interest in the pipeline gathering system, which gathering system shall remain the sole property of Operator or its Affiliates, including Laurel Mountain Midline if Atlas Pipeline Partners’ gathering system is transferred to Laurel Mountain Midline, and shall be maintained at their sole cost and expense.

(e)

Price Determinations. Notwithstanding anything in this Agreement to the contrary, the Developer shall pay all costs in proportion to the share of the Working Interest owned by the Developer in the wells with respect to obtaining price determinations under and otherwise complying with the Natural Gas Policy Act of 1978 and the implementing state regulations. This responsibility shall include, without limitation, preparing, filing, and executing all applications, affidavits, interim collection notices, reports and other documents necessary or appropriate to obtain price certification, to effect sales of natural gas, or otherwise to comply with the Act and the implementing state regulations.

Operator agrees to furnish the information and render the assistance as the Developer may reasonably request in order to comply with the Act and the implementing state regulations without charge for services performed by its employees.

(f)

Plugging and Abandonment. The Developer shall have the right to direct Operator to plug and abandon any well that has been completed under this Agreement as a producer. In addition, Operator shall not plug and abandon any well that has been drilled and completed as a producer under this Agreement before obtaining the written consent of the Developer. However, if the Operator determines that any well drilled and completed under this Agreement as a producer shall be plugged and abandoned in accordance with the generally accepted and customary oil and gas field practices and techniques then prevailing in the geographic area of the well location, and makes a written request to the Developer for authority to plug and abandon the well and the Developer fails to respond in writing to the request within forty-five (45) days following the date of the request, then the Developer shall be deemed to have consented to the plugging and abandonment of the well.

All costs and expenses related to plugging and abandoning wells that have been drilled and completed under this Agreement as producing wells shall be borne and paid by the Developer in proportion to the share of the Working Interest owned by the Developer in the wells. Also, at any time after one (1) year from the date each well drilled and completed under this Agreement is placed into production, Operator shall have the right to deduct each month from the proceeds of the sale of the production from the well up to $200, in proportion to the share of the Working Interest owned by the Developer in the well, for the purpose of establishing a fund to cover the Operator’s estimate of the Developer’s share of the costs of eventually plugging and abandoning the well. All of these funds shall be deposited by Operator in a separate interest bearing escrow account for the account of the Developer, and the total amount so retained and deposited shall not exceed Operator’s reasonable estimate of Developer’s share of the costs of eventually plugging and abandoning the well.

7.	Billing and Payment Procedure with Respect to Operation of Wells; Disbursements; Separate Account for Sale Proceeds; Records and Reports; Additional Information.

(a)

Billing and Payment Procedure with Respect to Operation of Wells. Operator shall promptly and timely pay and discharge on behalf of the Developer, in proportion to the share of the Working Interest owned by the Developer in the wells, the following:

(i)

all expenses and liabilities payable and incurred by reason of its operation of the wells in accordance with this Agreement , such as severance taxes, royalties, overriding royalties, operating fees, and pipeline gathering charges; and

(ii)

any third-party invoices received by Operator with respect to the Developer’s share of the costs and expenses incurred in connection with the operation of the wells.

Operator, however, shall not be required to pay and discharge any of the above costs and expenses that are being contested in good faith by Operator.

Operator shall:

(i)

deduct the foregoing costs and expenses from the Developer’s share of the proceeds of the oil and/or gas sold from the wells; and

(ii)

keep an accurate record of the Developer’s account, showing expenses incurred and charges and credits made and received with respect to each well.

If the Developer’s share of the proceeds of the oil and/or gas sold from the wells is insufficient to pay the costs and expenses, then Operator shall promptly and timely pay and discharge the costs and expenses described above, in proportion to the share of the Working Interest owned by the Developer in the wells, and prepare and submit an invoice to the Developer each month for those costs and expenses. The invoice shall be accompanied by the form of statement specified in sub-section (b) below, and shall be paid by the Developer within ten (10) business days of its receipt.

(b)

Disbursements. Operator shall disburse to the Developer, on a monthly basis, the Developer’s share of the proceeds received from the sale of oil and/or gas sold from the wells operated under this Agreement, less:

(i)

the amounts charged to the Developer under sub-section (a); and

(ii)

the amount, if any, withheld by Operator for future plugging costs pursuant to sub-section (f) of Section 6.

Each disbursement made and/or invoice submitted to the Developer pursuant to sub-section (a) above shall be accompanied by a statement from the Operator itemizing with respect to each well:

(i)

the total production of oil and/or gas since the date of the last disbursement or invoice billing period, as the case may be, and the Developer’s share of the production;

(ii)

the total proceeds received from any sale of the production, and the Developer’s share of the proceeds;

(iii)

the costs and expenses deducted from the proceeds and/or being billed to the Developer pursuant to sub-section (a) above;

(iv)

the amount withheld for future plugging costs; and

(v)

any other information as Developer may reasonably request, including without limitation copies of all third-party invoices listed on the statement for the period.

(c)

Separate Account for Sale Proceeds. Operator agrees to deposit all proceeds from the sale of oil and/or gas sold from the wells operated under this Agreement in a separate checking account maintained by Operator. This account shall be used solely for the purpose of collecting and disbursing funds constituting proceeds from the sale of production under this Agreement.

(d)

Records and Reports. In addition to the statements required under sub-section (b) above, Operator, within seventy-five (75) days after the completion of each well drilled, shall furnish the Developer with a detailed statement itemizing with respect to the well the total costs and charges under Section 4(a) and the Developer’s share of the costs and charges, and any other information as is necessary to enable the Developer:

(i)

to allocate any extra costs incurred with respect to the well between Tangible Costs and Intangible Drilling Costs; and

(ii)

to determine the amount of the investment tax credit or marginal well production tax credit, if applicable.

(e)

Additional Information. Operator shall promptly furnish the Developer with any additional information as it may reasonably request, including without limitation geological, technical, and financial information, in the form as may reasonably be requested, pertaining to any phase of the operations and activities governed by this Agreement. The Developer and its authorized employees, agents and consultants, including independent accountants shall, at Developer’s sole cost and expense:

(i)

on at least ten (10) days’ written notice to Operator have access during normal business hours to all of Operator’s records pertaining to operations under this Agreement, including without limitation, the right to audit the books of account of Operator relating to all receipts, costs, charges, expenses and disbursements and information regarding the separate account required under sub-section (c); and

(ii)

have access, at its sole risk, to any wells drilled by Operator under this Agreement at all times to inspect and observe any machinery, equipment and operations.

8.	Operator’s Lien; Right to Collect From Oil or Gas Purchaser.

(a)

Operator’s Lien. To secure the payment of all sums due from Developer to Operator under this Agreement, the Developer grants Operator a first and preferred lien on and security interest in the following:

(i)

the Developer’s interest in the Leases covered by this Agreement;

(ii)

the Developer’s interest in oil and gas produced under this Agreement and its share of the proceeds from the sale of the oil and gas; and

(iii)

the Developer’s interest in materials and equipment under this Agreement.

(b)

Right to Collect From Oil or Gas Purchaser. If the Developer fails to timely pay any amount owing under this Agreement by it to the Operator, then Operator, without prejudice to other existing remedies, may collect and retain from any purchaser or purchasers of oil or gas the Developer’s share of the proceeds from the sale of the oil and gas until the amount owed by the Developer, plus twelve percent (12%) interest on a per annum basis, and any additional costs (including without limitation actual attorneys’ fees and costs) resulting from the delinquency, has been paid. Each purchaser of oil or gas shall be entitled to rely on Operator’s written statement concerning the amount of any default.

9.	Successors and Assigns; Transfers; Appointment of Agent.

(a)

Successors and Assigns. This Agreement shall be binding on and inure to the benefit of the undersigned parties and their respective successors and permitted assigns. However, without the prior written consent of the Developer, the Operator may not assign, transfer, pledge, mortgage, hypothecate, sell or otherwise dispose of any of its interest in this Agreement, or any of its rights or obligations under this Agreement. Notwithstanding, this consent shall not be required in connection with:

(i)

the assignment of work to be performed for Operator to subcontractors, it being understood and agreed, however, that any assignment to Operator’s subcontractors shall not in any manner relieve or release Operator from any of its obligations and responsibilities under this Agreement;

(ii)

any lien, assignment, security interest, pledge or mortgage arising under Operator’s present or future financing arrangements; or

(iii)

the liquidation, merger, consolidation, or other corporate reorganization or sale of substantially all of the assets of Operator.

Further, in order to maintain uniformity of ownership in the wells, production, equipment, and leasehold interests covered by this Agreement, and notwithstanding any other provision of this Agreement to the contrary, the Developer shall not, without the prior written consent of Operator, sell, assign, transfer, encumber, mortgage or otherwise dispose of any of its interest in the wells, production, equipment or leasehold interests covered by this Agreement unless the disposition encompasses either:

(i)

the entire interest of the Developer in all wells, production, equipment and leasehold interests subject to this Agreement; or

(ii)

an equal undivided interest in all such wells, production, equipment, and leasehold interests.

(b)

Transfers. Subject to the provisions of sub-section (a) above, any sale, encumbrance, transfer or other disposition made by the Developer of its interests in the wells, production, equipment, and/or leasehold interests covered by this Agreement shall be made:

(i)

expressly subject to this Agreement;

(ii)

without prejudice to the rights of the Operator; and

(iii)

in accordance with and subject to the provisions of the Leases covering the Well Locations.

(c)

Appointment of Agent. If at any time the interest of the Developer is divided among or owned by co-owners, Operator may, in its discretion, require the co-owners to appoint a single trustee or agent with full authority to do the following:

(i)

receive notices, reports and distributions of the proceeds from production;

(ii)

approve expenditures;

(iii)

receive billings for and approve and pay all costs, expenses and liabilities incurred under this Agreement;

(iv)

exercise any rights granted to the co-owners under this Agreement;

(v)

grant any approvals or authorizations required or contemplated by this Agreement;

(vi)

sign, execute, certify, acknowledge, file and/or record any agreements, contracts, instruments, reports, or documents whatsoever in connection with this Agreement or the activities contemplated by this Agreement; and

(vii)

deal generally with, and with power to bind, the co-owners with respect to all activities and operations contemplated by this Agreement.

However, all the co-owners shall continue to have the right to enter into and execute all contracts or agreements for their respective shares of the oil and gas produced from the wells drilled under this Agreement in accordance with sub-section (c) of Section 11.

10.	Operator’s Insurance; Subcontractors’ Insurance; Operator’s Liability.

(a)

Operator’s Insurance. Operator shall obtain and maintain at its own expense so long as it is Operator under this Agreement all required Workmen’s Compensation Insurance and comprehensive general public liability insurance in amounts and coverage not less than $1,000,000 per person per occurrence for personal injury or death and $1,000,000 for property damage per occurrence, which shall include coverage for blow-outs, and total liability coverage of not less than $10,000,000.

Subject to the above limits, the Operator’s general public liability insurance shall be in all respects comparable to that generally maintained in the industry with respect to services of the type to be rendered and activities of the type to be conducted under this Agreement. Operator’s general public liability insurance shall, if permitted by Operator’s insurance carrier:

(i)

name the Developer as an additional insured party; and

(ii)

provide that at least thirty (30) days’ prior notice of cancellation and any other adverse material change in the policy shall be given to the Developer.

However, the Developer shall reimburse Operator for the additional cost, if any, of including it as an additional insured party under the Operator’s insurance.

Current copies of all policies or certificates of the Operator’s insurance coverage shall be delivered to the Developer on request. It is understood and agreed that Operator’s insurance coverage may not adequately protect the interests of the Developer and that the Developer shall carry at its expense the excess or additional general public liability, property damage, and other insurance, if any, as the Developer deems appropriate.

(b)

Subcontractors’ Insurance. Operator shall require all of its subcontractors to carry all required Workmen’s Compensation Insurance and to maintain such other insurance, if any, as Operator in its discretion may require.

(c)

Operator’s Liability. Operator’s liability to the Developer as Operator under this Agreement shall be limited to, and Operator shall indemnify the Developer and hold it harmless from, claims, penalties, liabilities, obligations, charges, losses, costs, damages, or expenses (including but not limited to reasonable attorneys’ fees) as provided in Section 4.05 of the Developer’s Partnership Agreement.

11.	Internal Revenue Code Election; Relationship of Parties; Right to Take Production in Kind.

(a)

Internal Revenue Code Election. With respect to this Agreement, each of the parties elects under Section 761(a) of the Internal Revenue Code of 1986, as amended, to be excluded from the provisions of Subchapter K of Chapter 1 of Subtitle A of the Internal Revenue Code of 1986, as amended. If the income tax laws of the state or states in which the property covered by this Agreement is located contain, or may subsequently contain, a similar election, each of the parties agrees that the election shall be exercised.

Beginning with the first taxable year of operations under this Agreement, each party agrees that the deemed election provided by Section 1.761-2(b)(2)(ii) of the Regulations under the Internal Revenue Code of 1986, as amended, will apply; and no party will file an application under Section 1.761-2 (b)(3)(i) of the Regulations to revoke the election. Each party agrees to execute the documents and make the filings with the appropriate governmental authorities as may be necessary to effect the election.

(b)

Relationship of Parties. It is not the intention of the parties to create, nor shall this Agreement be construed as creating, a mining or other partnership or association or to render the parties liable as partners or joint venturers for any purpose. Operator shall be deemed to be an independent contractor and shall perform its obligations as set forth in this Agreement.

(c)

Right to Take Production in Kind. Subject to the provisions of Section 8 above, the Developer shall have the exclusive right to sell or dispose of its proportionate share of all oil and gas produced from the wells to be drilled under this Agreement, exclusive of production:

(i)

that may be used in development and producing operations;

(ii)

unavoidably lost; and

(iii)

used to fulfill any free gas obligations under the terms of the applicable Lease or Leases.

Operator shall not have any right to sell or otherwise dispose of the oil and gas. The Developer shall have the exclusive right to execute all contracts relating to the sale or disposition of its proportionate share of the production from the wells drilled under this Agreement.

Developer shall have no interest in any gas supply agreements of Operator, except the right to receive Developer’s share of the proceeds received from the sale of any gas or oil from wells developed under this Agreement. The Developer agrees to designate Operator or Operator’s designated bank agent as the Developer’s collection agent in any contracts. On request, Operator shall assist Developer in arranging the sale or disposition of Developer’s oil and gas under this Agreement and shall promptly provide the Developer with all relevant information that comes to Operator’s attention regarding opportunities for selling production.

If Developer fails to take in kind or separately dispose of its proportionate share of the oil and gas produced under this Agreement, then Operator shall have the right, subject to the revocation at will by the Developer, but not the obligation, to purchase the oil and gas or sell it to others at any time and from time to time, for the account of the Developer at the best price obtainable in the area for the production. Notwithstanding, Operator shall have no liability to Developer should Operator fail to market the production.

Any such purchase or sale by Operator shall be subject always to the right of the Developer to exercise at any time its right to take in-kind, or separately dispose of, its share of oil and gas not previously delivered to a purchaser. Any purchase or sale by Operator of the Developer’s share of oil and gas under this Agreement shall be only for reasonable periods of time as are consistent with the minimum needs of the oil and gas industry under the particular circumstances, but in no event for a period in excess of one (1) year.

12.	Effect of Force Majeure; Definition of Force Majeure; Limitation.

(a)

Effect of Force Majeure. If Operator is rendered unable, wholly or in part, by force majeure (as defined below) to carry out any of its obligations under this Agreement, including but not limited to beginning the drilling of one or more wells by the applicable times set forth in Section 2(b), or any Addendum to this Agreement, the obligations of the Operator, so far as it is affected by the force majeure, shall be suspended during but no longer than, the continuance of the force majeure. The Operator shall give to the Developer prompt written notice of the force majeure with reasonably full particulars concerning it. Operator shall use all reasonable diligence to remove the force majeure as quickly as possible to the extent the same is within its reasonable control.

(b)

Definition of Force Majeure. The term “force majeure” shall mean an act of God, strike, lockout, or other industrial disturbance, act of the public enemy, war, terrorist acts, blockade, public riot, lightning, fire, storm, flood, explosion, governmental restraint, unavailability of drilling rigs, equipment or materials, plant shut-downs, curtailments by oil and gas purchasers and any other causes whether of the kind specifically enumerated above or otherwise, which directly preclude Operator’s performance under this Agreement and is not reasonably within the control of the Operator including, but not limited to, the inability of Operator to begin the drilling of the wells subject to this Agreement by the applicable times set forth in Section 2(b) or in any Addendum to this Agreement due to decisions of third-party operators to delay drilling the wells, poor weather conditions, inability to obtain drilling permits, access rights to the drilling site or title problems.

(c)

Limitation. The requirement that any force majeure shall be remedied with all reasonable dispatch shall not require the settlement of strikes, lockouts, or other labor difficulty affecting the Operator contrary to its wishes. The method of handling these difficulties shall be entirely within the discretion of the Operator.

13.

Term.

This Agreement shall become effective when executed by Operator and the Developer. Except as provided in sub-section (c) of Section 3, this Agreement shall continue and remain in full force and effect for the productive lives of each well being operated under this Agreement.

14.	Governing Law; Invalidity.

(a)

Governing Law. This Agreement shall be governed by, construed and interpreted in accordance with the laws of the Commonwealth of Pennsylvania, excluding its conflict of law provisions.

(b)

Invalidity. The invalidity or unenforceability of any particular provision of this Agreement shall not affect the other provisions of this Agreement, and this Agreement shall be construed in all respects as if the invalid or unenforceable provision were omitted.

15.	Integration; Written Amendment.

(a)

Integration. This Agreement, including the Exhibits to this Agreement, constitutes and represents the entire understanding and agreement of the parties with respect to the subject matter of this Agreement and supersedes all prior negotiations, understandings, agreements, and representations relating to the subject matter of this Agreement.

(b)

Written Amendment. No change, waiver, modification, or amendment of this Agreement shall be binding or of any effect unless in writing duly signed by the party against which the change, waiver, modification, or amendment is sought to be enforced.

16.	Waiver of Default or Breach.

No waiver by any party to any default of or breach by any other party under this Agreement shall operate as a waiver of any future default or breach, whether of like or different character or nature.

17.

Notices.

Unless otherwise provided in this Agreement, all notices, statements, requests, or demands that are required or contemplated by this Agreement shall be in writing and shall be hand-delivered or sent by registered or certified mail, postage prepaid, to the following addresses until a party’s address is changed by certified or registered letter so addressed to the other party:

(i)

If to the Operator, to:

Atlas Resources, LLC

Westpointe Corporate Center One

1550 Coraopolis Heights Road

2nd Floor

Moon Township, Pennsylvania 15108

Attention: President

(ii)

If to Developer, to:

Atlas Resources Public #18-2009(C) L.P.

c/o Atlas Resources, LLC

Westpointe Corporate Center One

1550 Coraopolis Heights Road

2nd Floor

Moon Township, Pennsylvania 15108

Notices that are served by registered or certified mail on the parties in the manner provided above shall be deemed sufficiently served or given for all purposes under this Agreement at the time the notice is hand-delivered or mailed in any post office or branch post office regularly maintained by the United States Postal Service or any successor. All payments shall be hand-delivered or sent by United States mail, postage prepaid to the addresses set forth above until a party’s address is changed by certified or registered letter so addressed to the other party.

18.	Interpretation.

The titles of the Sections in this Agreement are for convenience of reference only and shall not control or affect the meaning or construction of any of the terms and provisions of this Agreement. As used in this Agreement, the plural shall include the singular and the singular shall include the plural whenever appropriate.

19.	Counterparts.

The parties may execute this Agreement in any number of separate counterparts, each of which, when executed and delivered by the parties, shall have the force and effect of an original; but all counterparts of this Agreement shall be deemed to constitute one and the same instrument.

IN WITNESS WHEREOF, the parties hereto have duly executed this Agreement as of the day and year first above written.

	ATLAS RESOURCES, LLC


	By:
		Frank P. Carolas, Executive Vice President


	ATLAS RESOURCES PUBLIC #18-2009(C) L.P.

	By its Managing General Partner:
	ATLAS RESOURCES, LLC


	By:
		Frank P. Carolas, Executive Vice President

DESCRIPTION OF LEASES AND INITIAL WELL LOCATIONS

[To be completed as information becomes available]

1.	WELL LOCATION

(a)

Oil and Gas Lease from ______________________________________ dated _____________________ and recorded in Deed Book Volume __________, Page __________ in the Recorder’s Office of County, ____________, covering approximately _________ acres in ____________________________ Township, ___________________ County, __________________________.

(b)

The portion of the leasehold estate constituting the ____________________________________________ No. __________ Well Location is described on the map attached hereto as Exhibit A-l.

(c)

Title Opinion of _________________________________, ____________________________________, ________________________________________, ________________________________________, dated ___________________, 200___.

(d)

The Developer’s interest in the leasehold estate constituting this Well Location is an undivided __% Working Interest to those oil and gas rights from the surface to the deepest depth penetrated at the cessation of drilling activities (which is ___________ feet), subject to the landowner’s royalty interest and overriding royalty interests.

Exhibit A

Well Name, Twp.

County, State

ASSIGNMENT OF OIL AND GAS LEASE

STATE OF _______________________________

COUNTY OF _____________________________

KNOW ALL MEN BY THESE PRESENTS:

THAT the undersigned ______________________________________________________________ (hereinafter called “Assignor”), for and in consideration of One Dollar and other valuable consideration ($1.00 ovc), the receipt whereof is hereby acknowledged, does hereby sell, assign, transfer and set over unto _____________________________________ __________________ (hereinafter called “Assignee”), an undivided _____________________________ in, and to, the oil and gas lease described as follows:

together with the rights incident thereto and the personal property thereto, appurtenant thereto, or used, or obtained, in connection therewith.

And for the same consideration, the assignor covenants with the said assignee and his or its heirs, successors, or assigns that assignor is the lawful owner of said lease and rights and interest thereunder and of the personal property thereon or used in connection therewith; that the undersigned has good right and authority to sell and convey the same; and that said rights, interest and property are free and clear from all liens and encumbrances, and that all rentals and royalties due and payable thereunder have been duly paid.

In Witness Whereof, the undersigned owner ______ and assignor ______ ha___ signed and sealed this instrument the ______ day of _______________, 200___.


Signed and acknowledged in the presence of

Exhibit B

(Page 1)

ACKNOWLEDGMENT BY INDIVIDUAL

STATE OF
			BEFORE ME, a Notary Public, in and for said
COUNTY OF

County and State, on this day personally appeared who acknowledged to me that ____ he ____ did sign the foregoing instrument and that the same is _____________ free act and deed.

In testimony whereof, I have hereunto set my hand and official seal, at _____________________________, this ______ day of _______________, A.D., 200___.


	Notary Public

CORPORATION ACKNOWLEDGMENT

STATE OF
			BEFORE ME, a Notary Public, in and for said
COUNTY OF

County and State, on this day personally appeared known to me to be the person and officer whose name is subscribed to the foregoing instrument and acknowledged that the same was the act of the said ____________________________________________, a corporation, and that he executed the same as the act of such corporation for the purposes and consideration therein expressed, and in the capacity therein stated.

In testimony whereof, I have hereunto set my hand and official seal, at _____________________________, this ______ day of _______________, A.D., 200___.


	Notary Public

This instrument was prepared by:

Atlas Resources, LLC

Westpointe Corporate Center One

1550 Coraopolis Heights Road

2nd Floor

P.O. Box 611

Moon Township, PA 15108

Exhibit B

(Page 2)

ADDENDUM NO. __________

TO DRILLING AND OPERATING AGREEMENT

DATED ___________________ , 2009

THIS ADDENDUM NO. __________ made and entered into this ______ day of ________________, 2009, by and between ATLAS RESOURCES, LLC, a Pennsylvania limited liability company (hereinafter referred to as “Operator”),

and

ATLAS RESOURCES PUBLIC #18-2009(C) L.P., a Delaware limited partnership, (hereinafter referred to as the Developer).

WITNESSETH THAT:

WHEREAS, Operator and the Developer have entered into a Drilling and Operating Agreement dated ___________________, 2009, (the “Agreement”), which relates to the drilling and operating of ________________ (______)wells on the ________________ (______) Initial Well Locations identified on the maps attached as Exhibits A-l through A-______ to the Agreement, and provides for the development on the terms and conditions set forth in the Agreement of Additional Well Locations as the parties may from time to time designate; and

WHEREAS, pursuant to Section l(c) of the Agreement, Operator and Developer presently desire to designate ________________ Additional Well Locations described below to be developed in accordance with the terms and conditions of the Agreement.

NOW, THEREFORE, in consideration of the mutual covenants contained in this Addendum and intending to be legally bound, the parties agree as follows:

1. Pursuant to Section l(c) of the Agreement, the Developer hereby authorizes Operator to drill, complete (or plug) and operate, on the terms and conditions set forth in the Agreement and this Addendum No.__________, ________________ additional wells on the ________________ Additional Well Locations described on Exhibit A to this Addendum and on the maps attached to this Addendum as Exhibits A-______ through A-______.

2. Operator, as Developer’s independent contractor, agrees to drill, complete (or plug) and operate the additional wells on the Additional Well Locations in accordance with the terms and conditions of the Agreement and further agrees to begin drilling the first additional well within thirty (30) days after the date of this Addendum and to begin drilling all of the additional wells before the close of the 90th day after the close of the calendar year in which the Agreement was entered into by Operator and the Developer, or, if this Addendum is dated after that 90 day period, to begin drilling the first additional well within thirty (30) days after the date of this Addendum and to drill and complete (or plug) all of the remaining additional wells by the end of the calendar year in which this Addendum is dated.

3. Developer acknowledges that:

(a)

Operator has furnished Developer with the title opinions identified on Exhibit A to this Addendum; and

(b)

such other documents and information which Developer or its counsel has requested in order to determine the adequacy of the title to the above Additional Well Locations.

The Developer accepts the title to the Additional Well Locations and leased premises in accordance with the provisions of Section 5 of the Agreement.

4. The drilling and operation of the additional wells on the Additional Well Locations shall be in accordance with and subject to the terms and conditions set forth in the Agreement as supplemented by this Addendum No. __________ and except as previously supplemented, all terms and conditions of the Agreement shall remain in full force and effect as originally written.

Exhibit C

(Page 1)

5. This Addendum No. __________ shall be legally binding on, and shall inure to the benefit of, the parties and their respective successors and permitted assigns.

WITNESS the due execution of this Addendum on the day and year first above written.

	ATLAS RESOURCES, LLC


	By

	ATLAS RESOURCES PUBLIC #18-2009(C) L.P.


	By its Managing General Partner:

	ATLAS RESOURCES, LLC

	By

Exhibit C

(Page 2)

EXHIBIT (B)

SPECIAL DISCLOSURES TO INVESTORS

SPECIAL REPRESENTATIONS OF SUBSCRIBERS IN

CALIFORNIA, IOWA, NORTH CAROLINA AND PENNSYLVANIA.

I. If a resident of California, I am aware that:

IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS SECURITY, OR ANY INTEREST THEREIN, OR TO RECEIVE ANY CONSIDERATION THEREFOR, WITHOUT THE PRIOR WRITTEN CONSENT OF THE COMMISSIONER OF CORPORATIONS OF THE STATE OF CALIFORNIA, EXCEPT AS PERMITTED IN THE COMMISSIONER’S RULES.

As a condition of qualification of the units for sale in the State of California, the following rule is hereby delivered to each California purchaser.

California Administrative Code, Title 10, Ch. 3, Rule 260.141.11. Restriction on transfer.

(a)

The issuer of any security upon which a restriction on transfer has been imposed pursuant to Section 260.141.10 or 260.534 shall cause a copy of this section to be delivered to each issuee or transferee of such security at the time the certificate evidencing the security is delivered to the issuee or transferee.

(b)

It is unlawful for the holder of any such security to consummate a sale or transfer of such security, or any interest therein, without the prior written consent of the Commissioner (until this condition is removed pursuant to Section 260.141.12 of these rules), except:

(i)

to the issuer;

(ii)

pursuant to the order or process of any court;

(iii)

to any person described in Subdivision (i) of Section 25102 of the Code or Section 260.105.14 of these rules;

(iv)

to the transferor’s ancestors, descendants or spouse, or any custodian or trustee for the account of the transferor or the transferor’s ancestors, descendants or spouse, or to a transferee by a trustee or custodian for the account of the transferee or the transferee’s ancestors, descendants or spouse;

(v)

to holders of securities of the same class of the same issuer;

(vi)

by way of gift or donation inter vivos or on death;

(vii)

by or through a broker-dealer licensed under the Code (either acting as such or as a finder) to a resident of a foreign state, territory or country who is neither domiciled in this state to the knowledge of the broker-dealer, nor actually present in this state if the sale of such securities is not in violation of any securities law of the foreign state, territory or country concerned;

(viii)

to a broker-dealer licensed under the Code in a principal transaction, or as an underwriter or member of an underwriting syndicate or selling group;

(ix)

if the interest sold or transferred is a pledge or other lien given by the purchaser to the seller upon a sale of the security for which the Commissioner’s written consent is obtained or under this rule not required;

(x)

by way of a sale qualified under Sections 25111, 25112, 25113 or 25121 of the Code, of the securities to be transferred, provided that no order under Section 25140 or Subdivision (a) of Section 25143 is in effect with respect to such qualification;

(xi)

by a corporation to a wholly-owned subsidiary of such corporation, or by a wholly-owned subsidiary of a corporation to such corporation;

(xii)

by way of an exchange qualified under Section 25111, 25112 or 25113 of the Code, provided that no order under Section 25140 or Subdivision (a) of Section 25143 is in effect with respect to such qualification;

(xiii)

between residents of foreign states, territories or countries who are neither domiciled nor actually present in this state;

(xiv)

to the State Controller pursuant to the Unclaimed Property Law or to the administrator of the unclaimed property law of another state;

(xv)

by the State Controller pursuant to the Unclaimed Property Law or by the administrator of the unclaimed property law of another state if, in either such case, such person (i) discloses to potential purchasers at the sale that transfer of the securities is restricted under this rule, (ii) delivers to each purchaser a copy of this rule, and (iii) advises the Commissioner of the name of each purchaser;

(xvi)

by a trustee to a successor trustee when such transfer does not involve a change in the beneficial ownership of the securities;

(xvii)

by way of an offer and sale of outstanding securities in an issuer transaction that is subject to the qualification requirement of Section 25110 of the Code but exempt from that qualification requirement by subdivision (f) of Section 25102;

provided that any such transfer is on the condition that any certificate evidencing the security issued to such transferee shall contain the legend required by this section.

(c)

The certificates representing all such securities subject to such a restriction on transfer, whether upon initial issuance or upon any transfer thereof, shall bear on their face a legend, prominently stamped or printed thereon in capital letters of not less than 10-point size, reading as follows:

“IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS SECURITY, OR ANY INTEREST THEREIN, OR TO RECEIVE ANY CONSIDERATION THEREFOR, WITHOUT THE PRIOR WRITTEN CONSENT OF THE COMMISSIONER OF CORPORATIONS OF THE STATE OF CALIFORNIA, EXCEPT AS PERMITTED IN THE COMMISSIONER’S RULES.”

II. If a resident of Iowa or North Carolina, I am aware that:

IN MAKING AN INVESTMENT DECISION INVESTORS MUST RELY ON THEIR OWN EXAMINATION OF THE PERSON OR ENTITY CREATING THE SECURITIES AND THE TERMS OF THE OFFERING, INCLUDING THE MERITS AND RISKS INVOLVED. THESE SECURITIES HAVE NOT BEEN RECOMMENDED BY ANY FEDERAL OR STATE SECURITIES COMMISSION OR REGULATORY AUTHORITY. FURTHERMORE, THE FOREGOING AUTHORITIES HAVE NOT CONFIRMED THE ACCURACY OR DETERMINED THE ADEQUACY OF THIS DOCUMENT. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.

III.

PENNSYLVANIA INVESTORS: Because the minimum closing amount is less than 10% of the maximum closing amount allowed to the partnership in this offering, you are cautioned to carefully evaluate the partnership’s ability to fully accomplish its stated objectives and inquire as to the current dollar volume of partnership subscriptions. In addition, subscription proceeds received by the partnership from Pennsylvania investors will be placed into a short-term escrow (120 days or less) until subscriptions for at least 5% of the maximum offering proceeds have been received by a partnership, which for Atlas Resources Public #18-2009(C) L.P. means that subscriptions for at least $13,784,750 have been received by the partnership from investors, including Pennsylvania investors. If the appropriate minimum has not been met at the end of each escrow period, the partnership must notify the Pennsylvania investors in writing by certified mail or any other means whereby a receipt of delivery is obtained within 10 calendar days after the end of each escrow period that they have a right to have their investment returned to them. If an investor requests the return of such funds within 10 calendar days after receipt of notification, the issuer must return such funds within 15 calendar days after receipt of the investor’s request.

Instructions to Investor

NOTICE TO CALIFORNIA RESIDENTS: This offering deviates in certain respects from various requirements of Title 10 of the California Administrative Code. These deviations include, but are not limited to the following: the definition of Prospect in the Prospectus, unlike Rule 260.140.127.2(b) and Rule 260.140.121(1), does not require enlarging or contracting the size of the area on the basis of geological data in all cases. If I am a resident of California, I acknowledge the receipt of California Rule 260.141.11 set forth in Exhibit (B) to the Prospectus.

TABLE OF CONTENTS


Suitability Standards	1
Summary of the Offering	4
Risk Factors	12
Additional Information	29
Forward Looking Statements and Associated Risks	30
Investment Objectives	30
Actions to be Taken by Managing General Partner to Reduce Risks of Additional Payments by Investor General Partners	32
Capitalization and Source of Funds and Use of Proceeds	35
Compensation	39
Terms of the Offering	53
Prior Activities	55
Management	66
Management’s Discussion and Analysis of Financial Condition, Results of Operations, Liquidity and Capital Resources	82	ATLAS RESOURCES
Proposed Activities	85
Competition, Markets and Regulation	101	PUBLIC #18-2008 PROGRAM
Participation in Costs and Revenues	106
Conflicts of Interest	113
Fiduciary Responsibility of the Managing General Partner	124
Federal Income Tax Consequences	125
Summary of Partnership Agreement	153
Summary of Drilling and Operating Agreement	156
Reports to Investors	157
Presentment Feature	158
Transferability of Units	159
Plan of Distribution	160
Sales Material	163
Legal Opinions	164
Experts	164
Litigation	165
Financial Information Concerning the Managing General Partner and Atlas Resources Public #18-2009(C) L.P.	165
Index to Financial Statements	166		PROSPECTUS

Appendix A – Information Regarding Currently Proposed Prospects for Atlas Resources Public #18-2009(C) L.P.

EXHIBIT (A) –Form of Amended and Restated Certificate and Agreement of Limited Partnership for Atlas Resources Public #18-2009(C) L.P.
EXHIBIT (I-A) – Form of Managing General Partner Signature Page
EXHIBIT (I-B) – Form of Subscription Agreement
EXHIBIT (II) – Form of Drilling and Operating Agreement for Atlas Resources Public #18-2009(C) L.P.
EXHIBIT (B) – Special Disclosures to Investors

No one has been authorized to give any information or make any representations other than those contained in this prospectus in connection with this offering. If given or made, you should not rely on such information or representations as having been authorized by the managing general partner. The delivery of this prospectus does not imply that its information is correct as of any time after its date. This prospectus is not an offer to sell these securities in any state to any person where the offer and sale is not permitted.		Until December 31, 2009, 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.

Atlas Resources Public #18-2008 Program Inactive 424B3Prospectus supplement